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Ind. Eng. Chem. Prod. Res. Dev. 1984,23,308-311
A Method for the Isolation of Kerogen from Green River Oil Shale Kent E. Goklen,' Ted J. Stoecker,+ and Raymond F. Baddour Massachusetts Institute of Technology, Depatfment of Chemical Engineering. CambrMge, Massachusetts 02 139
The isolation of the insoluble fraction of oil shale organic, kerogen, has been attacked with many methods, both chemical and physical, by previous workers. The present work attempts to comblne these techniques into a simple method which produces material representative of kerogen in situ. The isolatlon technique involves an acid wash with hydrochloric acid for removal of carbonates, Soxhlet extraction with a mixture of methanol and toluene for removal of soluble organics (bitumens), hydrofluoric acid treatment for removal of silicates, and reduction with lithium aluminum hydride for removal of pyrites. The ash content of the resulting kerogen is roughly 5 % , comparable to methods employing substantially longer contact times and higher temperatures. The elemental analysis of the product is similar to that of kerogen isolates in the literature. The yield of kerogen is considerably higher than that obtained by physical isolation methods.
Purpose Although interest in the synfuels has generally ebbed in the past few years, substantial interest in shale oil persists. This interest is largely due to the fact that shale oils, derived from oil shale by retorting, have a higher H/C ratio than coal-derived liquids (Keller, 1983). This greatly simplifies subsequent refining. Oil shale consists of 10-20 wt % organic matter, 75% of which is the insoluble fraction known as kerogen. While it is presently uneconomical to isolate kerogen from oil shale prior to its conversion to liquid fuel, many research uses exist for the pure material. It is the purpose of this paper to review methods of isolating kerogen from oil shale and to present a procedure used in our laboratory. Some analysis will be presented to support our belief that the given method is better suited to production of kerogen for research use than earlier methods. Introduction Oil Shale Structure and Composition. Oil shale from the Green River Formation is a complex mixture of organic and mineral substances. The mineral matter can be divided into two main categories, carbonates and silicates. The carbonates are dominated by dolomite and calcite, while the silicate minerals are primarily quartz and potassium aluminum silicates. The organics can be divided into bitumens and kerogen. The bitumens can be extracted from oil shale by using organic solvents, while the kerogens are completely insoluble. The relative proportions of all these components are given in Table I. These mineral and organic components are combined in oil shale to make a very hard and nonporous material. The presence of the organics in the shale matrix gives it resilience,so that oil shale is a much tougher material than most purely mineral substances. The assembly of these components in oil shale can be compared to concrete; the mineral substances, which are in large quantity, are analogous to the sand and gravel, while the organics act as cement, binding the other components. It is the close association of all the components, combined with kerogen's insolubility, which makes its isolation a difficult task. Kerogen Isolation Techniques. Because of kerogen's refractory nature, most techniques which attempt to produce the material in a pure form strip all other oil shale components away, leaving behind the kerogen. For this reason, it is more appropriate to speak of kerogen isolation, 'Union Oil Co., Imperial Highway, Brea, CA.
Table I. Average Composition of Green River Oil Shalea m,neral matter
-
oil shale 100 9,
- organic matter
86 %
/
1 4 90
/ \
\
carbonates
silicates
43 %
43 %
a
kerogen I1 %
bitumen 3 90
Data from Yen and Chilingarian (1976).
rather than extraction. The restrictions on such treatments are governed by the desire to maintain the chemical integrity of the kerogen; i.e., the isolated kerogen should have the same chemical structure as the kerogen in situ. Some methods which can actually extract kerogen also modify its structure. Chemical oxidation has been used by many workers, extracting fragmented kerogen from oil shale. This technique has been used in several structural investigations (Burlingame, 1969; Djuricic et al., 1971; Djuiricic et al., 1972; Randall et al., 1938; Robinson et al., 1953; Robinson et al., 1963). The oxidizing agents frequently employed include potassium permanganate, hydrogen peroxide, and chromic acid. Thermolysis has also been used to obtain a fragmented kerogen from oil shale. In the absence of any oxidizing agent, exposure to high temperatures yields low molecular weight aliphatic and aromatic hydrocarbons, as well as high molecular weight carbonaceous residue (Schmidt-Collerus et al., 1976; Schmidt-Collerus and Prien, 1976). Several techniques have been applied to oil shale, each attempting to remove a different fraction of oil shale. A review by Robinson describes most of the available techniques (Robinson, 1969). Solvent extraction of oil shale with organic solvents will remove the bitumens (Saxby, 1976). A mixture of two solvents, one polar and one nonpolar, is usually necessary for complete extraction. Use of reactive solvents and high temperatures should be avoided, as they can lead to the undesired modification of kerogen. It is also necessary that the oil shale be reduced to a small particle size, such that the solvent has sufficient access to the bitumen. Solvent extraction does not affect the mineral fraction. Incomplete solvent extraction will leave behind bitumenous material which will manifest itself as an apparent change in the properties of the remaining kerogen. Carbonate minerals can be dissolved by exposure to hydrochloric acid of moderate concentration. As with solvent extraction, it is necessary to use fine particles to ensure sufficient contact of acid with carbonates. This method produces a substantial concentration of the ker-
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Ind. Eng. Chem. Prod. Res. Dev., Vol. 23, No. 2, 1984 309
ogen in the remaining oil shale. Modification of the kerogen by HC1, e.g, chlorination, is not believed to occur for short contact times. Other acids, e.g., acetic acid, can also be used for carbonate solubilization. Silicate minerals are classically dissolved by hydrogen fluoride (Dancy and Giedroyc, 1950). Very little fluorination of the kerogen is believed to occur. It is necessary to maintain the solids in suspension and to avoid extreme high temperatures to avoid the oxidation of organics. Nitric acid is effective in removing pyrites from oil shale. However, it has been found to modify the kerogen structure. Even dilute nitric acid has been shown to cause oxidation and nitration of organics (Down, 1939; Saxby, 1976). Zinc dust and HC1 have been used to remove pyrites (Saxby, 1976),but several workers have found pyrite removal by this technique to be incomplete. Lithium aluminum hydride has been used to reduce iron pyrite by the reaction LAH
FeS2 THF FeS
+ S2-
HC1
H20
Fe2++ 2H2S
Pyrite is reacted with LAH in tetrahydrofuran. The reaction products are converted to H2S and FeC12by an acid wash, which also serves to react excess hydride (Hubbard et al., 1952; Lawlor et al., 1963). I t is possible to exploit the density and wettability differences which exist between organic-rich and organic-poor particles of oil shale (Dancy and Giedroyc, 1950; Hubbard et al., 1952; Robinson, 1969; Smith and Higby, 1960). Flotation techniques have been described for the production of an organic-rich oil shale material containing only 9% ash. The problem with such methods is that kerogen is recovered in low yields, and the bitumen must still be extracted. Because of oil shales resilience, it is dificult to obtain the particle size reduction required for the success of these methods without special equipment. Hubbard obtained kerogen concentrates with only 8.7 % ash by benzene extraction followed by acetic acid extraction and gravity separation. His method did not include a pyrite removal. His sample of oil shale yielded 78 gpt by Fischer assay, which indicates it had a much lower mineral content than common Green River shales. The acetic acid extraction lasted ten days (Hubbard et al., 1952). Robinson applied the same method to a 28.1 gpt sample of oil shale, and obtained a kerogen concentrate containing 28.4% ash (Robinson et al., 1953). Later work refined this technique to produce a concentrate with 14.3% ash (Robinson et al., 1963). Schmidt-Collerus and Prien employed a similar technique and obtained 3% ash, but with an extremely low yield. A solvent extraction followed by acid leaching yielded a 12% ash kerogen from the same lot of oil shale (Schmidt-Collerus and Prien, 1976). In general, kerogen yield decreases with decreasing ash content of the kerogen isolate (Robinson, 1969). Smith and Higby combined an acetic acid wash with an n-cetanelwater grinding and partitioning treatment to obtain a kerogen concentrate with 15.24% ash (Smith and Higby, 1960). Pyrites were not removed. No yield was given, but it has been observed that similar techniques give low yields. Robinson et al. (1960) used the same technique with similar results. Djuricic et al., used a combination of HC1 and HF treatments with a benzene/methanol solvent extraction on Green River shale. The exact details of their procedure were not published. The resulting kerogen isolate contained 23.8% ash. They did not attempt to remove the pyrites (Djuricic et al., 1971,1972). Saxby used successive HC1, HF, LAH, and HNOBtreatments on samples of oil shale from several locations within Australia (Saxby, 1976).
Dancy employed a similar sequence, substituting a Zn/HC1 treatment for removal of pyrites, to oil shales of French, English, and South African origin (Dancy and Giedroyc, 1950). Burlingame et al., extracted Green River shale with benzene/methanol before acid treatment. Acid washes were performed twice with a 1:l mixture of HCl:HF, lasting two days each time. This was followed by a Zn/HC1 treatment for pyrite removal. They proceeded to solubilize parts of the kerogen, without presenting analysis of the product of the kerogen isolation procedure (Burlingame and Simoneit, 1969; Burlingame et al., 1969). Smith and Robinson et al. used similar HC1-HF treatments to obtain kerogen with ash content as low at 5% (Robinson et al., 1963; Smith and Higby, 1960). No pyrite or bitumen removal was used. The contact time of acid with oil shale was not stated. Considering the low ash content obtained without pyrite or bitumen removal, one might suspect that long contact times and/or high temperatures were employed. Laboratory Methods for Kerogen Isolation The guidelines which were applied in combining the existing treatments into a kerogen isolation method for our laboratory included the following: (a) The integrity of kerogen's molecular structure must be maintained. Only slight modifications could be tolerated. (b) Kerogen must be recovered from GreenRiver oil shale in high yield and with low ash content. (c) The method should be as simple as possible. It was desired to perform the isolation with commonly available equipment. (d) The entire method should not require more than two or three days, including drying steps. The method developed included an acid treatment of carbonates, a solvent extraction for removal of bitumens, a hydrogen fluoride treatment for removal of silicates, and an LAH reducing treatment for removal of pyritic sulfur. The exact procedure follows. Starting with roughly 250 g of oil shale, which has been milled to pass through a 100-mesh sieve, the procedure is as follows. Carbonate Mineral Removal. (1)Place oil shale in 4-L beaker. (2) Add 1L of 3 N HC1. (3) Heat with stirring to 65-70 "C. (4) Continue heating and stirring for 1h. (5) Vacuum filter, rinsing with distilled water until pH of water exiting filter is same as water used for rinse. (6) Repeat steps 1,2,3,4, and 5. (7) Dry filter cake in vacuum oven at 65 "C. (8) Re-sieve through 100 mesh. Bitumen Removal. (9) Place in extraction thimble rinsed with 3:l toluene to methanol. (10) Insert thimble in Soxhlet extractor which is charged with 800 mL of 3:l toluene to methanol mixture. (Make sure to use boiling chips.) (11)Turn heating mantel ON, and adjust powerstat so that cycle time in extractor is roughly 5 min. (12) Run Soxhlet extractor for 24 h. (13) Turn heating mantel OFF. (14) Remove thimble from extractor and dry at 65 "C in vacuum oven. Silicate Mineral Removal. (15) Transfer contents of thimble to 1-L plastic beaker. (16) With extreme caution, add 1 L of 1:l:l H20:HC1:HF solution. (17) Heat with stirring to 65 "C and maintain for 1 h. (18) Vacuum filter, quickly, and dilute filtrate with water to prevent etching of flask. (19) Repeat steps 15, 16, 17, and 18. (20) Rinse with several liters of distilled water and filter. (21) Dry at 65 "C in vacuum oven. Pyrite Removal (May Be Omitted for Low-Pyrite Shales). (22) Transfer dried solid to 1000-mL 3-neck flask, with roughly 7 g of lithium aluminum hydride (LAH). (23) Fit with refluxing condenser and filling funnel. (24) Slowly add 500 mL of tetrahydrofuran (THF),
Ind. Eng. Chem. Prod. Res. Dev., Vol. 23,No. 2, 1984
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Table 11. Oil Shale from the Mohogany Marker. Elemental Analysisa % carbon % hydrogen % nitrogen % sulfur % pyritic S % sulfate S % organic S % chlorine % ash
21.82 2.05 0.54 0.99 0.58 0.01 0.40 0.21 61.46 1.13
HIC a
Table 111. Kerogen Elemental Analysisa
(Dryand Ash Free Basis) % carbon % hydrogen % nitrogen % sulfur % pyritic S % sulfate S % organic S % oxygen % chlorine
Analysis by Galbraith Laboratories of Knoxville, TN.
200
80
R
Key -
1 ) O r i g i n a l Sample 3)Soxhlet E x t r a c t i o n wl
a
I
MeOH-To1 uene 4)HF-HC1
Leaching
5)LAH Reducing T r e a t m e n t
50
0
1
2
3
4
5
Treatment
Figure 1. Weight loss on kerogen isolation.
and reflux 30 min. (25) Vacuum filter. This is a tricky step; the mixture is quite messy and gives off disagreeable gases. Final Washing. (26) Transfer to 1-L beaker and add 500 mL of 3:l H 2 0 to HC1 solution. (27) Heat to 65 “C with stirring and maintain 1h. (28) Vacuum filter, rinsing with several liters of distilled water. (29) Vacuum dry at 65 “C. All work should be performed in a well-vented hood. Great care should be taken with solutions of HF and with LAH. Characterization of Kerogen Product Oil shale was obtained from TOSCO Corporation. It was mined from the Green River Formation, from a point in the vicinity of the mohogany marker. The Fischer assay of several samples gave an oil yield of 36.65 f 0.45 gpt. An elemental analysis of this material, performed by Galbraith Laboratories of Knoxville, TN, is given in Table 11. The average weight loss which occurred with each one of the isolation steps is presented in Figure 1. From these data, we can calculate that our oil shale contains 32.9% carbonates, 41.9% silicates, 1.7% bitumen, and 23.0% kerogen. This is comparable with the average literature values presented earlier when one considers that the oil shale used was slightly richer than average (an average yield being 28 gpt) and that a few percent of the weight given here as kerogen was shown by elemental analysis to be residual ash, which would contribute to the carbonate and silicate percentages. The results of elemental analyses performed on kerogen isolated by this technique are given in Table 111. The two samples were isolated by two different workers, one year apart. Differences in the analyses can be attributed to the inhomogeneity of oil shale, slight differences in the techniques of the different workers, and inaccuracy of the elemental analysis. The large difference in the chlorine content of the two samples is possibly due to insufficient
sample 1
sample 2
78.69 10.63 2.19 1.66 0.10 0.01 1.55 6.41 0.42
74.41 10.67 3.33 1.61 0.09 0.07 1.45 8.51 1.47
Analysis by Galbraith Labs of Knoxville, TN.
rinsing of the second sample, allowing chloride salts to remain in the sample. It is expected that the low chlorine content of the f i s t sample can be obtained. Pyritic sulfur, which is originally present in quantities roughly equal to that of organic sulfur, has been almost completely removed. Inaccuracy of the oxygen analysis does not allow a meaningful comparison of O/C before and after the LAH treatment. The H/C ratio of the isolated kerogen is much higher than that of the untreated oil shale. This emphasizes the aliphatic nature of kerogen and the aromatic nature of bitumen. The ash content of the kerogen isolates from four repetitions of this procedure ranged from 2.5 to 7.9%, averaging 5.6%. The persistence of ash in the isolated kerogen supports the model of oil shale in which organics are the continuous phase which bind together a discrete mineral phase. By this model, it is conceivable that kerogen could completely shield some mineral particles, preventing complete removal of the minerals by HC1 and HF. These results compare favorably with the results of earlier workers. The techniques employed are much simpler and require less equipment than density gradient, n-cetanelwater partitioning, and other physical methods (Robinson et al., 1953; Schmidt-Collerus and Prien, 1976; Smith and Higby, 1960). The yield of kerogen obtained by this method is also much greater than that obtained by the physical methods, when similar reductions in mineral content are obtained. The method described also appears superior to earlier chemical methods (Robinson et al., 1963; Smith and Higby, 1960), in that it produces a low ash kerogen which is also free of pyritic sulfur. Furthermore, the relatively short contact times and moderate temperatures used during the acid treatments result in a much more convenient process than has been previously reported, while minimizing modification of the kerogen. Registry No. Pyrite, 1309-36-0. Literature Cited Burlingame, A. L.; Haug, P. A.; Schnoes, H. K.; Simoneit, B. R. “Fatty Acids Derived from the Green,,River Formation Oil Shale by Extractions and Oxidations-A Review“, Advances in Organic Geochemistry”; Pergamon Press: Oxford, 1989. Burlingame, A. L.; Simonelt, B. R. Nature (London) 1969, 222, 741-7. Dancy, T. E.; Gledroyc, V. J . Inst. Pet. 1950, 36,593-803. Djuricic, M.;Vitorovic, D.; Andresen, B. D.; Hertz, H. S.; Murphy, R. C.; Preti, 0.; Biemann, K. “Acids Obtained by Oxidations of Kerogens in Ancient Sediments of Different Geographlcai Origin”, “Advances in Organic Geochemistry”; Pergamon: Oxford, 1972; p 305. Djuricic, M.;Murphy, R. C.; Vltorovic, D.; Biemann, K. Oeochim. Cosmochim. Acta 1971, 35, 1201-7. Down, A. L. J . Inst. Pet. 1939, 25, 230. Hubbard. A. B.; Smith. H. N.; Heady, H. H.; Robinson, W. E. U.S. Bureau of Mines, Report of Investigation No. 4872, 1952. Keiier, 0. “Frontlers of Chemical Engineering in the Oil Industry”, Warren K. Lewis Lecture presented at MIT, Cambridge, MA, April 15, 1983. Lawlor, D. L.; Fester, J. I.; Robinson, W. E. Fuel 1963, 4 1 , 239-44. Randall, R. 8.; Benger, M.; Groocock, C. M. Proc. R . Soc. London, Ser. A 1938, 165,432-52. Robinson, W. E. “Isoiatlon Procedures for Kerogens and Associated Soluble Organlc Materials”, Chapter 8 in “Organic Geochemistry”; Egiinton, G.; Murphy, M. T. J., Ed., Springer-Verlag, New York, 1989.
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311
Schmidt-Coiierus, J. J.; Prlen, C. H. “Investlgatlons of the Hydrocarbon Structure of K e r w n from 011 Shale of the Green River Formation”, I n “Science and Technology of Oil Shale”, Yen, T. F., Ed., Ann Arbor Sdentlflc: Ann Arbor, 1976. Smith, J. W.; Hlgby, E. W. Anal. Chem. 1060, 32, 1718-9. Yen, T. F.; Chlllngarlan, c. V. “Introduction to Oil Shales”, Chapter 1 In “Oil Shale”; Yen, T. F.; Chlllngarlan, G. V., Ed.; Elsevier: New York, 1976.
Robinson, W. E.; Heady, H. H.; Hubard, A. B. Ind. Eng. Chem. 1053, 45(4), 788-91. Robinson, W. E.; Lawlor, D. L.; Cummins, J. J.; Fester, J. J. “Oxidation of Colorado Oil Shale”, US. Bureau of Mines, Report of Investigations No. 6166, 1983. Saxby, J. D. “Chemical Separation and Characterization of Kerogen from Oil Shale”, I n “Oil Shale”; Yen, T. F.; Chllingarian, G. V., Ed., Elsevler: New York, 1976. SchmkltCdierus,J. J.; Bonomo, F.; Gala, K.; Leffler, L. ”Polycondensed A r e matlc Compounds and Carcinogens In the Shale Ash of Carbonaceous Spent Shale from Retorting of Oil Shale”, In ”Science and Technology of 0 1 1 Shale”, Yen, T. F., Ed., Ann Arbor Scientific: Ann Arbor, 1976.
Received for review October 31,1983 Revised manuscript received December 8, 1983 Accepted December 27, 1983
Long-Time Dynamic Compatibility of Two Ethylene Propylene Elastomers with Hydrazinet Cllfford D. Coulberl, Edward F. Cuddlhy, and Roberl F. Fedorr’ Jet Propulsion Laboratory, California Institute of Technology, Pasadena, Callfornk 9 1 103
A test method is described for predictlng the long-time survivability of elastomers in hydrazine under dynamic stressing conditions. The method selected Is based upon the existence and approximate invariance of a “physical property surface” relating the mechanical response of the elastomer In terms of stress, strain, time, and temperature. The property surface was generated for two selected elastomers (EPT-10 and AF-E-332). A novel carousel testlng tank was designed to allow sequential testlng of eight tensile specimens immersed in IiquM hydradne within a constant-temperature water bath. The test procedure and data reduction methods used to generate the property surface are described. The utility and validlty of these results applled to fatigue and flexure loading to these elastomeric materials over long-time periods are discussed.
Introduction Elastomeric materials in contact with liquid hydrazine may experience changes in physical properties as manifested by swelling, reduction in tensile strength, and possible leaching of constituents (Coulbert and Yankura, 1972; Martin et al., 1971). When these elastomers are employed as components subject to cyclic loading such as propellant tank bladders or diaphragms, it is important also to be able to predict their long-time survivability under dynamic stressing conditions in hydrazine. This paper describes a technique for characterizing elastomeric materials in liquid hydrazine during short-time tests to provide a basis for predicting the useful life of bladders or diaphragms subject to multiple propellant expulsion cycles over long time periods. The method is applied to those candidate elastomers which have survived a preliminary compatibility examination, typically static immersion at various temperatures in hydrazine with inspection for visible evidence of incompatibilities, and measurements of any swelling or softening of the elastomer (Boyd et al., 1965). In normal practice, the elastomers surviving the compatibility screening are removed from the hydrazine and tested for changes in tensile strength, modulus, elongation-at-break, etc. However, this approach only evaluates changes from immersion, if any, by comparison of properties before and after, but does not provide information on the level of elastomeric properties while in the hydrazine
environment, nor give information which directly allows for a prediction of dynamic lifetime. Method for Predicting Long-Time Behavior The approach selected as a bisis for predicting long-time behavior was based on the existence and approximate invariance of the tensile property surface for elastomers. The concept of the property surface is based on the fact that the mechanical response of an elastomer can be considered in terms of the three variables, viz., stress (a), strain (E), and time (t),and hence a convenient representation is an analytic surface in stress, strain, and time space. The effect of temperature is incorporated into the time scale by the relationship log t / u T , where the value of log uT is the experimentally determined time-temperature shift factor. The development of a tensile property surface which relates these parameters by a single analytic surface with a single rupture failure boundary is described by Landel and Fedors (1964). A typical tensile property surface for Viton B rubber in air taken from the reference is shown in Figure 1. The surface is conveniently generated by measuring the uniaxial stress-strain response of the given elastomer as a function of strain rate and temperature. Typically, it is necessary to test the elastomer at about 10 different strain rates at each of 10 to 15 test temperatures. Although this represents a considerable expenditure of time and effort, knowledge of the surface is of fundamental importance in understanding and predicting the mechanical response of an elastomer. The response of an elastomer to any uniaxial input will simply be a path traced out on the surface. For example, the path traced out during a creep experiment (i.e., constant load) starting at point A in Figure 1and terminating at the point B will be the curve AB which is generated by the intersection of this surface with a plane parallel to the
‘This paper representa one phase of research performed by the Jet Propulsion Laboratory, California Institute of Technology, sponsored by the Materials Division of the NASA National Space Flight Center, Huntsville, AL, and performed under NASA Contract No. NAS7-100. 0196-4321/84/1223-0311$01.50/0
0
1984 Amerlcan Chemical Society
