IMPROVED PERFORMANCE OF THE DESTEC GASIFIER Gasification Technologies Conference

Transcription

1 IMPROVED PERFORMANCE OF THE DESTEC GASIFIER 1999 Gasification Technologies Conference Dr. David L. Breton Dynegy, Inc Louisiana Street, Suite 5800 Houston, Texas ABSTRACT The DESTEC gasification process has a legacy that spans twenty-five years and three companies. After researching and developing the two-stage gasifier concept via a pilot unit and a proto unit, the Dow Chemical company built and operated the Louisiana Gasification Technology, Inc facility, (LGTI). LGTI was capable of processing 2400 tons/day of subbituminous coal while producing an equivalent 160 MW s in syngas and steam. This facility was operated from 1987 through The LGTI design was based on a two stage gasifier with heat recovery and wet particulate removal. Initial development of a dry particulate removal system was done at LGTI. It was during the LGTI operational period that Dow transferred the facility and the gasification technology it had developed to the newly formed Destec subsidiary, a wholly owned independent power producer of Dow. Through the research and development effort of Dow and operation of LGTI, much technology and operating experience was established around the Destec two stage gasification process. In the early 1990 s, the Wabash River Gasification Repowering Project (Wabash) was developed under the Department of Energy (DOE) Clean Coal IV solicitation. The Wabash project was a joint venture between Destec and PSI Energy, an Indiana utility. Destec gasified coal to syngas and high pressure steam, this enabled PSI to repower a 1950 s vintage steam turbine in conjunction with a General Electric 7FA combustion turbine in a combined cycle mode. The Destec gasifier at Wabash processes 2600 tons/day of Indiana bituminous coal to produce 262 MW s. The technology was further improved through the 4 years of operating experience. Of particular note are the following areas of improvement: (1) operational experience on bituminous coal, (2) design and operation of a syngas cooler producing HP steam, (3) refinement of a dry particulate removal system and (4) development of a COS hydrolysis system for syngas application. In 1997 Dynegy acquired Destec, and under Dynegy s ownership the technology and operating expertise at Wabash has continued to develop and improve. The first full scale gasification of petroleum coke in the two stage gasifier was performed at Wabash in This extended the successful application of the Destec gasifier to a broad gambit of solid fuels and has set the stage for logical extension of the technology to a hybrid wet and dry feed gasifier. 1

2 Introduction: The DESTEC gasification process has a legacy that spans twenty-five years and three companies. After researching and developing the two-stage gasifier concept via a 36 ton/day pilot unit and a 1600 ton/day proto-plant, The Dow Chemical Company built and operated the Louisiana Gasification Technology, Inc. (LGTI) gasification plant. LGTI was capable of processing 2400 tons/day of subbituminous coal while producing an equivalent 160 MW s in syngas and steam. This facility was operated from 1987 through The LGTI design was based on a two stage gasifier with heat recovery and wet particulate removal. Initial development of a dry particulate removal system was done at LGTI.. It was during the LGTI operational period that Dow transferred the facility and the gasification technology it had developed to the newly formed Destec subsidiary, a partly owned independent power producer for Dow. Through the research and development effort of Dow and operation of LGTI, much technology and operating experience was established around the Destec two stage gasification process. In the early 1990 s, the Destec gasification technology was chosen for the Wabash River Gasification Repowering Project (Wabash) which was selected by the Department of Energy (DOE) under the Clean Coal IV solicitation. The Wabash project was a joint venture between Destec and PSI Energy, the Indiana utility. Destec gasified coal to syngas and high pressure steam, this enabled PSI to repower a 1950 s vintage steam turbine in combined cycle mode with a General Electric 7FA combustion turbine. The Destec gasifier at Wabash processes 2600 tons/day of Indiana bituminous coal to produce 262 MW s. Dynegy acquired Destec in 1997, and under Dynegy s ownership the technology and operating expertise have continued to develop and improve. The first full scale gasification of petroleum coke in the two stage gasifier was performed at Wabash in This extended the successful application of the Destec gasifier to a broad gambit of solid fuels and has set the stage for logical extension of the technology to a hybrid wet and dry feed gasifier. Process Description: The Destec Gasification Process is center around an oxygen-blown two stage gasifier, a slagging horizontal stage followed by an entrained flow vertical stage. A block flow diagram of the gasification process is given in Figure 1. Coal or coke is milled with water in a rodmill to form a slurry. The slurry is combined with oxygen in mixer nozzles and injected into the first stage of the gasifier, which operates at F and 400 psig. Oxygen is supplied by a dedicated cryogenic distillation facility. In the first stage, slurry undergoes a partial oxidation reaction at temperatures high enough to bring the solid fuel s ash above its melting point. The fluid ash flows through a taphole at the bottom of the first stage into a water quench, forming an inert vitreous slag. The syngas flows up to the second stage, where additional slurry is injected. This slurry is vaporized and pyrolyzed in an endothermic reaction with the hot syngas to enhance syngas heating value and to improve overall efficiency. The syngas then flows to the high-temperature heat-recovery unit (syngas cooler), essentially a firedtube steam generator, to produce high-pressure saturated steam. After cooling in the syngas cooler, particulates in the syngas are removed in a hot/dry filter and recycled to the gasifier where the carbon 2

3 Figure 1: Destec Gasification Process Recycle Slurry Water Hot BFW Saturated HP Steam Sour Water Treatment Sour Discharge Water Water Coal Milling, Heating & Feeding Slurry Gasification High Temp. Heat Recovery Char Removal COS Hydrolysis, Moisturization & Condensate Heat Product Syngas Nitrogen Oxygen Slag Slurry Quench Water Char Tail Gas Cool Sour Syngas Sweet Syngas Air Air Separation Unit Slag Handling Sulfur Recovery Unit Acid Gas Acid Gas Removal Slag Product Sulfur Product in the char is converted into syngas. The syngas is further cooled in a series of heat exchangers, water scrubbed to remove chloride and then passed through a catalyst that hydrolyzes carbonyl sulfide into hydrogen sulfide. Hydrogen sulfide is removed using methyl di-ethanol amine (MDEA) based absorber/stripper columns. The sweet syngas is then available for export, use in a combustion turbine to generate power, or to be converted to various chemicals. Improvements at LGTI: At LGTI, successful improvements were made in the process and equipment. The major improvements were in slag removal system, the slurry mixing nozzles, the high temperature heat recovery system, the particulate removal system and the acid gas removal system. The continuous removal of slag from the water bath at the bottom of the gasifier without the use of maintenance prone lockhoppers worked almost flawlessly. Granted abrasive wear on the pressure reducing unit of the system was present, with the redundancy of these units the minimal maintenance required could be done while the rest of the plant continued to operate. The initial design of the mixer nozzle used for introducing slurry into the first stage of the gasifier had a short life due to the abrasive and thermal stress on this equipment item. With changes in the materials of construction and modifications of its mechanical design to address these issues, significant improved mixer life was realized. 3

4 High temperature heat recovery is an essential element in maintaining high overall thermal efficiency. The Destec gasification process utilizes a fired-tube design for the syngas cooler. This type of exchanger is compact, less costly than a water wall design and requires no soot blowers or mechanical devices to dislodge soot from the heat transfer surface. The lesser surface and ease of purging this type of heat exchanger minimizes the potential for downtime corrosion. Much was learned at LGTI about the operating parameters needed for successful operation and design of a firedtube heat exchange in this service. The boiler-superheater-economer design at LGTI produced 650 psig steam, superheated to 720 F. LGTI was designed with a wet scrubbing for particulate removal. Effective dewatering of particulate slurry to high concentrations was difficult to perform and maintain. This reduced the overall efficiency of the process significantly. The dewatered particulate was recycled back to the first stage of the gasifier increasing the quantity of water to the gasifier and thereby reducing the gasifiers chemical conversion efficiency. It was not desirable to cool the particulate laden raw syngas too close to its dewpoint, and the cooled raw syngas entering the scrubber had sufficient superheat which resulted in temperatures conducive to elevated dissolved solids in the circulated scrubber water. This in turn lead to scaling problems within wet particulate removal system. In addition, the number of equipment items required to effect the dewatering was quite large. This reduced the availability of the plant and increased the its maintenance cost. To address these negative impacts of the wet scrubbing system, a 100% dry particulate removal system was designed, installed and tested at LGTI. The dry system had fewer equipment items, and worked very well. However, downtime corrosion was a major problem since condensation of water in the presence of the particulate makes for a very corrosive environment. Operational procedures for future plants need to be such that dry conditions are maintained during startup and shutdown periods. The acid gas removal unit (AGR) included in the design of LGTI for removal of the hydrogen sulfide (H 2 S) from the sour syngas used an amine solvent, MDEA. Amines have long been used to remove H 2 S from natural gas and refinery gases. There were known difficulties with heat stable salt (HSS) formation within the amine solvents used in this service. In an AGR system for processing sour syngas, the rate formation of HSS is significantly greater than for natural gas and initially required frequent replacement of the amine. With much experimentation and trials of various methods to addressing this problem, a HSS removal technology based on ion exchange was proven successful on an as needed basis and in batch mode. Improvements at Wabash: At the Wabash facility, improvements in equipment and the process has continued. As at LGTI, ash deposition in the hot path of the gasifier and its accumulation at the inlet of the syngas cooler were encountered initially at Wabash. With much study, observing where the deposits formed and process conditions which lead to high rates of deposition, solutions have been found. With carefully chosen refractory materials and modifications in the geometric design of the refractory and piping system, ash deposition has been reduced to a level where ash management is practical. At Wabash the ash deposition has been dramatically reduced to the point that it is no longer a run limiting issue. Bituminous coal is processed at Wabash and with it came new challenges. The equipment item most affected was the mixer nozzle for slurry feed to the gasifier. A noticeable reduction in mixer life was observed from the start. This was not a show stopper, thanks to the capability of changing out a mixer within a day s time. This was a tolerable situation but not the preferred mode of operation. A 4

5 detailed review of the mixer design and geometry lead to a minor modification which has recovered and increased the life expectancy obtained at LGTI. In addition the modification enhanced the carbon conversion significantly and the carbon content of the slag produced from the gasifier is consistently less than 5 % yielding overall carbon conversion greater than 99 %. With less carbon present in the slag quench water system, the task of settling out solids from the slag quench system are reduced and black water problems are not present. Excellent performance of the continuous slag removal system at Wabash has paralleled that experienced at LGTI. The formation of HSS in the Wabash AGR system is at expected levels. Based on experiences at LGTI, an continuous ion exchange unit was installed in a slip stream of the amine circulation loop. Initial life of the resin bed was unsatisfactory. Research and development activities were initiated with different resins and processing schemes. Over approximately the last year, the resin bed has not required replacement and the units capacity for removing HSS has significantly increased. Wabash utilizes hot gas filtration with removed particulate recycled to the first stage of the gasifier. The initial filter element charge was ceramic cylinders held in place with a tie-rod assembly. Frequent element breakage was experienced. Assembly of each tie-rod element was tedious and the quality control during the assemble of the numerous tie-rod assemblies was difficult and time consuming which lead to extended outages for repair of unit failure. More than five days were typically required from the time the gasifier was taken off coal for repair until the system was producing syngas again. The frequency of these repairs added unnecessary thermal cycles to the gasifier refractory causing increased refractory wear rates. It was decided to use metal filter elements with metallurgy that would give an acceptable resistance to the corrosive sour syngas. Even though corrosion still remains an issue, filter elements made from appropriate metallurgy have outperformed the initial ceramic element design. A hot filtration slip stream unit has been installed at Wabash to test different element designs and materials as well as the configuration of multi-element clusters for studying blinding, bridging, failure modes, etc. The overall availability of the facility has been dramatically improved by the development activities in the hot filtration system at Wabash. The advantages of the hot dry particulate removal system used at Wabash are numerous. With dry solids being recycled from the particulate removal system, water vaporization required within the first stage of the gasifier is reduced and less oxygen per unit of feedstock is required to maintain the slagging temperatures. Dry filtration avoids contacting the particulate water and precipitating problems with dissolved solids and trace metals in the grey water of a wet particulate removal system. A small number of equipment items are required to remove and recycle particulate. With all noncombustible solids of the feed being directed to the slagging first stage of the gasifier, only one solids effluent stream is present. Petroleum Coke Gasification: Even though the Destec gasifier was originally conceived to gasify highly reactive lignite and subbituminous fuels. It has been demonstrated at Wabash that the two-stage design processes bituminous coals as well and with improved efficiency. Furthermore, the application of the two-stage gasifier concept to petroleum coke gasification has also been tested at Wabash. The first test was performed in November of 1997 during a 10 day test which gasified 20,000 tons of petroleum coke. The plant produced 100% of the rated output while maintaining the low emission rates expected from 5

6 the gasification technology. Carbon conversion was 99%. Very low tars levels were observed in the raw syngas. The nickel and vanadium were captured in the slag flux added to the petroleum coke. The slag flux aided in slag tapping, and no slagging tapping problems were encountered. Even though the operating temperature of the first stage was increased to F, the refractory wear rates were similar to that observed during coal operations. No negative impact on equipment was observed, and there was no excessive corrosion or fouling of the fire-tube syngas cooler. Recently, in September 1999, a 3½ day test was performed using petroleum coke from Mayan crude. Similar results were obtained, 99% carbon conversion, 100% output, no slag tapping problems, etc. Another test on Mayan crude petroleum coke will occur in the near future to confirm the low tar production in the second stage, as was observed in the 1997 test, and to further demonstrate the deep quenching aspects of petroleum coke. The 1999 tests will have processed10,000-12,000 tons of petroleum coke. A two stage gasifier offers several significant advantages to petroleum coke gasification. With the low volatile matter in petroleum coke, increased utilization of slurry quench in the second stage can be utilized without concern for excessive tar production. This increases the heat recovery aspect of the second stage since more of the thermal energy from the first stage can be put to better process use in the second stage, i.e. vaporizing the water from the slurry and allowing dry solids to be fed to the first stage. This reduces the oxygen requirements needed to gasify the coke. Less mixing energy is also needed to disperse the dry solids fed to the gasifier and consequently reduces the power required for the oxygen compressor. As we will see later, increased slurry feed to the second stage has a dramatic effect on oxygen requirements, cold gas efficiency, CO/H 2 ratio in the syngas as well as other positive influences.. Normally high reactivity of the feedstock is desired for effective operation of the second stage of the gasifier. However, low reactivity has its advantages. The low reactivity of the petroleum coke results in less reaction of the particles in the slurry fed to the gasifier and subsequently the average particle size entering the particulate filter are larger. Filter cake formed from larger particles has a lower permeability than for cakes of smaller particles. This results in less pressure drop for the same solids loading on the filter surface. With pressure drop being a critical parameter in filter design and operation, the larger particulate would be less likely to lead to high pressure drops and therefore more easily filtered. For a fixed size filter, the degree of solids loading that can be tolerated is greater for the larger particulate, and conversely would require less filter area for the same solids loading. Even though the solids loading in the syngas from the second stage would be greater for petroleum coke operation, the larger particulate size would not require a significantly larger filter system. Gasification efficiency is highly influenced by the slurry concentration obtainable from the feedstock, higher the slurry concentration, the greater the cold gas efficiency. Most petroleum coke solids would be expected to yield a relatively high slurry concentration, i.e., mid to high 60 s. This is another potential advantage in the gasification of petroleum coke. Having enumerated the advantages of two stage gasifier for gasifying petroleum coke, let s look at the expected performance of poly-generation process based on two stage gasification of coke. The processing steps in Figure 2 are very similar to that used at Wabash. Starting with the process basis given in Table 1, the expected performance was simulated for various fractions of the total slurry directed to the second stage, the remainder is sent to the first stage. Gas exiting the first stage is fixed at 2700 F and is quenched to 1650 F or below prior to entering the syngas cooler. Typically, syngas from the first stage is quenched to 1850 F in the second stage with further quenching with recycled syngas just prior to entering the syngas cooler. Quenching in the second stage can be 6

7 FIGURE 2: PROCESS BLOCK FLOW DIAGRAM EXPORT STEAM BFW BFW PET COKE SLURRY FEED SYSTEM SLURRY GASIFICATION HEAT RECOVERY PARTICULATE REMOVAL SYNGAS SYNGAS SCRUBBING COS HYDROLSIS SOUR WATER SLAG SOUR SYNGAS FINES SLURRY WATER SLAG EXPORT OXYGEN OXYGEN ASU OXYGEN TAIL GAS AGR & SRU SULFUR SWEET STEAM SYNGAS HYDROGEN CO SHIFT TO H 2 COMBINED CYCLE POWER SYNGAS 7

8 TABLE 1: SIMULATION PROCESS BASIS Petroleum coke feed (4,000) tons/day) Two Stage Gasification Syngas to Power (200 MW combustion turbine) Remaining Syngas to Hydrogen Export Superheated HP Steam (700 F / 700 psig) Optional Exports: Oxygen, Nitrogen, Syngas accomplished with either water or recycled syngas. Both options were simulated to show the flexibility of the second stage and the impact on the process parameters and syngas quality. It may help to discuss a little further what happens to the supplemental quenching with water or syngas as the quantity of slurry to the second stage is increased. To avoid confusion, let s consider the water quenching option to supplement the slurry quench to the second stage. Assume initially no slurry is directed to the second stage, therefore all quenching in the second stage is done with water. As slurry to the second stage is increased, less water is needed to quench to 1850 F. As the slurry to the second stage is increased further, a point is reached where the amount of slurry is sufficient to quench the first stage syngas to the desired level and no water quenching is needed. From this point on until all the slurry is directed to the second stage, no water quenching is needed and the syngas is quenched below the 1850 F. At about 50% slurry to the second stage, the exit temperature reaches 1650 F. When 100% of the slurry is directed to the second stage the exit temperature has dropped to about 1300 F. If syngas quenching is used as the supplemental quenching agent, a similar response will be occur. In fact, the quantity of slurry to the second stage which sufficient to quench the first stage gases to any given temperature is independent of the type of supplemental quenching medium. The impact on the oxygen required for gasification of slurried petroleum coke for increases feed to the second stage is shown in Figure 3. Note the oxygen requirement is the same for either supplemental quenching option, i.e., either water or cool syngas. This is because of the lack of reactivity of the petroleum coke in the second stage resulting in the first stage receiving the same ratio of slurried coke and dry solids returned from the particulate removal system. It decreases rapidly at first from 3,800 tons of contained oxygen per day at zero slurry to the second stage until about 50 % of the slurry is directed to the second stage and then asymptotically approaches about 3,300 tons per day. Current operation of the two stage gasifier directs about 5 to 15% of the slurry to the second stage. A period of rapid decrease occurs while there is insufficient slurry to quench the first stage syngas to 1850 F, after which additional slurry to the second stage has reduced effect. If 100% of the slurry is feed to the second stage, an 8 to 10% decrease in oxygen demand would be expected. 8

9 FIGURE 3: OXYGEN REQUIREMENT 4000 SINGLE STAGE, SLURRY FEED Contained Oxygen, TPD TWO STAGE, SLURRY FEED SINGLE STAGE, DRY FEED 0% 20% 40% 60% 80% 100% Slurry to Second Stage Figure 4 shows how the temperature from the second stage varies with second stage slurry flow. FIGURE 4: Second Stage Temperature Temperature, F % 20% 40% 60% 80% 100% Slurry to Second Stage 9

10 Supplemental quenching in the second stage is not required after about 20 to 40% of the slurry is directed to the second stage. With 100% of the slurry directed to the second stage, the second stage exit temperature is about 1300 F. The duty of the syngas cooler is another primary performance parameter that will vary with the slurry rate to the second stage. Cooler duty is dependent on the quantity and temperature of the syngas entering the unit. When quenching with cool syngas, the flow and temperature of the syngas entering the cooler is greater than for the water quench mode as seen in Figure 5. The option of water or syngas for supplemental quenching shows a dramatic effect on the amount of heat available within FIGURE 5: SYNGAS COOLER 600 SYNGAS TO SECOND STAGE Duty, MMBt/hr WATER TO SECOND STAGE 300 0% 20% 40% 60% 80% 100% Slurry to Second Stage the syngas cooler to produce steam. The system energy involved in the quench process will be distributed in the product as sensible heat, latent heat, and chemical energy. This distribution will be govern by chemical and thermal equilibrium relationships while maintaining the mass into the quench. More heat from the hot syngas is available to produce 700 psig steam when syngas is the quenching agent rather than water. The water s latent heat of vaporization is a dominate factor in the quenching process. The latent heat of vaporization present in the syngas generated during the quench is not available for heat exchange at the temperatures encountered within the syngas cooler. Condensation within the hot path of the syngas cooler is to be avoided or severe corrosion issues may be encountered. The cold gas efficiency increases with increased slurry to the second stage, see Figure 6. This is to be expected since less water within the total slurry is introduced into the first stage of the gasifier. This in turn requires less conversion of the carbon to CO 2 to supplied the required heat to vaporize of the water. Cold gas efficiency increases about 6% going from 10% slurry to the second stage to 100%. 10

11 When chemicals are to be made from syngas, a key process parameter is the H2/CO ratio. Figure 7 shows how this parameter varies with the amount of slurry directed to the second stage. Water in the system is the driver for the H2/CO ratio, more water translates to more hydrogen in the syngas and an increase in the ratio. This may seem to be a good thing for the production of hydrogen. However, when power is co-generated and hydrogen is not separated before the syngas is directed to a FIGURE 6: COLD GAS EFFICIENCY WATER TO SECOND STAGE Efficiency, % SYNGAS TO SECOND STAGE % 20% 40% 60% 80% 100% Slurry to Second Stage combustion turbine, that some of hydrogen produced in gasifier goes to the combustion turbine and is not available in the product hydrogen stream. Figure 8 shows, higher yields of hydrogen can be obtained while co-generating power by increasing the slurry rate to the second stage. With the higher cold gas efficiency at increased slurry quench, overall hydrogen yield is greater. If hydrogen were the only product then water quench would be the preferred mode. A two stage gasifier gives the option of where and how the hydrogen is generated. As can be seen, there are many options available to tailor the overall process for the optimum production of the desired products. SUMMARY: The Destec gasifier has gone through many hoops with excellent performance. Equipment and processes of its technology has continually improved. Through the experiences of LGTI and Wabash much has been learned and put into practice to bring the gasification technology to the global market for application to a broad range of feedstocks and products. Slurry mixer nozzles have been developed that can operate for four months and can be swapped out in less than a day s time. The 11

12 FIGURE 7: H2/CO RATIO H2/CO Ratio 0.6 WATER TO SECOND STAGE 0.4 SYNGAS TO SECOND STAGE 0.2 0% 20% 40% 60% 80% 100% Slurry to Second Stage gasifier has demonstrated it can gasify low rank coals, bituminous coals and petroleum coke with high gasification efficiency. The supporting process steps such as high temperature heat recovery, dry particulate removal, COS hydrolysis and acid gas removal have been adapted for application to the gasification technology with excellent success. Opportunities continue in the flexibility and efficiency of the technology. The advantages of two stage gasification of petroleum coke are ready for the taking. Using petroleum coke as a feedstock, effective use of the second stage of the Destec gasifier can improve performance and flexibility of the technology. Oxygen power requirements are a major contributor to the power consumption of all oxygen blown gasifiers. Significant reduction in the oxygen required for gasification can be obtain with increased sluryy to the second stage. Minor changes in equipment and operation of the two stage gasifier are required to realize the potential of increased slurry feed to the second stage. This approach could be extended to other feedstock as well, i.e. low rank and bituminous coals. Cold gas efficiencies approaching 80% are possible with out sacrificing the simplicity of a slurry feed process. The two stage technology has come a long way from the early 1970 s and is staged for a grand entrance into the 21 st century. 12