processdesign - User contributions [en]

Desalination - Team D

2016-03-10T23:02:34Z

Taunins: /* Appendix 2 - Posttreatment Water Quality Goals */

Team D: Final Report

Authors: Thomas Aunins, Robert Cignoni, John Dombrowski, Iris Zhao

Instructors: Fengqi You, David Wegerer

March 11, 2016

=Executive Summary=
Water shortage is one of the foremost and most urgent issues facing the world today, as developing and developed countries alike have struggled with depletion of natural reservoirs and severe droughts. This issue has resulted in the recent rapid development of desalination technology and the construction of desalination facilities. Since the turn of the millennium, the United State alone has increased its desalination capacity from 600 million gallons per day to 1650 million gallons per day, with much more currently being planned. California, in particular, is the focus of a large amount of the United States’ desalination efforts, as its current drought has exposed a discrepancy in water supply contingency and demonstrated a need for non-natural freshwater sources.

This project aims to design a 10 million gallon per day seawater desalination plant on the Southern California Bight--near San Diego--to fill this need. A reverse osmosis system was chosen based on the fact that it is the most rapidly developing and innovating technology in the desalination field, as well as the fact that it has a lower theoretical energy production per gallon of water than the common multi-stage flash purification methods. Our plant will pressurize seawater from subterranean wells off the coast of the bight and send it to our pre-treatment system. There, it will go through a drum screen, multimedia filter, antiscalant addition, and finally ultrafiltration to remove varying size of suspended solids and contaminants, before entering our reverse osmosis system.

The RO system itself is a 2-stage, 6 element per stage process, using Dow SW30XHR-440i membranes and operating at 50% recovery with a feed of 20 million gallons per day. This allows the process to achieve a final dissolved solids concentration of 109 mg/L, far below the California drinking water recommendation of 500 mg/L. This freshwater can then be sent to post-treatment and merged with water of the San Diego County Water Authority’s distribution system. Waste concentrate from the process is sent back into the bay through a long diffuser pipe system that will dilute the brine to necessary levels to avoid environmental damage.

An economic analysis of the process found total capital costs to be slightly more than $600 million, with yearly revenues and operating costs at $25.4 million and $6.2 million, respectively. On a 25 year time scale, this results in a final net present value for the project at -$402.5 million, causing us to conclude that as a commercial venture the project is not viable. We do note, however, that increased demand and decreased supply may cause water prices to rise and create a motivation for government investment in the project in the future. For this reason, we believe that it is possible for this project to become an economically feasible and practically necessary venture in coming years.

__TOC__

=Introduction=

==Background==
Due to drought and the depletion of groundwater, desalination is becoming an increasingly viable source for drinking water in the San Diego, California area. A map of the plant location can be found in Appendix 1. Reverse osmosis appears to be the best route for desalination due to its lower energy costs and high volume of current research efforts. It is also capable of purifying California seawater to the levels recommended by the World Health Organization (WHO) and the state government. The process will separate solids from seawater before subjecting it to a two-stage reverse osmosis unit. Concentrated brine waste will be diluted with seawater before going back into the environment. Permeate streams will be remineralized and disinfected before leaving the facility.

==Problem Statement==
The objective of this process will be to produce fresh drinking-quality water according to standards recommended by the Water Research Foundation. This sets an upper limit for the total dissolved solid in our product at 1000 mg/L, with a non-mandatory guideline of approximately 500 mg/L as an appropriate target. This can be found from in Appendix 2. This encompasses the secondary maximum contaminant levels (MCL) set forth by the State Resources Water Control Board [1]. Additionally, there are guidelines set forth for primary MCLs, which encompasses more dangerous and/or toxic substances in the water. These are a smaller concern for our project because sea water does not naturally contain amounts of these contaminants above the MCLs [2].

=Technical Approach=

==Site Location and Capacity==
This project is planned for construction on the Southern California Bight, located just north of San Diego and nearby the San Diego County Water Authority’s (SDCWA) distribution system. This area is of particular interest for seawater desalination projects due to the projected discrepancy between water supply and demand in upcoming years. Statewide in California, the demand for water is expected to increase by 1.2 billion cubic meters per year by 2030, as projections show that population increase of 16% dramatically outstripping water conservation goals. [3] Southern California in particular has a great need for more freshwater sources, as the lower two-thirds of the state require 80% of California’s water, while the upper third of the state supplies 75% of it. [4]

Per the aforementioned water scarcity, California’s water demand has become a large part of this growth. There are several large scale desalination plants planned for the area, including large-scale projects at Carlsbad and Camp Pendleton. Each of these plants will be constructed to produce 50 MGD of freshwater to the San Diego area, with the latter expected to expand to 150 MGD within ten years of completion. The construction of these plants, along with other smaller scale plants in the area, indicates an urgent need for desalination capacity. Our plant is being designed to produce 10 million gallons per day (MGD) of fresh water for the San Diego area.

==Feed Stream==
Seawater will be fed from a submerged pipeline off the coast of the Southern California Bight. The subterranean feed inlet will allow for an initial pseudo-filter as the water is pulled through the porous ocean floor, preventing large debris and aquatic life from being pulled into the process intake. Worldwide, seawater salinity averages approximately 35,000 mg/L of total dissolved solids, with the primary salts present being chloride and sodium at 19,000 mg/L and 10,500 mg/L, respectively. [5] It should be noted that while data on average local seawater composition for Southern California was not available, this area is known to typically have lower total dissolved solids concentrations than average seawater, placing our calculations on the conservative side. Further breakdown of the dissolved ion concentration of our seawater input can be found in Appendix 3.

==Product Stream==
The objective of this process will be to produce fresh drinking-quality water according to standards set by the California state government and the World Health Organization. Regulations set an upper limit for the total dissolved solid in our product at 1000 mg/L, with a non-mandatory guideline of approximately 500 mg/L as an appropriate target. This encompasses the secondary maximum contaminant levels (MCL) set forth by the State Resources Water Control Board. [6] Additionally, there are guidelines set forth for primary MCLs, which encompasses more dangerous and/or toxic substances in the water. These are a smaller concern for our project because sea water does not naturally contain amounts of these contaminants above the MCLs. [7]

Further goals for the permeate composition and quality following post-treatment were taken from recommendations given by the Water Research Foundation on seawater reverse osmosis and from averages taken from San Diego water treatment plants. These can be found in Appendix 2.

=Flowsheet=

==Process Flow Diagram, Major Technology, and Alternatives==
The process flow diagram (PFD) can be found in Appendix 4. Each stream and piece of equipment is labeled according to which section of the process it pertains to. The final simulation mass balance and stream pressure can be found in Appendix 5. Stream tables can be found in Appendix 6.

===100 - Pretreatment===
The feed flow rate set to the system is 20 MGD. The seawater intake system proposed for the site is a deep infiltration gallery (DIG) intake system due to the permeable hydrogeology offshore of the proposed location. DIG would be comprised of a series of angled or wells drilled radially and therefore would not supply a large amount of feed water due to low permeability. Therefore, the radial collector wells would be drilled at a downward angle from the barge to the dual-use tunnel, below the loose sand layer. The collector wells act as an infiltration gallery, in that the underground seawater infiltrates into the wells and gravity flows into the annular space of the tunnel, which conveys the feedwater onshore. [8]

The sea plays host to contaminants that extend well beyond salt. Poor feed quality can lead to short RO membrane lifetime, short periods of operation, and high maintenance costs. Contaminants include suspended solids, dissolved organic contaminants, and sparingly soluble salts. [9]

First off, a drum screen (F-110) will catch any large solids greater than 0.5 cm that could literally throw a wrench in our operations. A multimedia filter (F-120) captures smaller solids from 1 to 20 µm. The media will consist of anthracite, sand, and gravel, providing a gradient from coarse to fine which creates a media flow pattern necessary to achieve a very low silt density index. [9]

An antiscalant (T-131) will help us avoid fouling of UF and RO membranes by controlling carbonate scaling, magnesium hydroxide scaling, sulfate scaling, and calcium fluoride scaling. Organophosphates tend to be the most stable antiscalant, as they are not subject to hydrolysis or precipitation like sodium hexametaphosphate or polyacrylates. Alternatives to antiscalants that were investigated were water softening and acidification. Both are not economically favorable compared to antiscalants due to additional post treatment measures required when using these methods. Ultrafiltration (F-140), at 0.01–0.02 µm, will remove much of the remaining biological or particulate matter. This pore size also aids in disinfection, as it excludes viruses. These measures will result in a Silt Density index of less than 2.5. [9]

Conventional pretreatment methods using chemical coagulants such as ferric chloride in concert with Dissolved Air Flotation or Clarifier units were also considered. The equipment and media are long lasting and require low maintenance, but the chemical usage and disposal costs would be higher. UF membranes will need to be replaced every 5–10 years, so they require a moderate running cost. However, this extensive pretreatment process will help reduce RO operating costs and increase process efficiency downstream. [9] The selected pretreatment method will decrease our environmental footprint and extend the lifespan of our membranes.

===200 - Reverse Osmosis===

====Seawater Reverse Osmosis Technology====
The desalination method for this plant will be through reverse osmosis (RO). This method was chosen for a number of reasons. Firstly, new desalination plants appearing in the United States are increasingly run using reverse osmosis technology. The most notable example is the Carlsbad plant that recently opened up near San Diego which produces up to 50 million gallons per day of fresh water. Furthermore, a thermodynamic analysis was done on different desalination methods including multi-effect distillation (MED) and multistage flash evaporation (MSF). [10] The analysis found that reverse osmosis has the lowest theoretical energy consumption per unit of fresh water obtained. Due to this, building a reverse osmosis plant likely also has the most security moving forward.

Various membrane technology was investigated for use in this process. Thin film composite polyamide membranes are currently the industry gold standard. These have advantages over asymmetrical cellulose acetate membranes due to their higher permeate fluxes and higher salt rejection. Spiral wound membranes are the current state of the art module and are preferable to hollow fiber and plate and frame modules due to their low fouling which can be attributed to the parallel flow of the feed as opposed to the normal flow regime found in the other modules.

The Dow SW30XHR-440i spiral-wound membrane was chosen because each has the capacity for 6,600 gallons per day of permeate (the maximum available from Dow) and the highest overall dissolved solids rejection fraction at 99.82%. Additionally it is the membrane of choice for plants of a similar scale, such as the plant at Carlsbad, which verifies its practical usefulness for such large-scale operations. Based on this choice, it was determined that a 2-stage, 6 element per stage, single pass process would be necessary to achieve the desired flow rate and recovery for a single unit of our operation. A simplified RO system schematic is shown in Figure 1.
[IMAGE]
Using equations that were presented by Dow Chemical for designing RO plants, it was found that it was possible to produce 10 MGD of fresh water at a recovery of roughly 50% using 2280 membrane elements. These elements would be arranged in a series of 6 elements per pressure vessel for a total of 380 pressure vessels. The pressure vessels would be arranged in a two stage process with 220 pressure vessels in parallel in the first stage and 160 in the second stage. Detailed composition of pass streams from the reverse osmosis process can be found in Appendix 7.

====Energy Recovery====
The energy cost component of seawater RO can be up 70% of the total cost, so reducing the amount of energy consumed by the process was essential to minimizing not only cost, but also environmental impact. Energy use reduction is traditionally achieved through energy recovery devices (ERDs), such as centrifugal devices or isobaric, “pressure-equalizing,” devices. [11] In all cases, energy from the brine stream is transferred directly a portion of the membrane feed stream, reducing pumping requirements. The PFD and stream table detail how the feed is split, with a portion leading to an ERD before entering a booster pump and rejoining the stream from the high pressure (HP) pump. This significantly reduces the size and energy requirements of the HP pump. [12] Systems utilizing this technology can realize up to 60% energy reduction compared to those without it. [11]

Centrifugal ERDs incur lower capital costs, but have limited capacity and efficiency, typically running at a maximum of 82% efficiency. This is because they must transfer hydraulic energy from the brine stream into mechanical energy and then back into hydraulic energy. [12] Isobaric ERDs are the most efficient ERDs, operating at a maximum net transfer efficiency of up to 97%. Isobaric ERDs can handle increased capacity by being run in parallel, similar to the RO membranes. The PX Pressure Exchanger from Energy Recovery, Inc., requires minimal controls, can operate without periodic maintenance, and use ceramic rotors which do not corrode with seawater. [11] For that reason, it was selected for our process.

The PX Pressure Exchanger can operate at 96% efficiency for our process, and will require 24 units to handle our capacity. 6900 gpm (49.5%) of the feed stream will be redirected towards the PX Array, where it will be acted upon by the concentrated brine stream before flowing to the booster pump (P-213). The rest of the stream will be served by the HP pump (P-211). Through this technology, our process utilizes 8.9 kWh/kgal in the RO section, compared to 17.4 kWh/kgal without, almost 50% in energy savings. Pumping requirements are summarized in Appendix 8. A diagram portraying the simulation of this process is in Appendix 9.

===300 - Posttreatment===
After the reverse osmosis process, water will go through post-treatment by adding minerals to prevent corrosion of the distribution pipelines and resemble existing potable water supplies. By adjusting the hardness, alkalinity, and pH of the permeate, the aesthetic water quality will be assured and the distribution pipeline will be protected from corrosion. [13] The post-treatment will include the addition of sodium bicarbonate (T-311) and calcium chloride (T-312) for remineralization, sodium hydroxide (T-321) for pH adjustment, and sodium hypochlorite (T-331) for disinfection. [14]

Lastly, the product will be held in a holding tank (T-350) before being blended with municipal stores. This will allow for proper quality analysis of TDS, conductivity, and pH. Afterwards, the product water will blend with existing supplies so that the municipality may maintain consistent water quality for all consumers. Existing water treatment plants will ensure the water is suitable for consumption. The blended water can then be delivered throughout the region from there.

===400 - Brine Treatment===
There are several possible alternatives for brine treatment in large coastal seawater desalination plants. Possibilities include the use of large evaporation ponds, injection of brine into confined aquifers, and discharge into existing bodies of water. The first two options are largely not viable due to high land costs for evaporation ponds and the requirement of comprehensive land surveys for aquifers. Discharging to the ocean, however, is fairly commonly used as it is a reasonably practical option. [13]

Some smaller-scale facilities have been able to mix their effluent streams with cooling water effluent from nearby industrial plants or additional seawater as a dilution method to reach the necessary 40 ppt range of dissolved salts. [15] However, this requires either a conveniently located cooling water source, which our plant cannot assume, or prohibitively high costs to pump in enough seawater to dilute our effluent. Another option, and one that will be used at Camp Pendleton, is an engineered diffuser system on the brine discharge outfall. An engineered diffuser system consists of a long pipeline that will release smaller amounts of the brine over the course of its length and promote mixing to achieve dilution requirements. The Camp Pendleton desalination plant’s plans for this system are shown in Appendix 10 as an example. [13]

===500 - Solids Treatment===
Solids separated during the pretreatment process through the drum screen, multimedia filter, and UF membrane will be hauled off-site to a suitable landfill. Since no chemical coagulant, such as ferric chloride, is used in the pretreatment process, the spent backwash water can also be conveyed straight to the brine disposal pipeline and discharged to the ocean because the suspended solids contained will be entirely of marine origin.

=Economic Evaluation=

==Equipment Sizing/Pricing==

===Pretreatment===
Assuming that multimedia filters can support 20 gpm/sq. ft. area, [16] our process will require 4 multimedia filters, each with 200 sq. ft. of area and priced at $34000. Ultrafiltration modules can operate at 30 gpm, [17] necessitating 467 UF modules, each priced at $500.

===RO System===
The reverse osmosis system was designed in order to comply with the optimal operating conditions for the aforementioned FilmTec membranes and to achieve the necessary dissolved solids concentration and permeate flow rate for a 10 MGD-scale desalination plant. This resulted in 2280 RO elements in 380 pressure vessels. RO elements are cylinders of length 40.5 inches and diameter 7.9 inches. [18] A range of prices was found for bulk purchases of the required membrane, which could be conservatively estimated at 700 USD per element. The replacement percentage per year for Dow’s membranes filtering this level of SDI is 13%, which was added to the total capital cost of the system. Pressure vessel capital cost was estimated using the Aspen Economic Analyzer, and were found to cost $6700 each. This equipment capital cost was found to be 4.14 million USD. Additionally, there were significant costs associated with construction and auxiliary RO feed equipment was estimated by scaling the 50 MGD Camp Pendleton budget allocation [13] according to the following equation:

<math>C_2=C_1(S_2/S_1)^n</math>

where Ci refers to equipment and construction cost and Si refers to plant capacity. The value for ‘n’ was set as 0.7 based on guidelines from the Chemical Engineering Design textbook. [23] This extra capital cost was estimated at 56.3 million USD.

===Feed Intake===
Tunnel materials for the feed intake was calculated to cost $32.1 million, while construction costs were estimated at $48.7 million. The feedwater piping, intake well system, and pump station were estimated to have a total capital cost of $55.4 million. Further details on capital cost can be found in Appendix 11.

===Concentrate Return and Dilution Pipelines===
Concentrated brine disposal was also modeled after Camp Pendleton. Although their scale of brine disposal is much larger than that of this process, capital cost estimates and sizing were not lowered due to the necessity to dig to the same depth and the use of piping with a similar diameter to return brine concentrate. The brine discharge system was estimated to cost $50.2 million, while the brine discharge pipeline was estimated to cost $9.2 million.

===Pumps===
(Requirements summarized in Appendix 8)

====Pretreatment Pumps====
Ultrafiltration will require a pump in order to filter our process efficiently. Using guidelines from Dow Chemical, [17] the optimal operating pressure for each ultrafiltration module is 30 psi, and each filter can operate at 30 gpm. As a result, this process will require 467 UF modules. A pump pressurizing 13889 gpm to 30 psi will require 202.8 kW. Antiscalant will need to be supplied to the process at 1.39 gpm in order to properly prevent fouling in pretreatment membranes. The power required for this would be 3.88*10-5 kW.

====RO Pumps====
Assuming 50% recovery during the RO process, the brine flow rate will be equal to the permeate flow rate, 6945 gpm. The PX Pressure Exchanger requires lubrication for its hydrodynamic bearing, which will be supplied by the high pressure brine stream, leading to the slight loss in efficiency. As a result, 6877 gpm (49.5%) of the inlet stream can be redirected to the PX Array before reaching a booster pump, with the remaining 7012 gpm being served by the high-pressure pump. The booster pump will only need to supply 53 psi of additional pressure compared to the 629 psi required from the high pressure pump. In order to meet minimum discharge pressure required for proper PX operation, it is necessary for the feed streams to be pressurized to 30 psi so that the low pressure brine stream will exit at 15.9 psi.

====Post-Treatment Pumps====
Post treatment chemicals (sodium hypochlorite, sodium bicarbonate, calcium chloride, sodium hydroxide) are added to the permeate in order to remineralize and pH adjust our water. The pumps used to deliver these chemicals must simply overcome frictional losses in the pipe in order to keep the chemicals moving. All pumps were modeled at 80% efficiency.

===Chemical Storage Tanks===
Chemicals that are added to the water need to be stored beforehand. Chemical holding tanks were sized according to a day’s worth of chemicals. The holding tank for sodium bicarbonate is quite large and this is cause for concern. This issue could be corrected by introducing the solid chemical directly to the product stream rather than creating a solution, storing that solution and then mixing solutions. The cost of the holding tanks can be found in Appendix 12.

==Product Selling Price==
The San Diego County Water Authority agreed to pay Carlsbad (a plant of comparable size and location) $2014-2267 per acre foot of water depending on how much is purchased. [22] Based on this number we estimate that our yearly plant revenue will be roughly $25.4 million.

==Operating Costs==
The San Diego County Water Authority agreed to pay Carlsbad (a plant of comparable size and location) $2014-2267 per acre foot of water depending on how much is purchased. [22] Based on this number we estimate that our yearly plant revenue will be roughly $25.4 million.

==Capital Costs==
The overall capital costs of our plant are summarized below.
{| class="wikitable"
|-
! Project Sector
! Capital Cost (MM$)
|-
| Feedwater Intake and Concentrate Return
| 195.6
|-
| Desalination Facility
| 82.7
|-
| Product Water Conveyance
| 90.4
|-
| '''Subtotal'''
| '''368.7'''
|-
| Contingency
| 130.2
|-
| Working Capital
| 18.4
|-
| Implementation (Legal, Engineering, Administration)
| 84.3
|-
| '''Total'''
| '''601.7'''
|}

==NPV Analysis==
The economic viability of our desalination process was analyzed using a 25 year project lifetime. The cost of capital was set at 12% and the tax rate was set at 35%. A ten-year MACRS depreciation model was used.

The project was found overall to not be economically feasible on a purely commercial level. As revenues would only produce approximately $25.4 million per year the net present value after a project lifetime of 25 years remains extremely low at -$402.5 million. The full economic analysis can be found in Appendix 15.

==Optimization==
The primary opportunity for optimization within our process occurs in the management of the reverse osmosis process, with respect to the number of stages and the number of elements per stage used for our filtration. As a starting point we chose to use two stages and six elements per stage, as this is in-line with Dow Chemical Company’s product recommendations for the SW30XHR-440i RO membrane. Additionally, this is the typical configuration for large-scale RO plants using this particular Dow membrane such as the Carlsbad Desalination Plant. [24]

Using the Dow ROSA software, configurations were evaluated for one, two, and three sequential stages, ranging from four to eight elements per stage. Each of these process conditions was evaluated with respect to the capital costs of equipment as well as the yearly utility cost that would be required. The results of this optimization are summarized in Appendix 16, Table 16.1 and 16.2, with our starting condition and minimum highlighted in each.

This optimization was conducted using a desired recovery of 50%. The number of vessels total and number of vessels per stage were based on the maximum permeate flow for the RO membrane and sizing equations obtained from the Dow RO design guide, respectively. [18]

These data show a minimal variation between different configurations of our system, particularly compared with more dominant capital and operations cost throughout the remainder of our process. However, this process does find a minimum utility cost for the 1-stage, 8 element per stage configuration, at $80,000 per year less than our current setup. Additionally, the condition of a 2-stage, 4 element configuration has a lower utility cost--$60,000 per year less--with an equivalent capital cost. However, it was also observed in either alternative case that the initial element recovery percentage was 10-11%, rather than the 8% achieved in the original 2 stage, 6 element design. A lower recovery percentage indicates lower fouling rates and thus less frequent replacement of membranes, though this precise economic effect could not be quantified.

Based on the manufacturer and industry standard for reverse osmosis configuration, along with the minimal differences in total costs for alternatives and fouling concerns, the project chose to continue with the 2-stage, 6 element per stage configuration.

==Sensitivity Analysis==
Our process was found to be particularly sensitive to three main areas within capital costs, operating, costs, and revenue, which could have significant influence over the final economic analysis if the estimations are off by a significant margin or if the data used for these estimations changes significantly in the coming years.

===Capital Costs===
The construction of the project’s seawater intake/disposal pipeline is priced at approximately $200 million, making up about a third of total capital costs. It may be possible, rather than construct an entirely new water feed and disposal system, to draw used seawater from a nearby large-scale consumer and mitigate these construction costs greatly. For example, it is fairly common for desalination plants to use industrial cooling water effluent for their plants, whether it be as a feed or as a dilution measure, in order to significantly drive down capital costs.

===Operating Costs and Revenue===
The operating costs, while a small portion of total project expenses, consume more than a quarter of the plant revenue at $6.2 million per year. This is largely governed by the energy costs, which have been estimated at $0.08 per kilowatt-hour. A decrease in this cost would substantially decrease yearly operating cost and allow for greater profit.

Similarly, revenue is governed by the cost of water being paid to the Carlsbad Desalination Plant, at $2260 per acre-foot. [22] This price is expected to rise as the water shortage becomes more urgent and the population of California increases. A significant increase in this price could greatly help the desalination project to improve economic viability.

=Conclusion=
Overall, the project designed a 10 million gallon per day seawater desalination plant on the Southern California Bight to fill the need of water shortage. We chose reverse osmosis as a method for desalination. The plant would pressurize seawater from subterranean wells off the coast of the bight. The water is then sent to the pre-treatment system before entering the reverse osmosis system. We decided on a 2 stage, 6 element per stage process using Dow SW30XHR-440i membrane and operating at 50% recovery with a feed of 20 million gallons per day. The system achieves a final dissolved solid concentration of 109 mg/L, which well satisfies the California drinking water recommendation of 500 mg/L of dissolved solids concentration. The fresh water is then sent to post-treatment and merge with existing supplies. Waste concentrate from from the process is sent back into the bay through a long engineered diffuser pipe that can dilute the brine to necessary levels.

Furthermore, we did optimization for our process. The primary opportunity for optimization within our process occurs in the management of the reverse osmosis process, with respect to the number of stages and the number of elements per stage used for our filtration. The result shows a minimal variation between different configurations of our system, particularly compared with more dominant capital and operations cost throughout the remainder of our process. Based on the minimal differences, along with the manufacture and industry standard for reverse osmosis configuration, the project chose to continue with the 2-stage, 6 element per stage configuration.

However, based on the results from the economic analysis, we concluded from the final -$402.5 million net present value, that such an energy intensive process to produce a product that is generally taken for granted is extremely costly. As a commercial venture this project is not viable. On the other hand, with increased demand and decreased supply the water price may rise and become a motivation for the government to invest for the desalination in the future. The project would likely need to taken on by the city of San Diego rather than a private entity. For future development and viability of this project, we recommend to draw used seawater from a nearby large-scale process instead of constructing an entirely new water feed and disposal system. This can mitigate the construction costs greatly.

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# Towler GP, Sinnot R. Chemical Engineering Design: Principles, Practice and Economics of Plant and Process Design. Elsevier.
# Rogers, Paul Nation’s Largest Desalination Plant Goes Up Near San Diego; Future of the California Coast? San Jose Mercury News http://www.mercurynews.com/science/ci_25859513/nations-largest-ocean-desalination-plant-goes-up-near Accessed February 27, 2016.
# San Diego Electricity Rates. Electricity Local. http://www.electricitylocal.com/states/california/san-diego/ Accessed February 27, 2016.
# Dow Reverse Osmosis Membranes Treat Seawater and Offers Drinking Water to Southern California. http://msdssearch.dow.com/PublishedLiteratureDOWCOM/dh_0940/0901b80380940a81.pdf Accessed March 4, 2016.

=Appendices=

==Appendix 1 - Plant Location Map==
[[File:SoCalBight.png|center|700px|thumb|alt=|]]

==Appendix 2 - Posttreatment Water Quality Goals==
[[File:Ap2.PNG|center|700px|thumb|alt=|Table 2.1. Posttreatment water quality goals]]

==Appendix 3 - Dissolved Ion Concentration of Seawater Inlet==

[[File:3.1.PNG|center|600px|thumb|alt=|Table 3.1 Seawater composition.]]

==Appendix 4 - Process Flow Diagram==

[[File:4.PNG|center|600px|thumb|alt=|Process Flow Diagram.]]

==Appendix 5 - Final Simulation Mass Balance and Stream Pressure==

[[File:5.1.PNG|center|600px|thumb|alt=|Table 5.1 ROSA simulation stream summary.]]

==Appendix 6 - Stream Tables==

[[File:6.1.PNG|center|600px|thumb|alt=|Table 6.1 Stream summary tables for section 1 of PFD.]]

[[File:6.2.PNG|center|600px|thumb|alt=|Table 6.2 Stream summary tables for section 2 of PFD.]]

[[File:6.3.PNG|center|600px|thumb|alt=|Table 6.3 Stream summary tables for section 3 of PFD.]]

[[File:6.4.PNG|center|600px|thumb|alt=|Table 6.4 Stream summary tables for section 4 of PFD.]]

[[File:6.5.PNG|center|600px|thumb|alt=|Table 6.5 Stream summary tables for section 5 of PFD.]]

==Appendix 7 - Composition of Pass Streams from RO Process==

[[File:7.1.PNG|center|600px|thumb|alt=|Table 7.1 Composition of pass streams from Reverse osmosis.]]

==Appendix 8 - Pumping Requirements==

[[File:8.1.PNG|center|600px|thumb|alt=|Table 8.1 Pump Requirements.]]

==Appendix 9 - ERD Simulation==

[[File:9.PNG|center|600px|thumb|alt=|ERD Simulation.]]

==Appendix 10 - Example Diffuser System from Camp Pendleton Plant==

[[File:10.PNG|center|600px|thumb|alt=|Example Diffuser System from Camp Pendleton plant.]]

==Appendix 11 - Capital Cost==

[[File:11.1.PNG|center|600px|thumb|alt=|Table 11.1 Capital Cost breakdown.]]

==Appendix 12 - Holding Tank Costs==

[[File:12.1.PNG|center|600px|thumb|alt=|Table 12.1 Holding Tank Costs.]]

==Appendix 13 - Utility Calculations==

[[File:13.1.PNG|center|600px|thumb|alt=|Table 13.1 Utility calculations.]]

==Appendix 14 - Yearly Cost of Chemical Additions==

[[File:14.1.PNG|center|600px|thumb|alt=|Table 14.1 Chemical Addition Costs.]]

==Appendix 15 - Economic Analysis==

[[File:15.PNG|center|600px|thumb|alt=|Economic Analysis.]]

==Appendix 16 - Optimization==

[[File:16.1.PNG|center|600px|thumb|alt=|Table 16.1 Optimization of yearly utility for number of stages and elements per stage.]]

[[File:16.2.PNG|center|600px|thumb|alt=|Table 16.2: Optimization of yearly utility for number of elements per stage.]]

File:Ap2.PNG

2016-03-10T23:00:46Z

Taunins:

Desalination - Team D

2016-03-10T22:54:19Z

Taunins: /* Appendix 1 - Plant Location Map */

Team D: Final Report

Authors: Thomas Aunins, Robert Cignoni, John Dombrowski, Iris Zhao

Instructors: Fengqi You, David Wegerer

March 11, 2016

=Executive Summary=
Water shortage is one of the foremost and most urgent issues facing the world today, as developing and developed countries alike have struggled with depletion of natural reservoirs and severe droughts. This issue has resulted in the recent rapid development of desalination technology and the construction of desalination facilities. Since the turn of the millennium, the United State alone has increased its desalination capacity from 600 million gallons per day to 1650 million gallons per day, with much more currently being planned. California, in particular, is the focus of a large amount of the United States’ desalination efforts, as its current drought has exposed a discrepancy in water supply contingency and demonstrated a need for non-natural freshwater sources.

This project aims to design a 10 million gallon per day seawater desalination plant on the Southern California Bight--near San Diego--to fill this need. A reverse osmosis system was chosen based on the fact that it is the most rapidly developing and innovating technology in the desalination field, as well as the fact that it has a lower theoretical energy production per gallon of water than the common multi-stage flash purification methods. Our plant will pressurize seawater from subterranean wells off the coast of the bight and send it to our pre-treatment system. There, it will go through a drum screen, multimedia filter, antiscalant addition, and finally ultrafiltration to remove varying size of suspended solids and contaminants, before entering our reverse osmosis system.

The RO system itself is a 2-stage, 6 element per stage process, using Dow SW30XHR-440i membranes and operating at 50% recovery with a feed of 20 million gallons per day. This allows the process to achieve a final dissolved solids concentration of 109 mg/L, far below the California drinking water recommendation of 500 mg/L. This freshwater can then be sent to post-treatment and merged with water of the San Diego County Water Authority’s distribution system. Waste concentrate from the process is sent back into the bay through a long diffuser pipe system that will dilute the brine to necessary levels to avoid environmental damage.

An economic analysis of the process found total capital costs to be slightly more than $600 million, with yearly revenues and operating costs at $25.4 million and $6.2 million, respectively. On a 25 year time scale, this results in a final net present value for the project at -$402.5 million, causing us to conclude that as a commercial venture the project is not viable. We do note, however, that increased demand and decreased supply may cause water prices to rise and create a motivation for government investment in the project in the future. For this reason, we believe that it is possible for this project to become an economically feasible and practically necessary venture in coming years.

__TOC__

=Introduction=

==Background==
Due to drought and the depletion of groundwater, desalination is becoming an increasingly viable source for drinking water in the San Diego, California area. A map of the plant location can be found in Appendix 1. Reverse osmosis appears to be the best route for desalination due to its lower energy costs and high volume of current research efforts. It is also capable of purifying California seawater to the levels recommended by the World Health Organization (WHO) and the state government. The process will separate solids from seawater before subjecting it to a two-stage reverse osmosis unit. Concentrated brine waste will be diluted with seawater before going back into the environment. Permeate streams will be remineralized and disinfected before leaving the facility.

==Problem Statement==
The objective of this process will be to produce fresh drinking-quality water according to standards recommended by the Water Research Foundation. This sets an upper limit for the total dissolved solid in our product at 1000 mg/L, with a non-mandatory guideline of approximately 500 mg/L as an appropriate target. This can be found from in Appendix 2. This encompasses the secondary maximum contaminant levels (MCL) set forth by the State Resources Water Control Board [1]. Additionally, there are guidelines set forth for primary MCLs, which encompasses more dangerous and/or toxic substances in the water. These are a smaller concern for our project because sea water does not naturally contain amounts of these contaminants above the MCLs [2].

=Technical Approach=

==Site Location and Capacity==
This project is planned for construction on the Southern California Bight, located just north of San Diego and nearby the San Diego County Water Authority’s (SDCWA) distribution system. This area is of particular interest for seawater desalination projects due to the projected discrepancy between water supply and demand in upcoming years. Statewide in California, the demand for water is expected to increase by 1.2 billion cubic meters per year by 2030, as projections show that population increase of 16% dramatically outstripping water conservation goals. [3] Southern California in particular has a great need for more freshwater sources, as the lower two-thirds of the state require 80% of California’s water, while the upper third of the state supplies 75% of it. [4]

Per the aforementioned water scarcity, California’s water demand has become a large part of this growth. There are several large scale desalination plants planned for the area, including large-scale projects at Carlsbad and Camp Pendleton. Each of these plants will be constructed to produce 50 MGD of freshwater to the San Diego area, with the latter expected to expand to 150 MGD within ten years of completion. The construction of these plants, along with other smaller scale plants in the area, indicates an urgent need for desalination capacity. Our plant is being designed to produce 10 million gallons per day (MGD) of fresh water for the San Diego area.

==Feed Stream==
Seawater will be fed from a submerged pipeline off the coast of the Southern California Bight. The subterranean feed inlet will allow for an initial pseudo-filter as the water is pulled through the porous ocean floor, preventing large debris and aquatic life from being pulled into the process intake. Worldwide, seawater salinity averages approximately 35,000 mg/L of total dissolved solids, with the primary salts present being chloride and sodium at 19,000 mg/L and 10,500 mg/L, respectively. [5] It should be noted that while data on average local seawater composition for Southern California was not available, this area is known to typically have lower total dissolved solids concentrations than average seawater, placing our calculations on the conservative side. Further breakdown of the dissolved ion concentration of our seawater input can be found in Appendix 3.

==Product Stream==
The objective of this process will be to produce fresh drinking-quality water according to standards set by the California state government and the World Health Organization. Regulations set an upper limit for the total dissolved solid in our product at 1000 mg/L, with a non-mandatory guideline of approximately 500 mg/L as an appropriate target. This encompasses the secondary maximum contaminant levels (MCL) set forth by the State Resources Water Control Board. [6] Additionally, there are guidelines set forth for primary MCLs, which encompasses more dangerous and/or toxic substances in the water. These are a smaller concern for our project because sea water does not naturally contain amounts of these contaminants above the MCLs. [7]

Further goals for the permeate composition and quality following post-treatment were taken from recommendations given by the Water Research Foundation on seawater reverse osmosis and from averages taken from San Diego water treatment plants. These can be found in Appendix 2.

=Flowsheet=

==Process Flow Diagram, Major Technology, and Alternatives==
The process flow diagram (PFD) can be found in Appendix 4. Each stream and piece of equipment is labeled according to which section of the process it pertains to. The final simulation mass balance and stream pressure can be found in Appendix 5. Stream tables can be found in Appendix 6.

===100 - Pretreatment===
The feed flow rate set to the system is 20 MGD. The seawater intake system proposed for the site is a deep infiltration gallery (DIG) intake system due to the permeable hydrogeology offshore of the proposed location. DIG would be comprised of a series of angled or wells drilled radially and therefore would not supply a large amount of feed water due to low permeability. Therefore, the radial collector wells would be drilled at a downward angle from the barge to the dual-use tunnel, below the loose sand layer. The collector wells act as an infiltration gallery, in that the underground seawater infiltrates into the wells and gravity flows into the annular space of the tunnel, which conveys the feedwater onshore. [8]

The sea plays host to contaminants that extend well beyond salt. Poor feed quality can lead to short RO membrane lifetime, short periods of operation, and high maintenance costs. Contaminants include suspended solids, dissolved organic contaminants, and sparingly soluble salts. [9]

First off, a drum screen (F-110) will catch any large solids greater than 0.5 cm that could literally throw a wrench in our operations. A multimedia filter (F-120) captures smaller solids from 1 to 20 µm. The media will consist of anthracite, sand, and gravel, providing a gradient from coarse to fine which creates a media flow pattern necessary to achieve a very low silt density index. [9]

An antiscalant (T-131) will help us avoid fouling of UF and RO membranes by controlling carbonate scaling, magnesium hydroxide scaling, sulfate scaling, and calcium fluoride scaling. Organophosphates tend to be the most stable antiscalant, as they are not subject to hydrolysis or precipitation like sodium hexametaphosphate or polyacrylates. Alternatives to antiscalants that were investigated were water softening and acidification. Both are not economically favorable compared to antiscalants due to additional post treatment measures required when using these methods. Ultrafiltration (F-140), at 0.01–0.02 µm, will remove much of the remaining biological or particulate matter. This pore size also aids in disinfection, as it excludes viruses. These measures will result in a Silt Density index of less than 2.5. [9]

Conventional pretreatment methods using chemical coagulants such as ferric chloride in concert with Dissolved Air Flotation or Clarifier units were also considered. The equipment and media are long lasting and require low maintenance, but the chemical usage and disposal costs would be higher. UF membranes will need to be replaced every 5–10 years, so they require a moderate running cost. However, this extensive pretreatment process will help reduce RO operating costs and increase process efficiency downstream. [9] The selected pretreatment method will decrease our environmental footprint and extend the lifespan of our membranes.

===200 - Reverse Osmosis===

====Seawater Reverse Osmosis Technology====
The desalination method for this plant will be through reverse osmosis (RO). This method was chosen for a number of reasons. Firstly, new desalination plants appearing in the United States are increasingly run using reverse osmosis technology. The most notable example is the Carlsbad plant that recently opened up near San Diego which produces up to 50 million gallons per day of fresh water. Furthermore, a thermodynamic analysis was done on different desalination methods including multi-effect distillation (MED) and multistage flash evaporation (MSF). [10] The analysis found that reverse osmosis has the lowest theoretical energy consumption per unit of fresh water obtained. Due to this, building a reverse osmosis plant likely also has the most security moving forward.

Various membrane technology was investigated for use in this process. Thin film composite polyamide membranes are currently the industry gold standard. These have advantages over asymmetrical cellulose acetate membranes due to their higher permeate fluxes and higher salt rejection. Spiral wound membranes are the current state of the art module and are preferable to hollow fiber and plate and frame modules due to their low fouling which can be attributed to the parallel flow of the feed as opposed to the normal flow regime found in the other modules.

The Dow SW30XHR-440i spiral-wound membrane was chosen because each has the capacity for 6,600 gallons per day of permeate (the maximum available from Dow) and the highest overall dissolved solids rejection fraction at 99.82%. Additionally it is the membrane of choice for plants of a similar scale, such as the plant at Carlsbad, which verifies its practical usefulness for such large-scale operations. Based on this choice, it was determined that a 2-stage, 6 element per stage, single pass process would be necessary to achieve the desired flow rate and recovery for a single unit of our operation. A simplified RO system schematic is shown in Figure 1.
[IMAGE]
Using equations that were presented by Dow Chemical for designing RO plants, it was found that it was possible to produce 10 MGD of fresh water at a recovery of roughly 50% using 2280 membrane elements. These elements would be arranged in a series of 6 elements per pressure vessel for a total of 380 pressure vessels. The pressure vessels would be arranged in a two stage process with 220 pressure vessels in parallel in the first stage and 160 in the second stage. Detailed composition of pass streams from the reverse osmosis process can be found in Appendix 7.

====Energy Recovery====
The energy cost component of seawater RO can be up 70% of the total cost, so reducing the amount of energy consumed by the process was essential to minimizing not only cost, but also environmental impact. Energy use reduction is traditionally achieved through energy recovery devices (ERDs), such as centrifugal devices or isobaric, “pressure-equalizing,” devices. [11] In all cases, energy from the brine stream is transferred directly a portion of the membrane feed stream, reducing pumping requirements. The PFD and stream table detail how the feed is split, with a portion leading to an ERD before entering a booster pump and rejoining the stream from the high pressure (HP) pump. This significantly reduces the size and energy requirements of the HP pump. [12] Systems utilizing this technology can realize up to 60% energy reduction compared to those without it. [11]

Centrifugal ERDs incur lower capital costs, but have limited capacity and efficiency, typically running at a maximum of 82% efficiency. This is because they must transfer hydraulic energy from the brine stream into mechanical energy and then back into hydraulic energy. [12] Isobaric ERDs are the most efficient ERDs, operating at a maximum net transfer efficiency of up to 97%. Isobaric ERDs can handle increased capacity by being run in parallel, similar to the RO membranes. The PX Pressure Exchanger from Energy Recovery, Inc., requires minimal controls, can operate without periodic maintenance, and use ceramic rotors which do not corrode with seawater. [11] For that reason, it was selected for our process.

The PX Pressure Exchanger can operate at 96% efficiency for our process, and will require 24 units to handle our capacity. 6900 gpm (49.5%) of the feed stream will be redirected towards the PX Array, where it will be acted upon by the concentrated brine stream before flowing to the booster pump (P-213). The rest of the stream will be served by the HP pump (P-211). Through this technology, our process utilizes 8.9 kWh/kgal in the RO section, compared to 17.4 kWh/kgal without, almost 50% in energy savings. Pumping requirements are summarized in Appendix 8. A diagram portraying the simulation of this process is in Appendix 9.

===300 - Posttreatment===
After the reverse osmosis process, water will go through post-treatment by adding minerals to prevent corrosion of the distribution pipelines and resemble existing potable water supplies. By adjusting the hardness, alkalinity, and pH of the permeate, the aesthetic water quality will be assured and the distribution pipeline will be protected from corrosion. [13] The post-treatment will include the addition of sodium bicarbonate (T-311) and calcium chloride (T-312) for remineralization, sodium hydroxide (T-321) for pH adjustment, and sodium hypochlorite (T-331) for disinfection. [14]

Lastly, the product will be held in a holding tank (T-350) before being blended with municipal stores. This will allow for proper quality analysis of TDS, conductivity, and pH. Afterwards, the product water will blend with existing supplies so that the municipality may maintain consistent water quality for all consumers. Existing water treatment plants will ensure the water is suitable for consumption. The blended water can then be delivered throughout the region from there.

===400 - Brine Treatment===
There are several possible alternatives for brine treatment in large coastal seawater desalination plants. Possibilities include the use of large evaporation ponds, injection of brine into confined aquifers, and discharge into existing bodies of water. The first two options are largely not viable due to high land costs for evaporation ponds and the requirement of comprehensive land surveys for aquifers. Discharging to the ocean, however, is fairly commonly used as it is a reasonably practical option. [13]

Some smaller-scale facilities have been able to mix their effluent streams with cooling water effluent from nearby industrial plants or additional seawater as a dilution method to reach the necessary 40 ppt range of dissolved salts. [15] However, this requires either a conveniently located cooling water source, which our plant cannot assume, or prohibitively high costs to pump in enough seawater to dilute our effluent. Another option, and one that will be used at Camp Pendleton, is an engineered diffuser system on the brine discharge outfall. An engineered diffuser system consists of a long pipeline that will release smaller amounts of the brine over the course of its length and promote mixing to achieve dilution requirements. The Camp Pendleton desalination plant’s plans for this system are shown in Appendix 10 as an example. [13]

===500 - Solids Treatment===
Solids separated during the pretreatment process through the drum screen, multimedia filter, and UF membrane will be hauled off-site to a suitable landfill. Since no chemical coagulant, such as ferric chloride, is used in the pretreatment process, the spent backwash water can also be conveyed straight to the brine disposal pipeline and discharged to the ocean because the suspended solids contained will be entirely of marine origin.

=Economic Evaluation=

==Equipment Sizing/Pricing==

===Pretreatment===
Assuming that multimedia filters can support 20 gpm/sq. ft. area, [16] our process will require 4 multimedia filters, each with 200 sq. ft. of area and priced at $34000. Ultrafiltration modules can operate at 30 gpm, [17] necessitating 467 UF modules, each priced at $500.

===RO System===
The reverse osmosis system was designed in order to comply with the optimal operating conditions for the aforementioned FilmTec membranes and to achieve the necessary dissolved solids concentration and permeate flow rate for a 10 MGD-scale desalination plant. This resulted in 2280 RO elements in 380 pressure vessels. RO elements are cylinders of length 40.5 inches and diameter 7.9 inches. [18] A range of prices was found for bulk purchases of the required membrane, which could be conservatively estimated at 700 USD per element. The replacement percentage per year for Dow’s membranes filtering this level of SDI is 13%, which was added to the total capital cost of the system. Pressure vessel capital cost was estimated using the Aspen Economic Analyzer, and were found to cost $6700 each. This equipment capital cost was found to be 4.14 million USD. Additionally, there were significant costs associated with construction and auxiliary RO feed equipment was estimated by scaling the 50 MGD Camp Pendleton budget allocation [13] according to the following equation:

<math>C_2=C_1(S_2/S_1)^n</math>

where Ci refers to equipment and construction cost and Si refers to plant capacity. The value for ‘n’ was set as 0.7 based on guidelines from the Chemical Engineering Design textbook. [23] This extra capital cost was estimated at 56.3 million USD.

===Feed Intake===
Tunnel materials for the feed intake was calculated to cost $32.1 million, while construction costs were estimated at $48.7 million. The feedwater piping, intake well system, and pump station were estimated to have a total capital cost of $55.4 million. Further details on capital cost can be found in Appendix 11.

===Concentrate Return and Dilution Pipelines===
Concentrated brine disposal was also modeled after Camp Pendleton. Although their scale of brine disposal is much larger than that of this process, capital cost estimates and sizing were not lowered due to the necessity to dig to the same depth and the use of piping with a similar diameter to return brine concentrate. The brine discharge system was estimated to cost $50.2 million, while the brine discharge pipeline was estimated to cost $9.2 million.

===Pumps===
(Requirements summarized in Appendix 8)

====Pretreatment Pumps====
Ultrafiltration will require a pump in order to filter our process efficiently. Using guidelines from Dow Chemical, [17] the optimal operating pressure for each ultrafiltration module is 30 psi, and each filter can operate at 30 gpm. As a result, this process will require 467 UF modules. A pump pressurizing 13889 gpm to 30 psi will require 202.8 kW. Antiscalant will need to be supplied to the process at 1.39 gpm in order to properly prevent fouling in pretreatment membranes. The power required for this would be 3.88*10-5 kW.

====RO Pumps====
Assuming 50% recovery during the RO process, the brine flow rate will be equal to the permeate flow rate, 6945 gpm. The PX Pressure Exchanger requires lubrication for its hydrodynamic bearing, which will be supplied by the high pressure brine stream, leading to the slight loss in efficiency. As a result, 6877 gpm (49.5%) of the inlet stream can be redirected to the PX Array before reaching a booster pump, with the remaining 7012 gpm being served by the high-pressure pump. The booster pump will only need to supply 53 psi of additional pressure compared to the 629 psi required from the high pressure pump. In order to meet minimum discharge pressure required for proper PX operation, it is necessary for the feed streams to be pressurized to 30 psi so that the low pressure brine stream will exit at 15.9 psi.

====Post-Treatment Pumps====
Post treatment chemicals (sodium hypochlorite, sodium bicarbonate, calcium chloride, sodium hydroxide) are added to the permeate in order to remineralize and pH adjust our water. The pumps used to deliver these chemicals must simply overcome frictional losses in the pipe in order to keep the chemicals moving. All pumps were modeled at 80% efficiency.

===Chemical Storage Tanks===
Chemicals that are added to the water need to be stored beforehand. Chemical holding tanks were sized according to a day’s worth of chemicals. The holding tank for sodium bicarbonate is quite large and this is cause for concern. This issue could be corrected by introducing the solid chemical directly to the product stream rather than creating a solution, storing that solution and then mixing solutions. The cost of the holding tanks can be found in Appendix 12.

==Product Selling Price==
The San Diego County Water Authority agreed to pay Carlsbad (a plant of comparable size and location) $2014-2267 per acre foot of water depending on how much is purchased. [22] Based on this number we estimate that our yearly plant revenue will be roughly $25.4 million.

==Operating Costs==
The San Diego County Water Authority agreed to pay Carlsbad (a plant of comparable size and location) $2014-2267 per acre foot of water depending on how much is purchased. [22] Based on this number we estimate that our yearly plant revenue will be roughly $25.4 million.

==Capital Costs==
The overall capital costs of our plant are summarized below.
{| class="wikitable"
|-
! Project Sector
! Capital Cost (MM$)
|-
| Feedwater Intake and Concentrate Return
| 195.6
|-
| Desalination Facility
| 82.7
|-
| Product Water Conveyance
| 90.4
|-
| '''Subtotal'''
| '''368.7'''
|-
| Contingency
| 130.2
|-
| Working Capital
| 18.4
|-
| Implementation (Legal, Engineering, Administration)
| 84.3
|-
| '''Total'''
| '''601.7'''
|}

==NPV Analysis==
The economic viability of our desalination process was analyzed using a 25 year project lifetime. The cost of capital was set at 12% and the tax rate was set at 35%. A ten-year MACRS depreciation model was used.

The project was found overall to not be economically feasible on a purely commercial level. As revenues would only produce approximately $25.4 million per year the net present value after a project lifetime of 25 years remains extremely low at -$402.5 million. The full economic analysis can be found in Appendix 15.

==Optimization==
The primary opportunity for optimization within our process occurs in the management of the reverse osmosis process, with respect to the number of stages and the number of elements per stage used for our filtration. As a starting point we chose to use two stages and six elements per stage, as this is in-line with Dow Chemical Company’s product recommendations for the SW30XHR-440i RO membrane. Additionally, this is the typical configuration for large-scale RO plants using this particular Dow membrane such as the Carlsbad Desalination Plant. [24]

Using the Dow ROSA software, configurations were evaluated for one, two, and three sequential stages, ranging from four to eight elements per stage. Each of these process conditions was evaluated with respect to the capital costs of equipment as well as the yearly utility cost that would be required. The results of this optimization are summarized in Appendix 16, Table 16.1 and 16.2, with our starting condition and minimum highlighted in each.

This optimization was conducted using a desired recovery of 50%. The number of vessels total and number of vessels per stage were based on the maximum permeate flow for the RO membrane and sizing equations obtained from the Dow RO design guide, respectively. [18]

These data show a minimal variation between different configurations of our system, particularly compared with more dominant capital and operations cost throughout the remainder of our process. However, this process does find a minimum utility cost for the 1-stage, 8 element per stage configuration, at $80,000 per year less than our current setup. Additionally, the condition of a 2-stage, 4 element configuration has a lower utility cost--$60,000 per year less--with an equivalent capital cost. However, it was also observed in either alternative case that the initial element recovery percentage was 10-11%, rather than the 8% achieved in the original 2 stage, 6 element design. A lower recovery percentage indicates lower fouling rates and thus less frequent replacement of membranes, though this precise economic effect could not be quantified.

Based on the manufacturer and industry standard for reverse osmosis configuration, along with the minimal differences in total costs for alternatives and fouling concerns, the project chose to continue with the 2-stage, 6 element per stage configuration.

==Sensitivity Analysis==
Our process was found to be particularly sensitive to three main areas within capital costs, operating, costs, and revenue, which could have significant influence over the final economic analysis if the estimations are off by a significant margin or if the data used for these estimations changes significantly in the coming years.

===Capital Costs===
The construction of the project’s seawater intake/disposal pipeline is priced at approximately $200 million, making up about a third of total capital costs. It may be possible, rather than construct an entirely new water feed and disposal system, to draw used seawater from a nearby large-scale consumer and mitigate these construction costs greatly. For example, it is fairly common for desalination plants to use industrial cooling water effluent for their plants, whether it be as a feed or as a dilution measure, in order to significantly drive down capital costs.

===Operating Costs and Revenue===
The operating costs, while a small portion of total project expenses, consume more than a quarter of the plant revenue at $6.2 million per year. This is largely governed by the energy costs, which have been estimated at $0.08 per kilowatt-hour. A decrease in this cost would substantially decrease yearly operating cost and allow for greater profit.

Similarly, revenue is governed by the cost of water being paid to the Carlsbad Desalination Plant, at $2260 per acre-foot. [22] This price is expected to rise as the water shortage becomes more urgent and the population of California increases. A significant increase in this price could greatly help the desalination project to improve economic viability.

=Conclusion=
Overall, the project designed a 10 million gallon per day seawater desalination plant on the Southern California Bight to fill the need of water shortage. We chose reverse osmosis as a method for desalination. The plant would pressurize seawater from subterranean wells off the coast of the bight. The water is then sent to the pre-treatment system before entering the reverse osmosis system. We decided on a 2 stage, 6 element per stage process using Dow SW30XHR-440i membrane and operating at 50% recovery with a feed of 20 million gallons per day. The system achieves a final dissolved solid concentration of 109 mg/L, which well satisfies the California drinking water recommendation of 500 mg/L of dissolved solids concentration. The fresh water is then sent to post-treatment and merge with existing supplies. Waste concentrate from from the process is sent back into the bay through a long engineered diffuser pipe that can dilute the brine to necessary levels.

Furthermore, we did optimization for our process. The primary opportunity for optimization within our process occurs in the management of the reverse osmosis process, with respect to the number of stages and the number of elements per stage used for our filtration. The result shows a minimal variation between different configurations of our system, particularly compared with more dominant capital and operations cost throughout the remainder of our process. Based on the minimal differences, along with the manufacture and industry standard for reverse osmosis configuration, the project chose to continue with the 2-stage, 6 element per stage configuration.

However, based on the results from the economic analysis, we concluded from the final -$402.5 million net present value, that such an energy intensive process to produce a product that is generally taken for granted is extremely costly. As a commercial venture this project is not viable. On the other hand, with increased demand and decreased supply the water price may rise and become a motivation for the government to invest for the desalination in the future. The project would likely need to taken on by the city of San Diego rather than a private entity. For future development and viability of this project, we recommend to draw used seawater from a nearby large-scale process instead of constructing an entirely new water feed and disposal system. This can mitigate the construction costs greatly.

=References=
# Groundwater Information Sheet. State Water Resources Control Board website. http://www.waterboards.ca.gov/gama/docs/coc_salinity.pdf Published March 2010. Accessed January 12, 2016.
# Maximum Contaminant Levels and Regulatory Dates for Drinking Water. State Water Resources Control Board website. http://www.waterboards.ca.gov/drinking_water/certlic/drinkingwater/documents/dwdocuments/MCLsEPAvsDWP-2014-07-01.pdf Updated July 1st, 2015. Accessed January 12, 2016.
# Weiser M. State’s population growth expected to outstrip water conservation in coming years. sacbee. http://www.sacbee.com/news/local/environment/article10311635.html. Accessed January 29, 2016.
# General Facts About California’s Water. Association of California Water Agencies website. http://www.acwa.com/issues/general_water_facts/index.asp#water_supply. Accessed March 3, 2016.
# Composition of Seawater. Lenntech website. http://www.lenntech.com/composition-seawater.htm Published January, 2005. Accessed January 12, 2016.
# Groundwater Information Sheet. State Water Resources Control Board website. http://www.waterboards.ca.gov/gama/docs/coc_salinity.pdf Published March 2010. Accessed January 12, 2016.
# Maximum Contaminant Levels and Regulatory Dates for Drinking Water. State Water Resources Control Board website. http://www.waterboards.ca.gov/drinking_water/certlic/drinkingwater/documents/dwdocuments/MCLsEPAvsDWP-2014-07-01.pdf Updated July 1st, 2015. Accessed January 12, 2016.
# MWSD Desalination Feasibility Study - ExecSummary_desal-study_Dec09.pdf. http://www.sdcwa.org/sites/default/files/files/water-management/desal/ExecSummary_desal-study_Dec09.pdf. Accessed January 29, 2016.
# Prihasto N, Lui Q, Kim S. Pre-treatment strategies for seawater desalination by reverse osmosis system. 2009; 249(1): 308-316.
# Semiat R. Energy Issues in Desalination Processes. American Chemical Society. http://pubs.acs.org/doi/pdf/10.1021/es801330u. Accessed January 29, 2016
# Stover RL. Seawater reverse osmosis with isobaric energy recovery devices. Desalination. 2007;203(1–3):168-175. doi:10.1016/j.desal.2006.03.528.
# Schneider B. Selection, operation and control of a work exchanger energy recovery system based on the Singapore project. Desalination. 2005;184(1–3):197-210. doi:10.1016/j.desal.2005.04.031.
# Camp Pendleton Seawater Desalination Project Feasibility Report - Final Report. http://www.sdcwa.org/sites/default/files/files/water-management/desal/vol1_report_desal-study_Dec09.pdf. Accessed January 29, 2016.
# Sodium hypochlorite as a disinfectant. http://www.lenntech.com/processes/disinfection/chemical/disinfectants-sodium-hypochlorite.htm. Accessed January 29, 2016.
# Seawater Concentrate Management https://www.watereuse.org/wp-content/uploads/2015/10/Seawater_Concentrate_WP.pdf. Accessed January 29, 2016.
# H2K Technologies, Inc. - Multi Media Filters. http://www.h2ktech.com/multi-media-filters/media-filters-sand-filters.html. Accessed February 27, 2016.
# DOW Ultrafiltration Modules Product Data Sheet. http://msdssearch.dow.com/PublishedLiteratureDOWCOM/dh_0945/0901b803809456d7.pdf?filepath=liquidseps/pdfs/noreg/795-50225.pdf&fromPage=GetDoc. Accessed February 27, 2016.
# DOW FILMTEC Membranes - Steps to Design a Membrane System Using ROSA http://dowwater.custhelp.com/app/answers/detail/a_id/2209 Accessed February 27, 2016.
# DOW FILMTEC™ SW30XHR–440i Element http://msdssearch.dow.com/PublishedLiteratureDOWCOM/dh_0945/0901b80380945d8d.pdf?filepath=liquidseps/pdfs/noreg/609-03002.pdf&fromPage=GetDoc Accessed February 27, 2016.
# ICIS Indicative Chemical Prices A-Z http://www.icis.com/chemicals/channel-info-chemicals-a-z/ Accessed February 27, 2016.
# Towler GP, Sinnot R. Chemical Engineering Design: Principles, Practice and Economics of Plant and Process Design. Elsevier.
# Rogers, Paul Nation’s Largest Desalination Plant Goes Up Near San Diego; Future of the California Coast? San Jose Mercury News http://www.mercurynews.com/science/ci_25859513/nations-largest-ocean-desalination-plant-goes-up-near Accessed February 27, 2016.
# San Diego Electricity Rates. Electricity Local. http://www.electricitylocal.com/states/california/san-diego/ Accessed February 27, 2016.
# Dow Reverse Osmosis Membranes Treat Seawater and Offers Drinking Water to Southern California. http://msdssearch.dow.com/PublishedLiteratureDOWCOM/dh_0940/0901b80380940a81.pdf Accessed March 4, 2016.

=Appendices=

==Appendix 1 - Plant Location Map==
[[File:SoCalBight.png|center|700px|thumb|alt=|]]

==Appendix 2 - Posttreatment Water Quality Goals==

==Appendix 3 - Dissolved Ion Concentration of Seawater Inlet==

==Appendix 4 - Process Flow Diagram==

==Appendix 5 - Final Simulation Mass Balance and Stream Pressure==

==Appendix 6 - Stream Tables==

==Appendix 7 - Composition of Pass Streams from RO Process==

[[File:7.1.PNG|center|600px|thumb|alt=|Table 7.1 Composition of pass streams from Reverse osmosis.]]

==Appendix 8 - Pumping Requirements==

[[File:8.1.PNG|center|600px|thumb|alt=|Table 8.1 Pump Requirements.]]

==Appendix 9 - ERD Simulation==

[[File:9.PNG|center|600px|thumb|alt=|ERD Simulation.]]

==Appendix 10 - Example Diffuser System from Camp Pendleton Plant==

[[File:10.PNG|center|600px|thumb|alt=|Example Diffuser System from Camp Pendleton plant.]]

==Appendix 11 - Capital Cost==

[[File:11.1.PNG|center|600px|thumb|alt=|Table 11.1 Capital Cost breakdown.]]

==Appendix 12 - Holding Tank Costs==

[[File:12.1.PNG|center|600px|thumb|alt=|Table 12.1 Holding Tank Costs.]]

==Appendix 13 - Utility Calculations==

[[File:13.1.PNG|center|600px|thumb|alt=|Table 13.1 Utility calculations.]]

==Appendix 14 - Yearly Cost of Chemical Additions==

[[File:14.1.PNG|center|600px|thumb|alt=|Table 14.1 Chemical Addition Costs.]]

==Appendix 15 - Economic Analysis==

[[File:15.PNG|center|600px|thumb|alt=|Economic Analysis.]]

==Appendix 16 - Optimization==

[[File:16.1.PNG|center|600px|thumb|alt=|Table 16.1 Optimization of yearly utility for number of stages and elements per stage.]]

[[File:16.2.PNG|center|600px|thumb|alt=|Table 16.2: Optimization of yearly utility for number of elements per stage.]]

File:SoCalBight.png

2016-03-10T22:51:50Z

Taunins:

Desalination - Team D

2016-03-10T22:50:48Z

Taunins: /* References */

Team D: Final Report

Authors: Thomas Aunins, Robert Cignoni, John Dombrowski, Iris Zhao

Instructors: Fengqi You, David Wegerer

March 11, 2016

=Executive Summary=
Water shortage is one of the foremost and most urgent issues facing the world today, as developing and developed countries alike have struggled with depletion of natural reservoirs and severe droughts. This issue has resulted in the recent rapid development of desalination technology and the construction of desalination facilities. Since the turn of the millennium, the United State alone has increased its desalination capacity from 600 million gallons per day to 1650 million gallons per day, with much more currently being planned. California, in particular, is the focus of a large amount of the United States’ desalination efforts, as its current drought has exposed a discrepancy in water supply contingency and demonstrated a need for non-natural freshwater sources.

This project aims to design a 10 million gallon per day seawater desalination plant on the Southern California Bight--near San Diego--to fill this need. A reverse osmosis system was chosen based on the fact that it is the most rapidly developing and innovating technology in the desalination field, as well as the fact that it has a lower theoretical energy production per gallon of water than the common multi-stage flash purification methods. Our plant will pressurize seawater from subterranean wells off the coast of the bight and send it to our pre-treatment system. There, it will go through a drum screen, multimedia filter, antiscalant addition, and finally ultrafiltration to remove varying size of suspended solids and contaminants, before entering our reverse osmosis system.

The RO system itself is a 2-stage, 6 element per stage process, using Dow SW30XHR-440i membranes and operating at 50% recovery with a feed of 20 million gallons per day. This allows the process to achieve a final dissolved solids concentration of 109 mg/L, far below the California drinking water recommendation of 500 mg/L. This freshwater can then be sent to post-treatment and merged with water of the San Diego County Water Authority’s distribution system. Waste concentrate from the process is sent back into the bay through a long diffuser pipe system that will dilute the brine to necessary levels to avoid environmental damage.

An economic analysis of the process found total capital costs to be slightly more than $600 million, with yearly revenues and operating costs at $25.4 million and $6.2 million, respectively. On a 25 year time scale, this results in a final net present value for the project at -$402.5 million, causing us to conclude that as a commercial venture the project is not viable. We do note, however, that increased demand and decreased supply may cause water prices to rise and create a motivation for government investment in the project in the future. For this reason, we believe that it is possible for this project to become an economically feasible and practically necessary venture in coming years.

__TOC__

=Introduction=

==Background==
Due to drought and the depletion of groundwater, desalination is becoming an increasingly viable source for drinking water in the San Diego, California area. A map of the plant location can be found in Appendix 1. Reverse osmosis appears to be the best route for desalination due to its lower energy costs and high volume of current research efforts. It is also capable of purifying California seawater to the levels recommended by the World Health Organization (WHO) and the state government. The process will separate solids from seawater before subjecting it to a two-stage reverse osmosis unit. Concentrated brine waste will be diluted with seawater before going back into the environment. Permeate streams will be remineralized and disinfected before leaving the facility.

==Problem Statement==
The objective of this process will be to produce fresh drinking-quality water according to standards recommended by the Water Research Foundation. This sets an upper limit for the total dissolved solid in our product at 1000 mg/L, with a non-mandatory guideline of approximately 500 mg/L as an appropriate target. This can be found from in Appendix 2. This encompasses the secondary maximum contaminant levels (MCL) set forth by the State Resources Water Control Board [1]. Additionally, there are guidelines set forth for primary MCLs, which encompasses more dangerous and/or toxic substances in the water. These are a smaller concern for our project because sea water does not naturally contain amounts of these contaminants above the MCLs [2].

=Technical Approach=

==Site Location and Capacity==
This project is planned for construction on the Southern California Bight, located just north of San Diego and nearby the San Diego County Water Authority’s (SDCWA) distribution system. This area is of particular interest for seawater desalination projects due to the projected discrepancy between water supply and demand in upcoming years. Statewide in California, the demand for water is expected to increase by 1.2 billion cubic meters per year by 2030, as projections show that population increase of 16% dramatically outstripping water conservation goals. [3] Southern California in particular has a great need for more freshwater sources, as the lower two-thirds of the state require 80% of California’s water, while the upper third of the state supplies 75% of it. [4]

Per the aforementioned water scarcity, California’s water demand has become a large part of this growth. There are several large scale desalination plants planned for the area, including large-scale projects at Carlsbad and Camp Pendleton. Each of these plants will be constructed to produce 50 MGD of freshwater to the San Diego area, with the latter expected to expand to 150 MGD within ten years of completion. The construction of these plants, along with other smaller scale plants in the area, indicates an urgent need for desalination capacity. Our plant is being designed to produce 10 million gallons per day (MGD) of fresh water for the San Diego area.

==Feed Stream==
Seawater will be fed from a submerged pipeline off the coast of the Southern California Bight. The subterranean feed inlet will allow for an initial pseudo-filter as the water is pulled through the porous ocean floor, preventing large debris and aquatic life from being pulled into the process intake. Worldwide, seawater salinity averages approximately 35,000 mg/L of total dissolved solids, with the primary salts present being chloride and sodium at 19,000 mg/L and 10,500 mg/L, respectively. [5] It should be noted that while data on average local seawater composition for Southern California was not available, this area is known to typically have lower total dissolved solids concentrations than average seawater, placing our calculations on the conservative side. Further breakdown of the dissolved ion concentration of our seawater input can be found in Appendix 3.

==Product Stream==
The objective of this process will be to produce fresh drinking-quality water according to standards set by the California state government and the World Health Organization. Regulations set an upper limit for the total dissolved solid in our product at 1000 mg/L, with a non-mandatory guideline of approximately 500 mg/L as an appropriate target. This encompasses the secondary maximum contaminant levels (MCL) set forth by the State Resources Water Control Board. [6] Additionally, there are guidelines set forth for primary MCLs, which encompasses more dangerous and/or toxic substances in the water. These are a smaller concern for our project because sea water does not naturally contain amounts of these contaminants above the MCLs. [7]

Further goals for the permeate composition and quality following post-treatment were taken from recommendations given by the Water Research Foundation on seawater reverse osmosis and from averages taken from San Diego water treatment plants. These can be found in Appendix 2.

=Flowsheet=

==Process Flow Diagram, Major Technology, and Alternatives==
The process flow diagram (PFD) can be found in Appendix 4. Each stream and piece of equipment is labeled according to which section of the process it pertains to. The final simulation mass balance and stream pressure can be found in Appendix 5. Stream tables can be found in Appendix 6.

===100 - Pretreatment===
The feed flow rate set to the system is 20 MGD. The seawater intake system proposed for the site is a deep infiltration gallery (DIG) intake system due to the permeable hydrogeology offshore of the proposed location. DIG would be comprised of a series of angled or wells drilled radially and therefore would not supply a large amount of feed water due to low permeability. Therefore, the radial collector wells would be drilled at a downward angle from the barge to the dual-use tunnel, below the loose sand layer. The collector wells act as an infiltration gallery, in that the underground seawater infiltrates into the wells and gravity flows into the annular space of the tunnel, which conveys the feedwater onshore. [8]

The sea plays host to contaminants that extend well beyond salt. Poor feed quality can lead to short RO membrane lifetime, short periods of operation, and high maintenance costs. Contaminants include suspended solids, dissolved organic contaminants, and sparingly soluble salts. [9]

First off, a drum screen (F-110) will catch any large solids greater than 0.5 cm that could literally throw a wrench in our operations. A multimedia filter (F-120) captures smaller solids from 1 to 20 µm. The media will consist of anthracite, sand, and gravel, providing a gradient from coarse to fine which creates a media flow pattern necessary to achieve a very low silt density index. [9]

An antiscalant (T-131) will help us avoid fouling of UF and RO membranes by controlling carbonate scaling, magnesium hydroxide scaling, sulfate scaling, and calcium fluoride scaling. Organophosphates tend to be the most stable antiscalant, as they are not subject to hydrolysis or precipitation like sodium hexametaphosphate or polyacrylates. Alternatives to antiscalants that were investigated were water softening and acidification. Both are not economically favorable compared to antiscalants due to additional post treatment measures required when using these methods. Ultrafiltration (F-140), at 0.01–0.02 µm, will remove much of the remaining biological or particulate matter. This pore size also aids in disinfection, as it excludes viruses. These measures will result in a Silt Density index of less than 2.5. [9]

Conventional pretreatment methods using chemical coagulants such as ferric chloride in concert with Dissolved Air Flotation or Clarifier units were also considered. The equipment and media are long lasting and require low maintenance, but the chemical usage and disposal costs would be higher. UF membranes will need to be replaced every 5–10 years, so they require a moderate running cost. However, this extensive pretreatment process will help reduce RO operating costs and increase process efficiency downstream. [9] The selected pretreatment method will decrease our environmental footprint and extend the lifespan of our membranes.

===200 - Reverse Osmosis===

====Seawater Reverse Osmosis Technology====
The desalination method for this plant will be through reverse osmosis (RO). This method was chosen for a number of reasons. Firstly, new desalination plants appearing in the United States are increasingly run using reverse osmosis technology. The most notable example is the Carlsbad plant that recently opened up near San Diego which produces up to 50 million gallons per day of fresh water. Furthermore, a thermodynamic analysis was done on different desalination methods including multi-effect distillation (MED) and multistage flash evaporation (MSF). [10] The analysis found that reverse osmosis has the lowest theoretical energy consumption per unit of fresh water obtained. Due to this, building a reverse osmosis plant likely also has the most security moving forward.

Various membrane technology was investigated for use in this process. Thin film composite polyamide membranes are currently the industry gold standard. These have advantages over asymmetrical cellulose acetate membranes due to their higher permeate fluxes and higher salt rejection. Spiral wound membranes are the current state of the art module and are preferable to hollow fiber and plate and frame modules due to their low fouling which can be attributed to the parallel flow of the feed as opposed to the normal flow regime found in the other modules.

The Dow SW30XHR-440i spiral-wound membrane was chosen because each has the capacity for 6,600 gallons per day of permeate (the maximum available from Dow) and the highest overall dissolved solids rejection fraction at 99.82%. Additionally it is the membrane of choice for plants of a similar scale, such as the plant at Carlsbad, which verifies its practical usefulness for such large-scale operations. Based on this choice, it was determined that a 2-stage, 6 element per stage, single pass process would be necessary to achieve the desired flow rate and recovery for a single unit of our operation. A simplified RO system schematic is shown in Figure 1.
[IMAGE]
Using equations that were presented by Dow Chemical for designing RO plants, it was found that it was possible to produce 10 MGD of fresh water at a recovery of roughly 50% using 2280 membrane elements. These elements would be arranged in a series of 6 elements per pressure vessel for a total of 380 pressure vessels. The pressure vessels would be arranged in a two stage process with 220 pressure vessels in parallel in the first stage and 160 in the second stage. Detailed composition of pass streams from the reverse osmosis process can be found in Appendix 7.

====Energy Recovery====
The energy cost component of seawater RO can be up 70% of the total cost, so reducing the amount of energy consumed by the process was essential to minimizing not only cost, but also environmental impact. Energy use reduction is traditionally achieved through energy recovery devices (ERDs), such as centrifugal devices or isobaric, “pressure-equalizing,” devices. [11] In all cases, energy from the brine stream is transferred directly a portion of the membrane feed stream, reducing pumping requirements. The PFD and stream table detail how the feed is split, with a portion leading to an ERD before entering a booster pump and rejoining the stream from the high pressure (HP) pump. This significantly reduces the size and energy requirements of the HP pump. [12] Systems utilizing this technology can realize up to 60% energy reduction compared to those without it. [11]

Centrifugal ERDs incur lower capital costs, but have limited capacity and efficiency, typically running at a maximum of 82% efficiency. This is because they must transfer hydraulic energy from the brine stream into mechanical energy and then back into hydraulic energy. [12] Isobaric ERDs are the most efficient ERDs, operating at a maximum net transfer efficiency of up to 97%. Isobaric ERDs can handle increased capacity by being run in parallel, similar to the RO membranes. The PX Pressure Exchanger from Energy Recovery, Inc., requires minimal controls, can operate without periodic maintenance, and use ceramic rotors which do not corrode with seawater. [11] For that reason, it was selected for our process.

The PX Pressure Exchanger can operate at 96% efficiency for our process, and will require 24 units to handle our capacity. 6900 gpm (49.5%) of the feed stream will be redirected towards the PX Array, where it will be acted upon by the concentrated brine stream before flowing to the booster pump (P-213). The rest of the stream will be served by the HP pump (P-211). Through this technology, our process utilizes 8.9 kWh/kgal in the RO section, compared to 17.4 kWh/kgal without, almost 50% in energy savings. Pumping requirements are summarized in Appendix 8. A diagram portraying the simulation of this process is in Appendix 9.

===300 - Posttreatment===
After the reverse osmosis process, water will go through post-treatment by adding minerals to prevent corrosion of the distribution pipelines and resemble existing potable water supplies. By adjusting the hardness, alkalinity, and pH of the permeate, the aesthetic water quality will be assured and the distribution pipeline will be protected from corrosion. [13] The post-treatment will include the addition of sodium bicarbonate (T-311) and calcium chloride (T-312) for remineralization, sodium hydroxide (T-321) for pH adjustment, and sodium hypochlorite (T-331) for disinfection. [14]

Lastly, the product will be held in a holding tank (T-350) before being blended with municipal stores. This will allow for proper quality analysis of TDS, conductivity, and pH. Afterwards, the product water will blend with existing supplies so that the municipality may maintain consistent water quality for all consumers. Existing water treatment plants will ensure the water is suitable for consumption. The blended water can then be delivered throughout the region from there.

===400 - Brine Treatment===
There are several possible alternatives for brine treatment in large coastal seawater desalination plants. Possibilities include the use of large evaporation ponds, injection of brine into confined aquifers, and discharge into existing bodies of water. The first two options are largely not viable due to high land costs for evaporation ponds and the requirement of comprehensive land surveys for aquifers. Discharging to the ocean, however, is fairly commonly used as it is a reasonably practical option. [13]

Some smaller-scale facilities have been able to mix their effluent streams with cooling water effluent from nearby industrial plants or additional seawater as a dilution method to reach the necessary 40 ppt range of dissolved salts. [15] However, this requires either a conveniently located cooling water source, which our plant cannot assume, or prohibitively high costs to pump in enough seawater to dilute our effluent. Another option, and one that will be used at Camp Pendleton, is an engineered diffuser system on the brine discharge outfall. An engineered diffuser system consists of a long pipeline that will release smaller amounts of the brine over the course of its length and promote mixing to achieve dilution requirements. The Camp Pendleton desalination plant’s plans for this system are shown in Appendix 10 as an example. [13]

===500 - Solids Treatment===
Solids separated during the pretreatment process through the drum screen, multimedia filter, and UF membrane will be hauled off-site to a suitable landfill. Since no chemical coagulant, such as ferric chloride, is used in the pretreatment process, the spent backwash water can also be conveyed straight to the brine disposal pipeline and discharged to the ocean because the suspended solids contained will be entirely of marine origin.

=Economic Evaluation=

==Equipment Sizing/Pricing==

===Pretreatment===
Assuming that multimedia filters can support 20 gpm/sq. ft. area, [16] our process will require 4 multimedia filters, each with 200 sq. ft. of area and priced at $34000. Ultrafiltration modules can operate at 30 gpm, [17] necessitating 467 UF modules, each priced at $500.

===RO System===
The reverse osmosis system was designed in order to comply with the optimal operating conditions for the aforementioned FilmTec membranes and to achieve the necessary dissolved solids concentration and permeate flow rate for a 10 MGD-scale desalination plant. This resulted in 2280 RO elements in 380 pressure vessels. RO elements are cylinders of length 40.5 inches and diameter 7.9 inches. [18] A range of prices was found for bulk purchases of the required membrane, which could be conservatively estimated at 700 USD per element. The replacement percentage per year for Dow’s membranes filtering this level of SDI is 13%, which was added to the total capital cost of the system. Pressure vessel capital cost was estimated using the Aspen Economic Analyzer, and were found to cost $6700 each. This equipment capital cost was found to be 4.14 million USD. Additionally, there were significant costs associated with construction and auxiliary RO feed equipment was estimated by scaling the 50 MGD Camp Pendleton budget allocation [13] according to the following equation:

<math>C_2=C_1(S_2/S_1)^n</math>

where Ci refers to equipment and construction cost and Si refers to plant capacity. The value for ‘n’ was set as 0.7 based on guidelines from the Chemical Engineering Design textbook. [23] This extra capital cost was estimated at 56.3 million USD.

===Feed Intake===
Tunnel materials for the feed intake was calculated to cost $32.1 million, while construction costs were estimated at $48.7 million. The feedwater piping, intake well system, and pump station were estimated to have a total capital cost of $55.4 million. Further details on capital cost can be found in Appendix 11.

===Concentrate Return and Dilution Pipelines===
Concentrated brine disposal was also modeled after Camp Pendleton. Although their scale of brine disposal is much larger than that of this process, capital cost estimates and sizing were not lowered due to the necessity to dig to the same depth and the use of piping with a similar diameter to return brine concentrate. The brine discharge system was estimated to cost $50.2 million, while the brine discharge pipeline was estimated to cost $9.2 million.

===Pumps===
(Requirements summarized in Appendix 8)

====Pretreatment Pumps====
Ultrafiltration will require a pump in order to filter our process efficiently. Using guidelines from Dow Chemical, [17] the optimal operating pressure for each ultrafiltration module is 30 psi, and each filter can operate at 30 gpm. As a result, this process will require 467 UF modules. A pump pressurizing 13889 gpm to 30 psi will require 202.8 kW. Antiscalant will need to be supplied to the process at 1.39 gpm in order to properly prevent fouling in pretreatment membranes. The power required for this would be 3.88*10-5 kW.

====RO Pumps====
Assuming 50% recovery during the RO process, the brine flow rate will be equal to the permeate flow rate, 6945 gpm. The PX Pressure Exchanger requires lubrication for its hydrodynamic bearing, which will be supplied by the high pressure brine stream, leading to the slight loss in efficiency. As a result, 6877 gpm (49.5%) of the inlet stream can be redirected to the PX Array before reaching a booster pump, with the remaining 7012 gpm being served by the high-pressure pump. The booster pump will only need to supply 53 psi of additional pressure compared to the 629 psi required from the high pressure pump. In order to meet minimum discharge pressure required for proper PX operation, it is necessary for the feed streams to be pressurized to 30 psi so that the low pressure brine stream will exit at 15.9 psi.

====Post-Treatment Pumps====
Post treatment chemicals (sodium hypochlorite, sodium bicarbonate, calcium chloride, sodium hydroxide) are added to the permeate in order to remineralize and pH adjust our water. The pumps used to deliver these chemicals must simply overcome frictional losses in the pipe in order to keep the chemicals moving. All pumps were modeled at 80% efficiency.

===Chemical Storage Tanks===
Chemicals that are added to the water need to be stored beforehand. Chemical holding tanks were sized according to a day’s worth of chemicals. The holding tank for sodium bicarbonate is quite large and this is cause for concern. This issue could be corrected by introducing the solid chemical directly to the product stream rather than creating a solution, storing that solution and then mixing solutions. The cost of the holding tanks can be found in Appendix 12.

==Product Selling Price==
The San Diego County Water Authority agreed to pay Carlsbad (a plant of comparable size and location) $2014-2267 per acre foot of water depending on how much is purchased. [22] Based on this number we estimate that our yearly plant revenue will be roughly $25.4 million.

==Operating Costs==
The San Diego County Water Authority agreed to pay Carlsbad (a plant of comparable size and location) $2014-2267 per acre foot of water depending on how much is purchased. [22] Based on this number we estimate that our yearly plant revenue will be roughly $25.4 million.

==Capital Costs==
The overall capital costs of our plant are summarized below.
{| class="wikitable"
|-
! Project Sector
! Capital Cost (MM$)
|-
| Feedwater Intake and Concentrate Return
| 195.6
|-
| Desalination Facility
| 82.7
|-
| Product Water Conveyance
| 90.4
|-
| '''Subtotal'''
| '''368.7'''
|-
| Contingency
| 130.2
|-
| Working Capital
| 18.4
|-
| Implementation (Legal, Engineering, Administration)
| 84.3
|-
| '''Total'''
| '''601.7'''
|}

==NPV Analysis==
The economic viability of our desalination process was analyzed using a 25 year project lifetime. The cost of capital was set at 12% and the tax rate was set at 35%. A ten-year MACRS depreciation model was used.

The project was found overall to not be economically feasible on a purely commercial level. As revenues would only produce approximately $25.4 million per year the net present value after a project lifetime of 25 years remains extremely low at -$402.5 million. The full economic analysis can be found in Appendix 15.

==Optimization==
The primary opportunity for optimization within our process occurs in the management of the reverse osmosis process, with respect to the number of stages and the number of elements per stage used for our filtration. As a starting point we chose to use two stages and six elements per stage, as this is in-line with Dow Chemical Company’s product recommendations for the SW30XHR-440i RO membrane. Additionally, this is the typical configuration for large-scale RO plants using this particular Dow membrane such as the Carlsbad Desalination Plant. [24]

Using the Dow ROSA software, configurations were evaluated for one, two, and three sequential stages, ranging from four to eight elements per stage. Each of these process conditions was evaluated with respect to the capital costs of equipment as well as the yearly utility cost that would be required. The results of this optimization are summarized in Appendix 16, Table 16.1 and 16.2, with our starting condition and minimum highlighted in each.

This optimization was conducted using a desired recovery of 50%. The number of vessels total and number of vessels per stage were based on the maximum permeate flow for the RO membrane and sizing equations obtained from the Dow RO design guide, respectively. [18]

These data show a minimal variation between different configurations of our system, particularly compared with more dominant capital and operations cost throughout the remainder of our process. However, this process does find a minimum utility cost for the 1-stage, 8 element per stage configuration, at $80,000 per year less than our current setup. Additionally, the condition of a 2-stage, 4 element configuration has a lower utility cost--$60,000 per year less--with an equivalent capital cost. However, it was also observed in either alternative case that the initial element recovery percentage was 10-11%, rather than the 8% achieved in the original 2 stage, 6 element design. A lower recovery percentage indicates lower fouling rates and thus less frequent replacement of membranes, though this precise economic effect could not be quantified.

Based on the manufacturer and industry standard for reverse osmosis configuration, along with the minimal differences in total costs for alternatives and fouling concerns, the project chose to continue with the 2-stage, 6 element per stage configuration.

==Sensitivity Analysis==
Our process was found to be particularly sensitive to three main areas within capital costs, operating, costs, and revenue, which could have significant influence over the final economic analysis if the estimations are off by a significant margin or if the data used for these estimations changes significantly in the coming years.

===Capital Costs===
The construction of the project’s seawater intake/disposal pipeline is priced at approximately $200 million, making up about a third of total capital costs. It may be possible, rather than construct an entirely new water feed and disposal system, to draw used seawater from a nearby large-scale consumer and mitigate these construction costs greatly. For example, it is fairly common for desalination plants to use industrial cooling water effluent for their plants, whether it be as a feed or as a dilution measure, in order to significantly drive down capital costs.

===Operating Costs and Revenue===
The operating costs, while a small portion of total project expenses, consume more than a quarter of the plant revenue at $6.2 million per year. This is largely governed by the energy costs, which have been estimated at $0.08 per kilowatt-hour. A decrease in this cost would substantially decrease yearly operating cost and allow for greater profit.

Similarly, revenue is governed by the cost of water being paid to the Carlsbad Desalination Plant, at $2260 per acre-foot. [22] This price is expected to rise as the water shortage becomes more urgent and the population of California increases. A significant increase in this price could greatly help the desalination project to improve economic viability.

=Conclusion=
Overall, the project designed a 10 million gallon per day seawater desalination plant on the Southern California Bight to fill the need of water shortage. We chose reverse osmosis as a method for desalination. The plant would pressurize seawater from subterranean wells off the coast of the bight. The water is then sent to the pre-treatment system before entering the reverse osmosis system. We decided on a 2 stage, 6 element per stage process using Dow SW30XHR-440i membrane and operating at 50% recovery with a feed of 20 million gallons per day. The system achieves a final dissolved solid concentration of 109 mg/L, which well satisfies the California drinking water recommendation of 500 mg/L of dissolved solids concentration. The fresh water is then sent to post-treatment and merge with existing supplies. Waste concentrate from from the process is sent back into the bay through a long engineered diffuser pipe that can dilute the brine to necessary levels.

Furthermore, we did optimization for our process. The primary opportunity for optimization within our process occurs in the management of the reverse osmosis process, with respect to the number of stages and the number of elements per stage used for our filtration. The result shows a minimal variation between different configurations of our system, particularly compared with more dominant capital and operations cost throughout the remainder of our process. Based on the minimal differences, along with the manufacture and industry standard for reverse osmosis configuration, the project chose to continue with the 2-stage, 6 element per stage configuration.

However, based on the results from the economic analysis, we concluded from the final -$402.5 million net present value, that such an energy intensive process to produce a product that is generally taken for granted is extremely costly. As a commercial venture this project is not viable. On the other hand, with increased demand and decreased supply the water price may rise and become a motivation for the government to invest for the desalination in the future. The project would likely need to taken on by the city of San Diego rather than a private entity. For future development and viability of this project, we recommend to draw used seawater from a nearby large-scale process instead of constructing an entirely new water feed and disposal system. This can mitigate the construction costs greatly.

=References=
# Groundwater Information Sheet. State Water Resources Control Board website. http://www.waterboards.ca.gov/gama/docs/coc_salinity.pdf Published March 2010. Accessed January 12, 2016.
# Maximum Contaminant Levels and Regulatory Dates for Drinking Water. State Water Resources Control Board website. http://www.waterboards.ca.gov/drinking_water/certlic/drinkingwater/documents/dwdocuments/MCLsEPAvsDWP-2014-07-01.pdf Updated July 1st, 2015. Accessed January 12, 2016.
# Weiser M. State’s population growth expected to outstrip water conservation in coming years. sacbee. http://www.sacbee.com/news/local/environment/article10311635.html. Accessed January 29, 2016.
# General Facts About California’s Water. Association of California Water Agencies website. http://www.acwa.com/issues/general_water_facts/index.asp#water_supply. Accessed March 3, 2016.
# Composition of Seawater. Lenntech website. http://www.lenntech.com/composition-seawater.htm Published January, 2005. Accessed January 12, 2016.
# Groundwater Information Sheet. State Water Resources Control Board website. http://www.waterboards.ca.gov/gama/docs/coc_salinity.pdf Published March 2010. Accessed January 12, 2016.
# Maximum Contaminant Levels and Regulatory Dates for Drinking Water. State Water Resources Control Board website. http://www.waterboards.ca.gov/drinking_water/certlic/drinkingwater/documents/dwdocuments/MCLsEPAvsDWP-2014-07-01.pdf Updated July 1st, 2015. Accessed January 12, 2016.
# MWSD Desalination Feasibility Study - ExecSummary_desal-study_Dec09.pdf. http://www.sdcwa.org/sites/default/files/files/water-management/desal/ExecSummary_desal-study_Dec09.pdf. Accessed January 29, 2016.
# Prihasto N, Lui Q, Kim S. Pre-treatment strategies for seawater desalination by reverse osmosis system. 2009; 249(1): 308-316.
# Semiat R. Energy Issues in Desalination Processes. American Chemical Society. http://pubs.acs.org/doi/pdf/10.1021/es801330u. Accessed January 29, 2016
# Stover RL. Seawater reverse osmosis with isobaric energy recovery devices. Desalination. 2007;203(1–3):168-175. doi:10.1016/j.desal.2006.03.528.
# Schneider B. Selection, operation and control of a work exchanger energy recovery system based on the Singapore project. Desalination. 2005;184(1–3):197-210. doi:10.1016/j.desal.2005.04.031.
# Camp Pendleton Seawater Desalination Project Feasibility Report - Final Report. http://www.sdcwa.org/sites/default/files/files/water-management/desal/vol1_report_desal-study_Dec09.pdf. Accessed January 29, 2016.
# Sodium hypochlorite as a disinfectant. http://www.lenntech.com/processes/disinfection/chemical/disinfectants-sodium-hypochlorite.htm. Accessed January 29, 2016.
# Seawater Concentrate Management https://www.watereuse.org/wp-content/uploads/2015/10/Seawater_Concentrate_WP.pdf. Accessed January 29, 2016.
# H2K Technologies, Inc. - Multi Media Filters. http://www.h2ktech.com/multi-media-filters/media-filters-sand-filters.html. Accessed February 27, 2016.
# DOW Ultrafiltration Modules Product Data Sheet. http://msdssearch.dow.com/PublishedLiteratureDOWCOM/dh_0945/0901b803809456d7.pdf?filepath=liquidseps/pdfs/noreg/795-50225.pdf&fromPage=GetDoc. Accessed February 27, 2016.
# DOW FILMTEC Membranes - Steps to Design a Membrane System Using ROSA http://dowwater.custhelp.com/app/answers/detail/a_id/2209 Accessed February 27, 2016.
# DOW FILMTEC™ SW30XHR–440i Element http://msdssearch.dow.com/PublishedLiteratureDOWCOM/dh_0945/0901b80380945d8d.pdf?filepath=liquidseps/pdfs/noreg/609-03002.pdf&fromPage=GetDoc Accessed February 27, 2016.
# ICIS Indicative Chemical Prices A-Z http://www.icis.com/chemicals/channel-info-chemicals-a-z/ Accessed February 27, 2016.
# Towler GP, Sinnot R. Chemical Engineering Design: Principles, Practice and Economics of Plant and Process Design. Elsevier.
# Rogers, Paul Nation’s Largest Desalination Plant Goes Up Near San Diego; Future of the California Coast? San Jose Mercury News http://www.mercurynews.com/science/ci_25859513/nations-largest-ocean-desalination-plant-goes-up-near Accessed February 27, 2016.
# San Diego Electricity Rates. Electricity Local. http://www.electricitylocal.com/states/california/san-diego/ Accessed February 27, 2016.
# Dow Reverse Osmosis Membranes Treat Seawater and Offers Drinking Water to Southern California. http://msdssearch.dow.com/PublishedLiteratureDOWCOM/dh_0940/0901b80380940a81.pdf Accessed March 4, 2016.

=Appendices=

==Appendix 1 - Plant Location Map==

==Appendix 2 - Posttreatment Water Quality Goals==

==Appendix 3 - Dissolved Ion Concentration of Seawater Inlet==

==Appendix 4 - Process Flow Diagram==

==Appendix 5 - Final Simulation Mass Balance and Stream Pressure==

==Appendix 6 - Stream Tables==

==Appendix 7 - Composition of Pass Streams from RO Process==

==Appendix 8 - Pumping Requirements==

==Appendix 9 - ERD Simulation==

[[File:9.PNG|center|600px|thumb|alt=|ERD Simulation.]]

==Appendix 10 - Example Diffuser System from Camp Pendleton Plant==

[[File:10.PNG|center|600px|thumb|alt=|Example Diffuser System from Camp Pendleton plant.]]

==Appendix 11 - Capital Cost==

[[File:11.1.PNG|center|600px|thumb|alt=|Table 11.1 Capital Cost breakdown.]]

==Appendix 12 - Holding Tank Costs==

[[File:12.1.PNG|center|600px|thumb|alt=|Table 12.1 Holding Tank Costs.]]

==Appendix 13 - Utility Calculations==

[[File:13.1.PNG|center|600px|thumb|alt=|Table 13.1 Utility calculations.]]

==Appendix 14 - Yearly Cost of Chemical Additions==

[[File:14.1.PNG|center|600px|thumb|alt=|Table 14.1 Chemical Addition Costs.]]

==Appendix 15 - Economic Analysis==

[[File:15.PNG|center|600px|thumb|alt=|Economic Analysis.]]

==Appendix 16 - Optimization==

[[File:16.1.PNG|center|600px|thumb|alt=|Table 16.1 Optimization of yearly utility for number of stages and elements per stage.]]

[[File:16.2.PNG|center|600px|thumb|alt=|Table 16.2: Optimization of yearly utility for number of elements per stage.]]

Desalination - Team D

2016-03-10T22:45:52Z

Taunins: /* Conclusion */

Team D: Final Report

Authors: Thomas Aunins, Robert Cignoni, John Dombrowski, Iris Zhao

Instructors: Fengqi You, David Wegerer

March 11, 2016

=Executive Summary=
Water shortage is one of the foremost and most urgent issues facing the world today, as developing and developed countries alike have struggled with depletion of natural reservoirs and severe droughts. This issue has resulted in the recent rapid development of desalination technology and the construction of desalination facilities. Since the turn of the millennium, the United State alone has increased its desalination capacity from 600 million gallons per day to 1650 million gallons per day, with much more currently being planned. California, in particular, is the focus of a large amount of the United States’ desalination efforts, as its current drought has exposed a discrepancy in water supply contingency and demonstrated a need for non-natural freshwater sources.

This project aims to design a 10 million gallon per day seawater desalination plant on the Southern California Bight--near San Diego--to fill this need. A reverse osmosis system was chosen based on the fact that it is the most rapidly developing and innovating technology in the desalination field, as well as the fact that it has a lower theoretical energy production per gallon of water than the common multi-stage flash purification methods. Our plant will pressurize seawater from subterranean wells off the coast of the bight and send it to our pre-treatment system. There, it will go through a drum screen, multimedia filter, antiscalant addition, and finally ultrafiltration to remove varying size of suspended solids and contaminants, before entering our reverse osmosis system.

The RO system itself is a 2-stage, 6 element per stage process, using Dow SW30XHR-440i membranes and operating at 50% recovery with a feed of 20 million gallons per day. This allows the process to achieve a final dissolved solids concentration of 109 mg/L, far below the California drinking water recommendation of 500 mg/L. This freshwater can then be sent to post-treatment and merged with water of the San Diego County Water Authority’s distribution system. Waste concentrate from the process is sent back into the bay through a long diffuser pipe system that will dilute the brine to necessary levels to avoid environmental damage.

An economic analysis of the process found total capital costs to be slightly more than $600 million, with yearly revenues and operating costs at $25.4 million and $6.2 million, respectively. On a 25 year time scale, this results in a final net present value for the project at -$402.5 million, causing us to conclude that as a commercial venture the project is not viable. We do note, however, that increased demand and decreased supply may cause water prices to rise and create a motivation for government investment in the project in the future. For this reason, we believe that it is possible for this project to become an economically feasible and practically necessary venture in coming years.

__TOC__

=Introduction=

==Background==
Due to drought and the depletion of groundwater, desalination is becoming an increasingly viable source for drinking water in the San Diego, California area. A map of the plant location can be found in Appendix 1. Reverse osmosis appears to be the best route for desalination due to its lower energy costs and high volume of current research efforts. It is also capable of purifying California seawater to the levels recommended by the World Health Organization (WHO) and the state government. The process will separate solids from seawater before subjecting it to a two-stage reverse osmosis unit. Concentrated brine waste will be diluted with seawater before going back into the environment. Permeate streams will be remineralized and disinfected before leaving the facility.

==Problem Statement==
The objective of this process will be to produce fresh drinking-quality water according to standards recommended by the Water Research Foundation. This sets an upper limit for the total dissolved solid in our product at 1000 mg/L, with a non-mandatory guideline of approximately 500 mg/L as an appropriate target. This can be found from in Appendix 2. This encompasses the secondary maximum contaminant levels (MCL) set forth by the State Resources Water Control Board [1]. Additionally, there are guidelines set forth for primary MCLs, which encompasses more dangerous and/or toxic substances in the water. These are a smaller concern for our project because sea water does not naturally contain amounts of these contaminants above the MCLs [2].

=Technical Approach=

==Site Location and Capacity==
This project is planned for construction on the Southern California Bight, located just north of San Diego and nearby the San Diego County Water Authority’s (SDCWA) distribution system. This area is of particular interest for seawater desalination projects due to the projected discrepancy between water supply and demand in upcoming years. Statewide in California, the demand for water is expected to increase by 1.2 billion cubic meters per year by 2030, as projections show that population increase of 16% dramatically outstripping water conservation goals. [3] Southern California in particular has a great need for more freshwater sources, as the lower two-thirds of the state require 80% of California’s water, while the upper third of the state supplies 75% of it. [4]

Per the aforementioned water scarcity, California’s water demand has become a large part of this growth. There are several large scale desalination plants planned for the area, including large-scale projects at Carlsbad and Camp Pendleton. Each of these plants will be constructed to produce 50 MGD of freshwater to the San Diego area, with the latter expected to expand to 150 MGD within ten years of completion. The construction of these plants, along with other smaller scale plants in the area, indicates an urgent need for desalination capacity. Our plant is being designed to produce 10 million gallons per day (MGD) of fresh water for the San Diego area.

==Feed Stream==
Seawater will be fed from a submerged pipeline off the coast of the Southern California Bight. The subterranean feed inlet will allow for an initial pseudo-filter as the water is pulled through the porous ocean floor, preventing large debris and aquatic life from being pulled into the process intake. Worldwide, seawater salinity averages approximately 35,000 mg/L of total dissolved solids, with the primary salts present being chloride and sodium at 19,000 mg/L and 10,500 mg/L, respectively. [5] It should be noted that while data on average local seawater composition for Southern California was not available, this area is known to typically have lower total dissolved solids concentrations than average seawater, placing our calculations on the conservative side. Further breakdown of the dissolved ion concentration of our seawater input can be found in Appendix 3.

==Product Stream==
The objective of this process will be to produce fresh drinking-quality water according to standards set by the California state government and the World Health Organization. Regulations set an upper limit for the total dissolved solid in our product at 1000 mg/L, with a non-mandatory guideline of approximately 500 mg/L as an appropriate target. This encompasses the secondary maximum contaminant levels (MCL) set forth by the State Resources Water Control Board. [6] Additionally, there are guidelines set forth for primary MCLs, which encompasses more dangerous and/or toxic substances in the water. These are a smaller concern for our project because sea water does not naturally contain amounts of these contaminants above the MCLs. [7]

Further goals for the permeate composition and quality following post-treatment were taken from recommendations given by the Water Research Foundation on seawater reverse osmosis and from averages taken from San Diego water treatment plants. These can be found in Appendix 2.

=Flowsheet=

==Process Flow Diagram, Major Technology, and Alternatives==
The process flow diagram (PFD) can be found in Appendix 4. Each stream and piece of equipment is labeled according to which section of the process it pertains to. The final simulation mass balance and stream pressure can be found in Appendix 5. Stream tables can be found in Appendix 6.

===100 - Pretreatment===
The feed flow rate set to the system is 20 MGD. The seawater intake system proposed for the site is a deep infiltration gallery (DIG) intake system due to the permeable hydrogeology offshore of the proposed location. DIG would be comprised of a series of angled or wells drilled radially and therefore would not supply a large amount of feed water due to low permeability. Therefore, the radial collector wells would be drilled at a downward angle from the barge to the dual-use tunnel, below the loose sand layer. The collector wells act as an infiltration gallery, in that the underground seawater infiltrates into the wells and gravity flows into the annular space of the tunnel, which conveys the feedwater onshore. [8]

The sea plays host to contaminants that extend well beyond salt. Poor feed quality can lead to short RO membrane lifetime, short periods of operation, and high maintenance costs. Contaminants include suspended solids, dissolved organic contaminants, and sparingly soluble salts. [9]

First off, a drum screen (F-110) will catch any large solids greater than 0.5 cm that could literally throw a wrench in our operations. A multimedia filter (F-120) captures smaller solids from 1 to 20 µm. The media will consist of anthracite, sand, and gravel, providing a gradient from coarse to fine which creates a media flow pattern necessary to achieve a very low silt density index. [9]

An antiscalant (T-131) will help us avoid fouling of UF and RO membranes by controlling carbonate scaling, magnesium hydroxide scaling, sulfate scaling, and calcium fluoride scaling. Organophosphates tend to be the most stable antiscalant, as they are not subject to hydrolysis or precipitation like sodium hexametaphosphate or polyacrylates. Alternatives to antiscalants that were investigated were water softening and acidification. Both are not economically favorable compared to antiscalants due to additional post treatment measures required when using these methods. Ultrafiltration (F-140), at 0.01–0.02 µm, will remove much of the remaining biological or particulate matter. This pore size also aids in disinfection, as it excludes viruses. These measures will result in a Silt Density index of less than 2.5. [9]

Conventional pretreatment methods using chemical coagulants such as ferric chloride in concert with Dissolved Air Flotation or Clarifier units were also considered. The equipment and media are long lasting and require low maintenance, but the chemical usage and disposal costs would be higher. UF membranes will need to be replaced every 5–10 years, so they require a moderate running cost. However, this extensive pretreatment process will help reduce RO operating costs and increase process efficiency downstream. [9] The selected pretreatment method will decrease our environmental footprint and extend the lifespan of our membranes.

===200 - Reverse Osmosis===

====Seawater Reverse Osmosis Technology====
The desalination method for this plant will be through reverse osmosis (RO). This method was chosen for a number of reasons. Firstly, new desalination plants appearing in the United States are increasingly run using reverse osmosis technology. The most notable example is the Carlsbad plant that recently opened up near San Diego which produces up to 50 million gallons per day of fresh water. Furthermore, a thermodynamic analysis was done on different desalination methods including multi-effect distillation (MED) and multistage flash evaporation (MSF). [10] The analysis found that reverse osmosis has the lowest theoretical energy consumption per unit of fresh water obtained. Due to this, building a reverse osmosis plant likely also has the most security moving forward.

Various membrane technology was investigated for use in this process. Thin film composite polyamide membranes are currently the industry gold standard. These have advantages over asymmetrical cellulose acetate membranes due to their higher permeate fluxes and higher salt rejection. Spiral wound membranes are the current state of the art module and are preferable to hollow fiber and plate and frame modules due to their low fouling which can be attributed to the parallel flow of the feed as opposed to the normal flow regime found in the other modules.

The Dow SW30XHR-440i spiral-wound membrane was chosen because each has the capacity for 6,600 gallons per day of permeate (the maximum available from Dow) and the highest overall dissolved solids rejection fraction at 99.82%. Additionally it is the membrane of choice for plants of a similar scale, such as the plant at Carlsbad, which verifies its practical usefulness for such large-scale operations. Based on this choice, it was determined that a 2-stage, 6 element per stage, single pass process would be necessary to achieve the desired flow rate and recovery for a single unit of our operation. A simplified RO system schematic is shown in Figure 1.
[IMAGE]
Using equations that were presented by Dow Chemical for designing RO plants, it was found that it was possible to produce 10 MGD of fresh water at a recovery of roughly 50% using 2280 membrane elements. These elements would be arranged in a series of 6 elements per pressure vessel for a total of 380 pressure vessels. The pressure vessels would be arranged in a two stage process with 220 pressure vessels in parallel in the first stage and 160 in the second stage. Detailed composition of pass streams from the reverse osmosis process can be found in Appendix 7.

====Energy Recovery====
The energy cost component of seawater RO can be up 70% of the total cost, so reducing the amount of energy consumed by the process was essential to minimizing not only cost, but also environmental impact. Energy use reduction is traditionally achieved through energy recovery devices (ERDs), such as centrifugal devices or isobaric, “pressure-equalizing,” devices. [11] In all cases, energy from the brine stream is transferred directly a portion of the membrane feed stream, reducing pumping requirements. The PFD and stream table detail how the feed is split, with a portion leading to an ERD before entering a booster pump and rejoining the stream from the high pressure (HP) pump. This significantly reduces the size and energy requirements of the HP pump. [12] Systems utilizing this technology can realize up to 60% energy reduction compared to those without it. [11]

Centrifugal ERDs incur lower capital costs, but have limited capacity and efficiency, typically running at a maximum of 82% efficiency. This is because they must transfer hydraulic energy from the brine stream into mechanical energy and then back into hydraulic energy. [12] Isobaric ERDs are the most efficient ERDs, operating at a maximum net transfer efficiency of up to 97%. Isobaric ERDs can handle increased capacity by being run in parallel, similar to the RO membranes. The PX Pressure Exchanger from Energy Recovery, Inc., requires minimal controls, can operate without periodic maintenance, and use ceramic rotors which do not corrode with seawater. [11] For that reason, it was selected for our process.

The PX Pressure Exchanger can operate at 96% efficiency for our process, and will require 24 units to handle our capacity. 6900 gpm (49.5%) of the feed stream will be redirected towards the PX Array, where it will be acted upon by the concentrated brine stream before flowing to the booster pump (P-213). The rest of the stream will be served by the HP pump (P-211). Through this technology, our process utilizes 8.9 kWh/kgal in the RO section, compared to 17.4 kWh/kgal without, almost 50% in energy savings. Pumping requirements are summarized in Appendix 8. A diagram portraying the simulation of this process is in Appendix 9.

===300 - Posttreatment===
After the reverse osmosis process, water will go through post-treatment by adding minerals to prevent corrosion of the distribution pipelines and resemble existing potable water supplies. By adjusting the hardness, alkalinity, and pH of the permeate, the aesthetic water quality will be assured and the distribution pipeline will be protected from corrosion. [13] The post-treatment will include the addition of sodium bicarbonate (T-311) and calcium chloride (T-312) for remineralization, sodium hydroxide (T-321) for pH adjustment, and sodium hypochlorite (T-331) for disinfection. [14]

Lastly, the product will be held in a holding tank (T-350) before being blended with municipal stores. This will allow for proper quality analysis of TDS, conductivity, and pH. Afterwards, the product water will blend with existing supplies so that the municipality may maintain consistent water quality for all consumers. Existing water treatment plants will ensure the water is suitable for consumption. The blended water can then be delivered throughout the region from there.

===400 - Brine Treatment===
There are several possible alternatives for brine treatment in large coastal seawater desalination plants. Possibilities include the use of large evaporation ponds, injection of brine into confined aquifers, and discharge into existing bodies of water. The first two options are largely not viable due to high land costs for evaporation ponds and the requirement of comprehensive land surveys for aquifers. Discharging to the ocean, however, is fairly commonly used as it is a reasonably practical option. [13]

Some smaller-scale facilities have been able to mix their effluent streams with cooling water effluent from nearby industrial plants or additional seawater as a dilution method to reach the necessary 40 ppt range of dissolved salts. [15] However, this requires either a conveniently located cooling water source, which our plant cannot assume, or prohibitively high costs to pump in enough seawater to dilute our effluent. Another option, and one that will be used at Camp Pendleton, is an engineered diffuser system on the brine discharge outfall. An engineered diffuser system consists of a long pipeline that will release smaller amounts of the brine over the course of its length and promote mixing to achieve dilution requirements. The Camp Pendleton desalination plant’s plans for this system are shown in Appendix 10 as an example. [13]

===500 - Solids Treatment===
Solids separated during the pretreatment process through the drum screen, multimedia filter, and UF membrane will be hauled off-site to a suitable landfill. Since no chemical coagulant, such as ferric chloride, is used in the pretreatment process, the spent backwash water can also be conveyed straight to the brine disposal pipeline and discharged to the ocean because the suspended solids contained will be entirely of marine origin.

=Economic Evaluation=

==Equipment Sizing/Pricing==

===Pretreatment===
Assuming that multimedia filters can support 20 gpm/sq. ft. area, [16] our process will require 4 multimedia filters, each with 200 sq. ft. of area and priced at $34000. Ultrafiltration modules can operate at 30 gpm, [17] necessitating 467 UF modules, each priced at $500.

===RO System===
The reverse osmosis system was designed in order to comply with the optimal operating conditions for the aforementioned FilmTec membranes and to achieve the necessary dissolved solids concentration and permeate flow rate for a 10 MGD-scale desalination plant. This resulted in 2280 RO elements in 380 pressure vessels. RO elements are cylinders of length 40.5 inches and diameter 7.9 inches. [18] A range of prices was found for bulk purchases of the required membrane, which could be conservatively estimated at 700 USD per element. The replacement percentage per year for Dow’s membranes filtering this level of SDI is 13%, which was added to the total capital cost of the system. Pressure vessel capital cost was estimated using the Aspen Economic Analyzer, and were found to cost $6700 each. This equipment capital cost was found to be 4.14 million USD. Additionally, there were significant costs associated with construction and auxiliary RO feed equipment was estimated by scaling the 50 MGD Camp Pendleton budget allocation [13] according to the following equation:

<math>C_2=C_1(S_2/S_1)^n</math>

where Ci refers to equipment and construction cost and Si refers to plant capacity. The value for ‘n’ was set as 0.7 based on guidelines from the Chemical Engineering Design textbook. [23] This extra capital cost was estimated at 56.3 million USD.

===Feed Intake===
Tunnel materials for the feed intake was calculated to cost $32.1 million, while construction costs were estimated at $48.7 million. The feedwater piping, intake well system, and pump station were estimated to have a total capital cost of $55.4 million. Further details on capital cost can be found in Appendix 11.

===Concentrate Return and Dilution Pipelines===
Concentrated brine disposal was also modeled after Camp Pendleton. Although their scale of brine disposal is much larger than that of this process, capital cost estimates and sizing were not lowered due to the necessity to dig to the same depth and the use of piping with a similar diameter to return brine concentrate. The brine discharge system was estimated to cost $50.2 million, while the brine discharge pipeline was estimated to cost $9.2 million.

===Pumps===
(Requirements summarized in Appendix 8)

====Pretreatment Pumps====
Ultrafiltration will require a pump in order to filter our process efficiently. Using guidelines from Dow Chemical, [17] the optimal operating pressure for each ultrafiltration module is 30 psi, and each filter can operate at 30 gpm. As a result, this process will require 467 UF modules. A pump pressurizing 13889 gpm to 30 psi will require 202.8 kW. Antiscalant will need to be supplied to the process at 1.39 gpm in order to properly prevent fouling in pretreatment membranes. The power required for this would be 3.88*10-5 kW.

====RO Pumps====
Assuming 50% recovery during the RO process, the brine flow rate will be equal to the permeate flow rate, 6945 gpm. The PX Pressure Exchanger requires lubrication for its hydrodynamic bearing, which will be supplied by the high pressure brine stream, leading to the slight loss in efficiency. As a result, 6877 gpm (49.5%) of the inlet stream can be redirected to the PX Array before reaching a booster pump, with the remaining 7012 gpm being served by the high-pressure pump. The booster pump will only need to supply 53 psi of additional pressure compared to the 629 psi required from the high pressure pump. In order to meet minimum discharge pressure required for proper PX operation, it is necessary for the feed streams to be pressurized to 30 psi so that the low pressure brine stream will exit at 15.9 psi.

====Post-Treatment Pumps====
Post treatment chemicals (sodium hypochlorite, sodium bicarbonate, calcium chloride, sodium hydroxide) are added to the permeate in order to remineralize and pH adjust our water. The pumps used to deliver these chemicals must simply overcome frictional losses in the pipe in order to keep the chemicals moving. All pumps were modeled at 80% efficiency.

===Chemical Storage Tanks===
Chemicals that are added to the water need to be stored beforehand. Chemical holding tanks were sized according to a day’s worth of chemicals. The holding tank for sodium bicarbonate is quite large and this is cause for concern. This issue could be corrected by introducing the solid chemical directly to the product stream rather than creating a solution, storing that solution and then mixing solutions. The cost of the holding tanks can be found in Appendix 12.

==Product Selling Price==
The San Diego County Water Authority agreed to pay Carlsbad (a plant of comparable size and location) $2014-2267 per acre foot of water depending on how much is purchased. [22] Based on this number we estimate that our yearly plant revenue will be roughly $25.4 million.

==Operating Costs==
The San Diego County Water Authority agreed to pay Carlsbad (a plant of comparable size and location) $2014-2267 per acre foot of water depending on how much is purchased. [22] Based on this number we estimate that our yearly plant revenue will be roughly $25.4 million.

==Capital Costs==
The overall capital costs of our plant are summarized below.
{| class="wikitable"
|-
! Project Sector
! Capital Cost (MM$)
|-
| Feedwater Intake and Concentrate Return
| 195.6
|-
| Desalination Facility
| 82.7
|-
| Product Water Conveyance
| 90.4
|-
| '''Subtotal'''
| '''368.7'''
|-
| Contingency
| 130.2
|-
| Working Capital
| 18.4
|-
| Implementation (Legal, Engineering, Administration)
| 84.3
|-
| '''Total'''
| '''601.7'''
|}

==NPV Analysis==
The economic viability of our desalination process was analyzed using a 25 year project lifetime. The cost of capital was set at 12% and the tax rate was set at 35%. A ten-year MACRS depreciation model was used.

The project was found overall to not be economically feasible on a purely commercial level. As revenues would only produce approximately $25.4 million per year the net present value after a project lifetime of 25 years remains extremely low at -$402.5 million. The full economic analysis can be found in Appendix 15.

==Optimization==
The primary opportunity for optimization within our process occurs in the management of the reverse osmosis process, with respect to the number of stages and the number of elements per stage used for our filtration. As a starting point we chose to use two stages and six elements per stage, as this is in-line with Dow Chemical Company’s product recommendations for the SW30XHR-440i RO membrane. Additionally, this is the typical configuration for large-scale RO plants using this particular Dow membrane such as the Carlsbad Desalination Plant. [24]

Using the Dow ROSA software, configurations were evaluated for one, two, and three sequential stages, ranging from four to eight elements per stage. Each of these process conditions was evaluated with respect to the capital costs of equipment as well as the yearly utility cost that would be required. The results of this optimization are summarized in Appendix 16, Table 16.1 and 16.2, with our starting condition and minimum highlighted in each.

This optimization was conducted using a desired recovery of 50%. The number of vessels total and number of vessels per stage were based on the maximum permeate flow for the RO membrane and sizing equations obtained from the Dow RO design guide, respectively. [18]

These data show a minimal variation between different configurations of our system, particularly compared with more dominant capital and operations cost throughout the remainder of our process. However, this process does find a minimum utility cost for the 1-stage, 8 element per stage configuration, at $80,000 per year less than our current setup. Additionally, the condition of a 2-stage, 4 element configuration has a lower utility cost--$60,000 per year less--with an equivalent capital cost. However, it was also observed in either alternative case that the initial element recovery percentage was 10-11%, rather than the 8% achieved in the original 2 stage, 6 element design. A lower recovery percentage indicates lower fouling rates and thus less frequent replacement of membranes, though this precise economic effect could not be quantified.

Based on the manufacturer and industry standard for reverse osmosis configuration, along with the minimal differences in total costs for alternatives and fouling concerns, the project chose to continue with the 2-stage, 6 element per stage configuration.

==Sensitivity Analysis==
Our process was found to be particularly sensitive to three main areas within capital costs, operating, costs, and revenue, which could have significant influence over the final economic analysis if the estimations are off by a significant margin or if the data used for these estimations changes significantly in the coming years.

===Capital Costs===
The construction of the project’s seawater intake/disposal pipeline is priced at approximately $200 million, making up about a third of total capital costs. It may be possible, rather than construct an entirely new water feed and disposal system, to draw used seawater from a nearby large-scale consumer and mitigate these construction costs greatly. For example, it is fairly common for desalination plants to use industrial cooling water effluent for their plants, whether it be as a feed or as a dilution measure, in order to significantly drive down capital costs.

===Operating Costs and Revenue===
The operating costs, while a small portion of total project expenses, consume more than a quarter of the plant revenue at $6.2 million per year. This is largely governed by the energy costs, which have been estimated at $0.08 per kilowatt-hour. A decrease in this cost would substantially decrease yearly operating cost and allow for greater profit.

Similarly, revenue is governed by the cost of water being paid to the Carlsbad Desalination Plant, at $2260 per acre-foot. [22] This price is expected to rise as the water shortage becomes more urgent and the population of California increases. A significant increase in this price could greatly help the desalination project to improve economic viability.

=Conclusion=
Overall, the project designed a 10 million gallon per day seawater desalination plant on the Southern California Bight to fill the need of water shortage. We chose reverse osmosis as a method for desalination. The plant would pressurize seawater from subterranean wells off the coast of the bight. The water is then sent to the pre-treatment system before entering the reverse osmosis system. We decided on a 2 stage, 6 element per stage process using Dow SW30XHR-440i membrane and operating at 50% recovery with a feed of 20 million gallons per day. The system achieves a final dissolved solid concentration of 109 mg/L, which well satisfies the California drinking water recommendation of 500 mg/L of dissolved solids concentration. The fresh water is then sent to post-treatment and merge with existing supplies. Waste concentrate from from the process is sent back into the bay through a long engineered diffuser pipe that can dilute the brine to necessary levels.

Furthermore, we did optimization for our process. The primary opportunity for optimization within our process occurs in the management of the reverse osmosis process, with respect to the number of stages and the number of elements per stage used for our filtration. The result shows a minimal variation between different configurations of our system, particularly compared with more dominant capital and operations cost throughout the remainder of our process. Based on the minimal differences, along with the manufacture and industry standard for reverse osmosis configuration, the project chose to continue with the 2-stage, 6 element per stage configuration.

However, based on the results from the economic analysis, we concluded from the final -$402.5 million net present value, that such an energy intensive process to produce a product that is generally taken for granted is extremely costly. As a commercial venture this project is not viable. On the other hand, with increased demand and decreased supply the water price may rise and become a motivation for the government to invest for the desalination in the future. The project would likely need to taken on by the city of San Diego rather than a private entity. For future development and viability of this project, we recommend to draw used seawater from a nearby large-scale process instead of constructing an entirely new water feed and disposal system. This can mitigate the construction costs greatly.

=References=

=Appendices=

==Appendix 1 - Plant Location Map==

==Appendix 2 - Posttreatment Water Quality Goals==

==Appendix 3 - Dissolved Ion Concentration of Seawater Inlet==

==Appendix 4 - Process Flow Diagram==

==Appendix 5 - Final Simulation Mass Balance and Stream Pressure==

==Appendix 6 - Stream Tables==

==Appendix 7 - Composition of Pass Streams from RO Process==

==Appendix 8 - Pumping Requirements==

==Appendix 9 - ERD Simulation==

==Appendix 10 - Example Diffuser System from Camp Pendleton Plant==

==Appendix 11 - Capital Cost==

[[File:11.1.PNG|center|600px|thumb|alt=|Table 11.1 Capital Cost breakdown.]]

==Appendix 12 - Holding Tank Costs==

[[File:12.1.PNG|center|600px|thumb|alt=|Table 12.1 Holding Tank Costs.]]

==Appendix 13 - Utility Calculations==

[[File:13.1.PNG|center|600px|thumb|alt=|Table 13.1 Utility calculations.]]

==Appendix 14 - Yearly Cost of Chemical Additions==

[[File:14.1.PNG|center|600px|thumb|alt=|Table 14.1 Chemical Addition Costs.]]

==Appendix 15 - Economic Analysis==

[[File:15.PNG|center|600px|thumb|alt=|Economic Analysis.]]

==Appendix 16 - Optimization==

[[File:16.1.PNG|center|600px|thumb|alt=|Table 16.1 Optimization of yearly utility for number of stages and elements per stage.]]

[[File:16.2.PNG|center|600px|thumb|alt=|Table 16.2: Optimization of yearly utility for number of elements per stage.]]

Desalination - Team D

2016-03-10T22:44:54Z

Taunins: /* Economic Evaluation */

Team D: Final Report

Authors: Thomas Aunins, Robert Cignoni, John Dombrowski, Iris Zhao

Instructors: Fengqi You, David Wegerer

March 11, 2016

=Executive Summary=
Water shortage is one of the foremost and most urgent issues facing the world today, as developing and developed countries alike have struggled with depletion of natural reservoirs and severe droughts. This issue has resulted in the recent rapid development of desalination technology and the construction of desalination facilities. Since the turn of the millennium, the United State alone has increased its desalination capacity from 600 million gallons per day to 1650 million gallons per day, with much more currently being planned. California, in particular, is the focus of a large amount of the United States’ desalination efforts, as its current drought has exposed a discrepancy in water supply contingency and demonstrated a need for non-natural freshwater sources.

This project aims to design a 10 million gallon per day seawater desalination plant on the Southern California Bight--near San Diego--to fill this need. A reverse osmosis system was chosen based on the fact that it is the most rapidly developing and innovating technology in the desalination field, as well as the fact that it has a lower theoretical energy production per gallon of water than the common multi-stage flash purification methods. Our plant will pressurize seawater from subterranean wells off the coast of the bight and send it to our pre-treatment system. There, it will go through a drum screen, multimedia filter, antiscalant addition, and finally ultrafiltration to remove varying size of suspended solids and contaminants, before entering our reverse osmosis system.

The RO system itself is a 2-stage, 6 element per stage process, using Dow SW30XHR-440i membranes and operating at 50% recovery with a feed of 20 million gallons per day. This allows the process to achieve a final dissolved solids concentration of 109 mg/L, far below the California drinking water recommendation of 500 mg/L. This freshwater can then be sent to post-treatment and merged with water of the San Diego County Water Authority’s distribution system. Waste concentrate from the process is sent back into the bay through a long diffuser pipe system that will dilute the brine to necessary levels to avoid environmental damage.

An economic analysis of the process found total capital costs to be slightly more than $600 million, with yearly revenues and operating costs at $25.4 million and $6.2 million, respectively. On a 25 year time scale, this results in a final net present value for the project at -$402.5 million, causing us to conclude that as a commercial venture the project is not viable. We do note, however, that increased demand and decreased supply may cause water prices to rise and create a motivation for government investment in the project in the future. For this reason, we believe that it is possible for this project to become an economically feasible and practically necessary venture in coming years.

__TOC__

=Introduction=

==Background==
Due to drought and the depletion of groundwater, desalination is becoming an increasingly viable source for drinking water in the San Diego, California area. A map of the plant location can be found in Appendix 1. Reverse osmosis appears to be the best route for desalination due to its lower energy costs and high volume of current research efforts. It is also capable of purifying California seawater to the levels recommended by the World Health Organization (WHO) and the state government. The process will separate solids from seawater before subjecting it to a two-stage reverse osmosis unit. Concentrated brine waste will be diluted with seawater before going back into the environment. Permeate streams will be remineralized and disinfected before leaving the facility.

==Problem Statement==
The objective of this process will be to produce fresh drinking-quality water according to standards recommended by the Water Research Foundation. This sets an upper limit for the total dissolved solid in our product at 1000 mg/L, with a non-mandatory guideline of approximately 500 mg/L as an appropriate target. This can be found from in Appendix 2. This encompasses the secondary maximum contaminant levels (MCL) set forth by the State Resources Water Control Board [1]. Additionally, there are guidelines set forth for primary MCLs, which encompasses more dangerous and/or toxic substances in the water. These are a smaller concern for our project because sea water does not naturally contain amounts of these contaminants above the MCLs [2].

=Technical Approach=

==Site Location and Capacity==
This project is planned for construction on the Southern California Bight, located just north of San Diego and nearby the San Diego County Water Authority’s (SDCWA) distribution system. This area is of particular interest for seawater desalination projects due to the projected discrepancy between water supply and demand in upcoming years. Statewide in California, the demand for water is expected to increase by 1.2 billion cubic meters per year by 2030, as projections show that population increase of 16% dramatically outstripping water conservation goals. [3] Southern California in particular has a great need for more freshwater sources, as the lower two-thirds of the state require 80% of California’s water, while the upper third of the state supplies 75% of it. [4]

Per the aforementioned water scarcity, California’s water demand has become a large part of this growth. There are several large scale desalination plants planned for the area, including large-scale projects at Carlsbad and Camp Pendleton. Each of these plants will be constructed to produce 50 MGD of freshwater to the San Diego area, with the latter expected to expand to 150 MGD within ten years of completion. The construction of these plants, along with other smaller scale plants in the area, indicates an urgent need for desalination capacity. Our plant is being designed to produce 10 million gallons per day (MGD) of fresh water for the San Diego area.

==Feed Stream==
Seawater will be fed from a submerged pipeline off the coast of the Southern California Bight. The subterranean feed inlet will allow for an initial pseudo-filter as the water is pulled through the porous ocean floor, preventing large debris and aquatic life from being pulled into the process intake. Worldwide, seawater salinity averages approximately 35,000 mg/L of total dissolved solids, with the primary salts present being chloride and sodium at 19,000 mg/L and 10,500 mg/L, respectively. [5] It should be noted that while data on average local seawater composition for Southern California was not available, this area is known to typically have lower total dissolved solids concentrations than average seawater, placing our calculations on the conservative side. Further breakdown of the dissolved ion concentration of our seawater input can be found in Appendix 3.

==Product Stream==
The objective of this process will be to produce fresh drinking-quality water according to standards set by the California state government and the World Health Organization. Regulations set an upper limit for the total dissolved solid in our product at 1000 mg/L, with a non-mandatory guideline of approximately 500 mg/L as an appropriate target. This encompasses the secondary maximum contaminant levels (MCL) set forth by the State Resources Water Control Board. [6] Additionally, there are guidelines set forth for primary MCLs, which encompasses more dangerous and/or toxic substances in the water. These are a smaller concern for our project because sea water does not naturally contain amounts of these contaminants above the MCLs. [7]

Further goals for the permeate composition and quality following post-treatment were taken from recommendations given by the Water Research Foundation on seawater reverse osmosis and from averages taken from San Diego water treatment plants. These can be found in Appendix 2.

=Flowsheet=

==Process Flow Diagram, Major Technology, and Alternatives==
The process flow diagram (PFD) can be found in Appendix 4. Each stream and piece of equipment is labeled according to which section of the process it pertains to. The final simulation mass balance and stream pressure can be found in Appendix 5. Stream tables can be found in Appendix 6.

===100 - Pretreatment===
The feed flow rate set to the system is 20 MGD. The seawater intake system proposed for the site is a deep infiltration gallery (DIG) intake system due to the permeable hydrogeology offshore of the proposed location. DIG would be comprised of a series of angled or wells drilled radially and therefore would not supply a large amount of feed water due to low permeability. Therefore, the radial collector wells would be drilled at a downward angle from the barge to the dual-use tunnel, below the loose sand layer. The collector wells act as an infiltration gallery, in that the underground seawater infiltrates into the wells and gravity flows into the annular space of the tunnel, which conveys the feedwater onshore. [8]

The sea plays host to contaminants that extend well beyond salt. Poor feed quality can lead to short RO membrane lifetime, short periods of operation, and high maintenance costs. Contaminants include suspended solids, dissolved organic contaminants, and sparingly soluble salts. [9]

First off, a drum screen (F-110) will catch any large solids greater than 0.5 cm that could literally throw a wrench in our operations. A multimedia filter (F-120) captures smaller solids from 1 to 20 µm. The media will consist of anthracite, sand, and gravel, providing a gradient from coarse to fine which creates a media flow pattern necessary to achieve a very low silt density index. [9]

An antiscalant (T-131) will help us avoid fouling of UF and RO membranes by controlling carbonate scaling, magnesium hydroxide scaling, sulfate scaling, and calcium fluoride scaling. Organophosphates tend to be the most stable antiscalant, as they are not subject to hydrolysis or precipitation like sodium hexametaphosphate or polyacrylates. Alternatives to antiscalants that were investigated were water softening and acidification. Both are not economically favorable compared to antiscalants due to additional post treatment measures required when using these methods. Ultrafiltration (F-140), at 0.01–0.02 µm, will remove much of the remaining biological or particulate matter. This pore size also aids in disinfection, as it excludes viruses. These measures will result in a Silt Density index of less than 2.5. [9]

Conventional pretreatment methods using chemical coagulants such as ferric chloride in concert with Dissolved Air Flotation or Clarifier units were also considered. The equipment and media are long lasting and require low maintenance, but the chemical usage and disposal costs would be higher. UF membranes will need to be replaced every 5–10 years, so they require a moderate running cost. However, this extensive pretreatment process will help reduce RO operating costs and increase process efficiency downstream. [9] The selected pretreatment method will decrease our environmental footprint and extend the lifespan of our membranes.

===200 - Reverse Osmosis===

====Seawater Reverse Osmosis Technology====
The desalination method for this plant will be through reverse osmosis (RO). This method was chosen for a number of reasons. Firstly, new desalination plants appearing in the United States are increasingly run using reverse osmosis technology. The most notable example is the Carlsbad plant that recently opened up near San Diego which produces up to 50 million gallons per day of fresh water. Furthermore, a thermodynamic analysis was done on different desalination methods including multi-effect distillation (MED) and multistage flash evaporation (MSF). [10] The analysis found that reverse osmosis has the lowest theoretical energy consumption per unit of fresh water obtained. Due to this, building a reverse osmosis plant likely also has the most security moving forward.

Various membrane technology was investigated for use in this process. Thin film composite polyamide membranes are currently the industry gold standard. These have advantages over asymmetrical cellulose acetate membranes due to their higher permeate fluxes and higher salt rejection. Spiral wound membranes are the current state of the art module and are preferable to hollow fiber and plate and frame modules due to their low fouling which can be attributed to the parallel flow of the feed as opposed to the normal flow regime found in the other modules.

The Dow SW30XHR-440i spiral-wound membrane was chosen because each has the capacity for 6,600 gallons per day of permeate (the maximum available from Dow) and the highest overall dissolved solids rejection fraction at 99.82%. Additionally it is the membrane of choice for plants of a similar scale, such as the plant at Carlsbad, which verifies its practical usefulness for such large-scale operations. Based on this choice, it was determined that a 2-stage, 6 element per stage, single pass process would be necessary to achieve the desired flow rate and recovery for a single unit of our operation. A simplified RO system schematic is shown in Figure 1.
[IMAGE]
Using equations that were presented by Dow Chemical for designing RO plants, it was found that it was possible to produce 10 MGD of fresh water at a recovery of roughly 50% using 2280 membrane elements. These elements would be arranged in a series of 6 elements per pressure vessel for a total of 380 pressure vessels. The pressure vessels would be arranged in a two stage process with 220 pressure vessels in parallel in the first stage and 160 in the second stage. Detailed composition of pass streams from the reverse osmosis process can be found in Appendix 7.

====Energy Recovery====
The energy cost component of seawater RO can be up 70% of the total cost, so reducing the amount of energy consumed by the process was essential to minimizing not only cost, but also environmental impact. Energy use reduction is traditionally achieved through energy recovery devices (ERDs), such as centrifugal devices or isobaric, “pressure-equalizing,” devices. [11] In all cases, energy from the brine stream is transferred directly a portion of the membrane feed stream, reducing pumping requirements. The PFD and stream table detail how the feed is split, with a portion leading to an ERD before entering a booster pump and rejoining the stream from the high pressure (HP) pump. This significantly reduces the size and energy requirements of the HP pump. [12] Systems utilizing this technology can realize up to 60% energy reduction compared to those without it. [11]

Centrifugal ERDs incur lower capital costs, but have limited capacity and efficiency, typically running at a maximum of 82% efficiency. This is because they must transfer hydraulic energy from the brine stream into mechanical energy and then back into hydraulic energy. [12] Isobaric ERDs are the most efficient ERDs, operating at a maximum net transfer efficiency of up to 97%. Isobaric ERDs can handle increased capacity by being run in parallel, similar to the RO membranes. The PX Pressure Exchanger from Energy Recovery, Inc., requires minimal controls, can operate without periodic maintenance, and use ceramic rotors which do not corrode with seawater. [11] For that reason, it was selected for our process.

The PX Pressure Exchanger can operate at 96% efficiency for our process, and will require 24 units to handle our capacity. 6900 gpm (49.5%) of the feed stream will be redirected towards the PX Array, where it will be acted upon by the concentrated brine stream before flowing to the booster pump (P-213). The rest of the stream will be served by the HP pump (P-211). Through this technology, our process utilizes 8.9 kWh/kgal in the RO section, compared to 17.4 kWh/kgal without, almost 50% in energy savings. Pumping requirements are summarized in Appendix 8. A diagram portraying the simulation of this process is in Appendix 9.

===300 - Posttreatment===
After the reverse osmosis process, water will go through post-treatment by adding minerals to prevent corrosion of the distribution pipelines and resemble existing potable water supplies. By adjusting the hardness, alkalinity, and pH of the permeate, the aesthetic water quality will be assured and the distribution pipeline will be protected from corrosion. [13] The post-treatment will include the addition of sodium bicarbonate (T-311) and calcium chloride (T-312) for remineralization, sodium hydroxide (T-321) for pH adjustment, and sodium hypochlorite (T-331) for disinfection. [14]

Lastly, the product will be held in a holding tank (T-350) before being blended with municipal stores. This will allow for proper quality analysis of TDS, conductivity, and pH. Afterwards, the product water will blend with existing supplies so that the municipality may maintain consistent water quality for all consumers. Existing water treatment plants will ensure the water is suitable for consumption. The blended water can then be delivered throughout the region from there.

===400 - Brine Treatment===
There are several possible alternatives for brine treatment in large coastal seawater desalination plants. Possibilities include the use of large evaporation ponds, injection of brine into confined aquifers, and discharge into existing bodies of water. The first two options are largely not viable due to high land costs for evaporation ponds and the requirement of comprehensive land surveys for aquifers. Discharging to the ocean, however, is fairly commonly used as it is a reasonably practical option. [13]

Some smaller-scale facilities have been able to mix their effluent streams with cooling water effluent from nearby industrial plants or additional seawater as a dilution method to reach the necessary 40 ppt range of dissolved salts. [15] However, this requires either a conveniently located cooling water source, which our plant cannot assume, or prohibitively high costs to pump in enough seawater to dilute our effluent. Another option, and one that will be used at Camp Pendleton, is an engineered diffuser system on the brine discharge outfall. An engineered diffuser system consists of a long pipeline that will release smaller amounts of the brine over the course of its length and promote mixing to achieve dilution requirements. The Camp Pendleton desalination plant’s plans for this system are shown in Appendix 10 as an example. [13]

===500 - Solids Treatment===
Solids separated during the pretreatment process through the drum screen, multimedia filter, and UF membrane will be hauled off-site to a suitable landfill. Since no chemical coagulant, such as ferric chloride, is used in the pretreatment process, the spent backwash water can also be conveyed straight to the brine disposal pipeline and discharged to the ocean because the suspended solids contained will be entirely of marine origin.

=Economic Evaluation=

==Equipment Sizing/Pricing==

===Pretreatment===
Assuming that multimedia filters can support 20 gpm/sq. ft. area, [16] our process will require 4 multimedia filters, each with 200 sq. ft. of area and priced at $34000. Ultrafiltration modules can operate at 30 gpm, [17] necessitating 467 UF modules, each priced at $500.

===RO System===
The reverse osmosis system was designed in order to comply with the optimal operating conditions for the aforementioned FilmTec membranes and to achieve the necessary dissolved solids concentration and permeate flow rate for a 10 MGD-scale desalination plant. This resulted in 2280 RO elements in 380 pressure vessels. RO elements are cylinders of length 40.5 inches and diameter 7.9 inches. [18] A range of prices was found for bulk purchases of the required membrane, which could be conservatively estimated at 700 USD per element. The replacement percentage per year for Dow’s membranes filtering this level of SDI is 13%, which was added to the total capital cost of the system. Pressure vessel capital cost was estimated using the Aspen Economic Analyzer, and were found to cost $6700 each. This equipment capital cost was found to be 4.14 million USD. Additionally, there were significant costs associated with construction and auxiliary RO feed equipment was estimated by scaling the 50 MGD Camp Pendleton budget allocation [13] according to the following equation:

<math>C_2=C_1(S_2/S_1)^n</math>

where Ci refers to equipment and construction cost and Si refers to plant capacity. The value for ‘n’ was set as 0.7 based on guidelines from the Chemical Engineering Design textbook. [23] This extra capital cost was estimated at 56.3 million USD.

===Feed Intake===
Tunnel materials for the feed intake was calculated to cost $32.1 million, while construction costs were estimated at $48.7 million. The feedwater piping, intake well system, and pump station were estimated to have a total capital cost of $55.4 million. Further details on capital cost can be found in Appendix 11.

===Concentrate Return and Dilution Pipelines===
Concentrated brine disposal was also modeled after Camp Pendleton. Although their scale of brine disposal is much larger than that of this process, capital cost estimates and sizing were not lowered due to the necessity to dig to the same depth and the use of piping with a similar diameter to return brine concentrate. The brine discharge system was estimated to cost $50.2 million, while the brine discharge pipeline was estimated to cost $9.2 million.

===Pumps===
(Requirements summarized in Appendix 8)

====Pretreatment Pumps====
Ultrafiltration will require a pump in order to filter our process efficiently. Using guidelines from Dow Chemical, [17] the optimal operating pressure for each ultrafiltration module is 30 psi, and each filter can operate at 30 gpm. As a result, this process will require 467 UF modules. A pump pressurizing 13889 gpm to 30 psi will require 202.8 kW. Antiscalant will need to be supplied to the process at 1.39 gpm in order to properly prevent fouling in pretreatment membranes. The power required for this would be 3.88*10-5 kW.

====RO Pumps====
Assuming 50% recovery during the RO process, the brine flow rate will be equal to the permeate flow rate, 6945 gpm. The PX Pressure Exchanger requires lubrication for its hydrodynamic bearing, which will be supplied by the high pressure brine stream, leading to the slight loss in efficiency. As a result, 6877 gpm (49.5%) of the inlet stream can be redirected to the PX Array before reaching a booster pump, with the remaining 7012 gpm being served by the high-pressure pump. The booster pump will only need to supply 53 psi of additional pressure compared to the 629 psi required from the high pressure pump. In order to meet minimum discharge pressure required for proper PX operation, it is necessary for the feed streams to be pressurized to 30 psi so that the low pressure brine stream will exit at 15.9 psi.

====Post-Treatment Pumps====
Post treatment chemicals (sodium hypochlorite, sodium bicarbonate, calcium chloride, sodium hydroxide) are added to the permeate in order to remineralize and pH adjust our water. The pumps used to deliver these chemicals must simply overcome frictional losses in the pipe in order to keep the chemicals moving. All pumps were modeled at 80% efficiency.

===Chemical Storage Tanks===
Chemicals that are added to the water need to be stored beforehand. Chemical holding tanks were sized according to a day’s worth of chemicals. The holding tank for sodium bicarbonate is quite large and this is cause for concern. This issue could be corrected by introducing the solid chemical directly to the product stream rather than creating a solution, storing that solution and then mixing solutions. The cost of the holding tanks can be found in Appendix 12.

==Product Selling Price==
The San Diego County Water Authority agreed to pay Carlsbad (a plant of comparable size and location) $2014-2267 per acre foot of water depending on how much is purchased. [22] Based on this number we estimate that our yearly plant revenue will be roughly $25.4 million.

==Operating Costs==
The San Diego County Water Authority agreed to pay Carlsbad (a plant of comparable size and location) $2014-2267 per acre foot of water depending on how much is purchased. [22] Based on this number we estimate that our yearly plant revenue will be roughly $25.4 million.

==Capital Costs==
The overall capital costs of our plant are summarized below.
{| class="wikitable"
|-
! Project Sector
! Capital Cost (MM$)
|-
| Feedwater Intake and Concentrate Return
| 195.6
|-
| Desalination Facility
| 82.7
|-
| Product Water Conveyance
| 90.4
|-
| '''Subtotal'''
| '''368.7'''
|-
| Contingency
| 130.2
|-
| Working Capital
| 18.4
|-
| Implementation (Legal, Engineering, Administration)
| 84.3
|-
| '''Total'''
| '''601.7'''
|}

==NPV Analysis==
The economic viability of our desalination process was analyzed using a 25 year project lifetime. The cost of capital was set at 12% and the tax rate was set at 35%. A ten-year MACRS depreciation model was used.

The project was found overall to not be economically feasible on a purely commercial level. As revenues would only produce approximately $25.4 million per year the net present value after a project lifetime of 25 years remains extremely low at -$402.5 million. The full economic analysis can be found in Appendix 15.

==Optimization==
The primary opportunity for optimization within our process occurs in the management of the reverse osmosis process, with respect to the number of stages and the number of elements per stage used for our filtration. As a starting point we chose to use two stages and six elements per stage, as this is in-line with Dow Chemical Company’s product recommendations for the SW30XHR-440i RO membrane. Additionally, this is the typical configuration for large-scale RO plants using this particular Dow membrane such as the Carlsbad Desalination Plant. [24]

Using the Dow ROSA software, configurations were evaluated for one, two, and three sequential stages, ranging from four to eight elements per stage. Each of these process conditions was evaluated with respect to the capital costs of equipment as well as the yearly utility cost that would be required. The results of this optimization are summarized in Appendix 16, Table 16.1 and 16.2, with our starting condition and minimum highlighted in each.

This optimization was conducted using a desired recovery of 50%. The number of vessels total and number of vessels per stage were based on the maximum permeate flow for the RO membrane and sizing equations obtained from the Dow RO design guide, respectively. [18]

These data show a minimal variation between different configurations of our system, particularly compared with more dominant capital and operations cost throughout the remainder of our process. However, this process does find a minimum utility cost for the 1-stage, 8 element per stage configuration, at $80,000 per year less than our current setup. Additionally, the condition of a 2-stage, 4 element configuration has a lower utility cost--$60,000 per year less--with an equivalent capital cost. However, it was also observed in either alternative case that the initial element recovery percentage was 10-11%, rather than the 8% achieved in the original 2 stage, 6 element design. A lower recovery percentage indicates lower fouling rates and thus less frequent replacement of membranes, though this precise economic effect could not be quantified.

Based on the manufacturer and industry standard for reverse osmosis configuration, along with the minimal differences in total costs for alternatives and fouling concerns, the project chose to continue with the 2-stage, 6 element per stage configuration.

==Sensitivity Analysis==
Our process was found to be particularly sensitive to three main areas within capital costs, operating, costs, and revenue, which could have significant influence over the final economic analysis if the estimations are off by a significant margin or if the data used for these estimations changes significantly in the coming years.

===Capital Costs===
The construction of the project’s seawater intake/disposal pipeline is priced at approximately $200 million, making up about a third of total capital costs. It may be possible, rather than construct an entirely new water feed and disposal system, to draw used seawater from a nearby large-scale consumer and mitigate these construction costs greatly. For example, it is fairly common for desalination plants to use industrial cooling water effluent for their plants, whether it be as a feed or as a dilution measure, in order to significantly drive down capital costs.

===Operating Costs and Revenue===
The operating costs, while a small portion of total project expenses, consume more than a quarter of the plant revenue at $6.2 million per year. This is largely governed by the energy costs, which have been estimated at $0.08 per kilowatt-hour. A decrease in this cost would substantially decrease yearly operating cost and allow for greater profit.

Similarly, revenue is governed by the cost of water being paid to the Carlsbad Desalination Plant, at $2260 per acre-foot. [22] This price is expected to rise as the water shortage becomes more urgent and the population of California increases. A significant increase in this price could greatly help the desalination project to improve economic viability.

=Conclusion=

=References=

=Appendices=

==Appendix 1 - Plant Location Map==

==Appendix 2 - Posttreatment Water Quality Goals==

==Appendix 3 - Dissolved Ion Concentration of Seawater Inlet==

==Appendix 4 - Process Flow Diagram==

==Appendix 5 - Final Simulation Mass Balance and Stream Pressure==

==Appendix 6 - Stream Tables==

==Appendix 7 - Composition of Pass Streams from RO Process==

==Appendix 8 - Pumping Requirements==

==Appendix 9 - ERD Simulation==

==Appendix 10 - Example Diffuser System from Camp Pendleton Plant==

==Appendix 11 - Capital Cost==

[[File:11.1.PNG|center|600px|thumb|alt=|Table 11.1 Capital Cost breakdown.]]

==Appendix 12 - Holding Tank Costs==

[[File:12.1.PNG|center|600px|thumb|alt=|Table 12.1 Holding Tank Costs.]]

==Appendix 13 - Utility Calculations==

[[File:13.1.PNG|center|600px|thumb|alt=|Table 13.1 Utility calculations.]]

==Appendix 14 - Yearly Cost of Chemical Additions==

[[File:14.1.PNG|center|600px|thumb|alt=|Table 14.1 Chemical Addition Costs.]]

==Appendix 15 - Economic Analysis==

[[File:15.PNG|center|600px|thumb|alt=|Economic Analysis.]]

==Appendix 16 - Optimization==

[[File:16.1.PNG|center|600px|thumb|alt=|Table 16.1 Optimization of yearly utility for number of stages and elements per stage.]]

[[File:16.2.PNG|center|600px|thumb|alt=|Table 16.2: Optimization of yearly utility for number of elements per stage.]]

Desalination - Team D

2016-03-10T22:17:54Z

Taunins: /* Flowsheet */

Desalination - Team D

2016-03-10T22:15:49Z

Taunins: /* Technical Approach */

Desalination - Team D

2016-03-10T22:14:34Z

Taunins: /* Introduction */

Desalination - Team D

2016-03-10T22:14:01Z

Taunins: /* Executive Summary */

Utility systems

2016-02-22T01:35:10Z

Taunins: /* Utility Regeneration */

Authors: David Chen, [2014] Joshua Lee, [2015] Brett Sleyster, [2016] and Tom Aunins [2016] 

Stewards: David Chen, Jian Gong, and Fengqi You

Date Presented: January 13, 2014 /Date Revised: January 14, 2014

 


__TOC__

=Introduction=
Many chemical processes do not take place at ambient temperature or pressures. In order to reach these non-ambient conditions, utilities will have to be used to raise or lower temperatures and compress gases. (Towler, Towler/UOP) Utilities often contribute 5 to 10% of the price of a product, and may come from public or private utility companies or on-site plants. For purchased utilities, costs depend on consumption, while for company-owned utilities, there will be both capital and operating costs. They include things such as steam for heating, electricity, cooling water, refrigeration, fuels such as natural gas, wastewater treatment, waste disposal, and landfill. Steam is often the largest utility cost. Cogeneration unit can supply electricity accompanied with different steam pressures. (Seider 2009)

=Electricity=

Electricity is used to power many different kinds of equipment. It has many advantages: it is efficient (> 90%), reliable, available in a wide range of power, shaft speeds, designs, lifetimes, convenience, costs, and maintenance. It is generally used up to 200 hp, and sometimes over 10,000 Hp. In chemical process plants, the electricity demand is generally determined by the work or energy required for compression, pumping, air cooling, lights, and many other items. This electricity often times is purchased from local electricity providers, but many plants generate their own electricity via sophisticated processes.

Electricity is rarely used as a primary heat utility in large-scale chemical plants for a variety of reasons. The main disadvantages of using electricity as a heat utility are as follows (Towler 2012):

:*Heat from electricity is two to three times more expensive than heat from fuels. This is attributed to the lack of efficiency when creating heat from electricity.

:*Electrical heating units are expensive, require high maintenance, and must comply with strict safety regulations.

:*Electrical heating units are unsafe compared to steam heating units. In steam systems, the physically steam controls the temperature, whereas in electrical heating units temperature is controlled by temperature controllers, which can fail or burn out.

The use of electricity carries with it some hazards depending on the environment. Extra care must be taken when using electrically-powered equipment in areas which may have combustible fluids, vapors, or dust, and where liquids may be present. (Seider 2009 pg 606)

==Conventional Power Station==

In general, most electricity is generated from a conventional coal-fired process, whether it be on-site or purchased from a provider. Coal-fired processes have been used to create electricity throughout history, and technological advances have increased its efficiency and use worldwide. In a coal-fired steam station—much like a nuclear station—water is turned into steam, which in turn drives turbine generators to produce electricity. There are several variations on how to create energy from coal, but here are the basics of how a coal-fired process works:

[[File:coalfired.png|thumb|border|center|middle|upright=4|link=|atl=|General Coal-Fired Process Diagram (Duke Energy Company)]]

*Heat is created:
::Before the coal is burned, it is pulverized to the fineness of talcum powder. It is then mixed with hot air and blown into the firebox of the boiler. Burning in suspension, the coal/air mixture provides the most complete combustion and maximum heat possible.

*Water turns to steam:
::Highly purified water, pumped through pipes inside the boiler, is turned into steam by the heat. The steam reaches temperatures of up to 1,000 degrees Fahrenheit and pressures up to 3,500 pounds per square inch, and is piped to the turbine.

*Steam turns the turbine:
::The enormous pressure of the steam pushing against a series of giant turbine blades turns the turbine shaft. The turbine shaft is connected to the shaft of the generator, where magnets spin within wire coils to produce electricity.

*Steam is converted back to water:
::After doing its work in the turbine, the steam is drawn into a condenser, a large chamber in the basement of the power plant. In this important step, millions of gallons of cool water from a nearby source (such as a river or lake) are pumped through a network of tubes running through the condenser. The cool water in the tubes converts the steam back into water that can be used over and over again in the plant.

*Repeat:
::The cooling water is returned to its source without any contamination, and the steam water is returned to the boiler to repeat the cycle.

===Advantages & Disadvantages of Coal-Fired Energy Production===

[[File:coalfiredtable.png|thumb|border|center|middle|upright=4|link=|atl=|Advantages and Disadvantages of Coal-Fired Processes (Seider 2008)]]

==Gas-Turbine Cogeneration Process==

When generating energy on-site, many plants use a gas-turbine cogeneration process. The thermal efficiency of a gas-turbine process is in the range of 70-80% while conventional power stations, such as coal-fired processes, have a 30-40% efficiency. The lower efficiency in more conventional power stations is attributed to wasted heat in the exhaust steam in the condenser. One example of a gas-turbine process is outlined in the following figure. Figure 3.1 is a gas-turbine cogeneration process with a heat recovery steam generator (waste-heat) boiler.

[[File:cogeneration.png|thumb|border|center|middle|upright=4|link=|atl=|Gas-Turbine Cogeneration with a heat recovery steam generator boiler (Towler 2012 Fig 3.1)]]

Overall, the process illustrated is not much different from a coal-fired process. The main differences are that the cogeneration process creates both electricity and a heat utility, and cogeneration processes use natural gas instead of coal. Many of the advantages and disadvantages are similar to those of the coal-fired process, but the cogeneration has a much higher efficiency, creates heat to be used in another process, and uses a more volatile and expensive fuel. The main advantage of cogeneration over coal-fired energy production is that heat is not wasted. In coal-fired processes, heat is released and wasted during electricity generation. Cogeneration captures some, if not all of the byproduct for heat, which is an extremely useful utility that will be discussed in subsequent sections. In summary, the cogeneration plant is superior to the coal-fired process because of its higher efficiency and ability to create a useful heat utility.

Obviously any engineer would design the cogeneration plant to meet at least the energy requirement necessary for plant operation, but cogeneration plants often times are designed to exceed the plant electricity requirement to drive another source of capital. Many describe this scenario as a "make or buy" scenario (Towler 2012). This scenario provides chemical producers leverage when negotiating contracts with outsourced electricity providers and this allows plants to purchase electricity at a wholesale price. This is a huge advantage of considering on-site electricity production because electricity is needed in relatively high quantities for all chemical plants. Being able to minimize electricity costs, or even profit off of electricity production is a huge economical consideration that all plants employ.

=Process Heating=
The key objective of this section is to discuss how processes are heated. Heating utilities are necessary for proper usage of distillers, reactors, condensers, and several other integral types of equipment. More specifically, steam, fired heat, and hot oil/specialized heat transfer fluids will be discussed in the following subsections.

==Steam==
Steam is the most commonly used heat utility used in chemical plants, and as a result understanding how it is used is essential in the study of Utility systems. Steam is used both as a process fluid (feedstock, diluent to absorb heat of reaction, heating agent, and stripping agent in absorbers and adsorbers ) and utility. It can be used to drive pumps and compressors, ejectors (for producing a vacuum), and heat exchangers. As one can clearly see, steam is a versatile, and useful utility.

Here are a few advantages of using steam as opposed to other methods of process heating (Towler 2012):

:*By controlling the pressure of the steam, one can control the temperature at which the heat is released. Having a strong control over the temperature is essential in several processes. =
:*Steam is an efficient heat source because the heat of condensation of steam is very high. Meaning that there is is high output per mass of utility at a constant temperature.
:*Heat exchangers that use steam are relatively cheap because condensing steam has a high heat transfer coefficient.
:*Steam is nonflammable, nontoxic, and inert to several process fluids.

Chemical plants generally have a network of pipelines exclusively for providing steam. These networks generally have steam at a low pressure, a medium pressure, and a high pressure. The image below illustrates a basic steam system.

[[File:Steam.png|thumb|border|center|middle|upright=4|link=|atl=|(Towler 2012 Fig 3.2)]]

In the diagram above, boiler feed water at a high pressure is preheated and fed to other boilers. These other boilers superheat the steam to create a high pressure and high temperature steam stream. The steam is superheated past the dew point to account for heat loss in the pipelines. A portion of the high pressure steam is used for process heating in areas of the plant that require high temperatures. The rest of the high pressure steam is turned into medium pressure steam by valves and steam turbines. The medium pressure steam is then used to heat medium temperature processes and to form low pressure steam. The low pressure steam can be used to heat low pressure processes and it can be expanded in condensing turbines to create shaft work and energy. In summary, steam can be used for an innumerable amount of action items in a plant. High pressure, medium pressure, and low pressure steam can all be used as a heat source. Low pressure steam has utilities in creating electricity and it also has several other uses.

==Fired Heat==

In many cases, processes in a plant require a heat source stronger than high pressure and temperature steam. That is when fired heat is used, which is generally at temperatures above 523K. Streams can be heated directly in the furnace tubes or via a hot oil circuit or heat transfer fluid, which will be discussed in detail in the next section. Most fired heaters use natural gas as fuel because it burns cleaner than fuel oil. A cleaner burning fuel is always advantageous due to environmental and safety concerns. Furthermore, natural gases usually result in less wear and tear in burners and fuel lines.

Depending on the application of the fired-heater, different design specifications can be implemented to make the fired-heater as efficient as possible. The basic construction of a fired heater starts with a cylindrical chamber that is lined with with refractory bricks. The stream that is to be heated flows through tubes inside of the furnace. These tubes can be arranged in several different arrangements such as, around the walls of the furnace, or in horizontal or vertical banks (Towler 2012). The figure below illustrates the basic construction of the fired-heater and varying tube arrangements.

[[File:firedheater.png|thumb|border|center|middle|upright=4|link=|atl=|Basic Fired-Heater Diagrams (Towler 2012 Figure 19.66)]]

Fuel is burned to heat the entire furnace, and the heat transfer occurs from the combustion gases inside of the furnace across the tubes that are filled with our desired stream. The heat transfer between the tubes and the furnace is accomplished primarily via radiation. Modern designs take advantage of convective heat transfer by adding a smaller section on top of the fired-heater where the combustion gases flow over banks of tubes as seen in (c) in the figure above. Heat transfer can be further improved via convection by adding fins or pins in the combustion section.

The cost of fired heat can be calculated by the cost of fuel fired. Natural gas and heating oil are traded as commodities and prices can be found at many online trading sites or business news sites (i.e., www.cnn.money.com). Past historic prices for forecasting can be found in the Oil and Gas Journal or from the U.S. Energy Information Adminstration (www.eia.gov).

===Fuels===
Fuel is burned in utility facilities such as boilers, electricity generation, and cogeneration, and can be in solid, liquid, or gas form. It can also be burned to provide heating for a process or stream or to drive pumps and compressors. The fuel is usually burned with excess air to ensure complete combustion.

A way of quantifying the amount of heat generated is by using the heating values. Higher heating value (HHV) and the lower heating value (LHV) are used. The heating is the total heat evolved by complete combustion of a fuel with dry air with both at 60 ⁰F and the flue gas after combustion brought back down to ⁰F. If the water vapor in the flue gas is not condensed, we obtain the LHV. If the water vapor is condensed, the value of heat evolved is a bit higher, and this is the HHV.
Heating values for solids and liquids are usually on a per-mass basis, and gases on a per-volume basis.
A specified amount of heating cannot be met with the amount of fuel calculated using only the HHV. There will be heat losses, the flue gas temperature will be greater than 60 ⁰F, and water in the flue gas will typically be vapor. (Seider 608)

==Hot Oil/Specialized Heat Transfer Fluids==

Specialized heat transfer fluids and hot oil circuits are used as heat sources when steam and fired heat is not appropriate. Specialized heat transfer fluids and hot oil circuits are extremely versatile in that they can be used in the temperature range of 323K to 673K. This range however is quite variable. For hot oils, the upper temperature limit is gauged based off of the thermal decomposition of the oil and coking/fouling of heat exchanger tubes.

Hot oil circuit systems are most commonly used when the plant has several small temperature heating requirements because it is more economically sound. Rather than having several fired heaters heat each small temperature requirement, it is much more economical to have one fired heater heat the hot oil and circulate that oil through each of the process to meet all of the heat needs. Hot oil systems are also generally favored over high pressure steam in processes that involve high pressure differentials between the process stream and high pressure steam. Hot oil systems are favored in this scenario because of safety concerns. If the steam were to leak, the pressure drop could cause serious safety issues.

Mineral oils are the most commonly used heat transfer fluids, and one prominent example is Dowtherm A. Dowtherm A is a combination of 26.5 wt% diphenyl in diphenyl oxide (Towler 2012) and is extremely thermally stable. These mineral oil systems generally require high flow rates.

=Process Cooling=

==Cooling Water==
Cooling water is used to cool and/or condense streams. Cooling water is usually circulated between process heat exchangers and a cooling tower. Water is cooled during downward motion by contact with air blown upwards, which can bring the water temperature to come within ~ 5 ⁰F of air’s wet-bulb temperature.Approximately 80% of the temperature reduction is due to evaporation of the cooling water and heat transfer to the surrounding air. Water can also be cooled in spray ponds and cooling ponds. Both work by providing high area for water to exchange heat with air.
Water in cooling towers is lost through drift and blowdown, and makeup is usually 1.5 to 3% of the circulating rate.
If a large natural body of water is nearby, it can be used as a source of cooling water and discharged downstream. This water is usually filtered to remove salts and impurities that may lead to fouling, but it is not treated.

==Refrigeration==
Cooling water can usually be used to cool a stream to ~ 100 ⁰F. Air can only cool to ~ 120 ⁰F. Air may be used in places where water is scarce or more costly to transport. To cool or condense streams below 100 ⁰F, a refrigerant is typically used. Chilled brine can also be used, but is less common.

Until 1995, CFC Freon R-12 (dichlorodifuloromethane) and HCFC Freon R-22 (chlorodifuloromethane) were commonly used refrigerants. However, the chlorine atom in the molecules caused the depletion of the ozone layer. The U.S. Clean Air Act Amendments of 1990 went into effect in 1995, and the production of these refrigerants has since stopped or been greatly reduced.

Cost estimates are based on ton-day of refrigeration, where a ton is the heat that needs to be removed to freeze 1 ton per day of water at 32 ⁰F. Substitutes have since been developed. R-134a is often used in place of R-12. According to the EPA, R-134a is not combustible at ambient conditions, and is essentially non-toxic under 400 ppm, and is not ozone-depleting. (Seider pg 607)

=Energy Efficiency=
One of the chief concerns in selecting and designing process utility systems for heating and cooling is how to achieve the most energy efficient design. There are countless means by which plants lose energy, two of the foremost being through the mixing of different temperature or pressure streams and through the disposal of warmed cooling water. (Seider, 2009) Proper utilities design can help mitigate each of these losses as well as many others. The energy efficiency of a plant will depend primarily on the heating and cooling methods that are being used and the overall system design itself. These two parameters are important in determining how well energy is transferred to the desired media as well as how well that energy is recovered and recycled.

==Hot Utility Efficiency==
As mentioned above, the most commonly used utilities for process heating in large scale processes are steam, fired heat, and hot oil heaters. Of these, steam is the most commonly used. Electricity, while efficient at creating power, is not a viable source of heat in large industrial processes. Common ranges of heating efficiency for these three methods are displayed in Table 1. (Towler and Sinnott, 2012; Broughton, 1994)

{| class="wikitable"
|+Table 1: Process Heating Efficiencies
|-
! Process Heating Method
! Typical Efficiency
|-
| Steam (via coal boiler)
| 72%
|-
| Steam (via gas boiler)
| 73%
|-
| Steam (via oil boiler)
| 75%
|-
| Fired Heat w/ Convective Section
| 85%
|-
| Fired Heat w/o Convective Section
| 60%
|-
| Hot Oil Heaters/Vaporizers
| 80-85%
|}

===Steam===
As steam is so popular for heating purposes, it is useful to analyze the numerous ways in which losses can occur in steam systems. There are five primary sources of inefficiency and heat loss in the generation and distribution of steam throughout a process plant:

*The heat content of boiler exhaust gas
*Incomplete combustion of boiler fuel
*Radiant losses from the boiler exterior
*Blowdown losses
*Distribution losses (pipe transport, steam traps, etc.)

The first four of these losses take place at the boiler and contribute to the heating efficiencies seen in Table 1 for steam created with coal, gas, and oil. Several methods can be used to minimize these losses, one of the foremost being the control of air-to-fuel ratio in the boiler. This ratio must be managed by weighing losses due to uncombusted fuel against losses due to the heat content of excess exhaust gas. (Broughton, 1994)

[[File:Air-fuel ratio.PNG|thumb|border|center|middle|upright=4|link=|atl=|Air-to-fuel ratio relationship with heat losses (Broughton Fig 2.3)]]

The air-to-fuel ratio can be optimized using a feedback process controller. The control system will analyze the oxygen content of exhaust air and adjust the incoming air flow rate to achieve a set percentage of excess air. While desired excess oxygen will vary depending on the type of fuel, it is consistently seen that in the minimum loss-range a 1% increase in excess air will result in a 1% decrease in efficiency. ("Oxygen Control")

In addition to air-to-fuel ratio management, steam heat losses at the boiler can be mitigated via energy recovery, which is discussed in further detail [[Utility_systems#Energy_Recovery|below]].

Outside the boiler, losses in distribution of steam throughout facilities can decrease energy efficiency by a significant amount. This can cause up to a 60% increase in losses, but typically results in an overall steam efficiency of 50-55% (down from approximately 75% at the boiler). (Broughton, 1994) There are several ways that this issue can be addressed. First and foremost are steam metering systems, which can be used to monitor heat supply to separate sections of the process facility, check efficiency of fuel use, and determine which processes in a given plant have the highest steam requirements. Another method of minimizing transport losses is to decentralize steam generation systems. It can be advantageous to have numerous smaller boilers rather than a single centralized boiler so that steam does not have to travel as long of distances to reach its destination.

==Cold Utility Efficiency==
Efficiency in cooling processes depends more on the method used, and by extension the amount of coolant needed. Water and air utility efficiencies depend primarily on the fluid flow required to maintain the system at a desired temperature, while powered refrigeration utilities (for colder processes) have efficiencies at approximately 60%--but ranging up to 90%--of Carnot cycle efficiency, a metric of ideal refrigeration efficiency. (Towler and Sinnott, 2012) Cooling systems represent by definition a loss of energy from the main process to the utility stream, and as such it is often useful to find other uses for the heated media before discharge.

==Energy Recovery==
Recovery and recycle of energy is perhaps the most important aspect of creating an energy efficient plant design, and it is important for process engineers to fully consider possibilities for heat recovery in order to aid in economic viability.

===Process Heat Exchange===
Heat exchanger networks are a very common energy recovery method in industrial processes. These networks most frequently allow energy from heated product streams to be transferred to feed streams that must be brought up to process temperature. (Biegler, 1997) More information on the function and design of heat exchanger networks can be found on the [[Heat_exchanger#Heat_Exchanger_Networks|heat exchanger wiki page]]. The following are several examples of energy recovery via heat exchange that are used in industrial processes.

In distillation columns the bottoms and distillate effluents have the potential for energy exchange. Though the condenser at the top of the column cannot supply its waste heat to the reboiler due to their respective temperatures, the effluent streams can supply heat to the feed via a feed-effluent exchanger. This reduces the utility requirements to raise the feed to column temperature. (Biegler, 1997)

[[File:Feed_sterilization.jpg|thumb|border|right|middle|upright=4|link=|atl=|Feed sterilization schematic. (Towler and Sinnott Fig. 3.30)]]

Feed sterilization, commonly used in the food industry, is a common application for heat recovery through process stream heat exchange. In this application, the feed must be heated for a certain amount of time to kill any biological contaminants, after which it can be used to heat the new raw feed for sterilization. This reduces energy demands on the steam heater and thus reduces cost. (Towler and Sinnott, 2012)

In multi-vessel batch processes it can be advantageous to exchange heat as the process fluid is being transferred between vessels. Like the previous examples, this reduces the utility needed to bring the colder feed up to process temperature, thus reducing costs. (Towler and Sinnott, 2012)

[[File:Batch_heat_exchange.jpg|thumb|border|center|middle|upright=4|link=|atl=|Multi-vessel batch heat exchange schematic (Towler and Sinnott Fig. 3.31)]]

===Utility Regeneration===
[[File:Waste_heat_boiler.jpg|thumb|border|right|middle|200px|upright=4|link=|atl=|Industrial modular HRSG]]
When recovery of waste heat via transfer to other process streams is inconvenient or impossible, energy efficiency can still be improved through the regeneration of utilities. This is commonly done through the regeneration of steam by removing heat from exiting streams or from highly exothermic reactions. Waste heat in exiting streams can be removed via heat recovery steam generators (HRSGs), and is most often used on exiting gas streams. Heat recovery from reactions is a viable option when the reactor temperature will be at 150 C or above, as this will create steam at high enough pressure to be used in other processes. (Towler and Sinnott, 2012)

In the case of steam, waste heat and water treatment losses can be recovered from the utility generation process itself. One of the most common ways to do this is with an economizer. As seen in the schematic below, economizers have heat exchangers fit to the exhaust gas flow in order to transfer waste heat from these gases to the incoming boiler feed water. This can result in fuel energy savings of approximately 15% for typical excess air percentages in steam boilers. (Broughton, 1994; "Economizers")

[[File:Economizer.png|thumb|border|center|middle|upright=4|link=|atl=|Economizer schematic ("Economizers") and economizer energy recovery correlations (Broughton Fig 2.2)]]

[[File:Condensate recycle.PNG|thumb|border|right|middle|200px|upright=4|link=|atl=|Condensate return fuel savings (Broughton Fig 2.4)]]

Additionally, there are still more opportunities for recovery in steam generation processes. One typical case is the use of waste heat to preheat air entering the boiler. Optimistically, this can result in a 5% improvement in heat recovery for the system. Another method is the recycle of steam condensate back to the boiler. This has two main benefits: it retains the heat still present in the condensed steam and it retains the pretreatment chemicals added to the steam. (Broughton, 1994)

Furthermore, there is opportunity for energy recovery in the expansion of compressed gas through a turbine to create electricity, a process that can be economically viable given sufficiently high flows or pressure. One of the primary application of this type of energy recovery is in the creation of medium pressure and low pressure steam. In most processes, all steam is generated as high pressure steam and can be expanded through a turbine to decrease its pressure. Such technology has also been used in processes to synthesize ammonia, perform air separations, and synthesize nitric acid. (Towler and Sinnott, 2012) Recently, however, there has been a particularly strong interest for energy recovery in the natural gas industry, when gas is decompressed from major pipelines to residential low-pressure pipelines. A 2001 study estimated that there is the potential to recover 21 TWh, representing 11% of natural gas transport energy, via gas expansion. (Lehman)

=Process water and boiler-feed water=
Process water is water that will be directly used in the process. Boiler-feed water (BFW) is used to produce steam. Both may need to be purified to prevent impurities from contaminating a process or from foul equipment. It can be used as a cooling stream when the temperature of the stream to be cooled is greater than ~300 ⁰F. Cost of BFW can be partially offset by the steam credit.

Process water that undergoes moderate pretreatment can cost ~ $0.75/1,000 gal.

Extensive treatment ~ $6.00/1,000 gal.

Sterilized for pharmaceutical processes ~ $550/1,000 gal. (Seider pg 608)

=Demineralized Water=
In demineralized water, minerals have been removed by ion exchange. In boiler feed water, this is to prevent salt deposition, corrosion, formation of foam, and sluicing. In process water, the ions may contaminate the process.

=Waste Treatment=
Most chemical processes will produce some sort of waste. Disposal occurs to the atmosphere (in the case of some gases), sewers, body of water, or a landfill. Waste may require some treatment before disposal to meet regulations. Depending on process economics, byproducts may be recovered and processed. (Seider 2009 pg 609)

==Wastewater Treatment==
The United States EPA regulates industrial wastewater disposal through the Clean Water Act, introduced in 1948 as the Federal Water Pollution Control Act and amended to its current form in 1972. The sweeping 1972 amendments allowed the EPA to prevent industries and persons from discharging contaminated water into fresh water sources and set water quality standards. (Summary of the Clean Water Act) In accordance with this law, process plants in the United States treat wastewater at on-site or near-site treatment centers before releasing it into the surrounding environment.

Wastewater effluent streams, along with water runoff from around the plant, are treated to control for pH, toxicity, suspended solids, and biological oxygen demand (for aquatic life protection) prior to discharge. Each of these controls is typically addressed with a separate method. Acidity and basicity is balanced through the addition of an acid or alkaline solution. Toxic wastewater may be treated with chemical processes or simply diluted to safe concentrations. Suspended solids can be removed via filtration and/or with clarifiers. Oxygen demand of wastewater can be mitigated using activated sludge treatment processes. Once the water quality complies with the EPA, and state-mandated, regulations, it can be safely released. More information on the large number of industry-specific guidelines for waste effluent can be found on the EPA website (http://www.epa.gov/eg/industrial-effluent-guidelines).

==Air-Pollution Management==
===Introduction===

In the United States air pollution is regulated in the Clean Air Act, and almost all pollutant emitting plants are regulated under this law. The types of plants that can release significant emissions include petroleum refineries, sulfur recovery plants, carbon-black plants, fuel conversion plants, chemical process plants, fossil fuel plants, and petroleum storage and transfer facilities. To receive permission to construct a plant must undergo a review to show that it will not cause a violation of the Ambient Air Quality Standards(Peters, 2003).

===Methods===

There are two major types of pollutants that are released into the air, particulates and and gaseous pollutants. Particulates can be removed with mechanical forces while gaseous pollutants typically need to removed by chemical or physical means (Peters, 2003).

Particulates and volatile pollutants that need to be removed before disposal may be present. Particle removal equipment includes: cyclones, wet scrubbers, electrostatic precipitators, and fabric-filter systems (Seider 2009) such as bag filters (. The two charts below are from ''Plant Design and Economics for Chemical Engineers'' and show the types of equipment, separation methods, and particle sizes in different pollutant separation technologies (Peters, 1991).

[[File:AirPolChart.png|thumb|border|center|middle|upright=4|link=|atl=|Different Methods of Particle Separation, the Particle Sizes they Can Remove, and the Technologies Used]]

[[File:AirPolTable.png|thumb|border|center|middle|upright=4|link=|atl=| This Chart Shows the Specifications and Limitations of Different Separations Technologies Including Particle Size, Efficiencies, and Temperatures(Peters, 1991)]]

====Wet Scrubbers====
Wet scrubber use lime or limestone and water to remove SO2 and acid gases. The mixture can be injected into a scrubber or the gases can be bubbled through this mixture. This results in removal of 90-98% of SO2 and and acid gases (Clean Coal Technologies).

====Dry Scrubbers====
Dry scrubber blow powdered adsorbents into a vessel with gases and then after it has captured the SO2 and acid gases it is separated from gas using a fabric filter. These systems remove 90-93% of the contaminants (Clean Coal Technologies).

====Low-NOx Burners====
The purpose of low NOx burners is to decrease the amount of NOx created when the coal is burned. This is done by injecting coal and air in boilers. This can result in 40-50% NOx reduction. If air is injected into the area above the burner this can actually cause almost 70% NOx reduction (Clean Coal Technologies).

====Selective Non-Catalytic and Catalytic Reductions====
These systems inject ammonia into gases to remove NOx. The Catalytic reductions add a catalyst to the ammonia being injected to aid in the removal. Con-catalytic reductions result in about 35% removal, but adding a catalyst can increase that amount to about 90%. The catalytic-reduction can remove up to 80% of mercury as well (Clean Coal Technologies).

====Fabric Filters====
Also known as baghouses,these [[Separation processes#Filtration| filters]] remove particulates by passing air through filters. These can separate as much as 99.9% of particulate matter (Clean Coal Technologies).

====Electrostatic Precipitators====
Electrostatic Precicpitators remove particulate matter as gas passes through a device that has charged metal plates. The particles are then removed because of static electricity. These systems can remove between 99-99.9% of particulate matter (Clean Coal Technologies).

====Super-critical Boilers====
Super-Critical Boilers and Ultra-Supercritical Boilers operate at temperature and pressure higher than regular boilers. By operating at higher temperature these systems become more efficient. Super Critical Boilers typically have 10%-20% CO2 emissions than other similar sub-critical technologies. Ultra-Supercritical boilers can be as much as 30% more efficent than sub-critical technologies (Clean Coal Technologies).

====More Information====

For more information regarding some of these separations equipment see [[Solids-involved equipment]]

For more information Regarding Cyclones see [[Separation processes#Cyclones| Cyclones]], and for modeling cyclones see their[[Solids-involved equipment#HYSYS Simulation|HYSYS Simulation]]

Methods for removing inorganic and organic gaseous pollutants include: absorption, adsorption, condensation, and combustion (Seider 2009 pg 609). A list of typical of gases pollutants and their sources from ''Plant Design and Economics for Chemical Engineers'' is shown below (Peters, 1991).

[[File:GaseousPollutants.png|thumb|border|center|middle|upright=4|link=|atl=| Common Gaseous Pollutants and their Sources]]

Typically Gas-liquid absorption processes are done completed in a vertical, countercurrent, flow through packed, plate, or spray towers. These systems require good liquid-gas contact and proper equipment. These systems also often have significant energy consumption because of large pressure drops (Peters, 2003). For high volume systems absorption by scrubbing with water or another solvent is the most widely used method (Towler, 2012). Dry adsorbents can be used to remove the last races of gaseous pollutants. Adsorption typically requires blowers, condensers, separators, and controls. You also typically need two packed beds so that one can be used while the other is regenerated. Examples of adsorbents are molecular sieves and activated carbon. Incineration is typically used when there are gas streams that have no recovery value. This can be done with direct flame or catalytic oxidation. Catalytic oxidation usually has higher capital costs, but lower operating costs because it does not require fuel.

You can find more information on [[Separation processes#Absorption| Absorption]] and [[Separation processes#Adsorption| Adsorption]] in [[Separation processes]]

===Outcomes===

====United States Common Pollutant Emissions====

The United States implemented the Clean Air Act in 1970 and since then emissions in the U.S. have been drastically reduced. As a matter of fact despite increases in the population in the last 35 years the amount of pollutants emitted have decreased by almost 70% (EPA). More importantly this demonstrates that reasonable efforts can be put towards environmental protection without causing too much harm to industry.

[[File:EPA.png|thumb|border|center|middle|upright=4|link=|atl=| GDP and Other Growth Factors Vs Common Pollutants Released]]

====China Clean Coal====

=====Success Through 2005=====

Coal is a very inexpensive and abundant source of energy and is abundant in China (Xu 2010). In China Coal the cause of 90% of SO2 emissions, 70% of dust emissions, and 67% of NOx emissions, and 70% of CO2 emissions. These numbers are staggering considering that Coal has never been more than 50 percent of China's Energy Supply (Xu 2010).

[[File:Coal.jpg|thumb|border|center|middle|upright=4|link=|atl=| Coal Consumption for Power and the Percentage of Coal Used (Xu 2010)]]

Despite the increasing coal consumption, high efficiency electric dust removal systems with efficiencies that are as high as 99.6% have greatly decreased soot emissions to 32% below 1980's levels as of 2005.

[[File:Soot.jpg|thumb|border|center|middle|upright=4|link=|atl=| SO2 and Soot Emissions from 1981 to 2005 (Xu 2010)]]

=====Technologies and Life Cycle Comparison=====
As of 2010 China was consuming 48.2% of coal globally. Four potential technologies integrated gasification combined cycle (IGCC), sub-critical coal power generation (Sub-C); super-critical coal power generation (Super-C) ultrasuper-critical coal power generation (USC). These technologies are compared mostly on the basis of net generating efficiency and efficiency. Net generating efficiency is the output of the plant divided by the total available energy in the fuel used (Liang, 2013).

where efficiency is define as: η=E/Etotal

and

Etotal=Emining+Etransportation+Egeneration

[[File:technologies.PNG|thumb|border|center|middle|upright=4|link=|atl=|A comparison of many of the parameters important to lfe-cycle analysis (Liang, 2013)]]

This demonstrates that USC has the best net generation efficiency, while also having the largest capacity for a single system.

[[File:Lifecycle2.PNG|thumb|border|center|middle|upright=4|link=|atl=| (Liang, 2013)]]

This breaks down the energy efficiency of each system and demonstrates that USC is the most efficient

[[File:Lifecycle.PNG|thumb|border|center|middle|upright=4|link=|atl=| (Liang, 2013)]]

This demonstrates that the capital cost per unit of energy production is very high for IGCC, but shows that Super-C and USC are very competitive.

[[File:Price.PNG|thumb|border|center|middle|upright=4|link=|atl=| Capital cost in $/kW of clean coal power-generation technologies (Liang, 2013)]]

Lastly IGCC and USC are lowest on different element, but since these all have different global warming potential it is difficult to tell which is the most efficient.

And the table below defines all the relevant terms.

[[File:GWP.PNG|thumb|border|center|middle|upright=4|link=|atl=| Environemntal measures and their explanations (Liang, 2013)]]

All of the data suggests that USC is the highest in both energy efficiency and net generating efficiency while competitive in price and the lowest on emissions among the different boilers.

==Solid Waste==
U.S. federal regulations require that solid waste be classified as hazardous or nonhazardous. Conditions for a classification of hazardous include: ignitability, corrosivity, reactivity, toxicity, or posing a substantial threat to the surrounding environment and its inhabitants. Hazardous waste must be treated on- or near-site before being removed in containers. Non-hazardous waste may be landfilled or incinerated in some cases. A typical estimate of costs for waste disposal is $0.03/lb for nonhazardous solids and $0.10/lb for hazardous solids. (Seider 2009 pg 609)

=References=

*Biegler LT, Grossmann IE, Westerberg AW. ''Systematic Methods of Chemical Process Design'' Prentice-Hall: Upper Saddle River, 1997.

*Broughton, J. ''Process Utility Systems: Introduction to Design, Operation and Maintenance'' Institution of Chemical Engineers: Rugby, Warwickshire, UK, 1994.

*Clean Coal Technologies. America's Coalition for Clean Coal Electricity. http://www.americaspower.org/clean-coal-technologies-1663/

*Duke Energy Company (2013). How Do Coal Fired Plants Work? Charlotte: Duke Energy.

*"Economizers." Energy Solutions Center Inc.: Boiler Consortium. http://www.cleanboiler.org/Eff_Improve/Efficiency/Economizers.asp. Accessed February 21, 2016.

*Lehman B, Worrell E. ''Electricity Production from Natural Gas Pressure Recovery Using Expansion Turbines.'' Lawrence Berkeley National Laboratory; 2001.

*"Overview of the Clean Air Act and Air Pollution." Environmental Protection Agency. November 17, 2015. http://www.epa.gov/clean-air-act-overview. Accessed February 5, 2016.

*"Oxygen Control." Energy Solutions Center Inc.: Boiler Consortium. http://www.cleanboiler.org/Eff_Improve/Efficiency/Oxygen_Control.asp. Accessed February 21, 2016.

*Peters, Max S.; Timmerhaus, Klaus D.; West, Ronald E. (2003). " Plant Design and Economics for Chemical Engineers." McGraw Hill Higher Education.

*Ruina Xu Energy (2010). "Clean coal technology development in China." Elsevier.

*Seider, Seader, Lewin, Widagdo. (2009). ''Plant Design and Economics for Chemical Engineers, 5th Edition.'' Hoboken: Wiley.

*Seider, Seader, Lewin. (2008). ''Product and Process Design Principles, 2nd Edition.'' Hoboken: Wiley.

*Summary of the Clean Water Act. United States EPA website. http://www.epa.gov/laws-regulations/summary-clean-water-act

*Towler, G.P. and Sinnot, R. (2012). ''Chemical Engineering Design: Principles, Practice and Economics of Plant and Process Design.'' Elsevier.

*Turton R.; Bailie, R.C.; Whiting, W.B.; Shaeiwitz J.A.; Bhattacharyya D. (2012). ''Analysis, Synthesis, and Design of Chemical Processes.'' Upper Saddle River: Prentice Hall.

*G.D. Ulrich, A Guide to Chemical Engineering Process Design and Economics, Wiley: New York, 1984.

*Xiaoye Liang, Zhihua Wang, Zhijun Zhou, , Zhenyu Huang, Junhu Zhou, and Kefa Cen. (2013). "Up-to-date life cycle assessment and comparison study of clean coal power generation technologies in China" Elsevier.

File:Condensate recycle.PNG

2016-02-22T01:25:08Z

Taunins:

Utility systems

2016-02-22T01:18:39Z

Taunins: /* References */

Authors: David Chen, [2014] Joshua Lee, [2015] Brett Sleyster, [2016] and Tom Aunins [2016] 

Stewards: David Chen, Jian Gong, and Fengqi You

Date Presented: January 13, 2014 /Date Revised: January 14, 2014

 


__TOC__

=Introduction=
Many chemical processes do not take place at ambient temperature or pressures. In order to reach these non-ambient conditions, utilities will have to be used to raise or lower temperatures and compress gases. (Towler, Towler/UOP) Utilities often contribute 5 to 10% of the price of a product, and may come from public or private utility companies or on-site plants. For purchased utilities, costs depend on consumption, while for company-owned utilities, there will be both capital and operating costs. They include things such as steam for heating, electricity, cooling water, refrigeration, fuels such as natural gas, wastewater treatment, waste disposal, and landfill. Steam is often the largest utility cost. Cogeneration unit can supply electricity accompanied with different steam pressures. (Seider 2009)

=Electricity=

Electricity is used to power many different kinds of equipment. It has many advantages: it is efficient (> 90%), reliable, available in a wide range of power, shaft speeds, designs, lifetimes, convenience, costs, and maintenance. It is generally used up to 200 hp, and sometimes over 10,000 Hp. In chemical process plants, the electricity demand is generally determined by the work or energy required for compression, pumping, air cooling, lights, and many other items. This electricity often times is purchased from local electricity providers, but many plants generate their own electricity via sophisticated processes.

Electricity is rarely used as a primary heat utility in large-scale chemical plants for a variety of reasons. The main disadvantages of using electricity as a heat utility are as follows (Towler 2012):

:*Heat from electricity is two to three times more expensive than heat from fuels. This is attributed to the lack of efficiency when creating heat from electricity.

:*Electrical heating units are expensive, require high maintenance, and must comply with strict safety regulations.

:*Electrical heating units are unsafe compared to steam heating units. In steam systems, the physically steam controls the temperature, whereas in electrical heating units temperature is controlled by temperature controllers, which can fail or burn out.

The use of electricity carries with it some hazards depending on the environment. Extra care must be taken when using electrically-powered equipment in areas which may have combustible fluids, vapors, or dust, and where liquids may be present. (Seider 2009 pg 606)

==Conventional Power Station==

In general, most electricity is generated from a conventional coal-fired process, whether it be on-site or purchased from a provider. Coal-fired processes have been used to create electricity throughout history, and technological advances have increased its efficiency and use worldwide. In a coal-fired steam station—much like a nuclear station—water is turned into steam, which in turn drives turbine generators to produce electricity. There are several variations on how to create energy from coal, but here are the basics of how a coal-fired process works:

[[File:coalfired.png|thumb|border|center|middle|upright=4|link=|atl=|General Coal-Fired Process Diagram (Duke Energy Company)]]

*Heat is created:
::Before the coal is burned, it is pulverized to the fineness of talcum powder. It is then mixed with hot air and blown into the firebox of the boiler. Burning in suspension, the coal/air mixture provides the most complete combustion and maximum heat possible.

*Water turns to steam:
::Highly purified water, pumped through pipes inside the boiler, is turned into steam by the heat. The steam reaches temperatures of up to 1,000 degrees Fahrenheit and pressures up to 3,500 pounds per square inch, and is piped to the turbine.

*Steam turns the turbine:
::The enormous pressure of the steam pushing against a series of giant turbine blades turns the turbine shaft. The turbine shaft is connected to the shaft of the generator, where magnets spin within wire coils to produce electricity.

*Steam is converted back to water:
::After doing its work in the turbine, the steam is drawn into a condenser, a large chamber in the basement of the power plant. In this important step, millions of gallons of cool water from a nearby source (such as a river or lake) are pumped through a network of tubes running through the condenser. The cool water in the tubes converts the steam back into water that can be used over and over again in the plant.

*Repeat:
::The cooling water is returned to its source without any contamination, and the steam water is returned to the boiler to repeat the cycle.

===Advantages & Disadvantages of Coal-Fired Energy Production===

[[File:coalfiredtable.png|thumb|border|center|middle|upright=4|link=|atl=|Advantages and Disadvantages of Coal-Fired Processes (Seider 2008)]]

==Gas-Turbine Cogeneration Process==

When generating energy on-site, many plants use a gas-turbine cogeneration process. The thermal efficiency of a gas-turbine process is in the range of 70-80% while conventional power stations, such as coal-fired processes, have a 30-40% efficiency. The lower efficiency in more conventional power stations is attributed to wasted heat in the exhaust steam in the condenser. One example of a gas-turbine process is outlined in the following figure. Figure 3.1 is a gas-turbine cogeneration process with a heat recovery steam generator (waste-heat) boiler.

[[File:cogeneration.png|thumb|border|center|middle|upright=4|link=|atl=|Gas-Turbine Cogeneration with a heat recovery steam generator boiler (Towler 2012 Fig 3.1)]]

Overall, the process illustrated is not much different from a coal-fired process. The main differences are that the cogeneration process creates both electricity and a heat utility, and cogeneration processes use natural gas instead of coal. Many of the advantages and disadvantages are similar to those of the coal-fired process, but the cogeneration has a much higher efficiency, creates heat to be used in another process, and uses a more volatile and expensive fuel. The main advantage of cogeneration over coal-fired energy production is that heat is not wasted. In coal-fired processes, heat is released and wasted during electricity generation. Cogeneration captures some, if not all of the byproduct for heat, which is an extremely useful utility that will be discussed in subsequent sections. In summary, the cogeneration plant is superior to the coal-fired process because of its higher efficiency and ability to create a useful heat utility.

Obviously any engineer would design the cogeneration plant to meet at least the energy requirement necessary for plant operation, but cogeneration plants often times are designed to exceed the plant electricity requirement to drive another source of capital. Many describe this scenario as a "make or buy" scenario (Towler 2012). This scenario provides chemical producers leverage when negotiating contracts with outsourced electricity providers and this allows plants to purchase electricity at a wholesale price. This is a huge advantage of considering on-site electricity production because electricity is needed in relatively high quantities for all chemical plants. Being able to minimize electricity costs, or even profit off of electricity production is a huge economical consideration that all plants employ.

=Process Heating=
The key objective of this section is to discuss how processes are heated. Heating utilities are necessary for proper usage of distillers, reactors, condensers, and several other integral types of equipment. More specifically, steam, fired heat, and hot oil/specialized heat transfer fluids will be discussed in the following subsections.

==Steam==
Steam is the most commonly used heat utility used in chemical plants, and as a result understanding how it is used is essential in the study of Utility systems. Steam is used both as a process fluid (feedstock, diluent to absorb heat of reaction, heating agent, and stripping agent in absorbers and adsorbers ) and utility. It can be used to drive pumps and compressors, ejectors (for producing a vacuum), and heat exchangers. As one can clearly see, steam is a versatile, and useful utility.

Here are a few advantages of using steam as opposed to other methods of process heating (Towler 2012):

:*By controlling the pressure of the steam, one can control the temperature at which the heat is released. Having a strong control over the temperature is essential in several processes. =
:*Steam is an efficient heat source because the heat of condensation of steam is very high. Meaning that there is is high output per mass of utility at a constant temperature.
:*Heat exchangers that use steam are relatively cheap because condensing steam has a high heat transfer coefficient.
:*Steam is nonflammable, nontoxic, and inert to several process fluids.

Chemical plants generally have a network of pipelines exclusively for providing steam. These networks generally have steam at a low pressure, a medium pressure, and a high pressure. The image below illustrates a basic steam system.

[[File:Steam.png|thumb|border|center|middle|upright=4|link=|atl=|(Towler 2012 Fig 3.2)]]

In the diagram above, boiler feed water at a high pressure is preheated and fed to other boilers. These other boilers superheat the steam to create a high pressure and high temperature steam stream. The steam is superheated past the dew point to account for heat loss in the pipelines. A portion of the high pressure steam is used for process heating in areas of the plant that require high temperatures. The rest of the high pressure steam is turned into medium pressure steam by valves and steam turbines. The medium pressure steam is then used to heat medium temperature processes and to form low pressure steam. The low pressure steam can be used to heat low pressure processes and it can be expanded in condensing turbines to create shaft work and energy. In summary, steam can be used for an innumerable amount of action items in a plant. High pressure, medium pressure, and low pressure steam can all be used as a heat source. Low pressure steam has utilities in creating electricity and it also has several other uses.

==Fired Heat==

In many cases, processes in a plant require a heat source stronger than high pressure and temperature steam. That is when fired heat is used, which is generally at temperatures above 523K. Streams can be heated directly in the furnace tubes or via a hot oil circuit or heat transfer fluid, which will be discussed in detail in the next section. Most fired heaters use natural gas as fuel because it burns cleaner than fuel oil. A cleaner burning fuel is always advantageous due to environmental and safety concerns. Furthermore, natural gases usually result in less wear and tear in burners and fuel lines.

Depending on the application of the fired-heater, different design specifications can be implemented to make the fired-heater as efficient as possible. The basic construction of a fired heater starts with a cylindrical chamber that is lined with with refractory bricks. The stream that is to be heated flows through tubes inside of the furnace. These tubes can be arranged in several different arrangements such as, around the walls of the furnace, or in horizontal or vertical banks (Towler 2012). The figure below illustrates the basic construction of the fired-heater and varying tube arrangements.

[[File:firedheater.png|thumb|border|center|middle|upright=4|link=|atl=|Basic Fired-Heater Diagrams (Towler 2012 Figure 19.66)]]

Fuel is burned to heat the entire furnace, and the heat transfer occurs from the combustion gases inside of the furnace across the tubes that are filled with our desired stream. The heat transfer between the tubes and the furnace is accomplished primarily via radiation. Modern designs take advantage of convective heat transfer by adding a smaller section on top of the fired-heater where the combustion gases flow over banks of tubes as seen in (c) in the figure above. Heat transfer can be further improved via convection by adding fins or pins in the combustion section.

The cost of fired heat can be calculated by the cost of fuel fired. Natural gas and heating oil are traded as commodities and prices can be found at many online trading sites or business news sites (i.e., www.cnn.money.com). Past historic prices for forecasting can be found in the Oil and Gas Journal or from the U.S. Energy Information Adminstration (www.eia.gov).

===Fuels===
Fuel is burned in utility facilities such as boilers, electricity generation, and cogeneration, and can be in solid, liquid, or gas form. It can also be burned to provide heating for a process or stream or to drive pumps and compressors. The fuel is usually burned with excess air to ensure complete combustion.

A way of quantifying the amount of heat generated is by using the heating values. Higher heating value (HHV) and the lower heating value (LHV) are used. The heating is the total heat evolved by complete combustion of a fuel with dry air with both at 60 ⁰F and the flue gas after combustion brought back down to ⁰F. If the water vapor in the flue gas is not condensed, we obtain the LHV. If the water vapor is condensed, the value of heat evolved is a bit higher, and this is the HHV.
Heating values for solids and liquids are usually on a per-mass basis, and gases on a per-volume basis.
A specified amount of heating cannot be met with the amount of fuel calculated using only the HHV. There will be heat losses, the flue gas temperature will be greater than 60 ⁰F, and water in the flue gas will typically be vapor. (Seider 608)

==Hot Oil/Specialized Heat Transfer Fluids==

Specialized heat transfer fluids and hot oil circuits are used as heat sources when steam and fired heat is not appropriate. Specialized heat transfer fluids and hot oil circuits are extremely versatile in that they can be used in the temperature range of 323K to 673K. This range however is quite variable. For hot oils, the upper temperature limit is gauged based off of the thermal decomposition of the oil and coking/fouling of heat exchanger tubes.

Hot oil circuit systems are most commonly used when the plant has several small temperature heating requirements because it is more economically sound. Rather than having several fired heaters heat each small temperature requirement, it is much more economical to have one fired heater heat the hot oil and circulate that oil through each of the process to meet all of the heat needs. Hot oil systems are also generally favored over high pressure steam in processes that involve high pressure differentials between the process stream and high pressure steam. Hot oil systems are favored in this scenario because of safety concerns. If the steam were to leak, the pressure drop could cause serious safety issues.

Mineral oils are the most commonly used heat transfer fluids, and one prominent example is Dowtherm A. Dowtherm A is a combination of 26.5 wt% diphenyl in diphenyl oxide (Towler 2012) and is extremely thermally stable. These mineral oil systems generally require high flow rates.

=Process Cooling=

==Cooling Water==
Cooling water is used to cool and/or condense streams. Cooling water is usually circulated between process heat exchangers and a cooling tower. Water is cooled during downward motion by contact with air blown upwards, which can bring the water temperature to come within ~ 5 ⁰F of air’s wet-bulb temperature.Approximately 80% of the temperature reduction is due to evaporation of the cooling water and heat transfer to the surrounding air. Water can also be cooled in spray ponds and cooling ponds. Both work by providing high area for water to exchange heat with air.
Water in cooling towers is lost through drift and blowdown, and makeup is usually 1.5 to 3% of the circulating rate.
If a large natural body of water is nearby, it can be used as a source of cooling water and discharged downstream. This water is usually filtered to remove salts and impurities that may lead to fouling, but it is not treated.

==Refrigeration==
Cooling water can usually be used to cool a stream to ~ 100 ⁰F. Air can only cool to ~ 120 ⁰F. Air may be used in places where water is scarce or more costly to transport. To cool or condense streams below 100 ⁰F, a refrigerant is typically used. Chilled brine can also be used, but is less common.

Until 1995, CFC Freon R-12 (dichlorodifuloromethane) and HCFC Freon R-22 (chlorodifuloromethane) were commonly used refrigerants. However, the chlorine atom in the molecules caused the depletion of the ozone layer. The U.S. Clean Air Act Amendments of 1990 went into effect in 1995, and the production of these refrigerants has since stopped or been greatly reduced.

Cost estimates are based on ton-day of refrigeration, where a ton is the heat that needs to be removed to freeze 1 ton per day of water at 32 ⁰F. Substitutes have since been developed. R-134a is often used in place of R-12. According to the EPA, R-134a is not combustible at ambient conditions, and is essentially non-toxic under 400 ppm, and is not ozone-depleting. (Seider pg 607)

=Energy Efficiency=
One of the chief concerns in selecting and designing process utility systems for heating and cooling is how to achieve the most energy efficient design. There are countless means by which plants lose energy, two of the foremost being through the mixing of different temperature or pressure streams and through the disposal of warmed cooling water. (Seider, 2009) Proper utilities design can help mitigate each of these losses as well as many others. The energy efficiency of a plant will depend primarily on the heating and cooling methods that are being used and the overall system design itself. These two parameters are important in determining how well energy is transferred to the desired media as well as how well that energy is recovered and recycled.

==Hot Utility Efficiency==
As mentioned above, the most commonly used utilities for process heating in large scale processes are steam, fired heat, and hot oil heaters. Of these, steam is the most commonly used. Electricity, while efficient at creating power, is not a viable source of heat in large industrial processes. Common ranges of heating efficiency for these three methods are displayed in Table 1. (Towler and Sinnott, 2012; Broughton, 1994)

{| class="wikitable"
|+Table 1: Process Heating Efficiencies
|-
! Process Heating Method
! Typical Efficiency
|-
| Steam (via coal boiler)
| 72%
|-
| Steam (via gas boiler)
| 73%
|-
| Steam (via oil boiler)
| 75%
|-
| Fired Heat w/ Convective Section
| 85%
|-
| Fired Heat w/o Convective Section
| 60%
|-
| Hot Oil Heaters/Vaporizers
| 80-85%
|}

===Steam===
As steam is so popular for heating purposes, it is useful to analyze the numerous ways in which losses can occur in steam systems. There are five primary sources of inefficiency and heat loss in the generation and distribution of steam throughout a process plant:

*The heat content of boiler exhaust gas
*Incomplete combustion of boiler fuel
*Radiant losses from the boiler exterior
*Blowdown losses
*Distribution losses (pipe transport, steam traps, etc.)

The first four of these losses take place at the boiler and contribute to the heating efficiencies seen in Table 1 for steam created with coal, gas, and oil. Several methods can be used to minimize these losses, one of the foremost being the control of air-to-fuel ratio in the boiler. This ratio must be managed by weighing losses due to uncombusted fuel against losses due to the heat content of excess exhaust gas. (Broughton, 1994)

[[File:Air-fuel ratio.PNG|thumb|border|center|middle|upright=4|link=|atl=|Air-to-fuel ratio relationship with heat losses (Broughton Fig 2.3)]]

The air-to-fuel ratio can be optimized using a feedback process controller. The control system will analyze the oxygen content of exhaust air and adjust the incoming air flow rate to achieve a set percentage of excess air. While desired excess oxygen will vary depending on the type of fuel, it is consistently seen that in the minimum loss-range a 1% increase in excess air will result in a 1% decrease in efficiency. ("Oxygen Control")

In addition to air-to-fuel ratio management, steam heat losses at the boiler can be mitigated via energy recovery, which is discussed in further detail [[Utility_systems#Energy_Recovery|below]].

Outside the boiler, losses in distribution of steam throughout facilities can decrease energy efficiency by a significant amount. This can cause up to a 60% increase in losses, but typically results in an overall steam efficiency of 50-55% (down from approximately 75% at the boiler). (Broughton, 1994) There are several ways that this issue can be addressed. First and foremost are steam metering systems, which can be used to monitor heat supply to separate sections of the process facility, check efficiency of fuel use, and determine which processes in a given plant have the highest steam requirements. Another method of minimizing transport losses is to decentralize steam generation systems. It can be advantageous to have numerous smaller boilers rather than a single centralized boiler so that steam does not have to travel as long of distances to reach its destination.

==Cold Utility Efficiency==
Efficiency in cooling processes depends more on the method used, and by extension the amount of coolant needed. Water and air utility efficiencies depend primarily on the fluid flow required to maintain the system at a desired temperature, while powered refrigeration utilities (for colder processes) have efficiencies at approximately 60%--but ranging up to 90%--of Carnot cycle efficiency, a metric of ideal refrigeration efficiency. (Towler and Sinnott, 2012) Cooling systems represent by definition a loss of energy from the main process to the utility stream, and as such it is often useful to find other uses for the heated media before discharge.

==Energy Recovery==
Recovery and recycle of energy is perhaps the most important aspect of creating an energy efficient plant design, and it is important for process engineers to fully consider possibilities for heat recovery in order to aid in economic viability.

===Process Heat Exchange===
Heat exchanger networks are a very common energy recovery method in industrial processes. These networks most frequently allow energy from heated product streams to be transferred to feed streams that must be brought up to process temperature. (Biegler, 1997) More information on the function and design of heat exchanger networks can be found on the [[Heat_exchanger#Heat_Exchanger_Networks|heat exchanger wiki page]]. The following are several examples of energy recovery via heat exchange that are used in industrial processes.

In distillation columns the bottoms and distillate effluents have the potential for energy exchange. Though the condenser at the top of the column cannot supply its waste heat to the reboiler due to their respective temperatures, the effluent streams can supply heat to the feed via a feed-effluent exchanger. This reduces the utility requirements to raise the feed to column temperature. (Biegler, 1997)

[[File:Feed_sterilization.jpg|thumb|border|right|middle|upright=4|link=|atl=|Feed sterilization schematic. (Towler and Sinnott Fig. 3.30)]]

Feed sterilization, commonly used in the food industry, is a common application for heat recovery through process stream heat exchange. In this application, the feed must be heated for a certain amount of time to kill any biological contaminants, after which it can be used to heat the new raw feed for sterilization. This reduces energy demands on the steam heater and thus reduces cost. (Towler and Sinnott, 2012)

In multi-vessel batch processes it can be advantageous to exchange heat as the process fluid is being transferred between vessels. Like the previous examples, this reduces the utility needed to bring the colder feed up to process temperature, thus reducing costs. (Towler and Sinnott, 2012)

[[File:Batch_heat_exchange.jpg|thumb|border|center|middle|upright=4|link=|atl=|Multi-vessel batch heat exchange schematic (Towler and Sinnott Fig. 3.31)]]

===Utility Regeneration===
[[File:Waste_heat_boiler.jpg|thumb|border|right|middle|upright=4|link=|atl=|Industrial modular HRSG]]
When recovery of waste heat via transfer to other process streams is inconvenient or impossible, energy efficiency can still be improved through the regeneration of utilities. This is commonly done through the regeneration of steam by removing heat from exiting streams or from highly exothermic reactions. Waste heat in exiting streams can be removed via heat recovery steam generators (HRSGs), and is most often used on exiting gas streams. Heat recovery from reactions is a viable option when the reactor temperature will be at 150 C or above, as this will create steam at high enough pressure to be used in other processes. (Towler and Sinnott, 2012)

Additionally, in the case of steam, waste heat and water treatment losses can be recovered from the utility generation process itself. One

[[File:Economizer Schematic.jpg|thumb|border|center|middle|upright=4|link=|atl=|Economizer schematic ("Economizers")]]

Furthermore, there is opportunity for energy recovery in the expansion of compressed gas through a turbine to create electricity, a process that can be economically viable given sufficiently high flows or pressure. One of the primary application of this type of energy recovery is in the creation of medium pressure and low pressure steam. In most processes, all steam is generated as high pressure steam and can be expanded through a turbine to decrease its pressure. Such technology has also been used in processes to synthesize ammonia, perform air separations, and synthesize nitric acid. (Towler and Sinnott, 2012) Recently, however, there has been a particularly strong interest for energy recovery in the natural gas industry, when gas is decompressed from major pipelines to residential low-pressure piplines. A 2001 study estimated that there is the potential to recover 21 TWh, representing 11% of natural gas transport energy, via gas expansion. (Lehman)

=Process water and boiler-feed water=
Process water is water that will be directly used in the process. Boiler-feed water (BFW) is used to produce steam. Both may need to be purified to prevent impurities from contaminating a process or from foul equipment. It can be used as a cooling stream when the temperature of the stream to be cooled is greater than ~300 ⁰F. Cost of BFW can be partially offset by the steam credit.

Process water that undergoes moderate pretreatment can cost ~ $0.75/1,000 gal.

Extensive treatment ~ $6.00/1,000 gal.

Sterilized for pharmaceutical processes ~ $550/1,000 gal. (Seider pg 608)

=Demineralized Water=
In demineralized water, minerals have been removed by ion exchange. In boiler feed water, this is to prevent salt deposition, corrosion, formation of foam, and sluicing. In process water, the ions may contaminate the process.

=Waste Treatment=
Most chemical processes will produce some sort of waste. Disposal occurs to the atmosphere (in the case of some gases), sewers, body of water, or a landfill. Waste may require some treatment before disposal to meet regulations. Depending on process economics, byproducts may be recovered and processed. (Seider 2009 pg 609)

==Wastewater Treatment==
The United States EPA regulates industrial wastewater disposal through the Clean Water Act, introduced in 1948 as the Federal Water Pollution Control Act and amended to its current form in 1972. The sweeping 1972 amendments allowed the EPA to prevent industries and persons from discharging contaminated water into fresh water sources and set water quality standards. (Summary of the Clean Water Act) In accordance with this law, process plants in the United States treat wastewater at on-site or near-site treatment centers before releasing it into the surrounding environment.

Wastewater effluent streams, along with water runoff from around the plant, are treated to control for pH, toxicity, suspended solids, and biological oxygen demand (for aquatic life protection) prior to discharge. Each of these controls is typically addressed with a separate method. Acidity and basicity is balanced through the addition of an acid or alkaline solution. Toxic wastewater may be treated with chemical processes or simply diluted to safe concentrations. Suspended solids can be removed via filtration and/or with clarifiers. Oxygen demand of wastewater can be mitigated using activated sludge treatment processes. Once the water quality complies with the EPA, and state-mandated, regulations, it can be safely released. More information on the large number of industry-specific guidelines for waste effluent can be found on the EPA website (http://www.epa.gov/eg/industrial-effluent-guidelines).

==Air-Pollution Management==
===Introduction===

In the United States air pollution is regulated in the Clean Air Act, and almost all pollutant emitting plants are regulated under this law. The types of plants that can release significant emissions include petroleum refineries, sulfur recovery plants, carbon-black plants, fuel conversion plants, chemical process plants, fossil fuel plants, and petroleum storage and transfer facilities. To receive permission to construct a plant must undergo a review to show that it will not cause a violation of the Ambient Air Quality Standards(Peters, 2003).

===Methods===

There are two major types of pollutants that are released into the air, particulates and and gaseous pollutants. Particulates can be removed with mechanical forces while gaseous pollutants typically need to removed by chemical or physical means (Peters, 2003).

Particulates and volatile pollutants that need to be removed before disposal may be present. Particle removal equipment includes: cyclones, wet scrubbers, electrostatic precipitators, and fabric-filter systems (Seider 2009) such as bag filters (. The two charts below are from ''Plant Design and Economics for Chemical Engineers'' and show the types of equipment, separation methods, and particle sizes in different pollutant separation technologies (Peters, 1991).

[[File:AirPolChart.png|thumb|border|center|middle|upright=4|link=|atl=|Different Methods of Particle Separation, the Particle Sizes they Can Remove, and the Technologies Used]]

[[File:AirPolTable.png|thumb|border|center|middle|upright=4|link=|atl=| This Chart Shows the Specifications and Limitations of Different Separations Technologies Including Particle Size, Efficiencies, and Temperatures(Peters, 1991)]]

====Wet Scrubbers====
Wet scrubber use lime or limestone and water to remove SO2 and acid gases. The mixture can be injected into a scrubber or the gases can be bubbled through this mixture. This results in removal of 90-98% of SO2 and and acid gases (Clean Coal Technologies).

====Dry Scrubbers====
Dry scrubber blow powdered adsorbents into a vessel with gases and then after it has captured the SO2 and acid gases it is separated from gas using a fabric filter. These systems remove 90-93% of the contaminants (Clean Coal Technologies).

====Low-NOx Burners====
The purpose of low NOx burners is to decrease the amount of NOx created when the coal is burned. This is done by injecting coal and air in boilers. This can result in 40-50% NOx reduction. If air is injected into the area above the burner this can actually cause almost 70% NOx reduction (Clean Coal Technologies).

====Selective Non-Catalytic and Catalytic Reductions====
These systems inject ammonia into gases to remove NOx. The Catalytic reductions add a catalyst to the ammonia being injected to aid in the removal. Con-catalytic reductions result in about 35% removal, but adding a catalyst can increase that amount to about 90%. The catalytic-reduction can remove up to 80% of mercury as well (Clean Coal Technologies).

====Fabric Filters====
Also known as baghouses,these [[Separation processes#Filtration| filters]] remove particulates by passing air through filters. These can separate as much as 99.9% of particulate matter (Clean Coal Technologies).

====Electrostatic Precipitators====
Electrostatic Precicpitators remove particulate matter as gas passes through a device that has charged metal plates. The particles are then removed because of static electricity. These systems can remove between 99-99.9% of particulate matter (Clean Coal Technologies).

====Super-critical Boilers====
Super-Critical Boilers and Ultra-Supercritical Boilers operate at temperature and pressure higher than regular boilers. By operating at higher temperature these systems become more efficient. Super Critical Boilers typically have 10%-20% CO2 emissions than other similar sub-critical technologies. Ultra-Supercritical boilers can be as much as 30% more efficent than sub-critical technologies (Clean Coal Technologies).

====More Information====

For more information regarding some of these separations equipment see [[Solids-involved equipment]]

For more information Regarding Cyclones see [[Separation processes#Cyclones| Cyclones]], and for modeling cyclones see their[[Solids-involved equipment#HYSYS Simulation|HYSYS Simulation]]

Methods for removing inorganic and organic gaseous pollutants include: absorption, adsorption, condensation, and combustion (Seider 2009 pg 609). A list of typical of gases pollutants and their sources from ''Plant Design and Economics for Chemical Engineers'' is shown below (Peters, 1991).

[[File:GaseousPollutants.png|thumb|border|center|middle|upright=4|link=|atl=| Common Gaseous Pollutants and their Sources]]

Typically Gas-liquid absorption processes are done completed in a vertical, countercurrent, flow through packed, plate, or spray towers. These systems require good liquid-gas contact and proper equipment. These systems also often have significant energy consumption because of large pressure drops (Peters, 2003). For high volume systems absorption by scrubbing with water or another solvent is the most widely used method (Towler, 2012). Dry adsorbents can be used to remove the last races of gaseous pollutants. Adsorption typically requires blowers, condensers, separators, and controls. You also typically need two packed beds so that one can be used while the other is regenerated. Examples of adsorbents are molecular sieves and activated carbon. Incineration is typically used when there are gas streams that have no recovery value. This can be done with direct flame or catalytic oxidation. Catalytic oxidation usually has higher capital costs, but lower operating costs because it does not require fuel.

You can find more information on [[Separation processes#Absorption| Absorption]] and [[Separation processes#Adsorption| Adsorption]] in [[Separation processes]]

===Outcomes===

====United States Common Pollutant Emissions====

The United States implemented the Clean Air Act in 1970 and since then emissions in the U.S. have been drastically reduced. As a matter of fact despite increases in the population in the last 35 years the amount of pollutants emitted have decreased by almost 70% (EPA). More importantly this demonstrates that reasonable efforts can be put towards environmental protection without causing too much harm to industry.

[[File:EPA.png|thumb|border|center|middle|upright=4|link=|atl=| GDP and Other Growth Factors Vs Common Pollutants Released]]

====China Clean Coal====

=====Success Through 2005=====

Coal is a very inexpensive and abundant source of energy and is abundant in China (Xu 2010). In China Coal the cause of 90% of SO2 emissions, 70% of dust emissions, and 67% of NOx emissions, and 70% of CO2 emissions. These numbers are staggering considering that Coal has never been more than 50 percent of China's Energy Supply.

[[File:Coal.jpg|thumb|border|center|middle|upright=4|link=|atl=| Coal Consumption for Power and the Percentage of Coal Used]]

Despite the increasing coal consumption, high efficiency electric dust removal systems with efficiencies that are as high as 99.6% have greatly decreased soot emissions to 32% below 1980's levels as of 2005.

[[File:Soot.jpg|thumb|border|center|middle|upright=4|link=|atl=| SO2 and Soot Emissions from 1981 to 2005]]

=====Technologies and Life Cycle Comparison=====
As of 2010 China was consuming 48.2% of coal globally. Four potential technologies integrated gasification combined cycle (IGCC), sub-critical coal power generation (Sub-C); super-critical coal power generation (Super-C) ultrasuper-critical coal power generation (USC). These technologies are compared mostly on the basis of net generating efficiency and efficiency. Net generating efficiency is the output of the plant divided by the total available energy in the fuel used.

where efficiency is define as: η=E/Etotal

and

Etotal=Emining+Etransportation+Egeneration

[[File:technologies.PNG|thumb|border|center|middle|upright=4|link=|atl=|A comparison of many of the parameters important to lfe-cycle analysis]]

This demonstrates that USC has the best net generation efficiency, while also having the largest capacity for a single system.

[[File:Lifecycle2.PNG|thumb|border|center|middle|upright=4|link=|atl=|]]

This breaks down the energy efficiency of each system and demonstrates that USC is the most efficient

[[File:Lifecycle.PNG|thumb|border|center|middle|upright=4|link=|atl=|]]

This demonstrates that the capital cost per unit of energy production is very high for IGCC, but shows that Super-C and USC are very competitive.

[[File:Price.PNG|thumb|border|center|middle|upright=4|link=|atl=| Capital cost in $/kW of clean coal power-generation technologies]]

Lastly IGCC and USC are lowest on different element, but since these all have different global warming potential it is difficult to tell which is the most efficient.

And the table below defines all the relevant terms.

[[File:GWP.PNG|thumb|border|center|middle|upright=4|link=|atl=| Environemntal measures and their explanations]]

[[File:GWP.PNG|thumb|border|center|middle|upright=4|link=|atl=| Gloabl warming] potential and other measures]

All of the data suggests that USC is the highest in both energy efficiency and net generating efficiency while competitive in price and the lowest on emissions among the different boilers.

==Solid Waste==
U.S. federal regulations require that solid waste be classified as hazardous or nonhazardous. Conditions for a classification of hazardous include: ignitability, corrosivity, reactivity, toxicity, or posing a substantial threat to the surrounding environment and its inhabitants. Hazardous waste must be treated on- or near-site before being removed in containers. Non-hazardous waste may be landfilled or incinerated in some cases. A typical estimate of costs for waste disposal is $0.03/lb for nonhazardous solids and $0.10/lb for hazardous solids. (Seider 2009 pg 609)

=References=

*Biegler LT, Grossmann IE, Westerberg AW. ''Systematic Methods of Chemical Process Design'' Prentice-Hall: Upper Saddle River, 1997.

*Broughton, J. ''Process Utility Systems: Introduction to Design, Operation and Maintenance'' Institution of Chemical Engineers: Rugby, Warwickshire, UK, 1994.

*Clean Coal Technologies. America's Coalition for Clean Coal Electricity. http://www.americaspower.org/clean-coal-technologies-1663/

*Duke Energy Company (2013). How Do Coal Fired Plants Work? Charlotte: Duke Energy.

*"Economizers." Energy Solutions Center Inc.: Boiler Consortium. http://www.cleanboiler.org/Eff_Improve/Efficiency/Economizers.asp. Accessed February 21, 2016.

*Lehman B, Worrell E. ''Electricity Production from Natural Gas Pressure Recovery Using Expansion Turbines.'' Lawrence Berkeley National Laboratory; 2001.

*"Overview of the Clean Air Act and Air Pollution." Environmental Protection Agency. November 17, 2015. http://www.epa.gov/clean-air-act-overview. Accessed February 5, 2016.

*"Oxygen Control." Energy Solutions Center Inc.: Boiler Consortium. http://www.cleanboiler.org/Eff_Improve/Efficiency/Oxygen_Control.asp. Accessed February 21, 2016.

*Peters, Max S.; Timmerhaus, Klaus D.; West, Ronald E. (2003). "Plant Design and Economics for Chemical Engineers." McGraw Hill Higher Education.

*Seider, Seader, Lewin, Widagdo. (2009). ''Plant Design and Economics for Chemical Engineers, 5th Edition.'' Hoboken: Wiley.

*Seider, Seader, Lewin. (2008). ''Product and Process Design Principles, 2nd Edition.'' Hoboken: Wiley.

*Summary of the Clean Water Act. United States EPA website. http://www.epa.gov/laws-regulations/summary-clean-water-act

*Towler, G.P. and Sinnot, R. (2012). ''Chemical Engineering Design: Principles, Practice and Economics of Plant and Process Design.'' Elsevier.

*Turton R.; Bailie, R.C.; Whiting, W.B.; Shaeiwitz J.A.; Bhattacharyya D. (2012). ''Analysis, Synthesis, and Design of Chemical Processes.'' Upper Saddle River: Prentice Hall.

*G.D. Ulrich, A Guide to Chemical Engineering Process Design and Economics, Wiley: New York, 1984.

File:Economizer.png

2016-02-22T01:14:11Z

Taunins:

Utility systems

2016-02-22T01:09:18Z

Taunins: /* Utility Regeneration */

Authors: David Chen, [2014] Joshua Lee, [2015] Brett Sleyster, [2016] and Tom Aunins [2016] 

Stewards: David Chen, Jian Gong, and Fengqi You

Date Presented: January 13, 2014 /Date Revised: January 14, 2014

 


__TOC__

=Introduction=
Many chemical processes do not take place at ambient temperature or pressures. In order to reach these non-ambient conditions, utilities will have to be used to raise or lower temperatures and compress gases. (Towler, Towler/UOP) Utilities often contribute 5 to 10% of the price of a product, and may come from public or private utility companies or on-site plants. For purchased utilities, costs depend on consumption, while for company-owned utilities, there will be both capital and operating costs. They include things such as steam for heating, electricity, cooling water, refrigeration, fuels such as natural gas, wastewater treatment, waste disposal, and landfill. Steam is often the largest utility cost. Cogeneration unit can supply electricity accompanied with different steam pressures. (Seider 2009)

=Electricity=

Electricity is used to power many different kinds of equipment. It has many advantages: it is efficient (> 90%), reliable, available in a wide range of power, shaft speeds, designs, lifetimes, convenience, costs, and maintenance. It is generally used up to 200 hp, and sometimes over 10,000 Hp. In chemical process plants, the electricity demand is generally determined by the work or energy required for compression, pumping, air cooling, lights, and many other items. This electricity often times is purchased from local electricity providers, but many plants generate their own electricity via sophisticated processes.

Electricity is rarely used as a primary heat utility in large-scale chemical plants for a variety of reasons. The main disadvantages of using electricity as a heat utility are as follows (Towler 2012):

:*Heat from electricity is two to three times more expensive than heat from fuels. This is attributed to the lack of efficiency when creating heat from electricity.

:*Electrical heating units are expensive, require high maintenance, and must comply with strict safety regulations.

:*Electrical heating units are unsafe compared to steam heating units. In steam systems, the physically steam controls the temperature, whereas in electrical heating units temperature is controlled by temperature controllers, which can fail or burn out.

The use of electricity carries with it some hazards depending on the environment. Extra care must be taken when using electrically-powered equipment in areas which may have combustible fluids, vapors, or dust, and where liquids may be present. (Seider 2009 pg 606)

==Conventional Power Station==

In general, most electricity is generated from a conventional coal-fired process, whether it be on-site or purchased from a provider. Coal-fired processes have been used to create electricity throughout history, and technological advances have increased its efficiency and use worldwide. In a coal-fired steam station—much like a nuclear station—water is turned into steam, which in turn drives turbine generators to produce electricity. There are several variations on how to create energy from coal, but here are the basics of how a coal-fired process works:

[[File:coalfired.png|thumb|border|center|middle|upright=4|link=|atl=|General Coal-Fired Process Diagram (Duke Energy Company)]]

*Heat is created:
::Before the coal is burned, it is pulverized to the fineness of talcum powder. It is then mixed with hot air and blown into the firebox of the boiler. Burning in suspension, the coal/air mixture provides the most complete combustion and maximum heat possible.

*Water turns to steam:
::Highly purified water, pumped through pipes inside the boiler, is turned into steam by the heat. The steam reaches temperatures of up to 1,000 degrees Fahrenheit and pressures up to 3,500 pounds per square inch, and is piped to the turbine.

*Steam turns the turbine:
::The enormous pressure of the steam pushing against a series of giant turbine blades turns the turbine shaft. The turbine shaft is connected to the shaft of the generator, where magnets spin within wire coils to produce electricity.

*Steam is converted back to water:
::After doing its work in the turbine, the steam is drawn into a condenser, a large chamber in the basement of the power plant. In this important step, millions of gallons of cool water from a nearby source (such as a river or lake) are pumped through a network of tubes running through the condenser. The cool water in the tubes converts the steam back into water that can be used over and over again in the plant.

*Repeat:
::The cooling water is returned to its source without any contamination, and the steam water is returned to the boiler to repeat the cycle.

===Advantages & Disadvantages of Coal-Fired Energy Production===

[[File:coalfiredtable.png|thumb|border|center|middle|upright=4|link=|atl=|Advantages and Disadvantages of Coal-Fired Processes (Seider 2008)]]

==Gas-Turbine Cogeneration Process==

When generating energy on-site, many plants use a gas-turbine cogeneration process. The thermal efficiency of a gas-turbine process is in the range of 70-80% while conventional power stations, such as coal-fired processes, have a 30-40% efficiency. The lower efficiency in more conventional power stations is attributed to wasted heat in the exhaust steam in the condenser. One example of a gas-turbine process is outlined in the following figure. Figure 3.1 is a gas-turbine cogeneration process with a heat recovery steam generator (waste-heat) boiler.

[[File:cogeneration.png|thumb|border|center|middle|upright=4|link=|atl=|Gas-Turbine Cogeneration with a heat recovery steam generator boiler (Towler 2012 Fig 3.1)]]

Overall, the process illustrated is not much different from a coal-fired process. The main differences are that the cogeneration process creates both electricity and a heat utility, and cogeneration processes use natural gas instead of coal. Many of the advantages and disadvantages are similar to those of the coal-fired process, but the cogeneration has a much higher efficiency, creates heat to be used in another process, and uses a more volatile and expensive fuel. The main advantage of cogeneration over coal-fired energy production is that heat is not wasted. In coal-fired processes, heat is released and wasted during electricity generation. Cogeneration captures some, if not all of the byproduct for heat, which is an extremely useful utility that will be discussed in subsequent sections. In summary, the cogeneration plant is superior to the coal-fired process because of its higher efficiency and ability to create a useful heat utility.

Obviously any engineer would design the cogeneration plant to meet at least the energy requirement necessary for plant operation, but cogeneration plants often times are designed to exceed the plant electricity requirement to drive another source of capital. Many describe this scenario as a "make or buy" scenario (Towler 2012). This scenario provides chemical producers leverage when negotiating contracts with outsourced electricity providers and this allows plants to purchase electricity at a wholesale price. This is a huge advantage of considering on-site electricity production because electricity is needed in relatively high quantities for all chemical plants. Being able to minimize electricity costs, or even profit off of electricity production is a huge economical consideration that all plants employ.

=Process Heating=
The key objective of this section is to discuss how processes are heated. Heating utilities are necessary for proper usage of distillers, reactors, condensers, and several other integral types of equipment. More specifically, steam, fired heat, and hot oil/specialized heat transfer fluids will be discussed in the following subsections.

==Steam==
Steam is the most commonly used heat utility used in chemical plants, and as a result understanding how it is used is essential in the study of Utility systems. Steam is used both as a process fluid (feedstock, diluent to absorb heat of reaction, heating agent, and stripping agent in absorbers and adsorbers ) and utility. It can be used to drive pumps and compressors, ejectors (for producing a vacuum), and heat exchangers. As one can clearly see, steam is a versatile, and useful utility.

Here are a few advantages of using steam as opposed to other methods of process heating (Towler 2012):

:*By controlling the pressure of the steam, one can control the temperature at which the heat is released. Having a strong control over the temperature is essential in several processes. =
:*Steam is an efficient heat source because the heat of condensation of steam is very high. Meaning that there is is high output per mass of utility at a constant temperature.
:*Heat exchangers that use steam are relatively cheap because condensing steam has a high heat transfer coefficient.
:*Steam is nonflammable, nontoxic, and inert to several process fluids.

Chemical plants generally have a network of pipelines exclusively for providing steam. These networks generally have steam at a low pressure, a medium pressure, and a high pressure. The image below illustrates a basic steam system.

[[File:Steam.png|thumb|border|center|middle|upright=4|link=|atl=|(Towler 2012 Fig 3.2)]]

In the diagram above, boiler feed water at a high pressure is preheated and fed to other boilers. These other boilers superheat the steam to create a high pressure and high temperature steam stream. The steam is superheated past the dew point to account for heat loss in the pipelines. A portion of the high pressure steam is used for process heating in areas of the plant that require high temperatures. The rest of the high pressure steam is turned into medium pressure steam by valves and steam turbines. The medium pressure steam is then used to heat medium temperature processes and to form low pressure steam. The low pressure steam can be used to heat low pressure processes and it can be expanded in condensing turbines to create shaft work and energy. In summary, steam can be used for an innumerable amount of action items in a plant. High pressure, medium pressure, and low pressure steam can all be used as a heat source. Low pressure steam has utilities in creating electricity and it also has several other uses.

==Fired Heat==

In many cases, processes in a plant require a heat source stronger than high pressure and temperature steam. That is when fired heat is used, which is generally at temperatures above 523K. Streams can be heated directly in the furnace tubes or via a hot oil circuit or heat transfer fluid, which will be discussed in detail in the next section. Most fired heaters use natural gas as fuel because it burns cleaner than fuel oil. A cleaner burning fuel is always advantageous due to environmental and safety concerns. Furthermore, natural gases usually result in less wear and tear in burners and fuel lines.

Depending on the application of the fired-heater, different design specifications can be implemented to make the fired-heater as efficient as possible. The basic construction of a fired heater starts with a cylindrical chamber that is lined with with refractory bricks. The stream that is to be heated flows through tubes inside of the furnace. These tubes can be arranged in several different arrangements such as, around the walls of the furnace, or in horizontal or vertical banks (Towler 2012). The figure below illustrates the basic construction of the fired-heater and varying tube arrangements.

[[File:firedheater.png|thumb|border|center|middle|upright=4|link=|atl=|Basic Fired-Heater Diagrams (Towler 2012 Figure 19.66)]]

Fuel is burned to heat the entire furnace, and the heat transfer occurs from the combustion gases inside of the furnace across the tubes that are filled with our desired stream. The heat transfer between the tubes and the furnace is accomplished primarily via radiation. Modern designs take advantage of convective heat transfer by adding a smaller section on top of the fired-heater where the combustion gases flow over banks of tubes as seen in (c) in the figure above. Heat transfer can be further improved via convection by adding fins or pins in the combustion section.

The cost of fired heat can be calculated by the cost of fuel fired. Natural gas and heating oil are traded as commodities and prices can be found at many online trading sites or business news sites (i.e., www.cnn.money.com). Past historic prices for forecasting can be found in the Oil and Gas Journal or from the U.S. Energy Information Adminstration (www.eia.gov).

===Fuels===
Fuel is burned in utility facilities such as boilers, electricity generation, and cogeneration, and can be in solid, liquid, or gas form. It can also be burned to provide heating for a process or stream or to drive pumps and compressors. The fuel is usually burned with excess air to ensure complete combustion.

A way of quantifying the amount of heat generated is by using the heating values. Higher heating value (HHV) and the lower heating value (LHV) are used. The heating is the total heat evolved by complete combustion of a fuel with dry air with both at 60 ⁰F and the flue gas after combustion brought back down to ⁰F. If the water vapor in the flue gas is not condensed, we obtain the LHV. If the water vapor is condensed, the value of heat evolved is a bit higher, and this is the HHV.
Heating values for solids and liquids are usually on a per-mass basis, and gases on a per-volume basis.
A specified amount of heating cannot be met with the amount of fuel calculated using only the HHV. There will be heat losses, the flue gas temperature will be greater than 60 ⁰F, and water in the flue gas will typically be vapor. (Seider 608)

==Hot Oil/Specialized Heat Transfer Fluids==

Specialized heat transfer fluids and hot oil circuits are used as heat sources when steam and fired heat is not appropriate. Specialized heat transfer fluids and hot oil circuits are extremely versatile in that they can be used in the temperature range of 323K to 673K. This range however is quite variable. For hot oils, the upper temperature limit is gauged based off of the thermal decomposition of the oil and coking/fouling of heat exchanger tubes.

Hot oil circuit systems are most commonly used when the plant has several small temperature heating requirements because it is more economically sound. Rather than having several fired heaters heat each small temperature requirement, it is much more economical to have one fired heater heat the hot oil and circulate that oil through each of the process to meet all of the heat needs. Hot oil systems are also generally favored over high pressure steam in processes that involve high pressure differentials between the process stream and high pressure steam. Hot oil systems are favored in this scenario because of safety concerns. If the steam were to leak, the pressure drop could cause serious safety issues.

Mineral oils are the most commonly used heat transfer fluids, and one prominent example is Dowtherm A. Dowtherm A is a combination of 26.5 wt% diphenyl in diphenyl oxide (Towler 2012) and is extremely thermally stable. These mineral oil systems generally require high flow rates.

=Process Cooling=

==Cooling Water==
Cooling water is used to cool and/or condense streams. Cooling water is usually circulated between process heat exchangers and a cooling tower. Water is cooled during downward motion by contact with air blown upwards, which can bring the water temperature to come within ~ 5 ⁰F of air’s wet-bulb temperature.Approximately 80% of the temperature reduction is due to evaporation of the cooling water and heat transfer to the surrounding air. Water can also be cooled in spray ponds and cooling ponds. Both work by providing high area for water to exchange heat with air.
Water in cooling towers is lost through drift and blowdown, and makeup is usually 1.5 to 3% of the circulating rate.
If a large natural body of water is nearby, it can be used as a source of cooling water and discharged downstream. This water is usually filtered to remove salts and impurities that may lead to fouling, but it is not treated.

==Refrigeration==
Cooling water can usually be used to cool a stream to ~ 100 ⁰F. Air can only cool to ~ 120 ⁰F. Air may be used in places where water is scarce or more costly to transport. To cool or condense streams below 100 ⁰F, a refrigerant is typically used. Chilled brine can also be used, but is less common.

Until 1995, CFC Freon R-12 (dichlorodifuloromethane) and HCFC Freon R-22 (chlorodifuloromethane) were commonly used refrigerants. However, the chlorine atom in the molecules caused the depletion of the ozone layer. The U.S. Clean Air Act Amendments of 1990 went into effect in 1995, and the production of these refrigerants has since stopped or been greatly reduced.

Cost estimates are based on ton-day of refrigeration, where a ton is the heat that needs to be removed to freeze 1 ton per day of water at 32 ⁰F. Substitutes have since been developed. R-134a is often used in place of R-12. According to the EPA, R-134a is not combustible at ambient conditions, and is essentially non-toxic under 400 ppm, and is not ozone-depleting. (Seider pg 607)

=Energy Efficiency=
One of the chief concerns in selecting and designing process utility systems for heating and cooling is how to achieve the most energy efficient design. There are countless means by which plants lose energy, two of the foremost being through the mixing of different temperature or pressure streams and through the disposal of warmed cooling water. (Seider, 2009) Proper utilities design can help mitigate each of these losses as well as many others. The energy efficiency of a plant will depend primarily on the heating and cooling methods that are being used and the overall system design itself. These two parameters are important in determining how well energy is transferred to the desired media as well as how well that energy is recovered and recycled.

==Hot Utility Efficiency==
As mentioned above, the most commonly used utilities for process heating in large scale processes are steam, fired heat, and hot oil heaters. Of these, steam is the most commonly used. Electricity, while efficient at creating power, is not a viable source of heat in large industrial processes. Common ranges of heating efficiency for these three methods are displayed in Table 1. (Towler and Sinnott, 2012; Broughton, 1994)

{| class="wikitable"
|+Table 1: Process Heating Efficiencies
|-
! Process Heating Method
! Typical Efficiency
|-
| Steam (via coal boiler)
| 72%
|-
| Steam (via gas boiler)
| 73%
|-
| Steam (via oil boiler)
| 75%
|-
| Fired Heat w/ Convective Section
| 85%
|-
| Fired Heat w/o Convective Section
| 60%
|-
| Hot Oil Heaters/Vaporizers
| 80-85%
|}

===Steam===
As steam is so popular for heating purposes, it is useful to analyze the numerous ways in which losses can occur in steam systems. There are five primary sources of inefficiency and heat loss in the generation and distribution of steam throughout a process plant:

*The heat content of boiler exhaust gas
*Incomplete combustion of boiler fuel
*Radiant losses from the boiler exterior
*Blowdown losses
*Distribution losses (pipe transport, steam traps, etc.)

The first four of these losses take place at the boiler and contribute to the heating efficiencies seen in Table 1 for steam created with coal, gas, and oil. Several methods can be used to minimize these losses, one of the foremost being the control of air-to-fuel ratio in the boiler. This ratio must be managed by weighing losses due to uncombusted fuel against losses due to the heat content of excess exhaust gas. (Broughton, 1994)

[[File:Air-fuel ratio.PNG|thumb|border|center|middle|upright=4|link=|atl=|Air-to-fuel ratio relationship with heat losses (Broughton Fig 2.3)]]

The air-to-fuel ratio can be optimized using a feedback process controller. The control system will analyze the oxygen content of exhaust air and adjust the incoming air flow rate to achieve a set percentage of excess air. While desired excess oxygen will vary depending on the type of fuel, it is consistently seen that in the minimum loss-range a 1% increase in excess air will result in a 1% decrease in efficiency. ("Oxygen Control")

In addition to air-to-fuel ratio management, steam heat losses at the boiler can be mitigated via energy recovery, which is discussed in further detail [[Utility_systems#Energy_Recovery|below]].

Outside the boiler, losses in distribution of steam throughout facilities can decrease energy efficiency by a significant amount. This can cause up to a 60% increase in losses, but typically results in an overall steam efficiency of 50-55% (down from approximately 75% at the boiler). (Broughton, 1994) There are several ways that this issue can be addressed. First and foremost are steam metering systems, which can be used to monitor heat supply to separate sections of the process facility, check efficiency of fuel use, and determine which processes in a given plant have the highest steam requirements. Another method of minimizing transport losses is to decentralize steam generation systems. It can be advantageous to have numerous smaller boilers rather than a single centralized boiler so that steam does not have to travel as long of distances to reach its destination.

==Cold Utility Efficiency==
Efficiency in cooling processes depends more on the method used, and by extension the amount of coolant needed. Water and air utility efficiencies depend primarily on the fluid flow required to maintain the system at a desired temperature, while powered refrigeration utilities (for colder processes) have efficiencies at approximately 60%--but ranging up to 90%--of Carnot cycle efficiency, a metric of ideal refrigeration efficiency. (Towler and Sinnott, 2012) Cooling systems represent by definition a loss of energy from the main process to the utility stream, and as such it is often useful to find other uses for the heated media before discharge.

==Energy Recovery==
Recovery and recycle of energy is perhaps the most important aspect of creating an energy efficient plant design, and it is important for process engineers to fully consider possibilities for heat recovery in order to aid in economic viability.

===Process Heat Exchange===
Heat exchanger networks are a very common energy recovery method in industrial processes. These networks most frequently allow energy from heated product streams to be transferred to feed streams that must be brought up to process temperature. (Biegler, 1997) More information on the function and design of heat exchanger networks can be found on the [[Heat_exchanger#Heat_Exchanger_Networks|heat exchanger wiki page]]. The following are several examples of energy recovery via heat exchange that are used in industrial processes.

In distillation columns the bottoms and distillate effluents have the potential for energy exchange. Though the condenser at the top of the column cannot supply its waste heat to the reboiler due to their respective temperatures, the effluent streams can supply heat to the feed via a feed-effluent exchanger. This reduces the utility requirements to raise the feed to column temperature. (Biegler, 1997)

[[File:Feed_sterilization.jpg|thumb|border|right|middle|upright=4|link=|atl=|Feed sterilization schematic. (Towler and Sinnott Fig. 3.30)]]

Feed sterilization, commonly used in the food industry, is a common application for heat recovery through process stream heat exchange. In this application, the feed must be heated for a certain amount of time to kill any biological contaminants, after which it can be used to heat the new raw feed for sterilization. This reduces energy demands on the steam heater and thus reduces cost. (Towler and Sinnott, 2012)

In multi-vessel batch processes it can be advantageous to exchange heat as the process fluid is being transferred between vessels. Like the previous examples, this reduces the utility needed to bring the colder feed up to process temperature, thus reducing costs. (Towler and Sinnott, 2012)

[[File:Batch_heat_exchange.jpg|thumb|border|center|middle|upright=4|link=|atl=|Multi-vessel batch heat exchange schematic (Towler and Sinnott Fig. 3.31)]]

===Utility Regeneration===
[[File:Waste_heat_boiler.jpg|thumb|border|right|middle|upright=4|link=|atl=|Industrial modular HRSG]]
When recovery of waste heat via transfer to other process streams is inconvenient or impossible, energy efficiency can still be improved through the regeneration of utilities. This is commonly done through the regeneration of steam by removing heat from exiting streams or from highly exothermic reactions. Waste heat in exiting streams can be removed via heat recovery steam generators (HRSGs), and is most often used on exiting gas streams. Heat recovery from reactions is a viable option when the reactor temperature will be at 150 C or above, as this will create steam at high enough pressure to be used in other processes. (Towler and Sinnott, 2012)

Additionally, in the case of steam, waste heat and water treatment losses can be recovered from the utility generation process itself. One

[[File:Economizer Schematic.jpg|thumb|border|center|middle|upright=4|link=|atl=|Economizer schematic ("Economizers")]]

Furthermore, there is opportunity for energy recovery in the expansion of compressed gas through a turbine to create electricity, a process that can be economically viable given sufficiently high flows or pressure. One of the primary application of this type of energy recovery is in the creation of medium pressure and low pressure steam. In most processes, all steam is generated as high pressure steam and can be expanded through a turbine to decrease its pressure. Such technology has also been used in processes to synthesize ammonia, perform air separations, and synthesize nitric acid. (Towler and Sinnott, 2012) Recently, however, there has been a particularly strong interest for energy recovery in the natural gas industry, when gas is decompressed from major pipelines to residential low-pressure piplines. A 2001 study estimated that there is the potential to recover 21 TWh, representing 11% of natural gas transport energy, via gas expansion. (Lehman)

=Process water and boiler-feed water=
Process water is water that will be directly used in the process. Boiler-feed water (BFW) is used to produce steam. Both may need to be purified to prevent impurities from contaminating a process or from foul equipment. It can be used as a cooling stream when the temperature of the stream to be cooled is greater than ~300 ⁰F. Cost of BFW can be partially offset by the steam credit.

Process water that undergoes moderate pretreatment can cost ~ $0.75/1,000 gal.

Extensive treatment ~ $6.00/1,000 gal.

Sterilized for pharmaceutical processes ~ $550/1,000 gal. (Seider pg 608)

=Demineralized Water=
In demineralized water, minerals have been removed by ion exchange. In boiler feed water, this is to prevent salt deposition, corrosion, formation of foam, and sluicing. In process water, the ions may contaminate the process.

=Waste Treatment=
Most chemical processes will produce some sort of waste. Disposal occurs to the atmosphere (in the case of some gases), sewers, body of water, or a landfill. Waste may require some treatment before disposal to meet regulations. Depending on process economics, byproducts may be recovered and processed. (Seider 2009 pg 609)

==Wastewater Treatment==
The United States EPA regulates industrial wastewater disposal through the Clean Water Act, introduced in 1948 as the Federal Water Pollution Control Act and amended to its current form in 1972. The sweeping 1972 amendments allowed the EPA to prevent industries and persons from discharging contaminated water into fresh water sources and set water quality standards. (Summary of the Clean Water Act) In accordance with this law, process plants in the United States treat wastewater at on-site or near-site treatment centers before releasing it into the surrounding environment.

Wastewater effluent streams, along with water runoff from around the plant, are treated to control for pH, toxicity, suspended solids, and biological oxygen demand (for aquatic life protection) prior to discharge. Each of these controls is typically addressed with a separate method. Acidity and basicity is balanced through the addition of an acid or alkaline solution. Toxic wastewater may be treated with chemical processes or simply diluted to safe concentrations. Suspended solids can be removed via filtration and/or with clarifiers. Oxygen demand of wastewater can be mitigated using activated sludge treatment processes. Once the water quality complies with the EPA, and state-mandated, regulations, it can be safely released. More information on the large number of industry-specific guidelines for waste effluent can be found on the EPA website (http://www.epa.gov/eg/industrial-effluent-guidelines).

==Air-Pollution Management==
===Introduction===

In the United States air pollution is regulated in the Clean Air Act, and almost all pollutant emitting plants are regulated under this law. The types of plants that can release significant emissions include petroleum refineries, sulfur recovery plants, carbon-black plants, fuel conversion plants, chemical process plants, fossil fuel plants, and petroleum storage and transfer facilities. To receive permission to construct a plant must undergo a review to show that it will not cause a violation of the Ambient Air Quality Standards(Peters, 2003).

===Methods===

There are two major types of pollutants that are released into the air, particulates and and gaseous pollutants. Particulates can be removed with mechanical forces while gaseous pollutants typically need to removed by chemical or physical means (Peters, 2003).

Particulates and volatile pollutants that need to be removed before disposal may be present. Particle removal equipment includes: cyclones, wet scrubbers, electrostatic precipitators, and fabric-filter systems (Seider 2009) such as bag filters (. The two charts below are from ''Plant Design and Economics for Chemical Engineers'' and show the types of equipment, separation methods, and particle sizes in different pollutant separation technologies (Peters, 1991).

[[File:AirPolChart.png|thumb|border|center|middle|upright=4|link=|atl=|Different Methods of Particle Separation, the Particle Sizes they Can Remove, and the Technologies Used]]

[[File:AirPolTable.png|thumb|border|center|middle|upright=4|link=|atl=| This Chart Shows the Specifications and Limitations of Different Separations Technologies Including Particle Size, Efficiencies, and Temperatures(Peters, 1991)]]

====Wet Scrubbers====
Wet scrubber use lime or limestone and water to remove SO2 and acid gases. The mixture can be injected into a scrubber or the gases can be bubbled through this mixture. This results in removal of 90-98% of SO2 and and acid gases.

====Dry Scrubbers====
Dry scrubber blow powdered adsorbents into a vessel with gases and then after it has captured the SO2 and acid gases it is separated from gas using a fabric filter. These systems remove 90-93% of the contaminants.

====Low-NOx Burners====
The purpose of low NOx burners is to decrease the amount of NOx created when the coal is burned. This is done by injecting coal and air in boilers. This can result in 40-50% NOx reduction. If air is injected into the area above the burner this can actually cause almost 70% NOx reduction.

====Selective Non-Catalytic and Catalytic Reductions====
These systems inject ammonia into gases to remove NOx. The Catalytic reductions add a catalyst to the ammonia being injected to aid in the removal. Con-catalytic reductions result in about 35% removal, but adding a catalyst can increase that amount to about 90%. The catalytic-reduction can remove up to 80% of mercury as well.

====Fabric Filters====
Also known as baghouses,these [[Separation processes#Filtration| filters]] remove particulates by passing air through filters. These can separate as much as 99.9% of particulate matter.

====Electrostatic Precipitators====
Electrostatic Precicpitators remove particulate matter as gas passes through a device that has charged metal plates. The particles are then removed because of static electricity. These systems can remove between 99-99.9% of particulate matter

====Super-critical Boilers====
Super-Critical Boilers and Ultra-Supercritical Boilers operate at temperature and pressure higher than regular boilers. By operating at higher temperature these systems become more efficient. Super Critical Boilers typically have 10%-20% CO2 emissions than other similar sub-critical technologies. Ultra-Supercritical boilers can be as much as 30% more efficent than sub-critical technologies.

====More Information====

For more information regarding some of these separations equipment see [[Solids-involved equipment]]

For more information Regarding Cyclones see [[Separation processes#Cyclones| Cyclones]], and for modeling cyclones see their[[Solids-involved equipment#HYSYS Simulation|HYSYS Simulation]]

Methods for removing inorganic and organic gaseous pollutants include: absorption, adsorption, condensation, and combustion (Seider 2009 pg 609). A list of typical of gases pollutants and their sources from ''Plant Design and Economics for Chemical Engineers'' is shown below (Peters, 1991).

[[File:GaseousPollutants.png|thumb|border|center|middle|upright=4|link=|atl=| Common Gaseous Pollutants and their Sources]]

Typically Gas-liquid absorption processes are done completed in a vertical, countercurrent, flow through packed, plate, or spray towers. These systems require good liquid-gas contact and proper equipment. These systems also often have significant energy consumption because of large pressure drops (Peters, 2003). For high volume systems absorption by scrubbing with water or another solvent is the most widely used method (Towler, 2012). Dry adsorbents can be used to remove the last races of gaseous pollutants. Adsorption typically requires blowers, condensers, separators, and controls. You also typically need two packed beds so that one can be used while the other is regenerated. Examples of adsorbents are molecular sieves and activated carbon. Incineration is typically used when there are gas streams that have no recovery value. This can be done with direct flame or catalytic oxidation. Catalytic oxidation usually has higher capital costs, but lower operating costs because it does not require fuel.

You can find more information on [[Separation processes#Absorption| Absorption]] and [[Separation processes#Adsorption| Adsorption]] in [[Separation processes]]

===Outcomes===

====United States Common Pollutant Emissions====

The United States implemented the Clean Air Act in 1970 and since then emissions in the U.S. have been drastically reduced. As a matter of fact despite increases in the population in the last 35 years the amount of pollutants emitted have decreased by almost 70% (EPA). More importantly this demonstrates that reasonable efforts can be put towards environmental protection without causing too much harm to industry.

[[File:EPA.png|thumb|border|center|middle|upright=4|link=|atl=| GDP and Other Growth Factors Vs Common Pollutants Released]]

====China Clean Coal====

=====Success Through 2005=====

Coal is a very inexpensive and abundant source of energy and is abundant in China (Xu 2010). In China Coal the cause of 90% of SO2 emissions, 70% of dust emissions, and 67% of NOx emissions, and 70% of CO2 emissions. These numbers are staggering considering that Coal has never been more than 50 percent of China's Energy Supply.

[[File:Coal.jpg|thumb|border|center|middle|upright=4|link=|atl=| Coal Consumption for Power and the Percentage of Coal Used]]

Despite the increasing coal consumption, high efficiency electric dust removal systems with efficiencies that are as high as 99.6% have greatly decreased soot emissions to 32% below 1980's levels as of 2005.

[[File:Soot.jpg|thumb|border|center|middle|upright=4|link=|atl=| SO2 and Soot Emissions from 1981 to 2005]]

=====Technologies and Life Cycle Comparison=====
As of 2010 China was consuming 48.2% of coal globally. Four potential technologies integrated gasification combined cycle (IGCC), sub-critical coal power generation (Sub-C); super-critical coal power generation (Super-C) ultrasuper-critical coal power generation (USC). These technologies are compared mostly on the basis of net generating efficiency and efficiency. Net generating efficiency is the output of the plant divided by the total available energy in the fuel used.

where efficiency is define as: η=E/Etotal

and

Etotal=Emining+Etransportation+Egeneration

[[File:technologies.PNG|thumb|border|center|middle|upright=4|link=|atl=|A comparison of many of the parameters important to lfe-cycle analysis]]

This demonstrates that USC has the best net generation efficiency, while also having the largest capacity for a single system.

[[File:Lifecycle2.PNG|thumb|border|center|middle|upright=4|link=|atl=|]]

This breaks down the energy efficiency of each system and demonstrates that USC is the most efficient

[[File:Lifecycle.PNG|thumb|border|center|middle|upright=4|link=|atl=|]]

This demonstrates that the capital cost per unit of energy production is very high for IGCC, but shows that Super-C and USC are very competitive.

[[File:Price.PNG|thumb|border|center|middle|upright=4|link=|atl=| Capital cost in $/kW of clean coal power-generation technologies]]

Lastly IGCC and USC are lowest on different element, but since these all have different global warming potential it is difficult to tell which is the most efficient.

And the table below defines all the relevant terms.

[[File:GWP.PNG|thumb|border|center|middle|upright=4|link=|atl=| Environemntal measures and their explanations]]

[[File:GWP.PNG|thumb|border|center|middle|upright=4|link=|atl=| Gloabl warming] potential and other measures]

All of the data suggests that USC is the highest in both energy efficiency and net generating efficiency while competitive in price and the lowest on emissions among the different boilers.

==Solid Waste==
U.S. federal regulations require that solid waste be classified as hazardous or nonhazardous. Conditions for a classification of hazardous include: ignitability, corrosivity, reactivity, toxicity, or posing a substantial threat to the surrounding environment and its inhabitants. Hazardous waste must be treated on- or near-site before being removed in containers. Non-hazardous waste may be landfilled or incinerated in some cases. A typical estimate of costs for waste disposal is $0.03/lb for nonhazardous solids and $0.10/lb for hazardous solids. (Seider 2009 pg 609)

=References=

*Biegler LT, Grossmann IE, Westerberg AW. ''Systematic Methods of Chemical Process Design'' Prentice-Hall: Upper Saddle River, 1997.

*Broughton, J. ''Process Utility Systems: Introduction to Design, Operation and Maintenance'' Institution of Chemical Engineers: Rugby, Warwickshire, UK, 1994.

*Clean Coal Technologies. America's Coalition for Clean Coal Electricity. http://www.americaspower.org/clean-coal-technologies-1663/

*Duke Energy Company (2013). How Do Coal Fired Plants Work? Charlotte: Duke Energy.

*Lehman B, Worrell E. ''Electricity Production from Natural Gas Pressure Recovery Using Expansion Turbines.'' Lawrence Berkeley National Laboratory; 2001.

*"Overview of the Clean Air Act and Air Pollution." Environmental Protection Agency. November 17, 2015. http://www.epa.gov/clean-air-act-overview. Accessed February 5, 2016.

*"Oxygen Control." Energy Solutions Center Inc.: Boiler Consortium. http://www.cleanboiler.org/Eff_Improve/Efficiency/Oxygen_Control.asp. Accessed February 21, 2016.

*Peters, Max S.; Timmerhaus, Klaus D.; West, Ronald E. (2003). "Plant Design and Economics for Chemical Engineers." McGraw Hill Higher Education.

*Seider, Seader, Lewin, Widagdo. (2009). ''Plant Design and Economics for Chemical Engineers, 5th Edition.'' Hoboken: Wiley.

*Seider, Seader, Lewin. (2008). ''Product and Process Design Principles, 2nd Edition.'' Hoboken: Wiley.

*Summary of the Clean Water Act. United States EPA website. http://www.epa.gov/laws-regulations/summary-clean-water-act

*Towler, G.P. and Sinnot, R. (2012). ''Chemical Engineering Design: Principles, Practice and Economics of Plant and Process Design.'' Elsevier.

*Turton R.; Bailie, R.C.; Whiting, W.B.; Shaeiwitz J.A.; Bhattacharyya D. (2012). ''Analysis, Synthesis, and Design of Chemical Processes.'' Upper Saddle River: Prentice Hall.

*G.D. Ulrich, A Guide to Chemical Engineering Process Design and Economics, Wiley: New York, 1984.

File:Economizer Schematic.jpg

2016-02-22T01:07:33Z

Taunins:

Utility systems

2016-02-22T00:46:49Z

Taunins: /* Hot Utility Efficiency */

Authors: David Chen, [2014] Joshua Lee, [2015] Brett Sleyster, [2016] and Tom Aunins [2016] 

Stewards: David Chen, Jian Gong, and Fengqi You

Date Presented: January 13, 2014 /Date Revised: January 14, 2014

 


__TOC__

=Introduction=
Many chemical processes do not take place at ambient temperature or pressures. In order to reach these non-ambient conditions, utilities will have to be used to raise or lower temperatures and compress gases. (Towler, Towler/UOP) Utilities often contribute 5 to 10% of the price of a product, and may come from public or private utility companies or on-site plants. For purchased utilities, costs depend on consumption, while for company-owned utilities, there will be both capital and operating costs. They include things such as steam for heating, electricity, cooling water, refrigeration, fuels such as natural gas, wastewater treatment, waste disposal, and landfill. Steam is often the largest utility cost. Cogeneration unit can supply electricity accompanied with different steam pressures. (Seider 2009)

=Electricity=

Electricity is used to power many different kinds of equipment. It has many advantages: it is efficient (> 90%), reliable, available in a wide range of power, shaft speeds, designs, lifetimes, convenience, costs, and maintenance. It is generally used up to 200 hp, and sometimes over 10,000 Hp. In chemical process plants, the electricity demand is generally determined by the work or energy required for compression, pumping, air cooling, lights, and many other items. This electricity often times is purchased from local electricity providers, but many plants generate their own electricity via sophisticated processes.

Electricity is rarely used as a primary heat utility in large-scale chemical plants for a variety of reasons. The main disadvantages of using electricity as a heat utility are as follows (Towler 2012):

:*Heat from electricity is two to three times more expensive than heat from fuels. This is attributed to the lack of efficiency when creating heat from electricity.

:*Electrical heating units are expensive, require high maintenance, and must comply with strict safety regulations.

:*Electrical heating units are unsafe compared to steam heating units. In steam systems, the physically steam controls the temperature, whereas in electrical heating units temperature is controlled by temperature controllers, which can fail or burn out.

The use of electricity carries with it some hazards depending on the environment. Extra care must be taken when using electrically-powered equipment in areas which may have combustible fluids, vapors, or dust, and where liquids may be present. (Seider 2009 pg 606)

==Conventional Power Station==

In general, most electricity is generated from a conventional coal-fired process, whether it be on-site or purchased from a provider. Coal-fired processes have been used to create electricity throughout history, and technological advances have increased its efficiency and use worldwide. In a coal-fired steam station—much like a nuclear station—water is turned into steam, which in turn drives turbine generators to produce electricity. There are several variations on how to create energy from coal, but here are the basics of how a coal-fired process works:

[[File:coalfired.png|thumb|border|center|middle|upright=4|link=|atl=|General Coal-Fired Process Diagram (Duke Energy Company)]]

*Heat is created:
::Before the coal is burned, it is pulverized to the fineness of talcum powder. It is then mixed with hot air and blown into the firebox of the boiler. Burning in suspension, the coal/air mixture provides the most complete combustion and maximum heat possible.

*Water turns to steam:
::Highly purified water, pumped through pipes inside the boiler, is turned into steam by the heat. The steam reaches temperatures of up to 1,000 degrees Fahrenheit and pressures up to 3,500 pounds per square inch, and is piped to the turbine.

*Steam turns the turbine:
::The enormous pressure of the steam pushing against a series of giant turbine blades turns the turbine shaft. The turbine shaft is connected to the shaft of the generator, where magnets spin within wire coils to produce electricity.

*Steam is converted back to water:
::After doing its work in the turbine, the steam is drawn into a condenser, a large chamber in the basement of the power plant. In this important step, millions of gallons of cool water from a nearby source (such as a river or lake) are pumped through a network of tubes running through the condenser. The cool water in the tubes converts the steam back into water that can be used over and over again in the plant.

*Repeat:
::The cooling water is returned to its source without any contamination, and the steam water is returned to the boiler to repeat the cycle.

===Advantages & Disadvantages of Coal-Fired Energy Production===

[[File:coalfiredtable.png|thumb|border|center|middle|upright=4|link=|atl=|Advantages and Disadvantages of Coal-Fired Processes (Seider 2008)]]

==Gas-Turbine Cogeneration Process==

When generating energy on-site, many plants use a gas-turbine cogeneration process. The thermal efficiency of a gas-turbine process is in the range of 70-80% while conventional power stations, such as coal-fired processes, have a 30-40% efficiency. The lower efficiency in more conventional power stations is attributed to wasted heat in the exhaust steam in the condenser. One example of a gas-turbine process is outlined in the following figure. Figure 3.1 is a gas-turbine cogeneration process with a heat recovery steam generator (waste-heat) boiler.

[[File:cogeneration.png|thumb|border|center|middle|upright=4|link=|atl=|Gas-Turbine Cogeneration with a heat recovery steam generator boiler (Towler 2012 Fig 3.1)]]

Overall, the process illustrated is not much different from a coal-fired process. The main differences are that the cogeneration process creates both electricity and a heat utility, and cogeneration processes use natural gas instead of coal. Many of the advantages and disadvantages are similar to those of the coal-fired process, but the cogeneration has a much higher efficiency, creates heat to be used in another process, and uses a more volatile and expensive fuel. The main advantage of cogeneration over coal-fired energy production is that heat is not wasted. In coal-fired processes, heat is released and wasted during electricity generation. Cogeneration captures some, if not all of the byproduct for heat, which is an extremely useful utility that will be discussed in subsequent sections. In summary, the cogeneration plant is superior to the coal-fired process because of its higher efficiency and ability to create a useful heat utility.

Obviously any engineer would design the cogeneration plant to meet at least the energy requirement necessary for plant operation, but cogeneration plants often times are designed to exceed the plant electricity requirement to drive another source of capital. Many describe this scenario as a "make or buy" scenario (Towler 2012). This scenario provides chemical producers leverage when negotiating contracts with outsourced electricity providers and this allows plants to purchase electricity at a wholesale price. This is a huge advantage of considering on-site electricity production because electricity is needed in relatively high quantities for all chemical plants. Being able to minimize electricity costs, or even profit off of electricity production is a huge economical consideration that all plants employ.

=Process Heating=
The key objective of this section is to discuss how processes are heated. Heating utilities are necessary for proper usage of distillers, reactors, condensers, and several other integral types of equipment. More specifically, steam, fired heat, and hot oil/specialized heat transfer fluids will be discussed in the following subsections.

==Steam==
Steam is the most commonly used heat utility used in chemical plants, and as a result understanding how it is used is essential in the study of Utility systems. Steam is used both as a process fluid (feedstock, diluent to absorb heat of reaction, heating agent, and stripping agent in absorbers and adsorbers ) and utility. It can be used to drive pumps and compressors, ejectors (for producing a vacuum), and heat exchangers. As one can clearly see, steam is a versatile, and useful utility.

Here are a few advantages of using steam as opposed to other methods of process heating (Towler 2012):

:*By controlling the pressure of the steam, one can control the temperature at which the heat is released. Having a strong control over the temperature is essential in several processes. =
:*Steam is an efficient heat source because the heat of condensation of steam is very high. Meaning that there is is high output per mass of utility at a constant temperature.
:*Heat exchangers that use steam are relatively cheap because condensing steam has a high heat transfer coefficient.
:*Steam is nonflammable, nontoxic, and inert to several process fluids.

Chemical plants generally have a network of pipelines exclusively for providing steam. These networks generally have steam at a low pressure, a medium pressure, and a high pressure. The image below illustrates a basic steam system.

[[File:Steam.png|thumb|border|center|middle|upright=4|link=|atl=|(Towler 2012 Fig 3.2)]]

In the diagram above, boiler feed water at a high pressure is preheated and fed to other boilers. These other boilers superheat the steam to create a high pressure and high temperature steam stream. The steam is superheated past the dew point to account for heat loss in the pipelines. A portion of the high pressure steam is used for process heating in areas of the plant that require high temperatures. The rest of the high pressure steam is turned into medium pressure steam by valves and steam turbines. The medium pressure steam is then used to heat medium temperature processes and to form low pressure steam. The low pressure steam can be used to heat low pressure processes and it can be expanded in condensing turbines to create shaft work and energy. In summary, steam can be used for an innumerable amount of action items in a plant. High pressure, medium pressure, and low pressure steam can all be used as a heat source. Low pressure steam has utilities in creating electricity and it also has several other uses.

==Fired Heat==

In many cases, processes in a plant require a heat source stronger than high pressure and temperature steam. That is when fired heat is used, which is generally at temperatures above 523K. Streams can be heated directly in the furnace tubes or via a hot oil circuit or heat transfer fluid, which will be discussed in detail in the next section. Most fired heaters use natural gas as fuel because it burns cleaner than fuel oil. A cleaner burning fuel is always advantageous due to environmental and safety concerns. Furthermore, natural gases usually result in less wear and tear in burners and fuel lines.

Depending on the application of the fired-heater, different design specifications can be implemented to make the fired-heater as efficient as possible. The basic construction of a fired heater starts with a cylindrical chamber that is lined with with refractory bricks. The stream that is to be heated flows through tubes inside of the furnace. These tubes can be arranged in several different arrangements such as, around the walls of the furnace, or in horizontal or vertical banks (Towler 2012). The figure below illustrates the basic construction of the fired-heater and varying tube arrangements.

[[File:firedheater.png|thumb|border|center|middle|upright=4|link=|atl=|Basic Fired-Heater Diagrams (Towler 2012 Figure 19.66)]]

Fuel is burned to heat the entire furnace, and the heat transfer occurs from the combustion gases inside of the furnace across the tubes that are filled with our desired stream. The heat transfer between the tubes and the furnace is accomplished primarily via radiation. Modern designs take advantage of convective heat transfer by adding a smaller section on top of the fired-heater where the combustion gases flow over banks of tubes as seen in (c) in the figure above. Heat transfer can be further improved via convection by adding fins or pins in the combustion section.

The cost of fired heat can be calculated by the cost of fuel fired. Natural gas and heating oil are traded as commodities and prices can be found at many online trading sites or business news sites (i.e., www.cnn.money.com). Past historic prices for forecasting can be found in the Oil and Gas Journal or from the U.S. Energy Information Adminstration (www.eia.gov).

===Fuels===
Fuel is burned in utility facilities such as boilers, electricity generation, and cogeneration, and can be in solid, liquid, or gas form. It can also be burned to provide heating for a process or stream or to drive pumps and compressors. The fuel is usually burned with excess air to ensure complete combustion.

A way of quantifying the amount of heat generated is by using the heating values. Higher heating value (HHV) and the lower heating value (LHV) are used. The heating is the total heat evolved by complete combustion of a fuel with dry air with both at 60 ⁰F and the flue gas after combustion brought back down to ⁰F. If the water vapor in the flue gas is not condensed, we obtain the LHV. If the water vapor is condensed, the value of heat evolved is a bit higher, and this is the HHV.
Heating values for solids and liquids are usually on a per-mass basis, and gases on a per-volume basis.
A specified amount of heating cannot be met with the amount of fuel calculated using only the HHV. There will be heat losses, the flue gas temperature will be greater than 60 ⁰F, and water in the flue gas will typically be vapor. (Seider 608)

==Hot Oil/Specialized Heat Transfer Fluids==

Specialized heat transfer fluids and hot oil circuits are used as heat sources when steam and fired heat is not appropriate. Specialized heat transfer fluids and hot oil circuits are extremely versatile in that they can be used in the temperature range of 323K to 673K. This range however is quite variable. For hot oils, the upper temperature limit is gauged based off of the thermal decomposition of the oil and coking/fouling of heat exchanger tubes.

Hot oil circuit systems are most commonly used when the plant has several small temperature heating requirements because it is more economically sound. Rather than having several fired heaters heat each small temperature requirement, it is much more economical to have one fired heater heat the hot oil and circulate that oil through each of the process to meet all of the heat needs. Hot oil systems are also generally favored over high pressure steam in processes that involve high pressure differentials between the process stream and high pressure steam. Hot oil systems are favored in this scenario because of safety concerns. If the steam were to leak, the pressure drop could cause serious safety issues.

Mineral oils are the most commonly used heat transfer fluids, and one prominent example is Dowtherm A. Dowtherm A is a combination of 26.5 wt% diphenyl in diphenyl oxide (Towler 2012) and is extremely thermally stable. These mineral oil systems generally require high flow rates.

=Process Cooling=

==Cooling Water==
Cooling water is used to cool and/or condense streams. Cooling water is usually circulated between process heat exchangers and a cooling tower. Water is cooled during downward motion by contact with air blown upwards, which can bring the water temperature to come within ~ 5 ⁰F of air’s wet-bulb temperature.Approximately 80% of the temperature reduction is due to evaporation of the cooling water and heat transfer to the surrounding air. Water can also be cooled in spray ponds and cooling ponds. Both work by providing high area for water to exchange heat with air.
Water in cooling towers is lost through drift and blowdown, and makeup is usually 1.5 to 3% of the circulating rate.
If a large natural body of water is nearby, it can be used as a source of cooling water and discharged downstream. This water is usually filtered to remove salts and impurities that may lead to fouling, but it is not treated.

==Refrigeration==
Cooling water can usually be used to cool a stream to ~ 100 ⁰F. Air can only cool to ~ 120 ⁰F. Air may be used in places where water is scarce or more costly to transport. To cool or condense streams below 100 ⁰F, a refrigerant is typically used. Chilled brine can also be used, but is less common.

Until 1995, CFC Freon R-12 (dichlorodifuloromethane) and HCFC Freon R-22 (chlorodifuloromethane) were commonly used refrigerants. However, the chlorine atom in the molecules caused the depletion of the ozone layer. The U.S. Clean Air Act Amendments of 1990 went into effect in 1995, and the production of these refrigerants has since stopped or been greatly reduced.

Cost estimates are based on ton-day of refrigeration, where a ton is the heat that needs to be removed to freeze 1 ton per day of water at 32 ⁰F. Substitutes have since been developed. R-134a is often used in place of R-12. According to the EPA, R-134a is not combustible at ambient conditions, and is essentially non-toxic under 400 ppm, and is not ozone-depleting. (Seider pg 607)

=Energy Efficiency=
One of the chief concerns in selecting and designing process utility systems for heating and cooling is how to achieve the most energy efficient design. There are countless means by which plants lose energy, two of the foremost being through the mixing of different temperature or pressure streams and through the disposal of warmed cooling water. (Seider, 2009) Proper utilities design can help mitigate each of these losses as well as many others. The energy efficiency of a plant will depend primarily on the heating and cooling methods that are being used and the overall system design itself. These two parameters are important in determining how well energy is transferred to the desired media as well as how well that energy is recovered and recycled.

==Hot Utility Efficiency==
As mentioned above, the most commonly used utilities for process heating in large scale processes are steam, fired heat, and hot oil heaters. Of these, steam is the most commonly used. Electricity, while efficient at creating power, is not a viable source of heat in large industrial processes. Common ranges of heating efficiency for these three methods are displayed in Table 1. (Towler and Sinnott, 2012; Broughton, 1994)

{| class="wikitable"
|+Table 1: Process Heating Efficiencies
|-
! Process Heating Method
! Typical Efficiency
|-
| Steam (via coal boiler)
| 72%
|-
| Steam (via gas boiler)
| 73%
|-
| Steam (via oil boiler)
| 75%
|-
| Fired Heat w/ Convective Section
| 85%
|-
| Fired Heat w/o Convective Section
| 60%
|-
| Hot Oil Heaters/Vaporizers
| 80-85%
|}

===Steam===
As steam is so popular for heating purposes, it is useful to analyze the numerous ways in which losses can occur in steam systems. There are five primary sources of inefficiency and heat loss in the generation and distribution of steam throughout a process plant:

*The heat content of boiler exhaust gas
*Incomplete combustion of boiler fuel
*Radiant losses from the boiler exterior
*Blowdown losses
*Distribution losses (pipe transport, steam traps, etc.)

The first four of these losses take place at the boiler and contribute to the heating efficiencies seen in Table 1 for steam created with coal, gas, and oil. Several methods can be used to minimize these losses, one of the foremost being the control of air-to-fuel ratio in the boiler. This ratio must be managed by weighing losses due to uncombusted fuel against losses due to the heat content of excess exhaust gas. (Broughton, 1994)

[[File:Air-fuel ratio.PNG|thumb|border|center|middle|upright=4|link=|atl=|Air-to-fuel ratio relationship with heat losses (Broughton Fig 2.3)]]

The air-to-fuel ratio can be optimized using a feedback process controller. The control system will analyze the oxygen content of exhaust air and adjust the incoming air flow rate to achieve a set percentage of excess air. While desired excess oxygen will vary depending on the type of fuel, it is consistently seen that in the minimum loss-range a 1% increase in excess air will result in a 1% decrease in efficiency. ("Oxygen Control")

In addition to air-to-fuel ratio management, steam heat losses at the boiler can be mitigated via energy recovery, which is discussed in further detail [[Utility_systems#Energy_Recovery|below]].

Outside the boiler, losses in distribution of steam throughout facilities can decrease energy efficiency by a significant amount. This can cause up to a 60% increase in losses, but typically results in an overall steam efficiency of 50-55% (down from approximately 75% at the boiler). (Broughton, 1994) There are several ways that this issue can be addressed. First and foremost are steam metering systems, which can be used to monitor heat supply to separate sections of the process facility, check efficiency of fuel use, and determine which processes in a given plant have the highest steam requirements. Another method of minimizing transport losses is to decentralize steam generation systems. It can be advantageous to have numerous smaller boilers rather than a single centralized boiler so that steam does not have to travel as long of distances to reach its destination.

==Cold Utility Efficiency==
Efficiency in cooling processes depends more on the method used, and by extension the amount of coolant needed. Water and air utility efficiencies depend primarily on the fluid flow required to maintain the system at a desired temperature, while powered refrigeration utilities (for colder processes) have efficiencies at approximately 60%--but ranging up to 90%--of Carnot cycle efficiency, a metric of ideal refrigeration efficiency. (Towler and Sinnott, 2012) Cooling systems represent by definition a loss of energy from the main process to the utility stream, and as such it is often useful to find other uses for the heated media before discharge.

==Energy Recovery==
Recovery and recycle of energy is perhaps the most important aspect of creating an energy efficient plant design, and it is important for process engineers to fully consider possibilities for heat recovery in order to aid in economic viability.

===Process Heat Exchange===
Heat exchanger networks are a very common energy recovery method in industrial processes. These networks most frequently allow energy from heated product streams to be transferred to feed streams that must be brought up to process temperature. (Biegler, 1997) More information on the function and design of heat exchanger networks can be found on the [[Heat_exchanger#Heat_Exchanger_Networks|heat exchanger wiki page]]. The following are several examples of energy recovery via heat exchange that are used in industrial processes.

In distillation columns the bottoms and distillate effluents have the potential for energy exchange. Though the condenser at the top of the column cannot supply its waste heat to the reboiler due to their respective temperatures, the effluent streams can supply heat to the feed via a feed-effluent exchanger. This reduces the utility requirements to raise the feed to column temperature. (Biegler, 1997)

[[File:Feed_sterilization.jpg|thumb|border|right|middle|upright=4|link=|atl=|Feed sterilization schematic. (Towler and Sinnott Fig. 3.30)]]

Feed sterilization, commonly used in the food industry, is a common application for heat recovery through process stream heat exchange. In this application, the feed must be heated for a certain amount of time to kill any biological contaminants, after which it can be used to heat the new raw feed for sterilization. This reduces energy demands on the steam heater and thus reduces cost. (Towler and Sinnott, 2012)

In multi-vessel batch processes it can be advantageous to exchange heat as the process fluid is being transferred between vessels. Like the previous examples, this reduces the utility needed to bring the colder feed up to process temperature, thus reducing costs. (Towler and Sinnott, 2012)

[[File:Batch_heat_exchange.jpg|thumb|border|center|middle|upright=4|link=|atl=|Multi-vessel batch heat exchange schematic (Towler and Sinnott Fig. 3.31)]]

===Utility Regeneration===
[[File:Waste_heat_boiler.jpg|thumb|border|right|middle|upright=4|link=|atl=|Industrial modular HRSG]]
When recovery of waste heat via transfer to other process streams is inconvenient or impossible, energy efficiency can still be improved through the regeneration of utilities. This is commonly done through the regeneration of steam by either removing heat from exiting streams or from highly exothermic reactions. Waste heat in exiting streams is removed via heat recovery steam generators (HRSGs), and is most often used on exiting flue gas and exiting process gas streams. Heat recovery from reactions is a viable option when the reactor temperature will be at 150 C or above, as this will create steam at high enough pressure to be used in other processes. (Towler and Sinnott, 2012)

Furthermore, there is opportunity for energy recovery in the expansion of compressed gas through a turbine to create electricity, a process that can be economically viable given sufficiently high flows or pressure. Such technology has been used in processes to synthesize ammonia, perform air separations, and synthesize nitric acid. (Towler and Sinnott, 2012) Recently, however, there has been a particularly strong interest for energy recovery in the natural gas industry, when gas is decompressed from major pipelines to residential low-pressure piplines. A 2001 study estimated that there is the potential to recover 21 TWh, representing 11% of natural gas transport energy, via gas expansion. (Lehman)

=Process water and boiler-feed water=
Process water is water that will be directly used in the process. Boiler-feed water (BFW) is used to produce steam. Both may need to be purified to prevent impurities from contaminating a process or from foul equipment. It can be used as a cooling stream when the temperature of the stream to be cooled is greater than ~300 ⁰F. Cost of BFW can be partially offset by the steam credit.

Process water that undergoes moderate pretreatment can cost ~ $0.75/1,000 gal.

Extensive treatment ~ $6.00/1,000 gal.

Sterilized for pharmaceutical processes ~ $550/1,000 gal. (Seider pg 608)

=Demineralized Water=
In demineralized water, minerals have been removed by ion exchange. In boiler feed water, this is to prevent salt deposition, corrosion, formation of foam, and sluicing. In process water, the ions may contaminate the process.

=Waste Treatment=
Most chemical processes will produce some sort of waste. Disposal occurs to the atmosphere (in the case of some gases), sewers, body of water, or a landfill. Waste may require some treatment before disposal to meet regulations. Depending on process economics, byproducts may be recovered and processed. (Seider 2009 pg 609)

==Wastewater Treatment==
The United States EPA regulates industrial wastewater disposal through the Clean Water Act, introduced in 1948 as the Federal Water Pollution Control Act and amended to its current form in 1972. The sweeping 1972 amendments allowed the EPA to prevent industries and persons from discharging contaminated water into fresh water sources and set water quality standards. (Summary of the Clean Water Act) In accordance with this law, process plants in the United States treat wastewater at on-site or near-site treatment centers before releasing it into the surrounding environment.

Wastewater effluent streams, along with water runoff from around the plant, are treated to control for pH, toxicity, suspended solids, and biological oxygen demand (for aquatic life protection) prior to discharge. Each of these controls is typically addressed with a separate method. Acidity and basicity is balanced through the addition of an acid or alkaline solution. Toxic wastewater may be treated with chemical processes or simply diluted to safe concentrations. Suspended solids can be removed via filtration and/or with clarifiers. Oxygen demand of wastewater can be mitigated using activated sludge treatment processes. Once the water quality complies with the EPA, and state-mandated, regulations, it can be safely released. More information on the large number of industry-specific guidelines for waste effluent can be found on the EPA website (http://www.epa.gov/eg/industrial-effluent-guidelines).

==Air-Pollution Management==
===Introduction===

In the United States air pollution is regulated in the Clean Air Act, and almost all pollutant emitting plants are regulated under this law. The types of plants that can release significant emissions include petroleum refineries, sulfur recovery plants, carbon-black plants, fuel conversion plants, chemical process plants, fossil fuel plants, and petroleum storage and transfer facilities. To receive permission to construct a plant must undergo a review to show that it will not cause a violation of the Ambient Air Quality Standards(Peters, 2003).

===Methods===

There are two major types of pollutants that are released into the air, particulates and and gaseous pollutants. Particulates can be removed with mechanical forces while gaseous pollutants typically need to removed by chemical or physical means (Peters, 2003).

Particulates and volatile pollutants that need to be removed before disposal may be present. Particle removal equipment includes: cyclones, wet scrubbers, electrostatic precipitators, and fabric-filter systems (Seider 2009) such as bag filters (. The two charts below are from ''Plant Design and Economics for Chemical Engineers'' and show the types of equipment, separation methods, and particle sizes in different pollutant separation technologies (Peters, 1991).

[[File:AirPolChart.png|thumb|border|center|middle|upright=4|link=|atl=|Different Methods of Particle Separation, the Particle Sizes they Can Remove, and the Technologies Used]]

[[File:AirPolTable.png|thumb|border|center|middle|upright=4|link=|atl=| This Chart Shows the Specifications and Limitations of Different Separations Technologies Including Particle Size, Efficiencies, and Temperatures(Peters, 1991)]]

====Wet Scrubbers====
Wet scrubber use lime or limestone and water to remove SO2 and acid gases. The mixture can be injected into a scrubber or the gases can be bubbled through this mixture. This results in removal of 90-98% of SO2 and and acid gases.

====Dry Scrubbers====
Dry scrubber blow powdered adsorbents into a vessel with gases and then after it has captured the SO2 and acid gases it is separated from gas using a fabric filter. These systems remove 90-93% of the contaminants.

====Low-NOx Burners====
The purpose of low NOx burners is to decrease the amount of NOx created when the coal is burned. This is done by injecting coal and air in boilers. This can result in 40-50% NOx reduction. If air is injected into the area above the burner this can actually cause almost 70% NOx reduction.

====Selective Non-Catalytic and Catalytic Reductions====
These systems inject ammonia into gases to remove NOx. The Catalytic reductions add a catalyst to the ammonia being injected to aid in the removal. Con-catalytic reductions result in about 35% removal, but adding a catalyst can increase that amount to about 90%. The catalytic-reduction can remove up to 80% of mercury as well.

====Fabric Filters====
Also known as baghouses,these [[Separation processes#Filtration| filters]] remove particulates by passing air through filters. These can separate as much as 99.9% of particulate matter.

====Electrostatic Precipitators====
Electrostatic Precicpitators remove particulate matter as gas passes through a device that has charged metal plates. The particles are then removed because of static electricity. These systems can remove between 99-99.9% of particulate matter

====Super-critical Boilers====
Super-Critical Boilers and Ultra-Supercritical Boilers operate at temperature and pressure higher than regular boilers. By operating at higher temperature these systems become more efficient. Super Critical Boilers typically have 10%-20% CO2 emissions than other similar sub-critical technologies. Ultra-Supercritical boilers can be as much as 30% more efficent than sub-critical technologies.

====More Information====

For more information regarding some of these separations equipment see [[Solids-involved equipment]]

For more information Regarding Cyclones see [[Separation processes#Cyclones| Cyclones]], and for modeling cyclones see their[[Solids-involved equipment#HYSYS Simulation|HYSYS Simulation]]

Methods for removing inorganic and organic gaseous pollutants include: absorption, adsorption, condensation, and combustion (Seider 2009 pg 609). A list of typical of gases pollutants and their sources from ''Plant Design and Economics for Chemical Engineers'' is shown below (Peters, 1991).

[[File:GaseousPollutants.png|thumb|border|center|middle|upright=4|link=|atl=| Common Gaseous Pollutants and their Sources]]

Typically Gas-liquid absorption processes are done completed in a vertical, countercurrent, flow through packed, plate, or spray towers. These systems require good liquid-gas contact and proper equipment. These systems also often have significant energy consumption because of large pressure drops (Peters, 2003). For high volume systems absorption by scrubbing with water or another solvent is the most widely used method (Towler, 2012). Dry adsorbents can be used to remove the last races of gaseous pollutants. Adsorption typically requires blowers, condensers, separators, and controls. You also typically need two packed beds so that one can be used while the other is regenerated. Examples of adsorbents are molecular sieves and activated carbon. Incineration is typically used when there are gas streams that have no recovery value. This can be done with direct flame or catalytic oxidation. Catalytic oxidation usually has higher capital costs, but lower operating costs because it does not require fuel.

You can find more information on [[Separation processes#Absorption| Absorption]] and [[Separation processes#Adsorption| Adsorption]] in [[Separation processes]]

===Outcomes===

====United States Common Pollutant Emissions====

The United States implemented the Clean Air Act in 1970 and since then emissions in the U.S. have been drastically reduced. As a matter of fact despite increases in the population in the last 35 years the amount of pollutants emitted have decreased by almost 70% (EPA). More importantly this demonstrates that reasonable efforts can be put towards environmental protection without causing too much harm to industry.

[[File:EPA.png|thumb|border|center|middle|upright=4|link=|atl=| GDP and Other Growth Factors Vs Common Pollutants Released]]

====China Clean Coal====

=====Success Through 2005=====

Coal is a very inexpensive and abundant source of energy and is abundant in China (Xu 2010). In China Coal the cause of 90% of SO2 emissions, 70% of dust emissions, and 67% of NOx emissions, and 70% of CO2 emissions. These numbers are staggering considering that Coal has never been more than 50 percent of China's Energy Supply.

[[File:Coal.jpg|thumb|border|center|middle|upright=4|link=|atl=| Coal Consumption for Power and the Percentage of Coal Used]]

Despite the increasing coal consumption, high efficiency electric dust removal systems with efficiencies that are as high as 99.6% have greatly decreased soot emissions to 32% below 1980's levels as of 2005.

[[File:Soot.jpg|thumb|border|center|middle|upright=4|link=|atl=| SO2 and Soot Emissions from 1981 to 2005]]

=====Technologies and Life Cycle Comparison=====
As of 2010 China was consuming 48.2% of coal globally. Four potential technologies integrated gasification combined cycle (IGCC), sub-critical coal power generation (Sub-C); super-critical coal power generation (Super-C) ultrasuper-critical coal power generation (USC). These technologies are compared mostly on the basis of net generating efficiency and efficiency. Net generating efficiency is the output of the plant divided by the total available energy in the fuel used.

where efficiency is define as: η=E/Etotal

and

Etotal=Emining+Etransportation+Egeneration

[[File:technologies.PNG|thumb|border|center|middle|upright=4|link=|atl=|A comparison of many of the parameters important to lfe-cycle analysis]]

This demonstrates that USC has the best net generation efficiency, while also having the largest capacity for a single system.

[[File:Lifecycle2.PNG|thumb|border|center|middle|upright=4|link=|atl=|]]

This breaks down the energy efficiency of each system and demonstrates that USC is the most efficient

[[File:Lifecycle.PNG|thumb|border|center|middle|upright=4|link=|atl=|]]

This demonstrates that the capital cost per unit of energy production is very high for IGCC, but shows that Super-C and USC are very competitive.

[[File:Price.PNG|thumb|border|center|middle|upright=4|link=|atl=| Capital cost in $/kW of clean coal power-generation technologies]]

Lastly IGCC and USC are lowest on different element, but since these all have different global warming potential it is difficult to tell which is the most efficient.

And the table below defines all the relevant terms.

[[File:GWP.PNG|thumb|border|center|middle|upright=4|link=|atl=| Environemntal measures and their explanations]]

[[File:GWP.PNG|thumb|border|center|middle|upright=4|link=|atl=| Gloabl warming] potential and other measures]

All of the data suggests that USC is the highest in both energy efficiency and net generating efficiency while competitive in price and the lowest on emissions among the different boilers.

==Solid Waste==
U.S. federal regulations require that solid waste be classified as hazardous or nonhazardous. Conditions for a classification of hazardous include: ignitability, corrosivity, reactivity, toxicity, or posing a substantial threat to the surrounding environment and its inhabitants. Hazardous waste must be treated on- or near-site before being removed in containers. Non-hazardous waste may be landfilled or incinerated in some cases. A typical estimate of costs for waste disposal is $0.03/lb for nonhazardous solids and $0.10/lb for hazardous solids. (Seider 2009 pg 609)

=References=

*Biegler LT, Grossmann IE, Westerberg AW. ''Systematic Methods of Chemical Process Design'' Prentice-Hall: Upper Saddle River, 1997.

*Broughton, J. ''Process Utility Systems: Introduction to Design, Operation and Maintenance'' Institution of Chemical Engineers: Rugby, Warwickshire, UK, 1994.

*Duke Energy Company (2013). How Do Coal Fired Plants Work? Charlotte: Duke Energy.

*Lehman B, Worrell E. ''Electricity Production from Natural Gas Pressure Recovery Using Expansion Turbines.'' Lawrence Berkeley National Laboratory; 2001.

*"Overview of the Clean Air Act and Air Pollution." Environmental Protection Agency. November 17, 2015. http://www.epa.gov/clean-air-act-overview. Accessed February 5, 2016.

*"Oxygen Control." Energy Solutions Center Inc.: Boiler Consortium. http://www.cleanboiler.org/Eff_Improve/Efficiency/Oxygen_Control.asp. Accessed February 21, 2016.

*Peters, Max S.; Timmerhaus, Klaus D.; West, Ronald E. (2003). "Plant Design and Economics for Chemical Engineers." McGraw Hill Higher Education.

*Seider, Seader, Lewin, Widagdo. (2009). ''Plant Design and Economics for Chemical Engineers, 5th Edition.'' Hoboken: Wiley.

*Seider, Seader, Lewin. (2008). ''Product and Process Design Principles, 2nd Edition.'' Hoboken: Wiley.

*Summary of the Clean Water Act. United States EPA website. http://www.epa.gov/laws-regulations/summary-clean-water-act

*Towler, G.P. and Sinnot, R. (2012). ''Chemical Engineering Design: Principles, Practice and Economics of Plant and Process Design.'' Elsevier.

*Turton R.; Bailie, R.C.; Whiting, W.B.; Shaeiwitz J.A.; Bhattacharyya D. (2012). ''Analysis, Synthesis, and Design of Chemical Processes.'' Upper Saddle River: Prentice Hall.

*G.D. Ulrich, A Guide to Chemical Engineering Process Design and Economics, Wiley: New York, 1984.

Utility systems

2016-02-22T00:25:50Z

Taunins: /* References */

Authors: David Chen, [2014] Joshua Lee, [2015] Brett Sleyster, [2016] and Tom Aunins [2016] 

Stewards: David Chen, Jian Gong, and Fengqi You

Date Presented: January 13, 2014 /Date Revised: January 14, 2014

 


__TOC__

=Introduction=
Many chemical processes do not take place at ambient temperature or pressures. In order to reach these non-ambient conditions, utilities will have to be used to raise or lower temperatures and compress gases. (Towler, Towler/UOP) Utilities often contribute 5 to 10% of the price of a product, and may come from public or private utility companies or on-site plants. For purchased utilities, costs depend on consumption, while for company-owned utilities, there will be both capital and operating costs. They include things such as steam for heating, electricity, cooling water, refrigeration, fuels such as natural gas, wastewater treatment, waste disposal, and landfill. Steam is often the largest utility cost. Cogeneration unit can supply electricity accompanied with different steam pressures. (Seider 2009)

=Electricity=

Electricity is used to power many different kinds of equipment. It has many advantages: it is efficient (> 90%), reliable, available in a wide range of power, shaft speeds, designs, lifetimes, convenience, costs, and maintenance. It is generally used up to 200 hp, and sometimes over 10,000 Hp. In chemical process plants, the electricity demand is generally determined by the work or energy required for compression, pumping, air cooling, lights, and many other items. This electricity often times is purchased from local electricity providers, but many plants generate their own electricity via sophisticated processes.

Electricity is rarely used as a primary heat utility in large-scale chemical plants for a variety of reasons. The main disadvantages of using electricity as a heat utility are as follows (Towler 2012):

:*Heat from electricity is two to three times more expensive than heat from fuels. This is attributed to the lack of efficiency when creating heat from electricity.

:*Electrical heating units are expensive, require high maintenance, and must comply with strict safety regulations.

:*Electrical heating units are unsafe compared to steam heating units. In steam systems, the physically steam controls the temperature, whereas in electrical heating units temperature is controlled by temperature controllers, which can fail or burn out.

The use of electricity carries with it some hazards depending on the environment. Extra care must be taken when using electrically-powered equipment in areas which may have combustible fluids, vapors, or dust, and where liquids may be present. (Seider 2009 pg 606)

==Conventional Power Station==

In general, most electricity is generated from a conventional coal-fired process, whether it be on-site or purchased from a provider. Coal-fired processes have been used to create electricity throughout history, and technological advances have increased its efficiency and use worldwide. In a coal-fired steam station—much like a nuclear station—water is turned into steam, which in turn drives turbine generators to produce electricity. There are several variations on how to create energy from coal, but here are the basics of how a coal-fired process works:

[[File:coalfired.png|thumb|border|center|middle|upright=4|link=|atl=|General Coal-Fired Process Diagram (Duke Energy Company)]]

*Heat is created:
::Before the coal is burned, it is pulverized to the fineness of talcum powder. It is then mixed with hot air and blown into the firebox of the boiler. Burning in suspension, the coal/air mixture provides the most complete combustion and maximum heat possible.

*Water turns to steam:
::Highly purified water, pumped through pipes inside the boiler, is turned into steam by the heat. The steam reaches temperatures of up to 1,000 degrees Fahrenheit and pressures up to 3,500 pounds per square inch, and is piped to the turbine.

*Steam turns the turbine:
::The enormous pressure of the steam pushing against a series of giant turbine blades turns the turbine shaft. The turbine shaft is connected to the shaft of the generator, where magnets spin within wire coils to produce electricity.

*Steam is converted back to water:
::After doing its work in the turbine, the steam is drawn into a condenser, a large chamber in the basement of the power plant. In this important step, millions of gallons of cool water from a nearby source (such as a river or lake) are pumped through a network of tubes running through the condenser. The cool water in the tubes converts the steam back into water that can be used over and over again in the plant.

*Repeat:
::The cooling water is returned to its source without any contamination, and the steam water is returned to the boiler to repeat the cycle.

===Advantages & Disadvantages of Coal-Fired Energy Production===

[[File:coalfiredtable.png|thumb|border|center|middle|upright=4|link=|atl=|Advantages and Disadvantages of Coal-Fired Processes (Seider 2008)]]

==Gas-Turbine Cogeneration Process==

When generating energy on-site, many plants use a gas-turbine cogeneration process. The thermal efficiency of a gas-turbine process is in the range of 70-80% while conventional power stations, such as coal-fired processes, have a 30-40% efficiency. The lower efficiency in more conventional power stations is attributed to wasted heat in the exhaust steam in the condenser. One example of a gas-turbine process is outlined in the following figure. Figure 3.1 is a gas-turbine cogeneration process with a heat recovery steam generator (waste-heat) boiler.

[[File:cogeneration.png|thumb|border|center|middle|upright=4|link=|atl=|Gas-Turbine Cogeneration with a heat recovery steam generator boiler (Towler 2012 Fig 3.1)]]

Overall, the process illustrated is not much different from a coal-fired process. The main differences are that the cogeneration process creates both electricity and a heat utility, and cogeneration processes use natural gas instead of coal. Many of the advantages and disadvantages are similar to those of the coal-fired process, but the cogeneration has a much higher efficiency, creates heat to be used in another process, and uses a more volatile and expensive fuel. The main advantage of cogeneration over coal-fired energy production is that heat is not wasted. In coal-fired processes, heat is released and wasted during electricity generation. Cogeneration captures some, if not all of the byproduct for heat, which is an extremely useful utility that will be discussed in subsequent sections. In summary, the cogeneration plant is superior to the coal-fired process because of its higher efficiency and ability to create a useful heat utility.

Obviously any engineer would design the cogeneration plant to meet at least the energy requirement necessary for plant operation, but cogeneration plants often times are designed to exceed the plant electricity requirement to drive another source of capital. Many describe this scenario as a "make or buy" scenario (Towler 2012). This scenario provides chemical producers leverage when negotiating contracts with outsourced electricity providers and this allows plants to purchase electricity at a wholesale price. This is a huge advantage of considering on-site electricity production because electricity is needed in relatively high quantities for all chemical plants. Being able to minimize electricity costs, or even profit off of electricity production is a huge economical consideration that all plants employ.

=Process Heating=
The key objective of this section is to discuss how processes are heated. Heating utilities are necessary for proper usage of distillers, reactors, condensers, and several other integral types of equipment. More specifically, steam, fired heat, and hot oil/specialized heat transfer fluids will be discussed in the following subsections.

==Steam==
Steam is the most commonly used heat utility used in chemical plants, and as a result understanding how it is used is essential in the study of Utility systems. Steam is used both as a process fluid (feedstock, diluent to absorb heat of reaction, heating agent, and stripping agent in absorbers and adsorbers ) and utility. It can be used to drive pumps and compressors, ejectors (for producing a vacuum), and heat exchangers. As one can clearly see, steam is a versatile, and useful utility.

Here are a few advantages of using steam as opposed to other methods of process heating (Towler 2012):

:*By controlling the pressure of the steam, one can control the temperature at which the heat is released. Having a strong control over the temperature is essential in several processes. =
:*Steam is an efficient heat source because the heat of condensation of steam is very high. Meaning that there is is high output per mass of utility at a constant temperature.
:*Heat exchangers that use steam are relatively cheap because condensing steam has a high heat transfer coefficient.
:*Steam is nonflammable, nontoxic, and inert to several process fluids.

Chemical plants generally have a network of pipelines exclusively for providing steam. These networks generally have steam at a low pressure, a medium pressure, and a high pressure. The image below illustrates a basic steam system.

[[File:Steam.png|thumb|border|center|middle|upright=4|link=|atl=|(Towler 2012 Fig 3.2)]]

In the diagram above, boiler feed water at a high pressure is preheated and fed to other boilers. These other boilers superheat the steam to create a high pressure and high temperature steam stream. The steam is superheated past the dew point to account for heat loss in the pipelines. A portion of the high pressure steam is used for process heating in areas of the plant that require high temperatures. The rest of the high pressure steam is turned into medium pressure steam by valves and steam turbines. The medium pressure steam is then used to heat medium temperature processes and to form low pressure steam. The low pressure steam can be used to heat low pressure processes and it can be expanded in condensing turbines to create shaft work and energy. In summary, steam can be used for an innumerable amount of action items in a plant. High pressure, medium pressure, and low pressure steam can all be used as a heat source. Low pressure steam has utilities in creating electricity and it also has several other uses.

==Fired Heat==

In many cases, processes in a plant require a heat source stronger than high pressure and temperature steam. That is when fired heat is used, which is generally at temperatures above 523K. Streams can be heated directly in the furnace tubes or via a hot oil circuit or heat transfer fluid, which will be discussed in detail in the next section. Most fired heaters use natural gas as fuel because it burns cleaner than fuel oil. A cleaner burning fuel is always advantageous due to environmental and safety concerns. Furthermore, natural gases usually result in less wear and tear in burners and fuel lines.

Depending on the application of the fired-heater, different design specifications can be implemented to make the fired-heater as efficient as possible. The basic construction of a fired heater starts with a cylindrical chamber that is lined with with refractory bricks. The stream that is to be heated flows through tubes inside of the furnace. These tubes can be arranged in several different arrangements such as, around the walls of the furnace, or in horizontal or vertical banks (Towler 2012). The figure below illustrates the basic construction of the fired-heater and varying tube arrangements.

[[File:firedheater.png|thumb|border|center|middle|upright=4|link=|atl=|Basic Fired-Heater Diagrams (Towler 2012 Figure 19.66)]]

Fuel is burned to heat the entire furnace, and the heat transfer occurs from the combustion gases inside of the furnace across the tubes that are filled with our desired stream. The heat transfer between the tubes and the furnace is accomplished primarily via radiation. Modern designs take advantage of convective heat transfer by adding a smaller section on top of the fired-heater where the combustion gases flow over banks of tubes as seen in (c) in the figure above. Heat transfer can be further improved via convection by adding fins or pins in the combustion section.

The cost of fired heat can be calculated by the cost of fuel fired. Natural gas and heating oil are traded as commodities and prices can be found at many online trading sites or business news sites (i.e., www.cnn.money.com). Past historic prices for forecasting can be found in the Oil and Gas Journal or from the U.S. Energy Information Adminstration (www.eia.gov).

===Fuels===
Fuel is burned in utility facilities such as boilers, electricity generation, and cogeneration, and can be in solid, liquid, or gas form. It can also be burned to provide heating for a process or stream or to drive pumps and compressors. The fuel is usually burned with excess air to ensure complete combustion.

A way of quantifying the amount of heat generated is by using the heating values. Higher heating value (HHV) and the lower heating value (LHV) are used. The heating is the total heat evolved by complete combustion of a fuel with dry air with both at 60 ⁰F and the flue gas after combustion brought back down to ⁰F. If the water vapor in the flue gas is not condensed, we obtain the LHV. If the water vapor is condensed, the value of heat evolved is a bit higher, and this is the HHV.
Heating values for solids and liquids are usually on a per-mass basis, and gases on a per-volume basis.
A specified amount of heating cannot be met with the amount of fuel calculated using only the HHV. There will be heat losses, the flue gas temperature will be greater than 60 ⁰F, and water in the flue gas will typically be vapor. (Seider 608)

==Hot Oil/Specialized Heat Transfer Fluids==

Specialized heat transfer fluids and hot oil circuits are used as heat sources when steam and fired heat is not appropriate. Specialized heat transfer fluids and hot oil circuits are extremely versatile in that they can be used in the temperature range of 323K to 673K. This range however is quite variable. For hot oils, the upper temperature limit is gauged based off of the thermal decomposition of the oil and coking/fouling of heat exchanger tubes.

Hot oil circuit systems are most commonly used when the plant has several small temperature heating requirements because it is more economically sound. Rather than having several fired heaters heat each small temperature requirement, it is much more economical to have one fired heater heat the hot oil and circulate that oil through each of the process to meet all of the heat needs. Hot oil systems are also generally favored over high pressure steam in processes that involve high pressure differentials between the process stream and high pressure steam. Hot oil systems are favored in this scenario because of safety concerns. If the steam were to leak, the pressure drop could cause serious safety issues.

Mineral oils are the most commonly used heat transfer fluids, and one prominent example is Dowtherm A. Dowtherm A is a combination of 26.5 wt% diphenyl in diphenyl oxide (Towler 2012) and is extremely thermally stable. These mineral oil systems generally require high flow rates.

=Process Cooling=

==Cooling Water==
Cooling water is used to cool and/or condense streams. Cooling water is usually circulated between process heat exchangers and a cooling tower. Water is cooled during downward motion by contact with air blown upwards, which can bring the water temperature to come within ~ 5 ⁰F of air’s wet-bulb temperature.Approximately 80% of the temperature reduction is due to evaporation of the cooling water and heat transfer to the surrounding air. Water can also be cooled in spray ponds and cooling ponds. Both work by providing high area for water to exchange heat with air.
Water in cooling towers is lost through drift and blowdown, and makeup is usually 1.5 to 3% of the circulating rate.
If a large natural body of water is nearby, it can be used as a source of cooling water and discharged downstream. This water is usually filtered to remove salts and impurities that may lead to fouling, but it is not treated.

==Refrigeration==
Cooling water can usually be used to cool a stream to ~ 100 ⁰F. Air can only cool to ~ 120 ⁰F. Air may be used in places where water is scarce or more costly to transport. To cool or condense streams below 100 ⁰F, a refrigerant is typically used. Chilled brine can also be used, but is less common.

Until 1995, CFC Freon R-12 (dichlorodifuloromethane) and HCFC Freon R-22 (chlorodifuloromethane) were commonly used refrigerants. However, the chlorine atom in the molecules caused the depletion of the ozone layer. The U.S. Clean Air Act Amendments of 1990 went into effect in 1995, and the production of these refrigerants has since stopped or been greatly reduced.

Cost estimates are based on ton-day of refrigeration, where a ton is the heat that needs to be removed to freeze 1 ton per day of water at 32 ⁰F. Substitutes have since been developed. R-134a is often used in place of R-12. According to the EPA, R-134a is not combustible at ambient conditions, and is essentially non-toxic under 400 ppm, and is not ozone-depleting. (Seider pg 607)

=Energy Efficiency=
One of the chief concerns in selecting and designing process utility systems for heating and cooling is how to achieve the most energy efficient design. There are countless means by which plants lose energy, two of the foremost being through the mixing of different temperature or pressure streams and through the disposal of warmed cooling water. (Seider, 2009) Proper utilities design can help mitigate each of these losses as well as many others. The energy efficiency of a plant will depend primarily on the heating and cooling methods that are being used and the overall system design itself. These two parameters are important in determining how well energy is transferred to the desired media as well as how well that energy is recovered and recycled.

==Hot Utility Efficiency==
As mentioned above, the most commonly used utilities for process heating in large scale processes are steam, fired heat, and hot oil heaters. Of these, steam is the most commonly used. Electricity, while efficient at creating power, is not a viable source of heat in large industrial processes. Common ranges of heating efficiency for these three methods are displayed in Table 1. (Towler and Sinnott, 2012)

{| class="wikitable"
|+Table 1: Process Heating Efficiencies
|-
! Process Heating Method
! Typical Efficiency
|-
| Steam (via coal boiler)
| 72%
|-
| Steam (via gas boiler)
| 73%
|-
| Steam (via oil boiler)
| 75%
|-
| Fired Heat w/ Convective Section
| 85%
|-
| Fired Heat w/o Convective Section
| 60%
|-
| Hot Oil Heaters/Vaporizers
| 80-85%
|}

===Steam===

==Cold Utility Efficiency==
Efficiency in cooling processes depends more on the method used, and by extension the amount of coolant needed. Water and air utility efficiencies depend primarily on the fluid flow required to maintain the system at a desired temperature, while powered refrigeration utilities (for colder processes) have efficiencies at approximately 60%--but ranging up to 90%--of Carnot cycle efficiency, a metric of ideal refrigeration efficiency. (Towler and Sinnott, 2012) Cooling systems represent by definition a loss of energy from the main process to the utility stream, and as such it is often useful to find other uses for the heated media before discharge.

==Energy Recovery==
Recovery and recycle of energy is perhaps the most important aspect of creating an energy efficient plant design, and it is important for process engineers to fully consider possibilities for heat recovery in order to aid in economic viability.

===Process Heat Exchange===
Heat exchanger networks are a very common energy recovery method in industrial processes. These networks most frequently allow energy from heated product streams to be transferred to feed streams that must be brought up to process temperature. (Biegler, 1997) More information on the function and design of heat exchanger networks can be found on the [[Heat_exchanger#Heat_Exchanger_Networks|heat exchanger wiki page]]. The following are several examples of energy recovery via heat exchange that are used in industrial processes.

In distillation columns the bottoms and distillate effluents have the potential for energy exchange. Though the condenser at the top of the column cannot supply its waste heat to the reboiler due to their respective temperatures, the effluent streams can supply heat to the feed via a feed-effluent exchanger. This reduces the utility requirements to raise the feed to column temperature. (Biegler, 1997)

[[File:Feed_sterilization.jpg|thumb|border|right|middle|upright=4|link=|atl=|Feed sterilization schematic. (Towler and Sinnott Fig. 3.30)]]

Feed sterilization, commonly used in the food industry, is a common application for heat recovery through process stream heat exchange. In this application, the feed must be heated for a certain amount of time to kill any biological contaminants, after which it can be used to heat the new raw feed for sterilization. This reduces energy demands on the steam heater and thus reduces cost. (Towler and Sinnott, 2012)

In multi-vessel batch processes it can be advantageous to exchange heat as the process fluid is being transferred between vessels. Like the previous examples, this reduces the utility needed to bring the colder feed up to process temperature, thus reducing costs. (Towler and Sinnott, 2012)

[[File:Batch_heat_exchange.jpg|thumb|border|center|middle|upright=4|link=|atl=|Multi-vessel batch heat exchange schematic (Towler and Sinnott Fig. 3.31)]]

===Utility Regeneration===
[[File:Waste_heat_boiler.jpg|thumb|border|right|middle|upright=4|link=|atl=|Industrial modular HRSG]]
When recovery of waste heat via transfer to other process streams is inconvenient or impossible, energy efficiency can still be improved through the regeneration of utilities. This is commonly done through the regeneration of steam by either removing heat from exiting streams or from highly exothermic reactions. Waste heat in exiting streams is removed via heat recovery steam generators (HRSGs), and is most often used on exiting flue gas and exiting process gas streams. Heat recovery from reactions is a viable option when the reactor temperature will be at 150 C or above, as this will create steam at high enough pressure to be used in other processes. (Towler and Sinnott, 2012)

Furthermore, there is opportunity for energy recovery in the expansion of compressed gas through a turbine to create electricity, a process that can be economically viable given sufficiently high flows or pressure. Such technology has been used in processes to synthesize ammonia, perform air separations, and synthesize nitric acid. (Towler and Sinnott, 2012) Recently, however, there has been a particularly strong interest for energy recovery in the natural gas industry, when gas is decompressed from major pipelines to residential low-pressure piplines. A 2001 study estimated that there is the potential to recover 21 TWh, representing 11% of natural gas transport energy, via gas expansion. (Lehman)

=Process water and boiler-feed water=
Process water is water that will be directly used in the process. Boiler-feed water (BFW) is used to produce steam. Both may need to be purified to prevent impurities from contaminating a process or from foul equipment. It can be used as a cooling stream when the temperature of the stream to be cooled is greater than ~300 ⁰F. Cost of BFW can be partially offset by the steam credit.

Process water that undergoes moderate pretreatment can cost ~ $0.75/1,000 gal.

Extensive treatment ~ $6.00/1,000 gal.

Sterilized for pharmaceutical processes ~ $550/1,000 gal. (Seider pg 608)

=Demineralized Water=
In demineralized water, minerals have been removed by ion exchange. In boiler feed water, this is to prevent salt deposition, corrosion, formation of foam, and sluicing. In process water, the ions may contaminate the process.

=Waste Treatment=
Most chemical processes will produce some sort of waste. Disposal occurs to the atmosphere (in the case of some gases), sewers, body of water, or a landfill. Waste may require some treatment before disposal to meet regulations. Depending on process economics, byproducts may be recovered and processed. (Seider 2009 pg 609)

==Wastewater Treatment==
The United States EPA regulates industrial wastewater disposal through the Clean Water Act, introduced in 1948 as the Federal Water Pollution Control Act and amended to its current form in 1972. The sweeping 1972 amendments allowed the EPA to prevent industries and persons from discharging contaminated water into fresh water sources and set water quality standards. (Summary of the Clean Water Act) In accordance with this law, process plants in the United States treat wastewater at on-site or near-site treatment centers before releasing it into the surrounding environment.

Wastewater effluent streams, along with water runoff from around the plant, are treated to control for pH, toxicity, suspended solids, and biological oxygen demand (for aquatic life protection) prior to discharge. Each of these controls is typically addressed with a separate method. Acidity and basicity is balanced through the addition of an acid or alkaline solution. Toxic wastewater may be treated with chemical processes or simply diluted to safe concentrations. Suspended solids can be removed via filtration and/or with clarifiers. Oxygen demand of wastewater can be mitigated using activated sludge treatment processes. Once the water quality complies with the EPA, and state-mandated, regulations, it can be safely released. More information on the large number of industry-specific guidelines for waste effluent can be found on the EPA website (http://www.epa.gov/eg/industrial-effluent-guidelines).

==Air-Pollution Management==
===Introduction===

In the United States air pollution is regulated in the Clean Air Act, and almost all pollutant emitting plants are regulated under this law. The types of plants that can release significant emissions include petroleum refineries, sulfur recovery plants, carbon-black plants, fuel conversion plants, chemical process plants, fossil fuel plants, and petroleum storage and transfer facilities. To receive permission to construct a plant must undergo a review to show that it will not cause a violation of the Ambient Air Quality Standards(Peters, 2003).

===Methods===

There are two major types of pollutants that are released into the air, particulates and and gaseous pollutants. Particulates can be removed with mechanical forces while gaseous pollutants typically need to removed by chemical or physical means (Peters, 2003).

Particulates and volatile pollutants that need to be removed before disposal may be present. Particle removal equipment includes: cyclones, wet scrubbers, electrostatic precipitators, and fabric-filter systems (Seider 2009) such as bag filters (. The two charts below are from ''Plant Design and Economics for Chemical Engineers'' and show the types of equipment, separation methods, and particle sizes in different pollutant separation technologies (Peters, 1991).

[[File:AirPolChart.png|thumb|border|center|middle|upright=4|link=|atl=|Different Methods of Particle Separation, the Particle Sizes they Can Remove, and the Technologies Used]]

[[File:AirPolTable.png|thumb|border|center|middle|upright=4|link=|atl=| This Chart Shows the Specifications and Limitations of Different Separations Technologies Including Particle Size, Efficiencies, and Temperatures(Peters, 1991)]]

====Wet Scrubbers====
Wet scrubber use lime or limestone and water to remove SO2 and acid gases. The mixture can be injected into a scrubber or the gases can be bubbled through this mixture. This results in removal of 90-98% of SO2 and and acid gases.

====Dry Scrubbers====
Dry scrubber blow powdered adsorbents into a vessel with gases and then after it has captured the SO2 and acid gases it is separated from gas using a fabric filter. These systems remove 90-93% of the contaminants.

====Low-NOx Burners====
The purpose of low NOx burners is to decrease the amount of NOx created when the coal is burned. This is done by injecting coal and air in boilers. This can result in 40-50% NOx reduction. If air is injected into the area above the burner this can actually cause almost 70% NOx reduction.

====Selective Non-Catalytic and Catalytic Reductions====
These systems inject ammonia into gases to remove NOx. The Catalytic reductions add a catalyst to the ammonia being injected to aid in the removal. Con-catalytic reductions result in about 35% removal, but adding a catalyst can increase that amount to about 90%. The catalytic-reduction can remove up to 80% of mercury as well.

====Fabric Filters====
Also known as baghouses,these [[Separation processes#Filtration| filters]] remove particulates by passing air through filters. These can separate as much as 99.9% of particulate matter.

====Electrostatic Precipitators====
Electrostatic Precicpitators remove particulate matter as gas passes through a device that has charged metal plates. The particles are then removed because of static electricity. These systems can remove between 99-99.9% of particulate matter

====Super-critical Boilers====
Super-Critical Boilers and Ultra-Supercritical Boilers operate at temperature and pressure higher than regular boilers. By operating at higher temperature these systems become more efficient. Super Critical Boilers typically have 10%-20% CO2 emissions than other similar sub-critical technologies. Ultra-Supercritical boilers can be as much as 30% more efficent than sub-critical technologies.

====More Information====

For more information regarding some of these separations equipment see [[Solids-involved equipment]]

For more information Regarding Cyclones see [[Separation processes#Cyclones| Cyclones]], and for modeling cyclones see their[[Solids-involved equipment#HYSYS Simulation|HYSYS Simulation]]

Methods for removing inorganic and organic gaseous pollutants include: absorption, adsorption, condensation, and combustion (Seider 2009 pg 609). A list of typical of gases pollutants and their sources from ''Plant Design and Economics for Chemical Engineers'' is shown below (Peters, 1991).

[[File:GaseousPollutants.png|thumb|border|center|middle|upright=4|link=|atl=| Common Gaseous Pollutants and their Sources]]

Typically Gas-liquid absorption processes are done completed in a vertical, countercurrent, flow through packed, plate, or spray towers. These systems require good liquid-gas contact and proper equipment. These systems also often have significant energy consumption because of large pressure drops (Peters, 2003). For high volume systems absorption by scrubbing with water or another solvent is the most widely used method (Towler, 2012). Dry adsorbents can be used to remove the last races of gaseous pollutants. Adsorption typically requires blowers, condensers, separators, and controls. You also typically need two packed beds so that one can be used while the other is regenerated. Examples of adsorbents are molecular sieves and activated carbon. Incineration is typically used when there are gas streams that have no recovery value. This can be done with direct flame or catalytic oxidation. Catalytic oxidation usually has higher capital costs, but lower operating costs because it does not require fuel.

You can find more information on [[Separation processes#Absorption| Absorption]] and [[Separation processes#Adsorption| Adsorption]] in [[Separation processes]]

===Outcomes===

====United States Common Pollutant Emissions====

The United States implemented the Clean Air Act in 1970 and since then emissions in the U.S. have been drastically reduced. As a matter of fact despite increases in the population in the last 35 years the amount of pollutants emitted have decreased by almost 70% (EPA). More importantly this demonstrates that reasonable efforts can be put towards environmental protection without causing too much harm to industry.

[[File:EPA.png|thumb|border|center|middle|upright=4|link=|atl=| GDP and Other Growth Factors Vs Common Pollutants Released]]

====China Clean Coal====

=====Success Through 2005=====

Coal is a very inexpensive and abundant source of energy and is abundant in China (Xu 2010). In China Coal the cause of 90% of SO2 emissions, 70% of dust emissions, and 67% of NOx emissions, and 70% of CO2 emissions. These numbers are staggering considering that Coal has never been more than 50 percent of China's Energy Supply.

[[File:Coal.jpg|thumb|border|center|middle|upright=4|link=|atl=| Coal Consumption for Power and the Percentage of Coal Used]]

Despite the increasing coal consumption, high efficiency electric dust removal systems with efficiencies that are as high as 99.6% have greatly decreased soot emissions to 32% below 1980's levels as of 2005.

[[File:Soot.jpg|thumb|border|center|middle|upright=4|link=|atl=| SO2 and Soot Emissions from 1981 to 2005]]

=====Technologies and Life Cycle Comparison=====
As of 2010 China was consuming 48.2% of coal globally. Four potential technologies integrated gasification combined cycle (IGCC), sub-critical coal power generation (Sub-C); super-critical coal power generation (Super-C) ultrasuper-critical coal power generation (USC). These technologies are compared mostly on the basis of net generating efficiency and efficiency. Net generating efficiency is the output of the plant divided by the total available energy in the fuel used.

where efficiency is define as: η=E/Etotal

and

Etotal=Emining+Etransportation+Egeneration

[[File:technologies.PNG|thumb|border|center|middle|upright=4|link=|atl=|A comparison of many of the parameters important to lfe-cycle analysis]]

[[File:Lifecycle.PNG|thumb|border|center|middle|upright=4|link=|atl=|]]

[[File:Price.PNG|thumb|border|center|middle|upright=4|link=|atl=| Capital cost in $/kW of clean coal power-generation technologies]]

[[File:Lifecycle2.PNG|thumb|border|center|middle|upright=4|link=|atl=|]]

All of the data suggests that USC is the highest in both energy efficiency and net generating efficiency while competitive in price and the lowest on emissions among the different boilers.

==Solid Waste==
U.S. federal regulations require that solid waste be classified as hazardous or nonhazardous. Conditions for a classification of hazardous include: ignitability, corrosivity, reactivity, toxicity, or posing a substantial threat to the surrounding environment and its inhabitants. Hazardous waste must be treated on- or near-site before being removed in containers. Non-hazardous waste may be landfilled or incinerated in some cases. A typical estimate of costs for waste disposal is $0.03/lb for nonhazardous solids and $0.10/lb for hazardous solids. (Seider 2009 pg 609)

=References=

*Biegler LT, Grossmann IE, Westerberg AW. ''Systematic Methods of Chemical Process Design'' Prentice-Hall: Upper Saddle River, 1997.

*Broughton, J. ''Process Utility Systems: Introduction to Design, Operation and Maintenance'' Institution of Chemical Engineers: Rugby, Warwickshire, UK, 1994.

*Duke Energy Company (2013). How Do Coal Fired Plants Work? Charlotte: Duke Energy.

*Lehman B, Worrell E. ''Electricity Production from Natural Gas Pressure Recovery Using Expansion Turbines.'' Lawrence Berkeley National Laboratory; 2001.

*"Overview of the Clean Air Act and Air Pollution." Environmental Protection Agency. November 17, 2015. http://www.epa.gov/clean-air-act-overview. Accessed February 5, 2016.

*"Oxygen Control." Energy Solutions Center Inc.: Boiler Consortium. http://www.cleanboiler.org/Eff_Improve/Efficiency/Oxygen_Control.asp. Accessed February 21, 2016.

*Peters, Max S.; Timmerhaus, Klaus D.; West, Ronald E. (2003). "Plant Design and Economics for Chemical Engineers." McGraw Hill Higher Education.

*Seider, Seader, Lewin, Widagdo. (2009). ''Plant Design and Economics for Chemical Engineers, 5th Edition.'' Hoboken: Wiley.

*Seider, Seader, Lewin. (2008). ''Product and Process Design Principles, 2nd Edition.'' Hoboken: Wiley.

*Summary of the Clean Water Act. United States EPA website. http://www.epa.gov/laws-regulations/summary-clean-water-act

*Towler, G.P. and Sinnot, R. (2012). ''Chemical Engineering Design: Principles, Practice and Economics of Plant and Process Design.'' Elsevier.

*Turton R.; Bailie, R.C.; Whiting, W.B.; Shaeiwitz J.A.; Bhattacharyya D. (2012). ''Analysis, Synthesis, and Design of Chemical Processes.'' Upper Saddle River: Prentice Hall.

*G.D. Ulrich, A Guide to Chemical Engineering Process Design and Economics, Wiley: New York, 1984.

File:Air-fuel ratio.PNG

2016-02-22T00:07:30Z

Taunins:

Utility systems

2016-02-21T23:24:10Z

Taunins: /* References */

Authors: David Chen, [2014] Joshua Lee, [2015] Brett Sleyster, [2016] and Tom Aunins [2016] 

Stewards: David Chen, Jian Gong, and Fengqi You

Date Presented: January 13, 2014 /Date Revised: January 14, 2014

 


__TOC__

=Introduction=
Many chemical processes do not take place at ambient temperature or pressures. In order to reach these non-ambient conditions, utilities will have to be used to raise or lower temperatures and compress gases. (Towler, Towler/UOP) Utilities often contribute 5 to 10% of the price of a product, and may come from public or private utility companies or on-site plants. For purchased utilities, costs depend on consumption, while for company-owned utilities, there will be both capital and operating costs. They include things such as steam for heating, electricity, cooling water, refrigeration, fuels such as natural gas, wastewater treatment, waste disposal, and landfill. Steam is often the largest utility cost. Cogeneration unit can supply electricity accompanied with different steam pressures. (Seider 2009)

=Electricity=

Electricity is used to power many different kinds of equipment. It has many advantages: it is efficient (> 90%), reliable, available in a wide range of power, shaft speeds, designs, lifetimes, convenience, costs, and maintenance. It is generally used up to 200 hp, and sometimes over 10,000 Hp. In chemical process plants, the electricity demand is generally determined by the work or energy required for compression, pumping, air cooling, lights, and many other items. This electricity often times is purchased from local electricity providers, but many plants generate their own electricity via sophisticated processes.

Electricity is rarely used as a primary heat utility in large-scale chemical plants for a variety of reasons. The main disadvantages of using electricity as a heat utility are as follows (Towler 2012):

:*Heat from electricity is two to three times more expensive than heat from fuels. This is attributed to the lack of efficiency when creating heat from electricity.

:*Electrical heating units are expensive, require high maintenance, and must comply with strict safety regulations.

:*Electrical heating units are unsafe compared to steam heating units. In steam systems, the physically steam controls the temperature, whereas in electrical heating units temperature is controlled by temperature controllers, which can fail or burn out.

The use of electricity carries with it some hazards depending on the environment. Extra care must be taken when using electrically-powered equipment in areas which may have combustible fluids, vapors, or dust, and where liquids may be present. (Seider 2009 pg 606)

==Conventional Power Station==

In general, most electricity is generated from a conventional coal-fired process, whether it be on-site or purchased from a provider. Coal-fired processes have been used to create electricity throughout history, and technological advances have increased its efficiency and use worldwide. In a coal-fired steam station—much like a nuclear station—water is turned into steam, which in turn drives turbine generators to produce electricity. There are several variations on how to create energy from coal, but here are the basics of how a coal-fired process works:

[[File:coalfired.png|thumb|border|center|middle|upright=4|link=|atl=|General Coal-Fired Process Diagram (Duke Energy Company)]]

*Heat is created:
::Before the coal is burned, it is pulverized to the fineness of talcum powder. It is then mixed with hot air and blown into the firebox of the boiler. Burning in suspension, the coal/air mixture provides the most complete combustion and maximum heat possible.

*Water turns to steam:
::Highly purified water, pumped through pipes inside the boiler, is turned into steam by the heat. The steam reaches temperatures of up to 1,000 degrees Fahrenheit and pressures up to 3,500 pounds per square inch, and is piped to the turbine.

*Steam turns the turbine:
::The enormous pressure of the steam pushing against a series of giant turbine blades turns the turbine shaft. The turbine shaft is connected to the shaft of the generator, where magnets spin within wire coils to produce electricity.

*Steam is converted back to water:
::After doing its work in the turbine, the steam is drawn into a condenser, a large chamber in the basement of the power plant. In this important step, millions of gallons of cool water from a nearby source (such as a river or lake) are pumped through a network of tubes running through the condenser. The cool water in the tubes converts the steam back into water that can be used over and over again in the plant.

*Repeat:
::The cooling water is returned to its source without any contamination, and the steam water is returned to the boiler to repeat the cycle.

===Advantages & Disadvantages of Coal-Fired Energy Production===

[[File:coalfiredtable.png|thumb|border|center|middle|upright=4|link=|atl=|Advantages and Disadvantages of Coal-Fired Processes (Seider 2008)]]

==Gas-Turbine Cogeneration Process==

When generating energy on-site, many plants use a gas-turbine cogeneration process. The thermal efficiency of a gas-turbine process is in the range of 70-80% while conventional power stations, such as coal-fired processes, have a 30-40% efficiency. The lower efficiency in more conventional power stations is attributed to wasted heat in the exhaust steam in the condenser. One example of a gas-turbine process is outlined in the following figure. Figure 3.1 is a gas-turbine cogeneration process with a heat recovery steam generator (waste-heat) boiler.

[[File:cogeneration.png|thumb|border|center|middle|upright=4|link=|atl=|Gas-Turbine Cogeneration with a heat recovery steam generator boiler (Towler 2012 Fig 3.1)]]

Overall, the process illustrated is not much different from a coal-fired process. The main differences are that the cogeneration process creates both electricity and a heat utility, and cogeneration processes use natural gas instead of coal. Many of the advantages and disadvantages are similar to those of the coal-fired process, but the cogeneration has a much higher efficiency, creates heat to be used in another process, and uses a more volatile and expensive fuel. The main advantage of cogeneration over coal-fired energy production is that heat is not wasted. In coal-fired processes, heat is released and wasted during electricity generation. Cogeneration captures some, if not all of the byproduct for heat, which is an extremely useful utility that will be discussed in subsequent sections. In summary, the cogeneration plant is superior to the coal-fired process because of its higher efficiency and ability to create a useful heat utility.

Obviously any engineer would design the cogeneration plant to meet at least the energy requirement necessary for plant operation, but cogeneration plants often times are designed to exceed the plant electricity requirement to drive another source of capital. Many describe this scenario as a "make or buy" scenario (Towler 2012). This scenario provides chemical producers leverage when negotiating contracts with outsourced electricity providers and this allows plants to purchase electricity at a wholesale price. This is a huge advantage of considering on-site electricity production because electricity is needed in relatively high quantities for all chemical plants. Being able to minimize electricity costs, or even profit off of electricity production is a huge economical consideration that all plants employ.

=Process Heating=
The key objective of this section is to discuss how processes are heated. Heating utilities are necessary for proper usage of distillers, reactors, condensers, and several other integral types of equipment. More specifically, steam, fired heat, and hot oil/specialized heat transfer fluids will be discussed in the following subsections.

==Steam==
Steam is the most commonly used heat utility used in chemical plants, and as a result understanding how it is used is essential in the study of Utility systems. Steam is used both as a process fluid (feedstock, diluent to absorb heat of reaction, heating agent, and stripping agent in absorbers and adsorbers ) and utility. It can be used to drive pumps and compressors, ejectors (for producing a vacuum), and heat exchangers. As one can clearly see, steam is a versatile, and useful utility.

Here are a few advantages of using steam as opposed to other methods of process heating (Towler 2012):

:*By controlling the pressure of the steam, one can control the temperature at which the heat is released. Having a strong control over the temperature is essential in several processes. =
:*Steam is an efficient heat source because the heat of condensation of steam is very high. Meaning that there is is high output per mass of utility at a constant temperature.
:*Heat exchangers that use steam are relatively cheap because condensing steam has a high heat transfer coefficient.
:*Steam is nonflammable, nontoxic, and inert to several process fluids.

Chemical plants generally have a network of pipelines exclusively for providing steam. These networks generally have steam at a low pressure, a medium pressure, and a high pressure. The image below illustrates a basic steam system.

[[File:Steam.png|thumb|border|center|middle|upright=4|link=|atl=|(Towler 2012 Fig 3.2)]]

In the diagram above, boiler feed water at a high pressure is preheated and fed to other boilers. These other boilers superheat the steam to create a high pressure and high temperature steam stream. The steam is superheated past the dew point to account for heat loss in the pipelines. A portion of the high pressure steam is used for process heating in areas of the plant that require high temperatures. The rest of the high pressure steam is turned into medium pressure steam by valves and steam turbines. The medium pressure steam is then used to heat medium temperature processes and to form low pressure steam. The low pressure steam can be used to heat low pressure processes and it can be expanded in condensing turbines to create shaft work and energy. In summary, steam can be used for an innumerable amount of action items in a plant. High pressure, medium pressure, and low pressure steam can all be used as a heat source. Low pressure steam has utilities in creating electricity and it also has several other uses.

==Fired Heat==

In many cases, processes in a plant require a heat source stronger than high pressure and temperature steam. That is when fired heat is used, which is generally at temperatures above 523K. Streams can be heated directly in the furnace tubes or via a hot oil circuit or heat transfer fluid, which will be discussed in detail in the next section. Most fired heaters use natural gas as fuel because it burns cleaner than fuel oil. A cleaner burning fuel is always advantageous due to environmental and safety concerns. Furthermore, natural gases usually result in less wear and tear in burners and fuel lines.

Depending on the application of the fired-heater, different design specifications can be implemented to make the fired-heater as efficient as possible. The basic construction of a fired heater starts with a cylindrical chamber that is lined with with refractory bricks. The stream that is to be heated flows through tubes inside of the furnace. These tubes can be arranged in several different arrangements such as, around the walls of the furnace, or in horizontal or vertical banks (Towler 2012). The figure below illustrates the basic construction of the fired-heater and varying tube arrangements.

[[File:firedheater.png|thumb|border|center|middle|upright=4|link=|atl=|Basic Fired-Heater Diagrams (Towler 2012 Figure 19.66)]]

Fuel is burned to heat the entire furnace, and the heat transfer occurs from the combustion gases inside of the furnace across the tubes that are filled with our desired stream. The heat transfer between the tubes and the furnace is accomplished primarily via radiation. Modern designs take advantage of convective heat transfer by adding a smaller section on top of the fired-heater where the combustion gases flow over banks of tubes as seen in (c) in the figure above. Heat transfer can be further improved via convection by adding fins or pins in the combustion section.

The cost of fired heat can be calculated by the cost of fuel fired. Natural gas and heating oil are traded as commodities and prices can be found at many online trading sites or business news sites (i.e., www.cnn.money.com). Past historic prices for forecasting can be found in the Oil and Gas Journal or from the U.S. Energy Information Adminstration (www.eia.gov).

===Fuels===
Fuel is burned in utility facilities such as boilers, electricity generation, and cogeneration, and can be in solid, liquid, or gas form. It can also be burned to provide heating for a process or stream or to drive pumps and compressors. The fuel is usually burned with excess air to ensure complete combustion.

A way of quantifying the amount of heat generated is by using the heating values. Higher heating value (HHV) and the lower heating value (LHV) are used. The heating is the total heat evolved by complete combustion of a fuel with dry air with both at 60 ⁰F and the flue gas after combustion brought back down to ⁰F. If the water vapor in the flue gas is not condensed, we obtain the LHV. If the water vapor is condensed, the value of heat evolved is a bit higher, and this is the HHV.
Heating values for solids and liquids are usually on a per-mass basis, and gases on a per-volume basis.
A specified amount of heating cannot be met with the amount of fuel calculated using only the HHV. There will be heat losses, the flue gas temperature will be greater than 60 ⁰F, and water in the flue gas will typically be vapor. (Seider 608)

==Hot Oil/Specialized Heat Transfer Fluids==

Specialized heat transfer fluids and hot oil circuits are used as heat sources when steam and fired heat is not appropriate. Specialized heat transfer fluids and hot oil circuits are extremely versatile in that they can be used in the temperature range of 323K to 673K. This range however is quite variable. For hot oils, the upper temperature limit is gauged based off of the thermal decomposition of the oil and coking/fouling of heat exchanger tubes.

Hot oil circuit systems are most commonly used when the plant has several small temperature heating requirements because it is more economically sound. Rather than having several fired heaters heat each small temperature requirement, it is much more economical to have one fired heater heat the hot oil and circulate that oil through each of the process to meet all of the heat needs. Hot oil systems are also generally favored over high pressure steam in processes that involve high pressure differentials between the process stream and high pressure steam. Hot oil systems are favored in this scenario because of safety concerns. If the steam were to leak, the pressure drop could cause serious safety issues.

Mineral oils are the most commonly used heat transfer fluids, and one prominent example is Dowtherm A. Dowtherm A is a combination of 26.5 wt% diphenyl in diphenyl oxide (Towler 2012) and is extremely thermally stable. These mineral oil systems generally require high flow rates.

=Process Cooling=

==Cooling Water==
Cooling water is used to cool and/or condense streams. Cooling water is usually circulated between process heat exchangers and a cooling tower. Water is cooled during downward motion by contact with air blown upwards, which can bring the water temperature to come within ~ 5 ⁰F of air’s wet-bulb temperature.Approximately 80% of the temperature reduction is due to evaporation of the cooling water and heat transfer to the surrounding air. Water can also be cooled in spray ponds and cooling ponds. Both work by providing high area for water to exchange heat with air.
Water in cooling towers is lost through drift and blowdown, and makeup is usually 1.5 to 3% of the circulating rate.
If a large natural body of water is nearby, it can be used as a source of cooling water and discharged downstream. This water is usually filtered to remove salts and impurities that may lead to fouling, but it is not treated.

==Refrigeration==
Cooling water can usually be used to cool a stream to ~ 100 ⁰F. Air can only cool to ~ 120 ⁰F. Air may be used in places where water is scarce or more costly to transport. To cool or condense streams below 100 ⁰F, a refrigerant is typically used. Chilled brine can also be used, but is less common.

Until 1995, CFC Freon R-12 (dichlorodifuloromethane) and HCFC Freon R-22 (chlorodifuloromethane) were commonly used refrigerants. However, the chlorine atom in the molecules caused the depletion of the ozone layer. The U.S. Clean Air Act Amendments of 1990 went into effect in 1995, and the production of these refrigerants has since stopped or been greatly reduced.

Cost estimates are based on ton-day of refrigeration, where a ton is the heat that needs to be removed to freeze 1 ton per day of water at 32 ⁰F. Substitutes have since been developed. R-134a is often used in place of R-12. According to the EPA, R-134a is not combustible at ambient conditions, and is essentially non-toxic under 400 ppm, and is not ozone-depleting. (Seider pg 607)

=Energy Efficiency=
One of the chief concerns in selecting and designing process utility systems for heating and cooling is how to achieve the most energy efficient design. There are countless means by which plants lose energy, two of the foremost being through the mixing of different temperature or pressure streams and through the disposal of warmed cooling water. (Seider, 2009) Proper utilities design can help mitigate each of these losses as well as many others. The energy efficiency of a plant will depend primarily on the heating and cooling methods that are being used and the overall system design itself. These two parameters are important in determining how well energy is transferred to the desired media as well as how well that energy is recovered and recycled.

==Hot Utility Efficiency==
As mentioned above, the most commonly used utilities for process heating in large scale processes are steam, fired heat, and hot oil heaters. Of these, steam is the most commonly used. Electricity, while efficient at creating power, is not a viable source of heat in large industrial processes. Common ranges of heating efficiency for these three methods are displayed in Table 1. (Towler and Sinnott, 2012)

{| class="wikitable"
|+Table 1: Process Heating Efficiencies
|-
! Process Heating Method
! Typical Efficiency
|-
| Steam (via coal boiler)
| 72%
|-
| Steam (via gas boiler)
| 73%
|-
| Steam (via oil boiler)
| 75%
|-
| Fired Heat w/ Convective Section
| 85%
|-
| Fired Heat w/o Convective Section
| 60%
|-
| Hot Oil Heaters/Vaporizers
| 80-85%
|}

===Steam===

==Cold Utility Efficiency==
Efficiency in cooling processes depends more on the method used, and by extension the amount of coolant needed. Water and air utility efficiencies depend primarily on the fluid flow required to maintain the system at a desired temperature, while powered refrigeration utilities (for colder processes) have efficiencies at approximately 60%--but ranging up to 90%--of Carnot cycle efficiency, a metric of ideal refrigeration efficiency. (Towler and Sinnott, 2012) Cooling systems represent by definition a loss of energy from the main process to the utility stream, and as such it is often useful to find other uses for the heated media before discharge.

==Energy Recovery==
Recovery and recycle of energy is perhaps the most important aspect of creating an energy efficient plant design, and it is important for process engineers to fully consider possibilities for heat recovery in order to aid in economic viability.

===Process Heat Exchange===
Heat exchanger networks are a very common energy recovery method in industrial processes. These networks most frequently allow energy from heated product streams to be transferred to feed streams that must be brought up to process temperature. (Biegler, 1997) More information on the function and design of heat exchanger networks can be found on the [[Heat_exchanger#Heat_Exchanger_Networks|heat exchanger wiki page]]. The following are several examples of energy recovery via heat exchange that are used in industrial processes.

In distillation columns the bottoms and distillate effluents have the potential for energy exchange. Though the condenser at the top of the column cannot supply its waste heat to the reboiler due to their respective temperatures, the effluent streams can supply heat to the feed via a feed-effluent exchanger. This reduces the utility requirements to raise the feed to column temperature. (Biegler, 1997)

[[File:Feed_sterilization.jpg|thumb|border|right|middle|upright=4|link=|atl=|Feed sterilization schematic. (Towler and Sinnott Fig. 3.30)]]

Feed sterilization, commonly used in the food industry, is a common application for heat recovery through process stream heat exchange. In this application, the feed must be heated for a certain amount of time to kill any biological contaminants, after which it can be used to heat the new raw feed for sterilization. This reduces energy demands on the steam heater and thus reduces cost. (Towler and Sinnott, 2012)

In multi-vessel batch processes it can be advantageous to exchange heat as the process fluid is being transferred between vessels. Like the previous examples, this reduces the utility needed to bring the colder feed up to process temperature, thus reducing costs. (Towler and Sinnott, 2012)

[[File:Batch_heat_exchange.jpg|thumb|border|center|middle|upright=4|link=|atl=|Multi-vessel batch heat exchange schematic (Towler and Sinnott Fig. 3.31)]]

===Utility Regeneration===
[[File:Waste_heat_boiler.jpg|thumb|border|right|middle|upright=4|link=|atl=|Industrial modular HRSG]]
When recovery of waste heat via transfer to other process streams is inconvenient or impossible, energy efficiency can still be improved through the regeneration of utilities. This is commonly done through the regeneration of steam by either removing heat from exiting streams or from highly exothermic reactions. Waste heat in exiting streams is removed via heat recovery steam generators (HRSGs), and is most often used on exiting flue gas and exiting process gas streams. Heat recovery from reactions is a viable option when the reactor temperature will be at 150 C or above, as this will create steam at high enough pressure to be used in other processes. (Towler and Sinnott, 2012)

Furthermore, there is opportunity for energy recovery in the expansion of compressed gas through a turbine to create electricity, a process that can be economically viable given sufficiently high flows or pressure. Such technology has been used in processes to synthesize ammonia, perform air separations, and synthesize nitric acid. (Towler and Sinnott, 2012) Recently, however, there has been a particularly strong interest for energy recovery in the natural gas industry, when gas is decompressed from major pipelines to residential low-pressure piplines. A 2001 study estimated that there is the potential to recover 21 TWh, representing 11% of natural gas transport energy, via gas expansion. (Lehman)

=Process water and boiler-feed water=
Process water is water that will be directly used in the process. Boiler-feed water (BFW) is used to produce steam. Both may need to be purified to prevent impurities from contaminating a process or from foul equipment. It can be used as a cooling stream when the temperature of the stream to be cooled is greater than ~300 ⁰F. Cost of BFW can be partially offset by the steam credit.

Process water that undergoes moderate pretreatment can cost ~ $0.75/1,000 gal.

Extensive treatment ~ $6.00/1,000 gal.

Sterilized for pharmaceutical processes ~ $550/1,000 gal. (Seider pg 608)

=Demineralized Water=
In demineralized water, minerals have been removed by ion exchange. In boiler feed water, this is to prevent salt deposition, corrosion, formation of foam, and sluicing. In process water, the ions may contaminate the process.

=Waste Treatment=
Most chemical processes will produce some sort of waste. Disposal occurs to the atmosphere (in the case of some gases), sewers, body of water, or a landfill. Waste may require some treatment before disposal to meet regulations. Depending on process economics, byproducts may be recovered and processed. (Seider 2009 pg 609)

==Wastewater Treatment==
The United States EPA regulates industrial wastewater disposal through the Clean Water Act, introduced in 1948 as the Federal Water Pollution Control Act and amended to its current form in 1972. The sweeping 1972 amendments allowed the EPA to prevent industries and persons from discharging contaminated water into fresh water sources and set water quality standards. (Summary of the Clean Water Act) In accordance with this law, process plants in the United States treat wastewater at on-site or near-site treatment centers before releasing it into the surrounding environment.

Wastewater effluent streams, along with water runoff from around the plant, are treated to control for pH, toxicity, suspended solids, and biological oxygen demand (for aquatic life protection) prior to discharge. Each of these controls is typically addressed with a separate method. Acidity and basicity is balanced through the addition of an acid or alkaline solution. Toxic wastewater may be treated with chemical processes or simply diluted to safe concentrations. Suspended solids can be removed via filtration and/or with clarifiers. Oxygen demand of wastewater can be mitigated using activated sludge treatment processes. Once the water quality complies with the EPA, and state-mandated, regulations, it can be safely released. More information on the large number of industry-specific guidelines for waste effluent can be found on the EPA website (http://www.epa.gov/eg/industrial-effluent-guidelines).

==Air-Pollution Management==
===Introduction===

In the United States air pollution is regulated in the Clean Air Act, and almost all pollutant emitting plants are regulated under this law. The types of plants that can release significant emissions include petroleum refineries, sulfur recovery plants, carbon-black plants, fuel conversion plants, chemical process plants, fossil fuel plants, and petroleum storage and transfer facilities. To receive permission to construct a plant must undergo a review to show that it will not cause a violation of the Ambient Air Quality Standards(Peters, 2003).

===Methods===

There are two major types of pollutants that are released into the air, particulates and and gaseous pollutants. Particulates can be removed with mechanical forces while gaseous pollutants typically need to removed by chemical or physical means (Peters, 2003).

Particulates and volatile pollutants that need to be removed before disposal may be present. Particle removal equipment includes: cyclones, wet scrubbers, electrostatic precipitators, and fabric-filter systems (Seider 2009) such as bag filters (. The two charts below are from ''Plant Design and Economics for Chemical Engineers'' and show the types of equipment, separation methods, and particle sizes in different pollutant separation technologies (Peters, 1991).

[[File:AirPolChart.png|thumb|border|center|middle|upright=4|link=|atl=|Different Methods of Particle Separation, the Particle Sizes they Can Remove, and the Technologies Used]]

[[File:AirPolTable.png|thumb|border|center|middle|upright=4|link=|atl=| This Chart Shows the Specifications and Limitations of Different Separations Technologies Including Particle Size, Efficiencies, and Temperatures(Peters, 1991)]]

====Wet Scrubbers====
Wet scrubber use lime or limestone and water to remove SO2 and acid gases. The mixture can be injected into a scrubber or the gases can be bubbled through this mixture. This results in removal of 90-98% of SO2 and and acid gases.

====Dry Scrubbers====
Dry scrubber blow powdered adsorbents into a vessel with gases and then after it has captured the SO2 and acid gases it is separated from gas using a fabric filter. These systems remove 90-93% of the contaminants.

====Low-NOx Burners====
The purpose of low NOx burners is to decrease the amount of NOx created when the coal is burned. This is done by injecting coal and air in boilers. This can result in 40-50% NOx reduction. If air is injected into the area above the burner this can actually cause almost 70% NOx reduction.

====Selective Non-Catalytic and Catalytic Reductions====
These systems inject ammonia into gases to remove NOx. The Catalytic reductions add a catalyst to the ammonia being injected to aid in the removal. Con-catalytic reductions result in about 35% removal, but adding a catalyst can increase that amount to about 90%. The catalytic-reduction can remove up to 80% of mercury as well.

====Fabric Filters====
Also known as baghouses,these [[Separation processes#Filtration| filters]] remove particulates by passing air through filters. These can separate as much as 99.9% of particulate matter.

====Electrostatic Precipitators====
Electrostatic Precicpitators remove particulate matter as gas passes through a device that has charged metal plates. The particles are then removed because of static electricity. These systems can remove between 99-99.9% of particulate matter

====Super-critical Boilers====
Super-Critical Boilers and Ultra-Supercritical Boilers operate at temperature and pressure higher than regular boilers. By operating at higher temperature these systems become more efficient. Super Critical Boilers typically have 10%-20% CO2 emissions than other similar sub-critical technologies. Ultra-Supercritical boilers can be as much as 30% more efficent than sub-critical technologies.

====More Information====

For more information regarding some of these separations equipment see [[Solids-involved equipment]]

For more information Regarding Cyclones see [[Separation processes#Cyclones| Cyclones]], and for modeling cyclones see their[[Solids-involved equipment#HYSYS Simulation|HYSYS Simulation]]

Methods for removing inorganic and organic gaseous pollutants include: absorption, adsorption, condensation, and combustion (Seider 2009 pg 609). A list of typical of gases pollutants and their sources from ''Plant Design and Economics for Chemical Engineers'' is shown below (Peters, 1991).

[[File:GaseousPollutants.png|thumb|border|center|middle|upright=4|link=|atl=| Common Gaseous Pollutants and their Sources]]

Typically Gas-liquid absorption processes are done completed in a vertical, countercurrent, flow through packed, plate, or spray towers. These systems require good liquid-gas contact and proper equipment. These systems also often have significant energy consumption because of large pressure drops (Peters, 2003). For high volume systems absorption by scrubbing with water or another solvent is the most widely used method (Towler, 2012). Dry adsorbents can be used to remove the last races of gaseous pollutants. Adsorption typically requires blowers, condensers, separators, and controls. You also typically need two packed beds so that one can be used while the other is regenerated. Examples of adsorbents are molecular sieves and activated carbon. Incineration is typically used when there are gas streams that have no recovery value. This can be done with direct flame or catalytic oxidation. Catalytic oxidation usually has higher capital costs, but lower operating costs because it does not require fuel.

You can find more information on [[Separation processes#Absorption| Absorption]] and [[Separation processes#Adsorption| Adsorption]] in [[Separation processes]]

===Outcomes===

====United States Common Pollutant Emissions====

The United States implemented the Clean Air Act in 1970 and since then emissions in the U.S. have been drastically reduced. As a matter of fact despite increases in the population in the last 35 years the amount of pollutants emitted have decreased by almost 70% (EPA). More importantly this demonstrates that reasonable efforts can be put towards environmental protection without causing too much harm to industry.

[[File:EPA.png|thumb|border|center|middle|upright=4|link=|atl=| GDP and Other Growth Factors Vs Common Pollutants Released]]

====China Clean Coal====

=====Success Through 2005=====

Coal is a very inexpensive and abundant source of energy and is abundant in China (Xu 2010). In China Coal the cause of 90% of SO2 emissions, 70% of dust emissions, and 67% of NOx emissions, and 70% of CO2 emissions. These numbers are staggering considering that Coal has never been more than 50 percent of China's Energy Supply.

[[File:Coal.jpg|thumb|border|center|middle|upright=4|link=|atl=| Coal Consumption for Power and the Percentage of Coal Used]]

Despite the increasing coal consumption, high efficiency electric dust removal systems with efficiencies that are as high as 99.6% have greatly decreased soot emissions to 32% below 1980's levels as of 2005.

[[File:Soot.jpg|thumb|border|center|middle|upright=4|link=|atl=| SO2 and Soot Emissions from 1981 to 2005]]

=====Technologies and Life Cycle Comparison 2013=====
As of 2010 China was consuming 48.2% of coal globally. Four potential technologies integrated gasification combined cycle (IGCC), sub-critical coal power generation (Sub-C); sub-critical coal power generation (Sub-C) super-critical coal power generation (Super-C). These technologies are compared mostly on the basis of net generating efficiency.

where efficiency is define as: η=E/Etotal

and

Etotal=Emining+Etransportation+Egeneration

==Solid Waste==
U.S. federal regulations require that solid waste be classified as hazardous or nonhazardous. Conditions for a classification of hazardous include: ignitability, corrosivity, reactivity, toxicity, or posing a substantial threat to the surrounding environment and its inhabitants. Hazardous waste must be treated on- or near-site before being removed in containers. Non-hazardous waste may be landfilled or incinerated in some cases. A typical estimate of costs for waste disposal is $0.03/lb for nonhazardous solids and $0.10/lb for hazardous solids. (Seider 2009 pg 609)

=References=

*Biegler LT, Grossmann IE, Westerberg AW. ''Systematic Methods of Chemical Process Design'' Prentice-Hall: Upper Saddle River, 1997.

*Broughton, J. ''Process Utility Systems: Introduction to Design, Operation and Maintenance'' Institution of Chemical Engineers: Rugby, Warwickshire, UK, 1994.

*Duke Energy Company (2013). How Do Coal Fired Plants Work? Charlotte: Duke Energy.

*Lehman B, Worrell E. ''Electricity Production from Natural Gas Pressure Recovery Using Expansion Turbines.'' Lawrence Berkeley National Laboratory; 2001.

*"Overview of the Clean Air Act and Air Pollution." Environmental Protection Agency. November 17, 2015. http://www.epa.gov/clean-air-act-overview. Accessed February 5, 2016.

*Peters, Max S.; Timmerhaus, Klaus D.; West, Ronald E. (2003). "Plant Design and Economics for Chemical Engineers." McGraw Hill Higher Education.

*Seider, Seader, Lewin, Widagdo. (2009). ''Plant Design and Economics for Chemical Engineers, 5th Edition.'' Hoboken: Wiley.

*Seider, Seader, Lewin. (2008). ''Product and Process Design Principles, 2nd Edition.'' Hoboken: Wiley.

*Summary of the Clean Water Act. United States EPA website. http://www.epa.gov/laws-regulations/summary-clean-water-act

*Towler, G.P. and Sinnot, R. (2012). ''Chemical Engineering Design: Principles, Practice and Economics of Plant and Process Design.'' Elsevier.

*Turton R.; Bailie, R.C.; Whiting, W.B.; Shaeiwitz J.A.; Bhattacharyya D. (2012). ''Analysis, Synthesis, and Design of Chemical Processes.'' Upper Saddle River: Prentice Hall.

*G.D. Ulrich, A Guide to Chemical Engineering Process Design and Economics, Wiley: New York, 1984.

Utility systems

2016-02-21T23:20:29Z

Taunins: /* Utility Efficiency */

Authors: David Chen, [2014] Joshua Lee, [2015] Brett Sleyster, [2016] and Tom Aunins [2016] 

Stewards: David Chen, Jian Gong, and Fengqi You

Date Presented: January 13, 2014 /Date Revised: January 14, 2014

 


__TOC__

=Introduction=
Many chemical processes do not take place at ambient temperature or pressures. In order to reach these non-ambient conditions, utilities will have to be used to raise or lower temperatures and compress gases. (Towler, Towler/UOP) Utilities often contribute 5 to 10% of the price of a product, and may come from public or private utility companies or on-site plants. For purchased utilities, costs depend on consumption, while for company-owned utilities, there will be both capital and operating costs. They include things such as steam for heating, electricity, cooling water, refrigeration, fuels such as natural gas, wastewater treatment, waste disposal, and landfill. Steam is often the largest utility cost. Cogeneration unit can supply electricity accompanied with different steam pressures. (Seider 2009)

=Electricity=

Electricity is used to power many different kinds of equipment. It has many advantages: it is efficient (> 90%), reliable, available in a wide range of power, shaft speeds, designs, lifetimes, convenience, costs, and maintenance. It is generally used up to 200 hp, and sometimes over 10,000 Hp. In chemical process plants, the electricity demand is generally determined by the work or energy required for compression, pumping, air cooling, lights, and many other items. This electricity often times is purchased from local electricity providers, but many plants generate their own electricity via sophisticated processes.

Electricity is rarely used as a primary heat utility in large-scale chemical plants for a variety of reasons. The main disadvantages of using electricity as a heat utility are as follows (Towler 2012):

:*Heat from electricity is two to three times more expensive than heat from fuels. This is attributed to the lack of efficiency when creating heat from electricity.

:*Electrical heating units are expensive, require high maintenance, and must comply with strict safety regulations.

:*Electrical heating units are unsafe compared to steam heating units. In steam systems, the physically steam controls the temperature, whereas in electrical heating units temperature is controlled by temperature controllers, which can fail or burn out.

The use of electricity carries with it some hazards depending on the environment. Extra care must be taken when using electrically-powered equipment in areas which may have combustible fluids, vapors, or dust, and where liquids may be present. (Seider 2009 pg 606)

==Conventional Power Station==

In general, most electricity is generated from a conventional coal-fired process, whether it be on-site or purchased from a provider. Coal-fired processes have been used to create electricity throughout history, and technological advances have increased its efficiency and use worldwide. In a coal-fired steam station—much like a nuclear station—water is turned into steam, which in turn drives turbine generators to produce electricity. There are several variations on how to create energy from coal, but here are the basics of how a coal-fired process works:

[[File:coalfired.png|thumb|border|center|middle|upright=4|link=|atl=|General Coal-Fired Process Diagram (Duke Energy Company)]]

*Heat is created:
::Before the coal is burned, it is pulverized to the fineness of talcum powder. It is then mixed with hot air and blown into the firebox of the boiler. Burning in suspension, the coal/air mixture provides the most complete combustion and maximum heat possible.

*Water turns to steam:
::Highly purified water, pumped through pipes inside the boiler, is turned into steam by the heat. The steam reaches temperatures of up to 1,000 degrees Fahrenheit and pressures up to 3,500 pounds per square inch, and is piped to the turbine.

*Steam turns the turbine:
::The enormous pressure of the steam pushing against a series of giant turbine blades turns the turbine shaft. The turbine shaft is connected to the shaft of the generator, where magnets spin within wire coils to produce electricity.

*Steam is converted back to water:
::After doing its work in the turbine, the steam is drawn into a condenser, a large chamber in the basement of the power plant. In this important step, millions of gallons of cool water from a nearby source (such as a river or lake) are pumped through a network of tubes running through the condenser. The cool water in the tubes converts the steam back into water that can be used over and over again in the plant.

*Repeat:
::The cooling water is returned to its source without any contamination, and the steam water is returned to the boiler to repeat the cycle.

===Advantages & Disadvantages of Coal-Fired Energy Production===

[[File:coalfiredtable.png|thumb|border|center|middle|upright=4|link=|atl=|Advantages and Disadvantages of Coal-Fired Processes (Seider 2008)]]

==Gas-Turbine Cogeneration Process==

When generating energy on-site, many plants use a gas-turbine cogeneration process. The thermal efficiency of a gas-turbine process is in the range of 70-80% while conventional power stations, such as coal-fired processes, have a 30-40% efficiency. The lower efficiency in more conventional power stations is attributed to wasted heat in the exhaust steam in the condenser. One example of a gas-turbine process is outlined in the following figure. Figure 3.1 is a gas-turbine cogeneration process with a heat recovery steam generator (waste-heat) boiler.

[[File:cogeneration.png|thumb|border|center|middle|upright=4|link=|atl=|Gas-Turbine Cogeneration with a heat recovery steam generator boiler (Towler 2012 Fig 3.1)]]

Overall, the process illustrated is not much different from a coal-fired process. The main differences are that the cogeneration process creates both electricity and a heat utility, and cogeneration processes use natural gas instead of coal. Many of the advantages and disadvantages are similar to those of the coal-fired process, but the cogeneration has a much higher efficiency, creates heat to be used in another process, and uses a more volatile and expensive fuel. The main advantage of cogeneration over coal-fired energy production is that heat is not wasted. In coal-fired processes, heat is released and wasted during electricity generation. Cogeneration captures some, if not all of the byproduct for heat, which is an extremely useful utility that will be discussed in subsequent sections. In summary, the cogeneration plant is superior to the coal-fired process because of its higher efficiency and ability to create a useful heat utility.

Obviously any engineer would design the cogeneration plant to meet at least the energy requirement necessary for plant operation, but cogeneration plants often times are designed to exceed the plant electricity requirement to drive another source of capital. Many describe this scenario as a "make or buy" scenario (Towler 2012). This scenario provides chemical producers leverage when negotiating contracts with outsourced electricity providers and this allows plants to purchase electricity at a wholesale price. This is a huge advantage of considering on-site electricity production because electricity is needed in relatively high quantities for all chemical plants. Being able to minimize electricity costs, or even profit off of electricity production is a huge economical consideration that all plants employ.

=Process Heating=
The key objective of this section is to discuss how processes are heated. Heating utilities are necessary for proper usage of distillers, reactors, condensers, and several other integral types of equipment. More specifically, steam, fired heat, and hot oil/specialized heat transfer fluids will be discussed in the following subsections.

==Steam==
Steam is the most commonly used heat utility used in chemical plants, and as a result understanding how it is used is essential in the study of Utility systems. Steam is used both as a process fluid (feedstock, diluent to absorb heat of reaction, heating agent, and stripping agent in absorbers and adsorbers ) and utility. It can be used to drive pumps and compressors, ejectors (for producing a vacuum), and heat exchangers. As one can clearly see, steam is a versatile, and useful utility.

Here are a few advantages of using steam as opposed to other methods of process heating (Towler 2012):

:*By controlling the pressure of the steam, one can control the temperature at which the heat is released. Having a strong control over the temperature is essential in several processes. =
:*Steam is an efficient heat source because the heat of condensation of steam is very high. Meaning that there is is high output per mass of utility at a constant temperature.
:*Heat exchangers that use steam are relatively cheap because condensing steam has a high heat transfer coefficient.
:*Steam is nonflammable, nontoxic, and inert to several process fluids.

Chemical plants generally have a network of pipelines exclusively for providing steam. These networks generally have steam at a low pressure, a medium pressure, and a high pressure. The image below illustrates a basic steam system.

[[File:Steam.png|thumb|border|center|middle|upright=4|link=|atl=|(Towler 2012 Fig 3.2)]]

In the diagram above, boiler feed water at a high pressure is preheated and fed to other boilers. These other boilers superheat the steam to create a high pressure and high temperature steam stream. The steam is superheated past the dew point to account for heat loss in the pipelines. A portion of the high pressure steam is used for process heating in areas of the plant that require high temperatures. The rest of the high pressure steam is turned into medium pressure steam by valves and steam turbines. The medium pressure steam is then used to heat medium temperature processes and to form low pressure steam. The low pressure steam can be used to heat low pressure processes and it can be expanded in condensing turbines to create shaft work and energy. In summary, steam can be used for an innumerable amount of action items in a plant. High pressure, medium pressure, and low pressure steam can all be used as a heat source. Low pressure steam has utilities in creating electricity and it also has several other uses.

==Fired Heat==

In many cases, processes in a plant require a heat source stronger than high pressure and temperature steam. That is when fired heat is used, which is generally at temperatures above 523K. Streams can be heated directly in the furnace tubes or via a hot oil circuit or heat transfer fluid, which will be discussed in detail in the next section. Most fired heaters use natural gas as fuel because it burns cleaner than fuel oil. A cleaner burning fuel is always advantageous due to environmental and safety concerns. Furthermore, natural gases usually result in less wear and tear in burners and fuel lines.

Depending on the application of the fired-heater, different design specifications can be implemented to make the fired-heater as efficient as possible. The basic construction of a fired heater starts with a cylindrical chamber that is lined with with refractory bricks. The stream that is to be heated flows through tubes inside of the furnace. These tubes can be arranged in several different arrangements such as, around the walls of the furnace, or in horizontal or vertical banks (Towler 2012). The figure below illustrates the basic construction of the fired-heater and varying tube arrangements.

[[File:firedheater.png|thumb|border|center|middle|upright=4|link=|atl=|Basic Fired-Heater Diagrams (Towler 2012 Figure 19.66)]]

Fuel is burned to heat the entire furnace, and the heat transfer occurs from the combustion gases inside of the furnace across the tubes that are filled with our desired stream. The heat transfer between the tubes and the furnace is accomplished primarily via radiation. Modern designs take advantage of convective heat transfer by adding a smaller section on top of the fired-heater where the combustion gases flow over banks of tubes as seen in (c) in the figure above. Heat transfer can be further improved via convection by adding fins or pins in the combustion section.

The cost of fired heat can be calculated by the cost of fuel fired. Natural gas and heating oil are traded as commodities and prices can be found at many online trading sites or business news sites (i.e., www.cnn.money.com). Past historic prices for forecasting can be found in the Oil and Gas Journal or from the U.S. Energy Information Adminstration (www.eia.gov).

===Fuels===
Fuel is burned in utility facilities such as boilers, electricity generation, and cogeneration, and can be in solid, liquid, or gas form. It can also be burned to provide heating for a process or stream or to drive pumps and compressors. The fuel is usually burned with excess air to ensure complete combustion.

A way of quantifying the amount of heat generated is by using the heating values. Higher heating value (HHV) and the lower heating value (LHV) are used. The heating is the total heat evolved by complete combustion of a fuel with dry air with both at 60 ⁰F and the flue gas after combustion brought back down to ⁰F. If the water vapor in the flue gas is not condensed, we obtain the LHV. If the water vapor is condensed, the value of heat evolved is a bit higher, and this is the HHV.
Heating values for solids and liquids are usually on a per-mass basis, and gases on a per-volume basis.
A specified amount of heating cannot be met with the amount of fuel calculated using only the HHV. There will be heat losses, the flue gas temperature will be greater than 60 ⁰F, and water in the flue gas will typically be vapor. (Seider 608)

==Hot Oil/Specialized Heat Transfer Fluids==

Specialized heat transfer fluids and hot oil circuits are used as heat sources when steam and fired heat is not appropriate. Specialized heat transfer fluids and hot oil circuits are extremely versatile in that they can be used in the temperature range of 323K to 673K. This range however is quite variable. For hot oils, the upper temperature limit is gauged based off of the thermal decomposition of the oil and coking/fouling of heat exchanger tubes.

Hot oil circuit systems are most commonly used when the plant has several small temperature heating requirements because it is more economically sound. Rather than having several fired heaters heat each small temperature requirement, it is much more economical to have one fired heater heat the hot oil and circulate that oil through each of the process to meet all of the heat needs. Hot oil systems are also generally favored over high pressure steam in processes that involve high pressure differentials between the process stream and high pressure steam. Hot oil systems are favored in this scenario because of safety concerns. If the steam were to leak, the pressure drop could cause serious safety issues.

Mineral oils are the most commonly used heat transfer fluids, and one prominent example is Dowtherm A. Dowtherm A is a combination of 26.5 wt% diphenyl in diphenyl oxide (Towler 2012) and is extremely thermally stable. These mineral oil systems generally require high flow rates.

=Process Cooling=

==Cooling Water==
Cooling water is used to cool and/or condense streams. Cooling water is usually circulated between process heat exchangers and a cooling tower. Water is cooled during downward motion by contact with air blown upwards, which can bring the water temperature to come within ~ 5 ⁰F of air’s wet-bulb temperature.Approximately 80% of the temperature reduction is due to evaporation of the cooling water and heat transfer to the surrounding air. Water can also be cooled in spray ponds and cooling ponds. Both work by providing high area for water to exchange heat with air.
Water in cooling towers is lost through drift and blowdown, and makeup is usually 1.5 to 3% of the circulating rate.
If a large natural body of water is nearby, it can be used as a source of cooling water and discharged downstream. This water is usually filtered to remove salts and impurities that may lead to fouling, but it is not treated.

==Refrigeration==
Cooling water can usually be used to cool a stream to ~ 100 ⁰F. Air can only cool to ~ 120 ⁰F. Air may be used in places where water is scarce or more costly to transport. To cool or condense streams below 100 ⁰F, a refrigerant is typically used. Chilled brine can also be used, but is less common.

Until 1995, CFC Freon R-12 (dichlorodifuloromethane) and HCFC Freon R-22 (chlorodifuloromethane) were commonly used refrigerants. However, the chlorine atom in the molecules caused the depletion of the ozone layer. The U.S. Clean Air Act Amendments of 1990 went into effect in 1995, and the production of these refrigerants has since stopped or been greatly reduced.

Cost estimates are based on ton-day of refrigeration, where a ton is the heat that needs to be removed to freeze 1 ton per day of water at 32 ⁰F. Substitutes have since been developed. R-134a is often used in place of R-12. According to the EPA, R-134a is not combustible at ambient conditions, and is essentially non-toxic under 400 ppm, and is not ozone-depleting. (Seider pg 607)

=Energy Efficiency=
One of the chief concerns in selecting and designing process utility systems for heating and cooling is how to achieve the most energy efficient design. There are countless means by which plants lose energy, two of the foremost being through the mixing of different temperature or pressure streams and through the disposal of warmed cooling water. (Seider, 2009) Proper utilities design can help mitigate each of these losses as well as many others. The energy efficiency of a plant will depend primarily on the heating and cooling methods that are being used and the overall system design itself. These two parameters are important in determining how well energy is transferred to the desired media as well as how well that energy is recovered and recycled.

==Hot Utility Efficiency==
As mentioned above, the most commonly used utilities for process heating in large scale processes are steam, fired heat, and hot oil heaters. Of these, steam is the most commonly used. Electricity, while efficient at creating power, is not a viable source of heat in large industrial processes. Common ranges of heating efficiency for these three methods are displayed in Table 1. (Towler and Sinnott, 2012)

{| class="wikitable"
|+Table 1: Process Heating Efficiencies
|-
! Process Heating Method
! Typical Efficiency
|-
| Steam (via coal boiler)
| 72%
|-
| Steam (via gas boiler)
| 73%
|-
| Steam (via oil boiler)
| 75%
|-
| Fired Heat w/ Convective Section
| 85%
|-
| Fired Heat w/o Convective Section
| 60%
|-
| Hot Oil Heaters/Vaporizers
| 80-85%
|}

===Steam===

==Cold Utility Efficiency==
Efficiency in cooling processes depends more on the method used, and by extension the amount of coolant needed. Water and air utility efficiencies depend primarily on the fluid flow required to maintain the system at a desired temperature, while powered refrigeration utilities (for colder processes) have efficiencies at approximately 60%--but ranging up to 90%--of Carnot cycle efficiency, a metric of ideal refrigeration efficiency. (Towler and Sinnott, 2012) Cooling systems represent by definition a loss of energy from the main process to the utility stream, and as such it is often useful to find other uses for the heated media before discharge.

==Energy Recovery==
Recovery and recycle of energy is perhaps the most important aspect of creating an energy efficient plant design, and it is important for process engineers to fully consider possibilities for heat recovery in order to aid in economic viability.

===Process Heat Exchange===
Heat exchanger networks are a very common energy recovery method in industrial processes. These networks most frequently allow energy from heated product streams to be transferred to feed streams that must be brought up to process temperature. (Biegler, 1997) More information on the function and design of heat exchanger networks can be found on the [[Heat_exchanger#Heat_Exchanger_Networks|heat exchanger wiki page]]. The following are several examples of energy recovery via heat exchange that are used in industrial processes.

In distillation columns the bottoms and distillate effluents have the potential for energy exchange. Though the condenser at the top of the column cannot supply its waste heat to the reboiler due to their respective temperatures, the effluent streams can supply heat to the feed via a feed-effluent exchanger. This reduces the utility requirements to raise the feed to column temperature. (Biegler, 1997)

[[File:Feed_sterilization.jpg|thumb|border|right|middle|upright=4|link=|atl=|Feed sterilization schematic. (Towler and Sinnott Fig. 3.30)]]

Feed sterilization, commonly used in the food industry, is a common application for heat recovery through process stream heat exchange. In this application, the feed must be heated for a certain amount of time to kill any biological contaminants, after which it can be used to heat the new raw feed for sterilization. This reduces energy demands on the steam heater and thus reduces cost. (Towler and Sinnott, 2012)

In multi-vessel batch processes it can be advantageous to exchange heat as the process fluid is being transferred between vessels. Like the previous examples, this reduces the utility needed to bring the colder feed up to process temperature, thus reducing costs. (Towler and Sinnott, 2012)

[[File:Batch_heat_exchange.jpg|thumb|border|center|middle|upright=4|link=|atl=|Multi-vessel batch heat exchange schematic (Towler and Sinnott Fig. 3.31)]]

===Utility Regeneration===
[[File:Waste_heat_boiler.jpg|thumb|border|right|middle|upright=4|link=|atl=|Industrial modular HRSG]]
When recovery of waste heat via transfer to other process streams is inconvenient or impossible, energy efficiency can still be improved through the regeneration of utilities. This is commonly done through the regeneration of steam by either removing heat from exiting streams or from highly exothermic reactions. Waste heat in exiting streams is removed via heat recovery steam generators (HRSGs), and is most often used on exiting flue gas and exiting process gas streams. Heat recovery from reactions is a viable option when the reactor temperature will be at 150 C or above, as this will create steam at high enough pressure to be used in other processes. (Towler and Sinnott, 2012)

Furthermore, there is opportunity for energy recovery in the expansion of compressed gas through a turbine to create electricity, a process that can be economically viable given sufficiently high flows or pressure. Such technology has been used in processes to synthesize ammonia, perform air separations, and synthesize nitric acid. (Towler and Sinnott, 2012) Recently, however, there has been a particularly strong interest for energy recovery in the natural gas industry, when gas is decompressed from major pipelines to residential low-pressure piplines. A 2001 study estimated that there is the potential to recover 21 TWh, representing 11% of natural gas transport energy, via gas expansion. (Lehman)

=Process water and boiler-feed water=
Process water is water that will be directly used in the process. Boiler-feed water (BFW) is used to produce steam. Both may need to be purified to prevent impurities from contaminating a process or from foul equipment. It can be used as a cooling stream when the temperature of the stream to be cooled is greater than ~300 ⁰F. Cost of BFW can be partially offset by the steam credit.

Process water that undergoes moderate pretreatment can cost ~ $0.75/1,000 gal.

Extensive treatment ~ $6.00/1,000 gal.

Sterilized for pharmaceutical processes ~ $550/1,000 gal. (Seider pg 608)

=Demineralized Water=
In demineralized water, minerals have been removed by ion exchange. In boiler feed water, this is to prevent salt deposition, corrosion, formation of foam, and sluicing. In process water, the ions may contaminate the process.

=Waste Treatment=
Most chemical processes will produce some sort of waste. Disposal occurs to the atmosphere (in the case of some gases), sewers, body of water, or a landfill. Waste may require some treatment before disposal to meet regulations. Depending on process economics, byproducts may be recovered and processed. (Seider 2009 pg 609)

==Wastewater Treatment==
The United States EPA regulates industrial wastewater disposal through the Clean Water Act, introduced in 1948 as the Federal Water Pollution Control Act and amended to its current form in 1972. The sweeping 1972 amendments allowed the EPA to prevent industries and persons from discharging contaminated water into fresh water sources and set water quality standards. (Summary of the Clean Water Act) In accordance with this law, process plants in the United States treat wastewater at on-site or near-site treatment centers before releasing it into the surrounding environment.

Wastewater effluent streams, along with water runoff from around the plant, are treated to control for pH, toxicity, suspended solids, and biological oxygen demand (for aquatic life protection) prior to discharge. Each of these controls is typically addressed with a separate method. Acidity and basicity is balanced through the addition of an acid or alkaline solution. Toxic wastewater may be treated with chemical processes or simply diluted to safe concentrations. Suspended solids can be removed via filtration and/or with clarifiers. Oxygen demand of wastewater can be mitigated using activated sludge treatment processes. Once the water quality complies with the EPA, and state-mandated, regulations, it can be safely released. More information on the large number of industry-specific guidelines for waste effluent can be found on the EPA website (http://www.epa.gov/eg/industrial-effluent-guidelines).

==Air-Pollution Management==
===Introduction===

In the United States air pollution is regulated in the Clean Air Act, and almost all pollutant emitting plants are regulated under this law. The types of plants that can release significant emissions include petroleum refineries, sulfur recovery plants, carbon-black plants, fuel conversion plants, chemical process plants, fossil fuel plants, and petroleum storage and transfer facilities. To receive permission to construct a plant must undergo a review to show that it will not cause a violation of the Ambient Air Quality Standards(Peters, 2003).

===Methods===

There are two major types of pollutants that are released into the air, particulates and and gaseous pollutants. Particulates can be removed with mechanical forces while gaseous pollutants typically need to removed by chemical or physical means (Peters, 2003).

Particulates and volatile pollutants that need to be removed before disposal may be present. Particle removal equipment includes: cyclones, wet scrubbers, electrostatic precipitators, and fabric-filter systems (Seider 2009) such as bag filters (. The two charts below are from ''Plant Design and Economics for Chemical Engineers'' and show the types of equipment, separation methods, and particle sizes in different pollutant separation technologies (Peters, 1991).

[[File:AirPolChart.png|thumb|border|center|middle|upright=4|link=|atl=|Different Methods of Particle Separation, the Particle Sizes they Can Remove, and the Technologies Used]]

[[File:AirPolTable.png|thumb|border|center|middle|upright=4|link=|atl=| This Chart Shows the Specifications and Limitations of Different Separations Technologies Including Particle Size, Efficiencies, and Temperatures(Peters, 1991)]]

====Wet Scrubbers====
Wet scrubber use lime or limestone and water to remove SO2 and acid gases. The mixture can be injected into a scrubber or the gases can be bubbled through this mixture. This results in removal of 90-98% of SO2 and and acid gases.

====Dry Scrubbers====
Dry scrubber blow powdered adsorbents into a vessel with gases and then after it has captured the SO2 and acid gases it is separated from gas using a fabric filter. These systems remove 90-93% of the contaminants.

====Low-NOx Burners====
The purpose of low NOx burners is to decrease the amount of NOx created when the coal is burned. This is done by injecting coal and air in boilers. This can result in 40-50% NOx reduction. If air is injected into the area above the burner this can actually cause almost 70% NOx reduction.

====Selective Non-Catalytic and Catalytic Reductions====
These systems inject ammonia into gases to remove NOx. The Catalytic reductions add a catalyst to the ammonia being injected to aid in the removal. Con-catalytic reductions result in about 35% removal, but adding a catalyst can increase that amount to about 90%. The catalytic-reduction can remove up to 80% of mercury as well.

====Fabric Filters====
Also known as baghouses,these [[Separation processes#Filtration| filters]] remove particulates by passing air through filters. These can separate as much as 99.9% of particulate matter.

====Electrostatic Precipitators====
Electrostatic Precicpitators remove particulate matter as gas passes through a device that has charged metal plates. The particles are then removed because of static electricity. These systems can remove between 99-99.9% of particulate matter

====Super-critical Boilers====
Super-Critical Boilers and Ultra-Supercritical Boilers operate at temperature and pressure higher than regular boilers. By operating at higher temperature these systems become more efficient. Super Critical Boilers typically have 10%-20% CO2 emissions than other similar sub-critical technologies. Ultra-Supercritical boilers can be as much as 30% more efficent than sub-critical technologies.

For more information regarding some of these separations equipment see [[Solids-involved equipment]]

For more information Regarding Cyclones see [[Separation processes#Cyclones| Cyclones]], and for modeling cyclones see their[[Solids-involved equipment#HYSYS Simulation|HYSYS Simulation]]

Methods for removing inorganic and organic gaseous pollutants include: absorption, adsorption, condensation, and combustion (Seider 2009 pg 609). A list of typical of gases pollutants and their sources from ''Plant Design and Economics for Chemical Engineers'' is shown below (Peters, 1991).

[[File:GaseousPollutants.png|thumb|border|center|middle|upright=4|link=|atl=| Common Gaseous Pollutants and their Sources]]

Typically Gas-liquid absorption processes are done completed in a vertical, countercurrent, flow through packed, plate, or spray towers. These systems require good liquid-gas contact and proper equipment. These systems also often have significant energy consumption because of large pressure drops (Peters, 2003). For high volume systems absorption by scrubbing with water or another solvent is the most widely used method (Towler, 2012). Dry adsorbents can be used to remove the last races of gaseous pollutants. Adsorption typically requires blowers, condensers, separators, and controls. You also typically need two packed beds so that one can be used while the other is regenerated. Examples of adsorbents are molecular sieves and activated carbon. Incineration is typically used when there are gas streams that have no recovery value. This can be done with direct flame or catalytic oxidation. Catalytic oxidation usually has higher capital costs, but lower operating costs because it does not require fuel.

You can find more information on [[Separation processes#Absorption| Absorption]] and [[Separation processes#Adsorption| Adsorption]] in [[Separation processes]]

===Outcomes===

====United States Common Pollutant Emissions====

The United States implemented the Clean Air Act in 1970 and since then emissions in the U.S. have been drastically reduced. As a matter of fact despite increases in the population in the last 35 years the amount of pollutants emitted have decreased by almost 70% (EPA). More importantly this demonstrates that reasonable efforts can be put towards environmental protection without causing too much harm to industry.

[[File:EPA.png|thumb|border|center|middle|upright=4|link=|atl=| GDP and Other Growth Factors Vs Common Pollutants Released]]

====China Clean Coal====

=====Success Through 2005=====

Coal is a very inexpensive and abundant source of energy and is abundant in China (Xu 2010). In China Coal the cause of 90% of SO2 emissions, 70% of dust emissions, and 67% of NOx emissions, and 70% of CO2 emissions. These numbers are staggering considering that Coal has never been more than 50 percent of China's Energy Supply.

[[File:Coal.jpg|thumb|border|center|middle|upright=4|link=|atl=| Coal Consumption for Power and the Percentage of Coal Used]]

Despite the increasing coal consumption, high efficiency electric dust removal systems with efficiencies that are as high as 99.6% have greatly decreased soot emissions to 32% below 1980's levels as of 2005.

[[File:Soot.jpg|thumb|border|center|middle|upright=4|link=|atl=| SO2 and Soot Emissions from 1981 to 2005]]

=====Technologies and Life Cycle Comparison 2013=====
As of 2010 China was consuming 48.2% of coal globally. Four potential technologies integrated gasification combined cycle (IGCC), sub-critical coal power generation (Sub-C); sub-critical coal power generation (Sub-C) super-critical coal power generation (Super-C). These technologies are compared mostly on the basis of net generating efficiency.

where efficiency is define as: η=E/Etotal

and

Etotal=Emining+Etransportation+Egeneration

==Solid Waste==
U.S. federal regulations require that solid waste be classified as hazardous or nonhazardous. Conditions for a classification of hazardous include: ignitability, corrosivity, reactivity, toxicity, or posing a substantial threat to the surrounding environment and its inhabitants. Hazardous waste must be treated on- or near-site before being removed in containers. Non-hazardous waste may be landfilled or incinerated in some cases. A typical estimate of costs for waste disposal is $0.03/lb for nonhazardous solids and $0.10/lb for hazardous solids. (Seider 2009 pg 609)

=References=

*Biegler LT, Grossmann IE, Westerberg AW. ''Systematic Methods of Chemical Process Design'' Prentice-Hall: Upper Saddle River, 1997.

*Duke Energy Company (2013). How Do Coal Fired Plants Work? Charlotte: Duke Energy.

*Lehman B, Worrell E. ''Electricity Production from Natural Gas Pressure Recovery Using Expansion Turbines.'' Lawrence Berkeley National Laboratory; 2001.

*"Overview of the Clean Air Act and Air Pollution." Environmental Protection Agency. November 17, 2015. http://www.epa.gov/clean-air-act-overview. Accessed February 5, 2016.

*Peters, Max S.; Timmerhaus, Klaus D.; West, Ronald E. (2003). "Plant Design and Economics for Chemical Engineers." McGraw Hill Higher Education.

*Seider, Seader, Lewin, Widagdo. (2009). ''Plant Design and Economics for Chemical Engineers, 5th Edition.'' Hoboken: Wiley.

*Seider, Seader, Lewin. (2008). ''Product and Process Design Principles, 2nd Edition.'' Hoboken: Wiley.

*Summary of the Clean Water Act. United States EPA website. http://www.epa.gov/laws-regulations/summary-clean-water-act

*Towler, G.P. and Sinnot, R. (2012). ''Chemical Engineering Design: Principles, Practice and Economics of Plant and Process Design.'' Elsevier.

*Turton R.; Bailie, R.C.; Whiting, W.B.; Shaeiwitz J.A.; Bhattacharyya D. (2012). ''Analysis, Synthesis, and Design of Chemical Processes.'' Upper Saddle River: Prentice Hall.

*G.D. Ulrich, A Guide to Chemical Engineering Process Design and Economics, Wiley: New York, 1984.

Utility systems

2016-02-21T17:18:22Z

Taunins: /* Process Heat Exchange */

Authors: David Chen, [2014] Joshua Lee, [2015] Brett Sleyster, [2016] and Tom Aunins [2016] 

Stewards: David Chen, Jian Gong, and Fengqi You

Date Presented: January 13, 2014 /Date Revised: January 14, 2014

 


__TOC__

=Introduction=
Many chemical processes do not take place at ambient temperature or pressures. In order to reach these non-ambient conditions, utilities will have to be used to raise or lower temperatures and compress gases. (Towler, Towler/UOP) Utilities often contribute 5 to 10% of the price of a product, and may come from public or private utility companies or on-site plants. For purchased utilities, costs depend on consumption, while for company-owned utilities, there will be both capital and operating costs. They include things such as steam for heating, electricity, cooling water, refrigeration, fuels such as natural gas, wastewater treatment, waste disposal, and landfill. Steam is often the largest utility cost. Cogeneration unit can supply electricity accompanied with different steam pressures. (Seider 2009)

=Electricity=

Electricity is used to power many different kinds of equipment. It has many advantages: it is efficient (> 90%), reliable, available in a wide range of power, shaft speeds, designs, lifetimes, convenience, costs, and maintenance. It is generally used up to 200 hp, and sometimes over 10,000 Hp. In chemical process plants, the electricity demand is generally determined by the work or energy required for compression, pumping, air cooling, lights, and many other items. This electricity often times is purchased from local electricity providers, but many plants generate their own electricity via sophisticated processes.

Electricity is rarely used as a primary heat utility in large-scale chemical plants for a variety of reasons. The main disadvantages of using electricity as a heat utility are as follows (Towler 2012):

:*Heat from electricity is two to three times more expensive than heat from fuels. This is attributed to the lack of efficiency when creating heat from electricity.

:*Electrical heating units are expensive, require high maintenance, and must comply with strict safety regulations.

:*Electrical heating units are unsafe compared to steam heating units. In steam systems, the physically steam controls the temperature, whereas in electrical heating units temperature is controlled by temperature controllers, which can fail or burn out.

The use of electricity carries with it some hazards depending on the environment. Extra care must be taken when using electrically-powered equipment in areas which may have combustible fluids, vapors, or dust, and where liquids may be present. (Seider 2009 pg 606)

==Conventional Power Station==

In general, most electricity is generated from a conventional coal-fired process, whether it be on-site or purchased from a provider. Coal-fired processes have been used to create electricity throughout history, and technological advances have increased its efficiency and use worldwide. In a coal-fired steam station—much like a nuclear station—water is turned into steam, which in turn drives turbine generators to produce electricity. There are several variations on how to create energy from coal, but here are the basics of how a coal-fired process works:

[[File:coalfired.png|thumb|border|center|middle|upright=4|link=|atl=|General Coal-Fired Process Diagram (Duke Energy Company)]]

*Heat is created:
::Before the coal is burned, it is pulverized to the fineness of talcum powder. It is then mixed with hot air and blown into the firebox of the boiler. Burning in suspension, the coal/air mixture provides the most complete combustion and maximum heat possible.

*Water turns to steam:
::Highly purified water, pumped through pipes inside the boiler, is turned into steam by the heat. The steam reaches temperatures of up to 1,000 degrees Fahrenheit and pressures up to 3,500 pounds per square inch, and is piped to the turbine.

*Steam turns the turbine:
::The enormous pressure of the steam pushing against a series of giant turbine blades turns the turbine shaft. The turbine shaft is connected to the shaft of the generator, where magnets spin within wire coils to produce electricity.

*Steam is converted back to water:
::After doing its work in the turbine, the steam is drawn into a condenser, a large chamber in the basement of the power plant. In this important step, millions of gallons of cool water from a nearby source (such as a river or lake) are pumped through a network of tubes running through the condenser. The cool water in the tubes converts the steam back into water that can be used over and over again in the plant.

*Repeat:
::The cooling water is returned to its source without any contamination, and the steam water is returned to the boiler to repeat the cycle.

===Advantages & Disadvantages of Coal-Fired Energy Production===

[[File:coalfiredtable.png|thumb|border|center|middle|upright=4|link=|atl=|Advantages and Disadvantages of Coal-Fired Processes (Seider 2008)]]

==Gas-Turbine Cogeneration Process==

When generating energy on-site, many plants use a gas-turbine cogeneration process. The thermal efficiency of a gas-turbine process is in the range of 70-80% while conventional power stations, such as coal-fired processes, have a 30-40% efficiency. The lower efficiency in more conventional power stations is attributed to wasted heat in the exhaust steam in the condenser. One example of a gas-turbine process is outlined in the following figure. Figure 3.1 is a gas-turbine cogeneration process with a heat recovery steam generator (waste-heat) boiler.

[[File:cogeneration.png|thumb|border|center|middle|upright=4|link=|atl=|Gas-Turbine Cogeneration with a heat recovery steam generator boiler (Towler 2012 Fig 3.1)]]

Overall, the process illustrated is not much different from a coal-fired process. The main differences are that the cogeneration process creates both electricity and a heat utility, and cogeneration processes use natural gas instead of coal. Many of the advantages and disadvantages are similar to those of the coal-fired process, but the cogeneration has a much higher efficiency, creates heat to be used in another process, and uses a more volatile and expensive fuel. The main advantage of cogeneration over coal-fired energy production is that heat is not wasted. In coal-fired processes, heat is released and wasted during electricity generation. Cogeneration captures some, if not all of the byproduct for heat, which is an extremely useful utility that will be discussed in subsequent sections. In summary, the cogeneration plant is superior to the coal-fired process because of its higher efficiency and ability to create a useful heat utility.

Obviously any engineer would design the cogeneration plant to meet at least the energy requirement necessary for plant operation, but cogeneration plants often times are designed to exceed the plant electricity requirement to drive another source of capital. Many describe this scenario as a "make or buy" scenario (Towler 2012). This scenario provides chemical producers leverage when negotiating contracts with outsourced electricity providers and this allows plants to purchase electricity at a wholesale price. This is a huge advantage of considering on-site electricity production because electricity is needed in relatively high quantities for all chemical plants. Being able to minimize electricity costs, or even profit off of electricity production is a huge economical consideration that all plants employ.

=Process Heating=
The key objective of this section is to discuss how processes are heated. Heating utilities are necessary for proper usage of distillers, reactors, condensers, and several other integral types of equipment. More specifically, steam, fired heat, and hot oil/specialized heat transfer fluids will be discussed in the following subsections.

==Steam==
Steam is the most commonly used heat utility used in chemical plants, and as a result understanding how it is used is essential in the study of Utility systems. Steam is used both as a process fluid (feedstock, diluent to absorb heat of reaction, heating agent, and stripping agent in absorbers and adsorbers ) and utility. It can be used to drive pumps and compressors, ejectors (for producing a vacuum), and heat exchangers. As one can clearly see, steam is a versatile, and useful utility.

Here are a few advantages of using steam as opposed to other methods of process heating (Towler 2012):

:*By controlling the pressure of the steam, one can control the temperature at which the heat is released. Having a strong control over the temperature is essential in several processes. =
:*Steam is an efficient heat source because the heat of condensation of steam is very high. Meaning that there is is high output per mass of utility at a constant temperature.
:*Heat exchangers that use steam are relatively cheap because condensing steam has a high heat transfer coefficient.
:*Steam is nonflammable, nontoxic, and inert to several process fluids.

Chemical plants generally have a network of pipelines exclusively for providing steam. These networks generally have steam at a low pressure, a medium pressure, and a high pressure. The image below illustrates a basic steam system.

[[File:Steam.png|thumb|border|center|middle|upright=4|link=|atl=|(Towler 2012 Fig 3.2)]]

In the diagram above, boiler feed water at a high pressure is preheated and fed to other boilers. These other boilers superheat the steam to create a high pressure and high temperature steam stream. The steam is superheated past the dew point to account for heat loss in the pipelines. A portion of the high pressure steam is used for process heating in areas of the plant that require high temperatures. The rest of the high pressure steam is turned into medium pressure steam by valves and steam turbines. The medium pressure steam is then used to heat medium temperature processes and to form low pressure steam. The low pressure steam can be used to heat low pressure processes and it can be expanded in condensing turbines to create shaft work and energy. In summary, steam can be used for an innumerable amount of action items in a plant. High pressure, medium pressure, and low pressure steam can all be used as a heat source. Low pressure steam has utilities in creating electricity and it also has several other uses.

==Fired Heat==

In many cases, processes in a plant require a heat source stronger than high pressure and temperature steam. That is when fired heat is used, which is generally at temperatures above 523K. Streams can be heated directly in the furnace tubes or via a hot oil circuit or heat transfer fluid, which will be discussed in detail in the next section. Most fired heaters use natural gas as fuel because it burns cleaner than fuel oil. A cleaner burning fuel is always advantageous due to environmental and safety concerns. Furthermore, natural gases usually result in less wear and tear in burners and fuel lines.

Depending on the application of the fired-heater, different design specifications can be implemented to make the fired-heater as efficient as possible. The basic construction of a fired heater starts with a cylindrical chamber that is lined with with refractory bricks. The stream that is to be heated flows through tubes inside of the furnace. These tubes can be arranged in several different arrangements such as, around the walls of the furnace, or in horizontal or vertical banks (Towler 2012). The figure below illustrates the basic construction of the fired-heater and varying tube arrangements.

[[File:firedheater.png|thumb|border|center|middle|upright=4|link=|atl=|Basic Fired-Heater Diagrams (Towler 2012 Figure 19.66)]]

Fuel is burned to heat the entire furnace, and the heat transfer occurs from the combustion gases inside of the furnace across the tubes that are filled with our desired stream. The heat transfer between the tubes and the furnace is accomplished primarily via radiation. Modern designs take advantage of convective heat transfer by adding a smaller section on top of the fired-heater where the combustion gases flow over banks of tubes as seen in (c) in the figure above. Heat transfer can be further improved via convection by adding fins or pins in the combustion section.

The cost of fired heat can be calculated by the cost of fuel fired. Natural gas and heating oil are traded as commodities and prices can be found at many online trading sites or business news sites (i.e., www.cnn.money.com). Past historic prices for forecasting can be found in the Oil and Gas Journal or from the U.S. Energy Information Adminstration (www.eia.gov).

===Fuels===
Fuel is burned in utility facilities such as boilers, electricity generation, and cogeneration, and can be in solid, liquid, or gas form. It can also be burned to provide heating for a process or stream or to drive pumps and compressors. The fuel is usually burned with excess air to ensure complete combustion.

A way of quantifying the amount of heat generated is by using the heating values. Higher heating value (HHV) and the lower heating value (LHV) are used. The heating is the total heat evolved by complete combustion of a fuel with dry air with both at 60 ⁰F and the flue gas after combustion brought back down to ⁰F. If the water vapor in the flue gas is not condensed, we obtain the LHV. If the water vapor is condensed, the value of heat evolved is a bit higher, and this is the HHV.
Heating values for solids and liquids are usually on a per-mass basis, and gases on a per-volume basis.
A specified amount of heating cannot be met with the amount of fuel calculated using only the HHV. There will be heat losses, the flue gas temperature will be greater than 60 ⁰F, and water in the flue gas will typically be vapor. (Seider 608)

==Hot Oil/Specialized Heat Transfer Fluids==

Specialized heat transfer fluids and hot oil circuits are used as heat sources when steam and fired heat is not appropriate. Specialized heat transfer fluids and hot oil circuits are extremely versatile in that they can be used in the temperature range of 323K to 673K. This range however is quite variable. For hot oils, the upper temperature limit is gauged based off of the thermal decomposition of the oil and coking/fouling of heat exchanger tubes.

Hot oil circuit systems are most commonly used when the plant has several small temperature heating requirements because it is more economically sound. Rather than having several fired heaters heat each small temperature requirement, it is much more economical to have one fired heater heat the hot oil and circulate that oil through each of the process to meet all of the heat needs. Hot oil systems are also generally favored over high pressure steam in processes that involve high pressure differentials between the process stream and high pressure steam. Hot oil systems are favored in this scenario because of safety concerns. If the steam were to leak, the pressure drop could cause serious safety issues.

Mineral oils are the most commonly used heat transfer fluids, and one prominent example is Dowtherm A. Dowtherm A is a combination of 26.5 wt% diphenyl in diphenyl oxide (Towler 2012) and is extremely thermally stable. These mineral oil systems generally require high flow rates.

=Process Cooling=

==Cooling Water==
Cooling water is used to cool and/or condense streams. Cooling water is usually circulated between process heat exchangers and a cooling tower. Water is cooled during downward motion by contact with air blown upwards, which can bring the water temperature to come within ~ 5 ⁰F of air’s wet-bulb temperature.Approximately 80% of the temperature reduction is due to evaporation of the cooling water and heat transfer to the surrounding air. Water can also be cooled in spray ponds and cooling ponds. Both work by providing high area for water to exchange heat with air.
Water in cooling towers is lost through drift and blowdown, and makeup is usually 1.5 to 3% of the circulating rate.
If a large natural body of water is nearby, it can be used as a source of cooling water and discharged downstream. This water is usually filtered to remove salts and impurities that may lead to fouling, but it is not treated.

==Refrigeration==
Cooling water can usually be used to cool a stream to ~ 100 ⁰F. Air can only cool to ~ 120 ⁰F. Air may be used in places where water is scarce or more costly to transport. To cool or condense streams below 100 ⁰F, a refrigerant is typically used. Chilled brine can also be used, but is less common.

Until 1995, CFC Freon R-12 (dichlorodifuloromethane) and HCFC Freon R-22 (chlorodifuloromethane) were commonly used refrigerants. However, the chlorine atom in the molecules caused the depletion of the ozone layer. The U.S. Clean Air Act Amendments of 1990 went into effect in 1995, and the production of these refrigerants has since stopped or been greatly reduced.

Cost estimates are based on ton-day of refrigeration, where a ton is the heat that needs to be removed to freeze 1 ton per day of water at 32 ⁰F. Substitutes have since been developed. R-134a is often used in place of R-12. According to the EPA, R-134a is not combustible at ambient conditions, and is essentially non-toxic under 400 ppm, and is not ozone-depleting. (Seider pg 607)

=Energy Efficiency=
One of the chief concerns in selecting and designing process utility systems for heating and cooling is how to achieve the most energy efficient design. There are countless means by which plants lose energy, two of the foremost being through the mixing of different temperature or pressure streams and through the disposal of warmed cooling water. (Seider, 2009) Proper utilities design can help mitigate each of these losses as well as many others. The energy efficiency of a plant will depend primarily on the heating and cooling methods that are being used and the overall system design itself. These two parameters are important in determining how well energy is transferred to the desired media as well as how well that energy is recovered and recycled.

==Utility Efficiency==
As mentioned above, the most commonly used utilities for process heating in large scale processes are steam, fired heat, and hot oil heaters. Of these, steam is the most commonly used. Electricity, while efficient at creating power, is not a viable source of heat in large industrial processes. Common ranges of heating efficiency for these three methods are displayed in Table 1. (Towler and Sinnott, 2012)

{| class="wikitable"
|+Table 1: Process Heating Efficiencies
|-
! Process Heating Method
! Typical Efficiency
|-
| Steam (via package boiler)
| 80-90%
|-
| Fired Heat w/ Convective Section
| 85%
|-
| Fired Heat w/o Convective Section
| 60%
|-
| Hot Oil Heaters/Vaporizers
| 80-85%
|}

Efficiency in cooling processes depends more on the method used, and by extension the amount of coolant needed. Water and air utility efficiencies depend primarily on the fluid flow required to maintain the system at a desired temperature, while powered refrigeration utilities (for colder processes) have efficiencies at approximately 60%--but ranging up to 90%--of Carnot cycle efficiency, a metric of ideal refrigeration efficiency. (Towler and Sinnott, 2012) Cooling systems represent by definition a loss of energy from the main process to the utility stream, and as such it is often useful to find other uses for the heated media before discharge.

==Energy Recovery==
Recovery and recycle of energy is perhaps the most important aspect of creating an energy efficient plant design, and it is important for process engineers to fully consider possibilities for heat recovery in order to aid in economic viability.

===Process Heat Exchange===
Heat exchanger networks are a very common energy recovery method in industrial processes. These networks most frequently allow energy from heated product streams to be transferred to feed streams that must be brought up to process temperature. (Biegler, 1997) More information on the function and design of heat exchanger networks can be found on the [[Heat_exchanger#Heat_Exchanger_Networks|heat exchanger wiki page]]. The following are several examples of energy recovery via heat exchange that are used in industrial processes.

In distillation columns the bottoms and distillate effluents have the potential for energy exchange. Though the condenser at the top of the column cannot supply its waste heat to the reboiler due to their respective temperatures, the effluent streams can supply heat to the feed via a feed-effluent exchanger. This reduces the utility requirements to raise the feed to column temperature. (Biegler, 1997)

[[File:Feed_sterilization.jpg|thumb|border|right|middle|upright=4|link=|atl=|Feed sterilization schematic. (Towler and Sinnott Fig. 3.30)]]

Feed sterilization, commonly used in the food industry, is a common application for heat recovery through process stream heat exchange. In this application, the feed must be heated for a certain amount of time to kill any biological contaminants, after which it can be used to heat the new raw feed for sterilization. This reduces energy demands on the steam heater and thus reduces cost. (Towler and Sinnott, 2012)

In multi-vessel batch processes it can be advantageous to exchange heat as the process fluid is being transferred between vessels. Like the previous examples, this reduces the utility needed to bring the colder feed up to process temperature, thus reducing costs. (Towler and Sinnott, 2012)

[[File:Batch_heat_exchange.jpg|thumb|border|center|middle|upright=4|link=|atl=|Multi-vessel batch heat exchange schematic (Towler and Sinnott Fig. 3.31)]]

===Utility Regeneration===
[[File:Waste_heat_boiler.jpg|thumb|border|right|middle|upright=4|link=|atl=|Industrial modular HRSG]]
When recovery of waste heat via transfer to other process streams is inconvenient or impossible, energy efficiency can still be improved through the regeneration of utilities. This is commonly done through the regeneration of steam by either removing heat from exiting streams or from highly exothermic reactions. Waste heat in exiting streams is removed via heat recovery steam generators (HRSGs), and is most often used on exiting flue gas and exiting process gas streams. Heat recovery from reactions is a viable option when the reactor temperature will be at 150 C or above, as this will create steam at high enough pressure to be used in other processes. (Towler and Sinnott, 2012)

Furthermore, there is opportunity for energy recovery in the expansion of compressed gas through a turbine to create electricity, a process that can be economically viable given sufficiently high flows or pressure. Such technology has been used in processes to synthesize ammonia, perform air separations, and synthesize nitric acid. (Towler and Sinnott, 2012) Recently, however, there has been a particularly strong interest for energy recovery in the natural gas industry, when gas is decompressed from major pipelines to residential low-pressure piplines. A 2001 study estimated that there is the potential to recover 21 TWh, representing 11% of natural gas transport energy, via gas expansion. (Lehman)

=Process water and boiler-feed water=
Process water is water that will be directly used in the process. Boiler-feed water (BFW) is used to produce steam. Both may need to be purified to prevent impurities from contaminating a process or from foul equipment. It can be used as a cooling stream when the temperature of the stream to be cooled is greater than ~300 ⁰F. Cost of BFW can be partially offset by the steam credit.

Process water that undergoes moderate pretreatment can cost ~ $0.75/1,000 gal.

Extensive treatment ~ $6.00/1,000 gal.

Sterilized for pharmaceutical processes ~ $550/1,000 gal. (Seider pg 608)

=Demineralized Water=
In demineralized water, minerals have been removed by ion exchange. In boiler feed water, this is to prevent salt deposition, corrosion, formation of foam, and sluicing. In process water, the ions may contaminate the process.

=Waste Treatment=
Most chemical processes will produce some sort of waste. Disposal occurs to the atmosphere (in the case of some gases), sewers, body of water, or a landfill. Waste may require some treatment before disposal to meet regulations. Depending on process economics, byproducts may be recovered and processed. (Seider 2009 pg 609)

==Wastewater Treatment==
The United States EPA regulates industrial wastewater disposal through the Clean Water Act, introduced in 1948 as the Federal Water Pollution Control Act and amended to its current form in 1972. The sweeping 1972 amendments allowed the EPA to prevent industries and persons from discharging contaminated water into fresh water sources and set water quality standards. (Summary of the Clean Water Act) In accordance with this law, process plants in the United States treat wastewater at on-site or near-site treatment centers before releasing it into the surrounding environment.

Wastewater effluent streams, along with water runoff from around the plant, are treated to control for pH, toxicity, suspended solids, and biological oxygen demand (for aquatic life protection) prior to discharge. Each of these controls is typically addressed with a separate method. Acidity and basicity is balanced through the addition of an acid or alkaline solution. Toxic wastewater may be treated with chemical processes or simply diluted to safe concentrations. Suspended solids can be removed via filtration and/or with clarifiers. Oxygen demand of wastewater can be mitigated using activated sludge treatment processes. Once the water quality complies with the EPA, and state-mandated, regulations, it can be safely released. More information on the large number of industry-specific guidelines for waste effluent can be found on the EPA website (http://www.epa.gov/eg/industrial-effluent-guidelines).

==Air-Pollution Management==
===Introduction===

In the United States air pollution is regulated in the Clean Air Act, and almost all pollutant emitting plants are regulated under this law. The types of plants that can release significant emissions include petroleum refineries, sulfur recovery plants, carbon-black plants, fuel conversion plants, chemical process plants, fossil fuel plants, and petroleum storage and transfer facilities. To receive permission to construct a plant must undergo a review to show that it will not cause a violation of the Ambient Air Quality Standards(Peters, 2003).

===Methods===

There are two major types of pollutants that are released into the air, particulates and and gaseous pollutants. Particulates can be removed with mechanical forces while gaseous pollutants typically need to removed by chemical or physical means (Peters, 2003).

Particulates and volatile pollutants that need to be removed before disposal may be present. Particle removal equipment includes: cyclones, wet scrubbers, electrostatic precipitators, and fabric-filter systems (Seider 2009) such as bag filters (. The two charts below are from ''Plant Design and Economics for Chemical Engineers'' and show the types of equipment, separation methods, and particle sizes in different pollutant separation technologies (Peters, 1991).

[[File:AirPolChart.png|thumb|border|center|middle|upright=4|link=|atl=|A Chart Showing Different Technologies Used to Remove Particulates]]

[[File:AirPolTable.png|thumb|border|center|middle|upright=4|link=|atl=| This Chart Shows the Specifications and Limitations of Different Separations Technologies(Peters, 1991)]]

For more information regarding some of these separations eqipment see [[Solids-involved equipment]]

For more information Regarding Cyclones see [[Separation processes#Cyclones| Cyclones]]

Methods for removing inorganic and organic gaseous pollutants include: absorption, adsorption, condensation, and combustion (Seider 2009 pg 609). A list of typical of gases pollutants and their sources from ''Plant Design and Economics for Chemical Engineers'' is shown below (Peters, 1991).

[[File:GaseousPollutants.png|thumb|border|center|middle|upright=4|link=|atl=|]]

Typically Gas-liquid absorption processes are done completed in a vertical, countercurrent, flow through packed, plate, or spray towers. These systems require good liquid-gas contact and proper equipment. These systems also often have significant energy consumption because of large pressure drops (Peters, 2003). For high volume systems absorption by scrubbing with water or another solvent is the most widely used method (Towler, 2012). Dry adsorbents can be used to remove the last races of gaseous pollutants. Adsorption typically requires blowers, condensers, separators, and controls. You also typically need two packed beds so that one can be used while the other is regenerated. Examples of adsorbents are molecular sieves and activated carbon. Incineration is typically used when there are gas streams that have no recovery value. This can be done with direct flame or catalytic oxidation. Catalytic oxidation usually has higher capital costs, but lower operating costs because it does not require fuel.

You can find more information on [[Separation processes#Absorption| Absorption]] and [[Separation processes#Adsorption| Adsorption]] in [[Separation processes]]

===Outcomes===

The United States implemented the Clean Air Act in 1970 and since then emissions in the U.S. have been drastically reduced. As a matter of fact despite increases in the population in the last 35 years the amount of pollutants emitted have decreased by almost 70% (EPA). More importantly this demonstrates that reasonable efforts can be put towards environmental protection without causing too much harm to industry.

[[File:EPA.png|thumb|border|center|middle|upright=4|link=|atl=| GDP and Other Growth Factors Vs Common Pollutants Released]]

==Solid Waste==
U.S. federal regulations require that solid waste be classified as hazardous or nonhazardous. Conditions for a classification of hazardous include: ignitability, corrosivity, reactivity, toxicity, or posing a substantial threat to the surrounding environment and its inhabitants. Hazardous waste must be treated on- or near-site before being removed in containers. Non-hazardous waste may be landfilled or incinerated in some cases. A typical estimate of costs for waste disposal is $0.03/lb for nonhazardous solids and $0.10/lb for hazardous solids. (Seider 2009 pg 609)

=References=

*Biegler LT, Grossmann IE, Westerberg AW. ''Systematic Methods of Chemical Process Design'' Prentice-Hall: Upper Saddle River, 1997.

*Duke Energy Company (2013). How Do Coal Fired Plants Work? Charlotte: Duke Energy.

*Lehman B, Worrell E. ''Electricity Production from Natural Gas Pressure Recovery Using Expansion Turbines.'' Lawrence Berkeley National Laboratory; 2001.

*"Overview of the Clean Air Act and Air Pollution." Environmental Protection Agency. November 17, 2015. http://www.epa.gov/clean-air-act-overview. Accessed February 5, 2016.

*Peters, Max S.; Timmerhaus, Klaus D.; West, Ronald E. (2003). "Plant Design and Economics for Chemical Engineers." McGraw Hill Higher Education.

*Seider, Seader, Lewin, Widagdo. (2009). ''Plant Design and Economics for Chemical Engineers, 5th Edition.'' Hoboken: Wiley.

*Seider, Seader, Lewin. (2008). ''Product and Process Design Principles, 2nd Edition.'' Hoboken: Wiley.

*Summary of the Clean Water Act. United States EPA website. http://www.epa.gov/laws-regulations/summary-clean-water-act

*Towler, G.P. and Sinnot, R. (2012). ''Chemical Engineering Design: Principles, Practice and Economics of Plant and Process Design.'' Elsevier.

*Turton R.; Bailie, R.C.; Whiting, W.B.; Shaeiwitz J.A.; Bhattacharyya D. (2012). ''Analysis, Synthesis, and Design of Chemical Processes.'' Upper Saddle River: Prentice Hall.

*G.D. Ulrich, A Guide to Chemical Engineering Process Design and Economics, Wiley: New York, 1984.

Utility systems

2016-02-21T17:17:20Z

Taunins: /* Process Heat Exchange */

Authors: David Chen, [2014] Joshua Lee, [2015] Brett Sleyster, [2016] and Tom Aunins [2016] 

Stewards: David Chen, Jian Gong, and Fengqi You

Date Presented: January 13, 2014 /Date Revised: January 14, 2014

 


__TOC__

=Introduction=
Many chemical processes do not take place at ambient temperature or pressures. In order to reach these non-ambient conditions, utilities will have to be used to raise or lower temperatures and compress gases. (Towler, Towler/UOP) Utilities often contribute 5 to 10% of the price of a product, and may come from public or private utility companies or on-site plants. For purchased utilities, costs depend on consumption, while for company-owned utilities, there will be both capital and operating costs. They include things such as steam for heating, electricity, cooling water, refrigeration, fuels such as natural gas, wastewater treatment, waste disposal, and landfill. Steam is often the largest utility cost. Cogeneration unit can supply electricity accompanied with different steam pressures. (Seider 2009)

=Electricity=

Electricity is used to power many different kinds of equipment. It has many advantages: it is efficient (> 90%), reliable, available in a wide range of power, shaft speeds, designs, lifetimes, convenience, costs, and maintenance. It is generally used up to 200 hp, and sometimes over 10,000 Hp. In chemical process plants, the electricity demand is generally determined by the work or energy required for compression, pumping, air cooling, lights, and many other items. This electricity often times is purchased from local electricity providers, but many plants generate their own electricity via sophisticated processes.

Electricity is rarely used as a primary heat utility in large-scale chemical plants for a variety of reasons. The main disadvantages of using electricity as a heat utility are as follows (Towler 2012):

:*Heat from electricity is two to three times more expensive than heat from fuels. This is attributed to the lack of efficiency when creating heat from electricity.

:*Electrical heating units are expensive, require high maintenance, and must comply with strict safety regulations.

:*Electrical heating units are unsafe compared to steam heating units. In steam systems, the physically steam controls the temperature, whereas in electrical heating units temperature is controlled by temperature controllers, which can fail or burn out.

The use of electricity carries with it some hazards depending on the environment. Extra care must be taken when using electrically-powered equipment in areas which may have combustible fluids, vapors, or dust, and where liquids may be present. (Seider 2009 pg 606)

==Conventional Power Station==

In general, most electricity is generated from a conventional coal-fired process, whether it be on-site or purchased from a provider. Coal-fired processes have been used to create electricity throughout history, and technological advances have increased its efficiency and use worldwide. In a coal-fired steam station—much like a nuclear station—water is turned into steam, which in turn drives turbine generators to produce electricity. There are several variations on how to create energy from coal, but here are the basics of how a coal-fired process works:

[[File:coalfired.png|thumb|border|center|middle|upright=4|link=|atl=|General Coal-Fired Process Diagram (Duke Energy Company)]]

*Heat is created:
::Before the coal is burned, it is pulverized to the fineness of talcum powder. It is then mixed with hot air and blown into the firebox of the boiler. Burning in suspension, the coal/air mixture provides the most complete combustion and maximum heat possible.

*Water turns to steam:
::Highly purified water, pumped through pipes inside the boiler, is turned into steam by the heat. The steam reaches temperatures of up to 1,000 degrees Fahrenheit and pressures up to 3,500 pounds per square inch, and is piped to the turbine.

*Steam turns the turbine:
::The enormous pressure of the steam pushing against a series of giant turbine blades turns the turbine shaft. The turbine shaft is connected to the shaft of the generator, where magnets spin within wire coils to produce electricity.

*Steam is converted back to water:
::After doing its work in the turbine, the steam is drawn into a condenser, a large chamber in the basement of the power plant. In this important step, millions of gallons of cool water from a nearby source (such as a river or lake) are pumped through a network of tubes running through the condenser. The cool water in the tubes converts the steam back into water that can be used over and over again in the plant.

*Repeat:
::The cooling water is returned to its source without any contamination, and the steam water is returned to the boiler to repeat the cycle.

===Advantages & Disadvantages of Coal-Fired Energy Production===

[[File:coalfiredtable.png|thumb|border|center|middle|upright=4|link=|atl=|Advantages and Disadvantages of Coal-Fired Processes (Seider 2008)]]

==Gas-Turbine Cogeneration Process==

When generating energy on-site, many plants use a gas-turbine cogeneration process. The thermal efficiency of a gas-turbine process is in the range of 70-80% while conventional power stations, such as coal-fired processes, have a 30-40% efficiency. The lower efficiency in more conventional power stations is attributed to wasted heat in the exhaust steam in the condenser. One example of a gas-turbine process is outlined in the following figure. Figure 3.1 is a gas-turbine cogeneration process with a heat recovery steam generator (waste-heat) boiler.

[[File:cogeneration.png|thumb|border|center|middle|upright=4|link=|atl=|Gas-Turbine Cogeneration with a heat recovery steam generator boiler (Towler 2012 Fig 3.1)]]

Overall, the process illustrated is not much different from a coal-fired process. The main differences are that the cogeneration process creates both electricity and a heat utility, and cogeneration processes use natural gas instead of coal. Many of the advantages and disadvantages are similar to those of the coal-fired process, but the cogeneration has a much higher efficiency, creates heat to be used in another process, and uses a more volatile and expensive fuel. The main advantage of cogeneration over coal-fired energy production is that heat is not wasted. In coal-fired processes, heat is released and wasted during electricity generation. Cogeneration captures some, if not all of the byproduct for heat, which is an extremely useful utility that will be discussed in subsequent sections. In summary, the cogeneration plant is superior to the coal-fired process because of its higher efficiency and ability to create a useful heat utility.

Obviously any engineer would design the cogeneration plant to meet at least the energy requirement necessary for plant operation, but cogeneration plants often times are designed to exceed the plant electricity requirement to drive another source of capital. Many describe this scenario as a "make or buy" scenario (Towler 2012). This scenario provides chemical producers leverage when negotiating contracts with outsourced electricity providers and this allows plants to purchase electricity at a wholesale price. This is a huge advantage of considering on-site electricity production because electricity is needed in relatively high quantities for all chemical plants. Being able to minimize electricity costs, or even profit off of electricity production is a huge economical consideration that all plants employ.

=Process Heating=
The key objective of this section is to discuss how processes are heated. Heating utilities are necessary for proper usage of distillers, reactors, condensers, and several other integral types of equipment. More specifically, steam, fired heat, and hot oil/specialized heat transfer fluids will be discussed in the following subsections.

==Steam==
Steam is the most commonly used heat utility used in chemical plants, and as a result understanding how it is used is essential in the study of Utility systems. Steam is used both as a process fluid (feedstock, diluent to absorb heat of reaction, heating agent, and stripping agent in absorbers and adsorbers ) and utility. It can be used to drive pumps and compressors, ejectors (for producing a vacuum), and heat exchangers. As one can clearly see, steam is a versatile, and useful utility.

Here are a few advantages of using steam as opposed to other methods of process heating (Towler 2012):

:*By controlling the pressure of the steam, one can control the temperature at which the heat is released. Having a strong control over the temperature is essential in several processes. =
:*Steam is an efficient heat source because the heat of condensation of steam is very high. Meaning that there is is high output per mass of utility at a constant temperature.
:*Heat exchangers that use steam are relatively cheap because condensing steam has a high heat transfer coefficient.
:*Steam is nonflammable, nontoxic, and inert to several process fluids.

Chemical plants generally have a network of pipelines exclusively for providing steam. These networks generally have steam at a low pressure, a medium pressure, and a high pressure. The image below illustrates a basic steam system.

[[File:Steam.png|thumb|border|center|middle|upright=4|link=|atl=|(Towler 2012 Fig 3.2)]]

In the diagram above, boiler feed water at a high pressure is preheated and fed to other boilers. These other boilers superheat the steam to create a high pressure and high temperature steam stream. The steam is superheated past the dew point to account for heat loss in the pipelines. A portion of the high pressure steam is used for process heating in areas of the plant that require high temperatures. The rest of the high pressure steam is turned into medium pressure steam by valves and steam turbines. The medium pressure steam is then used to heat medium temperature processes and to form low pressure steam. The low pressure steam can be used to heat low pressure processes and it can be expanded in condensing turbines to create shaft work and energy. In summary, steam can be used for an innumerable amount of action items in a plant. High pressure, medium pressure, and low pressure steam can all be used as a heat source. Low pressure steam has utilities in creating electricity and it also has several other uses.

==Fired Heat==

In many cases, processes in a plant require a heat source stronger than high pressure and temperature steam. That is when fired heat is used, which is generally at temperatures above 523K. Streams can be heated directly in the furnace tubes or via a hot oil circuit or heat transfer fluid, which will be discussed in detail in the next section. Most fired heaters use natural gas as fuel because it burns cleaner than fuel oil. A cleaner burning fuel is always advantageous due to environmental and safety concerns. Furthermore, natural gases usually result in less wear and tear in burners and fuel lines.

Depending on the application of the fired-heater, different design specifications can be implemented to make the fired-heater as efficient as possible. The basic construction of a fired heater starts with a cylindrical chamber that is lined with with refractory bricks. The stream that is to be heated flows through tubes inside of the furnace. These tubes can be arranged in several different arrangements such as, around the walls of the furnace, or in horizontal or vertical banks (Towler 2012). The figure below illustrates the basic construction of the fired-heater and varying tube arrangements.

[[File:firedheater.png|thumb|border|center|middle|upright=4|link=|atl=|Basic Fired-Heater Diagrams (Towler 2012 Figure 19.66)]]

Fuel is burned to heat the entire furnace, and the heat transfer occurs from the combustion gases inside of the furnace across the tubes that are filled with our desired stream. The heat transfer between the tubes and the furnace is accomplished primarily via radiation. Modern designs take advantage of convective heat transfer by adding a smaller section on top of the fired-heater where the combustion gases flow over banks of tubes as seen in (c) in the figure above. Heat transfer can be further improved via convection by adding fins or pins in the combustion section.

The cost of fired heat can be calculated by the cost of fuel fired. Natural gas and heating oil are traded as commodities and prices can be found at many online trading sites or business news sites (i.e., www.cnn.money.com). Past historic prices for forecasting can be found in the Oil and Gas Journal or from the U.S. Energy Information Adminstration (www.eia.gov).

===Fuels===
Fuel is burned in utility facilities such as boilers, electricity generation, and cogeneration, and can be in solid, liquid, or gas form. It can also be burned to provide heating for a process or stream or to drive pumps and compressors. The fuel is usually burned with excess air to ensure complete combustion.

A way of quantifying the amount of heat generated is by using the heating values. Higher heating value (HHV) and the lower heating value (LHV) are used. The heating is the total heat evolved by complete combustion of a fuel with dry air with both at 60 ⁰F and the flue gas after combustion brought back down to ⁰F. If the water vapor in the flue gas is not condensed, we obtain the LHV. If the water vapor is condensed, the value of heat evolved is a bit higher, and this is the HHV.
Heating values for solids and liquids are usually on a per-mass basis, and gases on a per-volume basis.
A specified amount of heating cannot be met with the amount of fuel calculated using only the HHV. There will be heat losses, the flue gas temperature will be greater than 60 ⁰F, and water in the flue gas will typically be vapor. (Seider 608)

==Hot Oil/Specialized Heat Transfer Fluids==

Specialized heat transfer fluids and hot oil circuits are used as heat sources when steam and fired heat is not appropriate. Specialized heat transfer fluids and hot oil circuits are extremely versatile in that they can be used in the temperature range of 323K to 673K. This range however is quite variable. For hot oils, the upper temperature limit is gauged based off of the thermal decomposition of the oil and coking/fouling of heat exchanger tubes.

Hot oil circuit systems are most commonly used when the plant has several small temperature heating requirements because it is more economically sound. Rather than having several fired heaters heat each small temperature requirement, it is much more economical to have one fired heater heat the hot oil and circulate that oil through each of the process to meet all of the heat needs. Hot oil systems are also generally favored over high pressure steam in processes that involve high pressure differentials between the process stream and high pressure steam. Hot oil systems are favored in this scenario because of safety concerns. If the steam were to leak, the pressure drop could cause serious safety issues.

Mineral oils are the most commonly used heat transfer fluids, and one prominent example is Dowtherm A. Dowtherm A is a combination of 26.5 wt% diphenyl in diphenyl oxide (Towler 2012) and is extremely thermally stable. These mineral oil systems generally require high flow rates.

=Process Cooling=

==Cooling Water==
Cooling water is used to cool and/or condense streams. Cooling water is usually circulated between process heat exchangers and a cooling tower. Water is cooled during downward motion by contact with air blown upwards, which can bring the water temperature to come within ~ 5 ⁰F of air’s wet-bulb temperature.Approximately 80% of the temperature reduction is due to evaporation of the cooling water and heat transfer to the surrounding air. Water can also be cooled in spray ponds and cooling ponds. Both work by providing high area for water to exchange heat with air.
Water in cooling towers is lost through drift and blowdown, and makeup is usually 1.5 to 3% of the circulating rate.
If a large natural body of water is nearby, it can be used as a source of cooling water and discharged downstream. This water is usually filtered to remove salts and impurities that may lead to fouling, but it is not treated.

==Refrigeration==
Cooling water can usually be used to cool a stream to ~ 100 ⁰F. Air can only cool to ~ 120 ⁰F. Air may be used in places where water is scarce or more costly to transport. To cool or condense streams below 100 ⁰F, a refrigerant is typically used. Chilled brine can also be used, but is less common.

Until 1995, CFC Freon R-12 (dichlorodifuloromethane) and HCFC Freon R-22 (chlorodifuloromethane) were commonly used refrigerants. However, the chlorine atom in the molecules caused the depletion of the ozone layer. The U.S. Clean Air Act Amendments of 1990 went into effect in 1995, and the production of these refrigerants has since stopped or been greatly reduced.

Cost estimates are based on ton-day of refrigeration, where a ton is the heat that needs to be removed to freeze 1 ton per day of water at 32 ⁰F. Substitutes have since been developed. R-134a is often used in place of R-12. According to the EPA, R-134a is not combustible at ambient conditions, and is essentially non-toxic under 400 ppm, and is not ozone-depleting. (Seider pg 607)

=Energy Efficiency=
One of the chief concerns in selecting and designing process utility systems for heating and cooling is how to achieve the most energy efficient design. There are countless means by which plants lose energy, two of the foremost being through the mixing of different temperature or pressure streams and through the disposal of warmed cooling water. (Seider, 2009) Proper utilities design can help mitigate each of these losses as well as many others. The energy efficiency of a plant will depend primarily on the heating and cooling methods that are being used and the overall system design itself. These two parameters are important in determining how well energy is transferred to the desired media as well as how well that energy is recovered and recycled.

==Utility Efficiency==
As mentioned above, the most commonly used utilities for process heating in large scale processes are steam, fired heat, and hot oil heaters. Of these, steam is the most commonly used. Electricity, while efficient at creating power, is not a viable source of heat in large industrial processes. Common ranges of heating efficiency for these three methods are displayed in Table 1. (Towler and Sinnott, 2012)

{| class="wikitable"
|+Table 1: Process Heating Efficiencies
|-
! Process Heating Method
! Typical Efficiency
|-
| Steam (via package boiler)
| 80-90%
|-
| Fired Heat w/ Convective Section
| 85%
|-
| Fired Heat w/o Convective Section
| 60%
|-
| Hot Oil Heaters/Vaporizers
| 80-85%
|}

Efficiency in cooling processes depends more on the method used, and by extension the amount of coolant needed. Water and air utility efficiencies depend primarily on the fluid flow required to maintain the system at a desired temperature, while powered refrigeration utilities (for colder processes) have efficiencies at approximately 60%--but ranging up to 90%--of Carnot cycle efficiency, a metric of ideal refrigeration efficiency. (Towler and Sinnott, 2012) Cooling systems represent by definition a loss of energy from the main process to the utility stream, and as such it is often useful to find other uses for the heated media before discharge.

==Energy Recovery==
Recovery and recycle of energy is perhaps the most important aspect of creating an energy efficient plant design, and it is important for process engineers to fully consider possibilities for heat recovery in order to aid in economic viability.

===Process Heat Exchange===
Heat exchanger networks are a very common energy recovery method in industrial processes. These networks most frequently allow energy from heated product streams to be transferred to feed streams that must be brought up to process temperature. (Biegler, 1997) For more on the function and design of heat exchanger networks, see [[Heat_exchanger#Heat_Exchanger_Networks|Heat Exchanger Networks]]. The following are several examples of energy recovery via heat exchange that are used in industrial processes.

In distillation columns the bottoms and distillate effluents have the potential for energy exchange. Though the condenser at the top of the column cannot supply its waste heat to the reboiler due to their respective temperatures, the effluent streams can supply heat to the feed via a feed-effluent exchanger. This reduces the utility requirements to raise the feed to column temperature. (Biegler, 1997)

[[File:Feed_sterilization.jpg|thumb|border|right|middle|upright=4|link=|atl=|Feed sterilization schematic. (Towler and Sinnott Fig. 3.30)]]

Feed sterilization, commonly used in the food industry, is a common application for heat recovery through process stream heat exchange. In this application, the feed must be heated for a certain amount of time to kill any biological contaminants, after which it can be used to heat the new raw feed for sterilization. This reduces energy demands on the steam heater and thus reduces cost. (Towler and Sinnott, 2012)

In multi-vessel batch processes it can be advantageous to exchange heat as the process fluid is being transferred between vessels. Like the previous examples, this reduces the utility needed to bring the colder feed up to process temperature, thus reducing costs. (Towler and Sinnott, 2012)

[[File:Batch_heat_exchange.jpg|thumb|border|center|middle|upright=4|link=|atl=|Multi-vessel batch heat exchange schematic (Towler and Sinnott Fig. 3.31)]]

===Utility Regeneration===
[[File:Waste_heat_boiler.jpg|thumb|border|right|middle|upright=4|link=|atl=|Industrial modular HRSG]]
When recovery of waste heat via transfer to other process streams is inconvenient or impossible, energy efficiency can still be improved through the regeneration of utilities. This is commonly done through the regeneration of steam by either removing heat from exiting streams or from highly exothermic reactions. Waste heat in exiting streams is removed via heat recovery steam generators (HRSGs), and is most often used on exiting flue gas and exiting process gas streams. Heat recovery from reactions is a viable option when the reactor temperature will be at 150 C or above, as this will create steam at high enough pressure to be used in other processes. (Towler and Sinnott, 2012)

Furthermore, there is opportunity for energy recovery in the expansion of compressed gas through a turbine to create electricity, a process that can be economically viable given sufficiently high flows or pressure. Such technology has been used in processes to synthesize ammonia, perform air separations, and synthesize nitric acid. (Towler and Sinnott, 2012) Recently, however, there has been a particularly strong interest for energy recovery in the natural gas industry, when gas is decompressed from major pipelines to residential low-pressure piplines. A 2001 study estimated that there is the potential to recover 21 TWh, representing 11% of natural gas transport energy, via gas expansion. (Lehman)

=Process water and boiler-feed water=
Process water is water that will be directly used in the process. Boiler-feed water (BFW) is used to produce steam. Both may need to be purified to prevent impurities from contaminating a process or from foul equipment. It can be used as a cooling stream when the temperature of the stream to be cooled is greater than ~300 ⁰F. Cost of BFW can be partially offset by the steam credit.

Process water that undergoes moderate pretreatment can cost ~ $0.75/1,000 gal.

Extensive treatment ~ $6.00/1,000 gal.

Sterilized for pharmaceutical processes ~ $550/1,000 gal. (Seider pg 608)

=Demineralized Water=
In demineralized water, minerals have been removed by ion exchange. In boiler feed water, this is to prevent salt deposition, corrosion, formation of foam, and sluicing. In process water, the ions may contaminate the process.

=Waste Treatment=
Most chemical processes will produce some sort of waste. Disposal occurs to the atmosphere (in the case of some gases), sewers, body of water, or a landfill. Waste may require some treatment before disposal to meet regulations. Depending on process economics, byproducts may be recovered and processed. (Seider 2009 pg 609)

==Wastewater Treatment==
The United States EPA regulates industrial wastewater disposal through the Clean Water Act, introduced in 1948 as the Federal Water Pollution Control Act and amended to its current form in 1972. The sweeping 1972 amendments allowed the EPA to prevent industries and persons from discharging contaminated water into fresh water sources and set water quality standards. (Summary of the Clean Water Act) In accordance with this law, process plants in the United States treat wastewater at on-site or near-site treatment centers before releasing it into the surrounding environment.

Wastewater effluent streams, along with water runoff from around the plant, are treated to control for pH, toxicity, suspended solids, and biological oxygen demand (for aquatic life protection) prior to discharge. Each of these controls is typically addressed with a separate method. Acidity and basicity is balanced through the addition of an acid or alkaline solution. Toxic wastewater may be treated with chemical processes or simply diluted to safe concentrations. Suspended solids can be removed via filtration and/or with clarifiers. Oxygen demand of wastewater can be mitigated using activated sludge treatment processes. Once the water quality complies with the EPA, and state-mandated, regulations, it can be safely released. More information on the large number of industry-specific guidelines for waste effluent can be found on the EPA website (http://www.epa.gov/eg/industrial-effluent-guidelines).

==Air-Pollution Management==
===Introduction===

In the United States air pollution is regulated in the Clean Air Act, and almost all pollutant emitting plants are regulated under this law. The types of plants that can release significant emissions include petroleum refineries, sulfur recovery plants, carbon-black plants, fuel conversion plants, chemical process plants, fossil fuel plants, and petroleum storage and transfer facilities. To receive permission to construct a plant must undergo a review to show that it will not cause a violation of the Ambient Air Quality Standards(Peters, 2003).

===Methods===

There are two major types of pollutants that are released into the air, particulates and and gaseous pollutants. Particulates can be removed with mechanical forces while gaseous pollutants typically need to removed by chemical or physical means (Peters, 2003).

Particulates and volatile pollutants that need to be removed before disposal may be present. Particle removal equipment includes: cyclones, wet scrubbers, electrostatic precipitators, and fabric-filter systems (Seider 2009) such as bag filters (. The two charts below are from ''Plant Design and Economics for Chemical Engineers'' and show the types of equipment, separation methods, and particle sizes in different pollutant separation technologies (Peters, 1991).

[[File:AirPolChart.png|thumb|border|center|middle|upright=4|link=|atl=|A Chart Showing Different Technologies Used to Remove Particulates]]

[[File:AirPolTable.png|thumb|border|center|middle|upright=4|link=|atl=| This Chart Shows the Specifications and Limitations of Different Separations Technologies(Peters, 1991)]]

For more information regarding some of these separations eqipment see [[Solids-involved equipment]]

For more information Regarding Cyclones see [[Separation processes#Cyclones| Cyclones]]

Methods for removing inorganic and organic gaseous pollutants include: absorption, adsorption, condensation, and combustion (Seider 2009 pg 609). A list of typical of gases pollutants and their sources from ''Plant Design and Economics for Chemical Engineers'' is shown below (Peters, 1991).

[[File:GaseousPollutants.png|thumb|border|center|middle|upright=4|link=|atl=|]]

Typically Gas-liquid absorption processes are done completed in a vertical, countercurrent, flow through packed, plate, or spray towers. These systems require good liquid-gas contact and proper equipment. These systems also often have significant energy consumption because of large pressure drops (Peters, 2003). For high volume systems absorption by scrubbing with water or another solvent is the most widely used method (Towler, 2012). Dry adsorbents can be used to remove the last races of gaseous pollutants. Adsorption typically requires blowers, condensers, separators, and controls. You also typically need two packed beds so that one can be used while the other is regenerated. Examples of adsorbents are molecular sieves and activated carbon. Incineration is typically used when there are gas streams that have no recovery value. This can be done with direct flame or catalytic oxidation. Catalytic oxidation usually has higher capital costs, but lower operating costs because it does not require fuel.

You can find more information on [[Separation processes#Absorption| Absorption]] and [[Separation processes#Adsorption| Adsorption]] in [[Separation processes]]

===Outcomes===

The United States implemented the Clean Air Act in 1970 and since then emissions in the U.S. have been drastically reduced. As a matter of fact despite increases in the population in the last 35 years the amount of pollutants emitted have decreased by almost 70% (EPA). More importantly this demonstrates that reasonable efforts can be put towards environmental protection without causing too much harm to industry.

[[File:EPA.png|thumb|border|center|middle|upright=4|link=|atl=| GDP and Other Growth Factors Vs Common Pollutants Released]]

==Solid Waste==
U.S. federal regulations require that solid waste be classified as hazardous or nonhazardous. Conditions for a classification of hazardous include: ignitability, corrosivity, reactivity, toxicity, or posing a substantial threat to the surrounding environment and its inhabitants. Hazardous waste must be treated on- or near-site before being removed in containers. Non-hazardous waste may be landfilled or incinerated in some cases. A typical estimate of costs for waste disposal is $0.03/lb for nonhazardous solids and $0.10/lb for hazardous solids. (Seider 2009 pg 609)

=References=

*Biegler LT, Grossmann IE, Westerberg AW. ''Systematic Methods of Chemical Process Design'' Prentice-Hall: Upper Saddle River, 1997.

*Duke Energy Company (2013). How Do Coal Fired Plants Work? Charlotte: Duke Energy.

*Lehman B, Worrell E. ''Electricity Production from Natural Gas Pressure Recovery Using Expansion Turbines.'' Lawrence Berkeley National Laboratory; 2001.

*"Overview of the Clean Air Act and Air Pollution." Environmental Protection Agency. November 17, 2015. http://www.epa.gov/clean-air-act-overview. Accessed February 5, 2016.

*Peters, Max S.; Timmerhaus, Klaus D.; West, Ronald E. (2003). "Plant Design and Economics for Chemical Engineers." McGraw Hill Higher Education.

*Seider, Seader, Lewin, Widagdo. (2009). ''Plant Design and Economics for Chemical Engineers, 5th Edition.'' Hoboken: Wiley.

*Seider, Seader, Lewin. (2008). ''Product and Process Design Principles, 2nd Edition.'' Hoboken: Wiley.

*Summary of the Clean Water Act. United States EPA website. http://www.epa.gov/laws-regulations/summary-clean-water-act

*Towler, G.P. and Sinnot, R. (2012). ''Chemical Engineering Design: Principles, Practice and Economics of Plant and Process Design.'' Elsevier.

*Turton R.; Bailie, R.C.; Whiting, W.B.; Shaeiwitz J.A.; Bhattacharyya D. (2012). ''Analysis, Synthesis, and Design of Chemical Processes.'' Upper Saddle River: Prentice Hall.

*G.D. Ulrich, A Guide to Chemical Engineering Process Design and Economics, Wiley: New York, 1984.

Utility systems

2016-02-05T20:53:28Z

Taunins: /* Utility Regeneration */

Authors: David Chen, [2014] Joshua Lee, [2015] Brett Sleyster, [2016] and Tom Aunins [2016] 

Stewards: David Chen, Jian Gong, and Fengqi You

Date Presented: January 13, 2014 /Date Revised: January 14, 2014

 


__TOC__

=Introduction=
Many chemical processes do not take place at ambient temperature or pressures. In order to reach these non-ambient conditions, utilities will have to be used to raise or lower temperatures and compress gases. (Towler, Towler/UOP) Utilities often contribute 5 to 10% of the price of a product, and may come from public or private utility companies or on-site plants. For purchased utilities, costs depend on consumption, while for company-owned utilities, there will be both capital and operating costs. They include things such as steam for heating, electricity, cooling water, refrigeration, fuels such as natural gas, wastewater treatment, waste disposal, and landfill. Steam is often the largest utility cost. Cogeneration unit can supply electricity accompanied with different steam pressures. (Seider 2009)

=Electricity=

Electricity is used to power many different kinds of equipment. It has many advantages: it is efficient (> 90%), reliable, available in a wide range of power, shaft speeds, designs, lifetimes, convenience, costs, and maintenance. It is generally used up to 200 hp, and sometimes over 10,000 Hp. In chemical process plants, the electricity demand is generally determined by the work or energy required for compression, pumping, air cooling, lights, and many other items. This electricity often times is purchased from local electricity providers, but many plants generate their own electricity via sophisticated processes.

Electricity is rarely used as a primary heat utility in large-scale chemical plants for a variety of reasons. The main disadvantages of using electricity as a heat utility are as follows (Towler 2012):

:*Heat from electricity is two to three times more expensive than heat from fuels. This is attributed to the lack of efficiency when creating heat from electricity.

:*Electrical heating units are expensive, require high maintenance, and must comply with strict safety regulations.

:*Electrical heating units are unsafe compared to steam heating units. In steam systems, the physically steam controls the temperature, whereas in electrical heating units temperature is controlled by temperature controllers, which can fail or burn out.

The use of electricity carries with it some hazards depending on the environment. Extra care must be taken when using electrically-powered equipment in areas which may have combustible fluids, vapors, or dust, and where liquids may be present. (Seider 2009 pg 606)

==Conventional Power Station==

In general, most electricity is generated from a conventional coal-fired process, whether it be on-site or purchased from a provider. Coal-fired processes have been used to create electricity throughout history, and technological advances have increased its efficiency and use worldwide. In a coal-fired steam station—much like a nuclear station—water is turned into steam, which in turn drives turbine generators to produce electricity. There are several variations on how to create energy from coal, but here are the basics of how a coal-fired process works:

[[File:coalfired.png|thumb|border|center|middle|upright=4|link=|atl=|General Coal-Fired Process Diagram (Duke Energy Company)]]

*Heat is created:
::Before the coal is burned, it is pulverized to the fineness of talcum powder. It is then mixed with hot air and blown into the firebox of the boiler. Burning in suspension, the coal/air mixture provides the most complete combustion and maximum heat possible.

*Water turns to steam:
::Highly purified water, pumped through pipes inside the boiler, is turned into steam by the heat. The steam reaches temperatures of up to 1,000 degrees Fahrenheit and pressures up to 3,500 pounds per square inch, and is piped to the turbine.

*Steam turns the turbine:
::The enormous pressure of the steam pushing against a series of giant turbine blades turns the turbine shaft. The turbine shaft is connected to the shaft of the generator, where magnets spin within wire coils to produce electricity.

*Steam is converted back to water:
::After doing its work in the turbine, the steam is drawn into a condenser, a large chamber in the basement of the power plant. In this important step, millions of gallons of cool water from a nearby source (such as a river or lake) are pumped through a network of tubes running through the condenser. The cool water in the tubes converts the steam back into water that can be used over and over again in the plant.

*Repeat:
::The cooling water is returned to its source without any contamination, and the steam water is returned to the boiler to repeat the cycle.

===Advantages & Disadvantages of Coal-Fired Energy Production===

[[File:coalfiredtable.png|thumb|border|center|middle|upright=4|link=|atl=|Advantages and Disadvantages of Coal-Fired Processes (Seider 2008)]]

==Gas-Turbine Cogeneration Process==

When generating energy on-site, many plants use a gas-turbine cogeneration process. The thermal efficiency of a gas-turbine process is in the range of 70-80% while conventional power stations, such as coal-fired processes, have a 30-40% efficiency. The lower efficiency in more conventional power stations is attributed to wasted heat in the exhaust steam in the condenser. One example of a gas-turbine process is outlined in the following figure. Figure 3.1 is a gas-turbine cogeneration process with a heat recovery steam generator (waste-heat) boiler.

[[File:cogeneration.png|thumb|border|center|middle|upright=4|link=|atl=|Gas-Turbine Cogeneration with a heat recovery steam generator boiler (Towler 2012 Fig 3.1)]]

Overall, the process illustrated is not much different from a coal-fired process. The main differences are that the cogeneration process creates both electricity and a heat utility, and cogeneration processes use natural gas instead of coal. Many of the advantages and disadvantages are similar to those of the coal-fired process, but the cogeneration has a much higher efficiency, creates heat to be used in another process, and uses a more volatile and expensive fuel. The main advantage of cogeneration over coal-fired energy production is that heat is not wasted. In coal-fired processes, heat is released and wasted during electricity generation. Cogeneration captures some, if not all of the byproduct for heat, which is an extremely useful utility that will be discussed in subsequent sections. In summary, the cogeneration plant is superior to the coal-fired process because of its higher efficiency and ability to create a useful heat utility.

Obviously any engineer would design the cogeneration plant to meet at least the energy requirement necessary for plant operation, but cogeneration plants often times are designed to exceed the plant electricity requirement to drive another source of capital. Many describe this scenario as a "make or buy" scenario (Towler 2012). This scenario provides chemical producers leverage when negotiating contracts with outsourced electricity providers and this allows plants to purchase electricity at a wholesale price. This is a huge advantage of considering on-site electricity production because electricity is needed in relatively high quantities for all chemical plants. Being able to minimize electricity costs, or even profit off of electricity production is a huge economical consideration that all plants employ.

=Process Heating=
The key objective of this section is to discuss how processes are heated. Heating utilities are necessary for proper usage of distillers, reactors, condensers, and several other integral types of equipment. More specifically, steam, fired heat, and hot oil/specialized heat transfer fluids will be discussed in the following subsections.

==Steam==
Steam is the most commonly used heat utility used in chemical plants, and as a result understanding how it is used is essential in the study of Utility systems. Steam is used both as a process fluid (feedstock, diluent to absorb heat of reaction, heating agent, and stripping agent in absorbers and adsorbers ) and utility. It can be used to drive pumps and compressors, ejectors (for producing a vacuum), and heat exchangers. As one can clearly see, steam is a versatile, and useful utility.

Here are a few advantages of using steam as opposed to other methods of process heating (Towler 2012):

:*By controlling the pressure of the steam, one can control the temperature at which the heat is released. Having a strong control over the temperature is essential in several processes. =
:*Steam is an efficient heat source because the heat of condensation of steam is very high. Meaning that there is is high output per mass of utility at a constant temperature.
:*Heat exchangers that use steam are relatively cheap because condensing steam has a high heat transfer coefficient.
:*Steam is nonflammable, nontoxic, and inert to several process fluids.

Chemical plants generally have a network of pipelines exclusively for providing steam. These networks generally have steam at a low pressure, a medium pressure, and a high pressure. The image below illustrates a basic steam system.

[[File:Steam.png|thumb|border|center|middle|upright=4|link=|atl=|(Towler 2012 Fig 3.2)]]

In the diagram above, boiler feed water at a high pressure is preheated and fed to other boilers. These other boilers superheat the steam to create a high pressure and high temperature steam stream. The steam is superheated past the dew point to account for heat loss in the pipelines. A portion of the high pressure steam is used for process heating in areas of the plant that require high temperatures. The rest of the high pressure steam is turned into medium pressure steam by valves and steam turbines. The medium pressure steam is then used to heat medium temperature processes and to form low pressure steam. The low pressure steam can be used to heat low pressure processes and it can be expanded in condensing turbines to create shaft work and energy. In summary, steam can be used for an innumerable amount of action items in a plant. High pressure, medium pressure, and low pressure steam can all be used as a heat source. Low pressure steam has utilities in creating electricity and it also has several other uses.

==Fired Heat==

In many cases, processes in a plant require a heat source stronger than high pressure and temperature steam. That is when fired heat is used, which is generally at temperatures above 523K. Streams can be heated directly in the furnace tubes or via a hot oil circuit or heat transfer fluid, which will be discussed in detail in the next section. Most fired heaters use natural gas as fuel because it burns cleaner than fuel oil. A cleaner burning fuel is always advantageous due to environmental and safety concerns. Furthermore, natural gases usually result in less wear and tear in burners and fuel lines.

Depending on the application of the fired-heater, different design specifications can be implemented to make the fired-heater as efficient as possible. The basic construction of a fired heater starts with a cylindrical chamber that is lined with with refractory bricks. The stream that is to be heated flows through tubes inside of the furnace. These tubes can be arranged in several different arrangements such as, around the walls of the furnace, or in horizontal or vertical banks (Towler 2012). The figure below illustrates the basic construction of the fired-heater and varying tube arrangements.

[[File:firedheater.png|thumb|border|center|middle|upright=4|link=|atl=|Basic Fired-Heater Diagrams (Towler 2012 Figure 19.66)]]

Fuel is burned to heat the entire furnace, and the heat transfer occurs from the combustion gases inside of the furnace across the tubes that are filled with our desired stream. The heat transfer between the tubes and the furnace is accomplished primarily via radiation. Modern designs take advantage of convective heat transfer by adding a smaller section on top of the fired-heater where the combustion gases flow over banks of tubes as seen in (c) in the figure above. Heat transfer can be further improved via convection by adding fins or pins in the combustion section.

The cost of fired heat can be calculated by the cost of fuel fired. Natural gas and heating oil are traded as commodities and prices can be found at many online trading sites or business news sites (i.e., www.cnn.money.com). Past historic prices for forecasting can be found in the Oil and Gas Journal or from the U.S. Energy Information Adminstration (www.eia.gov).

===Fuels===
Fuel is burned in utility facilities such as boilers, electricity generation, and cogeneration, and can be in solid, liquid, or gas form. It can also be burned to provide heating for a process or stream or to drive pumps and compressors. The fuel is usually burned with excess air to ensure complete combustion.

A way of quantifying the amount of heat generated is by using the heating values. Higher heating value (HHV) and the lower heating value (LHV) are used. The heating is the total heat evolved by complete combustion of a fuel with dry air with both at 60 ⁰F and the flue gas after combustion brought back down to ⁰F. If the water vapor in the flue gas is not condensed, we obtain the LHV. If the water vapor is condensed, the value of heat evolved is a bit higher, and this is the HHV.
Heating values for solids and liquids are usually on a per-mass basis, and gases on a per-volume basis.
A specified amount of heating cannot be met with the amount of fuel calculated using only the HHV. There will be heat losses, the flue gas temperature will be greater than 60 ⁰F, and water in the flue gas will typically be vapor. (Seider 608)

==Hot Oil/Specialized Heat Transfer Fluids==

Specialized heat transfer fluids and hot oil circuits are used as heat sources when steam and fired heat is not appropriate. Specialized heat transfer fluids and hot oil circuits are extremely versatile in that they can be used in the temperature range of 323K to 673K. This range however is quite variable. For hot oils, the upper temperature limit is gauged based off of the thermal decomposition of the oil and coking/fouling of heat exchanger tubes.

Hot oil circuit systems are most commonly used when the plant has several small temperature heating requirements because it is more economically sound. Rather than having several fired heaters heat each small temperature requirement, it is much more economical to have one fired heater heat the hot oil and circulate that oil through each of the process to meet all of the heat needs. Hot oil systems are also generally favored over high pressure steam in processes that involve high pressure differentials between the process stream and high pressure steam. Hot oil systems are favored in this scenario because of safety concerns. If the steam were to leak, the pressure drop could cause serious safety issues.

Mineral oils are the most commonly used heat transfer fluids, and one prominent example is Dowtherm A. Dowtherm A is a combination of 26.5 wt% diphenyl in diphenyl oxide (Towler 2012) and is extremely thermally stable. These mineral oil systems generally require high flow rates.

=Process Cooling=

==Cooling Water==
Cooling water is used to cool and/or condense streams. Cooling water is usually circulated between process heat exchangers and a cooling tower. Water is cooled during downward motion by contact with air blown upwards, which can bring the water temperature to come within ~ 5 ⁰F of air’s wet-bulb temperature.Approximately 80% of the temperature reduction is due to evaporation of the cooling water and heat transfer to the surrounding air. Water can also be cooled in spray ponds and cooling ponds. Both work by providing high area for water to exchange heat with air.
Water in cooling towers is lost through drift and blowdown, and makeup is usually 1.5 to 3% of the circulating rate.
If a large natural body of water is nearby, it can be used as a source of cooling water and discharged downstream. This water is usually filtered to remove salts and impurities that may lead to fouling, but it is not treated.

==Refrigeration==
Cooling water can usually be used to cool a stream to ~ 100 ⁰F. Air can only cool to ~ 120 ⁰F. Air may be used in places where water is scarce or more costly to transport. To cool or condense streams below 100 ⁰F, a refrigerant is typically used. Chilled brine can also be used, but is less common.

Until 1995, CFC Freon R-12 (dichlorodifuloromethane) and HCFC Freon R-22 (chlorodifuloromethane) were commonly used refrigerants. However, the chlorine atom in the molecules caused the depletion of the ozone layer. The U.S. Clean Air Act Amendments of 1990 went into effect in 1995, and the production of these refrigerants has since stopped or been greatly reduced.

Cost estimates are based on ton-day of refrigeration, where a ton is the heat that needs to be removed to freeze 1 ton per day of water at 32 ⁰F. Substitutes have since been developed. R-134a is often used in place of R-12. According to the EPA, R-134a is not combustible at ambient conditions, and is essentially non-toxic under 400 ppm, and is not ozone-depleting. (Seider pg 607)

=Energy Efficiency=
One of the chief concerns in selecting and designing process utility systems for heating and cooling is how to achieve the most energy efficient design. There are countless means by which plants lose energy, two of the foremost being through the mixing of different temperature or pressure streams and through the disposal of warmed cooling water. (Seider, 2009) Proper utilities design can help mitigate each of these losses as well as many others. The energy efficiency of a plant will depend primarily on the heating and cooling methods that are being used and the overall system design itself. These two parameters are important in determining how well energy is transferred to the desired media as well as how well that energy is recovered and recycled.

==Utility Efficiency==
As mentioned above, the most commonly used utilities for process heating in large scale processes are steam, fired heat, and hot oil heaters. Of these, steam is the most commonly used. Electricity, while efficient at creating power, is not a viable source of heat in large industrial processes. Common ranges of heating efficiency for these three methods are displayed in Table 1. (Towler and Sinnott, 2012)

{| class="wikitable"
|+Table 1: Process Heating Efficiencies
|-
! Process Heating Method
! Typical Efficiency
|-
| Steam (via package boiler)
| 80-90%
|-
| Fired Heat w/ Convective Section
| 85%
|-
| Fired Heat w/o Convective Section
| 60%
|-
| Hot Oil Heaters/Vaporizers
| 80-85%
|}

Efficiency in cooling processes depends more on the method used, and by extension the amount of coolant needed. Water and air utility efficiencies depend primarily on the fluid flow required to maintain the system at a desired temperature, while powered refrigeration utilities (for colder processes) have efficiencies at approximately 60%--but ranging up to 90%--of Carnot cycle efficiency, a metric of ideal refrigeration efficiency. (Towler and Sinnott, 2012) Cooling systems represent by definition a loss of energy from the main process to the utility stream, and as such it is often useful to find other uses for the heated media before discharge.

==Energy Recovery==
Recovery and recycle of energy is perhaps the most important aspect of creating an energy efficient plant design, and it is important for process engineers to fully consider possibilities for heat recovery in order to aid in economic viability.

===Process Heat Exchange===
Heat exchanger networks are a very common energy recovery method in industrial processes. These networks most frequently allow energy from heated product streams to be transferred to feed streams that must be brought up to process temperature. (Biegler, 1997) For more on the function and design of heat exchanger networks, see [LINK TO HEN PAGE]. The following are several examples of energy recovery via heat exchange that are used in industrial processes.

In distillation columns the bottoms and distillate effluents have the potential for energy exchange. Though the condenser at the top of the column cannot supply its waste heat to the reboiler due to their respective temperatures, the effluent streams can supply heat to the feed via a feed-effluent exchanger. This reduces the utility requirements to raise the feed to column temperature. (Biegler, 1997)

[[File:Feed_sterilization.jpg|thumb|border|right|middle|upright=4|link=|atl=|Feed sterilization schematic. (Towler and Sinnott Fig. 3.30)]]

Feed sterilization, commonly used in the food industry, is a common application for heat recovery through process stream heat exchange. In this application, the feed must be heated for a certain amount of time to kill any biological contaminants, after which it can be used to heat the new raw feed for sterilization. This reduces energy demands on the steam heater and thus reduces cost. (Towler and Sinnott, 2012)

In multi-vessel batch processes it can be advantageous to exchange heat as the process fluid is being transferred between vessels. Like the previous examples, this reduces the utility needed to bring the colder feed up to process temperature, thus reducing costs. (Towler and Sinnott, 2012)

[[File:Batch_heat_exchange.jpg|thumb|border|center|middle|upright=4|link=|atl=|Multi-vessel batch heat exchange schematic (Towler and Sinnott Fig. 3.31)]]

===Utility Regeneration===
[[File:Waste_heat_boiler.jpg|thumb|border|right|middle|upright=4|link=|atl=|Industrial modular HRSG]]
When recovery of waste heat via transfer to other process streams is inconvenient or impossible, energy efficiency can still be improved through the regeneration of utilities. This is commonly done through the regeneration of steam by either removing heat from exiting streams or from highly exothermic reactions. Waste heat in exiting streams is removed via heat recovery steam generators (HRSGs), and is most often used on exiting flue gas and exiting process gas streams. Heat recovery from reactions is a viable option when the reactor temperature will be at 150 C or above, as this will create steam at high enough pressure to be used in other processes. (Towler and Sinnott, 2012)

Furthermore, there is opportunity for energy recovery in the expansion of compressed gas through a turbine to create electricity, a process that can be economically viable given sufficiently high flows or pressure. Such technology has been used in processes to synthesize ammonia, perform air separations, and synthesize nitric acid. (Towler and Sinnott, 2012) Recently, however, there has been a particularly strong interest for energy recovery in the natural gas industry, when gas is decompressed from major pipelines to residential low-pressure piplines. A 2001 study estimated that there is the potential to recover 21 TWh, representing 11% of natural gas transport energy, via gas expansion. (Lehman)

=Process water and boiler-feed water=
Process water is water that will be directly used in the process. Boiler-feed water (BFW) is used to produce steam. Both may need to be purified to prevent impurities from contaminating a process or from foul equipment. It can be used as a cooling stream when the temperature of the stream to be cooled is greater than ~300 ⁰F. Cost of BFW can be partially offset by the steam credit.

Process water that undergoes moderate pretreatment can cost ~ $0.75/1,000 gal.

Extensive treatment ~ $6.00/1,000 gal.

Sterilized for pharmaceutical processes ~ $550/1,000 gal. (Seider pg 608)

=Demineralized Water=
In demineralized water, minerals have been removed by ion exchange. In boiler feed water, this is to prevent salt deposition, corrosion, formation of foam, and sluicing. In process water, the ions may contaminate the process.

=Waste Treatment=
Most chemical processes will produce some sort of waste. Disposal occurs to the atmosphere (in the case of some gases), sewers, body of water, or a landfill. Waste may require some treatment before disposal to meet regulations. Depending on process economics, byproducts may be recovered and processed. (Seider 2009 pg 609)

==Wastewater Treatment==
The United States EPA regulates industrial wastewater disposal through the Clean Water Act, introduced in 1948 as the Federal Water Pollution Control Act and amended to its current form in 1972. The sweeping 1972 amendments allowed the EPA to prevent industries and persons from discharging contaminated water into fresh water sources and set water quality standards. (Summary of the Clean Water Act) In accordance with this law, process plants in the United States treat wastewater at on-site or near-site treatment centers before releasing it into the surrounding environment.

Wastewater effluent streams, along with water runoff from around the plant, are treated to control for pH, toxicity, suspended solids, and biological oxygen demand (for aquatic life protection) prior to discharge. Each of these controls is typically addressed with a separate method. Acidity and basicity is balanced through the addition of an acid or alkaline solution. Toxic wastewater may be treated with chemical processes or simply diluted to safe concentrations. Suspended solids can be removed via filtration and/or with clarifiers. Oxygen demand of wastewater can be mitigated using activated sludge treatment processes. Once the water quality complies with the EPA, and state-mandated, regulations, it can be safely released. More information on the large number of industry-specific guidelines for waste effluent can be found on the EPA website (http://www.epa.gov/eg/industrial-effluent-guidelines).

==Air-Pollution Management==
'''Introduction'''
In the United States air pollution is regulated in the Clean Air Act, and almost all pollutant emitting plants are regulated under this law. The types of plants that can release significant emissions include petroleum refineries, sulfur recovery plants, carbon-black plants, fuel conversion plants, chemical process plants, fossil fuel plants, and petroleum storage and transfer facilities. To receive permission to construct a plant must undergo a review to show that it will not cause a violation of the Ambient Air Quality Standards(Peters, 2003).

'''Methods'''
There are two major types of pollutants that are released into the air, particulates and and gaseous pollutants. Particulates can be removed with mechanical forces while gaseous pollutants typically need to removed by chemical or physical means (Peters, 2003).

Particulates and volatile pollutants that need to be removed before disposal may be present. Particle removal equipment includes: cyclones, wet scrubbers, electrostatic precipitators, and fabric-filter systems.(Seider 2009 pg 609). The two charts below are from ''Plant Design and Economics for Chemical Engineers'' and show the types of equipment, separation methods, and particle sizes in different pollutant separation technologies (Peters, 1991).

[[File:AirPolChart.png|thumb|border|center|middle|upright=4|link=|atl=|]]

[[File:AirPolTable.png|thumb|border|center|middle|upright=4|link=|atl=|]]

Methods for removing inorganic and organic gaseous pollutants include: absorption, adsorption, condensation, and combustion (Seider 2009 pg 609). A typical of gases and their sources from ''Plant Design and Economics for Chemical Engineers'' is shown below (Peters, 1991).

[[File:GaseousPollutants.png|thumb|border|center|middle|upright=4|link=|atl=|]]

Typically Gas-liquid absorption processes are done completed in a vertical, countercurrent, flow through packed, plate, or spray towers. These systems require good liquid-gas contact and proper equipment. These systems also often have significant energy consumption because of large pressure drops (Peters, 2003). Dry adsorbents can be used to remove the last races of gaseous pollutants. Adsorption typically requires blowers, condensers, separators, and controls. You also typically need two packed beds so that one can be used while the other is regenerated. Examples of adsorbents are molecular sieves and activated carbon. Incineration is typically used when there are gas streams that have no recovery value. This can be done with direct flame or catalytic oxidation. Catalytic oxidation usually has higher capital costs, but lower operating costs because it does not require fuel.

'''Outcome'''
The United States implemented the Clean Air Act in 1970 and since then emissions in the U.S. have been drastically reduced.

==Solid Waste==
U.S. federal regulations require that solid waste be classified as hazardous or nonhazardous. Conditions for a classification of hazardous include: ignitability, corrosivity, reactivity, toxicity, or posing a substantial threat to the surrounding environment and its inhabitants. Hazardous waste must be treated on- or near-site before being removed in containers. Non-hazardous waste may be landfilled or incinerated in some cases. A typical estimate of costs for waste disposal is $0.03/lb for nonhazardous solids and $0.10/lb for hazardous solids. (Seider 2009 pg 609)

=References=

*Biegler LT, Grossmann IE, Westerberg AW. ''Systematic Methods of Chemical Process Design'' Prentice-Hall: Upper Saddle River, 1997.

*Duke Energy Company (2013). How Do Coal Fired Plants Work? Charlotte: Duke Energy.

*Lehman B, Worrell E. ''Electricity Production from Natural Gas Pressure Recovery Using Expansion Turbines.'' Lawrence Berkeley National Laboratory; 2001.

*Seider, Seader, Lewin, Widagdo. (2009). ''Plant Design and Economics for Chemical Engineers, 5th Edition.'' Hoboken: Wiley.

*Seider, Seader, Lewin. (2008). ''Product and Process Design Principles, 2nd Edition.'' Hoboken: Wiley.

*Summary of the Clean Water Act. United States EPA website. http://www.epa.gov/laws-regulations/summary-clean-water-act

*Towler, G.P. and Sinnot, R. (2012). ''Chemical Engineering Design: Principles, Practice and Economics of Plant and Process Design.'' Elsevier.

*Turton R.; Bailie, R.C.; Whiting, W.B.; Shaeiwitz J.A.; Bhattacharyya D. (2012). ''Analysis, Synthesis, and Design of Chemical Processes.'' Upper Saddle River: Prentice Hall.

Utility systems

2016-02-05T20:52:06Z

Taunins: /* Process Heat Exchange */

Authors: David Chen, [2014] Joshua Lee, [2015] Brett Sleyster, [2016] and Tom Aunins [2016] 

Stewards: David Chen, Jian Gong, and Fengqi You

Date Presented: January 13, 2014 /Date Revised: January 14, 2014

 


__TOC__

=Introduction=
Many chemical processes do not take place at ambient temperature or pressures. In order to reach these non-ambient conditions, utilities will have to be used to raise or lower temperatures and compress gases. (Towler, Towler/UOP) Utilities often contribute 5 to 10% of the price of a product, and may come from public or private utility companies or on-site plants. For purchased utilities, costs depend on consumption, while for company-owned utilities, there will be both capital and operating costs. They include things such as steam for heating, electricity, cooling water, refrigeration, fuels such as natural gas, wastewater treatment, waste disposal, and landfill. Steam is often the largest utility cost. Cogeneration unit can supply electricity accompanied with different steam pressures. (Seider 2009)

=Electricity=

Electricity is used to power many different kinds of equipment. It has many advantages: it is efficient (> 90%), reliable, available in a wide range of power, shaft speeds, designs, lifetimes, convenience, costs, and maintenance. It is generally used up to 200 hp, and sometimes over 10,000 Hp. In chemical process plants, the electricity demand is generally determined by the work or energy required for compression, pumping, air cooling, lights, and many other items. This electricity often times is purchased from local electricity providers, but many plants generate their own electricity via sophisticated processes.

Electricity is rarely used as a primary heat utility in large-scale chemical plants for a variety of reasons. The main disadvantages of using electricity as a heat utility are as follows (Towler 2012):

:*Heat from electricity is two to three times more expensive than heat from fuels. This is attributed to the lack of efficiency when creating heat from electricity.

:*Electrical heating units are expensive, require high maintenance, and must comply with strict safety regulations.

:*Electrical heating units are unsafe compared to steam heating units. In steam systems, the physically steam controls the temperature, whereas in electrical heating units temperature is controlled by temperature controllers, which can fail or burn out.

The use of electricity carries with it some hazards depending on the environment. Extra care must be taken when using electrically-powered equipment in areas which may have combustible fluids, vapors, or dust, and where liquids may be present. (Seider 2009 pg 606)

==Conventional Power Station==

In general, most electricity is generated from a conventional coal-fired process, whether it be on-site or purchased from a provider. Coal-fired processes have been used to create electricity throughout history, and technological advances have increased its efficiency and use worldwide. In a coal-fired steam station—much like a nuclear station—water is turned into steam, which in turn drives turbine generators to produce electricity. There are several variations on how to create energy from coal, but here are the basics of how a coal-fired process works:

[[File:coalfired.png|thumb|border|center|middle|upright=4|link=|atl=|General Coal-Fired Process Diagram (Duke Energy Company)]]

*Heat is created:
::Before the coal is burned, it is pulverized to the fineness of talcum powder. It is then mixed with hot air and blown into the firebox of the boiler. Burning in suspension, the coal/air mixture provides the most complete combustion and maximum heat possible.

*Water turns to steam:
::Highly purified water, pumped through pipes inside the boiler, is turned into steam by the heat. The steam reaches temperatures of up to 1,000 degrees Fahrenheit and pressures up to 3,500 pounds per square inch, and is piped to the turbine.

*Steam turns the turbine:
::The enormous pressure of the steam pushing against a series of giant turbine blades turns the turbine shaft. The turbine shaft is connected to the shaft of the generator, where magnets spin within wire coils to produce electricity.

*Steam is converted back to water:
::After doing its work in the turbine, the steam is drawn into a condenser, a large chamber in the basement of the power plant. In this important step, millions of gallons of cool water from a nearby source (such as a river or lake) are pumped through a network of tubes running through the condenser. The cool water in the tubes converts the steam back into water that can be used over and over again in the plant.

*Repeat:
::The cooling water is returned to its source without any contamination, and the steam water is returned to the boiler to repeat the cycle.

===Advantages & Disadvantages of Coal-Fired Energy Production===

[[File:coalfiredtable.png|thumb|border|center|middle|upright=4|link=|atl=|Advantages and Disadvantages of Coal-Fired Processes (Seider 2008)]]

==Gas-Turbine Cogeneration Process==

When generating energy on-site, many plants use a gas-turbine cogeneration process. The thermal efficiency of a gas-turbine process is in the range of 70-80% while conventional power stations, such as coal-fired processes, have a 30-40% efficiency. The lower efficiency in more conventional power stations is attributed to wasted heat in the exhaust steam in the condenser. One example of a gas-turbine process is outlined in the following figure. Figure 3.1 is a gas-turbine cogeneration process with a heat recovery steam generator (waste-heat) boiler.

[[File:cogeneration.png|thumb|border|center|middle|upright=4|link=|atl=|Gas-Turbine Cogeneration with a heat recovery steam generator boiler (Towler 2012 Fig 3.1)]]

Overall, the process illustrated is not much different from a coal-fired process. The main differences are that the cogeneration process creates both electricity and a heat utility, and cogeneration processes use natural gas instead of coal. Many of the advantages and disadvantages are similar to those of the coal-fired process, but the cogeneration has a much higher efficiency, creates heat to be used in another process, and uses a more volatile and expensive fuel. The main advantage of cogeneration over coal-fired energy production is that heat is not wasted. In coal-fired processes, heat is released and wasted during electricity generation. Cogeneration captures some, if not all of the byproduct for heat, which is an extremely useful utility that will be discussed in subsequent sections. In summary, the cogeneration plant is superior to the coal-fired process because of its higher efficiency and ability to create a useful heat utility.

Obviously any engineer would design the cogeneration plant to meet at least the energy requirement necessary for plant operation, but cogeneration plants often times are designed to exceed the plant electricity requirement to drive another source of capital. Many describe this scenario as a "make or buy" scenario (Towler 2012). This scenario provides chemical producers leverage when negotiating contracts with outsourced electricity providers and this allows plants to purchase electricity at a wholesale price. This is a huge advantage of considering on-site electricity production because electricity is needed in relatively high quantities for all chemical plants. Being able to minimize electricity costs, or even profit off of electricity production is a huge economical consideration that all plants employ.

=Process Heating=
The key objective of this section is to discuss how processes are heated. Heating utilities are necessary for proper usage of distillers, reactors, condensers, and several other integral types of equipment. More specifically, steam, fired heat, and hot oil/specialized heat transfer fluids will be discussed in the following subsections.

==Steam==
Steam is the most commonly used heat utility used in chemical plants, and as a result understanding how it is used is essential in the study of Utility systems. Steam is used both as a process fluid (feedstock, diluent to absorb heat of reaction, heating agent, and stripping agent in absorbers and adsorbers ) and utility. It can be used to drive pumps and compressors, ejectors (for producing a vacuum), and heat exchangers. As one can clearly see, steam is a versatile, and useful utility.

Here are a few advantages of using steam as opposed to other methods of process heating (Towler 2012):

:*By controlling the pressure of the steam, one can control the temperature at which the heat is released. Having a strong control over the temperature is essential in several processes. =
:*Steam is an efficient heat source because the heat of condensation of steam is very high. Meaning that there is is high output per mass of utility at a constant temperature.
:*Heat exchangers that use steam are relatively cheap because condensing steam has a high heat transfer coefficient.
:*Steam is nonflammable, nontoxic, and inert to several process fluids.

Chemical plants generally have a network of pipelines exclusively for providing steam. These networks generally have steam at a low pressure, a medium pressure, and a high pressure. The image below illustrates a basic steam system.

[[File:Steam.png|thumb|border|center|middle|upright=4|link=|atl=|(Towler 2012 Fig 3.2)]]

In the diagram above, boiler feed water at a high pressure is preheated and fed to other boilers. These other boilers superheat the steam to create a high pressure and high temperature steam stream. The steam is superheated past the dew point to account for heat loss in the pipelines. A portion of the high pressure steam is used for process heating in areas of the plant that require high temperatures. The rest of the high pressure steam is turned into medium pressure steam by valves and steam turbines. The medium pressure steam is then used to heat medium temperature processes and to form low pressure steam. The low pressure steam can be used to heat low pressure processes and it can be expanded in condensing turbines to create shaft work and energy. In summary, steam can be used for an innumerable amount of action items in a plant. High pressure, medium pressure, and low pressure steam can all be used as a heat source. Low pressure steam has utilities in creating electricity and it also has several other uses.

==Fired Heat==

In many cases, processes in a plant require a heat source stronger than high pressure and temperature steam. That is when fired heat is used, which is generally at temperatures above 523K. Streams can be heated directly in the furnace tubes or via a hot oil circuit or heat transfer fluid, which will be discussed in detail in the next section. Most fired heaters use natural gas as fuel because it burns cleaner than fuel oil. A cleaner burning fuel is always advantageous due to environmental and safety concerns. Furthermore, natural gases usually result in less wear and tear in burners and fuel lines.

Depending on the application of the fired-heater, different design specifications can be implemented to make the fired-heater as efficient as possible. The basic construction of a fired heater starts with a cylindrical chamber that is lined with with refractory bricks. The stream that is to be heated flows through tubes inside of the furnace. These tubes can be arranged in several different arrangements such as, around the walls of the furnace, or in horizontal or vertical banks (Towler 2012). The figure below illustrates the basic construction of the fired-heater and varying tube arrangements.

[[File:firedheater.png|thumb|border|center|middle|upright=4|link=|atl=|Basic Fired-Heater Diagrams (Towler 2012 Figure 19.66)]]

Fuel is burned to heat the entire furnace, and the heat transfer occurs from the combustion gases inside of the furnace across the tubes that are filled with our desired stream. The heat transfer between the tubes and the furnace is accomplished primarily via radiation. Modern designs take advantage of convective heat transfer by adding a smaller section on top of the fired-heater where the combustion gases flow over banks of tubes as seen in (c) in the figure above. Heat transfer can be further improved via convection by adding fins or pins in the combustion section.

The cost of fired heat can be calculated by the cost of fuel fired. Natural gas and heating oil are traded as commodities and prices can be found at many online trading sites or business news sites (i.e., www.cnn.money.com). Past historic prices for forecasting can be found in the Oil and Gas Journal or from the U.S. Energy Information Adminstration (www.eia.gov).

===Fuels===
Fuel is burned in utility facilities such as boilers, electricity generation, and cogeneration, and can be in solid, liquid, or gas form. It can also be burned to provide heating for a process or stream or to drive pumps and compressors. The fuel is usually burned with excess air to ensure complete combustion.

A way of quantifying the amount of heat generated is by using the heating values. Higher heating value (HHV) and the lower heating value (LHV) are used. The heating is the total heat evolved by complete combustion of a fuel with dry air with both at 60 ⁰F and the flue gas after combustion brought back down to ⁰F. If the water vapor in the flue gas is not condensed, we obtain the LHV. If the water vapor is condensed, the value of heat evolved is a bit higher, and this is the HHV.
Heating values for solids and liquids are usually on a per-mass basis, and gases on a per-volume basis.
A specified amount of heating cannot be met with the amount of fuel calculated using only the HHV. There will be heat losses, the flue gas temperature will be greater than 60 ⁰F, and water in the flue gas will typically be vapor. (Seider 608)

==Hot Oil/Specialized Heat Transfer Fluids==

Specialized heat transfer fluids and hot oil circuits are used as heat sources when steam and fired heat is not appropriate. Specialized heat transfer fluids and hot oil circuits are extremely versatile in that they can be used in the temperature range of 323K to 673K. This range however is quite variable. For hot oils, the upper temperature limit is gauged based off of the thermal decomposition of the oil and coking/fouling of heat exchanger tubes.

Hot oil circuit systems are most commonly used when the plant has several small temperature heating requirements because it is more economically sound. Rather than having several fired heaters heat each small temperature requirement, it is much more economical to have one fired heater heat the hot oil and circulate that oil through each of the process to meet all of the heat needs. Hot oil systems are also generally favored over high pressure steam in processes that involve high pressure differentials between the process stream and high pressure steam. Hot oil systems are favored in this scenario because of safety concerns. If the steam were to leak, the pressure drop could cause serious safety issues.

Mineral oils are the most commonly used heat transfer fluids, and one prominent example is Dowtherm A. Dowtherm A is a combination of 26.5 wt% diphenyl in diphenyl oxide (Towler 2012) and is extremely thermally stable. These mineral oil systems generally require high flow rates.

=Process Cooling=

==Cooling Water==
Cooling water is used to cool and/or condense streams. Cooling water is usually circulated between process heat exchangers and a cooling tower. Water is cooled during downward motion by contact with air blown upwards, which can bring the water temperature to come within ~ 5 ⁰F of air’s wet-bulb temperature.Approximately 80% of the temperature reduction is due to evaporation of the cooling water and heat transfer to the surrounding air. Water can also be cooled in spray ponds and cooling ponds. Both work by providing high area for water to exchange heat with air.
Water in cooling towers is lost through drift and blowdown, and makeup is usually 1.5 to 3% of the circulating rate.
If a large natural body of water is nearby, it can be used as a source of cooling water and discharged downstream. This water is usually filtered to remove salts and impurities that may lead to fouling, but it is not treated.

==Refrigeration==
Cooling water can usually be used to cool a stream to ~ 100 ⁰F. Air can only cool to ~ 120 ⁰F. Air may be used in places where water is scarce or more costly to transport. To cool or condense streams below 100 ⁰F, a refrigerant is typically used. Chilled brine can also be used, but is less common.

Until 1995, CFC Freon R-12 (dichlorodifuloromethane) and HCFC Freon R-22 (chlorodifuloromethane) were commonly used refrigerants. However, the chlorine atom in the molecules caused the depletion of the ozone layer. The U.S. Clean Air Act Amendments of 1990 went into effect in 1995, and the production of these refrigerants has since stopped or been greatly reduced.

Cost estimates are based on ton-day of refrigeration, where a ton is the heat that needs to be removed to freeze 1 ton per day of water at 32 ⁰F. Substitutes have since been developed. R-134a is often used in place of R-12. According to the EPA, R-134a is not combustible at ambient conditions, and is essentially non-toxic under 400 ppm, and is not ozone-depleting. (Seider pg 607)

=Energy Efficiency=
One of the chief concerns in selecting and designing process utility systems for heating and cooling is how to achieve the most energy efficient design. There are countless means by which plants lose energy, two of the foremost being through the mixing of different temperature or pressure streams and through the disposal of warmed cooling water. (Seider, 2009) Proper utilities design can help mitigate each of these losses as well as many others. The energy efficiency of a plant will depend primarily on the heating and cooling methods that are being used and the overall system design itself. These two parameters are important in determining how well energy is transferred to the desired media as well as how well that energy is recovered and recycled.

==Utility Efficiency==
As mentioned above, the most commonly used utilities for process heating in large scale processes are steam, fired heat, and hot oil heaters. Of these, steam is the most commonly used. Electricity, while efficient at creating power, is not a viable source of heat in large industrial processes. Common ranges of heating efficiency for these three methods are displayed in Table 1. (Towler and Sinnott, 2012)

{| class="wikitable"
|+Table 1: Process Heating Efficiencies
|-
! Process Heating Method
! Typical Efficiency
|-
| Steam (via package boiler)
| 80-90%
|-
| Fired Heat w/ Convective Section
| 85%
|-
| Fired Heat w/o Convective Section
| 60%
|-
| Hot Oil Heaters/Vaporizers
| 80-85%
|}

Efficiency in cooling processes depends more on the method used, and by extension the amount of coolant needed. Water and air utility efficiencies depend primarily on the fluid flow required to maintain the system at a desired temperature, while powered refrigeration utilities (for colder processes) have efficiencies at approximately 60%--but ranging up to 90%--of Carnot cycle efficiency, a metric of ideal refrigeration efficiency. (Towler and Sinnott, 2012) Cooling systems represent by definition a loss of energy from the main process to the utility stream, and as such it is often useful to find other uses for the heated media before discharge.

==Energy Recovery==
Recovery and recycle of energy is perhaps the most important aspect of creating an energy efficient plant design, and it is important for process engineers to fully consider possibilities for heat recovery in order to aid in economic viability.

===Process Heat Exchange===
Heat exchanger networks are a very common energy recovery method in industrial processes. These networks most frequently allow energy from heated product streams to be transferred to feed streams that must be brought up to process temperature. (Biegler, 1997) For more on the function and design of heat exchanger networks, see [LINK TO HEN PAGE]. The following are several examples of energy recovery via heat exchange that are used in industrial processes.

In distillation columns the bottoms and distillate effluents have the potential for energy exchange. Though the condenser at the top of the column cannot supply its waste heat to the reboiler due to their respective temperatures, the effluent streams can supply heat to the feed via a feed-effluent exchanger. This reduces the utility requirements to raise the feed to column temperature. (Biegler, 1997)

[[File:Feed_sterilization.jpg|thumb|border|right|middle|upright=4|link=|atl=|Feed sterilization schematic. (Towler and Sinnott Fig. 3.30)]]

Feed sterilization, commonly used in the food industry, is a common application for heat recovery through process stream heat exchange. In this application, the feed must be heated for a certain amount of time to kill any biological contaminants, after which it can be used to heat the new raw feed for sterilization. This reduces energy demands on the steam heater and thus reduces cost. (Towler and Sinnott, 2012)

In multi-vessel batch processes it can be advantageous to exchange heat as the process fluid is being transferred between vessels. Like the previous examples, this reduces the utility needed to bring the colder feed up to process temperature, thus reducing costs. (Towler and Sinnott, 2012)

[[File:Batch_heat_exchange.jpg|thumb|border|center|middle|upright=4|link=|atl=|Multi-vessel batch heat exchange schematic (Towler and Sinnott Fig. 3.31)]]

===Utility Regeneration===
When recovery of waste heat via transfer to other process streams is inconvenient or impossible, energy efficiency can still be improved through the regeneration of utilities. This is commonly done through the regeneration of steam by either removing heat from exiting streams or from highly exothermic reactions. Waste heat in exiting streams is removed via heat recovery steam generators (HRSGs), and is most often used on exiting flue gas and exiting process gas streams. Heat recovery from reactions is a viable option when the reactor temperature will be at 150 C or above, as this will create steam at high enough pressure to be used in other processes. (Towler and Sinnott, 2012)

Furthermore, there is opportunity for energy recovery in the expansion of compressed gas through a turbine to create electricity, a process that can be economically viable given sufficiently high flows or pressure. Such technology has been used in processes to synthesize ammonia, perform air separations, and synthesize nitric acid. (Towler and Sinnott, 2012) Recently, however, there has been a particularly strong interest for energy recovery in the natural gas industry, when gas is decompressed from major pipelines to residential low-pressure piplines. A 2001 study estimated that there is the potential to recover 21 TWh, representing 11% of natural gas transport energy, via gas expansion. (Lehman)

=Process water and boiler-feed water=
Process water is water that will be directly used in the process. Boiler-feed water (BFW) is used to produce steam. Both may need to be purified to prevent impurities from contaminating a process or from foul equipment. It can be used as a cooling stream when the temperature of the stream to be cooled is greater than ~300 ⁰F. Cost of BFW can be partially offset by the steam credit.

Process water that undergoes moderate pretreatment can cost ~ $0.75/1,000 gal.

Extensive treatment ~ $6.00/1,000 gal.

Sterilized for pharmaceutical processes ~ $550/1,000 gal. (Seider pg 608)

=Demineralized Water=
In demineralized water, minerals have been removed by ion exchange. In boiler feed water, this is to prevent salt deposition, corrosion, formation of foam, and sluicing. In process water, the ions may contaminate the process.

=Waste Treatment=
Most chemical processes will produce some sort of waste. Disposal occurs to the atmosphere (in the case of some gases), sewers, body of water, or a landfill. Waste may require some treatment before disposal to meet regulations. Depending on process economics, byproducts may be recovered and processed. (Seider 2009 pg 609)

==Wastewater Treatment==
The United States EPA regulates industrial wastewater disposal through the Clean Water Act, introduced in 1948 as the Federal Water Pollution Control Act and amended to its current form in 1972. The sweeping 1972 amendments allowed the EPA to prevent industries and persons from discharging contaminated water into fresh water sources and set water quality standards. (Summary of the Clean Water Act) In accordance with this law, process plants in the United States treat wastewater at on-site or near-site treatment centers before releasing it into the surrounding environment.

Wastewater effluent streams, along with water runoff from around the plant, are treated to control for pH, toxicity, suspended solids, and biological oxygen demand (for aquatic life protection) prior to discharge. Each of these controls is typically addressed with a separate method. Acidity and basicity is balanced through the addition of an acid or alkaline solution. Toxic wastewater may be treated with chemical processes or simply diluted to safe concentrations. Suspended solids can be removed via filtration and/or with clarifiers. Oxygen demand of wastewater can be mitigated using activated sludge treatment processes. Once the water quality complies with the EPA, and state-mandated, regulations, it can be safely released. More information on the large number of industry-specific guidelines for waste effluent can be found on the EPA website (http://www.epa.gov/eg/industrial-effluent-guidelines).

==Air-Pollution Management==
'''Introduction'''
In the United States air pollution is regulated in the Clean Air Act, and almost all pollutant emitting plants are regulated under this law. The types of plants that can release significant emissions include petroleum refineries, sulfur recovery plants, carbon-black plants, fuel conversion plants, chemical process plants, fossil fuel plants, and petroleum storage and transfer facilities. To receive permission to construct a plant must undergo a review to show that it will not cause a violation of the Ambient Air Quality Standards(Peters, 2003).

'''Methods'''
There are two major types of pollutants that are released into the air, particulates and and gaseous pollutants. Particulates can be removed with mechanical forces while gaseous pollutants typically need to removed by chemical or physical means (Peters, 2003).

Particulates and volatile pollutants that need to be removed before disposal may be present. Particle removal equipment includes: cyclones, wet scrubbers, electrostatic precipitators, and fabric-filter systems.(Seider 2009 pg 609). The two charts below are from ''Plant Design and Economics for Chemical Engineers'' and show the types of equipment, separation methods, and particle sizes in different pollutant separation technologies (Peters, 1991).

[[File:AirPolChart.png|thumb|border|center|middle|upright=4|link=|atl=|]]

[[File:AirPolTable.png|thumb|border|center|middle|upright=4|link=|atl=|]]

Methods for removing inorganic and organic gaseous pollutants include: absorption, adsorption, condensation, and combustion (Seider 2009 pg 609). A typical of gases and their sources from ''Plant Design and Economics for Chemical Engineers'' is shown below (Peters, 1991).

[[File:GaseousPollutants.png|thumb|border|center|middle|upright=4|link=|atl=|]]

Typically Gas-liquid absorption processes are done completed in a vertical, countercurrent, flow through packed, plate, or spray towers. These systems require good liquid-gas contact and proper equipment. These systems also often have significant energy consumption because of large pressure drops (Peters, 2003). Dry adsorbents can be used to remove the last races of gaseous pollutants. Adsorption typically requires blowers, condensers, separators, and controls. You also typically need two packed beds so that one can be used while the other is regenerated. Examples of adsorbents are molecular sieves and activated carbon. Incineration is typically used when there are gas streams that have no recovery value. This can be done with direct flame or catalytic oxidation. Catalytic oxidation usually has higher capital costs, but lower operating costs because it does not require fuel.

'''Outcome'''
The United States implemented the Clean Air Act in 1970 and since then emissions in the U.S. have been drastically reduced.

==Solid Waste==
U.S. federal regulations require that solid waste be classified as hazardous or nonhazardous. Conditions for a classification of hazardous include: ignitability, corrosivity, reactivity, toxicity, or posing a substantial threat to the surrounding environment and its inhabitants. Hazardous waste must be treated on- or near-site before being removed in containers. Non-hazardous waste may be landfilled or incinerated in some cases. A typical estimate of costs for waste disposal is $0.03/lb for nonhazardous solids and $0.10/lb for hazardous solids. (Seider 2009 pg 609)

=References=

*Biegler LT, Grossmann IE, Westerberg AW. ''Systematic Methods of Chemical Process Design'' Prentice-Hall: Upper Saddle River, 1997.

*Duke Energy Company (2013). How Do Coal Fired Plants Work? Charlotte: Duke Energy.

*Lehman B, Worrell E. ''Electricity Production from Natural Gas Pressure Recovery Using Expansion Turbines.'' Lawrence Berkeley National Laboratory; 2001.

*Seider, Seader, Lewin, Widagdo. (2009). ''Plant Design and Economics for Chemical Engineers, 5th Edition.'' Hoboken: Wiley.

*Seider, Seader, Lewin. (2008). ''Product and Process Design Principles, 2nd Edition.'' Hoboken: Wiley.

*Summary of the Clean Water Act. United States EPA website. http://www.epa.gov/laws-regulations/summary-clean-water-act

*Towler, G.P. and Sinnot, R. (2012). ''Chemical Engineering Design: Principles, Practice and Economics of Plant and Process Design.'' Elsevier.

*Turton R.; Bailie, R.C.; Whiting, W.B.; Shaeiwitz J.A.; Bhattacharyya D. (2012). ''Analysis, Synthesis, and Design of Chemical Processes.'' Upper Saddle River: Prentice Hall.

File:Waste heat boiler.jpg

2016-02-05T20:50:23Z

Taunins:

File:Batch heat exchange.jpg

2016-02-05T20:50:04Z

Taunins:

Utility systems

2016-02-05T20:49:33Z

Taunins: /* Process Heat Exchange */

Authors: David Chen, [2014] Joshua Lee, [2015] Brett Sleyster, [2016] and Tom Aunins [2016] 

Stewards: David Chen, Jian Gong, and Fengqi You

Date Presented: January 13, 2014 /Date Revised: January 14, 2014

 


__TOC__

=Introduction=
Many chemical processes do not take place at ambient temperature or pressures. In order to reach these non-ambient conditions, utilities will have to be used to raise or lower temperatures and compress gases. (Towler, Towler/UOP) Utilities often contribute 5 to 10% of the price of a product, and may come from public or private utility companies or on-site plants. For purchased utilities, costs depend on consumption, while for company-owned utilities, there will be both capital and operating costs. They include things such as steam for heating, electricity, cooling water, refrigeration, fuels such as natural gas, wastewater treatment, waste disposal, and landfill. Steam is often the largest utility cost. Cogeneration unit can supply electricity accompanied with different steam pressures. (Seider 2009)

=Electricity=

Electricity is used to power many different kinds of equipment. It has many advantages: it is efficient (> 90%), reliable, available in a wide range of power, shaft speeds, designs, lifetimes, convenience, costs, and maintenance. It is generally used up to 200 hp, and sometimes over 10,000 Hp. In chemical process plants, the electricity demand is generally determined by the work or energy required for compression, pumping, air cooling, lights, and many other items. This electricity often times is purchased from local electricity providers, but many plants generate their own electricity via sophisticated processes.

Electricity is rarely used as a primary heat utility in large-scale chemical plants for a variety of reasons. The main disadvantages of using electricity as a heat utility are as follows (Towler 2012):

:*Heat from electricity is two to three times more expensive than heat from fuels. This is attributed to the lack of efficiency when creating heat from electricity.

:*Electrical heating units are expensive, require high maintenance, and must comply with strict safety regulations.

:*Electrical heating units are unsafe compared to steam heating units. In steam systems, the physically steam controls the temperature, whereas in electrical heating units temperature is controlled by temperature controllers, which can fail or burn out.

The use of electricity carries with it some hazards depending on the environment. Extra care must be taken when using electrically-powered equipment in areas which may have combustible fluids, vapors, or dust, and where liquids may be present. (Seider 2009 pg 606)

==Conventional Power Station==

In general, most electricity is generated from a conventional coal-fired process, whether it be on-site or purchased from a provider. Coal-fired processes have been used to create electricity throughout history, and technological advances have increased its efficiency and use worldwide. In a coal-fired steam station—much like a nuclear station—water is turned into steam, which in turn drives turbine generators to produce electricity. There are several variations on how to create energy from coal, but here are the basics of how a coal-fired process works:

[[File:coalfired.png|thumb|border|center|middle|upright=4|link=|atl=|General Coal-Fired Process Diagram (Duke Energy Company)]]

*Heat is created:
::Before the coal is burned, it is pulverized to the fineness of talcum powder. It is then mixed with hot air and blown into the firebox of the boiler. Burning in suspension, the coal/air mixture provides the most complete combustion and maximum heat possible.

*Water turns to steam:
::Highly purified water, pumped through pipes inside the boiler, is turned into steam by the heat. The steam reaches temperatures of up to 1,000 degrees Fahrenheit and pressures up to 3,500 pounds per square inch, and is piped to the turbine.

*Steam turns the turbine:
::The enormous pressure of the steam pushing against a series of giant turbine blades turns the turbine shaft. The turbine shaft is connected to the shaft of the generator, where magnets spin within wire coils to produce electricity.

*Steam is converted back to water:
::After doing its work in the turbine, the steam is drawn into a condenser, a large chamber in the basement of the power plant. In this important step, millions of gallons of cool water from a nearby source (such as a river or lake) are pumped through a network of tubes running through the condenser. The cool water in the tubes converts the steam back into water that can be used over and over again in the plant.

*Repeat:
::The cooling water is returned to its source without any contamination, and the steam water is returned to the boiler to repeat the cycle.

===Advantages & Disadvantages of Coal-Fired Energy Production===

[[File:coalfiredtable.png|thumb|border|center|middle|upright=4|link=|atl=|Advantages and Disadvantages of Coal-Fired Processes (Seider 2008)]]

==Gas-Turbine Cogeneration Process==

When generating energy on-site, many plants use a gas-turbine cogeneration process. The thermal efficiency of a gas-turbine process is in the range of 70-80% while conventional power stations, such as coal-fired processes, have a 30-40% efficiency. The lower efficiency in more conventional power stations is attributed to wasted heat in the exhaust steam in the condenser. One example of a gas-turbine process is outlined in the following figure. Figure 3.1 is a gas-turbine cogeneration process with a heat recovery steam generator (waste-heat) boiler.

[[File:cogeneration.png|thumb|border|center|middle|upright=4|link=|atl=|Gas-Turbine Cogeneration with a heat recovery steam generator boiler (Towler 2012 Fig 3.1)]]

Overall, the process illustrated is not much different from a coal-fired process. The main differences are that the cogeneration process creates both electricity and a heat utility, and cogeneration processes use natural gas instead of coal. Many of the advantages and disadvantages are similar to those of the coal-fired process, but the cogeneration has a much higher efficiency, creates heat to be used in another process, and uses a more volatile and expensive fuel. The main advantage of cogeneration over coal-fired energy production is that heat is not wasted. In coal-fired processes, heat is released and wasted during electricity generation. Cogeneration captures some, if not all of the byproduct for heat, which is an extremely useful utility that will be discussed in subsequent sections. In summary, the cogeneration plant is superior to the coal-fired process because of its higher efficiency and ability to create a useful heat utility.

Obviously any engineer would design the cogeneration plant to meet at least the energy requirement necessary for plant operation, but cogeneration plants often times are designed to exceed the plant electricity requirement to drive another source of capital. Many describe this scenario as a "make or buy" scenario (Towler 2012). This scenario provides chemical producers leverage when negotiating contracts with outsourced electricity providers and this allows plants to purchase electricity at a wholesale price. This is a huge advantage of considering on-site electricity production because electricity is needed in relatively high quantities for all chemical plants. Being able to minimize electricity costs, or even profit off of electricity production is a huge economical consideration that all plants employ.

=Process Heating=
The key objective of this section is to discuss how processes are heated. Heating utilities are necessary for proper usage of distillers, reactors, condensers, and several other integral types of equipment. More specifically, steam, fired heat, and hot oil/specialized heat transfer fluids will be discussed in the following subsections.

==Steam==
Steam is the most commonly used heat utility used in chemical plants, and as a result understanding how it is used is essential in the study of Utility systems. Steam is used both as a process fluid (feedstock, diluent to absorb heat of reaction, heating agent, and stripping agent in absorbers and adsorbers ) and utility. It can be used to drive pumps and compressors, ejectors (for producing a vacuum), and heat exchangers. As one can clearly see, steam is a versatile, and useful utility.

Here are a few advantages of using steam as opposed to other methods of process heating (Towler 2012):

:*By controlling the pressure of the steam, one can control the temperature at which the heat is released. Having a strong control over the temperature is essential in several processes. =
:*Steam is an efficient heat source because the heat of condensation of steam is very high. Meaning that there is is high output per mass of utility at a constant temperature.
:*Heat exchangers that use steam are relatively cheap because condensing steam has a high heat transfer coefficient.
:*Steam is nonflammable, nontoxic, and inert to several process fluids.

Chemical plants generally have a network of pipelines exclusively for providing steam. These networks generally have steam at a low pressure, a medium pressure, and a high pressure. The image below illustrates a basic steam system.

[[File:Steam.png|thumb|border|center|middle|upright=4|link=|atl=|(Towler 2012 Fig 3.2)]]

In the diagram above, boiler feed water at a high pressure is preheated and fed to other boilers. These other boilers superheat the steam to create a high pressure and high temperature steam stream. The steam is superheated past the dew point to account for heat loss in the pipelines. A portion of the high pressure steam is used for process heating in areas of the plant that require high temperatures. The rest of the high pressure steam is turned into medium pressure steam by valves and steam turbines. The medium pressure steam is then used to heat medium temperature processes and to form low pressure steam. The low pressure steam can be used to heat low pressure processes and it can be expanded in condensing turbines to create shaft work and energy. In summary, steam can be used for an innumerable amount of action items in a plant. High pressure, medium pressure, and low pressure steam can all be used as a heat source. Low pressure steam has utilities in creating electricity and it also has several other uses.

==Fired Heat==

In many cases, processes in a plant require a heat source stronger than high pressure and temperature steam. That is when fired heat is used, which is generally at temperatures above 523K. Streams can be heated directly in the furnace tubes or via a hot oil circuit or heat transfer fluid, which will be discussed in detail in the next section. Most fired heaters use natural gas as fuel because it burns cleaner than fuel oil. A cleaner burning fuel is always advantageous due to environmental and safety concerns. Furthermore, natural gases usually result in less wear and tear in burners and fuel lines.

Depending on the application of the fired-heater, different design specifications can be implemented to make the fired-heater as efficient as possible. The basic construction of a fired heater starts with a cylindrical chamber that is lined with with refractory bricks. The stream that is to be heated flows through tubes inside of the furnace. These tubes can be arranged in several different arrangements such as, around the walls of the furnace, or in horizontal or vertical banks (Towler 2012). The figure below illustrates the basic construction of the fired-heater and varying tube arrangements.

[[File:firedheater.png|thumb|border|center|middle|upright=4|link=|atl=|Basic Fired-Heater Diagrams (Towler 2012 Figure 19.66)]]

Fuel is burned to heat the entire furnace, and the heat transfer occurs from the combustion gases inside of the furnace across the tubes that are filled with our desired stream. The heat transfer between the tubes and the furnace is accomplished primarily via radiation. Modern designs take advantage of convective heat transfer by adding a smaller section on top of the fired-heater where the combustion gases flow over banks of tubes as seen in (c) in the figure above. Heat transfer can be further improved via convection by adding fins or pins in the combustion section.

The cost of fired heat can be calculated by the cost of fuel fired. Natural gas and heating oil are traded as commodities and prices can be found at many online trading sites or business news sites (i.e., www.cnn.money.com). Past historic prices for forecasting can be found in the Oil and Gas Journal or from the U.S. Energy Information Adminstration (www.eia.gov).

===Fuels===
Fuel is burned in utility facilities such as boilers, electricity generation, and cogeneration, and can be in solid, liquid, or gas form. It can also be burned to provide heating for a process or stream or to drive pumps and compressors. The fuel is usually burned with excess air to ensure complete combustion.

A way of quantifying the amount of heat generated is by using the heating values. Higher heating value (HHV) and the lower heating value (LHV) are used. The heating is the total heat evolved by complete combustion of a fuel with dry air with both at 60 ⁰F and the flue gas after combustion brought back down to ⁰F. If the water vapor in the flue gas is not condensed, we obtain the LHV. If the water vapor is condensed, the value of heat evolved is a bit higher, and this is the HHV.
Heating values for solids and liquids are usually on a per-mass basis, and gases on a per-volume basis.
A specified amount of heating cannot be met with the amount of fuel calculated using only the HHV. There will be heat losses, the flue gas temperature will be greater than 60 ⁰F, and water in the flue gas will typically be vapor. (Seider 608)

==Hot Oil/Specialized Heat Transfer Fluids==

Specialized heat transfer fluids and hot oil circuits are used as heat sources when steam and fired heat is not appropriate. Specialized heat transfer fluids and hot oil circuits are extremely versatile in that they can be used in the temperature range of 323K to 673K. This range however is quite variable. For hot oils, the upper temperature limit is gauged based off of the thermal decomposition of the oil and coking/fouling of heat exchanger tubes.

Hot oil circuit systems are most commonly used when the plant has several small temperature heating requirements because it is more economically sound. Rather than having several fired heaters heat each small temperature requirement, it is much more economical to have one fired heater heat the hot oil and circulate that oil through each of the process to meet all of the heat needs. Hot oil systems are also generally favored over high pressure steam in processes that involve high pressure differentials between the process stream and high pressure steam. Hot oil systems are favored in this scenario because of safety concerns. If the steam were to leak, the pressure drop could cause serious safety issues.

Mineral oils are the most commonly used heat transfer fluids, and one prominent example is Dowtherm A. Dowtherm A is a combination of 26.5 wt% diphenyl in diphenyl oxide (Towler 2012) and is extremely thermally stable. These mineral oil systems generally require high flow rates.

=Process Cooling=

==Cooling Water==
Cooling water is used to cool and/or condense streams. Cooling water is usually circulated between process heat exchangers and a cooling tower. Water is cooled during downward motion by contact with air blown upwards, which can bring the water temperature to come within ~ 5 ⁰F of air’s wet-bulb temperature.Approximately 80% of the temperature reduction is due to evaporation of the cooling water and heat transfer to the surrounding air. Water can also be cooled in spray ponds and cooling ponds. Both work by providing high area for water to exchange heat with air.
Water in cooling towers is lost through drift and blowdown, and makeup is usually 1.5 to 3% of the circulating rate.
If a large natural body of water is nearby, it can be used as a source of cooling water and discharged downstream. This water is usually filtered to remove salts and impurities that may lead to fouling, but it is not treated.

==Refrigeration==
Cooling water can usually be used to cool a stream to ~ 100 ⁰F. Air can only cool to ~ 120 ⁰F. Air may be used in places where water is scarce or more costly to transport. To cool or condense streams below 100 ⁰F, a refrigerant is typically used. Chilled brine can also be used, but is less common.

Until 1995, CFC Freon R-12 (dichlorodifuloromethane) and HCFC Freon R-22 (chlorodifuloromethane) were commonly used refrigerants. However, the chlorine atom in the molecules caused the depletion of the ozone layer. The U.S. Clean Air Act Amendments of 1990 went into effect in 1995, and the production of these refrigerants has since stopped or been greatly reduced.

Cost estimates are based on ton-day of refrigeration, where a ton is the heat that needs to be removed to freeze 1 ton per day of water at 32 ⁰F. Substitutes have since been developed. R-134a is often used in place of R-12. According to the EPA, R-134a is not combustible at ambient conditions, and is essentially non-toxic under 400 ppm, and is not ozone-depleting. (Seider pg 607)

=Energy Efficiency=
One of the chief concerns in selecting and designing process utility systems for heating and cooling is how to achieve the most energy efficient design. There are countless means by which plants lose energy, two of the foremost being through the mixing of different temperature or pressure streams and through the disposal of warmed cooling water. (Seider, 2009) Proper utilities design can help mitigate each of these losses as well as many others. The energy efficiency of a plant will depend primarily on the heating and cooling methods that are being used and the overall system design itself. These two parameters are important in determining how well energy is transferred to the desired media as well as how well that energy is recovered and recycled.

==Utility Efficiency==
As mentioned above, the most commonly used utilities for process heating in large scale processes are steam, fired heat, and hot oil heaters. Of these, steam is the most commonly used. Electricity, while efficient at creating power, is not a viable source of heat in large industrial processes. Common ranges of heating efficiency for these three methods are displayed in Table 1. (Towler and Sinnott, 2012)

{| class="wikitable"
|+Table 1: Process Heating Efficiencies
|-
! Process Heating Method
! Typical Efficiency
|-
| Steam (via package boiler)
| 80-90%
|-
| Fired Heat w/ Convective Section
| 85%
|-
| Fired Heat w/o Convective Section
| 60%
|-
| Hot Oil Heaters/Vaporizers
| 80-85%
|}

Efficiency in cooling processes depends more on the method used, and by extension the amount of coolant needed. Water and air utility efficiencies depend primarily on the fluid flow required to maintain the system at a desired temperature, while powered refrigeration utilities (for colder processes) have efficiencies at approximately 60%--but ranging up to 90%--of Carnot cycle efficiency, a metric of ideal refrigeration efficiency. (Towler and Sinnott, 2012) Cooling systems represent by definition a loss of energy from the main process to the utility stream, and as such it is often useful to find other uses for the heated media before discharge.

==Energy Recovery==
Recovery and recycle of energy is perhaps the most important aspect of creating an energy efficient plant design, and it is important for process engineers to fully consider possibilities for heat recovery in order to aid in economic viability.

===Process Heat Exchange===
Heat exchanger networks are a very common energy recovery method in industrial processes. These networks most frequently allow energy from heated product streams to be transferred to feed streams that must be brought up to process temperature. (Biegler, 1997) For more on the function and design of heat exchanger networks, see [LINK TO HEN PAGE]. The following are several examples of energy recovery via heat exchange that are used in industrial processes.

In distillation columns the bottoms and distillate effluents have the potential for energy exchange. Though the condenser at the top of the column cannot supply its waste heat to the reboiler due to their respective temperatures, the effluent streams can supply heat to the feed via a feed-effluent exchanger. This reduces the utility requirements to raise the feed to column temperature. (Biegler, 1997)

[[File:Feed_sterilization.jpg|thumb|border|right|middle|upright=4|link=|atl=|Feed sterilization schematic. (Towler and Sinnott Fig. 3.30)]]

Feed sterilization, commonly used in the food industry, is a common application for heat recovery through process stream heat exchange. In this application, the feed must be heated for a certain amount of time to kill any biological contaminants, after which it can be used to heat the new raw feed for sterilization. This reduces energy demands on the steam heater and thus reduces cost. (Towler and Sinnott, 2012)

In multi-vessel batch processes it can be advantageous to exchange heat as the process fluid is being transferred between vessels. Like the previous examples, this reduces the utility needed to bring the colder feed up to process temperature, thus reducing costs. (Towler and Sinnott, 2012)

===Utility Regeneration===
When recovery of waste heat via transfer to other process streams is inconvenient or impossible, energy efficiency can still be improved through the regeneration of utilities. This is commonly done through the regeneration of steam by either removing heat from exiting streams or from highly exothermic reactions. Waste heat in exiting streams is removed via heat recovery steam generators (HRSGs), and is most often used on exiting flue gas and exiting process gas streams. Heat recovery from reactions is a viable option when the reactor temperature will be at 150 C or above, as this will create steam at high enough pressure to be used in other processes. (Towler and Sinnott, 2012)

Furthermore, there is opportunity for energy recovery in the expansion of compressed gas through a turbine to create electricity, a process that can be economically viable given sufficiently high flows or pressure. Such technology has been used in processes to synthesize ammonia, perform air separations, and synthesize nitric acid. (Towler and Sinnott, 2012) Recently, however, there has been a particularly strong interest for energy recovery in the natural gas industry, when gas is decompressed from major pipelines to residential low-pressure piplines. A 2001 study estimated that there is the potential to recover 21 TWh, representing 11% of natural gas transport energy, via gas expansion. (Lehman)

=Process water and boiler-feed water=
Process water is water that will be directly used in the process. Boiler-feed water (BFW) is used to produce steam. Both may need to be purified to prevent impurities from contaminating a process or from foul equipment. It can be used as a cooling stream when the temperature of the stream to be cooled is greater than ~300 ⁰F. Cost of BFW can be partially offset by the steam credit.

Process water that undergoes moderate pretreatment can cost ~ $0.75/1,000 gal.

Extensive treatment ~ $6.00/1,000 gal.

Sterilized for pharmaceutical processes ~ $550/1,000 gal. (Seider pg 608)

=Demineralized Water=
In demineralized water, minerals have been removed by ion exchange. In boiler feed water, this is to prevent salt deposition, corrosion, formation of foam, and sluicing. In process water, the ions may contaminate the process.

=Waste Treatment=
Most chemical processes will produce some sort of waste. Disposal occurs to the atmosphere (in the case of some gases), sewers, body of water, or a landfill. Waste may require some treatment before disposal to meet regulations. Depending on process economics, byproducts may be recovered and processed. (Seider 2009 pg 609)

==Wastewater Treatment==
The United States EPA regulates industrial wastewater disposal through the Clean Water Act, introduced in 1948 as the Federal Water Pollution Control Act and amended to its current form in 1972. The sweeping 1972 amendments allowed the EPA to prevent industries and persons from discharging contaminated water into fresh water sources and set water quality standards. (Summary of the Clean Water Act) In accordance with this law, process plants in the United States treat wastewater at on-site or near-site treatment centers before releasing it into the surrounding environment.

Wastewater effluent streams, along with water runoff from around the plant, are treated to control for pH, toxicity, suspended solids, and biological oxygen demand (for aquatic life protection) prior to discharge. Each of these controls is typically addressed with a separate method. Acidity and basicity is balanced through the addition of an acid or alkaline solution. Toxic wastewater may be treated with chemical processes or simply diluted to safe concentrations. Suspended solids can be removed via filtration and/or with clarifiers. Oxygen demand of wastewater can be mitigated using activated sludge treatment processes. Once the water quality complies with the EPA, and state-mandated, regulations, it can be safely released. More information on the large number of industry-specific guidelines for waste effluent can be found on the EPA website (http://www.epa.gov/eg/industrial-effluent-guidelines).

==Air-Pollution Management==
'''Introduction'''
In the United States air pollution is regulated in the Clean Air Act, and almost all pollutant emitting plants are regulated under this law. The types of plants that can release significant emissions include petroleum refineries, sulfur recovery plants, carbon-black plants, fuel conversion plants, chemical process plants, fossil fuel plants, and petroleum storage and transfer facilities. To receive permission to construct a plant must undergo a review to show that it will not cause a violation of the Ambient Air Quality Standards(Peters, 2003).

'''Methods'''
There are two major types of pollutants that are released into the air, particulates and and gaseous pollutants. Particulates can be removed with mechanical forces while gaseous pollutants typically need to removed by chemical or physical means (Peters, 2003).

Particulates and volatile pollutants that need to be removed before disposal may be present. Particle removal equipment includes: cyclones, wet scrubbers, electrostatic precipitators, and fabric-filter systems.(Seider 2009 pg 609). The two charts below are from ''Plant Design and Economics for Chemical Engineers'' and show the types of equipment, separation methods, and particle sizes in different pollutant separation technologies (Peters, 1991).

[[File:AirPolChart.png|thumb|border|center|middle|upright=4|link=|atl=|]]

[[File:AirPolTable.png|thumb|border|center|middle|upright=4|link=|atl=|]]

Methods for removing inorganic and organic gaseous pollutants include: absorption, adsorption, condensation, and combustion (Seider 2009 pg 609). A typical of gases and their sources from ''Plant Design and Economics for Chemical Engineers'' is shown below (Peters, 1991).

[[File:GaseousPollutants.png|thumb|border|center|middle|upright=4|link=|atl=|]]

Typically Gas-liquid absorption processes are done completed in a vertical, countercurrent, flow through packed, plate, or spray towers. These systems require good liquid-gas contact and proper equipment. These systems also often have significant energy consumption because of large pressure drops (Peters, 2003). Dry adsorbents can be used to remove the last races of gaseous pollutants. Adsorption typically requires blowers, condensers, separators, and controls. You also typically need two packed beds so that one can be used while the other is regenerated. Examples of adsorbents are molecular sieves and activated carbon. Incineration is typically used when there are gas streams that have no recovery value. This can be done with direct flame or catalytic oxidation. Catalytic oxidation usually has higher capital costs, but lower operating costs because it does not require fuel.

'''Outcome'''
The United States implemented the Clean Air Act in 1970 and since then emissions in the U.S. have been drastically reduced.

==Solid Waste==
U.S. federal regulations require that solid waste be classified as hazardous or nonhazardous. Conditions for a classification of hazardous include: ignitability, corrosivity, reactivity, toxicity, or posing a substantial threat to the surrounding environment and its inhabitants. Hazardous waste must be treated on- or near-site before being removed in containers. Non-hazardous waste may be landfilled or incinerated in some cases. A typical estimate of costs for waste disposal is $0.03/lb for nonhazardous solids and $0.10/lb for hazardous solids. (Seider 2009 pg 609)

=References=

*Biegler LT, Grossmann IE, Westerberg AW. ''Systematic Methods of Chemical Process Design'' Prentice-Hall: Upper Saddle River, 1997.

*Duke Energy Company (2013). How Do Coal Fired Plants Work? Charlotte: Duke Energy.

*Lehman B, Worrell E. ''Electricity Production from Natural Gas Pressure Recovery Using Expansion Turbines.'' Lawrence Berkeley National Laboratory; 2001.

*Seider, Seader, Lewin, Widagdo. (2009). ''Plant Design and Economics for Chemical Engineers, 5th Edition.'' Hoboken: Wiley.

*Seider, Seader, Lewin. (2008). ''Product and Process Design Principles, 2nd Edition.'' Hoboken: Wiley.

*Summary of the Clean Water Act. United States EPA website. http://www.epa.gov/laws-regulations/summary-clean-water-act

*Towler, G.P. and Sinnot, R. (2012). ''Chemical Engineering Design: Principles, Practice and Economics of Plant and Process Design.'' Elsevier.

*Turton R.; Bailie, R.C.; Whiting, W.B.; Shaeiwitz J.A.; Bhattacharyya D. (2012). ''Analysis, Synthesis, and Design of Chemical Processes.'' Upper Saddle River: Prentice Hall.

File:Feed sterilization.jpg

2016-02-05T20:45:27Z

Taunins:

Utility systems

2016-02-05T20:43:37Z

Taunins:

Authors: David Chen, [2014] Joshua Lee, [2015] Brett Sleyster, [2016] and Tom Aunins [2016] 

Stewards: David Chen, Jian Gong, and Fengqi You

Date Presented: January 13, 2014 /Date Revised: January 14, 2014

 


__TOC__

=Introduction=
Many chemical processes do not take place at ambient temperature or pressures. In order to reach these non-ambient conditions, utilities will have to be used to raise or lower temperatures and compress gases. (Towler, Towler/UOP) Utilities often contribute 5 to 10% of the price of a product, and may come from public or private utility companies or on-site plants. For purchased utilities, costs depend on consumption, while for company-owned utilities, there will be both capital and operating costs. They include things such as steam for heating, electricity, cooling water, refrigeration, fuels such as natural gas, wastewater treatment, waste disposal, and landfill. Steam is often the largest utility cost. Cogeneration unit can supply electricity accompanied with different steam pressures. (Seider 2009)

=Electricity=

Electricity is used to power many different kinds of equipment. It has many advantages: it is efficient (> 90%), reliable, available in a wide range of power, shaft speeds, designs, lifetimes, convenience, costs, and maintenance. It is generally used up to 200 hp, and sometimes over 10,000 Hp. In chemical process plants, the electricity demand is generally determined by the work or energy required for compression, pumping, air cooling, lights, and many other items. This electricity often times is purchased from local electricity providers, but many plants generate their own electricity via sophisticated processes.

Electricity is rarely used as a primary heat utility in large-scale chemical plants for a variety of reasons. The main disadvantages of using electricity as a heat utility are as follows (Towler 2012):

:*Heat from electricity is two to three times more expensive than heat from fuels. This is attributed to the lack of efficiency when creating heat from electricity.

:*Electrical heating units are expensive, require high maintenance, and must comply with strict safety regulations.

:*Electrical heating units are unsafe compared to steam heating units. In steam systems, the physically steam controls the temperature, whereas in electrical heating units temperature is controlled by temperature controllers, which can fail or burn out.

The use of electricity carries with it some hazards depending on the environment. Extra care must be taken when using electrically-powered equipment in areas which may have combustible fluids, vapors, or dust, and where liquids may be present. (Seider 2009 pg 606)

==Conventional Power Station==

In general, most electricity is generated from a conventional coal-fired process, whether it be on-site or purchased from a provider. Coal-fired processes have been used to create electricity throughout history, and technological advances have increased its efficiency and use worldwide. In a coal-fired steam station—much like a nuclear station—water is turned into steam, which in turn drives turbine generators to produce electricity. There are several variations on how to create energy from coal, but here are the basics of how a coal-fired process works:

[[File:coalfired.png|thumb|border|center|middle|upright=4|link=|atl=|General Coal-Fired Process Diagram (Duke Energy Company)]]

*Heat is created:
::Before the coal is burned, it is pulverized to the fineness of talcum powder. It is then mixed with hot air and blown into the firebox of the boiler. Burning in suspension, the coal/air mixture provides the most complete combustion and maximum heat possible.

*Water turns to steam:
::Highly purified water, pumped through pipes inside the boiler, is turned into steam by the heat. The steam reaches temperatures of up to 1,000 degrees Fahrenheit and pressures up to 3,500 pounds per square inch, and is piped to the turbine.

*Steam turns the turbine:
::The enormous pressure of the steam pushing against a series of giant turbine blades turns the turbine shaft. The turbine shaft is connected to the shaft of the generator, where magnets spin within wire coils to produce electricity.

*Steam is converted back to water:
::After doing its work in the turbine, the steam is drawn into a condenser, a large chamber in the basement of the power plant. In this important step, millions of gallons of cool water from a nearby source (such as a river or lake) are pumped through a network of tubes running through the condenser. The cool water in the tubes converts the steam back into water that can be used over and over again in the plant.

*Repeat:
::The cooling water is returned to its source without any contamination, and the steam water is returned to the boiler to repeat the cycle.

===Advantages & Disadvantages of Coal-Fired Energy Production===

[[File:coalfiredtable.png|thumb|border|center|middle|upright=4|link=|atl=|Advantages and Disadvantages of Coal-Fired Processes (Seider 2008)]]

==Gas-Turbine Cogeneration Process==

When generating energy on-site, many plants use a gas-turbine cogeneration process. The thermal efficiency of a gas-turbine process is in the range of 70-80% while conventional power stations, such as coal-fired processes, have a 30-40% efficiency. The lower efficiency in more conventional power stations is attributed to wasted heat in the exhaust steam in the condenser. One example of a gas-turbine process is outlined in the following figure. Figure 3.1 is a gas-turbine cogeneration process with a heat recovery steam generator (waste-heat) boiler.

[[File:cogeneration.png|thumb|border|center|middle|upright=4|link=|atl=|Gas-Turbine Cogeneration with a heat recovery steam generator boiler (Towler 2012 Fig 3.1)]]

Overall, the process illustrated is not much different from a coal-fired process. The main differences are that the cogeneration process creates both electricity and a heat utility, and cogeneration processes use natural gas instead of coal. Many of the advantages and disadvantages are similar to those of the coal-fired process, but the cogeneration has a much higher efficiency, creates heat to be used in another process, and uses a more volatile and expensive fuel. The main advantage of cogeneration over coal-fired energy production is that heat is not wasted. In coal-fired processes, heat is released and wasted during electricity generation. Cogeneration captures some, if not all of the byproduct for heat, which is an extremely useful utility that will be discussed in subsequent sections. In summary, the cogeneration plant is superior to the coal-fired process because of its higher efficiency and ability to create a useful heat utility.

Obviously any engineer would design the cogeneration plant to meet at least the energy requirement necessary for plant operation, but cogeneration plants often times are designed to exceed the plant electricity requirement to drive another source of capital. Many describe this scenario as a "make or buy" scenario (Towler 2012). This scenario provides chemical producers leverage when negotiating contracts with outsourced electricity providers and this allows plants to purchase electricity at a wholesale price. This is a huge advantage of considering on-site electricity production because electricity is needed in relatively high quantities for all chemical plants. Being able to minimize electricity costs, or even profit off of electricity production is a huge economical consideration that all plants employ.

=Process Heating=
The key objective of this section is to discuss how processes are heated. Heating utilities are necessary for proper usage of distillers, reactors, condensers, and several other integral types of equipment. More specifically, steam, fired heat, and hot oil/specialized heat transfer fluids will be discussed in the following subsections.

==Steam==
Steam is the most commonly used heat utility used in chemical plants, and as a result understanding how it is used is essential in the study of Utility systems. Steam is used both as a process fluid (feedstock, diluent to absorb heat of reaction, heating agent, and stripping agent in absorbers and adsorbers ) and utility. It can be used to drive pumps and compressors, ejectors (for producing a vacuum), and heat exchangers. As one can clearly see, steam is a versatile, and useful utility.

Here are a few advantages of using steam as opposed to other methods of process heating (Towler 2012):

:*By controlling the pressure of the steam, one can control the temperature at which the heat is released. Having a strong control over the temperature is essential in several processes. =
:*Steam is an efficient heat source because the heat of condensation of steam is very high. Meaning that there is is high output per mass of utility at a constant temperature.
:*Heat exchangers that use steam are relatively cheap because condensing steam has a high heat transfer coefficient.
:*Steam is nonflammable, nontoxic, and inert to several process fluids.

Chemical plants generally have a network of pipelines exclusively for providing steam. These networks generally have steam at a low pressure, a medium pressure, and a high pressure. The image below illustrates a basic steam system.

[[File:Steam.png|thumb|border|center|middle|upright=4|link=|atl=|(Towler 2012 Fig 3.2)]]

In the diagram above, boiler feed water at a high pressure is preheated and fed to other boilers. These other boilers superheat the steam to create a high pressure and high temperature steam stream. The steam is superheated past the dew point to account for heat loss in the pipelines. A portion of the high pressure steam is used for process heating in areas of the plant that require high temperatures. The rest of the high pressure steam is turned into medium pressure steam by valves and steam turbines. The medium pressure steam is then used to heat medium temperature processes and to form low pressure steam. The low pressure steam can be used to heat low pressure processes and it can be expanded in condensing turbines to create shaft work and energy. In summary, steam can be used for an innumerable amount of action items in a plant. High pressure, medium pressure, and low pressure steam can all be used as a heat source. Low pressure steam has utilities in creating electricity and it also has several other uses.

==Fired Heat==

In many cases, processes in a plant require a heat source stronger than high pressure and temperature steam. That is when fired heat is used, which is generally at temperatures above 523K. Streams can be heated directly in the furnace tubes or via a hot oil circuit or heat transfer fluid, which will be discussed in detail in the next section. Most fired heaters use natural gas as fuel because it burns cleaner than fuel oil. A cleaner burning fuel is always advantageous due to environmental and safety concerns. Furthermore, natural gases usually result in less wear and tear in burners and fuel lines.

Depending on the application of the fired-heater, different design specifications can be implemented to make the fired-heater as efficient as possible. The basic construction of a fired heater starts with a cylindrical chamber that is lined with with refractory bricks. The stream that is to be heated flows through tubes inside of the furnace. These tubes can be arranged in several different arrangements such as, around the walls of the furnace, or in horizontal or vertical banks (Towler 2012). The figure below illustrates the basic construction of the fired-heater and varying tube arrangements.

[[File:firedheater.png|thumb|border|center|middle|upright=4|link=|atl=|Basic Fired-Heater Diagrams (Towler 2012 Figure 19.66)]]

Fuel is burned to heat the entire furnace, and the heat transfer occurs from the combustion gases inside of the furnace across the tubes that are filled with our desired stream. The heat transfer between the tubes and the furnace is accomplished primarily via radiation. Modern designs take advantage of convective heat transfer by adding a smaller section on top of the fired-heater where the combustion gases flow over banks of tubes as seen in (c) in the figure above. Heat transfer can be further improved via convection by adding fins or pins in the combustion section.

The cost of fired heat can be calculated by the cost of fuel fired. Natural gas and heating oil are traded as commodities and prices can be found at many online trading sites or business news sites (i.e., www.cnn.money.com). Past historic prices for forecasting can be found in the Oil and Gas Journal or from the U.S. Energy Information Adminstration (www.eia.gov).

===Fuels===
Fuel is burned in utility facilities such as boilers, electricity generation, and cogeneration, and can be in solid, liquid, or gas form. It can also be burned to provide heating for a process or stream or to drive pumps and compressors. The fuel is usually burned with excess air to ensure complete combustion.

A way of quantifying the amount of heat generated is by using the heating values. Higher heating value (HHV) and the lower heating value (LHV) are used. The heating is the total heat evolved by complete combustion of a fuel with dry air with both at 60 ⁰F and the flue gas after combustion brought back down to ⁰F. If the water vapor in the flue gas is not condensed, we obtain the LHV. If the water vapor is condensed, the value of heat evolved is a bit higher, and this is the HHV.
Heating values for solids and liquids are usually on a per-mass basis, and gases on a per-volume basis.
A specified amount of heating cannot be met with the amount of fuel calculated using only the HHV. There will be heat losses, the flue gas temperature will be greater than 60 ⁰F, and water in the flue gas will typically be vapor. (Seider 608)

==Hot Oil/Specialized Heat Transfer Fluids==

Specialized heat transfer fluids and hot oil circuits are used as heat sources when steam and fired heat is not appropriate. Specialized heat transfer fluids and hot oil circuits are extremely versatile in that they can be used in the temperature range of 323K to 673K. This range however is quite variable. For hot oils, the upper temperature limit is gauged based off of the thermal decomposition of the oil and coking/fouling of heat exchanger tubes.

Hot oil circuit systems are most commonly used when the plant has several small temperature heating requirements because it is more economically sound. Rather than having several fired heaters heat each small temperature requirement, it is much more economical to have one fired heater heat the hot oil and circulate that oil through each of the process to meet all of the heat needs. Hot oil systems are also generally favored over high pressure steam in processes that involve high pressure differentials between the process stream and high pressure steam. Hot oil systems are favored in this scenario because of safety concerns. If the steam were to leak, the pressure drop could cause serious safety issues.

Mineral oils are the most commonly used heat transfer fluids, and one prominent example is Dowtherm A. Dowtherm A is a combination of 26.5 wt% diphenyl in diphenyl oxide (Towler 2012) and is extremely thermally stable. These mineral oil systems generally require high flow rates.

=Process Cooling=

==Cooling Water==
Cooling water is used to cool and/or condense streams. Cooling water is usually circulated between process heat exchangers and a cooling tower. Water is cooled during downward motion by contact with air blown upwards, which can bring the water temperature to come within ~ 5 ⁰F of air’s wet-bulb temperature.Approximately 80% of the temperature reduction is due to evaporation of the cooling water and heat transfer to the surrounding air. Water can also be cooled in spray ponds and cooling ponds. Both work by providing high area for water to exchange heat with air.
Water in cooling towers is lost through drift and blowdown, and makeup is usually 1.5 to 3% of the circulating rate.
If a large natural body of water is nearby, it can be used as a source of cooling water and discharged downstream. This water is usually filtered to remove salts and impurities that may lead to fouling, but it is not treated.

==Refrigeration==
Cooling water can usually be used to cool a stream to ~ 100 ⁰F. Air can only cool to ~ 120 ⁰F. Air may be used in places where water is scarce or more costly to transport. To cool or condense streams below 100 ⁰F, a refrigerant is typically used. Chilled brine can also be used, but is less common.

Until 1995, CFC Freon R-12 (dichlorodifuloromethane) and HCFC Freon R-22 (chlorodifuloromethane) were commonly used refrigerants. However, the chlorine atom in the molecules caused the depletion of the ozone layer. The U.S. Clean Air Act Amendments of 1990 went into effect in 1995, and the production of these refrigerants has since stopped or been greatly reduced.

Cost estimates are based on ton-day of refrigeration, where a ton is the heat that needs to be removed to freeze 1 ton per day of water at 32 ⁰F. Substitutes have since been developed. R-134a is often used in place of R-12. According to the EPA, R-134a is not combustible at ambient conditions, and is essentially non-toxic under 400 ppm, and is not ozone-depleting. (Seider pg 607)

=Energy Efficiency=
One of the chief concerns in selecting and designing process utility systems for heating and cooling is how to achieve the most energy efficient design. There are countless means by which plants lose energy, two of the foremost being through the mixing of different temperature or pressure streams and through the disposal of warmed cooling water. (Seider, 2009) Proper utilities design can help mitigate each of these losses as well as many others. The energy efficiency of a plant will depend primarily on the heating and cooling methods that are being used and the overall system design itself. These two parameters are important in determining how well energy is transferred to the desired media as well as how well that energy is recovered and recycled.

==Utility Efficiency==
As mentioned above, the most commonly used utilities for process heating in large scale processes are steam, fired heat, and hot oil heaters. Of these, steam is the most commonly used. Electricity, while efficient at creating power, is not a viable source of heat in large industrial processes. Common ranges of heating efficiency for these three methods are displayed in Table 1. (Towler and Sinnott, 2012)

{| class="wikitable"
|+Table 1: Process Heating Efficiencies
|-
! Process Heating Method
! Typical Efficiency
|-
| Steam (via package boiler)
| 80-90%
|-
| Fired Heat w/ Convective Section
| 85%
|-
| Fired Heat w/o Convective Section
| 60%
|-
| Hot Oil Heaters/Vaporizers
| 80-85%
|}

Efficiency in cooling processes depends more on the method used, and by extension the amount of coolant needed. Water and air utility efficiencies depend primarily on the fluid flow required to maintain the system at a desired temperature, while powered refrigeration utilities (for colder processes) have efficiencies at approximately 60%--but ranging up to 90%--of Carnot cycle efficiency, a metric of ideal refrigeration efficiency. (Towler and Sinnott, 2012) Cooling systems represent by definition a loss of energy from the main process to the utility stream, and as such it is often useful to find other uses for the heated media before discharge.

==Energy Recovery==
Recovery and recycle of energy is perhaps the most important aspect of creating an energy efficient plant design, and it is important for process engineers to fully consider possibilities for heat recovery in order to aid in economic viability.

===Process Heat Exchange===
Heat exchanger networks are a very common energy recovery method in industrial processes. These networks most frequently allow energy from heated product streams to be transferred to feed streams that must be brought up to process temperature. (Biegler, 1997) For more on the function and design of heat exchanger networks, see [LINK TO HEN PAGE]. The following are several examples of energy recovery via heat exchange that are used in industrial processes.

In distillation columns the bottoms and distillate effluents have the potential for energy exchange. Though the condenser at the top of the column cannot supply its waste heat to the reboiler due to their respective temperatures, the effluent streams can supply heat to the feed via a feed-effluent exchanger. This reduces the utility requirements to raise the feed to column temperature. (Biegler, 1997)

Feed sterilization, commonly used in the food industry, is a common application for heat recovery through process stream heat exchange. In this application, the feed must be heated for a certain amount of time to kill any biological contaminants, after which it can be used to heat the new raw feed for sterilization. This reduces energy demands on the steam heater and thus reduces cost. (Towler and Sinnott, 2012)

In multi-vessel batch processes it can be advantageous to exchange heat as the process fluid is being transferred between vessels. Like the previous examples, this reduces the utility needed to bring the colder feed up to process temperature, thus reducing costs. (Towler and Sinnott, 2012)

===Utility Regeneration===
When recovery of waste heat via transfer to other process streams is inconvenient or impossible, energy efficiency can still be improved through the regeneration of utilities. This is commonly done through the regeneration of steam by either removing heat from exiting streams or from highly exothermic reactions. Waste heat in exiting streams is removed via heat recovery steam generators (HRSGs), and is most often used on exiting flue gas and exiting process gas streams. Heat recovery from reactions is a viable option when the reactor temperature will be at 150 C or above, as this will create steam at high enough pressure to be used in other processes. (Towler and Sinnott, 2012)

Furthermore, there is opportunity for energy recovery in the expansion of compressed gas through a turbine to create electricity, a process that can be economically viable given sufficiently high flows or pressure. Such technology has been used in processes to synthesize ammonia, perform air separations, and synthesize nitric acid. (Towler and Sinnott, 2012) Recently, however, there has been a particularly strong interest for energy recovery in the natural gas industry, when gas is decompressed from major pipelines to residential low-pressure piplines. A 2001 study estimated that there is the potential to recover 21 TWh, representing 11% of natural gas transport energy, via gas expansion. (Lehman)

=Process water and boiler-feed water=
Process water is water that will be directly used in the process. Boiler-feed water (BFW) is used to produce steam. Both may need to be purified to prevent impurities from contaminating a process or from foul equipment. It can be used as a cooling stream when the temperature of the stream to be cooled is greater than ~300 ⁰F. Cost of BFW can be partially offset by the steam credit.

Process water that undergoes moderate pretreatment can cost ~ $0.75/1,000 gal.

Extensive treatment ~ $6.00/1,000 gal.

Sterilized for pharmaceutical processes ~ $550/1,000 gal. (Seider pg 608)

=Demineralized Water=
In demineralized water, minerals have been removed by ion exchange. In boiler feed water, this is to prevent salt deposition, corrosion, formation of foam, and sluicing. In process water, the ions may contaminate the process.

=Waste Treatment=
Most chemical processes will produce some sort of waste. Disposal occurs to the atmosphere (in the case of some gases), sewers, body of water, or a landfill. Waste may require some treatment before disposal to meet regulations. Depending on process economics, byproducts may be recovered and processed. (Seider 2009 pg 609)

==Wastewater Treatment==
The United States EPA regulates industrial wastewater disposal through the Clean Water Act, introduced in 1948 as the Federal Water Pollution Control Act and amended to its current form in 1972. The sweeping 1972 amendments allowed the EPA to prevent industries and persons from discharging contaminated water into fresh water sources and set water quality standards. (Summary of the Clean Water Act) In accordance with this law, process plants in the United States treat wastewater at on-site or near-site treatment centers before releasing it into the surrounding environment.

Wastewater effluent streams, along with water runoff from around the plant, are treated to control for pH, toxicity, suspended solids, and biological oxygen demand (for aquatic life protection) prior to discharge. Each of these controls is typically addressed with a separate method. Acidity and basicity is balanced through the addition of an acid or alkaline solution. Toxic wastewater may be treated with chemical processes or simply diluted to safe concentrations. Suspended solids can be removed via filtration and/or with clarifiers. Oxygen demand of wastewater can be mitigated using activated sludge treatment processes. Once the water quality complies with the EPA, and state-mandated, regulations, it can be safely released. More information on the large number of industry-specific guidelines for waste effluent can be found on the EPA website (http://www.epa.gov/eg/industrial-effluent-guidelines).

==Air-Pollution Management==
'''Introduction'''
In the United States air pollution is regulated in the Clean Air Act, and almost all pollutant emitting plants are regulated under this law. The types of plants that can release significant emissions include petroleum refineries, sulfur recovery plants, carbon-black plants, fuel conversion plants, chemical process plants, fossil fuel plants, and petroleum storage and transfer facilities. To receive permission to construct a plant must undergo a review to show that it will not cause a violation of the Ambient Air Quality Standards(Peters, 2003).

'''Methods'''
There are two major types of pollutants that are released into the air, particulates and and gaseous pollutants. Particulates can be removed with mechanical forces while gaseous pollutants typically need to removed by chemical or physical means (Peters, 2003).

Particulates and volatile pollutants that need to be removed before disposal may be present. Particle removal equipment includes: cyclones, wet scrubbers, electrostatic precipitators, and fabric-filter systems.(Seider 2009 pg 609). The two charts below are from ''Plant Design and Economics for Chemical Engineers'' and show the types of equipment, separation methods, and particle sizes in different pollutant separation technologies (Peters, 1991).

[[File:AirPolChart.png|thumb|border|center|middle|upright=4|link=|atl=|]]

[[File:AirPolTable.png|thumb|border|center|middle|upright=4|link=|atl=|]]

Methods for removing inorganic and organic gaseous pollutants include: absorption, adsorption, condensation, and combustion (Seider 2009 pg 609). A typical of gases and their sources from ''Plant Design and Economics for Chemical Engineers'' is shown below (Peters, 1991).

[[File:GaseousPollutants.png|thumb|border|center|middle|upright=4|link=|atl=|]]

Typically Gas-liquid absorption processes are done completed in a vertical, countercurrent, flow through packed, plate, or spray towers. These systems require good liquid-gas contact and proper equipment. These systems also often have significant energy consumption because of large pressure drops (Peters, 2003). Dry adsorbents can be used to remove the last races of gaseous pollutants. Adsorption typically requires blowers, condensers, separators, and controls. You also typically need two packed beds so that one can be used while the other is regenerated. Examples of adsorbents are molecular sieves and activated carbon. Incineration is typically used when there are gas streams that have no recovery value. This can be done with direct flame or catalytic oxidation. Catalytic oxidation usually has higher capital costs, but lower operating costs because it does not require fuel.

'''Outcome'''
The United States implemented the Clean Air Act in 1970 and since then emissions in the U.S. have been drastically reduced.

==Solid Waste==
U.S. federal regulations require that solid waste be classified as hazardous or nonhazardous. Conditions for a classification of hazardous include: ignitability, corrosivity, reactivity, toxicity, or posing a substantial threat to the surrounding environment and its inhabitants. Hazardous waste must be treated on- or near-site before being removed in containers. Non-hazardous waste may be landfilled or incinerated in some cases. A typical estimate of costs for waste disposal is $0.03/lb for nonhazardous solids and $0.10/lb for hazardous solids. (Seider 2009 pg 609)

=References=

*Biegler LT, Grossmann IE, Westerberg AW. ''Systematic Methods of Chemical Process Design'' Prentice-Hall: Upper Saddle River, 1997.

*Duke Energy Company (2013). How Do Coal Fired Plants Work? Charlotte: Duke Energy.

*Lehman B, Worrell E. ''Electricity Production from Natural Gas Pressure Recovery Using Expansion Turbines.'' Lawrence Berkeley National Laboratory; 2001.

*Seider, Seader, Lewin, Widagdo. (2009). ''Plant Design and Economics for Chemical Engineers, 5th Edition.'' Hoboken: Wiley.

*Seider, Seader, Lewin. (2008). ''Product and Process Design Principles, 2nd Edition.'' Hoboken: Wiley.

*Summary of the Clean Water Act. United States EPA website. http://www.epa.gov/laws-regulations/summary-clean-water-act

*Towler, G.P. and Sinnot, R. (2012). ''Chemical Engineering Design: Principles, Practice and Economics of Plant and Process Design.'' Elsevier.

*Turton R.; Bailie, R.C.; Whiting, W.B.; Shaeiwitz J.A.; Bhattacharyya D. (2012). ''Analysis, Synthesis, and Design of Chemical Processes.'' Upper Saddle River: Prentice Hall.

Utility systems

2016-02-05T20:36:29Z

Taunins: /* Hot Utility Efficiency */

Authors: David Chen, [2014] Joshua Lee, [2015] Brett Sleyster, [2016] and Tom Aunins, [2016] 

Stewards: David Chen, Jian Gong, and Fengqi You

Date Presented: January 13, 2014 /Date Revised: January 14, 2014

 


__TOC__

=Introduction=
Many chemical processes do not take place at ambient temperature or pressures. In order to reach these non-ambient conditions, utilities will have to be used to raise or lower temperatures and compress gases. (Towler, Towler/UOP) Utilities often contribute 5 to 10% of the price of a product, and may come from public or private utility companies or on-site plants. For purchased utilities, costs depend on consumption, while for company-owned utilities, there will be both capital and operating costs. They include things such as steam for heating, electricity, cooling water, refrigeration, fuels such as natural gas, wastewater treatment, waste disposal, and landfill. Steam is often the largest utility cost. Cogeneration unit can supply electricity accompanied with different steam pressures. (Seider 2009)

=Electricity=

Electricity is used to power many different kinds of equipment. It has many advantages: it is efficient (> 90%), reliable, available in a wide range of power, shaft speeds, designs, lifetimes, convenience, costs, and maintenance. It is generally used up to 200 hp, and sometimes over 10,000 Hp. In chemical process plants, the electricity demand is generally determined by the work or energy required for compression, pumping, air cooling, lights, and many other items. This electricity often times is purchased from local electricity providers, but many plants generate their own electricity via sophisticated processes.

Electricity is rarely used as a primary heat utility in large-scale chemical plants for a variety of reasons. The main disadvantages of using electricity as a heat utility are as follows (Towler 2012):

:*Heat from electricity is two to three times more expensive than heat from fuels. This is attributed to the lack of efficiency when creating heat from electricity.

:*Electrical heating units are expensive, require high maintenance, and must comply with strict safety regulations.

:*Electrical heating units are unsafe compared to steam heating units. In steam systems, the physically steam controls the temperature, whereas in electrical heating units temperature is controlled by temperature controllers, which can fail or burn out.

The use of electricity carries with it some hazards depending on the environment. Extra care must be taken when using electrically-powered equipment in areas which may have combustible fluids, vapors, or dust, and where liquids may be present. (Seider 2009 pg 606)

==Conventional Power Station==

In general, most electricity is generated from a conventional coal-fired process, whether it be on-site or purchased from a provider. Coal-fired processes have been used to create electricity throughout history, and technological advances have increased its efficiency and use worldwide. In a coal-fired steam station—much like a nuclear station—water is turned into steam, which in turn drives turbine generators to produce electricity. There are several variations on how to create energy from coal, but here are the basics of how a coal-fired process works:

[[File:coalfired.png|thumb|border|center|middle|upright=4|link=|atl=|General Coal-Fired Process Diagram (Duke Energy Company)]]

*Heat is created:
::Before the coal is burned, it is pulverized to the fineness of talcum powder. It is then mixed with hot air and blown into the firebox of the boiler. Burning in suspension, the coal/air mixture provides the most complete combustion and maximum heat possible.

*Water turns to steam:
::Highly purified water, pumped through pipes inside the boiler, is turned into steam by the heat. The steam reaches temperatures of up to 1,000 degrees Fahrenheit and pressures up to 3,500 pounds per square inch, and is piped to the turbine.

*Steam turns the turbine:
::The enormous pressure of the steam pushing against a series of giant turbine blades turns the turbine shaft. The turbine shaft is connected to the shaft of the generator, where magnets spin within wire coils to produce electricity.

*Steam is converted back to water:
::After doing its work in the turbine, the steam is drawn into a condenser, a large chamber in the basement of the power plant. In this important step, millions of gallons of cool water from a nearby source (such as a river or lake) are pumped through a network of tubes running through the condenser. The cool water in the tubes converts the steam back into water that can be used over and over again in the plant.

*Repeat:
::The cooling water is returned to its source without any contamination, and the steam water is returned to the boiler to repeat the cycle.

===Advantages & Disadvantages of Coal-Fired Energy Production===

[[File:coalfiredtable.png|thumb|border|center|middle|upright=4|link=|atl=|Advantages and Disadvantages of Coal-Fired Processes (Seider 2008)]]

==Gas-Turbine Cogeneration Process==

When generating energy on-site, many plants use a gas-turbine cogeneration process. The thermal efficiency of a gas-turbine process is in the range of 70-80% while conventional power stations, such as coal-fired processes, have a 30-40% efficiency. The lower efficiency in more conventional power stations is attributed to wasted heat in the exhaust steam in the condenser. One example of a gas-turbine process is outlined in the following figure. Figure 3.1 is a gas-turbine cogeneration process with a heat recovery steam generator (waste-heat) boiler.

[[File:cogeneration.png|thumb|border|center|middle|upright=4|link=|atl=|Gas-Turbine Cogeneration with a heat recovery steam generator boiler (Towler 2012 Fig 3.1)]]

Overall, the process illustrated is not much different from a coal-fired process. The main differences are that the cogeneration process creates both electricity and a heat utility, and cogeneration processes use natural gas instead of coal. Many of the advantages and disadvantages are similar to those of the coal-fired process, but the cogeneration has a much higher efficiency, creates heat to be used in another process, and uses a more volatile and expensive fuel. The main advantage of cogeneration over coal-fired energy production is that heat is not wasted. In coal-fired processes, heat is released and wasted during electricity generation. Cogeneration captures some, if not all of the byproduct for heat, which is an extremely useful utility that will be discussed in subsequent sections. In summary, the cogeneration plant is superior to the coal-fired process because of its higher efficiency and ability to create a useful heat utility.

Obviously any engineer would design the cogeneration plant to meet at least the energy requirement necessary for plant operation, but cogeneration plants often times are designed to exceed the plant electricity requirement to drive another source of capital. Many describe this scenario as a "make or buy" scenario (Towler 2012). This scenario provides chemical producers leverage when negotiating contracts with outsourced electricity providers and this allows plants to purchase electricity at a wholesale price. This is a huge advantage of considering on-site electricity production because electricity is needed in relatively high quantities for all chemical plants. Being able to minimize electricity costs, or even profit off of electricity production is a huge economical consideration that all plants employ.

=Process Heating=
The key objective of this section is to discuss how processes are heated. Heating utilities are necessary for proper usage of distillers, reactors, condensers, and several other integral types of equipment. More specifically, steam, fired heat, and hot oil/specialized heat transfer fluids will be discussed in the following subsections.

==Steam==
Steam is the most commonly used heat utility used in chemical plants, and as a result understanding how it is used is essential in the study of Utility systems. Steam is used both as a process fluid (feedstock, diluent to absorb heat of reaction, heating agent, and stripping agent in absorbers and adsorbers ) and utility. It can be used to drive pumps and compressors, ejectors (for producing a vacuum), and heat exchangers. As one can clearly see, steam is a versatile, and useful utility.

Here are a few advantages of using steam as opposed to other methods of process heating (Towler 2012):

:*By controlling the pressure of the steam, one can control the temperature at which the heat is released. Having a strong control over the temperature is essential in several processes. =
:*Steam is an efficient heat source because the heat of condensation of steam is very high. Meaning that there is is high output per mass of utility at a constant temperature.
:*Heat exchangers that use steam are relatively cheap because condensing steam has a high heat transfer coefficient.
:*Steam is nonflammable, nontoxic, and inert to several process fluids.

Chemical plants generally have a network of pipelines exclusively for providing steam. These networks generally have steam at a low pressure, a medium pressure, and a high pressure. The image below illustrates a basic steam system.

[[File:Steam.png|thumb|border|center|middle|upright=4|link=|atl=|(Towler 2012 Fig 3.2)]]

In the diagram above, boiler feed water at a high pressure is preheated and fed to other boilers. These other boilers superheat the steam to create a high pressure and high temperature steam stream. The steam is superheated past the dew point to account for heat loss in the pipelines. A portion of the high pressure steam is used for process heating in areas of the plant that require high temperatures. The rest of the high pressure steam is turned into medium pressure steam by valves and steam turbines. The medium pressure steam is then used to heat medium temperature processes and to form low pressure steam. The low pressure steam can be used to heat low pressure processes and it can be expanded in condensing turbines to create shaft work and energy. In summary, steam can be used for an innumerable amount of action items in a plant. High pressure, medium pressure, and low pressure steam can all be used as a heat source. Low pressure steam has utilities in creating electricity and it also has several other uses.

==Fired Heat==

In many cases, processes in a plant require a heat source stronger than high pressure and temperature steam. That is when fired heat is used, which is generally at temperatures above 523K. Streams can be heated directly in the furnace tubes or via a hot oil circuit or heat transfer fluid, which will be discussed in detail in the next section. Most fired heaters use natural gas as fuel because it burns cleaner than fuel oil. A cleaner burning fuel is always advantageous due to environmental and safety concerns. Furthermore, natural gases usually result in less wear and tear in burners and fuel lines.

Depending on the application of the fired-heater, different design specifications can be implemented to make the fired-heater as efficient as possible. The basic construction of a fired heater starts with a cylindrical chamber that is lined with with refractory bricks. The stream that is to be heated flows through tubes inside of the furnace. These tubes can be arranged in several different arrangements such as, around the walls of the furnace, or in horizontal or vertical banks (Towler 2012). The figure below illustrates the basic construction of the fired-heater and varying tube arrangements.

[[File:firedheater.png|thumb|border|center|middle|upright=4|link=|atl=|Basic Fired-Heater Diagrams (Towler 2012 Figure 19.66)]]

Fuel is burned to heat the entire furnace, and the heat transfer occurs from the combustion gases inside of the furnace across the tubes that are filled with our desired stream. The heat transfer between the tubes and the furnace is accomplished primarily via radiation. Modern designs take advantage of convective heat transfer by adding a smaller section on top of the fired-heater where the combustion gases flow over banks of tubes as seen in (c) in the figure above. Heat transfer can be further improved via convection by adding fins or pins in the combustion section.

The cost of fired heat can be calculated by the cost of fuel fired. Natural gas and heating oil are traded as commodities and prices can be found at many online trading sites or business news sites (i.e., www.cnn.money.com). Past historic prices for forecasting can be found in the Oil and Gas Journal or from the U.S. Energy Information Adminstration (www.eia.gov).

===Fuels===
Fuel is burned in utility facilities such as boilers, electricity generation, and cogeneration, and can be in solid, liquid, or gas form. It can also be burned to provide heating for a process or stream or to drive pumps and compressors. The fuel is usually burned with excess air to ensure complete combustion.

A way of quantifying the amount of heat generated is by using the heating values. Higher heating value (HHV) and the lower heating value (LHV) are used. The heating is the total heat evolved by complete combustion of a fuel with dry air with both at 60 ⁰F and the flue gas after combustion brought back down to ⁰F. If the water vapor in the flue gas is not condensed, we obtain the LHV. If the water vapor is condensed, the value of heat evolved is a bit higher, and this is the HHV.
Heating values for solids and liquids are usually on a per-mass basis, and gases on a per-volume basis.
A specified amount of heating cannot be met with the amount of fuel calculated using only the HHV. There will be heat losses, the flue gas temperature will be greater than 60 ⁰F, and water in the flue gas will typically be vapor. (Seider 608)

==Hot Oil/Specialized Heat Transfer Fluids==

Specialized heat transfer fluids and hot oil circuits are used as heat sources when steam and fired heat is not appropriate. Specialized heat transfer fluids and hot oil circuits are extremely versatile in that they can be used in the temperature range of 323K to 673K. This range however is quite variable. For hot oils, the upper temperature limit is gauged based off of the thermal decomposition of the oil and coking/fouling of heat exchanger tubes.

Hot oil circuit systems are most commonly used when the plant has several small temperature heating requirements because it is more economically sound. Rather than having several fired heaters heat each small temperature requirement, it is much more economical to have one fired heater heat the hot oil and circulate that oil through each of the process to meet all of the heat needs. Hot oil systems are also generally favored over high pressure steam in processes that involve high pressure differentials between the process stream and high pressure steam. Hot oil systems are favored in this scenario because of safety concerns. If the steam were to leak, the pressure drop could cause serious safety issues.

Mineral oils are the most commonly used heat transfer fluids, and one prominent example is Dowtherm A. Dowtherm A is a combination of 26.5 wt% diphenyl in diphenyl oxide (Towler 2012) and is extremely thermally stable. These mineral oil systems generally require high flow rates.

=Process Cooling=

==Cooling Water==
Cooling water is used to cool and/or condense streams. Cooling water is usually circulated between process heat exchangers and a cooling tower. Water is cooled during downward motion by contact with air blown upwards, which can bring the water temperature to come within ~ 5 ⁰F of air’s wet-bulb temperature.Approximately 80% of the temperature reduction is due to evaporation of the cooling water and heat transfer to the surrounding air. Water can also be cooled in spray ponds and cooling ponds. Both work by providing high area for water to exchange heat with air.
Water in cooling towers is lost through drift and blowdown, and makeup is usually 1.5 to 3% of the circulating rate.
If a large natural body of water is nearby, it can be used as a source of cooling water and discharged downstream. This water is usually filtered to remove salts and impurities that may lead to fouling, but it is not treated.

==Refrigeration==
Cooling water can usually be used to cool a stream to ~ 100 ⁰F. Air can only cool to ~ 120 ⁰F. Air may be used in places where water is scarce or more costly to transport. To cool or condense streams below 100 ⁰F, a refrigerant is typically used. Chilled brine can also be used, but is less common.

Until 1995, CFC Freon R-12 (dichlorodifuloromethane) and HCFC Freon R-22 (chlorodifuloromethane) were commonly used refrigerants. However, the chlorine atom in the molecules caused the depletion of the ozone layer. The U.S. Clean Air Act Amendments of 1990 went into effect in 1995, and the production of these refrigerants has since stopped or been greatly reduced.

Cost estimates are based on ton-day of refrigeration, where a ton is the heat that needs to be removed to freeze 1 ton per day of water at 32 ⁰F. Substitutes have since been developed. R-134a is often used in place of R-12. According to the EPA, R-134a is not combustible at ambient conditions, and is essentially non-toxic under 400 ppm, and is not ozone-depleting. (Seider pg 607)

=Energy Efficiency=
One of the chief concerns in selecting and designing process utility systems for heating and cooling is how to achieve the most energy efficient design. The energy efficiency of a plant will depend primarily on the heating method that is being used and the overall system design itself, as these two parameters are important in determining how well energy is transferred to the desired media as well as how well that energy is recovered and recycled.

==Utility Method Efficiency==
As mentioned above, the most commonly used utilities for process heating in large scale processes are steam, fired heat, and hot oil heaters. Of these, steam is the most commonly used. Electricity, while efficient at creating power, is not a viable source of heat in large industrial processes. Common ranges of heating efficiency for these three methods are displayed in Table 1. (Towler and Sinnott, 2012)

{| class="wikitable"
|+Table 1: Process Heating Efficiencies
|-
! Process Heating Method
! Typical Efficiency
|-
| Steam (via package boiler)
| 80-90%
|-
| Fired Heat w/ Convective Section
| 85%
|-
| Fired Heat w/o Convective Section
| 60%
|-
| Hot Oil Heaters/Vaporizers
| 80-85%
|}

=Process water and boiler-feed water=
Process water is water that will be directly used in the process. Boiler-feed water (BFW) is used to produce steam. Both may need to be purified to prevent impurities from contaminating a process or from foul equipment. It can be used as a cooling stream when the temperature of the stream to be cooled is greater than ~300 ⁰F. Cost of BFW can be partially offset by the steam credit.

Process water that undergoes moderate pretreatment can cost ~ $0.75/1,000 gal.

Extensive treatment ~ $6.00/1,000 gal.

Sterilized for pharmaceutical processes ~ $550/1,000 gal. (Seider pg 608)

=Demineralized Water=
In demineralized water, minerals have been removed by ion exchange. In boiler feed water, this is to prevent salt deposition, corrosion, formation of foam, and sluicing. In process water, the ions may contaminate the process.

=Waste Treatment=
Most chemical processes will produce some sort of waste. Disposal occurs to the atmosphere (in the case of some gases), sewers, body of water, or a landfill. Waste may require some treatment before disposal to meet regulations. Depending on process economics, byproducts may be recovered and processed. (Seider 2009 pg 609)

==Wastewater Treatment==
(Seider 2009 pg 609)

==Air-Pollution Management==
'''Introduction'''
In the United States air pollution is regulated in the Clean Air Act, and almost all pollutant emitting plants are regulated under this law. The types of plants that can release significant emissions include petroleum refineries, sulfur recovery plants, carbon-black plants, fuel conversion plants, chemical process plants, fossil fuel plants, and petroleum storage and transfer facilities. To receive permission to construct a plant must undergo a review to show that it will not cause a violation of the Ambient Air Quality Standards(Peters, 2003).

'''Methods'''
There are two major types of pollutants that are released into the air, particulates and and gaseous pollutants. Particulates can be removed with mechanical forces while gaseous pollutants typically need to removed by chemical or physical means (Peters, 2003).

Particulates and volatile pollutants that need to be removed before disposal may be present. Particle removal equipment includes: cyclones, wet scrubbers, electrostatic precipitators, and fabric-filter systems.(Seider 2009 pg 609). The two charts below are from ''Plant Design and Economics for Chemical Engineers'' and show the types of equipment, separation methods, and particle sizes in different pollutant separation technologies (Peters, 1991).

[[File:AirPolChart.png|thumb|border|center|middle|upright=4|link=|atl=|]]

[[File:AirPolTable.png|thumb|border|center|middle|upright=4|link=|atl=|]]

Methods for removing inorganic and organic gaseous pollutants include: absorption, adsorption, condensation, and combustion (Seider 2009 pg 609). A typical of gases and their sources from ''Plant Design and Economics for Chemical Engineers'' is shown below (Peters, 1991).

[[File:GaseousPollutants.png|thumb|border|center|middle|upright=4|link=|atl=|]]

Typically Gas-liquid absorption processes are done completed in a vertical, countercurrent, flow through packed, plate, or spray towers. These systems require good liquid-gas contact and proper equipment. These systems also often have significant energy consumption because of large pressure drops (Peters, 2003). Dry adsorbents can be used to remove the last races of gaseous pollutants. Adsorption typically requires blowers, condensers, separators, and controls. You also typically need two packed beds so that one can be used while the other is regenerated. Examples of adsorbents are molecular sieves and activated carbon. Incineration is typically used when there are gas streams that have no recovery value. This can be done with direct flame or catalytic oxidation. Catalytic oxidation usually has higher capital costs, but lower operating costs because it does not require fuel.

'''Outcome'''
The United States implemented the Clean Air Act in 1970 and since then emissions in the U.S. have been drastically reduced.

==Solid Waste==
U.S. federal regulations require that solid waste be classified as hazardous or nonhazardous. Conditions for a classification of hazardous include: ignitability, corrosivity, reactivity, toxicity, or posing a substantial threat to the surrounding environment and its inhabitants. Hazardous waste must be treated on- or near-site before being removed in containers. Non-hazardous waste may be landfilled or incinerated in some cases. A typical estimate of costs for waste disposal is $0.03/lb for nonhazardous solids and $0.10/lb for hazardous solids. (Seider 2009 pg 609)

=Conclusions=

=References=

*L.T. Biegler, I.E. Grossmann, A.W. Westerberg, Systematic Methods of Chemical Process Design, Prentice-Hall: Upper Saddle River, 1997.

* Seider; Seader; Lewin; Widagdo. (2009). ''Plant Design and Economics for Chemical Engineers, 5th Edition.'' Hoboken: Wiley.

*Seider; Seader; Lewin. (2008). "Product and Process Design Principles, 2nd Edition." Hoboken: Wiley.

* Towler, G.P. and Sinnot, R. (2012). ''Chemical Engineering Design: Principles, Practice and Economics of Plant and Process Design.'' Elsevier.

* Turton R.; Bailie, R.C.; Whiting, W.B.; Shaeiwitz J.A.; Bhattacharyya D. (2012). ''Analysis, Synthesis, and Design of Chemical Processes.'' Upper Saddle River: Prentice Hall.

*Duke Energy Company (2013). "How Do Coal Fired Plants Work?" Charlotte: Duke Energy.

Utility systems

2016-02-05T00:53:40Z

Taunins:

Authors: David Chen, [2014] Joshua Lee, [2015] Brett Sleyster, [2016] and Tom Aunins, [2016] 

Stewards: David Chen, Jian Gong, and Fengqi You

Date Presented: January 13, 2014 /Date Revised: January 14, 2014

 


__TOC__

=Introduction=
Many chemical processes do not take place at ambient temperature or pressures. In order to reach these non-ambient conditions, utilities will have to be used to raise or lower temperatures and compress gases. (Towler, Towler/UOP) Utilities often contribute 5 to 10% of the price of a product, and may come from public or private utility companies or on-site plants. For purchased utilities, costs depend on consumption, while for company-owned utilities, there will be both capital and operating costs. They include things such as steam for heating, electricity, cooling water, refrigeration, fuels such as natural gas, wastewater treatment, waste disposal, and landfill. Steam is often the largest utility cost. Cogeneration unit can supply electricity accompanied with different steam pressures. (Seider 2009)

=Electricity=

Electricity is used to power many different kinds of equipment. It has many advantages: it is efficient (> 90%), reliable, available in a wide range of power, shaft speeds, designs, lifetimes, convenience, costs, and maintenance. It is generally used up to 200 hp, and sometimes over 10,000 Hp. In chemical process plants, the electricity demand is generally determined by the work or energy required for compression, pumping, air cooling, lights, and many other items. This electricity often times is purchased from local electricity providers, but many plants generate their own electricity via sophisticated processes.

Electricity is rarely used as a primary heat utility in large-scale chemical plants for a variety of reasons. The main disadvantages of using electricity as a heat utility are as follows (Towler 2012):

:*Heat from electricity is two to three times more expensive than heat from fuels. This is attributed to the lack of efficiency when creating heat from electricity.

:*Electrical heating units are expensive, require high maintenance, and must comply with strict safety regulations.

:*Electrical heating units are unsafe compared to steam heating units. In steam systems, the physically steam controls the temperature, whereas in electrical heating units temperature is controlled by temperature controllers, which can fail or burn out.

The use of electricity carries with it some hazards depending on the environment. Extra care must be taken when using electrically-powered equipment in areas which may have combustible fluids, vapors, or dust, and where liquids may be present. (Seider 2009 pg 606)

==Conventional Power Station==

In general, most electricity is generated from a conventional coal-fired process, whether it be on-site or purchased from a provider. Coal-fired processes have been used to create electricity throughout history, and technological advances have increased its efficiency and use worldwide. In a coal-fired steam station—much like a nuclear station—water is turned into steam, which in turn drives turbine generators to produce electricity. There are several variations on how to create energy from coal, but here are the basics of how a coal-fired process works:

[[File:coalfired.png|thumb|border|center|middle|upright=4|link=|atl=|General Coal-Fired Process Diagram (Duke Energy Company)]]

*Heat is created:
::Before the coal is burned, it is pulverized to the fineness of talcum powder. It is then mixed with hot air and blown into the firebox of the boiler. Burning in suspension, the coal/air mixture provides the most complete combustion and maximum heat possible.

*Water turns to steam:
::Highly purified water, pumped through pipes inside the boiler, is turned into steam by the heat. The steam reaches temperatures of up to 1,000 degrees Fahrenheit and pressures up to 3,500 pounds per square inch, and is piped to the turbine.

*Steam turns the turbine:
::The enormous pressure of the steam pushing against a series of giant turbine blades turns the turbine shaft. The turbine shaft is connected to the shaft of the generator, where magnets spin within wire coils to produce electricity.

*Steam is converted back to water:
::After doing its work in the turbine, the steam is drawn into a condenser, a large chamber in the basement of the power plant. In this important step, millions of gallons of cool water from a nearby source (such as a river or lake) are pumped through a network of tubes running through the condenser. The cool water in the tubes converts the steam back into water that can be used over and over again in the plant.

*Repeat:
::The cooling water is returned to its source without any contamination, and the steam water is returned to the boiler to repeat the cycle.

===Advantages & Disadvantages of Coal-Fired Energy Production===

[[File:coalfiredtable.png|thumb|border|center|middle|upright=4|link=|atl=|Advantages and Disadvantages of Coal-Fired Processes (Seider 2008)]]

==Gas-Turbine Cogeneration Process==

When generating energy on-site, many plants use a gas-turbine cogeneration process. The thermal efficiency of a gas-turbine process is in the range of 70-80% while conventional power stations, such as coal-fired processes, have a 30-40% efficiency. The lower efficiency in more conventional power stations is attributed to wasted heat in the exhaust steam in the condenser. One example of a gas-turbine process is outlined in the following figure. Figure 3.1 is a gas-turbine cogeneration process with a heat recovery steam generator (waste-heat) boiler.

[[File:cogeneration.png|thumb|border|center|middle|upright=4|link=|atl=|Gas-Turbine Cogeneration with a heat recovery steam generator boiler (Towler 2012 Fig 3.1)]]

Overall, the process illustrated is not much different from a coal-fired process. The main differences are that the cogeneration process creates both electricity and a heat utility, and cogeneration processes use natural gas instead of coal. Many of the advantages and disadvantages are similar to those of the coal-fired process, but the cogeneration has a much higher efficiency, creates heat to be used in another process, and uses a more volatile and expensive fuel. The main advantage of cogeneration over coal-fired energy production is that heat is not wasted. In coal-fired processes, heat is released and wasted during electricity generation. Cogeneration captures some, if not all of the byproduct for heat, which is an extremely useful utility that will be discussed in subsequent sections. In summary, the cogeneration plant is superior to the coal-fired process because of its higher efficiency and ability to create a useful heat utility.

Obviously any engineer would design the cogeneration plant to meet at least the energy requirement necessary for plant operation, but cogeneration plants often times are designed to exceed the plant electricity requirement to drive another source of capital. Many describe this scenario as a "make or buy" scenario (Towler 2012). This scenario provides chemical producers leverage when negotiating contracts with outsourced electricity providers and this allows plants to purchase electricity at a wholesale price. This is a huge advantage of considering on-site electricity production because electricity is needed in relatively high quantities for all chemical plants. Being able to minimize electricity costs, or even profit off of electricity production is a huge economical consideration that all plants employ.

=Process Heating=
The key objective of this section is to discuss how processes are heated. Heating utilities are necessary for proper usage of distillers, reactors, condensers, and several other integral types of equipment. More specifically, steam, fired heat, and hot oil/specialized heat transfer fluids will be discussed in the following subsections.

==Steam==
Steam is the most commonly used heat utility used in chemical plants, and as a result understanding how it is used is essential in the study of Utility systems. Steam is used both as a process fluid (feedstock, diluent to absorb heat of reaction, heating agent, and stripping agent in absorbers and adsorbers ) and utility. It can be used to drive pumps and compressors, ejectors (for producing a vacuum), and heat exchangers. As one can clearly see, steam is a versatile, and useful utility.

Here are a few advantages of using steam as opposed to other methods of process heating (Towler 2012):

:*By controlling the pressure of the steam, one can control the temperature at which the heat is released. Having a strong control over the temperature is essential in several processes. =
:*Steam is an efficient heat source because the heat of condensation of steam is very high. Meaning that there is is high output per mass of utility at a constant temperature.
:*Heat exchangers that use steam are relatively cheap because condensing steam has a high heat transfer coefficient.
:*Steam is nonflammable, nontoxic, and inert to several process fluids.

Chemical plants generally have a network of pipelines exclusively for providing steam. These networks generally have steam at a low pressure, a medium pressure, and a high pressure. The image below illustrates a basic steam system.

[[File:Steam.png|thumb|border|center|middle|upright=4|link=|atl=|(Towler 2012 Fig 3.2)]]

In the diagram above, boiler feed water at a high pressure is preheated and fed to other boilers. These other boilers superheat the steam to create a high pressure and high temperature steam stream. The steam is superheated past the dew point to account for heat loss in the pipelines. A portion of the high pressure steam is used for process heating in areas of the plant that require high temperatures. The rest of the high pressure steam is turned into medium pressure steam by valves and steam turbines. The medium pressure steam is then used to heat medium temperature processes and to form low pressure steam. The low pressure steam can be used to heat low pressure processes and it can be expanded in condensing turbines to create shaft work and energy. In summary, steam can be used for an innumerable amount of action items in a plant. High pressure, medium pressure, and low pressure steam can all be used as a heat source. Low pressure steam has utilities in creating electricity and it also has several other uses.

==Fired Heat==

In many cases, processes in a plant require a heat source stronger than high pressure and temperature steam. That is when fired heat is used, which is generally at temperatures above 523K. Streams can be heated directly in the furnace tubes or via a hot oil circuit or heat transfer fluid, which will be discussed in detail in the next section. Most fired heaters use natural gas as fuel because it burns cleaner than fuel oil. A cleaner burning fuel is always advantageous due to environmental and safety concerns. Furthermore, natural gases usually result in less wear and tear in burners and fuel lines.

Depending on the application of the fired-heater, different design specifications can be implemented to make the fired-heater as efficient as possible. The basic construction of a fired heater starts with a cylindrical chamber that is lined with with refractory bricks. The stream that is to be heated flows through tubes inside of the furnace. These tubes can be arranged in several different arrangements such as, around the walls of the furnace, or in horizontal or vertical banks (Towler 2012). The figure below illustrates the basic construction of the fired-heater and varying tube arrangements.

[[File:firedheater.png|thumb|border|center|middle|upright=4|link=|atl=|Basic Fired-Heater Diagrams (Towler 2012 Figure 19.66)]]

Fuel is burned to heat the entire furnace, and the heat transfer occurs from the combustion gases inside of the furnace across the tubes that are filled with our desired stream. The heat transfer between the tubes and the furnace is accomplished primarily via radiation. Modern designs take advantage of convective heat transfer by adding a smaller section on top of the fired-heater where the combustion gases flow over banks of tubes as seen in (c) in the figure above. Heat transfer can be further improved via convection by adding fins or pins in the combustion section.

The cost of fired heat can be calculated by the cost of fuel fired. Natural gas and heating oil are traded as commodities and prices can be found at many online trading sites or business news sites (i.e., www.cnn.money.com). Past historic prices for forecasting can be found in the Oil and Gas Journal or from the U.S. Energy Information Adminstration (www.eia.gov).

===Fuels===
Fuel is burned in utility facilities such as boilers, electricity generation, and cogeneration, and can be in solid, liquid, or gas form. It can also be burned to provide heating for a process or stream or to drive pumps and compressors. The fuel is usually burned with excess air to ensure complete combustion.

A way of quantifying the amount of heat generated is by using the heating values. Higher heating value (HHV) and the lower heating value (LHV) are used. The heating is the total heat evolved by complete combustion of a fuel with dry air with both at 60 ⁰F and the flue gas after combustion brought back down to ⁰F. If the water vapor in the flue gas is not condensed, we obtain the LHV. If the water vapor is condensed, the value of heat evolved is a bit higher, and this is the HHV.
Heating values for solids and liquids are usually on a per-mass basis, and gases on a per-volume basis.
A specified amount of heating cannot be met with the amount of fuel calculated using only the HHV. There will be heat losses, the flue gas temperature will be greater than 60 ⁰F, and water in the flue gas will typically be vapor. (Seider 608)

==Hot Oil/Specialized Heat Transfer Fluids==

Specialized heat transfer fluids and hot oil circuits are used as heat sources when steam and fired heat is not appropriate. Specialized heat transfer fluids and hot oil circuits are extremely versatile in that they can be used in the temperature range of 323K to 673K. This range however is quite variable. For hot oils, the upper temperature limit is gauged based off of the thermal decomposition of the oil and coking/fouling of heat exchanger tubes.

Hot oil circuit systems are most commonly used when the plant has several small temperature heating requirements because it is more economically sound. Rather than having several fired heaters heat each small temperature requirement, it is much more economical to have one fired heater heat the hot oil and circulate that oil through each of the process to meet all of the heat needs. Hot oil systems are also generally favored over high pressure steam in processes that involve high pressure differentials between the process stream and high pressure steam. Hot oil systems are favored in this scenario because of safety concerns. If the steam were to leak, the pressure drop could cause serious safety issues.

Mineral oils are the most commonly used heat transfer fluids, and one prominent example is Dowtherm A. Dowtherm A is a combination of 26.5 wt% diphenyl in diphenyl oxide (Towler 2012) and is extremely thermally stable. These mineral oil systems generally require high flow rates.

=Process Cooling=

==Cooling Water==
Cooling water is used to cool and/or condense streams. Cooling water is usually circulated between process heat exchangers and a cooling tower. Water is cooled during downward motion by contact with air blown upwards, which can bring the water temperature to come within ~ 5 ⁰F of air’s wet-bulb temperature.Approximately 80% of the temperature reduction is due to evaporation of the cooling water and heat transfer to the surrounding air. Water can also be cooled in spray ponds and cooling ponds. Both work by providing high area for water to exchange heat with air.
Water in cooling towers is lost through drift and blowdown, and makeup is usually 1.5 to 3% of the circulating rate.
If a large natural body of water is nearby, it can be used as a source of cooling water and discharged downstream. This water is usually filtered to remove salts and impurities that may lead to fouling, but it is not treated.

==Refrigeration==
Cooling water can usually be used to cool a stream to ~ 100 ⁰F. Air can only cool to ~ 120 ⁰F. Air may be used in places where water is scarce or more costly to transport. To cool or condense streams below 100 ⁰F, a refrigerant is typically used. Chilled brine can also be used, but is less common.

Until 1995, CFC Freon R-12 (dichlorodifuloromethane) and HCFC Freon R-22 (chlorodifuloromethane) were commonly used refrigerants. However, the chlorine atom in the molecules caused the depletion of the ozone layer. The U.S. Clean Air Act Amendments of 1990 went into effect in 1995, and the production of these refrigerants has since stopped or been greatly reduced.

Cost estimates are based on ton-day of refrigeration, where a ton is the heat that needs to be removed to freeze 1 ton per day of water at 32 ⁰F. Substitutes have since been developed. R-134a is often used in place of R-12. According to the EPA, R-134a is not combustible at ambient conditions, and is essentially non-toxic under 400 ppm, and is not ozone-depleting. (Seider pg 607)

=Energy Efficiency=
One of the chief concerns in selecting and designing process utility systems for heating and cooling is how to achieve the most energy efficient design. The energy efficiency of a plant will depend primarily on the heating method that is being used and the overall system design itself, as these two parameters are important in determining how well energy is transferred to the desired media as well as how well that energy is recovered and recycled.

==Hot Utility Efficiency==
As mentioned above, the most commonly used utilities for process heating in large scale processes are steam, fired heat, and hot oil heaters. Of these, steam is the most commonly used. Electricity, while efficient at creating power, is not a viable source of heat in large industrial processes. Common ranges of heating efficiency for these three methods are displayed in Table 1. (Towler and Sinnott, 2012)

{| class="wikitable"
|+Table 1: Process Heating Efficiencies
|-
! Process Heating Method
! Typical Efficiency
|-
| Steam (via package boiler)
| 80-90%
|-
| Fired Heat w/ Convective Section
| 85%
|-
| Fired Heat w/o Convective Section
| 60%
|-
| Hot Oil Heaters/Vaporizers
| 80-85%
|}

=Process water and boiler-feed water=
Process water is water that will be directly used in the process. Boiler-feed water (BFW) is used to produce steam. Both may need to be purified to prevent impurities from contaminating a process or from foul equipment. It can be used as a cooling stream when the temperature of the stream to be cooled is greater than ~300 ⁰F. Cost of BFW can be partially offset by the steam credit.

Process water that undergoes moderate pretreatment can cost ~ $0.75/1,000 gal.

Extensive treatment ~ $6.00/1,000 gal.

Sterilized for pharmaceutical processes ~ $550/1,000 gal. (Seider pg 608)

=Demineralized Water=
In demineralized water, minerals have been removed by ion exchange. In boiler feed water, this is to prevent salt deposition, corrosion, formation of foam, and sluicing. In process water, the ions may contaminate the process.

=Waste Treatment=
Most chemical processes will produce some sort of waste. Disposal occurs to the atmosphere (in the case of some gases), sewers, body of water, or a landfill. Waste may require some treatment before disposal to meet regulations. Depending on process economics, byproducts may be recovered and processed. (Seider 2009 pg 609)

==Wastewater Treatment==
(Seider 2009 pg 609)

==Air-Pollution Management==
'''Introduction'''
In the United States air pollution is regulated in the Clean Air Act, and almost all pollutant emitting plants are regulated under this law. The types of plants that can release significant emissions include petroleum refineries, sulfur recovery plants, carbon-black plants, fuel conversion plants, chemical process plants, fossil fuel plants, and petroleum storage and transfer facilities. To receive permission to construct a plant must undergo a review to show that it will not cause a violation of the Ambient Air Quality Standards(Peters, 2003).

'''Methods'''
There are two major types of pollutants that are released into the air, particulates and and gaseous pollutants. Particulates can be removed with mechanical forces while gaseous pollutants typically need to removed by chemical or physical means (Peters, 2003).

Particulates and volatile pollutants that need to be removed before disposal may be present. Particle removal equipment includes: cyclones, wet scrubbers, electrostatic precipitators, and fabric-filter systems.(Seider 2009 pg 609). The two charts below are from ''Plant Design and Economics for Chemical Engineers'' and show the types of equipment, separation methods, and particle sizes in different pollutant separation technologies (Peters, 1991).

[[File:AirPolChart.png|thumb|border|center|middle|upright=4|link=|atl=|]]

[[File:AirPolTable.png|thumb|border|center|middle|upright=4|link=|atl=|]]

Methods for removing inorganic and organic gaseous pollutants include: absorption, adsorption, condensation, and combustion (Seider 2009 pg 609). A typical of gases and their sources from ''Plant Design and Economics for Chemical Engineers'' is shown below (Peters, 1991).

[[File:GaseousPollutants.png|thumb|border|center|middle|upright=4|link=|atl=|]]

Typically Gas-liquid absorption processes are done completed in a vertical, countercurrent, flow through packed, plate, or spray towers. These systems require good liquid-gas contact and proper equipment. These systems also often have significant energy consumption because of large pressure drops (Peters, 2003). Dry adsorbents can be used to remove the last races of gaseous pollutants. Adsorption typically requires blowers, condensers, separators, and controls. You also typically need two packed beds so that one can be used while the other is regenerated. Examples of adsorbents are molecular sieves and activated carbon. Incineration is typically used when there are gas streams that have no recovery value. This can be done with direct flame or catalytic oxidation. Catalytic oxidation usually has higher capital costs, but lower operating costs because it does not require fuel.

'''Outcome'''
The United States implemented the Clean Air Act in 1970 and since then emissions in the U.S. have been drastically reduced.

==Solid Waste==
U.S. federal regulations require that solid waste be classified as hazardous or nonhazardous. Conditions for a classification of hazardous include: ignitability, corrosivity, reactivity, toxicity, or posing a substantial threat to the surrounding environment and its inhabitants. Hazardous waste must be treated on- or near-site before being removed in containers. Non-hazardous waste may be landfilled or incinerated in some cases. A typical estimate of costs for waste disposal is $0.03/lb for nonhazardous solids and $0.10/lb for hazardous solids. (Seider 2009 pg 609)

=Conclusions=

=References=

*L.T. Biegler, I.E. Grossmann, A.W. Westerberg, Systematic Methods of Chemical Process Design, Prentice-Hall: Upper Saddle River, 1997.

* Seider; Seader; Lewin; Widagdo. (2009). ''Plant Design and Economics for Chemical Engineers, 5th Edition.'' Hoboken: Wiley.

*Seider; Seader; Lewin. (2008). "Product and Process Design Principles, 2nd Edition." Hoboken: Wiley.

* Towler, G.P. and Sinnot, R. (2012). ''Chemical Engineering Design: Principles, Practice and Economics of Plant and Process Design.'' Elsevier.

* Turton R.; Bailie, R.C.; Whiting, W.B.; Shaeiwitz J.A.; Bhattacharyya D. (2012). ''Analysis, Synthesis, and Design of Chemical Processes.'' Upper Saddle River: Prentice Hall.

*Duke Energy Company (2013). "How Do Coal Fired Plants Work?" Charlotte: Duke Energy.

Utility systems

2016-02-05T00:01:34Z

Taunins:

Authors: David Chen, [2014] Joshua Lee, [2015] Brett Sleyster, [2016] and Tom Aunins, [2016] 

Stewards: David Chen, Jian Gong, and Fengqi You

Date Presented: January 13, 2014 /Date Revised: January 14, 2014

 


__TOC__

=Introduction=
Many chemical processes do not take place at ambient temperature or pressures. In order to reach these non-ambient conditions, utilities will have to be used to raise or lower temperatures and compress gases. (Towler, Towler/UOP) Utilities often contribute 5 to 10% of the price of a product, and may come from public or private utility companies or on-site plants. For purchased utilities, costs depend on consumption, while for company-owned utilities, there will be both capital and operating costs. They include things such as steam for heating, electricity, cooling water, refrigeration, fuels such as natural gas, wastewater treatment, waste disposal, and landfill. Steam is often the largest utility cost. Cogeneration unit can supply electricity accompanied with different steam pressures. (Seider 2009)

=Electricity=

Electricity is used to power many different kinds of equipment. It has many advantages: it is efficient (> 90%), reliable, available in a wide range of power, shaft speeds, designs, lifetimes, convenience, costs, and maintenance. It is generally used up to 200 hp, and sometimes over 10,000 Hp. In chemical process plants, the electricity demand is generally determined by the work or energy required for compression, pumping, air cooling, lights, and many other items. This electricity often times is purchased from local electricity providers, but many plants generate their own electricity via sophisticated processes.

Electricity is rarely used as a primary heat utility in large-scale chemical plants for a variety of reasons. The main disadvantages of using electricity as a heat utility are as follows (Towler 2012):

:*Heat from electricity is two to three times more expensive than heat from fuels. This is attributed to the lack of efficiency when creating heat from electricity.

:*Electrical heating units are expensive, require high maintenance, and must comply with strict safety regulations.

:*Electrical heating units are unsafe compared to steam heating units. In steam systems, the physically steam controls the temperature, whereas in electrical heating units temperature is controlled by temperature controllers, which can fail or burn out.

The use of electricity carries with it some hazards depending on the environment. Extra care must be taken when using electrically-powered equipment in areas which may have combustible fluids, vapors, or dust, and where liquids may be present. (Seider 2009 pg 606)

==Conventional Power Station==

In general, most electricity is generated from a conventional coal-fired process, whether it be on-site or purchased from a provider. Coal-fired processes have been used to create electricity throughout history, and technological advances have increased its efficiency and use worldwide. In a coal-fired steam station—much like a nuclear station—water is turned into steam, which in turn drives turbine generators to produce electricity. There are several variations on how to create energy from coal, but here are the basics of how a coal-fired process works:

[[File:coalfired.png|thumb|border|center|middle|upright=4|link=|atl=|General Coal-Fired Process Diagram (Duke Energy Company)]]

*Heat is created:
::Before the coal is burned, it is pulverized to the fineness of talcum powder. It is then mixed with hot air and blown into the firebox of the boiler. Burning in suspension, the coal/air mixture provides the most complete combustion and maximum heat possible.

*Water turns to steam:
::Highly purified water, pumped through pipes inside the boiler, is turned into steam by the heat. The steam reaches temperatures of up to 1,000 degrees Fahrenheit and pressures up to 3,500 pounds per square inch, and is piped to the turbine.

*Steam turns the turbine:
::The enormous pressure of the steam pushing against a series of giant turbine blades turns the turbine shaft. The turbine shaft is connected to the shaft of the generator, where magnets spin within wire coils to produce electricity.

*Steam is converted back to water:
::After doing its work in the turbine, the steam is drawn into a condenser, a large chamber in the basement of the power plant. In this important step, millions of gallons of cool water from a nearby source (such as a river or lake) are pumped through a network of tubes running through the condenser. The cool water in the tubes converts the steam back into water that can be used over and over again in the plant.

*Repeat:
::The cooling water is returned to its source without any contamination, and the steam water is returned to the boiler to repeat the cycle.

===Advantages & Disadvantages of Coal-Fired Energy Production===

[[File:coalfiredtable.png|thumb|border|center|middle|upright=4|link=|atl=|Advantages and Disadvantages of Coal-Fired Processes (Seider 2008)]]

==Gas-Turbine Cogeneration Process==

When generating energy on-site, many plants use a gas-turbine cogeneration process. The thermal efficiency of a gas-turbine process is in the range of 70-80% while conventional power stations, such as coal-fired processes, have a 30-40% efficiency. The lower efficiency in more conventional power stations is attributed to wasted heat in the exhaust steam in the condenser. One example of a gas-turbine process is outlined in the following figure. Figure 3.1 is a gas-turbine cogeneration process with a heat recovery steam generator (waste-heat) boiler.

[[File:cogeneration.png|thumb|border|center|middle|upright=4|link=|atl=|Gas-Turbine Cogeneration with a heat recovery steam generator boiler (Towler 2012 Fig 3.1)]]

Overall, the process illustrated is not much different from a coal-fired process. The main differences are that the cogeneration process creates both electricity and a heat utility, and cogeneration processes use natural gas instead of coal. Many of the advantages and disadvantages are similar to those of the coal-fired process, but the cogeneration has a much higher efficiency, creates heat to be used in another process, and uses a more volatile and expensive fuel. The main advantage of cogeneration over coal-fired energy production is that heat is not wasted. In coal-fired processes, heat is released and wasted during electricity generation. Cogeneration captures some, if not all of the byproduct for heat, which is an extremely useful utility that will be discussed in subsequent sections. In summary, the cogeneration plant is superior to the coal-fired process because of its higher efficiency and ability to create a useful heat utility.

Obviously any engineer would design the cogeneration plant to meet at least the energy requirement necessary for plant operation, but cogeneration plants often times are designed to exceed the plant electricity requirement to drive another source of capital. Many describe this scenario as a "make or buy" scenario (Towler 2012). This scenario provides chemical producers leverage when negotiating contracts with outsourced electricity providers and this allows plants to purchase electricity at a wholesale price. This is a huge advantage of considering on-site electricity production because electricity is needed in relatively high quantities for all chemical plants. Being able to minimize electricity costs, or even profit off of electricity production is a huge economical consideration that all plants employ.

=Process Heating=
The key objective of this section is to discuss how processes are heated. Heating utilities are necessary for proper usage of distillers, reactors, condensers, and several other integral types of equipment. More specifically, steam, fired heat, and hot oil/specialized heat transfer fluids will be discussed in the following subsections.

==Steam==
Steam is the most commonly used heat utility used in chemical plants, and as a result understanding how it is used is essential in the study of Utility systems. Steam is used both as a process fluid (feedstock, diluent to absorb heat of reaction, heating agent, and stripping agent in absorbers and adsorbers ) and utility. It can be used to drive pumps and compressors, ejectors (for producing a vacuum), and heat exchangers. As one can clearly see, steam is a versatile, and useful utility.

Here are a few advantages of using steam as opposed to other methods of process heating (Towler 2012):

:*By controlling the pressure of the steam, one can control the temperature at which the heat is released. Having a strong control over the temperature is essential in several processes. =
:*Steam is an efficient heat source because the heat of condensation of steam is very high. Meaning that there is is high output per mass of utility at a constant temperature.
:*Heat exchangers that use steam are relatively cheap because condensing steam has a high heat transfer coefficient.
:*Steam is nonflammable, nontoxic, and inert to several process fluids.

Chemical plants generally have a network of pipelines exclusively for providing steam. These networks generally have steam at a low pressure, a medium pressure, and a high pressure. The image below illustrates a basic steam system.

[[File:Steam.png|thumb|border|center|middle|upright=4|link=|atl=|(Towler 2012 Fig 3.2)]]

In the diagram above, boiler feed water at a high pressure is preheated and fed to other boilers. These other boilers superheat the steam to create a high pressure and high temperature steam stream. The steam is superheated past the dew point to account for heat loss in the pipelines. A portion of the high pressure steam is used for process heating in areas of the plant that require high temperatures. The rest of the high pressure steam is turned into medium pressure steam by valves and steam turbines. The medium pressure steam is then used to heat medium temperature processes and to form low pressure steam. The low pressure steam can be used to heat low pressure processes and it can be expanded in condensing turbines to create shaft work and energy. In summary, steam can be used for an innumerable amount of action items in a plant. High pressure, medium pressure, and low pressure steam can all be used as a heat source. Low pressure steam has utilities in creating electricity and it also has several other uses.

==Fired Heat==

In many cases, processes in a plant require a heat source stronger than high pressure and temperature steam. That is when fired heat is used, which is generally at temperatures above 523K. Streams can be heated directly in the furnace tubes or via a hot oil circuit or heat transfer fluid, which will be discussed in detail in the next section. Most fired heaters use natural gas as fuel because it burns cleaner than fuel oil. A cleaner burning fuel is always advantageous due to environmental and safety concerns. Furthermore, natural gases usually result in less wear and tear in burners and fuel lines.

Depending on the application of the fired-heater, different design specifications can be implemented to make the fired-heater as efficient as possible. The basic construction of a fired heater starts with a cylindrical chamber that is lined with with refractory bricks. The stream that is to be heated flows through tubes inside of the furnace. These tubes can be arranged in several different arrangements such as, around the walls of the furnace, or in horizontal or vertical banks (Towler 2012). The figure below illustrates the basic construction of the fired-heater and varying tube arrangements.

[[File:firedheater.png|thumb|border|center|middle|upright=4|link=|atl=|Basic Fired-Heater Diagrams (Towler 2012 Figure 19.66)]]

Fuel is burned to heat the entire furnace, and the heat transfer occurs from the combustion gases inside of the furnace across the tubes that are filled with our desired stream. The heat transfer between the tubes and the furnace is accomplished primarily via radiation. Modern designs take advantage of convective heat transfer by adding a smaller section on top of the fired-heater where the combustion gases flow over banks of tubes as seen in (c) in the figure above. Heat transfer can be further improved via convection by adding fins or pins in the combustion section.

The cost of fired heat can be calculated by the cost of fuel fired. Natural gas and heating oil are traded as commodities and prices can be found at many online trading sites or business news sites (i.e., www.cnn.money.com). Past historic prices for forecasting can be found in the Oil and Gas Journal or from the U.S. Energy Information Adminstration (www.eia.gov).

===Fuels===
Fuel is burned in utility facilities such as boilers, electricity generation, and cogeneration, and can be in solid, liquid, or gas form. It can also be burned to provide heating for a process or stream or to drive pumps and compressors. The fuel is usually burned with excess air to ensure complete combustion.

A way of quantifying the amount of heat generated is by using the heating values. Higher heating value (HHV) and the lower heating value (LHV) are used. The heating is the total heat evolved by complete combustion of a fuel with dry air with both at 60 ⁰F and the flue gas after combustion brought back down to ⁰F. If the water vapor in the flue gas is not condensed, we obtain the LHV. If the water vapor is condensed, the value of heat evolved is a bit higher, and this is the HHV.
Heating values for solids and liquids are usually on a per-mass basis, and gases on a per-volume basis.
A specified amount of heating cannot be met with the amount of fuel calculated using only the HHV. There will be heat losses, the flue gas temperature will be greater than 60 ⁰F, and water in the flue gas will typically be vapor. (Seider 608)

==Hot Oil/Specialized Heat Transfer Fluids==

Specialized heat transfer fluids and hot oil circuits are used as heat sources when steam and fired heat is not appropriate. Specialized heat transfer fluids and hot oil circuits are extremely versatile in that they can be used in the temperature range of 323K to 673K. This range however is quite variable. For hot oils, the upper temperature limit is gauged based off of the thermal decomposition of the oil and coking/fouling of heat exchanger tubes.

Hot oil circuit systems are most commonly used when the plant has several small temperature heating requirements because it is more economically sound. Rather than having several fired heaters heat each small temperature requirement, it is much more economical to have one fired heater heat the hot oil and circulate that oil through each of the process to meet all of the heat needs. Hot oil systems are also generally favored over high pressure steam in processes that involve high pressure differentials between the process stream and high pressure steam. Hot oil systems are favored in this scenario because of safety concerns. If the steam were to leak, the pressure drop could cause serious safety issues.

Mineral oils are the most commonly used heat transfer fluids, and one prominent example is Dowtherm A. Dowtherm A is a combination of 26.5 wt% diphenyl in diphenyl oxide (Towler 2012) and is extremely thermally stable. These mineral oil systems generally require high flow rates.

=Process Cooling=

==Cooling Water==
Cooling water is used to cool and/or condense streams. Cooling water is usually circulated between process heat exchangers and a cooling tower. Water is cooled during downward motion by contact with air blown upwards, which can bring the water temperature to come within ~ 5 ⁰F of air’s wet-bulb temperature.Approximately 80% of the temperature reduction is due to evaporation of the cooling water and heat transfer to the surrounding air. Water can also be cooled in spray ponds and cooling ponds. Both work by providing high area for water to exchange heat with air.
Water in cooling towers is lost through drift and blowdown, and makeup is usually 1.5 to 3% of the circulating rate.
If a large natural body of water is nearby, it can be used as a source of cooling water and discharged downstream. This water is usually filtered to remove salts and impurities that may lead to fouling, but it is not treated.

==Refrigeration==
Cooling water can usually be used to cool a stream to ~ 100 ⁰F. Air can only cool to ~ 120 ⁰F. Air may be used in places where water is scarce or more costly to transport. To cool or condense streams below 100 ⁰F, a refrigerant is typically used. Chilled brine can also be used, but is less common.

Until 1995, CFC Freon R-12 (dichlorodifuloromethane) and HCFC Freon R-22 (chlorodifuloromethane) were commonly used refrigerants. However, the chlorine atom in the molecules caused the depletion of the ozone layer. The U.S. Clean Air Act Amendments of 1990 went into effect in 1995, and the production of these refrigerants has since stopped or been greatly reduced.

Cost estimates are based on ton-day of refrigeration, where a ton is the heat that needs to be removed to freeze 1 ton per day of water at 32 ⁰F. Substitutes have since been developed. R-134a is often used in place of R-12. According to the EPA, R-134a is not combustible at ambient conditions, and is essentially non-toxic under 400 ppm, and is not ozone-depleting. (Seider pg 607)

=Process water and boiler-feed water=
Process water is water that will be directly used in the process. Boiler-feed water (BFW) is used to produce steam. Both may need to be purified to prevent impurities from contaminating a process or from foul equipment. It can be used as a cooling stream when the temperature of the stream to be cooled is greater than ~300 ⁰F. Cost of BFW can be partially offset by the steam credit.

Process water that undergoes moderate pretreatment can cost ~ $0.75/1,000 gal.

Extensive treatment ~ $6.00/1,000 gal.

Sterilized for pharmaceutical processes ~ $550/1,000 gal. (Seider pg 608)

=Demineralized Water=
In demineralized water, minerals have been removed by ion exchange. In boiler feed water, this is to prevent salt deposition, corrosion, formation of foam, and sluicing. In process water, the ions may contaminate the process.

=Waste Treatment=
Most chemical processes will produce some sort of waste. Disposal occurs to the atmosphere (in the case of some gases), sewers, body of water, or a landfill. Waste may require some treatment before disposal to meet regulations. Depending on process economics, byproducts may be recovered and processed. (Seider 2009 pg 609)

==Wastewater Treatment==
(Seider 2009 pg 609)

==Air-Pollution Management==
'''Introduction'''
In the United States air pollution is regulated in the Clean Air Act, and almost all pollutant emitting plants are regulated under this law. The types of plants that can release significant emissions include petroleum refineries, sulfur recovery plants, carbon-black plants, fuel conversion plants, chemical process plants, fossil fuel plants, and petroleum storage and transfer facilities. To receive permission to construct a plant must undergo a review to show that it will not cause a violation of the Ambient Air Quality Standards(Peters, 2003).

'''Methods'''
There are two major types of pollutants that are released into the air, particulates and and gaseous pollutants. Particulates can be removed with mechanical forces while gaseous pollutants typically need to removed by chemical or physical means (Peters, 2003).

Particulates and volatile pollutants that need to be removed before disposal may be present. Particle removal equipment includes: cyclones, wet scrubbers, electrostatic precipitators, and fabric-filter systems.(Seider 2009 pg 609). The two charts below are from ''Plant Design and Economics for Chemical Engineers'' and show the types of equipment, separation methods, and particle sizes in different pollutant separation technologies (Peters, 1991).

[[File:AirPolChart.png|thumb|border|center|middle|upright=4|link=|atl=|]]

[[File:AirPolTable.png|thumb|border|center|middle|upright=4|link=|atl=|]]

Methods for removing inorganic and organic gaseous pollutants include: absorption, adsorption, condensation, and combustion (Seider 2009 pg 609). A typical of gases and their sources from ''Plant Design and Economics for Chemical Engineers'' is shown below (Peters, 1991).

[[File:GaseousPollutants.png|thumb|border|center|middle|upright=4|link=|atl=|]]

Typically Gas-liquid absorption processes are done completed in a vertical, countercurrent, flow through packed, plate, or spray towers. These systems require good liquid-gas contact and proper equipment. These systems also often have significant energy consumption because of large pressure drops (Peters, 2003). Dry adsorbents can be used to remove the last races of gaseous pollutants. Adsorption typically requires blowers, condensers, separators, and controls. You also typically need two packed beds so that one can be used while the other is regenerated. Examples of adsorbents are molecular sieves and activated carbon. Incineration is typically used when there are gas streams that have no recovery value. This can be done with direct flame or catalytic oxidation. Catalytic oxidation usually has higher capital costs, but lower operating costs because it does not require fuel.

'''Outcome'''
The United States implemented the Clean Air Act in 1970 and since then emissions in the U.S. have been drastically reduced.

==Solid Waste==
U.S. federal regulations require that solid waste be classified as hazardous or nonhazardous. Conditions for a classification of hazardous include: ignitability, corrosivity, reactivity, toxicity, or posing a substantial threat to the surrounding environment and its inhabitants. Hazardous waste must be treated on- or near-site before being removed in containers. Non-hazardous waste may be landfilled or incinerated in some cases. A typical estimate of costs for waste disposal is $0.03/lb for nonhazardous solids and $0.10/lb for hazardous solids. (Seider 2009 pg 609)

=Conclusions=

=References=

*L.T. Biegler, I.E. Grossmann, A.W. Westerberg, Systematic Methods of Chemical Process Design, Prentice-Hall: Upper Saddle River, 1997.

* Seider; Seader; Lewin; Widagdo. (2009). ''Plant Design and Economics for Chemical Engineers, 5th Edition.'' Hoboken: Wiley.

*Seider; Seader; Lewin. (2008). "Product and Process Design Principles, 2nd Edition." Hoboken: Wiley.

* Towler, G.P. and Sinnot, R. (2012). ''Chemical Engineering Design: Principles, Practice and Economics of Plant and Process Design.'' Elsevier.

* Turton R.; Bailie, R.C.; Whiting, W.B.; Shaeiwitz J.A.; Bhattacharyya D. (2012). ''Analysis, Synthesis, and Design of Chemical Processes.'' Upper Saddle River: Prentice Hall.

*Duke Energy Company (2013). "How Do Coal Fired Plants Work?" Charlotte: Duke Energy.