553.27 W52 r
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TJMVERSITY OF WYOMING RESEARCH CORPORATION
WESTERN RESEARCH
INSTITUTE
Laramie, Wyoming
GEOLOGIC INFLUENCES ON THE IN SITU PROCESSING OF TAR SAND AT THE
NORTHWEST ASPHALT RIDGE DEPOSIT, UTAH
Property of UTAH GEOLOGICAL & MINERAL SURVEY
January 1985
LIST OF TABLES
le P
1 Gross lithologic descriptions of outcrop samples from Northwest Asphalt Ridge
2 Mineralogy of outcrop samples as determined by X-ray analysis
3 Gross lithologic descriptions of 12 tar sand samples from core 4P5, LETC field site
4 Gross lithologic descriptions of samples of target zone from selected cores, LETC field site
5 Mineralogy of tar sand samples from core 4P5 and other selected cores as determined by X-ray analysis
6 Minenlogy and visible porosity of samples from the middle zone of the Rim Rock Sandstone, core 4P5, as determined by petrographic analysis
7 Sandstone classification of 10 samples from core 4P5
8 Summary of zones and elevations for nine selected coreholes
vn
ACKNOWLEDGEMENTS
The author is grateful to the following Western Research Institute
(WRI) personnel for providing special services: Dr. Kenneth P. Thomas-
bitumen extraction; Glenn M. Mason and Lowell K. Spackman—X-ray
analyses; Anthony C. Munari and Steve Whittenberger—drafting; and Ms.
Jean Tweed and Ms. Jayne Adams—typing. Assistance on the scanning
electron microscope was provided by Ray Kablanow, Geology Department,
University of Wyoming.
Reviews of the manuscript by Lee C. Marchant and L. John Fahy (WRI)
and Gretchen C. Kuhn (Sohio Shale Oil Co.) are greatly appreciated. The
author wishes to thank George F. Dana (WRI) and Dr. Anthony F. Randazzo,
Dr. Paul A. Mueller and Dr. Frank N. Blanchard (University of Florida)
for their comments and suggestions.
VI 1 1
LIST OF FIGURES Figure Page
1 Major Utah tar sand deposits and location of study area 4
2 Major tar sand deposits of the Uinta Basin 8
3 Location of Northwest Asphalt Ridge and Asphalt Ridge, Uintah County 9
4 NE-SW geologic cross section of the Asphalt Ridge area 11
5 Generalized stratigraphic section at the LETC field site, Northwest Asphalt Ridge 13
6 Topographic map of Northwest Asphalt Ridge and -north end of Asphalt Ridge, with location of faults separating deposits 15
7 Aerial photograph (Page, 1981) of Northwest Asphalt Ridge, Sohio Shale Oil Co. "D" tract and study area 17
8 Tar sand outcrops, surface sample locations and inferred subsurface faults prior to seismic survey, Northwest Asphalt Ridge 20
9 Representative lithologic section of Rim Rock Sandstone at LETC field site 26
10 LETC site map with locations of field experiment areas and selected coreholes 28
11 Vertical variation in visible porosity, major minerals and rock fragments content of middle zone of Rim Rock Sandstone, core 4P5, as determined by petrographic analysis 37
12 Scanning electron micrographs of lower zone of Rim Rock Sandstone (a) and Asphalt Ridge Sandstone (b) 40
13 Scanning electron micrographs of middle (TS-1S) zone of Rim Rock Sandstone (a) and microcrystalline coating (b) 41
14 Location of seismic lines at LETC field site . . . 43
v
List of Figures (continued)
P
15 Seismic profiles for lines 1 and 2
16 Seismic profiles for lines 3 and 5
17 Seismic profiles for lines 4 and 6
18 Location of faults and structural contours as determined by yellow horizon of seismic survey and coring results (Applegate and Liu, 1983), field experiments and coring results
19 Variation in total thickness of Rim Rock Sandstone at corehole locations
20 Revised structural map at Northwest Asphalt Ridge and study area
21 Reverse and forward combustion processing techniques
22 Steamflood processing technique
23 Lateral extent of TS-1C field experiment
24 Lateral extent of TS-2C field experiment for 300°F and 1000°F isotherms
25 Lateral extent of TS-1S field experiment
vi
TABLE OF CONTENTS
PAGE
LIST OF FIGURES v
LIST OF TABLES vii
ACKNOWLEDGEMENTS viii
ABSTRACT 1
INTRODUCTION 2 General Statement 2 Research Objectives 5 Previous Studies 5
GEOGRAPHIC AND GEOLOGIC SETTING 7 Location 7 Stratigraphy 10 Regional Structure 14 Origin of Bitumen 16
NORTHWEST ASPHALT RIDGE DEPOSIT 16 Areal Extent 16 Outcrop Characterization 18
Sampling and Analysis 18 Interpretation 19
Subsurface Field Site Characterization 25 Sampling and Analysis 27 Interpretation 27
Local Structure 39 Previous Interpretations 39 Seismic Survey 42 Structure of the Field Site 42
Summary . 48
i i i
Page
IN SITU RECOVERY FIELD EXPERIMENTS 52 Pretest Site Characterization 52 Drilling and Coring 52 Downhole Well Logging 52 Air Injectivity Tests 53 Well Monitoring 53 Core Analysis 54
Processing Techniques . . . . 54 Combustion 55 Steamflooding 57
Operation and Results 57 First Combustion Experiment 57 Second Combustion Experiment 61 Steamflood Experiment 62
INFLUENCE OF GEOLOGIC PARAMETERS ON RESULTS OF FIELD EXPERIMENTS 66 Deposit Configuration 66 Local Structure 67 Test Zone Confinement 68 Lithology 70 Rock Properties 73
DISCUSSION 74
SUMMARY 75
REFERENCES CITED 78
IV
GEOLOGIC INFLUENCES ON THE IN SITU PROCESSING OF TAR SAND AT THE NORTHWEST ASPHALT RIDGE DEPOSIT, UTAH
By Donna J. Sinks
January 1985
Work Performed Under Interagency Agreement AD-89-F-0-026-0 and Cooperative Agreement DE-FC21-83FE60177
For U.S. Department of Energy Office of Fossil Fuel Morgantown Energy Technology Center Laramie Project Office Laramie, Wyoming
By Western Research Institute Laramie, Wyoming
GEOLOGIC INFLUENCES ON THE IN SITU PROCESSING
OF TAR SAND AT THE NORTHWEST ASPHALT RIDGE DEPOSIT, UTAH
By
Donna J. Sinks1
ABSTRACT
The Laramie Energy Technology Center, Department of Energy,
completed three in situ oil recovery field experiments, two combustion
and one steamflood, in tar sand at Northwest Asphalt Ridge, Utah.
Inadequate resource and site characterization prior to the field
experiments contributed to process design and operation problems. The
10-acre field site is part of the Sohio Shale Oil Co. "D" tract located
west of Vernal, Uintah County. The target zone, the middle portion of
the Cretaceous Rim Rock Sandstone of the Mesaverde Group, varied from
300-500 feet deep. From petrographic analyses of the target zone, this
portion is classified as a moderately sorted litharenite with an average
visible porosity of 18%. Dominant constituents include quartz, rock
fragments, chert, feldspars and clay minerals. X-ray analyses of
selected core samples from the Rim Rock and Asphalt Ridge Sandstones
indicate the presence of quartz, calcite, dolomite, ankerite,
microcline, orthoclase, anorthite, kaolinite and muscovite. Carbonate
mineral species were present only in the lower Rim Rock and Asphalt
Ridge Sandstones. Reservoir characteristics of the target zone which
adversely affected the field experiments include faulting at all three
experiment areas, lateral and vertical heterogeneities of permeability
and porosity, inadequate target zone confinement, rough surface texture
of clastic yrains, and oil-wet grains. Favorable target zone
characteristics include high quartz content; absence of carbonates; lack
Western Research Institute, Univ. of Wyoming Research Corp., Laramie, Wyoming
1
of clay minerals bridging and cementing pore spaces; and sufficient
porosity, initial oil saturation and overburden. Recommended geologic
evaluation methods to aid in the identification of potentially suitable
resources and sites for in situ oil recovery from tar sands include
seismic surveys; well logging; coring and core analyses; petrographic,
binocular, and scanning electron microscopy; and X-ray analyses.
INTRODUCTION
General Statement
As the need for alternative energy sources has increased over the
last few decades, interest in tar sands, or bituminous sandstones, as a
potential fuel source has increased. Other alternative hydrocarbon fuel
sources which have received considerably more attention in recent years
are oil shales and coals, both of which can be processed in situ, or in
place. Both of these alternate fuel sources have been field tested
extensively. In situ production of shale oil is near commercial
production in the United States, while underground coal gasification is
commercial in the Soviet Union. Tar sand bitumen (oil) extraction
processes have been field tested, but are not in commercial production
in the United States. Some of the difficulties in producing oil from
tar sands include inadequate knowledge of those reservoir
characteristics affecting production, the high viscosity of the bitumen,
and the resultant immobility of the bitumen.
Other terms for tar sand include bituminous sandstone, oil-
impregnated rock, oil sand, and asphaltic sandstone. Tar sand is
defined as any unconsolidated or consolidated rock which contains
bitumen with a viscosity of greater than 10,000 centipoise (cp) at
reservoir temperature, which in its natural state cannot be removed by
primary petroleum production methods (Cupps et al., 1976; Meyer et al.,
1983). The hydrocarbons contained in tar sands are soluble and,
therefore, extractable with toluene and other organic solvents.
2
Bitumen, the soluble hydrocarbon, has an API2 gravity of usually less
than 10° at reservoir temperature. These reservoir characteristics,
along with production difficulties, pose a challenge to technological
advancement in the development of tar sands.
The United States government has been involved in tar sand research
for a number of years. It was not until 1971 that a laboratory facility
was formally established to analyze tar sand samples at the Laramie
Energy Technology Center, Laramie, Wyoming (LETC; previous facility
names include Petroleum Field Office, Laramie Petroleum Research Center,
Laramie Energy Research Center; presently the Western Research Institute
[WRI]). Private companies reported results from laboratory and field
experiments conducted as early as the 1950's (Reed et al., 1960;
Trantham and Marx, 1966). In 1974 the federal facility in Laramie
conducted laboratory combustion tube experiments on two different
samples from tar sand deposits in northeastern Utah (Land et al.,
1975). These initial laboratory experiments were the beginning of the
federal government's commitment to tar sand research.
During this period of research, several laboratory experiments and
three in situ field experiments were conducted at the Northwest Asphalt
Ridge deposit, Utah (Fig. 1 ) , on land owned by the Sohio Shale Oil Co.
(Sohio). Results of the field experiments indicate several factors
which greatly influence the success of in situ processing of tar sand.
These factors include process well design and spacing, reservoir to
surface production of bitumen, and site and reservoir
characterization. As production histories from each of the field tests
were evaluated, it became increasingly evident that pre-test site
characterization and reservoir evaluation were essential. The selection
of a reservoir for in situ bitumen extraction can be a complicated
process, but many of the potential production problems can be eliminated
with the choice of an appropriate site and source rock.
2°API = 141.5 -131.5, where P - specific gravity of petroleum at 15.6°C. P
3
I D A H O
A R I Z O N A
(Kuusk raa and Hammershaimb, 198*0
Figure 1. Major Utah t a r sand depos i t s and l o c a t i o n of study area,
Research Objectives
The results of the three LETC field experiments at the Northwest
Asphalt Ridge deposit indicated that the geologic environment was a
greater influence on the experiments than anticipated. This study
identifies, in retrospect, those structural, stratigraphic and litho-
logic properties of this deposit which influenced the in situ field
experiments conducted by the Laramie facility and recommends resource
and site evaluation methods, including geophysical techniques, core
analyses, microscopy and X-ray analyses.
Conflicting identifications of tar sand outcrops at the Northwest
Asphalt Ridge appeared in the literature. Mineralogy of 21 outcrop
samples and 21 core samples from the Vernal field site were quali
tatively determined by X-ray analysis. Quantitative mineralogy was
determined by petrographic analysis for 10 samples from the target zone
of core 4P5. The petrographic analyses aided in the lithologic classi
fication of a portion of the Rim Rock Sandstone.
The areas of concern to the engineer designing an in situ project
include: deposit configuration (zone thickness, dip, homogeneity,
lateral and vertical continuity); local structure (faulting and
fracturing); test zone confinement (depth to test zone and permeability
of overburden and underburden); lithology (mineralogy, clay content,
grain size and shape, degree of sorting, pore configuration, and rock
wettability); and rock properties (porosity; permeability; bitumen, gas
and water saturations; and compressive strength).
Previous Studies
The existence of tar sands in northeastern Utah was noted in the
early part of this century. Eldridge (1901) described outcrops near
Vernal, Utah. A detailed study of the Cretaceous strata of northeastern
Utah was completed by Gale (1910). However, no mention was made of
bitumen saturation in the Mesaverde Group sandstones. The tendency of
these sandstones to form prominent ridges and hogbacks was described,
and detailed lithologic descriptions of the sandstones were included.
Spieker (1930) modified Gale's geologic map of the area to include tar
sand outcrops at Asphalt Ridge. A major fault at the northwest end of
5
Asphalt Ridge is mentioned. However, its significance relative to the
Asphalt Ridge and Northwest Asphalt Ridge deposits apparently was
unknown. The most comprehensive study of the area following Spieker's
paper was presented by Walton (1944). The two names for the sandstone
units of the Mesaverde Group, the Asphalt Ridge and Rim Rock, were
proposed at this time and are currently in use. A study of the geology
of Uintah County by Unterman and Unterman (1964) briefly discusses the
Mesaverde Group.
Initial investigation of the tar sand at Northwest Asphalt Ridge
was begun by Covington (1955b). Both the Rim Rock and Asphalt Ridge
Sandstones were described as cropping out in this area. The downthrown
block at the northern end of Asphalt Ridge was estimated to have a
displacement of approximately 1000 feet. Cross sections completed
subsequent to a coring program by Ridge Development Co. indicated
complex structure at the study area. This interpretation was supported
by McDonald (1957). Interest in the Asphalt Ridge deposit and the
peripheral outcrops at Northwest Asphalt Ridge continued (Pruitt, 1961;
Covington, 1963). It was not until 1966, when Kayser (1966) presented a
generalized surface geoloyic map of Northwest Asphalt Ridge, that this
area was initially recognized as a separate tar sand deposit. The
outcrops were described as undifferentiated Mesaverde Group. The most
recent summary of Utah tar sand deposits (Campbell and Ritzma, 1979)
identifies the outcrops at Northwest Asphalt Ridge as the Asphalt Ridge
Sandstone. Interpretations of local structure and stratigraphy which
appeared in the literature had been accepted prior to and during the
three field tests.
Reservoir rock properties and their relationship to in situ pro
cessing of tar sands have been investigated since field tests began in
the 1950's. Most ideas were based on laboratory experiments, which are
conducted under nearly ideal conditions. The heterogeneities of a natu
ral deposit pose many more problems in the selection and processing of
tar sand reservoirs. Kramers and Carrigy (1974) addressed many of the
areas which the geologist should consider when characterizing a deposit
for potential exploitation. These ideas were supported and expanded by
Lennox (1981). Both studies were completed by organizations in Canada,
6
where surface processing of unconsolidated oil sands has been commercial
for a number of years. The importance of rock properties on recovery
rates by the I IT Research Institute's Radio Frequency Heating Process
was addressed by Sresty (1981). The significance of geologic factors
affecting enhanced oil recovery was presented during a U.S. Department
of Energy workshop (Impact, 1982). The significance of pore space
geometry to recovery efficiency was presented in Wardlaw and Cassan
(1979) and Wardlaw (1980). This current study evaluates the factors pro
posed in these previous studies and determines which geologic factors
had the greatest influence on the results of the three field experiments
at Northwest Asphalt Ridge.
GEOGRAPHIC AND GEOLOGIC SETTING
Location
The Northwest Asphalt Ridge deposit is one of the tar sand deposits
which occur in the Uinta Basin of northeastern Utah (Fig. 2). Asphalt
Ridge, a 15-mile-long northwest trending hogback, is downdropped ap
proximately 1000 feet on,the northwest end by a series of major faults,
lowering significantly the northwest portion of Asphalt Ridge. The
downdropped block, a monocline dipping southwest, is termed the North
west Asphalt Ridge or Ridge deposit (Fig. 3).
The Uinta 3asin was formed during the late Cretaceous and early
Tertiary and presently covers an area of approximately 7,000 square
miles. It is bounded on the north by the Uinta Mountains, on the east
by the Douglas Creek Arch, on the west by the Wasatch Mountains, and is
terminated at the Book Cliffs on the south. The structural axis of the
Uinta Basin is approximately parallel to Asphalt Ridge and Raven Ridge
(Covington, 1957). The basin is asymmetric, with the steeply dipping
side to the north and the gently sloping side to the south. The most
significant sediments deposited during the formation of the basin were
the oil shales of the Eocene Green River Formation. These organic rich,
dolomitic marl stones (Bradley, 1931) were formed from sediments depos
ited in Lake Uinta. Abundant plankton, algae and other aquatic
organisms flourished in this shallow, fresh to slightly brackish water,
7
Tar Sand Deposit I. Tabiona
2. Lake Fork 3. Whiterocks 4. N.W. Asphalt Ridge 5. Asphalt Ridge 6. Raven Ridge
7. PR Spring 8. Hill Creek 9. Sunnyside
10. Nine Mile Canyon 11. Argyle Canyon
12. Willow Creek
Figure 2. Major tar sand deposits of the Uinta Basin,
8
SCALE
0 1 2 3 4 5 Mi. -\
Cross Section
Figure 3. Location of Northwest Asphalt Ridge and Asphalt Ridge, Ui ntah County.
9
providing the organic sources of the hydrocarbons found in the oil
shales of the basin. Climatic changes and tectonic activity influenced
the depositional environment and rate of sedimentation (Bradley,
1964). Lake Uinta diminished, and sediments of fluvial origin were
deposited on the lacustrine sediments. Late Tertiary tectonic activity
and subsequent erosion helped to shape the basin as seen today (Kayser,
1966). The complex history of the formation of the Uinta Basin
contributes to the difficulty in correlating Cretaceous and early
Tertiary deposits along the margin of the basin.
Stratigraphy
A continuous stratigraphic sequence, from the early Cretaceous to
the middle Oligocene, is not present in the subsurface at Northwest
Asphalt Ridge. Mesozoic and early Tertiary strata dip steeply to the
southwest. They are overlain by less steeply dipping formations of
middle Tertiary age. This stratigraphic relationship is represented by
a generalized cross section across north-central Asphalt Ridge (Fig. 4).
An angular unconformity exists between the Cretaceous Mesaverde Group
and the Oligocene Duchesne River Formation at Asphalt Ridge as well as
at Northwest Asphalt Ridge. Only three units have been cored at the
study area, the Mancos Group, Mesaverde Group and Duchesne River
Formation. The depositional and tectonic histories of the Uinta Basin
contribute significantly to hydrocarbon emplacement in the sandstones at
Northwest Asphalt Ridge.
The upper Cretaceous Mancos Group immediately underlies and inter-
tongues with the sandstones of the Mesaverde Group. There are three
members of the Mancos Group, predominantly of marine origin. Described
by Kinney (1955), they are (in ascending order): the Mowry shale, the
Frontier sandstone and the upper shale. This upper shale, a yellowish
to olive grey shale with thin, hard, calcareous sandstone beds less than
two feet thick, has been cored at the study area and portions of it
mapped north of the outcrops at Northwest Asphalt Ridge. The entire
section ranges from 800 feet thick at the western edge of the basin to
6000 feet thick near the Utah-Colorado border.
10
sw NE
Asphalt Ridge - 6000
- 4000
- 2000
SEA LEVEL
- - 2 0 0 0
•4000
GEOLOGIC AGE
0 - Oligocene E - Eocene P - Paleocene K - Cretaceous
Modified from Kayser, 1966
SCALE r K J n K a , n w w w f |
0 1/2 I Mile
Figure 4. NE-SW geologic cross section of the Asphalt Ridge area (see Figure 3 for l oca t ion ) .
Overlying the Mancos Group is the Mesaverde Group, also of late
Cretaceous age. The group consists of two distinct sections, the lower
marine sandstones and the upper brackish water sandstones, siltstones,
carbonaceous shales and coals. At Northwest Asphalt Ridge this upper
sequence has been eroded, and only the lower marine sandstones are
present. Walton (1944) proposed the nomenclature for the two basal
sandstones, the Rim Rock and Asphalt Ridge, which were deposited in a
marine shoreline environment. Figure 5 depicts a generalized strati-
graphic section of these two sandstones at the test site. The Asphalt
Ridge Sandstone is approximately 150 feet thick and is separated from
the Rim Rock Sandstone by a thin (100 feet) wedge of the upper shale
member of the Mancos Group. The Rim Rock Sandstone varies in thickness
at the study area from 100 to 350 feet thick. The middle zone of the
Rim Rock Sandstone was the target reservoir for all three in situ field
tests. Both sandstones contain bitumen at Northwest Asphalt Ridge, as
well as at Asphalt Ridge (G. C. Kuhn, personal communication). An
angular unconformity exists between the upper Rim Rock and the overlying
Duchesne River Formation.
Basinward from Asphalt Ridge, the fluvial Wasatch Formation and
lacustrine Green River Formation are present in the subsurface. The
Wasatch Formation, of late Cretaceous and early Eocene age, consists of
interbedded mudstones, shales, and sandstones, and unconformably
overlies the Mesaverde Group (Kayser, 1966). The contact between the
Wasatch and Green River Formations is gradational but is generally
chosen at the first occurrence of ostracodal limestone, oil shale, or
calcareous siltstone, depending upon which facies of the Green River
Formation is present. The Eocene Green River Formation consists of
abundant shales and dolomitic marlstones, and minor siltstones and
sandstones of lacustrine and near-shore origin. Portions of the
dolomitic marlstones are rich in kerogen and are thus termed oil shales.
The late Eocene Uinta Formation conformably overlies the Green
River Formation, but at the southern end of Asphalt Ridge it
unconformably overlies the Mesaverde Group. It consists of grey to
brown sandstones interbedded with white, grey and red shales. There are
sporadic occurrences of conglomeratic channel deposits interbedded with
12
5 9 5 0 -
5 9 0 0 — D ^
5800-
O) > O)
o a>
c o a>
e a> > o
o
ul
c
o > <1>
UJ
5700
5600
5500
5400
_°V.Q
>JP.C5
5300-
5200 —
5100 —
Surface
Aluvium
p:tt;
DUCHESNE RIVER FORMATION
(0LIG0CENE)
• Unconformity
Rim Rock Sandstone
Tongue of upper shale member of Mancos Group
Asphalt Ridge Sandstone
MESAVERDE GROUP
(CRETACEOUS)
Legend
Conglomerate
Sandstone
kr Silt stone
i-i-dl Shale
Limestone
Shale MANCOS GROUP
(CRETACEOUS)
Figure 5. Generalized s t ra t ig raph ic section at LETC f i e l d s i t e , Northwest Asphalt Ridge.
13
the other fluvial deposits. Bituminous sandstones of this formation
comprise the majority of the tar sands exposed at the southern end of
Asphalt Ridge.
The third significant formation at the study area is the Oligocene
Duchesne River Formation. It unconformably overlies the Mesaverde Group
at the Northwest Asphalt Ridge and at the central and northern portions
of Asphalt Ridge. This angular unconformity represents approximately
7000 feet of missing strata (Walton, 1944). The formation is of fluvial
origin and is 1ithologically similar to the Uinta Formation, but con
tains more sandstones and conglomerates. The lower portion of the for
mation is saturated with bitumen at the central and northern areas of
Asphalt Ridge, as well as at the study area (Covington, 1955a;
Covington, 1963; Campbell and Ritzma, 1979). This formation, along with
Quaternary alluvium, is exposed at the surface basinward from both
Asphalt Ridge and Northwest Asphalt Ridge.
Regional Structure
Asphalt Ridge is separated from Northwest Asphalt Ridge by faulting
at the north end of Asphalt Ridge (Fig. 6 ) . This fault zone was mapped
by Spieker (1930), and Walton (1944) estimated the throw to be 250 feet
and post-01igocene in age. Covington (1957) has estimated its displace
ment to be about 1200 feet, with the downthrown side to the northwest.
The only exposures of tar sand on the northwest side of the fault zone
are at Northwest Asphalt Ridge.
Asphalt Ridge trends northwest, and all strata dip to the south
west. The Mesaverde Group dips 12-28° southwest, while the strata
overlying the unconformity between the Mesaverde Group and the Duchesne
River Formation are less steep, with dips ranging 5-20° southwest
(Kayser, 1966). The axis of the Uinta Basin, southwest of Asphalt
Ridge, is within five miles of the north end of the ridge and about two
miles from the south end. Minor faulting occurs along the ridge, but it
does not alter the general structure of the main part of the ridge.
14
R 20 E R 21 E
SCALE
0 1/4 1/2 Mi.
Contour Interval: 100 Ft. U
Unimproved Road
Major Faults Separating Deposits
Figure 6. Topographic map of Northwest Asphalt Ridge and the north end of Asphalt Ridge, with locat ion of fau l t s separating deposits.
15
Origin of Bitumen
The source of the bitumen at Northwest Asphalt Ridge and Asphalt
Ridge has been speculated upon for the past 30 years. Hunt et al.
(1954) proposed that oil from the Green River Formation migrated updip
along the prevalent unconformities. Covington (1957; 1963) stated that
migration was halted by local faults, thus creating structural traps.
The more volatile constituents of the oil were lost during migration,
thus increasing the viscosity of the oil as it moved updip. This mi
gration is believed to have occurred post-01igocene because the occur
rence of bitumen saturation in rocks at Asphalt Ridge and the study area
range in age from Cretaceous through 01igocene. Biodegradation of the
oil also can contribute to an increase in viscosity.
In addition, the results of gas chromatographic and mass spectro
metry analyses of bitumen from Northwest Asphalt Ridge show that the
bitumen contained biomarkers, steranes and triterpanes, that are very
similar in relative amount and structure to those identified in Green
River oil shales. This further supports the theory that the source of
the bitumen was the Green River Formation (Thomas et al., 1977).
NORTHWEST ASPHALT RIDGE DEPOSIT
Area! Extent
The outcrops of tar sand at Northwest Asphalt Ridge were first
mapped in detail by Kayser (1966). However, the exposures of the
Mesaverde Group were not differentiated. He does state that saturated
Asphalt Ridge Sandstone is exposed at Northwest Asphalt Ridge, but it is
not clear if he considers the entire lateral extent of the outcrops as
part of the Asphalt Ridge Sandstone exclusively. Covington (1955b) and
McDonald (1957) inferred that the outcrops were represented by both the
Asphalt Ridge and Rim Rock Sandstones. Campbell and Ritzma (1979)
identified the outcrops as Asphalt Ridge Sandstone.
The tar sand extends for 4000 feet along a ridge, but the outcrops
are discontinuous. An aerial photograph of the study area and field
test site is shown in Figure 7 (Page, 1981; p. 14). The outcrops are
16
LETC Field Site Boundary of Sohio Shale Oil Co. "D" Tract
O Mesaverde Group Outcrop
SCALE
0 500 1000 Ft.
Figure 7. Ae r i a l photograph (Page, 1981) of Northwest Asphal t Ridge, Sohio Shale Oi l Co. "D" t r a c t and study a rea .
17
near the northern border of the Sohio Shale Oil Co. "D" tract. Because
of the lack of sufficient drillhole and core information outside "D"
tract, an estimation of the areal extent of the deposit is not made
beyond the outcrops and field area.
Outcrop Characterization
Descriptions of the bituminous sandstones of the Mesaverde Group by
earlier investigators (Spieker, 1930; Walton, 1944; Covington, 1955b)
were oversimplified, probably because of the limited exposures of the
entire sections at Asphalt Ridge. Kayser (1966) provided the most com
prehensive descriptions of unsaturated sandstones of the Mesaverde
Group. The following characterizations were compared to the outcrop
sample descriptions of this study (modified from Kayser, 1966; pp. 20,
23, 39, 41):
Asphalt Ridge - sandstone, light grey to buff, very fine to fine grained, friable. Mineralogy: 90% quartz, 7% chert, 2% orthoclase and plagioclase feldspars, 1% accessory heavy minerals; calcite cement commonly filling pore spaces (% calcite not reported)
Rim Rock - sandstone, light grey, fine to medium grained, uniform gross lithology. Mineralogy: 60% chert, 37% quartz, 2% orthoclase and plagioclase, 1% accessory heavy minerals; calcite and authigenic quartz as film on grains (% calcite not reported); abundant grey to black chert.
A more recent investigation by Altringer et al. (1984) concurred
with Kayser in relation to general mineralogy. However, specific sample
locations at Asphalt Ridge were not reported. Minerals identified in
cluded quartz, feldspar, chert, mica and pyrite. X-ray analyses
completed on two cores from the field site indicated occurrences of
quartz, feldspars, illite, kaolinite, calcite, pyrite and siderite
(Warembourg, 1976).
Sampling and Analysis
During late July, 1983, surface mapping of barren and saturated
sandstone outcrops in the immediate vicinity of Northwest Asphalt Ridge
was completed. Using an aerial photograph (Page, 1981), the outcrops
18
were located and plotted on an overlay. Twenty-one samples were
collected (Fig. 8 ) , and field descriptions were made for each sample.
No major discrepancy in lithologic descriptions of the Asphalt Ridge and
Rim Rock Sandstones (Kayser, 1966) was anticipated.
Several of the samples which were saturated with bitumen were sub
mitted to the WRI bitumen analysis laboratory for toluene extraction. An
attempt was made to identify the detrital grains with a binocular micro
scope. However, after bitumen removal, it was apparent that the grains
were partially coated with silt and clay size particles, inhibiting
positive identification of the detrital grains. Therefore, samples were
analyzed by X-ray diffraction for mineral content, using a Philips APO-
3600/02W automated powder diffTactometer with a computer search-match
identification system (SANDMAN). Gross lithologic descriptions were
completed using a binocular microscope. Lithologic characterization
combined field description parameters (color [Munsell Soil Color Charts,
1954], bitumen saturation, and degree of competency relative to other
outcrop samples) with microscopic descriptions (grain size, sorting).
Interpretation
Gross lithologic descriptions for each outcrop sample are presented
in Table 1. Mineralogy of the sandstones, as determined by X-ray
analysis, is shown in Table 2. Three tentative groupings of sandstone
types became apparent, based upon competency, degree of bitumen satu
ration and mineralogy.
Samples of the first group (sample numbers 1, 2, 3, 5, 9, 15, and
22) were identified as sandstone lenses of the upper shale member of the
Mancos Group. They were generally pale yellow to yellowish brown, very
fine grained, well sorted, and hard in outcrop. The second set of
samples (sample numbers 4, 6, 7, 8, 14, 20, and 21) was designated Group
A of the Mesaverde Group. Outcrop samples were light to dark grayish
brown, very fine to coarse, well to poorly sorted. The samples with
minor bitumen saturation were friable, but the saturated samples were
indurated. The third set of samples was designated Group B of the
Mesaverde Group. Hand specimens (sample numbers 10, 11, 12, 13, 16, 17,
and 19) had the following characteristics: light brownish gray to very
19
V-LETC FIELD \ \ SITE
* \ \
^4 .
Sec. 23 Sec. 24
SCALE
0 500 1000 Ft. Intermittent Stream
^D Inferred Fault Through "*u"**»«. Cretaceous Strata,
Prior to Seismic Survey
^ ^ Mesaverde Group
<̂ 3 Outcrop Sample 5 Location
Figure 8. Tar sand outcrops, surface sample locations, and inferred subsurface faults prior to seismic survey, Northwest Asphalt Ridge. Sample 18 is not included because of improper sampling.
20
Table 1. Gross lithologic description of outcrop samples. Key to abbreviations at end of table.
1 - Sandstone, It gray (2.5Y, 7/2), very fine, well sorted, hard
2 - Sandstone (silty?), It gray (2.5Y, 7/2), v fine to silt, mod
sorting, hard
3 - Sandstone, pale yellow (2..5Y, 7/4), v fine, well sorted, hard
4 - Sandstone, grayish brn (10YR, 5/2), v fine to fine, mod sorting,
friable, minor bitumen 5 - Silty sandstone, pale yellow (2.5Y, 7/4), v fine to silt, mod
sorting, hard
6 - Sandstone, grayish brn (10YR, 5/2), fine to coarse with some larger pebbles (up to 15mm), poorly sorted, friable, some bitumen
7 - Sandstone, pale brn (10YR, 6/3), v fine, well sorted, friable, minor bitumen
8 - Sandstone, It grayish brn (10YR,6/2), v fine, well sorted, friable, minor bitumen
9 - Silty sandstone, yellowish brn (10YR, 5/6), v fine to silt, well sorted, hard
10 - Sandstone, dk grayish brn (10YR, 4/2), v fine to med, poorly sorted, friable, some bitumen
11 - Sandstone, v dk gray (10YR, 3/1), v fine to med, poorly sorted, hard, bitumen sat
12 - Sandstone, dk grayish brn (10YR, 4/2), spotty, v fine, well sorted, friable, some bitumen
13 - Silty sandstone, v dk gray (10YR, 3/1), silt to v fine, mod sorting, hard, bitumen sat
14 - Sandstone, dk grayish brn (10YR, 4/2), v fine, well sorted, mod hard, bitumen sat
15 - Sandstone, It gray (10YR, 7/2), silt (?) to very fine, well sorted, hard
16 - Sandstone, dk grayish brn (10YR, 3/1), v fine to med, poorly sorted, hard, bitumen sat
17 - Sandstone, v dk gray (10YR, 4/2), v fine to fine, well sorted, hard, bitumen sat
21
19 - Sandstone, It brownish gray (2.5Y, 6/2), v fine, well sorted, mod
hard, bitumen sat
20 - Sandstone, It yellowish brn (10YR, 6/4), v fine, well sorted, hard
21 - Sandstone, It gray (2.5Y, 7/2) , v fine, well sorted, friable
22 - Sandy siltstone, It yellowish brn (10YR, 6/4), v fine to silt, well sorted, hard
blk - black brn - brown dk - dark It - light med - medium mod - moderate sat - saturated v - very
22
Table 2. Mineralogy of outcrop samples as determined by X-ray analysis.
Carbonates Feldspars Phy l los i l i ca tes Tourm D 0 N R
CO
MF 1 2 3 5 9
15 22
GA 4 6 7 8
14 20 21
GB 10 11 12 13 16 17 19
* k
k
k
* k
*
•k
k
* k
k
k
•k
•k
•k
k
•k
•k
•k
•k
k
k
k
k
k
k
k
k
k
k
k
k
k
k
k
k
k
k
k
k
k
k
k
k
k
•k
•k
•k
k
k
k
p"/-'"''''\"
A B
C
D
F
I
K
M
Anorthite
Biotite
Calcite
Dolomite
Ankerite
11 lite
Kaolinite
Microcline
N 0
P
Q
R
S
V
Tourrn
TABLE KEY
Albite
Orthoclase
Pyrite
Quartz
Dravite
Schorl
Muscovite
Tourmaline Group
GA Group A (Mesaverde)
GB Group B (Mesaverde)
MF Mancos Formation
# Outcrop Sample Number (see Fig. 8)
Detected by X-ray analysis
dark gray, silt to medium grained, well to poorly sorted. Poorly
saturated samples were friable. The following minerals were identified
by X-ray analysis in all three groups: quartz, microcline, orthoclase,
anorthite, kaolinite, and tourmaline. Calcite, dolomite and/or ankerite
were detected in all samples of the Mancos Group and Group A, but only
two samples of Group B had detectable calcite or dolomite (no ankerite).
II lite was present in both the Mancos Group and Group A samples but was
absent in the Group B samples. Muscovite was detected only in the
samples of Group B.
The primary mineralogical differences between the Group A and B
samples are: all Group A samples contain carbonate species and illite,
but no muscovite; only two samples of Group B contain carbonate species,
muscovite is detected in most samples, and no illite was reported in the
analyses.
Since more reliable mineral analyses could be obtained from un-
weathered core samples, 21 selected core samples from the LETC field
site were subjected to similar analyses as those performed on the out
crop samples. Ten thin sections of samples from the target zone of one
core were examined to determine quantitative mineralogy.
Subsurface Field Site Characterization
The Laramie Energy Technology Center conducted three in situ field
experiments (TS-1C, TS-2C, TS-IS) on an initial area consisting of 10
acres on Sohio's "D" tract; an additional 16 acres adjacent to the
original acreage were used in order to complete supplemental coring and
to plan the design of an additional field experiment. "D" tract is
located in portions of sections 23 and 24, T4S, R20E (Salt Lake Meridan
Survey). The boundaries of the field site and "D" tract are shown in
Figure 7.
The Rim Rock Sandstone is divided into three informal tar sand
zones (Fig. 9). The middle zone (TS-IS zone) of the Rim Rock Sandstone
was of particular interest in terms of subsurface characterization
because this zone was the target zone for all three field experiments.
Core analyses from the field site, on file at WRI, helped to form the
25
450 —
Upper Zone
Unconformity
L±J Z o \-co Q z <
o o a:
a:
Legend
Q. 3 O Q: o L±J
I 1 CO L±J
o
m H^-HE?:'
• ^ J - ^ J - Z
"
Sandstone
Bituminous Sandstone
Siltstone
Shale
Coal
WELL 4P5
Surface e 5969 .35
ev. ft.
Figure 9. Representative lithoiogic section of Rim Rock Sandstone at LETC field site.
26
following general description of each zone. The upper zone is highly
saturated with bitumen but is very low in saturated permeability. The
middle (TS-1S) zone is well saturated and has higher saturated perme
abilities. This zone was chosen for all three field tests. The lower
zone has high saturated permeability but low bitumen saturation.
Sampling and Analysis
Initial core sampling included 12 samples from core 4P5, which was
completed through the Asphalt Ridge Sandstone and into the upper shale
member of the Mancos Group. The Rim Rock Sandstone interval for this
core is represented in Figure 9. A 100-foot thick tongue of the Mancos
Group separates the Rim Rock Sandstone from the Asphalt Ridge Sandstone
(see Figure 5 for generalized stratigraphic section) at this location.
The Asphalt" Ridge Sandstone is approximately 120 feet thick, and the
total depth of this corehole is 884 feet. Three samples were selected
from the upper and middle (TS-1S) zones of the Rim Rock Sandstone, two
from the lower zone, and four from the Asphalt Ridge Sandstone. The
next step included sampling of nine representative cores across the
field site (Fig. 10). One sample was selected from the target zone (TS-
1S) from each core. Bitumen was extracted from these samples with
toluene prior to X-ray analysis.
Ten thin sections from the middle (TS-1S) zone of the Rim Rock
Sandstone (570-618 ft.) in core 4P5 were prepared commercially. The
bitumen-extracted samples were impregnated with a blue-tinted epoxy with
a refractive index of 1.56. Potassium feldspars were stained using
sodium cobaltinitrate, and calcite was stained with alizarin red S.
Interpretation
The 21 samples from core 4P5 and the other representative cores
across the field site were described initially from hand specimens and
then by utilizing a binocular microscope. The results from core 4P5 are
shown in Table 3, and the gross lithologic descriptions for the other
nine selected cores are presented in Table 4. The. qualitative miner
alogy of all core samples, as determined by X-ray analysis, is shown in
Table 5. Mineralogical identification was not attempted using a binocu-
27
3TI
3T2 • 2M2 3T3
•2MI [ 1
V TS-'lS
• 3T2 Corehole
1 1 Field Experiment Area
IMI
1 • h
215
—TS- IC
^ T S - 2 C
•3T4
4P7 •
4P3-B 4P5
•
5T3 •
*4P3-A
•4P3
1 N
4TI 1
SCALE
0 100 300 5 0 0 Ft.
Figure 10. LETC s i te map with locations of f i e l d tes t areas and selected coreholes.
28
Table 3. Gross lithologic descriptions of tar sand samples from core 4P5, LETC field site. Sample numbers in depth below surface. See Table 1 for abbreviations key.
UPPER RIM ROCK
455 - Sandstone, v dk gray (10YR, 3/1), v fine to med, poorly sorted, hard
480 -Sandstone, v dk grayish brn (10YR, 3/2),- v fine to fine, mod sorting, hard
510 - Sandstone, v dk gray (10YR, 3/1), v fine, well sorted, hard
MIDDLE (TS-1S) RIM ROCK
575 -Sandstone, blk (10YR, 2/1), v fine to med, poorly sorted, partially friable
595 -Sandstone, blk (10YR, 2/1), v fine to med, poorly sorted, partially friable
615 - Sandstone, blk (10YR, 2/1), v fine to med, mod sorted, partially friable
LOWER RIM ROCK
630 - Sandstone, v dk grayish brn (10YR, 3/2), v fine, well sorted, hard
640 - Sandstone, v dk gray (10YR, 3/1), v fine, well sorted, hard
ASPHALT RIDGE
775 - Sandstone, dk grayish brn (10YR, 4/2), v fine, well sorted, hard
812 - Sandstone, grayish brn (10YR, 5/2), v fine, well sorted, partially friable
835 -Silty sandstone, It brownish gray (2.5Y, 6/2), v fine to silt, well sorted, hard
862 - Sandstone, It gray (10YR, 6/1), salt and pepper, v fine to med, mod sorting, friable
29
Table 4. Gross lithologic descriptions of samples of target zone from selected cores, LETC field site. Core number indicated, with sample depth ( ) in ft. below surface. See Table 1 for abbreviations key.
1M1 (293*) -Sandstone, very dk grayish brn (10YR, 3/2), v fine, well sorted, hard
215 (357') - Sandstone, blk (7.5YR, 2/0), v fine to med, poorly sorted, hard
3T1 (435') - Sandstone, blk (7.5YR, 2/0), v fine to med, poorly sorted, hard
3T2 (556') - Sandstone, blk (7.5YR, 2/0), fine, well sorted, hard
3T4 (534') - Sandstone, blk (7.5YR, 2/0), v fine to med, poorly sorted, hard
4T1 (615') - Sandstone, dk grayish brn (10YR, 4/2), v fine to fine, mod sorted, partially friable
4P3B (629') -Sandstone, blk (10YR, 2/1), v fine to med, mod sorted, hard
4P7 (541') -Sandstone, blk (10YR, 2/1), v fine to med, poorly sorted, hard
5T3 (684') - Sandstone, dk grayish brn (10YR, 4/2), v fine to fine, mod sorted, hard
30
CU
to o
o
J=.
t -<n Q-</) •a
to <V
+-> <a c O
t_ re
o -
* Ji *
* * * * *
* * -K * * -X -X
* * -fc * * *
* * * * * *
* * * * * * * * * * * *
LT) i n o o i n i o i n o c LT> C\J LT> c\j o- a i n o 3 ' - n s - c n r H ( v i < j a r^. H m ic ^ j - c£"=3--=d-Lr>Lr>Lnici-C<x> < r - . cc oo co
* * * * * J c * J < - ) c
* * * * * * * * *
* * * * *
* * * * * * * * *
r—"Lnr—ic\j^3-r—i ro r~~ oo :r: 2: >—'i— t— t— v— a - o - v — o .—ic\ jcv->o-)0'-)^d-"=t^d-Lr>
31
M«y- !i: .,.••. K
4P5 Corehole 4P5
RR Rim Rock
AR Asphalt Ridge
00
CH List below includes selected core number
A Anorthite
C Calcite
TABLE KEY
D Dolomite
K Kaolinite
M Microcline
0 Orthoclase
Q Ouartz
V Muscovite
X Apatite
Y Marcasite
Z Pyrrhot i te
* Detected by X-ray analysis
lar microscope because the detrital grains were obscured by a particu
late coating.
Cursory examination of the samples from core 4P5 indicates that
previous lithologic descriptions of the Rim Rock and Asphalt Ridge
Sandstone were too general. Grain size in the Rim Rock varies from very
fine to medium, while the Asphalt Ridge contains grains of silt to
medium size (Tables 3 and 4). Sorting varies from poor to good in the
Rim Rock, but is generally good in the Asphalt Ridge. Chert occurs in
both the Rim Rock and Asphalt Ridge Sandstones. Previous generali
zations regarding occurrence of black chert in the Rim Rock Sandstone
and average grain size differences between the two sandstones appear
inappropriate for the stratigraphic section at the field site.
From X-ray analysis of core 4P5 it is apparent that the upper and
middle (TS-1S) zones of the Rim Rock Sandstone are comparable in quali
tative mineralogy, while the lower zone of the Rim Rock is similar to
the Asphalt Ridge. The nine samples from selected cores across the
field site exhibited qualitative mineralogy similar to the upper and
middle zones of the Rim Rock Sandstone. Quartz, microcline, and
muscovite were identified in all zones of the Rim Rock Sandstone, the
Asphalt Ridge Sandstone, and the selected target zone samples. Both
calcite and dolomite were identified in all samples from the lower Rim
Rock and the Asphalt Ridge, whereas only 2 of the 15 samples from the
upper and middle zones of the Rim Rock and the target zone samples
contained dolomite. The presence of carbonate species in the lower Rim
Rock and Asphalt Ridge distinguishes these portions of the Mesaverde
Group from the upper and middle (TS-1S) zones of the Rim Rock. Basing
identification of a sample solely on the presence or absence of
carbonate species is not recommended, but group sampling and X-ray
analysis can indicate general stratigraphic location within the
sandstones of the Mesaverde Group at Northwest Asphalt Ridge.
Quantitative mineralogy (Heinrich, 1965) was determined for 10 thin
sections from the middle (TS-1S) zone of the Rim Rock Sandstone. An
average of 1020 points were counted for each sample. Identification of
major species was made, and clay minerals were grouped together as one
fraction. Visible porosity was identified from the blue-stained epoxy.
33
Degree of sorting (Pettijohn et al., 1972) was noted for each thin
section sample. Table 6 summarizes percentages for the following
groups: visible porosity (including residual bitumen), quartz (in
cluding chalcedony), potassium feldspars, plagioclase feldspars, clay
minerals, muscovite, rock fragments, chert, accessory minerals, and
unknowns.
Some general vertical trends were noted for several groups within
core 4P5 (Fig. 11). Overall clay and quartz content decreased with
depth, while total rock fragments and chert generally increased. There
was no apparent trend in visible porosity or in total feldspar content.
The amounts of quartz, clays, rock fragments and chert were anomalous
for sample 595 ft. in relation to overall trend for each group.
Utilizing Folk's (1980) classification, each of the samples from
core 4P5 which was petrographically examined was categorized. The
degree of sorting was determined for each thin section (Pettijohn et
al., 1972). The results are presented in Table 7. The middle (TS-1S)
zone can be classified generally as a litharenite. Samples 575 ft. and
584 ft. are classified as a sublitharenite and feldspathic litharenite,
respectively. Most samples are moderately sorted, except sample 575
ft. (poorly) and sample 595 ft. (very poorly). The grains range from
angular to subrounded (Powers, 1953). The middle (TS-1S) zone of the
Rim Rock Sandstone can be classified as a moderately sorted litharenite
with an average visible porosity of 18%.
There is a lack of a cementing materials, either carbonate or
silicate, in the samples from core 4P5. If the bitumen extraction
process using toluene is prolonged, the samples tend to disaggregate or
become extremely friable. Postburn core recovery from the LETC
steamflood field experiment was poor in the zones where temperatures
were high; the bitumen was mobilized, and the detrital grains either
settled to the lower areas of the burn or flowed with the bitumen to the
production wells. It is apparent that the bitumen is the primary
adhesive material in these 1itharenites.
Samples from two zones of the Rim Rock Sandstone, the middle
(575 ft.) and the lower (630 ft.), and the Asphalt Ridge Sandstone
(812 ft.), were examined using a scanning electron microscope. Prior
34
Table 6. Mineralogy and visible porosity of samples from the middle zone of the Rim Rock .Sandstone, core 4P5, as determined by petrographic analysis.
# Pt.
575 1008
581 103
584 1005
589 1010
595 1004 GO on
601 1012
605 1029
611 1073
615 1006
617 1047
0
18 178)
16 156)
19 193)
18 183)
17 174)
20 205)
19 192)
16 173)
17 172)
17 174)
Q
63 (523
55 (463
55 (445
58 (483
28 (232
57 (462
61 (513
49 (441
42 (352
38 (332
KF PF
5 (44)
3 (29)
6 (52)
3 (28)
1 (12)
4 (29)
5 (41)
0.8 (7)
2 (14)
2 (17)
"
1 (8)
2 (13)
1
(in)
l (8)
3 (23)
1 (10)
2 (20)
0.7
(6)
1 (10)
CL M
13 107)
19 163)
15 125)
18 146)
5 :39)
10 182)
10 181)
8 (69)
11 [94)
7 [57)
1 (9)
0.5 (4)
2 (14)
0.5 (4)
—
0.5 (4)
0.7 (6)
0.2 (2)
1 (9)
0.5 (4)
RF CH
6 (53)
12 (103)
9 (73)
8 (64)
32 (265)
13 (106)
10 (83)
22 (199)
21 (178)
26 (2.30)
10 (82)
9 (72)
9 (75)
10 (79)
33 (270)
12 (96)
12 (98)
18 (159)
21 (177)
25 (222)
U AM
0.5 G, P (40) 1 (8)
0.3 P (3) 0.2 (2)
1 R, fi, Z (8) 0.9 (7)
0.6 R, T, Z (5) 1 (8)
0.2 P (2) 0.2 (2)
0.3 P, R (2) 0.4 (3)
0.5 R (4) 0.1 (1)
P, Z 0.3 (3)
0.2 P, Z (2) 0.2 (2)
Z
n.i (D
TABLE KEY
# Sample depth (below surface)
0 Porosity % (residual bitumen included)
AM Accessory minerals
B Biotite
CH Chert
CL Clay minerals
KF
Garnet
Potassium feldspars
M Muscovite
P Pyrite
PF Plagioclase feldspars
Pts. Number of points counted
R
Quartz (chalcedony included)
Rutile
RF Rock Fragments
T Tourmaline
U Unknown
Z Zircon
CO
en Values reported in percentages. Number of counts in ( ).
Percentages of minerals, rock fragments and chert calculated to total of points excluding porosity.
Percentages rounded to nearest 1.0 for values >1.0.
to
a
o o or
(0
o Q. (A
•D
«
w >» o o
o
O
35-30-25-20-15-10-
5-
35-30-25" 20-| 15-10-5-
8-7-6-5-4-3-2-
19-17-15-13-II-9-7-5-
55H
45-
35-|
25-20-
-.23 19-
- ^ 18-
17-
_l£i-
CD
Q
o a « * -t_ o
CO C V J * J - 1 0 0 0 1 ° C M * 1 - I O C O f - f ^ f ^ t ^ . I c o o o c o c o • • I I I I I 1 — 1 _
o co i n
1 CM cn
M-CO
CO CO
, 1
CO CO
1 -
o O CO
1 CM O 1
* » •
o 1
CO
o 1
cn o
_ 1 .
o CO
CO CO
-J U
e
u o
c trs
E
t_
o •—> E
*» > • >
-u »— o t_ o ex
c
m >>
(O
u
Q . ITS t_ zn o c_
O) Q .
>> -Q T 3 <D C
>
TO
<_> r— +-> 5_
<D i »
• tr> CL.
^r a> i _
o o
3 cn
37
Table 7. Sandstone classification of 10 samples from core 4P5. Determined by petrographic analysis.
Sample Qtz depth
R F F/R Classification1" Sorting^
575 75 19 6 (523) (135) (44)
0.32 sublitharenite poorly
581 69 26 5 (463) (175) (37)
0.19 1 i tharen i te moderately
584 68 22 10 0.45 feldspathic (445) (148) (65) litharenite
moderately
589 73 22 6 (483) (143) (38)
0.27 l i t h a r e n i t e moderately
595 29 68 3 (232) (535) (20)
0.04 litharenite very poorly
601 65 28 7 0.25 (462) (202) (52)
litharenite moderately
605 69 24 7 0.29 (513) (181) (51)
l i t h a r e n i t e moderately
611 53 43 3 0.06 (441) (358) (27)
l i t h a r e n i t e moderately
615 48 49 3 0.06 (352) (355) (20)
l i t h a r e n i t e moderately
617 41 56 3 (332) (452) (27)
0.05 litharenite moderately
Qtz - quartz F - total feldspars R - rock frags, and chert Qtz, F, R reported in %. ( ) indicate number of points. t Folk (1980) A Petti John et al. (1972)
38
to examination, bitumen from three samples from core 4P5 was extracted
with toluene. All samples were coated with gold and examined with a
JEOL JSM-35C Scanning Microscope at the Geology Department of the
University of Wyoming. All samples exhibited evidence of surficial
dissolution and the presence of a microcrystal1ine film draping the
grains, inhibiting identification of most of the grains. Identification
of the microcrystal 1 ine film was not made. If it is of organic origin,
it may be the waxy portion (C30 to C60) of the bitumen insoluble by
routine toluene extraction (K. P. Thomas, personal communication). If
the material is inorganic, it may be an amorphous or a microcrystal 1 ine
precipitate.
Micrographs of the lower Rim Rock (630 ft.) and the Asphalt Ridge
(812 ft.) are shown in Figure 12 (a and b, respectively). Grain size,
shape, and degree of sorting are comparable. Both kaolinite books and
carbonate rhombohedra were identified in the Asphalt Ridge sample.
In the sample from the middle (TS-1S) zone (Fig. 13, a) grains from
the larger-sized fraction are clearly altered and irregularly coated
with secondary overgrowths. The microcrystal1ine draping over the
smaller-sized fraction grains is shown in Figure 13, b. Extensive
surficial dissolution is prominently visible at this higher magnifi
cation. Surficial crystal structure has been obliterated on most
grains. No carbonates were found in this sample, but kaolinite books
were present.
Local Structure
Utilizing interpretations by previous investigators, coring results
from the LETC field site, and a high resolution seismic survey completed
in 1982, a revised and more detailed structural interpretation of the
study area is proposed.
Previous Investigations
Using core data from the tract currently owned by Sohio, Covington
(1955b) identified three faults which formed a graben structure trending
southeast across the tract. McDonald (1957) also used these same core
results and proposed three new locations of faults. An additional fault
39
a) Core 4P5 630 ft.
b) Core 4P5 812 ft.
Figure 12. Scanning electron micrographs of lower zone of Rim Rock Sandstone (a) and Asphalt Ridge Sandstone (b).
40
a) Core 4P5 57b ft.
^y**-'
b) Core 4P5 575 ft.
Figure 13. Scanniny electron microyraphs of middle (TS-IS) zone of Rim Rock Sandstone (a) and microcrystal1ine coating (b).
41
was suggested by Kayser (1966). Coring completed by LETC indicated the
presence of an additional fault which trended northwest across the field
site. These proposed locations of substantial faults were combined and
are illustrated in Figure 8.
Seismic Survey
In 1982, a high resolution seismic survey was completed at the LETC
field site and immediate vicinity (Applegate and Liu, 1983). The
purpose of the survey was to determine shallow structures (less than
1,000 feet deep), particularly in tar sand. Six short ( V4 mile) lines
were shot in a grid pattern (Fig. 14). Spacing between geophones was 20
feet, and standard source interval was 40 feet.
The first reflector with adequate continuity to be traced across
the area was termed the yellow horizon (Applegate and Liu, 1983). The
sandstones were not chosen as reflectors for several reasons, such as
facies changes and inconsistencies of bitumen saturation, porosity, and
clay content. This horizon is approximately 100 feet below the bottom
of tie lower zone of the Rim Rock Sandstone, near the center of the
field site. Seismic profiles for each of the six lines are shown in
Figures 15, 16 and 17 (modified from Applegate and Liu, 1983).
Structure of the Field Site
The field site is crossed by a northwest-southeast trending graben-
horst fault complex (Fig. 18). The complex, as presented by Applegate
and Liu (1983), was modified to include interpretations of this study
using additional core data and field experiment results. From the
seismic survey and coring results, fault displacement appears to exceed
100 feet for the fault whose fault trace extends beyond the southeast
border of the field site. A structural high (150 microseconds
[psec]) exists in the northeast section of the area (Applegate and Liu,
1983) which is part of an anticlinal structure trending northeast-
southwest. Another high area (150 psec) is in the southeast portion of
the site. A synclinal feature (170 psec) is evident between these two
highs. It is proposed that the faults extend into the tar sand field
test zone.
42
\ — r \
\
\
I N
\ \ \
\
X
<s> ^
LETC FIELD SITE
^
Sec. 23 | Sec. 24
SCALE
0 500 1000 Ft. Intermittent Stream
Seismic Line
Mesaverde Group Outcrops
Figure 14. Location of seismic l ines at LETC field s i t e .
43
w Line 6
LINE 2
'Line 4
W LINE -p. -p.
- 4 5 0
550
650
h 7 5 0 Q o>
h 8 5 0 "Z
CD 5L o € O o c 3
- 3 5 0
h450 2.
- 550
250 500 Ft.
„ . - . - ' "" Yellow Horizon ~*^~~ Fault
Seismic Datum = 5952 Ft.
650
-750
-850
Figure 15. Seismic profiles for lines 1 and 2. See Figure 25 for line locations.
w LINE 5 E Line 6
- 4 5 0
- 5 5 0
- 6 5 0
- 7 5 0
- 8 5 0 ^
W LINE 3
en 'Line 6 •Lin e 4
0
SCALE
"250 500 Ft.
--"Yel low Horizon •'Fault
Seismic Datum = 5952 Ft
450
-550
-650
-750
-850
Figure 16. Seismic profiles for lines 3 and 5. See Figure 25 for line locations.
sw
sw
'Line 2
'Line 2
LINE 6
'Line 3
LINE 4
kin e 3
• /
SCALE
0 250 500 Ft.
'Lin e 5
TU ine 5
NE
NE
- 5 5 0
- 6 5 0
- 7 5 0
- 8 5 0 o CD
950 -o
CD 2. o i o a c 3
Yellow Horizon
— - - Fault
Seismic Datum = 5952 Ft.
- 4 5 0 5 -
T) - 5 5 0 n>
CD
- 6 5 0
- 7 5 0
- 8 5 0
Figure 17. Seismic profiles for lines 4 and 6. See Figure 25 for line locations.
--J
^ ^ — Fault ^ . " " In fe r red
, . - ' Time ' " l 7 ° Datum
Seismic Dat
Contour Inte
0 100
I N
^ -̂ ̂
-(70 —
SCALE
Figure 18. Location of faults and structural contours as determined by yellow horizon of seismic survey (Applegate and Liu, 1983), f ie ld tests and coring results.
The thickness of the Rim Rock Sandstone varies considerably from
north to south across the site (Fig. 19), primarily due to the angular
unconformity present between the upper Rim Rock and the overlying
Duchesne River Formation. The upper zone of the Rim Rock is thinnest
(10 ft.) at corehole 1M1 and thickest (78 ft.) at corehole 4T1 (Table
8 ) . The top of the TS-1S zone is almost 400 ft. lower in elevation at
the southern margin of the field site than at the TS-1C field test
area. The strata dip 12-34° south-southwest across the field site.
Considering the complex structure, a contour map of any portion of the
Rim Rock Sandstone would be difficult to construct accurately because of
the faulting present at the field site and scarcity of control points
(coreholes, drillholes, well logs) within each fault block.
Summary
The lithologic characterization completed in this study, combined
with previous structural interpretations and the high resolution seismic
survey, were utilized to produce a revised structural map of the study
area (Fig. 20). The results of the seismic survey not only identified
faults at the field site, but also tied these faults to the proposed
faults on the western half of Sohio's "D" tract (compare with inferred
faults of Fig. 8 ) . The fault complex is much more extensive than that
originally proposed by Covington (1955b). Results from the field
experiments will be presented later, but it is suggested that five of
these faults crossed all three of the field experiment areas.
Two different groups of tar sand crop out at Northwest Asphalt
Ridge, as shown by carbonate, illite and muscovite content, bitumen
saturation, and competency. This differentiation is also present in the
21 samples from core 4P5. Outcrop Group A is similar to core 4P5
samples from the lower Rim Rock and Asphalt Ridge Sandstones. Outcrop
Group B is similar to the upper and middle (TS-1S) zones of the Rim Rock
Sandstone of core 4P5 and the nine samples from representative cores
across the site. Additional quantitative mineralogy (petrographic
analysis) would be necessary in order to classify these sandstones
1ithologically and to identify the outcrops by formation.
48
•3T4 (205)
rzzi
Corehole (Thickness of Rim Rock Sandstone)
Fie ld Experiment Area
Fault
Inferred Fault
SCALE
0 100 300 500 Ft.
Figure 19. Variation in total thickness of Rim Rock Sandstone at corehole locations.
49
Table 8. Summary of zones and elevations for nine selected coreholes. Elevations above mean sea level.
Surface Upper zone Top TS-IS Thickness elev. thickness zone, elev. Rim Rock
Corehole (ft.) (ft.) (ft.) (ft.)
1M1
215
3T1
3T4
4T1
4P3B
4P5
4P7
5T3
5963
5962
5970
5958
5965
5970
5969
5973
5951
10
14
14
48
78
65
70
67
66
5671
5608
5540
5463
5374
5367
5399
5440
5281
155
160
152
205
231
205
219
>200
222
50
Y T \
\
\
\ DS
XU
x \ \ U\D
\ \
i N
D , U \
V ••\<^
••.'K
\V\ \ 3 ^ ^
* * ^ \S>
x V\\ v\° X
••.J\ \ \ \>~LETC FIELD \D \ \ SITE UNs
121)
Sec. 23 | Sec. 24
SCALE
0 500 1000 Ft. Intermittent Stream
cssftfts Mesaverde Group Outcrop
^ 3 - t f Fault _- Inferred Fault
Figure 20. Revised s t ructural map of Northwest Asphalt Ridge and study area.
51
Using thin section analysis on 10 samples, the target (middle) zone
of core 4P5 is generally classified as a moderately sorted litharenite
with an average visible porosity of 18%. Its major constituents are
quartz, rock fragments, chert, clay minerals and feldspars. Other minor
and trace minerals include muscovite, pyrite, rutile, biotite, zircon,
and tourmaline.
IN SITU RECOVERY FIELD EXPERIMENTS
Pretest Site Characterization
Initial selection of an appropriate target zone for in situ
processing at the field site was begun in late 1974. Two cores were
drilled on the original 10-acre site. Results of core analyses aided in
the selection of the target zone for the first experiment. The use of
other methods to enhance evaluation of the reservoir sandstone expanded
over the following eight years.
Dri11ing and Coring
Eighty-six locations were drilled and/or cored at the field site.
The majority were associated with the process-monitor well patterns of
the field experiments. The remainder were site evaluation cores and
post-experiment cores, the latter used to help determine sweep
efficiency of each of the field experiments. Most of the holes were
drilled with a rotary bit to just above the top of the Mesaverde
Group. A predominant zone of conglomerate in the lower Duchesne River
Formation immediately lies above the Rim Rock Sandstone. Most core was
2 1/8 inches in diameter. Following brief field description, bitumen-
saturated intervals were wrapped in plastic sleeving to inhibit
degradation, boxed, and subsequently analyzed.
Downhole Wei 1 Logging
Various well logs were completed at the two combustion experiment
sites. In order to reduce the amount of coring necessary for resource
evaluation, reservoir properties of eight well locations were compared
52
using core analyses and/or downhole well logs. These results were used
in the design of the third field experiment and a fourth planned experi
ment; a suite of logs was completed for each well. A summary of the
comparisons is presented by Fahy et al. (1983).
Downhole well logging cannot replace core analyses for some
evaluation parameters, but it has proved valuable in several areas.
Logging results can provide general stratigraphic and lithologic
information when compared with logs that have been correlated with core
analyses in the same target zone. The study completed on the well logs
at the site concluded that logs could be used with confidence to
determine the following parameters: shale volume and porosity (straight
density log); oil saturation (carbon/oxygen logs yield conservative
data); and elastic rock properties (sonic).
Air Injectivity Tests
Prior to each of the three field experiments, air injection tests
were conducted at each pattern. The results of these tests were used to
determine air flux rates available for process initiation. Directions
of lateral orientation of permeability, along with vertical zonation
within the target zone, also were determined. The orientation of each
of the process well patterns was improved somewhat using these data.
Radioactive tracer tests were also conducted on the first two
experiment patterns. The tracer, 85 krypton, was injected into each
injection well separately; its arrival time and concentration were noted
in each production well. The results were used to determine direction
and orientation of permeable zones across the field site and in the
target zone of each borehole.
Well Monitoring
Each experiment pattern had a set of monitor wells interspersed
between the process wells, as well as beyond the pattern itself. These
holes each contained a sequence of thermocouples designed to observe
changes in temperature vertically in the borehole. A single thermo
couple was raised and lowered through the target zone of the first
experiment, but the thermocouples of the second and third experiments
53
were permanently installed every foot throughout the target zone.
Periodic readings from each monitor well were measured by
instrumentation connected to a mini-computer, which printed the data on
site for field use.
The injection wells were also equipped with air and/or steam
injection meters to monitor and control injection pressures and air flow
rates. Product gas analysis equipment was also available to monitor the
process.
Core Analysis
The analytical results from pre-experiment cores provided the
information needed to characterize the tar sand reservoir and
subsequently choose an appropriate target zone. Because of the low API
gravity of the bitumen, it cannot be displaced during routine porosity,
permeability, and bulk density measurements. Therefore, these
parameters are measured first with the bitumen in place and again with
the bitumen removed. The standard set of physical parameters determined
by core analysis included: 1) porosity (saturated and extracted), 2)
permeability (saturated and extracted), 3) bitumen saturation (% pore
volume and/or weight % ) , 4) water saturation (% pore volume), 5) grain
density, and 6) bulk density (saturated and extracted). Other parameters
less frequently determined were saturated and extracted compressive
strength. Porosity, permeability, bitumen and water saturation data
provided significant insight into reservoir characterization and field
experiment design and operation. These analyses were also compared to
the results from cores drilled after the completion of each experiment.
Comparison of saturations of bitumen and water contributed to the
evaluations of production gases and fluids, processing techniques, and
process well pattern design.
Processing Techniques
In the design of an in situ recovery process for tar sand, several
difficulties associated with this type of hydrocarbon production must be
addressed. The primary obstacle is the development of an effective
technique to sufficiently decrease the viscosity of the bitumen, and
54
thus to mobilize it. The second problem involves the application of the
viscosity reduction technique to the reservoir. Finally, a mechanism to
transport the mobilized bitumen, gases, and fluids from the reservoir to
the production wells must be developed. These three significant
problems have been overcome with the development of combustion
(fireflooding) and steamflooding techniques. Both processing types were
utilized at the LETC field site.
Combustion
Three forms of in situ combustion have been developed for recovery
of bitumen and heavy oil (Chu and Crawford, 1983). These are dry
forward combustion, reverse combustion and wet combustion. The first
two techniques were utilized at the LETC field site for the TS-1C
experiment (reverse) and the TS-2C experiment (combination reverse and
forward). The wet combustion process uses water along with injected air
during the forward combustion process. This technique was not attempted
at the field site.
In the reverse combustion process (Fig. 21, upper half) ignition of
the reservoir is at the production well, and the combustion front moves
to the injection well, opposite the direction of air flow. The movement
of the burn front is partially a function of heat conduction in the
reservoir ahead of the front. Advantages of this process include: 1)
the absence of plugging of the reservoir because the produced fluids and
gases move through the heated portion of the reservoir, and 2) pro
duction of a higher quality product, a crude oil with a higher API
gravity. However, there are some disadvantages to this technique. The
process is very sensitive to air flux; consequently, air flux must be
maintained at the appropriate rates to prevent reversal of the burn-
front direction. Spontaneous ignition in the unburned area of the
reservoir may occur ahead of the combustion front as the result of low
temperature oxidation (Cupps et al., 1976; Chu and Crawford, 1983).
The second combustion technique, (dry) forward combustion, is
similar to the reverse process, but the combustion front moves in the
same direction as air flow (Fig. 21, lower half). Ignition occurs at
the injection well; injected air, the burn front, and the combustion
55
REVERSE COMBUSTION Ignition at Production Well
Injection Well
Air
Cold Region of Reservoir
Overburden
Combustion Zone
Production Well
Hydrocarbon Vapors
Heated Reservoir
Injection Well
Air
FORWARD COMBUSTION Ignition at Injection Well
Heated Reservoir
Overburden
Combustion Zone
-p^ Z>
Production Well
Hydrocarbons
Cold Region of Reservoir
Figure 2 1 . Reverse and forward combustion processing techniques,
56
products all move toward the production well. A distinct disadvantage
of forward combustion is that produced fluids move into the unburned,
cool portion of the reservoir and may condense and plug the reservoir.
Advantages of this process include the production of coke (carbonized
bitumen) ahead of the burn front, providing fuel for combustion; and the
process is less sensitive to air flux (Cupps et al., 1976; Chu and
Crawford, 1983).
Steamflooding
The idealized steamflood process is schematically represented in
Figure 22. As steam is injected into the reservoir, its latent heat is
released upon contact with the cooler reservoir, thus heating the rock
matrix and bitumen (Farouq Ali and Meldau, 1983). The temperature of
the reservoir is elevated and maintained with constant steam injection.
Distillation of the lighter fractions of the produced hydrocarbons,
along with lower residual oil saturations and higher permeability in and
behind the steam front, aid in production of the bitumen. Conductive
heating of the reservoir occurs ahead of the steam front.
Operation and Results
From 1975 through 1980, three in situ field experiments were con
ducted at the LETC field site, following laboratory experiments (Land et
al., 1975) and process investigation (Watts, 1979), and in conjunction
with computer simulation (LETC, 1981). A summary of the entire project
is presented in In Situ Recovery (1983). The physical and chemical
properties of the produced oils were summarized by Dorrence et al.
(1981).
First Combustion Experiment
The TS-1C reverse combustion experiment was conducted in late 1975
in a 10-foot-thick zone of the middle (TS-1S) Rim Rock Sandstone (Cupps
et al., 1976; Land et al., 1977). The zone was selected on the basis of
bitumen saturation, effective permeability and zone confinement.
Approximately 300 feet of overburden overlie the target zone which dips
20° south-southwest. The zone is capped by a shale layer one to eight
57
OVERBURDEN
CO
H m > 2 ? m o H O
m r r
—>-
— •
— » -
—*»-
RESIDUAL / OIL / STEAM OIL /BANK/ FRONT
VAPORIZATION (DISTILLATION)
HOT WATER FLOOD
COLD WATER FLOOD
VIRGIN RESERVOIR
TJ ZO O O c o
m
CONDENSATION ENRICHMENT
VISCOSITY REDUCTION
UNDERBURDEN
Figure 22. Steamflood processing technique.
feet thick and is underlain by a limestone layer about one foot thick,
which is present across the test area except at the southwest corner
(Land et al., 1977). Analyses of 22 samples of core from the field test
area yielded the following average reservoir properties:
Porosity (%) 10.5 (sat.) 26.1 (ext.) Permeability (md) 132 (eff. gas) 651 (absolute) Oil Saturation (%) 62 (pore vol.) 8.6 (wt.) Water Saturation (%) 7.9 (pore vol.) Viscosity at reservoir temp., 52°F (cp) 106
The well pattern consisted of two parallel rows of three injection
wells each, with three production wells between the rows. The dimensions
of the pattern were 40 by 120 feet. Five monitor wells were drilled to
observe the movement of the combustion front across the pattern. Core
analyses indicated large variations in effective gas permeability, and
high permeability zones could not be correlated across the test zone.
Air injection tests completed prior to ignition showed that the test
zone would not accept air at injection pressures less than 300 psi. Air
pressures at the injection wells were increased until pneumatic
fracturing occurred and the reservoir accepted 16,000 scf/hr. of air at
each injection well. Radioactive tracer tests showed that the preferred
direction of permeability was along the strike of the bed (NW-SE), while
little of the air flowed along the dip. Injection wells 112 and 116 did
not communicate well with the production wells and were subsequently
abandoned. Only 25% of the injected air was recovered from the
production wells during preliminary air injection testing. The target
zone was ignited on November 25 with a 660-watt Calrod heater, and the
experiment was terminated on December 19. A total of 30.2 million
standard cubic feet (MMscf) of air was injected, and 4.7 MMscf (16%) of
gas was recovered. Sixty-five barrels of oil (5% of the original
bitumen in place) and 167 barrels (bbls.) of water were produced.
The estimated lateral extent of the heated tar sand, based on heat
generation, monitor well temperature readings, postburn core analyses,
and gas and fluid production, is shown in Figure 23 (Land et al.,
1977). It is apparent that the reservoir burned parallel to the
59
M6o
k
N
Scale yr rg f l r ia nman i r * .••-••••—••. f""mm*rvr.nrJ — " V r a m d
0 10 20feet • Production Well
® Injection Well
o Monitor Well
Well locations are at top of target zone
Figure 23. Lateral extent of TS-IC f i e l d tes t (Land et a l . , 1977).
approximate strike of the beds. A continuous zone of high permeability
did not exist in the target zone. Thus, a uniform combustion path could
not be established, inhibiting propogation of the combustion front. The
majority of the injected air was lost outside the pattern. Upon
examining the results of the seismic survey, it is proposed that a
fault, which parallels the strike of the beds, was the primary cause of
injected air loss.
Second Combustion Experiment
The TS-2C experiment used the same pattern layout as the TS-1C
experiment. However, it was aligned parallel to the strike of the tar
sand bed and the apparent preferred direction of permeability. The
experiment, conducted in 1977-78, combined a reverse combustion phase
followed by a forward combustion phase. The target zone, part of the
middle (TS-1S) zone of the Rim Rock Sandstone, was 15-20 feet thick, but
the upper 12-13 feet was separated from the main zone by a low
permeability interval. Average depth was 350 feet, and the dip ranged
19 to 34° southwest. Average reservoir properties, determined from core
analyses, are summarized below:
Porosity (%) 31.1 (ext.) Permeability (md) 85 (sat.) 675 (ext.) Oil Saturation (%) 65 9.6 (wt.) Water Saturation (%) 2.4 (pore vol.) Viscosity at reservoir
temp, 60°F (cp) 106
Thirteen monitor wells were completed across the pattern.
Preliminary air injection tests conducted prior to ignition
indicated preferred well communication and relatively improved air
recovery rates compared to the TS-1C test. Radioactive tracer tests
indicated that a zone of high permeability existed in the northwest
quadrant of the pattern, between wells 212 and 2P1, and along the
southwest edge of pattern, between 213 and 216. Because initial air
recovery rates averaged 58%, pneumatic fracturing of the reservoir was
unnecessary. Ignition succeeded on the third attempt using alternating
layers of diesel-soaked charcoal and burning charcoal. The experiment
was begun on August 28, 1977, and was terminated on February 27, 1978,
61
after 183 days. A total of 81.5 MMscf of air was injected into the
pattern; an average of 49% of the air was recovered. Twenty-five
percent of the original estimated bitumen in-place was recovered
(580 bbls.), and 600 bbls. of water were produced.
The lateral extent of the affected tar sand is shown in Figure 24
(Johnson et al., 1980). The 300°F isotherms represent the first phase,
reverse combustion. This phase was not continuous but was actually a
series of "echoings," alternating between reverse and forward com
bustion. This was not the original plan but accomplished the same ob
jective by sweeping the tar sand zone twice. Temperatures were generally
higher for the forward combustion echoes, as shown in Figure 24 for the
1000°F isotherms. Sixteen wells exhibited temperatures this high at
least once. Directional permeability did not parallel the strike of
beds at this pattern area, as it seemed to in the TS-1C experiment.
However, alignment along the strike did improve air recovery. High
permeability in the northwest portion of the pattern contributed to more
rapid movement of the combustion front through this area. The zones of
high permeability, in the northwest quadrant and along the southwest
margin, probably were caused by two faults (Fig. 16). Postburn core
analyses confirmed that the bitumen content was significantly reduced in
this part of the pattern (9 wt. % to 3 wt. % ) . An apparent barrier of
unknown cause in the western half of the pattern is evident in the 300°F
isotherm diagram and becomes more pronounced in the 1000°F isotherm
diagram.
Steamflood Experiment
The TS-IS steamflood experiment was conducted in 1980 on a 45-foot-
thick zone of tar sand in the middle (TS-IS) interval of the Rim Rock
Sandstone. The pattern consisted of one central injection well
surrounded by eight production wells (two concentric, inverted five-spot
patterns). Four monitor wells were completed within the pattern. The
dip of the bed averaged 28° southwest, and the amount of overburden
ranged from 454-520 feet thick. Preliminary core analyses yielded the
following reservoir properties:
62
3 0 0 ° F ( 150°C) i so the rms
Scale H M M •LUBIMJ
0 10 20 30 feet
V
• Injection Well ® Production Well ° Monitor Well
Well locations are at top of target zone
1 0 0 0 ° F ( 5 4 0 ° C ) isotherms
Figure 24. La te ra l ex tent of TS-2C f i e l d t e s t f o r 300°F and 1000°F isotherms (Johnson e t a l . , 1980).
Porosity (%) 29.5 (ext.) Permeability (md) 120 (sat) 2175 (ext.) Oil Saturation (%) 78.9 (pore vol.) 11.3 (wt.) Water Saturation (%) 6.6 (pore vol.) Viscosity at reservoir
temp., 60°F (cp) 10s
Air injection tests were completed at the TS-1S pattern prior to
commencement of the field experiments. The results indicated preferred
air flow downdip (southwest) and southeast. Air recovery was very poor,
averaging less than 1%. There was a zone of high permeability in the
lower portion of the target zone, ranging from 10-30 feet thick. A
north-south trending barrier, between wells 3I1-3P8 and wells 3P4-3P5,
was noted. The experiment was begun on April 23, with steam injection
into well 311. Well 3P4 (northwest corner) was the only well which did
not respond during the experiment. The experiment was terminated on
September 29. Only 5% of the original oil in place was recovered, a
total of 1,150 bbls. Approximately 10% (6,250 bbls.) of the injected
steam was recovered as water and steam; the remainder was lost through
the overburden, underburden, and high permeable zone which trended
northwest-southeast.
The extent of the hot water and steam fronts for the TS-1S pattern
is shown in Figure 25 (Johnson et al., 1981; Johnson, 1982). This
interpretation was made from analyses on nine post-experiment coreholes,
monitor and production well histories, and an electromagnetic
geophysical survey (Wayland et al., 1983). The majority of oil
production was at well 3P8 (60%); well 3P2 produced 30% of the total;
the remainder was produced across the rest of the pattern (except
3P4). The steam front progressed north-south, parallel to the proposed
fault which crosses the pattern. An impervious oil bank developed ahead
of the steam front; steam was lost into the underburden because of its
higher permeability compared to that of the lateral direction. These
problems, primarily loss of significant amounts of steam outside the
pattern, contributed to poor recovery results for this experiment.
64
3P4
/ X
/
3P3 3C5 \
3P8 \
0 10 20 30 40 Ft.
W e l l l oca t ions a t top of t a r g e t zone
Hot Water Zone Front Hot Wate r Zone Front
(Inferred) -• Steam Zone Front
Steam Zone Front (Inferred)
WW
Figure 25 . La te ra l ex ten t o f TS-IS f i e l d t e s t (Johnson, 1982)
65
INFLUENCE OF GEOLOGIC PARAMETERS ON RESULTS OF FIELD EXPERIMENTS
The importance of resource characterization of a tar sand reservoir
prior to site selection for in situ processing is evident from the
results of the three LETC field experiments. There are various geologic
parameters to consider in the selection of a reservoir and the field
design of an in situ process. It is essential that each potential
reservoir be evaluated prior to its selection in order to avoid or to
minimize operational difficulties as those encountered at this field
site. For this site, some factors are more significant than others.
Deposit Configuration
Several characteristics determine deposit configuration, including
zone thickness, dip, homogeneity, and lateral and vertical continuity.
Chu and Crawford (1983) recommend a zone thickness of greater than 10
feet for combustion processing; the two combustion field tests meet this
criterion. A lower limit of 25-30 feet zone thickness for steam in
jection is based upon heat balance between that which is lost to the
overburden and underburden and that which is transferred to the reser
voir (Farouq Ali and Meldau, 1983). The TS-1S steamflood experiment was
conducted in a 45-foot-thick zone, above this lower limit. The dip of
the beds (20-34° southwest) apparently had no effect on the combustion
experiments, and successful combustion processes have been reported (Chu
and Crawford, 1983) on other tar sand beds with dips up to 45°. In
creased dip would be expected to adversely affect the steamflood
process; steam would override oil and water and move updip (Farouq Ali
and Meldau, 1983). Because of the overwhelming effect that the faults
at the TS-1S field experiment area had on the results of this steamflood
experiment, the effect of dip cannot be assessed adequately.
Although the tar sand zones for all three field experiments ap
peared relatively homogeneous, rock properties varied considerably.
These properties are discussed later. The variation in grain size,
degree of sorting, pore configuration, and mineralogy of the middle zone
of the Rim Rock Sandstone was not readily apparent on a macroscopic
scale, but was evident following microscopic and X-ray analyses. The
66
vertical and horizontal continuity seemed sufficient prior to the field
experiments, but experimental results showed that variations in perme
ability in the target zone can adversely affect injected air and fluid
confinement. A reservoir may appear homogeneous and continuous, but ap
propriate distribution of permeability and porosity are vital reservoir
characteristics necessary for uniform sweep during processing. Lateral
communication between process wells is essential. All three field ex
periments exhibited problems with well communication, partially the re
sult of faulting which affects the tar sand beds, disrupting lateral
continuity. Because the majority of the geologic influences on the
field experiments were related to the faulting and highly permeable
zones within the reservoir, the effects of reservoir homogeneity and
continuity at this site are difficult to assess.
Local Structure
The faulted structure and associated fractures of the tar sand res
ervoir were the dominant factors affecting the field experiments. The
three faults crossing the field experiment areas caused loss of steam
(TS-1S experiment) and. loss of injected air along the faults (TS-IC and
TS-2C experiments). These losses resulted in decreases in both vertical
and horizontal sweep efficiency of the in situ processes. In addition,
there are probably numerous antithetic faults and fractures associated
with this fault system which were undetected by the seismic survey.
The direction of preferred air flow in the TS-IC pattern was origi
nally attributed to coincidence with the direction of the strike of the
beds (Fig. 18). Since the strike trends northwest, and the northeast
and southwest corner injection wells did not communicate with the rest
of the wells in the pattern, the preferred direction of permeability was
attributed to strike direction (Land et al., 1977). It was thought that
the injected air was lost through this permeable zone. Following comple
tion of the TS-2C field experiment (Johnson et al., 1980; Johnson et
al., 1981), which was aligned parallel to the strike, it was apparent
that directional permeability did not necessarily parallel the strike,
but trended both southeast and east southeast (Fig. 19). Displacement
of the two parallel faults which cross the TS-IC and TS-2C patterns is
57
apparently not sufficient to have been detected by the seismic survey.
Results of the air injection and tracer tests support the existence of
these faults. The fault which parallels the southwest edge of the TS-2C
pattern was detected partially by the seismic survey (Fig. 15), as shown
by the solid portion of the fault trace in Figure 19 (Applegate and Liu,
1983). The existence of a fault southwest of coreholes 4P3 and 4P3-A
was proposed during coring operations of fall, 1981, prior to the
seismic survey. It was suggested at that time that these coreholes
were drilled on a down-dropped fault block. Prior to abandonment of
these coreholes, fault displacement was estimated to be greater than 100
feet.
The strongest evidence for the influence of faulting on the results
of an experiment test at the field site lies in the TS-1S steamflood ex
periment (Johnson et al., 1981; Johnson, 1982). As shown in Figure 25,
the areal extent of affected tar sand trended north-south. It is pro
posed that steam loss in this direction can be attributed to an exten
sion of one of the northwest-southeast trending faults detected in the
seismic survey, both in the yellow and orango (deeper) horizons (Fig.
15). The other direction of steam loss, southwest of the pattern, is
evidence for an antithetic fault or unhealed fracture which probably
connects or intersects two parallel faults. This faulting was one of
the major causes of significant loss (90%) of injected steam. As shown
by Wayland et al. (1983), the majority of the hot water front was con
centrated in and beyond the western half of the pattern. The pattern is
primarily on the downthrown block of a normal fault (Line 3, Fig. 16).
Communication between the northernmost production well, 3P4, and the in
jection well could not be established, probably because of the bed off
set produced by the fault.
Test Zone Confinement
The success of a field experiment is partially dependent upon the
degree to which the injected air or steam can be delivered efficiently
and can be confined to the target zone. The factors which most influ
ence confinement are depth and permeability of the immediate overburden
and underburden of the target zone.
68
The lower limit of depth to the target zone varies according to
processing technique. A target zone depth of at least 100 feet is rec
ommended for combustion processes (Chu and Crawford, 1983). The LETC
combustion tests were conducted in zones ranging from 300-350 feet deep.
There were no apparent problems with processing a zone at this depth.
Successful steamflood projects were completed on zones with considerably
thicker overburden (Farouq and Ali, 1983). At depths less than 500
feet, overpressuring may occur and steam can be lost to the surface.
Injection rate and pressure must be maintained in order to introduce
steam efficiently into the reservoir. Average depth to the target zone
was 500 feet at the TS-1S field experiment. This did not seem to ad
versely affect the process design or operation. Loss of heat to the
wellbore was not a significant problem.
Once air or steam is delivered to the reservoir, loss to the over
burden and underburden must be kept at a minimum in order to control the
sweep of the reservoir (Technical, 1984). If permeability of the con
fining beds is too high, loss of air or steam above and below the test
zone may occur. The thermocouple placement in the monitor wells of the
TS-1C experiment did not detect any air loss to the overburden and un
derburden. Thermocouple monitoring histories from the TS-2C experiment
did not indicate any problems of this kind. Air loss at both these
sites was probably to the faults crossing the patterns, not through the
confining layers to the overburden or underburden. Steam loss was a
significant problem at the TS-1S steamflood field experiment (Johnson,
1982; Johnson et al., 1981). Because steam loss to the southeast-trend
ing fault prohibited maintenance of adequate viscosity-reducing tempera
tures, a bank of mobilized bitumen formed ahead of the steam front be
cause of cooler temperatures. The permeability of the oil bank zone was
less than the permeability of the underlying confining zone in some
portions of the test pattern; thus, the steam penetrated this zone and
entered the underlying, less saturated, higher permeable tar sand zone.
This problem may not have occurred had steam not been lost through the
faults, had reservoir temperatures been maintained, and had the forma
tion of an oil bank not occurred. From pre-experiment core analyses,
the confining layers apparently had low enough permeabilities to act as
effective barriers, but production problems enhanced the significance of
the degree of permeability of these layers.
69
Lithology
The lithology of a reservoir and its relationship to recovery
efficiency of in situ processing of tar sand are important factors in
resource choice and process design. The lithologic considerations
included here are mineralogy, clay content, grain size and shape, degree
of sorting, pore configuration, and rock wettability. Some of these
factors undoubtedly affected the field experiments, while others had
negligible influence.
Mineralogy of the TS-IS zone of the Rim Rock Sandstone is favorable
for in situ processing. Quartz, along with most feldspars and mica
species, has generally low reactivity to combustion and steamflooding
processes (Impact, 1982). Hutcheon et al. (1981) concluded that during
steamflooding there is little change in framework mineralogy, only on
matrix mineralogy. Temperatures are not high enough during the
steamflooding process to cause dissolution of framework grains. In
combustion processes, there are generally no fluids (excluding mobilized
bitumen) moving through the zone which could carry dissolved ions. The
only major mineral species identified (petrographic analysis) in the
TS-IS zone of core 4P5 are quartz and feldspars, along with rock
fragments (including chert). The trace minerals present were not
abundant enough to have caused any processing problems. The lack of
detectable carbonates is significant in relation to the steamflood.
Injected fluids can dissolve carbonates; redeposition of newly formed
carbonates in the pore spaces can cause a decrease in porosity and
permeabi1ity.
The presence of clays has been shown to adversely affect recovery
efficiency for both combustion and steamflooding techniques. Kramers
and Carrigy (1974) presented the following mineral reactions possible
during a steamflood:
70
250-300°C dolomite + kaol inite + quartz —n-n "*" calcite + montmor-
M2 illinite + C02
25O-30O°C calcite + kaol inite + quartz — n — ^ ->• montmori 11 inite +
H2° C02 + H20
Montmori11inite (smectite) swells upon contact with water, causing
plugging of pores. It will also lose the interlayer water layer with an
increase in temperature (>300°C) during combustion processing, resulting
in a decrease in volume. This may increase porosity enough to enhance
efficiency. Although both quartz and kaolinite were identified by X-ray
and petrographic analysis of the TS-1S target zone, no carbonates were
detected which could have completed these reactions. Hutcheon et al.
(1981) determined that <2ym illite, smectite, chlorite and zeolites
altered to 4-lOym smectite and analcime during steamflooding of Cold
Lake, Canada, tar sand at 250°C. A significant decrease in porosity
resulted.
A summary of the influence of position of clays in pore spaces is
presented in Crocker et al. (1983). The four configurations are: 1)
random, discrete particles, 2) pore lining or coating of matrix grains,
3) pore bridging, and 4) cementing. Random particles can be dislodged
by invading fluids and redeposited elsewhere in the reservoir, causing
clogging of the pores and a decrease in permeability. Pore bridging
clays can significantly reduce permeability. Pore lining and cementing
clays cause the least amount of problems; however, because of the large
surface area of pore lining clays, steamflooding of this type of clay-
containing reservoir can cause significant plugging problems. These
conclusions are supported by Lennox (1981). The presence of clays in
the microsections of core 4P5 was limited primarily to random pore-
filling clusters. There was some evidence of configurations 1, 2, and 3
as presented above, but in minor amounts.
Grain size, shape and sorting have been shown to affect bitumen
saturation. Lennox (1981) determined that bitumen-deficient laminae
from the Wabasca, Canada, oil sand were fine grained, angular, and
moderately to poorly sorted, while the bitumen-rich laminae were coarser
grained, rounded, and free of fines. The porosity did not vary signifi
cantly, but the permeability was affected by the differences in these
71
factors. Wardlaw and Cassan (1979) concluded that the optimum grain
size should be small because of the increase in porosity, the factor
which is presented as one of the most significant in oil recovery
efficiency. The detn'tal grains from the middle (TS-1S) zone of the Rim
Rock Sandstone are generally of very fine to medium sand size (1/16 to
1/2 millimeter) and poorly to moderately sorted. The grains range from
angular to subrounded. Because of the lack of a significant cementing
material (carbonates or silicates), these three parameters (grain size,
shape and sorting) probably did not have a significant effect on the in
situ field experiments. Once the reservoir was sufficiently heated the
bitumen was mobilized, and the detn'tal grains were disaggregated.
Wardlaw (1980) has conducted extensive studies of the effect of
pore structure on oil recovery efficiency during the waterflooding
process. Three factors under consideration are: 1) pore to throat size
contrast, 2) throat to pore coordination number, and 3) surface
roughness of pores. Throats are the intergranular passageways
connecting the pore spaces. The first factor can enhance recovery if
this ratio is small, as in the case of a small sand size, well sorted,
clean sandstone. An increase in the ratio for factor 2 correlates with
increased efficiency. Determination of factors 1 and 2 is conducted
using pore casts. SEM micrographs of the test zone showed that grain
surfaces are generally rough, the result of dissolution. 8ecause
bitumen is the adhesive material of this tar sand, once the bitumen is
mobilized, factors 1 and 2 have little effect on movement of bitumen
through the reservoir. The grains disaggregate as the reservoir is
heated.
The tar sand of Northwest Asphalt Ridge is oil-wet; the bitumen
adheres to the grain surfaces instead of concentrating in discrete
particles in the pore spaces. This characteristic is deleterious,
particularly to the steamflooding technique. The strong surface tension
between the grains and the bitumen (Sresty, 1981), inhibits separation
of the bitumen from the grains.
72
Rock Properties
Rock properties, such as porosity, permeability and oil saturation,
are dependent upon the factors previously presented. Lower limits of
these properties, recommended for bitumen recovery processes, are
presented in screening guide reviews by Farouq All and Meldau (1983) and
Chu and Crawford (1983). The following summarizes average
recommendations for combustion and steamflood techniques:
extracted permeability oil °API porosity saturation gravity
combustion 20% 100 md* 35% 10-45
steamflood 25% 1000 md* 50% 10-40
*millidarcy
At the LETC field site, extracted porosity is fairly consistent for the
TS-IS zone across the site, averaging about 29% (as determined by core
analyses, on file at WRI), above the lower limits for each technique.
Oil saturations at the three experiment sites are well above recommended
values, ranging from 62% PV at the TS-1C pattern to 79% PV at the TS-IS
pattern. These saturations were certainly sufficient for these field
experiments. Permeability varied randomly across the field site. The
target zones at the TS-1C and TS-2C patterns have extracted
permeabilities of 651 and 675 md, respectively. The TS-IS pattern site
had a higher average extracted permeability of 2175 md. These average
permeabilities are above the recommended lower limit, but the main
difficulties with inherent permeability (not the result of faulting and
fracturing) at the LETC field site were caused by vertical zonation in
the target zone. Danielson (1977) tested core samples from 13 locations
at the TS-1C pattern and identified eight layers of varying permeability
within 30 feet. Stratification was a major problem at the TS-IS field
experiment because this zonation did not necessarily correlate from well
to well. Six separate zones were identified at the TS-IS pattern which
had varying permeabilities and porosities, ranging from 2 to 1785 md and
13 to 32%, respectively (LETC, 1981). This heterogeneity prohibited
uniform sweeping of the deposit and concentrated the injected steam
along paths of higher permeability. Reservoir heterogeneities, whether
73
in permeability, porosity, oil or water saturation, are generally
determined by the structure and composition of the host rock. A better
understanding of the host rock, character would enable utilization of its
properties in relation to well design and processing technique.
DISCUSSION
As shown in the preceding sections, several geologic parameters
greatly influenced the results of the three LETC in situ field
experiments. These reservoir characteristics essentially were unknown
prior to selection of a portion of Sohio's "D" tract as the site to
conduct the experiments. The structural setting at the field site
caused significant operational difficulties. Inadequate lithologic
characterization of the target zone was not a serious problem because of
the favorable mineralogic constituents and the lack of significant
cementing material of this particular tar sand.
The following recommendations are made concerning preprocessing
geologic evaluation methods to aid in the identification of appropriate
resources and sites for potential in situ oil recovery processing.
Geophysical techniques - High resolution seismic surveys identify
most of the local structure, such as folding and faulting. Faulting and
fracturing can cause significant operational difficulties. Strati-
graphic relationships, dip of beds, and lateral continuity can be
determined from well logs.
Coring and core analysis - Rock properties, most importantly
porosity, permeability, oil saturation and water saturation, are deter
mined from standard core analyses. Vertical and lateral continuity,
along with homogeneity of reservoir properties, are important in the
selection of an appropriate resource. These analyses should include the
confining overburden and underburden in order to assess the target zone
confi nement.
Microscopy - Three of the more useful instruments are the
petrographic, binocular and scanning electron microscopes. These
instruments are used to determine lithologic properties which can
adversely or favorably affect resource selection and process choice and
74
design: grain size and shape, sorting, quantitative mineralogy, cement
types, presence of carbonates, clay mineral content and position within
pore spaces, and pore space configuration.
X-ray analysis - Qualitative mineralogy can be determined using
this technique. It is particularly useful in the identification of clay
minerals which are difficult to identify using a petrographic micro
scope.
These techniques can be used to determine the depositional environ
ment of the resource. For example, a fluvial deposit is generally
lenticular and has poor vertical and horizontal continuity. However, a
lacustrine or marine beach deposit generally has good horizontal
continuity and good to fair vertical continuity. Although the Rim Rock
Sandstone formed from elastics deposited in a marine shoreline
environment, horizontal or vertical homogeneity of rock properties
cannot be assumed. Determination of depositional environment is not
sufficient to ensure successful site selection. Local structure and
process technique selection are equally important when matching a
potential reservoir to the appropriate extraction technique.
SUMMARY
Evaluation of production histories from the three LETC in situ
recovery of bitumen from tar sand field experiment sites shows that
geologic characteristics of the reservoir contributed significantly to
the complications encountered during these experiments. A study of the
Rim Rock and Asphalt Ridge Sandstones at the Northwest Asphalt Ridge
deposit revealed the complex and varied nature of these lithologic
units. This study enabled identification of reservoir properties which
affected recovery efficiency and recommends reservoir and site selection
techniques.
Petrographic analysis of the middle (TS-1S) zone of the Rim Rock
Sandstone resulted in its general classification as a moderately sorted
litharenite with an average visible porosity of .18%. It consists
primarily of quartz, rock fragments, chert, feldspars and clay minerals.
It is very fine to medium grained, friable to hard, and variably
75
saturated with bitumen. Extensive surface dissolution of the detrital
grains hindered identification with a SEM.
X-ray analyses of the entire section of Rim Rock and Asphalt Ridge
Sandstones from one representative core identified primarily quartz,
along with calcite, dolomite, ankerite, microcline, orthoclase,
anorthite, kaolinite, muscovite, apatite, marcasite and pyrrhotite. Two
groups were identified; carbonates were present in the lower Rim Rock
and Asphalt Ridge Sandstones and were generally absent in the upper and
middle zones of the Rim Rock Sandstone. X-ray analysis of bituminous
sandstone outcrop samples indicated the presence of two groups,
primarily based upon carbonate, illite and muscovite content. Core
samples from the lower zone of the Rim Rock and the Asphalt Ridge are
similar in qualitative mineralogy to the Group A outcrop samples, while
the mineralogy of the upper and middle Rim Rock core samples resemble
that of the Group B outcrop samples. Both sandstones contain black and
grey chert and rock fragments in portions of the zones. Further
research is needed in order to identify the outcrops and to accurately
determine the lithologic character and depositional environments of the
Rim Rock and Asphalt Ridge Sandstones.
Target zone characteristics significantly influenced the field
experiments. The principal geologic factor adversely affecting all
three field experiments was the presence of faulting at each site.
Evidence for faulting at the TS-IS site was strong following the
experiment and was confirmed after completion of the seismic survey.
The preferred orientation of air flow at the TS-IC and TS-2C sites was
originally attributed to high permeable zones within the reservoir.
Integration of the seismic survey data, coring data, and production
histories led to the proposal that faults are also present at these two
sites. The faults identified by the seismic survey enabled better
approximation of fault locations identified by earlier investigators.
Other geologic factors which adversely affected the field experiments
included lateral and vertical heterogeneities of permeability and
porosity, target zone confinement, rough surface texture of clastic
grains, and oil-wet clastic grains. Favorable reservoir characteristics
include high quartz content; absence of carbonates; lack of clay
76
minerals bridging and cementing pore spaces; and sufficient porosity,
initial oil saturation and overburden.
The choice of a tar sand reservoir, an in situ recovery process,
and a well pattern partially depends upon balancing the adverse and
favorable geologic factors for a particular reservoir in order to
efficiently and economically produce the reservoir. Adequate resource
characterization would include the following evaluation techniques:
seismic profiling; well logging; core analysis (porosity, permeability,
oil and water saturation); petrographic, binocular and SEM microscopy
(lithologic characteristics); and X-ray analysis. Determination of
depositional environment is essential to reservoir selection and
production design for in situ processing of tar sands.
77
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