>INJECTION WELL INVENTORY OF WYOMING
VOLUME I
MICHAEL COLLENTINE
ROBERT LIBRA
LYNNE BOYD
CRAIG EI SEN, PROJECT MANAGER
WATER RESOURCES RESEARCH INSTITUTE
UNIVERSITY OF WYOMING
LARAMIE, WYOMING
Funded by the U.S. Environmental Protection Agency
Grant G-003269-79
Paul Osborne, Project Officer
JANUARY 1981
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INJECTION WELL INVENTORY OF WYOMING
VOLUME I
MICHAEL COLLENTINE
ROBERT LIBRA
LYNNE BOYD
CRAIG EI SEN, PROJECT MANAGER
WATER RESOURCES RESEARCH INSTITUTE
UNIVERSITY OF WYOMING
LARAMIE, WYOMING
Funded by the U.S. Environmental Protection Agency
Grant 6-003269-79
Paul Osborne, Project Officer
U.S.EPA REGION 8
Technical Library 80C-L
999 13th Street, Suite 500
Denver, CO 80202
JANUARY 1981
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Acknowledgements
Special thanks are extended to Mr. Donald Basko, Wyoming Oil and
Gas Commissioner, Mr. Charles Farmer, Petroleum Engineer, Mrs. Cheryl
Dowler, and the entire staff of the Oil and Gas Conservation Commission
office in Casper, for their help during the data compilation phase of
this project.
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INJECTION WELL INVENTORY OF WYOMING
TABLE OF CONTENTS
Volume I
INTRODUCTION part I
PETROLEUM RELATED INJECTION OPERATIONS part II
Review of Current Technologies II-l
Potential Environmental Impacts 11-17
Physical Descriptions of Petroleum Related
Injection Projects ......... 11-20
IN SITU URANIUM INJECTION PROJECTS part III
Occurrence and Characteristics of
Uranium Deposits III-l
Review of Current Technologies III-2
Potential Environmental Impacts III-3
Physical Descriptions of In Situ Uranium
Sites III-8
IN SITU TRONA INJECTION PROJECTS part IV
Characteristics of the Wyoming Trona
Deposits IV-2
Review of Current Technologies IV-2
Potential Environmental Impacts IV-5
Physical Descriptions of In Situ Trona Sites . . IV-6
UNDERGROUND COAL GASIFICATION PROJECTS part V
Review of Current Technologies V-l
Potential Environmental Impacts V-3
Physical Descriptions of Underground
Coal Gasification Sites V-5
CHEMICAL WASTE INJECTION SITES part VI
GLOSSARY part VII
LOCATION AND NUMBERING SYSTEM part VIII
REFERENCES part IX
MAP: Locations and Types of Injection Operations
in Wyoming map pocket
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Volume II: Data Tables
DEFINITION OF TERMS page 3
PETROLEUM RELATED INJECTION FACILITIES page 5
Water Injection page 5
Gas Injection page 323
Natural Gas Storage page 327
Hydrothermal Injection page 331
Water Disposal Systems page 335
Tertiary Recovery Projects page 343
IN SITU URANIUM MINING INJECTION FACILITIES page 347
UNDERGROUND COAL GASIFICATION FACILITIES page 353
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I. INTRODUCTION
This "Injection Well Inventory of Wyoming" is a detailed review
of underground injection projects within the state. Included are:
(1) overviews of injection technologies employed by the petroleum,
uranium, trona, coal, and chemical industries and the potential environ-
mental impacts associated with such injections; (2) physical descriptions
of existing injection fields within Wyoming; and (3) an inventory of
these injection wells including well location, depth, injected
formation, and other pertinent data. Technology reviews and site
descriptions of injection operations are contained in Volume I of
the report, while the injection well inventory of each operation is
contained in Volume II.
This study was funded by the U.S. Environmental Protection Agency
under contract no. GO-082-697-90, for the Underground Injection
Control Program (UIC). The UIC, authorized by the Safe Drinking Water
Act (P.L. 93-523), is designed to improve the protection of ground-
water resources from possible contamination caused by injection of
brines, sewage, and other fluids. This report, with its compilation
of roughly 4,000 petroleum industry related injection wells, 350
in situ uranium injection wells, and 400 underground coal gasification
injection wells, describes the current magnitude and distribution of
underground injection activities within the state, and will hopefully
serve as a background source directory for the UIC program.
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II. PETROLEUM RELATED
INJECTION OPERATIONS
REVIEW OF CURRENT TECHNOLOGIES
During the last 50 years, the oil industry of the United States
has placed increasing emphasis on secondary and tertiary methods of oil
production due to the increased price of oil, the increased costs of
exploration, and the low frequency of large domestic reservoir discov-
eries (Interstate Oil Compact Commission, 1974). In 1974, the Interstate
Oil Compact Commission estimated that by 1980, over half of the oil
produced in the United States, exclusive of the North Slope of Alaska,
would be produced by secondary and tertiary recovery methods.
Secondary and tertiary recovery are defined herein as the oil
and/or gas recovered by artificial flowing or pumping means, through the
joint use of two or more well bores (Smith, 1966). The purpose of a
secondary or tertiary recovery project is to displace as much oil as
possible from the reservoir to the producing well(s). In order to
effect an economical recovery, the injected fluid must be capable of
displacing oil from the pores of water-wet reservoir rock and/or break-
ing down the capillary forces between rock grains and the film of oil
around the grains in oil-wet reservoir rock. An enhanced recovery
operation should be designed to supplement the natural reservoir drive
mechanism(s) that provides for the primary oil recovery.
The types of injection operations that will be discussed in this
section include: (1) water and gas injection (secondary recovery
methods); (2) steam injection (advanced secondary recovery method);
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(3) polymer, miscible fluid, and microemulsion injection (tertiary
recovery methods); (4) salt water disposal; and (5) natural gas storage.
Primary Reservoir Drive Mechanisms
The mechanisms by which gas and oil are naturally displaced
through the reservoir to the producing wells are called the primary
reservoir drive mechanisms. They include: (1) fluid and rock expansion;
(2) natural fluid displacement; and (3) gravitational drainage.
Fluid and rock expansion energy is produced by the expansion of
hydrocarbon fluids and sediment grains within the reservoir matrix as
oil and/or gas are produced. As reservoir pressure decreases, fluid
pressure within the pore spaces is reduced, decreasing the bulk volume
of the rock, and increasing the volume of individual rock grains.
The combination of the bulk rock volume reduction and the solid rock
material expansion reduces the porosity of the rock by approximately
0.5 percent for each change of 1,000 psi in the internal fluid pressure
(Craft and Hawkins, 1959). As porosity decreases, hydrocarbons are
driven out of the pore spaces toward the producing well.
There are three types of fluid displacement drive mechanisms: (1)
solution gas drive; (2) water drive; and (3) gas cap drive. Solution
gas drive occurs in reservoirs that have no gas cap and are isolated
from water encroachment. The decreased reservoir pressure resulting
from production allows gases dissolved in oil and water to come out of
solution and displace oil toward producing wells. Primary recovery
from solution gas drive reservoirs is normally 5 to 30 percent of the
original oil in place.
Water drive is a natural drive mechanism caused by the encroachment
of water into the reservoir from an adjacent aquifer as gas and oil
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are produced and reservoir pressure declines. Primary recovery from a
water driven reservoir may be as high as 35 to 75 percent of the
original oil in place (Clark, 1969).
Gas cap drive is the reservoir energy produced by expansion of the
gas cap due to production and subsequent declines in reservoir pressure.
The expanding gas cap, which overlies the oil and water zones of the
reservoir, displaces oil downward toward the producing wells. Primary
recovery from a gas cap driven reservoir usually ranges from 20 to 40
percent and may be as high as 60 percent of the original oil in place.
Gravitational drainage or gravitational segregation may be con-
sidered a drive mechanism, but is usually a part of other drive types.
It is caused by the segregation of reservoir fluids (oil, gas, and water),
as the reservoir pressure is decreased by production. The fluids then
seek a new equilibrium distribution according to density.
Geologic and Hydrologic Controls
on Oil Recovery Efficiency
Structure, stratigraphy, hydraulic gradient, porosity, and perme-
ability play major roles in the mobility of both reservoir and injected
fluids and the bulk volume of the reservoir contacted by the injected
fluids (IOCC, 1974).
Oil recovery efficiency is a function of both the displacement
efficiency (the percentage of oil in place that the injected fluid
sweeps from a unit volume of the reservoir) and the volumetric sweep
efficiency (the percentage of the total reservoir volume that is
contacted by the injected fluid) (IOCC, 1974).
The displacement efficiency of the injected fluid is dependent
upon the saturation type (water-wet or oil-wet), and the relative
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permeability characteristics of the reservoir. In a reservoir where
the sediment grains are surrounded by a film of water (water-wet
reservoir), oil is readily displaced by the injection of water or gas;
however, where the sediment grains have oil films (oil-wet reservoir),
the injected fluid must be capable of breaking down the capillary
forces that exist between the grains and the oil in order to realize
economic oil recoveries (IOCC, 1974). The ability of the porous
reservoir rock to conduct a fluid in the presence of one or more
other fluids is a composite effect of pore geometry, reservoir
saturation type (either water-wet or oil-wet), fluid distribution, and
saturation history (Smith, 1966). The permeability characteristics of
a reservoir are a major factor involved in the determination of the type
of fluid injected in a secondary or tertiary recovery operation. For
example, a reservoir with poor permeability characteristics would be
injected with gas rather than water, due to the low relative viscosity
and high relative mobility of the gas in a low permeability reservoir.
A procedure for determining the relative permeability characteristics,
too detailed for the purposes of this report, is outlined in IOCC
(1974).
The volumetric sweep efficiency of the injected fluid is directly
affected by the mobility ratio and the injection well pattern.
Mobility ratio is defined as "the ratio of the injected fluid mobility
in the portion of the reservoir contacted by the injected fluid, to the
oil mobility in the non-invaded portion of the reservoir" (IOCC, 1974).
The mobility of a fluid is the permeability of the rock to that fluid,
divided by the viscosity of the fluid. Thus, the mobility ratio
decreases with increasing oil viscosity.
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The injection well pattern is, simply, the configuration of
injection well locations relative to production well locations. The
ideal injection pattern for any oil field is one that: (1) provides
the ultimate oil recovery capacity; (2) provides a sufficient rate of
fluid injection to attain this oil recovery; (3) maximizes the oil
recovery with a minimum of produced fluid to lift and dispose; (4)
utilizes known orientations of reservoir permeability irregularities,
fractures and stratification; (5) utilizes existing wells, minimizing
the drilling of new injection wells; and (6) is compatible with the
flooding patterns of operators on adjacent leases.
Among the most commonly used well patterns in Wyoming are the
five-spot, seven-spot, inverted seven-spot, nine-spot, line drive, and
peripheral patterns. Diagrams of these patterns are illustrated in
Figure 1. The five-spot pattern is the most popular configuration in
Wyoming and the rest of the United States due to its efficient flooding
performance and the ease of well convertibility from dry holes and
marginally economical production wells to the five-spot configuration
of injection wells. The five-spot pattern is utilized where reservoir
permeability is variable, in order to isolate known reservoir non-
uniformities. The seven- and nine-spot patterns are utilized under
field conditions similar to those of the five-spot pattern, but where
the conversion of wells is not conducive to the five-spot. Peripheral
and line drive patterns are employed where the injected reservoir has
a consistent, unidirectional fracture or permeability orientation
(IOCC, 1974).
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Direct Line Drive Pattern
I Injection Well
P Production Well
Pattern Boundaries
Nine-spot Pattern
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Peripheral Pattern
Figure 1. Injection well patterns (from IOCC, 1974, pp. 15 and 16).
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Drilling and Casing of Injection Wells
Before a fluid injection project can go into operation, the injec-
tion well(s) must be drilled and cased in a manner that insures both
the protection of the environment against inadvertent pollution and the
maximum utility of the well(s) (Barlow, 1972) . Whether it is designed
for disposal of brines, water injection, or microemulsion injection,
the well(s) must be designed to protect the near surface, fresh-water
aquifers through which it is drilled. An idealized schematic drawing
of an injection well is illustrated in Figure 2.
The borehole of the injection well is commonly 12 to 18 inches in
diameter and drilled to at least 200 feet below the deepest fresh-water
aquifer. Surface casing, of a diameter at least 2 inches less than
the diameter of the hole and equipped with centralizers, is run to the
bottom of the hole. The annular space between the borehole and the
surface casing is then filled with cement. Experience with brine
injection wells has shown this procedure to be effective in protecting
the cased-off fresh-water aquifers in the event of damage to the
injection casing.
After the surface casing is installed, a 7 to 12 inch diameter
hole is drilled from the bottom of the surface casing to the depth of
the formation that will receive the injection fluids. Borehole tests,
including cores, electric logs, caliper logs, etc., are run on the hole
prior to running the injection casing string. The injection (long)
string is usually 5h to 9 inches in diameter. After the injection
string is centered, cement is circulated to at least 1,500 to 2,000
feet above the total depth of the well in the annulus between the
casing and the wellbore. Depending on the nature of the injection zone
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ptessure gouge
INJECTED FLUID
Base of Fresh Water A
Aquifer(s) ¦
Injectca Unit
Figure 2. Idealized schematic drawing of an injection well (from
Donaldson, E. C., 1972).
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rock, the well is completed by perforating the cement in a friable for-
mation, by open hole in a hard consolidated sandstone or vugular lime-
stone, or by gravel packing in an unconsolidated sandstone interval.
Secondary Enhancement of Primary Reservoir
Drive Mechanisms
Mater Injection
Water injection is an oil recovery enhancement technique that involves
the injection of produced or non-produced water through wells into an
oil producing reservoir in order to: (1) displace oil from the reservoir
to producing wells as the primary production energy of the reservoir
declines; and (2) to maintain or increase reservoir pressure.
The water injection process was first used by accident, at a field
in western Pennsylvania over 100 years ago. Water from a shallow aquifer
leaked around a poorly sealed packer, entered the well's oil column and,
though it eliminated production from that well, production of oil from
surrounding wells increased noticeably. It wasn't until the 1890's that
the first waterflood test project in Wyoming was initiated at Salt Creek
Field in the second Wall Creek sand. Cole Creek Field was the site of
the next waterflood test in Wyoming in 1946. As of December, 1979,
the Wyoming Oil and Gas Conservation Commission reported 235 water
injection projects operating in the state.
There are nine general field characteristics considered favorable
for a water injection project. They are: (1) reservoir thickness
greater than ten feet and depth less than 10,000 feet; (2) sandstone
reservoir that does not contain major fracture porosity; (2) oil
saturation greater than 40 percent of pore volume; (4) water saturation
less than 45 percent of pore volume; (5) solution gas drive; (6)
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only moderate amounts of lenticularity; (7) a permeability profile that
is not extremely erratic; (8) viscosity of oil, at reservoir conditions,
of less than 30 centipoise; and (9) good water quality and an adequate
water supply (Recluse Field Engineering and Geologic Report, Oil and
Gas Commission Files).
Ideally, water is injected into the producing reservoir and
migrates through the permeable rock, displacing immiscible reservoir
fluids from the pore spaces toward the producing wells.
The oil recovery efficiency of a waterflood operation is primarily
dependent upon the type of reservoir saturation and the reservoir
permeability characteristics. For example, an oil-wet reservoir,
waterflooded for more than a year, might retain a significant percentage
of the original oil in place bound to the rock grain surfaces by
capillary forces. To remove the remaining oil, tertiary recovery
methods, utilizing fluids (surfactants, microemulsions, etc.) capable
of overcoming those forces, are necessary. The recovery efficiency from
a water-wet reservoir would depend more upon the permeability of the
reservoir. A greater percentage of in-place oil is displaced by water
in this type of reservoir, the controlling factor being the percentage
of reservoir volume contacted by the injected water.
The water used for secondary oil recovery operations may be
reservoir brine separated from produced oil, brine produced from a
water saturated portion of the produced reservoir, and/or "fresh"
water produced from a water saturated formation not associated with the
oil producing reservoir. The type of water used depends upon the
availability of fresh water and the compatibility of available water with
the connate fluids and mineralogy of the injected formation (IOCC, 1960).
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Gas Injection
Gas injection is a process similar to water injection, utilizing
produced gas to displace oil from the reservoir to producing wells.
The availability of gas and relative ease of injection make the secondary
oil recovery technique of gas injection an attractive option under
favorable reservoir conditions.
In a reservoir in which the fluids are segregated by density and
which has a permeability of at least 200 millidarcies, gas is most
often injected into the crest or gas cap of the reservoir. The expan-
sion of the gas displaces oil downward toward the producing wells,
usually resulting in high oil recovery efficiency. At fields where
producing oil wells were converted to injection wells, gas is injected
into the reservoir at a point below the gas cap. The injected gas then
rises toward the gas cap, displacing oil toward the producing wells
(IOCC, 1974). In reservoirs that lack sufficient permeability for
gravity drive to operate, a frontal drive or dispersed gas injection,
similar to that used for waterfloods, may be effective, especially in
reservoirs that have already been produced by solution gas drive
(IOCC, 1974).
There are two notable disadvantages to secondary oil recovery by
gas injection. They are: (1) the low viscosity of gas results in
poor displacement efficiency; and (2) the heterogeneity of permeability,
in most reservoirs, results in early breakthrough of injected gas to
producing wells.
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Steam Injection
The steam injection process is similar to water and gas injection
in that steam is injected into wells completed in the producing
reservoir, and that oil is produced from other wells placed in an
effective pattern around the injection wells. The injection of steam
is most effective in reservoirs with high viscosity (low gravity) oil
(IOCC, 1974).
Steam injection tests were initially conducted during the 1920's
and 1930's. The process gained prominence during the 1960's when Shell
Oil conducted a successful operation in California. Today, steam
injection is regarded as a well established method of advanced secondary
oil recovery.
The following are reservoir characteristics and design criteria
desirable for a steam injection operation, as outlined by the Interstate
Oil Compact Commission (1974, pp. 159-160):
1. The depth of the injected formation should be less than
3,000 feet.
2. The injection depth cannot exceed 5,000 feet, since the
critical pressure of steam is 3,202 pounds per square inch.
3. Formation thickness should not exceed 30 feet in order to
minimize heat loss.
4. Formation permeability should exceed 1,000 millidarcies.
5. Formation porosity should be approximately 30 percent.
6. The gravity and viscosity of the oil should be 12 to 25° API
and ^1,000 centipoise, respectively, at reservoir temperature.
7. Steam should be injected near the base of the oil zone.
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With the injection of steam into an oil reservoir, several fluid
zones are formed between the injection well bore and the oil producing
well as heat is lost to the surrounding rock material. Immediately
surrounding the well bore is a steam saturated zone. Beyond the steam
saturated zone is a zone of condensed steam. In the zone of steam
saturation, because of the presence of a gas phase, steam distillation
of the oil takes place. In the hot water zone in front of the steam
zone, a hot water flood occurs. Oil displacement from this zone results
from a reduction of oil viscosity, and thermal expansion of oil at
high temperatures, which leads to a reduction of residual oil saturation
and changes in the relative permeability characteristics. The latter
effect is poorly understood. Further displacement of oil occurs in the
cold water zone which precedes the hot water zone.
Tertiary Enhancement of Primary Drive Mechanisms
Tertiary recovery of oil differs from secondary recovery only in
the type of fluid injected. Rather than displacing oil from the pores
of the oil reservoir rock, as in water and gas injection processes,
tertiary fluids work as active agents which break down the capillary
forces binding oil to the rock grains of the reservoir. In Wyoming,
three types of tertiary recovery processes are now being utilized. They
are: microemulsion flooding, miscible fluid injection, and polymer
solution injection.
The most recent breakthrough in oil recovery processes is micro-
emulsion flooding, a miscible-type displacement process characterized
by 100 percent displacement of oil in the reservoir contacted (IOCC,
1974). Microemulsions are surfactant stabilized dispersions of
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hydrocarbons and water which, at high concentrations, form aggregates
called micelles. These micelles are capable of solubilizing fluid into
their cores. Alcohols and salts are also added to control stability,
viscosity, and other characteristics of the microemulsion.
Microemulsion flooding is a three-step procedure consisting of the
injection of a microemulsion slug, followed by the injection of a
"mobility buffer solution," which is, in turn, followed by the injec-
tion of water (IOCC, 1974). The mobility buffer solution is injected
after the slug of microemulsion to prevent rapid dispersion and thus
minimize the volume of microemulsion required for an effective flood.
Besides their high displacement efficiency, microemulsions also
have a high volumetric sweep efficiency. The mobility control of
microemulsion solutions inhibits the rapid dissipation of the micro-
emulsion injected by preventing "fingering" through the reservoir,
thus increasing the sweep efficiency (IOCC, 1974).
The microemulsion flooding method is applicable wherever a water
injection project has been successful and, in some instances, even
where water injection projects failed due to poor displacement of oil
by water. The economics of microemulsion flooding depend primarily on
the chemical requirement, cost of chemicals, and oil saturation in the
reservoir at the time the flood is initiated.
Miscible fluid injection is another recently developed tertiary
oil recovery process, involving an oil dissolving solvent capable of
complete displacement of oil from the contacted areas of a reservoir.
The miscible solvent may be an alcohol, a ketone, a number of
refined hydrocarbons, a condensed petroleum gas, carbon dioxide, or
exhaust gas.
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The procedure followed in a miscible fluid injection operation
consists of two steps. First, a slug of solvent, miscible with the type
of oil in the reservoir, is injected. Second, a fluid or gas, capable
of displacing the solvent and oil toward the producing wells, is
injected (IOCC, 1974).
In reservoirs with high viscosity oils, waterflood recovery
efficiency may be greatly improved by the addition of polymers or
similar chemicals, which increase the viscosity of the injected water.
Polymer injection advantages include a reduction in the amount of water
required for the flood and an increase in the volumetric sweep efficiency
due to a reduced, and thus improved, waterflood mobility ratio
(IOCC, 1974). However, the cost of increasing the viscosity of water
in some reservoirs may outweigh the advantages.
Salt Water Disposal
In most hydrocarbon reservoirs, oil and gas were trapped in the
presence of strongly saline or brine waters. The most environmentally
satisfactory method for the disposal of oil field brines has been to
inject them to a subsurface formation below the deepest known fresh-
water aquifer (IOCC, 1960). The subsurface formation may be the
reservoir from which the brines were originally produced (see water
injection section), or it may be one of the non-productive saline
water-bearing formations normally present in a producing region.
Ideally, the brine is injected into a formation from which the fluid
is unable to migrate vertically. An impermeable zone of shale or
evaporite is desirable above and below the injected formation.
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The life of the disposal system in a confined formation is limited
by the cumulative increase in hydrostatic pressure through compression
of interstitial fluids (gas and brine) and the rock matrix, as brine
is injected into the formation. Reservoir pressure gradually increases
to a point where continued injection is environmentally dangerous
because of possible fracturing of the confining strata and release of
the brine to overlying aquifers. The fracturing pressure of the
injected formation, therefore, defines the limits on the period and
rate of injection if no fluids are withdrawn from the reservoir
(Donaldson, 1972).
John Galley (1968, pp. 119-125) outlined the favorable geologic
setting for salt water disposal wells in four points: (1) porous and
permeable reservoir rocks in which the storage space may be caverns,
intergranular pores, or fracture crevices; (2) impermeable seals to
prevent escape of fluid wastes; (3) adequate understanding of hydrologic
parameters and planning to prevent undesirable migration of fluids;
and (4) compatibility between waste materials, the reservoir rocks,
and their natural fluids.
Natural Gas Storage
In the state of Wyoming, there are currently eight natural gas
storage facilities which inject natural gas into reservoirs known to
have both horizontal and vertical confining properties. Known gas
caps are frequently utilized as the storage reservoirs.
As with the confined subsurface formations into which salt water
is injected for disposal, the limits on the volume and rate of injection
to the storage reservoir are defined by the fracturing pressure limits
of the injected formation.
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POTENTIAL ENVIRONMENTAL IMPACTS
The primary environmental hazard associated with petroleum related
injection operations lies in the contamination of fresh-water aquifers
and surface water systems resulting from the leakage of injected brines,
organics, and hydrocarbons.
The possible causes of leakage and subsequent contamination from
such operations are three-fold: (1) corrosion of injection well casing;
(2) fracturing of reservoir and confining units; and (3) poor cementa-
tion between the well casing and the borehole.
As saline waters containing dissolved oxygen flow through ferrous
metal well casing, electrochemical reactions cause a gradual deteriora-
tion of the casing. This deterioration is known as corrosion and
represents a potentially serious contamination hazard to the fresh-water
aquifers through which casing is run. Injection well operators have
adopted several corrosion inhibiting practices to prevent casing damage,
especially where extremely corrosive carbonate brines are encountered.
Among the practices now utilized are the addition of anti-corrosive
agents such as phosphates and the use of corrosion resistant tubing as a
buffer between the steel casing and the corrosive fluids (Donaldson, 1972).
Hydraulic fracturing may be defined as "the process of creating a
fracture or fracture system in a porous medium by injecting a fluid
under pressure through a wellbore in order to overcome native stresses
and to cause material failure of the porous medium" (Howard and Fast,
1970). Hydraulic fracturing of injected formations is a potential
problem in subsurface injection operations. Under certain reservoir
conditions, operators may wish to fracture the reservoir rock in an
attempt to produce secondary permeability as a means of increasing the
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reservoir's ability to receive and/or produce fluids. However, the
concern with active and proposed high-pressure injection systems,
whether for' disposal or enhanced recovery, is that fracturing may exceed
calculated forecasts, penetrating low-permeability formations confining
the reservoir, and allowing the migration of potentially contaminating
fluids into overlying fresh-water aquifers (Galley, 1968a).
Most investigators agree that the theoretical overburden pressure
of the earth is approximately equal to 1.0 psi per foot of depth (Howard
and Fast, 1970). It is also generally agreed that the injection
pressure required to cause horizontal fracturing in reservoirs, regard-
less of rock type, is approximately 1 psi per foot of depth, to a depth
of 3,000 feet (Evers, personal communication, 1981). At a depth of
8,000 feet, fracturing pressures decrease to between 0.57 and 0.85 psi
per foot of depth (Howard and Fast, 1970). Because of the inherent
heterogeneity of actual rock formations, fracturing is difficult to
control. Where injection pressures approach the pressure/depth values
mentioned above, injection pressures and injection volumes should be
carefully monitored. Sharp decreases in injection pressures and/or
sharp increases in the volume of fluid injected are indicative of
reservoir fracturing.
Increases in injection pressure may result from the restriction
of flow of injected fluids from the wellbore to the reservoir. The two
primary causes of fluid flow restriction are scaling and the "skin
effect." The precipitation of minerals from saline solutions on the
injection well casing and at the well-formation interface is known as
scale deposition. Scaling may cause restricted flow into the injected
formation and necessitate substantial increases in injection pressures
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and costs. Scaling is usually inhibited or prevented by the addition
of phosphates to the brine at the injection-pump manifold (Donaldson,
1972).
The "skin effect" is defined as the loss or gain in permeability
in the vicinity of the borehole. The loss of permeability may result
from drilling and invasion, reactions between clays and minerals in
the injected fluid, chemical reactions between injected and formation
waters, bacterial growth, etc. (Warner and Lehr, 1977). Some of the
extremely high injection pressures at waterflood projects in Wyoming
may be due to undetected "skin effects" at the formation face.
Potential hazards associated with high injection pressures are the
rupturing of well casing and fracturing of reservoir and confining
rock units.
The requirement that waste disposal reservoirs be confined by
thick layers of incompetent rock reduces the danger that the confining
layers will be fractured by excessive injection pressures. Studies
done on the fracturing of oil reservoir rock have shown that "vertical
fractures induced in petroleum reservoirs do not penetrate adjacent
soft formations which have a high Poisson ratio relative to the reser-
voir rock" (C. W. Brown, personal communication, in Galley, 1968a).
In order to adequately seal off the fresh-water aquifers penetrated
by the injection well from the upward migration of brines, organics,
and hydrocarbons, an effective cement sheath must be set between the
well casing and the walls of the borehole. In all injection wells with
all types of casings, cement should be circulated, at least, between
the ground surface and 200 feet below the last fresh-water aquifer
(Barlow, 1972).
11-19
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Cement types range from common portland cement to those contain-
ing admixtures such as pozzolan, salt, acceleration gel, and
retardants (Barlow, 1972) . A mixture of 50-50 pozzolamic cement with
2 percent gel added is ideal for surface casing and the upper part of
the injection casing. Where the injected fluids are corrosive, extended
epoxy resins are used (Barlow, 1972).
A poor cementing job may allow the migration of injected fluids
into void spaces between the outer casing and the borehole, and
result in contamination to aquifers and/or external corrosion of the
well casing. Poor cement jobs may be caused by poor circulation in
the annulus, insufficient hardening time before drilling is resumed
or well is completed, or by the use of a cement not chemically
resistant to the fluids injected or in formations adjacent to the
borehole.
PHYSICAL DESCRIPTIONS OF PETROLEUM RELATED
INJECTION PROJECTS
The following section includes physical descriptions of all
petroleum related injection projects currently operating in Wyoming.
The projects include 265 secondary and tertiary recovery operations, 8
natural gas storage projects, and 90 salt water disposal systems,
numerous fields being the sites of more than one type of injection
project. The narratives are listed in alphabetical order by field
name.
Each description includes, where possible, information on the
field location and production history, geologic setting, hydrologic
parameters, injection history, and injection well data.
11-20
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Cumulative production figures given for each field were compiled
from production reports submitted to the Wyoming Oil and Gas Conserva-
tion Commission through July, 1980, and reported in the Commission's
Wyoming Oil and Gas Statistics publication for the 1979 production
year. Records of production at older fields may be incomplete.
The Petroleum Related Injection Well Inventory tables of Volume II
of this report are divided into separate sections for each type of
injection system (water, gas, steam, gas storage, salt water disposal,
and tertiary injection systems).
Alkali Anticline Field (1,492,944 bbls oil, 311 MCF gas; 1957-79)
Alkali Anticline Unit
The completion of Unit #3 well in 1957 marked the discovery of
Alkali Anticline Field in Township 55 North, Range 95 West, Sections
29, 39, and 32, approximately 6 miles west of the town of Himes in
the northeast portion of the Bighorn Basin.
The Alkali Anticline Unit covers 590 acres of federally owned land
situated on a northwest plunging anticlinal fold. The anticline is
cut on the east side by two nearly north-south dip-slip faults which
have a' combined displacement of 150 to 200 feet. Hydrocarbon accumula-
tion is structurally controlled.
Water injection into the Tensleep Sandstone began in April, 1979,
and is expected to expand into the Phosphoria Formation in the near
future. Water used in the project is obtained from production wells
around Alkali Anticline Field.
Casing pressures were checked with packers above and below the
Phosphoria and Tensleep zones to insure that injected water is confined
to those intervals.
11-21
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By the end of 1979, 66,662 barrels (2,799,804 gallons) of water
had been injected into the Tensleep reservoir.
Casing Record: Injection Well //4, T55N-R95W-29 ca, Alkali Anticline
Field-Unit, Total Depth = 5854 feet.
Casing Size Depth Set Cement Purpose
10-3/4" 264' 150 sacks Surface
7" 5865' 175 sacks Injection
Arch Field (17,672,724 bbls.oil, 78,827,795 MCF gas; 1959-79)
Arch Unit
The Arch oil field was developed within two years after the discovery
of Almond Formation oil in 1959. The field is located approximately 35
miles east of Rock Springs, Wyoming, in Township 19 North, Ranges 98 and
99 West, Sweetwater County. The Arch Unit covers an area of 22,198.73
acres and includes state, federal and privately owned land. The unit
is operated by the Champlin Petroleum Company.
The Almond sand reservoir consists of transgressive shoreline
barrier island sands, most favorably developed at the base of the Upper
Cretaceous Lewis Shale. The sands are clean, well sorted, long, lenticu-
lar bodies that intertongue with impermeable swamp and lagoonal coal-
bearing seams. The average depth of the productive Almond sands is
^4,800 feet. The reservoir covers 5,965 acres with an average pay
thickness of 21 feet. Porosity and permeability average 21 percent and
136 millidarcies, respectively, in the Almond reservoir.
Structurally, Arch Field is located on the east-central flank of
the Rock Springs uplift and near the western terminus of the Wamsutter
arch, which separates the Red Desert Basin to the north from the Washakie
Basin to the south. Entrapment of hydrocarbons is provided by facies
changes from sand to impervious silt, shale, and clay to the west. The
11-22
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northern and southern boundaries to production are structural closures
established by components of north and south dip on either flank of
the Wamsutter arch axis.
A pilot waterflood project was undertaken in 1964, to enhance pro-
duction from the Almond sand reservoir. A standard five-spot pattern
of injection wells was established, and water was supplied by a Fox
Hills well (T18N-R99W-3da). The project has expanded to include 50
injection wells, 45 of which were active as of December, 1979. Water
for the project is now provided by two source wells in the Fox Hills
Sandstone and Lance Formation. Water from the two formations was found
to be of similarly poor quality (high TDS), and compatible with that
of the Almond reservoir.
Between 1964 and 1980, a cumulative total of 28,920,125 barrels
9
(1.2146 x 10 gallons) of water was injected into the Almond sands.
Water Quality Analysis: Water Supply Well W-13-1, T19N-R99W-13 ac,
Arch Field, Arch Unit, Total Depth = 3680
feet, Lance Formation
Temperature: 95°F S0^: <5 mg/1
pH: 7.2 CI: 34,542 mg/1
Na: 22,284 mg/1 CO3: 48 mg/1
Ca: 212 mg/1 HC03: 976 mg/1
Mg: 129 mg/1 CaCO^: 1,060 mg/1
Fe: 3.7 mg/1 TDS: 58,143 mg/1
Ash Creek Field (5,513,696 bbls oil; 1952-79)
Shannon Unit
Ash Creek Field is located approximately 15 miles north-northwest of
Sheridan, Wyoming, and extends north across the Wyoming-Montana border.
The field was discovered in 1952 with the completion of the Elsie Barjry
Well //I in the Shannon sand at a depth of about 4,700 feet.
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The Shannon Unit was created in September, 1964, to increase oil
production efficiency from the Shannon sand. The unit covers 1,526.73
acres of federal, Indian and privately owned fee land.
The producing interval of the Shannon reservoir is a very fine-
to fine-grained sandstone with minor amounts of chert, glauconite,
carbonate and feldspar cemented by clay, secondary quartz and carbonate.
The reservoir covers ^980 acres with an average pay thickness of 17
feet. Average reservoir porosity and permeability are 22 percent and
275 millidarcies, respectively.
Structurally, the field is situated on a large, faulted, anticlinal
nose which plunges basinward from the Bighorn uplift for about 30 miles.
The faulted nose has an approximate closure of 400 feet. Hydrocarbons
migrating updip are trapped on the upthrown south sides of normal faults.
The faults trend northeast at right angles to the axis of the structure.
Dip of the faults is about 45° to the northwest with displacement of
about 250 feet.
Water injection began in 1964, and was expanded to a line drive
pattern waterflood from the north and south sides in 1965. Two water
supply wells in the Parkman sand provide all of the injected water.
Between 1964 and 1968, 7,749,925 barrels (3.255 x 10^ gallons) were
injected into the Shannon reservoir.
The northern portion of the field extends into the Montana Crow
Indian Reservation and contains four injection wells that were not
included in the Wyoming Oil and Gas Commission files.
A two well salt water disposal system, active since 1970, has
injected a cumulative volume of 366,233 barrels (15,381,786 gallons).
The injected formation is the Ash Creek sand at an average depth of
11-24
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4,800 feet. Maximum average injection pressures at the disposal wells
have been 2,000 psi.
Aspen Creek Field (186,989 bbls oil; 1974-79)
A salt water disposal system, utilizing one injection well, was
started in 1979 at Aspen Creek Field under the operation of Santa Fe Energy
Company. The field is located in Township 45 North, Range 101 West, Hot
Springs County. Produced brines are injected into the Triassic Dinwoody
Formation and the Permian Phosphoria Formation. Detailed data on the well
and injection reports were not available at the time of this writing.
Barber Creek Field (3,226,965 bbls oil, 267,966 MCF gas; 1957-79)
Parkman Sand Unit
The Parkman Sand Unit covers an area of 3,197.16 acres of federal,
state and patented lands at Barber Creek Field. The Parkman sand reser-
voir consists of a series of sand members, with the Ferguson Member
believed to represent a near shore, marine sand bar deposit. The
Ferguson sand is the producing member of the Parkman Sandstone.
Accumulation is a result of a sand pinchout to the east and an oil-
water contact to the west. Very little water influx has occurred during
the producing life of the reservoir. The oil-water contact is erratic
and becomes increasingly lower to the northwest. There is hydraulic
communication between sands, evidenced by equal bottom hole pressure
decreases throughout the field.
A major fault with about 60 feet of displacement between the Dead
Horse Creek-North Block Unit and the Barber Creek Unit, provides an
effective barrier between the two units.
11-25
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The northern limits of the Barber Creek Unit are defined by the oil-
water contact downdip and a sand pinchout updip in the south half of
Section 22, Township 50 North, Range 76 West.
Core analysis of the Ferguson sand indicates an average porosity
of 18.3 percent and an average permeability of 76.9 millidarcies.
Primary recovery from the Ferguson Member was predominated by
solution gas drive supplemented by a partial natural water drive. Water
injection began in 1972, with seven injection wells. One injector was
added in 1976, and another in 1977. As of December, 1979, seven of the
nine wells were actively injecting. The cumulative total of water
g
injected to that time was 4,756,403 barrels (1.997 x 10 gallons).
Water for injection is supplied by a nearby well in Fort Union sands.
Casing Record: Injection Well //44X-2, T49N-R76W-2 dec, Barber Creek
Field, Parkman Sand Unit, Total Depth = 6970 feet.
Casing Size Wt. (///ft) Depth Set Hole Size Cement
9-5/8" 32.3 301' 13-3/4" 230 sacks
5-1/2" 14,15.5 6970' 7-7/8" 300 sacks
Basin Field (906,949 bbls oil, 37,102 MCF gas; 1965-79)
Minnelusa Unit
The Minnelusa Unit of Basin Field covers an area of 560 acres of
federal and state owned land. The Minnelusa reservoir is an Upper
Pennsylvanian-Lower Permian unit found at a depth of about 9,650 feet.
It consists of thick intervals of sandstone interbedded with anhydrite
and dolomite. The producing sands are fine- to medium-grained, angular
to round, very slightly dolomitic and moderately friable.
Oil accumulation is confined to stratigraphic traps above the oil-
water contact, which forms the western limit of oil production. A
paleo-erosion channel and shale fill form the northern limit of the
productive sandstone at the unit. The eastern limit is closely aligned
11-26
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with a facies change from porous, oil productive sandstone to tight,
impermeable dolomite. The southern boundary is interpreted as a paleo-
erosion channel discontinuity.
The original mechanism of oil production from the Minnelusa reser-
voir was liquid and rock expansion.
At well number 62-13019 (T47N-R70W-16 da) the average porosity and
horizontal permeability are 14.7 percent and 61.8 millidarcies, respec-
tively, for a 24-foot interval of pay zone sands in the Minnelusa Formation.
Injected water is supplied by a shallow well (2,600 feet) in the
Fox Hills sands and by produced water from the Minnelusa Formation.
Injection began in 1966, and cumulative injection as of December,
1979, was 2,445,393 barrels (1.0271 x 10^ gallons) of water. Both
injection wells are presently shut-in.
Casing Record: Injection Well //l, T47N-R70W-16 caa, Basin Field,
Minnelusa Unit, Total Depth = 9765 feet.
Casing Size Mt. (///ft) Depth Set Hole Size Cement
8-5/8" 24 347' 12-1/4" 275 sacks
5-1/2" 17,15.5 9765' 7-7/8" 250 sacks
Basin Field Northwest (1,099,329 bbls oil, 175 MCF gas; 1965-79)
Piney Ranch Minnelusa Unit
Basin Field Northwest is located in Township 47 North, Range 70
West, Campbell County. Water injection began in the Basin Northwest
Piney Ranch Minnelusa Unit in 1970. By December, 1979, the cumulative
total of injected water was 1,926,881 barrels (8.0929 x 10^ gallons)
with only one of the three injection wells remaining active.
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The water supply for the Piney Ranch Minnelusa Unit waterflood
project was, until 1977, withdrawn from the Fort Union Formation.
In 1977, Union Texas Petroleum began supplementing the fresh water
from the Fort Union with produced water from the Minnelusa Formation
and, later that year, converted to the injection of produced water
only.
Water quality analyses from produced Minnelusa water indicated
very high concentrations of sodium plus potassium (42,202 mg/1) and
chloride (65,000 mg/1). The concentration of calculated total dissolved
solids was 112,613 mg/1.
The average porosity and permeability of the Minnelusa sands at
well //5 are 12.7 percent and 48.4 millidarcies, respectively, at depths
between 9,911 and 9,981 feet.
Casing Record: Injection Well it3, T47N-R70W-5 daa, Basin Field NW,
Piney Ranch Minnelusa Unit, Total Depth = 9812
feet.
Casing Size Wt. (///ft) Depth Set Hole Size Cement
8-5/8" 24 381' 12-1/4" 215 sacks
5-1/2" 17 9808' 7-7/8" 400 sacks
Water Quality Analysis: (Water sample from Minnelusa Formation at
well //2, Basin Field Northwest, Piney Ranch
Minnelusa Unit, T47N-R70W-Section 5 NE^ SE^s,
Depth of Well = 9812 feet, Perforations
9708-9728 feet)
Parameter
Concentration (mg/1)
Total Solids
Concentration (mg/1)
Na + K
42,202
By evaporation
114,588
Ca
866
after ignition
111,136
Mg
541
calculated
112,612
S04
3,228
CI
65,500
HCO4
562
PH
6.9
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Beaver Creek. Field (48,200,841 bbls oil, 471,605,353 MCF gas; 1938-79)
Beaver Creek Field is located in Township 33 North, Range 96
West, Sections 2, 3, 9, 10, 11, 15, and 16 in central Fremont County.
The field was discovered in 1938, when a natural gas well was completed
in the Dakota sand at a depth of 8,230 feet. Subsequent oil discoveries
were made in the Mesaverde (second Cody sand) Formation, Tensleep
Sandstone and Madison Limestone. Unitization of Beaver Creek Field,
which divided it into the Second Cody and Madison units, was approved
in 1937. Injection water is provided by the Meeteetse and Wind River
formations and by production wells in the Madison Limestone and second
Cody sand.
Structurally, Beaver Creek Field is situated en a gently folded
anticline.
Madison Unit
The Madison Unit of Beaver Creek Field covers 1,230 acres of
state and federal land. The Madison reservoir has an average gross
pay thickness of 150 feet and covers 1,260 acres. All of the pay
zones in the Madison Limestone of Beaver Creek Field are at depths
greater than 11,000 feet, making this the deepest water injection
project in the Rocky Mountain region. Average permeability and
porosity for the Madison Limestone are 8 millidarcies and 18 percent,
respectively.
The water injection project in the Madison Unit began in 1959,
utilizing water obtained from several wells completed in the alluvial
gravel of the Wind River Formation at a dpeth of about 100 feet.
The project was later expanded to include six injection wells and 19
11-29
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production wells. Five of the injection wells are dually completed
to permit water injection in the lower zone below a packer and oil
production from the upper zone above the packer.
g
Cumulative injection as of December, 1979, was 1.1277 x 10
9
barrels (4.7363 x 10 gallons) of water.
Second Cody Unit
The area covered by the Second Cody Unit of Beaver Creek Field
includes 760 acres of federally owned land and 770 acres of state
owned land. The second Cody reservoir covers 977 acres with an average
pay zone thickness of 24 feet.
A pilot waterflood of the second Cody (Mesaverde) reservoir
began in 1958, using water from the Meeteetse sand which is found at
depths between 2,122 and 2,210 feet. The pilot project was expanded
to a peripheral waterflood of five injection wells and nine producing
wells in 1959. Water from the Meeteetse Formation was analyzed as
hard and salty, rendering it undesirable for domestic or agricultural
use. The most recent cumulative injection statustics (December, 1979)
indicate that 27,078,181 barrels (1.1373 x 10^ gallons) of water
have been injected since the project began.
Big Muddy Field (52,498,213 bbls oil, 38,762 MCF gas; 1916-79)
The Big Muddy oil field, located near Glenrock, Wyoming (Townships
33 and 34 North, Range 76 West), was initially developed following the
completion of a well in the Shannon sand in 1916. Oil was subsequently
discovered in the Wall Creek sand between 3,147 and 3,217 feet in 1917,
in the Dakota sand in 1922, and in the Lakota sand between 4,353 and
4,364 feet in 1931.
11-30
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In March, 1953, a pilot water injection project began in the
Second Wall Creek Sand Unit. The Second Wall Creek project and
another waterflood project in the Dakota Unit are currently operated
by Continental Oil Company. J. G. Dyer Company now operates water
injection projects in the South Block Wall Creek and Dakota units.
A fifth waterflood project in the East Unit Dakota sand is operated
by Atlantic Richfield Company.
Injection water for all of the projects is obtained from the Wall
Creek, Lakota, and Tensleep sandstones, the Madison Limestone, the
Dakota sand, and two shallow wells near the North Platte River.
The Department of Energy and Continental Oil Company are
currently participating in a reservoir study at Big Muddy Field. The
purpose of the study, initiated in January, 1978, is to demonstrate
the commercial feasibility of a low tension injection process in a
typical Rocky Mountain reservoir with low matrix permeability and
low salinity, and which fractures at bottom hole injection pressures
near, and often less than, hydrostatic pressure.
Wall Creek Unit
The Wall Creek sand reservoir covers an area of 3,560 acres at
Big Muddy Field. The average thickness of the pay zone is 38 feet.
Average porosity and permeability of the reservoir sands are 20 percent
and 20-100 millidarcies, respectively. The initial producing mechanisms
of the reservoir were solution gas drive and a weak natural water
drive. Water encroachment around the edges of the reservoir had been
only one mile between 1933 and 1968.
11-31
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As of 1968, the ratio of water injected to secondary oil
recovered was 8:1. Water used for injection is obtained from two
wells in the Lakota Sandstone and one well in the Sundance Formation.
Produced water from Wall Creek and Dakota sand oil wells is also used.
The cumulative volume of water injected between 1953 and December,
1979, was 65,440,526 barrels (2.7485 x 10^ gallons). Only six
injection wells are currently active in the Wall Creek Unit.
Casing Record: Injection Well #79, T33N-R76W-9 ad, Big Muddy Field,
Wall Creek Unit, Total Depth = 3209 feet.
Casing
Size Depth Set Hole Size Wt. (///ft) Purpose Cement
8-5/8" 264' 12-1/4" 24 Surface 190 sacks
(Class "G")
4-1/2" 3209' 7-7/8" 10.5 Injection 100 sacks
(Class "G")
South Wall Creek Unit
Oil was discovered in the Wall Creek sand of South Big Muddy Field
in 1917. The area of state owned land was unitized in 1963, and water
injection began in 1964. The productive area and average pay thickness
of the Wall Creek reservoir are 507 acres and 20 feet, respectively.
The Wall Creek Sandstone contains two porous sand zones (first
and second Wall Creek sands) which are being injected with fresh water
from the Tensleep Sandstone and Madison Limestone.
The first Wall Creek sand has a gross thickness of 15 feet.
The second Wall Creek sand has a gross thickness of 60 feet and an
average permeability of 70 millidarcies. Four of the six injection
11-32
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wells are currently active and the cumulative volume of water injected
as of December, 1979, was 13,364,166 barrels (5.6129 x 10^ gallons).
Casing Record: Injection Well #3, T33N-R76W-16 aa, South Wall Creek
Unit, Total Depth = 3358 feet.
Casing Size Wt. (///ft) Perforations Purpose
10-3/4" 32.75 - Surface
5-1/2" 14 3272-3275 Injection
3281-3292
3294-3300
Dakota Unit
The Dakota reservoir covers an area of 1,941 acres within
the boundaries of the state, federal and privately owned land of
the Dakota Unit. The average thickness of the Dakota sand pay horizon
is 10 feet.
The producing mechanism of the Dakota reservoir was solution
gas drive until 1958, when a 5-spot pattern pilot waterflood was
initiated on the crest of the Big Muddy structure to enhance produc-
tion. The project was later expanded to a full scale waterflood
with 32 injection wells. Sites for the new wells were selected based
on records of faulting within the reservoir.
As of December, 1979, 19 of the wells were still actively inject-
9
int and 36,289,349 barrels (1.5242 x 10 gallons) of water had
been injected since the project began. Sources for the fresh and
produced water used in the Dakota injection project are the
Sundance Formation, Wall Creek and Lakota sandstones, and the
Dakota sand.
11-33
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Casing Record: Injection Well Stateland 10 //25, T33N-R76W-10 abc,
Big Muddy Field, Dakota Unit, Total Depth = 4579 feet.
Casing
Size Depth Set Hole Size
Wt. (///ft) Purpose Cement
9-5/8" 243' 12-1/4"
36 Surface 200 sacks
(Class "G")
15.5 Injection 460 sacks
light-weight
and 50 sacks
5-1/2"
4579'
8-3/4"
(Class "G")
Dakota South Sand Unit
The Dakota Sand Unit reservoir in South Big Muddy Field
underlies a small dome south of the main Dakota producing area. The
reservoir covers 200 acres and has an average pay horizon thickness of
5 feet.
The unit is operated by J. G. Dyer Company and is owned by private
landowners and the State of Wyoming. The area was unitized in 1961,
and water injection into the Dakota sand began a short time later.
The waterflood project has one active injection well and two wells
that have been temporarily shut-in. Between 1961 and 1980, 1,458,137
barrels (6.1242 x 10^ gallons) of water were injected into the Dakota
reservoir.
Casing Record: Injection Well State //0-20200 2A, T33N-R76W-21 be,
South Big Muddy Field, Dakota Unit, Total Depth =
4845 feet.
Casing Size Wt. (///ft) Amount Guide Make Purpose
8-5/8"
4-1/2"
9.5
32
113'
4845'
J-55
R-2
Surface
Inj ection
11-34
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East Unit
The East Unit of Big Muddy Field is located in Sections 1, 2 and
3 of Township 33 North, Range 76 West and Sections 34 and 35 of Town-
ship 34 North, Range 76 West. The unit is operated by Atlantic Rich-
field Company.
Water injection began in 1961, following unitization of 520 acres
of the Dakota reservoir in the northeast corner of Big Muddy Field.
The average thickness of the pay zone is 11 feet.
As of December, 1979, 12,550,348 barrels (5.2711 x 10^ gallons)
of water had been injected through 12 wells, only two of which are
still active. In 1968, the amount of produced oil attributed to the
waterflood project was ^630,000 barrels.
Big Piney Field (1,698,624 bbls oil, 37,332,843 MCF gas; 1964-79)
In the middle of winter, 1938, the discovery well at Big Piney
Field "blew in" with natural gas from the Almy gas sands which are
found at a depth of approximately 1,000 feet. Accompanying the gas was
water from sands overlying the gas zone. In the subzero temperatures
at the surface the water draped the drilling derrick with sheets of
ice. The well had been standing idle for three weeks at a total depth
of 1,695 feet when the blowout occurred.
Oil was initially produced at Big Piney from sands in the Wasatch
Formation in 1955. In July, 1957, oil was discovered in the "P" sand
reservoir of the Almy sand. Other oil discoveries were made in
lenticular sands of the Mesaverde and Wasatch formations. The Big Piney
anticline is located in Townships 28 and 29 North, Ranges 112 and 113
West, Sublette County. Big Piney Field includes the Mesaverde, "P"
Sand and Long Island "SC" units.
11-35
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The Tip Top Hogsback salt water disposal system at Big Piney
Field started in 1965 and was expanded to a two well system in 1971.
Between 1965 and December, 1979, 19,903,881 barrels (8.3596 x 10^
gallons) of produced brine were injected into the Fort Union Formation
at an average pressure of 1,300 psi. Both wells are actively injecting
at the present time.
Mesaverde Unit
The Big Piney Mesaverde reservoir lies near the southeast end of
the Big Piney anticline on the west edge of the Green River Basin. The
productive interval of the reservoir includes a Tertiary basal conglom-
erate formation and the upper and lower portions of the Cretaceous
Mesaverde Formation. The conglomerate lies unconformably above the
upper Mesaverde and the upper and lower Mesaverde are separated by a
shale bed of variable thickness. The Tertiary conglomerate is a quartz
pebble conglomerate with a sand and clay matrix. Average porosity and
permeability of the conglomerate are 11.9 percent and 58.6 millidarcies,
respectively. However, the core used for the analysis was incomplete
and considered nonrepresentative of the conglomerate pay zone.
The Mesaverde sands are fine- to medium-grained siliceous sand-
stones with minor amounts of argillaceous and carbonaceous material.
The upper sand has a matrix porosity of 18 percent and horizontal and
vertical permeabilities of 7.8 and 8.2 millidarcies, respectively.
The lower Mesaverde zone has a porosity of 14.6 percent and horizontal
and vertical permeabilities of 4.6 and 4.3 millidarcies, respectively.
The Mesaverde reservoir covers a broad area of locally unrestricted
and unfaulted rock. Production limits are defined by an oil-water
11-36
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contact to the east and water encroachment to the south. The western
production boundary is a structural high which caused entrapment of
hydrocarbons by either a northwest-southeast trending high relief
fold, a major fault of similar orientation or a reservoir pinchout
toward the axis of the structure.
The Mesaverde Unit consists of 2,949 acres of state and federal
land and is currently operated by Gulf Oil Company. Secondary recovery
of oil by water injection began in 1968, and utilizes water obtained
from oil production wells in the Mesaverde and from water supply wells
completed in the Almy sand at a depth of approximately 1,000 feet.
It was estimated that 6.8 x 10^ barrels of additional oil would be
recovered as a result of the waterflood project.
As of December, 1979, seven of the project's eight injection wells
were actively operating. Total volume of water injected to that point
was 28,505,697 barrels (1.1972 x 10^ gallons).
Casing Record: Injection Well //15—7, T29N-R113W-36 bbd, Big Piney
Field, Mesaverde Unit, Total Depth = 3600 feet.
Casing Size Wt. (///ft) Amount Perforations Purpose
8-5/8" 24 254' - Surface
5-1/2" 14 3448' 3320-3370' Injection
"P" Sand Unit
In July, 1957, oil was discovered in the "P" sand reservoir of the
Almy sand in Big Piney Field. The "P" sand reservoir covers an area
of 878 acres with a maximum thickness of 28 feet and an average pay
thickness of 16.2 feet. The "P" sand is a lenticular Paleocene sand
which varies in thickness from 0 to 100 feet and has a dip of 3 degrees
to the east. The average depth to the top of the sand is 2,675 feet.
11-37
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The reservoir consists of a primary gas cap partially overlying an oil
zone which is underlain by water.
Hydrocarbon accumulation in the "P" sand is a result of strati-
graphic entrapment associated with ideal anticlinal structural conditions.
The sand pinches out to the north and west, has an oil-water contact to
the east, and meets a barrier fault to the south. Performance data
indicate that the reservoir initially produced by a solution gas drive,
slightly augmented by gas cap expansion.
The "P" Sand Unit was unitized in November, 1962, by Pan American
Petroleum Corporation and covers 2,212.57 acres of federal and state
land. Waterflooding began in August, 1963, with water obtained from a
shallow well in the Green River Formation. Water was injected into
three wells near the gas-oil contact to prevent oil movement into the
"dry" gas reservoir. Once reservoir pressure was increased, production
through the gas wells was resumed. Gas injection into the gas cap
through one well began in December, 1962. As of December, 1979,
16,812,498 barrels (7.0612 x 10^ gallons) of water and 6,373,254 MCF of
natural gas had been injected into the "P" sand reservoir. Five wells
were actively injecting at that time.
Casing Record: Injection,Well #9, T29N-R113W-36 aa(ac), Big Piney
Field, "P" Sand Unit, Total Depth = 3670 feet.
Casing Size Wt. (///ft) Amount Perforations Purpose
8-5/8" 24 256' Surface
5-1/2" 14 3347' 2690-3288' Injection
Long Island Unit
The Long Island "SC" Sand Unit of Big Piney Field is located in
Sections 18, 19, 20, and 29 of Township 30 North, Range 112 West,
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Sublette County. The unit covers 680 acres of federally owned
land.
The "SC" sand reservoir is part of the Paleocene Almy sand
found at a depth of about 1,700 feet in the Big Piney area. The
Almy sand is a multicolored shale and siltstone with a few thick
sandstones interbedded. The sandstones are gray-white to salt and
pepper, very fine- to coarse-grained and well consolidated.
Structure in the area is a northeast dipping monocline of one
to two degrees inclination with only minor variations. The production
boundaries are defined by an updip pinchout of the "SC" sand on the
west and an oil-water contact on the east.
Waterflooding of the "SC" reservoir was initiated in 1969, using
water from outside the field with a polymer added. As of December,
1979, there were six active injection wells in this unit operated by
Belco Petroleum Corporation. Cumulative injection data were available
for 1976 only. During 1976, 716,548 barrels (30,095,016 gallons) of
water were injected into the "SC" reservoir. Casing records for
injection wells were unavailable at the time of this writing.
Billy Creek Field (6,471,217 MCF gas in storage; 1923-79)
Billy Creek Field, located in Township 48 North, Range 82 West,
Johnson County, has been the site of a gas storage project operated
by Montana-Dakota Utilities since 1941. The Frontier Formation is the
reservoir being used to store the 6,471,217 MCF of natural gas. Three
injection wells have been utilized during the project. Two of the wells
remain on active status according to statistics compiled in January,
1980, by the Oil and Gas Commission.
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Birch Creek Field (87,488,060 bbls oil, 111,998,816 MCF gas; 1957-79)
Almy (Birch Creek) Unit
The Almy Unit of Birch Creek Field is located in the east half of
Township 27 North, Range 113 West, Sublette County. The unit was
approved in January, 1957, and is still operated by Chevron Oil Company.
Gas was discovered in the Bear River Formation in April, 1957, and
subsequent oil discoveries were made in the Almy (Birch Creek) and
Mesaverde reservoirs.
The Almy sand reservoir covers an area of 600 acres and has an
average pay zone thickness of 31 feet. The original producing energy
in the reservoir was provided by gas expansion.
In December, 1963, water injection began through a line of three
wells located between the Almy and Mesaverde units. The purpose of
these injectors was to prevent the migration of oil between the two
reservoirs. Injection water for the Almy reservoir waterflood is
obtained from wells in the Wasatch Formation and from production wells
in the Almy sand.
As of December, 1979, 25,229,777 barrels (1.0597 x 10^ gallons)
of water had been injected through 4 injection wells since the water-
flood project began. Only one of the wells is currently active.
A salt water disposal system was started in 1977, to inject water
from Birch Creek Field producing wells into the Almy "D-2" sand.
The average injection pressure at the single disposal well is 1,300
psi. As of January, 1979, 63,768 barrels (2,678,256 gallons) of brine
had been disposed of through well //46DW.
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Mesaverde Unit
The Mesaverde Unit of Birch Creek Field is located just northwest
of the Almy Unit in Sections 15 and 22 of Township 27 North, Range 113
West. The unit area includes 540 acres of federally owned land.
The Mesaverde reservoir is a gray to light gray, salt and pepper,
calcareous, silty, slightly argillaceous, fine- to very fine-grained,
generally well sorted, subangular to subrounded, moderately friable
sandstone. Porosity averages 18 percent in the Mesaverde Formation and
the average permeability is 10 millidarcies. By the end of December,
1979, both injection wells completed in the Mesaverde reservoir were
temporarily shut-in. Cumulative injection through those wells has
Q
totaled 3,002,258 barrels (1.2609 x 10 gallons) of water. Casing
records for the two injection wells were unavailable at the time of
this writing.
South Bishop Ranch Field (1,607,901 bbls oil, 20,717 MCF gas; 1968-79)
South Bishop Ranch Minnelusa Unit
The South Bishop Ranch Unit covers an area of 640 acres of federally
and state owned land in the southeast corner of Township 48 North,
Range 70 West, Campbell County. Oil production began in 1964, with the
primary mechanism of production resulting from the expansion of compressed
reservoir fluids.
The Minnelusa A reservoir is found at a depth of approximately
9,250 feet at the South Bishop Ranch Unit. The average porosity and
permeability of the reservoir sands are 15.1 percent and 100 millidarcies,
respectively.
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The injection of water, produced from the Minnelusa Formation, was
initiated in 1970 through two wells. In 1973, a third injector was
added. Because this Minnelusa waterflood was atypical of the majority
of Minnelusa waterflood projects in the Powder River Basin, the State
Oil and Gas Commissioner of Wyoming closely monitored injection and
production records during 1976 and 1977. There was some doubt as to
whether or not the interval into which water was being injected was
hydraulically connected with any of the producing wells in the South
Bishop Ranch Unit. The Commissioner pointed to "the fact that three
years of injection has not yielded a conclusive production response at
wells within the unit. . . . We are concerned with the injection of
approximately one million barrels of water into an aquifer of unknown
extent, the result of which is also unknown. . . . response to water
injection (in several Minnelusa reservoirs, all located in the Powder
River Basin of Wyoming) is, without exception, immediate and typically
dramatic" (Oil and Gas Commission files). Another one million barrels
have been injected since 1977, and no "dramatic" responses in production
wells have yet occurred. Only one of the three injecting wells
remained active as of December, 1978. It is located on the approximate
oil-water contact of the reservoir, T48N-R70W-35 aa. The Commission
has not pursued the investigation.
Casing Record: Injection Well //l, T48N-R70W-35 aab, South Bishop Ranch
Field, Minnelusa Unit, Total Depth = 9600 feet.
Casing Size Wt. (///ft) Depth Set Hole Size Cement
8-5/8" 24 307 12-1/4" 240 sacks
5-1/2" 15.5, 17 9600 7-7/8" 300 sacks
4-1/2" 13.5, 11.6 9600 7-7/8" 300 sacks
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Bison Basin Field (1,958,698 bbls oil, 554,495 MCF gas; 1929-79)
Frontier Unit
Bison Basin Field is situated on a faulted anticline in Township
27 North, Range 95 West, Fremont County. The oil field was discovered
in 1923, when a well completed in the Cretaceous Frontier Formation
produced economic yields of natural gas. Soon thereafter, additional
wells struck oil in the Frontier Formation.
The Bison Basin Frontier Unit was approved in 1939, with Elmer
J. Boseke, Jr. as operator. He was succeeded in May, 1956, by Gulf
Oil Corporation.
The Frontier reservoir covers an area of 270 acres. The average
thickness of the pay zone is 75 feet. The Frontier reservoir is a
light gray, glauconitic conglomerate in the upper oil-bearing zones
with interbedded dark gray to black, silty to arenaceous shale and
minor bentonite. Average porosity and permeability of the Frontier
are 18 percent and 150 millidarcies, respectively.
Secondary recovery of oil by water injection began in August,
1971, when three wells were completed in a line drive pattern at the
northeast corner of the field. Only one of seven injection wells was
active as of December, 1979. Up to that point, 7,432,153 barrels
g
(3.1215 x 10 gallons) of water had been injected into the Frontier
Formation.
A plan is currently being formulated to convert the pilot water
flood in Bison Basin Field to a field-wide alkaline waterflood using
dilute (0.2 percent NaOH) caustic soda.
11-43
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Casing Record: Injection Well #16, T27N-R95W-20 bab, Bison Basin Field,
Frontier Unit, Total Depth = 1400 feet.
Casing Size Wt. (///ft) Depth Set Amount
8-5/8" 26 43' 35 sacks
5-1/2" 15.5 1395' 75 sacks
2-3/8" - 1343'
(tubing)
Black Mountain Field (12,110,369 bbls oil, 113,543 MCF gas; 1924-79)
A single well salt water disposal system was put into operation at
Black Mountain Field in 1979. The field is located in Townships 42 and
43 North, Range 91 West, Hot Springs County, and has been producing oil
and gas since its discovery in 1924. Texaco, Inc. operates the disposal
well, which injects produced brine into the Madison Limestone. Details
on the new system were unavailable for this writing.
Blue Gap II Field (29,495 bbls oil, 2,832,341 MCF gas; 1974-79)
CIG Exploration Company began operating a single well salt water
disposal system at Blue Gap II Field in 1978. The field is located
in Township 15 North, Range 92 West, Carbon County. The Fort Union
Formation is the recipient formation for the injected brines.
Bower Field (216,925 bbls oil, 152,874 MCF gas; 1973-79)
Teckla Unit
In 1974, Inexco Oil Company began operation of a single well salt
water disposal system in the Teckla Unit of Bower Field. Brines pro-
duced with oil from production wells at Bower Field are injected to the
Lewis Shale at a depth of 6,350 feet through the disposal well located
in Section 20, Township 37 North, Range 69 West, Converse County.
Injection data were available only for February, 1980. During that
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month, 3,770 barrels (158,340 gallons) of salt water were injected to
the Lewis Shale at average injection pressures ranging between 595
and 6,350 psi.
Brady Field (24,695,445 bbls oil, 88,259,278 MCF gas; 1973-79)
Weber Unit
The Weber Unit of Brady Field is the current site of an extensive,
deep formation, natural gas storage injection project. The unit area
covers portions of Townships 16 and 17 North, Range 101 West, Sweetwater
County. The storage project began in 1975, and has expanded to a six
well system. The formation being utilized for storage is the Pennsyl-
vanian Weber Sandstone which occurs between 14,150 and 14,275 feet below
the surface in the Brady Field area. As of March, 1980, 58,418,028
MCF of natural gas had been injected to the Weber Sandstone for temporary
storage. Average injection pressures have ranged from 0 to 4,888 psi
over the duration of the project.
Mesaverde Unit
Champlin Petroleum Company also operates a one well salt water
disposal system at Brady Field in the Mesaverde Unit. The project began
in 1977, with the injection of produced brine to the lower Rock Springs
and upper Ericson formations of the Mesaverde Group. A cumulative
g
volume of 2,622,760 barrels (1.1016 x 10 gallons) of salt water had
been injected through December, 1979. Average pressures of injection
have ranged from 100 to 800 psi during the project's lifetime. The
range of TDS concentrations of the injected brine is from 92,786 to
114,815 mg/1.
11-45
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Casing Record: Salt Water Disposal Well it 1, T16N-R101W-11, Brady Field,
Mesaverde Unit.
Casing Size Wt. (///ft) Amount Purpose
13-3/8" 48 400' Surface
7" 23 5450' Long String
3-1/2" Injection Tubing
Breaks Field (392,172 bbls oil; 1976-79)
Hembt-Federal Unit
A single well salt water disposal system was put in operation in
1977, at the Hembt-Federal Minnelusa Unit of Breaks Field. The field
is located in east-central Campbell County, Township 52 North, Range 69
West. Produced Minnelusa brines are injected to the Minnelusa Formation
at a depth of 7,426 feet and an average injection pressure of 1,000 psi.
As of December, 1979, injection reports from the operator, Smith-Fancher
Company, indicate that a cumulative volume of 478,977 barrels (2.0117
x 10^ gallons) of brine have been injected.
Bridger Lake Unit (No Production Record)
Bridger Lake Unit is located in Township 12 North, Range 114 West,
Uinta County, and is the present site of a single well salt water dis-
posal system that was put into operation in 1969. Salt water produced
with oil at Bridger Lake is separated from the oil and injected into the
Fort Union Formation at a depth of 8,336 feet. As of December, 1979,
cumulative injection of produced brine to the Fort Union was 1,418,930
barrels (5.9595 x 10^ gallons). Formation water within the Fort Union
has a NaCl concentration of 750 mg/1 according to one reported analysis.
NaCl concentrations in the injected brines have been reported as high as
6,000-8,000 mg/1. There have been no reported problems with the injec-
tion system.
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Brooks Ranch Field (2,523,905 bbls oil; 1957-79)
Brooks Ranch Unit
The Brooks Ranch Unit is located approximately 12 miles east of
Casper, at the west end of the Big Muddy anticline on 4,280 acres of
federal, state, and privately owned land. The field produces from a
stratigraphic trap on the nose of an asymmetrical anticline, with the
steep flank dipping north at 12°, and the more gentle south flank
dipping at about 5° into a doubly plunging syncline. The syncline
separates the Big Muddy structure from the northeastward plunge of the
Hat Six anticline.
The discovery well at Brooks Ranch Field was completed in 1957,
in the second Frontier sand. The second Frontier sand has an average
porosity of 16.9 percent, average permeability of 3.1 millidarcies,
average pay zone thickness of 7.7 feet, and thickens toward the north-
west. The initial mechanism of production from the second Frontier
was solution gas drive.
Water injection in the Brooks Ranch Unit began in 1967. Twenty-
seven wells, of which 21 were actively injecting, were shut-in in
February, 1972, due to the lack of pressure stimulation after the
g
injection of 5,894,828 barrels (2.4758 x 10 gallons) of water supplied
by a well in the Madison Limestone. Reservoir calculations, based on
100 percent effective injection, indicated, theoretically, that injec-
tion had surpassed 140 percent fill-up of the free gas saturation phase
which existed prior to secondary recovery operations.
Lack of reservoir pressure stimulation, coupled with the fact that
many of the injection wells still show surface pressures of over 1,500
psi after 23 months of shut-in status, led Terra Resources, Inc. to
11-47
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conclude that re-instatement of full scale injection operations could
not be economically justified.
At present (December, 1979), there is one active injection well
in the Brooks Ranch Unit. Cumulative injection into that well, between
1978 and the end of 1979, was 27,610 barrels (1,159,620 gallons) of
produced Frontier Formation water. Casing records for the well were
unavailable at the time of this writing.
Buck Creek Field (844,958 bbls oil, 794,410 MCF gas; 1952-79)
Converse Unit
The most recent salt water disposal system to come on line in
Wyoming is the single well operation at Buck Creek Field, Township 36
North, Range 63 West, Niobrara County. Produced brine from Buck Creek
Field is injected to the Converse sand of the upper Minnelusa Forma-
tion at a depth of 5,653 feet. Average injection pressures have ranged
between 25 and 50 psi. The initial injection was made during the early
part of 1980, and cumulative injection to June, 1980, was 15,666 barrels
(657,972 gallons).
Bunker Hill Field (3,448,744 MCF gas; 1937-79)
Bunker Hill Field is located in Townships 26 and 27 North, Range
89 West, Carbon County. The field is the present site of a two well
natural gas storage project that was started in 1972, under the operation
of Northern Gas Company. As of 1977, 3,448,744 MCF of natural gas were
stored in the Shannon Sandstone at a depth of 1,471 feet.
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Burke Ranch Field (6,225,241 bbls oil, 195,937 MCF gas; 1953-79)
Dakota Unit
Oil was discovered at Burke Ranch Field in 1953, upon completion
of a well in the Cretaceous Dakota sand. The Dakota Unit, approved in
1951, covers an area of 1,281.57 acres, of which 923.66 acres are
federally owned and the remaining 357.91 are privately owned fee lands.
The Burke Ranch Field Dakota Unit is situated on the east flank of the
Casper arch, a broad uplifted area separating the Wind River Basin from
the Powder River Basin, in the east-central part of Natrona County,
24 miles north of Casper.
The Dakota reservoir encompasses 1,282 acres and has an average
pay zone thickness of 12 feet. The average porosity and permeability
of the Dakota at well #5 (T37N-R78W-7 cdb) are 14 percent and 29
millidarcies, respectively. The Dakota sand is a fine- to medium-
grained white sand.
Seismic work established approximately 150 feet of structural
closure on the top of the Dakota. However, production from the Dakota
reservoir is believed to be stratigraphically controlled by the lenti-
cular nature of the effective porosity within the reservoir. The
producing energy within the reservoir was originally provided by a
combination of fluid expansion and solution gas drive.
In July, 1962, a pilot water injection project was initiated.
The pilot project was later expanded to a full scale peripheral water-
flood. Injection water is provided by water supply wells completed
in the Parkman Sandstone. As of December, 1979, cumulative injection
totaled 19,827,180 barrels (8.3274 x 10^ gallons) of water. Only four
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of 11 injection wells were active at that time. Casing records were
unavailable at the time of this writing.
Byron Field (102,519,099 bbls oil, 12,146,011 MCF gas; 1918-79)
Pre-Tensleep Unit
The Byron oil field is located just west of Lovell, in Township 56
North, Range 97 West, Big Horn County. The field was discovered in
1918, but it wasn't until 1929 that oil was encountered in the Sundance
Formation and 1930 when oil was found in the Embar Formation and
Tensleep Sandstone.
Structurally, Byron Field is situated on a northwest-southeast
trending, faulted anticline which dips steeply to the northeast.
The Pre-Tensleep Unit covers 3,710.2 acres of federal, state, and
privately owned fee land. Waterflooding of the Amsden Formation, to
enhance oil production, was started in 1970, utilizing produced water
from Amsden oil wells. As of December, 1979, the only injection well
in the Pre-Tensleep Unit was temporarily shut-in. Cumulative injection
data and casing records on the well were unavailable at the time of
this writing.
Embar-Tensleep Unit
The Embar-Tensleep Unit water injection project began in 1973,
using produced water from nearby Tensleep oil wells. The Embar-Tensleep
Unit is located in the east-central portion of Township 56 North, Range
97 West, Big Horn County.
Sixteen of the 21 injection wells were on active status as of
December, 1979. Injection data and casing records for the wells were
unavailable at the time of this writing.
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C-H Field (4,079,934 bbls oil, 22,584 MCF gas; 1967-79)
Minnelusa Unit
Oil was discovered in the Minnelusa Formation of C-H Field in
1967. In this area northeast of Gillette, Wyoming, the Minnelusa is a
sandy, dark red shale which grades vertically downward into a very
dolomitic, medium-grained, buff sandstone and then into a white, dense,
crystalline dolomite. The average porosity and permeability of the
Minnelusa are 18.3 percent and 230 millidarcies, respectively. Original
reservoir pressure was 3,300 psig. One year later, the pressure had
decreased to 851 psig.
The Minnelusa reservoir includes 667 acres. The reservoir boundaries
are defined by an oil-water contact on the western side of the produc-
tive area. The eastern and northern sides of the field are defined by
a pinchout of the porous and permeable sand determined by dry holes
in or very near the barrier.
When well W-2 (T52N-R70W-2) was plugged and abandoned in 1967,
the following plugging schedule was employed in order to shut off all
oil and water producing intervals:
Casing Record: Injection Well #3, T52N-R70W-2 cad, C-H Field-Minnelusa
Depth (ft)
Cement (sacks)
0-20
140-175
3000-3075
6185-6305
7580-7670
10
25
25
40
30
Unit, Total Depth = 7684 feet.
Casing Size
8-5/8"
5-1/2"
Wt. (///ft)
24
15,5, 17, 20
Depth Set
169 '
7680'
Hole Size Cement
12-1/4" 130 sacks
7-7/8" 400 sacks
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Camp Creek Field (3,649,088 bbls oil; 1962-79)
Dart Unit
Salt water disposal at the Dart Unit of Camp Creek Field started
in 1975. Produced brine was injected into the Minnelusa Formation
at a depth of 7,415 feet through a well located in Section 1, Township
54 North, Range 71 West, Campbell County. By 1979, the disposal well
was shut-in, after a cumulative volume of 6,782 barrels (284,844 gallons)
of salt water had been injected.
Carson Field (998,782 bbls oil, 1,954,388 MCF gas; 1969-79)
K //2 Unit
In 1972, Texaco, Inc. began operating a salt water disposal well
in the K //2 Unit of Carson Field, Township 54 North, Range 73 West,
Campbell County. The well is perforated in the Muddy Sandstone at a
depth of 7,761 feet. By 1979, the well had been shut-in. Reported
cumulative injection to the time of shut-in was 37,492 barrels
(1,574,664 gallons).
Casing Record: Salt Water Disposal Well //2, T54N-R73W-18 dc, Carson
Field, K #2 Unit, Total Depth = 7904 feet.
Casing Size Wt. (#/ft) Amount Cement
10-3/4" 40.5 582' 425 sacks
7" 23,26 7895' 250 sacks
3-1/2"
South Casper Creek Field (10,147,899 bbls oil; 1919-79)
Tensleep Unit
The South Casper Creek Field Tensleep Unit is the site of one of
Wyoming's two hydrothermal injection projects. This secondary oil
11-52
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recovery method has been in operation since 1974, at South Casper Creek,
and involves eight steam injection wells, only two of which were still
active as of the end of 1979.
The Tensleep Unit is located in Sections 2 and 3, Township 33
North, Range 83 West, Natrona County. Steam is injected into the
Pennsylvanian Tensleep Sandstone between 2,350 and 2,550 feet. Average
porosity and permeability of the Tensleep in this area are 16.7 percent
and 281 millidarcies. As of December, 1979, cumulative steam injected
since the project started was 198,584 MCF.
Cellars Ranch Field (4,947,193 bbls oil, 2,908 MCF gas; 1960-79)
Crow Mountain Unit
The Crow Mountain Unit of Cellars Ranch Field has, since 1977,
been the site of a single well salt water disposal system. The well
is located in Section 24, Township 44 North, Range 82 West, Johnson
County, and is completed in the Crow Mountain Formation at a depth of
5,684 feet. Cumulative injection through December, 1979, was 1,955,501
barrels (8.2131 x 10^ gallons) of produced brine. The average injection
pressure has been consistently around 900 psi.
Chan Field (3,386,003 bbls oil, 4,284,884 MCF gas; 1968-79)
Muddy Unit
The Muddy Unit of Chan Field is located in Sections 1, 2, and 11
of Township 56 North, Range 73 West, Campbell County. Oil was
discovered in the Muddy Sandstone in 1969.
Production at Chan Field is from a lenticular sandstone reservoir
developed at the base of the Dynneson Member of the Cretaceous Muddy
Sandstone. The reservoir is composed of shingle-like shoreline bars
11-53
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which show hydraulic communication with one another. Average porosity
and permeability of the Muddy reservoir are 14.2 percent and 44
millidarcies, respectively. The primary producing mechanism in the
reservoir was solution gas drive and the original bottom hole pressure
was 2,017 psi.
Water injection began in 1975, using 85 percent fresh water from
the Fox Hills Sandstone and Lance Formation which are found at depths
between 2,000 and 5,000 feet in the Chan Field area. The rest of the
water used in the injection project is produced water from the Muddy
Sandstone oil production wells. The Fox Hills water supply well is
located in the northwest quarter of the southeast quarter of Section 2,
Township 56 North, Range 73 West. Four of six injection wells were
active as of December, 1979. Cumulative injection to that date was
Q
3,946,830 barrels (1.6577 x 10 gallons) of water.
Casing Record: Injection Well #411, T56N-R73W-11 bb, Chan Field,
Muddy Unit, Total Depth = 7095 feet.
Casing Size Wt. (#/ft) Hole Size Depth Set Cement
8-5/8" 24 12-1/4" 200.97' 175 sacks
4-1/2" 11,10.5 7-7/8" 7095' 18 sacks
Circle Ridge Field (20,888,245 bbls oil; 1923-79)
Shoshone 63 Unit
Circle Ridge Field is located on the Wind River Indian Reservation
in Township 6 North, Range 2 West, Section 6. Field operations at the
Shoshone 63 Unit began in 1923. The oil producing formation is the
Darwin Sandstone of Mississippian age. The Darwin reservoir has an
average porosity of 18 percent and an average permeability of 41.7
millidarcies.
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Water injection into the Darwin Sandstone was started in 1977,
through three wells using produced water from the Amsden Formation.
Six injection wells were added in 1979 and all nine wells were
actively injecting at the end of the year. The cumulative volume of
water injected (December, 1979) was 356,336 barrels (14,966,112
gallons). Information on injection well casing was unavailable at the
time of this writing.
Clareton Field (1,309,701 bbls oil, 127,178 MCF gas; 1950-79)
Clareton oil field is located on the east flank of the Powder
River Basin in Townships 42 and 43 North, Ranges 65 and 66 West, Weston
County. Oil production in all of the Clareton Field units is from the
Lower Cretaceous Newcastle Sandstone. The Newcastle Sandstone in this
area is a succession of thin sandstone, siltstone and shale beds. The
oil sand of the Newcastle is fine- to medium-grained with shale inter-
calations and carbonaceous material. The predominant primary energy
source for the Newcastle reservoir is the expansion of solution gas.
There are four units within the Clareton Field that are using
water injection to enhance oil recovery from the Newcastle reservoir.
They are the Clareton-Thorson Unit, the Cotton Unit, the Black Thunder
Unit, and the Newcastle Unit.
Clareton-Thorson Unit
The Clareton-Thorson Unit of Clareton Field includes 2,062.74
acres of federal and privately owned fee land. The unit was approved
on November 24, 1967. Water injection into the Newcastle Sandstone
started in 1966, and was expanded to a five well project one year later.
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Average porosity and permeability of the Newcastle reservoir at
injection well #28 (T43N-R65W-14 bcc) are 9.3 percent and 5 milli-
darcies, respectively.
All five injection wells in the Clareton-Thorson Unit were
temporarily shut-in as of December, 1979. Cumulative injection to
that point was 2,978,637 barrels (1.251 x 10^ gallons).
Casing Record: Injection Well #28, T43N-R65W-14 bcc, Clareton Field,
Clareton-Thorson Unit, Total Depth = 6077 feet.
Casing Size Wt. (#/ft) Hole Size Depth Set Cement
8-5/8" 24 12-1/4" 167' 100 sacks
2-7/8" ? 7-7/8" 6065' 175 sacks
Cotton Unit
The Cotton Unit of Clareton Field is located in Sections 16 and
17 of Township 43 North, Range 65 West, Weston County. Water injection
into the Newcastle Sandstone began in 1971 through three wells. Fresh
water was supplied by a water well in the Fox Hills Sandstone (T43N-
R65W-16 cb).
By December, 1979, two of the injection wells had been temporarily
shut-in and the other well was permanently shut-in. Cumulative injec-
tion to that point was 424,413 barrels (17,825,346 gallons) of water.
Black Thunder Unit
The Black Thunder Unit of Clareton Field is located in the east-
central part of Township 42 North, Range 66 West, Weston County.
Water injection into the Newcastle Sandstone started in 1960, through
one well. The water supply well for the waterflood project was completed
in the Fox Hills Sandstone. The pilot flood was expanded to 9 injection
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wells in 1962, and eventually grew to 17 wells by 1967. As of December,
1979, all 17 injectors were temporarily shut-in and 8,590,160 barrels
g
(3.6079 x 10 gallons) of water had been injected since 1960. Casing
data on the injection wells were unavailable for this writing.
Newcastle Unit
The Newcastle Unit of Clareton Field covers 9,977 acres of
federal, state, and privately owned fee land in southwestern Weston
County.
Water injection into the Newcastle reservoir was initiated in
1960, and expanded to a full scale project with 46 injection wells by
1968. Injection water was supplied by wells completed in the Upper
Cretaceous Fox Hills Sandstone. As of December, 1979, 29,312,628
9
barrels (1.2311 x 10 gallons) of water had been injected into the
Newcastle reservoir and all 46 of the injection wells had been
permanently shut-in.
A two well salt water disposal system started in 1975, at the
Clareton Field Newcastle Unit. Both wells are located in Township 42
North, Range 65 West and inject water from Clareton Field production
wells into the Newcastle Sandstone. As of December, 1979, 274,602
barrels (11,533,284 gallons) of brine had been injected. The maximum
average injection pressure during the entire project has been 3,200 psi.
Casing Record: Injection Well #1149, T43N-R65W-29 bbd, Clareton Field,
Newcastle Unit, Total Depth = 6450 feet.
Casing Size Wt. (///ft) Depth Set Cement
10-3/4" 32.75 157' 100 sacks
5-1/2" 14 6447' 75 sacks
11-57
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Cody Field (723,976 bbls oil; 1976-79)
Horner Unit
Disposal of produced salt water brines into the Morrison Formation
began in 1978, at Cody Field in Township 53 North, Range 101 West,
Park County. One well, in tract 39, has been the only injector in the
system and through July, 1979, had disposed of a cumulative volume of
164,773 barrels (6,920,466 gallons) of salt water. Average injection
pressures have been around 1,500 psi. Injected water is from production
wells in the Tensleep Sandstone and Phosphoria Formation.
Cole Creek Field (16,967,267 bbls oil, 501,232 MCF gas; 1938-79)
A unit agreement for the development and operation of the Cole
Creek Field was approved in 1938, following the discovery of oil in the
Lakota sand. Production from the Shannon Sandstone began three years
later.
The field is located in Township 35 North, Range 77 West, in
Natrona County, just northeast of Casper, Wyoming. It is situated on
a northwest-southeast trending anticline and hydrocarbon entrapment is
provided by the structure and stratigraphy of the anticline.
Shannon Unit
The Shannon reservoir covers an area of 1,653 acres with an
average pay zone thickness of 17 feet, an average porosity of 19 percent,
and an average permeability of 56 millidarcies. A peripheral pattern
of water injection wells was put into operation in February, 1946, to
maintain bottom hole pressures in the reservoir, thereby increasing the
recovery of oil from the Shannon sand. Water for the injection project
was obtained from the Upper Cretaceous Parkman Sandstone.
11-58
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Injection was terminated in April, 1977, when it was estimated that
99.9 percent of the Shannon reserve had been recovered. The cumulative
volume of water injected to that time was 20,114,806 barrels (8.4482
Dakota "A" Unit
The Dakota "A" Unit of Cole Creek Field was approved in 1965, and
covers 995 acres of federal, state, and private land. The pay thickness
of the Dakota reservoir ranges from two to 20 feet. In 1965, water
injection into the Dakota reservoir began through three wells, utiliz-
ing water from the Shannon Unit supply well completed in the Parkman
Sandstone. Later the Parkman water was supplemented with treated pro-
duced water from the Dakota sand. As of December, 1979, 20,444,756
8
barrels (8,5868 x 10 gallons) of water had been injected through five
wells, four of which are currently active.
Dakota Unit
The Dakota Unit of Cole Creek Field is located just to the north-
west of the Dakota "A" Unit. Water injection began in 1969, with water
from the Parkman sand through one well and was expanded to a seven well
system by 1976. As of December, 1979, all of the wells had been shut-in
O
Cumulative injection to that point was 5,410,063 barrels (2.2722 x 10
gallons).
Case Record: Injection Well #33, T35N-R77W-16 cba, Cole Creek Field,
Dakota Unit, Total Depth = 8098 feet.
Casing Size Wt. (///ft) Depth Set Hole Size Cement
g
x 10 gallons) through 20 injection wells.
8-5/8"
5-1/2"
24
14,15-1/2,17
524'
8063'
12-1/4"
7-7/8"
300 sacks
150 sacks
11-59
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South Cole Creek Field (15,834,514 bbls oil, 18,557 MCF gas; 1948-79)
Dakota Unit
South Cole Creek Field was discovered in 1948, with the completion
of a well in the Lakota Sandstone. In 1950, another well was completed
in the Lower Cretaceous Dakota sand, a highly fractured, shaley sand
reservoir found at an average depth of 8,250 feet with an average pay
thickness of 15 feet, average porosity of 11.5 percent, and average
permeability of 20.6 millidarcies. The Dakota Unit covers an area of
1,165 acres of federally and privately owned land and is situated on
the same northwest-southeast trending anticline as the Cole Creek Field.
Production is limited on the north, east, and south by the oil-water
contact and on the west by decreasing permeability. The drive mechanism
of the Dakota reservoir has reportedly been provided by the expansion
of solution gas and formation fluid.
Water injection into the Dakota reservoir started in 1968, using
produced water from the Dakota reservoir. Five of 23 existing injection
wells were still active in December, 1979, and cumulative injection
9
to that time was 28,264,292 barrels (1.1871 x 10 gallons) of water.
Shannon-Lakota Units
The Shannon and Lakota units of South Cole Creek Field are located
in Sections 7, 17, 18, and 20 of Township 34 North, Range 76 West.
The Shannon Unit covers 210 acres of federally owned land and 160
acres of privately owned fee land. The Lakota reservoir contains 470
acres and has an average pay zone thickness of 20 feet. The initial
reservoir producing mechanism was a natural water drive.
11-60
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The Shannon Sandstone is an Upper Cretaceous, medium- to coarse-
grained , glauconitic sand with an average permeability of 54 millidarcies
and an average porosity of 18.7 percent. The net productive interval
has an average thickness of 7.5 feet.
The first injections of water into the Lakota Sandstone took place
in 1960, and utilized water from the Cole Creek and South Cole Creek
Field waterflood systems. Current estimates (December, 1979) of the
volume of water injected into the Shannon and Lakota reservoirs total
g
5,838,258 barrels (2.4521 x 10 gallons) through four active injection
wells—three in the Lakota and one in the Shannon Sandstone.
Collums Field (5,578,551 bbls oil, 6,722,091 MCF gas; 1969-79)
Collums Unit
Collums oil field covers 4,681.96 acres of federal and private
land in Township 55 North, Range 73 West, Campbell County. The year
of initial field operations was 1969. Water injection into the Muddy
Sandstone was initiated in 1970, through 7 wells, and by 1977, had been
expanded to 13 wells. By 1980, all of the injection wells had been
temporarily shut-in.
The Muddy reservoir at well //10 (T55N-R73W-9 aad) is 110 feet
thick and has an average porosity and average permeability of 19.3
percent and 62.6 millidarcies, respectively. Cumulative injection
volume as of December, 1979, was 18,995,327 barrels (7.978 x 10^
gallons) of fresh water from the Lance Formation.
11-61
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Cooper Cove Field (1,662,041 bbls oil, 492,989 MCF gas; 1944-79)
Cooper Cove Unit
The productive area of Cooper Cove Field is approximately 2.5
miles long, less than one-quarter mile wide and situated atop a thin
northwest-trending anticline characterized by steep dips on both
flanks. The field is located in Township 18 North, Range 77 West,
Carbon County, and was discovered in 1944, when a productive well was
completed in the Dakota sand. The first well in the Muddy sand was
completed in 1963.
Commingled production from wells in the Muddy Sandstone and
Dakota sand is bounded on the north by a north-south trending thrust
fault which separates the Muddy reservoirs at Cooper Cove and Dutton
Creek fields. On the east, west, and south sides the reservoir is
bounded by an oil-water contact at an elevation of about 2,920 feet
(MSL).
The Dakota reservoir produces by natural water drive in contrast
to the Muddy sand which produces by expansion of reservoir fluid.
Primary recovery from the Muddy reservoir was approximately 9 percent
of the oil in place and it is estimated that another 12 percent will
be recovered by secondary injection.
Water injection into the Muddy sand began in 1967, through 4 wells
and was expanded to 6 wells in 1975. The most recent injection reports
available from the files of the Wyoming Oil and Gas Commission are from
July, 1975, and report that a cumulative total of 2,999,722 barrels
g
(1.2599 x 10 gallons) of water had been injected.
11-62
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Casing Record: Injection Well #11, T18N-R77W-20 cdb, Cooper Cove
Field, Cooper Cove Unit, Total Depth = 4984 feet.
Casing
Size
Hole Size
(///ft)
32.75
Wt.
Depth
Set
Cement
Purpose
Surface
10-3/4"
7"
15"
9"
20
298'
4984'
1100 sacks
200 sacks Injection
Cottonwood Creek Field (43,239,706 bbls oil, 39,392,567 MCF gas; 1953-79)
Cottonwood Creek Unit
Cottonwood Creek oil field was discovered in 1953, when a well
was completed in the Phosphoria Formation. The field is located in
Township 47 North, Ranges 90 and 91 West, in Washakie County. Cottonwood
Creek Unit contained 32,979 acres when it was approved in 1959, but by
1968, the area had been reduced to 14,227 acres. The average thickness
of the Phosphoria pay zone is 20 feet. Hydrocarbon entrapment occurs
near the crest of the structure where porous dolomite undergoes a
facies change to red shale. On the east side of the field the upper
Phosphoria producing zone is at a depth of 5,000 feet, whereas on the
west side of the field it is 10,000 feet deep.
Gas and water injection into the Phosphoria began in 1958 and
1959, respectively. Late in 1962, it was discovered that while the
gas and water injection programs had increased the reservoir pressure,
oil production had decreased. Gas injection was stopped in late 1964,
and a detailed field study was made.
The field was then divided into three areas—two that were
responding normally to water injection and one that was extensively
fractured and did not respond to injection. A "flowback" or "imbibition"
program was started in the fractured area. Imbibition is a process
11-63
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utilized in heavily fractured reservoirs whereby the major fracture in
the area is injected with water. The injection well is then shut-in
and the water migrates from the major fracture into the smaller
fractures and displaces oil out into the major fracture. The injection
well then becomes a production well and the displaced oil is pumped
from the major fracture.
The water supply for the Cottonwood Creek Unit injection project
is provided by the Madison Limestone through several water supply wells.
Produced Phosphoria water is also utilized for injection. December,
1979, injection reports indicated that 17 of 46 existing wells were
actively injecting. Cumulative injection was 86,444,219 barrels
9
(3.6307 x 10 gallons) of water at that time.
Casing Record: Injection Well #106, T47N-R91W-13 cd, Cottonwood Creek
Field, Cottonwood Creek Unit, Total Depth = 7740 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
9-5/8" 32.3 12-1/4" 343' 350 sacks
7" 20,23,26 8-3/4" 7739' 300 sacks
Phosphoria Unit
The Phosphoria Unit of Cottonwood Creek Field covers 4,155.38 acres
of federal and state land. Of the unit area, 2,620 acres are underlain
by productive reservoir rock with an average net pay thickness of 20
feet. The average porosity and permeability of the dolomite are 71
percent and 18.3 millidarcies, respectively, with vertical fracturing
common. Hydrocarbon entrapment occurs in an algal reef deposit which
trends northwest to southeast. The primary mechanism of reservoir
production is by expansion of reservoir fluids. An additional 920,000
11-64
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barrels of oil are expected to be recovered by water injection. An
estimated 23 million barrels of water will be required for the remainder
of the secondary recovery project.
As of December, 1979, 4,415,850 barrels (1.8547 x 10^ gallons)
of Madison Limestone water had been injected through two active wells
in the Phosphoria Formation.
Coyote Creek Field (20,443,800 bbls oil, 24,545,381 MCF gas; 1958-79)
Watt "A" Unit
The Watt "A" Unit of Coyote Creek is located in the southwest
corner of Crook County. Oil is produced from the Dakota reservoir, a
fine- to coarse-grained sandstone with good porosity and permeability.
Water injection began in 1971, through well Z/33-28 using produced
water from the Dakota sand. Two injectors were added in 1975, and
additional water was provided by a well in the Fox Hills Sandstone.
The thickness of the injected Dakota interval ranges from 78 to 115
feet. Recent injection reports (December, 1979) indicate that 4,455,214
g
barrels (1.8712 x 10 gallons) of water have been injected since the
project started.
Casing Record: Injection Well Z/33-28, T49N-R68W-28 db, Coyote Creek
Field, Watt "A" Unit, Total Depth = 6410 feet.
Casing Size Wt. (#/ft) Hole Size Depth Set Cement
9-5/8" 32.3 12-1/4" 165' 100 sacks
5-1/2" 14,15.5 8-3/4" 6400' 125 sacks
Watt "B" Unit
Watt "B" Unit of Coyote Creek Field is located just south of Watt
"A" Unit in the extreme northwest corner of Weston County. Water
11-65
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injection into the Dakota reservoir started in 1975, utilizing produced
water from the Dakota and fresh Fox Hills Sandstone water.
According to most recent Oil and Gas Commission statistics
(December, 1979), 3,437,361 barrels (1.4437 x 10^ gallons) of water
have been injected into the Dakota reservoir through three currently
active wells.
Kewanee, Buttram Unit
A pair of salt water disposal wells were put into operation at
Coyote Creek Field in 1975. The wells are part of the Kewanee, Buttram
Unit and are located in Section 3, Township 48 North, Range 68 West,
and Section 33, Township 49 North, Range 68 West, Weston County.
Produced brine from around Coyote Creek Field is injected to the
Dakota sand at average injection pressures between 0 and 20 psi. As
of December, 1979, 487,560 barrels (2.0477 x 10^ gallons) of brine had
been injected since the start of the project.
South Coyote Creek Field (3,249,987 bbls oil, 1,266,319 MCF gas; 1963-79)
Turner Unit
The Turner Unit of South Coyote Creek Field began operating in
1963, with the production of oil from the Upper Cretaceous Turner
Sandstone. Average porosity and permeability of the Turner at well #10
(T48N-R68W-24 dc) are 14.3 percent and 4.1 millidarcies, respectively.
Water injection for secondary recovery purposes was first utilized
in 1968. Fresh water from the Fox Hills Sandstone was being injected
through 12 wells by 1972. As of January, 1980, all of the wells had
been temporarily shut-in and no cumulative injection data were available
for the unit.
11-66
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Casing Record: Injection Well //2, T48N-R68W-24 ac, South Coyote Creek
Field, Turner Unit, Total Depth = 5430 feet
Casing Size
8-5/8"
4-1/2"
Wt. (///ft)
24
11.5
Hole Size
12-1/2"
7-7/8"
Depth Set
172'
5428'
Cement
110 sacks (2% cc)
150 sacks (50/50
pozmix, 2% gel
with lit NaCl/sack)
Boxelder Draw Unit
The Boxelder Draw Unit of South Coyote Creek Field is located in
Township 48 North, Range 67 West, Section 19, Weston County. Injection
of water from the shallow Lance Formation started in 1975, through well
//LL1. Water quality analyses on water being injected through well //4
showed rich concentrations of sulfate (650 ppm) and chloride (450 ppm).
December, 1979, data indicated that 491,063 barrels (2.0625 x 10^
gallons) of water had been injected through three active wells.
Casing Record:
Casing Size
8-5/8"
4-1/2"
Injection Well //4, T48N-R67W-19 be, South Coyote Creek
Field, Boxelder Draw Unit, Total Depth = 5275 feet.
Wt. (///ft)
24
9.5
Hole Size
11"
7-7/8"
Depth Set
167'
5275'
Cement
125 sacks
130 sacks
Crooks Gap Field (12,566,952 bbls oil, 1,238,724 MCF gas; 1944-79)
Crooks Gap Unit
Crooks Gap Field is located in Township 28 North, Range 93 West,
Fremont County, and is the site of a salt water disposal well completed
in the Lakota Sandstone at a depth of 5,286 feet. The well was put
into operation in 1964, by Amoco Production Company. As of December,
O
1979, cumulative injection was 18,859,691 barrels (7.9211 x 10 gallons)
11-67
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of produced brine. The average injection pressure during the project's
lifetime has varied between 120 and 150 psi.
Casing Record: Salt Water Disposal Well #3, T28N-R93W-13 aad, Crooks
Gap Field, Crooks Gap Unit, Total Depth = 5500 feet
Casing Size Wt. (///ft) Depth Set Cement
5-1/2" 14,15 5500' 500 sacks
(cement top at 4300')
Dead Horse Creek Field (9,720,790 bbls oil, 2,870,641 MCF gas; 1957-79)
The first oil production from the Mesaverde Group of the Powder
River Basin occurred in 1957, when a well was completed in the Parkman
Sandstone at Dead Horse Creek oil field. The field is located in
Townships 47, 48, and 49 North, Ranges 75 and 76 West, Campbell County.
Dead Horse Creek Field consists of three unitized areas—the
Caballo Unit, operated by Stovall Oil Company; the North Block Unit,
operated by Farmers Union Central Exchange, Inc; and the Hippus 1A
Unit, operated by Northern Production Company, Inc.
The Parkman Sandstone underlying the Dead Horse Creek Field is an
offshore bar deposit composed of fine- to medium-grained sandstone with
average porosity and permeability of 18 percent and 50 millidarcies,
respectively. All three units produce from the Parkman reservoir.
However, east-west trending faults in Sections 13 and 25, Township 49
North, Range 76 West, may divide the Parkman into three separate
reservoirs. Limits of production are defined by the oil-water contact
on the west and a pinchout of the sandy reservoir rock updip to the
east. Drill stem test data yield evidence that the water table in the
area is irregular and that the elevation of the oil-water contact may
be variable.
11-68
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North Block Unit
The North Block Unit of Dead Horse Creek Field contains 2,652
acres of federal and private land. The North Block reservoir covers
approximately 2,100 acres with an average pay zone thickness of 15
feet. Injection to the reservoir began in 1962, with a pilot water-
flood project and was expanded to a full scale flood in 1964. Water
is injected along the oil-water contact on the west side of the reser-
voir. Through December, 1979, 8 of the 11 injection wells were listed
as active. Cumulative injection totaled 5,556,461 barrels (2.3337 x
g
10 gallons) of water from the Fort Union Formation.
Caballo Unit
The Parkman reservoir of the Caballo Unit covers 2,340 acres and
has an average pay zone thickness of 10 feet. The overlying Caballo
Unit participating area includes 4,280 acres of federal and state land.
In 1963, a secondary recovery waterflood project was initiated
utilizing a standard 5-spot well pattern. Injected water is supplied
by a water supply well in the Fort Union Formation and by producing
wells in the Parkman sand. Four of the six Caballo Unit injectors
were still active as of December, 1979. Cumulative injection to that
g
time was 4,229,487 barrels (1.7764 x 10 gallons) of water. Casing
data were unavailable at the time of this writing.
South Dead Horse Creek Field (581,250 bbls oil; 1961-79)
Hippus 1A Unit
The Hippus 1A Unit of Dead Horse Creek Field is located in Township
47 North, Range 75 West, Section 10, Campbell County. Disposal of
produced brines into the Parkman Sandstone began in 1976, through the
11-69
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Hippus it 1A Well (T47N-R75W-10 dc) at a depth of 7,136 feet. In 1979,
the well was converted to a secondary recovery water injection well.
During the first year, 8,485 barrels (365,370 gallons) were injected
into the reservoir.
Casing Record: Injection Well it 1A, T47N-R75W-10 dc, Dead Horse Creek
Field, Hippus 1A Unit, Total Depth = 7319 feet.
Casing Size Wt. (it/ft) Amount Perforations Purpose
8-5/8" 24 312' Surface
4-1/2" 11.6 7287' 7136-7257 Injection
Deadman Creek Field (407,687 bbls oil; 1973-79)
Deadman Creek Unit
Deadman Creek Field is located in Crook County approximately
20 miles north of Moorcroft, Wyoming. Oil was discovered in 1973,
in a discrete sand body within the Minnelusa Formation, known as
the "Lower 'B1 Porosity Zone". The productive (greater than 12
percent porosity) zone is 362 acres, with an average pay thickness
of 18 feet. Average porosity within the reservoir is 17.6 percent.
Water injection into the Minnelusa "B" zone began in 1979,
through well it23-18 (T53N-R67W-18 ca) with fresh and produced water
from the Minnelusa "C" and "B" zones, respectively. By the end of
1979, 133,511 barrels (5,607,462 gallons) of water had been injected.
A water quality analysis of formation water in the lower "B" zone
indicated very high TDS (21,177 ppm) water.
11-70
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Dewey Dome Field (8,979 bbls oil; 1936-79)
Bradley Unit
The Dewey Dome Field, located in Township 42 North, Range 61 West,
Section 36, Weston County, was discovered in 1936. Oil was produced
from the Sundance Formation.
Between 1967 and 1974, water from the Dakota and Lakota sands
was injected into the Sundance reservoir as part of a recovery enhance-
ment project. During that time 690,700 barrels (29,009,400 gallons)
of water were injected through two wells. In 1974, both wells were
shut-in by order of the Wyoming Oil and Gas Commission. The reason
for the order was not disclosed. Primary production of oil, however,
has continued despite the abandonment of the injection project.
Diamond Ranch Field (770,527 bbls oil, 121,151 MCF gas; 1957-79)
Lakota Unit
Diamond Ranch Field is located in Township 20 North, Range 78
West, Carbon County. The Lakota Unit is the site of an active one well
salt water disposal system that was put into operation in 1978, by
Marathon Oil Company. The injected formation is the Lakota Sandstone,
which received a volume of 8,899 barrels (373,758 gallons) during
the month of September, 1979, the only month for which injection data
were available.
Dillinger Ranch Field (11,062,497 bbls oil, 315,613 MCF gas; 1964-79)
Dillinger Ranch Unit
Dillinger Ranch Field was discovered in March, 1964, and unitized
for water injection in December, 1966. The Dillinger Ranch Unit
participating area includes 2,264.25 acres of federal, state, and
11-71
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private land in east-central Campbell County. Oil is produced from the
Minnelusa "B" pay zone, a variably porous zone of four sand lenses
separated by dolomite beds. The average thickness of the pay zone
is 30 feet, porosity averages 16.8 percent, and permeability averages
100 millidarcies.
The productive limits of the Minnelusa reservoir are defined by
an oil-water contact to the southwest and a porosity and permeability
loss updip to the northeast. Three Fox Hills Sandstone wells supply
all of the fresh water for the injection project. As of December, 1973,
g
11,402,284 barrels (4.789 x 10 gallons) of water had been injected
through 11 wells. At the end of 1976, 8 of these wells were still
actively injecting, but biannual injection totals have not been reported
since 1973.
Casing Record: Injection Well //16X, T47N-R69W-7 deb, Dillinger Ranch
Field, Dillinger Ranch Unit, Total Depth = 9352 feet.
Casing Size Wt. (///ft) Hole Size Setting Depth Cement
8-5/8" 24 12-1/4" 365' 150 sacks
4-1/2" 10.5,11.6 7-7/8" 9360' 300 sacks
Donkey Creek Field (14,460,631 bbls oil, 3,104,638 MCF gas; 1953-79)
Dakota "A" Unit
Donkey Creek Field is located in Townships 49 and 50 North, Range
68 West, Crook County. The field was discovered in 1953, and produces
from the Dakota sand. The Dakota "A" Unit participating area includes
835 acres of federal and private land.
The water injection project started in 1973, with four injectors
supplied by Minnelusa Formation water produced in a nearby field.
The cumulative volume of water injected through December, 1979, was
11-72
-------
8
3,989,538 barrels (1.6756 x 10 gallons). Average injection pressures
used in the Dakota waterflood have ranged from 50 to 1,500 pounds per
square inch (psi) at the wellhead.
Casing Record: Injection Well //W-l, T50N-R68W-32 ca, Donkey Creek
Field, Dakota "A" Unit, Total Depth = 6299 feet.
Casing Size
Wt. (///ft)
Amount
Grade
Purpose
10-3/4"
32.75
210'
H-40
Surface
7"
23
830'
N-80
Injection
7"
23
1650'
J-55
Injection
7"
20
3806'
J-55
Inj ection
Burrows "B" Unit
The Burrows "B" Unit of Donkey Creek Field is located in Township
49 North, Range 68 West, Crook County. A salt water disposal system,
which started in 1966, at the Burrows "B" Unit, consists of two
injection wells completed in the Dakota sand. One of the wells was
still active in December, 1979, when the cumulative volume of brine
injected during the project stood at 2,222,607 barrels (9.3349 x 10^
gallons). Average injection pressures have ranged from 0 to 1,320 psi.
South Donkey Creek Field (582,546 bbls oil; 1957-79)
Koch Unit
In 1975, a salt water disposal system similar to that in the
Burrow "B"Unit, began operating in the Koch Unit of South Donkey Creek
Field. The single well system is completed in the Dakota sand.
Cumulative injection through the end of 1979, was 120,816 barrels
(5,074,272 gallons) of produced brine from producing oil wells at
Donkey Creek Field.
11-73
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Dugout Creek Field (No production data available)
The Dugout Creek oil field was initially developed in 1953,
following the discovery of oil in the Shannon sand. The field is
located in the southeast corner of Johnson County in Section 18,
Township 42 North, Range 78 West, and Sections 12, 13, 14, and 17 of
Township 42 North, Range 79 West. The Dugout Creek reservoir includes
1,010 acres with an average pay thickness of 17 feet. It is bounded
on the south by an east-west trending fault, on the west by a decrease
in the permeability of the Shannon sand and on the north by the water-
oil contact. The structure within the area dips steeply to the north-
east and there are a number of small accumulations of gas trapped by
transverse faults at varying structural elevations. Faults divide the
reservoir into five distinct blocks, four of which have small gas caps.
All of the fault blocks are utilized in the water injection project.
The Shannon Sandstone is a friable, light gray, glauconitic sand
with a porosity of 25 percent and an estimated interstitial water
content of 21 percent.
Estimates of oil originally in place were 22.7 million barrels.
The primary recovery mechanism of the Shannon sand was solution gas
drive aided by the expansion of a small accumulation of updip gas,
gravity drainage and the influx of water from the north and east.
Secondary oil recovery began in 1963 and was expanded over the next 9
years to include 26 water injection wells of which 10 were still
actively injecting as of August, 1979. A total of 31,227,064 barrels
9
(1.3115 x 10 gallons) had been injected up to that point.
11-74
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Casing Record: Injection Well #A733, T43N-R80W-33 ccb, Dugout Creek
Field, Shannon Unit, Total Depth = 2265 feet.
Casing Size
10-3/4"
7"
Wt. (///ft)
32
23
Depth Set
228'
2265'
200 sacks Injection
200 sacks
Cement
Purpose
Surface
Dutch Field (639,134 bbls oil, 45,237 MCF gas; 1975-79)
Record Unit
The only injection well at the Record Unit of Dutch Field is a
salt water disposal well, completed in the Minnelusa Formation at a
depth of 9,056 feet. The well, located in Section 31, Township 51
North, Range 70 West, Campbell County, was put into operation in 1977.
By December, 1979, 240,070 barrels (1.0082 x 10^ gallons) of produced
salt water had been injected during the system's duration. Average
injection pressures have ranged from 750 to 1,250 psi.
Duvall Ranch Field (9,442,981 bbls oil; 1964-79)
Minnelusa Unit
The Minnelusa Unit of Duvall Ranch Field is situated on the
eastern shelf of the Powder River Basin approximately 20 miles south-
east of Gillette. Oil was discovered in the upper Minnelusa Formation
in 1964.
The Minnelusa reservoir is a stratigraphic trap bounded by an
oil-water contact to the west and a deep channel of Opeche Shale along
the eastern flank. The reservoir occurs at a depth of about 8,200
feet in the area and the primary producing mechanism is a solution gas
drive with a slight effect from edge water expansion. The top of the
pay zone dips to the west-southwest at nearly 2°. Average porosity and
permeability are 17 percent and 88.8 millidarcies, respectively.
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Water injection at Duvall Ranch Field began in 1971, and eleven
injection wells are currently active. December, 1979, data indicate
o
that 26,805,977 barrels (1.1259 x 10 gallons) of Fox Hills Sandstone
water has been injected into the upper Minnelusa reservoir.
Casing Record: Injection Well #8—2, T49N-R69W-14 db, Duvall Ranch Field,
Minnelusa Unit, Total Depth = 8311 feet.
Casing Wt.
Size (///ft) Hole Size Depth Set Cement Purpose
9-5/8" 32.3 13-3/4" 319' 320 sacks Surface
5-1/2" 15.5,17 8-3/4" 8311' 500 sacks Injection
Elk Basin Field (401,633,653 bbls oil, 291,294,260 MCF gas; 1915-79)
Elk Basin Field is located at the north end of the Bighorn Basin
in Townships 57 and 58 North, Ranges 99 and 100 West, Park County,
Wyoming, and Township 9 South, Range 23 East, Carbon County, Montana.
Oil was first discovered at Elk Basin in 1915, when a well was
completed in the first Frontier (Torchlight) sand. Subsequent discoveries
were made in the second Frontier (Peay) sand, the Cloverly Formation,
the Tensleep Sandstone, the Madison Limestone, the Jefferson Formation,
and the Bighorn Dolomite. Hydrocarbons are structurally entrapped
within a broad, double-crested, asymmetrical, northwest-southeast
trending anticline with a steeply sloping northeast side.
Madison Unit
The Madison reservoir of Elk Basin Field covers an area of 5,097
acres with an average pay zone thickness of 150 feet. Oil was discovered
in the Madison Limestone in 1946, when a well on the crest of the anti-
cline was deepened to 4,680 feet.
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A pilot waterflood project began in 1960, and was expanded to a
full scale flood one year later. The project was initially a pressure
maintenance operation which was converted to a secondary recovery
operation. Produced water from the Madison Limestone, Bighorn Dolomite,
Frontier and Embar (Phosphoria) formations, and Tensleep Sandstone and
fresh water from the Clarks Fork River are injected through 37 active
wells, 14 of which are dual annulus-tubing injectors. Ten other injec-
tion wells have been temporarily or permanently shut-in. As of December,
1979, 221,991,787 barrels (9.3237 x 10^ gallons) of water had been injected
into the Madison reservoir. Originally, the injection well configuration
was a peripheral pattern, but it was converted to a line drive pattern.
Case Record: Injection Well It 166, T58N-R99W-30 add, Elk Basin Field,
Madison Unit, Total Depth = 6835 feet.
Casing Size Wt. (#/ft) Depth Set Hole Size Cement
10-3/4" 32.75 2061' 15" Previously set
7" 20,23 58151 9" Previously set
Frontier Unit
The Elk Basin Frontier Unit produces from two sand horizons in the
upper Frontier Formation at depths between 1,000 and 1,700 feet. The
unit is located in Township 58 North, Ranges 99 and 100 West. Water
injection into the Frontier sands started in June, 1966, through 3
wells. The waterflood project followed a period of gas injections in
the Frontier reservoirs and was undertaken as a pilot project to deter-
mine whether or not future waterflooding of the reservoirs would be
successful. Four of the 10 active injecting wells (status as of 12/79)
are dual injectors which inject into the upper sand through the well
casing and into the lower sand through tubing.
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Current Oil and Gas Commission data indicate that 40,539,399
g
barrels (1.6965 x 10 gallons) of Madison Limestone water have been
injected between 1966 and 1980.
Embar-Tensleep Unit
All of the injection wells of the Embar-Tensleep Unit of Elk Basin
Field have been permanently shut-in for at least two years and are no
longer reported in the annual Oil and Gas Commission statistics
compilation.
South Elk Basin Field (15,982,216 bbls oil, 32,735,230 MCF gas; 1945-79)
Peay/Tensleep Unit
South Elk Basin Field was discovered in 1945, when a well was
completed in the Tensleep Sandstone between 6,975 and 7,135 feet. The
field is located in Township 57 North, Range 99 West, Park County.
The Tensleep Unit covers 540 acres of federal and private land
and governs production and injection in the underlying Tensleep and
Peay reservoirs. The Tensleep reservoir has an area of 520 acres with
an average pay zone thickness of about 75 feet. Data on the extent of
the Upper Cretaceous Peay reservoir at South Elk Basin were unavailable.
The Pennsylvanian Tensleep Sandstone is described as a series of 7
marine sandstone beds separated by impermeable sandy dolomite stringers.
Average porosity and permeability of the Tensleep are 14.2 percent and
190 millidarcies, respectively.
Structurally, South Elk Basin is a small, asymmetrical, northwest-
southeast trending anticline with a closure which includes the entire
area of the Tensleep reservoir. Fluid withdrawals have exceeded
formation water influx since 1955, resulting in a steady decline of
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reservoir pressure and productivity. In 1962, water injection into the
Tensleep began with the purpose of augmenting the limited natural
water drive pressure of the reservoir. Six of 7 injectors are currently
active (December, 1979) and 46,628,477 barrels (1.9584 x 10^ gallons)
of produced Tensleep water have been injected into the Tensleep and
Peay sands. The shut-in well is a dual Tensleep-Peay injection well.
Casing Record: Injection Well #45, T57N-R99W-17 dc, South Elk Basin
Field, Tensleep Unit, Total Depth = 7330 feet.
Casing Wt.
Size (///ft) Depth Set Hole Size Cement Purpose
9-5/8" 36 292' 12-1/4" 225 sacks Surface
7" 23,26 7330' 8-3/4" 1200 sacks Injection
Empire Field (534,588 bbls oil, 199,331 MCF gas; 1974-79)
Teapot Unit
A single well salt water disposal system was started in 1975, at
the Teapot Unit of Empire Field, under the operation of Texaco, Inc.
The injection well is located in Section 22, Township 47 North, Range
67 West, Johnson County, and is perforated in the Teapot Sandstone at
a depth of 7,238 feet. As of December, 1979, a cumulative volume of
446,601 barrels (1.8757 x 10^ gallons) of brine had been injected at
average pressures between 0 and 1,950 psi.
Fence Creek Field (1,447,444 bbls oil, 309,045 MCF gas; 1968-79)
Muddy Sand Unit
Fence Creek oil field is located in Townships 57 and 58 North,
Range 76 West, in Sheridan and Campbell counties. The field was
discovered in 1968, when a well was completed in the Muddy Sandstone.
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The Muddy Unit participating area includes 1,550 acres of federal and
private land.
The Muddy reservoir covers 967 acres and has an average pay zone
thickness of 10 feet. Average porosity and permeability are 16
percent and 70 millidarcies (air permeability), respectively. Hydro-
carbon entrapment to the east, north, and northwest results from an
upstructure permeability barrier. To the southwest, production is
limited by an apparent oil-water contact.
Water injection into the Muddy reservoir started in 1974, utilizing
fresh water from the Fox Hills Sandstone and produced Muddy Sandstone
water. The 4 injection wells had been temporarily shut-in as of the
end of 1979, with a cumulative injected water volume of 1,077,085
barrels (4.5238 x 10^ gallons).
Casing Record: Injection Well //A332, T58N-R76W-32 abb, Fence Creek
Field, Muddy Sand Unit, Total Depth = 7580 feet.
Casing Wt.
Size (///ft) Hole Size Depth Set Cement Purpose
8-5/8" 24 12-1/4" 255' - Surface
5-1/2" 15.5,17 7-7/8" 7588' 150 sacks Injection
Fiddler Creek Field (7,026,076 bbls oil* 1948-79)
West Fiddler Creek Unit
The West Fiddler Creek Unit includes 7,557.22 acres of federal,
state, acquired and patented land in the southern half of Township 46
North, Range 65 West, and southeast quarter of Township 46 North, Range
66 West, Weston County. Oil was discovered at Fiddler Creek Field in
1948, when a well in the East Fiddler Creek Unit area was completed in
the Newcastle Sandstone.
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The Newcastle Sandstone, often called the Muddy Sandstone, is a
highly variable zone of discontinuous beds of cross-bedded sandstone,
shale, sandy shale, carbonaceous shale, impure lignite and bentonite.
The pay sand of the Newcastle is medium- to fine-grained, with shaley
streaks and carbonaceous material. Overlying the Newcastle sand is a
cap of shale and sandy shale 300 feet thick, known as the Mowry Shale.
Underlying the Newcastle is the Skull Creek Shale.
The West Fiddler Creek reservoir covers 5,207 acres and has an
average pay thickness of 5.8 feet. The average porosity and perme-
ability of the Newcastle sand in this area are 20 percent and 1 to 18
millidarcies, respectively.
The initial mechanism of production from the reservoir was a
solution gas drive. Water injection began in the eastern part of the
unit in 1960. The injection pattern is a modified line drive pattern,
due to the meandering channel type sand deposits that are not suited
for conventional line drive injection. As of December, 1979, 66 of
the 76 injection wells in the West Fiddler Creek Unit had been shut-in.
The remaining ten wells were actively injecting. The cumulative amount
of water injected into the Newcastle from the Madison aquifer since
1960 was 88,404,124 barrels (3.713 x 10^ gallons) at the end of 1979.
Casing Record: Injection Well #130, T46N-R65W-28 ca, West Fiddler
Creek Unit, Total Depth = 5260 feet.
Casing Size Wt. (///ft) Depth Set (MP) Hole Size Cement
8-5/8" 24 207.85' 12-1/4" 150 sacks
regular
2-7/8" 6.5 5251.46' 7-7/8" 130 sacks
(50-50 pozmix)
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East Fiddler Creek Unit (11,029,418 bbls oil; 1948-79)
The East Fiddler Creek Unit covers an area of 2,799.79 acres of
federal, state, and private fee land- The area was unitized in 1955,
seven years after the first oil well had been completed in the
Newcastle sand. The depth to the Newcastle Sandstone in the area of
central Weston County is generally between 4,500 and 4,550 feet with an
average formation thickness of 50 feet. The Newcastle consists of a
succession of thin beds of sandstone, siltstone, and shale. The pay
zone is a fine- to medium-grained sand with shale intercalations and
carbonaceous material. The average porosity and permeability of the
pay zone are 18.6 percent and 3 to 6 millidarcies, respectively.
Water was first injected into the Newcastle sand in 1955, and has
expanded to a peripheral injection system of 80 injectors, ten of
which were active in December, 1979. The remainder of the injection
wells have been temporarily or permanently shut-in. Water for the
injection project is provided by a Madison Limestone supply well which
initially produced 11,000 barrels per day. The temperature of the
Madison water is reported to be 135°F, making it ideal for flooding the
cooler Newcastle Sandstone. The cumulative total injected through the
80 wells between 1955 and 1980, was 71,859,156 barrels (3.0181 x 10^
gallons) of water.
Casing Record: Injection Well #122, T46N-R65W-13 ddd, East Fiddler
Creek Unit, Total Depth = 4590 feet.
Casing Size Wt. (///ft) Make Amount (ft) Purpose
10-3/4"
32.75
H-40
160.48 Guide with Surface
float collar
7"
23
J-55
1661.5 Guide with Injection
float collar
7"
20
H-40
2856.62
Inj ection
Injection
7"
23
J-55
31.76
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Casing Record: Injection Well // 175A, T46N-R65W-23 cdc, East Fiddler
Creek Unit, Total Depth = 4871 feet.
Casing Wt.
Size (///ft) Make Amount (ft) Purpose
8-5/8" 24 J-55 100.5 Casing landed at
112 ft KB
4-1/2" 9.5 J-55 4871 3rd casing landed
at 4869 ft KB
Fourbear Field (21,073,431 bbls oil, 6,815 MCF gas; 1928-79)
North Fourbear Unit
The North Fourbear Unit, located in Township 48 North, Range 103
West, Park County, has, since 1972, been the site of a salt water
disposal system. Water produced with oil from wells at Fourbear Field
is injected into the Darwin Sandstone and Madison Limestone at depths
between 3,200 and 3,750 feet. Four wells were actively injecting the
produced brine as of December, 1979, with one well under construction.
8
Cumulative injection to that point was 1.6115 x 10 barrels (6.7684 x 10
gallons) of salt water.
Casing Record: Salt Water Disposal Well, T48N-R103W-20, Fourbear Field,
North Fourbear Unit.
Casing Size Depth Set Cement
13-3/8" 252' 500 sacks
9-5/8" 3562' 420 sacks
Fourbear Unit
The initial year of operation was 1976, for the single well salt
water disposal system at the Fourbear Unit of Fourbear Field. The well
is located in Section 3, Township 47 North, Range 103 West, Park County.
Cement
60 sacks
125 sacks
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As of December, 1979, 4,576,608 barrels (1.9222 x 10^ gallons) of
produced brine had been injected to the Dinwoody and Phosphoria
formations since the project started.
Frannie Field (95,497,671 bbls oil, 264,290 MCF gas; 1928-79)
Phosphoria/Tensleep Unit
The Frannie Field was discovered in 1928, with production of oil
from a well completed in the Phosphoria and Tensleep formations. The
Tensleep Sandstone in the Frannie Field area was deposited conformably
over the Amsden Formation during early and middle Pennsylvanian time.
The Tensleep is composed of fine- to medium-grained, cross-bedded, well
sorted, non-marine sandstone with interbedded dolomite. As a result of
interbedding and facies transitions, there is a significant variation
in porosity and permeability. Upper Tensleep zones tend to have less
dolomite than lower zones and thus have higher porosity and permeability.
The Phosphoria Formation was deposited during the middle Permian age.
It is predominantly a crystalline dolomite which grades into dolomitic
sandstones that have porosities and permeabilities similar to the
Tensleep. In the Phosphoria/Tensleep reservoir, the average porosity
and permeability of the productive zones are 16.3 percent and 223
millidarcies, respectively.
Structually, the Phosphoria/Tensleep reservoir is situated within
a northwest-southeast trending anticline, the flanks of which dip
approximately 13° to the southwest and 40° to the northeast. Water
pressure gradients in the area are from east to west. The major influx
of water has been through a saddle between the Frannie structure and
the Sage Creek anticline to the southeast. The primary mechanisms of
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production in Frannie Field are fluid expansion, solution gas drive,
gravity drainage, and water influx drive.
The Phosphoria/Tensleep Unit participating area covers 2,002
acres of federal, state, and private land. Of that area, 114 acres
are located in the state of Montana. Water injection started in 1970,
and by January, 1980, included 32 wells, 30 of which were still actively
injecting. Fourteen of the active wells are dual injectors. As of
December, 1979, 119,970,367 barrels (5.0388 x 10^ gallons) had been
injected into the Phosphoria/Tensleep reservoir. Data on casing
schedules at Frannie Field were unavailable at the time Of this writing.
Garland Field (137,347,757 bbls oil, 131,013,001 MCF gas; 1906-79)
Harriman Unit
Garland Field was discovered in 1906, when oil was first produced
from the Peay sand of the Frontier Formation. The field is located in
Townships 55 and 56 North, Ranges 97 and 98 West, Park and Big Horn
counties.
The Harriman Unit of Garland Field, operated by CENEX, Inc.,
governs production from the Morrison and Cloverly formations. Natural
gas was discovered in both formations during the 1920's. Three active
(December, 1979 status) water injection wells in the Morrison and
Cloverly reservoirs have injected 2,145,791 barrels (9.0123 x 10^
gallons) of produced Tensleep water since the waterflood project began
in 1971. Average porosity and permeability in the Morrison/Cloverly
reservoir are 15.5 percent and 63.7 millidarcies, respectively.
The Harriman Unit is also the site of a one well salt water
disposal system, which began operation during 1970. The well is
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completed in the Tensleep Sandstone at a depth of 4,770 feet. A
O
cumulative volume of 2,972,726 barrels (1.2485 x 10 gallons) of
produced brine from wells at Garland Field had been re-injected as of
December, 1979. Average injection pressures have ranged between 20
and 265 psi.
Casing Record: Injection Well #19, T56N-R98W-11 cbd, Garland Field,
Harriman Unit, Total Depth = 3702 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
8-5/8" 24 12-1/4" 200' 250 sacks
5-1/2" 14 7-7/8" 3702' 300 sacks
Casing Record: Salt Water Disposal Well //10, T56N-R98W-11 ccd,
Garland Field, Harriman Unit.
Casing Size Wt. (///ft) Depth Set Make Cement
7" 23 4912' J-55 150 sacks
Kinney-Coastal Unit
The Kinney-Coastal Unit participating area includes 1,646 acres of
the Tensleep Unit and 1,388 acres of the Embar Unit in Township 56
North, Ranges 97 and 98 West, Park and Big Horn counties.
The Tensleep reservoir has a productive area of 1,508 acres with
an average pay zone thickness of about 59 feet. In order to maintain
pressure within the reservoir, a water injection project was undertaken
in 1958, by Marathon Oil Company. Produced water from the Madison
Limestone of the Garland Field area is used for the project.
In December, 1966, a similar project was started in the Embar
(Phosphoria) reservoir using produced water from the Embar Formation and
Tensleep Sandstone. Currently (December, 1979), there are 27 injection
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wells involved in the Kinney-Coastal Unit waterflood of the Tensleep
and Embar reservoirs. Twenty-four of the wells are active injectors,
with 12 being dual injectors. Cumulative injection and well casing
data for the Kinney-Coastal Unit were unavailable at the time of this
writing. Average injection pressures in both projects range from a
minimum of 140 to a maximum of 1,370 psi.
Community #3 Unit
A salt water disposal system, completed in the Madison Limestone,
was put into operation in 1977, at the Community //3 Unit of Garland
Field. The single well system is located in Section 32, Township 56
North, Range 97 West, Park County. As of June, 1980, 3,315,193
g
barrels (1.3924 x 10 gallons) of produced salt water had been
injected to the Madison Limestone at average injection pressures between
120 and 1,680 psi.
Allen-Jones Unit
The Allen-Jones Unit salt water disposal system was shut-in during
1978, after three years of brine injection through two wells completed
in the Madison Limestone. At the time that the system was shut-in, a
O
cumulative volume of 20,330,991 barrels (8.539 x 10 gallons) of brine
had been injected.
Willey Unit
The single well salt water disposal system at the Willey Unit of
Garland Field is operated by Marathon Oil Company. Injection of
produced brine began at well #3 in 1979. The disposal well, located
in Lot 59, Township 56 North, Range 97 West, Big Horn County, is
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perforated at a depth of 4,407 feet in the Madison Limestone. Cumulative
injection and average pressure data were not yet available at the time
of this writing.
Garland Unit
The Garland Unit is the site of a natural gas storage project
that began operation in 1964. The project includes three gas injection
wells completed in the Cloverly Formation. Detailed data on the project
were not available from Oil and Gas Commission files.
Gas Draw Field (23,359,314 bbls oil, 2,047,685 MCF gas; 1968-79)
Gas Draw Field is located on the gently dipping east flank of the
Powder River Basin, approximately 20 miles north of Gillette. The
field was developed on an 80-acre spacing pattern and covers about
7,463 acres. The main producing interval, designated the Gas Draw
sand, occurs just below the top of the Muddy Sandstone. The sand is a
clean, bar sand with average porosity and permeability of 20.2 percent
and 188 millidarcies, respectively. The average thickness of the pay
zone of the Gas Draw sand is 8 feet.
Gas Draw Unit
The Gas Draw Unit covers 8,100 acres of federal, state, private,
commutized, and unleased land in Townships 53 and 54 North, Ranges 72
and 72 West, Campbell County. Water injection into the Gas Draw sand of
the Muddy Sandstone started in 1972. Cumulative injection through 16
wells to December, 1979, was 60,769,551 barrels (2.5523 x 10^ gallons)
of fresh water from the Fox Hills Sandstone and Lance Formation and pro-
duced Muddy water. Fifteen of the wells are still actively injecting.
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All injection wells were initially treated with calcium chloride to
prevent clay swelling and damage to the reservoir.
Casing Record: Injection Well #34—5b, T53N-R72W-5 dca, Gas Draw
Field, Gas Draw Unit, Total Depth = 7375 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
8-5/8" 24 12-1/4" 150' 200 sacks
5-1/2" 15.5,17 7-7/8" 7375' 300 sacks
Rogers Muddy Sand Unit
The Rogers Muddy Sand Unit is located in Townships 54 and 55 North,
Ranges 72 and 73 West and is a northward extension of the Gas Draw
Field. At the south end of the Rogers Unit is a neck of low perme-
ability strata that separates the unit from the main field. The
productive limits on the north, east, and west are defined by a pinchout
of the Gas Draw sand. The stratigraphy of the Rogers area differs from
that of the main field in that it is underlain by a highly porous lower
Muddy aquifer of considerable areal extent.
Water injection into the Muddy sand of the Rogers Unit began in
1972, through 3 wells. Those 3 wells remain active (December, 1979
O
status) and have injected a total of 5,625,173 barrels (2.3626 x 10
gallons) of water from the Fox Hills Sandstone and Lance Formation.
Casing Record: Injection Well //7-1, T55N-R72W-30 cb(cd), Gas Draw
Field, Rogers Muddy Sand Unit, Total Depth = 7168
feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
8-5/8" 24 12-1/4" 300' 500 sacks
(circulation)
5-1/2" 15.5,17 7-7/8" - 300 sacks
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East Gas Draw Field (622,977 bbls oil, 116,778 MCF gas; 1975-79)
Collins Unit
A single well salt water disposal system, operated by Marmik
Oil Company, began injection in 1976. The disposal well, located in
Section 12, Township 53 North, Range 72 West, Campbell County, is
perforated at a depth of 6,866 feet in the Muddy Sandstone. Cumulative
injection through July, 1979, totaled 275,305 barrels (1.1562 x 10^
gallons) of brine from producing oil wells at East Gas Draw Field.
The maximum average injection pressure has been 200 psi during the
project's lifetime.
Gibbs Ranch Field (679,482 bbls oil, 9,418 MCF gas; 1970-79)
MWM State Unit
A salt water disposal well completed in the Minnelusa Formation,
at a depth of 7,434 feet, was put into operation in 1977. The well is
located in Section 16, Township 52 North, Range 69 West, Campbell
County. The cumulative volume of salt water injected as of December,
1979, was 128,680 barrels (5,404,560 gallons).
Lindstrom-Federal Unit
Another salt water disposal system was constructed at the Lindstrom-
Federal Unit (T52N-R69W) in 1978. The sole disposal well is perforated
in the Minnelusa "C" sand. As of December, 1979, 27,207 barrels
(1,142,694 gallons) of produced brine had been injected since disposal
began.
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Glenrock Field (2,529,175 bbls oil, 158,215 MCF gas; 1949-79)
McNeil Unit
The McNeil Unit of Glenrock Field is located in Township 33 North,
Range 75 West, Converse County. A one well salt water disposal system
began injecting produced brine into the Dakota and first Wall Creek
sands at depths of 6,954 and 5,780 feet, respectively. The dually
perforated well is located in Section 4. Cumulative injection as of
December, 1979, was 458,150 barrels (1.9242 x 10^ gallons) of produced
salt water.
South Glenrock Field (70,944,609 bbls oil, 30,303,976 MCF gas; 1950-79)
South Glenrock Field, located just west of Big Muddy Field and
one-half mile south of Glenrock Field, covers over 17,200 acres in
Townships 32, 33, and 34 North, Ranges 75 and 76 West, Converse County.
The discovery well was completed in 1950, in the Dakota sand. Shows of
oil were later recorded in the Muddy and Shannon sandstones. The field
was divided into three blocks and separate waterflood agreements were
completed for each unit. Block "A," covering 1,284 acres of federal,
state, and private land, was divided into the Muddy and Dakota units,
both of which are operated by Atlantic Richfield Company. Block "B,"
10,874 acres of federal, state, and private land, was divided into 3
units operated by Continental Oil Company, the upper Muddy, lower Muddy
and the Dakota. M and K Oil Operations operates the Block "C" lower
Muddy Unit which includes 4,736 acres of state and private land.
Block "A" Muddy Unit
The upper Muddy reservoir of Block "A" covers about 320 acres with
an average pay zone thickness of 6 feet. Average porosity and
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permeability in the upper Muddy throughout South Glenrock Field are 20
percent and 200 millidarcies, respectively.
The primary mechanism of oil production in the reservoir is by
gas expansion drive and, since 1967, has been augmented by water
injection. Between 1967, and December, 1979, 4,113,185 barrels (1.7275
g
x 10 gallons) were injected into the upper Muddy "A" reservoir through
4 wells, only one of which was still active. Water for the injection
project is supplied by a well in an unknown aquifer reported as the
"shallow sands." Three of the injection wells, including the active
well, are dual injectors.
Block "A" Dakota Unit
The Dakota "A" reservoir encompasses 1,284 acres with a pay zone
thickness of 28 feet. Porosity and permeability average 14 percent
and 75 millidarcies, respectively, in the Dakota sand across the entire
South Glenrock Field.
Primary reservoir energy was provided by a partial water drive
and solution gas drive before water injection started in 1967. As of
O
December, 1979, 18,345,759 barrels (7.7052 x 10 gallons) of fresh
water from a well in an unknown aquifer called the "shallow sands" had
been injected into the Dakota "A" reservoir through 9 wells. Seven
of the injectors are still active and two of those wells are dual
injectors. Maximum injection pressures for both units in Block "A"
have been 2,300 psi.
Block "B" Upper Muddy Unit
The Block "B" Upper Muddy Unit is located in Township 33 North,
Range 75 West, Converse County. The upper Muddy reservoir spans an
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area of 4,838 acres and averages 6 feet in thickness. Average porosity
and permeability within the reservoir are similar to those of the
equivalent reservoir of Block "A." The primary producing mechanism
of the upper Muddy is solution gas drive.
The initial year of the Block "B" Upper Muddy Unit waterflood
project was 1961. Four wells were converted to injectors that year.
Since then, 31 injection wells have been added to the project. Twenty-
seven wells are equipped as dual injection wells, and 17 of the dual
injectors were active as of December, 1979. Over the life of the
project, injection pressures have ranged from a reported "vacuum" to
a maximum pressure of 3,700 psi. Current Oil and Gas Commission
9
statistics indicate that 64,338,960 barrels (2.7022 x 10 gallons) of
produced Madison Limestone and Tensleep Sandstone water have been
injected since the project began.
Block "B" Lower Muddy Unit
The Lower Muddy Unit of the "B" Block is in the south-central part
of South Glenrock Field adjacent to M and K Oil Operation's lower Muddy
project in Block "C" to the west. The Block "B" lower Muddy reservoir
includes 1,129 acres with an average pay thickness of 17 feet. The
average porosity and permeability of the reservoir are 14 percent and
82 millidarcies, respectively. The primary reservoir producing
mechanism is solution gas drive.
Waterflooding of the lower Muddy reservoir began in 1963, using a
line drive type injection pattern. Twenty-nine wells have been involved
in the waterflood since 1963. Thirteen of the wells remained active
as of December, 1979. Eight of the active wells and 8 of the shut-in
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wells are equipped for dual tubing and annulus injection. Between
1963 and the end of 1979, 26,804,160 barrels (1.1258 x 10^ gallons)
of produced Madison Limestone and Tensleep Sandstone water were injected
into the Lower Muddy Sandstone of Block "B".
Block "B" Dakota Unit
The Dakota reservoir of Block "B" encompasses 4,249 acres with
an average pay zone thickness of 27 feet. The primary reservoir
producing mechanisms were solution gas drive and partial water drive.
Average porosity and permeability of the Dakota "B" reservoir are 14
percent and 75 millidarcies, respectively.
A line drive pattern water injection project was started by
Continental Oil Company in September, 1961. By 1971, 36 injection
wells were involved in the Dakota "B" waterflood. Twenty-eight of
the wells are dual injectors. Ten of these dual injectors had been
shut-in by the end of 1979. As of December, 1979, 123,321,688 barrels
9
(5.1795 x 10 gallons) of produced Madison Limestone and Tensleep
Sandstone water had been injected into the Dakota reservoir. Injection
pressures ranged to a maximum of 3,040 psi.
Block "C" Lower Muddy Unit
The unit participating area of the lower Muddy Unit of Block "C"
is 4,736 acres. The lower Muddy reservoir covers 2,253 acres in the
southwest part of South Glenrock Field and lies adjacent to the lower
Muddy "B" project operated by Continental Oil Company. Average
thickness of the pay zone is 12 feet, porosity averages 14 percent and
permeability averages 82 millidarcies. Solution gas drive is the
primary producing mechanism of the reservoir.
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In June, 1961, a water injection project began with three wells
in a line drive pattern. By 1969, the project had been expanded to
29 wells and by 1974, all of the wells had been shut-in. A cumulative
g
total of 16,226,190 barrels (6.815 x 10 gallons) of Madison Limestone
water has been injected into the reservoir. Average injection well-
head pressures ranged from a minimum of 125 psi to a maximum of 2,800
psi.
Casing Record: Injection Well #49, T33N-R76W-33 deb, South Glenrock
Field, Block "C" Lower Muddy Unit, Total Depth =
6133 feet.
Casing Size Wt. (///ft) Amount
9-5/8" 32 241'
5-1/2" 15.5 6129'
Golden Prairie Field (1,891,522 bbls oil, 15,134 MCF gas; 1937-79)
East J-2 Unit
Golden Prairie Field is located in the central Denver Basin in
Township 16 North, Range 61 West, Laramie County. Oil was discovered
at Golden Prairie in 1937, and water injection started in 1969.
The East J-2 sand is a member of the Muddy Sandstone which occurs
at a depth of about 7,650 feet in the Golden Prairie area. Injection
of fresh shallow sand water and produced Muddy water amounted to 1,905,305
barrels (8.0023 x 10^ gallons) between 1969 and December, 1979. Only
two wells have been utilized for the injection project and both are
active according to Oil and Gas Commission statistics. Average injection
well pressures have ranged from 200 to 2,400 psi.
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Casing Record: Injection Well #5, T16N-R61W-22 bdb, Golden Prairie
Field, East J-2 Unit, Total Depth = 7798 feet.
Casing Size
8-5/8"
4-1/2"
Wt. (///ft)
24
11.6,10.5
Hole Size
12-1/4"
7-7/8"
Depth Set
350'
7850'
200 sacks
350 sacks
Cement
Grass Creek Field (159,521,582 bbls oil, 6,004,635 MCF gas; 1914-79)
Grass Creek Field is located on the southwest rim of the Bighorn
Basin. Oil was first discovered in June, 1914, with the completion of
a well in the Frontier Formation. One year later oil was found in the
Muddy Sandstone.
Structurally, Grass Creek is a large, crescent-shaped, double
plunging, northwest-southeast trending, asymmetrical anticline which
forms a topographic basin eroded in the soft Cody Shale, with a gentle
dip of 10 to 15° northeastward into the Bighorn Basin. The steep
southwest flank of the structure dips 35 to 40° into a major thrust
fault with about 2,000 feet of displacement and is on the convex or
mountainward side of the structure. Along the northwest side of the
structure there is a northeast trending, sharp, synclinal fold that
separates Grass Creek anticline from Little Grass Creek dome. The
basin is completely surrounded by a rim of ridge-forming Mesaverde
Formation except at 4 spots where it is cut by stream erosion.
Phosphoria-Tensleep Unit
The Phosphoria-Tensleep Unit of Grass Creek Field encompasses an
area of 3,016 acres in Township 46 North, Ranges 98 and 99 West, Hot
Springs County. The participating area is under federal, state, and
private ownership and is operated by Marathon Oil Company. The
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reservoir consists of permeable zones in the Phosphoria Formation and
Tensleep Sandstone. Black oil was discovered in both formations in
1922.
The Permian age Phosphoria Formation (often called Embar in oil
fields) is composed of dolomite, limestone and shale with a gross thick-
ness of up to 240 feet. It is divided into two distinct porosity zones:
the upper, which has a gross thickness of about 60 feet; and the middle,
with a gross thickness of about 45 feet. Only the dolomitic portion of
these zones is of reservoir quality and the porosity is predominantly
intercrystalline. The upper and lower zones have thicknesses of 22 and
14 feet, respectively. Average porosity is 18.5 percent and average
permeability is 20.4 millidarcies.
The Tensleep Sandstone is a Pennsylvanian sandstone of moderate to
poor sorting, subangular rounding and very fine to fine grain size with
a gross thickness of 250 feet. The reservoir has 6 significant porosity
zones which are separated by tight dolomite and sandstone over large
portions of the reservoir. Individual Tensleep pay zones have average
porosities and permeabilities which range from 10.6 to 15.6 percent and
15 to 152 millidarcies, respectively.
The reservoir energy for both the Phosphoria and the Tensleep is
provided, primarily, by a partial water drive. Water injection began
in 1975, with dual injection into both reservoirs. The injection wells
were arranged in an inverted 7-spot configuration around the produc-
ing wells. Water is supplied by producing Grass Creek wells and by
fresh water supply wells in shallow sands and the Madison Limestone.
By January, 1979, the injection field had expanded to 35 wells, 17 of
which are dual injectors. Twenty-three wells were active at that time
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and cumulative injection through all wells totaled 56,648,710 barrels
9
(2.3792 x 10 gallons) of water. Casing data were unavailable for
this writing.
Curtis Unit
The Upper Jurassic Curtis Formation, primarily a fine-grained red
sandstone, was discovered to be oil productive in the Grass Creek Field
area in 1952. The ensuing development resulted in 161 producing wells
in the Curtis sand. The Curtis Unit participating area includes 7,377
acres of federal, state, and private land. The underlying reservoir
includes 5,800 acres and has an average pay zone thickness of approxi-
mately 20 feet.
A pilot water injection project started in 1959, with the purpose
of supplementing the depleted reservoir pressure through the creation
of an artificial edgewater encroachment. One year later the project
was expanded to a full scale line drive pattern waterflood. According
to the most recent Oil and Gas Commission files on the Curtis Unit,
(January, 1979), 149,772,217 barrels (6.2903 x 10^ gallons) of Mesaverde
Formation, Madison Limestone, and Bighorn Dolomite water have been
injected through 74 wells, 39 of which were active injectors. Casing
data were unavailable for this writing.
Pre-Tensleep Unit
The Pre-Tensleep Unit includes 715 acres of federal, state, and
fee land in Township 46 North, Range 98 West, Hot Springs County. The
unit was formed to efficiently operate production from, and injection
into, the Darwin and Madison reservoirs. The Darwin reservoir covers
about 460 acres and has an average pay thickness of 19 feet. The
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underlying Madison Limestone is approximately 550 feet thick and is
composed primarily of dolomite with numerous zones of excellent porosity.
Water injection began in June, 1966, in the northeast part of the
Darwin reservoir. Seven wells, two of which were still active as of
January, 1979, had injected a cumulative volume of 3,473,681 barrels
g
(1.4589 x 10 gallons) of Madison Limestone and Bighorn Dolomite water
between 1966 and 1979. The average injection pressure during that
period was 550 psi.
Frontier Unit
The Frontier Formation was the first formation to produce oil at
Grass Creek Field. The initial well was completed in 1914 and by 1918,
421 wells had been drilled in 9 different sand zones within the
Frontier. The Frontier Unit covers 2,490 acres of federal, state, and
private land. The reservoir includes 1,660 acres and has an average
pay zone thickness of 55 feet.
A water injection pilot project started in 1960 in the third and
fifth Frontier sands, using water produced from Embar (Phosphoria)
Formation and Tensleep Sandstone wells. Because the produced water was
corroding pipes, water from the Mesaverde Formation, Madison Limestone,
and Bighorn Dolomite was substituted when the project was expanded to
a full scale peripheral waterflood. Sixty-nine wells, 9 of them dual
injectors, have been utilized in the project. As of January, 1977,
39 wells were still active and a cumulative volume of 86,592,914 barrels
9
(3.6369 x 10 gallons) of water had been injected during the course of
the project. Injection pressures have averaged between 400 and 565 psi
at the wellheads. Among the Frontier zones currently (January, 1979)
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receiving injected water are the "B" Frontier, the "C" Frontier and the
second, third, fourth, and fifth Frontier sands.
Green River Bend Field (9,015,674 bbls oil, 135,550,630 MCF gas; 1958-79)
Almy Birch Creek Unit
Since the injection projects at the Birch Creek Sand Unit and the
Almy T-5 Sand Unit have been shut-in since 1970, I have combined them
into one unit—the Almy Birch Creek—to briefly describe their water
injection history.
Green River Bend Field is located in Townships 26 and 27 North,
Ranges 112 and 113 West, in Lincoln and Sublette counties. The field
spans 15,025 acres of federal, state, and private land. Two water
injection projects were active in Green River Bend until 1970, when both
were discontinued.
The T-5 Sand Unit, operated by Belco Petroleum Corporation, began
injecting water into the Almy T-5 sand in September, 1964. The Almy
reservoir covers 270 acres and has an average pay zone thickness of
approximately 23 feet. Water injection wells were perforated at the
oil-water and oil-gas contacts. Injection at the oil-gas contact was
done to prevent encroachment of oil into the "dry" gas cap. Water for
the injection project was obtained from the upper sands of the Almy
member of the Wasatch Formation.
In 1967, water injection began at the Birch Creek Sand Unit, which
covers 185 acres of state and federal land. Injection was halted in
November, 1970.
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Cumulative injection for both units, through 1970, was 2,236,859
barrels (93,948,078 gallons) of fresh and produced water from the Almy
sand.
Casing Record: Injection Well #T—9, T27N-R113W-36 cca, Green River
Bend Field, Almy Birch Creek Unit, Total Depth =
2630 feet.
Casing Size Wt. (///ft) Hole Size Amount Cement Purpose
8-5/8" 24 11" 149' 60 sacks Surface
5-1/2" 14,15.5 7-7/8" 2557' 150 sacks Injection
Greybull Field (989,012 bbls oil; 1907-79)
Peay Unit
The Peay Unit of Greybull Field is located in Sections 8 and 17 of
Township 52 North, Range 93 West, Big Horn County. Oil was discovered
in the Greybull sand in 1907, and subsequently in the Peay sand. The
unit participating area includes 81.5 acres of private land.
Water injection into the shallow Peay reservoir (212-284 feet deep)
was started in 1967. Seven wells are actively injecting into the Peay
according to most recent (January, 1979) injection reports from Wilson
Oil Corporation. The cumulative volume injected was reported as
907,325 barrels (38,107,650 gallons) of produced Peay water.
Both injection wells of the Carlson Unit of Greybull Field have
been shut-in and injection data were unavailable for this writing.
Casing Record: Injection Well //3, T52N-R93W-17 cdd, Greybull Field,
Peay Unit, Total Depth = 375 feet.
Casing Size Wt. (///ft) Amount Purpose
13-3/8" 40 27' Conductor
9-5/8 24 99' Surface
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Casing Record: Injection Well //IP, T52N-R93W-17 cdc, Greybull Field,
Carlson Unit, Total Depth = 1287 feet.
Casing Size Wt. (///ft) Hole Size
8-5/8" 24 8-5/8"
2-7/8" 6.5 7-7/8"
Depth Set Purpose Cement
30' Surface -
1287' Injection 50 sacks
(tubing)
Grieve Field (29,614,836 bbls oil, 61,014,939 MCF gas; 1954-79)
Muddy Unit
The Muddy Unit of Grieve Field is located in Township 32 North,
Range 85 West, Natrona County. Until 1974, injection operations of the
Muddy Unit included water injection, gas injection, and salt water
disposal, all into the Muddy Sandstone. No injection reports have been
filed by the operator, Forest Oil Corporation, since 1974. At that time,
31,078,856 million cubic feet of dry gas had been injected at average
wellhead pressures ranging from 1,561 to 1,850 psi. Between 1970 and
O
December, 1974, 2,669,065 barrels (1.121 x 10 gallons) of produced
salt water from the Muddy Sandstone were disposed of in the same
formation. Injection pressures at the disposal wellhead, averaged over
6 month periods, covered a range between 1,600 and 1,952 psi.
Guthery Field (2,532,774 bbls oil, 318,343 MCF gas; 1963-79)
Minnelusa Unit
Oil was discovered in the Minnelusa Formation at Guthery Field in
October, 1963. Three distinct zones of porosity have been recognized
within the upper Minnelusa and each one is bounded by an updip facies
change or truncation by an Opeche Shale paleochannel. The Opeche
forms stratigraphic traps to the north and east while the south and
west sides of the reservoir are bounded by an oil-water contact. The
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average porosity of the Minnelusa pay zone, as determined by correlation
of core data with electric log analyses, is 18.9 percent. Permeability
ranges from 2 to 935 millidarcies and averages 184 millidarcies. The
primary reservoir producing mechanism is fluid expansion with minor
effects from water drive and gravity drainage. Maximum closure of the
Minnelusa reservoir above the interpreted oil-water contact is approxi-
mately 115 feet.
Water injection at Guthery Field started in 1968, and has totaled
O
3,864,802 barrels (1.623 x 10 gallons) of Fox Hills Sandstone water,
according to injection reports from December, 1979.
Half Moon Field (4,073,598 bbls oil; 1944-79)
Morrison Unit
The Morrison Unit of Half Moon Field is the site of a two well
salt water disposal system that began operating in 1971, and was shut-in
during July, 1979. Both wells are located in Section 23, Township 51
North, Range 102 West, Park County, and are perforated in the Embar For-
mation and Tensleep Sandstone at depths of 3,357 and 3,380 feet. When
the wells were shut-in, the cumulative volume of brine that had been
g
injected through both wells was 15,096,198 barrels (6.3404 x 10 gallons).
The maximum average injection pressure was 407 psi.
Casing Record: Salt Water Disposal Well #1, T51N-R102W-23 bca, Half
Moon Field, Morrison Unit.
Casing Size
7"
7"
Wt. (///ft)
23
13
Depth Set
3550'
3652'
3536-3665'
350 sacks
Cement
5" liner
22 sacks
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Halverson Ranch Field (12,621,988 bbls oil, 208,436 MCF gas; 1961-79)
Minnelusa Unit
Halverson Ranch Field is located on the east flank of the Powder
River Basin approximately 14 miles east-southeast of Gillette. Oil
was discovered in the Minnelusa Formation in 1962. The Minnelusa Unit
participating area includes 2,383 acres. The areal extent of the
Minnelusa reservoir is 1,750 acres. The Permian sands of the upper
Minnelusa "A" and "B" pay zones are clean, very fine-grained, porous,
permeable sands with occasional streaks of tight, anhydritic dolomite.
Average pay zone thickness, determined from sonic log analysis is 30
feet. Stratigraphic hydrocarbon entrapment is provided by truncation
of the Minnelusa sand on the eastern updip edge and by the oil-water
contact downstructure to the west. The "B" sand is the main producing
zone. The principal reservoir producing mechanism is solution gas
drive. It has been concluded that the reservoir is not being affected
by an active water drive since reservoir pressure is declining and no
significant encroachment of water has been detected. Estimates of
field average porosity and permeability are 13 percent and 56 milli-
darcies, respectively.
A line drive type waterflood system was started in 1967. The line
drive pattern was utilized to accommodate the elongated shape of the
Halverson Ranch Field, the producing well development pattern, and the
orientation of the Minnelusa sand structure. Between 1967 and December,
1979, 15 injection wells pumped 35,268,929 barrels (1.4813 x 10^
gallons) of fresh Fox Hills and produced Minnelusa Formation water into
the reservoir. Eleven of the wells were active at that time, 3 had
been temporarily shut-in and one well was permanently abandoned. Two
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holes were found in the tubing string of injection well #13 in 1976.
The holes were plugged immediately after the discovery was made with
no significant consequences.
Casing Record: Injection Well //13, T49N-R69W-17 cba, Halverson Ranch
Field, Minnelusa Unit, Total Depth = 8730 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Purpose Cement
10-3/4" 40.5 15" 40 Surface 645 sacks
5-1/2" 15.5,17 7-7/8" 15.5,17 Injection 500 sacks
Hamilton Dome Field (201,492,981 bbls oil, 82,698 MCF gas; 1918-79)
In September, 1918, a producing oil well was completed in the
Curtis sand of the Chugwater Formation, marking the discovery of the
Hamilton Dome Field. The field is located in Hot Springs County, about
20 miles northwest of Thermopolis on a local closure of the Thermopolis
anticline.
The anticline is a regional, east-west trending feature which
extends some 30 miles across the southwest corner of the Bighorn
Basin. The south flank of the structure dips as much as 90° into a
system of near vertical northwest-southeast trending thrust faults with
up to 4,500 feet of total displacement. Total structural closure is
approximately 2,000 feet into the saddle in the eastward plunge of
the anticline. A north-south trending thrust fault cuts the west
end of the anticline, separating the reservoir between Sections 10 and
15 in Township 44 North, Range 98 West.
Phosphoria Unit
The Phosphoria Unit of Hamilton Dome Field is located in Township
44 North, Ranges 97 and 98 West, Hot Springs County. Oil was discovered
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in the Phosphoria Formation in 1919. The Phosphoria is composed of
dolomitic limestone and dolomite interbedded with shale and anhydrite.
Gross thickness of the Phosphoria varies from 160 to 200 feet. The
productive part of the formation is found near the top and consists of
up to 60 feet of interbedded, microcrystalline, fossiliferous lime-
stones and dolomites. The thickness of the pay zone ranges from 4 to
47 feet and averages 28 feet thick. Porosities and permeabilities,
within the producing zone, are highly variable. Among 16 producing
wells in the Phosphoria reservoir which have core data considered
representative of the reservoir, porosity ranges from 5.9 percent to
35.1 percent and averages 21.5 percent. At the same wells, core
permeability (air permeability) ranges from .90 to 1,000 millidarcies
with an average of 85 millidarcies. However, well productivities
indicate that the effective permeability of the reservoir, due presumably
to fracturing, is significantly higher. The primary producing mechanism
in the reservoir is solution gas drive,but a limited water drive appears
to have influenced recovery in the vicinity of the west fault and, to a
lesser degree, around the structural flanks.
The Phosphoria Unit participating area involves 3,152 acres of
federal land. A large scale waterflood of the Phosphoria started in
1973, with 27 wells injecting. One of the wells is a dual injector
completed in the Curtis sand and the Phosphoria Formation. By December,
1979, three of the wells had been shut-in. Cumulative injection to that
9
time was 51,446,785 barrels (2.1608 x 10 gallons) of produced water
from the Tensleep Sandstone and Phosphoria Formation. Injection
pressures range to a maximum of 1,200 psi.
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Casing Record: Injection Well 11106, T44N-R98W-24 adb, Hamilton Dome
Field, Phosphoria Unit, Total Depth = 2915 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
8-5/8" 32 12-1/4" 200' 120 sacks
5-1/2" 15.5 7-7/8" 2915' 200 sacks
Federal Lease Unit
The Federal Lease Unit of Hamilton Dome Field is located in Township
44 North, Range 98 West, Hot Springs County. Water injection into the
Curtis sand of the Chugwater Formation started in 1970, and was dis-
continued in 1979, after 4,521,571 barrels (1.8991 x 10^ gallons) of
produced Tensleep Sandstone and Phosphoria Formation water had been
injected. Average injection wellhead pressures during the decade-long
project ranged from 10 to 450 psi.
Casing Record: Injection Well //13, T44N-R98W-11 bcc, Hamilton Dome
Field, Federal Lease Unit, Total Depth = 2714 feet.
Casing Size Wt. (It/ft) Hole Size Depth Set Cement
8-5/8" 28 13" 200' Solid to surface
5-1/2" 15.5 7-7/8" 2800' 485 ft3
Government 37697 Unit
The Government 37697 Unit water injection project was initiated
in 1970, with injection into the fourth Curtis sand. The fourth Curtis
reservoir covers about 240 acres with a net pay zone thickness of 14
feet. Water used for ""he injection project is supplied by producing
wells in the Curtis sand and Tensleep Sandstone. The most recent injec-
tion reports on file at the Oil and Gas Commission (June, 1976) indicate
that all five injection wells have been shut-in and that 3,091,118
g
barrels (1.2983 x 10 gallons) of produced water have been injected
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since the start of the flood. Average injection pressures have varied
between a minimum of 12 and a maximum of 1,200 psi. Reservoir responses
to the waterflood have supplied strong evidence for hydraulic communi-
cation between the fourth Curtis sand, the Phosphoria Formation, and
the Tensleep Sandstone.
Casing Record: Injection Well //1-7, T44N-R97W-7 ccb, Hamilton Dome
Field, Government 37697 Unit, Total Depth = 2950 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
8-5/8" 28 12-1/4" 209' 150 ft3
(regular)
5-1/2" 15.5 7-7/8" 2948' 110 ft3
(pozmix)
Government 54257 Unit
The Government 54257 Unit also involves a water injection project
in the fourth Curtis sand in the same area as the Government 37697 Unit
(T44N-R97 and 98W). The project started in 1966 and, as of June, 1976,
Q
4,233,736 barrels (1.7782 x 10 gallons) of produced Curtis sand and
Tensleep Sandstone water had been injected. The status of all four of
the injectors in June, 1976, was temporarily shut-in. Average injection
pressures at the wellhead ranged from 211 to 1,365 psi.
On August 30, 1972, a leak was reported in injection well //1—11
(T44N-R98W-11 cbc). Water was being injected at the rate of 692 barrels
per day at a wellhead pressure of 800 psi. Operators of the well
measured leakage to the surface at the rate of 321 barrels per day.
The holes were immediately plugged between 700 and 2,400 feet with 900
sacks of cement. Casing schedules for the injection wells were not
available for this writing.
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Hamm Field (5,406,007 bbls oil, 91,979 MCF gas; 1967-79)
Minnelusa Unit
Hamm Field is located in Sections 20 and 29, Township 51 North,
Range 69 West, Campbell County. Oil was discovered in the "B" sand
of the Minnelusa Unit in 1966. The "B" sand is the only oil producing
reservoir in the field.
The Minnelusa "B" sand reservoir is composed of clear, fine-grained,
well to moderately cemented sandstone and has an average thickness of
approximately 35 feet. The depth to the top of the Minnelusa Formation
ranges from 7,900 to 7,950 feet in the Hamm Field area. The reservoir
covers 391 acres with production limited by truncation of beds to the
east, north, and south and by an oil-water contact downdip to the west.
Porosity of the reservoir, 19.7 percent, was given as a weighted
average from core related log analyses. Core analyses of 212 samples
were used to determine the average permeability of 239 millidarcies.
The original recovery mechanism was fluid and rock expansion of the
reservoir and contiguous aquifer. Expansion of the aquifer and with-
drawal of fluids from the reservoir have resulted in water encroachment
and have provided additional reservoir energy.
Between 1972 and June, 1979, 5,155,713 barrels (2.1654 x 108
gallons) of water from the Fox Hills Sandstone were injected into the
"B" reservoir of the Minnelusa Formation. The average injection pressures
during the project have ranged from 1,175 to 2,637 psi. Both injection
wells were temporarily shut-in as of June, 1979.
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Casing Record: Injection Well //7, T51N-R69W-29 ba, Hamm Field,
Minnelusa Unit, Total Depths = 8094 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement Purpose
8-5/8" 24 12-1/4" 366' 300 sacks Surface
5-1/2" 17,20 7-7/8" 8094' 300 sacks Injection
Happy Springs Field (8,073,713 bbls oil, 4,572,780 MCF gas; 1950-79)
Dakota Unit
Happy Springs oil field is located along the southern margin of
the Sweetwater uplift in Township 28 North, Range 93 West, Fremont
County. Between 1950 and 1953, oil was discovered in the Tensleep,
Nugget, Muddy, and Lakota sandstones, the Phosphoria and Frontier
formations and the Dakota sand.
Water injection into the Dakota reservoir started in 1973, through
one well. Produced water from Frontier and Dakota wells has been the
source of injected water. Through December, 1979, 9,449,261 barrels
g
(3.9687 x 10 gallons) of water had been injected. The Dakota Unit
participating area covers 180 acres of federally owned land. The
current status of the Dakota Unit waterflood is temporarily shut-in.
Frontier Unit
The Happy Springs Field Frontier Unit includes 320 acres of
federal land operated by Amoco Production Company. The unit was divided
into "A," "B," and "C" areas prior to the beginning of the "A" and "C"
area water injection projects in 1958. Water injected into the "C"
area at the north end of the field from August, 1959 to August, 1964,
caused no response in the reservoir.
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The 236 acres of productive reservoir underlying the "A" area
have an average pay zone thickness of 14 feet. The "A" area injection
project began in 1958, and is currently shut-in. The system was not
winterized at the outset, resulting in a project shutdown between
September, 1958, and October, 1960. As of June, 1979, 962,559 barrels
(40,427,478 gallons) of surface water had been injected through one
well.
Lakota Unit
The Lakota Unit of Happy Springs Field consists of two active
salt water disposal wells. The disposal system was started in 1977,
injecting brines from producing wells into the Lakota Sandstone.
Detailed injection data were unavailable.
Hidden Dome Field (4,928,829 bbls oil, 22,295,371 MCF gas; 1918-79)
Tensleep Unit
Hidden Dome Field is located in the southwest corner of Township
48 North, Range 90 West, the southeast corner of Township 48 North,
Range 91 West, and the northwest corner of Township 47 North, Range 90
West, Washakie County. Waterflooding of the Frontier started in 1966,
but was shut-in by 1978.
Another waterflood project began in 1976, when the Tensleep
Sandstone was flooded with produced Tensleep water. Two injection wells
have been involved in the project. Cumulative injection totals were
not available from Oil and Gas Commission files at the time of this
writing.
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Hilight Field (66,475,815 bbls oil, 206,549,589 MCF gas; 1969-79)
Hilight Field is situated on the east flank of the Powder River
Basin of northeast Wyoming, approximately 30 miles south of Gillette.
The field was discovered in 1969, when a productive oil well was
completed in the Muddy Sandstone. The structure associated with the
Muddy trap is, essentially, a monocline with local, subtle nosing. No
structural closure is indicated by present subsurface control.
Regionally, the northeast flank of the Powder River Basin lies
in an area of marginal marine Muddy sand development. In Hilight Field
proper, uniformity of the Muddy stratigraphy and relatively low well
density at the present time precludes reliable geologic interpretation
of the Muddy depositional environment. Current data suggest a near-
shore bar or possibly a deltaic type sand deposition. The basic trap
mechanism is stratigraphically controlled and the range in well produc-
tivity results primarily from variable shaliness, intergranular
porosity-permeability and fractures, rather than any significant change
in sand thickness. Hilight Field was divided into 3 units to increase
the efficiency of production from the Muddy reservoir. Average porosity
and permeability of the reservoir are 20.3 percent and 104 milli-
darcies, respectively.
Grady Unit
The Grady Unit of Hilight Field was established in 1971, and covers
9,439 acres in Townships 45 and 46 North, Range 71 West, Campbell
County. Nine wells have been involved in the Grady Unit waterflood.
g
Currently (December, 1979), 10,653,728 barrels (4.4746 x 10 gallons)
of fresh and produced Muddy Sandstone water have been injected into
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the Muddy reservoir. Only four of the injection wells remain active.
The rest have been temporarily shut-in.
Casing Record: Injection Well #52, T45N-R71W-2 bd, Hilight Field,
Grady Unit, Total Depth = 9365 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
8-5/8" 24 13-3/4" 727' 600 sacks
5-1/2" various 7-7/8" 9365' 300 sacks
Jayson Unit
The Jayson Unit of Hilight Field covers most of Township 46 North,
Range 70 West, Campbell County. In 1972, injection into the Muddy
reservoir began in the Jayson Unit. By.1974, 15 wells were injecting
fresh and produced Muddy water. Ten wells were active as of December,
1979; however, cumulative injection data were not available from the
files of the Oil and Gas Commission.
Casing Record: Injection Well //W-0154562 2-3, T46N-R70W-31 acc,
Hilight Field, Jayson Unit, Total Depth = 9059 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
9-5/8" 36 13-1/2" 895' 650 sacks
5-1/2" 17 7-7/8" 9059' 350 sacks
Central Unit
The Central Unit of Hilight Field is by far the largest of the
three Hilight units, covering an area of 25,683 acres of federal, state,
and private land. Water injection started at the Central Unit in 1972
and in December, 1979, 32 of 48 existing injectors remained active.
Cumulative injection at that point totaled 204,183,889 barrels (8.5757
9
x 10 gallons) of fresh and produced Muddy Sandstone water. Average
injection pressures at the wellhead ranged from 875 to 2,348 psi.
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Casing Record: Injection Well #132—1, T45N-R70W-9 cd, Hilight Field,
Central Unit, Total Depth = 9060 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
9-5/8" 36 13-3/4" 716' 400 sacks
5-1/2" various 7-7/8" 9059' 300 sacks
Horse Creek Field (6,892,646 bbls oil, 216,947 MCF gas; 1942-79)
Horse Creek Unit
The Horse Creek Field discovery well was completed in the Lakota
Sandstone in 1942. The field covers 2,342 acres of federal and private
land in Townships 16 and 17 North, Range 68 West, Laramie County. Horse
Creek Field was unitized in 1943, with Mobil Oil Corporation as unit
operator. Water injection began in 1960, to supplement the existing
natural water drive of the Muddy reservoir, which was discovered
productive in the Horse Creek area in 1943.
The waterflood well configuration is semi-peripheral along the
downstructure, east side of the field. Performance of the reservoir
resulting from water injection has been satisfactory, though hindered
to some degree by a known reservoir fracture system. During the early
stages of the project, injected water moved into fractures along the
southeast edge of the field and watered out several of the structurally
lower wells on the southwest edge of the anticline. Waterflood response
in the north-central part of the reservoir has been better as a probable
result of more competent reservoir rock.
The Muddy reservoir includes 2,340 acres with an average pay zone
thickness of 23 feet. Cumulative water injection volumes between 1960
Q
and December, 1979, were 20,122,940 barrels (8.4516 x 10 gallons).
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Average injection pressures for the same period ranged from
vacuum to 2,010 psi. Nine wells are actively injecting.
Hunter Ranch Field (810,778 bbls oil, 670,638 MCF gas; 1968-79)
Muddy Unit
Hunter Ranch Field is situated on a monoclinal structure in the
northern Powder River Basin, one mile south of Ute Field and six miles
south of the Wyoming-Montana state line. The field was discovered
in 1968, and oil is produced from the Muddy Sandstone at an average
depth of 6,350 feet. The area covered by the Muddy Unit of Hunter Ranch
is 1,554 acres of federal, state, and private land. The productive
area of the reservoir is 1,081 acres.
The producing sand bodies of the Muddy Unit at Hunter Ranch Field
are part of a regional marine shoreline system deposited on and against
remnant high areas developed on the underlying Skull Creek Shale. The
sandstones of all 3 zones are very fine- to fine-grained, salt and
pepper sands with moderate to high clay content. The hydrocarbon trap
is stratigraphic in nature and limited by sand pinchouts to the east
and south, a permeability barrier to the north, and an oil-water contact
along the west edge. The reservoir's primary producing mechanism is
fluid expansion and solution gas drive with possible water drive
support on the west edge where the reservoir is in apparent hydraulic
communication with a downdip aquifer. Ultimate recovery of oil from
the Muddy reservoir is estimated to be about 30 percent of the original
oil in place with secondary recovery supplying nearly 45 percent of the
total recovery. Average porosity and permeability according to well
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log data, well productivity and drill stem information from the Muddy
sands, are 19.5 percent and 47 millidarcies, respectively.
Water injection into the Muddy reservoir started in 1976, and is
still active at three wells according to December, 1979 data. The
cumulative volume of water injected is 1,075,476 barrels (4.517 x 10^
gallons). Injection water is supplied by the Fox Hills Sandstone and
has been injected at pressures ranging from vacuum to 2,900 psi.
Isenhour Field (No production data available)
Isenhour Unit
As of January, 1980, Belco Petroleum Corporation had not yet begun
operation of a tertiary oil recovery project at the Isenhour Unit,
Township 29 North, Range 112 West, Sublette County. Plans for the
project call for the injection of a water/polymer solution into the
Almy "M-42" sand.
Approval for the project was recently given by the U.S. Geological
Survey. Three injection wells have been drilled and prepared for
injection, which is expected to begin within the next few months.
Joe Creek Field (1,269,420 bbls oil, 2,950,353 MCF gas; 1960-79)
Joe Creek Unit
Joe Creek Field encompasses an area of 1,544 acres of federal and
private land in the northern Powder River Basin, 3 miles west of Recluse
Field, and includes much of the area in Townships 56 and 57 North, Range
75 West, Campbell County. The discovery well was completed in the
Muddy Sandstone in 1969.
The geometry of the reservoir at Joe Creek Field suggests non-marine
point bar deposition. In general, there is a complete facies change from
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silt and shale on the west side to a thick sand reservoir on the east.
Further to the east, the reservoir sand tapers out. In between, the
Muddy reservoir is well defined and continuous. The contact at the
base of the Muddy reservoir appears to be an erosional unconformity.
The hydrocarbon trap is the result of a sand pinchout at the end of a
tidal channel deposit oriented in a northeasterly, updip direction.
Production history indicates that the reservoir initially produced by a
solution gas drive mechanism with little or no influx of water. Prior
to the start of the waterflood, it was estimated that 22 percent of the
original oil in place had been recovered by water injection. Average
pay zone thickness of the Muddy reservoir is 29 feet with an average
porosity of 12.2 percent.
Fresh water from the Fox Hills Sandstone and Lance Formation has
been injected into the Muddy reservoir since the waterflood began in
1975. As of December, 1979, all four of the injection wells had been
temporarily shut-in, having injected 1,074,764 barrels (4.514 x 10^
gallons) of water at average pressures ranging from 963 to 2,336 psi.
Joyce Creek Field (170,230 bbls oil, 10,323,625 MCF gas; 1958-79)
Dakota Unit
The Dakota Unit of Joyce Creek Field is the site of a one well salt
water disposal system operated by Hilliard Oil and Gas Company. The
initial injections of produced brine from the Dakota sand occurred in
1975. Between the start of injection and December, 1979, 141,378 barrels
(5,937,876 gallons) of salt water were injected into the Dakota sand
at a depth of 3,958 feet. Average porosity and permeability of the
Dakota in the Joyce Creek Field area are 17.4 percent and 140
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millidarcies, respectively. One analysis of produced Dakota brine
indicated a TDS concentration of 67,476 mg/1.
Casing Record: Salt Water Disposal Well #23, T15N-R103W-8 bd, Joyce
Creek Field, Dakota Unit, Total Depth = 4075 feet.
Casing Size Wt. (///ft) Depth Set Cement
9-5/8" 32 529' circ. to surface
5-1/2" 15.5 4075' cement top at 2620'
2-3/8" tubing
Kane Field (805,418 bbls oil, 52,849 MCF gas; 1966-79)
Minnelusa Unit
Salt water disposal to the Minnelusa Formation at Kane Field began
in 1978, through an injection well located in Section 9, Township 57
North, Range 70 West, Campbell County. The well is perforated in the
Minnelusa at a depth of 8,394 feet. Average injection pressures have
ranged between 500 and 550 psi. December, 1979, injection reports
indicate that 91,289 barrels (3,834,138 gallons) of brine have been
injected since the project started.
Casing Record:
Casing Size
5-1/2"
5-1/2"
5-1/2"
Salt Water Disposal Well //l, T57N-R70W-9 bd, Kane
Field, Minnelusa Unit, Total Depth = 8590 feet.
Wt. (///ft)
17
15.5
17
Depth Set
0-110'
1100-6400'
6400-8590'
Make
K-55
K-55
K-55
Cement
cement top at
7500'
Keyhole Field (8,315 bbls oil; 1967)
16 State Unit
Keyhole Field was discovered in 1967, when a producing well was
completed in the Fall River Sandstone. The field is located in Township
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50 North, Range 66 West, Crook County. The 16 State Unit involves all
state owned land on a 10 acre spacing schedule.
Water Injection to the Fall River Sandstone started in 1969, and
one well was still active as of January, 1979. Injection water is
supplied by a well in the Lakota sand. Between the start of injection
in 1969, and the end of 1970, 8,955 barrels (376,110 gallons) of water
were injected. The project resumed in 1977, and through January, 1979,
an additional 13,345 barrels (560,490 gallons) were injected. Average
injection pressures ranged from 275 to 350 psi.
Casing Record: Injection Well #7, T50N-R66W-16 acb, Keyhole Field,
16 State Unit, Total Depth = 577 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement Purpose
2-7/8" 6.5 6-1/4" 564' 40 sacks Injection
Kirby Creek Field (627,694 bbls oil; 1918-79)
Kirby Creek Unit
In 1944, oil was discovered in the Permian age Phosphoria Formation
of Kirby Creek Field at an average depth of about 3,400 feet. Kirby
Creek Field and the unit area of the same name are located on the south-
east flank of the Bighorn Basin, approximately 120 miles northwest of
Casper in Hot Springs County. The unit participating area covers 941
acres of federal, state, and private land with productive reservoir
underlying 772 acres of the unit.
Structurally, the field lies along the axis of the Zimmerman Butte
anticline, an asymmetrical, elongated, northwest-southeast trending
structure with about 350 feet of closure. The Zimmerman Butte anticline
is one of a series of parallel anticlines formed in the vicinity of
Kirby Creek during the Laramide Revolution.
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The Phosphoria Formation is a well fractured, dolomitic limestone
with an average effective porosity of 11.5 percent. Core analyses
indicate a matrix permeability of 2.4 millidarcies, whereas, fracture
permeability exceeds 1,000 millidarcies. An average effective perme-
ability to oil of 40 millidarcies was calculated using the radial flow
equation. The primary mechanism of production is a combination of
water drive and expansion of reservoir rock and fluid. The fractured
nature of the reservoir rock, high oil viscosity and high water satura-
tion make any type of secondary recovery project risky.
A pilot water injection project with one well was initiated in
1968, and 2,688,668 barrels (1.1292 x 10^ gallons) of water had been
injected by December, 1979. Injection pressure averages ranged from
980 to 1,250 psi.
Kirk Ranch Field (935,688 MCF gas; 1954-79)
Cloverly Unit
The natural gas storage project at Kirk Ranch Field, operated by
Northern Gas Company, is currently (December, 1979) shut-in. The
storage injection wells are located in Sections 6 and 7, Township 28
North, Range 92 West, and Section 1, Township 28 North, Range 93 West,
Fremont County. The project started in 1972, with injection to the
Cloverly Formation at a depth of about 2,500 feet. No further details
were available on the gas storage project from the files of the Oil and
Gas Commission.
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Kuehne Ranch Field (2,601,942 bbls oil, 21,324 MCF gas; 1965-79)
Kuehne Ranch Unit
Kuehne Ranch Field includes 480 acres in the northeast Powder
River Basin on a productive southeast to northwest trend in the Permo-
Pennsylvanian Minnelusa Formation, which extends from the Pleasant
Valley Garner Lake area on the southeast, to Wallace Field on the north-
west. The Minnelusa discovery well was completed in 1965. Average
depth to the productive upper Minnelusa zones is approximately 7,950
feet. Well drilling at Kuehne Ranch Field followed an 80-acre spacing
schedule.
Hydrocarbon entrapment is a result of updip truncation of the
productive sands. The primary producing mechanism of the Minnelusa
pay zones is fluid expansion. Core analyses of the Minnelusa "B"
zone indicate an average porosity and permeability of 14.7 percent and
64.1 millidarcies, respectively. The "C" zone has an average porosity
and permeability of 13.8 percent and 32.1 millidarcies, respectively.
A secondary recovery waterflood project started in 1969. In
1972, a second injection well was added. Water is obtained from a supply
well completed in the Fox Hills Sandstone. As of December, 1979,
O
3,354,703 barrels (1.409 x 10 gallons) of water had been injected
through both wells since the waterflood began. Average injection
pressures during that period ranged from 1,400 to 3,150 psi.
Casing Record: Injection Well #4, T51N-R70W-13 ab, Kuehne Ranch Field
Kuehne Ranch Unit, Total Depth = 8051 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement Purpose
8-5/8" 24 12-1/4" 234' 240 sacks Surface
5-1/2" 15.5,17 7-7/8" 8024' 300 sacks Injection
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Kuehne Ranch Southeast Unit
The unit participating area at Kuehne Ranch Field Southeast Unit
encompasses 1,240 acres of federal and private land in Township 51
North, Range 69 West, Campbell County. The productive area of the upper
Minnelusa reservoir underlies about 846 acres with an average thickness
of 18 feet. Average porosity and permeability within the reservoir are
15.8 percent and 100 millidarcies, respectively. The reservoir
temperature is 130°F.
Water injection began in 1975, at the Southeast Unit and injection
reports show that it continued until the latter part of 1976. By
January, 1977, the sole injection well had been shut-in after injecting
745,402 barrels (3.1307 x 10^ gallons) of fresh Fox Hills Sandstone
water into the upper Minnelusa oil reservoir. Injection pressures
averaged between 2,134 and 2,551 psi during that period.
Casing Record: Injection Well //l, T51N-R69W-19 abd, Kuehne Ranch
Field, Southeast Unit, Total Depth = 8185 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
5-1/2" 15.5,17,19,20 7-7/8" 8139' 500 sacks
Kummerfeld Field (8,498,335 bbls oil, 731,127 MCF gas; 1960-79)
Minnelusa Unit
The Minnelusa Unit of Kummerfeld Field is located about 20 miles
east-northeast of Gillette and comprises 1,040 acres of federal and
private land. Production from the Minnelusa Formation was first
established in 1969. The oil productive Minnelusa "B" sand is composed
of clear, fine-grained, well to moderately cemented sandstone. Esti-
mated field average porosity and permeability are 17 percent and 208
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millidarcies, respectively. The "B" reservoir is bounded by a porosity
pinchout to the north, south, and east, and by an oil-water contact
on the west and southwest sides. The primary producing mechanism is
fluid and rock expansion with some additional reservoir energy contri-
buted by solution gas drive and water encroachment from the southwest.
In 1973, a line drive type water injection project began. Fresh
water from the Fox Hills Sandstone and produced Minnelusa Formation
water are injected into the Minnelusa "B" reservoir at average pressures
ranging from 643 to 2,364 psi. December, 1979 data indicated that 5
wells were actively injecting and that a cumulative total of 7,659,659
g
barrels (3.2171 x 10 gallons) of water had been injected up to that
time.
Kummerfeld Field also utilizes a two well water disposal system.
Started in 1974, with a well perforated in the Lakota Sandstone, the
system is used to dispose of brines produced with oil from the Minnelusa
Formation. Another well which injects brine to the Minnelusa Formation
was added in 1978. As of July, 1979, 3,151,869 barrels (1.3238 x 10^
gallons) of salt water had been injected through the Lakota well alone.
Injection data for the Minnelusa well were not available.
Casing Record: Injection Well //A-l-32, T51N-R68W-32 abb, Kummerfeld
Field, Minnelusa Unit, Total Depth = 7698 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement Purpose
8-5/8" 24 12-1/4" 245' 210 sacks Surface
5-1/2" 15.5,17 7-7/8" 7697' 300 sacks Injection
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Water Quality Analysis - (Water sample from Minnelusa Formation at
producing well //30-1, T41N-R68W-30 add,
Kummerfeld Field, Minnelusa Unit, Depth of
well = 7730 feet, Perforations 7612-7616
feet.)
Cations (ppm) Anions (ppm)
Na 18,673 SC>4 5,465
K 480 Cl2 30,000 TDS = 57)194 ppm
pH = 6.7
Ca 1,300 HC03 610
Mg 976 H^S
Fe
LaBarge Field (20,213,281 bbls oil, 53,663,478 MCF gas; 1925-79)
Almy Unit
Oil was discovered in the Almy reservoir in 1924, via a well
completed at a depth of 560 to 572 feet. The Almy Unit comprises
1,400 acres of federal and private land. The principal producing zone,
between 650 and 1,100 feet, may be divided into four distinct sands.
The first is a persistent, 20-foot thick sand and the other three make
up a lower series of three sandstones that vary greatly in thickness
and persistence.
Some hydrocarbon trap separation in the field is believed to have
resulted from minor thrust faulting associated with the Hilliard fault
to the west. The Almy Unit is situated on the south high of a long,
narrow, north-south trending anticline with two distinct highs. About
two miles west of and parallel to the anticline is the Darby fault, a
major thrust fault of southwest Wyoming with an estimated stratigraphic
displacement of 43,000 feet in LaBarge Mountain. Prediction of oil
productive reservoirs is extremely difficult due to the variability in
trap conditions resulting from the thrusting. The primary reservoir
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energy is provided by solution gas and expansion of small gas caps along
the crest of the structure.
The Almy Unit was approved in 1949, with Texaco, Inc. as operator.
A pilot waterflood started in 1961, and was expanded to a full scale
project in 1965. Of 115 existing injection wells, 80 have been shut-in
as of December, 1979. Cumulative injection figures for the entire
waterflood project totaled 37,354,000 barrels (1.5689 x 10^ gallons)
of fresh water from a supply well in the alluvial aquifer and produced
Almy sand water.
In 1977, a salt water disposal well (T26N-R113W-3 c) began
injecting produced brines back into the Almy sand at a depth of 966
feet. Injection pressures have averaged between 700 and 850 psi since
the project began. Approximately 143,000 barrels (6,006,000 gallons)
of water have been disposed of through the well as of December, 1979.
A tertiary recovery program was undertaken by Texaco, Inc. in 1975,
with the injection of a water/surfactant mixture through four wells in
the Almy sand.
Casing Record: Injection Well //D134, T27N-R113W-34 bca, LaBarge
Field, Almy Unit, Total Depth = 1255 feet.
Casing Size Wt. (#/ft) Hole Size Depth Set Cement
4-1/2" 10.5,11.6 7-5/8" 1224' 450 sacks
2-3/8" 1109'
East LaBarge Field (444,764 bbls oil, 36,519,966 MCF gas; 1957-79)
East LaBarge Unit
East LaBarge Field is located in Township 27 North, Range 112 West,
Sublette and Lincoln counties. A secondary recovery waterflood project
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started in 1975, through one well. Injection into the Almy sand between
1975 and December, 1979, totaled 584,409 barrels (2.4545 x 10^ gallons)
of fresh and produced water from an alluvial well near the Green River
and from the Almy sand, respectively. Average injection pressures have
ranged from 2,200 to 2,500 psi during that period.
Casing Record: Injection Well #R—2, T27N-R112W-29 ad(be), East LaBarge
Field, East LaBarge Unit, Total Depth = 2843 feet.
Casing Size Wt. (///ft) Amount Perforations Purpose
8-5/8" 24 239' Surface
4-1/2" 9.5 2426' 2669-2671' Injection
11.6 416' 2690-2692' Injection
North LaBarge Field (690,020 bbls oil, 84,773,964 MCF gas; 1958-79)
Saddle Ridge Unit
Oil was discovered at North LaBarge Field in 1960, when Belco
Petroleum Corporation completed a well in the 5th Mesaverde sand. The
Saddle Ridge Unit was established in 1963, and comprises 2,680 acres
in Townships 27 and 28 North, Range 113 West, Sublette County.
The 5th Mesaverde sand reservoir consists of a massive Cretaceous
sandstone with some interbedded shale lenses. Overlying the sandstone
is a thick continuous shale member. Structurally, the reservoir is
part of a symmetrical anticline 1.5 miles long and .5 miles wide at
the north end of the larger LaBarge anticline. The productive area of
the reservoir covers about 350 acres with an average pay zone thickness
of 30 feet.
Water injection began in 1967, with water obtained from production
wells in the Mesaverde Formation. As of December, 1979, 7 of 8 existing
injection wells remained active and a cumulative total of 4,646,003
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barrels (1.9513 x 10 gallons) of water had been injected to the 5th
Mesaverde zone. Average injection pressures have ranged from 700 to
1,960 psi.
North LaBarge Field is also the site of a water disposal well
completed in the Almy sand at a depth of 1,316 feet. Between the
starting date of the disposal project and December, 1979, 20,388 barrels
(856,296 gallons) of produced brine have been injected to the Almy
sand.
Casing Record: Injection Well #2-4, T27N-R113W-4 bba, North LaBarge
Field, Saddle Ridge Unit, Total Depth = 2080 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
8-5/8" 24 11" 157' 85 sacks
5-1/2" 14 7-7/8" 2080' 235 sacks
Lance Creek Field (105,121,400 bbls oil, 140,313,523 MCF gas; 1918-79)
The Lance Creek Field is located just west of the center of
Niobrara County, approximately 30 miles west of the tri-state borders
of Wyoming, South Dakota, and Nebraska.
Oil was discovered at Lance Creek Field in 1918, when a well was
completed in the Wall Creek sand. Oil was later found in the Dakota,
Muddy, Lakota, and Sundance reservoirs, and in the Leo and Converse
sands of the Minnelusa Formation.
Structurally, the Lance Creek area is part of an elongated, curved,
asymmetric fold which lies in the southeast corner of the Powder River
Basin and occupies the west end of an anticlinal axis that extends
twelve miles to the east. The field is divided areally into east and
west portions by structural and lithological anomalies.
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A natural gas storage project at Lance Creek utilizes the Dakota
reservoir. As of December, 1979, only one of eight storage wells
remained active. Further details on the project were not available for
this report.
Lance Creek OPC Sundance Unit
The Lance Creek OPC Sundance Unit covers an area of 958 acres of
federal and state owned land in west-central Niobrara County. Oil was
discovered in the basal Sundance Formation in 1918. The original
mechanisms of production were solution gas drive and limited natural
water drive. The average pay zone thickness of the OPC reservoir is 26
feet with an average porosity of 14 percent.
The Continental Oil Company began a three-well pilot waterflood
project in the east end of the reservoir during 1960. The pilot was
expanded in 1961, to a full scale peripheral flood pattern over an area
of about 300 acres. Water for the injection project was produced
water from the Leo and Dakota sands, which was purchased from the
Marathon Oil Company.
The last year of active injection in the unit was 1972. As of
January, 1979, there were eleven shut-in injectors in the OPC Unit.
Cumulative injection into the reservoir is 8,614,352 barrels (3.6180
g
x 10 gallons) of water.
Muddy Unit
The Muddy Unit of Lance Creek Field includes 450 acres of federal
and private land. The Muddy reservoir covers 500 acres and has an
average pay zone thickness of 10 to 20 feet. Structurally, the reser-
voir is part of a faulted anticline. Faulting limits production on the
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east side of the unit. Average porosity and permeability figures from
1918 core analyses were 17 percent and 20 millidarcies, respectively.
Water injection was initiated in 1960, 42 years after the discovery
of oil in the Muddy reservoir. Produced water from the Leo sands was
used in a peripheral waterflood of the unit until 1973, when injection
was halted and wells were shut-in. There is a proposal to begin a new
water injection project in the Muddy which would sweep oil from the
southeast portion of the reservoir.
Morrison Unit
The Lance Creek Morrison Unit covers an area of 198.7 acres—
63.7 acres of federally owned land and 135 acres of privately owned
land. The Morrison reservoir includes 179 acres of pay zone sands that
average 21 feet in thickness. The average porosity of the Morrison
reservoir is 11 percent. Permeability within the sand varies from 0-400
millidarcies. Original reservoir energy was provided by a natural
water drive. Oil was discovered in a Jurassic sandstone in 1955,
and, with the aid of secondary recovery techniques, was still producing
oil as of December, 1979.
The Morrison waterflood project began in July, 1959, with two
injection wells. A third well was added later. The source of water
used in the injection project is the Leo sand, which consists of inter-
bedded layers of sand and dolomite with some chert.
First Sundance Unit
Available data on the First Sundance Unit of Lance Creek Field are
limited. The First Sundance reservoir includes an area of 455 acres
and has an average pay zone thickness of 25 feet.
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Water injection began in 1960, and continued into 1963. Eight
wells were active during that time and injected a cumulative total of
1,301,296 barrels (54,654,432 gallons) of water.
Typically, wells completed in the first Sundance reservoir employ
the following casing schedule to protect the well and penetrated forma-
tions from possible contamination:
Casing Record: Injection Well 0. Rohlff #15, T36N-R65W-32 cca, Lance
Creek Field, First Sundance Unit, Total Depth =
3628 feet.
Casing Size Amount Cement Perforations
10-3/4" 154' 85 sacks 2855-2870'
7" 3502' 125 sacks 3560-3618'
5" 186'
Basal Sundance Unit
Oil production from the Basal Sundance Unit of Lance Creek Field
began in 1935. The history of production, since 1935, has shown an
expansion of the gas cap and a slow decline in both reservoir pressure
and rate of production.
A pilot waterflood project began in 1952, with peripheral flooding
of the basal Sundance reservoir, and was expanded to a 20-well injection
system by 1962. Water for injection purposes was obtained from producing
wells in the Leo sand member of the Minnelusa Formation. The most
recent reported injections occurred in 1969, and brought the cumulative
total of water injected since the project began to 27,917,230 barrels
(1.1725 x 10^ gallons).
The basal Sundance reservoir covers an area of 1,715 acres with
an estimated pay horizon thickness of 64 feet. Core analyses of pay
11-130
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zone sand between 4,000 and 4,020 feet below the surface yielded an
average porosity of 21 percent and an average permeability of 338
millidarcies.
Leo Sand Unit
Initial water injections into the Leo sand reservoir of Lance
Creek Field occurred in 1962, through two wells which were temporarily
shut-in as of 1979. The injection program was initiated to supplement
declining reservoir pressure which was originally provided by a natural
water drive. Water used for injection purposes was supplied by producing
wells in the Leo sand reservoir.
Casing Record: Injection Well Carrie Putnam //18, T35N-R65W-4, Lance
Creek Field, Leo Sand Unit, Total Depth = 5465 feet.
Casing Size Amount Cement
11-3/4" 280', 7" 175 sacks
7" 5368', 8" 500 sacks
2-1/2" 5453'
First Converse Unit
The Permian Converse sand member of the Minnelusa Formation
has an effective pay zone thickness of 30 feet. Average porosity and
permeability of the Converse reservoir are 16 percent and 3 millidarcies,
respectively. Oil was discovered in the Converse sand in 1936.
A water injection project, which eventually expanded to six wells,
was utilized for pressure maintenance within the reservoir. Water for
the project was obtained from producing wells in the Leo reservoir.
As of 1979, all of the injectors were temporarily shut-in.
11-131
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Lander Field (8,381,577 bbls oil, 1909-79)
Phosphoria Unit
Lander Field is situated on a narrow, north-south trending
anticline in Sections 13, 24, and 25, Township 2 South, Range 1 East,
and Sections 19 and 30, Township 2 South, Range 2 East of the Wind River
Indian Reservation and in Section 4, Township 33, North, Range 99 West,
Fremont County. The Phosphoria Unit participating area comprises
562.55 acres of tribal Indian land, 469.31 acres of allotted Indian
land and 396.46 acres of privately owned fee land. The discovery well
at Lander Field was completed in the Phosphoria Formation in 1909.
Structurally, the field lies along the Lander anticline, the major
line of folding that includes the Dallas and Derby Dome fields to the
southeast. The total closure of the anticline is at least 1,500 feet.
A pilot waterflood project was approved in 1964, using produced
water from the Tensleep Sandstone. Thirty-one of 36 injection wells
were actively injecting as of December, 1979, when the cumulative volume
of water injected since the project started was 29,173,151 barrels
Casing Record: Injection Well it60, T33N-R99W-4 dca, Lander Field,
(1.2253 x 10^ gallons).
Phosphoria Unit, Total Depth = 1900 feet.
Casing Size
13-3/8"
8-5/8"
5-1/2"
Wt. (///ft)
Hole Size
17-1/2"
12-1/4"
7-7/8"
Depth Set
Cement
38
24
14,15.5
43'
180'
1899'
550 sacks
200 sacks
30 sacks
11-132
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Casing Record: Injection Well #123, T2S-R2E-30 bba, Lander Field,
Phosphoria Unit, Total Depth = 1865 feet.
Casing Size
8-5/8"
5-1/2"
Wt. (///ft)
24
14
Hole Size
12-1/4"
7-7/8"
Depth Set
213'
1523'
260 sacks
200 sacks
Cement
Lazy "B" Field (1,124,238 bbls oil, 3,643,373 MCF gas; 1969-79)
Muddy Unit
Lazy "B" Field was initially developed in 1969, following the
completion of the discovery well in the Muddy Sandstone. The field is
located approximately ten miles west of Gillette and includes 3,953
acres of federal, state, and private land called the Muddy Unit.
The Lower Cretaceous Muddy Sandstone is found at an average depth
of 9,670 feet and dips to the southwest at about 100 feet per mile.
Compositionally, the Muddy consists of interbedded sandstone, siltstone
and shale, ranging in thickness from 100 to 130 feet in the Lazy "B"
Field area. Fifty-two core samples at the Muddy reservoir were analyzed
and indicated an average porosity of 13.6 percent. Average core
permeability to air is 14.1 millidarcies with a maximum of 115 milli-
darcies. Estimated temperature of the reservoir is 220°F. Primary
production from the reservoir is controlled by solution gas drive
energy. A small gas cap is also present within the Muddy sand.
Injection of fresh water from the Fox Hills Sandstone and Lance
Formation into the Muddy Sandstone reservoir started in 1975. Five
active injection wells at the Muddy Unit had injected a cumulative
g
volume of 3,848,343 barrels (1.6163 x 10 gallons) of water as of
December, 1979. Through the duration of the project, injection pressures
have averaged between 500 and 2,525 psi at the wellhead.
11-133
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Lightning Creek Field (2,223,236 bbls oil, 863,205 MCF gas; 1949-79)
Newcastle Unit
Lightning Creek Field is situated on a broad, east-west trending
anticlinal nose which plunges westward at 7.5 degrees about six miles
southwest of Lance Creek Field in Niobrara County. The discovery well
was drilled to the basal Sundance Formation in 1949. In April, 1951,
an oil producing well was completed in the Newcastle Sandstone, the
top of which was logged at 1,447 feet. The 1,577 acre productive area
of the Newcastle reservoir was unitized in 1965, as a pilot operation
by Marathon Oil Company.
The hydrocarbon trap of the Newcastle sand at Lightning Creek
Field is formed by an updip sand pinchout and an apparent oil-water
contact along the downdip productive boundary. The downdip water table
has remained virtually stationary during the productive life of the
field and no encroachment into the producing area is evident. The
extreme southern limit of the field is controlled by a loss of perme-
ability in the sand as a result of clay filling. Oil expansion drive
was the principal source of reservoir energy during primary production.
However, when coupled with the low permeability of the reservoir, the
oil expansion energy was insufficient to provide adequate natural
production. To increase the reservoir's productivity, sand fracturing
was necessary for nearly all of the wells in addition to the commence-
ment of a water injection project in the Newcastle Formation.
The Newcastle reservoir is composed of a hard, fine-grained, silty
to shaley sand which varies in thickness from 0 to 12 feet of net
floodable sand. Average porosity and permeability of the Newcastle
11-134
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are 19.5 percent and 10 millidarcies, respectively. The reservoir
includes only 600 acres of the unit participating area.
The Newcastle Unit waterflood began in November, 1964, with two
injection wells. Water for the project is obtained from a surface
runoff pond and from a well completed in the White River Formation at
a depth of 350-400 feet. During the first nine years of the project,
g
4,222,579 barrels (1.7735 x 10 gallons) of fresh and produced water
were injected into the Newcastle Sandstone. Average injection pressures
have ranged from 135 to 900 psi. Well injection data were not on file
at the Oil and Gas Commission for reports after January, 1974.
Little Buffalo Basin Field (83,598,844 bbls oil, 115,733,562 MCF gas;
1914-79)
Tensleep Unit
Little Buffalo Basin Field is located on the southwest flank of the
Bighorn Basin in Townships 47 and 48 North, Range 100 West, Park County,
and Township 47 North, Range 99 West, Hot Springs County. Gas was
discovered in the Frontier Formation between 1,750 and 1,792 feet in
November, 1914. Oil production from the Tensleep Sandstone was dis-
covered in 1943. In September, 1944, oil was discovered in the Phosphoria
Formation. The field was unitized in 1931.
Structurally, the field is situated atop two elliptical domes (East
and West Buffalo domes) of an asymmetrical, north-south trending anti-
cline which encompasses 1,500 productive surface acres. Five reservoirs
on the structure produce hydrocarbons.
The Tensleep Sandstone reservoir at Little Buffalo Basin Field has
average porosity and permeability of 14 percent and 61.3 millidarcies
(air permeability), respectively. However, the reservoir is quite
11-135
-------
heterogeneous and permeability ranges from 0 to 1,150 millidarcies. As
a result, primary production from the Tensleep reservoir left numerous
pockets of undepleted, tight, reservoir rock.
Secondary recovery by gas injection started in June, 1958. A
water injection project began in April, 1966, using produced water from
the Embar and Tensleep reservoirs. Of the 58 existing injection wells
(1979 data), 12 are injecting water into both the Embar and Tensleep
reservoirs, 25 are injecting gas into both reservoirs, six are injecting
gas to the Tensleep and 15 are injecting water into the Tensleep.
Fifty of the wells were still active as of December, 1979, though status
changes occur quite frequently as a function of field production.
Recent injection reports (December, 1979) indicate that 115,633,559
9
barrels (5.6158 x 10 gallons) of water have been injected since the
waterflood began. Injection pressures have averaged between 140 and
1,915 psi during that time.
Casing Record: Injection Well #57, T47N-R100W-12 dbc, Little Buffalo
Basin Field, Tensleep Unit, Total Depth = 4807 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
10-3/4" 32.75 15" 314' 300 sacks
7" 20 8-3/4" 4806' 175 sacks
(1st stage)
425 sacks
(2nd stage)
Embar Unit
The Embar Unit at Little Buffalo Basin Field is located in Township
47 North, Ranges 99 and 100 West, Hot Springs County. In September,
1944, oil was discovered in the Embar (Phosphoria) Formation.
Water injection into the Embar reservoir began in 1972. As of
December, 1979, 43 injection wells had been in operation since the
11-136
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project started. Thirty-two of those wells are still active. Sixteen
injectors are capable of dual water injection to the Embar and Tensleep
reservoirs. Eleven wells are equipped for dual water and gas injection
and six wells are strictly gas injectors to the Embar reservoir. By
the end of 1979, a cumulative total of 31,864,186 barrels (1.3383 x 10^
gallons) of water had been injected through all of the injection wells.
Cumulative data on gas injection wells were not available. Until
October, 1979, the waterflood project utilized fresh water from the
Madison Limestone. From November, 1979, to the present, produced Embar
Formation and Tensleep Sandstone water was used.
Casing Record: Injection Well #105, T47N-R99W-6 cca, Little Buffalo
Basin Field, Embar Unit, Total Depth = 4905 feet.
Casing Size Wt. (///ft) Amount Perforations Purpose
10-3/4" 45 247' Surface
7" 26 29' 4627-4742' Injection
23 4895' 4757-4808' Injection
20 16.5' .4822-4882' Injection
Northwest Dome Unit
A dual water injection well to the Embar and Tensleep reservoirs
was put into operation in 1971. The well is located in the Northwest
Dome Unit of Little Buffalo Basin Field in Township 47 North, Range 100
West, Section 3, Hot Springs County.
The Embar Formation and Tensleep Sandstone are encountered at depths
of 4,659 and 4,891 feet, respectively. Cumulative injection between
1971 and December, 1979, amounted to 4,240,619 barrels (1.7811 x 10^
gallons) of produced Embar/Tensleep water. Average injection pressures
ranged from 50 to 2,250 psi during that period.
11-137
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Casing Record: Injection Well #12, T47N-R100W-3 ac(ad), Little Buffalo
Basin Field, Northwest Dome Unit, Total Depth = 5150 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
9-5/8" 43.5 12-1/4" 312' 300 sacks
5-1/2" 15.5 7-7/8" 5147' 175 sacks
450 sacks
Little Mitchell Creek Field (5,125,594 bbls oil, 18,247 MCF gas; 1967-79)
Minnelusa Unit
Little Mitchell Creek Field is located along the east flank of the
Powder River Basin, about 15 miles northwest of Moorcroft, Wyoming.
The Minnelusa Unit comprises 2,800 acres of federal (2,240 acres), state
(320 acres), and private fee (240 acres) land.
The productive limits of the Minnelusa reservoir are controlled by
an updip pinchout of porous sand which correlates with a thickening of
the Opeche Shale to the north and east. The boundaries to the south and
west are defined by the downdip oil-water contact.
In 1969, injection of fresh water from the Fox Hills Sandstone
into the Minnelusa Formation commenced through one well. No additional
wells have been added to the waterflood project since 1969. According
Q
to December, 1979, injection reports, 5,597,881 barrels (2.3511 x 10
gallons) of water had been injected through well //13-14,1 at average
pressures of 100 to 600 psi.
Casing Record: Injection Well //13-14,1, T52N-R69W-14 cb, Little
Mitchell Creek Field, Minnelusa Unit, Total Depth =
7623 feet.
Casing Size Wt. (///ft) Depth Set Cement
10-3/4" 32.75 558'
4-1/2" 11.6,10.5 7618' 400 sacks
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Little Sand Draw Field (6,207,625 bbls oil; 1949-79)
Nelson Unit
A two well salt water disposal system started in 1972, at the
Nelson Unit of Little Sand Draw Field, Township 44 North, Range 96
West, Hot Springs County. Brine produced with oil from wells at Little
Sand Draw Field is injected to the Phosphoria Formation and Tensleep
Sandstone at a depth of about 5,836 feet. Cumulative injection through
both wells since the project began was 13,211,404 barrels (5.5488 x
g
10 gallons) of brine as of December, 1979. The maximum average
injection pressure was 380 psi.
Lost Soldier Field (181,554,016 bbls oil, 73,412,623 MCF gas; 1916-79)
The Lost Soldier oil and gas field occupies a highly faulted,
slightly elliptical dome adjacent to and en echelon with the west end
of the Wertz-Mahoney-Ferris anticline. The Mesaverde Formation forms
hogback escarpments that surround part of the field. The Niobrara
Shale is exposed on the crest of the structure at an average elevation
of 6,900 feet. The Lost Soldier dome has an independent closure of
approximately 3,500 feet. Dips on the basinward southwest flank reach
45 degrees, while on the mountainward northeast flank, dips reach a
maximum of 35 degrees. Lost Soldier Field is located in Township 26
North, Range 90 West, Sweetwater County. The field was discovered in
1916 when a well was completed in the Wall Creek sand and produced
200 barrels of oil per day.
Tensleep Unit
Oil was discovered in the Tensleep Sandstone at Lost Soldier Field
in 1930, with the completion of a well between 3,942 and 4,009 feet
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-------
deep. By January, 1968, 34 other production wells had been completed
in the same formation. The Tensleep reservoir in this area covers
1,488 acres of federally and privately owned land.
In order to maintain reservoir pressure, a water injection project
was initiated in the Tensleep in 1955. The waterflood has expanded to
become the largest of the three injection projects at Lost Soldier Field
with 42 wells, 40 of which are currently (December, 1979) active.
The Tensleep reservoir includes 1,193 acres with an average pay
zone thickness of 250 feet. The primary reservoir producing mechanism
is a combination of water drive, solution gas drive, and gravity
drainage. The Tensleep Sandstone was unitized in 1962, under the opera-
tion of Amoco Production Company.
Between 1955, when water injection began, and December, 1979,
9
167,421,046 barrels (7.0316 x 10 gallons) of fresh ground water from
the Battle Spring, the Sundance, Madison, and Tensleep formations, and
produced Flathead Sandstone water were injected into the Tensleep at
average injection pressures between 0 and 2,860 psi.
Casing Record: Injection Well //48, T26N-R90W-11 bab, Lost Soldier
Field, Tensleep Unit, Total Depth = 6572 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
13-3/8" 48 17-1/4" 584' 300 sacks
7" 26 9" 6572' 580 sacks
Cambrian Unit
The first commercial production of oil from rocks of Cambrian age
in the Rocky Mountain region occurred in June, 1948, with the completion
of a well in the Flathead Sandstone at Lost Soldier Field. The Flathead
11-140
-------
is approximately 700 feet thick in the Lost Soldier area and is composed
primarily of arkosic sandstone. The productive reservoir within the
Flathead is a 200-foot thick porous bed near the base of the formation.
The reservoir covers 670 acres and has an average pay zone thickness of
94 feet. The initial reservoir producing mechanism was a limited water
drive and fluid expansion.
The Cambrian reservoir was unitized in 1962, and two years later
a water injection pressure maintenance project began. The unit
encompasses 938 acres of federal and private land. Five dual water
injection wells were active in the Cambrian Unit by 1971. As of
December, 1979, two of the wells had been permanently shut-in and
9
cumulative injection amounted to 28,217,966 barrels (1.1852 x 10
gallons) of produced water from the Sundance, Flathead, Madison, and
Tensleep. Average injection pressures for the period ranged from a
vacuum to 2,875 psi.
Madison Unit
The Madison reservoir was unitized in September, 1962, with Sinclair
Oil and Gas Corporation as unit operator. The unit is currently operated
by Amoco Production Company. The unit participating area encompasses
908 acres of federal and private land. The underlying Madison reservoir
includes 709 acres with an average pay zone thickness of 188 feet.
The Madison Limestone at Lost Soldier Field is nearly 300 feet
thick with the best reservoir rock occurring near the base of the
formation. Oil was discovered in the Madison in January, 1948, in a
well completed at a depth between 5,398 and 5,863 feet. The initial
reservoir producing mechanism was water drive. Four dual water
11-141
-------
injection wells have been utilized for pressure maintenance since the
waterflood project began in 1965. By December, 1979, 17,382,630
g
barrels (7.3007 x 10 gallons) of produced water from the Sundance,
Flathead, Madison, and Tensleep had been injected to the Madison
reservoir at average pressures ranging from a vacuum to 2,500 psi.
L-X Bar Ranch Field (790,854 bbls oil, 2,864,396 MCF gas; 1973-79)
L-X Bar Ranch Unit
The L-X Bar Ranch Field encompasses 2,003 acres of federal, state,
and private land in Townships 55 and 56 North, Range 75 West, Campbell
County. The field was discovered in 1973, with a producing well com-
pleted in the Muddy Sandstone. The Muddy sand in the L-X Bar Ranch
area is a narrow sand body oriented in a northeast-southwest direction.
The producing reservoir covers 541 acres and has an average thickness
of 15.1 feet. The average porosity of the producing sands is 16.5
percent.
A secondary recovery waterflood was placed in operation in 1975,
continued for three years and was subsequently shut-in. During that
period, 1,274,919 barrels (5.3547 x 10^ gallons) of water from the
Muddy and Fox Hills sandstones were injected into the Muddy reservoir.
Average injection pressures over the life of the project ranged from
1,750 to 2,450 psi.
Casing Record: Injection Well it8-81, T56N-R75W-35 ccd, L-X Bar Ranch
Field-Unit, Total Depth = 8000 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement Purpose
8-5/8" 24 12-1/4" 325' 235 sacks Surface
5-1/2" 17,15.5 7-7/8" 8000' 150 sacks Injection
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Mac Field (90,975 bbls oil, 1,572 MCF gas; 1970-79)
Condon-Federal Unit
In 1979, a single well salt water disposal system at Mac Field
began injecting salt water from Minnelusa Formation producing wells
back into the Minnelusa. Reported TDS concentrations of produced
Minnelusa water at Mac Field are approximately 55,500 mg/1. The
injection well is located in Section 28, Township 52 North, Range 69
West, Campbell County. Cumulative injection data were not yet avail-
able at the time this report was written.
Casing Record: Salt Water Disposal Well #2, T52N-R69W-28 cc, Mac Field,
Condon-Federal Unit, Total Depth = 7816 feet.
Casing Size
8-5/8"
5-1/2"
Wt. (///ft)
24
15.5,17
Hole Size
12-1/4"
7-7/8"
Depth Set
225'
7816'
Cement
Circulated
60 sacks
Madden Field (222,777 bbls oil, 125,437,516 MCF gas; 1969-79)
Madden Deep Unit
Monsanto Company began operating a single well salt water disposal
system at Madden Field in 1979. The well is located in Section 31,
Township 39 North, Range 90 West, Fremont County, and is perforated at
a depth of 5,922 feet in the lower part of the Fort Union Formation.
Injection data were not yet available for the project as of December,
1979.
Casing Record: Salt Water Disposal Well #1-12, T39N-R90W-31 be, Madden
Field, Madden Deep Unit, Total Depth = 11,422 feet.
Casing Size
5-1/2"
5-1/2"
5-1/2"
Wt. (///ft)
20
17
17
Depth Set
2113'
7332'
11422'
Cement
1740 sacks
11-143
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East Mahoney Field (10,757,623 MCF gas; 1923-79)
Dakota Unit
Very little information on the natural gas storage project at the
Dakota Unit of East Mahoney Field is available from Oil and Gas
Commission files. Gas is reportedly stored in the Dakota, Sundance, and
Muddy sands at unreported depths. East Mahoney Dome Field is located
in Township 26 North, Ranges 87 and 88 West, Carbon County.
Manning Field (1,172,470 bbls oil, 1,895,280 MCF gas; 1970-79)
//I Federal 44-17 Unit
In addition to the 23 producing wells at Manning oil and gas field,
there is a single well salt water disposal system which is completed
in the Parkman sand at a depth of 8,416 feet. The system began operating
in 1978, and by June, 1980, 343,739 barrels (14,437,038 gallons) of
produced brine had been injected to the Parkman. The average
injection pressure has ranged from 0 to 1,500 psi during that time.
Casing Record: Salt Water Disposal Well //1, T39N-R73W-17, Manning
Field, //I Federal 44-17 Unit, Total Depth = 8577 feet.
Casing Size Wt. (///ft) Depth Set Cement
8-5/8" 24 1022' 525 sacks
5-1/2" 17 8577' 250 sacks
Maverick Springs Field (10,987,067 bbls oil; 1917-79)
Chatterton Unit
Maverick Springs Field is located in Township 6 North, Range 2 West,
Fremont County. A salt water disposal well, located in Section 15 of
the same township and range, was activated in 1971, to inject produced
brines into the Embar Formation. As of December, 1979, 3,912,413
g
barrels (1.6432 x 10 gallons) of brine had been injected.
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McDonald Draw Field (7,468,812 bbls oil; 32,842,380 MCF gas; 1960-79)
The Almy sand, usually considered as the basal member of the
Wasatch Formation, is the principal producing zone of McDonald Draw
Field. More than 20 producing sands have been found in the Almy member
within the 18,742 acre area of the McDonald Draw participating area.
The field was discovered in 1960, with the completion of a gas producing
well in the Wasatch Formation between 3,000 and 3,035 feet. The initial
oil producing wells in both the "south oil pool" and the "north oil
pool" were completed in 1961.
In the "south pool" area, waterflood projects in the M-9 and M-13
sands began in October, 1964. By January, 1966, three more sands of
the Almy member, the M-20, M-42, and M-47 sands, were included in the
fieldwide water injection project.
Almy M-9 Unit
The Almy M-9 reservoir is found at depths between 3,058 and 3,204
feet in the McDonald Draw area. The reservoir covers 200 acres and has
an average pay zone thickness of 12 feet. Porosity and permeability
average 22 percent and 34 millidarcies, respectively. Cumulative
injection through five dual injection wells was 4,116,849 barrels
g
(1.7501 x 10 gallons) as of December, 1979. Injection water is supplied
by producing wells in the Almy sands. Two of the five wells were still
actively injecting.
Almy M-13 Unit
The Almy M-13 sand lies stratigraphically above the M-9 sand in the
McDonald Draw area and includes 350 acres of reservoir rock with an
average pay zone thickness of 10 feet. Isopach contours based on well
11-145
-------
logs indicate that the M-13 Unit reservoir is actually a pair of inter-
connected lenses. Six injection wells have operated in the M-13 Unit
over the lifetime of the project. Five of those wells are dual injectors
in the M-9 and M-13 sands. However, only one of the wells, a dual
injector, is still active. As of December, 1979, 4,292,331 barrels
g
(1.8028 x 10 gallons) of produced water had been injected to the M-13
sand at average pressures between 1,410 and 2,600 psi.
Almy M-17 Unit
The Almy M-17 Unit is the site of the sole salt water disposal
well of McDonald Draw Field. Injection of produced brine through well
#17 (T28N-R112W-29 dc) started in 1968. Through January, 1971, 280,514
barrels (1.1781 x 10^ gallons) of water had been disposed of in a two-
foot thick lense of Almy sand at a depth of 3,103 feet. Average
injection pressures have ranged from 1,000 to 2,000 psi.
Casing Record: Disposal Well //17, T28N-R112W-29 dc, McDonald Draw
Field, Almy M-17 Unit, Total Depth = 3240 feet.
Casing Size Wt. (///ft) Depth Set Cement
4-1/2" 9.5,10.5,11.6 3240' 175 sacks
Almy M-20 Unit
Water injection to the Almy M-20 Unit of McDonald Draw Field
started in December, 1965, through three wells that are dually perforated
in the M-20 and M-47 sands. The project was later expanded to include
eight wells, six of which are dual injectors.
The Almy M-20 reservoir encompasses 480 acres with an average pay
zone thickness of 16 feet. Porosity and permeability within the reser-
voir sand average 18 percent and 52 millidarcies, respectively. Between
11-146
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December, 1965, and December, 1979, 8,674,203 barrels (3.6432 x 10^
gallons) of Almy sand water were injected. Average injection
pressures were 1,320 to 2,550 psi.
Almy M-42 Unit
The Almy M-42 sand reservoir covers an area of 260 acres with an
average pay zone thickness of 10 feet. The productive boundaries of
the reservoir are controlled by permeable sand pinchouts on the north,
south, and west, and by an oil-water contact to the east. The primary
drive mechanism of the reservoir is solution gas expansion.
Water injection began in January, 1966, through two wells. A
third well was added in 1969. Cumulative injection to December, 1979,
was 1,922,647 barrels (8.0751 x lO'' gallons) of fresh and produced
Almy sand water. Injection pressures averaged 1,375 to 2,400 psi over
the 13 year period. Only one of the wells (#42) is still on active
injection status.
Almy M-47 Unit
The Almy M-47 reservoir has the largest sand volume of the six
Almy sand units at McDonald Draw Field with water injection projects.
The reservoir spans 480 acres with an average thickness of 30 feet.
Injection of fresh and produced Almy water began in December,
1965, through three wells dually perforated in both the M-20 and M-47
sands. Water is injected to the deeper M-20 sand through the tubing
while injection to the M-47 sand is through annular perforations. Two
more dual injectors were added in 1969 and 1973, and a third well,
perforated only in the M-47 sand, was completed in 1972. Five of the
six wells were actively injecting through December, 1979, when the
11-147
-------
cumulative injected volume of water was 9,182,599 barrels (3.8567 x
g
10 gallons). Average injection pressures have varied between a minimum
of 600 psi and a maximum of 2,600 psi.
Almy M-50 Unit
The Almy M-50 Unit is located in Townships 28 and 29 North, Range
112 West, Sublette County. Water injection to the M-50 sand began in
1972, through three dual injection wells. Cumulative injection between
1972 and December, 1979, totaled 847,654 barrels (3.5601 x 10^ gallons)
of fresh and produced water from the Almy sand at injection pressures
that averaged between 1,665 and 2,600 psi. One injection well was
added to the project in 1974. Two of the four wells have been shut-in
since then.
M-D Field (4,065,720 bbls oil; 1967-79)
T. P. LeClair Unit
The T. P. LeClair Unit of M-D Field is located in Township 53 North,
Range 69 West, Campbell County, and has been the site of a single well
salt water disposal system since 1968. The injection well is completed
in "the lower Minnelusa Formation at a depth of 7,236 feet. Between the
time of the initial injections and December, 1979, 637,827 barrels
(2.6788 x 107 gallons) of produced brine were injected to the lower
Minnelusa at average injection pressures between 638 and 851 psi.
Casing Record: Salt Water Disposal Well //1, T53N-R69W-36 dd, M-D
Field, T. P. LeClair Unit, Total Depth = 7357 feet.
Casing Size Wt. (///ft) Depth Set Cement
5-1/2" 15.5,17 7357' 250 sacks
11-148
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Government - C. F. True Unit
A second salt water disposal well was put into operation at M-D
Field in 1970. This well is located in Section 1, Township 52 North,
Range 69 West, Campbell County, and completed in the Dakota and
Lakota sands at a depth of 5,808 feet. As of December, 1979, 3,325,970
g
barrels (1.3969 x 10 gallons) of produced brine had been injected
since the project began.
Casing Record: Salt Water Disposal Well //GT-1, T52N-R69W-1 ab, M-D
Field, Government - C. F. True Unit, Total Depth =
7427 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
10-3/4" 40.5 15" 413' 260 sacks
5-1/2" 15.5,17,20 8-3/4" 7437' 235 sacks
Meadow Creek Field (31,028,960 bbls oil, 77,819,790 MCF gas; 1950-79)
The Meadow Creek oil field is located about 65 miles north of
Casper, Wyoming, in Township 41 North, Range 78 West, and one section of
Township 42 North, Range 78 West, Johnson County. Oil was first
discovered in the Meadow Creek area on April 3, 1950, in the Lakota
Sandstone at a depth of 7,475 feet. Subsequent producing wells were
completed in the second Frontier, Tensleep, Shannon, and Sussex sands.
A natural gas processing plant was constructed at Meadow Creek Field
in 1953, to process locally derived gas, remove butane and propane,
and re-inject the gas into the Sussex, Shannon, Lakota, and Tensleep
producing zones.
Continental Oil Company has operated the water injection projects
in the Shannon "A" and "B," Second Frontier, Lakota "A," Lakota "B,"
and Tensleep "A" Units. The first such project was undertaken in the
Lakota "B" reservoir in 1956.
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Water supply for the Meadow Creek area injection wells is obtained
from the Shiloh Water Supply System which consists of four wells
completed in the Madison Limestone. The system is also operated by
the Continental Oil,Company.
Lakota "B" Unit
The Lakota "B" reservoir is a light brownish-gray, cherty, coarse-
grained to conglomeratic, quartzose sandstone of the Lower Cretaceous.
The areal extent of the reservoir is 350 acres with an average thickness
of 60 feet and an average pay thickness of 20 feet. Porosity averages
about 15 percent and the permeability varies between 40 and 200
millidarcies.
The productive boundaries of the Lakota "B" Unit are defined by a
normal north-dipping fault on the north side and by the oil-water
contact on the south, east, and west.
Water injection into the Lakota "B" reservoir began in 1956, and
was terminated in 1964. During that period, 651,330 barrels of water
(27,355,860 gallons) were injected into the formation. Since 1964, two
of the injection wells have been recompleted as oil production wells in
the Shannon "A-B" Unit.
Casing Record: Injection Well //60, T41N-R78W-10 cca, Meadow Creek
Field, Lakota "B" Unit, Total Depth = 7445 feet.
Casing Size Wt. (///ft) Make Depth Set Cement Purpose
10-3/4" 29 Spiral 175' 175 sacks Surface
7" 23 J-55, 7445' 250 sacks Injection
N-80
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Second Frontier "A" Unit
The second Frontier sand is the middle unit of three "salt and
pepper" sandstone beds within the Frontier Formation. The Frontier
sands are Late Cretaceous in age and are part of a faulted anticlinal
structure. Production in the second Frontier sand is bounded on the
north by a sealing normal fault, on the west and south by an oil-water
contact and on the east by a facies change from sand to shaley sand
which significantly decreases permeability.
The Second Frontier "A" reservoir areally covers 964 acres and is
found at an average depth of 6,556 feet. It has an average thickness
of 90 feet with an average oil productive thickness of 12 to 20 feet
and a structural closure of 60 feet. The estimated porosity of the
reservoir is about 15 percent.
Oil production from the Second Frontier "A" Unit was initiated in
1951, by the Continental Oil Company. Water injection began in 1963,
through well //89. Two additional injecting wells were completed in
1968, one more was added in 1970, and another in 1978. As of July,
1979, there were five wells actively injecting water into the second
Frontier sand. Fresh water for injection is drawn from the Madison
Limestone (Shiloh Water Supply Line). The cumulative volume of water
injected since the project began is 8,345,154 barrels (3.5049 x
10^ gallons).
Casing Record: Injection Well #28, T41N-R78W-10 daa, Meadow Creek Field,
Second Frontier "A" Unit, Total Depth = 7554 feet.
Casing Size Wt. (///ft) Make Depth Set Cement Purpose
10-3/4" 36 H-40 166' 150 sacks Surface
7" 23 J-55 7554' 550 sacks Injection
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Tensleep "A" Unit
The Tensleep Sandstone is a Pennsylvanian-Permian age sandstone
found at an average depth of 9,000 feet in the Meadow Creek area. The
Tensleep is composed of clean, white, fine- to medium-grained, friable
sand with some streaks of hard, dolomitic sand.
Structurally, the unit is part of an anticline and is bounded on
all sides by an oil-water contact. The gross thickness of the sand-
stone is 200-250 feet with an average pay thickness of 17 feet and a
maximum closure of 60 feet. Reservoir data collected by the Continental
Oil Company indicate an average porosity of 11 percent and permeability
of 14 millidarcies.
The areal extent of the Tensleep "A" reservoir is 2,918 acres, but
the unit participating is only 1,560 acres, 1,440 of which are
federally owned with 120 acres of privately owned fee lands.
Primary oil production began in 1953, and was predominantly con-
trolled by an active natural water drive from the west and north. The
injection of fluids was initiated in 1963, with the injection of natural
gas and water into the reservoir. Currently (July, 1979), there are
four active water injection wells, two temporarily shut-in wells and a
water supply well, which is completed in the Madison Limestone. The
water supply well provided 9,000 barrels (378,000 gallons) of water
during an 8-hour well test for an estimated flowing potential of 87,000
barrels of water (3,654,000 gallons) per day. Cumulative water injection
into the Tensleep "A" reservoir has totaled 21,400,468 barrels (8.988
x 10^ gallons) (July, 1979). It is estimated that 3,130,000 barrels
of oil will be obtained as a result of secondary recovery by fluid
inj ection.
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Casing Record: Injection Well #178, T41N-R78W-1 dbd, Meadow Creek
Field, Tensleep "A" Unit, Total Depth = 9088 feet.
Casing Size
10-3/4"
7"
Wt. (///ft)
32.75
23,26
Depth Set
340'
9088'
Hole Size
13-3/4"
9"
650 sacks
200 sacks
Cement
Shannon "A" Unit
The Shannon Sandstone is an Upper Cretaceous gray or green, fine-
to medium-grained, glauconitic sandstone which occurs at an average
depth of 4,200 feet in the Meadow Creek Field. The Shannon sand
consists of two sand benches—the main Shannon and the false Shannon.
The false Shannon is developed on the northwest and west sides of the
reservoir and has a gross thickness of 18 feet. The main Shannon
underlies the false Shannon and 30 to 50 feet of shale. It has a gross
thickness of 40 feet and a maximum structural closure of 350 feet.
The average porosity of the Shannon sands is 25 percent.
The Shannon sands are part of a normally faulted anticline which
is divided into four distinct fault blocks with limited communication
between the blocks as a result of an average fault displacement of 100
feet. The entire structure is bounded by more faulting to the north,
faulting and sand development to the east and south, and an oil-water
contact to the west. The areal extent of the Shannon "A-B" reservoir
is 3,759 acres with an average pay thickness of 16 feet.
The Continental Oil Company began producing oil from the Shannon
Sandstone in 1950. To enhance oil production, gas injection (gas and
liquefied petroleum gas) was initiated in March, 1953. A pilot program
for waterflooding started in 1960, and has developed into the largest
water injection project at Meadow Creek Field. Since 1960, more than
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9
27,570,426 barrels of water (1.1579 x 10 gallons) have been injected
into the Shannon "A-B" Unit through 25 injection wells. As of August,
1979, 17 of the wells were still active injectors, while 8 had been
temporarily shut-in. The source of injected water is the Madison
Limestone (Shiloh Water Supply Line).
Casing Record: Injection Well #10, T41N-R78W-2 bbb, Meadow Creek Field,
Shannon "A" Unit, Total Depth = 4415 feet.
Casing Size Wt. (///ft) Make Depth Set Cement
9-5/8" 40 J-55 222' 200 sacks
7" 20 H-40 4415' 175 sacks
Lakota "A" Unit
The Lower Cretaceous Lakota Sandstone of the Lakota "A" participating
area consists of two porous sand zones separated by a shale bed. The
areal extent of the Lakota "A" reservoir is 1,230 acres with an average
pay thickness of 15 feet. The total unit area is 710 acres—650 acres
are federally owned and the remainder are privately owned fee lands.
The productive boundaries of the cherty, coarse-grained to con-
glomeratic quartzose sandstone are defined by a major fault to the
north, an oil-water contact to the south and west, and a facies change
from a porous, permeable sand to a tight, shaley sandstone on the
eastern edge.
Average porosity within the Lakota "A" Unit is 15 percent with a
variable permeability which ranges between 40 and 200 millidarcies.
Gas injection into the reservoir began in 1953, and was continued
until 1980. During that time 12.8 billion cubic feet were injected.
In 1963, a full scale water injection operation was started around the
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perimeter of the reservoir. Between 1963 and August, 1979, 6,857,587
g
barrels of water (2.88 x 10 gallons) were injected into the Lakota
"A" Unit. Casing records were not available for the injection wells
in this unit.
North Meadow Creek Field (9,485,328 bbls oil, 28,598,359 MCF gas; 1949-79)
The North Meadow Creek Field is located on the west flank of the
Powder River Basin between Meadow Creek and Sussex fields, on a faulted
anticlinal nose plunging north from the Meadow Creek structure. Several
transverse normal faults cut this nose forming oil and gas traps in
the Sussex and Shannon sandstones, and the Frontier Formation.
The North Meadow Creek Field production and injection projects are
operated by the Continental Oil Company. As of August, 1979, all of
the 47 injection wells of the North Meadow Creek Field were temporarily
shut-in.
Sussex Unit
The Upper Cretaceous Sussex Sandstone is a light-gray to green,
fine- to medium-grained, highly glauconitic sand, very similar to the
Shannon sand and just above the Shannon stratigraphically. The Sussex
Sandstone is found at an approximate depth of 3,900 feet in the North
Meadow Creek area and covers 962 acres with an average pay thickness of
32 feet. The total participating area of the Sussex Unit is 1,560
acres, of which 1,240 acres are federally owned and 320 acres are state
owned.
Structurally, the Sussex Unit is part of an anticline which is
truncated on the south by a major east-west trending fault with a
maximum displacement of 230 feet. The fault delineates the productive
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boundary of the Sussex sand on the south. Production is limited in
other directions by an oil-water contact and by minor faulting. Faulting
divides the reservoir into three distinct blocks with little hydraulic
communication between them. The maximum structural closure on the
Sussex reservoir is 150 feet.
Oil production started in 1951, and was controlled predominantly by
solution gas drive. The waterflooding operations began in 1953, using
an irregular five-spot pattern to enhance production. It was estimated
that secondary flooding would provide an additional 830,000 barrels of
oil from the Sussex reservoir.
All of the injection wells have been shut-in in the Sussex Unit
since 1971. Cumulative injection from the 27 wells has been roughly
g
20 million barrels of water (8.4 x 10 gallons). Several of the wells
have been recompleted since 1968, from the Sussex to the Shannon sand
for the purpose of producing oil from the Shannon reservoir.
Casing Record: Injection Well //12, T42N-R78W-36 abd, North Meadow
Creek Field, Sussex Unit, Total Depth = 4436 feet.
Casing Size Wt. (///ft) Depth Set Cement
10-3/4" 32.75 239' 200 sacks
7" 20 4436' 300 sacks
Shannon Unit
The Shannon sand reservoir is found at an average depth of 4,430
feet within the area of North Meadow Creek Field. The areal extent of
the Upper Cretaceous sand is 1,214 acres with a net productive sand
thickness which ranges between 0 and 18 feet and averages 12 feet. The
total participating area of the Shannon Unit is 1,597.5 acres. Federally
owned land comprises 1,280 acres and state lands comprise 317.5 acres.
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A major fault to the south and the oil-water contact on the other
sides outline the productive area of the Shannon sand. The primary
mechanism for oil production was solution gas drive when the North
Meadow Creek Shannon Unit was developed in 1950.
Secondary recovery of oil by waterflooding was initiated in 1959,
with a five-spot and peripheral flood pattern. In 1977, the waterflood
pattern was considered to be ineffective and was discontinued. The
ratio of produced oil to produced water had risen to 9.6:1 in 1976 and
10.0:1 in 1977 compared to a 0.9:1 cumulative ratio since the water-
flooding program began. Hydraulic communication between the Shannon
and Sussex sands was considered a major contributing factor.
At the present time, all producing wells in the Shannon reservoir
have been shut-in temporarily. Four of the wells are equipped to return
to producing status as soon as a renewed water injection program affects
the areas near the production wells. Injection water has been supplied
by three North Meadow Creek wells completed in the Madison Limestone.
Casing Record: Injection Well #66, T42N-R78W-36 abd, North Meadow
Creek Field, Shannon Unit, Total Depth = 4437 feet.
Casing Size Wt. (///ft) Depth Set Cement
10-3/4" 32.75 262' 170 sacks
7" 23 4437' 300 sacks
Frontier Unit
The North Meadow Creek Frontier Formation is a tight, fine- to
medium-grained, "salt and pepper" sandstone with streaks of shale. The
formation ranges in thickness from 26 to 63 feet and occurs at an aver-
age depth of 6,500 feet. The sandstone is extensively fractured both
vertically and horizontally. Average values of the porosity and
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permeability of the Upper Cretaceous sand are 11.9 percent and 0.5
millidarcies, respectively.
The Frontier reservoir is productive over an area of 3,850 acres.
It is situated within the broad Meadow Creek anticline and is a combined
structural and stratigraphic trap. The productive unit of the Frontier
is bounded on the east by an extensive oil-water transition zone, on
the west by a decrease in reservoir permeability, on the north by a
sealing fault, and on the south by decreased permeability and the oil-
water contact.
The Frontier Unit area covers 3,953.52 acres. The area is divided
between federally owned (2,133.94 acres), state owned (640 acres), and
privately owned fee lands (1,179.58 acres).
The water-oil ratio for producing wells completed in the Frontier
reservoir was 2.5:1 in 1978, compared to a cumulative ratio of .1:1
since production began.
The Frontier reservoir has also been used as a salt water disposal
site since 1974. Water produced with oil from Frontier wells is
re-injected at a depth of-6,573 feet through well #16 (T42N-R78W-25 da).
In 1967, a natural gas injection project began at the North Meadow
Creek Frontier Unit. Through 1979, 2,784,080 million cubic feet (MCF)
of gas had been injected into the Frontier Formation through two wells
perforated at depths of 6,258 and 6,278 feet. One of the wells is still
actively injecting. Average injection pressures have ranged from 0
to 1,800 psi.
Information on individual producing, water disposal, and water and
gas injection wells was unavailable at the time this report was written.
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Mellott Ranch Field (4,047,023 bbls oil; 1960-79)
Minnelusa Unit
Mellott Ranch Field covers 1,000 acres of federal, state, and
private land in west-central Crook County. The Minnelusa Formation
oil discovery well was completed in 1961, at depths between 6,782 and
6,804 feet. The Minnelusa reservoir spans approximately 700 acres with
an average pay zone thickness of 25 feet. Core analyses indicate an
average reservoir porosity of 16 percent. The primary producing energy
is provided by fluid expansion.
Water injection for secondary recovery of oil was approved in
June, 1965, with Shell Oil Company as operator. However, the initial
injection did not occur until December of that year. Water supply for
the project is from the wells completed in the Fox Hills Sandstone
at a depth of about 1,000 feet. Originally, the project had two
injection wells. A third well was added in 1972. Cumulative injection
O
through December, 1979, was 7,108,653 barrels (2.9856 x 10 gallons) of
water. Two of the three wells were still active at that time. Average
injection pressures have ranged between 840 and 2,300 psi.
Casing Record: Injection Well #12, T52N-R68W-11 bca, Mellott Ranch
Field, Minnelusa Unit, Total Depth = 6930 feet.
Casing Size Wt. (///ft) Depth Set Cement
8-5/8" 24 318' 180 sacks
2-7/8" 6.5 6879'
Mike's Draw Field (4,669,318 bbls oil, 5,270,713 MCF gas; 1974-79)
Steinle Unit
A single well salt water disposal system, operated by Mitchell
Energy Corporation, was started in 1979, at the Steinle Unit of Mike's
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Draw Field (Township 36 North, Range 70 West, Converse County). The
injection well is completed in the Teckla sand at a depth of 6,782 feet.
Through the first year of injection, 9,470 barrels (397,740 gallons)
of produced brine were injected to the Teckla sand.
Casing Record: Salt Water Disposal Well //1—15, T36N-R70W-15 bd, Mike's
Draw Field, Steinle Unit, Total Depth = 7371 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
8-5/8" 24 12-1/4" 1042' 500 sacks
5-1/2" 17,15.5 7-7/8" 7371' 300 sacks
Miller Creek Field (5,780,893 bbls oil, 4,365,122 MCF gas; 1959-79)
Twiford-Forney Unit
The Miller Creek Field Twiford-Forney Unit is the site of a single
well salt water disposal system completed in the Dakota sand at a
depth of 5,984 feet. Disposal of produced brine started in 1971, and
injection reports filed in June, 1980, with the Oil and Gas Commission,
indicate that 703,904 barrels (2.9563 x 10^ gallons) of salt water have
been disposed of through well //5 since 1971.
Casing Record: Salt Water Disposal Well #5, T51N-R68W-20 da, Miller
Creek Field, Twiford-Forney Unit, Total Depth = 6062
feet.
Casing Size Wt. (///ft) Depth Set Cement
7" 20,23 6062' 100 sacks
Cordell Unit
The Cordell Unit of Miller Creek Field is the site of another salt
water disposal well completed in the Dakota sand. The well is located
in Section 8, Township 51 North, Range 68 West, Crook County, and is
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completed at a depth of 5,890 feet. Between the time of the initial
injections in 1971, and June, 1980, 1,157,706 barrels (4.8623 x 10^
gallons) of produced brine were injected at average pressures between
210 and 2,275 psi.
Casing Record: Salt Water Disposal Well #2, T51N-R68W-8, Miller Creek
Field, Cordell Unit, Total Depth = 5968 feet.
Casing Size Wt. (///ft) Depth Set Cement
5-1/2" 14,15 5968' 100 sacks
Mobile Government Unit
A third Miller Creek Field salt water disposal well is located at
the Mobil Government Unit in Section 17, Township 51 North, Range 68
West, Crook County. The well is completed in the Dakota sand and began
injection of produced brine in 1972. Cumulative injection through
June, 1980, was 564,882 barrels (2.3725 x 10^ gallons) of produced salt
water.
Arcol Unit
Terra Resources, Inc. began operation of the fourth salt water
disposal well at Miller Creek Field in 1978. The well is located in
the Arcol Unit of the field, in Section 16, Township 51 North, Range
68 West. Cumulative injection into the Dakota sand reservoir as of
July, 1980, was 216,478 barrels (9,092,076 gallons) of produced brine.
West Moorcroft Field (6,119,999 bbls oil, 6,332,431 MCF gas; 1956-79)
Newcastle Unit
The West Moorcroft Field Newcastle Unit area covers 1,146 acres
of federal, state, and private land along the west flank of Oil Butte
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anticline, an asymmetrical structure on the extreme west edge of the
Black Hills uplift.
The main oil-bearing zone underlying West Moorcroft Field is the
Newcastle Sandstone. The Newcastle in this area is composed of sand-
stone with some shale and ranges in thickness between 45 and 60 feet.
Overlying the Newcastle reservoir is a formational cap of nearly 200
feet of Mowry Shale. The Skull Creek Shale lies immediately below the
reservoir.
The Newcastle Unit waterflood project started in 1971, and by 1976
included 11 wells, seven of which were still active as of December, 1979.
Injection reports on file at the Oil and Gas Commission indicated
that cumulative injection to that point was 8,512,293 barrels (3.5752
g
x 10 gallons) of water from producing wells in the Dakota sand
at a nearby field. Average injection pressures have not exceeded
1,780 psi.
A tertiary recovery water/polymer injection project was undertaken
by Planet Associates, Inc., in 1974, at the Waters Unit of Moorcroft
Field. Of the project's nine wells, only six are currently (June, 1980)
active.
Casing Record: Injection Well #1, T52N-R68W-36 dd(ad), West Moorcroft
Field, Newcastle Unit, Total Depth = 4185 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement Purpose
8-5/8" 24 12-1/4" 204' 150 sacks Surface
4-1/2" 10.5 7-7/8" 4179' 125 sacks Injection
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Mule Creek Field (3,356,598 bbls oil, 87,301 MCF gas; 1919-79)
Argo Unit
Mule Creek oil field is siatuated on an elongated dome, the axis of
which lies along the line between Ranges 60 and 61 West and the crest
of which is located at about the center of Township 39 North, Niobrara
County. The dome has over 200 feet of structural closure.
In 1919, Mule Creek Field was discovered when a producing oil well
was completed in the Lakota Sandstone. Injection of produced Lakota
water for secondary oil recovery purposes began in 1974. Two wells are
actively injecting according to the most recent injection reports filed
at the Oil and Gas Commission by Tesoro Petroleum Corporation (December,
1979). The reports indicate that 859,247 barrels (3.6088 x 10^
gallons) of water have been injected since the waterflood started.
Reported average injection pressures have never exceeded 558 psi.
Ziegler Unit
The Minnelusa Formation discovery well at Mule Creek Field was
drilled in 1929, and perforated an oil reservoir that spans 120 acres
with an average pay zone thickness of approximately 23 feet. Water
injection started in 1959, utilizing water from the Dakota sand. The
Minnelusa waterflood has been abandoned. Cumulative injection statistics
for the Ziegler Unit flood indicate that 536,442 barrels (2.2530 x 10^
gallons) of water were injected during the life of the project.
Mush Creek Field (12,059,785 bbls oil, 2,108,339 MCF gas; 1943-79)
Mush Creek oil field is located just to the west of Skull Creek
Field and just east of West Mush Creek Field in Township 44 North, Range
63 West, Weston County. Structurally, the field is situated on a
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relatively gentle, terraced monocline dipping two degrees westward
from the Black Hills uplift. The Newcastle Sandstone, the lowest
member of the Upper Cretaceous series, is the only oil-bearing forma-
tion at Mush Creek Field. Hydrocarbon entrapment apparently is due
primarily to lensing or permeability changes in the Newcastle. Although
the Newcastle Sandstone is about 60 feet thick in this area, the oil-
bearing portion is usually found in the lower part of the formation and
varies in thickness from six to 28 feet. At least five separate sand
lenses are known to be oil-bearing, but none are productive over the
entire field. Facies changes from shale to sand and sand to shale are
very pronounced in the Newcastle at Mush Creek. The discovery well
was completed in May, 1944, in the Newcastle between 3,851 and 3,875
feet. No commercial quantities of oil or gas were found below the
Newcastle Sandstone.
Pilot water injection projects were started by Texaco, Inc.> in
1950, and continued intermittently for several years. Later, Texaco
and H. T. Thorson formed a cooperative project and J. G. Dyer and CRA,
Inc., also started projects.
Michaels Unit //4
Mush Creek Field Michaels Unit is located in Township 44 North,
Range 63 West, Weston County. Water injection to the Newcastle Sand-
stone at a depth of 4,270 feet began in 1975, through one well. Water
for the injection project is provided by supply wells in the Dakota
and Lakota sands. As of December, 1979, 49,413 barrels (2.0753 x
£
10 gallons) of water had been injected at average pressures between
1,100 and 1,700 psi.
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Casing Record: Injection Well #1, T44N-R63W-17 dd, Mush Creek Field,
Michaels Unit //4, Total Depth = 4302 feet.
Casing Size Wt. (///ft) Amount Purpose
10-3/4" 42 125' Surface
5-1/2" 14 4270' Injection
Rogers State 0-15723 Unit
Under the operation of the Toco Corporation, the Rogers Unit water-
flood was initiated during 1968, in Sections 10, 15, and 16 of Township
44 North, Range 63 West, Weston County. All but two of the eight
injection wells that were once active, had been shut-in by December,
1979. Cumulative injection to that date through all wells was 3,857,092
g
barrels (1.62 x 10 gallons) of Dakota and Lakota sand water. Over the
last 20 years of reported injection activity at the Rogers Unit,
average injection pressures have ranged from 10 to 1,705 psi.
Buffalo-037775 Updike-Thorson Unit
The Updike-Thorson Unit of Mush Creek Field covers an area of
1,650 acres. The Newcastle Sandstone, the oil productive reservoir
which underlies the unit and extends beyond the unit boundaries, has
an average pay zone thickness of 5.6 feet. The overlying cap rocks are
the Belle Fourche and Mowry shales.
Water injection for secondary oil recovery was initiated in
September, 1950, under the joint operation of Texaco, Inc. and H. T.
Thorson. Since then, Texaco has sold its interests at Mush Creek.
The waterflood currently involves only three active wells. Seven
others have been shut-in. Injection reports from December, 1979,
g
indicate that 3,255,205 barrels (1.3672 x 10 gallons) of water from
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the Dakota and Lakota sands have been injected to the Newcastle reser-
voir since the project started. Injection pressure averages have
ranged from 10 to 2,240 psi.
Casing Record: Injection Well #7, T44N-R63W-21 bbc, Mush Creek Field,
Updike-Thorson Unit, Total Depth = 4332 feet.
Casing Size Wt. (#/ft) Depth Cement
10-3/4" 32.75 163* K.B. 100 sacks
5-1/2" 14,17 4171' K.B. 150 sacks
Wade Unit
The Wade Unit of Mush Creek Field covers portions of Sections 17,
18, and 19 in Township 44 North, Range 63 West, Weston County. The
unit is operated by Toco Corporation which began a secondary recovery
water injection project in 1971, through three wells perforated in the
Newcastle Sandstone at depths of 4,150 to 4,250 feet. The project was
later expanded to nine wells. Through December, 1979, 1,628,551 barrels
(6.8399 x 10 ^ gallons) of Dakota sand water had been injected over the
duration of the project. The original three injectors have been shut-
in for six years. Average injection pressures have ranged from 150 to
1,900 psi.
Casing Record:
Casing Size
10-3/4"
5-1/2"
11-166
Injection Well // 10, T44N-R63W-18 ddb, Mush Creek
Field, Wade Unit, Total Depth = 4505 feet.
Wt. (///ft) Amount Perforations Purpose
33 150' - Surface
15 4505' 4432-58' Injection
-------
North Fork Field (18,534,216 bbls oil, 8,418 MCF gas; 1951-79)
Cellars Ranch Unit
The Cellars Ranch Unit of North Fork Field is located in Township
44, Range 82 West, Johnson County. Disposal of salt water produced
with oil at North Fork Field started in 1977, through a well completed
in the Crow Mountain Formation at a depth of 5,684 feet. Average
injection pressures have ranged from 0 to 900 psi over the duration of
the project. Cumulative injection through January, 1980, was
2,050,418 barrels (8.6117 x 10^ gallons) of produced brine.
Casing Record: Salt Water Disposal Well //3, T44N-R82W-24 ad, North
Fork Field, Cellars Ranch Unit, Total Depth = 6845
feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
10-3/4" 32.75 13-3/4" 521' 250 sacks
5-1/2" 14,15.5 8-3/4" 6844* 135 sacks
Oedekoven Field (2,372,804 bbls oil, 5,322,002 MCF gas; 1968-79)
Muddy Sand Unit
The only injection project currently operating at Oedekoven Field,
Township 55 North, Ranges 73 and 74 West, Campbell County, is a three
well salt water disposal system which began in 1971. Cumulative injec-
tion into the Muddy Sandstone was 2,329,833 barrels (9.7853 x 10^
gallons) as of December, 1979. Average injection pressures have ranged
from a vacuum (gravity injection) to 2,040 psi. The average porosity
of the Muddy sand in the Oedekoven area is 17.2 percent.
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Oil Springs Field (12,971,118 MCF gas in storage; 1938-79)
A natural gas storage project operated by Northern Gas Company,
was started in 1951, at Oil Springs Field. The field is located in
Township 23 North, Range 79 West, Carbon County. Since 1951, natural
gas has been injected into the Sundance, Lakota, and Dakota sand reser-
voirs through five injection wells. As of January, 1980, three of the
wells were still active. Total injection to storage for the year 1979,
was 1,206,896 MCF.
OK Field (12,111,663 bbls oil, 68,301 MCF gas; 1973-79)
OK Unit
Since 1975, Universal Resources Company has been operating a one
well tertiary oil recovery project at the OK unit of OK Field. The
field is located in Township 51 North, Range 70 West, Campbell County.
The project involves the injection of water/polymer solution into
the oil producing Minnelusa Formation. Cumulative injection data for
the OK Field tertiary recovery project were not available in the files
of the Oil and Gas Commission.
Olds Field (21,422 bbls oil; 1975-79)
Tupper Unit
Olds Field, located in Township 49 North, Range 65 West, Crook
County, is currently the site of a single well salt water disposal
project. Injection of produced brine into the Butler sand was
initated in 1977. As of June, 1980, 2,340 barrels (98,280 gallons)
of brine had been injected.
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Oregon Basin Field (299,970,223 bbls oil, 149,901,637 MCF gas; 1912-79)
Oregon Basin, approximately six miles wide and 11 miles long, is
the largest surface depression on the west side of the Bighorn Basin.
Oregon Basin Field was discovered in 1912, when natural gas was produced
from a well completed in the Cloverly Formation. The oil and gas
field is situated in Townships 50-52 North, Range 100 West, Park County,
on the north and south Oregon Basin domes, which are separated by a
narrow structural saddle.
In 1927, oil was discovered in the Embar Formation and Tensleep
Sandstone of the north dome. Madison Limestone oil was not discovered
until 1943, in the south dome. The north and south domes have indepen-
dent structural closures of about 500 feet and 900 feet, respectively.
A fault block at the south end of the south dome appears to be the
only fault that has affected hydrocarbon accumulation in the lower
productive formations.
A plan to unitize development and operation at Oregon Basin Field
was approved by the Secretary of the Interior in 1948. An experimental
water injection project was started in 1956, on the north dome with
injection into the Embar reservoir. Currently (December, 1979), there
are three pressure maintenance waterflood projects active at Oregon
Basin Field—the North Dome Embar-Tensleep, the South Dome Embar-
Tensleep, and the South Dome Madison units. Water for the projects
is provided by production wells in the Embar Formation, the Tensleep
Sandstone, and the Madison Limestone. Three Madison wells drilled in
1967, primarily for water supply, unexpectedly produced over 2,000
barrels of oil per day.
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North Embar-Tensleep Unit
Water injection into the north dome Embar Formation was not resumed
until 1962. Tensleep Sandstone injection began in 1960. The unit
participating area spans 3,715 acres of federal, state, and fee land.
The Embar sand has an average effective pay thickness of 38 feet and a
primary permeability of 10 millidarcies or less. It is assumed that
reservoir permeability is provided by a fracture network. The Tensleep
pay zone is approximately 60 feet thick with a permeability of about
150 millidarcies. Limited available core data indicate that the Embar
and Tensleep have average porosities of 14 percent and 16 percent,
respectively. As of July, 1973, 46 of 52 existing injection wells
were active, and 29 of the active wells were dual injectors perforated
in both the Embar and Tensleep reservoirs. At that time, 228,585,465
9
barrels (9.6006 x 10 gallons) of water had been injected since the
start of the project. Average injection pressures have ranged from 0
to 560 psi.
A water quality analysis was performed on water injected at the
Frisby A-3 injection well and indicated extremely high sulfate
concentrations (3,450 mg/1).
Casing Record: Injection Well Atherly #5, T52N-R100W-33 ccb, North
Oregon Basin Field, Embar-Tensleep Unit, Total
Depth = 3930 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
13-3/8" 48 17-1/2" 519' 625 sacks
8-5/8" 32 11" 3930' 440 sacks
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South Embar-Tensleep Unit
Water injection into the Tensleep and Embar Formations of the south
dome of Oregon Basin Field began in 1958 and 1963, respectively. The
South Embar-Tensleep Unit covers 5,862 acres of federal, private, and
uncommitted land. Fifty-six of the 66 active injectors in the South
Embar-Tensleep Unit are dually perforated in both formations. Eight
wells have been temporarily shut-in. Cumulative injection through
July, 1973, was 201,640,225 barrels (8.4689 x 10^ gallons) of produced
water from the Madison Limestone, Embar Formation, and Tensleep Sandstone.
Casing Record: Injection Well Brendel //4, T50N-R100W-7 aba, South
Oregon Basin Field, Embar-Tensleep Unit, Total Depth
= 4665 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
9-5/8" 32.3 13-3/4" 233' 175 sacks
(Type "G")
5-1/2" 15.5 7-7/8" 4663' 300 sacks
(50-50 pozmix)
South Madison Unit
The Madison Unit of South Oregon Basin Field includes 2,392 acres
of federal and private land in Sections 31 and 32 of Township 51 North,
Range 100 West, Park County. One of two water injection wells was
actively injecting produced water from the Madison Limestone, Embar
Formation, and Tensleep Sandstone. Injection reports were not available
for the Madison Unit at the Oil and Gas Commission.
Osage Field (25,271,901 bbls oil, 122,123 MCF gas; 1919-79)
Osage Field is located in north-central Weston County, approxi-
mately 15 miles northwest of Newcastle, Wyoming. The first oil
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well in the field was completed in 1919, in the Graneros Shale. One
year later, a well was completed in the Newcastle (Muddy) Sandstone.
The field is located on a west-dipping monocline, which lies on
the southwest flank of the Black Hills uplift. The structure contains
a number of pitches and terraces with dips ranging from 1 to 10 degrees.
The most important producing formation is the Lower Cretaceous
Newcastle (Muddy) sand in which oil has accumulated in stratigraphic
traps. The major aquifers within the Osage area are the Greenhorn
Shale, the Dakota-Lakota sands, and the Madison Limestone. The Newcastle
(Muddy) Sandstone is a fine- to medium-grained lenticular sandstone
with some siltstone and shale. The formation thickness in the Osage
area ranges between 20 and 100 feet. Detailed reservoir studies
indicated that permeability varied thorughout the field and presented
the possibility that several reservoirs might be present.
There are eleven separate units within the Osage and Osage West
Fields that were operating active waterflood projects as of December,
1979. They are the Coronado Shallow Lens Unit, the Somers Area Unit,
the State Waterflood Unit, the Juniper Newcastle Unit, the Osage Juniper
Area Unit, the Bradley Newcastle Unit, the Mush Creek Extension Unit,
the Osage Unit, the Buffalo Lease Unit, the Osage West Unit, and the
Osage Miscellaneous Unit. Each of the units is injecting water into
the multiple benches of the Newcastle (Muddy) sand and the fractured
Nefsy Shale which overlies the Newcastle.
The first pilot waterflood began in 1959. By 1968, Coronado Oil
Company, Juniper Oil Company, Buttes Resources Company, and William
Blake were operating water injection projects at Osage Field.
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Reserve Oil Company started a one well salt water disposal system
at Osage Field in 1977. As of June, 1980, 9,480 barrels (398,160
gallons) of produced brine had been injected into the Newcastle Sand-
stone at an average injection pressure of less than 700 psi.
Juniper (Newcastle Sand) Unit
The Juniper Unit of Osage Field covers 2,432.52 acres in Township
46 North, Ranges 63 and 64 West, Weston County, Wyoming. It is
situated high on the gentle, northeastern flank of the Powder River
Basin, southwest of the Black Hills uplift.
The Newcastle reservoir of the Juniper Unit includes 2,400 acres
with an average pay zone thickness of 5 feet. Porosity and permeability
measurements were taken from core analyses at 27 of the 42 injection
wells at one foot intervals within the productive pay zone of each well.
The measurements were averaged for each well and then averages at each
of the 27 wells were again averaged to arrive at average porosity and
permeability figures for the Newcastle sand of the Juniper Unit of
22.8 percent and 44.2 millidarcies, respectively. A water injection
project, which included six injection wells, began in 1966, and has
since been expanded to 42 active injectors as of December, 1979. Water
for the project is provided by a Madison supply well in Township 46
North, Range 64 West, Section 23. Total cumulative injection in the
42 wells has been 11,286,743 barrels (4.7404 x 10^ gallons).
Casing Record: Injection Well 12-3W, T46N-R64W-25 adb, Osage Field,
Juniper (Newcastle Sand) Unit, Total Depth = 1505 feet.
Casing Size
7"
2-7/8"
Wt. (#/ft)'
17
6.4
Hole Size1
8-3/4"
6-1/4"
Depth Set
100' +
1505'
Cement
25 sacks
80 sacks
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Osage Juniper Area
The Osage Juniper Area is located in Township 46 North, Ranges 63
and 64 West, Weston County.
As of December, 1979, the waterflood project operated by Buttes
Resources Company included eight active injectors. Waterflooding
of the Newcastle Sandstone began in 1968. The Newcastle sand has an
average porosity and permeability of 23 percent and 25.9 millidarcies,
respectively, in the Juniper area.
The water supply for the injection field is provided by the
Madison Limestone via the same well that supplies the Juniper Newcastle
Unit, the Osage West Unit and the Osage Bradley Unit in Township 46
North, Range 64 West, Section 23. Cumulative injection to December,
O
1979, was 2,503,250 barrels (1.0513 x 10 gallons) of water.
Casing Record: Lemin Lease Injection Well W-l, T46N-R63W-19 c(bc),
Osage Juniper Area, Osage Field, Total Depth = 1455
feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
7" 20 9" 101' 30 sacks
(regular)
2-7/8" 6.5 6" 1447' 60 sacks
(50-50 pozmix)
(2% gel, 10% NaCl)
Osage West Unit
The Osage West Unit is located between the Osage State Waterflood
to the east and Fiddler Creek Field to the west. The unit covers an
area of 2,760 acres of federal, state, and private land. It is
situated on a steep, westward dipping homocline, in contrast to the
much more gentle dip associated with the rest of Osage Field updip to
the east and Fiddler Creek Field downdip to the west. At the extreme
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southern end of the unit, the beds strike northwest and dip southwest
at about 20 degrees. Northward, the strike swings toward the north,
dipping westerly at about 14 degrees.
An unconformity between the Newcastle sand and underlying beds
has an irregular surface resulting in a Newcastle sand thickness which
varies between 28 and 79 feet, with thickness generally greater toward
the south. Depth to the Newcastle sand within the unit ranges from
1,900 feet to 3,800 feet. The unit boundary has been selected on the
basis of a stratigraphic pinchout of the Newcastle sand reservoir.
The Osage West reservoir includes 1,600 acres with an average pay
zone thickness of 8 feet. Porosity and permeability measurements
taken from three core analyses of wells in the Osage West Unit indicate
an average porosity of 18.1 percent and an average permeability of
87.7 millidarcies for the reservoir. Fresh water for the injection
project, which began in 1965, with three wells, is supplied by a Madison
Limestone well in Township 46 North, Range 64 West, Section 23. The
waterflood has been expanded to include 18 wells, 14 active and 4
temporarily shut-in, as of December, 1979. Cumulative injection to that
g
date was 10,714,745 barrels (4.500 x 10 gallons) of water.
Osage Bradley Newcastle Unit
The Bradley Newcastle Unit covers an area of 880 acres of federal
and private land located approximately 20 miles northwest of Newcastle,
Wyoming. The unit area is near the center of Osage Field.
Buttes Resources Company, operator of the unit, initiated the
water injection project in 1969. Madison Limestone water from the well
used in the Osage West, Juniper Area and Juniper Newcastle Sand units
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also provides the water supply for the Bradley Unit waterflood. By
December, 1979, 25 wells were actively injecting into the Newcastle
reservoir.
The average porosity of the Newcastle in the Bradley area is 21.1
percent and permeability averages 51 millidarcies. Cumulative water
injected into the reservoir to the end of 1979, was 5,140,719 barrels
(2.1591 x 10^ gallons).
Osage State Waterflood
The Osage State Waterflood Unit is located in the east-central
portion of Township 46 North, Range 64 West, Weston County. This
project has also been called the Coronado Deep Lens Project. The deep
lense is actually a single sand bar which grades into shale in all
directions. The reservoir covers an area of about 960 acres with an
average pay thickness of approximately 10 feet. Analyses of cores from
13 wells completed in the reservoir showed averages of 23.3 percent
porosity and 428 millidarcies permeability.
When the waterflood project in the State Unit began in 1959, water
for injection was supplied by a well 1,800 feet deep in the Lakota Sand-
stone. From 1961 to the present, injection water has been provided by
a well completed in the Madison Limestone (Township 46 North, Range 64
West, Section 13 cca). A cumulative total of 25,913,328 barrels
9
(1.0884 x 10 gallons) of water have been injected since the project
began.
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Casing Record: State Lease Well 1-6, T46N-R64W-14 cac, Osage Field,
State Waterflood Unit, Total Depth = 1962 feet.
Casing Wt. Amount/ Kind of
Size (#/ft) Grade Make Shoe Perforations Purpose
2-3/8" 4.6 J-55 1983.51/ Float & 1896.5-1906 Injection
Youngstown Guide Casing
Osage Somers Unit
The Somers Unit is located at the east end of Osage Field northwest
of Newcastle, Wyoming. The Newcastle sand zones of the Somers Area
are found at very shallow depths (217 to 528 feet) relative to other
units at Osage Field. The cap rock over the Newcastle sand in this area
and others within the Osage Field is the Mowry Shale, a siliceous shale
about 200 feet thick in the Newcastle Area.
Water injection into the Newcastle sand began in 1972, with the
completion of 17 injection wells. Water is supplied to the injectors
from a Madison supply well located in Township 46 North, Range 63 West,
Section 17 cb. Between the start of the project and December, 1979,
1,999,846 barrels of water (8.3994 x 10^ gallons) had been injected.
Twenty wells were actively injecting as of that date.
Casing Record: State Lease Injection Well I-9W, T46N-R63W-16 cab, Osage
Field, Somers Unit, Total Depth = 285 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement Purpose
2-7/8" 6.5 6-1/4" 283' 55 sacks Water
injection
Coronado Shallow Lens Unit
The area covered by the Coronado Shallow Lens reservoir is 1,240
acres with an average pay zone thickness of 8 feet. Average reservoir
porosity and permeability are 22 percent and 55 millidarcies, respectively.
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In this area, the Newcastle Sandstone is a tan to gray, fine- to very
fine-grained, mottled, clay-filled, cross-bedded sand.
The Coronado Shallow Lens waterflood project started in 1960,
supplied by water from two wells in the Lakota Sandstone. A Madison
supply well in Township 46 North, Range 63 West, Section 17 cb has
provided the water supply since its completion in 1969.
The injection wells of the Coronado Shallow Lens Unit are protected
with 2-7/8 inch casing run to the total depth of the hole, perforated
in the Newcastle Sandstone and cemented 300 feet above the perforations.
Of the 78 injectors in the unit, 68 were active as of December, 1979,
and the cumulative total of water injected since 1960, was 12,217,381
barrels (5.1313 x 10^ gallons).
Buffalo 028328A Lease
The Buffalo Lease of the Osage Field is located in Sections 22 and
23 of Township 46 North, Range 64 West, Weston County. The Newcastle
Sandstone reservoir is extremely thin in this area ranging from 8 to
13 feet in thickness at a depth of 1,700 to 2,200 feet. Average porosity
and permeability measurements from core analyses of three wells in the
unit were 19.1 percent and 2 to 87.7 millidarcies, respectively.
The waterflooding of the Buffalo Lease began in 1969, and currently
(December, 1979) involves 14 injection wells—10 active and 4 shut-in.
Cumulative injection totals were not available.
Osage Unit
The Osage Unit of Osage Field is confined to Section 11, Township
46 North, Range 64 West, Weston County.
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Water injection into the Newcastle Sandstone of the Osage Unit
began in 1975, through two wells. The proposed configuration for the
wells was a five-spot pattern utilizing a producing well at the center
and four injectors at the corners of each 40 acre tract.
Between 1975 and December, 1979, 276,472 barrels (1.1612 x 10^
gallons) of water were injected into the Newcastle Sandstone.
Painter Reservoir (1,785,407 bbls oil, 9,306,755 MCF gas; 1977-79)
Painter Reservoir Unit
Painter Reservoir, located in Township 16 North, Ranges 119 and
120 West, Uinta County, is currently the site of two injection projects.
The first is a gas injection project, started in 1978, under the opera-
tion of Chevron, U.S.A. Twelve wells are involved in the injection of
nitrogen gas into the Nugget Sandstone. The purpose of the nitrogen
injection project is to augment the reservoir pressure, thereby increas-
ing oil production from the Nugget. Cumulative nitrogen injection
through June, 1980, was 38,435 MCF.
The second active injection project at Painter Reservoir is a two
well salt water disposal system that was put into operation in 1979.
Produced Nugget Sandstone brines are separated from produced oil and
injected to the Nugget at depths between 9,500 and 10,500 feet.
Cumulative injection data were unavailable at the time of this writing.
Salt Water Disposal Well //32-9B, T16N-R119W-9, Painter
Reservoir Field, Painter Reservoir Unit, Total Depth =
9800 feet.
Casing Record:
Casing Size
13-3/8"
9-5/8"
7"
Wt. (///ft)
54.5
43.5
26
Hole Size
17-1/2"
12-1/4"
Depth Set
811'
7618'
9800'
Cement
1500 sacks
4700 sacks
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Patrick Draw Field (1,978,492 bbls oil, 10,478,344 MCF gas; 1959-79)
Monell Unit
The Monell Unit of Patrick Draw Field covers 10,120 acres of
federal, state, and private land in Townships 18 and 19 North, Ranges
98 and 99 West, Sweetwater County. In 1959, oil was discovered in the
Almond sands of Patrick Draw Field.
The Almond sand reservoir is found at an average depth of 4,700
feet in the Monell Unit area and average reservoir porosity and perme-
ability are 20 percent and 33 millidarcies, respectively. The Almond
reservoir covers an area of approximately 7,500 acres with an average
net sand thickness of 21 feet.
In July, 1963, a one well pilot water injection project was
initiated in order to determine the water sensitivity of the Almond
sand. It was determined that shales within the reservoir contained
kaolinite and illite, minerals known for their tendency to deflocculate
when in contact with water of an incompatible chemical nature. The
movement of deflocculated shale particles can cause mechanical plugging
of pore spaces within the reservoir.
The water injection project was expanded to a full scale waterflood
in 1968, and by June, 1979, 77 wells were injecting water from supply
wells in the Lance Formation and Fox Hills Sandstone. Water from both
formations has been shown, through lab and field testing, to be compatible
with water of the Almond reservoir, thereby decreasing the potential for
shale deflocculation and plugging of the reservoir's effective porosity.
Cumulative injection through June, 1979, amounted to 68,947,912 barrels
9
(2.8958 x 10 gallons) of water. Injection pressures have averaged
between 0 and 2,450 psi during the project's lifetime. Estimates of
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the original oil in place within the Almond reservoir were 133,112,145
barrels. Through primary recovery and secondary recovery by gas
injection, it was estimated that 27,953,550 barrels of oil would be
recovered from the reservoir. Additional recovery of oil as a result of
water injection to the Almond sand was expected to total 12,046,450
barrels.
Gas injection pressure maintenance projects, which were started in
both the Arch and Monell units of Patrick Draw Field in 1961 and 1962,
respectively, have been shut-in for at least two years. At the Monell
Unit, 51,884,402 MCF of natural gas were injected into the Almond sand
at depths between 4,180 and 4,402 feet through five wells. Injection
pressures ranged between 35 and 2,425 psi, on the average. The Arch
Unit gas injection project involves only two wells which injected a
cumulative total of 36,556,902 MCF at average pressures between 750 and
2,358 psi.
A salt water disposal project operated by El Paso Products, Inc.,
began in 1974, at the Monell Unit of Patrick Draw Field. The sole
injector is located in Section 13, Township 18 North, Range 99 West, and
as of June, 1980, had injected 2,075,236 barrels (8.7159 x 10^ gallons)
of produced brine into the Fox Hills Sandstone at a depth of 3,905 feet.
Casing Record: Injection Well #19, T19N-R99W-25 cd, Patrick Draw Field,
Monell Unit, Total Depth = 4930 feet.
Casing Size Wt. (///ft) Depth Set Cement Purpose
8-5/8"
5-1/2"
15.5
24
258'
4925'
130 sacks Surface
90 sacks Injection
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Water Quality Analysis: (Fox Hills water supply well, T18N-R99W-3 da,
Perforated 3108-3311 feet)
pH = 7.8
TDS = 64,783 mg/1
Na = 24,818 mg/1
CI = 39,000 mg/1
Pickrel Ranch Field (1,306,127 bbls oil, 25,596 MCF gas; 1965-79)
Minnelusa Unit
Oil production at the Pickrel Ranch Field Minnelusa Unit started
in 1965, with the completion of a 9,000 foot well in the Pennsylvanian
Minnelusa Formation. The field is located in east-central Campbell
County (T48N-R69W). The Minnelusa Unit participating area covers
1,110.88 acres of federal, state, and private land and is currently
under an 80 acre well spacing order. The productive zone of the Minne-
lusa reservoir is a stratigraphic trap bounded by a permeability pinchout
on the north and east and by an oil-water contact on the southwest.
The permeability pinchout is believed to have resulted from the develop-
ment of a channel in the Minnelusa paleosurface and the subsequent
infilling with Opeche Shale. Average reservoir porosity and permeability
are 16.1 percent and 126 millidarcies, respectively.
Influx of water to the Minnelusa reservoir is believed to be
limited due to the drop in reservoir pressure associated with production
and to the fact that water cuts of produced oil have remained constant.
For these reasons, it is thought that the oil-water contact has not moved
up structure any appreciable distance.
Water injection to the Minnelusa reservoir started in 1970,
utilizing fresh water supplied by wells in the Fox Hills Sandstone.
Three injection wells have been employed during the project; however,
only one well remained active as of October, 1979. Cumulative
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g
injection to that date was 5,480,244 barrels (2.3017 x 10 gallons) of
water. Average injection pressures reported by the operator, M. J.
Mitchell, have ranged from a vacuum to a maximum of 2,550 psi.
Casing Record: Injection Well //4, T48N-R69W-18 dd(cd), Pickrel Ranch
Field, Minnelusa Unit, Total Depth = 9057 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement Purpose
8-5/8" 24 12-1/4" 274' 200 ft3 Surface
5-1/2" 15.5,17,23 7-7/8" 9057' 350 ft3 Injection
Pitchfork Field (22,553,947 bbls oil; 1930-79)
Pitchfork Unit
Husky Oil Company is currently (December, 1979) operating a six
well salt water disposal system at Pitchfork Field. The wells are
located in Sections 2, 11, and 14, Township 48 North, Range 102 West,
Park County. The disposal project started in 1972. Produced brines
are injected to the Tensleep sand reservoir, which occurs at an
approximate depth of 4,000 feet. The cumulative volume of salt water
injected between 1972 and June, 1979, was 64,396,021 barrels (2.7046 x
9
10 gallons). All six of the wells were still actively injecting
according to June, 1979, injection reports.
Casing Record: Salt Water Disposal Well //16, T48N-R102W-2 cd,
Pitchfork Field, Pitchfork Unit.
Casing Size Wt. (///ft) Depth Set Cement
7" 17 3996' 150 sacks
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Pleasant Valley Ranch Field (712,997 bbls oil; 1963-79)
Heptner Unit
Pleasant Valley Ranch Field was discovered in 1963, when a produc-
ing oil well was completed in the Minnelusa Formation. The field is
located in Township 51 North, Range 69 West, Campbell County. In the
Pleasant Valley Ranch area, the average porosity and permeability of the
Minnelusa producing zone are 11.1 to 14 percent and 29 millidarcies,
respectively.
A small scale waterflood project was started at the Heptner Unit
of Pleasant Valley Ranch in 1967. Water for the project is provided by
a supply well in the shallow alluvium. The most recent injection reports
(December, 1970) indicate that a cumulative total of 2,744,227 barrels
g
(1.1526 x 10 gallons) of water have been injected into the Minnelusa
reservoir since 1967. Average injection pressures have ranged from
750 to 2,200 psi at the wellhead.
Casing Record: Injection Well //A-2, T51N-R69W-30 dc, Pleasant Valley
Ranch Field, Heptner Unit, Total Depth = 8200 feet.
Casing Size Wt. (///ft) Depth Set Cement Purpose
10-3/4" 32.75 177' 100 sacks Surface
5-1/2" 17,15.5,14 8199' 300 sacks Injection
Poison Draw Field (5,577,067 bbls oil, 6,021,707 MCF gas; 1972-79)
Teckla "B" Unit
Poison Draw Field is located in the southern Powder River Basin.
The Teckla "B" Unit of the field includes 1,440 acres of federal,
state, and private land which overlie the productive Teckla "B" sand
reservoir. The reservoir, an Upper Cretaceous, clay-filled sand, is
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stratigraphically situated between the younger Pierre Shale and the
older Teapot Sandstone and covers 4,950 acres with an average net pay
zone thickness of 21 feet. Average porosity of the reservoir is
17.3 percent.
In 1976, a pilot water injection project began, utilizing one
injection well supplied with water from the Lance and Lewis sands.
X-ray diffraction tests and core analyses of Teckla "B" sand indicated
that 10 percent of the clay content within the reservoir sands was
montmorillonite, a swelling clay that severely reduces reservoir
permeability when mixed with fresh water. As of December, 1979, the
injection project had been discontinued. During the period of active
injection, a cumulative volume of 743,981 barrels (31,247,202 gallons)
of water were injected into the Teckla "B" reservoir.
Since 1977, salt water produced with oil from the Teckla sand
reservoir has been injected to the Teckla reservoir through a single
salt water disposal well located in Township 39 North, Range 69 West,
Section 35. The depth of the well perforations are 5,872 feet.
Through December, 1979, a cumulative volume of 109,272 barrels (4,589,424
gallons) of brine had been injected.
Casing Record: Salt Water Disposal Well #1, T39N-R69W-35 cd, Poison
Draw Field, Teckla "B" Unit, Total Depth = 6026 feet.
Casing Size Wt. (///ft) Depth Set Cement
8-5/8" 24 307' 225 sacks
5-1/2" 15.5 6026' 250 sacks
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Poison Spider Field (3,368,343 bbls oil, 65,000 MCF gas; 1917-79)
Sundance Unit
Poison Spider Field was discovered in 1917, when a well completed
in the upper Sundance Formation began producing at a rate of 5 million
cubic feet of natural gas per day. Oil was discovered in 1919, in the
lower Sundance at a depth of 1,506 feet. The lower sand of the Sundance
Formation is the principal oil producing sand at Poison Spider and
has an average thickness of 91 feet.
The field is situated atop a minor dome along the Pine Mountain-
Oil Mountain fold. The dome is somewhat elongated in a northwest-
southeast direction and has approximately 175 feet of closure independent
of the South Casper Creek structure to the northwest.
A pilot waterVinjection project was started in March, 1961,
utilizing one well at the southeast end of the field. The purpose of the
project is to supplement the reservoir producing energy provided by a
natural water drive. The area of the reservoir that is being water-
flooded covers about 120 acres and has an average pay zone thickness
of about 30 feet. The average porosity and permeability of the lower
Sundance reservoir are 18.2 percent and 241 millidarcies, respectively.
Cumulative oil production to January 1, 1980, exceeded the original
estimate of oil in place by more than 273,000 barrels. Cumulative
water injection between 1961 and December, 1979, totaled 2,932,176
g
barrels (1.2315 x 10 gallons) of produced Sundance Formation water.
Reported average injection pressures have yet to exceed 0 psi.
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Cody "B" Unit
The Cody "B" Unit of Poison Spider Field is located in Township
33 North, Range 84 West, Natrona County. It is the site of an eleven
well natural gas injection project, operated by Union Oil Company of
California. Injection began in 1974. All of the wells are completed
in the Upper Cretaceous Cody Shale at depths between 10,150 and
10,800 feet.
The average porosity of the Cody Shale is 10 to 12 percent, while
the average permeability of the reservoir is less than one millidarcy.
Nine of the injection wells were active during the last six months
of 1979. Cumulative injection, since the project started, was
4,915,446 million cubic feet, as of December, 1979. Average injection
pressures during that period ranged from 4,300 to 4,850 psi.
Mesaverde "B" Unit
Natural gas injection to the Mesaverde "B" reservoir started
in 1970, through a single well located in Section 11, Township 33
North, Range 84 West, Natrona County. The Mesaverde reservoir is
encountered at a depth of 9,084 feet at that location. As of December,
1979, 20,388,774 million cubic feet of gas had been injected at
average injection pressures between 1,600 and 2,930 psi.
Prairie Creek Field (958,759 bbls oil, 322,682 MCF gas; 1960-79)
Lewark Government 6 Unit
Continental Oil Company is currently operating a single well
salt water disposal system at the Lewark Government 6 Unit of
Prairie Creek Field. The disposal well is located in Section 6,
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Township 53 North, Range 68 West, Crook County. Produced brines
have been injected to the Newcastle Sandstone since 1976. Cumulative
injection data on file at the Oil and Gas Commission indicate that
a total of 19,293 barrels (810,306 gallons) of salt water were
disposed of through well //6 between 1976 and June, 1980.
Prong Creek Field (3,241,084 bbls oil; 1959-79)
Prong Creek Unit
A one well salt water disposal system under the operation
of Champlin Petroleum began injecting in 1972 at Prong Creek Field.
Produced water is injected to the Minnelusa Formation at a
depth of 6,277 feet through a well located in Section 6, Township
50 North, Range 67 West, Crook County. Average injection pressures
have varied between 540 and 550 psi. Cumulative injection through
December, 1979, totaled 1,452,050 barrels (6.0986 x 10^ gallons) of
salt water.
Casing Record: Salt Water Disposal Well //l, T50N-R67W-6 bcc, Prong
Creek Field, Prong Creek Unit.
Casing Size Wt. (///ft) Depth Set Cement
9-5/8" 32.3 284' 200 sacks
5-1/2" 15.5 6367' 200 sacks
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Prospect Creek Field (188,413 bbls oil; 1963-79)
Crow Mountain Unit
Oil was discovered in the Triassic Crow Mountain sand in 1963,
at Prospect Creek Field. The Crow Mountain Unit covers 1,120 acres
of federal, state, and private land in Township 45 North, Range 100
West, Hot Springs County, and is situated on an anticlinal structure
along the southern margin of the Bighorn Basin. The Crow Mountain
reservoir is composed of redbed sandstones typical of the Chugwater
Group in the Bighorn Basin. The reservoir depth ranges from 4,850
to 5,160 feet on the anticline. The Crow Mountain Unit is under an
80 acre spacing order by the Oil and Gas Conservation Commission.
The first water injection wells at Prospect Creek Field went
into operation in 1972. By 1978, eight wells were injecting water
from the Lakota Sandstone into the Crow Mountain Formation. Average
injection pressures have ranged from a minimum of 69 psi to a maximum
of 1,757 psi at the wellhead. As of December, 1979, 4,198,508 barrels
g
(1.7634 x 10 gallons) had been injected since the waterflood began.
One of the wells was shut-in at the time data were collected for this
report.
Casing Record: Injection Well Montgomery //1, T45N-R100W-22 dd(cd),
Prospect Creek Field, Crow Mountain Unit, Total
Depth = 4863 feet.
Casing Size Wt. (///ft) Grade Depth Set Perforations Cement
4-1/2" 9.5 K-55 4854' 4758-65' 100 sacks
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Quealy Dome Field (11,823,181 bbls oil; 1934-79)
Tensleep Unit
The Tensleep Unit participating area, under the operation of
Chevron, U.S.A., encompasses 896 acres of federal and private land in
Township 17 North, Ranges 76 and 77 West, Albany County. The under-
lying Tensleep reservoir covers 260 acres with an average pay zone
thickness of about 90 feet. The Tensleep is composed of white to light
gray, fine- to medium-grained, cross-bedded, quartz sandstone with
average porosity of 15 percent and average permeability of 105 milli-
darcies.
The reservoir is part of the Quealy dome, one of several structures
situated along the west margin of the Laramie Basin. The Quealy dome
is a small, sharply folded dome, elongated in a northwest-southeast
direction. The east flank of the dome dips about 20° toward the Laramie
Basin, while the west flank plunges westward until it is almost vertical.
Quealy dome was the first productive structure in the Rocky Mountain
area to be defined by seismographic testing. Oil was discovered at
Quealy Dome Field in 1934, when a producing well was completed in the
Muddy Sandstone. In 1947, the Tensleep Sandstone came into oil
production. The field was unitized in 1961, and divided into the
Muddy and Tensleep units.
Water injection started in one Tensleep Unit well in 1961,
utilizing water produced by wells in the Dakota and Tensleep sands. The
waterflood was expanded to five wells by 1972, and injection water was
provided by additional wells in the Muddy and Lakota sandstones. As
of December, 1979, a cumulative volume of 19,947,451 barrels (8.3779
g
x 10 gallons) of water had been injected into the Tensleep Sandstone
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since the project began. Average injection pressures for the Tensleep
project have ranged from 800 to 2,450 psi. Three of the five existing
injectors were still active as of January 1, 1980.
Casing Record: Injection Well //ll, T17N-R77W-13 aca, Quealy Dome Field,
Tensleep Unit, Total Depth = 5875 feet.
Casing Size Wt. (///ft) Amount Depth Set Cement
13" 40 103' 118' 75 sacks
7" 24 3238' 3254' 100 sacks
Muddy Unit
The Muddy Unit of Quealy Dome Field covers the same unit area as
the Tensleep Unit. The Muddy reservoir is composed of gray to brown,
fine- to medium-grained, porous sandstone with stringers of black shale.
Water injection into the Muddy Sandstone started in 1969, with one
injection well. An additional well was added to the waterflood in 1973.
Produced water from the Muddy, Dakota, Lakota, and Tensleep sands was
used in the flood. By the end of 1978, both of the injectors had been
shut-in. Cumulative injection during the project amounted to 503,827
barrels (2.1160 x lO'7 gallons) of water. Average injection pressures
ranged from 0 to 2,600 psi.
Casing Record: Injection Well //4, T17N-R76W-18 ebb, Quealy Dome Field,
Muddy Unit, Total Depth = 3601 feet.
Casing Size Wt. (///ft) Depth Set Cement
13" 40 145' 100 sacks
7" 24 3455' 100 sacks
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Raven Creek Field (35,628,912 bbls oil; 1956-79)
Mitmelusa Unit
The Minnelusa oil reservoir at Raven Creek Field was discovered
in 1960. The discovery well was completed in the "B" sand of the
Minnelusa Formation at a depth of 8,338 feet. The productive area of
the field was unitized in 1966, and put on an 80 acre spacing order by
the Oil and Gas Conservation Commission. The Minnelusa Unit, an area
of 4,510 acres of federal, state, and private land, is located in
Townships 48 and 49 North, Range 69 West, Campbell County.
The average thickness of the Minnelusa "B" sand reservoir is 38
feet. Average reservoir porosity and permeability are 15 percent and
92 millidarcies, respectively.
A secondary oil recovery waterflood project was initiated in
February, 1967, with 8 injection wells arranged in a line drive pattern
along the west edge of the field and completed in the "B" sand of the
Minnelusa Formation. By 1971, the project had been expanded to a 20
well system. Fifteen of the wells were still active in December, 1979.
Q
Injection reports indicate that 59,992,609 barrels (2.5197 x 10
gallons) of water from the Fox Hills Sandstone have been injected
into the "B" sand. The Fox Hills aquifer is found at a depth of about
2,240 feet. Average injection pressures have ranged from a reported
minimum of a vacuum to a maximum pressure of 2,650 psi.
Recluse Field (21,167,909 bbls oil, 85,764,150 MCF gas; 1967-79)
Muddy Unit
Recluse Field is located in northern Campbell County, about six
miles south of the Wyoming-Montana border, in Townships 56 and 57 North,
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Ranges 74 and 75 West. The field was discovered in August, 1967, with
the completion of producing wells in the "A" and "B" sands of the Lower
Cretaceous Muddy Sandstone. Average depth to the Muddy reservoir in the
Recluse Field area is 7,525 feet.
The Muddy Sandstone in the vicinity of Recluse Field is a complex
series of interbedded sands, shales, siltstones, and locally thin layers
of coal or lignite. It is considered the approximate stratigraphic
equivalent of the Newcastle Sandstone of the Fiddler Creek-Clareton area.
The average reservoir porosity and permeability are 16.8 percent and
87 millidarcies (permeability to air), respectively.
The productive limits of the Muddy reservoir, a stratigraphic hydro-
carbon trap, are defined by facies changes along the northeast, north-
west, and southeast boundaries. To the southwest, the boundary is formed
by a combination of facies changes and an oil-water contact. The depths
of the oil-water contacts vary as much as 183 feet in the downdip lobes
of the southwest boundary. The reservoir rock of the Muddy Sandstone
is described as white, fine- to medium-grained, friable, porous sand-
stone with occasional hairline shale streaks. The north half of Recluse
Field was initially producing under a solution gas drive, while the
southern part of the area will be produced primarily by a gas cap drive.
The Muddy Unit at Recluse Field covers 8,571.24 acres of federal,
state, and private lands. The federal, state, and patented leases are
divided among 30 working interest owners with the federal government
holding lease rights on about 82 percent of the productive area.
Water injection to the Muddy began in 1971, with water provided by
supply wells in the Fox Hills Sandstone and Lance Formation. of the 28
injection wells within the Muddy Unit waterflood, only six were active
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during the second half of 1979. Cumulative injection to the Muddy
reservoir, as of December, 1979, was 36,778,813 barrels (1.5447 x 10^
gallons) of water. The maximum average injection pressure during the
life of the waterflood has been 3,500 psi.
Casing Record: Injection Well #456, T56N-R74W-8 ab, Recluse Field,
Muddy Unit, Total Depth = 7680 feet.
Casing Size Mt. (///ft) Hole Size Depth Set Cement
8-5/8" 24 12-1/4" 317' 210 sacks
5-1/2" 14,15.5,17 7-7/8" 7680' 350 sacks
No. 6 Unit
The No. 6 Unit of Recluse Field is the site of a single well salt
water disposal system which was put into operation in 1977, by Eason Oil
Company. The disposal well is located in Section 22, Township 56 North,
Range 74 West, Campbell County, and is completed in the Muddy Sandstone.
As of June, 1979, cumulative injection of produced Muddy Sandstone
brine totaled 8,626 barrels (362,292 gallons).
Red Springs Field (13,286 bbls oil; 1919-79)
Frisby-Government Unit
An experimental tertiary oil recovery project at the Frisby-
Government Unit of Red Springs Field was initiated in 1976, by Coronado
Oil Company. The project involved the injection of water and steam
into the Tensleep Sandstone through five wells. As of December, 1978,
all of the wells were inactive and the project had apparently been
abandoned.
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Reel Field (5,863,528 bbls oil, 25,380 MCF gas; 1962-79)
Minnelusa Unit
The Minnelusa Unit of Reel Field includes the area within Sections
27, 28, and 29, Township 49 North, Range 69 West, Campbell County.
A secondary oil recovery waterflood project began at Reel Field in
1972, under the operation of Shell Oil Company. Fresh water for the
project is provided by a supply well in the Fox Hills Sandstone. Four
of the five existing injection wells were active during the last six
months of 1979. Cumulative injection between the start of the project
Q
and the end of that period was 9,695,285 barrels (4.072 x 10 gallons)
of water. Average injection pressures have ranged from a minimum of
1,250 psi to a maximum of 3,000 psi.
Casing Record: Injection Well //43, T49N-R69W-29 da, Reel Field,
Minnelusa Unit, Total Depth = 8700 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
8-5/8" 24 12-1/4" 415' 300 sacks
5-1/2" 15.5,20 7-7/8" 8698' 325 sacks
Reno Field (8,870,286 bbls oil, 176,979 MCF gas; 1965-79)
Reno Unit
The Reno Unit of Reno Field is located in the Powder River Basin
about fifteen miles northeast of Kaycee, Wyoming. The unit area
encompasses 1,474.72 acres, of which 933.14 acres are federally owned
and 541.58 acres are fee lands.
The Minnelusa water injection project is operated by the Shell Oil
Company and began in 1968, with injection into three wells. Both fresh
water from the Fox Hills Sandstone and produced water from the Minnelusa
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Formation are used in the waterflood project. The project was expanded
to six wells in 1970, and as of January, 1980, only three of the wells
were actively injecting. Between 1968 and 1980, 13,746,007 barrels
g
(5.7733 x 10 gallons) of water were injected into the Minnelusa
Formation. A breakdown by water source is not available.
The Minnelusa Formation is at a depth of approximately 15,000 feet
in the Reno Field area and has an average total thickness of 156 feet.
A water quality analysis was performed on May 5, 1967, on
Minnelusa water from well 12-18, located in T45N-R79W-18 be. Results
of the analysis are listed below:
TDS 3,564 mg/1
CI 1,550 mg/1
Na 743 mg/1
S04 440 mg/1
HC03 342 mg/1
Ca 435 mg/1
Mg 54 mg/1
pH 7.5
Hardness 1,308 mg/1 as CaCO^
Reynolds Ranch Field (723,488 bbls oil; 1972-79)
1 Sun T. P. State Unit
The only injection well at Reynolds Ranch Field is a salt water
disposal well completed in the Butler Sand at a depth of 5,221 feet.
The well is located in Section 1, Township 52 North, Range 68 West,
Crook County. Injection of produced brine started in 1973, and as of
December, 1978, a cumulative volume of 399,290 barrels (1.6782 x 10 ^
gallons) had been injected.
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East Riverton Dome Field (224,646 bbls oil, 55,330,889 MCF gas; 1965-79)
East Riverton Unit
In 1972, Continental Oil Company began injecting brine, produced
with oil from wells around East Riverton Dome Field, through a single
salt water disposal well. The well is located in Section 36, Township
1 South, Range 5 East, Fremont County. Produced brine is injected into
the Frontier and Nugget formations. Between 1972 and June, 1980,
1,446,547 barrels (6.0754 x 10^ gallons) of salt water were injected
through well //3.
Robinson Ranch Field (6,939,277 bbls oil; 1958-79)
Minnelusa Unit
The Minnelusa Unit participating area covers 880 acres of Robinson
Ranch Field, which is located about three miles east of Moorcroft, in
Township 50 North, Range 67 West, Crook County. The field was discovered
in 1958, and was federally operated until 1962. Low gas to oil ratios
and a limited water drive were indicated early in the life of the field.
The Minnelusa Formation in the Robinson Ranch area is a sandstone,
interlayered with beds of dolomite and anhydrite, forming a stratigraphic
trap where hydrocarbons have accumulated. The average depth to the top
of the Minnelusa pay zone is 6,027 feet. The accumulated oil is under-
lain by a water table which provides the major source of reservoir
energy.
A full scale gas-water injection program was approved by the
Wyoming Oil and Gas Conservation Commission on May 29, 1962. The
project is unusual in both technical and mechanical aspects. Technically,
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the plans called for a two phase injection of slugs of gas, followed by
water, with amounts and time intervals determined by a pilot injection
study. Mechanically, the "A" and "B" sands of the Minnelusa Formation
are separated by packers in the injection wells, permitting injection
of either fluid in either zone. In theory, the gas will lower the
viscosity of the oil and occupy void space within the reservoir. The
injected water will tend to maintain reservoir pressure and drive the
oil. The supply of water for the project is provided by production
wells at Robinson Ranch Field.
The productive area of the reservoir includes 462 acres. Six of
seven existing injection wells were active during the last six months
of 1979. As of December, 1979, a cumulative volume of 18,117,105
g
barrels (7.6092 x 10 gallons) of water had been injected at average
injection pressures ranging from 50 to 2,400 psi.
Rock River Field (37,082,926 bbls oil, 7,979,278 MCF gas; 1918-79)
Muddy Unit
Rock River Field is situated on one of several asymmetrical anti-
clines along the east slope of the Medicine Bow Mountains in Townships
19 and 20 North, Range 78 West, Carbon County. The east flank of the
anticline is severely faulted and dips toward the basin at angles up
to 70 degrees. The west flank dips back toward the mountains at angles
of 20 to 35 degrees. The structure has approximately 1,600 feet of
closure. An interesting feature of Rock River Field is the steep
gradient of the water table in the Muddy sand, estimated to be 750 feet
in 3.5 miles.
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The field was discovered in 1918, with the completion of a produc-
ing well in the Muddy Sandstone at a depth of 2,581 feet. Production
wells have also been completed in the Dakota and Lakota sands.
The Muddy reservoir covers 1,098 acres with an average pay zone
thickness of 14 to 20 feet. Average reservoir porosity and perme-
ability are 17.8 percent and 3.8 millidarcies, respectively.
A water injection project to enhance oil production from the
Muddy sand began in 1961. At that time, the project consisted of one
injection well and six producing wells. As of January, 1978, cumula-
tive injection to the Muddy through the same well was 4,730,666 barrels
g
(1.9869 x 10 gallons) of water from surface runoff ponds and from a
supply well in the Tensleep Sandstone. Average injection pressures
have ranged between 290 and 2,000 psi during the period between 1961
and 1978.
Injection well //ll (T19N-R78W-11 ba) was drilled to a total
depth of 5,661 feet. Seven inch casing was run to the total depth
and cemented with 250 sacks of cement. The top of the cement was
determined by temperature survey to be at 2,470 feet, or 586 feet
above the top of the Muddy Formation. A Baker bridge plug was set at
3,126 feet, thus isolating the Muddy from the other formations
encountered in the hole. Injection takes place through perforations
in the seven inch casing opposite the Muddy sand. Both the casing and
the Baker bridge were pressure tested prior to injection to insure that
all fluids injected are confied to the Muddy reservoir and cannot
escape to other formations.
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Cretaceous Unit
The Cretaceous Unit of Rock River Field covers an 1,890.18 acre
area of federal, state, and private land in Townships 19 and 20
North, Range 78 West, Carbon County. The Lakota reservoir underlying
the unit, covers about 1,500 acres with an average pay zone thick-
ness estimated to be 25 to 30 feet thick. The average reservoir
porosity is 16.1 percent and the geometric mean permeability is 24
millidarcies.
Water injection to the Lakota, Dakota, and Muddy sands in the
Cretaceous Unit participating area started in 1964. Cumulative
injection through the nine wells that are still actively injecting
was 7,578,336 barrels (3.1829 x 10^ gallons) as of January, 1979.
Water used for the injection project is obtaeind from a Tensleep
Sandstone supply well and from producing wells in the Cretaceous
Unit.
A single gas injection well is also currently active at the
Cretaceous Unit. The well is completed in the Lakota reservoir and
is utilized for pressure maintenance within the reservoir. The most
recent data available on the gas injection project are from December,
1967, when the two gas injectors were averaging 674,000 cubic feet
of gas per day to the Lakota sand.
Roehrs Field (520,323 bbls oil, 12,441 MCF gas; 1966-79)
Minnelusa Unit
The Minnelusa Unit of Roehrs Field covers 400 acres of federal
land in Township 53 North, Range 70 West, Campbell County. The average
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porosity and permeability of the Minnelusa reservoir in the Roehrs
Field area are 17.3 percent and 115 millidarcies, respectively. Primary
reservoir production mechanisms are fluid and rock expansion along with
partial water drive.
Water injection to the Minnelusa reservoir began in 1975, through
one well. During the last six months of 1979, the well was shut-in.
Cumulative injection to that point was 1,683,626 barrels (7.0712 x 10^
gallons) of fresh water provided by a Fox Hills Sandstone supply well.
Average injection pressures have ranged from a minimum of 1,175 psi to
a maximum of 2,950 psi.
Casing Record: Injection Well W-3, T53N-R70W-15 ad, Roehrs Field,
Minnelusa Unit, Total Depth = 7532 feet.
Casing Size Amount Cement
9-5/8" 156' 150 sacks
4-1/2" 753' 300 sacks
Rourke Gap Field (1,987,173 bbls oil; 1973-79)
Minnelusa Unit
Since 1975, the Minnelusa Unit at Rourke Gap Field has been the
site of a two well water injection project completed in the Minnelusa
Formation. The field is located in Township 48 North, Range 71 West,
Campbell County. The depth to the Minnelusa Formation in the Rourke
Gap area is about 10,100 feet.
Cumulative injection to the Minnelusa reservoir was 4,742,104
g
barrels (1.9917 x 10 gallons) of water from the Fox Hills Sandstone,
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as of December, 1979. Average injection pressures have ranged from
1,100 to 3,200 psi.
Casing Record: Injection Well #8, T48N-R71W-6 dca, Rourke Gap Field,
Minnelusa Unit, Total Depth = 10,378 feet
Casing Size Wt. (///ft) Hole Size Depth Set Cement Purpose
8-5/8" 24 12-1/4" 590' 520 sacks Surface
5-1/2" 17,24 7-7/8" 10377' 575 sacks Injection
Rozet Field (17,400,672 bbls oil, 8,815,316 MCF gas; 1959-79)
Muddy Unit
The Muddy Unit of Rozet Field covers an area of 6,638 acres
of federal, state, and private land in Township 50 North, Ranges
69 and 70 West, Campbell County. A secondary oil recovery water
injection project started at the Muddy Unit in 1968, with the injec-
tion of water from the Fox Hills Sandstone to the Muddy sand reservoir
through eight wells completed at depths between 6,500 and 7,200
feet.
The Muddy reservoir at Rozet Field is stratigraphically trapped
within the Mowry Shale above and the Skull Creek Shale below. By
1972, the waterflood had expanded to 33 wells. As of December, 1979,
25 wells were actively injecting and a cumulative volume of 42,018,857
9
barrels (1.7648 x 10 gallons) had been injected during the life of
the project. Injection pressures, averaged over each six-month period
at each active well, have ranged from a minimum of 118 psi to a
maximum of 3,700 psi.
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Casing Record: Injection Well Tr. 10 W-l, T50N-R69W-7 adc, Rozet Field,
Muddy Unit, Total Depth = 8555 feet.
Casing Size Wt. (///ft) Depth Set Cement
8-5/8" 24 308' 200 sacks
4-1/2" 11.6 7375" 750 sacks
Federal Campbell "A" Unit
Atlantic Richfield Company began operating a salt water disposal
well at the Federal Campbell "A" Unit of Rozet Field in 1975. The
well is completed in the Minnelusa Formation and is located in Section
11, Township 50 North, Range 70 West, Campbell County. Since 1975,
brine injection has averaged nearly 10,000 gallons per day. Cumulative
injection to January, 1980, was 428,970 barrels (1.8016 x lO'7 gallons)
of salt water. Average injection pressures have ranged from 700 to
1,208 psi.
East Rozet Field (2,361,701 bbls oil, 217,006 MCF gas; 1961-79)
Minnelusa Unit
The discovery of oil at East Rozet Field was made in June, 1965,
in the Minnelusa Formation. The Minnelusa Unit includes 600 acres of
federal, state, and private land in Township 59 North, Range 69 West,
Campbell County. Currently (December, 1979), there is one active
injection well within the Minnelusa Unit at East Rozet. The well is
completed in the Minnelusa reservoir at a depth of 8,108 feet. Water
for injection is provided by a supply well in the Fox Hills Sandstone.
Cumulative injection through 1979, was 1,151,089 barrels (4.8345 x 10^
gallons) of water. Injection pressures, averaged for each six-month
period, have been below 180 psi since injection began.
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Casing Record: Injection Well #1, T50N-R69W-20 aaa, East Rozet Field,
Minnelusa Unit, Total Depth = 8206 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
8-5/8" 24 12-1/4" 167' 145 sacks
Muddy Unit
The oil reservoir within the Muddy Sandstone at East Rozet Field,
was discovered in 1961, at a depth of approximately 8,100 feet. The
reservoir is stratigraphically trapped by overlying shales. The
porosity of samples from the Muddy Sandstone, that have a permeability
greater than one millidarcy, ranges from 5.9 to 25.5 percent and
averages 15 percent. The permeability of the same samples ranges from
1.3 to 251 millidarcies, and averages 63 millidarcies.
A water injection project at the Muddy Unit was initiated in 1975.
The cumulative volume of water injected to the Muddy reservoir was
230,844 barrels (9,695,448 gallons) as of December, 1979. Injection
pressures, averaged over six-month periods at the two active wells,
have ranged from 0 to 2,450 psi.
Casing Record: Injection Well Carroll-Duvall #1, T50N-R69W-21 acc,
East Rozet Field, Muddy Unit, Total Depth = 8301 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement Purpose
8-5/8" 24 12-1/4" 202' 175 sacks Surface
4-1/2" 9.5,10.5 7-7/8" 6773' 300 sacks Injection
South Rozet Field (4,573,763 bbls oil, 114,927 MCF gas; 1965-79)
North Minnelusa "A" Unit
South Rozet Field was discovered in 1965, when a producing well
was completed in the Minnelusa Formation at a depth of about 8,400 feet.
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The erratic stratigraphic nature of the Minnelusa, and the difficulty
of developing a field with undefined reservoir limits were pointed out
by the field's development during 1966. Of the 30 wells completed that
year, 19 were dry holes and only 11 were producing wells.
The Minnelusa Formation in South Rozet Field consists of at least
four lenticular sand bodies. The north and south areas of each of the
two upper and lower sands are isolated by a permeability pinchout in
the center of the field. The limits of the "A" sand, or upper sand, in
the north reservoir are primarily controlled by the thickness of the
Opeche Shale. Rock characteristics of the north Minnelusa "A" sand
were determined from analysis of electric and sonic log data, as well
as core data. The weighted average porosity was determined to be 17.8
percent. Permeability from 36 sample cores averaged 212 millidarcies.
A water injection well was completed in the Minnelusa in 1975, to
enhance the productivity of the reservoir. As of December, 1979,
1,590,027 barrels (6.6781 x 10^ gallons) of produced Minnelusa water
had been injected to the north "A" sand. Average injection pressures
have ranged from 600 to 2,433 psi during the project.
Casing Record: Injection Well //l, T50N-R69W-30 bb, South Rozet Field,
North Minnelusa "A" Unit, Total Depth = 8505 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement Purpose
9-5/8" 32.3 13-3/4" 322' 270 sacks Surface
5-1/2" 15.5,17 8-3/4" 8505' 500 sacks Injection
Mitchell State Unit
A second water injection project, at South Rozet Field, was
established at the Mitchell State Unit in Section 35, Township 50 North,
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Range 70 West, Campbell County. Water is provided by supply wells in
the Fox Hills Sandstone and injected into the Minnelusa reservoir.
Further details on the project were not available in the Oil and Gas
Commission petroleum files.
West Rozet Field (5,220,709 bbls oil, 11,385 MCF gas; 1967-79)
Minnelusa Unit
The Minnelusa Unit at West Rozet Field covers an area of 1,720
acres of federal, state, and private lands in Township 50 North, Range
70 West, Campbell County. The Minnelusa reservoir at West Rozet is
described as a vuggy, fractured, fine- to medium-grained, rose colored
sand with chert nodules.
Water injection to the Minnelusa Formation at a depth of 8,700+
feet started in 1971. By 1978, six injection wells were in operation.
Two of the wells are dually completed in the Minnelusa reservoir.
Cumulative injection, as of December, 1979, was 24,564,029 barrels
9
(1.0317 x 10 gallons) of produced Minnelusa water. Injection pressures,
averaged over each six-month period at each well since injection began,
have reached a maximum of 2,361 psi.
Casing Record: Injection Well W-4, T50N-R70W-27 da(cd), West Rozet
Field, Minnelusa Unit, Total Depth = 8844 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement Purpose
8-5/8" 24 12-1/4" 339' 300 sacks Surface
4-1/2" 10.5,13.5 7-7/8" 8842' 400 sacks Injection
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Ruben Field (4,309,088 bbls oil, 4,874,223 MCF gas; 1969-79)
Ruben Unit
The Ruben Unit of Ruben Field includes 1,298.5 acres of federally
owned land, situated on a monoclinal structure in Township 30 North,
Ranges 112 and 113 West, Sublette County. The structural dip in the
area is to the northeast at 1.5 to 2 degrees. Oil and gas production
in the area is from two lenticular lower Almy sands of Eocene age at
depths of 3,300 and 3,600 feet. The sands are elongated in a north-
south direction. Production limits of the Almy reservoirs are defined
by the pinchout of both sands updip to the west, and by the oil-water
contact to the east. The area encompassed by each of the reservoirs,
called the Stray 3 and Stray 4 sands, is approximately 750 acres. The
average thickness and porosity of the Stray 3 sand are 19.8 feet and
13.4 percent, respectively. In the Stray 4 sand, the average thickness
and porosity are 15.7 feet and 13.4 percent, respectively.
Injection of water from a supply well in the Knight sand to the
Almy sands began in 1970. The waterflood project is operated by Belco
Petroleum Corporation. Six of the nine existing injection wells at the
Ruben Unit are dually completed in the Stray 3 and 4 sands. As of
December, 1979, the cumulative volume of water injected to the Almy was
g
6,290,429 barrels (2.642 x 10 gallons). Average injection pressures
have ranged from 500 to 2,750 psi. Seven of the wells were active
during the last six months of 1979.
Casing Record: Injection Well #3, T30N-R112W-19 cad, Ruben Field,
Ruben Unit, Total Depth = 3640 feet.
Casing Size
8-5/8"
5-1/2"
Wt. (///ft)
24
14,15.5
Hole Size
12-1/4"
7-7/8"
Depth Set
228'
3640
200 sacks
150 sacks
Cement
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Ryckman Creek Field (3,782,786 bbls oil, 1,234,288 MCF gas; 1976-79)
Ryckman Creek Unit
Since 1977, the Ryckman Creek Unit has been the site of a single
well salt water disposal system and a five well gas injection project.
The unit is located in Township 17 North, Ranges 118 and 119 West,
Uinta County, and includes 1,235.83 acres of federal and private land.
The purpose of the gas injection project is to enhance oil and
gas production from the Nugget Sandstone. The Nugget reservoir is
encountered at depths between 7,200 and 7,600 feet in the Ryckman
Creek area. All five injection wells were active during the last six
months of 1979., Cumulative injection through December, 1975, was
5,754,420 MCF of natural gas. Injection pressures, averaged over each
six-month period between 1977 and December, 1979, ranged between 1,345
and 2,358 psi.
The salt water disposal well is located in Section 25, Township
17 North, Range 119 West. Injection is to the Nugget Formation at a
depth of 7,581 feet. Cumulative injection to the Nugget, through June,
1980, was 862,323 barrels (3.6217 x 10^ gallons) of produced brine.
Average injection pressures have ranged from 50 to 280 psi.
Sage Creek Field (9,216,952 bbls oil; 1948-79)
Tensleep Unit
Sage Creek Field is situated on the asymmetrical Frannie anticline
in Township 57 North, Range 97 West, Big Horn and Park counties.
Contours on the top of the Frontier Formation indicate that Sage Creek
Field is a second dome on the anticlinal structure, with less than 200
feet of closure. Oil was discovered at Sage Creek in 1948, with the
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completion of a productive well in the Madison Limestone. The discovery
of Tensleep oil did not occur until 1953.
Shortly thereafter, the Tensleep Unit was established in order to
more efficiently exploit the resources underlying the area. Sohio
Petroleum Company became the operator of the Tensleep Unit, a 737.6
acre area of federal and private land. Water injection through one well
began at the Tensleep Unit of Sage Creek Field in 1971. Another well
was added in 1976. Water for the project is obtained from Tensleep
producing wells. Cumulative injection through December, 1979, was
g
12,869,573 barrels (5.4052 x 10 gallons) at average injection pressures
between 400 and 1,200 psi.
Sage Spring Creek Field (10,788,558 bbls oil, 3,342,399 MCF gas; 1949-79)
Dakota "A" Unit
Sage Spring Creek Field is located in Townships 36 and 37 North,
Range 77 West, Natrona County. Seismic studies have outlined the under-
lying structure of the field as a south-plunging anticlinal nose. The
Sage Spring Creek discovery well was completed in the Dakota sand in
1949.
The Dakota "A" Unit covers a 1,845.79 acre area of federal
(1,346.46 acres), state (100 acres), and private (399.33 acres) land
and was established during the 1950's. The injection of water to
enhance the productivity of oil from the Dakota sand was started in
1972, through four wells. The fifth well was added in 1975. All of
the wells are completed in the Dakota reservoir at depths between 7,300
and 7,500 feet. Water for the project is obtained from supply wells
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in the Parkman Sandstone. To January, 1980, cumulative injection amounted
g
to 7,501,685 barrels (3.1507 x 10 gallons). All five wells were active
during the last half of 1979.
Casing Record: Injection Well //A-19, T37N-R77W-29 cdb, Sage Spring
Creek Field, Dakota "A" Unit, Total Depth = 7556 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
10-3/4" 40.5 13-3/4" 333' 200 sacks
4-1/2" 9.5,10.5,11.6 7-7/8" 7555' 225 sacks
Salt Creek Field (575,972,623 bbls oil, 711,185,987 MCF gas; 1889-1979)
Salt Creek oil and gas field is located in Townships 39 and 40
North, Ranges 78 and 79 West, Natrona County, and is one of the largest
oil fields in the entire Rocky Mountain region.
Oil seeps were reported in the Salt Creek Field area before 1880,
in the accounts of the early settlers of east-central Wyoming. The
first well was drilled to the Shannon Sandstone on the north end of the
Salt Creek dome in 1889. The Shannon reservoir covers about 160 acres
at a depth of 700 to 1,000 feet. The Shannon Formation crops out less
than two miles south of the original well and forms the escarpment
around the Salt Creek dome.
Several minor oil finds were made in Upper Cretaceous shales in
1906, but it wasn't until 1908, that the Salt Creek dome attracted the
attention of the oil producing companies. During that year, a well
drilled to the first Wall Creek sand came into production at a rate of
200 barrels of oil per day. During the subsequent 46 years, the
following formations came into production at Salt Creek Field: second
Wall Creek sand, 1917; Lakota Sandstone, 1921; third Wall Creek sand,
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1924; second Sundance sand and Lakota shale, 1925; third Sundance sand,
1926; Morrison, 1929; Tensleep Sandstone, 1930; first Sundance sand,
1953; and Fishtooth shale, 1954.
By December, 1979, there were eight active water injection opera-
tions at Salt Creek Field. The Light Oil Unit - first, second, and
third Wall Creek projects are operated by Amoco Production Company.
Terra Resources, Inc., operates the Staley Government and Salt Creek
South Units. At East Salt Creek Field, Atlantic Richfield Company
operates water injection projects in the Second Wall Creek and Tensleep
units, and Kewanee Oil Company is the operator of the waterflood at
the Second Wall Creek Unit of West Salt Creek Field.
Staley Unit
The Staley Unit of Salt Creek Field is located in Townships 39 and
40 North, Range 78 West, Natrona County. Water injection to the second
Wall Creek sand started in 1963, and by 1969, had expanded to a full
scale, ten well waterflood. The Madison Limestone is the source forma-
tion for water. All of the injectors are completed at depths between
1,900 and 2,150 feet.
Cumulative injection, as of December, 1979, was 61,446,728 barrels
9
(2.5808 x 10 gallons) of Madison water at average injection pressures
ranging from 400 to 1,375 psi.
Casing Record: Injection Well #37, T40N-R78W-31 ccd, Salt Creek Field,
Staley Unit, Total Depth = 2,123 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
8-5/8"
4-1/2"
9.5
24
12-1/4"
7-7/8"
2116
32
150 sacks
10 sacks
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Light Oil Unit - First Wall Creek Sand
The Light Oil Unit at Salt Creek Field was established in
September, 1939, and covers 15,338 acres in Townships 39 and 40
North, Ranges 78 and 79 West, Natrona County. The water injection
project in the Light Oil Unit first Wall Creek sand started in January,
1955. The injection well configuration was a twin five-spot pattern.
Expansion to a full scale waterflood took place between 1957 and 1961,
and by 1979, 262 wells had been completed in the first Wall Creek
sand. Within 6 months of the start of the pilot project oil produc-
tion increased by more than 500 barrels per day.
The first Wall Creek reservoir includes 4,035 acres with an
average pay zone thickness of 80 feet. Core analyses indicate an
average porosity and permeability of 16 percent and 80 millidarcies,
respectively. The water source for the injection project is the Madison
Limestone. A water supply well, capable of providing 80,000 gallons
per day, was drilled for the project.
The cumulative volume of Madison water injected since the pilot
project began was 798,729,371 barrels (3.3547 x 10"^ gallons) as of
December, 1979. Reported average injection pressures during that
period did not exceed 500 psi. During the last six months of 1979,
171 of the wells were actively injecting.
Casing Record: Injection Well #33, T40N-R79W-13 cc, Salt Creek Field,
Light Oil Unit - First Wall Creek Sand, Total Depth =
1710 feet.
Casing Size Wt. (///ft) Depth Set Cement
13-3/8" 45 113' 10 sacks
10-3/4" 45 1219'
8-5/8" 20 1459' 210 sacks
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Light Oil Unit - Second Wall Creek Sand
The second pilot water injection project at the Light Oil Unit
started in June, 1960, with injection to the second Wall Creek sand.
It was expanded to a full scale flood in November, 1961.
The second Wall Creek reservoir covers more than 15,000 acres at
Salt Creek Field, with an average pay thickness of 59 feet and average
porosity and permeability, from core analyses, of 18 percent and 100
millidarcies, respectively. The original producing mechanism of the
reservoir was solution gas drive. Water injection is generally updip
from the reservoir and supplements natural gravity drainage.
Four water supply wells completed in the Madison Limestone provide
water for the injection project. The combined open flow from the wells
is over 250,000 barrels (1.05 x lo'' gallons) per day. Water from the
Madison comes out of the supply wells at 184°F. A chemical is added to
the water, prior to injection, to control sulfate reducing bacteria.
Produced water from the Tensleep Sandstone is also injected.
As of December, 1979, there were 406 injection wells completed in
the second Wall Creek sand of the Light Oil Unit. Of that total, 346
were injecting during the last six months of 1979. The remainder of
the wells are temporarily or permanently shut-in. Cumulative injection
through 1979, was 1,392,890,952 barrels (5.8501 x 10"^ gallons) of
water.
Casing Record: Injection Well //9, T40N-R79W-23 bb, Salt Creek Field,
Light Oil Unit - Second Wall Creek Sand.
Casing Size Wt. (///ft) Depth Set Cement
13" 45 87' 10 sacks
8-5/8" 28 1447' 60 sacks
7" 20 1586'
5-1/2" 14 1536-1704'
(liner)
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Light Oil Unit - Third Wall Creek Sand
Water injection into the third Wall Creek sand at the Light Oil
Unit of Salt Creek Field started in 1969. The depth to the third Wall
Creek reservoir is about 1,800 feet. Water for the injection project
is obtained from supply wells in the Madison Limestone. Only three of
the nine existing injectors were active during the second half of 1979.
The other wells were temporarily shut-in. Cumulative injection as of
December, 1979, was 6,719,260 barrels (2.8221 x 10^ gallons) of water.
Casing Record: Injection Well //22, T40N-R79W-34 dd, Salt Creek Field,
Light Oil Unit - Third Wall Creek Sand, Total Depth =
1874 feet.
Casing Size Wt. (///ft) Depth Set Cement
12-1/2" 45 49' 10 sacks
8-1/4" 28 1522' 40 sacks
6-5/8" 20 1832'
South Unit
The second Wall Creek reservoir of the South Unit at Salt Creek
Field covers a 6,110 acre area with an average pay zone thickness of
25 feet. The primary producing mechanisms of the reservoir were solu-
tion gas drive and gravity drainage. Average reservoir porosity and
permeability are 16 percent and 4 millidarcies, respectively, at well
//12—159 (T39N-R79W-12 ab) . The second Wall Creek sand is found at a
depth of 1,950 to 2,600 feet in the South Unit area.
The South Unit is located in Township 39 North, Ranges 78 and 79
West, Natrona County. The second Wall Creek sand water injection
project at South Unit began in August, 1962, with four wells. Water
for the project was obtained from supply well //I drilled to the Madison
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Limestone. The original injection wells were located along the north
and south unit boundaries to prevent oil from migrating across them.
During the last 18 years, the project has been expanded to include
157 injection wells, of which 116 were actively injecting during
the second half of 1979. The rest were either shut-in for that
period, or were previously abandoned. Cumulative injection through
all wells as of December, 1979, was 497,193,754 barrels (2.0882 x 10^
gallons) of water from the Madison Limestone. Average injection
pressures during the project's lifetime have ranged from 17 to 3,040 psi.
Salt Creek Unit
Amoco Production Company started a four well tertiary oil recovery
injection project in 1972, at Salt Creek Field. The project involves
the injection of a water/micellar solution into the Wall Creek Sand-
stone. Further details were not available from files at the Oil and
Gas Commission.
East Salt Creek Field (11,721,277 bbls oil, 790,130 MCF gas; 1951-79)
Second Wall Creek Unit
The discovery well at East Salt Creek Field was a dual completion
well in the second Wall Creek and Lakota sands, and began producing in
December, 1951. The second Wall Creek reservoir covers 440 acres with
an average pay zone thickness of 28 feet. The average porosity and
permeability of the reservoir are 19 percent and 26 millidarcies,
respectively.
The participating area of the Second Wall Creek Unit overlies the
reservoir in Sections 4, 9, 10, and 22, Township 40 North, Range 78
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West, Natrona County. Late in 1966, the East Salt Creek waterflood
agreement was approved. Water injection to the second Wall Creek sand
began in May, 1967. By 1975, five wells were injecting water from
Tensleep Sandstone production wells- As of December, 1979, only three
wells remained on active status and cumulative injection totaled
g
14,497,601 barrels (6.09 x 10 gallons) of water since the waterflood
started. Average injection pressures have ranged between 200 and 1,676
psi.
Lakota Unit
The start of the water injection project at the Lakota Unit of
East Salt Creek Field also occurred in May, 1967. The sole Lakota
Sandstone injector was shut-in a few years later and has not been
utilized since. A total of 538,425 barrels (2.2613 x 10^ gallons) of
produced Tensleep water was injected while the well was active. Average
injection pressures ranged from 400 to 1,750 psi.
Tensleep Unit
The first oil production from the Tensleep Sandstone at East Salt
Creek Field took place in October, 1956. Water injection to enhance
production from the Tensleep reservoir started in 1970, through one
well. The Tensleep Unit is located in Township 40 North, Range 78 West,
Natrona County. The reservoir is encountered at a depth of 7,472 feet
in the unit area. Cumulative injection during the past ten years
0
totaled 4,443,722 barrels (1.8664 x 10 gallons) of produced water from
the Tensleep Sandstone. Injection pressures averaged over each six
month period have ranged between 353 and 1,450 psi.
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West Salt Creek Field (1,746,305 bbls oil, 4,003 MCF gas; 1917-79)
West Unit
West Salt Creek Field is located in Township 40 North, Range 79
West, Natrona County, just to the west of the structural axis of the
Bothwell syncline. The field was discovered as a result of step-out
drilling at Salt Creek Field. Oil was found in the Niobrara-Carlile
sands at about 2,200 feet, the second Wall Creek sand at about 2,600
feet, and the Fishtooth sand from 742 to 790 feet.
The injection of water from the Madison Limestone to the second
Wall Creek reservoir started in July, 1964, through ten wells arranged
peripherally around the West Unit. The Madison water, which contained
hydrogen sulfide, was chemically treated prior to injection. The
waterflood project was shut-in during 1979. Cumulative injection at
g
the time the wells were shut-in was 8,776,474 barrels (3.6861 x 10
gallons). Average injection pressures ranged from 205 to 1,310 psi.
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Semlek Field (3,251,630 bbls oil, 31,792 MCF gas; 1962-79)
B-2 Mellott Unit
In 1970, Texaco, Inc. started a salt water disposal project at
Semlek Field in the B-2 Mellott Unit, located in Township 52 North,
Range 68 West, Crook County. Produced brine is injected into the
Dakota-Lakota sands at a depth of 5,449 feet. As of June, 1980,
12,802,139 barrels (5.3769 x 10^ gallons) of salt water had been
injected.
Casing Record: Salt Water Disposal Well ill, T52N-R68W-27, Semlek
Field, B-2 Mellott Unit, Total Depth = 7024 feet.
Casing Size Wt. (///ft) Depth Set Cement
10-3/4" 40.5 302' 190 sacks
7" 20,23,26,29 6998' 725 sacks
West Semlek Field (4,814,625 bbls oil; 1962-79)
West Unit
A pair of water injection projects are currently (June, 1980)
active at the West Unit of West Semlek Field. The first project, a
secondary recovery waterflood of the "A" sand of the Minnelusa Forma-
tion, started in 1972, and is operated by Terra Resources, Inc.
Cumulative injection data and average injection pressures were not
available at the time of this writing.
The second injection project is a single well salt water disposal
system, completed in the "C" sand of the Minnelusa Formation. Disposal
of produced Minnelusa brine started in 1978, through a well located in
Section 28, Township 52 North, Range 68 West, Crook County. Cumulative
injection through June, 1980, was 508,949 barrels (2.1375 x 10^ gallons)
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of brine. Injection pressures averaged over each six month period ranged
between a minimum of 1,250 psi and a maximum of 2,734 psi. The depth
to the Minnelusa Formation is 7,420 feet at the well site.
Casing Record: Salt Water Disposal Well //8, T52N-R68W-28 bd, West
Semlek Field, West Unit, Total Depth = 7575 feet.
Casing Size Wt. (///ft) Depth Set Cement
5-1/2" 17 45',841' 565 sacks
5-1/2" 15.5 6705' 460 sacks
Sharp Field (218,428 bbls oil, 11,150 MCF gas; 1975-79)
Minnelusa Unit
The Minnelusa Unit of Sharp Field is located in Township 49 North,
Range 71 West, Campbell County. The field was discovered in 1975, when
a producing well was completed in the Minnelusa Formation. The Minnelusa
reservoir is found at a depth of about 10,100 feet in the Sharp Field
area and has an average porosity of 15.5 percent.
Anderson Oil Company began water injection to the Minnelusa
reservoir in 1977, with water obtained from the Fox Hills Sandstone.
In 1979, a second well was added to the waterflood. Cumulative injection
through December of that year was 501,467 barrels (2.1061 x 10^ gallons).
Average injection pressures have ranged from 1,300 to 2,900 psi.
Casing Record: Injection Well Wolfe //1, T49N-R71W-29 ba(bc) , Sharp
Field, Minnelusa Unit, Total Depth = 10,390 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement Purpose
8-5/8" 24 12-1/4" 714' 460 sacks Surface
5-1/2" 15.5,17 10,269' 3 25 sacks Injection
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Northwest Sheldon Dome Field (3,352,618 bbls oil, 1,753 MCF gas; 1954-79)
Tribal "A" Unit
The Tribal "A" Unit of Northwest Sheldon Dome Field is the site of
a two well salt water disposal system started in 1969, and operated by
Skelly Oil Company. Produced brine, from wells completed in the
Triassic Crow Mountain Sandstone, is injected to the Crow Mountain
reservoir. Cumulative injection and pressure data for the disposal
project were not available at the time of this writing.
Shoshone Field (2,321,820 bbls oil; 1929-79)
Crickett Unit
Shoshone Field is located in Township 53 North, Range 101 West,
Park County, and is the site of a single well salt water disposal
system completed in the Permian Phosphoria Formation at a depth of
4,378 feet. Injection of produced brine into the Phosphoria started
in 1972, and is operated by Husky Oil Company. Cumulative injection
as of June, 1979, was 936,161 barrels (3.9318 x 10^ gallons) of salt
water. Average injection pressures have ranged from 1,444 to 2,302
psi during the period from 1972 to June, 1979.
Casing Record: Salt Water Disposal Well //2, T53N-R101W-28, Shoshone
Field, Crickett Unit, Total Depth = 4378 feet.
Casing Size Wt. (///ft) Depth Set Cement
7" 20,23 4378' 101 sacks
Silver Tip Field (4,504,523 bbls oil, 26,765,455 MCF gas; 1948-79)
Silver Tip Unit
Silver Tip Field was discovered in April, 1948, when a producing
well was completed in the Phosphoria Formation. It began producing oil
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and gas at a rate of 1,200 barrels and 4.2 million cubic feet,
respectively, per day. Production of oil from the Frontier Formation
and Tensleep Sandstone began during the same month.
The Silver Tip Unit was approved in November, 1953, with Texaco,
Inc., as the unit operator. A gas injection and a water injection
project have operated in the field since unitization. A gas injection
project in the Phosphoria Formation was discontinued because of
mechanical and safety problems related to the handling of hydrogen
sulfide rich "sour gas." The other was a water injection project in
the Frontier Formation. The project was started in 1961, but was
discontinued in 1966, due to a lack of injectable water. There was
also no evidence of increased production from the Frontier as a result
of water injection.
A salt water disposal well, perforated in the Phosphoria and
Tensleep formations, was placed in operation during 1979. The top of
the Phosphoria Formation is encountered at a depth of 8,620 feet in
the Silver Tip area. Cumulative injection and average pressure data
were not available at the time of this writing.
Casing Record: Salt Water Disposal Well #37, T58N-R100W-28, Silver
Field, Silver Tip Unit, Total Depth = 8815 feet.
Casing Size Depth Set Cement
13-3/8" 367' 275 sacks
7" 8620' 600 sacks
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Simpson Ranch Field (160,570 bbls oil, 38,374 MCF gas; 1971-79)
Simpson Ranch Unit
The Simpson Ranch Unit of Simpson Ranch Field is the site of a
two well water injection project completed in the Minnelusa Formation
at a depth of about 7,850 feet. The waterflood was initiated in 1979,
and is operated by Davis Oil Company. The Minnelusa reservoir at
Simpson Ranch Field has an average porosity of 12.6 percent.
Cumulative injection data were reported only for the //I well.
As of November, 1979, 120,527 barrels (5,012,634 gallons) of water
from the Fox Hills Sandstone had been injected through that well. The
other injection well (#3) has been temporarily shut-in.
Casing Record: Injection Well //3, T51N-R69W-15 bdd, Simpson Ranch
Field, Simpson Ranch Unit, Total Depth = 7960 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
9-5/8" 36 13-1/2" 305' 300 sacks
5-1/2" 15.5 8-3/4" 7960' 350 sacks
Skull Creek Field (10,807,674 bbls oil, 1,417,608 MCF gas; 1946-79)
Skull Creek Field, located approximately seven miles southwest of
Newcastle, in Townships 44 and 45 North, Range 62 West, Weston County,
was discovered in April, 1946. The discovery well was completed in
the Lower Cretaceous Newcastle Sandstone.
The productive reservoir consists of three or four porous intervals
in some areas of Skull Creek Field, and only one interval in other
sections of the field. Stratigraphic cross-sections based on electric
logs indicate that the separate intervals merge in some areas, thereby
forming a common oil reservoir. This has been further substantiated
by the production history of the reservoir.
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The Newcastle sand varies in composition from a clean sand to
a shaley sand with, in some cases, a considerable amount of carbona-
ceous material. The average depth to the Newcastle Sandstone at Skull
Creek is about 3,300 feet.
Structural contours, on the top of the Newcastle Sandstone,
reveal a monoclinal structure with a gentle dip of 150 feet per mile
to the southwest. The productive limits of the reservoir are defined,
primarily, by sand pinchouts, except to the southwest, where an oil-
water contact is encountered.
Six separate water injection projects are currently operating at
Skull Creek Field and another waterflood at North Skull Creek Field
is also active. All of the injection wells were completed by cement-
ing casing through the productive interval and selectively perforating
in the objective sand.
Skull Creek Unit
The Skull Creek Unit of Skull Creek Field introduced the first
Newcastle reservoir waterflood in 1965. The one well injection
project was expanded in subsequent years, and by 1968, included 11
injection wells completed in the Newcastle Sandstone at depths between
3,100 and 3,400 feet.
The Newcastle reservoir covers 1,541 acres with an average pay
zone thickness of about 12 feet. Reservoir behavior indicates that the
primary mechanism of production has been by solution gas drive and that
the lenticular character of the sand bodies has inhibited access to any
significant natural water drive. The initial reservoir pressure, in
1946, was 1,385 psi. A bottom hole pressure survey in November, 1957,
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showed that the reservoir pressure had declined to 978 psi. The bottom
hale pressure was estimated at 100 to 200 psi in 1964.
In order to increase the reservoir pressure and enhance oil
production from the Newcastle reservoir, water injection was initiated.
The water supply for the flood is obtained from wells in the Lakota
and Dakota sands. As of December, 1979, 17,257,191 barrels (7.248 x
g
10 gallons) had been injected since the project started. Average
injection pressures during that time ranged from 225 to 2,215 psi.
Casing Record: Injection Well #26, T44N-R62W-22 bb, Skull Creek Field,
Skull Creek Unit, Total Depth = 3375 feet.
Casing Size Wt. (///ft) Amount Perforations Purpose
8-5/8" 24 151.12'' None Surface
5-1/2" 14 3374.26' 3302-3306' Injection
Newcastle Unit
The Newcastle Unit of Skull Creek Field covers an area of 2,200
acres: 880 acres of federal land, 220 acres of state land, and 1,100
acres of privately owned fee land. A water injection project at the
unit was started in 1970, and is operated by Texaco, Inc.
The Newcastle Sandstone is found at a depth of around 3,000 feet
in the unit participating area, has average thickness of 50 feet, and an
average pay zone thickness of 8 to 38 feet near the bottom of the
formation. Analyses of cores indicate an average reservoir porosity
and permeability of 15.8 percent and 89 millidarcies, respectively.
Injection began in nine wells during 1970, and by 1975, the project
had been expanded to 12 wells. As of December, 1979, three of the
wells were shut-in and cumulative injection totaled 6,505,138 barrels
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(2.7322 x 10 gallons) of water from the Dakota sand. Average injection
pressures have not exceeded 1,950 psi during the first ten years of
injection.
Casing Record: Injection Well //D-511, T44N-R62W-11 caa, Skull Creek
Field, Newcastle Unit, Total Depth = 2980 feet.
Casing Size Wt. (///ft) Amount Purpose
10-3/4" 32.75 154.67' Surface
7" 20 2977.58' Injection
Donielson Unit
Water injection at the Donielson Unit of Skull Creek Field was
started in 1974, by Grace Petroleum Company. All of the seven injection
wells are located in Section 10, Township 44 North, Range 62 West,
Weston County. Water from the Fox Hills Sandstone is injected into the
Newcastle reservoir at a depth of just over 3,000 feet. Six of the
seven existing wells were actively injecting during the last six months
of 1979; however, cumulative injection volumes were not available from
the injection reports on file at the Oil and Gas Commission. Average
injection pressures have ranged between 1,000 and 1,700 psi during the
first six years.
Casing Record: Injection Well //W-8, T44N-R62W-10 deb, Skull Creek
Field, Donielson Unit, Total Depth = 3114 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement Purpose
7" 9" 106' 60 sacks Surface
4-1/2" 9.5 6-1/4" 3100' 100 sacks Injection
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Bock Unit
The Bock Unit of Skull Creek Field is operated by L and R Drilling
Company, and is currently (June, 1980) the site of a five well water
injection project. The wells are located in Sections 5, 7, and 8,
Township 44 North, Range 62 West, Weston County. During the last six
months of 1979, three of the wells were actively injecting water from
the Dakota and Lakota sands into the Newcastle Sandstone reservoir.
Cumulative injection between 1970 and December, 1979, amounted to
456,064 barrels (1.9154 x 10^ gallons) of water injected at average
pressures ranging from 110 to 1,695 psi.
Casing Record: Injection Well #12W, T44N-R62W-7 dac, Skull Creek
Field, Bock Unit, Total Depth = 3490 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement Purpose
5-1/2" 15.5 8-3/4" 3490' 150 sacks Injection
String
South Unit
The South Unit of Skull Creek Field covers 960 acres of federal
land and, since 1966, has been operated by American Petrofina. A
waterflood pilot project started in 1966, and was expanded to a full
scale, five well flood by 1972. Water for the injection project is
provided by a supply well completed in the Lakota Sandstone. Cumulative
g
injection, through December, 1979, was 5,655,017 barrels (2.3751 x 10
gallons) of water. The maximum average injection pressure reached
during the last 14 years of injection was 2,250 psi.
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Casing Record: Injection Well #3-27, T44N-R62W-27 ca, Skull Creek
Field, South Unit, Total Depth = 3380 feet.
Casing Size
8-5/8"
4-1/2"
Wt. (///ft)
24
9.3
Amount Perforations
3380'
153'
3311-3314'
Purpose
Surface
Inj ection
North Skull Creek Field (1,409,042 bbls oil, 1,381,553 MCF gas; 1946-79)
North Unit
North Skull Creek Field is located in Township 45 North, Range 62
West, Weston County. A pilot waterflood was put into operation in 1972,
and was expanded to a nine well system during the next year. All
injection wells are perforated in the Newcastle Sandstone between 2,850
and 3,100 feet. Water for the flood is pumped from the Newcastle and
Lakota sandstones. As of December, 1979, 2,457,170 barrels (1.032 x
g
10 gallons) had been injected into the Newcastle reservoir. Injection
pressures averaged over each six month period of injection at each well,
ranged from 26 to 1,704 psi. During the second half of 1979, eight of
the wells were actively injecting.
Slick Creek Field (4,722,094 bbls oil, 6,592,426 MCF gas; 1950-79)
Slick Creek Unit
Slick Creek Field was discovered on October 8, 1950, when a pro-
ducing well was completed in the Phosphoria Formation. It began
producing at a rate of 732 barrels of oil and 797,000 cubic feet of
sour (19.8 percent hydrogen sulfide) gas per day. The field is located
about two and one-half miles southeast of Worland in Sections 32 to 35,
Township 47 North, Range 92 West, and Sections 2 and 3, Township 46
North, Range 92 West, Washakie County. Core analyses of the Phosphoria
indicate that the average effective porosity of the producing zone
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(10,460 to 10,554 feet in the discovery well) is 9 percent. Only 26
feet, near the bottom of the cored zone, tested permeable. The Phosphoria
reservoir area covers 1,967 acres with an average pay zone thickness of
20 feet.
Slick Creek Field was unitized for operation in July, 1950, with
Mobil Oil Corporation as unit operator. A total of 3,675 acres is
committed to the Unit. Injection of water, purchased from the City of
Worland, into the Phosphoria Formation and the Muddy Sandstone, started
in July, 1965. Recent data from Slick Creek were unavailable. As
of January, 1970, 3,234,016 barrels (1.3583 x 10^ gallons) of water had
been injected through two of the three wells. One of the wells was
reconverted for production. Average injection pressures have ranged
from 1,600 to 2,850 psi.
In 1970, Tenneco Oil Company started disposing of produced salt
water from the Phosphoria Formation through a well located in Section
35, Township 46 North, Range 92 West, Washakie County. The well is
completed in the Cody Shale at an unreported depth. Further details on
the disposal system were unavailable at the time of this writing.
Casing Record: Injection Well //8, T47N-R92W-34 bdd, Slick Creek Field,
Slick Creek Unit, Total Depth = 10,553 feet.
Casing Size Top of Cement Amount
13-3/8" 500' 360 sacks
7" 10375' 400 sacks
5" 3000'
Spence Dome Field (353,401 bbls oil; 1944-79)
Koch Production Company started the operation of a pair of single
well salt water disposal systems in the Spence Dome and Western Giant
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units of Spence Dome Field during 1976. Spence Dome Field is located
in Township 54 North, Range 94 West, Big Horn County. Both systems
are completed in the Madison Limestone. Cumulative injection totals
are only available for the Spence Dome Unit system and indicate that
2,081,056 barrels (8.7404 x 10^ gallons) of produced brine from Spence
Dome Field had been injected as of December, 1979. Injection pressures
have not exceeded 10 psi during the four years of record.
South Spring Creek Field (12,486,841 bbls oil, 1,402 MCF gas; 1929-79)
In 1965, Texaco, Inc. initiated the first of two salt water disposal
systems at South Spring Creek Field in Township 49 North, Range 102
West, Park County. The first system consisted of two wells in the
South Spring Creek Unit of the field.
Both wells were completed in the Madison Limestone at depths of
4,640 and 4,840 feet, respectively. As of December, 1978, both wells
were on active status and the cumulative volume of injected brine was
204,063,019 barrels (8.5706 x 10^ gallons).
The second disposal system began injecting produced salt water to
the Madison Limestone through one well in 1976. The well is completed
at a depth of 4,570 feet and open to the formation for 280 feet. The
disposal well is located in the Phelps Unit of South Spring Creek Field
in Section 2, Township 49 North, Range 102 West, Park County. As of
December, 1978, 21,954,269 barrels (9.2208 x 10^ gallons) of brine had
been injected into the Madison since the system began operating.
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Casing Record: Salt Water Disposal Well //7, T49N-R102W-12, South
Spring Creek Field, South Spring Creek Unit, Total
Depth = 4771 feet.
Casing Size Wt. (///ft) Depth Set Cement
13-3/8" 48,54.5 236' 190 sacks
9-5/8" 36,40 4750' 421 sacks
Springen Ranch Field (9,396,961 bbls oil, 13,909,559 MCF gas; 1968-79)
Muddy Unit
Springen Ranch Field is located in Townships 50 and 51 North,
Range 71 West, Campbell County. The field was discovered in 1968, when
a productive oil well was completed in the Muddy Sandstone. In the
Springen Ranch area, the porosity and permeability of the Muddy reser-
voir are highly variable. Core samples from Muddy injection wells
show porosities ranging from 2 to 15 percent and permeabilities that
average between 2.4 and 588 millidarcies.
A water injection project, operated by Amoco Production Company,
started in 1973, at the Muddy Unit of Springen Ranch Field. Sixteen
wells began injecting water to the Muddy reservoir at an average depth
of about 7,600 feet. One well was added to the system in 1976, and
four more wells began injecting in 1977. Water for the project is
obtained from the Fox Hills Sandstone and Lance Formation and from
producing wells in the Muddy Sandstone.
Injection reports from November, 1979, indicate that a cumulative
g
volume of 16,655,552 barrels (6.9953 x 10 gallons) of water have been
injected since the project began in 1973. Due to the lithologic
variation within the Muddy reservoir, average injection pressures have
ranged between 100 and 2,800 psi. During the last period covered by the
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injection reports (May to November, 1979), 11 of the wells were
temporarily shut-in.
Casing Record: Injection Well #16, T51N-R71W-27 dbb, Springen Ranch
Field, Muddy Unit, Total Depth = 7695 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement Purpose
8-5/8" 24 12-1/4" 348' 150 sacks Surface
5-1/2" 15.5,17 7-7/8" 7695' 250 sacks Injection
East Star Corral Field (1,631,007 bbls oil, 2,508,095 MCF gas; 1961-79)
Long Island Unit
The injection of water into the Almy sands of the Wasatch Formation
began in 1969, in order to enhance oil production from the reservoir at
East Star Corral Field. The field is located in Township 30 North,
Range 112 West, Sublette County, and was discovered in 1961.
Belco Petroleum Corporation, operator of the Long Island Unit of
East Star Corral Field, initiated the waterflood using four injection
wells completed in the Almy sands at depths ranging from 1,500 to 3,500
feet. Water for the project is supplied by four wells in the Knight
sand in the upper Wasatch Formation. All of the supply wells are
located in Section 19, Township 30 North, Range 112 West.
Cumulative injection data through December, 1979, indicated that
Q
7,333,013 barrels (3.0799 x 10 gallons) of water had been injected at
average pressures between 500 and 2,650 psi. Six of the eight injection
wells were active during the last half of 1979. The other two were
temporarily shut-in. One of the wells is dually perforated in the
Stray 3 and 4 sands of the Wasatch Formation, at depths of 3,325 and
3,520 feet.
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Casing Record: Injection Well #31, T30N-R112W-20 ccc, East Star Corral
Field, Long Island Unit, Total Depth = 3631 feet.
Casing Size
8-5/8"
4-1/2"
Wt. (///ft)
24
10.5,11.6
Hole Size
11"
7-7/8"
Depth Set Cement
202* 100 sacks
3620' 150 sacks
(50-50 pozmix)
Steamboat Butte Field (78,658,959 bbls oil, 10,152,385 MCF gas; 1943-79)
Steamboat Butte Field is located on the Wind River Indian Reserva-
tion, about three and one-half miles northwest of Pilot Butte oil field,
in Townships 3 and 4 North, Range 1 West, Fremont County. Between
1943 and 1948, oil was discovered in the Nugget Sandstone, the Tensleep
Sandstone, the Lakota Sandstone, the third Frontier sand and the
Phosphoria Formation.
Tribal Unit
Due to rapidly declining bottom hole pressures in the Tensleep
reservoir, water injection into the reservoir was started in 1952.
The project consisted of only one well until 1962, when three injection
wells were added to the Tensleep waterflood.
The Tensleep reservoir is encountered at depths between 6,800 and
7,300 feet in the Tribal Unit area and covers about 1,270 acres, with
an average pay zone thickness of about 200 feet. Average porosity and
permeability from two Tensleep Sandstone core samples are 12 to 13
percent and 38 to 45 millidarcies, respectively.
The Tribal Unit injection wells are located in Sections 19, 29,
32, and 33, Township 4 North, Range 1 West, Fremont County. The water-
flood project currently consists of six active dual injection wells.
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As of December, 1979, a cumulative volume of 195,462,207 barrels
9
(8.2093 x 10 gallons) of water had been injected from shallow wells
near the Wind River and Tensleep producing wells at Steamboat Butte.
Average injection pressures have ranged from a minimum of 350 to a
maximum of 4,885 psi.
The Phosphoria reservoir of the Tribal Unit covers an area of
about 900 acres with an average pay zone thickness of about 40 feet.
Water injection into the reservoir started in November, 1962, through
three wells which are dually completed in the Phosphoria and Tensleep
reservoirs. By 1979, the waterflood included ten wells, five of which
are dual injectors. Cumulative injection through December of that
9
year was 41,554,475 barrels (1.7453 x 10 gallons) of water produced
by shallow supply wells and Phosphoria oil production wells. The
average injection pressures at each well, averaged over each six-month
period of injection, have ranged between 1,565 and 3,195 psi. Six
of the ten wells were actively injecting during the last six months of
1979.
Casing Record: Injection Well //V-1, T4N-R1W-33 ccc, Steamboat Butte
Field, Tribal Unit, Total Depth = 7496 feet.
Casing Size Wt. (tf/ft) Amount Perforations Purpose
10-3/4" 32.75 243' Surface
7" 20,23 7494' 6970-7015' Injection
Casing Record: Injection Well //C-16, T4N-R1W-32 bdb, Steamboat Butte
Field, Tribal Unit, Total Depth = 7038 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
16" 55 19-1/4" 92' 100 sacks
10-3/4" 40.5 13-3/4" 771' 425 sacks
7" 23 9" 7041' 600 sacks
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Tribal-Brinkerhoff Unit
The Tribal-Brinkerhoff Unit of Steamboat Butte Field is located in
Township 3 North, Range 1 West, Fremont County. Water injection to the
Phosphoria Formation started in 1970, through one well perforated at a
depth of 6,709 feet. The water for the project is provided by shallow
supply wells near the Wind River and by oil producing wells in the
Phosphoria.
Another well was added in 1977. Cumulative injection through both
wells, as of December, 1979, was 6,103,450 barrels (2.5634 x 10^
gallons) of fresh and produced water. Average injection pressures have
been high relative to other projects around Wyoming, ranging from 1,900
to 3,055 psi.
Casing Record: Injection Well //6, T3N-R1W-9 bed, Steamboat Butte
Field, Tribal-Brinkerhoff Unit, Total Depth = 6988 feet.
Stewart Field (7,857,638 bbls oil, 1,138 MCF gas; 1965-79)
Minnelusa "B" Sand Unit
In 1965, oil was discovered in the Minnelusa Formation underlying
Stewart Field. The field is located in Townships 50 and 51 North,
Range 69 West, Campbell County. Water injection to the Minnelusa "B"
sand started in 1970, through four wells. By 1976, there were 13 wells
injecting water from supply wells in the Fox Hills and Minnelusa
formations and from production wells at Pan Am Windmill Field and the
east and south batteries of Stewart Field.
Casing Size
10-3/4"
7"
Wt. (///ft)
32
23
Amount
510'
6904'
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The depth to the Minnelusa "B" sand at Stewart Field ranges from
7,900 to 8,100 feet. The porosity of the reservoir was determined from
core samples at four of the injection wells and ranges from 5.8 to
14.8 percent. Permeability estimates were made at two wells and
ranged from 10.7 to 134 millidarcies.
Eleven of the wells were injecting during the first six months of
1979. The remainder were temporarily shut-in. The total volume of
water injected between 1970 and July, 1979, was 23,550,769 barrels
g
(9.8913 x 10 gallons). Injection pressures, averaged over each six-
mont period of injection at each well, ranged from 1,500 to 2,900 psi.
Casing Record: Injection Well #22, T51N-R69W-34 bb(cd), Stewart Field,
Minnelusa "B" Sand Unit, Total Depth = 8185 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement Purpose
8-5/8" 28 12-1/4" 198' 150 sacks Surface
4-1/2" 9.5,10.5,11.6 7-7/8" 8181' 450 sacks Injection
Sussex Field (62,355,722 bbls oil, 13,744,239 MCF gas; 1948-79)
The Sussex oil field is located in Johnson County, Township 42
North, Ranges 78 and 79 West. The field was discovered in 1948, with
the completion of a well in the Lakota Sandstone. Subsequent oil
discoveries were made during the next five years in the Shannon, Sussex,
Tensleep, second Frontier, first Frontier, Sundance, and Parkman sands.
The Continental Oil Company is the operator of Sussex Field which
covers 13,376 acres. The field is divided into areas "A," "B," "C,"
"D," "E," and "F." Various units are located within each area listed
above, and are producing from the Shannon, Sussex, Tensleep, or other
formations. Seven waterfloods were still actively injecting as of
December, 1979.
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Geologic conditions which influence the waterflood projects differ
for each unit and may not be generalized over the entire field.
Several wells completed in the Madison Limestone provide the fresh
water supply for the injection wells via the Shiloh Water Supply System.
Sussex "A" Unit
The Sussex "A" Unit covers 370 acres of federally owned land. The
Sussex "A" reservoir includes 306 acres with an average pay thickness of
18 feet. The initial producing mechanism of the reservoir was solution
gas drive.
In 1951, a pilot waterflood project was initiated. The pilot study
expanded to a full scale project in 1957, and eventually included ten
injection wells set in a peripheral flood pattern which conformed to the
existing fault pattern in the area. By 1979, all of the injectors had
been shut-in.
Casing Record: Injection Well //45, T42N-R78W-17 acb, Sussex Field,
Sussex "A" Unit, Total Depth = 4574 feet.
Casing Size Wt. (///ft) Depth Set Cement
9-5/8" 36 174' 150 sacks
7" 23 4574' 300 sacks
Sussex "C" Unit
The Sussex "C" Unit includes 480 acres of which 240 acres are
federally owned, 140 acres are state owned land, and 100 acres are
privately owned fee lands. The Late Cretaceous Sussex sand is found
at an average depth of 4,000 feet in the unit area. The average porosity
of the sandstone is 21 percent and the average permeability to air is
32 millidarcies. The sandstone has a gross thickness of 40 feet and the
reservoir has a maximum closure of 500 feet. Initial reservoir pressure
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was 1,545 psi and the original mechanisms of production were provided by
gas cap expansion and solution gas drive. The small gas cap is located
on the structural crest of the reservoir. The Sussex "C" reservoir
covers 453 acres and has an average pay thickness of 26 feet. It is a
faulted anticline which is bounded on the south by a major sealing normal
fault and on the east, west, and north by the oil-water contact and by
a series of minor southwest-northeast trending normal faults. The
faulting divides the reservoir into three distinct fault blocks.
Water and gas injection began in December, 1959. As of March,
Q
1979, 13,179,905 barrels (5.5356 x 10 gallons) of water had been
injected into the Sussex "C" reservoir. The cumulative ratio of
produced water to oil for the Sussex "C" unit is 0.4 to 1.0. Of the
sixteen water injection wells in the Sussex "C" Unit, seven were still
actively injecting in June, 1979.
Casing Record: Injection Well #197, T42N-R78W-14 cac, Sussex Field,
Sussex "C" Unit, Total Depth = 4761 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
8-5/8" 24 12-1/4" 184' 150 sacks
CI. "G"
5-1/2" 15.5,17 7-7/8" 4761' 320 sacks
CI. "G"
Sussex "D" Unit
The producing reservoir of the Sussex "D" Unit covers 147 acres
and has an average pay thickness of 33 feet.
The Sussex Sandstone in this area is composed of fine- to medium-
grained, gray to green, salt and pepper sandstone and is found at a
depth of approximately 4,255 feet. The average porosity of the reser-
voir is 20.7 percent.
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The reservoir is apparently controlled by a normal dip-slip fault
on the south, a water-oil contact on the north and west, and a series
of minor faults on the east. The original mechanism of production was
solution gas drive.
The waterflood project began here in 1958, and was expanded to
eight wells in 1973. By 1979, only one of the wells was actively
injecting. The produced water-oil ratio had increased to 27.0 to 1 in
1978, compared to a cumulative ratio of 1.2 to 1 since injection began.
Casing Record: Injection Well #70, T42N-R79W-12 ddd, Sussex Field,
Sussex "D" Unit, Total Depth = 4600 feet.
Casing Size Wt. (#/ft) Depth Set Cement Purpose
9-5/8" 26 171' 150 sacks Surface
5-1/2" 14 4599' 300 sacks Injection
Shannon "A" Unit
The Shannon "A" Unit covers 420 acres of federally owned land.
The reservoir includes 368 acres and has an average pay thickness of
14 feet. Solution gas drive and partial natural water drive provided
the energy for initial reservoir production.
A water injection pilot program began in 1951, and was expanded to
a full scale program in 1957. All nine of the wells were dual injectors
in the Shannon and Sussex sands when they were shut-in. As of 1979,
all of the wells were either temporarily or permanently shut-in.
Cumulative injection at the time into the Shannon "A" Unit was 3,761,787
g
barrels (1.58 x 10 gallons). In these wells, water is injected down
the tubing under a packer into the deeper Shannon sand and down the
casing annulus into the Sussex sand reservoir.
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Casing Record: Injection Well #67, T42N-R78W-18 aad, Sussex Field,
Shannon "A" Unit, Total Depth = 4570 feet.
Casing Size
9-5/8"
5-1/2"
Wt. (///ft)
26
14
Depth Set
173'
45701
150 sacks
300 sacks
Cement
Shannon "C-E" Unit
The Shannon "C-E" Unit includes 1,030 acres—370 acres of federal
land, 480 acres of state land, and 180 acres of privately owned fee
land. The Shannon "C-E" reservoir covers 867 acres with an average
pay thickness of 12 feet. The average porosity and permeability of the
Shannon are 12.4 percent and 2 millidarcies, respectively.
The Shannon Sandstone is an Upper Cretaceous sand which is found
at an average depth of 4,350 feet in this unit area. The reservoir is
a faulted anticline which is sealed on the south by a normal fault.
It is bounded on the other three sides by an oil-water contact and other
minor faults. Faulting divides the reservoir into five distinct fault
blocks with little hydraulic communication between them. The Shannon
sand has a gross thickness of 40 feet with a maximum closure of 500 feet.
The water injection project in the Shannon "C-E" Unit began in
1959, and was expected to provide an additional 836,000 barrels of
secondary oil.
Total cumulative injection as of June, 1979, was 8,335,601 barrels
g
(3.5 x 10 gallons) of water from the Madison Limestone via the Shiloh
Water Supply Line. The produced water-oil ratio has increased in
recent years. In 1978, the ratio was 4.6 to 1, compared to a cumulative
ratio of 0.6 to 1 since production began in 1950.
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Casing Record: Injection Well #56, T42N-R78W-18 bbb, Sussex Field,
Shannon "C-E" Unit, Total Depth = 4458 feet.
Casing Size Wt. (///ft) Depth Set Cement
10-3/4" 29 172' 150 sacks
5-1/2" 14 4458' 300 sacks
Shannon "D" Unit
The Shannon "D" Unit reservoir is a zone which contains three
benches of sandstone which range in composition from a gray, sandy
shale to a fine- to medium-grained, gray, shaley sandstone. The
Shannon Sandstone is at least 96 feet thick and is found at a depth of
4,600 feet in the Shannon "D" Unit area. The reservoir covers 377 acres
and has an average pay thickness of 38 feet. Average porosity in the
Shannon sand is 18.6 percent.
The waterflood project in the Shannon "D" Unit began in 1958, and
was expanded in 1967 and 1973. All of the injection wells are dual
injectors into the Shannon and Sussex sandstones. Water is injected
down the tubing under a packer into the deeper Shannon and down the
casing annulus into the Sussex. As of December, 1979, only one of seven
wells were still actively injecting water into the two sandstones.
g
Cumulative injection to that time was 8,830,493 barrels (3.7088 x 10
gallons).
Casing Record: Injection Well //58, T42N-R79W-13 bab, Sussex Field,
Shannon "D" Unit, Total Depth = 4796 feet.
Casing Size Wt. (///ft) Depth Set Cement
9-5/8" 26 1731 150 sacks
5-1/2" 14 4225' 250 sacks
4" 9.5 4796' 200 sacks
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Lakota "A" Unit
The Lakota "A" Unit includes 200 acres of federally owned land.
The upper portion of the Lakota "A" reservoir is found at an average
depth of 7,600 feet and is composed of hard, fine-grained sand which
overlies a conglomerate. Beneath the conglomerate is another hard,
fine-grained sand with dirty sand streaks interbedded throughout the
interval. The reservoir covers 328 acres with an average pay thickness
of 25 feet. The porosity of the sandstone was estimated at 15.8 percent.
The initial producing mechanism of the reservoir was fluid expansion
and partial water drive.
Water injection into the Lakota "A" reservoir began in 1951, and
continued until 1955, when the only injection well was shut-in. In
1967, injection of water supplied by the Shiloh Water Line was resumed
in a nearby well which was still actively injecting in December, 1979.
Cumulative injection through both wells totaled 1,858,853 barrels
(78,071,826 gallons) at that time. During the first year of injection
through the second well, the monthly oil production figures did not show
any response to the water injection.
Casing Record: Injection Well #91, T42N-R78W-17 da, Sussex Field,
Lakota "A" Unit, Total Depth = 9115 feet.
Casing Size Wt. (///ft) Depth Set Cement
10-3/4" 32 299' 350 sacks
7" 23 9115' 625 sacks
Tensleep "A" Unit
The Tensleep "A" Unit covers 340 acres of federal land which
overlies the Tensleep reservoir. The Tensleep "A" reservoir contains
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320 acres with an average pay thickness of 35 feet. The original
reservoir energy was provided by a natural water drive.
The water injection project on the Tensleep "A" reservoir began
in 1958, with two wells. One of those wells is still active as a dual
injector into the Tensleep "A" and Lakota "A" reservoirs. The injection
project was expanded to include seven injectors, five of which were
active as of December, 1979. Cumulative injection up to that time was
20,457,038 barrels (8.592 x 108 gallons).
Casing Record: Injection Well #78, T42N-R78W-17 cbc, Sussex Field,
Tensleep "A" Unit, Total Depth = 8995 feet.
Casing Size Wt. (///ft) Depth Set Cement
10-3/4" 32.75 238' 200 sacks
7" 26 8995' 200 sacks
Tensleep "B" Unit
The Tensleep "B" Unit of Sussex Field covers 1,520 acres of
federal, state, and private fee land. The Tensleep "B" reservoir
consists of 1,092 acres of gray to white, dolomitic, fine-grained
sandstone with an average pay thickness of 103 feet.
Core analyses at two well sites indicated that the permeability
and porosity of the Tensleep sand in this area were highly variable.
Porosity estimates ranged from 0.4 to 18.6 percent and permeability
measurements varied between 0.01 to 271 millidarcies. The two wells
are located within the same quarter-quarter of Section 15, Township
42 North, Range 78 West.
Structurally, there is a major east-west tending fault which cuts
across the south end of the reservoir. The original producing mechanism
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of the reservoir was fluid and rock expansion. Water injection began
in 1958, to stimulate declining oil production. It was expected that
the peripherally patterned waterflood project would provide the stimulus
for the recovery of 23.8 percent of the original oil in place.
As of December, 1979, eleven of the twelve injection wells were
still actively injecting. A cumulative total of 116,953,612 barrels
9
(4.9121 x 10 gallons) of water from the Madison Limestone had been
injected into the Tensleep "B" reservoir at that time.
Casing Record: Injection Well //187, T42N-R78W-15 cad, Sussex Field,
Tensleep "B" Unit, Total Depth = 9439 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
13-3/8" 54.5 17-1/2" 310' 375 sacks
CI. "G"
7" 23,26 3-31/32" 9439' 700 sacks
CI. "G"
Lakota "B" Unit
The Lakota "B" reservoir is a Lower Cretaceous sandstone found at
an average depth of 7,875 feet. The reservoir is a faulted, anticlinal
structure bound on the south by a major normal sealing fault and on the
other three sides by an oil-water contact. The Lakota sand in this area
has a gross thickness of 50 feet and the reservoir has a maximum
closure of 250 feet.
Primary production began in 1949, and reservoir energy has been
provided by a combination of fluid expansion, solution gas drive, and
natural water encroachment. Secondary recovery of oil was initiated in
1970, and was expected to provide an estimated 290,000 barrels of
additional oil. A cumulative total of 1,920,833 barrels (80,674,986
gallons) of water had been injected prior to July, 1976, when both
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injection wells were temporarily shut-in. Water used in the secondary
recovery project was produced from the Madison Limestone and obtained
from the Shiloh Water System.
Casing Record: Injection Well #22, T42N-R78W-22 abd, Sussex Field,
Lakota "B" Unit, Total Depth = 7400 feet.
Casing Size Wt. (///ft) Depth Set Cement
10-3/4" 32.75 310" 160 sacks
7" 23 7400' 300 sacks
West Sussex Field (17,100,613 bbls oil, 8,378,739 MCF gas; 1951-79)
Shannon "A-B" Unit
The Shannon "A-B" Unit covers an area of 1,832.87 acres, of which
1,652.87 acres are federally owned and 180 acres are privately owned
fee lands. The Shannon reservoir is found at an average depth of
approximately 3,180 feet in this area. The reservoir contains 1,738
acres of light gray, glauconitic, well-sorted, coarse-grained, friable
sandstone. The average thickness of the pay zone is 23.8 feet. A
complex system of seven separate fault blocks, three of which have small
gas caps, make up the Shannon "A-B" reservoir.
Water injection into the seven fault blocks began in 1955. The
project was expanded to 36 wells, of which 16 were actively injecting
as of December, 1979. Cumulative water injection to that point was
9
51,408,144 barrels (2.1591 x 10 gallons). Fresh water is supplied from
the Madison Limestone through the Shiloh Water Supply Line.
Casing Record: Injection Well #12, T42N-R79W-5 deb, West Sussex Field,
Shannon "A-B" Unit, Total Depth = 3159 feet.
Casing Size Wt. (///ft) Make Depth Set Cement
9-5/8" 29 Armco 170' 150 sacks
4-1/2" 9.5 J-55 3159' 200 sacks
with gel
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Table Rock Field (1,830,325 bbls oil, 227,062,857 MCF gas; 1946-79)
Table Rock Unit
The Table Rock Unit is the site of a future salt water disposal
site in Section 35, Township 19 North, Range 98 West, Sweetwater County.
Texaco, Inc., is the operator of a disposal well that has been drilled
and prepared for injection into the Ericson Formation of the Upper
Cretaceous Mesaverde Group. The well is perforated at a depth of
6,583 feet.
Teapot Field - Naval Petroleum Reserve it3 (9,924,277 bbls oil,
2,622,429 MCF gas; 1922-79)
Teapot Dome Unit
A full scale water injection project was recently put into operation
at the Teapot Dome Unit of Naval Petroleum Reserve //3, in Sections 20 and
21, Township 39 North, Range 78 West, Natrona County. Ten wells began
injection into the second Wall Creek sand during the early months of 1979.
Water for the flood is obtained from Madison Limestone supply well //17
WX 21.
As of July, 1979, 306,174 barrels (1.2859 x 10^ gallons) of water
had been injected through the ten wells at average pressures between 100
and 800 psi.
Tholson Field (1,802,808 bbls oil, 5,384 MCF gas; 1969-79)
Minnelusa "A" Sand Unit
The Minnelusa "A" Sand Unit of Tholson Field is located in Township
49 North, Range 70 West, Campbell County. Water injection to the
Minnelusa "A" sand began in 1973, through one well in Section 2. A
second well was added in 1977, also in Section 2. Both injectors are
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perforated at a depth of about 8,750 feet. Cumulative injection to
December, 1979, was 1,927,157 barrels (8.094 x 10^ gallons) of water
from the Fox Hills Sandstone. Average injection pressures at the two
wells have ranged from a minimum of 100 psi to a maximum of 2,700 psi.
Timber Creek Field (12,015,888 bbls oil, 263,961 MCF gas; 1958-79)
Timber Creek Field is located in township 49 north, range 70 west,
Campbell County. It is the site of five salt water disposal systems
at five separate units of the field. Four of the systems—the Federal
311 Campbell Unit, Lesueur Unit, Lesueur "S" Unit, and the V. H. Wolff
Unit systems—are completed in the Minnelusa Formation. The disposal
well at the F. E. Cook Unit is perforated in the Dakota sand at a depth
of 7,800 feet.
The first system to be operated at Timber Creek was a single
disposal well at the V. H. Wolff Unit. Injection began in 1967, and
continued until December, 1973, when the well was temporarily shut-in.
The depth of perforation is 9,178 feet. Cumulative injection through
the well was 319,462 barrels (1.3417 x lo'' gallons) of brine from
production wells at Timber Creek Field. The maximum average injection
pressure was 638 psi while the well was operating.
The disposal well at the Federal 311 Campbell Unit also began
operating in 1967; however, that well is still actively injecting. The
depth at which the produced brine is being injected is 9,218 feet.
The well is located in Section 8 of the previously mentioned township
and range. Cumulative injection, as of January, 1980, was 278,290
barrels (1.1688 x 10^ gallons) of salt water.
Salt water disposal at the Lesueur Unit started in 1969, through
an injection well in Section 18. The well is perforated at 9,227 feet
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in the Minnelusa Formation. The most recent injection report indicates
that a cumulative volume of 679,773 barrels (2.855 x 10^ gallons) of
produced brine had been injected as of June, 1980. Average injection
pressures ranged from 1,600 to 2,289 psi.
The disposal system at the Lesueur "S" Unit is the only two well
operation at Timber Creek. Injection of produced brine started in
1972. Both wells are located in Section 17. Cumulative injection
through both wells, as of June, 1980, was 439,883 barrels (1.8475 x
107 gallons) of water.
In 1978, a single well disposal system was added at the F. E.
Cook Unit of Timber Creek Field. The well is located in Section 7,
Township 49 North, Range 70 West, and is¦perforated at a depth of 7,800
feet in the Dakota sand. Cumulative injection for 1978 and 1979
combined was 10,940 barrels (459,480 gallons) of produced salt water
from wells at Timber Creek. Average injection pressures have ranged
between 400 and 1,000 psi.
Casing Record: Salt Water Disposal Well //2, T49N-R70W-8 dc, Timber
Creek Field, Federal 311 Campbell Unit, Total Depth
= 9423 feet.
Casing Size Wt. (///ft) Depth Set Cement
5-1/2" 15.5,17 9423' 400 sacks
Casing Record: Salt Water Disposal Well //5, T49N-R70W-18 da, Timber
Creek Field, Lesuer Unit, Total Depth = 9412 feet.
Casing Size Wt. (///ft) Depth Set Cement
10-3/4" 40.5 305* 250 sacks
5-1/2" 17 9412' 300 sacks
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Tip Top Field (4,251,584 bbls oil, 270,414,250 MCF gas; 1928-79)
Shallow Unit
Tip Top Field was discovered in 1928, when a productive well was
completed in the Almy reservoir of the Wasatch Formation. It wasn't
until 1974, that a water injection project was put into operation at the
Tip Top Shallow Unit. The unit is located in Township 28 North, Range
118 West, Sublette County.
Injection to the Almy reservoir started through five wells
supplied with water from three Almy source wells, as well as Tip Top
Field producing wells. The reservoir is found at depths between 885
and 1,192 feet. All of the injection wells were active during the last
six months of 1979. Cumulative injection to December, 1979, was
g
3,436,703 barrels (1.4434 x 10 gallons) of water. Maximum average
injection pressures have not exceeded 1,700 psi.
A salt water disposal system, consisting of two wells completed
in the Almy sand, was put into operation by Mountain Fuel Supply
Company in 1971. The wells are located in Sections 28 and 33, Township
28 North, Range 113 West, Sublette County. Cumulative injection through
both wells was 9,762,349 barrels (4.1002 x 10^ gallons) as of June,
1980. Injection pressures have been very low, averaging 50 psi. Both
wells were active during the first six months of 1980.
Casing Record: Injection Well //57, T28N-R113W-21, Tip Top Field, Tip
Top Shallow Unit, Total Depth = 1288 feet.
Casing Size VJt. (///ft) Amount Perforations Purpose
8-5/8" 24 204' - Surface
4-1/2" 14,15.5 1270' 1011-1017' Injection
1070-1074'
1151-1169'
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Casing Record: Salt Water Disposal Well it68, T28N-R113W-28 cd, Tip Top
Field, Tip Top Shallow Unit, Total Depth = 1390 feet.
Casing Size
8-5/8"
5-1/2"
Wt. (///ft)
24
14,15.5
Depth Set
236'
1390'
North Tisdale Field (2,814,316 bbls oil, 44,724 MCF gas; 1952-79)
An eleven well tertiary oil recovery project has been in operation
at North Tisdale Field since 1963. The project is operated by Continental
Oil Company and is located in Township 41 North, Range 81 West, Johnson
County. A hot water solution is injected to the Jurassic Curtis Sand-
stone. Further details on the project were unavailable from Oil and
Gas Commission files.
Tomcat Creek Field (272,479 bbls oil; 1959-79)
Fall River Unit
Tomcat Creek Field is located in Township 49 North, Range 65 West,
Crook County, and was discovered in 1959, when oil was initially
produced from the Fall River Sandstone.
In 1976, Grace Petroleum Company initiated a water injection
project at the Fall River Unit of Tomcat Creek Field. The waterflood
includes four wells, perforated at depths ranging from 350 to 430 feet
in the lower Fall River sand. Water for the project is provided by a
supply well, also completed in the Fall River Sandstone at a depth of
416 feet.
All of the wells were actively injecting during the last six months
of 1979, and cumulative injection at the end of that period totaled
758,794 barrels (3.1869 x 10^ gallons) of water injected since the
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project started in 1976. Average injection pressures have ranged from
150 to 425 psi.
Torchlight Field (14,177,454 bbls oil, 3,888,449 MCF gas; 1935-79)
Madison Unit
The Madison Unit of Torchlight Field is located in Township 51
North, Ranges 92 and 93 West, Big Horn County. Structurally, the field
is situated atop an elliptical dome in the center of Township 51 North,
on the line between the two ranges.
The Madison Limestone reservoir underlying the unit, covers 685
acres with an average pay zone thickness of 67 feet. Core analyses
indicate an average reservoir porosity and permeability of 21 percent
and 33.5 millidarcies, respectively.
In September, 1962, a one well gas injection project was started.
Then, in May, 1963, with the approval of the Oil and Gas Conservation
Commission, the gas injection project expanded to a full scale water
and gas injection program. Water and gas for the projects were obtained
from the Madison and Phosphoria formations, respectively. At the time
this report was compiled, both projects had been discontinued.
Cumulative injection totals for the waterflood were 8,964,832 barrels
g
(3.7652 x 10 gallons) of water through nine wells. Average injection
pressures did not exceed 2,000 psi while the wells were in operation.
Casing Record: Injection Well //30, T51N-R93W-24 cba, Torchlight Field,
Madison Unit, Total Depth = 3903 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
10-3/4" 32.75 15" 661' 700 sacks
7" 20 9" 3902' 425 sacks
(50-50 pozmix)
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Tensleep Unit
A tertiary recovery project, operated by Amoco Production Company,
began operations at the Tensleep Unit of Torchlight Field in 1976.
The Tensleep reservoir in this area covers 291 acres with an
average pay zone thickness of 23 feet. The original reservoir producing
mechanism was a limited water drive. In 1957, a water injection project
began at the Tensleep Unit with the purpose of maintaining Tensleep
reservoir pressure. The waterflood was expanded in 1958, and then
stopped in July, 1967. Cumulative injection to that date, was 4,440,344
g
barrels (1.8649 x 10 gallons) of water.
The tertiary recovery project includes five injection wells which
have been injecting a water/micellar solution into the Tensleep
reservoir. One of the wells has been shut-in. Further details on the
project were not available at the time of this writing.
Torrington Field (464,495 bbls oil; 1955-79)
Van Mark Unit
The Van Mark Unit of the Torrington Field has, since 1975, been the
site if a secondary oil recovery water injection project completed in
the "J" sand of the Muddy Sandstone. The field is located in Townships
23 and 24 North, Range 61 West, Goshen County, about three miles south-
west of the city of Torrington.
The project began as a single well pilot study, using water
provided by shallow supply wells, and was expanded to three injection
wells in 1977, and to six wells in 1978. The depth to the Muddy "J"
sand reservoir is about 6,900 feet in the Torrington Field area. As
of October, 1979, cumulative injection was 362,012 barrels (1.5204
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x 10 gallons) of water. Only one of the wells was actively injecting
during the last reported period. The remainder had been shut-in.
Reported injection pressures, averaged at each well for each six
month period, ranged from 2,900 to 4,450 psi and are considered
extremely high for the type of casing used in the wells. A casing
schedule representative of the injection wells is given below.
Casing Record: Injection Well //W-5, T24N-R61W-33 cb(bc), Torrington
Field, Van Mark Unit, Total Depth = 7003 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement Purpose
8-5/8" 24 12-1/4" 415' 250 sacks Surface
5-1/2" 17,15.5 7-7/8" 7002' 150 sacks Injection
Ute Field (8,890,789 bbls oil, 22,156,306 MCF gas; 1967-79)
Muddy Sand Unit
Water injection at Ute Field began in 1973, at the Muddy Sand
Unit, located in the northern portion of Township 57 North, Range 72
West, and the southern portion of Township 58 North, Range 72 West,
Campbell County. The injected formation is the Muddy Sandstone which
is encountered at depths ranging from 6,237 to 6,534 feet in the Ute
Field area. The average porosity of the Muddy reservoir is between
16.8 and 21.3 percent, based on core samples from three of the injection
wells. Water for the flood is obtained from the Fox Hills Sandstone.
By 1976, the waterflood project included 13 wells, all of which
were actively injecting during 1979. Cumulative injection for the
O
project, as of December, 1979, was 20,419,997 barrels (8.5764 x 10
gallons) of water. Average injection pressures ranged from a minimum
of 75 psi to a maximum of 4,134 psi.
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Casing Record: Injection Well //Tr. 3-11, T57N-R72W-10 ba, Ute Field,
Muddy Sand Unit, Total Depth = 6,416 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement Purpose
8-5/8" 24 12-1/4" 163' 150 sacks Surface
5-1/2" 15.5 7-7/8" 6416' 200 sacks Injection
Olmstead Unit
The injection of water to the Muddy sand reservoir underlying the
Olmstead Unit of Ute Field, started in 1975, through three wells. The
unit area includes parts of Sections, 1, 2, and 12, Township 57 North,
Range 72 West, Campbell County. A fourth well was added to the water-
flood in 1979. Water for the project is provided by a supply well
in the Fox Hills Sandstone.
As of December, 1979, 1,915,048 barrels (8.0432 x lO'' gallons)
of water had been injected through all four wells. Injection pressures
at each well, averaged over each six month period of injection, ranged
from 433 to 3,025 psi.
Casing Record: Injection Well #7-1, T57N-R72W-1 bd, Ute Field,
Olmstead Unit, Total Depth = 6,414 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
8-5/8" 24 12-1/4" 150' 190 sacks
5-1/2" 15.5,17 7-7/8" 6414' 300 sacks
Wagonspoke Field (1,025,172 bbls oil, 40,302 MCF gas; 1972-79)
Ashmar-Federal Unit
Wagonspoke Field is located in Township 52 North, Range 69 West,
Campbell County. Oil was discovered at Wagonspoke in 1972, when a
productive well was completed in the Minnelusa Formation at a depth
of about 7,300 feet.
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In 1978, water injection to the Minnelusa reservoir was started
in order to enhance reservoir pressure and increase production. The
Fox Hills Sandstone was tapped to supply water for the injection
project. In the two years that the single well waterflood has been
operating, a cumulative volume of 463,066 barrels (1.9448 x 10^
gallons) of water have been injected at average pressures ranging
from 2,100 to 2,466 psi.
Casing Record: Injection Well #5-3, T52N-R69W-3 bcb, Wagonspoke
Field, Ashmar-Federal Unit, Total Depth = 7460 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
8-5/8" 24 12-1/4" 180' to surface
5-1/2" 15.5,17 7-7/8" 7400' 350 sacks
Wallace Field (4,394,284 bbls oil, 6,843 MCF gas; 1966-79)
Minnelusa Unit
A pilot water injection study was initiated at the Minnelusa Unit
of Wallace Field in 1970, by Atlantic Richfield Company. The Minnelusa
Unit is located in the extreme northern part of Township 51 North,
Range 70 West, and the extreme southern part of Township 52 North,
Range 70 West, Campbell County. Gradual expansion of the Minnelusa
reservoir waterflood has increased the number of injection wells to
nine. All of the wells are perforated in the Minnelusa at depths
ranging from 7,800 to 8,040 feet.
Cumulative injection to the Minnelusa reservoir, through December,
O
1979, totaled 16,034,493 barrels (6.7345 x 10 gallons) of water from
the Fox Hills Sandstone water supply well //l. Average injection
pressures have fluctuated between 1,100 and 2,750 psi since the project
11-254
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started in 1970. All of the wells were actively injecting during the
second half of 1979.
Casing Record: Injection Well //W-7, T52N-R70W-26 dec, Wallace Field,
l' • Minnelusa Unit, Total Depth = 8049 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement Purpose
8-5/8" 24 12-1/4" 204' 160 sacks Surface
,5-1/2" 17,20 7-7/8" 8050' 350 sacks Injection
I (
Warm Springs Field (1,519,328 bbls oil; 1917-79)
West Freudenthal Unit
Warm Springs Field is located in Township 43 North, Ranges 93 and
94 West, Hot Springs County, and was discovered in 1917. A water
injection project was initiated in 1975, with Cork Petroleum Company
as operator. As of December, 1979, the project consisted of six wells
perforated in the Phosphoria Formation at a depth of approximately 900
feet. Four of the wells were still on active status, one had been
temporarily shut-in and the other was permanently shut-in. Cumulative
injection to that date was 2,199,800 barrels (9.2391 x 10^ gallons) of
water from the Darwin and Phosphoria formations. Injection pressures,
averaged over each six-month period at each well, were relatively low,
ranging from 150 to 650 psi.
Casing Record: Injection Well //38, T43N-R94W-35 cbd, West Warm Springs
Field, Freudenthal Unit, Total Depth = 870 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement Purpose
8-5/8" 24 10" 30' 10 sacks Surface
5-1/2" 14 8" 868' 100 sacks Injection
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Well Draw Field (17,027,774 bbls oil, 33,622,537 MCF gas; 1973-79)
Well Draw Field covers a large area in Townships 33 to 36 North,
Ranges 67 to 70 West, Converse County. The field was discovered in
1973, and has expanded to include 310 producing wells, making it one
of the most productive fields in the state after only six years of
development.
There are three injection wells at Well Draw Field, all of them
salt water disposal wells, that started operating in 1977. Disposal
wells are located in the //I Lebar Unit, the Williams Unit and the
Hoffman Unit. Wells at the #1 Lebar and Williams units are completed
in the Lewis Shale at 5,840 and 5,338 feet, respectively. Cumulative
injection data were available for the Williams Unit well only, and
indicated that 10,733 barrels (450,786 gallons) of produced brine had
been injected between 1977 , and February, 1980.
The disposal well at the Hoffman Unit is located in section 30,
Township 34 North, Range 68 West, Converse County. It is completed
in the Teapot Sandstone at a depth of 7,003 feet. As of June, 1978,
68,699 barrels (2,885,358 gallons) of produced salt water had been
injected since the start of the operation.
Casing Record: Salt Water Disposal Well #4, T34N-R68W-30 aa, Well
Draw Field, Hoffman Unit, Total Depth = 7176 feet.
Casing Size Wt. (#/ft) Hole Size Depth Set Cement
8-5/8" 24 12-1/4" 316' 196 sacks
5-1/2" 15.5 7-7/8" 7178' 175 sacks
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Wertz Field (77,262,481 bbls oil, 22,299,990 MCF gas; 1921-79)
Wertz Unit
Wertz Field is situated on an elliptical dome in Township 26 North,
Ranges 89 and 90 West, Sweetwater and Carbon counties. In 1920, gas
was discovered in the Dakota sand. Later discoveries of oil and/or gas
were made in the Mowry Shale, the Frontier Formation, the Lakota Sand-
stone, the Sundance Formation, the Tensleep Sandstone, the Amsden
Formation, the Madison Limestone, and a sand of Cambrian age.
In 1941, a gas injection pressure maintenance project was started
to supplement the natural water drive of the Tensleep reservoir. Gas
produced with oil from the Tensleep and some gas from the upper sands
is injected into one well on the crest of the Wertz Field dome. The
benefits of this gas injection project were listed in the waterflood
study done by Biggs and Koch (1970). They are (1) the Tensleep gas,
which has low fuel value (52 percent CO^), was put to good use instead
of being wasted; (2) the flowing life of the wells was prolonged; and
(3) increased rate of recovery has been possible without damage to the
reservoir. The program was begun before bottom hole pressures had
declined below levels necessary for flowing wells.
Water injection to the Tensleep reservoir started in 1954, to
supplement the reservoir pressure provided by gas injection and
water influx from the southeast. The Tensleep reservoir covers 1,150
acres with an average pay zone thickness of 150 feet. By the end of
1978, there were 11 wells actively injecting to the reservoir. Three
of the wells are dually completed in the Tensleep and Madison or Amsden
reservoirs.
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Cumulative injection of produced water from the Madison Limestone
through December, 1979, was 62,850,190 barrels (2.6397 x 109 gallons) of
water and 45,196,540 million cubic feet of natural gas. Average injec-
tion pressures at the waterflood project have not exceeded 2,100 psi.
Cas injection pressures have not exceeded 1,426 psi.
West Wertz Unit
The West Wertz Unit of Wertz Field became the site of a water
injection project in 1968, with the initial injection of water from
the Madison Limestone to the Tensleep reservoir, at a depth of 5,880
feet.
Cumulative injection, as of December, 1979, was 5,521,113 barrels
g
(2.3189 x 10 gallons) of water. Average injection pressures have
ranged from 1,183 to 1,700 psi.
Casing Record: Injection Well //4, T26N-R90W-1 bb(cd), Wertz Field,
West Wertz Unit, Total Depth = 7388 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement
13-3/8" 48 17-1/2" 495' 500 sacks
5-1/2" 15.5,17 9" 7375' 600 sacks
(50-50 pozmix)
Whisler Field (337,798 bbls oil, 6,175 MCF gas; 1967-79)
Minnelusa Unit
Water injection to the Minnelusa Formation underlying the Minnelusa
Unit of Whisler Field, started in 1975, with Prenalta Corporation as
unit operator. In 1976, a second well was added to the project. The
wells are completed at depths of 8,288 and 8,442 feet in the Minnelusa
reservoir. Produced Minnelusa water is used in the waterflood.
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Cumulative injection as of December, 1979, was 655,751 barrels
(2.7541 x lO'' gallons) of water.
The Minnelusa Unit of Whisler Field covers a 320 acre area of
federal and private land. The reservoir area includes 164.3 acres
with an average pay zone thickness of 12.1 feet. Average porosity
and permeability of the reservoir are 18.6 percent and 242.2 milli-
darcies, respectively.
Casing Record: Injection Well #2, T51N-R70W-35 bed, Whisler Field,
Minnelusa Unit, Total Depth = 8442 feet.
Casing Size Wt. (///ft) Holev Size Depth Set Cement Purpose
8-5/8" 24 12-1/4" 165' 150 sacks Surface
5-1/2" 15.5,17,20 7-7/8" 8420' 450 sacks Injection
Whitetail Field (5,110,663 bbls oil, 1,985,063 MCF gas; 1968-79)
Muddy Sand Unit
The Muddy Sand Unit of Whitetail Field covers 2,170.8 acres of
federal, state, private, and commutized (joint federal and state
ownership) land inTownship 56 North, Range 72 West, Campbell County.
The first productive well at Whitetail Field was completely in the Muddy
Sandstone during 1968. The Muddy Sandstone reservoir has an average
porosity and air permeability of 22.4 percent and 148 millidarcies,
respectively.
Water injection to the Muddy Sandstone began in 1974, through nine
wells completed at depths ranging from 6,488 to 6,888 feet. Cumulative
Q
injection as of December, 1979, was 15,245,701 barrels (6.4032 x 10
gallons) of water obtained from a supply well in the Fox Hills Sand-
stone. Injection pressures averaged for each well during each six-
month reporting period have ranged from 19 to 2,069 psi.
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Casing Record: Injection Well #109, T56N-R72W-16 adb, Whitetail
Field, Muddy Sand Unit, Total Depth = 6812 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement Purpose
8-5/8" 24 12-1/4" 205' 140 sacks Surface
5-1/2" 14,15.5,17 7-7/8" 6810' 400 sacks Injection
South Muddy Sand Unit
The first producing well in the South Muddy Unit of Whitetail
Field was completed in the Cretaceous Muddy sand reservoir in 1969.
The reservoir is part of a north-south trending segment of a stream
channel deposit, confined on the north, south and east by a sand
pinchout, and on the west by an aquifer contact. Some structural
truncation is evident on the isopach map but, apparently, has little
effect on the entrapment of hydrocarbons. The areal extent of the
reservoir, determined from isopach map planimeter readings, is 276
acres. The average porosity of the productive Muddy sand zone is
16.5 percent.
The South Muddy Sand Unit participating area includes 456.1 acres
of federal and state land. Injection of fresh water from the Fox
Hills Sandstone to the Muddy was initiated in 1980, through three
wells. Cumulative data for the injection project was not available
from the files of the Oil and Gas Commission at the time of this writing.
It has been estimated that the total water requirements for the approxi-
£
mate seven year duration of the waterflood will be 1.8 x 10 barrels
(7.56 x 10^ gallons).
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Casing Record: Injection Well #16-1, T56N-R72W-16 dd(cd), Whitetail
Field, South Muddy Sand Unit, Total Depth = 6749 feet.
Casing Size Wt. (///ft) Hole Size Depth Set Cement Purpose
8-5/8" 24.5 12-1/4" 250' 200 sacks Surface
5-1/2" 15.5 7-7/8" 6749' 125 sacks Injection
Willow Draw Field (1,488,389 bbls oil; 1972-79)
State 30 Unit
The State 30 Unit of Willow Draw Field is located in Township 48
North, Range 103 West, Park County, and is the site of a single well
salt water disposal system and a two well air injection project.
Both projects are located in section 30 of the forementioned
area.
The disposal well was put into operation in 1973. It is completed
in the Madison Limestone. Cumulative injection of brine produced from
wells in the Phosphoria Formation totaled 6,614,865 barrels
g
(2.7782 x 10 gallons) as of June, 1980. Injection pressures have
averaged 150 psi during the project's lifetime.
The air injection project started in 1975. Both injectors are
completed in the Dinwoody and Phosphoria formations at a depth of
about 4,250 feet. Cumulative injection between 1'975, and December,
1979, was 151,822 million cubic feet of air through both wells.
The average pressure at which the air is injected has ranged from
435 to 651 psi.
Wind Creek Field (373,263 bbls oil; 1958-79)
Wind Creek Unit
A single well salt water disposal system, operated by Olds Oil
Company, started injection in 1972. Produced brine is injected to
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the Lower Cretaceous Butler sand at injection pressures that have
averaged between 410 and 550 psi since the start of the project. The
well is located in Section 23, Township 49 North, Range 66 West, Crook
County. Cumulative injection through June, 1980, was 7,328,551
g
barrels (3.078 x 10 gallons) of salt water.
Winkleman Dome Field (72,729,434 bbls oil, 1,892,616 MCF gas; 1917-79)
S. A. Tribal ."A" Unit
Winkleman Dome Field is located in Township 2 North, Ranges 1 and
2 West, Fremont County, and covers 2,269 acres of the Wind River
Indian Reservation. The field was discovered in February, 1944, when
a productive well was completed in the Tensleep Sandstone between
2,915 and 3,205 feet. The first well was drilled in 1917; however,
only shows of gas in the Lakota Sandstone and gas and oil in the
Sundance Formation were encountered.
Water injection to the Tensleep reservoir at the S. A. Tribal
"A" Unit started in January, 1967, with the purpose of accelerating
oil production by supplementing the active water drive of the reservoir.
The Tensleep reservoir covers about 1,000 acres with an average pay
zone thickness of 160 feet.
As of December, 1979, there were 22 injection wells, 14 of which
are dually completed in the Tensleep and Phosphoria (Embar) reservoirs.
Twelve of the wells have also injected natural gas into the Tensleep.
Cumulative water injection, through the above date, was 84,733,526
9
barrels (3.5588 x 10 gallons) of produced Tensleep water. The
volume of gas injected to the Tensleep was not reported. Average
injection pressures have ranged from 25 to 1,300 psi.
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A 16 well steam injection project, operated by Amoco Production
Company, was started in 1965. The injection wells are completed in
the Nugget Sandstone. According to the Oil and Gas Commission's
1979 Statistics Book, all 16 of the wells were active during 1979.
Further details on the project are available in SPE paper 2131,
presented at the Rocky Mountain Regional Meeting of the Society of
Petroleum Engineers of AIME, Billings, Montana, June 5-7, 1968.
Phosphoria Unit
The Phosphoria reservoir of Winkleman Dome covers an area of about
1,414 acres with an average pay zone thickness of 54 feet. Pressure
data, from producing wells completed in the Phosphoria, indicate
that the primary producing mechanism of the reservoir was fluid
expansion with a limited water drive. It was estimated that primary
recovery would be 17 percent of the original oil in place and that
secondary recovery would be 7.5 percent of the original oil in place.
Water injection to the Phosphoria started in August, 1962. As of
December, 1979, there were 38 injection wells completed in the Phosphoria
reservoir. Fifteen of the wells are dual injectors to the Phosphoria
and Tensleep reservoirs or to two separate intervals within the
Phosphoria. Several of the wells also inject natural gas with the
water. Thirty-six of the wells were actively injecting during the
second half of 1979. Cumulative water injection between August,
1962, and December, 1979, was 47,401,136 barrels (1.9908 x 10^
gallons) of produced Phosphoria Formation water. Average injection
pressures during that period ranged from 100 to 1,750 psi.
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Casing Record: Injection Well #310, T2N-R1W-29 bad, Winkleman Dome
Field, Phosphoria Unit, Total Depth = 3560 feet.
Casing Size
9-5/8"
5-1/2"
Wt. (///ft)
36
14
Hole Size
12-1/4"
8-3/4"
Depth Set
169'
3558'
315 sacks
250 sacks
Cement
Worland Field (17,671,353 bbls oil, 361,691,699 MCF gas; 1946-79)
Worland Unit
A single well salt water disposal system, operated by Union Oil
Company of California, began injection to the Phosphoria Formation in
1977. The well is located in Section 20, Township 48 North, Range
92 West, Washakie County, and is completed at a depth of 10,078 feet.
Further details on the system were not available from the files of
the Oil and Gas Commission.
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III. IN SITU URANIUM
INJECTION PROJECTS
As of late 1980, permitted in situ uranium operations in Wyoming
include three commercial scale mines, and an additional 17 research and
development sites. The relatively large number of recently issued
research and development permits indicates industry's increased interest
in in situ uranium development. Current in situ mining techniques,
however, can produce degradation of ground water through mobilization
of toxic elements and increased dissolved solids, though available
information suggests that the extent of ground-water contamination is
site specific and dependent on localy geology, hydrology, and electro-
chemical conditions (Galloway and others, 1980; Walsh and others, 1979).
The following sections review the geology of sedimentary uranium
deposits, in situ mining and restoration techniques, potential environ-
mental impacts associated with active solution mining, restoration, and
post-restoration periods, as well as the current status of Wyoming in
situ uranium operations.
OCCURRENCE AND CHARACTERISTICS OF
URANIUM DEPOSITS
In situ uranium extraction techniques are generally applied to
sedimentary uranium deposits. These deposits, often termed roll
fronts, appear as elongated tubular masses in sandstone or conglomerate
lenses interbedded in shales (McKelvey and others, 1955). Roll front
deposits are believed to form where shallow uranium-bearing ground
III-l
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waters encounter reducing conditions. Uranium is generally insoluble
under reducing conditions and precipitates principally as urananite
(UC^), coffinite [ (USiO^) (OH^) ] , or uraniferrous asphaltite
(asphaltic organic matter containing uranium). Often associated with
uranium deposition are pyrite and/or marcasite (FeS^), along with lesser
amounts of vanadium, selenium, arsenic, and molybdenum minerals
(Stanton, 1972). Non-metallic minerals commonly found within sedi-
mentary uranium deposits include gypsum, calcite, dolomite, fluorite,
barite, and kaolinite.
The concentration of uranium as U„0o, found in uranium roll front
3 0
deposits in the Colorado plateau, commonly varies from 0.1 to 1.0
percent, though may be as high as 20 percent (Stanton, 1972). Concen-
trations of vanadium, selenium, arsenic, and molybdenum are highly
variable, and all may not be found within one deposit. Core samples
in south Texas contained <1-1,638 micrograms per liter (pg/1) Se,
1-1,370 Mg/1 Mo, and 1-129 Mg/1 As (Galloway and others, 1980).
Vanadium concentrations in Utah reported by Stanton (1972) varied from
0.2 to 1.0 percent.
REVIEW OF CURRENT TECHNOLOGIES
In Situ Mining Techniques
Solution mining of sedimentary uranium ore essentially reverses
the hydrochemical processes which initially formed the deposits. A
solution impregnated with 300-1,500 milligrams per liter (mg/1) of
an oxidant (02, H^O^, NaC103) and 1,000-10,000 mg/1 of an alkaline
(>pH 9) uranium complexing agent (Na-CO^, NH^-C0^)'is injected into the
deposit. The oxidizing agent renders reduced uranium minerals unstable,
III-2
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liberating uranium into solution as UO^ , while the carbonate complexing
agent enhances uranium solubility through the formation of
+2 - 0
(UO^ )2^ (Langmuir, 1978). An array of production wells is
used to withdraw the uranium-bearing fluid. The size and shape of the
injection/production well array is dependent upon the size and perme-
ability of the uranium ore zone being solution-mined.
Restoration Techniques
When the uranium concentration of the extract drops below levels
considered economic, injection of mining fluid stops and site restora-
tion begins. Restoration generally involves pumping the mine unit
after injection has stopped, in order to withdraw any lixiviant
remaining within the deposit and to draw unaffected formation water
through the mine zone. This process is referred to as a ground-water
sweep. When a solution mine site fails to respond to a ground-water
sweep, chemical cleansing and reinjection of produced fluids may be
employed to reduce drawdowns. A 10-15 percent loss of fluid is
generally associated with chemical cleansing and reinjection restoration
practices. Site restoration is achieved when predevelopment hydro-
chemical conditions exist within the mined deposit.
POTENTIAL ENVIRONMENTAL IMPACTS
Impacts of Active Solution Mining
During the course of active solution mining, hydrologic effects
are minimal; the injected solution is recycled, thereby dampening any
effects of artificial recharge and discharge on the ore-bearing aquifer.
Generally, some drawdown is allowed to occur in the vicinity of
III-3
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producing wells, enhancing recovery and limiting the spread of mining
fluid.
Significant changes occur in the hydrochemistry of the ore-bearing
aquifer. The injected solution displaces ore formation waters, pro-
ducing an aqueous environment relatively higher in TDS (2,000-12,000
mg/1), metal complexing ions, pH and Eh, depending upon the type and
strength of lixiviant employed. Reduced mineralogies become unstable,
and the injected solution therefore mobilizes uranium and geochemically
similar elements, notably vanadium, selenium, arsenic, and molybdenum.
Iron sulfides, often abundant in sedimentary uranium deposits,
are also oxidized, releasing hydrogen and sulfate ions into solution
and forming insoluble ferric oxides or hydroxides. Acidity generated
by sulfide oxidation may be consumed through carbonate buffering or
| J | J _
silicate hydrolysis releasing Ca , Mg , Na , K , HCO^ , and SiC^
into solution.
Chemical alteration of major cation concentrations in ore zone
waters also takes place through exchange reactions involving clays,
zeolites, and organic material. The injected cation specie (Na+ or
NH^+) is generally the dominant positive ion in solution. Assuming a
sodium lixiviant, the representative exchange reaction
ZNa+ + MZ+ 1 < ZNa+ , + MZ+
aqueous clay clay aqueous
(where M represents an exchangeable cation with charge Z) is driven
strongly to the right. If a concentrated injection fluid is used,
sodium may saturate exchange sites, releasing virtually all exchange-
able cations into solution. Ion exchange, along with solution and
oxidation reactions, may alter the major ion chemistry of the injected
III-4
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fluid sufficiently to cause solution or precipitation of non-metallic
phases such as calcite or gypsum.
The effects of injection and mining solution-aquifer interaction
are generally limited to the ore zone itself, through balanced rates
of injection and production and well field design. Effects of mine
fluid migration out of mined zones are dependent upon many hydrologic
factors, but the mobility of uranium and other trace elements is largely
controlled by the Eh conditions of the excursion area. Movement into
a reducing environment would result in precipitation of trace elements
in a manner analogous to the natural depositional process. Galloway
and others (1980) calculated the extent of trace element movement into
£
reducing conditions, assuming an excursion water volume of 10 liters
containing 1,000 mg/1 0^, and a pyrite concentration of 1 percent in
the zone affected. Under these conditions, the pyrite contained in
3
50 m of sediment would be sufficient to consume all dissolved oxygen.
2
If the excursion moved through a 100 m cross-sectional area, only a
0.5 meter thickness of sediment would be required to reduce the fluid
and render uranium and geochemically similar elements insoluble.
Excursions into oxidizing environments would reduce solubility
controls on these trace elements, though adsorption onto iron oxides/
hydroxides and clays would likely reduce trace element levels (Howard,
1972; Kaback, 1977; Langmuir, 1978; Gulens and others, 1979). The
efficiency of trace element removal by adsorption has not been quanti-
fied, however.
Concentrations of major ions and total dissolved solids in an
excursion zone would likely remain high until affected by a mechanical
process such as dilution or dispersion. Excursions are generally
III-5
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characterized by increases in the concentrations of dissolved solids
(or conductivity), sulfate, carbonate species, or other major ions,
rather than uranium or other trace elements (Wyoming Department of
Environmental Quality - Land Quality Division, Information Files).
Impacts of Restoration
Impacts associated with restoration are not well known as few
commercial-scale in situ uranium developments have completed restora-
tion efforts. Restoration of test sites has not always been successful.
At the Highland test site in Campbell County, Wyoming, ground-water
sweep restoration has been attempted continuously since 1974, without
returning ore zone waters to baseline conditions. Galloway and others
(1980) noted a similar slow chemical response to restoration pumpage
at in situ sites in Texas. Where restoration efforts require long-
term pumpage, significant drawdowns may occur within the ore aquifer.
Chemical cleansing and re-injection of the water produced during
restoration may be employed in such cases, reducing total restoration
related water withdrawals by 85 to 90 percent. At test sites where
chemical cleansing and re-injection have been utilized (Irigaray in
situ site, Johnson County, Wyoming; Bison Basin in situ site, Fremont
County, Wyoming), five to eight mine area pore volumes of fluid have
been recycled through the deposit before restoration was achieved.
The slow return of mine zone waters to baseline conditions,
despite repeated flushings, is poorly understood. In the Texas
uranium district, Galloway and others (1980) noted persistently high
concentrations of dissolved solids, the injected cation specie, and
uranium and geochemically similar elements in produced restoration
III-6
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waters. High dissolved solids concentrations may result from solution
of minerals formed during active mining. Slow release of the injected
cation from exchange sites likely causes the observed high levels of
this ion, in spite of continued flushing, especially if an ammonium-
based lixiviant was used for mining (Walsh and others, 1979).
The response of uranium and geochemically similar trace elements
during restoration is largely controlled by the Eh-pH of the inflowing
waters. An influx of reducing water, more likely to occur during a
ground-water sweep than during a cleansing/re-injection restoration,
would re-establish premining Eh conditions within the deposit, resulting
in precipitation of reduced minerals. The sulfide content of a reducing
inflow would be important for formation of insoluble metal-sulfide
phases.
An oxidizing inflow would result in oxidation of portions of the
deposit that survived mining, or oxidation of subeconomic ores adjacent
to the mined zone. Both these effects would prolong high trace element
levels in mine zone waters during restoration.
Release of trace metals absorbed on clays and oxide/hydroxide
phases (especially iron hydroxides formed through pyrite oxidation)
may also hinder restoration efforts. Adsorption/desorption processes,
though not totally understood, are apparently controlled by pH and
complexing ion (CO^ » SO^ ) concentrations. Within the pH range of
most ground waters, oxide/hydroxide phases strongly adsorb uranium,
selenium, and molybdenum, with the degree of adsorption modified by
the presence of complexing ions (Langmuir, 1978; Kaback, 1977; Howard,
1977).
III-7
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Post-Restoration Impacts
Little is known concerning long-term impacts at a restored in situ
uranium mine. During the solution mining process, however, the type,
amount, and partitioning of elements within the aquifer matrix is
altered, through solution and/or formation of different minerals and
oxide/hydroxide phases, and through exchange and adsorption/desorption
reactions. While restoration returns mine zone waters to premining
conditions, the degree to which the aquifer matrix is restored is
uncertain and likely small. Water-rock interactions within the restored
deposit may differ appreciably from those that occurred previous to
mining, resulting in altered downgradient hydrochemistry.
The type and amount of chemical species mobilized within the post-
mining aquifer depend upon the type, amount, and partitioning of
elements within the aquifer matrix and the hydrochemistry of inflowing
ground waters. Migration of the mobilized species would depend largely
upon the hydrochemical conditions existing downgradient from the
restored site.
PHYSICAL DESCRIPTIONS OF
IN SITU URANIUM SITES
The following section describes the geology, hydrology, and
developmental history of nine in situ uranium sites within Wyoming.
Information for these descriptions was gathered from the files of the
Wyoming Department of Environmental Quality, Land Quality Division
(DEQ-LQD). Permitted sites which are not discussed here are currently
classed as confidential by the Wyoming DEQ-LQD, at the request of the
mine operator.'
III-8
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Restoration criteria for Wyoming in situ uranium developments are
set by the Wyoming DEQ-LQD and require that all chemical parameters
affecting future water use be returned to pre-mining concentrations.
Specifically, for any given chemical parameter of concern a baseline
concentration range and average is established for the mine unit.
Following restoration, all sampling points used to establish baseline
conditions must yield parameter concentrations within the baseline
concentration range, and the average of all parameter concentrations
must be equal to or less than the baseline average. Where this degree
of restoration cannot be obtained, lesser standards may be applied if
the Wyoming DEQ-LQD determines that the best management practice has
been applied during the restoration effort (Wyoming DEQ-LQD, 1980).
The Wyoming DEQ-LQD requires that distinctive components of the
mining fluid be monitored outside the mine zone. Where the concen-
trations of two such components exceed upper control limits (highest
expected concentrations under natural conditions), the monitor well
yielding the excesses is placed on excursion status. The cause of the
excursion must then be determined, and the affected zone returned to
pre-excursion chemical conditions. As of late 1980, however, no
criteria for defining upper control limits had been established. Such
definitions are currently made by the mine operator and are subject to
approval by the Wyoming DEQ-LQD. Generally, the upper control limit
for a given parameter is defined as: (1) the established baseline value
plus a percentage of the baseline value; or (2) the established base-
line value plus some set value.
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Bison Basin Site (Commercial-Scale)
The Bison Basin in situ uranium site is located in Section 25,
Township 27 North, Range 97 West, and Section 30, Township 27
North, Range 96 West, Fremont County, Wyoming. The permitted mine
area covers 751 acres. The uranium ore body at Bison Basin lies within
the Laney Member of the Green River Formation, roughly 350 feet to
400 feet below the surface. The ore-bearing sandstone averages 15
feet in thickness, contains a six-foot thick mineralized zone, and is
overlain and underlain by shales. Strata at the site dip to the south-
east at about 2 degrees. Locally minor faults cut the area, including
2
the ore body. Ore sandstone permeabilities vary from 2.8 to 17 gpd/ft ,
with transmissivities of 42 to 300 gpd/ft. While no permeability
estimates for the confining shales are available, aquifer tests on the
ore sandstone showed no evidence for significant leakage.
A pilot in situ test was conducted at Bison Basin from April 1
through August 1, 1979. Four wells were used to inject a sodium
carbonate/bicarbonate and oxygen enriched solution at a constant rate
of 25 gpm. Three production wells were employed to withdraw the
uranium-bearing fluid, and five wells surrounding the site were used to
monitor water quality in adjacent zones. Approximately 0.93 acres
were mined during the test.
Test site restoration began on August 1 and was completed on
August 14, 1979. Restoration was accomplished through re-injection of
produced waters following reverse osmosis cleansing. Roughly eight
pore volumes of fluid were recycled through the system.
Commercial-scale development of the Bison Basin site has been
approved by the Wyoming DEQ-LQD. The planned facility will have a
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plant capacity of 1,200 gpm and is expected to produce about 200 tons
of uranium (as Uo0o) annually. The site will be divided into four
J o
mining units, and will contain a total of 620 injection wells, 320
production wells, and 58 monitor wells. A total of 56.1 acres of
uranium will be mined. Injection well pressures are expected to be
between 60 and 100 psi. Restoration activities at the commercial
development will be similar to those employed at the test site.
Collins Draw Site (Research and Development)
The Collins Draw in situ uranium site is located in the SE^s, NE^,
NE^;, Section 35 and the S%, NWlj, SW^;, Section 36, Township 43 North,
Range 76 West, Campbell County, Wyoming. The permitted area covers
42.4 acres. The ore body at Collins Draw is 50 to 55 feet thick, lies
450 to 500 feet below the surface, and is overlain and underlain by
2
claystones. Ore zone permeabilities range from 3 to 5 gpd/ft ,
and transmissivities are between 146 and 270 gpd/ft. No continuous
sandstone bodies lie above or below the ore body.
The Collins Draw site is permitted for research and development
testing. Testing was scheduled to begin in May, 1979, and continue for
30 months, though the current field status is not available. Several
100-foot by 100-foot well patterns are planned. The injected solution
will contain 5,000 to 15,000 mg/1 NH^-CO^/HCO^ and 1,000 to 2,000 mg/1
^2^2* Injection pressures are expected to be less than 100 psi.
Restoration will be attempted through cleansing and re-injection of
produced fluids.
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Highland Mine Pilot 1 & 2 (Research and Development)
The Highland mine site, originally permitted for open pit and
underground uranium mining, was additionally permitted for in situ
uranium mining research and development operations beginning in 1972.
The mine site is located in Sections 17, 20-22, 27-29, 33, and 34,
Township 36 North, Range 72 West, and Sections 23 and 24, Township
36 North, Range 73 West, Converse County, Wyoming. Exxon has requested
a permitted area for in situ mining of 1,240 acres.
The mineralized zone is located in the Highland Sand Group of the
Fort Union Formation, roughly 360 to 430 feet below the surface. The
Highland Sand Group is composed of three distinct sands separated and
confined by siltstones and shales. The permeability of the ore-bearing
sand is 19 gpd/ft and porosity is 29 percent. Permeability of the
-3 2
shale is less than 2 x 10 gpd/ft .
An initial pilot test was conducted from March, 1972, to November,
1974, utilizing one injection well, six producing wells, and six
observation wells. A sodium carbonate-bicarbonate lixiviant was
injected at a surface pressure of 50 psi. Produced fluids had an
average grade of 25 mg/1 U^Og.
Restoration of the initial test site began in 1974, and is
currently ongoing. A ground-water sweep is being employed with pumped
water going to solar evaporation ponds.
In 1978, a second pilot area was developed with 25 injection,
production, and monitor wells. This area was placed in operation during
1979, and had produced 39.78 x 10^ gallons of leach solution as of
July, 1980.
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Long-range development plans for commercial scale in situ uranium
mining of the Highland site include the drilling of roughly 74 injection
and 446 production wells, covering 70 acres. Injection wells will be
offset by four production wells with observation wells encircling the
operating area. Monitor wells will be completed into the aquifer above
and below the ore zone. Observation wells will be 250-350 feet apart
and approximately 200 feet from the production perimeter. The distance
between production and injection wells will be about 70 feet. The
proposed plant is designed to process 1,200 gal/min.
Excursion History
During the initial testing two excursions involving elevated levels
of uranium occurred within the ore-sandstone body. They were controlled
by increasing the production and/or decreasing the injection rate, which
suggests that the initial injection-production rates were the cause of
mine fluid migration.
An excursion associated with the second pilot site was linked to
a faulty injection well casing. Leaching fluid was detected in an
overlying aquifer when special observation wells were drilled. Aquifer
clean-up was accomplished through production of these observation wells.
Irigaray Ranch (Commercial Scale)
The Irigaray mine site is located in Sections 5, 8, 9, and 16,
Township 45 North, Range 77 West, Johnson County, Wyoming. The total
permitted mine area covers 600.25 acres with an estimated 191 acres to
be disturbed by all mining related activities. As of August, 1980,
126.24 acres have been developed, including 12 acres of the well field.
This site was the first commercial-scale operation permitted in Wyoming,
and became operational in August, 1978.
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The roll-type uranium mineralization is located in the 100-foot
thick arkosic Upper Irigaray Sandstone of the Wasatch Formation. The
direction of both regional dip and hydraulic gradient is north. The
mineralized zone lies an average of 200 feet below the surface, with
claystones at the site immediately above and below the ore-bearing
2
sandstone. Permeability of the ore sandstone is 3.5 gpd/ft and
porosity is 23 percent. Ore zone transmissivity is 1,000 gpd/ft.
A- 2
Permeability of the confining claystones is below 9 x 10 gpd/ft .
An in situ pilot test was conducted in 1976. Three five-spot
test patterns were used to inject an ammonium bicarbonate-carbonate
solution. Monitor wells were placed 200 feet apart, and 400 feet from
the operating well field.
Test site restoration began in May, 1977. Restoration was
accomplished by re-injecting recovered water after contaminant removal
by means of either ion exchange or a combination of chemical precipi-
tation and reverse osmosis treatment. Using the reverse osmosis process
approximately five pore volumes were recycled.
Commercial-scale operations of the Irigaray site began in August,
1978. The facility has the capacity to produce 500,000 lb/y of
uranium as Uo0o. Approximately 19 AF/y of ground water will be con-
3 o
sumed in production related processes. Well field plans include develop-
ment of nine production units with approximately 40 seven-spot
production cells in each unit. The mining operation will ultimately
include 300 production wells, 800 injection wells, and 85 monitor wells.
Six production units have been fully developed, with units 7-9 currently
being drilled. A maximum pressure of 140 psi at the surface is used
to inject the lixiviant.
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Restoration of the site will be similar to the test site restora-
tion procedure. An estimated 130 AF of water will be consumed in the
restoration of the 30-acre well field.
An alternative injection fluid was tested during 1979-80 at the
Irigaray site. Site restoration began in March, 1980. The alternative
lixiviant has sodium-bicarbonate composition, and will be used in
mining units 6 through 9.
Excursion History
In 1979, three shallow monitor wells exceeded upper control limits
for conductivity, alkalinity, and chloride. They were placed on
excursion status and overpumping of adjacent production wells was
initiated. The cause of the excursions was determined to be a large
number of faulty well casings which allowed for the upward migration of
mining fluids. All casings were examined and repaired where necessary.
During the spring of 1980, the Irigaray mine site was issued an
"Order to Show Cause" by the U.S. Nuclear Regulatory Commission due to
repeated shallow zone monitor well excursions. Lixiviant injection was
ceased for one month and previously injected fluids were recirculated.
In July, 1980, a monitor well exceeded upper control limits for
total alkalinity and conductivity, and was placed on excursion status.
A study of the geology of the area was initiated during summer,
1980, to determine if the repeated excursions were an indication that
the site was actually unsuitable for in situ uranium mining. The
results indicated the area was suitable for the in situ mining procedure
and the excursions were related to migration of fluids in abandoned
exploration holes which had been improperly plugged. Clean-up opera-
tions involved locating, drilling out, and cementing the exploration
111-15
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holes. Subsequent water samples taken from the monitor wells have
shown improved water quality.
Luenberger Site (Research and Development, Commercial Scale Pending)
The Luenberger mine site is located in Sections 13 and 14, Township
34 North, Range 74 West, Converse County, Wyoming. The total permitted
area planned for commercial-scale mining covers 760 acres with an esti-
mated 150 acres to be disturbed by mining activities. The proposed
well field covers 80 acres and will be developed over 11 years.
The uranium mineralization is located in the Lebo Member of the
Fort Union Formation, which is interbedded fine- to coarse-grained
sandstone, siltstone, claystone, and coal. There are two ore bodies at
the Luenberger site. The upper mineralized zone is in the "N" sand at
a depth of 220 to 270 feet below the surface. Total thickness of the
"N" sand is about 50 feet, and the uranium deposit is from five to
20 feet thick. The average permeability of this sandstone is 14
2
gpd/ft , porosity is 26 percent, and the average transmissivity is
700 gpd/ft. It contains 26 percent of the minable ore in the permit
area. The "N" sand is overlain by a claystone and is separated from
the lower host sand by interbedded claystone and siltstone.
The lower ("M") sand lies approximately 320-390 feet below the
surface. Average thickness of the bed is 50-60 feet with the ore
interval ranging from five to 20 feet. The average permeability,
2
transmissivity, and porosity of the host sandstone are 6.7 gpd/ft ,
410 gpd/ft, and 25 percent, respectively. All claystones within the
sequency have "negligible" permeabilities and low storage coefficients;
111-16
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therefore, leakage through the claystone above and below the production
zone is considered unimportant.
Initial research and development testing of the site was in April
and May of 1979, with two single hole tests using a sodium bicarbonate
lixiviant. The pilot test was expanded in January, 1980, with the
addition of two five-spot patterns completed in each of the ore zones.
The uranium extraction plant associated with the test area has a
capacity of 100 gpm.
Restoration tests began in July, 1980, in one of the test patterns,
and currently a ground-water sweep method is being tested. If it
proves unsuccessful, produced water will be recycled through the reverse
osmosis process and re-injected.
In the proposed commercial-scale operations the 80-acre well field
would be divided into eight mining units (six in the "M" sand and two
in the "N" sand), each using a five-spot pattern. An estimated 180
wells, completed in the "M" sand, would be drilled in Unit 1.
The proposed extraction plant will have a flow capacity of 2,000
gpm when mining and ground-water restoration activities are operating
concurrently. The lixiviant utilized in the initial test will also be
injected during commercial-scale operations.
Restoration of the 80 acres will be accomplished by re-injection
of produced water following circulation through a reverse osmosis unit.
To prevent excessive drawdowns within a mining unit during restoration,
water will be pumped from an unmined unit in the same production zone
to the unit being restored. This water will then be pumped out of the
unit being restored, recycled through a reverse osmosis unit, and
re-inj ected.
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Nine Mile Site (Research and Development)
The Nine Mile in situ uranium site is located in the Sh, Section
35, and the NE^s, NW^, Section 34, Township 35 North, Range 79 West,
Natrona County, Wyoming. The permitted mine area covers 81.9 acres.
The uranium ore body at this site lies in the Teapot Sandstone Member
of the Mesaverde Formation, at a depth of about 500 feet. The Teapot
Member is 30 to 80 feet in thickness at the site, contains 20 to 35
feet of uranium ore, and is overlain and underlain by shales. Ore
2
zone permeability averages 32.7 gpd/ft , with transmissivities of 1,300
to 3,800 gpd/ft. Porosity averages 28 percent. Permeabilities of the
2
bounding shales are less than 0.02 gpd/ft .
Testing at the Nine Mile site began in November, 1976. Three test
patterns were leached with a sulfuric acid lixiviant, at injection rates
of approximately 10 gpm. A fourth test, utilizing an alkaline lixiviant,
is currently underway. A total of 15 injection wells and 10 production
wells have been used. Early restoration attempts involved prolonged
pumping of the test site. Later efforts involved lime neutralization,
chemical cleansing, and re-injection of produced fluids. Restoration
of the current test site is expected to require recirculation of
roughly 5 pore volumes of reverse osmosis treated fluid.
Excursion History
An excursion of mining solution was noted at the Nine Mile site
in late 1979, when several parameters exceeded upper control limits.
The excursion problem was solved by increased production rates.
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Peterson Site (Research and Development Pending)
The proposed Peterson in situ uranium site lies in the NEh;, NW^,
Section 35, and the SE^c, SW^, Section 26, Township 36 North, Range 73
West, Converse County, Wyoming. The uranium-bearing sandstone at the
Peterson site lies 220 to 260 feet below the surface, averages 40 feet
in thickness, and contains a 5 to 15 foot thick mineralized zone.
The ore sand is overlain and underlain by 30 feet and 170 feet,
respectively, of mudstone. Strata at the site dip about 2 degrees to
2
the southeast. Ore sandstone permeability varies from 5 to 15 gpd/ft ,
with transmissivities of 242 to 372 gpd/ft. Porosity averages 27
percent. No permeabilities are available for the bounding shales,
but aquifer tests on the ore sand show no evidence for significant
leakage.
Testing at the Peterson site, though not yet approved, is planned
for March, 1981. Twelve injection wells, four production wells, and
eight monitor wells are planned for the 1.6-acre test site. The
injected solution will contain 2,000 to 5,000 mg/1 NaCO^, and 300 to
1,500 mg/1 of O2 or ^2^2' R-estorat;iori will involve cleansing and
re-injection of produced fluids, and will result in a net withdrawal
of about 0.63 acre-feet of water.
Reno Creek ISL Project (Research and Development)
Reno Creek is located in Sections 27 and 28, Township 43 North,
Range 72 West, Campbell County, Wyoming. Research and development
operations began in 1979, on a permitted area of 39.32 acres.
The uranium deposit is located within a sandstone of the Wasatch
Formation that is about 200 feet below the surface and confined by
111-19
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mudstones. Average sandstone porosity, permeability, and thickness
2
are 28 percent, 1.0 gpd/ft , and 118 feet, respectively.
Test site I included one five-spot pattern consisting of four
injection wells, one producing well, and seven monitor wells. This
test was scheduled to last two years and included the addition of two
more five-spots. A sulfuric acid leach was injected at a rate of 40
gpm (10 gpm/well) and withdrawn at 42 gpm. Problems arose in March
of 1979, after three months of production, including a rise in calcium
levels and evidence of gypsum scaling that resulted in a loss of
production. Efforts to restore production were only semi-successful
and the uranium content of the produced fluid was considerably lower
than anticipated. Due to scaling, fungus plugging, high acid consump-
tion and the low U^Og content of produced fluids, it was concluded that
an acid leach was unsuccessful at Reno Creek.
An addendum was filed with the Wyoming DEQ-LQD to allow for the
drilling of a second test pattern (test site II) and testing of a
carbonate lixiviant. This pattern was drilled in September, 1979, and
is currently being tested. The extraction plant has a production
capacity of 35 to 45 gpm.
Restoration of the initial site (test site I) began in November,
1979. The method tested involved re-injection of clean water from
treated leach solution. Water was cleansed by lime neutralization,
CC>2 addition, and either barium hydroxide addition, ion exchange, or
reverse osmosis. As of December 31, 1979, three pore volumes of clean
water had been pumped through the pattern.
Restoration of test site II will be accomplished by re-injecting
produced water that has been cycled through a reverse osmosis unit.
111-20
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Ruth ISL Site (Research and Development Pending)
The proposed Ruth ISL mine site is located in the SE^s, NE^;, and
NE^, SE^s, Section 14, SW^, NW^s, Section 13, Township 27 North, Range 77
West, Johnson County, Wyoming. The operation would include a permitted
area of 39.94 acres with less than 10 acres disturbed by mining
activities.
The target sand is located in the lower part of the Wasatch Forma-
tion approximately 500 to 565 feet below the surface. It is primarily
arkosic in composition, with substantial organic debris, carbonaceous
stringers, and localized sandy shale lenses. Total thickness of the
sand unit, which is confined by shales, is roughly 50 feet.
Transmissivity of the ore sandstone is 141.9 gpd/ft and porosity is
29 percent.
The in situ test site will contain five seven-spot hexagonal
patterns including 19 injection wells and five recovery wells. An
alkaline carbonate-bicarbonate lixiviant will be tested. The pilot
processing plant has a planned maximum capacity of 50 gpm.
Initial restoration tests will involve a ground-water sweep with
disposal of recovered water into solar evaporation ponds. If this
method should prove unsuccessful, re-injection of water purified by
reverse osmosis will be tested.
Pending DEQ-LQD approval, site preparation, well field drilling,
and plant and pond construction will begin in spring of 1981. The
pilot leach test is scheduled to begin early summer, 1981. Leaching
will last for 10 months, followed by four months of site restoration.
111-21
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IV. IN SITU TRONA INECTION
PROJECTS
Trona (Na^CO^'NaHCO^*2H^O), a highly soluble evaporite mineral,
occurs within saline lake deposits in several parts of the world,
including the Sahara and Kalahari Deserts of Africa, parts of Iran,
Armenia, and Tibet in Asia, and California and Wyoming in the United
States. Trona is used as a raw source of pure sodium carbonate (NaCO^)
or soda ash. Major uses of soda ash include glass manufacture, sodium-
based chemical production, and pulp and paper processing. Roughly
12 million short tons of trona were mined in the United States during
1978; about 95 percent of this tonnage was produced in Wyoming by
conventional subsurface mining methods (U.S. Bureau of Mines, 1980).
The highly soluble nature of trona has raised interest in the
possible in situ recovery of this resource. No in situ trona recovery
projects were operational within Wyoming as of mid-1981. However, two
research and development scale trona solution projects have been
proposed, with the test plans recently approved by the Wyoming Depart-
ment of Environmental Quality-Land Quality Division (DEQ-LQD). The
following sections contain discussions of (1) the characteristics of
the Wyoming trona deposits; (2) the technology and potential environ-
mental impacts of in situ trona recovery; and (3) brief descriptions of
the two proposed research and development trona solution sites.
IV-1
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CHARACTERISTICS OF THE WYOMING TRONA DEPOSITS
The largest known trona deposits in existence occur within the
Wilkins Peak Member of the Eocene Green River Formation, Sweetwater
County, Wyoming. Here, an area of roughly 1,100 square miles is under-
lain by bedded trona. The bulk of the deposits are contained in 25
or more major beds ranging from about 3 to 40 feet in thickness
(Bradley and Eugster, 1969), and lying from 1,500 to 2,000 feet below
the surface. Extent of the individual beds varies from less than 165
square miles to over 723 square miles. Thinner trona layers, up to
2 feet in thickness, are present between the major beds and are of
uncertain extent. Dolomitic mudstones and shales, some high in organic
matter, are interbedded with the trona deposits.
Associated with the Wilkins Peak trona deposits are other evaporite
minerals, including considerable amounts of shortite (Na^CO^'CaCO^* 2^0),
northrupite (Na2C02'MgC02'NaCl), and halite (NaCl). Detailed analysis
of a 555-foot core of the Wilkins Peak member (Section 2, Township 18
North, Range 110 West) by Fahey (1962), indicates it contained 10 percent
shortite, 6.4 percent trona, and 2.2 percent northrupite. In general,
only trona and occasionally halite are present as distinct beds,
although exceptions exist (Bradley and Eugster, 1969).
For a more detailed description of Wilkins Peak mineralogies, see
Fahey (1962) and Bradley and Eugster (1969).
REVIEW OF CURRENT TECHNOLOGIES
Little published information is available concerning the tech-
nological aspects of in situ trona recovery. Although other bedded
evaporite deposits, particularly halite, have been solutionally mined
IV-2
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since the 1940's (Bay, 1962), in situ trona recovery has yet to be
tested in the field. Two research and development trona solution
projects, proposed for Sweetwater County, Wyoming, have recently been
approved by the state. Much of the technological aspects of these
tests is considered confidential by the mine operators. Therefore the
following sections are based largely upon portions of the test plans
for the above sites which are not considered proprietary information,
and are on open file at the Wyoming DEQ-LQD. Additionally, some
analogies are drawn between trona and bedded halite solution mining
techniques, because of the large amount of available data on in situ
halite processes and the similar geological and geochemical character-
istics of these minerals.
The basic methodology of in situ trona mining is fairly simple.
A pair of wells, one designed for fluid injection and one for brine
production, are completed in the trona deposit. An efficient spacing
distance between the injection/production wells is currently unknown.
The proposed test sites will utilize a 350 to 450 foot spacing (Wyoming
DEQ-LQD,information files, 1981). A commercial-scale trona solution
mine would likely utilize greater separations; well spacings at active
halite solution mines are generally between 500 and 1,500 feet (Bay,
1962).
Following well completions the injection/production wells are
hydrologically linked. The proposed trona test sites will attempt
linkage through hydrofracturing. Injection pressure needed for initial
2
fracturing is expected to be less than 3,500 lb/in (Wyoming DEQ-LQD,
information files, 1981). Data from halite solution mines where
IV-3
-------
hydrofracturing has been employed indicate injection pressures of about
2
2,500 lb/in are required, at similar depths (Mair, 1960). Solution
passage development in halite, and likely in trona as well, tends to
follow the zones of weakness induced by hydrofracturing; therefore
directional well perforation and/or formation "notching" is often
employed to insure proper solution passage growth from the injection
well to the production well (Henderson, 1962). A saturated brine solu-
tion is used for in the initial fracturing to control cavity development
adjacent the injection well. Other well linking techniques employed
at halite solution mines, and which may be suitable for trona deposits,
are directional drilling and blasting.
When the injection/production wells are successfully linked, active
solution mining commences. A heated, water based solvent is introduced
into the deposit through the injection well, and the resulting brine
is withdrawn through the production well, conveyed to shallow ponds,
and the trona is redeposited through evaporation. Temperature of the
injected solvent is dependent upon heat loss to the formation, but is
expected to be less than 180°F at the Wyoming test sites (Wyoming DEQ-
LQD, information files, 1981). Composition of the injected solvent is
considered confidential by the mine operators. The solvent is likely
utilized to insure that as the sodium concentration of the brine
increases, sodium bicarbonate and sodium carbonate minerals, which have
differing solubilities depending upon temperature and partial pressure
of remain unstable as solid phases.
Active solution mining continues until recovery is no longer
economic. If no fluid losses are taking place when mining ceases, the
cavity is filled with saturated brine, as support against roof collapse.
IV-4
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Due to the low permeability of trona, no restoration activities
are proposed (Wyoming DEQ-LQD, information files, 1981).
POTENTIAL ENVIRONMENTAL IMPACTS
Potential environmental impacts associated with in situ trona
recovery include excursions of the injected solvent or produced brine
into overlying or underlying aquifers, and subsidence problems as the
solutionally mined cavity grows. These effects are discussed below.
Excursions of solvent and/or brine are considered unlikely during
the normal course of solution mining due to the low primary permeability
in trona deposits. Hydrofracturing of the deposits results in greatly
increased permeability, but pressure gradients induced by the injection/
production well pair would likely restrict flow to the area between the
wells. Excursion problems could arise if hydrofracturing affects over-
or under-lying strata, opening a path for brine escape. The potential
for such brine loss may be evaluated prior to mining, by circulating
a saturated solution through the injection/projection well pair.
Saturated brine cannot cause cavity growth; therefore if injection and
production volumes are equal, no fluid loss is taking place (Wyoming
DEQ-LQD, information files, 1981).
A commercial scale trona solution mine may cause roof collapse
or even surface subsidence, depending upon the size, shape, and depth
of the produced cavity. While such problems cannot be alleviated
entirely, several methods of limited collapse, such as are employed
at halite solution mines, are applicable to trona. These include: (1)
planned cavity development with a minimum of roof exposure; (2)
monitor of cavity development by material removal monitoring and sonar
IV-5
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investigations; (3) surface and subsurface monitoring for earth move-
ments; and (4) saturated brine filling of the cavity when mining ceases.
PHYSICAL DESCRIPTIONS OF IN SITU TRONA SITES
Information used for in situ trona site descriptions is taken from
mine test plans submitted to the Wyoming DEQ-LQD. Much of the infor-
mation on one of these sites is considered confidential by the mine
operator; its description is limited to location only.
Vulcan Materials
Vulcan Materials, Inc., will test in situ trona recovery at a
10-acre site located within Section 16, Township 16 North, Range 109
West. The evaporite-bearing section of the Wilkins Peak Member lies
1,650 to 2,026 feet below the surface at the site. The trona deposits
are interbedded with mudstones and oil shales. Drill stem test perme-
2
abilities of the interbedded mudstones vary from 0.0045 to 0.02 gpd/ft .
Tests at the Vulcan Materials site will utilize one injection/
production well pair, spaced at about 350 to 450 feet. Hydrofracturing
will be used to hydrologically connect the well pair. Fracture pressure
2
is expected to be less than 3,500 lb/in . Elevated hydraulic pressure
will be maintained after the initial fracture to insure hydrologic
connection, and to solutionally widen the path between the wells.
Once well linkage is accomplished, saturated brine will be circu-
lated through the system for about one week, at 50 gpm, to detect any
fluid losses. This phase of testing will be followed by injection of
hot water, at temperatures up to 180°F, to determine heat losses. The
final testing phase will involve injection of a heated solvent solution
IV-6
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to determine the feasibility of trorva solution mining. Composition of
the injected solvent is considered confidential by the mine operator.
Feasibility testing is expected to last four to six weeks.
FMC
FMC, which has long mined trona by conventional subsurface methods,
will test in situ trona recovery at a site within Section 36, Township
17 North, Range 110 West. Details of this test are considered confi-
dential by the operator.
IV-7
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V. UNDERGROUND COAL
GASIFICATION PROJECTS
The process of underground gasification of coal to methane, though
facing technical difficulties and not currently applied on a commercial
scale in the United States, may someday provide an economically feasible
method for exploiting the deeply buried coals of the American West.
Underground coal gasification (UCG) is not a new concept; as early as
1868, gasification of slack and waste coal remaining in mineshafts was
suggested. During the 1930's several UCG techniques were developed
in the Soviet Union, and one commercial-scale facility was brought into
operation. Experimental work with UCG in the United States began in
the late 1940's under the direction of the U.S. Bureau of Mines and
continues today through the U.S. Department of Energy. A general dis-
cussion of the UCB process and potential environmental effects is given
below. For a more detailed treatment of UCG technology, see
"Environmental Aspects of Coal Conversion" (Oak Ridge National
Laboratory, 1977).
REVIEW OF CURRENT TECHNOLOGIES
Underground coal gasification consists of coal seam combustion,
aided by inflowing oxygen, air, or air and steam, followed by the
collection of produced gases. Early work by the Russians involved
extensive mechanical development of the coal seam, such as digging or
blasting tunnels for enhancement of combustant/product gas flow, and
for isolation of the coal panels to be gasified. While these methods
V-l
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provided a fair degree of success, economic considerations limit their
applicability to shallow deposits. UCG experiments in the United
States have emphasized borehole methods, eliminating the need for
mechanical pre-gasification seam development.
Although specifics of borehole gasification methods vary, the
processes are generally similar. Pairs of boreholes, one for injection
and one for production, are drilled into the coal seam. These, or other
wells, may be used to dewater the seam if dewatering is deemed necessary.
Coal seam permeability between the injection/production wells is often
increased by hydrofracturing, directional drilling, explosives, or
electrocarbonization (passing sufficient electric current through the
seam to heat the coal to distillation and coking temperatures and
inducing fracturing). After the seam is ignited near one of the bore-
holes, a combustant is injected into the seam that controls the burn
rate and drives the fire face through the seam. Injection pressures
are usually equal to or greater than the existing hydrostatic pressure,
to limit intrusion of ground water. Occasionally, high initial
injected pressures may be used for dewatering purposes. The direction
of fire face movement through the seam may be either horizontal or
vertical. Combustion may be in the same direction as the gas flow,
called forward combustion, or opposite to the gas flow, termed reverse
combustion.
Factors affecting the efficiency of UCG experimental developments
include: (1) gas leakage out of the combustion zone; (2) uncontrolled
intrusion of ground water into the combustion zone; (3) inability to
control the burn direction and rate; (4) loss of coal seam fracture
permeability due to plugging with coal tars and other heavy liquid
V-2
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gasification by-products; and (5) failure to establish a sufficiently
permeable linkage between injection/production well pairs (Oak Ridge
National Laboratory, 1977; Campbell and others, 1974; Gregg and others,
1976).
POTENTIAL ENVIRONMENTAL IMPACTS
In situ coal gasification offers several environmental advantages
over conventional extraction methods. Acid drainage, disturbance of
overburden and the mine area land surface, and other impacts of strip
mining are avoided, as are the potential health dangers associated
with underground coal mining. However, the magnitude of environmental
effects of a large UCG project are poorly known, due to the present
lack of commercial-scale development.
Investigations at research and development sites have identified
several features of the UCG process that may lead to local ground-
water degradation, including: (1) escape of gas into adjacent portions
of the coal and/or overlying strata, increasing the concentration of
dissolved organics in area ground waters; (2) leaching of residual
materials remaining in the burn zone following combustion, leading to
increased downgradient concentrations of trace elements, organics, and
dissolved solids; and (3) subsidence of overlying strata due to coal
combustion, producing a hydraulic connection between the combustion
zone and overlying ground-water sources.
Combustion Gas Leakage
Gas loss to zones adjacent to the burn often is greater than 10
percent of total gas production (Oak Ridge National Laboratory, 1977).
While produced gas composition is variable, the gas generally contains
V-3
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a complex mixture of volatile organic compounds; analysis of steam
produced during an in situ gasification test near Gillette, Wyoming
(Hoe Creek site) identified over 250 different organic compounds, with
greater than 1 mg/1 concentrations of condensed acetone, benzene,
toluene, and naphalene. Dispersion of these volatile organics into
adjacent zones is controlled by molecular weight, with lighter compounds
migrating farther from the burn than relatively heavier compounds
(Campbell and others, 1979).
Effects of Combustion Zone Leaching
Leaching of coal tars, ash, and other by-products of gasification
remaining in the burn zone takes place after burn zone temperatures
have fallen below 100°C. Monitoring of Lawrence Livermore Laboratory's
UCG pilot project near Gillette, Wyoming, showed that coal seam ground
waters passing through the burn zone contained increased concentrations
of dissolved solids, major ions, lithium, cyanide, bromide, phenolic
materials, and trace metals, relative to baseline conditions (Mead and
others, 1978). Elevated concentrations of trace metals diminished
rapidly with distance from the burn zone. Laboratory evidence indicates
that adsorption of metal ions onto coal was responsible for the observed
decrease (Wang, 1979).
Though high trace metal concentrations were limited to areas
adjacent to the burn, subtle increases in other inorganic, nonvolatile
species were noted as far as 100 feet from the burn zone within three
days after combustion ceased. Mead and others (1978) suggested that
this rapid movement is caused by convection currents, induced by
temperature differentials existing across the burn boundary. Long-term
V-4
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(25 months) monitoring showed concentrations of most combustion related
contaminants to decrease significantly with time, though not to baseline
levels. Decreases were ascribed to a loss of convective currents and
a lowering of solubilities as the burn zone cools.
Overburden Subsidence
Where large thicknesses of coal are removed, significant roof
collapse is likely to occur, potentially allowing for movement of
gases and contaminated burn zone waters into overlying strata. If
large-scale subsidence occurs, shallow flow systems may be totally
disrupted. The effects of subsidence-induced hydraulic connection
between the coal aquifer and overlying aquifers are highly site specific
and likely dependent upon: (1) the relative hydraulic head differences
in the coal and overlying aquifers; (2) the hydrochemical and electro-
chemical conditions of overlying ground waters; (3) the presence or
absence of adsorbing materials in overlying strata; (4) effects of
convective currents originating in the burn zone; and (5) the areal
extent of subsidence. Although subsidence has occurred at several
research and development UCG sites, environmental effects of this
phenomenon are not presently documented. Development on a commercial
scale may result in significant subsidence over a relatively large
geographic area.
PHYSICAL DESCRIPTIONS OF UNDERGROUND
COAL GASIFICATION SITES
The following section describes the hydrogeology and developmental
history of UCG sites within Wyoming. As of late 1980, three research
and development UCG sites, operated directly by or under the direction
V-5
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of the U.S. Department of Energy, existed within Wyoming: the Hanna,
Hoe Creek, and North Knob UCG experiments.
Hanna Site
The Hanna UCG site lies in the SW^s, Section 29 and the SE^s, Section
30, Township 22 North, Range 81 West, Carbon County, Wyoming. The
deposit being exploited at this site is the sub-bituminous Hanna #1
coal of the Hanna Formation. Depths to the coal seam vary from 275 to
450 feet at the site. Seam thickness varies from 26 to 30 feet.
Four UCG tests have been completed at the Hanna site, beginning
in 1973. In all tests, reverse combustion was used to link the
injection/production well pairs, and air was utilized as the injected
combustant.
Hanna tests I-III were considered successful, but Hanna IV,
designed to test the feasibility of commercial-scale (greater than 100
feet) process well spacings, failed due to an inability to establish
a sustained burn between the injection/production well pair. The
problem was linked to a faulty well completion. Although the well was
repaired and additional process wells were added to the original pattern,
a sustained burn was not attained, and the Hanna IV test was abandoned.
Production related details of the Hanna tests are given in Table
V — 1. For a more detailed discussion of the Hanna site and associated
UCG testing, see Bartke and others (1980).
V-6
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Table V-l. U.S. Department of Energy - Hanna Site Tests.
Test
Duration
(days)
Average
Gas
Quality
(BTU/ft5)
Average
Production
Rate
(ft3/day)
Combustant
Coal
Gasif ied
(tons)
Process
q
Efficiency
Number of
Injection/
Production
Wells
Well
Spacing
(ft)
Hanna I
180
126
1,600,000
Air
4,000
-
17
Hanna II-l
38
152
2,700,000
Air
1,260
83%
2
52.5
11-2
25
175
8,500,000
Air
2,520
89%
4
60.0
II-3
38
138
12,000,000
Air
4,200
76%
4
60.0
Hanna III
38
138
10,000,000
Air
2,850
76%
2
60
Hanna IV
55b
_
_
Air
_
_
8
100-150°
Process efficiency refers to the energy value of the gas collected relative to the energy value of the
coal seam volume gasified.
^Sustained gasification not maintained in Hanna IV test.
c
Spacing of original three wells. Process related problems resulted in additional wells at various
spacings.
-------
Hoe Creek Site
The Hoe Creek UCG site is located in Section 7, Township 47 North,
Range 72 West, Campbell County, Wyoming. The coal being exploited at
this site is the sub-bituminous Felix II coal of the Wasatch Formation.
The Felix II coal averages 25 feet in thickness, and lies about 125
feet below the land surface at this site. Overlying and underlying the
coal are siltstones and claystones. Coal seam permeability varies from
3.7 to 7.3 gpd/ft2.
Three UCG tests have been completed at Hoe Creek, under the
direction of Lawrence Livermore Laboratory, Livermore, California.
Test I was a small-scale, short duration experiment. Explosives were
used to enhance permeability between process wells, and air was
utilized as the injected combustant. Test II also employed air as the
combustant; process wells were linked by reverse combustion. In test
III, directional drilling was used to link the boreholes, and C^/steam
was the injected oxidant. Coal gas of an average quality greater
3
than 200 BTU/ft was produced during the 47-day O^/steam test.
Production related details of the Hoe Creek UCG tests are given
in Table V-2. For a more detailed discussion of the Hoe Creek site
and associated UCG testing, see Fisher and Aiman (1978).
V-8
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Table V-2. U.S. Department of Energy - Hoe Creek Site Tests
Average
Average
Number of
Gas
Production
Coal
Inj ection/
Well
Test
Duration
(days)
Quality
(BTU/ft )
Rate
(ft3/day)
Combustant
Gasified
(tons)
Process
Efficiency3
Production
Wells
Spacing
(ft)
Hoe Creek
I
11
110
1,700,000
Air
120
73%
2
30
Hoe Creek
II
58
2
106
263
3,300,000
Air
02/steam
2,300
68%
2
2
60
60
Hoe Creeic
III
7
115
—
Air
260
-
4
100
47
218
-
02/steam
3,900
-
4
100
aProcess efficiency refers to the heating value of the gas collected relative to the energy value of the
coal seam volume gasified.
-------
North Knob Site
The North Knob UCG site is located within Section 11, Township
21 North, Range 89 West, Carbon County, Wyoming. The deposit being
exploited at North Knob is the sub-bituminous G coal seam of the Fort
Union Formation. The G coal is about 23 feet thick at the site, and
dips at 63 degrees to the southwest. Depth to the coal seam varies
from 0 feet to 600 feet. Coal seam permeability is less than 0.1
gpd/ft2.
The North Knob site was selected for research into the feasibility
of in situ gasification of steeply dipping coal beds. One UCG test
has been conducted at North Knob, as a joint venture between the U.S.
Department of Energy and Gulf Research and Development Corporation.
The injection/production well pair used at North Knob was linked
by directional drilling. Air was employed as the combustant throughout
most of the test, although 02/steam was utilized for a short part of
the experiment. Both the air and 02/steam tests yielded successful
results.
Production related details of the North Knob test are given in
Table V-3. For a more detailed discussion of the North Knob site
and associated UCG testing, see Gulf Research and Development
Corporation (1980).
V-10
-------
Table V-3. U.S. Department of Energy/Gulf Research and Development Corp. - North Knob Site Tests
Test
Duration
(days)
Average
Gas
Quality
(BTU/ft )
Average
Production
Rate
(ft3/day)
Combustant
Coal
Gasified
(tons)
Process
Efficiency3
Number of
Inj ection/
Production
Wells
Well
Spacing
(ft)
North Knob la
38
167
-
Air
1,200
75%
2
100
lb
5
250
-
C^/steam
-
-
2
100
aProcess efficiency refers to the heating value of the gas collected relative to the energy value of the
coal seam volume gasified.
-------
VI. CHEMICAL WASTE
INJECTION SITES
As of late 1980, only one chemical waste disposal well was
operational within Wyoming. The well is located in the SW%, SW%,
Section 16, Township 13 North, Range 67 West, Laramie County, and is
operated by Wycon Chemical Corporation. Total well depth is 6,305
feet, and the well is perforated from 6,010 to 6,040 feet. The
injected unit is the Hygiene Sandstone member of the Pierre Shale.
Permeability of the Hygiene at the site is variable, generally ranging
2
from 0.2 to 14 gpd/ft . Porosity varies from 15 to 20 percent.
Injection of chemical wastes, containing principally nitrogen
+ U
compounds such as nitrate (N0^ ), ammonia (NH^ ), and urea (NH2-C-NH2),
began in June of 1969. As of October, 1980, roughly 88 million
gallons of waste solution had been injected through the Wycon well.
Average injection rates and pressures vary from 100 to 225 gpm and
650 to 1,000 psi, respectively. Concentrations of injected species
also vary. The range of monthly averages for nitrate is 100 to 5,000
mg/1; for ammonia, 750 to 6,500 mg/1; for urea, 120 to 8,800 mg/1.
Dissolved solids concentration varies from 4,000 to 20,000 mg/1, and
the injected solution pH ranges from 8.4 to 10.0.
VI-1
-------
VII. GLOSSARY
aquifer: A porous, permeable, water-saturated geologic unit capable
of yielding economically significant quantities of water to
wells.
barrel: Unit of oil field measurement equal to forty-two gallons.
brine: Concentrated brackish saline or sea waters containing more than
100,000 mg/1 of total dissolved solids.
cementing: The operation whereby a cement slurry is pumped into a
drill hole and/or forced behind the casing for such purposes
as: sealing the casing to the walls of the hole; preventing
unwanted leakage of fluids into the hole or migration of
liquids or gas into or out of the hole; closing the hole
back to a shallower depth; sealing a dry hole; or redrilling
to straighten the hole; and plugging and abandonment.
centipoise: A unit of viscosity based on the standard of water at
20°C, which has a viscosity of 1.005 centipoise.
corrosion: The gradual deterioration or destruction of a substance
or material by chemical action, frequently induced by electro-
chemical processes.
darcy: A standard unit of permeability, equivalent to the passage of
one cubic centimeter of fluid of one centipoise viscosity
flowing in one second under a pressure differential of one
atmosphere through a porous medium having a cross-sectional
area of one square centimeter and a length of one centimeter.
1 darcy = 1,000 millidarcies.
drill stem test: A procedure for determining productivity of an oil
or gas well by measuring reservoir pressures and flow
capacities while the drill pipe is in the hole and the well
is full of drilling mud. A drill stem test may be done in
a cased or uncased hole.
dual injection: A process of fluid injection which uses one well to
inject fluid into two different perforated intervals. Tubing
is run inside the casing and is used to inject fluid to the
deeper of the two intervals. Fluid is injected to the other
interval through the annular space between the tubing and the
casing. Packers placed below the upper interval and/or above
the lower interval confine injection to the objective
perforated intervals.
VII-1
-------
effective porosity: The measure of the total volume of interconnected
void space of a rock, soil or other substance. Usually
expressed as a percentage of the bulk volume of material
occupied by the interconnected void space.
emulsion: A heterogeneous mixture of two or more liquids not normally
dissolved in one another, but held in suspension by forceful
agitation or by emulsifiers which modify the surface tension
of the droplets to prevent coalescence.
facies change: A lateral or vertical variation in the lithologic
characteristics of contemporaneous sedimentary deposits.
It is caused by, or reflects, a change in the depositional
environment.
fault: A surface or zone of fractured rock along which there has been
displacement.
flocculation: The agglomeration of colloidal and finely divided
suspended matter.
formation: A body of rock characterized by a degree of lithologic
homogeneity, mappable on the earth's surface or traceable in
the subsurface.
geophysical logs: The records of a variety of logging tools which
measure the geophysical properties of geologic formations
penetrated and their contained fluids. These properties
include electrical conductivity and resistivity, the ability
to transmit and reflect sonic energy, natural radioactivity,
hydrogen ion content, temperature, gravity, etc. These
geophysical properties are then interpreted in terms of
lithology, porosity, fluid content and chemistry.
injection pressure: The pressure per unit area acting on the injected
fluid within the well. Usually measured at the wellhead
in pounds per square inch.
injection well: A well into which fluid(s) is pumped for the purpose of
increasing the yield of oil and/or gas from producing wells in
the area or to dispose of fluids in the subsurface environment
by allowing them to enter by gravity flow or injection under
pressure.
packer: In well drilling, a device lowered in the lining tubes which
swells automatically or can be expanded by manipulation from
the surface to produce a water-tight seal against the sides
of the borehole or the casing, thus entirely excluding water
from different horizons.
pay zone: The term applied to that portion of the oil reservoir which
exceeds a minimum porosity determined by the operating
company of the field (usually 10%) and lies above the oil-
water contact.
VII-2
-------
permeability: The measure of the relative ease of fluid flow under
unequal pressure. The customary unit of measurement is the
millidarcy.
porosity: The measure of the volume of pore space within a rock
divided by the bulk volume of the rock. Usually expressed
as a percentage.
reservoir: The term applied to that portion of a geologic formation
which contains hydrocarbons in a single hydraulically
connected system.
unit: The term applied to the surface area covered by a formal agree-
ment between operators and royalty owners approved by the
U.S. Geological Survey and/or the Wyoming Oil and Gas
Conservation Commission. The purpose of the agreement is
to increase the efficiency of hydrocarbon withdrawal by
consolidating field activities under one operator.
VII-3
-------
VIII. LOCATION AND NUMBERING
SYSTEM
The locations of wells, units, and fields given in this report
are designated by a well numbering system based on the federal system
of land subdivision. The first number denotes the township, the
second number denotes the range, and the third number denotes the
section. Any letters following the section number denote the location
within the section. The section is divided into quarters (160 acres
each) and lettered a, b, c, and d in a counter-clockwise direction,
beginning in the northeast quarter. Similarly, each quarter may be
further divided into quarters (40 acres) and divided again into 10-
acre tracts and lettered as before.
R.70W. R.69W. R.68W. R.67W.
VIII-1
-------
The first letter, if shown, following the section number denotes
the quarter section; the second letter, if shown, denotes the quarter-
quarter section; the third letter, if shown, denotes the quarter-quarter-
quarter section, or 10-acre tract. For example, in the illustration
above, well number 49N-69W-21 cab is in the NWh; of the NE^ of the SW^
of Section 21, T. 49 N., R. 69 W.
VIII-2
-------
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IX-1
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