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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81