Facility Inspection Report

Gasification Plant

Prepared by: International Process Plants Hamilton Business Center 17A Marlen Drive Hamilton, NJ 08691

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Gasification Plant

Executive Summary This plant was installed in 2000 to convert heavy refinery residues into clean syngas utilizing licensed technology from Texaco (GE Gasification), ABB, UOP, Parson (Claus units), and Praxair. It is designed to consume 59 mt/hr (1,400 mt/day) of heavy residues to produce 130 mt/hr of clean syngas, consisting primarily of CO and H2. The facility is slightly over-designed (6%) to accommodate crude oils other than the standard Arab Heavy. The Claus sections are 36% over-designed to accommodate Basrah Medium high-sulfur feedstocks. The grey water treatment system is 58% overdesigned to accommodate Iranian Heavy feedstocks. This facility was running at the time of inspection and is expected to shut down at the end of this year (2012). Spare parts for this facility are abundant and include gasifier internals, complete exchangers, compressor internals, compressor motors up to 25 MW, a Claus unit, and some distillation tower internals. Documentation is excellent in both paper and electronic formats. All types of documentation were reviewed and found acceptable during the inspection. We have electronic copies of PFDs, major equipment data sheets, major equipment manufacturers’ drawings, mass balances, detailed equipment lists, plot plans, process descriptions, and historical production data. Process control is by ABB Advant DCS and is available with the sale of the plant. There is no asbestos in this facility due to its fairly recent construction. The site has good rail and truck access. It is located directly on the ocean and has its own harbor for crude oil unloading and finished product loading. Equipment removed from this facility can be loaded directly on barges at the facility shoreline, since this is how the equipment was delivered.

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Site Description

SMPP Facility Plot Plant

The site has good rail and truck access. It is located directly on the ocean and has its own harbor for crude oil unloading and finished product loading. Equipment removed from this facility can be loaded directly on barges at the facility shoreline since this is how the equipment was delivered. The Syngas Manufacturing Process Plant (SMPP) can operate with 37 people. The turnarounds were generally dictated by the 300-MW turbine generator for which it supplied syngas.

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Process Description

SMPP Facility Process Flow Diagram (red portion not available)

This plant converts heavy refinery residues into clean syngas utilizing licensed technology from Texaco, ABB, UOP, Parson, and Praxair. Under normal operating conditions, approximately 59 mt/hr (1,400 mt/day) of heavy residues are consumed by the SMPP (Syngas Manufacturing Process Plant) in the production of about 130 mt/hr of clean syngas, consisting primarily of CO and H2. This equates to 166 Nm3/hr based on a syngas density of 0.782 kg/Nm3. The syngas is then diluted with nitrogen and burned as a combustible fuel in the Combined-Cycle Process Plant (CCPP) gas turbine (not available for sale). This process results in very low production of sulfur oxides and NOx. The output from this unit includes about 33 m3/hr of pre-treated water and a 4 mt/hr of liquid sulfur. Utility consumptions for the unit are shown in the following table:

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Utility Consumption (NOC = Normal Operating Conditions)

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GASIFICATION AND GAS SCRUBBING The core of the SMPP process consists of the Texaco gasification system. This technology was chosen because of its widely demonstrated success in the commercial field and because of its superiority from the standpoint of environmental impact. The facility built using the Texaco license includes:

• Charge preparation section • Gasification section (two gasifiers) • Gas scrubbing which includes:

o Recovery unit for unconverted carbon o Grey water treatment section

The charge oil preparation section is typically operated on low sulfur fuel oil for start-up of the gasifiers. It then switches to the highly viscous refinery feedstock residues. The average density for the refinery residue fed to this facility is 1,075 kg/m3. This section heats the residues to lower the viscosity and provide good pumpability and atomizing capabilities in the gasifier burners. The heated residue is also used in the carbon extraction unit to absorb the unconverted carbon from the gasifier products. High-end Uraca pumps are used to pump the viscous feedstocks for this unit.

Gasification Structure

The quench gasifier technology is used in this facility because of its reliability and simplicity of operation. The quench gasifier is also the best choice when the gasifier feed product has a high concentration of metals (up to 800 ppm). Otherwise, the facility would have a strong possibility of plugging the pipes in the Heat Recovery Steam Generator (HRSG).

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The heavy oil gasification unit consists of two parallel trains with redundant gasifiers and syngas scrubbers. The gasifiers operate at 62 bars and an outlet temperature of 1375oC (design maximum of 1540oC). The gasifiers are constructed in two sections: a refractory-lines reaction section in the upper area and the quench section in the lower area.

Gasifier Inlet (Top)

Steam is mixed with the heavy oil in a static mixer to assist in atomization of the feed in the water-cooled gasifier burners. Oxygen is fed at a rate less than what is required for complete combustion, forcing more production of carbon monoxide. The partial oxidation of the heavy hydrocarbons results in complex intermediate chemical reactions that finally produce the desired syngas.

The amount of oxygen added varies with the different feedstocks, but is generally about 0.5 moles of oxygen to 1.0 moles of carbon. The oxygen concentration is a delicate balance; too much creates more CO2 and too little creates more unconverted carbon. Both of these results are undesirable. The oxygen double-block-and-bleed valves above the gasifiers are special-order 6” globe valves made of Monel. They are said to cost €350,000 each, and there are 10 of these valves in operation. The oxygen piping to the gasifiers is also made of Monel. The oxygen stream is then combined with the heavy oil and steam in a water-cooled injector inside the top of the gasifier. The feed streams spontaneously combust due to the pressure and temperature and syngas is produced. There are five injectors including the three spares. The upper section of the gasifier is called the combustion section and it is heavily lined with refractory to protect the 74 mm thick carbon steel shell. The syngas flows from the reaction section to the quench section within the gasifiers. The gas enters through a dip-pipe below the water level in the quench section. There is also a quench ring spraying water in the upper quench section for additional cooling. The syngas exits the quench section saturated with water at 245oC. The water from the quench section contains soot and is pumped to the carbon extraction unit at the rate of 69 mt/hr for each gasifier train.

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The wastewater flow from this unit, after the recovery of unconverted carbon, contains metals that are treated in the grey water treatment unit to obtain water which can then be treated with an ordinary biological treatment facility. The syngas produced in the gasifiers typically consists of 46% CO, 45% H2, and 7% CO2 with 13,900 kJ/kg energy value. The conditions leaving the gasification section are 35 bar and 50oC. The energy value is actually too high for the turbine generator system design, so the stream is diluted with nitrogen to bring the energy value down. After dilution with nitrogen, the composition is typically 29% CO, 28% H2, 4% CO2, and 37% N2 with 7,000 KJ/kg energy value. The syngas scrubbing system is designed to remove soot and particulates from the syngas. The system begins with a nozzle-scrubber where the gas is intimately mixed with water so that the wetted soot particles will transfer to the water phase of the scrubbers. Any entrainment is washed from the syngas with wash trays that use clean condensate. Finally, a vane-type mist eliminator removes any entrained droplets. Syngas free of any soot or particulates is then routed to the gas cooling section.

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CARBON EXTRACTION UNIT The carbon extraction unit is made up of three sections: decanter and water flash separator, naphtha and oil heating, and naphtha stripping. The soot formed in this gasification process typically range from 20-70 millimicrons. They agglomerate readily to the 5-10 micron range and have surface areas of 200-800 m2/gm.

Carbon Extraction Unit

A small amount of naphtha is added to sufficiently coat the soot particles. The soot water is mixed with the small naphtha stream in a static mixer. This effectively transfers the soot from the water phase to the naphtha phase. However, some of the ash still remains in the water phase. The mixture then enters a decanter where separation of the water and naphtha phase occurs. Additional naphtha is added to the decanter to aid the separation. The decanter is controlled at 17.9 bar. The water layer (grey water) is transferred from the decanter to the water flash separator. The pressure is dropped so that about 5% of the water vaporizes in the flash separator. The flashed gas is cooled and sent to the tail gas treatment unit. A continuous stream of grey water is pumped from the flash separator to the grey water treatment plant.

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The naphtha layer from the decanter flows to the naphtha and oil heating section of the unit. The naphtha (with soot) is mixed with the heavy feed oil from the refinery (for extraction of soot), heated, and routed to a flash drum. The vaporized product goes to the upper section of the naphtha stripper. The liquid from the flash drum is heated further and fed to the lower section of the naphtha stripper. The naphtha stripper operates at 3.7 bar to complete the separation of soot-free naphtha from the heavy feed oil used for extraction. The heavy extraction oil with soot is pumped from the bottom of the naphtha stripper back to the feed section of the facility. Clean naphtha goes overhead from the stripper. The clean naphtha is condensed and recycled back to the decanter section of the unit. Only about 0.3% of the naphtha is lost to the extraction oil in this process.

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GAS COOLING & COS HYDROLYSIS SECTION This section was designed by ABB Lummus Global for the purpose of recovering heat at the medium to low temperatures available in the syngas after scrubbing with water. The heat recovery occurs through the generation of steam at three different pressures. This section also includes a gas expander for the recovery of potential energy connected with the high pressure of syngas (pressure in the gasifiers is about 62 bars). The expander reduces the syngas pressure to 35 bar and generates 3 MW of electricity.

Gas Cooling (Steam Generators)

The saturated gas from the scrubber enters the gas cooling section at 239oC and 59 bar. The stream is first cooled in the 20 bar steam generator, which cools the syngas stream to 222oC. Then, it proceeds to the 15 bar steam generator where the gas is cooled to 208oC. Finally, it enters the 6 bar steam generator where the syngas is cooled to 166oC. Each of the gas coolers has its own separate condensate drum. The cooled gas then proceeds to the carbonyl sulfides (COS) hydrolysis guard reactors (2) followed by the COS hydrolysis reactor. The syngas is further cooled in a series of exchangers and cross-exchangers to 38oC. Water that is condensed in all of these cooling steps contains ammonia and H2S, so it is sent to the sour water stripper.

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Hydrolysis Reactor & Guard Reactors

The COS hydrolysis guard reactors (one operating and one spare) remove particulates and metal carbonyls which would deactivate the main hydrolysis catalyst. The guard beds consist of highly porous inert material (K306 from Süd Chemie) where particulates accumulate and metal sulfides resulting from the decomposition of the carbonyls will deposit. They operate at 57 bar and 190-200oC. A promoted chromium oxide/alumina oxide catalyst (G-41P from Süd Chemie) is used in the main hydrolysis reactor to convert COS to CO2 and H2S. Carbonyl sulfide is also converted to H2S in the main reactor. Steam is added with the syngas to the inlet of the main hydrolysis reactor. Catalyst lifetime in this unit is typically 5-8 years.

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SELEXOL UNIT (ACID GAS REMOVAL) A selective physical process, the UOP Selexol system, is utilized for the treatment of the syngas. This unit utilizes a solvent (Selexol), which selectively absorbs the hydrogen sulfide formed in the gasifier. This is a physical absorption process that selectively removes H2S and part of the remaining carbonyl sulfides. Water vapor and part of the CO2 are also absorbed. Selexol solvent is di-alkyl polyglycol ether with about 5% water. Syngas enters the bottom of the absorber column at 38oC and 51 bar. It is contacted counter-currently with the Selexol solvent, which is fed to the top tray. Clean syngas exits the top of the column and proceeds to the expansion turbine. The H2S-rich Selexol solvent stream proceeds out to the bottom of the column to the liquid power recovery turbine. This turbine recovers the power hydraulically to drive one of the lean solution pumps by dropping the rich solvent stream pressure from 50 bar down to seven bar. It produces the equivalent of 150 Kw of power.

Selexol Columns

The liquid stream goes to a flash drum where some gases are flashed off and compressed in the Nuevo Pignone (now GE) reciprocating flash gas recycle compressor. The flashed gases are cooled and mixed with the incoming syngas stream. The liquid stream is heated in cross-exchangers and introduced to the Selexol stripper column. This column has three packed sections and two wash trays at the top of the column. Steam and acid gases are washed on the top two trays with reflux. The overhead vapors are sent to the sulfur recovery unit. The bottoms stream is partially filtered and recycled back to the absorber column.

A syngas expansion turbine is located downstream of the acid gas removal system. It has a recently installed dry-gas sealing system. The syngas enters the power recovery turbine at 51 bar and the energy is recovered in an electrical generator. Dilution nitrogen from the Praxair air separation plant is then added to the syngas stream prior to entering the gas turbine unit.

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SULFUR RECOVERY UNIT & TAIL GAS TREATMENT UNIT The recovery of the sulfur contained in the H2S absorbed in the SELEXOL is carried out in two Claus units, the license for which has been acquired from Ralph M. Parsons. Connected to these two units is a section for the treatment of tail gas. This facility can recover 99.9% of the sulfur in the feed product. This is much more efficient than the normal Sulfur Recovery Unit (SRU) design which recovers only about 94% of the sulfur. The 4 mt/hr of elemental sulfur produced from this facility has a typical purity of 99.8% with less than 650 ppm carbon, 250 ppm ash, and 10 ppm H2S.

Sulfur Recovery Units

The sulfur recovery unit receives acid gas overhead from the Selexol stripper column and sour gas from the sour gas stripper column. The sulfur in these acid gas streams is converted to elemental sulfur in the reaction section of the Claus units running at about 0.9 bar and receiving oxygen for combustion from the Praxair unit. They run at a minimum of 1250oC in oxygen deficient conditions to prevent the formation of NOx and SO3. The reaction gases then go through a waste heat boiler where 20.5 bar steam is produced. The partially cooled gases then enter the first condenser where 6 bar steam is produced. The non-condensed gases go to the first converter, which is filled with activated alumina (S-201 from LaRoche Industries).

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The gases then proceed through the second condenser, where low-pressure steam is produced and liquid elemental sulfur is withdrawn. The remaining gases then proceed to the third converter and the third and final condenser, which produces 1.0 bar steam. The liquid elemental sulfur from all three condensers is drained to the sulfur degassing pit. There are two Claus units and one tail gas treatment unit. The tail gases are heated to 309oC and sent to a hydrogenation reactor where hydrogenation and hydrolysis reactions take place. The catalyst is a cobalt/molybdenum product C-29 from Süd Chemie. All sulfur compounds are converted to H2S. The gases exiting the hydrogenation reactor are cooled from 385oC to 171oC, generating low-pressure steam.

Tail Gas Treatment Columns

The gases are scrubbed with caustic in a column to remove SO2 and then fed to the MDEA absorber where the H2S is absorbed into the MDEA solution. The absorber contains six baffle trays, two bubble cap trays, and a packed upper section. The tailgas containing H2S and CO2 exits the top of the column and enters the contactor. Here, it meets a countercurrent flow of MDEA solution (Ucarsol HS-101 at 50% aqueous). The gases are then fed to the thermal oxidizer before being emitted to atmosphere.

The rich MDEA solution is pumped from the bottom of the contactor to the regenerator column. This column has 22 valve trays, two chimney trays, and an upper packed section. Acid gases from the top of the column are sent to the sulfur recovery unit. The lean MDEA solution from the bottom of the column is recycled back to the contactor.

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GREY WATER & SOUR GAS TREATMENT The 33 m3/hr of grey water (31 mt/hr) is pre-treated to make it acceptable for conventional biological waste water treatment facilities. After pre-treatment, the grey water will contain no more than 10 ppm suspended solids, 250 ppm COD, 2 ppm H2S, 3 ppm cyanide, 1 ppm vanadium, 1 ppm nickel, and 300 ppm chlorides. The solid filter cake from the pre-treatment facility is typically produced at 166 kg/hr. The cake consists of 11.5% cyanide, 7.7% vanadium, 1.1% nickel, 0.7 % sulfides, and about 70% moisture. It has value and is sold to a metal recovery company.

Grey Water & Sour Gas Units

The grey water from the flash separator in the carbon extraction unit is first treated with ferrous sulfate, caustic, and a “Polymer 1” to precipitate sulfide and cyanide compounds. The effluent flows to a solids settler and then to the alkalization reactor. “Polymer 2” is added at this point to precipitate any remaining ferrous ions. The bottoms stream from these vessels is pumped with sludge pumps to the sludge filters where the sludge is dewatered and filter cake is formed. The water stream from these vessels proceeds through sand filters and is then fed to the ammonia stripper column. The overheads piping on the ammonia stripper had corrosion problems and was eventually replaced with stainless steel pipe. The bottoms stream from the ammonia stripper is acceptable to feed to a conventional biological waste water treatment facility. The sour water stripper column receives sour water from the COS hydrolysis unit. The stripper removes H2S, ammonia, and dissolved carbon dioxide from the sour water. The clean water is then recycled back to the carbon extraction unit. There were some problems with erosion of the overhead lines on the stripper, so they were eventually replaced with Hastelloy pipe.

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AIR SEPARATION UNIT The air separation unit (ASU) produces the oxygen necessary for gasification and for the Claus units (70 mt/hr total oxygen). This operation is based on the traditional principle of fractionated distillation of liquid air. The oxygen from the Praxair licensed facility is greater than 95% purity and is produced at 76 bar and 132oC. The nitrogen is produced at 36 bar and 50oC. The “warm side” of the ASU (mainly compressors) is located indoors with a 60 mt overhead crane. The “cold side” is located outdoors.

Main Air Compressor

The large, main air compressor is a four-stage Sulzer centrifugal unit with a 23 MW ABB electric drive motor. It compresses enough air to produce 1782 mt/day of 95% pure oxygen. The compressed air is cooled with two absorption refrigeration units (ARU using lithium bromide solution). The air is then purified with alumina and molecular sieve before entering the cryogenic distillation section. The first column separates gaseous nitrogen and an oxygen rich liquid at 7 bar and -168oC. The bottoms liquid stream is fed to the second column, which continues the separation of nitrogen and oxygen at 4.3 bar. The liquid bottoms stream from the second column is fed to the third column, which operates at 1.3 and -187oC for the final separation. The booster air compressor in this ASU is a Borsig unit driven by a 3.1-MW ABB electric motor. It has a capacity of 70,000 Nm3/hr, boosting the air pressure from 8.2 to 22.5 bar. The Renk gearbox increases the drive speed to 17,000 rpm. The final oxygen product is delivered from the coldbox at 4.7 bar, which is high enough for the SRU operations. A portion of the stream is compressed to 76 bar for use in the gasifiers. The oxygen compressor is a Sulzer three-stage unit with six impellers. It has a 5.5-MW ABB motor turning at 1482 rpm driving a Renk gearbox that spins the compressor at 15,000 rpm. The compressor is rated for 50,000 Nm3/hr with 90 bar discharge pressure (normal operation is 76 bar).

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The nitrogen compressor is a five-stage Borsig machine driven by a 10.8 MW ABB electric motor. The Renk gearbox has three output shafts that turn at speeds from 14,000 to 17,000 rpm. The complex compressor has two suction lines and takes the nitrogen pressure from 12 to 38 bar. However, the machine is rated for a maximum of 55 bar. It pumps nitrogen at 41,000 Nm3/hr or 38 kg/sec.

Cold Box

The high-pressure nitrogen product is expanded through a generator loaded nitrogen turbo-expander to recover the energy. The unit is capable of handling 950,000 ft3/hr turning at 6,250 rpm. The generator is rated for 400 hp turning at 3020 rpm. It produces electricity at 380 V and 50 Hz. The electricity is used for refrigeration in the cryogenic section. The nitrogen is then used for dilution in the gas turbine feedstream.

This Air Separation Unit can undergo some rather simple modifications to achieve 98% oxygen purity, which is needed in coal gasification plants. To achieve 99+% purity for chemical use, a fourth distillation column would need to be added to remove argon from the oxygen product. While this will add to project and operation costs, the argon can be sold to defray some of the costs. The massive seawater pumping and distribution system is located in the ASU section of the facility.

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Conversion to Coal Gasification: It has been verified by GE Energy (gasification technology licensor) that this unit can indeed be converted to use coal as the gasification feedstock instead of refinery tars. The estimated cost for the conversion to coal is about $15 MM US using new equipment. The major changes to the process are listed below:

1. Install coal grinding and handling system. Coal will be ground with water present. Then the slurry will be pumped at very high pressures to the gasifier (existing tar pumps will be modified to handle coal slurry). The coal slurry will target 62% coal and 38% water.

2. Replace refractory in gasifier since coal operates at slightly higher temperature and it is more abrasive. This is not an issue since refractory will be removed for dismantling and shipping anyway.

3. Install lock hopper system on bottom of gasifier for coal slag removal. The dump rate will vary from every two hours to every eight hours depending on coal composition. The slag is typically recycled back to the coal grinders since it still has carbon value. A purge stream must be maintained so that the system does not over-concentrate with slag.

4. Increase Air Separation Unit efficiency to achieve 98% oxygen purity instead of 95% purity. This is done by fairly simple modification to the existing columns.

5. Addition of two more trays in the syngas scrubbers (2). This would take the wash section of the scrubbers from two wash trays to four trays. The scrubbers also have packed sections that would remain the same.

6. The Carbon Extraction Unit may not be necessary depending on the coal composition and operation of the gasifier.

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Major Equipment Details

Pressure Temperature Material ofSh/Tu Sh/Tu Diameter Height Area Construction

Equipment Description Quantity (bar) (oC) (m) (m) (m2) Sh/Tu

GasificationD8001 Charge Oil Drum 1 5.6 305 3.1 9.6 CSD8002 Extraction Oil Drum 1 5.6 305 3.9 12.1 CSD8008 Slop Oil Drum 1 5.0 290 2.6 6.4 CSE8001A/B Charge Oil Heater 2 76/84 305/330 1.0 7.3 458 CS/CSE8002A/B Extraction Oil Heater 2 76/84 305/330 1.0 7.3 458 CS/CSE8003A/B Oil Circ Heater 2 16/13 215/200 0.9 4.9 197 CS/CSE8005 Grey Water Exch 4 69/83 275/245 1.2 7.3 722 CS/SSR8001-1/2 Gasifier 2 69.0 430 2.8 10.2 74 mm thk CS/Inc 825 cladT-8001-1/2 Scrubber 2 68.0 300 3.2 7.9 CS/316L clad

Carbon ExtractionD8101 Decanter 1 20.0 225 4.0 5.3 CS/316L cladD8102 Water Flash Separator 1 8.0 200 3.2 16.7 316L SSD8105 Naphtha Stripper Reflux Dm 1 5.5 200 2.3 8.9 CSD8111 Naphtha Slop Drum 1 5.0 165 2.9 4.9 CSE8101 Water Flash Sep OH Cond 1 6.0 200 4.2 10.5 Fin-Fan CS/SSE8103E-F Soot Water Coolers 6 69.0 225 4.9 10.5 Fin-Fan CS/CSE8104 Naphtha Vaporizer 1 16/20 215/305 2.1 7.3 2029 CS/CSE8105 Naphtha Stripper Feed Htr 1 12/84 305/330 1.1 7.3 550 CS/CSE8107A-C Naphtha Stripper OH Con 3 6.0 200 4.7 10.5 Fin-Fan CS/CST8101 Naphtha Stripper 1 6.0 305 2.4 17.4 CSTK8101 Soot Water Tank 1 Atm 103 18.0 22.0 CS

Gas Cooling & COS HydrolysisD8201 Syngas KO Drum 1 1 66 260 2.4 4.7 CS/316L cladD8202 Syngas KO Drum 2 1 66 260 2.2 3.5 CS/316L cladD8203 Syngas KO Drum 3 1 66 260 1.9 4.5 CS/316L cladD8204 Process Condensate Drum 1 60 330 2.5 7.0 CS/316L cladD8207 Syngas KO Drum 4 1 66 180 1.8 2.8 CS/316L cladD8208 Syngas KO Drum 5 1 66 90 1.8 2.8 CS/316L cladD8212 Syngas Mixing Drum 1 45 120 3.2 8.7 CSE8201 20 bar Steam Generator 1 35/66 245/260 3.2 7.3 2264 CS/316LSSE8202 15 bar Steam Generator 1 35/66 245/260 2.3 7.3 1122 CS/316LSSE8203 6 bar Steam Generator #1 1 35/67 245/261 2.7 7.3 1481 CS/316LSSE8204 Hydrolysis Feed Exchanger 1 66/66 300/250 1.2 6.1 435 CS/316LSSE8207 6 bar Steam Generator #2 1 35/66 245/245 1.3 3.7 178 CS/316LSSE8209 Boiler Feedwater Heater 1 60/66 210/210 0.9 7.3 511 CS/316LSSE8211 Syngas Air Cooler 1 66 140 5.6 10.5 Fin-Fan CS/316LSSE8212 Syngas Water Cooler 1 65/60 90/65 1.1 4.9 306 CS/316LSSE8213 Treated Water Heater 1 60/66 140/140 0.9 7.3 336 CS/316LSSR8201A/B Hydrolysis Guard Reactor 2 66 300 2.8 2.4 CSR8202 Hydrolysis Reactor 1 66 300 3.3 5.9 CS

Selexol UnitC8302 Product K-O Drum 1 60 65 1.8 5.5 CSD8303 Hydrocarbon K-O Drum 1 11 100 2.5 12.0 CSD8307 Sump Drum 1 5 145 3.6 4.5 CSE8304 Stripper Reboiler 1 3.5/16 200/215 1.7 7.3 288 CS/316LSSE8305 Stripper OH Air Cooler 1 3.5 130 4.6 10.5 Fin-Fan CS/316LSST8301 H2S Absorber 1 60 65 3.3 39.5 CS - SS traysT8302 Selexol Stripper 1 3.5 160 2.7 35.5 CSTK8301 Selexol Storage Tank 1 Atm 65 7.5 6.5 CS

Sulfur Recovery Units (2)BF8401/51 Reaction Furnace 2 5.2 343 1.7 5.1 CSE8401/51 Waste Heat Boiler 2 24/5.2 225/343 1.7 6.0 180 CS/CSE8402 1st Condenser 2 7.5/5.2 160/343 1.2 8.8 141 CS/CSE8404 2nd Condenser 2 7.5/5.3 160/344 1.2 8.8 121 CS/CSE8406 3rd Condenser 2 7.5/5.4 160/345 1.2 8.8 105 CS/CSR8401/2-51/52 Converters 2 5.2 343 2.2 7.2 CS

Tailgas Treatment UnitBQ8501 Thermal Oxidizer 1 2.1 7.1 CSE8501 Reactor Effluent Cooler 1 7.5/5.2 180/343 1.3 6.6 196 CS/CSE8505 Regenerator Reboiler 1 4/7.5 180/180 1.7 4.7 387 CS/CSR8501 Hydrogenation Reactor 1 5.2 343 2.2 4.1 CST8501 Contact Condenser 1 3.5 200 1.8 16.0 CST8502 Contactor 1 3.5 76 1.6 19.3 CST8503 Regenerator 1 3.5 150 1.7 28.8 CS

Grey Water Treatment UnitD8602 Ammonia Stripper Feed Drum 1 3.5 125 3.6 11.0 CSE8605A/B Ammonia Stripper Reboil. 2 7.5/5.0 180/170 1.0 7.3 CS/CSFD8601 Solids Settler 1 3.5 125 5.9 7.0 CSFD8602 Sludge Filter 2 15 CST8601 Ammonia Stripper 1 4.1 175 1.5 26.0 CSTK8601 Water Diversion Tank 1 Atm 125 10.9 12.5 CS

Sour Gas Treatment UnitD8651 Sour Water Stripper Feed Dm 1 3.5 150 3.5 10.0 CSE8652 Sour Water Stripper Reboiler 1 7.5/6.5 180/175 0.9 4.9 306 CS/CST8651 Sour Water Stripper 1 5 175 0.8 22.8 CS

Air Separation UnitD8901 Chilled Water Suction Drum 1 CSD8902A/B Prepurifiers 2 CSE8904 Aftercooler #1 1 CSE8905 Aftercooler #2 1 CSE8910 Interstage Cooler 1 CSFG8905/9 N2 Vent Silencer 2 CSPA8905 Chiller Unit 1 CS