Chapter 3: Gasification for electricity generation

Chapter 3: Gasification for electricity generation

CHAPTER 3: GASIFICATION FOR ELECTRICITY GENERATIONt 3.1. Integrated Coal-Gasification Combined Cycles (IGCC) 3.1-1. Introduction Because of the h...

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Integrated Coal-Gasification Combined Cycles (IGCC)



Because of the huge US coal reserves (estimated to last at least 200-300 years), the preferred use of the cheapest available energy source, the stalemate faced by the nuclear industry, and the uncertainty of future natural gas (NG) prices, it is likely that coal will continue to he the major fuel for electric utilities in the future. Integrated coal-gasification combined cycle (IGCC) systems offer many advantages over conventional pulverlzed-coal combustors. These advantages include higher energy-conversion efficiency, reduced pollutant emissions, lower financial risks associated with staged capacity additions, and the relatively small modular unit size used, as well as the ability to accept a variety of feedstocks. An IGCC power plant involves the coupling of a coal-gasification system producing s clean fuel gas to combustion and steam turbines that generate electric power. A schematic diagram of a unit of this type is illustrated in Fig. 3.1-1. To illustrate the important features of an IGCC, the Cool Water Coal Gasification Program (CWCGP), which is an actually operating IGCC plant, will be described in Sec. 3.2. 3.1-2.

IGCC System


Development of a number of advanced coal-gasification systems has been progressing at a rapid pace (compare Table 3.1-1). Uncertainty regarding conventional fuels (NG and oil), environmental regulations that represent increasingly tight standards, and uncertainties regarding nuclear power deployment in a number of countries have spurred commercial developments of coal-gasification systems for diverse applications such as (a) electricity generation, (b) fertilizer, hydrogen and organic chemicals production, and (c) generation of hot water for district heating, etc. Coal-gasification systems may be classified according to the type of gasifier used in which coal is contacted and reacted with an oxidant (air or oxygen) to produce the desired fuel gas. If the system is blown with air, the fuel gas is Iow-Btu gas; if the system is blown with oxygen, the fuel gas is medium-Btu gas. Three types of contacting devices are moving beds, fluidized beds, and entrained flows. In moving beds, a descending bed Of coal, usually 1/8 to 1 inch in size, is fed by a pressurized lockhopper system to the top of a shaft. Reactant gaseous oxygen (or air) and steam enter the bottom of the vessel. As coal descends, it is devolatilized; then, pyrolysis reactions occur and finally carbon is gasified. The raw product gas contains tars and oils, which need to be condensed and removed. The ash may he withdrawn as a dry solid or as molten slag. In some moving-bed versions, tars, oils, and coal fines are recycled to extinction. In fludized-bed reactors, coal is ground to produce a fluid-bed grind (ca 8 mesh or less). The oxidant gas (and some steam) are introduced through a perforated deck or grid at the bottom of a vessel. The flow rate of the reactants is high enough to suspend the coal particulates but not blow them out of the vessel. A uniform temperature is obtained as the result of the mixing that occurs. Depending on the temperature, tars and oils can be avoided but fines carryover and ash slagging limit conversion of some coals to 80-90% of the carbon. In order to overcome this limitation, the carbon-containing ash may be processed in an additional vessel or the unconverted carbon can be recycled to the gasifier. In entrained-flow systems, a relatively fine grind of coal (ca 75% through 200 mesh) is fed either as a dry solid or as a water and coal mixture to a short-residence time reactor. Contacting with the oxidant is achieved by means of a nozzle arrangement. At the high velocities and temperatures used in entrained systems (2000 to 3000°F), no tars or oils are produced. Carbon burn-out is nearly complete and the product gas is essentially a mixture of CO and H 2. In the US and abroad, advanced coal-gasification technologies have been under development for the last decade. Several technologies have been supported by EPRI: (i) Texaco technology represents an entrained system that features a coal-water slurry feeding the pressurized, oxygen-blown gasifier. It is the farthest advanced in that three commercial or demonstration plants are in operation. Two of these plants are located in the US and one in Japan. A plant in the FRG will start up in late 1986 to produce organic chemicals and hot water for district heating. Projects have also been announced for China and Sweden. (ii) The Shell coal-gasification unit is under construction at a 250/400 TPD pilot-plant scale at their

tSections 3.1 and 3.2 were written by S. B. Alpert, S. S. Penner and D. F. Wiesenhahn; Sec. 3.3-3 by P. B. Tarman, and the remaining subsections of Sec. 3.3, as well as Sec. 3.4, by S. S. Penner and D. F. Wiesenhahn with advice and inputs from correspondents identified in the subsections. ~Thls section is reproduced from Ref. i.




X~ne International Journal






F~r~Stea~m: I






Combusti TurbinoenI


Heat _.LHot Exhaust Exchanger~ Gases . [-~-]____.~ ExhaustGases I I _l--~"lo Atmosphere s~e~F ' ~ -I~ FeedWater


Power Turbine Exhaus~ Steam



Table 3,1-i.

Schematic drawing showing a generic IGCC system.

Status of selected coal-gasification technologies.


Operating Plants


Cool Water: 2 × I000 TPD; 117 MWe; Ube: 4 × 500 TPD; Tennessee Eastman: 2 × 900 TPD; Ruhrchemie: i x 600 TPD


250 TPD pilot plant in TX


160 MW e IGCC at Plaquemine, LA; I x 2,500 TPD gasifiers


600 TPD at Westfield,


600 TPD at Wood River


35 TPD at Waltz Mills; 500 TPD in China (1989 start-up)


40 TPD at Chicago; 200 TPD proposed for France


Gasification for Electricity Generation


research center in Deer Park, Texas, and is expected to lead to commercial designs in the late 1980s. The Shell process features a dry-feed, entrained gasifier system that operates at elevated temperature and pressure. Current studies with US electricity companies are defining commercial opportunities. (iii) The British Gas Corporation and Lurgi CmbH have jointly developed a slagging, moving-bed gasifier system. A commercial gasifier prototype (600 TPD) will be started up at Westfield, Scotland, in early 1986. Virginia Power is considering installation of a coal-gaslfication system for a 200-MW e IGCC power plant based on the BGC/Lurgi technology. (iv) An air-blown, rotary, ported kiln (similar to a moving-bed device) is under development by Allis Chalmers Corporation. A 600 TPD prototype is located at an Illinois Power Co. power station. (v) The Dow Chemical Company is installing a 160-MW e IGCC plant in Louisiana that will produce electricity and synthesis gas for industrial chemicals. Details of the system are proprietary, but it features a coal-water-slurry-fed entrained gasifier. Price supports of $620 million from the Synthetic Fuels Corporation have been obtained for the project. Other gasification-systems technologies have been evolving, including the KelloggRust-Westinghouse gasifier and the Institute of Gas Technology U-GAS system. These are representative of ash-agglomerating fluid-bed systems. Advanced fluid-bed systems are also being developed in Japan. A Winkler demonstration fluid-bed system operating at elevated temperature and pressure is being started up in the FRG by Rheinische Braunkohle. The Winkler system will handle 700 TPD of coal to produce industrial chemicals and electric power. Other projects that are at the pilot-plant stage of development include a 50 TPD pressurized pilot plant by GKT-Krupp. The Vereinigte Elektrizit~tswerke Westfalen (VEW) has started up a 250 TPD pressurized pilot plant that partially converts coal (60% conversion) to low-Btu gas for power generation. Lurgi has gasified lignite in an atmospheric-pressure, circulating fluid bed in their 15 TPD pilot plant in Frankfurt, FRG. In Japan, several pilot-plant programs are also underway, including development of a molten-iron gasification system. A 250 TPD pilot plant is under construction in Sweden by Sumitomo-KHD; in this unit, sulfur is captured in the slag. Development of advanced combustion turbines is also proceeding rapidly. The efficiency of combined-cycle equipment is increasing because of the ability to operate at higher firing temperatures. In utility applications, firing temperatures of 2,000°F are conventionally used and higher temperatures of 2,300°F may be expected before 1990. Developments in the areas of reheat, materials, and advanced cooling methods promise additional improvements in efficiency in the 1990s. 3.1-3.

Advantages of IGCCs

High efficiencies are obtained in combined-cycle operation because efficient combustion turbines are combined with steam turbines. The gas turbine converts high temperature (~2300=F) heat efficiently while the steam turbine utilizes low-temperature heat efficiently in the form of steam (-1050°F). Figure 3.1-1 shows a schematic drawing of a generic IGCC system. Low pollutant-emission levels result from the combustion of a clean fuel. Pollutants are removed before combustion by using gas-purification systems tested in other industries. Combined-cycle systems yield very low emissions when NG is burned. Water consumption of IGCC systems is also substantially lower (-33%) than for pulverized-coal combustors. Thus, coalgasification systems are environmentally superior to other alternate coal-utilization technologies and will meet rigorous environmental standards for S and NOx, as well as particulates. Compared to conventional coal-combustion plants, IGCCs have both lower capital and lower operating costs, 2 resulting in lower net electricity costs to consumers. Compared to conventional or combined-cycle systems burning NG, the economic benefits based on current costs (c a $2/milllon Btu) are not so clear. 2 When NG prices are very low, as at present, it is the preferred fuel for power generation. Because of its modular design, an IGCC system may be phased in at different stages of plant construction, as is ilustrated in Fig. 3.1-2. Each stage has a short construction time. The use of small capacity additions eliminates the need for large, high-risk capital investments. This aspect of IGCC units is especially attractive to utilities with uncertain future demand requirements. The last step (addition of the gasifier) may be delayed until fuel prices make this addition economically attractive. A properly designed IGCC system will have the flexibility of accepting many different types of feedstocks, including such l o w - r a n k coals as lignites, as well as petroleum coke. Additionally, gasification systems may be configured to produce other industrial chemical products, which adds a desirable degree of flexibility. 3.1-4.

Future Utilization of IGCCs

Table 3.1-2 is a summary of future goals for 500-600 MW e IGCC plants. Research needs relate especially to studies designed to reduce capital and operating costs. Among existing coal technologies for electricity generation, the IGCC may well represent a superior choice. The most serious limitation for IGCC use is its cost when compared with the use of NG and petroleum at currently low prices in conventitonal electricity generation units. Continuing research to reduce system costs is recommended.



T h e I n t e r n a t i o n a l Journal


Phase 1


N a t u r a l g a s o r oil

]:::'gas t u r b i n e ( .i'.:':] . . . . "~" ~;'...,..,v.':..:.-:,.,'.v....,~:| N e t p o w e r

Water (b)



Natural gas or oil ....



...~ l.g+s turb:,+ne'/,-,l


" 1 . " " '""'":"'-'- "1

Water Na~al


Net power

~i!.:-~X;dv~.~.d:?::...:.-. I 1~.0 Mw

gas o~ o i l

=t!!!:i.( N e t p o w e r










350 MW

230 M W


Net power



gas or oil


Water ~

,--," ....... _



1 25 MW

I '~ ~--~ .... I


Na~ral gas or oil - ~ ' X d ~ c.% d ( ... ~gas, t v~ .bln; Water ........... I

~~:ii?l I


.'.'.:.'.'.'.'.'-'.':::" Phase 4 270 MW


400 MW



200 M W ¢ I



l;~,t.~r....t¢.,11.1 it, Aav-ancect~l .~ .

I li~r~Fi,r,,U,l ,iH R S G -,

I ~ I= - " -" q L

I ,

I,ga+.~bln4"--,'*'l'~-~,,,-~:,l----I Coal



S~ i c a t i o n " I

Water __~%!'::::::p~.~t::::(::::??)::


5 MW Internal c onsumption







Table 3.1-2.


,'-- -- -






I -

Net power


70 MW t- . . _



_., ~.,-,ufl

S t e a m ).(]

i :t~:n~:"l

Four installation stages of a phase-in IGCC system; reproduced from Ref. 2. The existing capacity is designated ~ and newly installed capacity by ~ .

F u t u r e g o a l s f o r 5 0 0 - 6 0 0 MW e I G C C p l a n t s ; r e p r o d u c e d f r o m l%ef. 3. C o m p a r i s o n s r e f e r to c o n v e n t i o n a l c o a l - f l r e d p l a n t s a s b a s e l i n e .

A b o u t 10% h i g h e r e f f i c i e n c y , i . e . , h e a t r a t e s o f 9 0 0 0 - 9 1 0 0 B t u / k W h , c o r r e s p o n d i n g to 3 7 . 5 - 3 7 . 9 % e f f i c i e n c y . L o w e r p o l l u t a n t e m i s s i o n s , 33% l e s s w a t e r c o n s u m p t i o n , r e d u c e d w a s t e water treatment and formation of non-hazardous, useful by-products. A 15% r e d u c t i o n i n l e v e l i z e d e l e c t r i c i t y


M o r e r a p i d a n d c h e a p e r c o n s t r u c t i o n of s m a l l e r

modular units.

Gasification for Electricity Generation


References for Section 3.1 i.

2. 3.

D. F. Spencer, S. B. Alpert and M. J. Gluckman, "Integrated Coal Gasification Combined Cycles (IGCC) an Emerging Commercial Option for the Power Industry," paper presented at a 1985 ACS meeting, EPRI, Palo Alto, CA (1986). D. F. Spencer, "The Commercial Implications of the Cool Water Project for the Electric Power Industry," EPRI, Palo Alto, CA (1986), unpublished. W. N. Clark, "Remarks at Alternative Coal Tests Press Briefing," Cool Water Coal Gasification Plant, Daggett, CA (April 4, 1986).


The Cool Water IGCC


General Features

The Cool Water Coal Gasification Program (CWCGP) utilizes a 100 MW e IGCC plant located in Daggett, CA. It has a coal capacity of 1000 TPD and is located adjacent to a 600 MW e NGfired plant of the Southern California Edison Co. Construction was started on December 15, 1981, and first electricity production occurred on May 20, 1984. The CWCGP was completed ahead of schedule and below budget. 1 The total capital cost was $263 million. There are six participants, each contributing a minimum of $25 million: Texaco Inc. ($45 million), Southern California Edison Co. ($25 million), EPRI ($69 million), Bechtel ($30 million), General Electric Co. ($30 million), and the Japanese Cool Water Program Partnership ($30 million). Additional $5 million contributions came from the Empire State Electric Energy Research Corp. and from Sohlo Alternate Energy Day. Co.; there was also a $24 million loan. 3.2-2.

Process Description

The CWCGP is shown schematically in Fig. 3.2-1. More detailed diagrams can be found i n Ref. 2. Coal is brought by rail cars, stored in two large storage silos Q , and transferred to be ground and slurried O " A 60/40% coal-water slurry is normally used. The slurryr~, is reacted with 02 in the gasifier @ . Oxygen is supplied from an over-the-fence plant ~ J . A Texaco gasifier is used (compare Sec. 3.3-1). If the gasifier operates in the heat-recovery mode, the hot gases are cooled in a heat exchanger and high pressure steam (~I00 arm) is raised. Slag is removed with a lockhopper system O ; ash and water from the gaslfier separated Q . Some solids are recycled back to the grinding and slurrying processes ~ . Solid slag is presently stored in speclally-llned landfills. Recently, however, the EPA and the State of California Health Department have determined that this slag is non-hazardous. Studies of markets for concrete or asphalt applicatlons are being undertaken. The producAt gases are scrubbed to remove particulatesp, ~3~ and are then transferred to the syngas cooler (7] and the sulfur removal unit ~ . Sul furk~-compounds (H2S and COS) are sent to the sulfuY recovery unit ~ , where the sulfur is converted to elemental form and sold (currently at $100/ton). Sulfur removal is accomplished by the Selexol process; sulfur recovery from H2S and COS is implemented by using the Claus system. Waste acid-gases from the Claus unit are cleaned by the SCOT process. The clean syngas is saturated ~(i0) to control NO x emiss~ions prior to combustion and power generation in the General Electric combustion turbine i ~ . T h e combustion-turbine exhaust gases are sent to the Heat Recovery Steam Generator, HRSG ~ , and vented to the atmosphere. In the HRSG, heat from the hot combustion gases is used to make steam. This steam is combined with the steam made by cooling of the syngas ~ (if applicable) and is then passed through the steam turbine I ~ . At Cool Water, the combustion turbine generates 65 MW e and the steam turbine 55 MW e for a to~tal capacity of 120 MW e. Boiler feedwater I ~ for the steam turbine is supplied from the adjacent Southern California Edison plant. Well water ~ is used for slag processing ( ~ . Waste-water is treated i ~ and sent to on-slte evaporation'~W ponds. 3.2-3.

Performance Results

Some of the design goals and actually achieved performances are listed in Table 3.2-1. Three representative coals have been gasified so far. The plant has met all of the design goals. The performance of the CWCGP is very good for the coals that have been tested. Illinois No. 6 and the Pittsburgh No. 8 coals with sulfur contents of 3.1 and 2.9wt%, respectively, have been handled. Plans call for the testing of additional coals, including an Australian coal. Because of the high carbon-conversion efficiency, the carbon recycling system illustrated in Fig. 3.2-1 has not been used. Refractory wear in the gasifler has exceeded expectations. Minor problems encountered were wear and plugging of the slag-handllng system, difficulty in keeping the lockhopper valves operating smoothly, and fine slag particles remaining in the gas-scrubbing system. 1 All of these problems were resolved by making minor modifications in plant operation or design. Pollutant-emlssion results are given in Table 3.2-2. Actual emission levels were always well below requirements, even with hlgh-sulfur Eastern coals. The environmental requirements listed in Table 3.2-2 are the strictest for any coal-burnlng power plant in the US. Both modes of gasifier operation have been utilized: gasifler heat recovery and direct quenching (compare Sac. 3.3-1). Capacity factors have met targets expected for the EGY 12;8/9-C




Iuteruatloual J o u r u a l





~D ~D v


il, ~ws I:~~""



o~ ~o

bO E-i'~





G a s i f i c a t i o n for E l e c t r i c i t y G e n e r a t i o n

Table 3.2-1.


D e s i g n and a c t u a l p e r f o r m a n c e for the CWCGP; r e p r o d u c e d from Ref. 4.

Performance Parameter

Design T

Coal type S u l f u r c o n t e n t (wt%) HHV (Btu/Ib)

Actual Performance Illinois No. 6

Pittsburgh No. 8







12, 300

12, 300







Oxygen consumption (TPD)




97 9

Gross power production (IV[We)





Byproduct sulfur produced (TPD)









Carbon conversion (%)





Gasifier/syngas cooler efficiency (%)









ii, 300

12, 000






Coal-feed rate (TPD)

Coal/~ater slurry concentration (wt% solids)

Gasifier refractory life (yr) Overall heat rate (Btu/kWh) § Efficiency (%) t D e s i g n p a r a m e t e r s b a s e d on S U F C O


Data not y e t a v a i l a b l e .


The h e a t r a t e s w e r e not o p t i m i z e d and a r e e x p e c t e d to be r e d u c e d by ~ 2 , 5 0 0 B t u / k W h in f u t u r e :plants.

Table 3.2-2. A l l o w e d pollutant l e v e l s and a c t u a l CWCGP pollutant e m i s s i o n s m e a s u r e d a t the HRSG. All u n i t s a r e I b s / 106 Btu f r o m R e f . 4.

Coal Type


Permit & 1%e g u l a t l o n Limits



(o. 5% s)

i l l i n o i s No. 6 (3.0% S)

P i t t s b u r g h No, 8 (2.9% S)

1985 E PA Test

Preliminary Test Re sults

Federal NSPS (b) 0. Z4 (c)

SO 2









0. 004

NS (e)

SO 2


0. 076

o. 6 (d)



O. 094






0. 004


Particulate s


0. 009


SO z


0. 086

o. 6 (d)






0. 004




(a) E m i s s i o n r e q u i r e m e n t s for the HI~SG S t a c k f r o m l i m i t i n g p e r m i t and r e g u l a t o r y e m i s s i o n criteria.

Co) N e w Source Performance Standards for a coal-fired power burning equivalent coal as CWCGP. (c) 0 . 8 l b / 1 0 6 Btu u n c o n t r o l l e d e m i s s i o n s × 0.30 for c o n t r o l l e d e m i s s i o n s .

(d) Emissions controlled to O. 6 Ib/lO 6 Btu. (e) NS: No standard.

Energy, The I n t e r n a t i o n a l J o u r n a l


first 2 years of operation and have been generally equal to or superior to targeted goals. is expected that a multi-purpose ICCC will have a capacity factor greater than 80%.


References for Section 3.2 i. 2.

D. F. Spencer, S. B. Alpert and H. H. Gilman, Science 232, 609 (1986). Electric Power Research Institute, "Cool Water Coal Gasification Program -First Annual Report," Report No. EPRI AP-2487, Palo Alto, CA (1982). Ref. 2 of Sec. 3.1. Ref. 3 of Sec. 3.1.

3. 4.


Selected Gasifiers for IGCC Plants

The following coal-gasification systems represent important developments in gasification technology. The systems are designed to handle a wide variety of coals and to be useful in both combined-cycle gasification systems for electricity generation or for the production of plpeline-quallty SNG. 3.3-1.

The Texaco Coal-Gaslficatlon Process (TCGP) t



The Texaco Coal Gasification Process (TCGP) has the following design features: (a) a pressurized reaction vessel; (b) a downward loading, entrained flow, slagging reactor; (c) airor 02-blown gasification; (d) high operating temperatures; (e) flexible feeds of fuels and output products; (f) system coupling for cogeneration (i.e., using the excess heat produced in the gaslfier to generate electricity). The development schedule for the TCGP is summarized in Table 3.3-1. 3.3-IB.

Process Description

Two configurations of the TCGP are shown in Fig. 3.3-1, depicting two different gascooling methods. The TCGP is designed to operate at pressures between 20 and 80 arm and at temperatures between 1200 and 1500°C.

Table 3.3-I,


Type of P l a n t

Texaco, Inc.


Texaco, Inc.i


Texaco, Inc.




Dow Chemical

D e v e l o p m e n t of the T C G P ;

Location California

Coal Capacity, TPD


taken f r o m iAef. I.

Gas Cooling





direct quench (d.q.)




d.q./heat recovery

C a l i f o r nia




W. Germany






197 9














acetic anhydride

Southern Calif. Edison Co., e t c . (Cool Water)


C a l i f o r nla




commet cial






comm e t cial

W. Germany



d.q./heat recovery

heat recovery

oxo- c h e m i c a l s

synthesis gas for e l e c t r i c power

h e a t r e c o v e r y or d.q.

synthesis gas for e l e c t r i c power

ammonia oxo- chemical/ H2

SThe radiant section is necessary to cool the gases below the sticking temperature of the slag before entering the convective cooler.

Gasification for E l e c t r i c i t y Generation

Coal Grindingand Oxidant SlurryPreparation Water~-- Coal Grinding Oil . co~,


Gasificationand Gas Cooling



i~ :






~ ~Texac° Particulate1. J~Gasifier Scrubber~" ~Y-~ _ .. - --i ~uencnea syngas., ,,1(

L~) ~

(~.~, I,


~ Coarse Slog to ~ Disposal

Sump Slog [~~So? Separator

Coal Grindingand Oxidant SlurryPreparation -

T "



Particulate-Free Synthes~sGas

Fj L. ,~

LockhopperU ~



Gas Scrubbing

.~ r----

I"~1 ":" I"-'~ ] I ~ | J Slurry l ] ISlurryl . Tonl~I oLo lPump] (Optional)


Gasification and Gas Cooling


P~ge Water Fine Slag and Char To Disposal

Recycle (Optional) I


Oil Coal Grinding Mill CooJ Feed ,--.t,~ ,:-.. ~ , I I I'


(~) ,Texaco Gasifier ', r--I~ ,


Recycle (Optional)


Gas Scrubbing

Slurr) Tank @

HighI~ Pressure Steam Particulate-Free SynthesisGas L w

P~tcirCu~ ~)teerC ~. ` Convective If Cooler ']~1" I


Radiant Cooler ,,


Coarse Slag to Disposal I_



Boiler Feedwater Fine Slag and Char To Disposal

Slog SumpI ~. Separator

Recycle (Optional)


The process diagram for the TCGP is shown for two gas-coollng modes: (a) direct quench and (b) waste-heat recovery; reproduced, with minor modification, from Ref. 1.



The International Journal

The coal is wet-ground O and slurried with oil or water Q . If (molten) coalliquefaction residues are used, these steps are omitted. Typical slurry feeds have ~between 60 The slurry is mixed with 02 or air in the gasifier-burner ~ J . For and 70wt% of solids. gasification of an oil slurry, steam or another temperature moderator is added to the burner stream; water serves this purpose for water slurries. By properly adjusting the O2/slurry ratio, temperatures are maintained above ash-fluid temperatures. After leaving the gasifier (burner), the gases are cooled Q , either by direct contact with quenching water [Fig. 3.3-i(a)] or by passing through a radiative coolers and then a convective cooler [Fig. 3.3-I(b)]. In the latter case, heat is recovered from these gases (and from the gasifier) in the form of high-pressure steam, which can be used to generate electric power. The former method is preferred when the output product is NH 3 or H 2, since the required shift reactor is easily integrated in the quench mode; also, heat transfer from the gases to the quenching water produces steam, which is used downstream to increase the H 2 yield. The direct-quench method requires smaller capital and is smalle~rthan the heat recovery method. After cooling, the gases enter a water scrubber ~ J , where char and fly-ash are removed from the product gas. If necessary, the product gases also undergo sulfur cleanup (not shown) using commercially available technology. The scrubbing water is sent to the clarifier Q and is then recycled to the particulate scrubber Q , thus forming a closed loop. Some of the recycled water is purged to prevent scaling and to control the level of dissolved solids. A small amount of make-up water is needed. Most of the ash from the gasifier Q is removed as a quenched slag through a water-sealed depressurizing lockhopp~.r system O and is then sent to the slag-collection sump ~ . Fines from the slag separator ~ are pumped to the clarifier Q for recycle or disposal while the coarse slag from the separatoq~r is removed. The product gases leaving the particulate scrubber ~ ) contain H 2, CO, CO 2, H20, and traces of Ar, N2, CH 4, H2S, and COS. The amounts of the two sulfur pollutants present depend on the sulfur contents of the feed fuels. 2 There is no detectable amount of NO x formed, 2 and it is stated that no SO x is produced. 1 Generally, very low pollutant levels result from the TCGP in both the gaseous and wastewater streams. A detailed analysis of all pollutant levels is given in Ref. 2. The observed excellent gasifier performance is attributed to the high reaction temperatures 2 and the highly-reduclng environment used in the process. 1 A number of different products have been prepared in commercial plants (compare Table 3.3-1). These include H2, NH3, fuel gas for electricity generation, and synthesis gas (CO and H2) for the production of methanol or other oxo-products. Many different types of fuels have been successfully gasified in the TCGP. According to Texaco, any carbonaceous material that may be formed into a pumpable, concentrated slurry can he gasified. A summary of the types of coals, cokes and liquefaction residues that have been gasified in the Texaco pilot plants is given in Table 3.3-2. Free-swelling indices ranging between 0 and 8 have been handled at the RAG/RCH plant in FRG. 1 In Ref. 3, the conversion of petroleum coke to synthesis gas in a 30 TPD plant in Ube City, Japan, is described in detail. This plant has been operating since 1982. Table 3.3-2.

Examples of feedstocks gasified in the Texaco Montebello plants.

Coals: anthracites, semi-anthracites, bituminous and subbituminous coals, and lignites. Petroleum cokes: fluid, delayed, sands bitumens.

calcined, fluid from tar-

Coal liquefaction residues: formed from solvent refined coal (SRC I and II), H-coal, and in the Exxon donor solvent (EDS) process. Others:

Lurgi tar/oil.


The Shell Coal-Gaslfication Process (SCGP)t



The past and current development schedules of the SCGP are summarized in Table 3.3-3. The SCGP is described as a "highly efficient process with demonstrated feedstock flexibility from lignites to coke". 4 The SCGP-I demonstration unit is expected to be completed during the fourth quarter of 1986, with plant start-up scheduled for the first half of 1987. 4 It is being developed by several Shell Oil units, in collaboration with EPRI and Lummus Crest (a Combustion Engineering subsidiary). The initial application of this technology is expected to be to electric power generation.

tThls is a brief summary of technical material provided by Heitz and Nager. 4 It has been reviewed and approved for accuracy by M. Nager (Shell Oil Company) to whom we are greatly indebted for advice and assistance.

G a s i f i c a t i o n for E l e c t r i c i t y G e n e r a t i o n

Table 3.3~3.



Milestones in the SCGP development.

Scale of Operation



development initiation

1976 (start-up)

6 TPD pilot plant

Amsterdam, Holland

1978 (start-up)

150 TPD experimental unit

Harburg, b'1~G


SCGP-I (-1/5 of commercial size): 250 TPD of highS bituminous coal, -400 TPD of wet, high-ash lignites

near Houston, TX

An evaluation of the 6 TPD SCGP in Amsterdam is given in Ref. 5. Two coals were tested: Illinois No. 5 and a Texas lignite. Further information on the SCGP, including an economic assessment of an IGCC system utilizing the Shell gasifler, may be found in Ref. 6. 3.3-2B.

Process Description

The process diagram for the 6 TPD process-development unit is reproduced in Fig. 3.3-2 from Ref. 5. Pulverized coal is sieved over a vibrating screen with A1 mm openings to remove the coarse materials. It is then pressurized in a lockhopper system ~I~ and is pneumatically transported from the feed vessel Q to the reactor ~ , which consists of two oppositelyfired burners. Temperatures in the reactor are sufficiently high to melt the coal ash and produce a liquid slag. A dense, non-leachable slag is formed as the liquid slag leaves the reactor through the slag tap and falls into a water bath @ . The reactor product gas and fly slag (which is comprised mostly of residual carbon and partially molten ash) is quenched ~ with recycled product ga2~ to about 350°C. Primary separation of fly slag from product_Eas occurs in a cyclone ~ . Further separation is accomplished in the venturi scrubber ~ , the separator vessel ~ , and the packed-bed scrubber Q. The product gas is now free of solids (

Energy, The International Journal

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al -r


l_ ~


I __


i u%

G) ~J

L (D

m> i






E~ c4 J

N~ c



Gasification for Electricity Generation

Table 3.3-4.


R e p r e s e n t a t i v e p r o d u c t - g a s c o m p o s i t i o n s (in v o l t ) o b t a i n e d a t the S C G P i n A m s t e r d a m ; f r o m l~ef. 5. Coal Type


Texas Lignite

Illinois No. 5 H 2




52. Z4

5Z. 43



CH 4





0. Z7

14. 98




CO 2

N z t H20 % V o l t on a dry-gas basis.

Table 3.3-5.

Typical treated product-gas composition anticipated for the S C G P - I ; reproduced f r o m llef. 4.



The U-GAS Processt



go by v o l u m e (Nz-free)

H z






0. I









0. 001

NH 3


0. 001



0. 001



0. 001

CH 4






The Institute of Gas Technology (IGT) has developed the U-GAS process to produce gas from coal in an efficient, economic, and environmentally acceptable manner. The product gas from the process may be used to produce iow-Btu gas, medium-Btu gas, and substitute NG for use as fuels, or chemical products such as ammonia, methanol, hydrogen, and oxo-chemicals, or electricity generated by a combined cycle or a fuel cell. The three main goals for developing a new gasification process have been economical handling of large volumes of gas throughput, high carbon conversion of coal to gas without producing tar or oil by-products, and minimum damage to the environment. The U-GAS process has been developed in a multiphase progKam over a period of 8 years and has utilized skills and expertise evolving from earlier coal-gasification projects at IGT that date back to 1950. The process has been extensively tested in a pilot plant to establish process feasibility and provide a large data base for scale-up and design of the first commercial plant. The U-GAS process is considered to be one of the more flexible, efficient,

fPrepared by P. B. Tarman, Vice President, Research and Development, Chicago, IL 60616.

IGT, 3424 South State St.,



The International


and economical coal-gasification technologies developed in the US during the last decade. The U-GAS technology is currently available for licensing from GDC, Inc., a wholly owned subsidiary of IGT. 3.3-3B.

Process Description

The U-GAS process accomplishes four important functions in a single-stage, fluidizedbed gasifler (Fig. 3.3-3): it decakes coal, devolatilizes coal, gasifies coal, and agglomerates and separates ash from char. Other characteristics of the process are shown in Table 3.3-6. In the process, coal (1/4 inch x 0) is dried only to the extent required for handling purposes. It is pneumatically injected into the gasifier through a lockhopper system. Within the fluidized bed, coal reacts with steam and oxygen (air can he substituted for oxygen) at a temperature of 1750 to 2000°F. The temperature of the bed depends on the type of coal feed and is controlled to maintain nonslagging conditions for ash. The operating pressure of the process depends on the ultimate use of product gas and may vary between 50 and 350 psi. The pressure must be optimized for a particular system; for production of an industrial fuel, a minimum pressure of 80 to I00 psi is desirable. At the specified conditions, coal is gasified rapidly, producing a mixture of H2, CO, C02, and small amounts of CH 4. Because reducing conditions are always maintained in the bed, nearly all of the sulfur present in coal is converted to H2S. Simultaneously with coal gasification, the ash is agglomerated into spherical particles and separated from the bed. A portion of the fluidizing gas enters the gaslfler through a sloping grid. The remaining gas flows upward at high velocity through the ash-agglomerating device and forms a relatively hot zone Within the fluidized bed. High-ashcontent particles agglomerate under these conditions and grow into larger and heavier particles. Agglomerates grow in size until they can be selectively separated and discharged from the bed into water-filled ash hoppers, from which they are withdrawn as a slurry. In this manner, the fluidized bed achieves the same low level of carbon losses in the discharge ash that is generally associated with ash-slagging gasifiers. Coal fines elutriated from the fluidized bed are collected in two external cyclones. Fines from the first cyclone are returned to the bed, and fines from the second cyclone are returned to the ash-agglomerating zone, where they are gasified and the ash is agglomerated with bed ash. The raw product gas is virtually free of tar and oils, thus simplifying the ensuing heat recovery and purification steps.


Crushed coal feed


G a s ifle r

gas " .° • • . . ' .

Feed lockhoppe~


• . ..

Secondstage cyclone


h : .°.. %


orStearn/°xygen~-air v Venturi

Stearn/o~ or air


_ Classifier

- - ~

Ash a ~ l o r n e r ate s ~




hb.' - '.:7-'-"

A s h agglomerates slurry



Schematic diagram of the U-GAS fluidized-bed gasifier.

Gasificatiou for Electricity Generation

Table 3.3-6.


U-GAS process characteristics.

High conversion of coal to gas using an ash-agglomerating technique; capability to gasify all ranks of coal; ability to accept fines in the coal feed; simple design,

safe and reliable operation;

easy to control, ability to withstand upsets; product gas virtually free of tar and oils; no environmental problems; operation at lower temperature than are used with slagging gasifiers; large turndown capability; large unit capacity.


Pilot-Plant Description

Most of the U-GAS process development work has been accomplished on a pilot plant put into operation in 1974. A chronological listing of pilot-plant development is given in Table 3.3-7. The development program has been funded by the US DoE and the American Gas Association. The pilot plant is located at IGT's test facilities in southwest Chicago. It consists of a gasifier and all required peripheral equipment with utilities and other support services. Most of the equipment is contained in an enclosed structure that is about i00 ft high. The pilot plant consists of a drying and screening system, feed-storage silos, a lockhopper system for feeding coal at rates up to 3000 Ib/hr, a refractory-lined fluidized-hed reactor with a special agglomerate withdrawal system in its base, a product gas quench system, a cyclone system for removal and recycle of elutriated fines, a product-gas scrubber, a product-gas incinerator, and a lockhopper ash-removal system. The pilot plant flow diagram is shown in Fig. 3.3-4. The gasifier is a mild-steel, refractory-lined vessel with an inside diameter of 3 ft and a height of about 30 ft. The pilot plant is thoroughly instrumented to provide necessary operating information and data for the calculation of accurate mass and energy balances. A computer system for automatic data acquisition provides on-line process flows, balances, critical variable trend plots, and operating data summaries at regular intervals. The pilot plant contains special sampling systems for complete characterization of the raw product gas, water effluents, and coal fines necessary for design of gas-purification and wastewater systems.

Table 3.3-7.

Date(s) 1974

Test history of the U-GAS pilot plant.

Number of Tests 9

Function Equipment shakedown


Process-feasibility studies



Testing of highly-reactlve small-size feed



Shakedown of the modified pilot plant



Testing of highly-reactive feedstock



First bituminous coal tests



Testing of unwashed high-ash feedstock




Demonstration/commercial design data



Testing of highly-caking feedstock


Coal-verification test with different feedstocks for different clients


Coal-verification tests with ROM French coal


Coal-verification tests with ROM Utah Coal (air and enriched-air gasification)


Energy, The InternatlonalJournal





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G a s i f i c a t i o n for E l e c t r i c i t y G e n e r a t i o n



Process Development

Over the last 7 years, IGT has conducted an extensive, multldlscipllnary program to develop important aspects of the U-GAS technology and to obtain information for the design of a commercial plant. The program has included the following steps: (1). Operation of the U-GAS pilot plant to demonstrate process feasibility, including ash agglomeration and fines recycle. The pilot plant has also yielded data on the process, mechanical and operational design of a commercial plant. A detailed mechanical design of the gasifler has been on-golng while the pilot plant has been operational. This procedure has been of great benefit in identifying design data gaps that could be obtained from the operating pilot plant. (il). Scale-up studies on large, cold-flow models. The basic concerns in scaling up from a pilot plant to commercial scale are centered around the grid and venturi region of the gasifier. A semi-clrcular cold-flow model and a pressurized cold-flow model have been operated to understand the hydrodynamics of the grid/venturi region, determine the mechanical configuration of the scaled-up grid-venturi, and select the dimensions of the venturl to discharge the necessary quantity of ash agglomerates. An X-ray clnestudyhas been conducted to examine visually solids circulation, jet penetration, and bubble dynamics in the grid/venturi zones of different mechanical configurations. Numerical simulation and engineering calculations have been carried out to compare the thermal and hydrodynamic similarities between the pilot and commercial plants and to select appropriate design parameters. (ill). Ash-chemistry studies and bench-scale experiments. Extensive ash-chemistry studies have been conducted to understand and develop mechanistic models of ash agglomeration and ash adhesion. Bench-scale experiments have been carried out to determine the main operating variables affecting the formation of ash agglomerates. Steam-oxygen gasification and hlgh-pressure fluidizatlon knowledge and skills have been developed in various other coalgasification projects at IGT dating back to 1950. A computer model of the U-GAS gasification system has also been developed to predict the performance of the gasifier at different operating conditions and with different coals. (iv). Environmental characterization of the process. During the pilot-plant operation, extensive sampling and analysis have been conducted to obtain information for complete environmental characterization of the process. The raw product-gas samples have been collected in a specially developed sampling train to trap all impurities present in the gas. These analyses have yielded the needed data for design of the downstream gas-purlficatlon equipment. The water-discharge stream for the venturi-scrubber system has been analyzed for information on design of wastewater-treatment facilities. All solid streams entering and leaving the gasifler have been analyzed for trace metals to obtain a material balance and determine the fate of trace metals present in the coal feed. Ash agglomerates and other solid discharges have undergone leaching tests to assess compliance with regulations. No environmental problem has been encountered in the design of the commercial plant, as evidenced by approval of the Environmental Impact Statement by all US, state,i and local regulatory agencies. Based on successful development of all aspects of the U-GAS technology, the process is ready for commercialization. Independent evaluations by several large engineering and petroleum companies support this conclusion. 3.3-3E.

Pilot-Plant Operations

The U-GAS pilot plant has been the primary unit in which the process development has been conducted. A total of I0,000 hrs of operating time has been logged in the pilot plant, during which period over 120 tests have been conducted with about 3500 tons of various coals. Several test runs have lasted over 2 weeks, thereby providing long, steady-state operating periods with excellent mass and energy-balance closures. The pilot-plant development has been carried out in a multiphased program starting in 1974. As is typical in pilot-plant developments, both mechanical and process problems were encountered. One by one, solutions were found for each of these. By the end of the development program, all important aspects of the process (raw coal feed, stable ash agglomeration, and fines recycle) were both routinely and repeatedly achieved in several tests. A detailed description of the pilot-plant development is given in IGT reports. In phase I, process feasibility was demonstrated using metallurgical coke and char as feed. For phase II, the pilot plant was modified to feed coals, and trial tests were made with subbituminous and bituminous coals. During phase III, process feasibility was proved using hlgh-sulfur-content, caking, bituminous coal as feed and data were developed for scale-up and design of a commercial plant. In phase IV, environmental data were collected and the reactor dynamic response was investigated. The major achievements in the pilot plant have been as follows: (i) Process feasibility has been verified in a series of tests of extended duration. (ll) The application of the technique of ash agglomeration and fines recycle has been perfected, and an overall coal-utillzatlon efficiency of over 98% has been achieved. (Ill) The process has been shown to have a wide operating window, thus providing flexibility to gasify a wide variety of feedstocks. (iv) The tests have produced a strong data base for scale-up and design of the first commercial plant. (v) Data related to environmental aspects of the process, particularly raw gas and wastewater characteristics, have been obtained. These data show that there are virtually no tars or oils produced in the process. (vi) Commercially available refractories and metallurgical products have performed quite satisfactorily in the gasifler. Mechanical information has been obtained for designing gaslfier internals, critical hardware, valves, cyclones, etc., which are important for reliable operation.




The I n t e r n a t i o n a l 5 o u r n a l


A wide variety of feedstocks have been used in the pilot plant to determine process sensitivity to variables such as ash content, ash properties, particle size, reactivity, free swelling index, and volatile matter. Eight types of different coals and three types of chars have been tested in the pilot plant (cf. Table 3.3-8). The feedstocks for testing have been selected to cover a wide range of important coal properties that could have significant effects on gasification and ash agglomeration. The range of feedstock properties is shown in Table 3.3-9. All feedstocks except chars are 1/4 inch x 0 in size and are fed to the gasifler without any removal of fines. The coals are also directly fed into the gasifler fluidlzed bed without any pretreatment, regardless of their caking tendencies (free swelling index). Also, for western Kentucky coals, both washed and unwashed coals have been successfully tested to determine the effects of the large quantity of clay and shale that is present in unwashed, underground-mined coals. Lignltes have not been tested in the pilot plant because of funding limitations, but the Wyoming subbituminous coal has reactivity, moisture, and volatile matter content very similar to lignites. Therefore, lignites should not pose any problems in the U-GAS process. Specifically, ash properties are more significant in the U-GAS process than coal reactivity, and the range of coals tested in the pilot plant covers almost all lignite-ash compositions. 3.3-3G.

Utah Bituminous Coal Test

A test was carried out with Utah bituminous coal in the U-GAS pilot plant. ANR was interested in evaluating the performance of the U-GAS process to produce low-Btu gas and to provide data for the design of a commercial plant. The test called for 7 days of operation at 5 different set-points.

Table 3.3-8.

U-GAS gasifier feedstocks.

Western Kentucky No. 9 bituminous coal (both washed and unwashed) Western Kentucky No. ii bituminous coal Illinois No. 6 bituminous coal Pittsburgh No. 8 bituminous coal Australian bituminous coal Polish bituminous coal French bituminous (unwashed) Utah bituminous (unwashed)



Montana subbituminous coal Wyoming subbituminous coal Metallurgical coke Western Kentucky coal char Illinois No. 6 coal char

Table 3.3-9.

Range of U-GAS gasifier feedstock properties.



Moisture, %

i to 32 t

Volatile Hatter, %

3 to 43~

Ash, %

6 to 35~

Sulfur, %

0.5 to 4.6~

Free Swelling Index


Ash-Softening Temperature,

°F °C

Gross Heating Value, Btu/Ib kJ/kg

~As received; Idry basis.

1980 to 2490 1080 to 1370 7,580 to 12,650 t 17,631 to 29,424

G a s i f i c a t i o n for E l e c t r i c i t y G e n e r a t i o n


The test was successful in achieving all of ANR's predetermined test objectives. These objectives were: (i) to prove the feasibility of producing low-Btu gas by gasifying the coal with air and steam, (ii) to ~aximize coal- conversion efficiency, (iii) to gasify coal with enriched air, (iv) to investiga£e gasifier turndown, (v) to test gas desulfurization using limestone, (vi) to evaluate a high-temperature coal-dust filter, (vii) to test combustion characteristics of the low-Btu product gas, and (viii) to obtain data for the design of a commercial plant. The pilot plant was operated for 6 days during which time 58 tons of Utah coal were gasified. Steady-state, ash-balanced operations were maintained for 6 different set-point operating conditions. The coal-conversion efficiency was 93 to 99% during the various setpoints of operating conditions. The test was voluntarily terminated when all of the test objectives were completed. A summary o f the pilot plant test results from one of the setpoints is shown in Fig. 3,3-5. Gasification was carried out with air and steam and enriched air (34% oxygen) and steam. The heating vaue of the low-Btu product gas was varied from 75 to 171 Btu/SCF. The heating value of the low-Btu gas was lower than is expected in a commercial plant because of (i) high heat losses relative to the reactor coal feed capacity and (ii) excessive cooling of recycled fines in the primary water-jacketed cyclone. During one of t h e set points, the capability of the gasifier f o r turndown was demonstrated by reducing the gas-production rate by half. The ability of banking the gasifier was demonstrated also during some mechanical failures encountered during the test. For example, the coal-feed system was shut down for almost i0 hours to repair the variable speed feed mechanism. During this period, the gasifier was maintained in a hot, standby position and restarted without any problems after repairs were completed. During typical plant upsets, the gaslfier w a s made to respond in a controlled and logical fashion, without major interruptions in gas production~ The test demonstrated total fines recycle, which is necessary to achieve high coalconversion efficiency. The fines from the primary cyclone were recycled during all six setpoints and the fines from the secondary cyclone were recycled during five of the six setpoints. Secondary fines recycle was achieved under smooth and controlled conditions and was shown to be easily initiated and controlled. Any intermittent interruptions in therecycle of the secondary fines did not cause operating upsets or reduction in gas production. As part of the overall program, three special tests were conducted that were aimed at improving the performance and economics of commercial low-Btu gas plants. In one of these, limestone was injected into the fluidized bed along with coal to test the capture of sulfur compounds generated during coal gasification. The addition of limestone did not have adverse effects in the gasifier, ash discharge, or fines recycle. Data indicated that a large portion of the spent limestone exited the gasifier as CaSO 4 rather than CaS. The former is the preferred by-product because of its stability in an atmospheric environment. The degree of sulfur reduction in the product gas could not be precisely determined because of difficulty in measuring relatively low concentrations of sulfur compounds (the coal contained only 0.6 wt% of sulfur).

C o a l 1343 Ib C ~ 1141 Ib Ash 141 lh Moisture 61 Ib


24 lb

C~ Ash

17 lb 7 lb


U =G A S 1845 °F 55 psi


Steam & air

175 lb

C ~' 29 lb A s h 146 lb



Results of the test conducted with Utah coal in the U-GAS pilot plant; coal conversion - 96.0%; C* represents MAF-coal.

E n e r g y , The I n t e r n a t i o n a l J o u r n a l


In another special test, we evaluated the high-temperature coal-fines fiiter. If coal fines could he removed from the iow-Btu product gas at high temperatures (I000 ° to 1500°F), then product gas could be utilized directly, thus simplifying the commercial plant design and improving efficiency and economics. A hot ceramic candle filter was installed in the pilot plant on a slipstream after the primary cyclone. The filter operated during the test in a completely automatic mode throughout the six-day test and removed all of the dust from the hot product gas. There was no blinding of the filter medium Or any continuous increase in pressure drop or cycle time of the filter system. The measurement of dust in the filtered gas was conducted using a photometric particle counter. The results of the measurement at one of the set points is shown in Fig. 3.3-6. The combustion characteristics of the iow-Btu product gas resulting from operations at three of the set-points were evaluated in a specially-installed burner and furnace. Stable combustion was achieved with gases from all set-points. The SO 2 and NO x emissions were measured during the combustion tests; in addition, both thermal and fuel NO x formations were determined. A complete environmental characterization of the iow-Btu product gas was made by using a specially designed sampling loop. These results indicate that the gas does not contain any significant quantity of tar and oils and both the gas-purification and waste-water treatments in a U-GAS plant could be handled by conventional technologies. 3.3-3H,

Pilot-Plant Tests with a French Coal

A French Merlebaeh coal was successfully gasified in the U-GAS pilot plant during tests conducted for CdF. Two tests were conducted: The first test provided useful information on operational characteristics of the coal. The second test yielded a long steady-state operating period in which all of CdF's test objectives were achieved. These objectives were: (i) demonstration of the operability of the U-GAS process with high-ash French coal, (ii) maximization of coal-conversion efficiency, (iii) production of good-quality product gas, and (iv) data for the design of a demonstration plant. In the second test, the plant was operated continuously for 92 hrs, when 48 tons of coal were gasified during 60 hrs of steady-state operation. Ash-agglomerating and ash-balanced operations were maintain%d during three different operating conditions. These involved (i) testing without recycle of fines from the secondary cyclone, (ii) testing with total recycle of fines, and (lii) testing with a lower steam-to-coal ratio. A coal-conversion efficiency higher than 95% was continuously maintained during the last two tests.



0 I0


to ._J






Limit 1

15.0 Lower 0 I










Time, rain Fig.


Dust loading in the filter exit gas for one of the set points.

G a s i f i c a t i o n for E l e c t r i c i t y G e n e r a t i o n


The gasifier was used to handle coals with ash contents from 20 to 35 wt%. In addition, because the coal was unwashed, it contained a large quantity of shale, which was also handled by the gasifier without any detrimental operational effects. Once steady-state operation was achieved and ash agglomeration established, 96% of the ash discharged was withdrawn through the bottom venturl; the remaining 4% of ash was withdrawn through the overhead along with the fines. No ash buildup occurred in the fluldized bed, despite the uneven ash-feed rate to the gasifier. The quality of the product gas in the U-GAS process is strongly influenced by the characteristics of the feed coal. Despite the combination of a high ash and a low volatile matter content in the Merlebach coal, the U-GAS pilot plant yielded a good-quality product gas with an HHV of about 215 Btu/SCF (8600 kJ/m3). The pilot plant has relatively high heat losses compared to its coal-feed capacity. In addition, excessive cooling of the recycled fines occurs, both in the primary water-jacketed cyclone and the flrst-stage quench. Our estimate is that a commercial gasifier with appropriately designed cyclones and experiencing lower heat loss per unit volume of product gas will produce a gas with a heating value from 250 to 270 Btu/SCF (i0,000 to 10,800 kJ/m3). During the last set-point in the Merlebaeh coal test, it was demonstrated that the heating value of the product gas could be significantly improved by appropriate optimization of operating parameters. When generating synthesis gas from coal to produce chemicals, a more critical number than gas-heating value is the combined yield of H 2 and CO; any CH 4 in the product gas is considered to be by-product. In the U-GAS pilot-plant test, the yield of H2+CO was up to 20 SCF/Ib (1.25 m3/kg) of MAF coal. During the test (see Fig. 3.3-7), we demonstrated with the U-GAS process the ability for a total recycle of fines that is necessary to achieve high coal-conversion efficiency. The fines from the primary cyclone were recycled during all three set points, while the fines from the secondary cyclone were recycled during the latter two set points only. Secondary fines recycle was shown to be easily initiated and controlled. The testing also demonstrated that occasional minor interruptions in the recycle of the secondary fines did not reduce gas production or cause operating upsets. In fact, the automatic oxygen/temperature controller employed in the U-GAS process promptly responded to these interruptions and maintained the gasifier under stable operating conditions. Recycle of fines was maintained for more than 34 hrs and conclusively demonstrated that the fines could be gasified to extinction while the resultant fine ash was agglomerated and discharged along with the bed ash through the venturi, without any buildup of fines or ash in the gasifier system. The pilot-plant test showed that the ash of the Merlebach coal could he readily agglomerated in the U-GAS process. This was demonstrated by classification and withdrawal of only high ash-content material through the venturi. 3.3-4.

Other Gasifiers

A comprehensive review of selected gasification systems and associated coals has been prepared for EFRI by Synthetic Fuels Associates. 6 We refer to this study and references cited therein for descriptions of the Lurgl Dry Ash, BGC/Lurgi, KilnGas, and other gasifiers. Descriptions of a number of currently active gasification technologies will he found in Chapter 4. i




Fines 33 Ib

C* 17 lb A s h 16 Ib

Coal 139Z Ib

C* Ash Moistuze

943 Ib 422 ib ~7 ib


U-GAS 1850°F 30 psi

Steam & oxygen

A s h 407 lb C$ Z7 lb A s h 380 lb Fig.

EGY 12:8/9-D


Results of the test conducted with French coal in the U-GAS pilot plant; coal conversion - 95.3%; C* represents MAF-coal.



T h e International 5 o u r n a l

References for Section 3.3 i. 2. 3. 4. 5. 6.

"Texaco Coal Gasification Process," Texaco Development Corporation, Montebello, CA (1986). W. G. Schlinger and G. N. Richter, Hydrocarbon Processing 59, 66 (1980). W. G. Schlinger, J. H. Kolaian, M. E. Quintana, and T. G. Dorawala, Energy Progress 5, 234 (1985). W. L. Heitz and M. Nager, "Status of the Shell Coal Gasification Process (SCGP)," Fifth Annual EPRI Contractors' Conference, Palo Alto, CA (October 30-31 1985). Electric Power Research Institute, "Evaluation of US Coal Performance in the Shell Coal Gasification Process (SCGP)," Report No. EPRI AP-2844, Palo Alto, CA (1984). Electric Power Research Institute, "Coal Gasification Systems: A Guide to Status, Applications, and Economics," Report No. EPRI AP-3109, Palo Alto, CA (1983).


Research Recommendations for Improving Gasifiers$

Primary motivations for supporting research are the needs for cost reduction and operating-life extensions of gasifiers. There are two important identified research areas, the pursuit of which may lead to improved performance in the SCGP and TCGP. These are reduction or elimination of fouling I and elimination of failure caused by high-temperature corrosion fatigue. 2 3.4-1.

FoullnR and Sla~gin~

According to the authors of Ref. i, research on slagging is expected to lead to improved methods for predicting fouling in practical systems. At present, the methods used are largely empirical and based on static models, which do not correspond to actually existing conditions in combustors or gasifiers where many different sizes of pulverized coals are utilized. An improved ASME procedure is required to define slagging conditions for coals since the ash-fusion temperature has been shown to be an inadequate measure for slagging. The authors of Ref. i suggest the use of bench-scale experiments, with special emphasis on innovative approaches. Research should include the following types of studies. (i) Predictions of the slag viscosity, especially under gasifier conditions. Slag viscosity is of critical importance in assurlng that the slag is removed continuously from the gasification chamber. This problem is complicated by the fact that slags appear in homogeneous and multi-phase systems. (ii) Phase diagrams incorporating new and existing empirical data, especially for binary, ternary and higher-order mixtures. To use the results properly, the equilibrium behavior of ash must be determined. This approach will also lead to improved understanding of wall- and tube-deposlt formations. (iii) Many modern dynamic experiments are performed with large variations in conditions. Data from different experiments may be difficult to compare. Applications to practical systems present even greater challenges. Since experiments may he performed that represent reasonable simulations of actual combustion conditions, standardization of experimental test procedures would be desirable. (iv) The use of improved diagnostic techniques is recommended to verify or improve fundamental understanding of gasification rates and mechanisms and the best available modeling procedures. (v) Static experiments on bulk samples are attractive because of their relatively low costs and simplicity. If possible, static experiments should be devised that provide useful information on fouling and slagging. 3.4-2.

Corrosion and FatiKue

Three research areas are suggested in Ref. 2: (i) Measurements of high-temperature, corrosion-fatlgue data for alloys of commercial interest under accurately controlled and welldefined conditions. (ii) Information on the kinetics and mechanisms of corrosion-fatigue damage formation. (iii) An augmented model incorporating the results obtained under (i) and (ll) into design calculations. There has been special emphasis on the reducing conditions found in coal gasifiers, but other environments could be usefull X employed to obtain data over wider ranges of conditions. Interesting temperature ranges lie 2 between 350 and 700°C, while pressures fall in the 20-60 arm range. New studies should be performed on the effects of cyclic loadings (50 to 5000 cycles) to identify the influence of cycling on failure rates. 3.4-3.

Hi~h-TemDerature Sulfur Removal

Application of a high-temperature sulfur-removal process will significantly improve the efficiency of an IGCC system and a DoE-supported program in this area is therefore recommended.

SWe are indebted for helpful comments to M. Nager and W. Schlinger in the preparation of this section.

G a s i f i c a t i o n for E l e c t r i c i t y G e n e r a t i o n



Gasifiers for Low-Rank Coals

Gasifiers for IGCC (cf. Sec. 3.3) have been extended to low-rank coals. EPRI has made a preliminary evaluation of this proposal for the Texaco gasifier using C02-1ignite slurries as gasifier feed. The Shell, Dow and other gasifiers have also been demonstrated to be applicable to low rank coals. 3.4-5.

Low-Cost Gas S~paration and Air Enrichment

The Shell and Texaco gasifiers, as well as other gasification systems, will benefit from lower costs if improved gas-separatlons with air-enrichment systems are developed. This important topic is addressed in Chapter 13.

References for Section 3.4 I.


"Recommendations for Research Leading to New Bench-Scale Experiments for the Prediction of Slagging and Fouling Behavior," ASME Research Committee on Corrosion and Deposits from Combustion Gases (March 18, 1985). W. T. Bakker, "Suggestions for Direction - Low Cycle Fatigue Program," Report of the Second Meeting of COGARN, pp. 212-215 (February 25, 1986), unpublished.