From Oil Shale to.
Production of Pipeline Gas by hydrogenolysis E. B. SHULTZ, Jr., and H. R. LINDEN Institute of Gas Technology, Chicago, 111.
High pressure process yields high methane and ethane content fuel gases with low-level C o n R E C O V E R Y of oil shale organic constituents as high heating value gas was studied to determine its value as an alternative to conventional liquid products recovery. Dry, high-pressure hydrogenolysis (hydrogasification) of oil shale was accomplished as part of a program concerned with natural gas supplements and substitutes from liquid and solid fossil fuels (4,73, 74). Discovery and production of natural gas and crude oil are closely linked. Thus, conversion of solid fossil fuels to pipeline gas may become necessary if lack of economic incentives retards development of potential domestic crude oil reserves. Total U. s. natural gas supply is estimated to be 1200 trillion cubic feet, but the effective price ceiling imposed on domestic crude by imports or shale oil production may reduce production to about half the estimated ultimate value. Oil shale would then gain importance as an alternative source of pipeline gas in view of the large proved reserves.
Experimental A Colorado oil shale of the analysis
below was selected as representative of the most abundant U. S. deposits. The 1-liter Autoclave Engineers reactor used in previous batch hydrogenolysis studies (73,74)was charged with crushed shale and hydrogen at room temperature. Heating at full input (4.5 kw.) was maintained through the rising temperature portion of the run, with temperature rising a t about 9' F. per minute. Simul-
Analysis of Oil Shale" Fischer Assayb Oil, wt. % Water, wt. % Spent shale, wt. % Gas loss, wt. 70 Total Oil, gal./ton Water, gal./ton s p . gr. of oil, 60°/600 F.
+
C-H llnalysisc Mineral C Organic C Total C H Ash Mineral COZ
8.8 1.2 88.0 2.0 100.0 22.9 3.0 0.917-0.918
-
wt.yc 4.88 10.52 15.40 1.59 68.98 17.88
Sieve Analysisd
Economic Background for Oil Shale Hydrogenolysis Subject Ref. Average future recovery of natural gas ( 5 , 16) Present U. S. natural gas reserves (1) Potential domestic oil recovery ( 7 , 16) Minimum domestic oil price to recover 160 billion barrels (5) Thermal value of oil shale reserves approaches that of recoverable coal (10,12) Green River formation (Colorado) shale oil reserves (6)
U.S.S. Sieve
TTt.
+40 40-50
50-60 60-70 70-80 80-100 - 100
Total
70
0.8 25.3 20.0 19.1 16.7 13.6 4.5 100.0
-
a U. S. Bureau of Mines SBR58-40X. Average of U. S. Bureau of Mines runs 53456 and 53457 ( 1 7 ) . C Average of L-. S. Bureau of Mines runs 10291 and 10292 (17) I.G.T. laboratory No. 3910.
taneous temperature and pressure measurements were made, and gas samples were obtained at intervals throughout each run which consisted of a 128- to 152-minute period before reaching norninal temperature of 1300' F. and an additional 30-minute period at 1300' F. In all cases reaction was initiated well below 1300' F.; rapid gasification appeared to begin with the appearance of a well-developed temperature dip at 1025' F. Feed and residue shale samples were subjected to sieve analysis and to ultimate analysis for total carbon and hydrogen. Mineral carbon was drrermined gravimetrically from carbon dioxide evolved with acid by a technique employed by the Bureau of Mines Experiment Station, Laramie, Wyo. ; organic carbon was obtained by difference (17). Carbon clioxide liberation values determined from residue shale analyses were uniformly greater than values obtained from gas analysis data, because of continued evolution of carbon dioxide after runs were terminated ; conclusions concerning carbon oxides formation Jvere drawn from product gas yields and compositions. Product gas samples were analyzed with a Consolidatrd Engineering Co. Model 21-103 mass spectrometer; heating values and specific gravities were calculated from analyses assuming the ideal gas law. All gas volumes are reported as SCF (standard cubic feet at 60' F.. 30 inches of mercury absolute pressure. and saturation with water vapor). Specific gravities were calculated on a dry basis from average molecular weight of the gas referred to air of molecular weight 28.37. Initial hydrogen volumes were obtained by direct measurement; the reactor was charged with shale and VOL. 51, NO. 4
APRIL 1959
573
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INDUSTRIAL AND ENGINEERING CHEMISTRY
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P I P E L I N E GAS hydrogen to desired pressure, and hydrogen then slowly vented through a wet test meter. Use of compressibility data at room temperature permitted calculation of reactor free space when charged with shale. Product gas volumes at temperatures of 950' F. and above were calculated from observed temperatures and pressures and initial reactor free space, assuming ideal gas behavior. Previous work with coal has shown that gas volumes calculated by this method agree with wet-test meter values, with a deviation of about 3% (73). Further, the reasonably close agreement of reported organic carbon and hydrogen conversions based on computed product gas volumes, and organic carbon conversions based on residue ultimate analyses, supports the use of pressuretemperature-reactor volume measurements with assumption of ideal gas behavior,
_
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TIME
Figure 1.
ABOVE
ROOM
TEMPERATURE, MIN.
Effect of pressure on hydrogasification yield
Higher pressures increased initial ethane formation, as well as final methane yield, and reduced evolution of total carbon oxides
Effects of Pressure
At initial pressures of 340, 735, and 1710 p.s.i.g. (1215, 2430, and 5540 p.s.i.g., respectively, at 1300' F . ) >high heating value gases were produced at high organic carbon-plus-hydrogen conversions as the nominal run temperature of 1300" F. was approached; dilution with carbon oxides was not excessive and practically no liquid products were formed (Table I). The spent shale was free flowing and had virtually the same sieve analysis as the charge. Rapid attainment of high conversions of organic matter to gas (primarily methane, ethane, and propane) at temperatures of only 1200" to 1300' F. was primarily responsible for the low evolution of mineral carbon oxides (8); this differs significantly from results obtained in high-temperature retorting at low pressures in the absence of hydrogen (2, 7 8 ) . Although higher pressure would be expected to suppress carbon dioxide evolution. apparent yield and mole per cent of carbon dioxide were not affected significantly by pressure level (Figure 1). However, total yields of carbon oxides were decreased at higher pressures, reflecting the decrease in carbon dioxide conversion to carbon monoxide by the reaction CO2 Hz CO HaO, as hydrogen content of the product gas decreased. Even at the lowest pressure level, total carbon oxides content was only 22.4 mole 7 0 . (Reported nitrogen plus carbon monoxide content was primarilv the latter.) The hydrocarbon hydrogenolysis reactions and the sequence of appearance of stable intermediates in methane production from higher molecular weight carbon-containing materials (such as oil
+
-
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ance to methane aboke 1200' F., accompanied by increases in gasification of organic carbon and hydrogen. Increased hydrogen consumption at higher pressures, together with lower carbon oxide yields and higher methane yields. resulted in considerable increases in product gas heating values. For example. heating values of 792, 871, and 908 B.t.u./'SCF were observed at 1300' F. as pressure was increased from 1215 to 2430 to 5540 p.s.i.g., respectively (Table I) At the tu70 higher pressures studied, as well as in other runs carried out at 100% of stoichiometric feed ratio, gasification of organic carbon and hydrogen decreased slightly between 1200" and 1300' F.. iic
shale kerogen) corresponded closely to those observed in hydrogenolysis of petroleum oils (73) and pure compounds related to petroleum oils (74). Propane and higher paraffin hydrocarbons formed in earlier portions of each run were soon hydrogenolyzed with increasing appearance of ethane and methane. Ethane yields and concentrations in turn passed through maxima with increases in time and temperature, as methane, the stable final product, continued to increase. Maximum ethane yields were observed at 1200' F. at all pressures (Figure 1). The effect of pressure increase was to increase ethane production rate below 1200" F. and rate of ethane disappear20000 ORG CCH.0
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Effect of feed ratio on hydrogasification yield
Below 1200' F., methane formation was favored b y 5070 o f stoichiometric feed ratio, but at higher temperatures final methane yields were reduced b y decreases in hydrogen supply VOL. 51, NO. 4
APRIL 1959
575
companied by a decline in gas heating value in excess of that corresponding to increased carbon oxide formation. This indicates that insufficient hydrogen may have been present in the later portions of these runs to prevent a small amount of carbon formation from product hydrocarbons. This effect was greater a t higher pressures because of the higher hydrogen consumption characteristic of higher pressure operation.
tively large particle sizes if a practical hydrogenolysis process can be developed for moving- or fixed-bed operation. To explore this variable, two tests were made with particle size ranges differing significantly from the 40-to 140-mesh range employed. The key test (run 10) was repeated with shale of 5 to 20 mesh and 140 to 325 mesh. Only insignificant variations in gas yields and composition were observed.
Effects of HydrogenShale Feed Ratio
Commercial Possibilities
Figure 2 presents gas yield data at hydrogen-shale feed ratios of 5070 (run 1l), 100% (run lo), and 20070 (run 5) of stoichiometric requirements for conversion to methane; additional data for runs 11, 5, and run 10, the key test, are given in Table I. At temperatures below 1200’ F., extent of gasification a t 50% of stoichiometric hydrogen-shale feed ratio was approximately the same as a t higher feed ratios so that, in the absence of excess hydrogen dilution, high heating value product gas was formed earlier. However, at higher temperatures, conversions were reduced substantially by decreases in hydrogen supply, but not proportionally to reductions in feed ratio. For instance, at 1300’ F., gasification of organic carbon and hydrogen was 77% (weight) at 50% of stoichiometric, 9070 (weight) at 100% of stoichiometric, and complete a t 200y0 of stoichiometric feed ratio. Considerable vapor-phase carbon formation was indicated during the later portion of the run at 5070 of stoichiometric and none at 2007, of stoichiometric. Only limited vapor-phase carbon formation occurred late in the course of the run a t 100% of stoichiometric feed ratio, indicated by a gradual decline in conversion and product gas heating value. Pressure levels for runs 10 and 5 at 100 and 200y0 of stoichiometric feed ratio, respectively, were quite comparable, permitting direct evaluation of the effect of hydrogen concentration on carbon oxides formation. Total carbon oxide yields were about the same for these two runs, but increased hydrogen concentration at 20094 of stoichiometric feed ratio caused much greater conversion of evolved carbon dioxide to carbon monoxide. Ethane yields were increased by increases in feed ratio from 50 to 200% of stoichiometric ; however, ethane concentration was greatest a t 100% of stoichiometric feed ratio. Dilution of product gas with excess hydrogen reduced ethane concentration at 2007, of stoichiometric, and pyrolysis reactions favoring methane over ethane formation at reaction temperatures below 1300’ F. reduced ethane concentration at 50% of stoichiometric. Effects of Particle Size Range
Because oil shale size reduction is costly ( 7 7) it would be desirable to utilize rela-
576
Production of pipeline gas from oil shale may be preferable to liquid fuel production because of higher conversion of organic matter-90 to 1 0 0 ~ o (weight) for hydrogasification, compared to about 80Y0 (weight) conversion to liquid and gaseous products in conventional retorting (2)-and elimination of costly liquid product refining operations. Wydrogasification, in addition to producing a free-flowing residue containing little organic matter, also yields only negligible quantities of liquid products. This differs from oil hydrogasification (73, 74) and pyrolysis of crude shale oil ( 9 ) ,where substantial quantities of liquid by-products are formed. Absence of agglomeration problems should permit development of continuous moving- or fluid-bed oil shale hydrogasification processes. Fixed-bed operation would reduce feed preparation costs. Hydrogen requirements could be met with conventional catalytic steam reforming and carbon oxide removal processes, utilizing a portion of purified product gas for feed and fuel. Based on results with 22.9-gallon-pero stoichiometric ton shale at 50 to 1 0 0 ~ of feed ratio, about 4900 to 6600 SCF/ton of gas can be produced with 3800 to 7600 SCF/ton of hydrogen feed when gas yields are expressed in t e r m of 1000 B.t.u./SCF equivalent. Total product gas requirements for hydrogen production, including all fuel requirements, would be about 1700 to 3800 SCF/ton, leaving a net gas yield of 2800 to 3000 SCF/ton. If gas combustion retort data ( 3 ) are applicable, heat requirements for the shale processing step would be about 500,000 B.t.u./ton. Thus, with product gas used as a source of heat, a net gas yield of 2300 to 2500 SCF/ton would finally be obtained. At 50 cents per ton mining cost and 25 cents per ton crushing cost ( 7 7 ) , this would result in a raw material cost of 30 to 33 cents per 1000 SCF (million B.t.u.) for 22.7-gallon-per-ton shale. Large deposits of shale average 30 gallons per ton ( 6 )so that raw material cost could be further reduced. Existing pipeline systems and requested extensions could supply the major West Coast and Middle West marketing areas with pipeline gas produced in Colorado. With adequate storage, already under consideration by Congress, the flow of the Colorado river is adequate to provide
INDUSTRIAL AND ENGINEERING CHEMISTRY
water for a 2,000,000-barrel-per-day oil shale industry, which is equivalent to about 8 billion cubic feet per day of net pipeline gas production ( 7 7). Acknowledgment
M. A. Elliott, director of the Institute of Gas Technology, and H. M. Henry, president of the New England Gas and Electric Association Service Corp., were helpful in formulating the program. H. M. Thorne, chief of oil-shale research, Region 111, Bureau of Mines, supplied the oil shale and analyses and contributed valuable information. Batch hydrogenation tests were performed by R. F. Johnson; D. M. Mason and J. E. Neuzil provided the analytical data. References (1) Am. Gas Assoc. and Am. Petroleum
Inst., New York, and Canadian Petroleum Assoc., Calgary, Alberta, “Proved Reserves of Crude Oil, Natural Gas Liquids and Natural Gas in the United States and Canada, Dec. 31, 1957,” No. 12. ~- 1957. (2) Brantley, F. E., Cox, R. J., Sohns, H. W., Barnet, W. I., Murphy, W. I. R., IND.ENG.CHEM.44, 2641-50 (1952). (3) Cameron, R. J., Guthrie, B., Cham. Eng. Progr. 50, 336-41 (1954). (4) Channabasappa, K. C., Linden, H. R., IND.ENG.CHEM.50. 637-44 (1958). (5) Davis, W., Oil Gas J. 56, 1’05-19 (Feb. 24, 1958). (6) Donnell, J. R., U. S. Geol. Survey Bull. 1042-H, 1957. (7) Hill, K. E., Hammar, H. D., Winger, J. G., “Future Growth of the World Petroleum Industry,” Chase Manhattan Bank, New York, April 1957. (8) Jukkola, E. E., Denilauler, A. J., Jensen. H. B.. Barnet. W. I.. Murphv. W. I. R . , IN;. ENG.CHEM.45, mi-1’4 (19531. --,(9) Linden, H. R., Peck, R. E., Brooks, C. E., Miller, L. N., Shultz, E. B., Jr., Guyer, J. J., Ibid.,47, 2467-82 (1955). (10) Oil Gas J . 56, 110-11 (April 7, 1958). (11) Prien, C. H.’, Savage, j. W., Chem. Eng. Progr. 52,16J-26J (1956). (12) Rubel. A. C.. Mines M a e . (Denver) 45, 72-6 ’(October 1955). 3) Shultz, E. B., Jr., Channabasappa, K. C., Linden, H. R., IND.ENG.CHEM. 48, 894-905 (1956). 4) Shultz, E. B , Jr., Linden, H. R., Zbzd., 49, 2011-16 (1957). 5) Sohns, H. W., Jukkola, E. E., Cox, R. J., Brantley, F. E., Collins, W. G., Murphy, W. I. R., Ihid., 47, 461-4 (1955). 6 ) Terry, L. F., Winger, J. G., “Future Growth of the Natural Gas Industry,” Chase Manhattan Bank, New York, May \ - -
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1957
(17) Thorne, H. M., Bur. Mines Expt. Sta., Laramie, Wyo., private communication, February 1958. (18) Tihen, S. S., Brown, J. F., Jensen, H. B., Tisot, P. R., Melton, N. M., Murphy, W. I. R., IND.EHG.CHEM.47, 464-8 (1955). RECEIVED for review July 24, 1958 ACCEPTED October 16, 1958 Division of Gas and Fuel Chemistry, 134th Meeting, ACS, Chicago, Ill., September 1958. Study conducted as part of basic research program of the Institute of Gas Technology with funds provided by members and contributors.
