Kemper County IGCC Project Preliminary Public Design Report

DEPARTMENT OF ENERGY PRELIMINARY PUBLIC DESIGN REPORT

Kemper County IGCCTM Project Preliminary Public Design Report

Report Title: Preliminary Public Design Report Type of Report: Topical Report Reporting Period: Final –End of FEED Effort Authors: Matt Nelson

Randall Rush Diane Madden Tim Pinkston Landon Lunsford

Issue Date: June 30th, 2012 DOE Award No.: DE-FC26-06NT42391 Recipient: Southern Company Services, Inc. 42 Inverness Ctr Pkwy Birmingham, AL 35242


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Report Disclaimer

This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe on privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof.


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ABSTRACT

The Kemper County IGCC Project is an advanced coal technology project that is being developed by Mississippi Power Company (MPC). The project is a lignite-fueled 2-on-1 Integrated Gasification Combined-Cycle (IGCC) facility incorporating the air-blown Transport Integrated Gasification (TRIG™) technology jointly developed by Southern Company; Kellogg, Brown, and Root (KBR); and the United States Department of Energy (DOE) at the Power Systems Development Facility (PSDF) in Wilsonville, Alabama. The estimated nameplate capacity of the plant will be 830 MW with a peak net output capability of 582 MW. As a result of advanced emissions control equipment, the facility will produce marketable byproducts of ammonia, sulfuric acid, and carbon dioxide. 65 percent of the carbon dioxide (CO2) will be captured and used for enhanced oil recovery (EOR), making the Kemper County facility’s carbon emissions comparable to those of a natural-gas-fired combined cycle power plant. The commercial operation date (COD) of the Kemper County IGCC plant will be May 2014. This report describes the basic design and function of the plant as determined at the end of the Front End Engineering Design (FEED) phase of the project.


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CONTENTS Section

1.0 EXECUTIVE SUMMARY AND INTRODUCTION ............................................ 1

Page

1.1 Description of project ................................................................................ 1 1.2 Project Participants ................................................................................... 1 1.3 Current Project Status and Schedule ........................................................ 2 1.4 Technology Development ......................................................................... 3 1.5 Front-End Engineering Design (FEED) ..................................................... 4 1.6 Challenges During FEED .......................................................................... 5

2.0 PROCESS OVERVIEW ................................................................................... 7

2.1 Gasification Island ..................................................................................... 9 2.2 Combined Cycle ...................................................................................... 10 2.3 Balance of Plant ...................................................................................... 11 2.4 Summary of Projected Thermal and Environmental Performance .......... 12

3.0 KEMPER COUNTY IGCC PROJECT SITE ................................................... 14

3.1 Project Site .............................................................................................. 14 3.2 Site Infrastructure .................................................................................... 14

4.0 PROJECT SCHEDULE ................................................................................. 17

4.1 Detailed Engineering Design ................................................................... 17 4.2 Construction ............................................................................................ 19 4.3 Commissioning and Startup .................................................................... 19 4.4 Commercial Operations .......................................................................... 20

5.0 KEMPER COUNTY GASIFICATION ISLAND DESIGN INFORMATION ...... 21

5.1 Plant Design Basis .................................................................................. 21 5.2 Process Description ................................................................................ 28 5.3 Process Flow Diagrams .......................................................................... 44 5.4 Overall Material Balance ......................................................................... 61 5.5 Plant 3D Renderings ............................................................................... 65

APPENDIX A – Equipment List ................................................................................ 69


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1.0 EXECUTIVE SUMMARY AND INTRODUCTION

1.1 DESCRIPTION OF PROJECT

The Kemper County IGCC Project is an advanced coal technology project that is being developed by Mississippi Power Company (MPC). The project is a viable resource alternative to support future load growth, to provide a reliable, diverse fuel supply, and to replace the retirement of aging generation. The project is a lignite-fueled 2-on-1 Integrated Gasification Combined-Cycle (IGCC) facility incorporating the air-blown Transport Integrated Gasification (TRIG™) technology jointly developed by Southern Company; Kellogg, Brown, and Root (KBR); and the United States Department of Energy (DOE) at the Power Systems Development Facility (PSDF) in Wilsonville, Alabama.

Lignite reserves near the plant site, developed and mined by Liberty Fuels, a subsidiary of North American Coal Corporation (NACC), will be the feedstock for the IGCC plant. The estimated nameplate capacity of the plant will be 830 MW with a peak net output capability of 582 MW. The peak capacity of 582 MW occurs while firing syngas in the combustion turbine coupled with natural gas firing in the duct burners. During syngas-only operations, the plant will achieve a net generating capacity of 524 MW and a heat rate of 11,708 Btu/kWh. As a result of advanced emissions control equipment, the facility will produce marketable byproducts of ammonia, sulfuric acid, and carbon dioxide. 65 percent of the carbon dioxide (CO2) will be captured and used for enhanced oil recovery (EOR), making the Kemper County facility’s carbon emissions comparable to those of a natural-gas-fired combined cycle power plant. The commercial operation date (COD) of the Kemper County IGCC plant will be May 2014.

In addition to using lignite in an efficient and environmentally friendly manner, the plant will also assist MPC in achieving key strategic objectives of fuel and geographical diversity, and cost stability, while providing an economic and reliable resource to meet customer needs.

1.2 PROJECT PARTICIPANTS

The major organizations involved in the project are:

1.2.1 Project Owner

MPC, headquartered in Gulfport, Mississippi, is an investor-owned utility and an affiliate of Southern Company. As of December 2008, MPC had 1,254 employees and served 188,837 customers in 23 counties of southeast Mississippi. MPC’s total generating capacity is 3,166 MW; 52 percent coal fueled, 48 percent natural gas fueled. The MPC Generation organization has experience in burning a variety of fossil fuels, including bituminous coal, PRB coal, petroleum coke, and natural gas. The operating performance of MPC and other Southern Company generating units consistently results in forced outage rates that are among the best in the industry.

MPC will be responsible for overall project management during all phases of the project, including control of budgets and schedule. MPC will also obtain all regulatory approvals and perform all environmental permitting and compliance activities necessary to construct and operate the plant.


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1.2.2 Project Contributors

• Southern Company Services (SCS). • NACC. • KBR.

SCS, a Southern Company subsidiary that provides engineering and support services to affiliate operating companies, will be responsible for the engineering and design of the plant. SCS will manage all of the engineering, procurement, and construction (EPC) phases of the project, including EPC budgets and schedules. SCS, as MPC’s agent, will be responsible for designing the combined cycle power block, selected portions of the gasifier island, lignite receiving, storage and handling systems, procurement of equipment, and management of the construction of the facility. SCS will also assist MPC in the environmental permitting process.

The SCS technical staff has considerable practical experience and fundamental understanding of a wide range of coal-based technologies and associated ancillary equipment. This work experience—much of which came from SCS operation of the PSDF—includes many items necessary for managing the project EPC, including, extensive project management, equipment design, plant construction, start-up and commissioning, controls and instrumentation, plant operation and troubleshooting, test planning, data evaluation, reporting, and technical and economic studies.

NACC, through the subsidiary Liberty Fuels, will perform all lignite mining activities. This will include all necessary permits to perform a surface mine operation in Kemper County, Mississippi. NACC has extensive experience in mining lignite and currently is America’s largest miner of lignite, operating six surface mines, including one in Mississippi.

KBR is an international technology-based engineering and construction contractor that has successfully completed more than 5,000 projects in more than 80 countries for more than 1,200 private enterprises and governmental entities. KBR will provide engineering design and procurement assistance for portions of the gasifier island equipment. It will also provide onsite engineers for start-up assistance and to collect comprehensive operational information to enhance future plant designs.

KBR has extensive experience with synthesis gas production and, along with SCS, designed the Transport Gasifier test facility at the PSDF. KBR and Southern Company jointly own the Transport Gasifier technology and have worked together at the PSDF to advance its development, providing process analysis and equipment design services.

1.3 CURRENT PROJECT STATUS AND SCHEDULE

SCS Engineering and Construction Services (E&CS) is responsible for the overall design with support from KBR on the gasification island portion of the facility. The first phase of front-end engineering and design (FEED) was completed on the project in November 2007 prior to changing the design to capture 65 percent of the carbon entering the facility with the lignite. Since that time efforts have been focused on modifying the November 2007 design to incorporate the increased carbon capture case.


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The project was given approval by the Mississippi Public Service Commission (MPSC) and construction began in the summer of 2010. The commercial operation date is planned for May 2014.

1.4 TECHNOLOGY DEVELOPMENT

The largest Transport Gasifier built to date, with a maximum coal-feed rate of 5,500 lb/hr, commenced operation in 1996 at the PSDF near Wilsonville, Alabama. This unit has proven easy to operate and control, achieving 5,000 hours as a combustor and more than 14,600 hours as a gasifier. Both air and oxygen have been used successfully as the gasification oxidant.

SCS has acquired invaluable experience with the Transport Gasification technology from its 15-year involvement in the design, construction, operation, and management of the PSDF. The equipment at the PSDF was sized to provide reliable data for confident scale-up to commercial scale.

The Gasification Technology staff in the E&CS organization has been involved in extensive process design, data evaluation, and cost estimation studies for the TRIG technology for more than 10 years. The focus of this work has been to identify how to lower capital costs and increase cycle efficiency to provide a cost competitive, environmentally superior commercial coal-based power generation technology. FEED has been completed for two separate IGCC projects including the Kemper County IGCC Project.

The Transport Gasifier is a fuel-flexible design with a higher efficiency and lower capital and operating costs than the currently available oxygen-blown entrained flow gasifiers. The TRIG system at Kemper County is designed to achieve high environmental standards for sulfur dioxide (SO2), nitrous oxide (NOX), dust emissions, mercury, and CO2. Analysis based on the extensive design and cost information generated during FEED shows that the economic benefits offered by the air-blown Transport Gasifier relative to other systems, including those that are oxygen-blown, are preserved even when CO2 capture and sequestration are incorporated into the design. Means of reducing water consumption are incorporated into the design and potential gasifier ash utilization applications have been identified.

Testing of the Mississippi lignite at the PSDF has been key to the success of the Kemper County IGCC Project. High-moisture lignite from the Red Hills Mine was successfully gasified in four separate test campaigns for more than 2,300 hours of operation, which provided key design parameters for the gasifier as well as downstream systems.

On lignite, the Transport Gasifier operated smoothly over a range of conditions, confirming the gasifier design for Kemper County. The gasifier was operated at a range of temperatures between 1,700 to 1,820 °F, coal feed rates of between 2,000 to 5,100 lb/hr, and riser velocities from 18 to 28 ft/s. Recycle gas aeration requirements were minimal because of high flowability of the lignite ash. The gasifier carbon conversion was excellent, at more than 97 percent for all conditions tested.

A fluid bed dryer similar to the design chosen for Kemper County was installed at the PSDF to evaluate the reliability and performance of the unit and to verify that low grade heat could be successfully utilized for drying the coal. Prior to the installation of the fluid bed dryer at the PSDF, the existing coal milling and feeding systems could only process coals with a maximum moisture content of 38 weight percent, while the Mississippi lignite can have a moisture content


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of greater than 50 weight percent. The fluid bed dryer at the PSDF processed more than 6,800 tons of as-received lignite from an average moisture content of around 40 weight percent to less than 20 weight percent, a value low enough for reliable milling and feeding as was demonstrated during the test campaigns at the PSDF.

The pressure-decoupled advanced coal feeder (PDAC) and continuous coarse ash depressurization (CCAD) and continuous fine ash depressurization (CFAD) systems operated reliably through the test campaigns. The particulate collection device (PCD) also operated smoothly, and the particulate collection efficiency was more than 99.99 percent, and the baseline pressure drop was stable over the range of conditions tested.

Overall, the testing at the PSDF indicated no design or operational challenges that were unique to the Mississippi lignite when using the Transport Gasifier. The lignite could be dried reliably in the fluid bed dryer and fed to the gasifier; and the gasifier, PCD, and ash removal systems would operate reliably as well.

1.5 FRONT-END ENGINEERING DESIGN (FEED)

The original FEED for the Kemper County IGCC Project was completed in November 2007. At the time of its completion, the design incorporated no CO2 capture, had an amine-based system for the removal of hydrogen sulfide (H2S), and utilized a Claus plant for the conversion of H2S to elemental sulfur with a tailgas treatment unit to clean the gas leaving the Claus unit before being vented to atmosphere.

Because of a changing environmental landscape over the life of the project, Southern Company’s management decided to incorporate carbon capture into the Kemper County TRIG design, and a study was conducted at the end of 2007 and early 2008 to evaluate technologies for the removal of CO2 from syngas. The conclusion of this study was to use UOP’s Selexol technology for acid gas removal. In addition to the incorporation of the Selexol technology, it was decided to reduce capital cost by replacing the Claus unit and tailgas treatment unit with Haldor Topsoe’s wet sulfuric acid (WSA) process to convert H2S into sulfuric acid. In the second quarter of 2008, work began to modify the original FEED design to incorporate the process changes.

The original design basis was 25 percent CO2 removal, based on removing the inherent CO2 in the syngas. Over time, the design basis evolved to 50 percent carbon capture to match the California standard of 1,100 lb CO2 emitted/MWh (net) for power imported into the state. Finally, it was decided to match the CO2 emissions of a natural-gas-fired combine cycle (NGCC). The CO2 emissions from a typical NGCC are approximately 800 lb CO2 emitted/MWh (net). For the Kemper County IGCC Project, this equated to the removal of 65 percent of the carbon in the lignite that is fed into the unit. Changing from 25 percent to 65 percent capture required the incorporation of water-gas-shift (WGS) reactors. Also, because the coal is dry-fed into the gasifier, and particulate removal is with a filtration system instead of a wet scrubber, the syngas leaving the gasifier has a relatively low moisture content. To provide adequate water for the WGS reactors, a Syngas Scrubber was added to the process to moisturize the syngas.

As the syngas flows through the WGS reactors, and CO2 is removed from the syngas, the hydrogen concentration of the gas significantly increases, impacting the turbine selection. The original FEED was based on a GE 7FA gas turbine, which was not originally designed for high hydrogen syngas feed. To combust the increased hydrogen content syngas, GE wanted to


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change to a 7FB turbine. This change had a significant performance impact on the facility and it was decided to evaluate other turbine designs. Ultimately, a Siemens 5000F turbine was selected for the project.

The FEED project with KBR provided a number of documents that will support the project through detailed engineering and into operation, and are typical of the documents provided on a project of this magnitude:

• Process Documentation − H&MB – created for 0 percent, 25 percent, 50 percent, and 65 percent carbon

capture. − Process Flow Diagrams (PFD) – created for 0 percent, 25 percent, 50 percent,

and 65 percent carbon capture. − Piping and Instrumentation Diagrams (P&IDs) – created for 0 percent,

50 percent, and 65 percent carbon capture. − Vendors of major subsystems have submitted design plans. − RAM analysis. − Project schedule developed. − HAZOP completed for all systems. − Preliminary cold start-up sequence developed. − Engineering simulator being developed. − Equipment and instrumentation list being finalized. − Equipment load sheets developed. − Pressure relief study conducted and preliminary valve sizing determined. − Operations and maintenance (O&M) model created. − Operations work charts completed.

• Costing/Procurement − Steam turbine purchased. − Gas turbine vendor selected. − Engineering and license agreements signed with UOP and Haldor Topsoe. − Detailed procurement schedule developed. − Procurement on long lead time equipment to begin November 2009.

• Design Drawings − Plot plan created. − 3-D model build started.

• Construction − Major milestones identified and scheduled. − Preliminary detailed schedule completed.

1.6 CHALLENGES DURING FEED

As mentioned in section 1.5, significant changes were required from the November 2007 design to the final design of the Kemper County project to incorporate the Selexol process at various levels of carbon capture, to incorporate the WSA process and to change from the GE to the Siemens turbine. These changes were critical to the ultimate success of the project, but created a significant amount of rework for the project team.

An IGCC facility is typically designed around the combustion turbine. The Siemens and GE turbines were significantly different in design and operation, which affected the overall process design of the unit. The Siemens turbine has a much larger compressor than the GE turbine,


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and during syngas operations a significant amount of this air can be extracted from the combustion turbine compressor. This air will supply approximately one-third of the total air required for the gasification process, which significantly saves on compression energy. During this time, separate process designs were being managed in parallel to keep the project on schedule. In addition, the changing amounts of carbon capture changed the syngas composition to the turbine. This changed the syngas flow requirements, which changed the design of the plant equipment.

The impacts of the turbine selection were significant to the design of the facility, but possibly the biggest design challenge was the variability of the composition of the lignite as shown in section 5.1.5. A large number of core drillings were performed to supply design information for the project, and it was found that the lignite in the planned mine area had significant variability in its heating value as well as moisture, sulfur, and ash content. The affect of this variability relative to the average coal composition can be seen in figure 1-1.

COALFEED

COAL DRYING

DUTY

AIRFEED

MAIN STEAM

PRODUCED

ASHPRODUCED

SYNGASPRODUCED

PRODUCT CO2

PRODUCED

SULFURIC ACID

PRODUCED

AMMONIAPRODUCED

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AN

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Figure 1.1 – Lignite Variability and its Impact on Design This variability created design challenges throughout the plant, but especially in the coal preparation and feed areas, particulate collection and ash removal, sulfuric acid production, and in the gasifier sour water system which recovers and purifies anhydrous ammonia.


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2.0 PROCESS OVERVIEW

The site for the IGCC power generation facility is in Kemper County, Mississippi. It is a 2,968-acre greenfield site without any pre-existing power generation facilities. A net 582 MW (524 MW on syngas alone) combined-cycle power island will be built and placed in commercial operation in 2014, fueled with syngas produced from air-blown, lignite-fueled Transport Gasifiers. Figure 2-1 shows a block flow diagram of the overall process. The diagram is followed by a general description of the IGCC process.

From figure 2-1, some of the overall layout characteristics of the facility can be seen:

• There are two separate gasification trains; each gasification train supplies syngas to a single combustion turbine and heat recovery steam generator (HRSG).

• Each gasification train has three parallel coal drying and milling (coal preparation) trains and each of these trains feed two high-pressure coal feed systems. Therefore, there are six coal feeders per gasifier.

• There are two process air compressors per gasification train. • Exiting each gasifier, the syngas splits into two parallel streams through the high-

temperature syngas coolers and the particulate control devices (PCD). These streams recombine after the PCDs and flow as a single stream through the gas cleanup systems to a combustion turbine.

• Several systems shown are common to both gasification trains – the steam turbine, the gasifier sour water system, ammonia recovery, and the WSA process.

• There are a number of balance of plant (BOP) systems not shown that are also common to both gasification trains – water treatment, cooling tower/closed loop cooling water, instrument air, natural gas, diesel, etc. There are two separate cooling towers – one for the gasification island heat load and one for the combined cycle.


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CRUSHED COAL

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Kemper IGCC Block Diagram© Southern Company Services, Inc. All rights reserved.

NITROGEN PLANT AND

LIQUID STORAGE

NOTE: N2 FLOWS TO NUMEROUS LOCATIONS FOR INERTING AND PURGING.

RECOVERED WATER

RECOVERED WATER

Figure 2.1 – Kemper County IGCC Project Block Diagram


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2.1 GASIFICATION ISLAND

Each of the two gasifiers will be fueled with lignite for a total raw feed rate of 575 ton/hr and a total air air-feed rate of 870 ton/hr, based on the expected average lignite composition. Carbon conversion is projected to be more than 97 percent. Sulfur and other contaminants in the lignite are removed from the syngas upstream of the gas turbine.

The particulate-laden syngas leaves the gasifier at approximately 650 psia and is indirectly cooled from 1,740 to 600 °F, producing high-pressure superheated steam. Subsequent dry gas filtration in the PCD removes essentially all the particulate matter present in the cooled syngas stream. A proprietary continuous fine ash depressurization (CFAD) unit removes the ash from the filter vessel, while cooling and depressurizing it. Similar to CCAD, CFAD has no moving parts and has exhibited 100 percent reliability in more than 11,000 hours of operation at the PSDF.

Following filtration, the syngas enters a syngas scrubber column where water-soluble compounds such as chlorides and fluorides are removed, and the syngas is saturated with water prior to entering the WGS reactors. In the WGS reactors, CO reacts with water to produce CO2 and H2. This step facilitates the removal of CO2 in the acid gas removal (AGR) unit.

Exiting the WGS reactors, the syngas is cooled using high-temperature recuperators before entering the carbonyl sulfide (COS) hydrolysis reactor, which converts most of the COS (a trace sulfur compound) to H2S to facilitate removal in the AGR. Low-temperature recuperators and water-cooled heat exchangers further cool the syngas, while condensing moisture from it. The resulting process condensate is recycled back to the syngas scrubber. After the process condensate is removed, the syngas is cooled further before passing through a final water-spray column, the ammonia scrubber, to remove the remaining soluble species present. The resulting sour water is combined with sour water from the syngas scrubber and sent to the plant sour water system. The sour water system prepares the water for reuse while producing anhydrous ammonia for sale as a byproduct.

The scrubbed syngas then enters absorbers that remove > 99 percent of the H2S using a SELEXOLTM solvent. The captured H2S is stripped from the solvent, which is then recycled back to the absorbers, and the concentrated H2S stream is routed to a sulfuric acid plant where the sulfur is converted into commercial grade sulfuric acid. Following sulfur removal, a portion of the CO2 in the syngas is removed using an additional set of absorbers. The removed CO2 stream is dehydrated and compressed and sold as a byproduct for EOR, resulting in its geologic storage.

After the CO2 removal system, the syngas passes through a fixed-bed adsorption vessel that will remove nearly all of the mercury remaining in the gas. A portion of the “sweet” syngas is separated and passed to the syngas recycle system where it is used to back-pulse clean the filter elements in the dust filtration system, for aeration in the gasifiers, and for concentrating the acid gas stream in AGR area. The remainder of the sweet syngas stream is heated by passing it back through the low- and high-temperature recuperators before flowing to the gas turbines. Approximately 425 ton/hr of syngas is sent to each gas turbine with a lower heating value of approximately 120 Btu/scf. The gas turbine compressors provide the combustion air for the syngas and approximately one-third of the air required by the gasification island at full load. The remaining air required is delivered by motor-driven process air compressors.


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Ash removed from the gasifier and the dry gas filtration system is sent to a storage silo. The silo, complete with dust-suppression equipment, is discharged into trucks that transport the ash to an appropriate ash disposal site.

The plant is comprised primarily of commercially available equipment with the exceptions being the transport gasifiers, fine- and coarse-ash cooling and depressurization systems, and coal feed devices. These proprietary systems are based on established design principles, incorporate commercially available equipment items, and have been successfully demonstrated at the PSDF.

2.2 COMBINED CYCLE

The two combustion turbines for the Kemper County project are Siemens SGT6-5000F units modified to operate on syngas. Flame-diffusion combustors, rather than low-NOX designs, will be used to prevent flashback caused by the hydrogen content of the syngas. Ports will be added to the compressor casing, allowing air to be extracted and supplied to the gasification island.

When firing syngas, each combustion turbine generates approximately 232 MW. This power output is maintained across the expected ambient temperature range by adjusting the air extraction rate so that the mass of gas passing through the turbine is constant. For example, at low ambient temperatures, more air is induced into the compressor section because of the increased air density, and this allows more to be extracted. The total air entering the gasifier is relatively constant for a given load, so the mass flow rate of air from the process air compressor is reduced because of the availability of the increased extraction air, which decreases the power consumption of the process air compressor. To maximize the air induced into the compressor and maintain gas turbine output during periods of high-ambient temperature, an inlet air evaporative cooling system is placed in service whenever the ambient temperature is at or above 65 °F.

Although the plant is designed and intended to operate on syngas, the capability exists to fire the combustion turbines on natural gas. During natural gas operations, steam must be injected into the combustion cans to limit thermal NOX formation to 25 ppmv. The reduction in fuel mass flow rate during natural gas firing would decrease power output at these conditions to as low as 200 MW at high ambient temperatures.

Each gas turbine exhausts into a conventionally designed, triple-pressure level HRSG. When operating on syngas, the normal HRSG gas exit temperature is 274 °F. This is above the acid dewpoint temperature so there are no problems with wet corrosion. Any ammonium bisulfate that may deposit on the economizer tubes downstream of the SCR unit will be removed by off-line washing.

High-pressure superheated steam from the HRSGs is combined with superheated steam from the gasifier island and passed to the steam turbine. Under normal conditions, the high pressure superheated steam enters the steam turbine at approximately 1,720 psia and 1,000 °F. Steam exhausted from the high-pressure turbine is reheated in the HRSGs to 1,000 °F at 320 psia, combined with superheated intermediate-pressure steam generated in the HRSGs, and expanded through the intermediate-pressure turbine. Exhaust from the intermediate pressure turbine is combined with superheated low-pressure steam generated in the HRSGs and passed to the low-pressure turbine before being condensed at 1.8 in. of mercury. Varying amounts of


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each steam level are extracted from the HRSGs and steam turbine for use in the gasifier island processes. At normal operating conditions, the steam turbine generates 290 MW. For peaking duty, steam turbine output can be increased to around 360 MW by firing natural gas in the HRSGs.

Condensate from the steam turbine condenser is used for cooling in the gasification process before returning to the HRSG for further heating and deaeration. High-pressure feedwater flows from the HRSG to the gasifier island where it is used in the syngas cooler to raise the high pressure superheated steam supplied by the gasification island to the steam turbine.

Within the HRSG, an SCR unit for NOX reduction during natural gas operation is installed at a location where the flue gas temperature is in the optimal temperature range of 600 to 700 °F. Liquid anhydrous ammonia produced by the gasification island is used for the SCR reagent.

2.3 BALANCE OF PLANT

2.3.1 Cooling Water

A 12-cell mechanical draft cooling tower designed for 1,650 MBtu/hr provides cooling water for the steam turbine condenser and the combined-cycle. Plate-and-frame heat exchangers transfer the heat from a closed-loop cooling system to the cooling tower. The cooling tower blow-down flow is approximately 152,000 lb/hr and the make-up flow is around 910,000 lb/hr, when operating at full load under design ambient conditions.

Cooling water is supplied to the gasifier island equipment via a separate 10-cell mechanical draft cooling tower rated for approximately 1,360 MBtu/hr. Plate-and-frame heat exchangers will again be used to transfer heat from a closed-loop cooling system to the cooling tower. The gasifier island cooling tower’s blow-down flow will be approximately 131,000 lb/hr with a make-up flow of about 695,000 lb/hr when operating at full load design ambient conditions.

2.3.2 Natural Gas System

Natural gas is supplied from the pipeline at 1,000 psia and a gas-conditioning station regulates the gas pressure, heats, and filters the gas as needed to meet combustion turbine specifications.

2.3.3 Nitrogen Plant

A 100-ton/hr nitrogen plant will be built onsite to provide nitrogen to purge coal vessels and instrumentation lines where air is not appropriate. During startup and emergency shutdown, additional nitrogen will be provided from liquid storage.

2.3.4 Flare

Flares will be provided to combust and dispose of syngas and other process gases during startup, shutdown, and upset conditions.


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2.3.5 Plant Electrical

Electrical power will be generated at 18 kV by the two gas turbine generators and one steam turbine generators. All three generators have dedicated step-up transformers to increase voltage to 230 kV. This 3-phase, 60-Hertz power will be supplied through the switchyard for distribution to the grid. Power used within the facility to operate motors, lighting, instrumentation and controls, etc. will be supplied at 13.8 kV, 4.16 kV, 480 V, 277 V, and 120 V.

2.3.6 Instrumentation and Controls

The plant instrument and control system will allow startup, normal operation, and shutdown of the facility from a central control room with minimum operating staff. Control and monitoring functions in the central control room will be via an integrated control system (ICS). The ICS will include multiple, identical video display units, any one of which will allow the operator to perform all required tasks to remotely operate any item of plant equipment. The ICS will communicate digitally and redundantly with any self-contained control or monitoring system packages being provided by the equipment suppliers.

This digital communication system will be robust enough to allow operating functions to be performed from the ICS. These operations include alarm acknowledgement, alarm management, sequence-of-event reporting, generator synchronization, breaker closing and opening, equipment starting and stopping, equipment loading, voltage regulation, data trending and analysis, data storage and retrieval, report generation, and all other control and monitoring functions. For reliability, critical control functions and safety-related signals will be hardwired as appropriate.

A plant operating information system (OIS) will provide the capability to program performance calculation algorithms. Via trend display screens, the OIS will provide real-time calculation capability for all plant operating equipment. Plant information will also be accessible to offsite personnel. Performance measurements and calculated results will be used to minimize plant operating and maintenance costs by providing a variety of diagnostic data. These data will help resolve operational problems, identify component performance degradation, and optimize the startup, loading, unloading, and shut-down ramp rates for the major plant equipment items.

An engineering simulator is being developed for the project to allow analysis of transient events such as the startup or shutdown of specific pieces of equipment. This simulator also provides a method to evaluate startup scenarios and develop procedures for startup and shutdown of the plant. This analysis provides for a more efficient startup of the plant and speeds the progress to commercial operations.

2.4 SUMMARY OF PROJECTED THERMAL AND ENVIRONMENTAL PERFORMANCE

2.4.1 Heat Rate

The higher heating value of the “average” as-received lignite is 5,290 Btu/lb. When operating with this coal, the projected heat rate is 11,708 Btu/kWh (29.1 percent efficiency on an HHV basis).


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2.4.2 Emissions

2.4.2.1 Sulfur Dioxide

Sulfur removal is projected to be > 99 percent and the SO2 content of the flue gas discharged from the gas turbine is permitted at around 13.1 lb/hr based on a 24-hour rolling average

2.4.2.2 NOX Emissions

The level of NOX in the combustion turbine exhaust gas while burning syngas is permitted at 210 lb/hr on a 24-hours rolling average basis. To reduce high NOx emissions that occur during natural gas operations, the HRSG unit will be equipped with an SCR. The SCR unit is expected to reduce NOX emissions to levels of approximately 0.015 lb/MMBtu (approximately 3.8 ppm at 15-percent oxygen). For syngas operations a SCR Demonstration Test will be conducted.

2.4.2.3 PM Emissions

The gasification island filter system removes high levels of the particulate from the syngas and loadings to the combustion turbine are expected to be below 0.0001 lb/MMBtu (0.1 ppmw). Particulate emissions are permitted at 52 pph per stack when firing syngas.

2.4.2.4 Mercury Emissions

Packed beds of sulfur-on-alumina adsorbent will remove more than 90 percent of the mercury in the product syngas and CO2 streams.


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3.0 KEMPER COUNTY IGCC PROJECT SITE

3.1 PROJECT SITE

The 2,968-acre plant site will be located near the unincorporated community of Liberty in Kemper County, Mississippi, on or about latitude 32º 38’ N and longitude 88º 46’W. The proposed site is located 20 miles north of interstate 20/59 and adjacent to State Route 493 as shown in figure 3.1. It is also 22 miles north of Meridian Regional Airport. The land where the plant will be located is relatively flat with slight rolling terrain. Current land use of the site and surrounding area is agriculture and primarily timberland. Of the 2,968-acre site, less than 300 acres will be used in development of the plant. The plant footprint will occupy 80 acres including the gasifier and combined-cycle power block and the lignite-handling facilities.

MPC is currently investigating plans to beneficially use the ash for industrial processes such as building roads, soil amendment, or other uses approved by the Mississippi Department of Environmental Quality. However, if the ash is deemed unacceptable for beneficial use, 150 acres have been identified for onsite ash management. The property also includes space required for temporary activities such as construction laydown.

3.2 SITE INFRASTRUCTURE

The major infrastructure available to the site includes transmission, water, gas, and lignite. The availability of each item is outlined below.

3.2.1 Transmission

MPC currently owns and operates approximately 2,090 miles of transmission circuit (46,000 V and higher) including more than 600 miles of 230,000-V (230 kV) transmission circuits. Transmission facilities owned by MPC are interconnected to the other operating companies within Southern Company, as well as Entergy and two electric power associations. The proposed site of the TRIG plant is located approximately 17.5 miles north of an existing MPC 230-kV transmission circuit.

The current transmission plan for the proposed TRIG plant includes construction of an estimated 63 miles of new transmission line: 54 miles of 230 kV and 9 miles of 115 kV; rebuilding 24 miles of existing 115 kV transmission line; construction of five new substations including an onsite generator collector bus and a transmission substation; addition of a new 230/115 kV autotransformer at an existing substation; and, modification of two existing substations to accommodate new transmission line terminations. These facilities provide for interconnection and firm transmission service for the entire projected net output of the plant. MPC will acquire all necessary rights-of-way (ROW) in order to interconnect and integrate the new power plant into its existing transmission network.


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Figure 3.1 – Location of Kemper County IGCC Project Site


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3.2.2 Water Supply

The primary water source for the facility will be treated effluent from the city of Meridian, MS. The treated effluent will be piped through an approximately 31-mile pipeline to the plant and stored in a 100 acre reservoir onsite.

3.2.3 Gas Supply

Proximity to a source of natural gas is necessary for startup operation, shutdown, and during maintenance of the gasifier. The site offered two potential sources for natural gas supply: Southern Natural Gas (SONAT) and Tennessee Gas. The SONAT pipelines were located on the site property, while the Tennessee Gas lines were 6 miles to the east of the plant site. The SONAT pipelines, however, would have required substantial upgrades to use for the plant natural gas supply. Economic analysis resulted in the selection of the Tennessee Gas pipelines.

3.2.4 Lignite Supply

The site is adjacent to a lignite reserve identified as the “Damascus Prospect” by NACC. The area of interest for the mine covers approximately 31,000 acres, however less than 13,000 acres will be disturbed. It is anticipated that 175M tons of lignite will be mined over a 40-year period. Annual mining rates are expected to be in the range of 4.4M tons per year.

3.2.5 Rail

Proximity to a railroad is not a requirement of the facility. As a mine-mouth operation, primary coal delivery will be by truck or overland conveyor. As consideration for possible future operations or equipment delivery, the Kansas City Southern Railroad has tracks 16 miles east of the site. Norfolk Southern is also available in the City of Meridian, approximately 20 miles south of the site.

3.2.6 CO2 Pipeline

To supply the CO2 captured in the process to the offtakers for EOR, MPC will construct a 61-mile pipeline from the plant site to points of delivery for two third-party offtakers for use in enhanced oil recovery projects.


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4.0 PROJECT SCHEDULE

A summary of the overall project schedule is provided in figure 4-1. The in-service date for the project is May 2014. The schedule includes a timeline for the technical, business, financial, and permitting aspects of the project.

Figure 4.1 – Overall Project Schedule

4.1 DETAILED ENGINEERING DESIGN

Detailed design engineering, which began after the MPSC certification in May 2010, will produce the information and documentation necessary to construct the TRIG facility. In this phase, all detailed design packages, bid specifications and engineering drawings of the plant will be produced. The product of this task will be to complete the facility design documents suitable for installation and operation. At completion of construction, design documentation will be updated to reflect as-built conditions.

SCS and KBR will prepare requests for proposals (RFPs) for competitive solicitations of major components of the plant. Components for the plant will be awarded to suppliers based on the evaluation of the proposals obtained in response to these RFPs.

The major engineering tasks include the following:

Structural Steel and Concrete – This subtask will include all civil, structural, and geotechnical engineering associated with the design of the facility, including 3-D computer modeling of the process structures.

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

EngineeringFEEDDetail Design

ProcurementLong Lead ItemsBulk Equipment

ConstructionSite WorkPilingUndergroundGasifier IslandCombined Cycle

OperationStartup

2013 20142008 2009 2010 2011 2012

CODMay


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Architectural – This subtask will include the design of all buildings and facilities, including the administration building, mechanical shop, and warehouse.

Mechanical – This subtask includes the following:

• Mechanical design of all equipment including the development of fabrication drawings and specifications for procurement.

• Piping layout, stress analysis, and support design, generation of isometric drawings for all piping, definition of the piping, and valve specifications for procurement.

• Site service systems including fire protection, water supplies, sewage, and fuel facilities. Electrical – This subtask includes the following:

• Development of the single-line configuration to determine the electrical distribution throughout the facility.

• Design of the substation and interconnecting facilities required to interface the generating plant with the electrical distribution grid.

• Development of plans for electrical grounding, lighting, cable trays, and conduit. • Design of the station service and plant communication systems. • Development of interconnection wiring diagrams for all the equipment, programmable

logic controllers, and the integrated control system (ICS). • Design and procurement specifications for the motor control centers, switchgear,

transformer, and other electric equipment. Instrumentation and Controls – This subtask includes the following:

• Configuration of the Southern Company standard plant data archiving system. • Instrumentation sizing, specification, and selection. • Instrument location drawings and installation details. • Instrumentation loop drawings, control schematics, logic diagrams, and interlock logic

diagrams. • ICS control configuration. • Performance management configuration programming.

Procurement – This subtask includes the development of bid inquiry packages, bid evaluation, selection and procurement for all equipment, and bulk materials. Subcontracts for construction and other services will be bid and awarded.

Cost and Scheduling – This subtask includes all cost and scheduling activities required to track engineering and construction progress throughout the project. Activities include monitoring of actual cost against budgeted cash flows, tracking material costs, updating monthly task log/man-hour reports, and updating the work schedule.

Construction Bid Packages – This subtask includes all engineering activity needed to prepare construction bid packages. Work includes assembly of plans, drawings, and specifications for the construction bid packages. Work will include developing a list of qualified bidders for each package, issuing each package to qualified bidders, evaluating construction bids, and preparing requisitions and purchase orders for award of construction contracts. SCS will participate in contractor prebid meetings, evaluation of construction bids, and award of construction contracts.


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4.2 Construction

Tasks in this phase include construction and installation, commissioning, and startup, and the remaining engineering. SCS E&CS is responsible for the construction of the IGCC facility and all related support systems and facilities using construction services managed by SCS home office and field support personnel. This task includes all equipment, materials, labor, supervision, and other expenses required to install the foundations, process structures, buildings, bulks for the facility, and balance of plant utilities required.

Major construction milestones include the following activities:

• Commencement of construction (first day on site). • Site clearing and grubbing. • Site grading complete. • Pile driving complete. • Major foundation pours complete. • Completion of major equipment deliveries. • Completion of major equipment installation on foundations. • Installation of structural steel, piping, electrical, and instrumentation. • First fire of gas turbines. • Steam blow completion. • First fire of gasifier island. • Startup of combined cycle complete. • Startup of gasifier complete. • Unit commercial operation date.

The major equipment delivery schedules will include the following:

• Gas turbine generators. • HRSGs. • Steam turbine generator. • Primary gasifier vessels. • Key gasifier island components.

4.3 COMMISSIONING AND STARTUP

Commissioning and startup plans, procedures, and schedules for the systems and components will be prepared. Detailed acceptance criteria will be provided for all new items to be operated during the commissioning period.

O&M staff will be recruited and trained during construction and startup activities, with a complete staff ready and in place as the facility is placed into commercial service. Training at the PSDF (consistent with DOE requirements) will be instituted as necessary.

Qualified engineers, operators, technicians, and other labor necessary to support commissioning and operate the facility will be provided. All areas necessary to prepare for operating the TRIG facility will be addressed, including but not limited to: the types of sample analyses necessary to evaluate component and system performance; methods of collecting,


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reducing, and analyzing data from various components; and methods for storage and retrieval of raw and refined performance data.

4.4 COMMERCIAL OPERATIONS

The TRIG facility will be operated and maintained for commercial generation of electricity. MPC and Southern Company have significant operations and maintenance experience with both coal and natural gas generating units. The MPC and Southern Company generation fleets have demonstrated a consistent track record of high availability, low forced outage rates, and low cost operation, all well below the national average. Additional testing, characterization, and optimization of the TRIG unit and its equipment will begin during the initial commissioning and continue throughout the life of the facility.


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5.0 KEMPER COUNTY GASIFICATION ISLAND DESIGN INFORMATION

5.1 PLANT DESIGN BASIS

5.1.1 General information

• Plant service: Two gasification islands to convert approximately 14,000 tpd of lignite coal to 1.69 MM lb/hr of synthesis gas (syngas) utilizing the Transport Gasifier as part of a TRIGTM plant.

• On stream time : 8,000 hours per year

5.1.2 Project site Conditions

5.1.2.1 Geological Conditions

5.1.2.1.1 Elevation

• Low point of ground level (LGL) : Design mean sea level +473 ft @ grid line N.1147615’ 2 5/8” and at grid line N. 1146087’ 2 5/8”.

• High point of ground level (HGL) : Design mean sea level +481 ft. (Between grid

reference line N. 1146915’ 2 5/8” and N. 1146831’ 10 5/8”) • Site is to be provided with a -1 percent slope from grid reference line N. 1146915’ 2 5/8”

to reference line N 1147615’ 2 5/8” and a -1. 5 percent slope from reference line N. 1146831’ 10 5/8” to reference line N. 1146087’ 2 5/8”.

• Actual Grade : +481 ft

5.1.2.1.2 Earthquake

• Section zone : X • Applicable Code : ASCE 7-05 • Soil Profile (Seismic Type) Site Class C • Occupancy Importance Factor I = 1.25 • Occupancy Category III • Site Coefficient, Fa 1.20 • Site Coefficient, Fv 1.70 • Seismic Design Category “B”

(Per Tables 11.6-1 and 11.6-2; AISC & 7-05) • One Second (1.0 sec) SD1 = 0.099 g Design Spectral Acceleration • Short Period (0.2 sec) SDS = 0.163 g Design Spectral Acceleration • Maximum considered earthquake return is 2,500 years. • Ss=.204; Fa=1.2; Sms=.244 • S1=.087; F1=1.7; Sm1=.148


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5.1.2.1.3 Frost Depth

• Design depth of frost : 6 in. 5.1.2.2 Climate Conditions

5.1.2.2.1 Air Temperature

Min. (oF)

Max. (oF)

Dry bulb temperature for the design of mechanical equipment 10 110 Dry bulb temperature for the design of electrical/instrument equipment and materials

Indoor temperature Earth Temperature

10 130 130 130

Dry bulb temperature for the design basis of heating and steam/electrical tracing 10 Dry bulb temperature for the design basis of hot insulation 140 Dry bulb temperature for the design basis of cold insulation 10 Dry bulb temperature for design basis of winterizing 10

5.1.2.2.2 Humidity

Design basis for all equipment:

• Relative humidity (summer peak) 45% at 95 oF Wet bulb temperature 77.0 oF

• Relative humidity (annual average) 75% at 65 oF Wet bulb temperature 59.9 oF

5.1.2.2.3 Rainfall and Snowfall

• Daily maximum rainfall: 9.6 in. • Design hourly rainfall: 8.6 in/hr for 24 hours (25 year point)

3.1 in./hr (10 year point) • Snow loading code: ASCE 7-05 • Design snow load: Pg = 5 psf • Terrain category: C

• Design depth of snowfall: 5.7 in. • Thermal category: Ct = 1.2 (unheated structures)

(see ASCE7-05 Table 7-3) • Importance factor: I = 1.1

5.1.2.2.4 Wind Condition

• Wind direction (prevailing): N/NE (fall and winter) S (spring and summer)


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• Applicable code ASCE 7-05 o Basic wind speed 100 mph o Exposure category C o Occupancy category III o Importance factor I = 1.15

5.1.2.2.5 Barometric Pressure

• Design barometric pressure: 29.404 in Hg or 14.44 psia 5.1.3 Environmental Conditions

5.1.3.1 Wastewater - leaving the gasification island

Stripped water (to SCS water treatment)

• pH value 9.2 • HCl 173 ppm • HF 694 ppm • NH3 14 ppm • NaOH 853 ppm

5.1.3.2 Air

5.1.3.2.1 Gasifier Startup Stacks 1&2 (limits apply to each emission point)

Contaminants Emissions Limitations

Opacity

Comments

20% Determined by EPA Test Method 9, 40 CFR 60, Appendix A

Other contaminants (SOX, NOX, etc) to be monitored during the first 12 months of startups/shutdowns and subsequently used to establish permit limits during startup/shutdown.

5.1.3.2.2 Gasifier Flare Derrick (limits apply to entire flare derrick)


Carbon Monoxide

Comments

24.3 lb/hr As determined by an approved gas monitoring plan

106.5 tons/year As determined by an approved gas monitoring plan

Pollutants Emissions limitations Comments

Nitrogen Oxides 30.3 lb/hr as NO2

As determined by an approved gas monitoring plan

133.0 tons/year as NO2 As determined by an approved gas monitoring plan


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Sulfur Oxides 45 lb/hr as SO2

As determined by an approved gas monitoring plan

197.1 tons/year as SO2 As determined by an approved gas monitoring plan

Opacity 0% (except for periods not to exceed five minutes every two consecutive hours)

Determined by EPA Test Method 22, 40 CFR 60, Appendix A

Pollutants (SOX, NOX, etc) to be monitored during the first 12 months of startups/shutdowns and subsequently used to establish permit limits during startup/shutdown. These limits do not apply during periods of upset or equipment malfunction.

5.1.3.2.3 AGR Process Startup and Shutdown Vents 1&2 (limits apply to each emission point)


Opacity

Comments

20% Determined by EPA Test Method 9, 40 CFR 60, Appendix A

The limitation of total reduced sulfur compounds (H2S, COS, etc.) from the combination of the AGR process startup and shutdown vents and the combustion turbine stacks shall be less than 9.9 tons/year. Other contaminants (SOX, NOX, etc) to be monitored during the first 12 months of startups/shutdowns and subsequently used to establish permit limits during startup/shutdown.

5.1.3.2.4 Auxiliary Boiler Stack (limits apply to each emission point)


Nitrogen Oxides

Comments

0.04 lbms/MMBTU

On a 30-day rolling average on a 12-month rolling total, as determined by EPA Test Method 7, 40 CFR 60, Appendix A.

11.4 lb/hr

As determined by EPA Test Method 7, 40 CFR 60, Appendix A.

8.55 tons/year As determined by EPA Test Method 7, 40 CFR 60, Appendix A.


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Opacity 20% Determined by EPA Test Method 9, 40 CFR 60, Appendix A

After characterization of normal startup operations, the auxiliary boiler shall be limited to a maximum operating time of 1,500 hours in any consectuvie 12 month period.

5.1.3.2.5 Wet Sulfuric Acid (WSA) Unit


Sulfur Dioxide

Comments

45.4 lb/hr Based on a 24-hour operating rolling average.

199.0 tons/year

Based on a 12-month rolling total, as determined by EPA Test Method 6, 40 CFR 60, Appendix A.

Sulfuric Acid Mist

5.0 lb/hr

On a 24-hour rolling average, as determined by EPA Test Method 6, 40 CFR 60, Appendix A.

22.0 tons/year

On a 12-month rolling total, as determined by EPA Test Method 6, 40 CFR 60, Appendix A.

Opacity 40% Determined by EPA Test Method 9, 40 CFR 60, Appendix A

Total sulfur oxides shall be limited to 500 ppmv or less.

5.1.3.2.6 Gas Turbines 1&2 (limits apply to each emission point on syngas)


Sulfur Dioxide

Comments

13.1 lb/hr Based on a 24-hour operating rolling average.

58 tons/year



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Nitrogen Oxides

210 lb/hr as NO2 Based on a 24-hour operating rolling average.

920 tons/year


Carbon Monoxide (no AGR process vent to IGCC

stack)

105 lb/hr

Based on a 24-hour operating rolling average as determined by EPA Test Method 10, 40 CFR 60, Appendix A.

557 tons/year As determined by EPA Test Method 10, 40 CFR 60, Appendix A.

Carbon Monoxide

(AGR process vent to IGCC

stack)

380 lb/hr

Based on a 24-hour operating rolling average as determined by EPA Test Method 10, 40 CFR 60, Appendix A.

PM/PM10 (filterable)

52 lb/hr Based on a 3-hour block average.

228 tons/year Determined by EPA Test Methods 1-5, 40 CFR 60, Appendix A.

Volatile Organic Compounds

17.1 lb/hr Based on a 3-hour block average.

91 tons/year Determined by EPA Test Methods 25A/18, 40 CFR 60, Appendix A.

Sulfuric Acid Mist

1.8 lb/hr Based on a 3-hour block average.

8 tons/year Determined by EPA Test Method 6, 40 CFR 60, Appendix A.

Reduced Sulfur Compounds 9.9 tons/year

Determined by EPA Test Method 15, 40 CFR 60, Appendix A.

Opacity

20% (6-minute average), except for one 6-minute

period per hour of not more than 27%

Determined by EPA Reference Method 9, 40 CFR 60, Appendix A.

The limitation of total reduced sulfur compounds (H2S, COS, etc.) includes the AGR process startup and shutdown vents and the combustion turbine stacks.


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5.1.4 Coal Composition

Kemper County IGCC Project Fuel Composition

Design Basis

Lignite Composition

Average Coal

Composition

Worst Case

{Minimum} Best Case {Maximum}

Minimum Coal Constituents

Maximum Coal

Constituents

As-Received

HHV Btu/lb 5290.0 4827.0 5962.0 4765.0 5872.0 Moisture % 45.5 45.56 42.64 42.2 50.0

Ash % 11.95 15.02 10.02 8.61 17.0 Sulfur % 0.99 0.998 0.99 0.35 1.7

Nitrogen % 0.48 0.47 0.55 0.33 0.61 Carbon % 31.53 28.87 35.68 28.1 35.68

Hydrogen % 1.98 1.91 2.02 1.73 2.40 Oxygen % 7.57 7.19 8.11 4.17 10.47 Chlorine ppm 116.0 101.5 85.0 45.0 295.0 Mercury ppm 0.077 0.054 0.084 0.027 0.187 Fluorine ppm 28.7 70.5 29.0 8.6 79.6

Grindability 105 Top Size (inches) 2.0

Ash Fusibility (Reducing) I.T. 2,195 °F S.T. 2,226 °F H.T. 2,239 °F F.T. 2,281 °F


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5.1.5 SCS OSBL/Infrastructure Facilities

• Water treatment facilities including reverse osmosis system, demineralizer, and polisher unit.

• Cooling water system. • Fuel gas distribution system. • Plant and instrument air supply system. • Safety and firefighting system. • Waste water treatment system. • Fire water system. 5.2 PROCESS DESCRIPTION

Please refer to the process flow diagrams in section 5.3 to accompany this process description.

5.2.1 Coal Preparation – Figure 5.3.1

The primary feedstock for the plant is Mississippi lignite with an average heating value of 5,290 Btu/lb and 1.0 percent average sulfur on as-received basis. The coal mine will be managed by NACC. Off-road mining trucks will deliver lignite from the mine to a covered truck dump hopper located near the power plant.

The Lignite Delivery Facility (LDF) managed by NACC provides the interface between the mine and the plant with the purpose of processing run-of-mine coal to 2 inch minus product. The Lignite Delivery Facility design is capable of delivering lignite that will minimize handing problems in the crushing, handling, and drying processes of the Plant. From the point the material enters the hopper an apron feeder directs the lignite into the primary crusher. The primary crusher is capable of processing run-of-mine material to 2 inch minus. Once the product has been processed, a single conveyor transfers the material to three possible points to which the product can be directed.

1. Product can be fed directly to the IGCC plant. 2. Product can be directed to a concrete storage dome equipped with a circular

stacker/reclaimer. 3. Product can be directed to an outdoor stockpile

The lignite that has been stored in either the concrete storage dome or outdoor storage pile can be reclaimed to the barn transfer station.

From the common transfer point, lignite can be delivered onto either of two parallel independent conveyor/tripper systems to the day silos. Each of the parallel conveyors is sized to be capable of delivering 1,200 tons per hour which is approximately twice the demand of the IGCC plant at full production. Further, both lines can deliver simultaneously allowing for rapid recovery when needed.


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There are six lignite preparation systems (three per gasifier) with sufficient design capacity such that if one system trips off-line, the others will increase to meet the design preparation rate. The six preparation and feed systems operate identically, so the operation of only one of the feed systems will be described. Coal is supplied to the crushed coal silo (SI1102) as described above. The gas displaced by the coal feed being fed into the silo will be vented through the coal silo dust collection system (FL0002) before being vented to atmosphere.

The 2-in. coal falls by gravity to the crushed coal feeder (FD1102) and is fed into the roll crusher (ML1107) where it is crushed to < 0.5 in. before being fed into the fluid bed dryer (FBD, PG1102).

The lignite fed into the FBD has a moisture content of up to 50 percent. In the FBD, the lignite is dried to approximately 22 percent moisture using a mixture of air and nitrogen containing less than 10 vol percent oxygen for the drying gas. For lignite, National Fire Protection Association Code 69 defines gas with such low oxygen concentrations as being inert and unable to sustain a fire. The oxygen content of the drying gas is monitored and nitrogen added as necessary. The FBD uses tempered water as the primary heat source and heats the coal directly with in-bed heating coils as well as by heating the drying gas. Low-pressure (LP) steam is used for additional heating if required. The tempered water system is a hot water loop that transfers heat from one area of the gasification process to another. Using this “low level” heat for drying is preferable because it avoids the operating cost associated with fuel-fired burners, minimizes the amount of moisture present in the drying gas (reducing the gas circulation rate), and improves the overall process efficiency.

After leaving the FBD, the drying gas passes through a multi-clone unit (FL1103), in which most of the fine lignite particles entrained in the drying gas are removed. The drying gas then passes through a venturi scrubber nozzle on CL1101 where the final particulate is removed. The upper part of the venturi scrubber (CL1101) acts as direct contact condenser where the water evaporated from the coal is condensed by coming in contact with circulating water cooled by the cooling tower in the venturi scrubber pump around cooler (HX1104). As the water condenses, the level rises in CL1101, and the water is withdrawn into the recovered water drum (DR0004) where it is used in various places throughout the process. The excess water is discharged with other clean wastewater from the gasification process to the cooling tower. The cooled gas is recirculated by the coal dryer gas feed fan (FN1102) back to the FBD.

After processing through the FBD, the lignite is combined with the fines from the multi-clone and pulverized in a nitrogen swept coal mill (ML1108) to a top size of 500 μm. The gas-solids mixture enters the PC cyclonic baghouse (FL1104) where the lignite is separated and gravity fed into the gasifier coal feed storage bins (SI1110A/B) which are part of the coal feed system. The gas from the baghouse is recycled back to the coal mill using the coal mill feed fan (FN1106).

The coal fines collected by the venturi scrubber are continuously purged to the Filtrate drum (DR0006) where they are combined with the purge streams from the other five


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venturi scrubbers. The fines are filtered by the drum filter (FL0005), and the water is recycled to the process. The coal fines are backfilled in the coal mine.

5.2.2 Coal Feed, Transport Gasifier, and Solids Makeup – Figure 5.3.2

The lignite entering each PC cyclonic baghouse (FL1104) falls by gravity to one of two gasifier coal feed storage bins (SI1110 A or B). Each of the storage bins supplies coal to a high-pressure coal feed system. As previously mentioned, there are two gasification trains and a total of six parallel coal preparation systems (three per gasification train). Each coal preparation system supplies lignite to 2 high-pressure coal feed systems, so there are a total of 12 high-pressure coal feed systems (6 per gasification train.) These high-pressure coal feed systems are sized so that if two of the six tripped offline, the gasifier can continue to run at full capacity.

The storage bins operate at atmospheric pressure, and because the gasifier operates at high pressure, the coal feed system must pressurize the lignite before feeding it into the gasifier. This is done by means of a “batch” lock vessel, and then a continuous pressurized dispense vessel and feeder. The gasifier coal feed dispense vessel (FD1115A/B) continuously operates at slightly above the gasifier pressure. It supplies coal to a proprietary Southern Company designed feeder (FD1116A/B) which varies the coal feed into the gasifier based on the syngas demands of the combustion turbine. As the coal is fed into the gasifier, the level drops in the dispense vessel. When a low level is reached, the valve between the dispense vessel and the gasifier coal feed lock vessel (FD1110A/B) is closed and the lock vessel is depressurized to atmospheric pressure. The valve between the lock vessel and the storage bin is then opened and the lock vessel is filled with coal. The valve between the lock vessel and the storage bin is closed and the lock vessel is pressurized to the dispense vessel pressure using high-pressure nitrogen. When both vessels are at the same pressure, the valve between the lock vessel and the dispense vessel is opened and the coal falls by gravity from the lock vessel to refill the dispense vessel.

The design of the pressurized transport gasifier (RX1002) is based on KBR’s fluidized catalytic cracking (FCC) technology and operating experience at the PSDF. Each gasifier has a total height of approximately 185 ft and consists of several refractory-lined pipe sections. The design operating temperature range is 1,500 to 1,800 °F and thermal expansion is accommodated without the expansion joints which have been found to be problematic in high-temperature, refractory-lined systems.

Lignite and air are fed into the mixing zone at the bottom of the gasifier and mixed with gasifier ash which is recirculated through the J-leg from the standpipe. Lignite is fed near the top of the mixing zone and air is fed at the bottom. Oxygen in the air is consumed by carbon present in the recirculating ash, forming primarily CO, and releases the heat required to maintain gasifier temperature. The lignite is heated up very rapidly by the hot recirculating ash, eliminating tar formation.

Gasifier ash and syngas pass vertically upward from the mixing zone to the riser at a velocity of 18 to 20 ft/s. The high temperature and residence time in the riser crack any


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tar that is formed. Syngas and gasifier ash pass to a presalter cyclone where larger, denser particles are removed by gravity and fall into a seal leg. The syngas then passes to the standpipe cyclone where most of the remaining gasifier ash is removed and falls by gravity into the standpipe. The syngas leaving the cyclone flows through refractory-lined pipe to the syngas coolers which generate high-pressure steam before flowing through metal alloy pipes to a filter system for final particulate removal. Gasifier ash flowing through the presalter cyclone seal leg is combined in the standpipe with gasifier ash from the standpipe cyclone. The combined ash stream passes down the standpipe and through the J-leg back into the mixing zone. The J-leg and seal leg are non-mechanical valves that allow the gasifier ash to flow against a reverse pressure gradient. To achieve reliable flow in these valves, the solids are well fluidized. Recycled syngas from the Recycled Gas Compressor (CO1008) is used for fluidization instead of nitrogen to avoid diluting the product syngas and to reduce operating costs.

During the unit’s startup, the gasifier must be preheated to approximately 1,600 oF before feeding lignite. This is accomplished by the use of two diesel-fired burners. The primary gasifier startup burners (AH1102 and AH1202), combust diesel to heat the gasifer vessel and the circulating solids. Once the temperature in the gasifier is hot enough to support the combustion of diesel fuel, additional diesel is directly added through the gasifier second startup burners (AH1103, AH1203 and AH1303) to continue heating the gasifier to the required temperature for coal feed.

The circulation rate of the gasifier is determined by the level of solids in the gasifier standpipe. A high level increases the circulation rate, and a low level decreases the circulation rate. To operate the gasifier at a steady circulation rate, solids can be added or removed from the gasifier during operation. If coal ash is accumulating in the gasifier, causing the level to increase, gasifier ash can be removed continuously from the presalter cyclone seal leg. The hot solids are first cooled in the CCAD coarse ash cooler (HX1130), using condensate as the cooling medium. The cooled pressurized solids flow into the proprietary Southern Company designed CCAD (FD1130) system where the pressure of the solids is reduced to near-atmospheric pressure. The cooled, depressurized solids are then conveyed to the coarse ash silo (SI0007) for reuse as bed material in the gasifier, or if the silo is full, conveyed to ash storage silo (SI0008) for removal.

If there is a low level of solids in the gasifier, or during startup, solids can be added from the coarse ash silo using the coarse ash feeder (FD0007). The coarse ash feeder is a batch feeder that takes the solids at atmospheric pressure from the coarse ash silo and pressurizes them to the gasifier pressure before pneumatically conveying the solids to the gasifier. During the initial startup, sand is purchased, dried, and prepared to a top size of 500 μm. Up to 130 tons are required for plant startup, although in practice most of the start-up material will be recovered bed material.

During shutdown, cooled, depressurized solids can be removed from the gasifier using the gasifier bottoms drain pot feeder (FD1011). This is also a batch feeder for conveying the solids from the gasifier into the coarse ash silo during shutdown.


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5.2.3 Syngas Cooling and Particulate Removal – Figure 5.3.3

Hot syngas from the gasifier flows into the primary syngas coolers for steam generation. Because of the large volume of syngas flow and manufacturing/shipping constraints, there are two syngas cooler units per gasifier. The approximately 1,740 oF syngas first enters the primary syngas cooler steam generator (HX1110) where the heat is used to raise high pressure steam. The steam generator is a natural circulation boiler, taking saturated boiler feedwater through the downcomer from the high-pressure (HP) steam drum (DR1008) and returning a two-phase mixture through the riser between the steam generator and the steam drum.

The steam drum separates the 1,800 psia steam generated by the steam generator and supplies it to the primary syngas cooler superheater (HX1112) where the steam is heated to slightly over 1,000 oF using the hot syngas leaving the steam generator. This superheated steam is combined with the HP superheated steam from the combustion turbine HRSG and fed into the steam turbine for power generation. The steam can be attemporated with boiler feedwater as required to control temperature.

High pressure boiler feedwater at 1,900 psia and 260 oF is supplied to the primary syngas cooler economizers (HX1114 and HX1116) from the HRSG boiler feedwater pumps and is heated to nearly saturation temperature using the syngas leaving the superheater. The boiler feedwater enters HX1116 first then flows into HX1114 before entering the steam drum. The syngas exiting HX1116 will have been cooled to around 600 oF before entering the particulate control device (PCD - FL1106).

As with the primary syngas coolers, there are two PCDs per gasifier train. This is primarily for manufacturing/transportation reasons, but having a filter system at the exit of each syngas cooler also balances the syngas flow between the two coolers. Each PCD will consist of a number of metal filter elements, approximately 6.6 ft long and about 2.4 in. in diameter. Based on the operating experience at the PSDF, a minimum operating life of 8,000 hours is expected on these filter elements. The particulate is separated from the syngas and accumulates on the outer surface of the filter elements. Periodically (based on a timer sequence) a small percentage of the filter elements are pulse cleaned using clean syngas from the recycle gas compressor (CO1008). By pulse cleaning a small percentage of the elements on a regular time interval, the pressure drop across the filter system will remain essentially constant during operation. The particulate loading of the syngas exiting the PCD is projected to be less than 0.1 ppmw, which has been routinely demonstrated at the PSDF and is well below the limits set for the combustion turbine. A failsafe device is installed into each filter element to protect the turbine and downstream equipment from particulate-related damage in the event of a filter element failure or leak. The particulate free syngas from the two PCDs is combined and flows into the syngas scrubber (CL1007).

The solids leaving the PCDs are cooled in PCD fines receiver (HX1118) before flowing into the continuous fine ash removal system (CFAD – FD1120). Like the CCAD system discussed in section 5.2.2, this is a proprietary Southern Company design which takes the cooled, pressurized solids from the PCD fines receiver and depressurizes them to


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nearly atmospheric pressure. The gas which is vented off of the CCAD and CFAD units is collected into the pressure letdown device (PLD) vent drum (DR1043) and is used to pneumatically convey the solids leaving these devices to the silos. The remaining vented syngas flows to the WSA combustor (AH0070) where it is oxidized.

The cool, depressurized gasifier ash is then pneumatically conveyed to the ash storage silo (SI0008) for removal. Because of the small particle size of these solids, they are not reused in the gasifier for bed material. The gasifier ash is mixed with water in the ash moisturizer (MX0002) before being hauled away from the facility by truck and landfilled or returned to the mine for site reclamation.

Since solids are conveyed to the coarse ash silo and the ash storage silo by syngas, the syngas must be separated from the solids and safely burned before being vented to the atmosphere. There is a baghouse on top of each silo, and the syngas exiting the baghouse is first cooled by the LP vent gas compressor precooler (HX0040) before entering the LP vent gas compressor (CO0041). The vent gas compressor raises the pressure of the near-atmospheric syngas, leaving the silo baghouses to the pressure required to enter the WSA combustor (AH0070) where the syngas is combusted.

5.2.4 Syngas Cooling and Water Gas Shift – Figure 5.3.4

Almost all of the equipment in figure 5.3.4 is used to minimize the gaseous emissions from the gasification unit. Most of this equipment has specific temperature requirements, and the heat exchangers in figure 5.3.4 are primarily there to meet these requirements or to heat the product syngas before it enters the combustion turbine.

The facility is designed to capture 65 percent of the carbon in the lignite as CO2, and sell the CO2 as a product. However, to remove this large amount of CO2, the syngas composition leaving the gasifier must be modified. This is accomplished by using two stages of WGS reactors in series (RX1108 and RX1109). The catalyst in the WGS reactors changes the syngas composition by the following reaction:

CO + H2O ↔ H2 + CO2 This conversion decreases the carbon monoxide (CO) and water composition in the syngas while increasing the amount of hydrogen and CO2 in the syngas. Because the gasifier is dry fed instead of slurry fed, and the particulate is removed with a dry filter system instead of a quench system, the syngas leaving the PCD has a relatively low water content. To “shift” the significant amount of CO to CO2 required, the syngas must first be saturated in the syngas scrubber (CL1007).

The syngas entering the syngas scrubber is contacted with water counter-currently over multiple packed beds. The syngas leaving the syngas scrubber has adequate moisture for the downstream WGS reactions. The syngas scrubber also provides additional cleaning for the syngas. The water removes essentially all soluble compounds such as chloride and fluoride and thus protects the downstream catalyst beds from contamination. A portion of the circulating water from the syngas scrubber is purged to


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the sour water area for cleanup. Because this is the first process step in which syngas is directly contacted with water, the syngas scrubber has the ability to remove any light organic compounds that may collect in the sump of the column.

A significant amount of makeup water must be added to the column to replace the water that is vaporized into the syngas. As the syngas is cooled, any excess water condenses and is removed from the syngas in the intermediate temperature syngas cooler (HX1021) and the process condensate knockout drum (DR1010). This water is pumped back to the column using the process condensate pump (PU1010) and heated with LP steam in the process condensate trim heater (HX1027). The remaining makeup water is a portion of the water condensed from the lignite drying described in section 5.2.1. Some of the condensate leaving the recovered water drum (DR0004) flows through the sour water system where it picks up heat in wastewater cooler (HX0056) and is further heated with LP steam in the makeup water trim heater (HX0059) before entering the syngas scrubber. These heat exchangers can be found on figure 5.3.9.

The pump-around water exiting the syngas scrubber is reheated using a combination of process heat and intermediate-pressure (IP) steam. The circulating water first enters the scrubber pump around heater (HX1007) where it is heated by cooling the syngas leaving the second WGS reactor. The circulating water is further heated to near saturation temperature by IP steam in the scrubber pump around IPS heater (HX1008).

The syngas leaves the syngas scrubber saturated with water and flows to the first WGS reactor (RX1108). The exothermic WGS reaction is catalyzed with cobalt and molybdenum active metals over a high surface area support. The energy released by this reaction is used to heat the syngas entering RX1108 via the shift feed recuperator 1 (HX1009).

A greater percentage of the CO is converted to CO2 in the first stage WGS reactor. Because of the exothermic reaction and the large quantity of CO converted, the temperature of the syngas leaving HX1009 is still fairly high, so some of this heat is transferred from the “sour” syngas leaving the HX1009 to the “sweet” product syngas in the high temperature syngas recuperator (HX1020). Heating of the product syngas will be further described in this section.

The “sour” syngas exits HX1020 and enters the shift feed recuperator II (HX1011) where it is reheated before entering the second stage WGS reactor (RX1109). The second stage WGS reactor converts additional CO to CO2 so it can be removed in the Selexol unit.


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The next process for minimizing emissions is the COS hydrolysis reactor (RX1104). The sulfur entering the gasifier in the process is primarily converted to H2S, however, a small percentage of the sulfur is converted to carbonyl sulfide (COS). If not converted to H2S and removed, the COS entering the Selexol unit would exit with the product CO2, and would be of sufficient quantity to exceed the total sulfur concentration in the product CO2 specification. Therefore, the COS is converted to additional H2S through the following reaction:

COS + H2O ↔ H2S + CO2 More than 95 percent of the COS will be converted to H2S over an alumina-based nickel-molybdenum or cobalt-molybdenum catalyst. The COS hydrolysis reactor requires an inlet gas temperature of approximately 400 oF, so the syngas exiting the second WGS reactor is first cooled in HX1011 and HX1007 as previously described. Even though the reaction is exothermic, there is so little COS in the syngas that there is no appreciable rise in temperature across the COS hydrolysis reactor.

After the gas leaves the COS hydrolysis reactor, the next clean-up step is the removal of ammonia from the syngas in the ammonia scrubber (CL1006). Any ammonia entering the combustion turbine in the syngas will most likely be converted to NOX. Therefore, to minimize NOX emissions, ammonia is scrubbed from the syngas. As in the syngas scrubber (CL1007), the syngas entering CL1006 will be contacted with water flowing counter-currently over packed beds. However, to efficiently remove the ammonia from the syngas, this must occur at near ambient temperatures. The 400 oF syngas leaving the COS hydrolysis reactor is cooled in the low temperature syngas recuperator (HX1022).

The syngas then enters the intermediate temperature syngas cooler (HX1021) where heat is transferred to the tempered water system and used for coal drying. The water that condenses during cooling is separated from the syngas in the process condensate knockout drum (DR1010), where it is returned to the syngas scrubber for makeup as previously described. HX1021 provides the majority of the heat for the tempered water system.

The syngas is further cooled, first with tempered water in the low temperature syngas cooler (HX1024) and then with cooling water in the low temperature syngas trim cooler (HX1025) before entering the ammonia scrubber. The additional water that condenses from the syngas as it is cooled is separated in the sump of the ammonia scrubber. Water is circulated through the column using the sour water pump around pumps (PU1006). Since water from the syngas is condensing in the ammonia scrubber, the excess water is purged to the sour water system described in section 5.2.9. The syngas leaving the ammonia scrubber is about 10 to 20 oF above ambient temperature.

The Selexol system (described in section 5.2.6) operates at below ambient temperatures. The product syngas leaving Selexol is cross-exchanged with the sour syngas in the AGR feed product exchanger (HX1060) to minimize the temperature of the sour syngas entering the Selexol system and reduce the refrigeration duty.


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The sweet product syngas exits the Selexol system at below ambient temperatures, but the design temperature of the syngas entering the turbine is 450 oF. To reheat the syngas efficiently, and minimize steam usage, heat is transferred from the sour syngas through three exchangers as previously described. The first of these is the AGR feed product exchanger (HX1060) where the syngas is heated to around 75 oF. The syngas exiting HX1060 then enters the mercury adsorber (RX1106) where the mercury in the syngas is absorbed on a sulfur-on-alumina adsorbent. The syngas leaving the Selexol unit has a very low water content and is superheated in HX1060, eliminating the possibility of water condensation in the mercury adsorber. The syngas exiting the mercury adsorber flows through a filter system (FL1010) to protect the combustion turbine from any adsorbent fines that may exit the mercury adsorber. The syngas is further heated in the syngas recuperators, HX1022 and HX1020, with the hot sour syngas as previously described before entering the export syngas trim heater (HX1023) where it is heated with MP steam before entering the combustion turbine (as shown on figure 5.3.11).

After the syngas passes through the mercury adsorber, but before entering the low-temperature syngas recuperator, HX1022, a portion of the product syngas is diverted to the recycle gas compressor (CO1008). The pressure of the syngas is increased and it is used in several places throughout the gasification process. The primary uses are aeration gas in the transport gasifier, pulse gas in the PCD, and “stripping” gas in the AGR concentrator column (CL1064) (described in section 5.2.6).

As described in section 5.2.2, the gasifier is initially heated by combusting diesel fuel. This exhaust gas does not go to the combustion turbine, but is vented to atmosphere through the start-up stack (ST1099). When the gasifier reaches a temperature of around 1,700 °F, coal feed begins. The diesel injection stops, while the air flow to the gasifier is adjusted, and the gasifier transitions from an oxidizing environment to a reducing environment. During this time the syngas will be burned in the HP flare (BR1098). Once the syngas flow and quality is sufficient to enter the combustion turbine, flaring of the syngas will stop. However, if there is a trip of the gasification system or the combined cycle, the syngas will be burned in the HP flare on an emergency basis until the unit can be brought back online or safely shut down.

5.2.5 Air Supply System – Figure 5.3.5

The TRIG gasifier at Kemper will be an air-blown (vs. oxygen-blown) gasifier. The majority of the air supplying the gasifier is supplied by two multi-stage centrifugal compressors per train (the process air compressors – CO1102 and CO1202).

Additional air is extracted from the combustion turbine compressor. This air leaves the compressor at approximately 260 psia and 800 oF. To be used in the gasifier, the pressure of the air must be increased to slightly more than 700 psia by the extraction air compressor (CO1004), however, the air must be cooled first before it can be compressed. Most of the heat is transferred to the air entering the gasifier in the extraction air recuperator (HX1028). Additional cooling of the air occurs with tempered water in the extraction air cooler (HX1029) and with cooling water in the extraction air


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trim cooler (HX1019). Any water that condenses from the air is separated in the extraction air compressor knockout drum (DR1003) before the air enters CO1004. The air leaving CO1004 combines with the air leaving the process air compressors.

Coal is conveyed into the gasifier using a portion of this combined air stream, but the pressure of the conveying air must be increased to more than 750 psia using the transport air compressor (CO1005). This air must have a very low water content, so it is first cooled and any condensed water is separated before it enters the compressor. After the air is compressed in CO1005, it is cooled in the transport air cooler (HX1006) with cooling water and any condensed water is separated from the air in the transport air cooler knockout drum (DR1012) before the air enters the transport air dryer (PG1007) where it is dried to a very low dewpoint. This air is then used to convey the coal exiting the coal feeder (FD1116A/B).

The quantity and pressure of air required for startup is relatively low and is supplied by the air separation unit (ASU)/startup air compressor (CO0106). During normal operation this compressor also supplies air to the cryogenic ASU which produces the nitrogen used by the process.

5.2.6 Acid Gas Removal System – Figure 5.3.6

The acid gas removal system is a multi-column Selexol unit which removes essentially all of the H2S and a majority of the CO2 from the syngas stream. The syngas exiting the AGR feed product exchanger (HX1060), first enters the AGR H2S absorber (CL1060) where the H2S is removed using the Selexol solvent. The syngas then enters the AGR CO2 absorbers (CL1161/CL1261/CL1361) where the CO2 is also removed from the syngas using the Selexol solvent. Because of the large amount of CO2 removed from the syngas, there are three of these columns per train. The sweet gas exits the AGR CO2 absorber at a low temperature and is reheated before being burned in the combustion turbine (described in section 5.2.4).

The Selexol solvent circulates through the system in two separate loops: one loop — the lean solvent loop — provides solvent for H2S removal, and the other loop — the semi-lean solvent loop — provides solvent for the bulk of the CO2 removal. Both streams flow through the AGR CO2 absorber and that will be the starting point for the discussion, starting with the lean solvent loop.

Lean solvent enters the top of the AGR CO2 absorber where it is used to “polish” CO2 from the syngas. (The bulk of the CO2, however, is removed in the semi-lean solvent loop discussed later in this section). It is desired to “preload” the solvent with CO2 before it enters the AGR H2S absorber so that the solvent will selectively remove the H2S from the syngas in CL1060. The combined solvent stream exits the bottom of the AGR CO2 absorbers, where it is split into two streams. The stream for the H2S removal is pumped with the AGR loaded solvent pumps (PU1166) through the AGR loaded solvent chiller (HX1169) where it is cooled with refrigerant before entering CO1060 to remove the H2S from the syngas. The other stream is the semi-lean solvent loop to be discussed below.


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The solvent passes through the H2S absorber, removing H2S from the syngas and is now referred to as “rich” solvent, since it is now rich in H2S. The pressure of the rich solvent exiting CL1060 is increased using the AGR rich solvent pumps (PU1060) to a pressure above the operating pressure of CL1060 and is heated in the AGR lean/rich solvent exchanger (HX1061) before entering the AGR concentrator (CL1064). The rich solvent entering the column is “stripped” using recycled syngas from the recycle gas compressor (CO1008), described in section 5.2.7. The purpose of this column is to remove as much of the CO2 and other light gases from the solvent as possible to make a concentrated H2S stream which will be supplied to the WSA unit (described in section 5.2.7). This concentrated stream improves the operability of the WSA unit. Since the operating pressure of CL1064 is greater than CL1060, the stripped gas will flow back to CL1060 without compression, but is first cooled in the AGR stripped gas cooler (HX1062).

The pressure of the rich solvent exiting the bottom of CL1064 is decreased across a control valve, and the decrease in pressure causes absorbed gases to flash out of the solvent. These gases are separated from the solvent in the AGR rich solvent flash drum (DR1063), and then cooled and compressed by the AGR flash gas compressor (CO1065). This gas combines with the gas from the AGR concentrator and returns to CL1060. A small flash gas stream from the sour water system (described in section 5.2.9) also enters DR1063 where it combines with the gases that flash from the rich solvent and are recycled back to CL1060.

From the AGR rich solvent flash drum, the rich solvent flows to the AGR regenerator (CL1063). In this column, the H2S and remaining CO2 are steam stripped from the solvent. The resulting acid gas stream flows to the WSA unit to be converted into sulfuric acid (described in section 5.2.7). The hot, “lean” solvent leaves the bottom of CL1063 and is pumped through HX1061 where it is cooled by heating the rich solvent leaving CL1060. It is further cooled with refrigerant in the AGR lean solvent chiller (HX1067) before it returns to AGR CO2 absorber to complete the loop.

The bulk of the CO2 removal from the syngas occurs in the semi-lean solvent loop. The circulation rate of the semi-lean loop is significantly higher than that of the “rich/lean” loop, because of the significant quantity of CO2 that must be removed from the syngas. The semi-lean solvent also enters the AGR CO2 Absorber, but at an intermediate position in the column instead of at the top and physically absorbs the CO2 from the syngas. It combines with the solvent circulating in the rich/lean loop and exits the bottom of the column where the two streams are divided.

The pressure of the loaded solvent is dropped across a valve to an intermediate pressure where “light” gases such as H2 and CH4 flash from the solvent. These gases are compressed in the AGR CO2 recycle compressor (CO1066) and returned to the AGR CO2 absorber. The pressure of the solvent is again decreased to approximately 50 psia where a significant amount of the CO2 is liberated from the solvent in the AGR MP CO2 flash drum (DR1167). The solvent flows across another valve where the pressure is decreased to approximately 5 psia and the remaining CO2 flashes from the solvent in the AGR LP CO2 flash drum (DR1168). The two CO2 product streams flow to


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the CO2 compressor (CO1080) shown on figure 5.3.8. From DR1168, the solvent is pumped back up to operating pressure and chilled with refrigerant in the AGR semi-lean solvent chiller (HX1168) before returning to the midsection of the AGR CO2 absorber.

5.2.7 Wet Sulfuric Acid (WSA) Process – Figure 5.3.7

As mentioned in the previous section, the acid gas stream is separated from the Selexol solvent in the AGR regenerator where it flows to the WSA unit to be converted to sulfuric acid (H2SO4). To be converted to H2SO4, the H2S in the acid gas stream must first be converted to sulfur trioxide (SO3) and then reacted with water vapor to produce the H2SO4.

The first step in this process is the combustion of H2S with air to SO2 in the WSA combustor (AH0070). This combustor also oxidizes several syngas vent streams from the ash removal equipment (described in sections 5.2.2 and 5.2.3). Under normal circumstances, the acid gas stream has a high enough heating value that it will burn without the addition of natural gas, but if the lignite being fed into the gasifier has a very low sulfur content, then natural gas will be added to maintain the combustor temperature.

The hot gas from the WSA combustor is cooled in the waste heat steam generator (HX0070) where MP steam is raised before entering an SCR reactor (RX0070) for thermal NOX control. The gas leaving the SCR reactor then flows to the SO2 converter (RX0071). The SO2 converter consists of multiple catalyst beds with cooling coils between each bed to remove the heat released by the exothermic conversion of SO2 to SO3. The heat released in each catalyst bed is used to superheat the MP steam generated in the waste heat steam generator. This superheated MP steam is used in the gasification process (described in section 5.2.10).

The exhaust from the SO2 converter, which contains SO3 and water vapor from the initial combustion of the H2S, flows to a vertical condenser tower (HX0074) where it is indirectly cooled with air to promote the formation of sulfuric acid. The condensed acid flows down the walls of the condenser tubes while the hot gases flowing up the tubes concentrate the acid to produce a nominal 96 to 97 wt% acid that is collected the bottom of the condenser vessel.

The vapor leaving the top of the condenser is routed to the quench column (CL0070) and scrubber column (CL0071) where the gases are cooled and the residual SO2 in the gas is reacted with hydrogen peroxide (H2O2) and recovered as sulfuric acid. Before exiting through the vent stack, the gases pass through a wet ESP (FL0071) to minimize emissions of H2SO4 droplets. The liquid acid from HX0074 flows to an acid loop where it is mixed with water and the acid recovered from the scrubber to produce commercial strength (93 percent) sulfuric acid. The acid product is cooled in the acid cooler (HX0076) and sent to the acid product tanks where it is removed by tanker truck.


Page 40

5.2.8 CO2 Compression and Selexol Refrigeration – Figure 5.3.8

The CO2 is liberated from the Selexol semi-lean solvent loop (described in section 5.2.6) at two pressure levels – approximately 50 and 5 psig. These two streams flow into the multi-stage CO2 compressor (CO1080) after passing through knockout drums (DR1078 and DR1079) to remove any residual droplets of solvent. The low-pressure CO2 enters the first stage of the compressor, and the medium-pressure CO2 enters the compressor at the inlet of the second stage. The product CO2 being delivered to the CO2 off-taker has stringent requirements for moisture as well as mercury, so all of the CO2 leaves an intermediate stage of the compressor where it passes through the CO2 dehydration package (PG1080) and then the CO2 mercury absorber (RX1080) before returning to the CO2 compressor. The CO2 is compressed to a final pressure of 2200 psia and cooled before being delivered to the CO2 pipeline.

Also shown in figure 5.3.8 is the AGR refrigeration package (PG0061). This anhydrous ammonia-based refrigeration system chills the Selexol solvent to below ambient temperatures. Cooling the Selexol increases its ability to absorb H2S and CO2 which reduces the solvent circulation rate and decreases the size of the equipment.

5.2.9 Sour Water System – Figure 5.3.9

Water condensed from the syngas or purged from the syngas and ammonia scrubbers is sent to the sour-water treatment area where the streams from both gasification trains are combined into the single waste water drum (DR0040). As the sour water streams flow into the drum, the pressure is dropped, which flashes out dissolved gases. The ammonia in the water retains most of the dissolved H2S, so the gas released from the DR0040 will primarily be CO2 and nitrogen. This vent gas stream is recycled to the AGR rich solvent flash drum (DR1063), where it is recycled to the AGR H2S absorber (described in section 5.2.6). DR0040 is a multi-phase separator designed for the removal of any organics that condense with the sour water. These organic streams are separated from the sour water and recycled back to the gasifier for destruction via the hydrocarbon drain drum (DR0047). In the event that the sour water system goes offline, the water is temporarily collected in the wastewater storage tank (TK0042) and processed when the sour water system returns to operation.

The water leaving DR0040 passes through an activated carbon bed filter (PG0040) for the removal of any dissolved organics and heavy metals before being heated in the hydrogen sulfide stripper feed preheater (HX0041) entering the hydrogen sulfide stripper (CL0042). In CL0042, the sour water is stripped with heat from steam, causing the dissolved H2S, CO, and CO2 to be released from the water. These gases also flow to DR1063 and onto the AGR H2S absorber.

The pH of the stripped water leaving the bottom of CL0042 is adjusted with caustic before passing to the steam heated wastewater ammonia stripper (CL0044) where dilute ammonia is removed from the water and condensed in the wastewater ammonia stripper reflux drum (DR0045). The stripped water from CL0044 flows through HX0041 to heat the sour water and cool the stripped water. Additional heat from the stripped


Page 41

water stream is recovered in the wastewater cooler (HX0056) where condensate from the lignite drying is heated before being used as makeup in the syngas scrubber (described in section 5.2.4). The cooled, stripped water exiting HX0056 flows into the unit’s reclaim sump. Water from the reclaim sump is used to offset makeup water required by the cooling towers.

The dilute liquid ammonia from DR0045 flows to a steam heated wastewater ammonia purifier column (CL0052) where the ammonia is concentrated and stored in the ammonia storage tank (TK0054) for sale or use in the plant SCR reactors or other SCR reactors in the Southern Company system. Because of the high purity ammonia product required, the water drawn from the bottom of CL0052 still contains appreciable ammonia and is therefore recycled to the gasifier mixing zone for destruction.

5.2.10 Steam System – Figure 5.3.10

Steam is generated at two pressures in the gasification process: high pressure, high temperature (1700 psia/1,000 oF) steam is generated in the syngas coolers (described in section 5.2.3) and medium-pressure superheated steam (820 psia/750 oF) is generated in the WSA system (described in section 5.2.7). For the most part, the high-pressure steam is supplied to the steam turbine for generating power. However, steam can be let down to supply the MP steam header if necessary. The MP steam is used as a feed into the gasifier, and for heating the product syngas before it is supplied to the combustion turbine. Excess MP steam is let down to supply the IP steam header, supplementing steam from the steam turbine. The feedwater for generating the HP steam is supplied by the gasifier island boiler feedwater pumps.

The majority of the steam “consumers” within the gasification process utilize either IP (325 psia) or LP (50 psia) steam. Even though some of the IP steam is let down from the MP steam header, the majority of the IP steam is extracted from the IP section of the steam turbine. Similarly, the LP steam is supplied from the LP section of the steam turbine as well.

After the steam is utilized and condensed in the various exchangers, the condensate is collected in collection headers at each steam pressure level. The higher pressure condensate is flashed to supply steam at the lower pressure levels. Ultimately all of the condensate is collected in the LP condensate drum (DR0090). The boiler feedwater necessary to generate the MP steam in the WSA unit is supplied from DR0090 by the MP steam generation condensate pumps (PU0092) and the rest of the condensate is returned to the HRSG. Additional low-pressure, low-temperature condensate from the HRSG is supplied to the gasification island as “cooling water” to recover low-grade heat and improve the efficiency of the overall process. This condensate is also returned to the HRSG.

5.2.11 Combustion Turbine and Heat Recovery Steam Generator – Figure 5.3.11

Syngas leaving the export syngas trim heater (HX1023) in figure 5.3.4 flows to the combustion turbine of the combined cycle unit shown in figure 5.3.11. The hot


Page 42

combustion exhaust flows over the turbine blades, powering the generator and air compressor. When leaving the gas turbine, the hot exhaust flows through the HRSG, generating high-, low-, intermediate-pressure steam. If demand warrants additional power, natural gas can be injected into the HRSG duct burners, where it combusts and provides energy to raise more steam. For gasifier startup, shutdown, or outages, the combustion turbine can also run on natural gas alone, at an efficiency penalty. Most of the air compressed in the turbine air compressor is used for combusting the syngas with the excess flowing to the gasification island air supply system via the extraction air compressors described above.

5.2.12 Steam Turbine and Auxiliary Boiler – Figure 5.3.12

As shown in figure 5.3.12, steam raised in the two HRSGs combines with steam produced in the gasifier island syngas coolers and flows into the high-pressure stages of the steam turbine, allowing the generator to rotate and produce power. The resulting cold reheat flows back to the HRSG for heating, producing hot reheat to send to the intermediate-pressure stage of the steam turbine. Some of the IP steam is extracted to provide the gasifier island IP steam supply. The remainder flows to the low pressure stage of the steam turbine, and then on to the steam condenser.

Figure 5.3.12 also shows the auxiliary boiler. The auxiliary boiler provides steam to the unit during startup and shutdown, when sufficient steam for equipment operation is not available.

5.2.13 Steam Condenser – Figure 5.3.13

The steam turbine condenser is shown in figure 5.3.13. The exhaust of the LP stage of the steam turbine flows into the condenser, where water from the cooling towers removes heat. The remaining water vapor condenses and flows into the condenser hotwell. The hotwell supplies water to the HRSG via the boiler feed pumps on figure 5.3.11. The hotwell also supplies condensate to the heat exchangers in the gasifier island, including the primary gas coolers.

As the system operates, some steam is lost to the process through steam injection to the gasifier and other process units. That water is made up from the demineralized water tank.

5.2.14 Cooling Water and Tempered Water Systems – Figure 5.3.14

Southern Company typically uses a closed-loop cooling system for heat exchangers. The closed loop circulates demin quality water, and therefore avoids the fouling/plugging issues that can be caused by circulating cooling tower water through heat exchangers, especially at low cooling loads. The Kemper County IGCC project uses such a system for the majority of the heat exchangers in the gasification process. Heat is rejected to the 10-cell, mechanical draft cooling tower by cross-exchanging the water circulating in the closed loop with the water circulating in the cooling tower loop.


Page 43

The downside to using such a system is that because of the heat exchanger, temperature approach between the cooling tower and the closed loop circulation system (the coldest temperature in the closed-loop cooling system) is about 10 oF warmer than the coldest temperature in the cooling tower loop. There are two exchanger services where the colder water is needed – the venturi scrubber pump around cooler (HX1104) in the coal preparation area (section 5.2.1) and the CO2 compressor aftercooler (HX1085); these are both located on the cooling tower loop.

The tempered water loop is a circulating hot water system used to transfer low-grade heat from process exchangers to the fluid bed dryer system. The tempered water system operates at a constant flowrate of water at the discharge of PU0094. Under all conditions, this flowrate provides a greater heating capacity than needed by the process exchangers so adequate cooling media will always be available.

5.2.15 Nitrogen and Flare System – Figure 5.3.15

Nitrogen is generated in a cryogenic air separation unit (ASU - PG0096). LP nitrogen at approximately 115 psia is supplied from the ASU to a LP nitrogen header. Additional nitrogen is pressurized to an intermediate pressure (725 psia) as well as high pressure (900 psia) using the nitrogen compressor (CO0096). Liquid nitrogen will be stored onsite (PG0097) as a backup in the event that the ASU trips. During normal operation, the ASU will produce liquid nitrogen to fill the storage system, or it can be trucked to the site.

Three separate flare systems exist at the facility – the HP flares (BR1098/BR2098), the ammonia flare (BR0099), and the LP/acid gas flare (BR0097). The HP flares are used during startup to combust the syngas produced before it is of sufficient quantity and/or quality to enter the combustion turbine. The HP flare is also used during a plant trip to safely combust the syngas during shutdown. The ammonia flare and the LP/acid gas flares are sized to combust gases that would be released from safety valves on these systems in the event of an emergency. These systems are separate from one another primarily because of differing materials of construction requirements and possible chemical interaction of these two systems.

5.2.16 Chemical Storage – Figure 5.3.16

In addition to the CO2 used for EOR, the Kemper IGCC facility also produces anhydrous ammonia and sulfuric acid. Both of these chemicals will be loaded from storage tanks into trucks to be hauled away from the site for beneficial use by others. In addition to these storage tanks, tanks are onsite to provide storage for the bulk chemicals used by the facility. The AGR Selexol storage tank (TK0060) provides storage for the Selexol solvent, especially during plant outages. Sodium hydroxide is stored in TK0095 to provide caustic for the sour water system. Hydrogen peroxide is stored in TK0070 for use in the WSA facility.


Page 44

5.3 PROCESS FLOW DIAGRAMS


Page 45

PG1102

FD1102

TO SI1202, 1302,2102, 2202,2302

TO ATMAT SAFE

LOCATION

BL0002

SI1102

PLANTAIR

COAL FROM NAC

FL0002

FN1102

ML1107

FL1103

FD1103

FROM SI1202/1302/2102/2202/2302

TEMPERED WATER SUPPLYFIG. 5.3.11

LP STEAMFIG. 5.3.10

TEMPERED WATER RETURNFIG. 5.3.11

LP CONENDSATEFIG. 5.3.10

FN1105

ML1108

M

FN1106

COAL TO SI1110A

FIG. 5.3.2

FL1104

FD1104A

TO FD1104B

FL0005 A/B

PU1101A/B

PU0008A/BPU1104A/B

DR0004

WATER TO HX0056

FIG. 5.3.9

HX1104

WATER TO CAUSTIC MIXER

FIG. 5.3.13

TO CL1201, 1301, 2101, 2201, 2301

FROM PU1204, 1304, 2104, 2204, 2304

CL1101

PU0002A/B

WATER TO CL1006

FIG. 5.3.4

TOWERWATER

WATER TO DISCHARGE

FIG. 5.3.9

PU0005A/B

DR0006

FROM PU1201, 1301, 2101, 2201, 2301

MX0006

PU0009A/B

DR0002

BACK-UPWATER

FL0001

BACK WASH

BALANCE LINE FROM SI1110A

FIG. 5.3.2

FD1108

M

VENT TO SAFE

LOCATION

BACKFILL TO MINE

LP N2

LP N2

Figure 5.3.1 – Coal Preparation


Page 46

BALANCE LINE TO FL1104FIG. 5.3.1

COAL FROM FD1104AFIG. 5.3.1

TRANSPORT AIR FROM PG1007FIG. 5.3.5

SYNGAS TO HX1110

FIG. 5.3.3

RECYCLE GAS FROM CO1008

FIG. 5.3.4

AH1102

MPS FROM HEADERFIG. 5.3.10

TO RX2002FROM

FD1216, 1316

FROMFD2011

FD1011

SI1110A/B

FD1110A/B

FD1115A/B

FD1116A/B

TO AH1202, 1203, 1303, 2102, 2103, 2202, 2203, 2303

TO RX2002

DIESEL FROM SCS

AH1103

NAT GAS FIG. 5.3.12

PROCESS AIR FROM HX1028FIG. 5.3.5

AMMONIA/WATER FROM PU0054FIG. 5.3.9

FD1130

HX1130

FROMFL2030

DR1030

RX1002

CONVEYING GAS FROM DR1043

FIG 5.3.3

VENT TO DR1043

FIG. 5.3.2

VENT TO AH0070

FIG. 5.3.7

COND FROM HX0031

FIG 5.3.10

COND TO HX1118

FIG. 5.3.3

COND RETURN TO HRSG

FIG. 5.3.10

FL0007

FD0007

SI0007

(NNF)

VENT TO HX0040FIG. 5.5.3

SOLIDS BY TRUCK

SOLIDS TO SI0008

FIG. 5.3.3

SOLIDS TO SI0008

FIG. 5.3.3

TO RX2002

IP N2

FL1130

LP N2

HP N2

HP N2

HYDROCARBON LIQUIDS FROM PU0047FIG. 5.3.9

LP N2

HP N2

LP N2

LP N2

Figure 5.3.2 - Coal Feed, Transport Gasifier and Solids Makeup


Page 47

TO HX1210SYNGAS FROM RX1002FIG. 5.3.2

RECYCLE GAS FROM CO1008

FIG. 5.3.4

SYNGAS TO CL1007

FIG. 5.3.4

HX1114

FROM HX1210

TO HX1212

TO HX1210

FROMHX1214

FROM HX1212

TO HX1216

HX1118

FROMFL1206

TOFL1206

FROM FL1220, 2120, 2220

FROM FD1220

FL1106

DR1008

HPBD

HX1110

HX1112

HX1218

HP STEAMFIG. 5.3.10

BFWFIG. 5.3.10

FD1120

COND FROM

DR1030FIG. 5.3.2

COND TO HRSGFIG. 5.3.10

FD0009A/B/C/D

GASIFIER ASH FROM FL1130FIG. 5.3.2

FL0008A/B/C/D

SI0008A/B/C/D

MX0002A/B/C/D

WATER FROM SCS

CO0041

FROMDR2043

CW

DR1043

VENT GAS FROM FD1130

FIG 5.3.2

FROMFD2130

MAKEUP GAS FROM FL1010

FIG. 5.3.4

VENT TO AH0070FIG. 5.3.7

FROMFD2120

GAS TO FL1130FIG. 5.3.2HX0040

TRUCK

VENT TO AH0070FIG. 5.3.7

VENT FROM FL0007FIG. 5.3.2

FL1120

TO SOUR WATER

FIG. 5.3.3

HX1116

LP N2

LP N2IP N2

7

Figure 5.3.3 - Syngas Cooling and Particulate Removal


Page 48

SOUR WATER TO DR0040FIG. 5.3.9

SYNGAS FROM FL1106, 1206FIG. 5.3.3

HX1020 HX1022

RX1104

(START-UP)

(NNF)

RX1108

CL1007

HX1009

PU1010A/B

PU1007A/B

HX1007

IPS

HX1008

TMW

HX1021

WATER FROM HX0059FIG. 5.3.9

LPS

HX1027

SYNGAS TO GAS TURBINE A

MPS

HX1023

HEAVY ORGANICS TO DR0047FIG. 5.3.9

RX1109

HX1011

LIGHT ORGANICS TO DR0047FIG. 5.3.9

DR1010

CW

HX1025

TMW

HX1024

RECYCLE GAS TO RX1002FIG. 5.3.2

RECYCLE GAS TO FL1106FIG. 5.3.3

WATER FROM PU0008

FIG. 5.3.1

SWEET GAS FROM DR1061

FIG. 5.3.6

SOUR GAS TO CL1060FIG. 5.3.6

RX1106

CO1008

PU1006A/B

1

2

CL1006

SWEET GAS TO DR1043

FIG. 5.3.3

DR1009

FL1010

HX1060

DR1060

HP SOURWATER DRAIN

SOUR WATER TO DR0040FIG. 5.3.9

TO SOUR WATER(NNF)

LIGHT ORGANICS TO DR0047FIG. 5.3.9

RECYCLE GAS TO CL1064FIG. 5.3.6CW

HX1032

ST1099

TO HP FLAREFIG. 5.3.11

FROM DR2010

Figure 5.3.4 - Syngas Cooling and Water Gas Shift


Page 49

M

FL1209

DRAIN

PROCESS AIR TO RX1002FIG. 5.3.2

DR1005 CO1005

CW

HX1006

PG1007

TRANSPORT AIR TO FD1116FIG. 5.3.2

TO FD1216, 1316

DRAIN

FEED AIR TO PG0096FIG. 5.3.12

AIRFROMATM

DRAIN

CWHX1026

TMW

HX1005

CO1004

EXTRACTION AIR FROM GAS

TURBINE

DRAIN

CW HX1019 TMW HX1029 HX1028

DR1003

AIRFROMATM

FROM CO0206

FL0111

CW

CW

HX0003

DRAIN

START-UP

TO HX2005/HX2028

CW (TEWAC)

DR1012

DRAIN

CW

CO0106

M

FL1109

DRAIN

AIRFROMATM

CW (INTER-STAGE)

CW (TEWAC)

CO1102

CO1202

CW (INTER-STAGE)

Figure 5.3.5 - Air Supply System


Page 50

PU1060A/B

PU1068A/B/C/D

PU1067A/B

SWEET GAS TO HX1060FIG. 5.3.4

CL1060

SOUR GAS FROM DR1060FIG. 5.3.4

PU1166A/B

CO1066

DR1167

LP CO2 TO CO1080

FIG. 5.3.8

DR1061

CL1161

FL1060DEMINWATER

LP N2 FILTERCAKERECOVERED

SOLVENT TO SUMP

DR1168

FROM CL1261,

1361

FROMCL1261 CL1361

TOCL1261,

1361

TOHX1268,

1368

TOCL1261,

1361MP CO2 TO

CO1080FIG. 5.3.8

PU1058A/B

TO DR1266

FROM DR1268

DR1166

FROM DR1267

FROM DR1268

FROM DR1266

DR1054

DR1155

HX1067

HX1168

DR1153

REFRIGRETURN

HX1169

FROMHX1269, 1369

REFRIGSUPPLY

REFRIGSUPPLY

REFRIGRETURN

REFRIGSUPPLY

REFRIG RETURN

CW

HX1066

TW

HX1061

DR1062

1

10

CL1063

IPS

HX1063A/B

PU1064A/B

H2S ACID GAS TO RX0070FIG. 5.3.7

PU1063A/B

FROMDR2064

GAS FROM CL0042FIG. 5.3.9

AGR PURGE WATER TO

CL0044FIG. 5.3.9

CL1064

DR1063

DR1065

DR1064

MAKEUP WATER

FIG. 5.3.11

RECYCLE GAS FROM CO1008FIG. 5.3.4

FROMPU2064

DR1069A/B

CW

HX1065

CW

HX1062

CW

HX1080

CW

HX1064CO1065

TW

SELEXOLFROM FL0061

FIG. 5.3.13

IPC RETURNFIG. 5.3.10

Figure 5.3.6 - Acid Gas Removal System


Page 51

PU0075A/B

H2S ACID GAS FROM DR1064FIG. 5.3.6

NATGAS

5.3.12AH0070

HX0070

DR0070

LPCPU0092

FIG. 5.3.10

MP BDFIG. 5.3.10

RX0071

MPSTO

FIG. 5.3.10

HX0074

PU0070A/B CW HX0076

PG0070 A/B

CL0070

CL0071

PU0073A/B

BL0072

H2O2 FROM

PU0074FIG. 5.3.13

FL0071

DR0071

BL0070

(ATM)

BL0071

SULFURIC ACID TO TK0071

FIG. 5.3.13

RX0070

ELECTRIC

HX0075

NATURALGAS

FIG. 5.3.12

FL0070LP VENT GAS FROM SI0007/SI0008FIG. 5.3.6

OFF GAS FROM DR0047FIG. 5.3.9

(NNF)

HX0073

HX0072

HX0071MX0070

START-UP STEAM

IPS FIG. 5.3.10

DEMIN WATER

FIG. 5.3.4

PU0071A/B

NH3 FROM TK0054FIG. 5.3.9

ELECTRIC

HX0077

HOT AIR VENT TO ATM

PU0072A/B/C

ST0060

VENT FROM FD1130FIG. 5.3.2

FROM FD2130

LP VENT GAS FROM DR1043

FIG 5.3.3

Figure 5.3.7 - Wet Sulfuric Acid (WSA) Process


Page 52

PG1080

CWHX1085

CO2 PRODUCT

RX1080

FL1082

LP CO2 FROM DR1168FIG. 5.3.6

MP CO2 FROM DR1167FIG. 5.3.6

FROM HX2085

M

CW (INTER-STAGE)

CW (MOTOR)

LP SOURWATERDRAIN(NNF)

HP SOURWATERDRAIN(NNF)

DRAIN TO AGR SUMP

A1057

DRAIN TO AGR SUMP

A1057

DR1078

DR1079

CW (TEWAC)

REFRIGERANT TO AND FROM DR1054/DR1153/DR1155

CW (INTER-STAGE)

PG0061

CO1080

CW

Figure 5.3.8 - CO2 Compression and Selexol Refrigeration


Page 53

PU0047A/B

PU0040A/B

IPS

12

1

5

CL0042HX0041

PG0040

DR0040

(NNF)

OFF GAS TO AH0070FIG. 5.3.6

TK0042

PU0042

DR0047

FROM CL2006

WASTEWATER FROM PU0097/0099FIG. 5.3.10

SOUR WATER FROM CL1006FIG. 5.3.4

LPS

GAS TO DR1063FIG. 5.3.6

SOUR WATER FROM CL1007FIG. 5.3.4

FROM CL2007

HEAVY ORGANICS FROM DR1010FIG. 5.3.4

LIGHT ORGANICS FROM CL1007FIG. 5.3.4

LIGHT ORGANICS FROM CL1006FIG. 5.3.4

HYDROCARBON LIQUIDS TO RX1002FIG. 5.3.2

CO1080FIG. 5.3.8

(NN

F)

(NNF)(NNF)

(NNF)

(NNF)

(NNF)

DR1043/2043FIG. 5.3.3

(NNF)

(NNF)

HX0042

AGR PURGE WATER FROM PU1064FIG. 5.3.6

CAUSTIC FROM PU0095FIG. 5.3.13

TO DR2063

FROM DR2010

FROM CL2006

FROM CL2007

(NNF)

WATER FROM PU0002

FIG. 5.3.1

AMMONIA/WATER TO RX1002FIG. 5.3.2

19

1

4

CL0044

IPS

TMW

HX0045

DR0045

PU0045A/B

CW

HX0046

IPS

1

6

3

CL0052

CW

HX0054

PU0057A/B TO RX2002

ANHYDROUS AMMONIA TO SCS

PU0050A/B

HX0056

WATER FROM PU0008

FIG 5.3.1

WATER TO CL1007

FIG. 5.3.4

LPS HX0059

PU0053A/B

CWHX0051

PG0054

STRIPPED WATER TO RECLAIM SUMP

PU0054A/B

NH3 TO RX0070FIG. 5.3.7

DR0051

LP COND FROM

PU0090 FIG. 5.3.10

HX0044

HX0052

TK0054

DR1060/2060FIG. 5.3.4

DR1009/2009FIG. 5.3.4

CO1080/2080FIG. 5.3.8

PG1080/2080FIG. 5.3.8

(NN

F)

(NNF)

(NNF)

(NNF)

LP N2

DR1043FIG. 5.3.3

(NNF)

Figure 5.3.9 - Sour Water System


Page 54

MP STEAM HEADER .

MPS TO RX1002

FIG. 5.3.2

HPS FROM

TRAIN 2

(NNF)

FIG. TAG5.3.4 HX1023

FIG. TAG5.3.3 HX11105.3.3 HX11125.3.3 HX11145.3.3 HX1116

FIG. TAG5.3.7 HX00715.3.7 HX0072

FIG. TAG5.3.7 HX00735.3.7 HX0070

DR0091

LP STEAM HEADER

DR0095

DR0090 HRSG COND

HX0090

PU0090A/B

TMW HX0091

PU0092A/B

IP STEAM HEADER

SP1060

LP CONDENSATE HEADER

DR0092

BLOWNDOWN TO RECLAIM SUMP SCS FLOW DIAGRAM

COND RETURN FROM HX1030/2030 AND HX1118/1218/2118/2218

HRSG COND

HX0031

TO TK0054

FIG. TAG5.3.4 HX10085.3.7 DR00705.3.9 HX00425.3.9 HX00445.3.9 HX0052 FIG. TAG

5.3.6 HX1063

FIG. TAG5.3.1 PG11025.3.4 HX10275.3.9 DR00475.3.9 HX0059

5.3.11 HX00955.3.13 TK0095

TRACING

FIG. TAG5.3.10 HX00905.3.10 HX0031

IP CONDENSATE HEADER

CONDTO

DR2030

HPS TO STEAM TURBINE

START-UP STEAM FROM AUX BOILER

STEAM FROM ST/HRSG

STEAM FROM TURBINE

BFW FROM BFW

PUMPS

STEAM FROM HRSG MAIN STEAM HEADER

COND TO DR1030

FIG. 5.3.2

CONDENSATE TO HRSG

CONDENSATE FROM CONDENSATE PUMPS

Figure 5.3.10 – Steam System


Page 55

COMBUSTOR

FINAL FUELSEPARATORS

HEAT EXCHANGERFINAL FUEL GAS

STATION

FUEL GAS CONDITIONING

FIG.5.3.12 TO COMBUSTOR TRAIN “B”

FIG.5.3.4

MAIN STEAM TO STEAM TURBINE

DRUMIP

IP E

CO

NO

MIZ

ER

DSH #1

HP

SH

HP

SH

HP

ECO

NO

MIZ

ER

LP DRUMDRUMHP

DSH #2

HP

SH

DSH

IP S

H

HOT REHEAT STEAM TO IP

STEAM TURBINE

RE

HE

ATE

R

RE

HE

ATE

R

COLD REHEAT STEAM FROM

HP STEAM TURBBINE

FIG.5.3.13

TO CONDENSER

BACKUP PEGGING STEAM FROM SYNGAS COOLERS/

AUX BOILERHP PEGGING STEAM

HRSG "A"

#1 HP STEAM ATTEMP SPRAYWATER

#2 HP STEAM ATTEMP SPRAYWATER

DUCT BURNER

SEAL AIR FAN

DAMPERISOLATION

AUGMENTATION AIR FANS

NAT. GAS FROM PIPELINE

FIG.5.3.12

CT”A”

FIG.5.3.12

FIG.5.3.12

FIG.5.3.12

IP ECONOMIZER FEEDWATER TO GAS HEAT EXCHANGER

CHEMICALFLUSH

BOILER FEED PUMPSCT/HRSG "A"

HP FEEDWATER DISCHARGE

IP FEEDWATER DISCHARGE

BOILER FEED PUMP SUCTION

NO

X IN

JEC

TIO

N S

TEA

MA

TTE

MP

. SP

RA

YW

ATE

R

HP SPRAYWATER TO HP STEAM BYPASS ATTEMP

FIG.5.3.12

IP SPRAYWATER TO 325 PSIA PROCESS STEAM ATTEMP

GI BOILERFW PUMP TRAIN "A"

FEEDWATER TO GITRAIN "A"

FIG.5.3.10

FIG.5.3.12

CHEMICALCLEANING

FLUSH

FIG.5.3.12

HP SPRAYWATER TO GI MP STEAM ATTEMP

FIG.5.3.12

HP SPRAYWATER TO BACKUP 805 PSIA STEAM

ATTEMP

FIG.5.3.12

HP SPRAYWATER TO BACKUP PEGGING STEAM ATTEMP

TO CONDENSER

FUEL GAS AUX BOILER

AIR FROM ATM

NOX INJECTION FROM COLD REHEAT(ONLY WHEN DUCT BURNING)

FIG.5.3.12

FIG.5.3.13

AIR

AIR COMPRESSOR

ATTEMP

TO HRSG STACK

GENERATOR

FIG.5.3.13

FROM CONDENSATE PUMPS

TO EXTRACTION AIR COMPRESSOR

FIG.5.3.5

FIG.5.3.13

IP BYPASS TO CONDENSER NECK

(NNF)

ATTEMPERATOR SPRAYWATER

(NNF)

(NNF)

Figure 5.3.11 – Combustion Turbine and Heat Recovery Steam Generator


Page 56

MAIN STEAM

HP IP LP LP GENERATOR

FIG.5.3.13

STEAMTURBINE

FIG.5.3.10

HP STEAM BYPASS TRAIN “A” TO CONDENSER

FROM HRSG "A"

ATTEMP

FIG.5.3.11

ATTEMP

ATTEMPFIG.5.3.11

FIG.5.3.11

FIG.5.3.11

FROM HRSG "B"

HP FEEDWATER

FROM HRSG "B"

HP FEEDWATERFROM HRSG "A"

FROM HRSG "B"

HP FEEDWATERFROM HRSG "A"

FIG.5.3.10

STARTUP PEGGING STEAM 325 PSIA PROCESS STEAM TO GI

50 PSI PROCESS STEAM TO GI

HO

T R

EH

EA

T

MAIN STEAMFROM HRSG “A”

HOT REHEATFROM HRSG “B”

FROM HRSG ”A”

FIG.5.3.13

SPRAYWATER FROM CONDENSATE PUMP

50 PSI PROCESS STEAM TO WASTE TREATMENT PLANT

STEAM TURBINE SEALS

FRO

M M

AIN

STE

AM

FIG.5.3.11

FIG.5.3.11

FROM HP FEEDWATER

HP BYPASS TO COLD REHEAT

COLD REHEAT TO HRSG “B”

CO

LD R

EH

EA

T

STEAM FROM SYNGAS COOLERS A

FROM HRSG “B”

SPRAYWATER FROM HRSG “A” 325 PSIA IP FEEDWATER

HP

EX

TRA

CTI

ON

S

TEA

M

FIG.5.3.10

FIG.5.3.10

MAIN STEAM FROM HRSG “B”

IP STEAM HEADER

FIG.5.3.11

IP E

XTR

AC

TIO

N S

TEA

M

FIG.5.3.11

GAS FLOW

FW PUMPAUX BOILER

FAN

PEGGING STEAM

WATER FROMAUX BOILER MAKEUP

WATER PUMPS

FUEL GAS

FUEL

GAS

R

ECO

VER

Y

DEAERATOR

FIG.5.3.13

ECONSTEAM DRUM

PR

OC

ES

S S

TEA

M

FIG.5.3.11

FIG.5.3.11

TO NOX INJECTION STEAM

FIG.5.3.11

COLD REHEAT TO HRSG ”A”

HOT REHEAT

FROM SYNGAS COOLERS “B”

(NN

F)

CR

OS

S O

VE

R

STE

AM

ATTEMP

ATTEMP

ATTEMP

HP FEEDWATER

HP FEEDWATER

TO GI MP STEAM HEADER

BACK UP PEGGING STEAM “B”

BACK UP PEGGING STEAM TO HRSG “A”

(NNF)

STA

RT

UP

FIG.5.3.13

TO CONDENSER NECK

AUXILARY BOILER

(NNF)

(NNF)

(NNF)

(NNF)

STARTUP (NNF)

(NNF)

805 PSIA MAKEUP STEAM

Figure 5.3.12 – Steam Turbine and Auxiliary Boiler


Page 57

"DUMP/RECIRCULATION" LINE "A"

CONDENSER

HOTWELL

FROM HRSG "B"

IP BYPASS SPRAYWATER TRAIN “B”

HP BYPASS SPRAYWATER TRAIN ”A”

HP BYPASS SPRAYWATER TRAIN “B”

GLAND STEAMCONDENSER

TO STEAM SEAL SPRAYS

TO GI LP ATTEMPERATOR

IP FEEDWATER FROM FUELGAS HEATER TRAIN "A"

FIG.5.3.11C

ON

DE

NS

ER

DO

ME

HO

OD

SP

RA

Y

FIG.5.3.11

FEEDWATER TO HRSG "B"

LP DRUM

FILL LINE

GI B

YP

AS

S

FIG.5.3.12

VACUUM PUMP MAKEUP

FEEDWATER TO HRSG “A” LP DRUM

FROM STEAM TURBINE

FIG.5.3.12

ATTEMP

ATTEMPIP BYPASS TRAIN "B"

EXHAUST HOOD SPRAYS

ATTEMP

ATTEMP

GI HP STEAM BYPASS FROM HRSG TRAIN “B”

FIG.5.3.12

GI HP STEAM BYPASS FROM HRSG TRAIN “A”

TO WASTE WATER TREATMENT SPRAYWATER ATTTEMP.

PUMPS

CONDENSATE MAKEUP DEMINERALIZED EFFLUENT

FROM WATER TREATMENT PLANT

DEMIN WATER

STORAGE TANK

NORMAL MAKEUP CO

OLI

NG

WA

TER

SY

STE

M

SU

RG

E T

AN

K

TO P

RIM

AR

Y (C

LOS

ED

LO

OP

) FIG.5.3.14

TO GASIFICATION ISLAND CLOSEDLOOP COOLING WATER SYSTEM, ETC.

TO CONDENSATE SYSTEM

PUMPS MAKEUP

AUX BOILER

MAKE UP WATERTO AUX BOILER

FIG.5.3.12

FIG.5.3.11

CONDENSATE PUMPS

FIG.5.3.10

FIG.5.3.10

FIG.5.3.12

FROM LP DRUM

IP BYPASS FROM HRSG TRAIN “A”

IP BYPASS SPRAYWATER TRAIN “A”

(NNF)

TOWERWATER TO CC COOLING TOWER

TOWERWATER FROM CC COOLING TOWER

Figure 5.3.13 – Steam Condenser


Page 58

DR0093

PU0094A/B

PU0093A/B

LPS

HX0095

COOLINGTOWER

DR0094

CW

HX0094

WATER TO DR0071

FIG. 5.3.7

WATER TO FL1060FIG. 5.3.6

WATER TO CL1063FIG. 5.3.6

FIG. TAG5.3.4 HX10215.3.4 HX10245.3.5 HX10055.3.5 HX10295.3.9 HX0045

FIG. TAG5.3.1 PG1102

FIG. TAG5.3.10 HX0091

FIG. TAG5.3.1 HX11045.3.8 HX1085

FIG. TAG

5.3.6 HX10665.3.6 HX10805.3.7 HX00765.3.8 CO10805.3.8 CO1080M5.3.8 PG00615.3.8 PG0061M5.3.8 PG10805.3.9 HX00465.3.9 HX00515.3.9 HX0054

5.3.11 HX00945.3.12 CO00965.3.12 HX00965.3.12 PG0097

FIG. TAG5.3.3 HX00405.3.4 HX10255.3.4 HX10325.3.5 CO01065.3.5 CO10045.3.5 CO11025.3.5 CO1102M5.3.5 CO12025.3.5 CO1202M5.3.5 HX00035.3.5 HX1006

5.3.6 HX1064

5.3.5 HX10195.3.5 HX10265.3.6 CO10655.3.6 CO1066

PROCESS EXCHANGERS

LP N2

LP N2

5.3.6 HX1062

DEMIN WATER

Figure 5.3.14- Cooling Water and Tempered Water Systems


Page 59

OXYGEN RICHSTREAMTO ATM

LP NITROGEN HEADER

CO0096

DR1196

CW

FEED AIR FROM HX0003FIG. 5.3.5

IP NITROGEN HEADER

TRUCK LOADING/UNLOADINGPG0096

PG0097(NNF)

LIQUID NITROGEN

CW

(NN

F)

HP

HEA

DER

CW HX0096

LP NITROGEN USERS

HP NITROGEN USERS

IP NITROGEN USERS

DR0099

PU0099A/B

BR0099

WASTEWATER TO TK0042FIG. 5.3.9

AMMONIA FLARE HEADER

BR1098

HP FLARE HEADER

(NNF)

PG0098

FROM RELIEF VALVE DISCHARGES

FROM VENTS


FROM VENTS

HX1023FIG. 5.3.6

DR1098

WW

SERVICEWATER

PU0097A/B

BR0097

LP/ACID GAS FLARE HEADER (NNF)


FROM VENTS

DR0097

AH1102FIG. 5.3.2

PG0070FIG. 5.3.7

AH0070FIG. 5.3.7

HP NITROGEN USERS

NATURAL GAS

Figure 5.3.15 - Nitrogen and Flare System


Page 60

PU0077A/B/C/D

TK0095

PU0095A/B

CAUSTIC TO CL0044

FIG. 5.3.9

WATER FROM PU0008

FIG. 5.3.1

TK0070

PU0074A/B

H2O2 TO CL0071

FIG. 5.3.7

TRUCKUNLOADING

OF 50 WT.% H2O2HOLD 1

TK0071SULFURIC ACID FROM PU0071A/BFIG. 5.3.7

PU0076A/B

PG0071

N2TO SAFE

LOCATIONTO SAFE

LOCATION

TK0060NOTE 2

PU0062A/B

SELEXOL TO CL1063FIG. 5.3.6

TO SAFE LOCATION

TO CL2063

FL0061

LPC

LPS

TK0072

TO SAFE LOCATION

TRUCKUNLOADINGOF 50 WT.%

CAUSTICTRUCKUNLOADINGOF SELEXOL

LPN2

LPN2

LPN2

PG0072

Figure 5.3.16 – Chemical Storage


Page 61

5.4 OVERALL MATERIAL BALANCE

Figure 5.4.1 shows an overall mass balance for the gasification process based on the average lignite coal composition. The flows shown represent the total flows for both gasification trains.


Page 62

Coal Preparation

Transport Gasifier, High-Temperature Syngas Cooling, Particulate

Removal

Low-Temperature Syngas Cooling

H2S and CO2 Removal

Sour Water Treatment

Sulfur Recovery

1 2

6 75

14

10

15

21

20

16

8 9

17

11

19

24

22

13

12

4

3

23

RawCoal

Air

BoilerFeedwater

FromHRSG

Super-heated

Steam to HRSG

Steamto

Gasifier

GasifierAsh

ProcessedCoal

RecycledSyngas

RawSyngas

Water

Water toDischarge

NH3 for Sale

SourWater

Product Syngas to Gas Turbine

SourSyngas

SweetSyngas

CO2 to Pipeline for Sale

Vent to Atmosphere

Air

H2SO4 for Sale

18

Sour WaterVent

Figure 5.4.1 – Overall Material Balance


Page 63

Table 5.4.1 – Material Balance Streams

Stream No. 1 2 3 4 5 6 7 8 9 10 11 12Mass Flow, LB/HR 1,158,200 809,280 87,324 261,596 1764581 851,680 851,680 45,886 149,466 2,603,358 126,710 193,509Temperature, F 65 150 133 133 493 310 1002 733 200 594 140 148Pressure, PSIA 15 15 35 35 698 1880 1697 820 15 620 190 30Mole Fraction CH4 0.0259 9 ppm CO 0.1752 16 ppm CO2 0.0003 0.0854 0.0497 COS 170 ppm H2 0.1172 76 ppm HCN 189 ppm H2O 1.0000 1.0000 0.0026 1.0000 1.0000 1.0000 0.0781 0.8992 1.0000 H2S 0.0033 665 ppm N2 0.7791 0.5060 130 ppm NH3 0.0030 0.0503 Ar 0.0092 0.0055 4 ppm O2 0.2088 H2SO4


Page 64

Table 5.4.1 – Material Balance Streams (Continued)

Stream No. 13 14 15 16 17 18 19 20 21 22 23 24Mass Flow, LB/HR 5,641 133,077 68,731 2,738,245 1,870,836 14,884 1,669,028 900,222 50,802 139637 126045 37210Temperature, F 102 177 177 102 77 191 450 100 110 176 65 104Pressure, PSIA 520 736 736 523 501 190 470 2150 28 15 15 36Mole Fraction CH4 0.029 0.029 0.024 0.029 178 ppm 0.029 0.002 0.007 CO 0.020 0.020 0.017 0.020 306 ppm 0.020 556 ppm 0.002 CO2 0.049 0.049 0.223 0.045 0.933 0.044 0.992 0.442 0.148 300 ppm COS H2 0.316 0.316 0.255 0.316 0.001 0.316 0.002 0.028 HCN H2O 0.003 161 ppm 164 ppm 0.004 164 ppm 0.050 164 ppm 632 ppm 0.258 0.083 0.016 0.291 H2S 0.003 0.013 6 ppm 0.230 N2 0.579 0.579 0.470 0.583 0.002 0.583 0.003 0.032 0.728 0.768 NH3 0.997 Ar 0.007 0.007 0.005 0.006 71 ppm 0.006 1 ppm 0.001 0.009 0.009 O2 0.032 0.206 H2SO4 0.709


Page 65

5.5 PLANT 3D RENDERINGS


Page 66

Figure 5.5.1 – Gasification Island Looking North


Page 67

Figure 5.5.2 – Gasification Island Looking Southeast


Page 68

Figure 5.5.3 – Entire Kemper County IGCC Facility


Page 69

Appendix

Appendix A – Equipment List

Equipment Tag Number Item Description

A0044 GI WASTEWATER SUMP A0060 A SOUTH GASIFIER STRUCTURE

SUMP A0060 B NORTH GASIFIER STRUCTURE

SUMP A0065 AGR AREA SUMP A0078 SULFURIC ACID AREA SUMP A1057/2057 AGR SOLVENT SUMP A1080/2080 GAS CLEAN UP AREA SUMP AH0070 WSA COMBUSTOR AH1102/1202/2102/2202 GASIFIER START-UP BURNERS AH1103/1203/1303/2103/2203/2303 GASIFIER SECOND START-UP

BURNERS BL0002 COAL SILO BAGHOUSE

EXHAUST BLOWER BL0070 COOLING AIR BLOWER BL0071 COMBUSTOR AIR BLOWER BL0072 STACK GAS BLOWER BR0097 LP/ACID GAS FLARE BR0099 AMMONIA FLARE BR1098/ 2098 HP FLARE CL0042 HYDROGEN SULFIDE STRIPPER CL0044 WASTEWATER AMMONIA

STRIPPER CL0052 WASTEWATER AMMONIA

PURIFIER CL0070 QUENCH COLUMN CL0071 SCRUBBER COLUMN CL1006/2006 AMMONIA SCRUBBER CL1007/2007 SYNGAS SCRUBBER CL1060/2060 AGR H2S ABSORBER CL1063/2063 AGR REGENERATOR CL1064/2064 AGR CONCENTRATOR CL1101 /1201 /1301 /2101 /2201 /2301 VENTURI SCRUBBER


Page 70

Equipment Tag Number Item Description CL1161/1261/1361/2161/2261/2361 AGR CO2 ABSORBER

CO0041 LP VENT GAS COMPRESSOR CO0041 LO LP VENT GAS COMPRESSOR

LUBE OIL SKID CO0096 NITROGEN COMPRESSOR CO0096LO NITROGEN COMPRESSOR LUBE

OIL SKID CO0106/0206 ASU/STARTUP AIR

COMPRESSOR CO0106/0206 LO ASU/STARTUP AIR

COMPRESSOR LUBE OIL SKID CO1004/2004 EXRACTION AIR COMPRESSOR CO1004/2004 LO EXTRACTION AIR COMPRESSOR

LUBE OIL SKID CO1005/2005 TRANSPORT AIR COMPRESSOR CO1005/2005 LO TRANSPORT AIR COMPRESSOR

LUBE OIL SKID CO1008/2008 RECYCLE GAS COMPRESSOR CO1008/2008 LO RECYCLE GAS COMPRESSOR

LUBE OIL SKID CO1065 LP/2065 LP AGR FLASH GAS FIRST STAGE

COMPRESSOR CO1065 LP/2065 LP LO AGR FLASH GAS FIRST STAGE

COMPRESSOR LUBE OILSKID CO1065 MP/2065 MP AGR FLASH GAS SECOND

STAGE COMPRESSOR CO1065 MP/2065 MP LO AGR FLASH GAS SECOND

STAGE COMPRESSOR LUBE OILSKID

CO1066/2066 AGR CO2 RECYCLE COMPRESSOR

CO1066/2066 LO AGR CO2 RECYCLE COMPRESSOR LUBE OIL SKID

CO1080/2080 CO2 COMPRESSOR CO1080 LO/2080 LO CO2 COMPRESSOR LUBE OIL

SKID CO1102/1202/2102/2202 PROCESS AIR COMPRESSOR

PACKAGE


Page 71

Equipment Tag Number Item Description CO1102/1202/2102/2202 LO PROCESS AIR COMPRESSOR

LUBE OIL SKID DR0002 FILTRATE DRUM DR0004 RECOVERED WATER DRUM DR0006 DRUM FILTER FEED DRUM DR0011 PC FINES DRYING RECOVERED

WATER DRUM DR0040 WASTEWATER DRUM DR0042 HX0042 LEVEL POT DR0044 HX0044 LEVEL POT DR0045 WASTEWATER AMMONIA

STRIPPER REFLUX DRUM DR0047 HYDROCARBON DRAIN DRUM DR0048 HX0095 LEVEL POT DR0049 HX0059 LEVEL POT DR0050 HX0052 LEVEL POT DR0051 WASTEWATER AMMONIA

PURIFIER REFLUX DRUM DR0056 AGR WATER BREAK DRUM DR0070 MP STEAM DRUM DR0071 ACID VESSEL DR0090 LP CONDENSATE DRUM DR0091 IP CONDENSATE DRUM DR0092 BLOWDOWN FLASH DRUM DR0093 COOLING WATER DRUM DR0094 TEMPERED WATER DRUM DR0095 LP BLOWDOWN FLASH DRUM DR0097 LP/ACID GAS FLARE KO DRUM DR0099 AMMONIA FLARE KO DRUM DR1003/2003 EXTRACTION AIR COMPRESSOR

KO DRUM DR1005/2005 TRANSPORT AIR COMPRESSOR

KO DRUM DR1007/2007 HX1008/2008 LEVEL POT DR1008/2008 HP STEAM DRUM DR1009/2009 RECYCLE GAS COMPRESSOR

KO DRUM DR1010/2010 PROCESS CONDENSATE K.O.


Page 72

Equipment Tag Number Item Description DRUM

DR1023/2023 HX1023 /2023 LEVEL POT DR1027/2027 HX1027/2027 LEVEL POT DR1030/2030 CCAD STEAM DRUM DR1043/2043 PLD VENT GAS DRUM DR1054/2054 AGR LEAN SOLVENT

REFRIGERANT DRUM DR1057/2057 AGR SUMP DRUM DR1060/2060 AGR FEED K.O. DRUM DR1061/2061 AGR SOLVENT K. O. DRUM DR1062/2062 AGR STRIPPED GAS K. O. DRUM DR1063/2063 AGR RICH SOLVENT FLASH

DRUM DR1064/2064 AGR REGENERATOR REFLUX

DRUM DR1065/2065 AGR FLASH GAS K.O. DRUM DR1069A/B/2069A/B AGR REGENERATOR REBOILER

CONDENSATE DRUM DR1080/2080 AGR FLASH GAS COMPRESSOR

KO DRUM DR1098/2098 HP FLARE SEAL DRUM DR1153/1253/1353/2153/2253/2353 AGR LOADED SOLVENT

REFRIGERANT DRUM DR1155/1255/1355/2155/2255/2355 AGR SEMI-LEAN SOLVENT

REFRIGERANT DRUM DR1166/1266/2166/2266 AGR HP CO2 FLASH DRUM DR1167/1267/2167/2267 AGR MP CO2 FLASH DRUM DR1168/1268/2168/2268 AGR LP CO2 FLASH DRUM DR1196/1296/1396/2196/2296/2396 NITROGEN SURGE DRUM

FD0001 COAL SILO DUST COLLECTION AIRLOCK

FD0006 COAL SILO DUST COLLECTION DIVERTER VALVE

FD0007 COARSE ASH FEEDER FD0009A/B/C/D ASH STORAGE SILO DISCHARGE

ROTARY FEEDER FD0017 PC FINES CYCLONIC BAGHOUSE

AIRLOCK


Page 73

Equipment Tag Number Item Description FD0018 PC FINES TUBULAR CHAIN

CONVEYER FD1011/2011 GASIFIER BOTTOMS DRAIN POT

FEEDER FD1013A/B/C/2013A/B/C ASH SILO DIVERTER VALVE FD1014/2014 CCAD DIVERTER VALVE FD1102/1202/1302/2102/2202/2302 CRUSHED COAL FEEDER

FD1103/1203/1303/2103/2203/2303 MULTI-CLONE AIR LOCK

FD1104A/B/1204A/B/1304A/B/2104A/B/2204A/B/2304A/B

PC CYCLONIC BAGHOUSE AIR LOCK

FD1108/1208/ 1308/2108/2208/2308 FLUID BED DRYER DISCHARGE FEEDER

FD1110A/B/1210A/B/1310A/B/2110A/B/2210A/B/2310A/B

GASIFIER COAL FEED LOCK VESSEL

FD1115A/B/1215A/B/1315A/B/2115A/B/2215A/B/2315A/B

GASIFIER COAL FEED DISPENSE VESSEL

FD1116A/B/1216A/B /1316A/B/2116A/B/2216A/B/2316A/B

GASIFER COAL FEED SYSTEM (PDAC)

FD1120A/B-1/2/3/4/5/6 /1220A/B-1/2/3/4/5/6/2120A/B-1/2/3/4/5/6/2220A/B-1/2/3/4/5/6

CFAD PRESSURE LET-DOWN DEVICE

FD1130-1/2/3/4 /1230-1/2/3/4/2130-1/2/3/4/2230-1/2/3/4

CCAD PRESSURE LET-DOWN DEVICE

FL0001 RECOVERED WATER FILTER FL0002 COAL SILO DUST COLLECTION FL0005A/B DRUM FILTER FL0007 COARSE ASH SILO BAGHOUSE FL0008A/B/C/D ASH STORAGE SILO BAGHOUSE FL0017 PC FINES CYCLONIC BAGHOUSE FL0061 AGR SOLVENT MAKEUP FILTER FL0070 COOLING AIR BLOWER INLET

FILTER FL0071 WET ESP FL0111/0211 ASU/STARTUP AIR

COMPRESSOR INTAKE AIR FILTER

FL1010/2010 MICRON FILTER


Page 74

Equipment Tag Number Item Description FL1060/2060 AGR SOLVENT FILTRATION

SYSTEM FL1082/2082 CO2 COMPRESSOR INLET

FILTER FL1103/1203/1303/2103/2203/2303 MULTI-CLONE

FL1104/1204/1304/2104/2204/2304 PC CYCLONIC BAGHOUSE

FL1106/1206/2106/2206 PARTICULATE CONTROL DEVICE

FL1109/1209/2109/2209 PROCESS AIR COMPRESSOR INTAKE AIR FILTER

FL1120A/B/1220A/B/2120A/B/2220A/B CFAD CLINKER CATCHER

FL1130/1230/2130/2230 CCAD CLINKER CATCHER FN0017 PC FINES TUBULAR DRYER GAS

FEED FAN FN0017 LO PC FINES TUBULAR DRYER GAS

FEED FAN LO SKID FN1102/1202/1302/2102/2202/2302 COAL DRYER GAS FEED FAN

FN1102/1202/1302/2102/2202/2302 LO COAL DRYER GAS FEED FAN LO SKID

FN1104/1204/1304/2104/2204/2304 COAL DRYER GAS FEED BOOSTER FAN

FN1104/1204/1304/2104/2204/2304 LO COAL DRYER GAS FEED BOOSTER FAN LO SKID

FN1105/1205/1305/ 2105/2205/2305 PC CYCLONIC BAGHOUSE BACKFLUSH FAN

FN1106/1206/1306/2106/2206/2306 COAL MILL FEED FAN

FN1106/1206/1306/2106/2206/2306 LO COAL MILL FEED FAN LO SKID

HX0003 ASU/STARTUP COMPRESSOR AFTER COOLER

HX0015 PC FINES TUBULAR DRYER GAS FEED HEATER

HX0017 PC FINES CYCLONIC BAGHOUSE VENT GAS CONDENSER


Page 75

Equipment Tag Number Item Description HX0040 LP VENT GAS COMPRESSOR

PRE-COOLER HX0041 HYDROGEN SULFIDE STRIPPER

FEED PREHEATER HX0042 HYDROGEN SULFIDE STRIPPER

REBOILER HX0044 WASTEWATER AMMONIA

STRIPPER REBOILER HX0045 WASTEWATER AMMONIA

STRIPPER CONDENSER HX0046 WASTEWATER AMMONIA

STRIPPER TRIM CONDENSER HX0051 AMMONIA PRODUCT

CONDENSER HX0052 WASTEWATER AMMONIA

PURIFIER REBOILER HX0054 WASTEWATER AMMONIA

PURIFIER CONDENSER HX0056 WASTEWATER COOLER HX0057 WASTEWATER TRIM COOLER HX0059 MAKEUP WATER TRIM HEATER HX0070 WASTE HEAT STEAM

GENERATOR HX0071 1ST INTERBED COOLER HX0072 2ND INTERBED COOLER HX0073 PROCESS GAS COOLER HX0074 WSA CONDENSER HX0075 AIR HEATER (ELECTRICAL) HX0076 ACID COOLER HX0077 AMMONIA EVAPORATOR

(ELECTRICAL) HX0090 LP CONDENSATE DRUM VENT

CONDENSER HX0091 HRSG CONDENSATE HEATER HX0094 TEMPERED WATER TRIM

COOLER HX0095 TEMPERED WATER HEATER HX1005/2005 TRANSPORT AIR COMPRESSOR

PRECOOLER HX1006/2006 TRANSPORT AIR COOLER HX1007/2007 SCRUBBER PUMPAROUND

HEATER


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Equipment Tag Number Item Description HX1008/2008 SCRUBBER PUMPAROUND IPS

HEATER HX1009/2009 SHIFT FEED RECUPERATOR I HX1011/2011 SHIFT FEED RECUPERATOR II HX1019/2019 EXTRACTION AIR TRIM COOLER HX1020/2020 HIGH TEMP. SYNGAS

RECUPERATOR HX1021/2021 INTERMEDIATE TEMP. SYNGAS

COOLER HX1022/2022 LOW TEMP. SYNGAS

RECUPERATOR HX1023/2023 EXPORT SYNGAS TRIM HEATER HX1024/2024 LOW TEMP. SYNGAS COOLER HX1025/2025 LOW TEMP. SYNGAS TRIM

COOLER HX1026/2026 TRANSPORT AIR COMPRESSOR

TRIM COOLER HX1027/2027 PROCESS CONDENSATE TRIM

HEATER HX1028/2028 EXTRACTION AIR

RECUPERATOR HX1029/2029 EXTRACTION AIR COOLER HX1030/2030 CCAD COARSE ASH COOLER HX1032/2032 RECYCLE GAS COMPRESSOR

SPILLBACK COOLER HX1060/2060 AGR FEED PRODUCT

EXCHANGER HX1061/2061 AGR LEAN/RICH SOLVENT

EXCHANGER HX1062/2062 AGR STRIPPED GAS COOLER HX1063A/B /2063A/B AGR REGENERATOR REBOILER HX1064/2064 AGR REGENERATOR

CONDENSER HX1065/2065 AGR FLASH GAS COOLER HX1066/2066 AGR CO2 RECYCLE

COMPRESSOR AFTER COOLER HX1067A/B/2067A/B AGR LEAN SOLVENT CHILLER HX1080/2080 AGR FLASH GAS COMPRESSOR

SPILLBACK COOLER HX1085/2085 CO2 COMPRESSOR

AFTERCOOLER HX1086/2086 AGR FLASH GAS COMPRESSOR

INTERSTAGE COOLER


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Equipment Tag Number Item Description HX1101/1201/1301/2101/2201/2301 PC DRYING STAGE 1 HEATER HX1102/1202/1302/2102/2202/2302 PC DRYING STAGE 2 HEATER HX1104/1204/1304/2104/2204/2304 VENTURI SCRUBBER

PUMPAROUND COOLER HX1110/1210/2110/2210 PRIMARY SYNGAS

COOLER/STEAM GENERATOR HX1112/1212/2112/2212 PRIMARY SYNGAS

COOLER/SUPERHEATER HX1114/1214/2114/2214 PRIMARY SYNGAS

COOLER/ECONOMIZER II HX1116/1216/2116/2216 PRIMARY SYNGAS

COOLER/ECONOMIZER I HX1118/1218/2118/2218 PCD FINES RECEIVER HX1168/1268/1368/2168/2268/2368 AGR SEMI-LEAN SOLVENT

CHILLER HX1169/1269/1369/2169/2269/2369 AGR LOADED SOLVENT CHILLER ME0001 GASIFIER STRUCTURE FREIGHT

ELEVATOR ME0002 GASIFIER STRUCTURE

PERSONNEL ELEVATOR ML1107/1207/1307 /2107/2207/2307 ROLL CRUSHER ML1108/1208/1308/2108/2208/2308 COAL MILL ML1108/1208/1308/2108/2208/2308 LO COAL MILL LUBE OIL CONSOLE MX0002A/B/C/D ASH MOISTURIZER MX0006 DRUM FILTER FEED DRUM

AGITATOR MX0070 AMMONIA/AIR MIXER MX1002/2002 UPPER/LOWER MIXING ZONE PG0017 PC FINES DRYING PACKAGE PG0040 CARBON BED FILTER PACKAGE PG0054 ANHYDROUS AMMONIA TRUCK

LOADING PG0060 AGR ANTIFOAM INJECTION

PACKAGE PG0061 AGR REFRIGERATION PACKAGE PG0070A/B/C/D MIST CONTROL UNIT PG0071 SULFURIC ACID TRUCK

LOADING PG0072 HYDROGEN PEROXIDE DOSING

PACKAGE PG0096 NITROGEN GENERATOR PG0097 LIQUID NITROGEN STORAGE PG0098 FLAME FRONT GENERATOR


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Equipment Tag Number Item Description PG1007/2007 TRANSPORT AIR DRYER PG1080/2080 CO2 DEHYRATION PACKAGE PG1102/1202/1302/2102/2202/2302 COAL DRYING PACKAGE

PU0002A/B EXCESS WATER PUMP PU0005A/B FILTRATE PUMP PU0008A/B HP MAKEUP WATER PUMP PU0009A/B DRUM FILTER FEED PUMP PU0017A/B PC FINES DRYING RECOVERED

WATER PUMP PU0040A/B WASTEWATER BOTTOMS PUMP PU0042 WASTEWATER PUMP PU0044A/B GI WASTEWATER SUMP PUMP PU0045A/B WASTEWATER AMMONIA

STRIPPER REFLUX PUMP PU0047A/B HYDROCARBON DRAIN PUMP PU0050A/B WASTEWATER AMMONIA

PURIFIER REFLUX PUMP PU0053A/B ANHYDROUS AMMONIA

LOADING PUMP PU0054A/B ANHYDROUS AMMONIA RERUN

PUMP PU0055A/B SOUTH GASIFIER STRUCTURE

SUMP PUMP PU0055C/D NORTH GASIFIER STRUCTURE

SUMP PUMP PU0057A/B WASTEWATER AMMONIA

PURIFIER BOTTOMS PUMP PU0062A/B AGR SOLVENT TRANSFER PUMP PU0065A/B AGR AREA SUMP PUMP PU0070A/B ACID PUMP PU0071A/B ACID PRODUCT PUMP PU0072A/B/C QUENCH WATER PUMP PU0073A/BC/D/E SCRUBBER WATER PUMP PU0074A/B HYDROGEN PEROXIDE DOSING

PUMP PU0075A/B WET ESP EFFLUENT PUMP PU0076A/B SULFURIC ACID RUNDOWN

PUMP


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Equipment Tag Number Item Description PU0077A/B/C/D SULFURIC ACID PRODUCT

PUMP PU0078 A/B SULFURIC ACID AREA SUMP

PUMP PU0090A/B LP CONDENSATE PUMP PU0092A/B MP STEAM GENERATION

CONDENSATE PUMP PU0093A/B COOLING WATER CIRCULATION

PUMP PU0094A/B TEMPERED WATER

CIRCULATION PUMP PU0095A/B 50 WT. % CAUSTIC PUMP PU0096A/B DIESEL PUMP PU0097A/B LP/ACID GAS FLARE KO DRUM

PUMP PU0099A/B AMMONIA FLARE KO DRUM

PUMP PU1006A/B/2006A/B SOUR WATER PUMPAROUND PU1007A/B/2007A/B SYNGAS SCRUBBER

PUMPAROUND PU1010A/B/2010A/B PROCESS CONDENSATE PUMP PU1058A/B/2058A/B AGR SOLVENT FILTRATION

SYSTEM PUMPS PU1060A/B/2060A/B AGR RICH SOLVENT PUMP PU1061A/B/2061A/B AGR SUMP PUMP PU1063A/B/2063A/B AGR LP LEAN SOLVENT PUMP PU1064A/B/2064A/B AGR REGENERATOR REFLUX

PUMP PU1067A/B/2067A/B AGR HP LEAN SOLVENT PUMP PU1068A/B/C/D/2068A/B/C/D AGR SEMI-LEAN SOLVENT PUMP PU1069A/B/2069A/B AGR WATER MAKEUP PUMP PU1085A/B/2085A/B GAS CLEAN UP AREA SUMP

PUMP PU1101A/B/1201A/B/1301A/B/ 2101A/B/2201A/B/2301A/B

VENTURI SCUBBER PUMP

PU1104A/B/1204A/B/1304A/B/2104A/B/2204A/B/2304A/B

VENTURI SCRUBBER PUMPAROUND

PU1166A/B/1266A/B/1366 A/B/2166A/B/2266A/B/2366A/B

AGR LOADED SOLVENT PUMP

RX0070 SCR REACTOR


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Equipment Tag Number Item Description RX0071 SO2 CONVERTER RX1002/2002 PRESSURIZED TRANSPORT

GASIFIER RX1080/2080 CO2 MERCURY ADSORBER RX1104 /1204/2104/2204 COS HYDROLYSIS REACTOR RX1106/1206/2106/2206 MERCURY ADSORBER RX1108 /1208/1308/2108/2208/2308 WGS REACTOR I

RX1109/1209/1309/2109/2209/2309 WGS REACTOR II SI0007 COARSE ASH SILO SI0008A/B/C/D ASH STORAGE SILO SI1102/1202/1302/2102/2202/2302 CRUSHED COAL SILO

SI1110A/B/1210A/B/1310A/B/2110A/B/2210A/B/2310A/B

GASIFIER COAL FEED STORAGE BIN

ST0060 WSA STACK ST1099/2099 START-UP STACK TK0042 WASTEWATER STORAGE TANK TK0054 AMMONIA STORAGE TANK TK0060 AGR SELEXOL STORAGE TANK TK0070 HYDROGEN PEROXIDE TANK TK0071 SULFURIC ACID RUNDOWN

TANK TK0072 SULFURC ACID PRODUCT TANK TK0095 50 WT. % CAUSTIC TANK TK0096 DIESEL TANK

Kemper County IGCC Project Preliminary Public Design Report

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Transcript of Kemper County IGCC Project Preliminary Public Design Report