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An evaluation of in situ coal gasification
Energy,
Vol.I. pp.71-94.
Pergamon Press 1976.
Printed in Great
AN EVALUATION
Britain
OF IN SITU COAL GASIFICATIONi
J. C. FAIR, 0.
A. LARSON and
H. H. HASIBA
Gulf Research&Development Company, Pittsburgh,PA 15230,U.S.A. (Received 11November
1975)
Abstract-The in situ conversion of coal to other energy forms such as gas or liquids is receiving increased attention as the framework of a national energy R & D program is becoming more clearly defined. Efforts to gasify coal underground date back to the middle of the 19th century, with a significant increase in activities occurring between 1945and 1%5, mostly in Russia, England and the U.S.A., with active projects reported to be underway in Russia at present. Recent tests in the U.S.A. have been reported by the Gulf Research & Development Company, which conducted a brief test in Kentucky in 1%8, and by the ERDA Laramie Energy Research Center (LERC), which has been conducting pilot tests near Hamta, Wyoming, since 1972.Also active in this field are workers at the Lawrence Livermore Laboratory (LLL) of the University of California, and the Morgantown Energy Research Center of ERDA. A group of utilities in Texas has recently made contractual agreements to acquire Russian in situ gasification technology. Renewed interest in this area has also been expressed in Canada, England and Belgium. While economic analyses related to various surface-gasification schemes have recently proliferated, few economic studies have been reported for in sifu schemes. In this paper, we consider the orientation economics and some market aspects relative to a commercial extrapolation of the Gulf Research & Development Company thin-seam in situ gasification scheme. Our analysis is aimed at the determination of produced gas cost for a commercial application of the forward gasification of coal from vertical boreholes using pneumatic pressure linking. It is assumed that the produced gas composition will be similar to that of a surface Lurgi gasifier using the same coal. Recent results from the second group of Hanna field experiments by LERC have shown that Lurgi results can be obtained by an underground gasifier using vertical boreholes linked by backward burning. Gas costs are calculated as a function of production system variables such as well spacing, seam thickness, depth of cover, conversion sweep efficiency, product gas loss, and injection oxidant loss. Other variables involved in the analysis are associated with end-use considerations. Gas produced from an oxygen-consuming process may be upgraded to pipeline quality by methanation or to a medium heating-value by CO, and H,S extraction, while air-produced gas can only be slightly upgraded by this latter process and remains a relatively low-heating-value gas. A market analysis is then made on the basis of end-use options for the potentially evolving gas supply. Limitations concerning the transportation and consumption of each type of product are explored. The major competing energy sources within the energy market are examined for each of the gas product alternatives. Several research and development implications are discussed.
1. INTRODUCTION
Recent energy economics, declining domestic oil and gas production, and interest in exploiting huge domestic coal reserves have resulted in a new lease on life for the concept of underground coal gasification. This idea has been around for more than 100 years and has been the subject of numerous experiments of varying quality and value. Stated very simply, underground gasification of coal involves the conversion of energy present in the solid coal into a combustible gas without mining the coal. As with any process conducted underground, one must deal in some way with the geological and hydrological features of the earth’s crust and the prevailing force of gravity while maintaining severely restricted contact with and control over the ongoing process. Benefits claimed for in situ gasification range from humanitarian through ecological and economic. It is not the purpose of this paper to restate the pros and cons of the concept, which are already the subject of many good reviews (see, e.g. Refs [ 1 and 21).Nor do we wish to present another review of past history. However, a brief outline of current activities is required to establish the relevance of this study. Workers at ERDA-LERC are conducting a very encouraging series of field tests near Hanna, Wyoming. These tests were initiated in 1972. ERDA is also sponsoring other investigations into underground coal gasification at the Morgantown Energy Research Center (MERC) and at LLL. Laboratory tests and mathematical model studies are being conducted at the Universities of Texas, New Mexico, Kentucky, Wyoming, West Virginia and at the Pennsylvania State tThis paper was presented at the American Nuclear Society Winter Meeting, 16-21Nov. 1975,San Francisco, California. 77
78
J. C. FAIR et al.
University. Texas Utilities Services Co. is planning a pilot demonstration using technology based on many years of experimentation and plant operation within the USSR. Governmental agencies in Belgium and a province of Canada are planning tests and the National Coal Board in England is re-assessing in situ coal conversion. The major differences in these programs involve the resource target and linking techniques to be applied. The Laramie and LLL programs, for example, are directed at deposits of subbituminous coal and lignite found in the Western states; Texas Utilities Services Co. is interested in developing Texas lignites; and the Morgantown program is aimed at Eastern bituminous coals. Linking is the term applied to establishing and maintaining a flow path through the coal between the points of injection and production. Each linking technique attempts to solve problems of low natural permeability, liquid plugging, coal swelling, and bypassing of coal by the reaction front. Backwards burning is used at Laramie, explosive fracturing at LLL and directional drilling at Morgantown. Electrolinking and hydraulic fracturing have also been proposed. Yet another technique, high pressure pneumatically-induced fracturing, was used by Gulf Research & Development Company (GR&DC). Workers at GR&DC began investigating in situ processing of coal for energy recovery during the early l%Os. Laboratory experimental work in the production of liquid and gaseous products from coal preceded a field test conducted at the Pittsburg and Midway Coal Company Colonial Mine in Kentucky in 1%8. Results of the field test have been published recently[3]. The test achieved the major objective of verifying that oil-field technology could be applied to the recovery of useful products from coal by in situ combustion. Interest in underground coal gasification at GR&DC has increased in recent years after nearly 6 years of only minor activity. In-house evaluation of ongoing work included a recent joint study with LLL on their deep, thick coal-seam gasification concept.4 These recent efforts led to a recognition of a shortcoming in the literature on underground coal gasification. Economic studies of surface gasification plants have proliferated. Market assessments have been somewhat less abundant; indeed, most authors have assumed a market would exist for their product. Economic and/or market evaluations are both process and site specific. Details of process costs, coal characteristics, product variation and market location will require that a number of such studies be performed and reported. 2. OBJECTIVES
OF THE
STUDY
Results of an economic and marketing study of one possible method of gasifying coal underground, namely, that of thin seam conversion using pneumatic linking, are presented in this report.? The objectives of this orientation economics and marketing study are the following: (a) Determine the cost of various product options from the in situ process using reasonable estimates where factual information does not exist. (b) Determine the sensitivity of product cost to variations in system parameters over a reasonable range. Analyze the information from this parameter study to identify important parameters and important ranges of these parameters. (c) Maintain the link between these results and reality. Assumptions which are required to perform such a study at this early stage should always be kept in mind when evaluating the results and formulating conclusions. (d) Compare cost estimates from this study with competing fuels in the energy market. All costs accruing to the use of each energy source must be considered to evaluate the market potential for the final product. (e) Apply the results of the study to aid in directing similar analyses of other in situ process concepts, to point out questions which need to be answered in future R & D work, and to characterize the role underground gasification might play in filling the energy needs of the country. 3. ASSUMPTIONS
AND PROCEDURES
Major assumptions
Bituminous coals require special consideration in the choice of linking technique because their high volatile matter content leads to potential liquid plugging problems and their tendency to tThe views are those of the authors and do not necessarily
represent those of Gulf Oil Corporation.
79
An evaluation of in situ coal gasification
swell on heating can reduce flow permeability. However, potential marketing advantages exist because of the proximity of suitable deposits to industrial and population centers. The GR & DC underground coal conversion test was conducted in a relatively thin (3 m) seam of moderately swelling (free swelling index = 3.5) bituminous coal by using high injection pressures (about 29.4 kPa/m of overburden or 1.3 psi/ft) to maintain a flow path between injection and production wells. Our familiarity with the pneumatic linking technique, as applied to thin seams, led to the choice of such a system for this initial analysis. We present this linking technique as one alternative of many and do not attempt to compare underground gasification concepts. The coals of the Illinois basin were chosen for this study, both on the basis of similarity to the coal encountered in the Kentucky test and on the basis of major industrial energy demands nearby. Relative location of the Illinois coals to other U.S. coal deposits is shown in Fig. 1.
-
ANTHRACITE & SEMIANTHRACITE
‘\
Rsi
LOW-VOLATILE BITUMINOUS
@I
MEDIUM &HIGH-VOLATILE BITUMINOUS COAL
eza
SUBBITUMINOUS
m
LIGNITE
\I-
COAL
COAL
‘-1
0 Li
8.
200 I
400
600
y
MILES
Fig. 1. Coal fields of the conterminous United States
The underground process postulated for this paper has been extrapolated from the Gulf Colonial Mine Field Test of underground coal conversion. This test was limited to dry combustion with the heat of combustion used for in-place retorting. However, we assume in this paper that gasification could be achieved from the same test configuration if water or steam were injected. Performance of the underground gasifier is a major unknown. Although we have, for the sake of this study, put aside questions regarding subsidence, liquid plugging and other mechanical aspects of the process, we needed to determine injection parameters, such as oxygen required per unit mass of coal and water to oxygen ratio. Furthermore, given these parameters, how much gas would be produced for a unit mass of coal and what would be the composition of this gas? These are basic questions affecting the amount of coal resource required, oxidant capacity, and design and cost of the purification and/or methanation facilities. It was decided that data from the Lurgi gasifier tests in Westfield, Scotland, should be used. The Westfield data are from a systematic, well documented test that included both Illinois Nos. 5 and 6 coals, the seams of greatest importance in the Illinois basin. Reports from ERDA’s underground gasification experiments at Hanna, Wyoming, have indicated that, for their test conditions, underground gasification results have been “similar” to those reported for a Lurgi gasifier.’ Despite many differences in operating conditions, it was felt that the Lurgi data were, at least, indicative of the reactivity of the coal of interest. Lurgi data reported by Elgin and Perks6 are shown in Table 1. One major difference between the conditions under which their data were taken and the postulated operating conditions for the EGY Vol. I, No. I-F
80
J. C. FAIRet al. Table 1. Data from gasification of Illinois No. 6 coal in a Lurgi gasifier ___._._-___... .-... .- . -....-. ..---.----.-.------
Product
Gas Calorific
Value
in situ gasification scheme is the state of injected water. The Lurgi gasifier requires steam injection, whereas we have assumed that liquid water injection is possible in underground gasification. Steam injection in the underground process is a subject for further study. Although the Hanna test utilizes nearly ideal conditions of natural ground-water flow to provide required water, we do not feel this fully justifies our use of liquid water injection. We are not certain, at this point, that the Hanna results could be obtained if the same water volumes came into the system from the wellbore. A surface gasifier unit of the type used in Westfield tests is constrained to operate at a temperature below the ash fusion point of the coal. Temperature control is maintained by injecting excess steam. Steam requirements for Eastern bituminous coals tested were particularly high due to their relatively low ash fusion point. Since slag removal is not a problem in the in situ gasification process, higher gasification temperatures requiring less steam or water could be tolerated. Nevertheless, we have retained the reported water requirements from Westfield for our study. Water costs are a very small part of the overall cost of gas production. Commercial
system
The conceptual commercial system employs a line drive configuration consisting of a number of five-spot patterns, as shown in Figs. 2(A-C). Choice of this configuration is based on the initial test experience and conventional oilfield practice. Fluid produced from this array of wells is conducted to a transportable field production station. Here the gas is cooled, coal liquids and liquid water are separated, and the produced gas is compressed for transmission to the gas treatment plant. The production station is located near the active pattern to reduce gathering line pressure drop. The gas treatment facility, however, is located at a fixed site outside the active area for protection against surface subsidence. Also located at the gas plant site are the oxygen plant or air compressors and water supply system. Delivery lines run to the active site where distribution lines connect to each injection well. Figure 3 shows a schematic diagram of this piping system. As the coal within each line drive pattern is consumed, an adjacent pattern, which has been previously prepared, is gradually brought on stream to provide a continuous flow of product gas. Manifold piping for two patterns must therefore be provided. Each succeeding line drive is connected to the main lines prior to ignition, using the piping from the burned-out pattern. At
81
An evaluation of in situ coal gasification A
FIVE-SPOT
PATTERN
Y4
0
Production
‘cl
c
LINE
DRIVE
GASIFIER
well
0
InJectIon
\
well
0
\
0
“\#4 B
ELEVATION
A-A
Gas,fmt,on Products
Overburden
Production
Fig. 2. Gas-production
I
Rows
configuration.
I
Fig. 3. Plan view of surface facilities.
periodic intervals, the field production station is moved as the advancing active zone approaches. Sufficient excess equipment capacity reduces the effect of this move on continuous gas production capability. Physical plant The system is comprised of three distinct operational divisions: the production facilities, the gas treatment plant, and the injection facilities. Gas production operations involve injection and production wells, all piping between production facilities and the central plant, gas coolers, field seperators for gas and liquid separation and gas clean-up, and compressors required for transmission of produced gas to central treatment facilities. Pipe diameter and wall thickness are selected according to flow rate, fluid pressure and pressure drop requirements. Lines required include oxidant main and manifold, water main and manifold, product gathering manifold, product gas transmission line, tar and oil transport line and a line for the desulfurized fuel gas supply. All piping is assumed to be carbon steel, except for oxygen lines which must be stainless steel. Injection and production wells are assumed to be cased and cemented through the coal. The production well casing I.D. is a function of gas flow rate and a specified pressure drop criterion.
82
J. C. FAIR et al.
Separators, oil dehydrators, gas coolers, liquid storage facilities and compressors are sized according to assumed or calculated conditions using accepted formulae. Compressor interstage temperature is limited to 150°C.Flexibility for continuous operation is provided by requiring 25% production equipment standby capacity. The central gas treatment plant design varies according to end product requirements. A gas produced with oxygen may be upgraded by acid gas (HZl + COZ) removal to provide mediumheat-value gas for fuel or synthesis feedstock (we will call this synthesis gas) or it may be converted into synthetic pipeline gas (SPG) by shift conversion, purification, and then methanation to a pipeline quality of 35.2 MJ/m3 (945 Btu/SCF). A gas produced from air injection has a low heat value but would be suitable for nearby consumption as a fuel once sulfur compounds are removed. We will call this product producer gas. The hot potassium carbonate process, as described by McCrea and Field,’ is used in both synthesis gas and producer gas purification plants. Process parameters are adjusted to remove nearly all CO2 in the case of the synthesis gas, but only about 25% of the COZwith more selective H&Sabsorption in the producer gas case. If COZcan be tolerated in the end product, savings are realized both in plant capital and energy requirements. A Claus sulfur plant is used to convert the H,S in the concentrated acid gas stream to elemental sulfur for byproduct sales. A portion of the produced gas is split off for use as plant fuel. Selective H,S and partial CO2 removal is used to desulfurize the fuel gas. This fuel is used in gas turbines and boilers to provide gas compression at the field production station, regeneration steam for the gas purification process, shift conversion steam, power for the sulfur plant, oxidant at the required injection pressure, and final compression of the product gas to the required delivery pressure. Thus, the major energy requirements of the system come from internally generated gas. Only a small amount of energy is purchased as commercial electric power. The oxygen plant requirement is calculated with a maximum single train size of 0.66 Mtla (2000 tons/day). Air compression is by gas turbine powered compressors of approximately 7500 kW (10,000 HP) capacity. In either case, the plant fuel is desulfurized product gas. Capital cost, as well as operating cost, varies with the required injection pressure. This, in turn is a function of the assumed pressure gradient required to maintain gas flow underground, depth of cover and pressure drop in the surface piping. Cost analysis
Details of the costs used in this analysis are included in Appendix I. All costs are indexed to early 1975. Every effort was made to design surface-system components and estimate equipment capital cost accurately so that the principal uncertainty in results would lie in the major process assumptions. One exception to this principle is the amount chosen as royalty to be paid for coal used by this process, which proved to be a difficult number to estimate. Coal royalty costs of $0.33/t (3O#ton) were selected. This royalty represents about $O.O29/GJ (341MMBtu)if half of the energy available in the coal is converted to sales gas. Coal which is not currently recoverable by any other means has little economic value. On the other hand, development of in situ conversion technology would increase that value. It seems reasonable to expect that the royalty should reflect the increased value of coal recoverable by the new technology but that it would not be so high that the new technology becomes non-competitive in the energy marketplace. At any rate, reasonable variat.ions from the chosen value would have little effect on the product price. Calculations involved in each case study were not complex but there are a great number of calculations and a wide range of parameter studies were desired. Thus a computer program was written to take care of equipment sizing, line sizing and cost estimation. Annual capital charges are 0.13 x (total capital) for utility financing based on 75/25 debt equity ratio, 15% return on equity, 8.5% interest rate, 48% federal income tax, and 4% depreciation (25-yr term). For equity financing, the annual charge is 0.24 x (total capital) based on 20% return on capital before taxes and 4% depreciation. 4. ECONOMIC
STUDY
RESULTS
Base case parameters
Base case parameters are shown in Table 2. Depth and seam thickness were chosen after reviewing several publications of the Illinois State Geological Survey on coal resources in the
An evaluation of in siru coal gasification
83
Table 2. Base case parameters
counties which contain the deeper part of the Illinois basin.lc” Depths as great as 1200ft have been recorded for the No. 5 coal; half that depth was chosen for the base case. Seam thickness as a parameter in this investigation reflects only on the magnitude of the coal resource per unit land area. Variation in heat loss and product composition with seam thickness is not considered. Since the Nos. 5 and 6 coals are not greatly separated, seam thickness is taken to represent net coal rather than a single physical dimension. For example, the Illinois Nos. 5 and 6 coals are each 1.5 m (5 ft) in some areas of the Illinois basin and the two constitute the base case net coal thickness of 3 m (10 ft). Implicit in this interpretation is the assumption that multiple overlying seams can be gasified either simultaneously or sequentially. At very high ratios of injection pressure to depth of cover, the economic estimates using a net coal figure will be slightly in error: capital and fuel gas consumption are functions of the operating pressure which is a function of seam depth. No gas is lost in the base case and no coal bypassed by the reaction front. Actual values of these numbers would vary with local geology, hydrology, operating pressures, etc. The effect of sweep efficiency is not quite the same as a reduced coal thickness since royalty is charged on the basis of total coal, whether gasified or not, but the difference is minor. Well spacing and flow of product gas from a single wellhead are reasonable values, fully examined in the parameter studies. The base case was chosen to represent the ideal case and the parameter study shows the effect of relaxing this assumption. Plant capacity is based on one half the size of the proposed surface gasification plants. The effect of system capacity on gas price is included in the parameter study. Product gas delivery pressures for this base case were derived from linear scaling of output pressure with gas heating value using 35.21 MJ/m3 (945 BtulSCF) pipeline gas at 6.89 MPa (1000 psig) as the reference point. This choice is arbitrary and its effect is discussed later. Injection pressure required to maintain pneumatic linkage is the same as was encountered in the Gulf field test. This value is about 30% greater than that normally thought of as the fracture-pressure gradient. Other techniques to achieve linkage, such as directional drilling, backward burning, or electrolinking would allow a decrease in this pressure requirement. However, it was the intention in this paper to present an evaluation of a system based directly on the 1968 Gulf test experience. Cost reported in the parameter studies include byproduct credit calculated for a 100% recovery of byproducts as listed in Table 1. Credit for byproducts was found to have a small effect on final gas cost. Base case results
Results of the economic analysis for the base case are presented in Table 3 for each product option under consideration. The absolute value of these costs has no meaning unless it is
84
I. C. FAIRet al. Table 3. Base case results for various product options (no loss of injected gas, produced gas or byproduct)
128.0 156.5 180.5 465.0
1.910.02)
1.460.54)
1.31(1.38)
2.94c3.10)
2.23(2.35)
1.98(2.09)
0.16(0.17)
0.14(0.15)
0.13(0.14)
46.8
53.4
56.3
8.0
8.0
13.5
4.1 \ 10.3 i 8.0 2.5
1.7
?4.8
20.5
100.0
100.0
100.0
356.4 1094.6
312.7 960.4
500.6 1537.7
42.1
47.0
49.5
24.8
Total
Gas Praducrion*- Jk
(MMSCFD)
discussed in the context of competition in the energy marketplace; the significance of cost levels shown in Table 3 is discussed in the section on market considerations. In addition to the capital requirement and gas price, the computer output includes information about energy used within the plant and overall energy efficiency, as shown in the bottom half of this table. Energy efficiency includes the purchased electric power at 35% generation efficiency and the byproduct contribution. Parameter
study results
Major parameters were varied over reasonable ranges to determine gas cost sensitivity. For the purpose of this study parameters which are related through the physics of the underground gasifier were decoupled. For example, injection gas flow rate and injection pressure were varied independently, while they are in reality interdependent. The volume of air injected must be five times the volume of oxygen injected for similar gasification rates, yet we examine the base case for both air and oxygen and hold the injection pressure constant. This decoupling must be kept in mind when examining the results of the parameter study. Depth and seam thickness. The data in Figs. 4 and 5 demonstrate the effect of depth and coal seam thickness on the cost of produced gas for both types of financing. increasing seam thickness has a diminishing effect on gas price. Low-heat-value gas cost increases more rapidly with depth than does the cost of either oxygen produced gas. The slope of cost with depth depends on the relationship assumed between injection pressure and depth. Final gas delivery pressure. The cost advantage enjoyed by low-heat-value (air produced) gas disappears with an increase in gas delivery pressure, as is shown in Fig. 6. This result emphasizes the desirability of using this gas as a source of fuel for nearby installations only. Due to the higher heat value of an oxygen-produced synthesis gas, the cost increase with pressure is much more gradual. The position of these curves with respect to the SPG points also suggests that synthesis gas could be transmitted over moderate distances at some cost benefit over SPG.
An evaluation of in situ
coal gasification
10 t
Fig. 4. Seam thickness and depth of cover. Seam thickness Feet (Meters1
15 (4.56) 20(6 08)
5(1
521
SPG 5 (1521 1013 041 15(4 ZO(b
56) 08)
lOl3.041 15(4 561 2Ob5.08)
2.0
I
I
I
0
I 0
600
Depth
900 I 200
I 100 to Bottom
I 1200
I
I
I
300
I 300
tFeet)
(Meters)
of Seam
Fig. 5. Seam thickness and depth of cover.
Plant capacity. Over a reasonable range of plant sizes, restricted only by limits on our cost estimating technique for SPG plants, the gas price is relatively unaffected by underground gasification plant capacity, as is shown in Fig. 7. A slight increase in gas cost is noted for large air-blown plants. Here the effect of the seam thickness is felt as the gathering network covers a large land area and is handling about twice as much product as in the O2cases because of nitrogen dilution.
J. C. FAIRet al.
/
SPG -Utility
1.4 ,.O4 0 I 0
200
400
I
I
2
I Sales
600 I
800 I
1
3
4
Gas Final
Delwery
5
’
1000 I 6
(PSIG) I 7tMPa)
Pressure
Fig. 6. Final delivery pressure.
30
Fig. 7. Plant capacity.
Well spacing and production well flow rate. These parameters are undoubtedly determined by the gasifier system, but we have chosen to vary them independently, as previously stated. Figures 8 and 9 show that well spacing greater than about 1.2 ha (3 acres) yields little, if any, cost reduction. Increasing gas flow rate from each production well yields a diminishing reduction in gas price: little incentive exists to increase the flow rate beyond 1.6m3/s (5 MMSCFD). Production and injection wellhead pressure. The effects of injection pressure on gas cost are shown in Figs. 10 and 11. As one would expect, lower pressures are favored, but in these figures, where gas losses are not linked to pressures, the effect of injection pressure variation is not large.
87
An evaluation of in situ coal gasification 30 r
, SPG 2 Synthesis 3 Low
Gas
St”
Fig. 8. Well spacing and flow rate from each production well
Gas duct,on
flow well
rate
from
MMSCFD
each
pro-
:m3/s1
I SPG 2 synthes,s
Gas
3 Low
Value
Heat
Gas
Fig. 9. Well spacing and flow rate from each production well.
The effect of production wellhead pressure is more dramatic. At low production pressures, cost increases reflect both the increase in production compressor horsepower and in fuel-gas consumption. Although operations at very low ratios of pressure to overburden might seem desirable to reduce injection costs, it is much better to increase reservoir pressure and avoid compressing larger volumes of produced gas from low absolute pressures. Gas losses. Figures 12 and 13 show gas price as affected by losses of injected gas and/or produced gas in the underground situation. The rate of gas loss would be a function of parameters such as gas pressure relative to formation pressure, local geology, presence of water and
aa
J. C. FAIRet al.
I SPG 2 Synthew
Gas
3 Low Heat Value
1 0
0
I 60
1
I
40
20
1
Gas
I 80
I 120
I
100
I
I
1
I
200
400
600
800
Pressure
at the
ProductIon
I 140 (PSIGI 1
IOOOlkPa)
Wellhead
Fig. 10.Production and injection wellhead pressures.
0 I 0
I
1
I
20
A0
60
1 200
I 400 Pressure
100
80 I 600
at the Product,on
120 I 800
140
IPSIGI
I 1000
IkPa)
Wellhead
Fig. 11.Production and injection wellhead pressures.
permeability. Any parameter interdependence has been ignored for this paper. Before any conclusion is drawn that oxygen loss is no more severe than air loss, we should point out that losses are expressed as a per cent rather than as a total gas loss volume. For equal volumes of gas lost, the loss of oxygen would have a much higher incremental cost, Similarly, equal volumes of product gas loss would be more costly if the gas were of high calorific value as produced by gasification with oxygen.
89
An evaluation of in situ coal gasification
Ut,l,ty
I 0
I
I
,
I
1
IO Percent
Finance
,
Injected
Air
I
30
20 Lost
Fig. 12.Underground gas losses for an air-blown process
/ / / /
-
Percent
L 0
/
\ IO Percent
I
Product
-
SynthessGas SPG
Gas Loss I
I
30
20 ,n,rxted
oxygen
~OSZ.
Fig. 13.Underground gas losses for an oxygen-blown process.
Oxygen requirement. Low char reactivity affects the economics of surface-gasification plants adversely; Fig. 14 shows the increase in cost produced by higher oxygen consumption (a measure of reactivity) for the in situ case. For this figure, all of the base-case parameters, including specific gas production and gas composition, were held constant and only oxygen consumption was varied.
J. C. FAIRet al.
/
/
/
I SPG 2 Synthew 3 Low
/
/
/
Gas
/
/
/
Heat ValueGas
/
/ /
0.5 Oxygen
0.6
0.7
Consumption, llllnois
/
I
I
0.8
0.9
Fraction No
25
/
/
of Lurgi
1
I
I
1.0
1.1
1.2
Requirement
for
6 Coal
Fig. 14.Oxygen requirement.
Market considerations
The selling price of energy at the point of production is not a good measure of the real value of that energy. We must determine the market in which the fuel will compete, the relative location of resource and market to determine transportation cost, the relative concentration of the end use to determine distribution cost, the efficiency of end-use consumption as compared to other fuels, demand cycles, and the cost of end-use capital equipment relative to other fuels. Figure 15 shows how energy was used in the United States in 1968. Approximately 75.4% of the energy total is consumed in the non-transportation sector, the maximum potential market area for a gaseous fuel produced from coal. This sector is further divided into areas with particular
PROCESS
HEAT
Fig. 15.Functional use of energy--1968.
91
Anevaluationof in situ coalgasification
energy requirements. Of those remaining markets, the industrial sector stands out as being the most likely market for gas from coal. The following characteristics of this market lead to this conclusion: (a) Industrial choice of fuel is, more than in other sectors, governed in the long term by economic law. Considerations other than cost, for example convenience, enter into the decision making process in other market sectors, but overall cost closely governs the industrial sector. (b) Some segments of industry have learned to handle fuel gas containing carbon monoxide safely; the steel industry is a prime example. It is less likely that consumer-safety advocates would accept a gas containing toxic carbon monoxide for residential or commercial use. (c) Displacement of premium fuels such as natural gas from the industrial sector would reduce supply problems for other demand sectors. (d) The industrial market is large; about 40% of the energy consumed in the U.S. is in this sector. Demands at a specific plant site are high relative to commercial and residential use, but not so high as in the electric power industry. Distribution costs would be reduced. Most of the energy required by industry is either for process heat or steam generation. The technology of using coal for process heat has advanced little from the level existing at least 40 years ago. Much better temperature and emissions control can be achieved with gaseous or liquid fuels. Coal combustion could, however, be used to produce industrial steam. It is this portion of the industrial energy sector that will be evaluated for potential sales of gas from underground coal gasification. The cost of generating industrial steam can be expressed in the following formula: cost/unit quantity of steam =
energy unit cost + boiler system cost x annual capital charge boiler rated capacity x demand factor conversion efficiency + operating cost per unit of steam,
where energy cost = production cost + transportation cost + distribution cost, Plant demand for steam may be cyclic and more or less seasonal, depending on plant type and location. Cyclic demand reduces thermal efficiency when individual boilers are run at less than capacity. Demand is also a factor in determining capital related end-use costs. Utilization factor (or demand factor), a measure of demand, is the total steam generated per year divided by the rated plant capacity for steam generation in a year. We have used this formula to evaluate the cost of generating industrial steam with various fuels. Figure 16 shows the pipeline distances from Centralia, Illinois, an identifiable site near suitable coal deposits and adjacent industrial markets. Table 4 shows the results of this evaluation, as applied to the generation of industrial steam in Chicago. Coal is clearly the primary competition in the industrial process steam market. Capital costs of coal-fired boilers and coal-handling systems rise as boiler unit size decreases. Firing of high sulfur coal requires the additional cost of stack-gas scrubbing units. Since consumption patterns of the industrial market were not well enough known, representative thermal efficiencies were n
Sagmaw ‘.
\
FItnt DETROIT
440
CHICAGO TOledoj___AcLqEYgtiAND cc
n So Bend
:
I I I
I I I
PITTSBURGH
:Lt,, Muncie Indlanapolls,
‘80 ,I, /’
, m’
/ n,
’
Columbus
, Dayton ~#cl”cl”“atl
250 ,
Inch
Fig. 16.Pipeline network for gas; distances from Centralia.
I. C. FAIR et al.
92
Table 4. Total cost of generating industrialprocess steam* in Chicago, Illinois (230miles from Centralia) Underground Casifica~ion Producer Synthesis Gas Gas SK Ga
1.55 2.46
1.70 2.13
Surface Pia”? SK
Highs caa1
LO”S ihal
2.21
2.98
0.8”
1.5”
2.45
3.23
1.09
1.79
chosen and the utilization factor varied. The trade-off of capital cost and fuel cost is clearly shown. Using the results of our study for the base case at 50% sweep efficiency, we see a cost advantage for gases from coal at lower unit sizes and utilizations. Comparison of the latest available data for surface gasification cost shows an advantage for underground gasification. Our costs must be regarded as less firm in the in situ case, however. The preferable product for this market is synthesis gas. Low-heat-value gas is penalized by high transportation and distribution costs while SPG suffers from the high cost of the upgrading process. Table 5 shows the data recalculated for an “energy park” of concentrated industrial use near Centralia. Costs involved in distributing low-heat-value producer gas still offset the slightly lower gas generation cost. Cost advantages are once more shown for gasification products at low unit size and utilization. Figure 17 shows a forecast of 1980industrial boiler sales. It may be seen from this figure that the smaller boilers, which would comprise the market for gasification products, represent a significant portion of the industrial steam market. Less is known about the demand factor for industrial steam generation: this area requires further study. We estimate that the demand factor could range from 30 to 90%, with lower numbers being more common. Implications
and conclusions
We have examined the production and marketing costs of various product options based on an underground coal gasification process using pneumatic linking in thin seams of bituminous Table 5. Total cost of generating industrial process steam* in Centralia, Illinois (an energy park concept) “nder*ro”ndGasiffcaLio” Pradueer Synthesis SPG GBS G.%S
Surface Plant SPG
Highs Coal
LawS ihal
cas Plant or vine ($/MNtx”)
1.55
1.7”
2.21
2.98
0.m
1.50
Delivered
2.06
l.QR
2.36
3.11
1.00
1.70
cast
(S;mBtu)
93
An evaluation of in situ coal gasification
o-7
E-15
16-30
31-45
46 -75
76-106
>107
MW
O-24
25-49
50-99
100-149
150-249
250-349
>350
THOUSANDS OF POUNDS PER HOlJR
steam
Etoller
capac1ry Range
Fig. 17.Forecast of industrial boiler sales-1980.
coal. Assumptions regarding the performance of the underground gasifier can be divided into those specific to the postulated process and those common to any system. We can gather the principal unknowns into the following list: gas composition, effect of parameters on heat loss, effect of heat loss on gas composition, subsidence effects, and required state of injected water. These areas remain as major uncertainties in our knowledge of underground coal gasification. Our assumptions lead to a number of conclusions regarding in situ gasification. (i) Coal-gasification products were shown to be economically preferable to coal as a fuel for small, low utilization industrial boilers. (ii) The preferable product from end-use considerations is a gas produced with oxygen. Air-produced gas has no advantage as an industrial fuel for generating steam, cannot be converted to SPG economically, and has severely limited application as a chemical feedstock. (iii) Intermediate heat value (synthesis) gas has cost advantages as an industrial fuel. It is also the most versatile to other options because of our ability to convert it to other forms. Methanol from synthesis gas is another route to a clean liquid fuel from coal. (iv) Production cost for gas produced in situ is shown to be significantly lower than for comparable gases derived from a surface process. (v) The produced gas must be at some minimum pressure near 1 mPa (150 psi) to be usable. It is advantageous to obtain a portion of this pressure at the production wellhead rather than in subsequent surface compression. (vi) Parameter studies involving seam thickness, coal reactivity, and injection pressure indicate that the thick, highly permeable, highly reactive Western coals should have significant gas production cost advantages. (vii) High pressures used in pneumatic linking increase gasification costs due to higher plant consumption, higher capital cost and penalties incurred for gas loss. (viii) Other methods of linking should be examined to determine possible cost savings. Acknowledgement-The authors wish to express their gratitude to Gulf Research & Development Company for permission to publish this paper.
REFERENCES 1. J. L. Elder, The underground gasification of coal. Chemisrryof&al Utilization, Supplementary Volume (Edited by H. H. Lowry). Wiley, New York (1%3). 2. A. D. Little, Inc., A current appraisal of underground coal gasification. NTIS, PB-209 274 (1972). 3. P. Raimondi et al., A field test of underground combustion of coal. .I. Petrol. Technol. (Jan. 1975). 4. Joint GR&DC/LLL Report, The LLL in sifu coal gasification research program in perspective. TID-26825(10 June 1975). 5. D. D. Fischer and L. S&rider, Comparison of results from underground coal gasification and from a stirred-bed producer. Presented at the National AIChE Meeting, Houston, Texas (K-20 Mar. 1975). 6. D. C. Elgin and H. R. Perks, Results of Trials of American Coals in Lurgi Pressure-Gasification Plant at Westfield, Scotland, Proceedings of the Sixth Synthetic Pipeline Gas Symposium, Chicago (28-30 Oct. 1974).
94
J. C. FAIR et al.
7. D. H. McCrea and J. H. Field, The Purification of Coal Derived Gases: Applicability and Economics of the Benfield Processes” Paper Number 2%, American Institute of Chemical Engineers, 78th National Meeting (18-21Aug. 1974). 8. J. M. Campbell, Gas Condirioning and Processing, Campbell Petroleum Series, Norman, Oklahoma (1974). 9. K. hf. Guthrie, Process Plant Estimating Eoaluation and Control. Craftsman Book Company of America, Solana Beach, California (1974). 10. 1973Joint Association Survey of the U.S. Oil and Gas Producing Industry, Section I: Drilling Costs, API Statistical Publications, Washington, D.C. (Feb. 1975). 11. S. P. Marshall and J. L. Brandt, 1974installed cost of corrosion resistant piping. Chem. Engng, October 28 (1974). 12. Pipeline economics. Oil and Gas .T.(12 Aug. 1974). 13. D. L. Bidlack to A. N. Mann, Gulf Research & Development Co. Planning and Economics Division, private communication (31 Mar. 1975and 7 July 1975). 14. G. H. Cady et al., Subsurface geology and coal resources of the Pennsylvanian System in certain counties of the Illinois Basin, Report of Investigations No. 148, Illinois State Geological Survey (1951). 15. G. H. Cady, Coal resources of Franklin County, Illinois. Circular No. 151, Illinois State Geological Survey (1949). 16. J. A. Harrison, Subsurface geology and coal resources of the Pennsylvanian System in White County, Illinois. Report of Investigations No. 53, Illinois State Geological Survey (1951). 17. E. P. DuBois, Geology and coal resources of a part of the Pennsylvanian System in Shelby, Moultrie, and portions of Effingham and Fayette Counties. Report of Inoestigations No. 156, Illinois State, Geological Survey (1951). APPENDIX
I
Basic cost data All cost data are indexed to the first quarter of 1975.Compressor capital cost data are taken from recent manufacturers’ quotations. Tankage, separators, and gas coolers come from Gulf data and assorted references.B.9Drilling and completion costs have fluctuated wildly in the last several years under demand pressures and equipment shortages; however, recent data on a large number of intiUholes, as weUas published well costs,” were used to estimate drilling costs of $17/ft (drilled, cased and cemented) plus $4000 fixed cost per injection well and $3000 for each production well. Casing is considered non-recoverable but tubing and packers used in the injection well are reused. Surface piping material costs of $0.48/kg ($0.22/lb)for carbon steel and $3.08/kg ($14O/lb)for stainless steel come from a variety of sources9.” Labor costs for installing piping were derived from a pipeline industry survey report,” 50% of this value is charged for disassembling installed piping systems. Cost of clearing, grading and building access roads, electrical substations, and water-supply systems came from Gulf data and Guthrie’s manual9 Cost data for the oxygen plant and SPG plant were provided by the Planning and Economics Division of Gulf Research & Development Company.” The SPG plant costs were based on submissions to the FPC for surface plant construction, a southern Blinoisplant site, and the gas composition data from Elgin and Perks.6 Cost and operating data for the hot carbonate gas clean-up process came from McCrea and Field.’ APPENDIX
II
Calculation of steam-generation cost Steam from coal combustion. The costs of mined coal chosen represent the relative values of high and low sulfur coal in a
spot purchase rather than a long-term contract. Transportation from the mine to an industrial area is estimated to be $O.O062/tkm ($O.O09/tonmile) and delivery charges are estimated at $5.50/t ($5/tori)))The 84% energy conversion efficiency chosen represents a steady state efficiency of coal fired steam generation. A 2% efficiency reduction for high sulfur coal is used to reflect the stack gas scrubbing energy requirement. These numbers represent maxima sincecyclic boiler loading and off-peak operation would reduce thermal efficiency. Capital and operating cost information were obtained from boiler data published in a variety of sources. The values used can be backed out of the data table if desired, using the equation for steam cost shown in the text. Flue gas desulfurization capital and operating costs were determined from data for larger units using a 0.6 scaling factor for capital. Steam from coal gas
The data used for underground coal gasification product cost are the base case; however, a 1.5m (5 ft) seam thickness was chosen. One can interpret this as representing anything from two 1.5m (5 ft) seams converted with a 50% sweep efficiency to a single 1.5m (5 ft) seam and a 100%sweep efficiency. The surface gasification plant SPG price was taken from a recent GR &DC estimate for Illinois coal using the Westfield data. Transnortation cost was determined for each gas from a detailed analysis of pipeline and compressorstation capital and operating costs. Line size used is the economic optimum of available sizes for the gas flow desired. A value of SO.O95/GJ ($O.lO/MMBtu)resulted from this analysis for SPG transport to Chicago. A distribution cost of $O.l3/GJ($O.lYMMBtu)was selected after reviewing gas-industry data. Other gas-distribution costs were scaled from natural gas data by the ratio of transportation costs previously determined. A charge of $O.O47/GJ ($O.OS/MMBtu)was added to the cost of gases containing CO to cover the cost of extra precautions required in the distribution system for safely handling a toxic gas. Synthesis gas distribution cost was 80.265iG.l($0.28/MMBtu)and producer gas distribution cost $0.48/GJ ($O.Sl/MMBtu). A steady state thermal efficiency of 82% was used for SPG conversion to steam and 80% for both producer gas and synthesis gas. Capital costs of all gas-fired boilers of the same rating were considered to be equal. Data from several sources were used to determine boiler cost variation with size. Since such boilers are generally modular, the capital cost does not change greatly with rated steam output. Annual capital charge
As annual charge of 20% of the invested capital was used for steam generation equipment. Stack-gas scrubbers, however, were charged at 17%/yr on invested capital assuming some incentive financing would be available. Gas prices used assume utility financing or some similar lower cost financing scheme will exist for the synthetic fuels industry.
Vol.I. pp.71-94.
Pergamon Press 1976.
Printed in Great
AN EVALUATION
Britain
OF IN SITU COAL GASIFICATIONi
J. C. FAIR, 0.
A. LARSON and
H. H. HASIBA
Gulf Research&Development Company, Pittsburgh,PA 15230,U.S.A. (Received 11November
1975)
Abstract-The in situ conversion of coal to other energy forms such as gas or liquids is receiving increased attention as the framework of a national energy R & D program is becoming more clearly defined. Efforts to gasify coal underground date back to the middle of the 19th century, with a significant increase in activities occurring between 1945and 1%5, mostly in Russia, England and the U.S.A., with active projects reported to be underway in Russia at present. Recent tests in the U.S.A. have been reported by the Gulf Research & Development Company, which conducted a brief test in Kentucky in 1%8, and by the ERDA Laramie Energy Research Center (LERC), which has been conducting pilot tests near Hamta, Wyoming, since 1972.Also active in this field are workers at the Lawrence Livermore Laboratory (LLL) of the University of California, and the Morgantown Energy Research Center of ERDA. A group of utilities in Texas has recently made contractual agreements to acquire Russian in situ gasification technology. Renewed interest in this area has also been expressed in Canada, England and Belgium. While economic analyses related to various surface-gasification schemes have recently proliferated, few economic studies have been reported for in sifu schemes. In this paper, we consider the orientation economics and some market aspects relative to a commercial extrapolation of the Gulf Research & Development Company thin-seam in situ gasification scheme. Our analysis is aimed at the determination of produced gas cost for a commercial application of the forward gasification of coal from vertical boreholes using pneumatic pressure linking. It is assumed that the produced gas composition will be similar to that of a surface Lurgi gasifier using the same coal. Recent results from the second group of Hanna field experiments by LERC have shown that Lurgi results can be obtained by an underground gasifier using vertical boreholes linked by backward burning. Gas costs are calculated as a function of production system variables such as well spacing, seam thickness, depth of cover, conversion sweep efficiency, product gas loss, and injection oxidant loss. Other variables involved in the analysis are associated with end-use considerations. Gas produced from an oxygen-consuming process may be upgraded to pipeline quality by methanation or to a medium heating-value by CO, and H,S extraction, while air-produced gas can only be slightly upgraded by this latter process and remains a relatively low-heating-value gas. A market analysis is then made on the basis of end-use options for the potentially evolving gas supply. Limitations concerning the transportation and consumption of each type of product are explored. The major competing energy sources within the energy market are examined for each of the gas product alternatives. Several research and development implications are discussed.
1. INTRODUCTION
Recent energy economics, declining domestic oil and gas production, and interest in exploiting huge domestic coal reserves have resulted in a new lease on life for the concept of underground coal gasification. This idea has been around for more than 100 years and has been the subject of numerous experiments of varying quality and value. Stated very simply, underground gasification of coal involves the conversion of energy present in the solid coal into a combustible gas without mining the coal. As with any process conducted underground, one must deal in some way with the geological and hydrological features of the earth’s crust and the prevailing force of gravity while maintaining severely restricted contact with and control over the ongoing process. Benefits claimed for in situ gasification range from humanitarian through ecological and economic. It is not the purpose of this paper to restate the pros and cons of the concept, which are already the subject of many good reviews (see, e.g. Refs [ 1 and 21).Nor do we wish to present another review of past history. However, a brief outline of current activities is required to establish the relevance of this study. Workers at ERDA-LERC are conducting a very encouraging series of field tests near Hanna, Wyoming. These tests were initiated in 1972. ERDA is also sponsoring other investigations into underground coal gasification at the Morgantown Energy Research Center (MERC) and at LLL. Laboratory tests and mathematical model studies are being conducted at the Universities of Texas, New Mexico, Kentucky, Wyoming, West Virginia and at the Pennsylvania State tThis paper was presented at the American Nuclear Society Winter Meeting, 16-21Nov. 1975,San Francisco, California. 77
78
J. C. FAIR et al.
University. Texas Utilities Services Co. is planning a pilot demonstration using technology based on many years of experimentation and plant operation within the USSR. Governmental agencies in Belgium and a province of Canada are planning tests and the National Coal Board in England is re-assessing in situ coal conversion. The major differences in these programs involve the resource target and linking techniques to be applied. The Laramie and LLL programs, for example, are directed at deposits of subbituminous coal and lignite found in the Western states; Texas Utilities Services Co. is interested in developing Texas lignites; and the Morgantown program is aimed at Eastern bituminous coals. Linking is the term applied to establishing and maintaining a flow path through the coal between the points of injection and production. Each linking technique attempts to solve problems of low natural permeability, liquid plugging, coal swelling, and bypassing of coal by the reaction front. Backwards burning is used at Laramie, explosive fracturing at LLL and directional drilling at Morgantown. Electrolinking and hydraulic fracturing have also been proposed. Yet another technique, high pressure pneumatically-induced fracturing, was used by Gulf Research & Development Company (GR&DC). Workers at GR&DC began investigating in situ processing of coal for energy recovery during the early l%Os. Laboratory experimental work in the production of liquid and gaseous products from coal preceded a field test conducted at the Pittsburg and Midway Coal Company Colonial Mine in Kentucky in 1%8. Results of the field test have been published recently[3]. The test achieved the major objective of verifying that oil-field technology could be applied to the recovery of useful products from coal by in situ combustion. Interest in underground coal gasification at GR&DC has increased in recent years after nearly 6 years of only minor activity. In-house evaluation of ongoing work included a recent joint study with LLL on their deep, thick coal-seam gasification concept.4 These recent efforts led to a recognition of a shortcoming in the literature on underground coal gasification. Economic studies of surface gasification plants have proliferated. Market assessments have been somewhat less abundant; indeed, most authors have assumed a market would exist for their product. Economic and/or market evaluations are both process and site specific. Details of process costs, coal characteristics, product variation and market location will require that a number of such studies be performed and reported. 2. OBJECTIVES
OF THE
STUDY
Results of an economic and marketing study of one possible method of gasifying coal underground, namely, that of thin seam conversion using pneumatic linking, are presented in this report.? The objectives of this orientation economics and marketing study are the following: (a) Determine the cost of various product options from the in situ process using reasonable estimates where factual information does not exist. (b) Determine the sensitivity of product cost to variations in system parameters over a reasonable range. Analyze the information from this parameter study to identify important parameters and important ranges of these parameters. (c) Maintain the link between these results and reality. Assumptions which are required to perform such a study at this early stage should always be kept in mind when evaluating the results and formulating conclusions. (d) Compare cost estimates from this study with competing fuels in the energy market. All costs accruing to the use of each energy source must be considered to evaluate the market potential for the final product. (e) Apply the results of the study to aid in directing similar analyses of other in situ process concepts, to point out questions which need to be answered in future R & D work, and to characterize the role underground gasification might play in filling the energy needs of the country. 3. ASSUMPTIONS
AND PROCEDURES
Major assumptions
Bituminous coals require special consideration in the choice of linking technique because their high volatile matter content leads to potential liquid plugging problems and their tendency to tThe views are those of the authors and do not necessarily
represent those of Gulf Oil Corporation.
79
An evaluation of in situ coal gasification
swell on heating can reduce flow permeability. However, potential marketing advantages exist because of the proximity of suitable deposits to industrial and population centers. The GR & DC underground coal conversion test was conducted in a relatively thin (3 m) seam of moderately swelling (free swelling index = 3.5) bituminous coal by using high injection pressures (about 29.4 kPa/m of overburden or 1.3 psi/ft) to maintain a flow path between injection and production wells. Our familiarity with the pneumatic linking technique, as applied to thin seams, led to the choice of such a system for this initial analysis. We present this linking technique as one alternative of many and do not attempt to compare underground gasification concepts. The coals of the Illinois basin were chosen for this study, both on the basis of similarity to the coal encountered in the Kentucky test and on the basis of major industrial energy demands nearby. Relative location of the Illinois coals to other U.S. coal deposits is shown in Fig. 1.
-
ANTHRACITE & SEMIANTHRACITE
‘\
Rsi
LOW-VOLATILE BITUMINOUS
@I
MEDIUM &HIGH-VOLATILE BITUMINOUS COAL
eza
SUBBITUMINOUS
m
LIGNITE
\I-
COAL
COAL
‘-1
0 Li
8.
200 I
400
600
y
MILES
Fig. 1. Coal fields of the conterminous United States
The underground process postulated for this paper has been extrapolated from the Gulf Colonial Mine Field Test of underground coal conversion. This test was limited to dry combustion with the heat of combustion used for in-place retorting. However, we assume in this paper that gasification could be achieved from the same test configuration if water or steam were injected. Performance of the underground gasifier is a major unknown. Although we have, for the sake of this study, put aside questions regarding subsidence, liquid plugging and other mechanical aspects of the process, we needed to determine injection parameters, such as oxygen required per unit mass of coal and water to oxygen ratio. Furthermore, given these parameters, how much gas would be produced for a unit mass of coal and what would be the composition of this gas? These are basic questions affecting the amount of coal resource required, oxidant capacity, and design and cost of the purification and/or methanation facilities. It was decided that data from the Lurgi gasifier tests in Westfield, Scotland, should be used. The Westfield data are from a systematic, well documented test that included both Illinois Nos. 5 and 6 coals, the seams of greatest importance in the Illinois basin. Reports from ERDA’s underground gasification experiments at Hanna, Wyoming, have indicated that, for their test conditions, underground gasification results have been “similar” to those reported for a Lurgi gasifier.’ Despite many differences in operating conditions, it was felt that the Lurgi data were, at least, indicative of the reactivity of the coal of interest. Lurgi data reported by Elgin and Perks6 are shown in Table 1. One major difference between the conditions under which their data were taken and the postulated operating conditions for the EGY Vol. I, No. I-F
80
J. C. FAIRet al. Table 1. Data from gasification of Illinois No. 6 coal in a Lurgi gasifier ___._._-___... .-... .- . -....-. ..---.----.-.------
Product
Gas Calorific
Value
in situ gasification scheme is the state of injected water. The Lurgi gasifier requires steam injection, whereas we have assumed that liquid water injection is possible in underground gasification. Steam injection in the underground process is a subject for further study. Although the Hanna test utilizes nearly ideal conditions of natural ground-water flow to provide required water, we do not feel this fully justifies our use of liquid water injection. We are not certain, at this point, that the Hanna results could be obtained if the same water volumes came into the system from the wellbore. A surface gasifier unit of the type used in Westfield tests is constrained to operate at a temperature below the ash fusion point of the coal. Temperature control is maintained by injecting excess steam. Steam requirements for Eastern bituminous coals tested were particularly high due to their relatively low ash fusion point. Since slag removal is not a problem in the in situ gasification process, higher gasification temperatures requiring less steam or water could be tolerated. Nevertheless, we have retained the reported water requirements from Westfield for our study. Water costs are a very small part of the overall cost of gas production. Commercial
system
The conceptual commercial system employs a line drive configuration consisting of a number of five-spot patterns, as shown in Figs. 2(A-C). Choice of this configuration is based on the initial test experience and conventional oilfield practice. Fluid produced from this array of wells is conducted to a transportable field production station. Here the gas is cooled, coal liquids and liquid water are separated, and the produced gas is compressed for transmission to the gas treatment plant. The production station is located near the active pattern to reduce gathering line pressure drop. The gas treatment facility, however, is located at a fixed site outside the active area for protection against surface subsidence. Also located at the gas plant site are the oxygen plant or air compressors and water supply system. Delivery lines run to the active site where distribution lines connect to each injection well. Figure 3 shows a schematic diagram of this piping system. As the coal within each line drive pattern is consumed, an adjacent pattern, which has been previously prepared, is gradually brought on stream to provide a continuous flow of product gas. Manifold piping for two patterns must therefore be provided. Each succeeding line drive is connected to the main lines prior to ignition, using the piping from the burned-out pattern. At
81
An evaluation of in situ coal gasification A
FIVE-SPOT
PATTERN
Y4
0
Production
‘cl
c
LINE
DRIVE
GASIFIER
well
0
InJectIon
\
well
0
\
0
“\#4 B
ELEVATION
A-A
Gas,fmt,on Products
Overburden
Production
Fig. 2. Gas-production
I
Rows
configuration.
I
Fig. 3. Plan view of surface facilities.
periodic intervals, the field production station is moved as the advancing active zone approaches. Sufficient excess equipment capacity reduces the effect of this move on continuous gas production capability. Physical plant The system is comprised of three distinct operational divisions: the production facilities, the gas treatment plant, and the injection facilities. Gas production operations involve injection and production wells, all piping between production facilities and the central plant, gas coolers, field seperators for gas and liquid separation and gas clean-up, and compressors required for transmission of produced gas to central treatment facilities. Pipe diameter and wall thickness are selected according to flow rate, fluid pressure and pressure drop requirements. Lines required include oxidant main and manifold, water main and manifold, product gathering manifold, product gas transmission line, tar and oil transport line and a line for the desulfurized fuel gas supply. All piping is assumed to be carbon steel, except for oxygen lines which must be stainless steel. Injection and production wells are assumed to be cased and cemented through the coal. The production well casing I.D. is a function of gas flow rate and a specified pressure drop criterion.
82
J. C. FAIR et al.
Separators, oil dehydrators, gas coolers, liquid storage facilities and compressors are sized according to assumed or calculated conditions using accepted formulae. Compressor interstage temperature is limited to 150°C.Flexibility for continuous operation is provided by requiring 25% production equipment standby capacity. The central gas treatment plant design varies according to end product requirements. A gas produced with oxygen may be upgraded by acid gas (HZl + COZ) removal to provide mediumheat-value gas for fuel or synthesis feedstock (we will call this synthesis gas) or it may be converted into synthetic pipeline gas (SPG) by shift conversion, purification, and then methanation to a pipeline quality of 35.2 MJ/m3 (945 Btu/SCF). A gas produced from air injection has a low heat value but would be suitable for nearby consumption as a fuel once sulfur compounds are removed. We will call this product producer gas. The hot potassium carbonate process, as described by McCrea and Field,’ is used in both synthesis gas and producer gas purification plants. Process parameters are adjusted to remove nearly all CO2 in the case of the synthesis gas, but only about 25% of the COZwith more selective H&Sabsorption in the producer gas case. If COZcan be tolerated in the end product, savings are realized both in plant capital and energy requirements. A Claus sulfur plant is used to convert the H,S in the concentrated acid gas stream to elemental sulfur for byproduct sales. A portion of the produced gas is split off for use as plant fuel. Selective H,S and partial CO2 removal is used to desulfurize the fuel gas. This fuel is used in gas turbines and boilers to provide gas compression at the field production station, regeneration steam for the gas purification process, shift conversion steam, power for the sulfur plant, oxidant at the required injection pressure, and final compression of the product gas to the required delivery pressure. Thus, the major energy requirements of the system come from internally generated gas. Only a small amount of energy is purchased as commercial electric power. The oxygen plant requirement is calculated with a maximum single train size of 0.66 Mtla (2000 tons/day). Air compression is by gas turbine powered compressors of approximately 7500 kW (10,000 HP) capacity. In either case, the plant fuel is desulfurized product gas. Capital cost, as well as operating cost, varies with the required injection pressure. This, in turn is a function of the assumed pressure gradient required to maintain gas flow underground, depth of cover and pressure drop in the surface piping. Cost analysis
Details of the costs used in this analysis are included in Appendix I. All costs are indexed to early 1975. Every effort was made to design surface-system components and estimate equipment capital cost accurately so that the principal uncertainty in results would lie in the major process assumptions. One exception to this principle is the amount chosen as royalty to be paid for coal used by this process, which proved to be a difficult number to estimate. Coal royalty costs of $0.33/t (3O#ton) were selected. This royalty represents about $O.O29/GJ (341MMBtu)if half of the energy available in the coal is converted to sales gas. Coal which is not currently recoverable by any other means has little economic value. On the other hand, development of in situ conversion technology would increase that value. It seems reasonable to expect that the royalty should reflect the increased value of coal recoverable by the new technology but that it would not be so high that the new technology becomes non-competitive in the energy marketplace. At any rate, reasonable variat.ions from the chosen value would have little effect on the product price. Calculations involved in each case study were not complex but there are a great number of calculations and a wide range of parameter studies were desired. Thus a computer program was written to take care of equipment sizing, line sizing and cost estimation. Annual capital charges are 0.13 x (total capital) for utility financing based on 75/25 debt equity ratio, 15% return on equity, 8.5% interest rate, 48% federal income tax, and 4% depreciation (25-yr term). For equity financing, the annual charge is 0.24 x (total capital) based on 20% return on capital before taxes and 4% depreciation. 4. ECONOMIC
STUDY
RESULTS
Base case parameters
Base case parameters are shown in Table 2. Depth and seam thickness were chosen after reviewing several publications of the Illinois State Geological Survey on coal resources in the
An evaluation of in siru coal gasification
83
Table 2. Base case parameters
counties which contain the deeper part of the Illinois basin.lc” Depths as great as 1200ft have been recorded for the No. 5 coal; half that depth was chosen for the base case. Seam thickness as a parameter in this investigation reflects only on the magnitude of the coal resource per unit land area. Variation in heat loss and product composition with seam thickness is not considered. Since the Nos. 5 and 6 coals are not greatly separated, seam thickness is taken to represent net coal rather than a single physical dimension. For example, the Illinois Nos. 5 and 6 coals are each 1.5 m (5 ft) in some areas of the Illinois basin and the two constitute the base case net coal thickness of 3 m (10 ft). Implicit in this interpretation is the assumption that multiple overlying seams can be gasified either simultaneously or sequentially. At very high ratios of injection pressure to depth of cover, the economic estimates using a net coal figure will be slightly in error: capital and fuel gas consumption are functions of the operating pressure which is a function of seam depth. No gas is lost in the base case and no coal bypassed by the reaction front. Actual values of these numbers would vary with local geology, hydrology, operating pressures, etc. The effect of sweep efficiency is not quite the same as a reduced coal thickness since royalty is charged on the basis of total coal, whether gasified or not, but the difference is minor. Well spacing and flow of product gas from a single wellhead are reasonable values, fully examined in the parameter studies. The base case was chosen to represent the ideal case and the parameter study shows the effect of relaxing this assumption. Plant capacity is based on one half the size of the proposed surface gasification plants. The effect of system capacity on gas price is included in the parameter study. Product gas delivery pressures for this base case were derived from linear scaling of output pressure with gas heating value using 35.21 MJ/m3 (945 BtulSCF) pipeline gas at 6.89 MPa (1000 psig) as the reference point. This choice is arbitrary and its effect is discussed later. Injection pressure required to maintain pneumatic linkage is the same as was encountered in the Gulf field test. This value is about 30% greater than that normally thought of as the fracture-pressure gradient. Other techniques to achieve linkage, such as directional drilling, backward burning, or electrolinking would allow a decrease in this pressure requirement. However, it was the intention in this paper to present an evaluation of a system based directly on the 1968 Gulf test experience. Cost reported in the parameter studies include byproduct credit calculated for a 100% recovery of byproducts as listed in Table 1. Credit for byproducts was found to have a small effect on final gas cost. Base case results
Results of the economic analysis for the base case are presented in Table 3 for each product option under consideration. The absolute value of these costs has no meaning unless it is
84
I. C. FAIRet al. Table 3. Base case results for various product options (no loss of injected gas, produced gas or byproduct)
128.0 156.5 180.5 465.0
1.910.02)
1.460.54)
1.31(1.38)
2.94c3.10)
2.23(2.35)
1.98(2.09)
0.16(0.17)
0.14(0.15)
0.13(0.14)
46.8
53.4
56.3
8.0
8.0
13.5
4.1 \ 10.3 i 8.0 2.5
1.7
?4.8
20.5
100.0
100.0
100.0
356.4 1094.6
312.7 960.4
500.6 1537.7
42.1
47.0
49.5
24.8
Total
Gas Praducrion*- Jk
(MMSCFD)
discussed in the context of competition in the energy marketplace; the significance of cost levels shown in Table 3 is discussed in the section on market considerations. In addition to the capital requirement and gas price, the computer output includes information about energy used within the plant and overall energy efficiency, as shown in the bottom half of this table. Energy efficiency includes the purchased electric power at 35% generation efficiency and the byproduct contribution. Parameter
study results
Major parameters were varied over reasonable ranges to determine gas cost sensitivity. For the purpose of this study parameters which are related through the physics of the underground gasifier were decoupled. For example, injection gas flow rate and injection pressure were varied independently, while they are in reality interdependent. The volume of air injected must be five times the volume of oxygen injected for similar gasification rates, yet we examine the base case for both air and oxygen and hold the injection pressure constant. This decoupling must be kept in mind when examining the results of the parameter study. Depth and seam thickness. The data in Figs. 4 and 5 demonstrate the effect of depth and coal seam thickness on the cost of produced gas for both types of financing. increasing seam thickness has a diminishing effect on gas price. Low-heat-value gas cost increases more rapidly with depth than does the cost of either oxygen produced gas. The slope of cost with depth depends on the relationship assumed between injection pressure and depth. Final gas delivery pressure. The cost advantage enjoyed by low-heat-value (air produced) gas disappears with an increase in gas delivery pressure, as is shown in Fig. 6. This result emphasizes the desirability of using this gas as a source of fuel for nearby installations only. Due to the higher heat value of an oxygen-produced synthesis gas, the cost increase with pressure is much more gradual. The position of these curves with respect to the SPG points also suggests that synthesis gas could be transmitted over moderate distances at some cost benefit over SPG.
An evaluation of in situ
coal gasification
10 t
Fig. 4. Seam thickness and depth of cover. Seam thickness Feet (Meters1
15 (4.56) 20(6 08)
5(1
521
SPG 5 (1521 1013 041 15(4 ZO(b
56) 08)
lOl3.041 15(4 561 2Ob5.08)
2.0
I
I
I
0
I 0
600
Depth
900 I 200
I 100 to Bottom
I 1200
I
I
I
300
I 300
tFeet)
(Meters)
of Seam
Fig. 5. Seam thickness and depth of cover.
Plant capacity. Over a reasonable range of plant sizes, restricted only by limits on our cost estimating technique for SPG plants, the gas price is relatively unaffected by underground gasification plant capacity, as is shown in Fig. 7. A slight increase in gas cost is noted for large air-blown plants. Here the effect of the seam thickness is felt as the gathering network covers a large land area and is handling about twice as much product as in the O2cases because of nitrogen dilution.
J. C. FAIRet al.
/
SPG -Utility
1.4 ,.O4 0 I 0
200
400
I
I
2
I Sales
600 I
800 I
1
3
4
Gas Final
Delwery
5
’
1000 I 6
(PSIG) I 7tMPa)
Pressure
Fig. 6. Final delivery pressure.
30
Fig. 7. Plant capacity.
Well spacing and production well flow rate. These parameters are undoubtedly determined by the gasifier system, but we have chosen to vary them independently, as previously stated. Figures 8 and 9 show that well spacing greater than about 1.2 ha (3 acres) yields little, if any, cost reduction. Increasing gas flow rate from each production well yields a diminishing reduction in gas price: little incentive exists to increase the flow rate beyond 1.6m3/s (5 MMSCFD). Production and injection wellhead pressure. The effects of injection pressure on gas cost are shown in Figs. 10 and 11. As one would expect, lower pressures are favored, but in these figures, where gas losses are not linked to pressures, the effect of injection pressure variation is not large.
87
An evaluation of in situ coal gasification 30 r
, SPG 2 Synthesis 3 Low
Gas
St”
Fig. 8. Well spacing and flow rate from each production well
Gas duct,on
flow well
rate
from
MMSCFD
each
pro-
:m3/s1
I SPG 2 synthes,s
Gas
3 Low
Value
Heat
Gas
Fig. 9. Well spacing and flow rate from each production well.
The effect of production wellhead pressure is more dramatic. At low production pressures, cost increases reflect both the increase in production compressor horsepower and in fuel-gas consumption. Although operations at very low ratios of pressure to overburden might seem desirable to reduce injection costs, it is much better to increase reservoir pressure and avoid compressing larger volumes of produced gas from low absolute pressures. Gas losses. Figures 12 and 13 show gas price as affected by losses of injected gas and/or produced gas in the underground situation. The rate of gas loss would be a function of parameters such as gas pressure relative to formation pressure, local geology, presence of water and
aa
J. C. FAIRet al.
I SPG 2 Synthew
Gas
3 Low Heat Value
1 0
0
I 60
1
I
40
20
1
Gas
I 80
I 120
I
100
I
I
1
I
200
400
600
800
Pressure
at the
ProductIon
I 140 (PSIGI 1
IOOOlkPa)
Wellhead
Fig. 10.Production and injection wellhead pressures.
0 I 0
I
1
I
20
A0
60
1 200
I 400 Pressure
100
80 I 600
at the Product,on
120 I 800
140
IPSIGI
I 1000
IkPa)
Wellhead
Fig. 11.Production and injection wellhead pressures.
permeability. Any parameter interdependence has been ignored for this paper. Before any conclusion is drawn that oxygen loss is no more severe than air loss, we should point out that losses are expressed as a per cent rather than as a total gas loss volume. For equal volumes of gas lost, the loss of oxygen would have a much higher incremental cost, Similarly, equal volumes of product gas loss would be more costly if the gas were of high calorific value as produced by gasification with oxygen.
89
An evaluation of in situ coal gasification
Ut,l,ty
I 0
I
I
,
I
1
IO Percent
Finance
,
Injected
Air
I
30
20 Lost
Fig. 12.Underground gas losses for an air-blown process
/ / / /
-
Percent
L 0
/
\ IO Percent
I
Product
-
SynthessGas SPG
Gas Loss I
I
30
20 ,n,rxted
oxygen
~OSZ.
Fig. 13.Underground gas losses for an oxygen-blown process.
Oxygen requirement. Low char reactivity affects the economics of surface-gasification plants adversely; Fig. 14 shows the increase in cost produced by higher oxygen consumption (a measure of reactivity) for the in situ case. For this figure, all of the base-case parameters, including specific gas production and gas composition, were held constant and only oxygen consumption was varied.
J. C. FAIRet al.
/
/
/
I SPG 2 Synthew 3 Low
/
/
/
Gas
/
/
/
Heat ValueGas
/
/ /
0.5 Oxygen
0.6
0.7
Consumption, llllnois
/
I
I
0.8
0.9
Fraction No
25
/
/
of Lurgi
1
I
I
1.0
1.1
1.2
Requirement
for
6 Coal
Fig. 14.Oxygen requirement.
Market considerations
The selling price of energy at the point of production is not a good measure of the real value of that energy. We must determine the market in which the fuel will compete, the relative location of resource and market to determine transportation cost, the relative concentration of the end use to determine distribution cost, the efficiency of end-use consumption as compared to other fuels, demand cycles, and the cost of end-use capital equipment relative to other fuels. Figure 15 shows how energy was used in the United States in 1968. Approximately 75.4% of the energy total is consumed in the non-transportation sector, the maximum potential market area for a gaseous fuel produced from coal. This sector is further divided into areas with particular
PROCESS
HEAT
Fig. 15.Functional use of energy--1968.
91
Anevaluationof in situ coalgasification
energy requirements. Of those remaining markets, the industrial sector stands out as being the most likely market for gas from coal. The following characteristics of this market lead to this conclusion: (a) Industrial choice of fuel is, more than in other sectors, governed in the long term by economic law. Considerations other than cost, for example convenience, enter into the decision making process in other market sectors, but overall cost closely governs the industrial sector. (b) Some segments of industry have learned to handle fuel gas containing carbon monoxide safely; the steel industry is a prime example. It is less likely that consumer-safety advocates would accept a gas containing toxic carbon monoxide for residential or commercial use. (c) Displacement of premium fuels such as natural gas from the industrial sector would reduce supply problems for other demand sectors. (d) The industrial market is large; about 40% of the energy consumed in the U.S. is in this sector. Demands at a specific plant site are high relative to commercial and residential use, but not so high as in the electric power industry. Distribution costs would be reduced. Most of the energy required by industry is either for process heat or steam generation. The technology of using coal for process heat has advanced little from the level existing at least 40 years ago. Much better temperature and emissions control can be achieved with gaseous or liquid fuels. Coal combustion could, however, be used to produce industrial steam. It is this portion of the industrial energy sector that will be evaluated for potential sales of gas from underground coal gasification. The cost of generating industrial steam can be expressed in the following formula: cost/unit quantity of steam =
energy unit cost + boiler system cost x annual capital charge boiler rated capacity x demand factor conversion efficiency + operating cost per unit of steam,
where energy cost = production cost + transportation cost + distribution cost, Plant demand for steam may be cyclic and more or less seasonal, depending on plant type and location. Cyclic demand reduces thermal efficiency when individual boilers are run at less than capacity. Demand is also a factor in determining capital related end-use costs. Utilization factor (or demand factor), a measure of demand, is the total steam generated per year divided by the rated plant capacity for steam generation in a year. We have used this formula to evaluate the cost of generating industrial steam with various fuels. Figure 16 shows the pipeline distances from Centralia, Illinois, an identifiable site near suitable coal deposits and adjacent industrial markets. Table 4 shows the results of this evaluation, as applied to the generation of industrial steam in Chicago. Coal is clearly the primary competition in the industrial process steam market. Capital costs of coal-fired boilers and coal-handling systems rise as boiler unit size decreases. Firing of high sulfur coal requires the additional cost of stack-gas scrubbing units. Since consumption patterns of the industrial market were not well enough known, representative thermal efficiencies were n
Sagmaw ‘.
\
FItnt DETROIT
440
CHICAGO TOledoj___AcLqEYgtiAND cc
n So Bend
:
I I I
I I I
PITTSBURGH
:Lt,, Muncie Indlanapolls,
‘80 ,I, /’
, m’
/ n,
’
Columbus
, Dayton ~#cl”cl”“atl
250 ,
Inch
Fig. 16.Pipeline network for gas; distances from Centralia.
I. C. FAIR et al.
92
Table 4. Total cost of generating industrialprocess steam* in Chicago, Illinois (230miles from Centralia) Underground Casifica~ion Producer Synthesis Gas Gas SK Ga
1.55 2.46
1.70 2.13
Surface Pia”? SK
Highs caa1
LO”S ihal
2.21
2.98
0.8”
1.5”
2.45
3.23
1.09
1.79
chosen and the utilization factor varied. The trade-off of capital cost and fuel cost is clearly shown. Using the results of our study for the base case at 50% sweep efficiency, we see a cost advantage for gases from coal at lower unit sizes and utilizations. Comparison of the latest available data for surface gasification cost shows an advantage for underground gasification. Our costs must be regarded as less firm in the in situ case, however. The preferable product for this market is synthesis gas. Low-heat-value gas is penalized by high transportation and distribution costs while SPG suffers from the high cost of the upgrading process. Table 5 shows the data recalculated for an “energy park” of concentrated industrial use near Centralia. Costs involved in distributing low-heat-value producer gas still offset the slightly lower gas generation cost. Cost advantages are once more shown for gasification products at low unit size and utilization. Figure 17 shows a forecast of 1980industrial boiler sales. It may be seen from this figure that the smaller boilers, which would comprise the market for gasification products, represent a significant portion of the industrial steam market. Less is known about the demand factor for industrial steam generation: this area requires further study. We estimate that the demand factor could range from 30 to 90%, with lower numbers being more common. Implications
and conclusions
We have examined the production and marketing costs of various product options based on an underground coal gasification process using pneumatic linking in thin seams of bituminous Table 5. Total cost of generating industrial process steam* in Centralia, Illinois (an energy park concept) “nder*ro”ndGasiffcaLio” Pradueer Synthesis SPG GBS G.%S
Surface Plant SPG
Highs Coal
LawS ihal
cas Plant or vine ($/MNtx”)
1.55
1.7”
2.21
2.98
0.m
1.50
Delivered
2.06
l.QR
2.36
3.11
1.00
1.70
cast
(S;mBtu)
93
An evaluation of in situ coal gasification
o-7
E-15
16-30
31-45
46 -75
76-106
>107
MW
O-24
25-49
50-99
100-149
150-249
250-349
>350
THOUSANDS OF POUNDS PER HOlJR
steam
Etoller
capac1ry Range
Fig. 17.Forecast of industrial boiler sales-1980.
coal. Assumptions regarding the performance of the underground gasifier can be divided into those specific to the postulated process and those common to any system. We can gather the principal unknowns into the following list: gas composition, effect of parameters on heat loss, effect of heat loss on gas composition, subsidence effects, and required state of injected water. These areas remain as major uncertainties in our knowledge of underground coal gasification. Our assumptions lead to a number of conclusions regarding in situ gasification. (i) Coal-gasification products were shown to be economically preferable to coal as a fuel for small, low utilization industrial boilers. (ii) The preferable product from end-use considerations is a gas produced with oxygen. Air-produced gas has no advantage as an industrial fuel for generating steam, cannot be converted to SPG economically, and has severely limited application as a chemical feedstock. (iii) Intermediate heat value (synthesis) gas has cost advantages as an industrial fuel. It is also the most versatile to other options because of our ability to convert it to other forms. Methanol from synthesis gas is another route to a clean liquid fuel from coal. (iv) Production cost for gas produced in situ is shown to be significantly lower than for comparable gases derived from a surface process. (v) The produced gas must be at some minimum pressure near 1 mPa (150 psi) to be usable. It is advantageous to obtain a portion of this pressure at the production wellhead rather than in subsequent surface compression. (vi) Parameter studies involving seam thickness, coal reactivity, and injection pressure indicate that the thick, highly permeable, highly reactive Western coals should have significant gas production cost advantages. (vii) High pressures used in pneumatic linking increase gasification costs due to higher plant consumption, higher capital cost and penalties incurred for gas loss. (viii) Other methods of linking should be examined to determine possible cost savings. Acknowledgement-The authors wish to express their gratitude to Gulf Research & Development Company for permission to publish this paper.
REFERENCES 1. J. L. Elder, The underground gasification of coal. Chemisrryof&al Utilization, Supplementary Volume (Edited by H. H. Lowry). Wiley, New York (1%3). 2. A. D. Little, Inc., A current appraisal of underground coal gasification. NTIS, PB-209 274 (1972). 3. P. Raimondi et al., A field test of underground combustion of coal. .I. Petrol. Technol. (Jan. 1975). 4. Joint GR&DC/LLL Report, The LLL in sifu coal gasification research program in perspective. TID-26825(10 June 1975). 5. D. D. Fischer and L. S&rider, Comparison of results from underground coal gasification and from a stirred-bed producer. Presented at the National AIChE Meeting, Houston, Texas (K-20 Mar. 1975). 6. D. C. Elgin and H. R. Perks, Results of Trials of American Coals in Lurgi Pressure-Gasification Plant at Westfield, Scotland, Proceedings of the Sixth Synthetic Pipeline Gas Symposium, Chicago (28-30 Oct. 1974).
94
J. C. FAIR et al.
7. D. H. McCrea and J. H. Field, The Purification of Coal Derived Gases: Applicability and Economics of the Benfield Processes” Paper Number 2%, American Institute of Chemical Engineers, 78th National Meeting (18-21Aug. 1974). 8. J. M. Campbell, Gas Condirioning and Processing, Campbell Petroleum Series, Norman, Oklahoma (1974). 9. K. hf. Guthrie, Process Plant Estimating Eoaluation and Control. Craftsman Book Company of America, Solana Beach, California (1974). 10. 1973Joint Association Survey of the U.S. Oil and Gas Producing Industry, Section I: Drilling Costs, API Statistical Publications, Washington, D.C. (Feb. 1975). 11. S. P. Marshall and J. L. Brandt, 1974installed cost of corrosion resistant piping. Chem. Engng, October 28 (1974). 12. Pipeline economics. Oil and Gas .T.(12 Aug. 1974). 13. D. L. Bidlack to A. N. Mann, Gulf Research & Development Co. Planning and Economics Division, private communication (31 Mar. 1975and 7 July 1975). 14. G. H. Cady et al., Subsurface geology and coal resources of the Pennsylvanian System in certain counties of the Illinois Basin, Report of Investigations No. 148, Illinois State Geological Survey (1951). 15. G. H. Cady, Coal resources of Franklin County, Illinois. Circular No. 151, Illinois State Geological Survey (1949). 16. J. A. Harrison, Subsurface geology and coal resources of the Pennsylvanian System in White County, Illinois. Report of Investigations No. 53, Illinois State Geological Survey (1951). 17. E. P. DuBois, Geology and coal resources of a part of the Pennsylvanian System in Shelby, Moultrie, and portions of Effingham and Fayette Counties. Report of Inoestigations No. 156, Illinois State, Geological Survey (1951). APPENDIX
I
Basic cost data All cost data are indexed to the first quarter of 1975.Compressor capital cost data are taken from recent manufacturers’ quotations. Tankage, separators, and gas coolers come from Gulf data and assorted references.B.9Drilling and completion costs have fluctuated wildly in the last several years under demand pressures and equipment shortages; however, recent data on a large number of intiUholes, as weUas published well costs,” were used to estimate drilling costs of $17/ft (drilled, cased and cemented) plus $4000 fixed cost per injection well and $3000 for each production well. Casing is considered non-recoverable but tubing and packers used in the injection well are reused. Surface piping material costs of $0.48/kg ($0.22/lb)for carbon steel and $3.08/kg ($14O/lb)for stainless steel come from a variety of sources9.” Labor costs for installing piping were derived from a pipeline industry survey report,” 50% of this value is charged for disassembling installed piping systems. Cost of clearing, grading and building access roads, electrical substations, and water-supply systems came from Gulf data and Guthrie’s manual9 Cost data for the oxygen plant and SPG plant were provided by the Planning and Economics Division of Gulf Research & Development Company.” The SPG plant costs were based on submissions to the FPC for surface plant construction, a southern Blinoisplant site, and the gas composition data from Elgin and Perks.6 Cost and operating data for the hot carbonate gas clean-up process came from McCrea and Field.’ APPENDIX
II
Calculation of steam-generation cost Steam from coal combustion. The costs of mined coal chosen represent the relative values of high and low sulfur coal in a
spot purchase rather than a long-term contract. Transportation from the mine to an industrial area is estimated to be $O.O062/tkm ($O.O09/tonmile) and delivery charges are estimated at $5.50/t ($5/tori)))The 84% energy conversion efficiency chosen represents a steady state efficiency of coal fired steam generation. A 2% efficiency reduction for high sulfur coal is used to reflect the stack gas scrubbing energy requirement. These numbers represent maxima sincecyclic boiler loading and off-peak operation would reduce thermal efficiency. Capital and operating cost information were obtained from boiler data published in a variety of sources. The values used can be backed out of the data table if desired, using the equation for steam cost shown in the text. Flue gas desulfurization capital and operating costs were determined from data for larger units using a 0.6 scaling factor for capital. Steam from coal gas
The data used for underground coal gasification product cost are the base case; however, a 1.5m (5 ft) seam thickness was chosen. One can interpret this as representing anything from two 1.5m (5 ft) seams converted with a 50% sweep efficiency to a single 1.5m (5 ft) seam and a 100%sweep efficiency. The surface gasification plant SPG price was taken from a recent GR &DC estimate for Illinois coal using the Westfield data. Transnortation cost was determined for each gas from a detailed analysis of pipeline and compressorstation capital and operating costs. Line size used is the economic optimum of available sizes for the gas flow desired. A value of SO.O95/GJ ($O.lO/MMBtu)resulted from this analysis for SPG transport to Chicago. A distribution cost of $O.l3/GJ($O.lYMMBtu)was selected after reviewing gas-industry data. Other gas-distribution costs were scaled from natural gas data by the ratio of transportation costs previously determined. A charge of $O.O47/GJ ($O.OS/MMBtu)was added to the cost of gases containing CO to cover the cost of extra precautions required in the distribution system for safely handling a toxic gas. Synthesis gas distribution cost was 80.265iG.l($0.28/MMBtu)and producer gas distribution cost $0.48/GJ ($O.Sl/MMBtu). A steady state thermal efficiency of 82% was used for SPG conversion to steam and 80% for both producer gas and synthesis gas. Capital costs of all gas-fired boilers of the same rating were considered to be equal. Data from several sources were used to determine boiler cost variation with size. Since such boilers are generally modular, the capital cost does not change greatly with rated steam output. Annual capital charge
As annual charge of 20% of the invested capital was used for steam generation equipment. Stack-gas scrubbers, however, were charged at 17%/yr on invested capital assuming some incentive financing would be available. Gas prices used assume utility financing or some similar lower cost financing scheme will exist for the synthetic fuels industry.