UNITED STATES DEPARTMENT OF THE INTERIOR 
Report of Investigations 8243 

Methane Absorption in Oil Shale 

and Its Potential Mine Hazard 

By J. E. Matta, J. C. LaScola, and Fred N. Kissell 

UNITED STATES DEPARTMENT OF THE INTERIOR 

Cecil D. Andrus, Secretary 

BUREAU OF MINES 
This pub1 ication has been cataloged as follows : 

Matta, Joseph E 

Methane absorption in oil shale and its potential mine hazard / by J. E. Matta, J. C. LaScola, and Fred N. Kissell. 

[Washington] : U.S. Dept. of the Interior, Bureau of Mines, 

1977. 

13 p. : ill., diagrams ; 26 cm. (Report of investigations - Bureau 

of Mines ; 8243) 

Bibliography: p. 10. 

1. Methane. 2. Oil-shales. 3. Mine gases. I. LaScola, John 

C., joint author. 11. Kissell, Fred N., joint author. 111. United 

States. Bureau of Mines. IV. Title. V. Series: United States. 

Bureau of Mines. Report of investigations - Bureau of Mines ; 

8243. 

TN23.U7 no. 8243 622.06173 

U.S. Dept. of the Int. Library 
CONTENTS 

Page 

Introduction ............................................................ 1 

Laboratory results .............e........................................ 2 

Field tests and results ...................................*.............. 6 

Explanation of the direct method ................................... 6 

Cores from the same hole .......................................... 7 

Cores from different locations ..................................... 8 

Cores from trona regions ..........................I.............e.. 8 

Conclusions ............................................................. 9 

References .............................................................. 10 

Appendix.--Laboratory equipment and procedure ........................... 11 

ILLUSTRATIONS 

Emission curve for a 50.8-gallton oil shale pressured with 

methane and helium .............................................. 3 

Methane released versus oil yield content for samples pressured 

to 200 psig ..................................................... 4 

Methane released versus pressure for oil shale with an oil yield 

of 30.3 gallton ................................................. 4 

Methane released as a function of oil yield and pressure .......... 5 

Sample container-- gas emission by displacement of water ........... 5 

Coalbed gas amount via the direct method versus actual mine 

emission ....................................................... 6 

Direct-method field results for cores taken from the same hole out 

of the Uinta basin .............................................. 7 

Direct-method field results for seven cores from five locations ... 8 

Apparatus to measure gas in oil shale ............................. 12 

1. Methane emission characteristics of two gassy trona mines in 

southwestern Wyoming ............................................ 9 
METHANE ABSORPTION IN OIL SHALE AND ITS POTENTIAL 

MINE HAZARD 

by 

J* E, Matta, 1 J. C* LaScola,2 and Fred N* Kissell3 

ABSTRACT 

The Bureau of Mines made laboratory absorption measurements on oil shale 

samples, which showed that the amount of methane absorbed is proportional to 

pressure and oil yield, and can be much larger than would be predicted based 

solely on porosity. 

Oil shale cores collected in the field were also measured for their gas 

content using the Bureau of Mines direct method, Cores taken from deep locations and far from outcrops yielded more gas than cores from shallower locations or at outcrops, when taking into account variations in oil yield, and 

all data indicate that oil shale mines that are both deep and far from an outcrop will emit low levels of methane gas. 

INTRODUCTION 

One of the many difficulties faced by any prospective oil shale mine is 

the possibility that methane gas may seep into the mine, creating an explosion 

hazard and causing the mine to be classified as gassy under State or Federal 

laws. Methane has never been detected at existing oil shale mines in Colorado, 

However, the early history of oil shale mining indicates that at least in some 

cases methane was detected. 

Near the turn of the century oil shale was being mined actively in several 

parts of the world, most notably in Scotland, where for many years it was the 

basis of a large industry (4).4 In 1912, Caldwell (2) reported that "The gases 

found in shale workings, though not of the volume of-those in coal seams, are 

of an explosive a-nd dangerous character," In Colorado mining officials, 

l~esearch physicist. - athe hem at ician. 

3Physical research scientist. 

All authors are with the Pittsburgh Mining and Safety Research Center, Bureau 

of Mines, Pittsburgh, Pa. 

4Underlined numbers in parentheses refer to items in the list of references 

preceding the appendix. 
anticipating the possibility of encountering methane, wrote a fire boss 

inspection requirement for oil shale mines into the State mining regulations 

of 1919 (E). However, because no methane was ever detected, this requirement 

was eventually dropped. 

Recently, Kissell recognized that the nongassy nature of the existing oil 

shale mines in Colorado, which are all located at outcrops, might not be a 

very good indicator of what could be expected for a deeper mine located far 

from any outcrop. Coal mines located close to or at an outcrop are known to 

be less gassy than mines in the same bed that are deeper and far from the outcrop. The situation might be the same for oil shale. A preliminary study (7) - gave some support to this reasoning, based on three main observations: 

1. Drillers working at exploration holes located far from outcrops had 

observed methane emissions, often from the tuff layers near the oil shale. 

2. The trona mines in southwestern Wyoming are gassy, and the gas is 

thought to originate in the oil shales located near the trona. 

3. The Bureau of Mines direct method (8) was applied to two fresh oil 

shale cores, and both were found to contain Tow levels of methane. Although 

their methane contents were considerably less than would be found in fresh 

coal cores taken from a deep coalbed, they were not negligible. 

However, this preliminary study left many questions unanswered. For 

example, much of themethanemight be associated with the porous tuff layers 

rather than with the oil shale. Nor was it clear to what extent the differences in the methane contents measured by the direct method were due to location (depth, distance to outcrop) and/or to changes in the oil yield of the 

sample tested. This might be an important factor, since in the case of coal, 

McCulloch and Diamond (10) have linked increased methane content to an 

increase in the fixed-carbon content. For other sediments, organic richness 

is currently used as an indicator of the hydrocarbon source potential, providing information in oil and gas exploration (?). 

In this current study, direct-method tests were conducted in the field to 

measure the methane levels in fresh oil shale cores. In addition, laboratory 

absorption measurements were made to determine if much more methane is 

absorbed than can be accounted for by the low oil shale porosity. If this is 

the case, it would indicate that the oil shale at least had the capacity to 

act as a source of gas. Moreover, if methane is absorbed, a correlation 

between methane absorption and oil yield would be sought, because this would 

be necessary in interpreting results from direct-method tests in the field. 

LABORATORY RESULTS 

Details of the laboratory experiments are presented in the appendix. The 

results of these experiments may be summarized as follows : 

1. Methane is absorbed by the oil shale. In figure 1 a sample which had 

been pressured to 200 psig and then reduced to atmospheric pressure released 
JTIME, min 'I2 

FIGURE 1. - Emission curve for a 50.8-c~al/ton oil shale pressured with methane and helium. 

10 times more methane than helium under the same conditions. Since helium 

does not absorb under these conditions, the difference must be attributed to 

absorption of methane. The amount of methane released from this sample is 

equivalent to what would be released from a nonabsorbing material with 

approximately 15 pct porosity.5 

2. For a given pressure, the quantity of methane released when the pressure is reduced to atmospheric varies linearly with the oil yield of the sample, as measured by the standard Fischer retort method (fig. 2). This 

indicates that for direct-method samples, the depth and distance to outcrop 

are not the only factors to be considered in assessing the gas content. Oil 

yield is also important. 

3, For a given oil yield, the quantity of methane released varies 

linearly with pressure, at least up to about 350 psig (fig. 3). 

The results from figures 2 and 3 are combined in figure 4, in which the 

methane released is given as a function of pressure and oil yield, with the 

pressure shown as a series of isobars. 

"or samples with a lower oil yield, the equivalent porosity would be proportionally lower, as indicated by the second result. 
KEY 

-Oil shale 

- 0- Impregnated tar tuff 

- - 

- - 

- 

- 

I I 

0 10 20 30 40 50 60 

OIL YIE LD, gal/ton 

FIGURE 2. - Methane released versus oil yield content for 

samples pressured to 200 psig; 

0 100 200 300 400 5

PRESSURE, psig 

FIGURE 3. - Methane released versus pressu

shale with an oil yield of 30.3 g
The mechanism by which 

1.2 

A. 

FIGURE 4. - Methane released as a function of oil yield results in figure 4 indicate 

I I I/ / 1 ,' a 

/ / 

/ 

/ / 

1.0 

CT 

m' 

E " .8 D 

W 

v, 

a 

W 

-' .6- w 

LT 

W 

Z 

a 

1.4- 

tw 

2 

0 

and pressure. 

the methane is held in the 

oil shale remains unclear, 

but it is roba able that the 

that a 1-ton shale sample 

with a kerogen yield of 42 

gal/ton (1 bbl) will contain, 

in crude oil under similar OILYIELD, gal/ton conditions. For exam~le . 

- / / 

/ - 

/ / 

3OOpsig / ZOO psig) / 

- J/ / - 

/ / 

/ / 

/ / 

/ 0 /' / 0 0 - / 0 

/ 0 0 '/ IOOpsig , / / 10 

/ / 0 0 - / / 0 

0 

/ 1 0 

/ 0 / 

-@ 

0 50psigZ _ - A / 0 0 

0 / 

4 

+// / 0 /- 

- 

0 4 MCC 

0 / 

C 

0 R :/-- I I 1 I 

10 20 30 40 50 60 

FIGURE 5. - Sample container-gas emission by displacement of water. 

gas absorbs in the organic 

material of the shale. The 

linear relationship between 

methane released and the oil 

yield (fig. 2) supports this 

explanation. One of the 

laboratory tests was conducted on an impregnated tar 

tuff which had been ground 

to a powder. Interestingly, 

when plotted against oil 

yield it corresponds with 

the oil shale samples 

(fig. 2). 

The amount absorbed is 

also roughly comparable to 

the methane held in solution 
at 200 psig, about 0.95 cm3/g or 30 ft3 of methane. If, on the other hand, 

one assumes that the ton of shale contained 42 gal (1 bbl) of crude oil 

instead of kerogen, the amount of methane held in solution at 200 psig would 

range from about 15 ft3 for crude oil with an API gravity of 10 to about 160 

ft3 for crude oil with an API gravity of 60 (12). - 

FIELD TESTS AND RESULTS 

Ex~lanation of the Direct Method 

The direct method developed in 1973 by the Bureau was designed as a simple method of estimating the gas content of coalbeds by testing cores taken 

during exploration drilling (8). - The procedure follows : 

2,800 Beatrice / 

/ -I 

/ 

2,200 

2,000 / 

/' OHowe 

/ 

1,800 / Loveridge. Federal No. 2 

1,600 / 

1. A 1-foot piece of 

coal core is placed in a 

small container as soon as 

the core is brought out of 

the hole. 

2. Methane bleeding 

from the core is measured 

immediately by bubbling it 

into an inverted water-filled 

graduated cylinder ( fig. 5). 

30 The methane "lost" 

from the core while it was 

being brought out of the 

borehole is calculated by 

plotting the amount of gas 

released from the container 

versus the square root of 

time, and extrapolating back. 

DIRECT METHOD, cm3/g 

800 

600- 

400 

200 

vicinity of coal mines to 

obtain a rough correlation 

FIGURE 6. - Coalbed gas amount via the direct method between the gas content of 

0 2 4 6 8 10 12 14 16 18 20 from virgin coal in the 

- / - 

~esta No. 5 

/ 

- / 

/ 3 l Inland 

- 

, I I 1 i 

versus actual mine emission. 

4. Eventually, the 

core essentially stops bleeding methane, but its residual gas can be measured by 

crushing the core to a fine 

powder. 

Cores have been desorbed 

the core and the amount of 

methane emerging from the 

nearby mine (fig. 6). Thus 
the direct method can be 

used to roughly forecast the 

methane emission of a prospective coal mine when it 

has reached full production. 

By analogy, the method was 

also applied to oil shale 

cores to obtain some very 

rough indications of how 

gassy an oil shale mine 

might be. 

Cores From the Same Hole 

= .4 Results in the laboratory had indicated that at /. a given pressure, the amount i1 .2 0 10 20 30 40 50 60 proportional of methane released to thewas oil 

OIL Y I E LD, gal/ton yield. To determine whether 

FIGURE 7, - Direct-method field results for cores taken the same would be true of 

from the same hole out of the Uinta basin, cores taken in the field, 

the direct method was 

applied to four oil shale 

cores taken from a single 

corehole in the Uinta basin. All were within 20 feet of the Mahogany Marker, 

which was the mining zone of interest. The overburden depth to the marker was 

approximately 1,020 feet, and the location was about 5:1/2 miles from an outcrop. After completion of the corehole, the mining zone was partitioned off 

with packers, and a drill stem equilibrium pressure of approximately 300 psig 

was measured. Since these cores were all within 20 feet of one another, it 

( was assumed that they all were subjected to about 300 psig pressure The 

total6 gas released for each of the core samples is plotted versus oil yield 

( in figure 7. As in the laboratory test, results from these field samples 

again indicate that, for a given pressure, the methane released varies 

linearly with the oil yield of the samples. 

The 300-psig isobar from figure 4 is also shown in figure 7 to indicate 

how much gas would be released from laboratory samples that have been pressured to 300 psig. The direct method samples taken in the field yielded about 

two-thirds of the gas in this instance. 

I 

60f the total gas, the lost gas was 5 pct or less. The gas released from the 

container in 3 weeks was about 35 pct, and the remaining 60 pct was residual gas released during crushing. The low permeability of the oil shale 

does not prevent a substantial portion of the gas from seeping from the 

solid core. 
Cores From Different Locations 

The four cores from the same location had all presumably been subjected 

to 300 psig before extraction. Cores taken from shallower depths or locations closer to an outcrop will probably have been subjected to lower methane 

pressures. Figure 8 gives the methane contents and oil yields of seven additional cores taken at other locations. 

Using figure 4 as a guide, various isobars are drawn on figure 8 to 

represent the results that would be obtained for samples subjected to various 

pressures in the laboratory. The core that contained the most gas would fall 

on a 200-psig isobar, the intermediate cores on 65- and 45-psig isobars, and 

the least gassy on a 0-psig isobar. 

It seems from figure 8 that core samples taken from locations that are 

deeper and farther from outcrops are subjected to higher pressures, and that 

this, in conjunction with the oil yield, affects the amount of methane 

re leased. 

1.0 1 1 Cores From Trona Regions 

A specific example of the effect of overburden depth is shown in figure 8 

by the samples taken from the Green River basin. All were taken approximately 

20 miles from an outcrop and have roughly the same oil yield, but the gas 

content of the shale 

1.2 

200 psig ' 3' 

/ 20 mi les 

/ /&l,680 f t / Green River / 

/ 

increases markedly with 

increasing overburden depth. 

I 

- 

- 

Green River L:,",",:~~ I I I I 

I 

0 10 20 30 40 50 60 

OIL YI E LD, gal/ton 

FIGURE 8, - Direct-method field results for seven cores 

from five locat ions, (Distance to outcrop, 

overburden depth, and basin are given for 

each location,) 

Methane has been 

encountered in the trona 

mines at Green River, Wyo. 

(7). These mines are classified as gassy and may serve 

as an indication of what 

might be expected at certain 

oil shale mines, since the 

trona is interbedded with 

oil shales moderately rich 

in carbonaceous matter. 

Most of the gas is encountered when the roof is caved, 

indicating that it is 

emitted by the adjacent 

strata rather than by the 

trona. Table 1 gives the 

methane emission characteristics of two of these mines, 

both of which are about 20 

miles from the nearest 

outcrop. 
TABLE I. - Methane emission characteristics of two gassy 

trona mines in southwestern Wyoming 

Of the seven direct-method samples shown in figure 8, five (shown as 

Green River) were collected near these two trona mines. The sample at 1,680 

feet was taken from below the trona at mine 2. The samples at 950 feet were 

taken from below the trona, and the samples at 750 feet were taken above the 

trona at mine I. The fact that mine 1 is shallower and does not intentionally 

cave the roof could account for its lower gas emission. However, the direct 

method does indicate that the shale beds adjacent to mine 1 are about a third 

as gassy as the bed adjacent to mine 2 (table 1). 

Approximate depth ............................. feet.. 

Daily tonnage.. ..................................... Daily methane.. .............................. .MMcf.. 

Methane concentration (main returns) ........... pct.. 

Direct-method results for adjacent shale in 

30- to 45=gal/ton range ................... .cd/g.. 

These Green River samples may be compared with the others collected at 

different locations. For instance, the two samples listed as Piceance (fig. 8) 

have less gas, and the four samples listed as Uinta (fig. 7) have similar or 

higher gas contents. 

Based on this laboratory and field study, the following conclusions can 

be drawn: 

Mine 1 

800 

8,000 

0.4 

0.1 

0.15-0.30 

1. Much more methane is absorbed by oil shale than can be accounted for 

by the low oil porosity. The amount absorbed is proportional to the pressure 

to which the sample has been subjected and to its oil content. The probable 

mechanism is absorption in the organic material. 

Mine 2 

1,500 

10,000 

2 .6 

0.2 

0 70 

2. The amounts of gas released from oil shale samples in laboratory 

experiments are roughly comparable to the amounts of gas re leased from directmethod samples taken in the field. 

3. Cores taken from locations that are deeper and far from outcrops 

yield more gas than those taken at or near outcrops, even after variations in 

oil yield have been taken into account. 

While the present information is hardly conclusive, all the data continue 

to indicate that oil shale mines that are both deep and far from an outcrop 

will emit low levels of methane gas. Just what the measured concentrations 

will be remains to be seen. Since the measured concentrations also depend on 

the quantity of ventilation air provided for dilution, it would seem that sane 

good ventilation planning is appropriate. 
REFERENCES 

Bielicki, R. J., J. H. Perkins, and F. N. Kissell. Methane Diffusion 

Parameters for Sized Coal Particles--A Measuring Apparatus and Some 

Preliminary Results. BuMines RI 7697, 1972, 12 pp. 

Caldwell, W. The Oil Shales of the Lothians. Pt. 11. Methods of 

Working the Oil Shales. Memoir Geol. Survey, Scotland, 3d ed., 1927, 

274 pp. 

Crank, J. The Mathematics of Diffusion. The Clarendon Press, Oxford, 

England, 1956, p. 87. 

Gavin, J. J. Oil Shale, an Historic, Technical, and Economical Study. 

BuMines Bull. 210, 1922, 201 pp. 

Geochem Laboratories, Inc. Regional Hydrocarbon Source Rock Evaluation. 

Houston, Tex . , November 1976 , 76 pp. 

Jolly, D. C., L. H. Morris, and F. B. Hinsley. An Investigation Into 

the Relationship Between Methane Sorption Capacity of Coal and Gas 

Pressure. Min. Eng. , v. 127, No. 94, July 1968, pp. 539-548. 

Kissell, F. N. The Potential Hazards of Methane Gas in Oil Shale Mines. 

Proc. Environmental Oil Shale Symp., Colorado School of Mines, Denver, 

Colo. , Oct . 9-10, 1975. Quart. Colo. School Mines, v. 70, No. 4, 1975, 

pp. 19-27. 

Kissell, F. N. , C. M. McCulloch, and C. H. Elder. The Direct Method of 

Determining Methane Content of Coalbeds for Ventilation Des ign. 

BuMines RI 7767, 1973, 17 pp. 

Lunt , H. F. , J. Dalrywiple , and J. Duce. The Oil Shales of Northwestern 

Colorado. Colo. State BuMines Bull. No. 18, 1919, pp. 45-46. 

McCulloch , C. M. , and Ff . P. Diamond. Inexpensive Method Helps Predict 

Methane Content of Coal Beds. Coal Age, v. 81, No. 6, June 1976, 

pp* 102-106. 

Ruppel, T., C. Grein, R. E. Kelly, and D. Bienstock. Adsorption of 

Methane on Coal to 140 Atmospheres Pressure. Pres. at 157th Nat. 

Meeting, Div. of Colloid and Surface Chem. , ACS , Minneapolis, Minn. , Apr. 3-5, 1969; available upon request from Thomas C. Ruppel, 

Pittsburgh Energy Research Center, U.S. Energy Research and Development 

Administration, Pittsburgh, Pa. 

Society of Petroleum Engineers of AIME . Oil and Gas Property Evaluation 

and Reserve Estimates. Petroleum Transaction Reprint Series No. 3, 

1970, pp. 114-127. 
APPENDIX. --LABORATORY EQUIPMENT AND PROCEDURE 

1 In designing the experiment to measure absorption on oil shale, the 

approach used by many investigators to measure absorption1 on coal samples 

(1, g) was considered first. In this standard absorption procedure the "dead 

space ,I1 which is the pore volume of the coal plus the "free volume" of the 

sample chamber, is determined by helium pressure-volume measurements because 

helium does not absorb. The amount of gas actually absorbed by coal is the 

total gas released minus the amount of gas that can be accounted for by 

compression into the dead space. This technique is useful for coal where the 

amount of methane absorbed is much higher than the quantity compressed into 

the dead space. However, it was anticipated that only a small quantity of 

methane would be absorbed by oil shale and that this would be difficult to 

determine accurately by the standard procedure because of the proportionally 

larger dead space correction. Accordingly, a simpler apparatus and procedure 

were developed which also have more inherent accuracy for samples which emit 

low methane quantities. 

I The procedure used is an adaptation of the direct-method test used in the 

field (8). - Rather than attempt to measure the amount of gas compressed in the 

dead space, the approach was to simply bleed it off quickly. Naturally, while 

the dead space gas is being bled off, the sample begins to lose its absorbed 

gas. However, if the absorbed gas does not come off too quickly, then the 

quantity lost during bleed-off is calculated in the same way as the "lost gas" 

in the direct method. 

This approach has the advantages that the free volume of the container 

does not enter directly into the sorption calculation and that no elaborate 

sorption apparatus is necessary. Rapid depressurization of the sample 

canister eliminates the gas that was compressed in the free volume from the 

sorption measurement, and thus the error associated with its determination. 

The method has the disadvantage that it only works for materials with very low 

permeability. If the permeability is too high, the lost gas is too high a 

proportion of the total. Errors in calculating the lost gas then become 

dominant. 

Rapid depressurization of the sample cylinder causes a temperature drop 

that can also be a source of error. If the methane in the dead space is 

cooled slightly, then it will expand as the cylinder returns slowly to room 

temperature and be measured along with the absorbed gas being released from 

the sample. To minimize this error, the sample cylinders were filled 

completely with oil shale, so that the free cylinder volume was usually less 

than 250 cn?. Under these conditions, a temperature change of lo C would 

correspond to less than a c$ change in volume. Tests indicated that rapid 

depressurization of the cylinder caused less than a 3O C change in the 

internal temperature, so methane from expansion during warming was less than 

3 cm3. Since the gas released from the samples was in the range 125 to 250 

cm3 , the 3 c$ was considered to be negligible. 

l~trictly speaking, methane is adsorbed in coal rather than absorbed. For a 

definition, see Jolly (6). - 
Apparatus 

The apparatus consisted of a 500-c~8 aluminum sample cylinder which could 

be pressurized to several hundred pounds per square inch, and a common laboratory buret filled with water and inverted into a pan of water. Connected to 

the sample cylinder along with the buret were helium and methane tanks, an 

accurate pressure gage, and a vacuum pump (fig. A-1). 

Procedure 

All eight samples were from the Uinta basin, Utah. Preliminary experiments indicated that if the oil shale was crushed to less than 4 mesh, the 

samples could reach absorption equilibrium within a few days, yet the lost gas 

would not be too high. 

A crushed sample was placed in the cylinder, which was then evacuated 

and pressurized with methane to a selected pressure. A valve between the 

methane tank and the sample cylinder was then closed. As the sample absorbed 

gas, the pressure in the sample cylinder dropped. Periodically, the valve 

was reopened to restore the initial pressure. Generally 3 to 4 days were 

required to complete the absorption, but the sample was always pressurized 

for at least a week. 

He and CH4 Pressure Vacuum 

tanks gage 

8 8 

Sample cylinder Pan of water 

FIGURE A-1. - Apparatus to measure gas in oil shale. 
After absorption was complete, the desorption was measured. A second 

valve on the sample cylinder was opened, and the gas inside was bled into the 

air through a hose for 5 sec. This was more than enough to bring the 

internal pressure in the sample cylinder down to atmospheric. Then, the hose 

was inserted into the water-filled buret so the gas being released from the 

sample could be measured. 

A key assumption of the direct method is that the methane release rate 

from the sample follows the diffusion equation for spherical particles (2). 

If this is the case, then the amount released varies linearly with (time)l12 

if the time is not too large. This was shown to be true for coal cores 

extracted from the ground, and was found to be true for the oil shale samples. 

Therefore, by plotting the amount of gas released versus (time)l12 and extrapolating the initial portion of the curve linearly backwards to zero time 

(when depressurization began), one can account for the gas lost from the 

sample during depressurization. The loss was not large; for example, it was 

about 0.025 cd /g for the sample in figure 1. The 'hethane released" values 

in figures 2, 3, and 4 include this "lost" methane. Results from repeated 

tests were within 5 pct. 

To determine whether the methane released could be accounted for by 

porosity rather than actual absorption, the procedure was repeated using 

helium, which is known not to absorb. The helium released was much less, 

indicating that methane is absorbed by the oil shale.