Energy & Fuels 1989,3, 216-223
216
Water Generation during Pyrolysis of Oil Shales. 1. Sources Thomas T. Coburn,* Myongsook S. Oh, Richard W. Crawford, and Kenneth G. Foster Lawrence Livermore National Laboratory, P.O. Box 808, L-207, Livermore, California 94550 Received September 30, 1988. Reuised Manuscript Receiued November 28, 1988 Water formation has an impact on both the chemistry and energy balance in an oil shale retort. Quantitative measurements of real-time water release as oil shale is heated have not been available previously. We have developed a mass spectrometric method and have applied it to the study of water evolution during batch pyrolysis of oil shale in a small thermal-gradient vessel. We have investigated a Devonian oil shale (Kentucky, New Albany Shale) and a Green River Formation oil shale (Colorado, Mahogany Zone). Precursors of pyrolysis water are different for these oil shales since they differ in mineralogy and kerogen structure. Each of the following types of water contributes to a greater or lesser extent: (a) free water; (b) water from hydrated minerals; (c) water from the reaction of iron compounds with H2S; (d) water from elimination of organic oxygen; (e) equilibrated water. Pyrolysis of acid-leached Green River oil shale and Fischer assay water release provide additional details. We have applied our methods to an Israeli oil shale and compared the results to a previous report. An appendix with quality-assurance results is included.
Introduction Oil shale retorting generates shale oil, gas, water, and a spent shale consisting of residual char and inorganics. Because shale oil is the product of value, its formation has been thoroughly investigated. The formation of noncondensable gases is also well understood. We have reported use of a mass spectrometer (MS) to monitor the gases evolved during batch retorting;'T2 others have reported similar experiments with Fourier transform infrared (FTIR) dete~ti0n.b~ However, water generated during retorting has received little attention, even though sources and amounts of pyrolysis water must be known to carry out a satisfactory energy b a l a n ~ e ;early ~ ? ~ water release adds significantly to gas flow, perhaps resulting in self-fluidization under certain flash-pyrolysis conditions; and details of water release are needed to confidently use a new detector that measures isothermal oil shale pyrolysis kinetics.' We took an MS method developed for gas-evolution studies and modified it by keeping the detector and inlet lines above 125 "C, so that condensables such as water vapor could be detected. We implemented an accurate water-calibration method and, for the first time, obtained quantitative water-evolution data as we pyrolyzed oil shale. Experimental Procedures Materials. Oil shales studied were as follows: a Devonian oil shale from the New Albany Shale high-grade zone, obtained from Bullitt County, KY;'s2 a Colorado oil shale from the Mahogany Zone of the Green River Formation, obtained from the Anvil Points mine;2s8an Israeli shale from a core sample designated (1)Coburn, T.T.; Crawford, R. W.; Gregg, H. R.; Oh, M. S. In Proceedings, 1986 Eastern Oil Shale Symposium; Kentucky Energy -. Cabinet Laboratory: Lexington, KY, 1987;pp 291-302. (2)Oh, M. S.;Coburn, T. T.; Crawford, R. W.; Burnham, A. K. In Proceedings of International Conference on Oil Shale and Shale Oil; Chemical Industry Press: Beijing, 1988; pp 295-302. (3)Solomon, P. R.; Carangelo, R. M.; Horn, E. Fuel 1986,65,650-62. (4)Carangelo, R. M.; Solomon, P. R.; Gerson, D. J. Fuel 1987,66, 960-7. (5)Camp, D. W. In 20th Oil Shale Symposium Proceedings; Colorado School of Mines: Golden, CO, 1987;pp 13C-44. (6)Camp, D. W.In Proceedings, 1987Eastern Oil Shale Symposium; Kentucky Energy Cabinet Laboratory: Lexington, KY, 1988;pp 353-63. (7)Coburn, T.T.; Taylor, R. W.; Morris, C. J.; Duval, V. In Proceedings of International Conference on Oil Shale and Shale Oil; Chemical Industry Press: Beijing, 1988; pp 245-52.
0887-0624/89/2503-0216$01.50/0
EF'E-79, for which analysis results are available in an LLNL compilation? The particle size range of material was -20 to +70 mesh; fines were pressed, crushed, and resieved. Before being retorted, oil shale samples were vacuum-dried overnight or equilibrated 10 days a t 75% relative humidity. We prepared carbonate-free Green River oil shale by acid leaching -200 mesh shale for 5 days at 20 "C under N2with 6 N HCl. After isolation, washing, and vacuum drying,the material was pressed into pellets, crushed, and sieved to -20 to +70 mesh. Batch Pyrolysis. To obtain water-evolution profiles, specimens were heated from 50 to 900 "C at 4 "C/min with argon sweep a t 185 cm3/min (STP). The retorting procedure was similar to that of our earlier studies for which a batch retort such as that shown in Figure 1A was ~ s e d . ' * ~However, *~ for this study we pyrolyzed 25-g samples in the small thermal-gradient vessel shown in Figure 1B. Heat was applied both internally, by a center Cal-rod heater, and externally, with a tube furnace. The heaters used a single heating ramp, computer controlled with thermocouple feedback; internal and external furnace temperatures matched to f 4 "C. For uniform heating, the vertical tube furnace had the heating element wound more tightly at the ends than at the enter.^ We removed heavy oil with a 50-cm3 trap filled with packing and held at between 125 and 140 "C. Some mixing was allowed in the trap to improve efficiency, but the trap's size assured nearly plug flow. A box oven heated the valves, heavy-oil trap, and connectors; transfer lines and the MS inlet system were warmed to 150 f 10 "C by using heat tape. Although condensation is of less concern at low pressure, the MS instrument from source to detector was held at 100 f 20 "C. Adsorption-desorption was thus minimized, and slight temperature variations ("cold spots") could be tolerated. Fischer assay-type (FA) experiments were carried out with an ASTM D3904 heating schedule (50-500 "C a t 12 OC/min with 20-min hold);1° the gas needed to sweep products to the MS instrument was introduced a t the exit of the retort vessel, and pyrolysis was autogenous. We used a modification of the ASTM D3904 method that allowed us to vary experimental conditions We over a wide range with good repeatability (fl% for retorted 140-g specimens of Colorado oil shale that had been (8)Cena, R. J.; Mallon, R. G. In 19th Oil Shale Symposium Proceedings; Colorado School of Mines: Golden, CO, 1986;pp 102-25. (9)Singleton, M. F.; Koskinas, G. J.; Burnham, A. K.; Raley, J. H. Assay Products from Green River Oil Shale [Report]; UCRL-53273, Rev. 1; Lawrence Livermore National Laboratory: Livermore, CA, 1986. (10)Oil from Oil Shale (Resource Evaluation bv the USBM Fischer Assay Procedure). ASTM Book of Standards; Pak 31;ASTM: Philadelphia, PA, 1980;D3904-80.
0 1989 American Chemical Society
Pyrolysis of Oil Shales
Energy & Fuels, Vol. 3, No. 2, 1989 217 Indented Top
100-gFrit
Thermocouple Well
0 Thermocouple Guide
B
Figure 1. (A) Large and (B) small thermal-gradient retort vessels for batch pyrolysis of oil shale. 0.8 h
E I
1 J
400
600
800
Temperature, " C Figure 3. Water evolution from Colorado oil shale (Mahogany Zone) with and without an acid leaching that e l i i a t e s carbonate minerals (182 cm3/min sweep; 4 OC/min heat up).
U
A
200
t
I
,
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Table I. Water Yield by Fischer Assay (FA) and by Mass Spectrometry (MS; 50-550 OC at 4 OC/min) amt of wateP oil shale FA MS Devonian 2.3 2.6 Colorado 1.5 1.5 Israeli 5.4 4.6 "In g of water/100 g of oil shale.
0.04 0
200
400
600
800
Temperature, "C Figure 2. Water evolution from Devonian oil shale (Kentucky, U.S.)at 4 OC/min heat-up with 185 cm3/min argon sweep. Calibrations during the experiment (0) and the calibration before the experiment (- - -) are shown. vacuum-dried a t ambient temperature for 18 h. Our assays matched those from an outside analytical laboratory (J&A Assoc. provided the ASTM D3904 assays; repeatability was &2%). Temperature Calibration. For temperature measurement, we used calibration sheathed thermocouples (K-type) that were inert to H2S and H2 over the temperature range of the experiments. They retained their calibrations, and accuracy was f l OC. For experiments using the retort vessel of Figure lB, the thermocouple for measuring sample temperature was sealed into an open stainless-steel guide a t the specimen's midpoint. MS Method for Real-Time Determination of Water. Our experimental techniques have been outlined in considerable detail in earlier papers.'8 We use an ELMS method with 70-eV ionizing voltage. To determine water, the triple quadrupole MS instrument, operating in parent-only or MS mode, monitored m / e 18. The MS instrument sampled effluent gas, which was obtained through a capillary inlet. The computer checked the secondary electron multiplier (SEM) every 10 ps during 0.03-0.1 s a t each mass and averaged out noise. Argon, with flow maintained by a precision mass flow controller a t 185 cm3/min (STP), was the internal standard needed to determine flow of evolved components. The argon served as an internal sensitivity reference and was used to correct results for instrument drift and instability. We calibrated for water by sweeping a series of thermostated (30 "C) saturated salt solutions with argon.
Results and Discussion Water-Evolution Profiles. Instantaneous water generation (rate of water evolution) as a function of temperature provides the details of water release during oil shale pyrolysis. Figures 2 and 3 show significantly different water-evolution profiles f r o m t w o oil shales heated at 4 OC/min. The ordinates of the figures have been scaled to
Table 11. Approximate Composition of the Oil Shales (wt %) component type formula Devonian Colorado kerogen C*HyN,S, 13.9 13.4 quartz SiOz 30 17 analcime Na(A1SizO6).HZ0 12 feldspars orthoclase KA1Si308 9 3 albite NaA1Si308 7 buddingtonite NH4A1Si308.1/zHz0 3.5 clays illite KA14(A1Si,0m)(OH)4 22 4 kaolinite A1&010(OHh 8 0.4 Mgdl~Si3010(OH)~ 2 chlorite mixed clays 4.8 carbonates Ank. dolomite Mgo.ssCaFeo,16(C0& 2 26 calcite CaC03 13 siderlite FeC03 0.7 pyrites FeS2 7.6 0.7
account for more water generated from the "wet" Devonian oil shale than the "dry" Colorado oil shale. Assay retort water released b y these oil shales and one additional sample are given i n Table I (assays from a commercial laboratory). Water formed between 50 and 550 O C , obtained b y integrating water-evolution profiles, is also given. Agreement of the methods is within the limits of repeatability, and accuracy of the MS method m a y be superior. Sources of Water from the Oil Shales. Differences in water-evolution profiles of these oil shales result mainly from differences i n kinds and amounts of hydrous minerals. Table I1 shows representative mineral analyses. Data were selected f r o m published tabulations (Devonian5,'' and Colorado6J2J3); numbers have been adjusted to (11) Mason, G. M.; Spackman, L. K.; Leimer, H. W. In Proceedings,
1984 Eastern Oil Shale Symposium; Kentucky Energy Cabinet Laboratory: Lexington, KY, 1985;pp 393-400. (12)Mason, G. M.;Spackman, L. K.; Williams, J. D. In 17th Oil Shale Symposium Proceedings; Colorado School of Mines: Golden, CO, 1984, pp 121-32.
(13)Engler, P.;Iyengar, S. S. Am. Mineral. 1987,72, 832-8.
Coburn et al.
218 Energy & Fuels, Vol. 3, No. 2, 1989
match our elemental analyses and acid-evolved-COzdeterminations. Oil shale pyrolysis water can be separated into five broad categories: (a) free water; (b) water from inorganic hydrates; (c) water from reaction of H2S with iron compounds; (d) water from elimination of organic oxygen; (e) equilibrated water. Oil shales have precursors of each water type in differing amounts, and we report here single examples from two huge, variable deposits. Water-evolution profiles of each change in response to natural variations in grade and mineral-matter composition. (A) Free Moisture. Oil shales that contain a sizable fraction of clay minerals release large amounts of surface water upon heating. Illite, montmorillonite, and mixed clays give thermogravimetric analysis (TGA) traces that show significant water release near 100 OC.14 The Devonian shale's surface moisture is consistent with a high clay mineral content (see Table 11). Handling had an important influence on the surface water liberated from *as-received" oil shale specimens. A range of f30% is usual for surface-moisture analyses of clay mineral standards.14J5 We observed a similar variation in free water (&30%; five experiments) despite efforts to standardize handling. Lack of surface water from Colorado oil shale is consistent with the near absence of smectitic clay minerals in the shale. Figure 3 is from a specimen equilibrated a t 75% relative humidity; it may have had more surface moisture than it would have had in a dry Colorado setting. (B) Inorganic Hydrates. Many salts evolve water just above 100 OC, but this water often appears only as a shoulder or inflection on a surface moisture peak in the profile (see Figures 2 and 3). Some water of hydration may be associated with sulfur-oxygen anions that form from pyrite by air oxidation.16 Repeatability was too poor to prove conclusively a cause-and-effect relationship between air oxidation and water of hydration, but the following qualitative observations support this possibility. Israeli oil shale with 3.2% pyrite and much air exposure released more water between 100 and 150 "C than did Devonian shale with 7.6% pyrite and minimum air exposure; Colorado oil shale with only 0.7% pyrite and minimum exposure released the least water of this type. Colorado oil shale usually contains a trace of nahcolite, NaHC03, which may be responsible for some of the low-temperature water seen in Figure 3. Liberation of firmly held water of hydration as a broad band centered at about 300 "C is a distinctive feature of the water-evolution profile of Colorado oil shale (Figure 3). Analcime (analcite) is primarily responsible for this water"-about 15% analcime would account for all the water that we observed; wet chemical analysis indicated &lo% analcime. Quartz is not hydrated, but it has the potential to release some water in this temperature range. While quartz sand is very dry, usually evolving less than 0.2% water, silica gel loses a substantial amount of water.l8 Quartz may be responsible for the small amount of water evolved from (14)Van Olphen, H., Fripiat, J. J., Eds. Data Handbook for Clay Minerals and Other Non-Metallic Minerals; Pergamon Press: Oxford, U.K., 1979. (15)Mielenz, R. C.; Schieltz, N. C.; King, M. E. In Proceedings of the 2nd National Conference on Clays and Clay Minerals; Swineford, A., Plummer, N., Eds.; National Academy of Sciences-National Research Council; Publication No. 327;NRC: Washington, DC, 1954;pp 285-313. (16)Coburn, T.T.;Barron, L. S. In Proceedings, 1984 Eastern Oil Shale Symposium; Kentucky Energy Cabinet Laboratory: Lexington, KY, 1985;pp 91-8. (17)Johnson, D. R.; Young, N. B.; Robb, W. A. Fuel 1975,54,249-52. (18)Lazarev, V. B.; Panasyuk, G. P.; Budova, G. P.; Voroshilov, I. L. J. Therm. Anal. 1982,23,73-81.
Devonian oil shale between 200 and 400 "C. Dawsonite, NaA1(OH),CO3, and trona, NazC03.NaHC03.2H20,can dehydrate and decompose in this temperature range. Absence of narrow evolution peaks due to such reactions and of the C02 associated with decomposition rules out these minerals as important sources of water from our Green River oil shale sample. (C) Acid-Base Chemistry of Iron Compounds. The reaction of iron compounds with H2S may be a minor source of water. The siderite reaction (reaction 1)is repFeC03 + H2S FeS + C02 + HzO (1)
-
resentative, although ankerite or iron oxide might be more important reactants. Some HPSforms on the leading edge of kerogen decomposition. Certain C-S bonds (nonthiophenic) are weaker than C-C bonds, so organic matter liberates some H2S in the early stages of pyrolysis. Also, those first-formed pyrolysis intermediates and the pyrobitumen include powerful hydrogen donors that may reduce some pyrite to give HPS. Sufficient C02is expelled for reaction 1to account for the small amount of water not due to analcime that Colorado oil shale evolves in the 400-500 "C temperature range. However, there is no correlation between water and COPrelease from Devonian shale, so water release from iron carbonates must be unimportant in this case. Decomposition of carbonate minerals without water release may occur as an HzS-catalyzed reaction in this temperature range. Magnesium oxide could form in this way. Iron oxides, with iron at a higher oxidation state than in pyrrhotite, may or may not be stable under the strongly reducing conditions of oil generation (reducing agents even more reactive than H2 apparently are present). (D) Organic Oxygen. Dehydration of organic matter is a minor contributor to retort water. Organic water release is not well separated from water formed by reaction 1. Relatively weak C-0 bonds and the presence of hydrogen donors capable of reducing oxidized compounds account for water produced from kerogen. The chemistry is analogous to that of H2S formation from organic sulfur species. Devonian oil shale has a water-evolution peak centered near the temperature of maximum oil production a t 440 "C (see Figure 2). Oil generated from this kerogen is richer in oxygen compo~nds.'~The Colorado kerogen apparently has less organic oxygen, or the organic oxygen is mainly of types not readily susceptible to elimination as water. About 0.2 g/100 g of oil shale is the maximum water expected from organic sources (the sample is about 10% kerogen and oxygen is present in kerogen at the percent level). Thus, for a water peak due to organics with a width at half-height of 100 "C, the maximum rate of water release would be only 0.1 cm3/(min g). It is no surprise, then, that water evolved from kerogen is hardly visible in Figure 3; Figure 2 is the exceptional case, but the water may be due, in part, to other sources such as iron oxides. (E) Equilibrated Water. Above 550 "C, water evolution is no longer totally source-related, independent of other products. The water gas shift equilibrium is established, and the concentrations of HP,C02, and CO define the water content of the gas:
Figure 4 shows the equilibrium ratio calculated by using (19)Greenwood, G. J. In Abstracts of the 30th Annual Conference on Mass Spectrometry and Allied Topics; ASMS: Honolulu, HI, 1982;pp 771-2.
Pyrolysis of Oil Shales 800
Energy & Fuels, Vol. 3, No. 2, 1989 219
700
600
550
500
450
Table 111. Water from Colorado Oil Shale by Fischer Assay (FA) amt of water"
Temperature, " C
c
Theory
+,,,,'
,,'"
!
run 1 2 3
conditions trapped vapor total autogenous Fischer assay, 12 OC/min 1.07 1.07 MS, 185 cm3/minsweep to cold trap 0.82 0.14 0.96 MS, 185 cm3/min sweep, no trap 1.08 1.08
"In g of water/100 g of oil shale.
0.9
1 .o
1.2
1.1
lOOO/Temperature,
K
1.3 -1
1.4
-
Figure 4. Water gas shift reaction equilibrium, CO + HzO C 0 2 + H,,for components produced during 4 "C/min pyrolysis of Devonian oil shale in the large thermal-gradient vessel of Figure 1A.
experimental data obtained from pyrolysis of Devonian oil shale in the large thermal-gradient retort vessel.' For this experiment, H2 (6 ~ 0 1 % was ) added to the sweep gas to improve the accuracy of our H2and CO analyses. Minerals (particularly iron compoundsp0)and the hot metal walls of the retort catalyze reaction 2. Catalyst content and accessibility determine the temperature at which equilibrium is established. For Devonian shale, with its high iron content, the temperature is slightly less than 550 "C. The water gas shift reaction also controlled water release from Colorado oil shale at about 550 "C, when the retort was of stainless steel. The water gas reaction has an impact on water evolution only if Cop, H2, and CO are all present in amounts comparable to H20. An oil shale such as that from Colorado, which releases a lot of C 0 2 as mineral carbonates decompose, has water-evolution and COP-evolutionprofiles above 550 "C that are qualitatively similar. However, even this "dry" oil shale produces relatively little additional water as a result of reaction 2. Limited amounts of reactant or unfavorable thermodynamics exclude other equilibria that could generate water. For COz + H2S COS + H20, reaction stoichiometry and a low COS-release rate limit the maximum impact on water-release rate to less than 0.1%. The water gas shift equilibrium is not the whole story. Some Copreduction under kinetic control takes place even before equilibrium is reached, and reducing agents other than H2 are certainly capable of converting COz to CO and water. Chemistry, like reaction 2 but probably kinetically controlled with "H2" replaced by "H donor", must be considered once CO formation becomes significantperhaps even a t 400 OC for Colorado oil shale. This weakens conclusions about minor sources of water evolved during oil evolution; but given the low rate of CO release below 550 "C, the effect on the water-release rate in the 400-550 "C temperature range will be less than 15%. In general, water is unstable at high temperatures. Char gasification (reaction 3) removes water directly. The H2O + C(S) CO Hp (3)
-
-
+
Boudouard reaction (reaction 4) followed by the water-gas shift reaction (reaction 2) also removes water. cop + C(s) 2 c o (4)
-
Minerals that decompose above 550 "C are main sources of the high-temperature water. Some minerals and their (20)Burnham, A. K. Unpublished results presented at the 3rd LLNL Oil Shale Briefing, Livermore, CA, 1980.
temperatures of maximum water evolution (by TGA) are as follows: illite, 550 "C; kaolinite, 600 "C; chlorite, 650 "C; montmorillonite, 700 0C.14,15Possible minor contributors of water include the quartz phase change (CY p transition) at 550 "C that can physically free a little water; the decomposition of buddingtonite, NH4(AlSi308)J/2H20, to yield NH3 and H20; the reduction of magnetite to FeO or metallic iron at 580 "C and above; the loss of hydroxyl functionality as aluminum silicates and silica begin to fuse and form anhydrous silicates such as akermanite and diopside;12and the elimination of 0 and H from char as it becomes increasingly graphitic. Because local equilibrium conditions exist in the hightemperature region, water will have an influence on other evolved gases and obscure their chemistry of formation. For example, (a) H2 release will not necessarily correlate with the H/C ratio of a spent shale's carbonaceous residue, and (b) it will not be possible to deduce directly the kinetics of carbonate mineral decomposition from Cop evolution. Water Evolution from Acid-Leached Colorado Oil Shale. A water-evolution curve for carbonate-free Colorado oil shale is shown in Figure 3. The rate of water release is displayed per gram of the original specimen (i.e., before acid treatment). As expected, the high-temperature portion of the water-evolution profile changes significantly when less than 1%of the dolomite and calcite remain. Since analcime, the major moderate-temperature source of water in the Colorado oil shale, is also partially removed by room-temperature acid leaching (it is quite soluble in hot dilute HCl'3J7), the entire water-evolution profile of the carbonate-free oil shale differs significantly from that of the raw shale. With less analcime and with reaction 3 serving to remove water formed above 550 "C, free water (hydrates) dominates the water-release profile of acidleached oil shale. The key points are a decrease in moderate- and hightemperature water from acid-leached material and further evidence for major contributions from analcime and carbonates when native Green River oil shale of the Mahogany Zone releases water. More free water and more obvious water elimination from kerogen may be artifacts of acid treatment-perhaps due to ion-exchange reactions that form hygroscopic chloride salts or greatly increased porosity that makes pyrite and kerogen more susceptible to air oxidation and permits water to be trapped in pores. Water from Fischer Assay (FA) of Green River Oil Shale. The modified FA technique (ASTM D3904) is the standard batch-pyrolysis method.'O Table I11 compares experiments in which assay-generated water was handled in various ways. All three experiments were autogenous assays (no gas sweep through the pyrolyzer). In the first experiment, water was trapped in a standard condensation unit consisting of a pair of 50-cm3centrifuge tubes cooled in an ice bath (no added sweep). In the second experiment, 185 cm3/min of argon was introduced immediately before the 0 "C traps; some water passed through the traps and was swept to the MS instrument where it was detected (all lines
-
Coburn et al.
220 Energy & Fuels, Vol. 3, No. 2, 1989 a c
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Table IV. Water-Evolution Data (Normalized Highest Peak = 1) heating rate, (normal- Wl,z: rate, T,,, ized) "C ref OC/min "C 1 270 Khanz1 50 (a) 610 1 380 Carangelo, Solomon, 30 (a) 375 and Gearson' 0.7 (b) 725 1 260 Jeong and Patzerz2 10 (a) 180 (b) 395 0.9 210 (c) 575 0.45 95 this work 0.45 4 (a) 90 1 260 (b) 340 0.7 (c) 700
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Time (min) Figure 6. Water vapor from Fischer assay pyrolysis of Colorado oil shale that passes a 0 "C cold trap (185 cma/min argon sweep; time-temperature history shown). were kept hot; only traps were cooled). In the final experiment, 185 cm3/min of argon was again added after the retort, but traps were heated to 135 OC; all water, as vapor, reached the MS instrument. As Table I11 shows, the amounts of water from the experiments agreed well. Figure 5 shows water evolution as a function of time for the third experiment, all evolved water reaching the MS instrument. The time-temperature history plotted in the figure has error bars of *60 "C because of the thermal gradient typical of such assays. Water from various sources overlaps and resolution is poor, so a Fischer assay can provide only limited information regarding water evolution. Colorado oil shale specimens that have less analcime or have more nahcolite, or that have not been subjected to vacuum drying, will generate more water in the early stages of heat up. A flat water-evolution peak &e., rather constant water release over the entire temperature range) is commonly noted when a Mahogany Zone oil shale is pyrolyzed in a 1.5-in.-0.d. retort a t 12 "C/min. Figure 6 shows water vapor reaching the MS instrument under the conditions of experiment 2 (185 cm3/min of argon flow through a cold trap). The trap's apparent surface temperature can be determined from this experiment. Provided gas exited the trap water-saturated, its temperature was 3 "C. Hot effluent gas warms surfaces of the small trap only slightly. Consistency of the data in Table I11 confirms good precision and accuracy in determining water with our MS method. However, the gravimetric method for water determination, the modified FA procedure (run l , Table 111), has inherent limitations that restrict its utility as a control. Even with a large specimen (140 g), our precision for assay-water determinations was, at best, *5%, comparable to that of the MS method.
s e
0
200
400
600
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"C Figure 7. Water evolution from Israeli oil shale: (A) this work, 4 OC/min heat up with 185 cm3/min argon sweep; (B)work of Solomon, Carangelo, and Horn, 30 OC/min heat up (adapted from Temperature,
ref 3).
Conclusions We have obtained from oil shales the first quantitative water-release data as a function of pyrolysis temperature. In Table IV, we compare our Colorado oil shale results with some qualitative water-evolution profiles in the literat ~ r e . ~ iThe ~ ~ temperature p~~ of maximum water-release rate, T,,, that we report for the major water peak (uncorrected for heating-rate differences) matches that observed by Carangelo and co-workers,4 but our peaks are narrower with deeper minima (i.e., better resolved). The use of composition differences to explain this is unsatisfactory, since other Mahogany Zone oil shales that we have pyrolyzed give more similar water-evolution profiles than Table IV would imply.2 Figure 7 compares an Israeli oil shale water-evolution profile obtained by using our method and one previously published by Solomon et al.3 Apatite minerals that release bound water in the 200-400 "C temperature range, along with kaolinite as the predominant clay mineral,= account for the water-release profile that we observe. Mineralcontent disparity and different heating rates may partially explain poor agreement with the earlier published report. Our better resolution may also be a factor. We believe that our batch-retorting/MS technique for water achieves resolution superior to that possible with other real-time methods. For example, thermogravimetric (21)Khan, M. R.In 19th Oil Shale Symposium Proceedings; Colorado School of Mines: Golden, CO, 1986;pp 139-48. (22)Jeong, K. M.; Patzer, J. D., 11. In Geochemistry and Chemistry of Oil Shales; Miknis, F. P., McKay, J. F., Eds., ACS Symposium Series 230;American Chemical Society: Washington, DC, 1983;pp 529-42. (23) Shirav, M.; Ginzburg, D. In Geochemistry and Chemistry of Oil Shales; Miknis, F. P., McKay, J. F., Eds.; ACS Symposium Series 230; American Chemical Society: Washington, DC, 1983;pp 85-96.
Energy &Fuels, Vol. 3, No. 2, 1989 221
Pyrolysis of Oil Shales a
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Figure 8. Large thermal-gradient water-evolution profiles of Devonian oil shale pyrolyzed a t 4 OC/min. Table V. Peak Broadening Due to a Thermal Gradient, from Eq 5 and 6 (a= 1 X cm2/s) heating rate, increase in decrease in vesse1' oC/inin Wl,,,b OC Tmax,b "C 0.15 (0.5)b 1.7 (3.2Ib 1B 4 1A 4 15 1A
12
100
'From Figure 1. bWorst case calculation given in parentheses; a = 0.5 X cmz/s.
analysis (TGA) with water-specific detection avoids a thermal gradient by use of a very small specimen,21but a substantial time (temperature change) is often needed to produce enough water vapor for detection. Dispersion of effluents in the volume of the TGA apparatus and time needed for data and sample collection, particularly if an infrared gas cell must pose difficulties that limit resolution. However, recent coal pyrolysis studies using advanced FTIR procedures also claim quantitative, realtime water detection with continually improving resoluti~n.~~ The Appendix gives quality-assurance efforts. Calculations based on measured thermal gradients and dispersion suggest that, for our experiments, effects that degrade resolution have largely been eliminated. Primarily, the kinetics of water-release reactions determine peak shape. Thus, the water-evolution peak due to each precursor is, for the most part, a fundamental characteristic of the chemical reaction and of mass-transfer effects associated with gas release from a solid (i.e., the evaporation and diffusion of water vapor through grains and across boundaries). We plan to use data obtained in this way to determine kinetic parameters for water evolution.
Acknowledgment. Armando Alcaraz and Hugh Gregg provided expert assistance with the MS measurements. The help of Alan Burnham and John Reynolds as they studied gas evolution from petroleum source rocks and tar sands was especially beneficial. The work was performed under the auspices of the US.Department of Energy by Lawrence Livermore National Laboratory under Contract NO. W-7405-ENG-48. Appendix Use of a triple-quadrupole MS instrument as a quantitative water detector is sufficiently unusual that we provide here, as a supplement to our experimental methods, a few details of a quality-assurance study. We address ~~
the problems of repeatability, resolution, precision, and accuracy. We evaluate the specificity and selectivity of the MS instrument along with the uniformity with which pyrolysis temperature can be controlled and measured. Repeatability. Experimental repeatability was better (by at least a factor of 2) for experiments using the retort vessel of Figure 1B rather than vessel 1A. Figure 8 shows data from a set of similar Devonian oil shale retorting experiments carried out in retort vessel 1A. Temperature was precise to 3t4 "C a t the point of steepest rise where temperature measurement limitations determine repeatability. The longitudinal temperature gradient (*3 "C for a 2-in. retort, as determined by monitoring 16 thermocouples) and our ability to position the thermocouple at the specimen's mean-temperature point defined the empirical precision. An error of f l mm in positioning the key thermocouple will introduce a temperature inaccuracy of f0.5 "C for vessel 1B (heating rate 4 "Cfmin). Because of a steeper thermal gradient, the inaccuracy would be f2.5 OC for vessel 1A. Precision. For the three experiments of Figure 8 (Devonian oil shale), agreement in the rate of water evolution a t TmB,was f3%. Precision and accuracy of water-content measurements depend on features related to the use of an MS instrument as a water-specific detector. Specificity, noise, short-term stability, and drift all affect the profiles. Corrections to account for instability are important for achieving satisfactory gas-evolution profiles. We removed noise effectivelywith single-point averaging. What appears to be noise in many of our water-evolution profiles is actually short-term instability. There was a time lag between when the spectrometer determined water a t mlz 18 and argon a t m/z 40. This delay was about 2 s, if 40 compounds were being monitored (the usual case), or as short as 0.2 s, if as few as seven gases were detected. A sensitivity change during this time showed up as short-term instability. It was reduced by multipoint average (smoothing) that we applied in a few instances (Figures 2, 3, and 8). Without such averaging (Figures 5-7) one can directly observe in the MS data the error bars for the determinations (f5%). Uninterrupted, use of a triple-quadrupole MS instrument is unusual. Instrument drift, or long-term instability, was observed as the performance of electrical components changed with time. Furthermore, water degrades MS sensitivity, as do CO and COP,while hydrocarbons enhance sensitivity. The cause does not seem to be related solely to filament performance, as has been suggested.25 Sensitivity changes appear to be due to surface effects to which active elements such as the repeller or lenses are especially susceptible. Fortunately, such changes (both instrument drift and compound-specific sensitivity variations) are uniform over the entire mass range. The use of argon for sensitivity corrections eliminates these problems. Analysis of a standard over the 4-h time span of a pyrolysis experiment (see Figure 2) provided proof that the water: argon ratio remained constant. MS specificity and selectivity are excellent for water at m/z 18 (and also for argon at m/z 40). The dilute mixture of pyrolysis gas forms few ions a t masses m / z 17 and 19, so there is no significant overlap of adjacent large peaks. Every oxygen-containing compound has an m / z 18 peak because water and the l8O isomer are common stable fragments. However, water is a major oil shale pyrolysis product, and it dwarfs components that give interfering
~
(24)Serio, M. A.;Solomon, P. R.; Carangelo, R. M. Prepr. Pap.-Am. Chem. SOC.Diu. Fuel Chem. 1988, 33(2),295-309.
(25)Masuda, Y.Shitsuryo Bunseki 1971, 19, 150-7.
222 Energy & Fuels, Vol. 3, No. 2, 1989
fragments. To calculate the ratio of water gas shift components a t temperatures where CO dominated, we corrected the water signal in the usual way using CO and C02 cracking patterns, but the water-evolution profile was unchanged. Argon has an isotope of mass 36 (0.33%) which, when doubly charged, produces an m++/z 18 peak. Although doubly charged argon can be avoided if the ionization voltage is 40 rather than 70 eV,%we used a 70-eV ionizing voltage and routinely corrected for the m++/z 18 interference using the m++/z 20 intensity and the isotope ratio. This correction applied to retorting experiments WBS small; it typically reduced the area of the m/z 18 peak by less than 0.3%. However, for dilute water-vapor calibration standards, it was a required correction. A background correction was unnecessary; when made, the important m++/z 18 contribution was subtracted. Resolution. Resolution is degraded in several ways. Dispersion and sample thermal gradients are primary concerns. We tested dispersion effects by introducing a spike of gas and determining band broadening at the detector. Results were used to convolute an expression for first-order gas release at a linear heating rate of 4 "C/min. Dispersion had a negligible effect on the gas-evolution profile, provided no chemical reactions occurred. The peak width at half-height (WlI2) increased by less than 0.5 "C. Data collection time and smoothing also had negligible impact-again, less than 0.5 "C broadening. Water is notorious for memory effect^.^' We noted slight effects due to adsorption of water on surfaces when we calibrated the MS instrument during the course of a retorting experiment (Figure 2)-wet effluent gas raised the observed water content of a calibration by up to 3%; dry gas lowered it. Adsorption must be minimized to assure good resolution. Figures 2 and 8 allow comparison of water-evolution profiles from small and large thermal-gradient retort vessels. The improved definition of the 440 "C peak in the small thermal-gradient profile (Figure 2) is particularly notable. While the free water peaks of the two figures also look different, this is of no consequence-vacuum-dried material was pyrolyzed for Figure 8, and as-received material was pyrolyzed for Figure 2. For a cylindrical retort (Figure 1A) heated through the wall linearly with time, equation 5 is the textbook solution for the radial temperature profile, T(r,t), as a function of m
T(r,t) = T, - 2m C AnJo(xnr)(l- exp(-axn2t)) (5) n=l
time (thermal conductivity and thermal diffusivity are assumed constant). In eq 5, a = thermal diffusivity = 1 X cm2/s for powder from a rock of density =2 (the interstitial gas sets thermal conductivity), T, = wall temperature = To+ mt, To= initial temperature, m = heating Jo,J1= Bessel functions, rate, A, = [(aux,2)(znr,)J1(z,ro)]-1, first kind of order 0 or 1, x , satisfies Jo(xnr,) = 0, and ro = radius of the retort can. We have solved for the radial temperature profile of a retort with a concentric cylinder design (Figure lB, with both inside and outside walls heated linearly with time): m
T(r,t) = T, - 2m CBJo(.Ynr)(l - exp(-aym2t)) (6) n=l
(26) Wood, G. M.; Yeager, P. R. In Proceedings of the Symposium on Enuironmental and Climatic Impact of Coal Utilization, 1979; Singh, J. J., Deepak, A., Eds.;Academic Press: New York, 1980; pp 187-211. (27) Carlson, G . L.; Morgan, W. R. Appl. Spectrosc. 1977, 31, 48-9.
Coburn et al.
and where yn satisfies fo(ynro)= 0, rI, r, = inner and outer sample radii, and Yo, Yl = Bessel functions, second kind of order 0 or 1. At a 4 "C/min heating rate, the time-temperature dependence of the thermal gradient becomes negligible above 150 "C (retort 1A) or above 50 "C (1B). The maximum temperature differential, the temperature difference between the wall and the center, for retort 1A is then AT = 0.252mr,2/a. For retort vessel 1B with rI = 0.95 cm and ro = 1.74 cm, the coldest spot is at r = 1.35 cm (the sample midpoint), and the maximum temperature differential is A T = 0.0188mr,2/a. For retorts with the same rot the temperature gradient decreases 13-fold in going from configuration 1A to 1B; volume is reduced only 25%, for vessels of the same length. We divided the sample radially into 10 equal-volume segments and determined the average temperature of each from experimentally measured temperatures by interpolating with eq 5 or 6. Theoretical first-order reaction profiles with EA = 51 kcal/mol and A = lOI3 s-l were calculated for each segment and summed to determine peak broadening. Results with a = 1 X cmz/s are shown in Table V; we also show a worst case calculation, a = 0.5 X cm2/s, since there is a longitudinal temperature differential ( f 3 "C for a 2-in.-long vessel) and uncertainty in a (avaries slightly with temperature). For the experiments that were run in the concentric cylinder vessel, the peak width at half-height ( Wl/& increased negligibly. However, the T, as measured by a midpoint thermocouple, was 2 "C lower than the actual mean temperature (data were taken from the Figure 3 experiment), but the lag time of =45 s needed for gas to reach the MS instrument afforded a compensating correction (about 3 "C). Size reduction, so as to reduce lag time, mixing, adsorption, and secondary reactions, holds the potential for some additional improvement in resolution. Accuracy. Calibrating the triple-quadrupole MS instrument is no different from calibrating any other moisture monitor, and our ability to calibrate defines accuracy. Calibration is sufficiently difficult that oil shale researchers have avoided calibrating for water, and published profiles have units of relative i n t e n ~ i t y . ~ rWe ~,~~*~~ used argon passed successively through four saturated salt solutions, properly thermostated (30 "C) and equilibrated, for this purpose. Programmed heating of BaClZ-2Hz0and isobutane combustion referenced to a COPstandard were used to check the calibration (f3% agreement). Nonlinearity due to compound-specific variations in sensitivity were avoided by use of argon as a sensitivity reference; all calibration standards were at the 1-10% level. We usually calibrated the MS instrument just before an experiment or immediately thereafter. In one case, a water standard was checked nine times during the pyrolysis experiment (Figure 2, open circles); the dashed line of Figure 2 shows what the calibration would have been had we relied on a standard run prior to the experiment. The nine calibrations had a standard deviation of f4.7 70;the usual calibration (two differing by f3.2%) was 4.5% high. Water calibrations suffer from the tendency of water to adsorb on or desorb from surfaces. Increased line tem-
Energy & Fuels 1989,3, 223-230 peratures and time expended in equilibrating surfaces improved the quality of calibrations. Careful water Calibrations could be done with an accuracy of i 5 % . However, many experiments were quite complex. For example, from the Figure 7 experiment we generated gas-evolution profiles for water and 40 other compounds with the spectrometer operating in both MS and MS/MS modes and recording information every 2 "C at three tuning file
223
settings. Accuracy for water was only about f 2 5 % ,in this case. However, on the basis of information obtained in the present study, we have recently implemented a convenient standard calibration procedure for water that gives good results (f5% accuracy) even when calibrations must be done hastily. Registry No. H20, 7732-18-5.
Influence of Steam Pretreatment on Coal Composition and Devolatilization M. Rashid Khan* Morgantown Energy Technology Center, U S . Department of Energy, P.O. Box 880, Morgantown, West Virginia 26507-0880
Wei-Yin Chent Gulf South Research Institute, P.O. Box 26518, New Orleans, Louisiana 70186
Eric Suuberg Division of Engineering, Brown University, Providence, Rhode Island 02912 Received July 1, 1988. Revised Manuscript Received November 18, 1988
Previous studies have shown that pretreating coal with steam can enhance the liquid yields during coal pyrolysis. The objective of this research was to characterize steam- and helium-treated coals to better understand the effects of pretreatment on pyrolysis-produced yield and composition. Pretreated samples were pyrolyzed in rapid and slow heating rate reactors. The following characterization techniques were used to analyze the products: elemental analysis, Fourier transform infrared spectroscopy, gas chromatography/mass spectrometry, and cross-polarization/magic-angle-spinning I3C nuclear magnetic resonance spectroscopy. This research demonstrated that steam treatment of a low-rank coal reduces the concentration of methoxy, phenolic, and aliphatic carbonyl and carboxyl groups in the coal. The low-rank coal showed significant reductions in total oxygen concentration after steam treatment, but the high-rank coals showed unchanged or even higher oxygen content. After steam pretreatment, phenols were the major components found in the water used. Pretreatment with steam increased the aromaticity of Wyodak coal. Steam treatment did not enhance total volatile yields from vacuum pyrolysis for any of the coals. Low-rank coals showed increases in tar yields when pyrolyzed at a rapid rate after steam treatment, but these increases seemed to be at the expense of total volatiles yield. When steam-treated coal was devolatilized at a slow heating rate, no increase in tar yield was observed for either a low- or a high-rank coal.
Introduction Graff and Brandes1S2report that pretreating coal with steam enhances the liquid yield from coal pyrolysis. They found that carbon conversion to liquids in steam pyrolysis at 740 "C increased from 23% to over 50% when they pretreated Illinois No. 6 coal with steam. Bienkowski et aL3recently reported that conversion increased 32 % when they pretreated Wyodak coal at 240 "C and subsequently liquified it at 400 "C in the presence of steam. However, none of these workers reported any compositionalchanges in the pyrolysis liquids due to pretreatment. In their reviews of coal conversion mechanisms in nitrogen heterocycles used as solvents, Atherton and Kulik4p5
* To whom correspondence should be addressed. Present address: Department of Chemical Engineering, Louisiana State University, Baton Rouge, LA 70803.
0887-0624/89/2503-0223$01.50/0
suggested a number of chemical models that contributed to the enhancement of liquefaction under mild conditions. The interactions between the nucleophilic solvents and the hydrogen bonds and oxygen-containingcross-links in coal were critical in those mechanisms. Between 200 and 400 "C, a basic nitrogen compound is able to cleave ethers, esters, and amide cross-links and induces tautomerization (1) Graff, R. A.; Brandes, S. D. Energy Fuels 1987, I , 84. (2) (a) Graff, R. A.; Brandes, S. D. Prepr. Pap.-Am. Chem. SOC.,Diu.
Fuel Chem. 1984,29(2), 104. (b)Brandes, S.D.; Graff,R. A. Investigation on the Nature of Steam-Modified Coal. Prepr. Pap-Am. Chem. SOC., Diu.Fuel Chem. 1987, 32(3), 385. (3) Bienkowski, P. R.; Narayan, R.; Greenkom, R. A.; Chao, K. C. Ind. Eng. Chem. Res. 1987,26, 202. (4) Atherton, L. F.; Kulik, C. J. Coal Liquefaction Chemistry. Paper presented at the 1984 AIChE Annual Meeting, Anaheim, CA, 1984. (5) Atherton, L. F.; Kulik, C. J. Advanced Coal Liquefaction. Paper presented at the 1982 AIChE Annual Meeting, Los Angeles, CA, 1982.
0 1989 American Chemical Society
