Bureau of Mines Report of lnvestigations/l987 

Methane Contents of Oil Shale 

From the Piceance Basin, CO 

By S. J. Schatzel, D. M. Hyman, A. Sainato, 

and J. C. LaScola 

UNITED STATES DEPARTMENT OF THE INTERIOR 
UNITED STATES DEPARTMENT OF THE INTERIOR 

Donald Paul Hodel, Secretary 

BUREAU OF MINES 

Robert C. Horton, Director 
Methane contents of oil shale from the Piceance Basin, CO 

(Report of investigations ; 9063) 

Bibliography: p. 26 - 27. 

Supt. of Docs. no.: 128.23: 9063. 

1. Gas, Natural-Colorado-Piceance Creek Watershed. 2. Methane-ColoradoPiceance Creek Watershed. 3. Oil-shales-Colorado-Piceance Creek Watershed. 

I. Schatzel, Steven J. 11. Series: Report of investigations (United States. Bureau of 

Mines); 9063. 

TN23.U43 [TN881.C6] 622 s [622'.81 86-600128 
CONTENTS 

Page 

Abstract ....................................................................... Introduction ................................................................... Acknowledgements ............................................................... Regional geolom ............................................................... Geologic and depositional history ............................................ Stratigraphy ................................................................. Structure .................................................................... Drill equipment and drill-hole configuration^..........^^......^^.^..^.^^^^^^.. 

Site geology and core lithology ................................................ Site geology ................................................................. Vertical hole core lithology ................................................. UV1 .......................................................................... 

UV6 .......................................................................... 10 

Results of modified direct method testing ...................................... 10 

In situ permeability ........................................................... 15 

Discussion ..................................................................... 19 

Conclusions .................................................................... 24 

References ..................................................................... 26 

Appendix.--Modified direct method procedure .................................... 28 

ILLUSTRATIONS 

Outline of Green River Formation within margin of Piceance Basin. CO ...... 2 

Cross section of Horse Draw Nine .......................................... 3 

Green River stratigraphy and location of mine workings at Horse Draw Mine 

and Cathedral Bluffs Mine site^....................^^.........^^........^ 6 

Location of holes drilled in Cathedral Bluffs Upper Void Level. with an 

enlarged view of the horizontal holes site ............................... 7 

Map view of Cathedral Bluffs Upper Void Level showing locations of tuff 

dikes .................................................................... 8 

Compilation of vertical corehole data from Upper Void Level. Cathedral 

Bluffs Mine .................................. e.mme( in pocket) 

Gases measured within container for sample UV208 .......................... 11 

Volumes of gases measgred within container for sample UV310 ............... 12 

Gases measured within container for sample UV102 .......................... 12 

Amount of methane desorbed from sample UV102 between each gas sampling. 

divided by the amount of time elapsed between each gas sampling .......... 12 

Sample UV303: gases measured within container; linear regression fit to 

desorbed methane data .................................................... 13 

Sample UH109: gases measured within container; second-degree polynomial 

fit to desorbed methane data ............................................. 13 

Sample UH210: gases measured within container; second-degree polynomial 

fit to desorbed methane data ............................................. 14 

Sample UH223: gases measured within container; linear regression fit to 

desorbed methane data .................................................... 15 

Hole UH2: variation of average equivalent fracture aperture and permeability with fluid pressure as measured by constant head ................. 18 
ILLIJSTRATIONS--Cont inued 

Page 

Actual Lneasured assay values for vertical holes before samples were 

 eight-averaged to match the desorption sample interval................. 

Correlation between methane content at 40 days of desorption and oil 

yield for holes UV1 and UV2............................................. 

Nethane contents of samples at 3 days of desorption. ..................... Methane contents oE samples at 40 days of desorption ..................... Methane contents of samples at 125 days of desorption .................... Mean and range of methane contents released from assorted rock samples ... Generalized apparatus...............b.........b.bbbbbbbb.........b....... 

Sample data-collection form.............................................. 

UNIT OF MEASURE ABBREVIATIONS USED IN THIS REPORT 

bbl barrel h hour 

" C degree Celsius hp horsepower 

c m3 cubic centimeter in inch 

cm3 lg cubic centimeter K kelvin 

per gram 

lb/f t pound per cubic foot 

~rn~/(~*h) cubic centimeter 

per gram per hour lbf (s /f t ) pound (force) seconds 

per square foot 

cP centipoise 

mD millidarcy 

D darcy 

mi 2 square mile 

f t foot 

mi n minute 

~t'ld cubic foot per day 

mm I-Ig millimeter of mercury 

f t/mi foot per mile (pressure) 

f t/min foot per minute Pet percent 

ft3/st cubic foot per psi pound per square inch 

short ton 

~sig pound per square inch, 

g gram gauge 

gal/rnin gallon per minute wt pct weight percent 

galls t gallon per short ton Yr year 
METHANE CONTENTS OF OIL SHALE 

FROM THE PICEANCE BASIN, CO 

By S. J. Schatzel,l D. M. Hyman,l A. Sainato,* and J. C. LaScola3 

ABSTRACT 

The Bureau of Mines determined the gas contents of 135 oil shale samples obtained frorn approximately 630 ft of core drilling. Drilling was 

done within a projected mining zone of the Cathedral Sluffs Mine, located in the Piceance Basin of western Colorado. Methane contents were 

determined by the modified direct method, which can measure the volumes 

of several gases released frorn or reacted with mine rock without destructive sample treatment. Over the duration of the test, nitrogen was 

largely unreactive, C02 increased slightly, oxygen decreased markedly, 

and methane increased more than the total increase of all contained 

gases. 

The gas volumes were normalized per unit sample mass and are given 

in cubic centimeters per gram. Common time irzdices for test duration of 

3, 40, and 125 days were used to compare methane desorption among samples. The means of the sample populations for these indices were 

0.0316, 0.114, and 0.195 ~rn~/~, respectively. These quantities are lower than those reported in a Bureau emissions study at the Horse Draw 

Mine in the Piceance Basin. Oil shale samples that were gas enriched 

beyond the mean methane contents frequently contained bitumens and 

pyrite. 

Geologist. 

2~4ining engineering technician. 

3~hysical scientist. 

Pittsburgh Research Center, Bureau of Mines, Pittsburgh, PA. 
sions from oil shale mine production. 

Some of this information is the result of 

work done at the Horse Draw Mine site 

(fig. 1). 

The Horse Draw Mine was developed by 

the Bureau of Mines in 1978 as an experimental mine. Between the middle of 1979 

and the end of 1981, the Horse Draw Mine 

was operated for the Bureau by the Multi 

Minerals Corp. Four mining levels were 

driven at the Horse Draw Mine, between 

1,840 and 2,230 ft below the surface 

(fig. 2). All of these depths are below 

the dissolution surface, which is the 

horizon where leaching of soluble minerals terminates and ground water sinks 

no deeper into the Green River Format ion. The minerals halite, dawsonite, 

and nahcolite, in addition to oil shale, 

were preserved and were planned mining 

coproducts. 

4~nderlined numbers in parentheses refer to items in the list of references 

preceding the appendix at the end of this 

report. 

I' Approx area underlain 

by Green River Formation 

FIGURE 1.-Outline of Green River Formation within margin 

of Piceance Basin, CO. (Adapted from Russell (2).) 
The relationship between methane and 

oil shale is supportable on a theoretical 

as well as an empirical basis. It is 

generally accepted that the preservation, 

degradation, and thermal alteration of 

1,840-ft leve organic matter in sediments can lead to 

the formation of methane in fossil fuels. 

Methane is known to be an inherent byproduct of the coalification process. 

Methane associated with petroleum is usually considered the result of thermal 

cracking, the breaking down of complex 

hydrocarbon chains under intense heat and 

pressure conditions into lighter and simpler compounds. Genetically, oil shale 

is related to certain unusual coals containing abundant spore and/or algal material. These coals have historical significance, but little current economic 

importance. 

Petrologic studies can be very useful 

in identifying the specific progenitors 

of solid organically derived fuels. The 

petrographic identification of organic 

matter in Green River oil shale is usually difficult owing to interactions with 

the mineral matrix, the fine-grained nature of the organic and mineral matter, and the disseminated state of the 

organic material. However, there is gen2,080-ft level eral agreement that the organic matter 

in the Green River oil shale is chiefly 

formed from algae. Partially because of 

Raise the relationship between oil shales and 

algal coals, some of the same controls on 2,130-ft level gas content in coals (depth of burial, 

temperature, age, geologic structure, 

etc.) have been suggested for oil shale. 

The decomposition of algae may also play Raise and stope an important role in petroleum genesis 

from oil source rocks (5). 

The Bureau recently undertook field 

Greeno sublevel experiments at the Cathedral Bluffs Mine 

Raise (fig. 1) to determine the amount of gas contained in oil shale and the behav- 2,230-ft level ior of the gas within the oil shale and 

in the mine atmosphere. Two holes were 

Ramp core-drilled horizontally from the Upper Void Level, each hole being about 200 ft 

Sublevel deep. These holes were drilled into the 

face of an exploration drift. They were 

oriented parallel to each other and separated by about 25 ft at the hole colFIGURE 2.-Cross section of Horse Draw Mine. (Adapted from 

Cole (3).) lars. In addition, six vertical holes 

were core-drilled from the Upper Void 
Level to betu~een 30 and 40 ft below the 

nine floor. 

The drilling of each hole was integrated with experimental tasks. The mail 

tasks were (I) to quantify the amount and 

conposition of gas cnitted frorn both the 

core and the hole, (2) to count and locate fract~ires intersecting the core, and 

(3) to record detailed core lithology. 

Following rernoval of an interval of rock 

sample, the sample lengtll was mea:;;lred, 

depths and orientation indicators Idere 

marked on the core, core loss intervals 

were assigned if necessary, and core 

E ractures were logged. Fracture orientat ion data were mer-lningful only relat ive 

to other fractures within a single reconstructed core interval 5ecause the 

core did not have an absolute orientation 

when drilled. Lithologic data were recorded next. All core logging was done 

in accordance ~ith Hartley and Beard (6), 

standard procedure for the cathedral 

Bluffs Pline. Once the descriptive lithologic logging was complete, the cored 

intervals were inserted into polyvinyl 

chloride (PVC) or steel containers. The 

containers were then sealed so that gases 

desorbing from the core would remain 

within the container. 

At the time of the planning of this 

study, there was no acceptable test to 

determine quantities of gas desorbing 

f rorn oil shale. The direct method test, 

designed to quantify methane in coal samples, has been used by the Bureau and 

other investigators on coal (7). However, adaptations of direct method testing 

to potential methane-emitting rock samples other than coal can produce less 

than sat is factory results. One problem 

is that preliminary data indicate that an 

oil shale sample may emit only one-tenth 

the amount of gas as that emitted by a 

coal sample of equal size. 5naller cltlantit ies of gas can lead to ercaneous r~- 

~111-ts when the amount4 of gas released 

approach the sensitivity of meas:ire~nent. 

3ecaiise oil shale call generally be expected to contain less nethane than coal, 

the sensitivity of direct neth hod testing 

would pose a greater problem. A second 

problem results Erorn the chemical composition of desorbing gas. Surcau experience with U.S. coalbed gas has identified 

its cornposition as generally at least 90 

pct CH4 and as high as 99 pct CH4. The 

direct method test incorporates no gas 

analysis in the technique and ass:lmes all 

gas to be methane. Without sabstant iation of similar oil shale gas composition 

or tile incorporation of gas composition 

analytical techniques, oil shale gas determinations by the direct method would 

be inadequate. 

A modified direct method test has been 

designed to measure an amount of gas 

which is siailar to that emitted from 

mined rock into the nine environment. 

This gas is normally diluted by ventilation air flow. The modified direct method can produce methane content data under 

field or laboratory conditions with an 

accuracy superior to that of the direct 

method. Reactions between gases emitted 

from the ore or within the mine atmosphere can be observed by compositionally 

analyzing and quantifying cllanging volumes of gas compounds. Quantifying standard temperature and pressure (STP) gas 

volumes at each point in time produces 

information on rates of gas released and 

reactions, which is considered essential 

in understanding methane emissions in oil 

shale mines. 

ACKNOWLEDGMENTS 

'The authors thank the following for 

contributing technical expertise in the 

co~npletion of this publication: N. Stellavato, senior geologist, Cathedral 

Bluffs Shale Oil Mine, for assisting in 

the design and operation of the study; 

J. Townsend, principal mining engineer, 

Cathedral Bluffs Shale Oil Mine, for 

technically reviewing the modified direct 

method test procedure; John A. Hartley, 

president, Ammeralda Resources, Inc., for 

description of the oil shale cor? and 

assistance in underground activities; and 

William E. Bruce, supervisory mining engineer, U.S. Mine Safety and Health 

Administration, for his technical input 

and for sharing his experience in other 

types of mines. 
REGIONAL GEOLOGY 

GEOLOGIC AND UEPOS L'r t0NAL HIS'rORY ai nerals arz preserved belo4 the dissolution s;irface and are leached oat above 

The Green Xiver Formation, located in 

t?le States of IJyorning, Colorado, and 

Utah, contains one of the world's largest 

kno~n deposits of oil shales. Deposition 

of these units took place ill response to 

o rogenic act ivity and subsequent downiJarping or1 the western slope of what are 

now tlle Rocky M0untai.n~. Two large intermontane lakes were formed. Take Uinta 

occupied the region known as t1ne Piceance 

Basin and parts of Utah, and persisted 

for 5 to 8 million yr (1). - The combined 

maximurl areal extent of the two lakes was 

about 20,000 mi2 (1). Evidence may exist 

for the initiation of mountain building 

in the Precambrian, although corltrol of 

sediment distribution did not begin until 

the development of the structural units 

in the Pennsylvanian, as described by 

Murray and IIaun (8). - The Grzen River 

Formation was formed during the Eocene 

epoch. The depocenter for the major oil 

shale units is located about 25 miles 

southwest of Meeker, CO. Several tuffaceous layers found in Green River oil 

shales are frequently used as marker beds 

and were produced during volcanic episodes concurrent dith orogenic activity. 

The deposltion of Green Xiver oil 

shales resulted from a combillation of 

conditions that led to preservation of 

the organic material. The intermontane 

lakes were quite saline, and conditions 

of surface waters were such that a food 

supply was available for micro-organisms 

to flourish (9). The lakes were sufficiently saline near the bottom so that 

the water was stratified, preventing mixing of the dense saline water with the 

more oxygenated surface water. Organic 

material flowing to the lake bottom was 

preserved under reducing conditions. The 

Hahogany beds make up a persistently rich 

layer of oil shale ranging from 50 to 200 

€-t thick in the Piceance Basin. During 

the deposition of the Nahogany beds, the 

formation of Piceance Basin saline minerals was most abundant near the basin's 

the surface. Leaching of salines leaves 

vuggy porr>s iyy, which is ell developed 

above the dissolut ion s:lrf ace. v- cvaporite mi neral-s are associated with 

oil shales in many areas of Colorado 

and IJyoming. The most abundant of these 

minerals are nahcolit P_ (NaHC03), ha1 i te 

(NaCl), dawsonite [NaAl(OH)2C03], and 

trona (Ya2CO3*YaHCO3*2H2O). Nahcolite 

beds are common in the oil shales of Colorado's Piceance Basin as interbedded deposits showing growth structclres that 

deforined surrounding oi l shale bedding. 

Evaporation and recession of the lake 

shoreline may have been important in deposition of the evaporites. Another mechanism for formation of these minerals is 

possible because of the production of C02 

during the decay of organic matter (10). -- 

The oldest unit of the Eocene Green 

River Formation is the Douglas Creek Yenher which is made up of light-colored 

sandstone and shales, as well as some 

limestone. In the northern portion of 

the Piceance Basin, the Douglas Creek 

grades into the overlying Garden Gulch 

Yember, which consists of gray marlstone, 

gray and brown shale, and some thin 

beds of oil shale. In the vicinity of 

the Cathedral Sluffs tract, the two units 

have a combined thickness of approximately 500 f t. The Parachute Creek Hember lies above the Garden Gulch. The 

Parachute Creek Yember is a gray, brown, 

and black marlstone with the persistent 

dark, rich oil shale beds such as those 

in the Nahogany Zone. Near the mine location, the total thickness of the Parachute Creek Xember is about 1,500 ft. 

The Uinta Formation rests on the Parachute Creeic Yenber and is composed of 

gray or brovn sandstone interbedded with 

marlstone and some thin oil shale beds 

0-1 

The Parachute Creek Yember of the Green 

center. Throughout the basin, saline River Formation contains the principal 
oil shale units. Stratigraphic units in 

the Parachute Creek are frequently differentiated in terms of oil yield due to 

the vertical lithologic consistency of 

the oil shales. The richness or leanness 

of the oil shale unit is signified by R 

or L, respectively, as in figure 3. (R7 

is commonly known as the Mahogany Zone.) 

Figure 3 shows a generalized stratigraphic column for the Horse Draw Mine and 

Cathedral Bluffs Mine sites. The locations of the mine workings are superimposed on the rock units. Although the 

elevations of the two mine sites are very 

different, the columns are matched at- the 

top of the A-Groove unit, showing the 

differing mining horizons. 

General stratigraphy, General stratigraphy, 

Horse Draw Mine site Cathedral Bluffs Mine site 

I--~our Senators 

It --Ignition Level, 1,182 ft 

-Groove 

--LUpper Void Level, 1,342 ft 

Mahogany Zone 

B-Groove B- Groove 

ff6 1 Level, ,620 fi 

Dissolution surface ZiK xSTRUCTURE 

ff5 

Within the Piceance Basin Eocene units, 

FDissoIution surface 

structural trends are quite gentle. In 

Rio Blanco County, there is a series of 

synclines and anticlines with axes generally ranging from east to west and 

from northeast to southwest (8). Dips 

are limited to no more than a couple 

of degrees. On the Cathedral Bluffs 

tract, beds strike east-west and dip 

northward about 150 ft/mi (approximately 

1.5") (11). 

underground mapping at Cathedral Bluffs 

revealed a few small-scale folds. The 

largest fold in the Lower Void Level was 

about 10 ft in amplitude and disrupted a 

vertical section about 50 to 75 ft in 

height. The fold axis had a strike of 

N 40" E, and the axial plane of the fold 

dipped 55" NU. Folds of this magnitude 

can be considered local features. 

Joint patterns on the mine tract have 

been noted by previous investigations. 

Stellavato recorded joint orientations 

at the surface and at all five subsurface levels in the mine (11). One set of 

joints was oriented at ~75" W with dips 

increasing from 66" on the surface to 90" 

at the Upper Void Level. Joint dips were 

found to increase with depth. In particular, pronounced joint steepening was 

measured just below the A-Groove. Also, 

joints were found to be persistent in 

lean oil shale units and to end abruptly 

FIGURE 3.-Green River stratigraphy and location of mine 

workings at Horse Draw Mine and Cathedral Bluffs Mine sites. 

at richer units. At the service and production shafts in the Upper Void Level, 

other joints had strikes of N 76" W, 

N 57" E, N 60" E, N 78" E, and east-west. 

Tuff dikes are frequently encountered 

in the Cathedral Bluffs Mine workings. 

They generally follow established joint 

patterns, especially the northeast-trending joints. Numerous tuff dikes were encountered on the Upper Void Level, ranging from 3 to about 12 in thick (11). 

The contact between the dike and the oil 

shale beds ranges from sharp and abrupt 

to very irregular. The source of the 

dikes may be a curly bedded tuff, which 

shows characteristic thinning and thickening and achieves a maximum thickness of 

18 in (11). This tuff is located just 

above the B-Groove (fig. 3). 
cuttings from becoming lodged between the 

inner barrel bit and the inside annulus 

of the drill bit. 

A platform was constructed on which to 

mount the drill for drilling the vertical holes. It was constructed of 1/8- 

in steel plate and H-beams, and it situated the drill about 50 in above the 

drill floor. Scaffolding was assembled 

to reach the required locations for 

drill string assembly, disassembly, and 

maintenance. 

The face drilled for the collars of 

horizontal holes UH1 and UH2 was stepped 

in shape (fig. 4). The added thickness 

of oil shale at the UH2 hole collar was 

highly fractured, probably as a result 

of blasting. Core drilling through this 

zone was highly inefficient since the 

drill tools had to be pulled from the 

hole many times, as the result of loss of 

drill fluid through unusually large fractures. The highly fractured rock also 

FIGURE 4.-Location of holes drilled in Cathedral Bluffs Upper Void Level, with an enlarged view of the horizontal holes site. 

UV6 /- ./- 

UVI Vertical hole 

- A Air door 

UV5 

1 \ 

u12 \, ', 

\ 

A 

D b 

A 

-0 

"7 

UV4 

' 

\, 

\, 

-uv3 

', 
depth at which core drilling began i.n attempted on hole UV1, but the influx 

each hole varied because of drill site of rubble necessitated reaning the hole 

conditions. Ideally, core drilling would with a drag bit. Holes IJV4 and UV6 were 

begin at the mine floor so that the en- rotary-drilled to depths of 4.1 and 1.7 

tire drilled interval could be recovered. ft , respectively, where core drilling was 

However, only holes UV2 and UV5 were begun. 4 hole was dug through the muck 

cored entirely, starting from the Upper to establish the collar of hole UV3. A 

Void Level :nine floor. At all other ver- short section of 8-in steel pipe was cetical hole locations, the presence of mented in place at a depth of 4.2 ft, and 

muck accumulations of varying thicknesses coring was initiated through the pipe. 

deterred core drilling the mine floor. Bedrock was encountered 4.5 ft deep in 

Core drilling froin the mine floor was the hole. 

SITE GEOLOGY AND CORE LITHOLOGY 

SITE GEOLOGY 

Upper Void Level (fig. 5). Most of the 

roof on this mining level is shotcreted 

in projects of this nature, drilling Tuff dike mapped 

activities frequently consuae so much during Bureau 

time that little is left for detailed 

geologic investigations. The most time 

available for observation in this study 

was at the site of the horizontal holes. 

Continuous laminations in the oil shale 

were easily traced across a rib, the 

face, and the adjacent rib, although color changes and sometimes thickness variations occurred within the confines of 

this site. Fracture or joint orientations were measured on a few locations 

and were found to be striking very near 

true north, roughly east-west, and also - LEGEND 

about N 45" E. All were steeply dipping. Tuff dike 

This is in general agreement with far 

water dr ippage a the FIGURE 5.-Map view of Cathedral Bluffs Upper Void Level 

openings , making geologic observations showing locations of tuff dikes. (Adapted from Stellavao (1 I).) 

impossible in these localities. 

more detailed data reported by Stellavato 

at the same locations (11). . -

A bed of nahco~ite~ersisted about N85OE --- 

9 ft above the mine floor, which showed 

boudinage-like growth structures throughout. The bed Production ranged in thickness from a 

couple of inches to about 2 ft. A tuff 

dike striking N 39" E was intercepted by 

UH2 and was readily visible in the rib 

adjacent to UH1. Holes UV3 and UV4 were 

situated near several identifiable dikes, 

corresponding to the area where Stellavat0 had mapped four tuff dikes on the 
VEK'TICAL HOLE COKE I,ITHOI,OGY 

Detailed lithologic descriptions of the 

cores were made before the cores were inserted into desorpt ion cannisters. Following completion of desorption testing, 

the cores were removed froin the airtight 

containers, and each of the six vertical 

holes were reconstructed and situated 

next to the nearest adjacent core in accordance with the drill hole sequence 

(fig. 4). No reliable marker bed Mas 

observed ~ithin the vertically drilled 

sequence to facilitate a lithologic correlation bet~een holes. Apparent rich 

and lean oil shale zones could not be cff ectively used for correlation probably 

because of laminae thickening and thinning and lateral changes in laminae color. The top of each hole, the Upper Void 

Level mine floor, was used for stratigraphic correlation. 

Core lithologies described below can be 

observed in figure 6 (in pocket). Fractured zones and mlgs partially filled 

with clay were encountered between about 

32 and 40 ft in four of the six vertical 

holes. These were zones of variable 

thickness. The holes with the greatest 

lateral distance to adjacent holes were 

the two holes at the end of the vertical 

sequence, hole UV5 (about 110 f t) and 

hole UV6 (about 165 ft). Holes UV5 and 

UV6 are characterized by harder, denser 

oil shale with fewer Eractures than 

the inside four holes have. The core 

from UV5 and UV6 was rernoved from the 

core barrel in fewer pieces. Occasionally, core from these holes was removed 

frorn the 5-ft inner barrel completely 

unbroken. 

lJv1 

Zones of core loss in UVl occurred between footages 5.9 and 8.4, 17.6 and 

20.2, 36.2 and 36.8, and 44.7 and 45. 

Solution fractured and brecciated zones 

were located bet~ecn 34.2 and 37.6 ft, 

43and 43.7 ft, and 44.5and 44.7 ft. 

Gas flowed frorn the hole upon penetration 

Selod 36.2 ft, a core 1-oss interval, and 

just below 41 Et in an area of oblique 

and longitudinal fractilres. Yethane-rich 

gas also emanated from the bottom tj~o 

f ract~ired-brecciated zones. The first 

and third of these gas-producing horizons 

also ejected water from UVl. Tuffaceous 

layers were located at 8.4 to 8.7 ft and 

at 25.5 to 26.4 ft, pyritic layers Erorn 

20.2 to 21.8 ft, and 26.5 to 30.6 ft. A 

marl-rich interval was intercepted hetween 4 and 5.9 ft, and calcite and 

kaolinite mineralization frequently accompanied f ractclred and vuggy horizons. 

Bitumen appeared only sporadically in 

UV1. 

uv2 

Two zones of core loss were located in 

UV2; from 4.4 to 5 ft and frorn 31.3 to 

32.3 ft. Other vuggy and/or highly fractured zones were located at depths oE 

34.7 to 36.8 ft and 39.2 to 40 ft. Marllime-rich horizons were found near the 

top of the hole from 1.7 to 3.5 ft and 

from 5.2 to 8.4 f t. Bitumen is abundant 

in the upper two thirds of the hole, occurring with kaolinite and pyrite between 

O and 3 ft. Another bitumen-rich layer 

occurs between 15.5 and 17.5 ft, with associated marly streaks. Below this zone, 

pyrite, kaolinite, and calcite, are found 

in zones of fractured vuggy oil shale. 

gale UV3 penetrated densely fractured 

and vug-prone zones from 27.4 to 28 ft, 

from 33.2 to 35.5 ft, and from 36 to 

39.2 ft. Core loss intervals occurred 

just below the First and last of these 

zones, and the methane-producing horizons 

in UV3 were located just above the uppermost zone and in the middle zone. Bitumen and pyrite were abundant, with the 

greatest combined concentrations found 

between 13.5 and 28 f t and between 31 and 

34.5 ft. Calcite, kaolinite, and some 

pyrite were associated with the upper two 

fractured zones. 
the cored intervals were mostly unbroken 

and without core loss zones. Kaolinite 

Three core loss zones were penetrated 

in hole UV4--between 13.4 and 14.8 ft, 

between 20.9 and 21.9 ft, and between 

37.7 and 39.2 ft. Water and methane-rich 

gas were discharged from the middle zone 

and also from a thin kaolinitic and 

bitumen-rich zone from 12.3 to 13.7 ft. 

Additional zones of dense fracturing and 

dissolution were found from 15.3 to 17.5 

ft, 33.1 to 36.3 ft, and 36.9 to 37.6 

ft. The lithologies below 29.5 ft were 

highly tuffaceous; a tuff dike occupied 

about a third of the cross section of the 

core from 29.5 to 32 ft, and the lower 

two vuggy zones were very tuff rich. The 

top of a 0.6-ft tuff layer was located at 

26.3 ft. Kaolinite and pyrite were found 

in fractured and water-producing zones; 

bitumen and pyrite were found from 4.1 to 

about 7 ft. 

Core from hole UV5 was characterized by 

"poker chips" (closely spaced, regularly 

occurring partings) from 1.6 to 7.2 ft 

and 18 to 22 ft. Outside these portions, 

mineralization was generally associated 

with fractures between 1.7 and 3 ft, 17 

and 20 ft, and 21 and 29 ft. Two zones 

of solution fractures were encountered, 

fron 23.5 to 27.5 ft and from 35.5 to 

37.5 ft. Limy zones with associated tuff 

stringers were intercepted between 9.5 

and 12 ft and 30 and 31 ft. Bitumen was 

found between 17 and 20 ft. Finely disseminated pyrite crystals were located 

between 34.5 and 37 ft. Two zones of 

small vugs (usually less than 0.5 in 

across their longest axis) were logged 

from 21 to 30 ft and 31.5 to 37 ft. 

The most frequent material identified in the UV6 core was bitumen. The 

bitumen-rich intervals were located between 9 and 10.6 ft, 15.6 and 18.5 ft, 

and 25.5 and 29 ft. Infrequent calcite 

and kaolinite mineralizations were found 

on fracture planes. Methane gas was encountered in hole UV6 at 16.5 f t; gas 

flow was greatly reduced after 5 min. 

RESULTS OF MODIFIED DIRECT METHOD TESTING 

The modified direct method test (MDM) 

was conducted on essentially all cored 

oil shale samples drilled during the 

course of this study. A total of 631.1 

Et of oil shale was core-drilled, although all core was not recovered. The 

recovered shale was divided into 76 horizontally cored desorption samples and 

59 vertically cored desorption samples. 

Sample lengths were usually determined by 

the length of core recovered in a single 

core barrel run. 

The 135 oil shale core samples sealed 

in airtight containers were gas-sampled 

repeatedly during the study. Each Sampling included recording the date and 

time of sampling, measuring the dif f erential pressure between the container atmosphere and the mine atmosphere, retrieving a gas sample of the container 

atmosphere, bleeding the container gas 

pressure to mine atmospheric pressure, 

and recording the temperature and 

atmospheric pressure at the underground 

work station. The duration of gas desorption monitoring was nonuniform because measurements began as soon as the 

core sample was removed from the hole and 

placed in the airtight container. As a 

result, the position of the sample in the 

hole and ' in the drill hole sequence determined the duration of desorption 

monitoring. 

The concentration of gases at each Sampling was multiplied by the STP total 

contained gas volume. After the completion of gas sampling, the gas volumes can 

be totaled to find the amount of gas liberated (or consumed) over a known period 

of time. Some deviations to this procedure did occur, and the MDM test is discussed in greater detail in the appendix. 

To compare gas desorption and/or reactions between samples, it was necessary 

to eliminate inconsistencies in test duration and sample size. Time indices were 

chosen to facilitate sample comparison. The longest common duration of NDM 
testing for a group of core samples, vertical or horizontal, was chosen for the 

index: a 40-day (960-h) index for the 

vertically cored samples and a 125-day 

(3,000-h) index for the horizontally 

cored samples. The horizontal core Sample gases were also indexed at 40 days so 

they could be compared with the vertical 

samples. In addition, a 3-day (72-11) desorption time index was determined, to 

simulate that period of time gas would be 

released from a muckpile before being removed f rorn the mine environnent. All gas 

totals were divided by the sample mass, 

providing weight-normalized gas quantities for interpretation. Although there 

is precedence for metal and nonmetal gas 

normalization on a basis of cubic centimeters per 100 g, gas normalization on a 

basis of cubic centimeters per gram was 

chosen to be more easily related to the 

convention of existing coal desorption 

data. Multiplying these numbers by 32 

converts the data to cubic feet per short 

ton. 

Previous investigations on coal and oil 

shale gas desorption have shown a linear 

relationship for cumulative methane when 

graphed in terms of the square root of 

time (1). Figure 7 shows a graph of 

square root of time in hours against cumulative gas volume per unit weight. The 

sample shown is labeled UV208, indicating 

oil shale removed from the eighth coring 

run on the second vertical hole drilled 

from the Upper Void Level during this 

study. This sample is an example of 

typical behavior of the gases as shown by 

the MDM test in the latter portion of 

this study. Error analysis of the MDM 

technique showed an additive effect of 

inaccuracies in volume measurenents. 

Relatively infrequent gas sampling was 

important to maintain optimum accuracy in 

gas content determination. Cored intervals removed fron drill holes early in 

the study were gas-sampled as many as 13 

times. Oil shale core produced later in 

the study was gas-sampled three to six 

times, and the duration of MDM testing 

was much shorter. 

For sample UV208 (fig. 7 the volume 

of nitrogen was quite high at the beginning since the mine atmosphere was enclosed in the sealed container at the 

start of the test. The volume of nitrogen decreased slightly. Oxygen decreased 

steadily in volume during the test interval. The slope of the oxygen curve is 

much steeper than the slopes of other 

atmosphere-contained gases, such as nitrogen, which were not emitted in measurable volumes from the oil shale sample. 

Presently, it is not clear whether oxygen 

is lost because of sorption onto surface 

sites on the oil shale or whether oxygen 

is consumed by low-level oxidation reactions. The decrease in oxygen was not 

accompanied by a significant increase in 

CO or C02, as was noted in some trona and 

coal mines where self-heating reactions 

were found to occur (12). - C02 increased 

in volume with time. However, the total 

volumetric increase was small compared 

with that of the more abundant and more 

reactive gases. The volume of methane 

increased markedly over the course of 

this test. The 40-day indexed value for 

methane content equals about 31 on the v square root of time axis and equals 0.116 

KEY - cm3Ig. Oxygen, nitrogen, and COz were .-.-. n dV also measured by indexing. An indexed 

-- - O2 - methane content value is estimated by inN2 0.' 

0 - ...-... terpolating a straight line between the - closest data points before and after 

the chosen time index. Figure 7 shows - a substantial increase in overall gas 

volume (dV) over time. The total in10 20 30 40 50 60 crease in gas volume is smaller than the 

TIME, h% increase in methane alone, largely because of the volumetric decrease in FIGURE 7.-Gases measured within container for sample UV208. The dashed line shows the time index value for methane Oxygen. bough le cOm~ ar 

content at 40 days. favor normalizing gas volumes on 
a weight or mass basis, figure 8 shows 

the changing contained gas volumes .ig 

cubic centimeters for sample UV310, to 

show tile scale of the nea:;:lred data from 

a 5-ft core sample of oil sha1.e. 

A linear increase in methane from oil 

shale over time as aeasared in the square 

root oE hours was Eound not to be exact 

in marly cases. Similar data plots of a 

number of samples show a tendency towards 

curvature. The curves are generally concave down. The curved methane plots 

have been fitted to second-degree polynomials very successfully, with tile coefficient of determination (r2) values generally in excess of 0.98. Another graph 

was made to better discern whether the 

second-degree polynomial was a better 

description of the oil shale desorption 

data. A sample was chosen that was gassampled frequently and that showed a relat ively linear increase OF culnulat ive 

methane volume when graphed against the 

square root of time (fig. 9). The difference in gas volume between successive 

points for sample UV102 was Eound and 

divided by the amount of time, in hours, 

that passed between the two points. 

These gas volumes vere graphed against 

time in hours to show how much methane 

was released per unit time from the core 

and to illustrate how these volumes 

changed over time (fig. 10). The curve 

shows the largest amounts of gas released 

per unit time were at the beginning of 

the MDM test. The curve declines quickly 

and approaches the X-axis asymptotically. 

"-- 

KEY 

- .-.-. dV 

-4 02 

- - N2 -...-... 0 c02 -- 4 CH4 

10 20 I 30 40 

TIME, h'2 

The aforement ioncd plot of incremental 

gas volumes per unit time against time 

essent ially represents the dorivat ion of 

the graph of cumulative gas versus square 

root of time. Linear plots on the latter 

graph have the form y - al "'l2+b. The 

first derivative with respect to time 

dould be dy/dT = a(l/~'/~). Seconddegree polynomi,-rl curves on tile cum~llirit ive-gas-ve rsus-t ime graph have the form 

y = a(~'/~)~ + ST"^ + C, where the first 

derivative with respect to time is dy/dT 

= a + b(l/~'/~). A graph of y = (1/~'/~) 

is very similar to the shape of the curve 

shown in figure 10. The derivative of 

the second-degree polynomial is very similar to the derivative of the linear, 

except that a constant is added. This 

would increase the Y-intercept of the 

plot. Since the gas desorption rate is 

high at the beginning of YDM testing 

but declines so rapidly, infrequent gas 

TIME, hb 

FIGURE 9.-Gases measured within container for sample 

UV102. 

0 1,000 2,000 3,000 

TIME, h 

FIGURE 10.-Amount of methane desorbed from sample 

FIGURE 8.-Volumes of gases measured within container for UV102 between each gas sampling, divided by the amount of 

sample UV310. time elapsed between each gas sampling. 
sanpling at the beginning of the test 

averages high rates of desorption with 

lower ones that occur shortly thereafter. 

>lore frequent sampling at the beginning 

of gas monitoring reduces the av2raging 

of high and lo^^ desorption rates and increases the Y-intercept of the graph. 

This is consistent ~ith the forin of the 

first derivative of the second-degree 

polynomial. It appears that sampling 

frequency and duration of testing can af - 

fect the shape of the graph of cun~ll~ative 

gas versus square root of time and that 

second-degree polynomial cllrve f its to 

some graphs are better approxinat ions of 

the observed desorpt ion phenomena. 

An example of a successful linear curve 

fit is given in figure 11. Sample UV303 

is shown with gas volumes normalized per 

unit mass in figure 11A. The methane 

content of this sample is lower than 

t?~at of the majority of Cathedral Bluffs 

samples. At the 40-day time i,~dex (31 

h'"), UV303 desorbed 0.0750 crn3Ig CH4. 

The curve fit in figure 11B shows methane 

data only. The time between the Y-axis 

and the first data point represents the 

estimated lost-gas period in square root 

of hours before the sealing of the core 

1 

A 

KEY 

.-.- a dV 

-- - 02 

-...-... N2 

0 C02 

--* CH4 

0 5 10 15 20 25 30 35 

TIME, hh 

FIGURE 11 .-Sample UV303: A, gases measured within container; B, linear regression fit to desorbed methane data. 

samplc in an airtight container. The nitrogen ccirve in 11A ha:; three points iqstead of four ,~ossibly because either nitrogen analysis was not done on the gas 

sample or a gas-sampling or gas-analysis 

nalfl~nct ion occrirred. 

Figure 12A presents a graph of gas volume per unit mass plotted against square 

root of time for sample UH109. Sample 

Uli109 produced a larger quantity of met11- 

ane than did most other Cathedral Sluffs 

samp1t.s undergoing MDM testing. The 

time-volurnet ric methane indices for this 

sample are 0.0804 and 0.253 cn3Ig at 3 

and 40 days, respectively. Also, the duration of testing was Ear longer for this 

sample, 132 days, than for those sanples 

presented thus far. The plot shown has 

heen interpreted as an example of a concave-clown plot of methane per anit mass 

versus square root of time. It possesses 

all three of the qualities recognized 

as conducive to producing concave-down 

plots: 

1. The duration of testing was long, 

so that high early desorption rates were 

combined on the same graph with lower 

ones occurring later in the test. 

,/- ,.0.- KEY 

Od,,.O. .-.-. dV 

,0<." .I5 -- 02 

-7 ././. - N 2 

B KEY 

- 

CH4 

y= -4.695771-~ x2 

+0.010113~-5.691627-~ 

r2 = 0.999 

LLI 

0 10 20 40 5 0 60 30 1 

TIME, h'2 

FIGURE 12.-Sample UH109: A, gases measured within container; B, second-degree polynomial fit to desorbed methane 

data. 
2. Frequent gas samples were taken at 

the beginning of the test to minimize 

averaging high desorption rates with 

lower ones that followed. 

3. Compared with other samples in the 

study, this sample is relatively gas 

enriched. 

Figure 12B shows only methane data 

plotted on a graph of normalized cumulative gas volume versus square root 

of time. A second-degree polynomial was 

fitted to this data. For X = TI/', 

y = -4.696 x ~o-~x' + 0.0101X - 5.692 

x This equation fits the data with 

an r2 coefficient of determination equal 

to 0.999. Methane-rich gas flowed from 

the hole during core drilling at a depth 

of 45 to 47.5 ft. The UH109 desorption 

sample interval contains core from 41.8 

to 51.3 ft of hole UH1. This core sample 

is gas enriched beyond the majority of 

oil shale samples presented here and included a gas-flow-producing zone. An association between methane flows from a 

drill hole and high methane contents from 

the same footage interval is tentatively 

supported. 

Hole UH2 also contained examples of 

gas-producing zones. High-concent rat ion 

methane gas averaging 95.1 pct, measured 

by gas chromatography on gas samples, was 

released from hole UH2 at a depth of 

about 59.2 ft. Average gas concentrations of 02 + Ar, N2, C02, and C2Hh measured 0.45 pct, 2.8 pct, l. 65 pct, and 

0.01 pet, respectively. The first signs 

of a free-flow gas zone were observed at 

about 57 ft. When the hole was sealed at 

about 59.2 ft, no pressure buildup was 

observed; however, the equipment used was 

not sensitive enough to register a pressure buildup of less than about 10 psi. 

Gas flow measurements of up to 20,000 

ft3/d were neasilred following coring to 

63.5 ft. Manometer readings of gas flows 

through an orifice plate were oscillating 

greatly as water and gas blew out of the 

hole. The interval from 57 to 63.5 ft 

was divided between two desorption samples for MDM testing, UH210 and UH211. 

Unfortunately, gas sampling of sample 

UH211 was not successful in obtaining 

representative contained-gas concentrations early in the duration of YDM 

testing, and no gas data are available 

after that time. 

Figure 13 shows a plot of the square 

root of time versus cumulative gas volume 

per mass for sample UH210. Some deviations from smooth predictable trends oE 

gas behavior can be seen at about the 5- 

and 29-h1/2 times. These have been attributed to atmospheric contamination of 

the contained gases. This phenomenon is 

usually indicated by increases in the 

volume of gases that are abundant in atmosphere, such as nitrogen and oxygen, 

and a decline in those gases that are not 

contained in the atmosphere, such as 

methane (fig. 13A). In terms of the 

overall sample gases, the erroneous gas 

data is not extreme, and this graph is 

still useful in showing trends of gas 

data. The methane data is fit to a 

second-degree polynomial in figure 13R. 

The equation is given, and the r2 

/' 

/' 

KEY 

.-.-.o dV 

- ---O o2 N2 - . . . - . . . 0 C02 --4 CH4 

I -- 

I I I L 1 I J 

0 10 20 30 40 50 60 70 

TIME, h1'2 

FIGURE 13.-Sample UH210: A, gases measured within container; B, second-degree polynomial fit to desorbed methane 

data. 
the interval. 

Me thane gas flows were observed again 

in UH2 at a depth of about 115 ft and at 

a terminal depth of 197.9 ft. Chromatography on gas samples taken at the hole 

collar once terminal depth had been 

reached averaged 80.47 pct CH,, 15.57 pct 

N2, 3.84 pct 02 + Ar, 0.44 pct C02, and 

about 0.02 pct C2H6. The last two desorption samples from UH2 were interrupted during MDM testing by experimental 

irregularities. The last two desorption 

samples for hole UH2 that yielded reliable experimental data measured from 

172.1 it to 180.9 and from 180.9 to 

182.4 f t and resulted in 40-day indices 

of methane contents of 0.101 and 0.147 

cm31g, respectively. The deeper of these 

coefficient of determination is 0.995. 0.25 

At the 40-day methane time index, sample 

UH210 has desorbed 0.295 ~rn~/~, one of 20 

the highest gas quantities in this study. 15 

In this case, methane enrichment in the 

desorption sample corresponds well with 10 

two samples shows a significant degree of 

- -- 

methane enrichment. 

Desorption sample UH223 contains the 

gas-producing horizon at a depth of 115 

ft. Figure 14 shows the graph of the 

square root of time versus cumulative 

volume divided by mass for this sample. 

Although an atmosphere leak appears to 

have occurred during MDM testing, it did 

not significantly affect the overall 

gas emissions encountered while drilling 

1 I I 

w A * 

KEY 

.-.-.o dV 

-- - 02 

N 2 /a 

-... -... 0 C02 / /// .n 

-- /.A,/ -0 CH4 

,+.. * ...-...-.,, 4.0 ..-... 0- ...-...-...-...-...-... 0 

I I I 

V) 

03 0 a 

5 

\ 

w -.050 

5 20 40 60 80 

3 2 0.14 I -- 

> KEY 

'I2- CH4 

.lo- - y=2.069715-~~ 

.06 - 

r 2 = 0.991 

0 10 20 30 40 50 60 70 

TIME, ht'2 

FIGURE 14.-Sample UH223: A, gases measured within container; B, linear regression fit to desorbed methane data. 

desorption curve in figure 14B. The 40- 

day methane index for this sample measures 0.0619 ~rn~/~, which is below the 

40-day indexed value of the majority of 

Cathedral Bluffs samples. No quantitative gas measurements were taken from the 

drill hole at a depth of 115 ft, but gas 

could be seen bubbling from the returning 

drilling water. 

IN SITU PERMEABILITY 

The in situ hydraulic conductivity de- One measures the steady-state fluid flow 

terminations were performed using a discontinuum approach described by Bennett 

and Anderson (13). - In this approach, the 

significant permeability is attributed 

to the fractures intercepted by the test 

interval (a 5.5-ft section isolated by 

inflatable packers); the unfractured 

rock matrix does not make a significant 

from the test interval into the fissure 

at a constant head or pressure. The 

other, the falling-head method, is performed by injecting water into a test 

interval and measuring the pressure drop 

over a period of time. The average 

equivalent aperture (e, in inches) for a 

constant-head test is calculated from 

contribution. The average equivalent 

aperture of the fissure was calculated, e = [(l/n) [Q/(~~Ho)I (121Ju/Yw) 

and the average fracture permeability 

calculation was made assuming a parallel- [In (RI~O)]]"~, (1) 

plate model. Two test methods were used. 
where n = number of intercepted fractures; 

Q = measured steady-state waterflow rate, gal/min; 

H, = applied waterhead, ft;5 

p, = dynamic viscosity of water, cP = 1147,880 lbf*(s/ft2); 

Y, = unit weight of water, 62.4 lb/ft3; 

R = radius of influence, which is assumed to be half the test interval 

length, ft; 

and r, = radius of borehole, ft. 

When the units used in this report are inserted, 

[12 (1147,880) ~bf.(s/ft~) / 11 [In (R/r,)] 

where P - Po = pressure differential. 

Simplifying the above equation yields 

R and ro should be measured in the same units so that R/ro becones a dimensionless 

quantity. 

The perneability (K) of the average fissure from above is 

The intrinsic permeability (k) is given by 

Substituting for e and simplifying, 

k = 6.041 x lo-' { [Q/(~(P - Po))] 1n (~/r,)]~/~. 

Converting the above equation from square feet to millidarcies and simplifying 

gives 

k = 5.686 x 10"~ [[Q/(~(P - Po))] in (~/r,)]~/~. (4) 

The equivalent aperture concept is used because the surface roughness of the fracture 

was not known. The equivalent aperture is essentially the width of the fracture if 

that width is conceptualized as being wide enough such that the real surface roughness of the fracture becomes quite small. A parallel-plate model is used to approximate the fracture configuration to determine its permeability. 

5~ennett and Anderson (1 3) measured waterhead in feet.. A conversion factor of 144 

(p - p,)/Y, is inserted into equation 1 to convert Ho to units of pounds per square 

inch to be consistent with other units in this report. 
For the falling-head test, the average equivalent aperture is calcul.ated by 

Substituting the units used in this report, the above equation for e becomes 

= {[(r02 ft2) / (2n ~t min)] [12 (1147,880 lbfo(s/ft2) 

where H,, and Ho2 = test interval pressures at t 1 and t2, respectively, psi; 

tl and t2 = initial and final times, respectively, corresponding to a set of 

permeability data; 

and At = t2 - tl, min. 

Simplifying the above equation yields 

All other variables have the same meaning and are measured in the same units as in 

the equation for the constant-head case. 

Under pressure-drop conditions, 

k (single fracture, intrinsic) = (IJ,/~~) [ro2/(2n Ate) I [In (Ho /Ho2) I 

After the units used in this report are inserted, a substitution is made for e, and 

the equation is simplified, it is found that 

This expression gives the intrinsic permeability of the average single fracture in 

the test zone in units oE square feet. To find k in terms of millidarcies, it is derived that 

Two intervals of hole UH2 were chosen for in situ permeability testing. Both intervals had produced methane gas flows from the hole during core-drilling operations. 

The test interval length, the separation between the two inflatable packers, was 

identical for both tests: 5.5 ft. The first test zone was located between 63 and 

68.5 ft. This portion of the hole was seen to be transected by fractures during logging; a total of 13 were counted. A constant-head test was conducted within this interval. Water was used as the test fluid for this and all other permeability tests 

conducted at the site during the study. The 63.0- to 68.5-ft section was tested at 

pressures of 565 to 600 psig. 
Graphs made from the experimental data 

show how both equivalent aperture and 

fracture permeability varied with increasing pressure. In the shallow zone 

test (fig. 15A), both the equivalent aperture and the permeability decreased 

with increasing pressure. It is difficult to account for this behavior. Test 

pressures were below the hydraulic fracture gradient as determined by Briedenhoft (14). The personnel on-site indicated that the pump used during the test 

was functioning at maximum flow capacity 

in generating the 600-psig pressure. 

Although the gauge at the collar of the 

hole registered 600 psig, an unstable 

pressure differential within the tested 

interval could account for the performance shown in figure 15A. Those portions 

of the test section at the greatest distance from the hole collar may not have 

been pressurized to the test pressure because test fluid was removed via fracture 

permeability more rapidly than pressurized water was flowing in. If this condition did exist, it would eventually 

produce falling pressure at the gauge, 

but the test duration of about 68 min may 

not have been long enough to record a 

pressure drop at the gauge. The data do 

show that permeability and fracture aperture decreased with time, with the test 

pressure beginning at 560 psi and ending 

at 600 psi. The unusual relationship observed between fracture aperture and permeability and fluid pressure may also be 

attributable to alteration of the in situ 

stress field in the vicinity of the shaft 

by shaf t-sinking operations. The capacity of the induced fracture reservoir may 

have been too large for the test fluids 

to fill. 

t 1 1 I I 1 1 

- - 

- - 

- . . - 

t 

- A, Shallow test zone 4 

a - 7 

a - - 

a 

a - 

I I I I I 

2GO B, Deep test zone 

PRESSURE ( P - Po), psi 

FIGURE 15.-Hole UH2: variation of average equivalent fracture aperture and permeability with fluid pressure as measured by 

constant head. 
The deeper test interval in hole UH2 

extended from 115 to 120.5 ft. The constant-head test was maintained at 900 

and 1,000 psi. Figure 15R presents the 

equivalent aperture and average fracture 

permeability, graphed against absolute 

pressure in the test interval. Although 

only two pressures were maintained during 

this test, there does appear to be an increase in equivalent aperture that ranges 

from less than 0.0023 to over 0.0025 in 

at 900 psi and from over 0.0029 to just 

under 0.0031 in at 1,000 psi. Some of 

these separations overlap those determined in the 63.0- to 68.5-ft interval at 

lower pressures. Permeabilities in the 

deeper test section of hole UH2 ranged 

from about 280 to over 500 D. At lower 

pressures in the shallower test section 

of UH2, the determined permeabilities 

ranged from about 395 to 435 D. 

DISCUSSION 

Figure 6 presents geologic data for 

each of the vertical holes. The horizontal distance between hole collars is 

not given, but depth is shown to scale 

as distance in feet below the Upper 

Void Level mine floor. The desorption 

sample number in the leftmost column. 

The next column gives lithologic information about the core. The relative lithological abundance is given by the number 

or density of symbols indicative of the 

appropriate constituent. The next coll~mn 

is a histogram showing oil yields as determined by modified Fischer assay by 

Dickinson Laboratories, Inc. The assay 

sample sizes were generally 2 ft or less. 

The measured assays are given in figure 

16. A high degree of lateral continuity 

in grade is apparent. These data were 

normalized to match the desorption sample 

interval by a weighted average. Sample 

mass was determined by multiplying the 

volume of the oil shale sample by its 

specific gravity. Specific gravities 

were calculated using Smith's empirical 

relationship between oil shale density 

and oil yield (15). 

The next column to the right on figure 

6 is another histogram showing the 40-day 

index of methane content per unit mass as 

measured by desorption in a closed container. The column on the right gives 

the location and quantity of fractures in 

the core. Distinctions are made between 

fractures and bedding plane separations. 

Also, different types of core breaks are 

accounted for. Where fractures occur too 

close together to map accurately, a symbol (shown in the key) gives information 

about fracture density. 

Figure 6 allows the qualitative evaluation of interdependence between several 

factors. In general, gas flows emanated 

from fractures, vugs, fracture planes 

coated with kaolinite, and core loss 

zones. The relationship between gas 

-Approx location of Upper Void Level mine floor 

Depth, 

lo[ 0 ft 

0 20 40 60 80 100 0 20 40 60 80 100 0 20 40 60 80 100 0 20 40 60 80 100 0 20 40 60 80 100 0 20 40 60 80 100 

GRADE, gal /st 

FIGURE 16.-Actual measured assay values for vertical holes before samples were weight-averaged to match the desorption sample 

interval. 
exists in a free gas state or dissolved 

in water before penetration by drilling 

operations. It woul-d not be necessary 

for this gas to remain near its source. 

However, reservoirs that produce gas appear to have been very limited in volume 

as they bled ofE within the duration of a 

single shift. Although the permeability 

data represent only an initial step toward understanding the reservoir characteristics of oil shale ore bodies, they 

do indicate high permeability, hundreds 

of darcies, within the fracture network 

of gas-producing zones. Although data 

fron this study on the permeability of 

unfractured oil shale are not yet available, previous workers have found the unfractured rock to have a permeability on 

the order oE microdarcies. 

It has been postulated that an association might exist between the amount 

of methane enrichment and the oil yield 

richness of oil shale fron the same Sample upon retorting. Predictions of oil 

shale specific gravity based on oil yield 

imply a relationship between assays and 

the actual amount of organic matter contained in a sample. The histograms in 

figure 6 do not qualitatively support an 

association bet~een methane content and 

oil yield. A quantitative approach was 

at tempted by graphically representing 

methane desorbed per unit mass in terms 

of oil yields, in figures 17A and 17B. 

An association is not supported by either 

of these plots. Similar graphs were prepared for other gases with similar results. Nitrogen was quite unreactive. 

C02 generally increased slightly in volume but was not highly reactive, and the 

calculated quantities of C02 are less 

reliable with increasing test time as 

additive experimental errors increase. 

flows during drilling operations 'and gas 0 12 

enrichment neasured by MDM gas desorption II 

testing was tentatively upheld. It may lo 

be that methane flows are better cotre- 09 

lated with the form or structure oE the 

08 methane-2nitting zone than with its de07 sorption gas content or chemical conposi- 06 tion. This is a somewhat appealing pren- F 

I()E 05- ise because methane that readily f lo~s 

04- 

08 I I 1 

25 30 35 40 45 50 55 60 

OIL YIELD, gallst 

I 

- 

- 

- a 

- 

- 

- 

a 

6 

2 0.18 I T I I ! I 

FIGURE 17.-Correlation between methane content at 40 days 

of desorption and oil yield for holes UV1 and UV2. 

from a drill hole is probably mobile and 20 2 5 

x 

W 

,, 6 5 

Oxygen can also be problematic in terms 

of additive experimental error because 

its volume decreases over time. Graphs 

of oxygen per unit mass agaigst oil yield 

did not show them to be correlative. 

The parameter shown in figure 6 that 

directly and most consistently varies 

with methane content appears to be the 

occurrence of asphalts or bitumen and 

sometimes pyrite. Asphalts in the context of this study refer to streaks or 

small, rounded inclusions of bituminous 

material found in the core. The finegrained, dispersed nature of this material suggests that the organic materials 

in the oil shale have been the source of 

the bitumen formation. The exact mechanisms for this formation are not totally 

understood; however, associations between 

bitumen and oil shale are common in the 

Uinta Basin. 

Three primary factors are recognized as 

influencing the type or chemical composition of bitumen produced in environments 

of oil shale genesis. The first factor 

is suggested by petrologic investigations of coal. It has been shown that 

KEY uv2 

- Normalized difference 

in CH4 at 40 days 
the specific botanical conposition of 

coal proge~litors is an inportant Factor 

in the physical and cl~emical makeup of 

the coal formed. The pr~genitors of 

Green River oil shale and rare algal 

coals are similar, so it is arlticipated 

that both oil shale and coal share this 

primary control. Oil shale does contain 

far more mineral matter than conventional 

coal. The other recognized primary factors of bitumen Formation are related to 

the chemical environment of the ancient 

lake oE oil shale deposition. It has 

been inferred that the lake waters varied 

chemically through time, and differing 

bitumens are preferred on the basis of 

the salinity of the environment where 

they form (16). - The third primary control of bitunen formation is the avalla b i l i t y o r depletion of oxygen during 

deposition and burial of the bitumens' 

precursors. The degree of reduction in 

the lake waters favors the chemistry oE 

certain bitumens (16). - 

A secondary control might result from 

differences in the chemical and physical 

stabilities of the bitumens and/or their 

precursors. These stabilities could determine the presence or absence of the 

substances now found in the rock. The 

pyrite sometimes associated with these 

bitumens probably resulted from reduction 

of sulfate to sulfide, which combined 

with iron from mineral matter, similar to 

pyrite formation in coal-forming swamps. 

Figure 18 shows the frequency distributions of methane contents indexed to 72 h 

of desorptions for the total sample population (n) in this study. The mean (X) 

of the samples is 0.0316 cm3/g, with a 

standard deviation (S) of 0.0169 cm31g. 

Experimental malfunctions reduced the total sample population from 134 to 119 at 

72 h and to 100 at 40 days. The bimodal 

distribution of the vertical holes has 

not been accounted or The slightly 

higher degree oE methane enrichment of 

the horizontal hole samples might be 

attributable to shorter lost-gas tines 

or to gas enrichment OF the horizon(s) 

drilled by the horizontal holes as opposed to the diversity of oil shale beds 

and nethane contents penetrated by the 

vertical holes. These postal-ntes are not 

substantiated. l7 rigur~ 19 presents methane contents of 

the sample population on a 40-day time 

index. The mean of the group is 0.114 

cm3/g, with a standard deviation of 

0.0505 c~n~/~. A bimodal distribution for 

the vertical hole samples and a slightly 

higher degree of methane enrichment €or 

horizontally derived samples is apparent. 

Figure 20 shows the 50 horizoiltal hole 

samples indexed to 125 days of methane 

desorption. Similar to data shown in the 

previous two figures, the overall distribution is skewed to the left, toward the 

loder end of the scale. The data of figure 20 have a mean of 0.195 cm3/g and a 

standard deviation of 0.071 ~m'/~. 

The composition oE gas released from 

oil shale samples can be estimated from 

this study. The gases rvutinely analyzed 

by gas chromatography included Ar, N2, 

02, C02, CH4 and, less frequently, CO and 

C2Hs. Of the seven oil shale samples 

discussed in the section "Results of Modified Direct Yethod Testing," five produced smooth and regular gas evolution 

and/or reaction curves indicative of reliable experimental execution. CH4, C02, 

and C2H6 were the only gases showing predictable increases in volume. Vitrogen 

showed an increase in some instances and 

a decrease in others. Nitrogen volume 

did not increase in a regular trend between sample points. Overall changes 

generally accounted for less than 10 pct 

of the N2 starting volume. When CH4, 

C02, and C2H6 were normalized to 100 pct, 

the five samples averaged 91.56 pct CH4, 

8.43 pct C02, and 0.01 pct C2H6. 

Comparisons can he made between the 

gas contents of oil shale samples and 

the gas contents of a variety of other 

rock samples. The methane content means 

and ranges of all oil shale samples are 

given for the tine indices of 3, 40, and 

125 days in figure 21. The units of gas 

content are cubic centimeters per gram. 

All three time indices for oil shale samples overlap with high-volatile bituminous coal (e.g., Pittsburgh Coalbed). 
METHANE CONTENT, cm3/g 

FIGURE 18.-Methane contents of samples at 3 days of desorption showing vertical corehole sample distribution 

and total sample distribution. 

However, the logarithmic horizontal scale 

shows the mean of high-volatile bituminous coal to be an order of magnitude 

higher than the mean gas content of oil 

shales reported for 40- and 125-day time 

indices and two orders of magnitude higher than the mean gas content of oil shale 

samples at the 3-day time index. Gas 

contents of Cathedral Bluffs oil shale 

samples at the 3-day time index are quite 

similar to outburst-type domal salt in 

both mean and range. This does not indicate outbursting tendencies in oil shale. 

It does show a resemblence between the 

volume of gas released from the gassiest 

domal salt type categorized by the Bureau 

and the amount released in the shortest 

time duration of oil shale gas-content 

testing reported here. There is overlap 

shown between the ranges of the 3- and 

40-day time indices of oil shale gas contents and the ranges of the other two 

salt types. 

It is not possible to account for the 

differing gas-content test methods for 

salt, coal, and oil shale. The MDM 

technique used on the oil shale samples 
- 

6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 44 

METHANE CONTENT, 10-~cm~/g 

FIGURE 20.-Methane contents of samples at 125 days of desorption showing horizontal hole sample distribution. 

involves no destructive sample treatment treatment. The direct method data reand measures gas released from the Sam- ported for coal samples in figure 21 are 

ple under essentially atmospheric con- obtained generally by a few months of deditions after the rock is removed from sorption testing until the process has 

in situ conditions. Dissolution gas- greatly declined, after which the coal 

content testing for evaporites measures samples are crushed and the gas released 

gas released only by destructive sample is measured and added to the total. 
I I I 1 I I I I I I 

10-7 10-6 10-5 10-4 10-3 10-2 10-1 100 lo1 102 

TOTAL GAS CONTENT, cm3/g 

KEY 

CL Lignite OA 3 days of desorption 

SB Subbituminous Formation test lng 

HB High-volatile bituminous oil shale, 06 40 days of desorption 

Piceance Basin testing MB Medium-volatile bituminous OC 125 days of desorption 

LB Low-volatile bituminous testing 

SA Semianthracite 

CA Anthracite 

AC Average 

SN Gulf Coast domal rock 

salt, normal 

SG Gulf Coast domal rock 

salt, anomalous, 

Impure, gassy 

SO Outburst salt 

FIGURE 21 .-Mean and range of methane contents released from assorted rock samples. 

CONCLUSIONS 

The occurrence of methane when mining 

oil shale is supportable theoretica1l.y 

and empiricall-y. However, there is not 

a great deal of agreement on the amount 

of methane released upon mining a given 

quantityof oil shale. Data frorn the 

Horse Draw Nine probably represent some 

of the best information available on this 

subject; the average arrived at was 42 

ft3/st (1.3 ~m~/~). In using these data, 

it is useful to consider that the Horse 

Draw Mine was designed to recover dawsonite and nahcolite in addition to oil 

shale. This required mine workings to be 

developed below the dissolution surface, 

where the saline minerals are preserved. 

These horizons are below many oil shale 

beds usually of major interest to the 

oil shale mining industry, including the 

Hahogany Zone. The geologic character 

of the oil shale is very different above 

the dissolution surface in the Piceance 

Basin, where vuggy porosity and water 

movement through fractures are relatively 

commonplace. The stratigraphic differences between the Cathedral 3luffs and 

Horse Draw Nines probably inhibits the 

sharing of methane data between the two 

sites. 

A number of geologic factors have been 

suggested as being important in the control of methane enrichment in oil shale. 

This report has attempted to address 

some of them. There is no evidence for a 
si~nificant correlation between oil yield 

by modified Fischer assay and methane 

content. The existence of certain local 

structural features s:lch as fractures and 

vugs nay provide channels for gas movement in oil shale. These features are 

sometimes associated vith methane enrichment in oil shale but appear to be more 

significant in controlling the movement 

of free gas in the ore body. The featare 

having the most persistent direct relationship with gas enrichment sas the occurrence of bitumen and possibly pyrite 

in the rock. The bitumen occurred as 

streaks and small rounded inclllsions of 

solid material in the rock matrix. 

The amount of methane contained in 

fresh oil shale samples was measured by 

a new technique knot~n as the modified 

direct method (MDM). The method is described in detail in the appendix. This 

test measures the STP volume of gas released from a rock sample that is removed 

f rorn in situ conditions to essentially 

atmospheric conditions without crushing 

or similar destructive action on the sample. Quantifying STP gas volumes each 

time a sample is taken during the duration of the test produces information on 

rates of gas desorption and gas reactions. It has been shown that methane is 

released relatively rapidly when a sample 

is first removed from the in situ environment, but this rate quickly declines, 

probably in less than 24 h. It is recomnended that in using the test, (1) if the 

objective is to measure total gas content, infrequent gas sampling be done, 

with samples taken most frequently at the 

beginning of the test and (2) if rates of 

gas releases or reactions are the objective, then samples be taken much more often; the methane desorption rate can be 

expected to change rapidly immediately 

Following removal of the sample from the 

host rock. 

This study represents a detailed drilling program successfully completed from 

underground mine workings. A surface-set 

diamond drill bit with a seniround crown 

and internal discharge was the best 

choice for core drilling in the Piceance 

Zasin, in order to maintain water pressure in penetrating vugs filled with 

tuffaceous or argillaceous material-. 

Use of a split inner barrel is suggested. 

1 drill with independently variable 

thrust and ro~ational controls imparts 

maximur? flexibility to the driller for 

cont ~nding wi th inhomogcnei t ies varying 

from conparat ivel;~ hard and somewhat 

elastic oil shale to fractures, and to 

vugs oc fractures Filled with loose or 

weakly lithified material. 4 drill unit 

powered by 25 hp or more is appropriate 

for all but very short hole drilling. 

Permeability data presented here should 

be considered preliminary. The most reliable data gener.3ted during this study 

suggests that very high permeabilities can exist in the fracture network, 

especially in zones that produced gas 

flows during drilling. The permeabilities given here ranged from about 300 to 

500 D. Evidence also suggests that gas 

reservoirs as they exist in oil shale 

format ions are very limited in volume, 

perhaps because of the narrow apertures 

of the fracture system. 

rlethane contents per unit as: were 

calculated from MDM for three time intervals of gas desorption. Methane contents 

were calculated at 72 h to simulate a 

typical amount of time rauckpiles would 

remain underground. The mean value of 

119 samples was 0.0316 clo3/g. Methane 

contents were calculated at 40 days to 

get higher gas values without excluding 

samples removed from drill holes completed near the termination of the study. 

This population numbered 100 oil shale 

samples, and the mean gas content was 

0.114 ~m'/~. At 125 days, the longest 

time for which gas contents were indexed, 

a mean of 0.195 cm3/g was determined for 

50 samples. All sample populations deviated somewhat from normal distributions, 

with the majority of samples being skewed 

slightly toward the low end of the scale 

and a few samples forming a tail in the 

more gas-enriched direct ion. 

Comparisons can be made between the gas 

contents of oil shale samples and other 

rock samples. Rock sample testing has 

determined that methane released from 

Mahogany Zone oil shale from the Piceance 

Basin is far less than that evolved from 

U. S. high-volatile bituninous coal. Test 
results also indicate that oil shale min- gas released without destructive sample 

ing may produce slightly more methane treatment. One can only speculate on how 

than is generally released in domal salt much gas remains in the oil shale even 

mines. However, dissimilarities in gas- after 125 days of gas desorption, as 

content testing methodology are highly reported here. Under no circumstances 

significant to these comparisons. Coal would it be advisable to apply data reand salt gas determinations attempt to ported here to oil shale occurring in 

neasure the total gas contained. MDM other basins or within differing straitesting for oil shale samples measures graphic units. 

REFERENCES 

1. Robinson, W. E. Origin and Characteristics of Green River Oil Shale. Ch. 

in Oil Shale, ed. by To Fo Yen and Go V. 

Chilingarian. Elsevier, 1976, pp. 61-79. 

2. Russell, P. L. History of Western 

Oil Shale. Cent. Prof. Adv. , East Brunswick, NJ, 1980, 152 pp. 

3. Cole, Re Do, Go Jo Daub, and Be Eo 

Weichman. Geology of the Horse Draw Nahcolite and Oil-Shale Mine, Piceance Creek 

Basin, Colorado. Paper in 15th Oil Shale 

Symposium Proceedings (Golden, CO, Apr. 

28-30, 1982). CO Sch. Mines, Au~. 1982, 

pp. 15-28. 

4. Sapko, Me J., J. KO Richmond, and 

J. P. McDonne11. Continuous Monitoring 

of Methane in a Deep Oil Shale Nine. Paper in 15th Oil Shale Symposium Proceedings (Golden, CO, Apr. 28-30, 1982). CO 

Sch. Mines, Au~. 1982, pp. 320-340. 

5. Teichmuller, Me Origin of the Petrographic Constituents of Coal. Sec. 

in Coal Petrology. (Engl. transl. ). 

Gebruder Borntraeger, West Berlin and 

Stuttgart, 3d ed., 1982, pp. 219-294. 

6. Hartley, Jo A*, and To No Beard. 

A Standard Technique for Handling, Marking, and Logging Oil Shale Core. Paper 

in 16th Oil Shale Symposium Proceedings 

(Golden, CO, Apr. 13-15, 1983). CO Sch. 

Mines, Au~. 1983, pp. 81-98. 

7. Kissell, Fe No, C. Me McCulloch, 

and C. He Elder. The Direct Hethod of 

Determining Methane Content of Coalbeds 

for Ventilation Design. BuMines RI 7767, 

1973, 17 pp. 

8. Murray, Do KO, and Jm Do Haun. 

Introduction to the Geology of the Piceance Creek Basin and Vicinity, Northwestern Colorado. Ch. in Guidebook to the 

Energy Resources of the Piceance Creek 

Basin Colorado, ed. by Do KO Murray. 

Rocky Mto ASSOC. Geol., 1974, pp. 29-40. 

9. Yen, To F., and Go V. Chilingarian. Introduction to Oil Shales. Ch. 

in Oil Shale, ed. by To Fa Yen and Go V. 

Chilingarian. Elsevier, 1976, pp. 1-12. 

10. Eugster, He P. Origin and Deposition of Trona. Contrib. Geol.: Trona 

Issue, v. 10, NO. 1, 1971, pp. 49-56. 

11. Stellavato, No Results of the 

Geologic Mapping Program During Shaft 

Sinking and Subsequent Station Development at C-B Tract. Paper in 15th Oil 

Shale Symposium Proceedings st old en, CO, 

Apr. 28-30, 1982). CO Sch. Mines, Au~. 

1982, pp. 115-136. 

12. Kuchta, J. Me, Me Hertzberg, 

Re Cato, C. Do Litton, Do Burgess, and 

Re W. Van Dolah. Criteria of Incipient 

Combustion in Coal Mines. Paper in 15th 

Symposium (International) on Combustion 

(Tokyo, Japan, Au~. 25-31, 1974). Combustion Inst., Pittsburgh, PA, 1974, 

pp. 127-136. 

13. Bennett, Ro Do, and Re Fo Anderson. New Pressure Test for Determining 

Coefficient of Permeability of Rock 

Masses. U.S. Army Eng. Waterways Expo 

Stn. , Tech. Rep. GL-82-3, July 1982, 

41 PP. 

14. Bredehoeft, J. Do, Re Go Wolff, 

W. S. Keys, and Eo Shuter. Hydraulic 

Fracturing To Determine the Regional 

In Situ Stress Field, Piceance Basin, COO 

Geol. Soc. America Bull., v. 87, NO. 2, 

1976, pp. 250-258. 

15. Smith, Jo W. Theoretical Relationship Between Density and Oil Yield 

for Oil Shales. BuMines RI 7248, 1969, 

14 PP. 
16. Bell, K. G., and J. M. Hunt. Native Bitumens Associated With Oil Shales. 

Int. Ser. Monogr. Earth Sci., v. 16, 

1963, pp. 333-366. 

17. Darton, N. H. Occurrence of Explosive Gases in Coal Mines. BuMines 

B 72, 1915, 248 pp. 

18. Bertrard, C., B. Bruyet, and 

J. Gunther. Determination of Desorbable 

Gas Concentration of Coal (Direct Method). Int. J. Rock Mech. and Min. Sci., 

v. 7, 1970, pp. 43-65. 

19. Cheng, K. C., K. K. Feng, and 

R. Augsten. Test Procedure for Methane 

Desorption From Coal By Direct Method. 

Can. Explos. Res. Lab., CANMET Kep. FRP/ 

MRL 81-63 (TR), Aug. 1981, 18 pp. 

20. McCulloch, C. M., .J. R. Levine, 

F. N. Kissell, and M. Deul. Measuring 

the Methane Content of Bituminous Coalbeds. BuMines RI 8043, 1975, 22 pp. 

21. Curl, S. J. Methane Prediction in 

Coal Mines. TEA Coal Res., London, 1975, 

77 PP* 
APPENDIX. --?.iODIFIED D IRECT METHOD PROCEDURE 

Several procedures have been used by 

the Bureau to study the occurrence of gas 

in coal and oil shale. A method reported 

by Darton in 1915, essentially examined 

the gas composition of the atmosphere oE 

a sealed can or bottle containing lump 

or crushed coal at various points in tine 

(1 - 7).' The original atmosphere of the 

container was either ambient atmosphere 

or a vacuum. The method reported by 

Darton measured only gas released upon 

crushing the coal sample. Oxygen sorption and/or reaction by coal was 

also examined and in some cases was 

considerable. 

A frequently used procedure For measuring the amounts of gases released 

from coal uses displaced water volume 

and yields the algebraic gas volume of a 

scaled co~~tainer with a rock sample. 

This technique is known as the direct 

method and is described in references 7, 

18, and 19. The gas volume can be composed of one or more gases that have either desorbed and thus comt ributed "positive" volumes or sorbed and/or reacted, 

contributing "negative1' volumes. Essential, but generally not practiced, is the 

sampling of the container atmosphere so 

the relative proportions of the individual gas species can be examined. A direct method type of test without gas composition information yields an approximation of the gas contents and desorption 

rates of the rock sample, which can be 

erroneously small because of the negative 

volume effects of sorption and/or reaction of gases with the sample in the 

sealed container. Standard temperature 

and pressure (STP) corrections to these 

desorbed gas volumes are applied in general but not always. 

The method described in this report, 

MDM, uses the ideal gas law equation to 

determine the STP gas volume in the 

sealed sample container and a gas sample 

of the container atmosphere to compute 

the volume of each gas species under 

Underlined numbers in parentheses refer to items in the list oE references 

preceding the appendix. 

consideration at any point in time. The 

main advantages of the :lDM are (1) desorption or release and/or reaction rates 

of individual gas species can be accurately deter~nined and (2) the deter~nination of these rates can be perfor~ned 011 

samples of snaller size or lower gas contents than in previous direct method 

practices. These advantages allow a more 

accurate and flexible characterization of 

multiple gas source variables where the 

direct method yields information on the 

changing overall volume of the total 

gases contained. This method can be performed in laboraLory, field, and underground settings. 

PROCEDURE, CALCULATIONS, 

AND EXPERIMENTAL APPARATUS 

Procedure 

The main purpose of the XDM is to obtain gas volumes over a period of time to 

characterize gas desorption and reaction 

rates. Gas should be sampled more f requently when a rock sample is first 

sealed into the container and less frequently at later times. Coal samples are 

usually sampled six to eight times within 

the first 2 h, a week later, and once a 

month for each of the next 2 to 6 months. 

The buildup of pressure in the sealed 

sample container should be minimized so 

that the desorption process is not inhibited. However, taking samples of small 

volume changes can introduce potentially 

large cumulative errors. By controlling 

pressure and atmosphere composition in 

the sealed container, desorption, sorption, and reaction phenomena can also be 

studied at different conditions. 

Basic Calculation 

The essence of this procedure is the 

calculation of gas composition and volume (corrected to STP conditions) in the 

sealed sample container at a given point 

in time. This quantity of gas is compared with the container atmosphere at a 

prior point in time, and the gas species 

volume differences are accumulated. 
Using the ideal gas law, the volume at 

STP conditions of gas species x in a container at time interval n (V,,) is determiiled by 

V,, = {[(~atmn + ?ventn + dPn) Vg] 

where Pat~n = atinosphere pressure, mm Hg; 

Pvent = underground mine ventilation pressure differential 

over Patm from surface if 

samples are sealed underground, mm Hg; 

dP = differential pressure of 

container atmosphere with 

respect to (Patm + Pvent) , mm Hg; 

Tg = temperature of gas atmosphere in container, K; 

Vg = free space for gas atmosphere to occupy in container, cm3; 

T = standard teinperature 

(273 K); 

P = standard pressure (760 

Inm Hg); 

and [x] = volume fraction of gas 

species or group x in 

container atmosphere, 

cm3/crn3. 

Experimental Apparatus 

A typical configuration of the apparatus is presented in figure A-1. The experimental apparatus used in demonstrating this method was estimated to perform 

within the following limits: 

1. Barometer: +1 to 2 mm Hg. 

2. Thermometer: f0.5 to l.OO C. 

3. Differential pressure gauge: '1 to 

2 pct full scale. 

4. Evacuated container and gas sample 

port for gas sample or detector giving 

Differential pressure 

gauge, 

Selector valve, 0' 

container 

FIGURE A-1 .-Generalized apparatus. 

compositional analysis: '1 to 2 pct of 

value. 

5. Sample container with at least one 

inlet and valve with volume measured: tl 

to 2 pct of total volume (determined by 

weight oE water required to fill container with and without sample to obtain 

sample and free-space volumes). 

The Bureau's experience with gas Sampling of rock samples has found the design of experimental apparatus to be of 

paramount importance in obtaining accurate results. Hematological test tubes 

and needles have proven very reliable as 

containers for sampled gas and for transference of released gas. A diaphragmtype pressure gauge is used to measure 

partial pressures in the oil shale sample 

containers. 

Magnahelic pressure gauges are available in a variety of ranges and are built 

to be accurate to within 2 pct of the 

full scale measured. Sample containers 

for the oil shale core were constructed 

of 2.5-in-diameter schedule 40 PVC pipe. 

It is desirable for the diameter of the 

container to be somewhat larger, in this 

case by slightly more than 0.5 in, than 

the core diameter, to facilitate insertion and removal from the container. 

Schedule 80 PVC caps were tapped and 

fitted with quick disconnects for closing the open end of the container underground. The opposing ends had been 
closed by the gluing of schedule 40 caps 

at the Bureau. Hansen, Swagelock, and 

Milton-type quick disconnects were used 

on the core containers. 

BASIC DATA COLLECTION CYCLE 

To obtain a container atmosphere data 

point at a given time: 

1. Record date and time of data point 

determination. 

2. Measure atmosphere pressure (Patm) 

and temperature of the gas in the container (Tg), which can be considered to 

be ambient if the storage area for containers does not undergo large and/or 

rapid temperature changes. 

3. Measure barometric pressure. If 

the test site is located underground 

(e.g. , coal mine) and only the surface 

atmospheric pressure is known, then the 

ventilation pressure differential (Pvent) 

with respect to surface must be measured. 

4. Connect a differential pressure 

gauge to the sample container, and measure an initial differential pressure 

with respect to ambient pressure (dPi). 

5. Purge the sample circuit with container gas if dPi 2 0 or with an inert 

gas if dPi < 0, then take a gas sample of 

the container atmosphere. This gas sample is for gas composition analysis. 

6. If assurance is required that an 

appropriate volume of gas from the container was obtained, take an intermediate differential pressure measurement 

(dpinter) after the gas sample, and approximate the volume (V sample): 

V sample = [(dPi - d~inter)(Vg) l/(Patm) 

7. After gas sampling, if dPinter is-- 

a. Positive, then bleed excess 

differential pressure (dPf ) to atmospheric pressure and measure. This terminates measurements at this data point. 

3. Zero or negative, terminate 

data point measurement; dPf = dPinter. 

If any gases are injected or air leaks 

into the container, another gas composition sample must be taken and a final dPf 

taken to terminate the measurements. 

A sample data collection form is presented as figure A-2. 

Data Reduction 

The first step in t,he data reduction 

process is to determine the atmosphere 

composition when the sample is first 

sealed. The ambient atmosphere is sampled for composition, and the temperature 

and pressure are measured. The free 

space in the container with the rock 

sample is known, and the STP-corrected 

volumes of the gases sealed in the container with the sample are calculated by 

equation A-1 and represent the initial 

conditions. 

Gas samples of the container atmosphere, as well as measurements of the 

corresponding pressures and temperature, 

are taken periodically, and the gas species STP volumes are calculated by equation A-l for each sampling period. In 

each sampling period, measurements are 

taken both before and after release of 

excess gas pressure. The current initial 

gas volumes in the container are compared 

with the final gas volumes from the previous sampling period: The individual gas 

volumes before any release of excess gas 

pressure are subtracted from those calculated at the end of the previous sampling 

period after release of excess pressure. 

These differences represent the changes 

in gas species volumes that have taken 

place since the end of the previous sampling period. The volume changes are applied to the cumulative gas volumes that 

began with the initial conditions when 

the container was sealed. The cumulative 

gas species volumes can then be presented 

graphically as a function of time. The 

STP gas volumes should be normalized to 

either a unit mass (cubic centimeters per 

gram) or volume of rock (cubic centimeters per cubic centimeter) basis. 

The MDM testing discussed in this report was performed underground at the 

Cathedral Bluffs Mine, where the test 

environment was at a nearly constant temperature over the duration of measurements. However, core removed f ron surface drilling in a separate study was 

tested and stored at a surface site, and 

results were not totally satisfactory because of the differing rates at which the 

gas, core, and container equilibrate with 

changing air temperatures. A constanttemperature environment is recommended. 

Unaccounted for with the MDM are the 

gases lost between the time the rock sample is taken and when it is sealed in the 

container. Essential to determining the 

lost gas is determining the length of 

time that gas has been desorbing from the 

sample before it is sealed in the container. Previous researchers have calculated the lost-gas time for a vertical 

drill hole filled with water or drilling 

fluid by assuming that desorption begins 

when the sample has traveled half the 

distance out of the drill hole (20). - In 

using this technique, the lost gas can be 

determined graphically by plotting the 

cumulative gas volumes on a graph with 

the square root transformation applied to 

the time axis and drawing a linear ext rapolation to "zerov1 time. 

Lost gas was not calculated for data 

presented in this report, but it is 

advisable that a lost-gas technique be 

applied to MDM experiments in any study 

where the rock sample is exposed to atmospheric conditions for more than about 

1 h before being sealed in a container. 

The necessary data are available to 

perform a lost-gas correction on the 

Cathedral Bluffs results, although some 

question does remain concerning the initiation of lost-gas conditions in this 

study . The one component of a rock's gas content not yet addressed is the gas remaining in the sample after the monitoring of 

gas activity in the sealed container has 

been terminated. To determine this, some 

form of crushing of the sample can be 

performed in a sealed container with an 

inert (nitrogen) atmosphere (1, 2). The 

released gas volumes are determined with 

the above method. Since it takes relatively great lengths to liberate this remaining gas from the rock, it seems probable that this component of the total gas 

content of the rock is not significant in 

mine emission or gas drainage studies.