Technical Review of Subpart RR MRV Plan for
Rangely Gas Plant (RGP)
April 2024
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OFFICE OF AIR AND RADIATION
WASHINGTON, D.C. 20460
April 26, 2024
Mr. Juan Nevarez
Scout Energy Management
100 Chevron Road
Rangely, Colorado 81648
Re: Monitoring, Reporting and Verification (MRV) Plan for Rangely Gas Plant
Dear Mr. Nevarez:
The United States Environmental Protection Agency (EPA) has reviewed the Monitoring, Reporting and
Verification (MRV) Plan submitted for Rangely Gas Plant, as required by 40 CFR Part 98, Subpart RR of
the Greenhouse Gas Reporting Program. The EPA is approving the MRV Plan submitted by Rangely Gas
Plant on March 28, 2024, as the final MRV plan. The MRV Plan Approval Number is 1009244-1. This
decision is effective May 1, 2024 and is appealable to the EPA's Environmental Appeals Board under 40
CFR Part 78. In conjunction with this MRV plan approval, we recommend reviewing the Subpart PP
regulations to determine whether your facility may also be required to report data as a supplier of
carbon dioxide. Furthermore, this decision is applicable only to the MRV plan and does not constitute
an EPA endorsement of the project, technologies, or parties involved.
If you have any questions regarding this determination, please contact me or Melinda Miller of the
Greenhouse Gas Reporting Branch at miller.melinda@epa.gov.
Chief, Greenhouse Gas Reporting Branch
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Contents
1 Overview of Project 1
2 Evaluation of the Delineation of the Maximum Monitoring Area (MMA) and Active
Monitoring Area (AMA) 3
3 Identification of Potential Surface Leakage Pathways 4
4 Strategy for Detecting and Quantifying Surface Leakage of C02 and for Establishing Expected
Baselines for Monitoring 7
5 Considerations Used to Calculate Site-Specific Variables for the Mass Balance Equation 14
6 Summary of Findings 19
Appendices
Appendix A: Final MRV Plan
Appendix B: Submissions and Responses to Requests for Additional Information
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This document summarizes the U.S. Environmental Protection Agency's (EPA's) technical evaluation of
the Greenhouse Gas Reporting Program (GHGRP) Subpart RR Monitoring, Reporting, and Verification
(MRV) plan submitted by Scout Energy Management (SEM), LLC's Rangely Gas Plant (RGP) for its carbon
dioxide (C02)-enhanced oil recovery (EOR) project in the Permian-aged Rangely Field in Rio Blanco
County, Colorado. Note that this evaluation pertains only to the Subpart RR MRV plan, and does not in
anyway replace, remove, or affect Underground Injection Control (UIC) permitting obligations.
Furthermore, this decision is applicable only to the MRV plan and does not constitute an EPA
endorsement of this project, technologies, or parties involved.
1 Overview of Project
As described in the MRV plan, Scout Energy Management, LLC (SEM) currently operates a C02-E0R
project at the RGP located in Rio Blanco County, Colorado, for the primary purpose of enhanced oil
recovery using C02, with retention of C02 serving a subsidiary purpose of geologic sequestration of C02
in a subsurface geologic formation. The MRV plan states that the RGP is comprised of the Rangely
Weber Sand Unit (RWSU) and the associated Raven Ridge Pipeline (RRPC), which together are referred
to as the Rangely Field. The producing formation, which also serves as the sequestration zone, is the
Weber Formation. While the Rangely Field was discovered in 1933, the MRV plan states that C02
flooding was initiated in 1986. Under this MRV plan, RGP plans to inject and store approximately 51.2
million metric tonnes (MMMT) of C02 over the duration of the project from 1986 through 2060, or
35.7% of the theoretical storage capacity of Rangely Field. The MRV plan further notes that as of the end
of 2022, 2,320,000 million standard cubic feet (MMscf) (122.76 MMMT) of C02 has been injected into
Rangely Field, of which 1,540,000 MMscf (81.48 MMMT) was produced and recycled. RGP expects that
the total amount of C02 injected and stored over the modelled injection period to be 967,000 MMscf
(51.2 MMMT). This MRV plan was developed in accordance with 40 CFR §98.440-449 (Subpart RR) to
provide for the monitoring, reporting, and verification of the quantity of C02 sequestered at the RGP.
The MRV plan states that all EOR injection wells in the RGP are currently classified as UIC Class II wells
permitted by the Colorado Oil and Gas Conservation Commission (COGCC). COGCC has primacy to
implement the UIC Class II program in the state for injection wells. Wells in the RGP are identified by
name, American Petroleum Institute (API) number, status, and type. The list of wells as of April 2023 is
included in Appendix 5 of the MRV plan. RGP recognizes that any changes to wells within the RGP will be
indicated in the Subpart RR Annual Report.
RGP is located in the northwestern corner of Colorado within the Rocky Mountain Province along the
structural high of the Douglas Arch, which separates the Uinta Basin to the west and Piceance Basin to
the east. More locally, large thrust faults shaped the overall structure of the subsurface north of the
Douglas Arch and around the RGP. These asymmetrical anticlines are doubly plunging, creating a dome-
shaped trap that allows hydrocarbons to accumulate within. The MRV plan states that the Weber
Formation is a Permian-aged clean eolian quartz sandstone that was deposited in an erg (sand sea).
Internally, the dune sands are separated into six main packages with the fluvial Maroon Formation
interfingering the field from the north. RGP states that the Weber Formation is underlain by the
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fossiliferous Desmoinesian carbonates of the Morgan Formation and overlain by the siltstones and
shales of the Posphoria/Park City and Moenkopi Formations. The Moenkopi Formation will serve as the
confining seal. The MRV plan also states that there are no confined freshwater aquifers present
between the reservoir rock and the surface and that the shallowest point of the reservoir is 5,486 feet
below the surface (4,986 feet below any possible fresh rainwater seepage).
The MRV plan states that the Weber Formation was deposited on top of the Morgan Formation, which is
a combination of interbedded shale, siltstone, and cherty limestone. While few wells were drilled deep
enough to penetrate the Morgan Formation within the Rangely field to gather porosity/permeability
data locally, analysis of the Morgan from other fields/outcrops indicate that it is a non-reservoir rock
(low porosity/permeability), making it a sufficient basal barrier for the Rangely Field. The Rangely Field
has one main field fault (MFF) and numerous smaller faults (isolated and joint) and fractures that are
present throughout the stratigraphic column between the base of the Weber reservoir and surface. The
MRV plan states that faults within the reservoir were measured by well-to-well displacement, while the
fractures were measured and observed as calcite veins on the surface with no displacement. RGP states
that the MFF has a NE-WSW trend and cuts through the reservoir interval. The USGS installed seismic
monitoring stations in and around the town of Rangely, Colorado after the Rangely residents began
experiencing felt earthquakes in the 1960s. In 1971, a study was conducted to evaluate the stress state
in the vicinity of the fault which determined a critical fluid pressure of approximately ~3,730 pounds per
square inch (psi), above which fault slippage may occur. Since five earthquakes were recorded between
2015 and 2017, no seismic events have been recorded at the RGP. A new interpretation of 3D seismic
revealed a series of previously unknown joint faults perpendicular to the MFF. RGP states that these
natural fractures do not diminish the seal's integrity.
According to the MRV plan, C02 is purchased from ExxonMobil's (XOM) Shute Creek Plant and delivered
to the RGP via the Raven Ridge Pipeline. The mass of C02 received at RGP is metered and calculated
through one custody transfer meter located at the pipeline delivery point. The mass of C02 received is
combined with a recycled C02/hydrocarbon gas mix from the recycle compression facility (RCF) and
distributed to the water alternating gas (WAG) headers for injection according to the injection plan for
each well pattern. RGP states that as of April 2023, approximately 160 MMscf is injected into 280
injection wells, of which approximately 15% is purchased C02 and the remaining 85% is recycled.
The MRV plan states that gathering lines bring the produced fluids from each of the 382 active
production wells operated by SEM in the RGP to one of 27 collection stations for gas and liquid
separation. Following separation, the gas phase is transported by pipeline to the C02 reinjection facility
for processing. There is an operations meter at the facility inlet. RGP states that currently, the average
composition of this gas mixture as it enters the facility is 92% C02 and 800 parts per million (ppm)
hydrogen sulfide (H2S). The liquid phase, which is a mixture of oil and water, is sent to one of two
centralized water plants where oil is separated from water via two 3-phase separators. The separated oil
is metered through the Lease Automatic Custody Transfer (LACT) unit located at the custody transfer
point between the Chevron pipeline and the RGP. The separated water is sent to holding tanks and any
gas that is released from the liquid phase rises to the top of the tanks and is collected by a Vapor
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Recovery Unit (VRU) that compresses the gas and sends it to the C02 recycling and compression facility
for processing. Once gas enters the C02 reinjection facility, it undergoes dehydration and compression.
An additional process separates Natural Gas Liquids (NGLs) for sale. At the end of these processes there
is a C02 rich stream that is recycled through reinjection. The MRV plan also states that meters at the C02
recycling and compression facility outlet are used to determine the total volume of the C02 stream
recycled back into the EOR operations.
The description of the project provides the necessary information for 40 CFR 98.448(a)(6).
2 Evaluation of the Delineation of the Maximum Monitoring Area
(MMA) and Active Monitoring Area (AMA)
As part of the MRV plan, the reporter must identify and delineate both the maximum monitoring area
(MMA) and active monitoring area (AMA), pursuant to 40 CFR 98.448(a)(1). Subpart RR defines
maximum monitoring area as "the area that must be monitored under this regulation and is defined as
equal to or greater than the area expected to contain the free phase C02 plume until the C02 plume has
stabilized plus an all-around buffer zone of at least one-half mile." Subpart RR defines active monitoring
area as "the area that will be monitored over a specific time interval from the first year of the period (n)
to the last year in the period (t). The boundary of the active monitoring area is established by
superimposing two areas: (1) the area projected to contain the free phase C02 plume at the end of year
t, plus an all-around buffer zone of one-half mile or greater if known leakage pathways extend laterally
more than one-half mile; (2) the area projected to contain the free phase C02 plume at the end of year t
+ 5." See 40 CFR 98.449.
The MRV plan states that because C02 is present throughout the Rangely Field and retained within it,
the AMA is defined by the boundary of the Rangely Field plus a one-half mile buffer. C02 injected into
the Rangely Field remains contained within the AMA because of the fluid and pressure management
results associated with EOR. The maintenance of an injection to withdrawal ratio (IWR) of 1.0 assures a
stable reservoir pressure; managed lease line injection and production wells are used to retain fluids in
the Rangely Field. The MRV plan, therefore, suggests that it is highly unlikely that injected C02 will
migrate downdip and laterally outside the Rangely Field because of the nature of the geology and the
approach used for injection. Rangely Field is situated at the top of a dome structural trap, which means
that over long periods of time, injected C02 will tend to rise vertically towards the point with the highest
elevation. The MRV plan also states that operations will not expand beyond the currently active C02-E0R
portion of the Rangely Field; therefore, the AMA is not expected to increase. Based on the MMA
definition and the expectation that the maximum extent of the injected C02 plume will be bounded by
the Rangely Field, the MMA is the Rangely Field Unit boundary plus the one-half mile buffer as required by
40 CFR §98.440-449 (Subpart RR).
The delineations of the MMA and AMA are acceptable per the requirements in 40 CFR 98.448(a)(1). The
MMA and AMA described in the MRV plan are clearly delineated in the plan and are consistent with the
definitions in 40 CFR 98.449.
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3 Identification of Potential Surface Leakage Pathways
As part of the MRV plan, the reporter must identify potential surface leakage pathways for C02 in the
MMA, and that the likelihood, magnitude, and timing of surface leakage of C02 through these pathways
pursuant to 40 CFR 98.448(a)(2). RGP identified the following as potential leakage pathways in their
MRV plan that required consideration:
1. Existing Wellbores
2. Faults and Fractures
3. Natural or Induced Seismicity
4. Previous Operations
5. Pipeline/Surface Equipment
6. Lateral Migration Outside the Rangely Field
7. Drilling Through the C02 Area
8. Diffuse Leakage Through the Seal
3.1 Leakage through Existing Wellbores
The MRV plan states that leakage through existing wellbores is a potential risk at the RGP. RGP states
that they work to prevent leakage through existing wellbores by adhering to regulatory requirements for
well drilling and testing; implementing best practices that RGP has developed through its extensive
operating experience; monitoring injection/production performance, wellbores, and the surface; and
maintaining surface equipment. The MRV plan states that regulations require that wells be completed
and operated so that fluids are contained in the strata in which they are encountered and that well
operation does not pollute subsurface and surface waters. Depending on the purpose of the well, the
requirements can include additional standards for evaluation and Mechanical Integrity Testing (MIT).
RGP states that their best practices include pattern level analysis to guide injection pressures and
performance expectations; utilizing diverse teams of experts to develop EOR projects based on specific
site characteristics; and creating a culture where all field personnel are trained to look for and address
issues promptly. RGP states that their practices ensure that well completion and operation procedures
are designed not only to comply with regulations but also to ensure that all fluids (e.g., oil, gas, and C02)
remain in the Rangely Field until they are produced through an RGP well. The MRV plan states that in
the time that RGP has operated the Rangely Field, there have not been any C02 leakage events from a
wellbore.
Thus, the MRV plan provides an acceptable characterization of C02 leakage that could be expected
through existing wellbores.
3.2 Leakage through Faults and Fractures
According to the MRV plan, there are no known faults or fractures that transect the entirety of the
Weber Sands in the project area. The MRV plan states that the MFF is present below the reservoir and
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terminates within the Weber Sands without breaching the upper seal. Furthermore, the MRV plan states
that additional faults have been identified in formations that are stratigraphically below the Weber
Sands, but this faulting has been shown not to affect the Weber Sands or to have created potential
leakage pathways given that they do not contract the Upper Pennsylvanian or Permian strata (Weber
Formation).
RGP believes that they have extensive experience in designing and implementing EOR projects to ensure
injection pressures will not damage the oil reservoir by inducing new fractures or creating shear. RGP
states that, as a safeguard, injection satellites are set with automatic shutoff controls if injection
pressures exceed fracture pressures.
Thus, the MRV plan provides an acceptable characterization of C02 leakage that could be expected
through faults and fractures.
3.3 Leakage through Natural or Induced Seismicity
RGP concludes in the MRV plan that there is no direct evidence that natural seismic activity poses a
significant risk for loss of C02 to the surface in the RGP. RGP believes this is due to the fact that
hydrocarbons are still contained within the anticline, meaning that there have been no major seismic
events in the last few million years capable of releasing these hydrocarbons to the surface.
The MRV plan states that induced seismic events are tied to the MFF and its joint faults, which can be
impacted by RGP operations. To prevent this from occurring, the MRV plan states that RGP will collect
bottom hole pressure surveys one or two times per year across the RGP, which helps to monitor
pressure changes across the area. The MRV plan also states that by keeping reservoir pressure from
exceeding the threshold of approximately 3,730 psi for extended periods of time (multiple years),
induced seismic events can be greatly mitigated. If reservoir pressure exceeds threshold pressure, a
reduction in injection volumes in the vicinity will bring down the pressures gradually over a period of
time.
Thus, the MRV plan provides an acceptable characterization of C02 leakage that could be expected
through natural or induced seismicity.
3.4 Leakage from Previous Operations
The MRV plan states RGP's operational experience supports the conclusion that there are no unknown
wells within the RGP that penetrate the Weber Sands and that it has sufficiently mitigated the risk of
migration from older wells. The MRV plan also states that RGP and the prior operators have kept records
of the site of C02 flooding, which was initiated in 1986, and have completed numerous infill wells.
Furthermore, RGP states that they will follow Area of Review (AOR) requirements under the UIC Class II
program, which require identification of all active and abandoned wells in the AOR and implementation
of procedures that ensure the integrity of those wells when applying for a permit for any new injection
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well. RGP believes that these practices ensure that identified wells are sufficiently isolated and do not
interfere with C02-E0R operations and reservoir pressure management.
Thus, the MRV plan provides an acceptable characterization of C02 leakage that could be expected from
previous operations.
3.5 Leakage from Pipeline/Surface Equipment
The MRV plan states that RGP reduces the risk of unplanned leakage from its surface facilities to the
maximum extent practicable by relying on the use of prevailing design and construction practices and
maintaining compliance with applicable regulations. The MRV plan states that the facilities and pipelines
currently utilize and will continue to utilize materials of construction and control processes that are
standard for CO2-EOR projects in the oil and gas industry. Furthermore, the MRV plan states that
operating and maintenance practices at the RGP currently follow and will continue to comply with all
applicable regulations. Finally, frequent routine visual inspection of surface facilities by field staff will
provide an additional way to detect leaks and further support SEM's efforts to detect and remedy any
leaks in a timely manner. Should leakage be detected from pipeline or surface equipment, the volume of
released C02 will be quantified following the requirements of Subpart W of EPA's GHGRP.
Thus, the MRV plan provides an acceptable characterization of C02 leakage that could be expected from
pipeline/surface equipment.
3.6 Leakage from Lateral Migration Outside the Rangely Field
The MRV plan states that it is highly unlikely that injected C02 will migrate downdip and laterally outside
the RGP because of the nature of the geology and the approach used for injection. The MRV plan states
that the RGP is situated at the top of a dome structural trap, with all directions pointing down-dip from
the highest point. Therefore, injected C02 will tend to rise vertically towards the point in the Rangely
Field with the highest elevation. The MRV plan also states that the planned injection volumes and active
fluid management during injection operations will prevent C02 from migrating laterally stratigraphically
out of the structure. Finally, RGP states that they will not be increasing the total volume of fluids in the
RGP.
The MRV plan states that COGCC requires that injection pressures be limited to ensure injection fluids
do not migrate outside the permitted injection interval. RGP uses two methods to contain fluids: 1)
reservoir pressure management, and 2) the careful placement and operation of wells along the outer
producing limits of the units. RGP states that they manage the reservoir pressure by maintaining an IWR
of approximately 1.0. To maintain the IWR, RGP states that they monitor fluid injection to ensure that
reservoir pressure does not increase to a level that would fracture the reservoir seal or otherwise
damage the oil field.
Thus, the MRV plan provides an acceptable characterization of C02 leakage that could be expected from
lateral migration outside the Rangely Field.
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3.7 Leakage from Drilling through the CO2 Area
The MRV plan states that it is possible that at some point in the future, drilling through the containment
zone into the Weber Sands could occur and inadvertently create a leakage pathway. RGP believes that
the risk of leakage caused by drilling through the C02 area is very low for two reasons. First, RGP's visual
inspection process, including routine site visits, is designed to identify unapproved drilling activity in the
RGP. Second, RGP plans to operate the CO2-EOR flood in the RGP for several more years and will
continue to be vigilant about protecting the integrity of its assets and maximizing the potential of
resources (oil, gas, and C02).
Thus, the MRV plan provides an acceptable characterization of C02 leakage that could be expected from
drilling through the C02 area.
3.8 Diffuse Leakage through the Seal
The MRV plan states that diffuse leakage through the seal formed by the Moenkopi Formation is highly
unlikely. RGP asserts that that the presence of a gas cap trapped over millions of years confirms that the
seal has been secure for a very long time. RGP's injection monitoring program assures that no breach of
the seal will be created. The MRV plan also states that the seal is highly impermeable where
unperforated and cemented across the horizon where perforated by wells. In addition, unexplained
changes in injection pressure would trigger investigation into the cause. Furthermore, the MRV plan
states that if C02 were to migrate through the Moenkopi seal, it would migrate vertically until becoming
trapped by any of the numerous shallower shale seals.
Thus, the MRV plan provides an acceptable characterization of C02 leakage that could be expected
through the seal.
The MRV plan concludes that, based on a careful assessment of the potential risk of release of C02 from
the subsurface, SEM determined that there are no leakage pathways at the RGP that are likely to result
in significant loss of C02 to the atmosphere. Thus, the MRV plan provides an acceptable characterization
of potential C02 leakage pathways as required by 40 CFR 98.448(a)(2).
4 Strategy for Detecting and Quantifying Surface Leakage of C02 and
for Establishing Expected Baselines for Monitoring
40 CFR 98.448(a)(3) requires that an MRV plan contain a strategy for detecting and quantifying any
surface leakage of C02, and 40 CFR 98.448(a)(4) requires that an MRV plan include a strategy for
establishing the expected baselines for monitoring C02 surface leakage. Sections 4 and 5 of the MRV
plan detail RGP's strategy for monitoring and quantifying C02 leakage, and Section 6 of the MRV plan
details strategies for establishing expected baselines for C02 leakage. RGP's approach for detecting and
quantifying surface leakage of C02 primarily includes modeling, direct measurements, routine field
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inspections, SCADA system monitoring of wellhead pressures, MITs, monitoring reservoir pressure,
engineering estimates, and emission factors.
A summary table of RGP's strategies for monitoring and responding to any possible C02 leakage can be
found in Table 3 of the MRV plan and is reproduced below:
Risk
Monitoring Plan
Response Plan
Parallel
Reporting (if
any)
Loss of Well Control
Tubing Leak
Monitor changes in tubing and
annulus pressure; MIT for injectors
Well is shut in and
Workover crews respond
within days
COGCC
r inn. . Routine Field inspection; monitor
g Lea changes in annulus pressure; MIT for
injectors; extra attention to high risk
{wells
Well is shut in and
Workover crews respond
within days
COGCC
Wellhead Leak
Routine Field inspection
Well is shut in and
Workover crews respond
within days
COGCC
Loss of Bottom-
hole
pressure control
Blowout during well operations
Maintain well kill
procedures
COGCC
Unplanned wells Routine Field inspection to
drilled through prevent unapproved drilling;
Weber Sands compliance with COGCC permitting
(for planned weils.
Assure compliance with
COGCC regulations
COGCC
Permitting
Loss of seal in
abandoned wells
Reservoir pressure in monitor wells;
high pressure found in new wells
Re-enter and reseal
abandoned wells
COGCC
Leaks in Surface Facilities
Pumps, valves, etc.
Routine Field inspection; SCADA
Maintenance crews
respond within days
Subpart W
Subsurface Leaks
Leakage along
faults
Reservoir pressure in monitor wells;
high pressure found in new wells
Shut in injectors near
faults
-
Overfill beyond
spill
points
Reservoir pressure in monitor wells;
high; pressure found in new wells
Fluid management
along
lease lines
-
Leakage through
induced fractures
Reservoir pressure in monitor wells;
high pressure found in new wells
Comply with rules for
keeping pressures
below
parting pressure
-
Leakage due to Reservoir pressure in monitor wells;
seismic event high
pressure found in new wells
Shut in injectors near
seismic event
-
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4.1 Detection of Leakage through Existing Wellbores
As stated in the MRV plan, leakage through existing wellbores is a potential risk at the RGP. RGP states
that their continual and routine monitoring of wellbores and site operations will be used to detect leaks,
including those from non-RGP wells, or other potential well problems. RGP also states that the following
methods will be employed to detect leakage from existing wellbores:
Well pressure in injection wells is monitored on a continual basis. The injection plans for each
pattern are programmed into the injection WAG controller to govern the rate and pressure of
each injector. As such, pressure monitors on the injection wells are programmed to flag
pressures that significantly deviate from the plan. If such excursions occur, they are investigated
and addressed.
RGP states that they will use the experience gained over time to strategically approach well
maintenance. RGP maintains well maintenance and workover crews onsite for this purpose. RGP
also states that they use all the information at hand including pattern performance and well
characteristics to determine well maintenance schedules.
RGP states that production well performance is monitored using the production well test
process conducted when produced fluids are gathered and sent to a collection station. This test
allows RGP to allocate a portion of the produced fluids measured at the collection station to
each production well, assess the composition of produced fluids by location, and assess the
performance of each well. The MRV plan states that performance data are reviewed on a
routine basis to ensure that C02 flooding is optimized. If production is off plan, it is investigated,
and any identified issues are addressed.
The MRV plan states that field inspections are conducted on a routine basis by field personnel.
Leaking C02 is very cold and leads to formations of bright white clouds and ice that are easily
spotted. All field personnel are trained to identify leaking C02 and other potential problems at
wellbores and in the field.
Additionally, Section 5.0 of the MRV plan states that RGP uses the data collected by H2S monitors, which
are always worn by all field personnel, as a last method to detect leakage from wellbores. The H2S
monitors have a detection limit of 10 ppm. Should an H2S alarm be triggered, the source of the alarm
will be safely investigated. RGP considers H2S a proxy for potential C02 leaks in the field. Therefore, the
MRV plan states that detected H2S leakage will be investigated to determine if potential C02 leakage is
present, but not used to determine the leak volume.
The MRV plan states that if an investigation of leakage leads to a work order, field personnel would
inspect the equipment in question and determine the nature of the problem. If the leakage is a simple
matter, repair would be made, and the volume of leaked C02 would be included in the 40 CFR Part 98
Subpart W report for the Rangely Field as well as reported in Subpart RR. If the leakage required more
extensive repair, a work order would be generated and RGP would determine the appropriate approach
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for quantifying leakage C02 using the relevant parameters (e.g., the rate, concentration, and duration of
leakage).
Table 3 of the MRV plan provides a detailed characterization of detecting C02 leakage that could be
expected through existing wellbores. Thus, the MRV plan provides adequate characterization of RGP's
approach to detect potential leakage through existing wellbores as required by 40 CFR 98.448(a)(3).
4.2 Detection of Leakage through Faults and Fractures
As stated in the MRV plan, RGP has concluded that there are no known faults or fractures that transect
the entirety of the Weber Sands in the project area. The MRV plan states that reservoir pressure in
monitor wells and high pressure found in new wells will be used to detect leakage along faults and
leakage through induced fractures.
Table 3 of the MRV plan provides a detailed characterization of detecting C02 leakage that could be
expected through faults and fractures. Thus, the MRV plan provides adequate characterization of RGP's
approach to detect potential leakage through faults and fractures as required by 40 CFR 98.448(a)(3).
4.3 Detection of Leakage through Natural or Induced Seismicity
The MRV plan states that there is no direct evidence that natural seismic activity poses a significant risk
for loss of C02 to the surface in the RGP. The MRV plan also states that bottom hole pressure surveys are
collected one or two times per year across the RGP to help monitor pressure changes across the RGP.
Specifically, reservoir pressure in monitor wells and high pressure found in new wells will be used to
detect leakage due to seismic events.
Table 3 of the MRV plan provides a detailed characterization of detecting C02 leakage that could be
expected through natural or induced seismicity. Thus, the MRV plan provides adequate characterization
of RGP's approach to detect potential leakage through natural or induced seismicity as required by 40
CFR 98.448(a)(3).
4.4 Detection of Leakage from Previous Operations
As stated in the MRV plan, RGP's operational experience supports the conclusion that there are no
unknown wells within the RGP that penetrate the Weber Sands. Therefore, RGP states that it has
sufficiently mitigated the risk of migration from older wells. The MRV plan states that reservoir pressure
in monitor wells and high pressure found in new wells will be used to detect leakage from previous
operations.
Table 3 of the MRV plan provides a detailed characterization of detecting C02 leakage that could be
expected from previous operations. Thus, the MRV plan provides adequate characterization of RGP's
approach to detect potential leakage from previous operations as required by 40 CFR 98.448(a)(3).
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4.5 Detection of Leakage from Pipeline/Surface Equipment
The MRV plan states that RGP reduces the risk of unplanned leakage from surface facilities to the
maximum extent practicable, by relying on the use of prevailing design and construction practices and
maintaining compliance with applicable regulations. However, the MRV plan also states that pressure
transducers with low pressure alarms monitored through the SCADA system prevent and detect leakage
through pipeline and surface equipment. Furthermore, routine and frequent visual inspections of
surface facilities by field staff will provide an additional way to detect leaks and further support RGP's
efforts to detect and remedy any leakage from pipelines and surface equipment.
Table 3 of the MRV plan provides a detailed characterization of detecting C02 leakage that could be
expected from pipelines and surface equipment. Thus, the MRV plan provides adequate characterization
of RGP's approach to detect potential leakage from pipelines and surface equipment as required by 40
CFR 98.448(a)(3).
4.6 Detection of Leakage from Lateral Migration Outside the Rangely Field
The MRV plan states that it is highly unlikely that injected C02 will migrate downdip and laterally outside
the Rangely Field because of the nature of the geology and the approach used for injection. Even still,
the MRV plan states that reservoir pressure in monitor wells and high pressure found in new wells will
be used to monitor leakage beyond spill points (lateral migration).
Table 3 of the MRV plan provides a detailed characterization of detecting C02 leakage that could be
expected from lateral migration outside the Rangely Field. Thus, the MRV plan provides adequate
characterization of RGP's approach to detect potential leakage from lateral migration outside the
Rangely Field as required by 40 CFR 98.448(a)(3).
4.7 Detection of Leakage from Drilling Through the CO2 Area
As stated in the MRV plan, RGP's concluded that the risk of C02 leakage occurring from drilling through
the C02 area is very low for two reasons. RGP's visual inspection process, including routine site visits, is
designed to identify unapproved drilling activity in the RGP. Furthermore, the MRV plan states that
compliance with COGCC permitting for planned wells will help monitor for unplanned wells drilled
through the Weber Sands.
Table 3 of the MRV plan provides a detailed characterization of detecting C02 leakage that could be
expected from drilling through the C02 area. Thus, the MRV plan provides adequate characterization of
RGP's approach to detect potential leakage from drilling through the C02 area as required by 40 CFR
98.448(a)(3).
11
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4.8 Detection of Diffuse Leakage through the Seal
As stated in the MRV plan, diffuse leakage through the seal formed by the Moenkopi Formation is highly
unlikely. However, the MRV plan states that unexplained changes in injection pressure would trigger
investigation regarding the cause.
Table 3 of the MRV plan provides a detailed characterization of detecting diffuse C02 leakage that could
be expected through the seal. Thus, the MRV plan provides adequate characterization of RGP's
approach to detect potential diffuse leakage through the seal as required by 40 CFR 98.448(a)(3).
4.9 Quantification of Potential CO2 Leakage
As described in the MRV plan, given the uncertainty concerning the nature and characteristics of leaks
that will be encountered, the most appropriate methods for quantifying the volume of leaked C02 will
be determined at the time the leak is discovered. In the event leakage occurs, RGP plans to determine
the most appropriate methods for quantifying the volume of C02 leaked and will report the quantity of
C02 leaked as required as part of the annual Subpart RR Submission.
Estimates of the amount of C02 leaked to the surface will depend on several site-specific factors
including measurements of flowrates and pressures, size of leak opening, and duration of the leak.
Engineering estimates and emission factors will also be used depending on the source and nature of the
leakage. RGP's process for quantifying leakage will also entail using the best engineering principles or
emission factors.
The MRV plan states that a subsurface leak might not lead to surface leakage. In the event of a
subsurface leak, RGP would determine the appropriate approach for tracking subsurface leakage to
determine and quantify leakage to the surface. In the event leakage to the surface occurs, RGP would
quantify and report leakage amounts, and retain records that describe the methods used to estimate or
measure the volume leaked as reported in the Annual Subpart RR Report. RGP would estimate the
relevant parameters (e.g., the rate, concentration, and duration of leakage) to quantify the leak volume.
Depending on specific circumstances these determinations may rely on engineering estimates.
4.10 Determination of Baselines
According to the MRV plan, RGP intends to utilize existing automatic data systems to identify and
investigate excursions from expected performance that could indicate C02 leakage. RGP's data systems
are used primarily for operational control and monitoring and as such are set to capture more
information than is necessary for reporting in the Annual Subpart RR Report. RGP will develop the
necessary system guidelines to capture the information that is relevant to identify possible C02 leakage.
RGP describes the following approaches for collecting this information:
Visual Inspections
12
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The MRV plan states that work orders are generated in the electronic system for maintenance activities
that cannot be addressed on the spot. Methods to capture work orders that involve activities that could
potentially involve C02 leakage will be developed, if not currently in place. Each incident will be flagged
for review by the person responsible for MRV documentation. RGP states that the Annual Subpart RR
Report will include an estimate of the amount of C02 leaked.
Personal H2S Monitors
The MRV plan states that H2S monitors are worn by all field personnel. Any monitor alarm triggers an
immediate response to ensure personnel are not at risk and to verify the monitor is working properly.
The person responsible for MRV documentation will receive notice of all incidents where H2S is
confirmed to be present. The Annual Subpart RR Report will provide an estimate of the amount of C02
emitted from any such incidents.
Injection Rates, Pressures and Volumes
The MRV plan states that RGP develops a target injection rate and pressure for each injector based on
the results from ongoing pattern modeling and within permitted limits. The injection targets are
programmed into the WAG controllers. High and low set points are also programmed into the SCADA
system, and flags are triggered whenever statistically significant deviations from the targeted ranges are
identified. For the purposes of Subpart RR reporting, excursions will be screened to determine if they
could also lead to C02 leakage to the surface. The person responsible for the MRV documentation will
receive notice of excursions and related work orders that could potentially involve C02 leakage. The
Annual Subpart RR Report will provide an estimate of C02 emissions.
Production Volumes and Compositions
The MRV plan states that RGP develops a general forecast of production volumes and composition to
periodically evaluate performance and refine current and projected injection plans. This information is
used to make operational decisions but is not recorded in an automatic data system. Sometimes, this
review may result in the generation of a work order in the maintenance system. The MRV plan
implementation lead will review such work orders and identify those that could result in C02 leakage.
Thus, RGP provides an acceptable approach for detecting and quantifying leakage and for establishing
expected baselines in accordance with 40 CFR 98.448(a)(3) and 40 CFR 98.448(a)(4).
13
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5 Considerations Used to Calculate Site-Specific Variables for the
Mass Balance Equation
5.1 Calculation of Mass of CO2 Received
Section 7.1 of the MRV plan states that Equation RR-2 in Subpart RR §98.443 will be used to calculate
the mass of C02 received from each delivery meter upstream at the receiving custody transfer meter
from the Raven Ridge pipeline delivery system at the RGP. The volumetric flow at standard conditions
will be multiplied by the C02 concentration and the density of C02 at standard conditions to determine
mass.
CO 2t, r - Net annual mass of CO2 received through flow meter r (metric tons).
Qr p = Quarterly volumetric flow through a receiving flow meter r in quarter p at
standard conditions (standard cubic meters).
Sr,p = Quarterly volumetric flow through a receiving flow meter r that is redelivered
to another facility without being injected into your well in quarter p (standard
cubic meters).
D = Density of C02 at standard conditions (metric tons per standard cubic meter):
0.0018682.
Cco2,P,r = Quarterly C02 concentration measurement in flow for flow meter r in quarter p
(vol. percent C02, expressed as a decimal fraction).
p = Quarter of the year.
r = Receiving flow meter.
RGP states that all C02 delivered to the RGP is used within the unit so the quarterly flow redelivered, Sr p,
is zero and will not be included in the equation.
The MRV plan also states that Equation RR-3 in Subpart RR §98.443 will be used to sum the total mass of
C02 received through all receiving flow meters.
where:
14
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R
C°2 = (Ec3 RR-3)
t ¦ -!
where:
C02 = Total net annual mass of C02 received (metric tons).
CO 2T,r Net annual mass of CO2 received (metric tons) as calculated in Equation RR-1 or RR-2 for
flow meter r.
r = Receiving flow meter.
RGP provides an acceptable approach for calculating the mass of C02 received under Subpart RR
requirements.
5.2 Calculation of Mass of CO2 Injected
Section 7.2 of the MRV plan states that the mass of C02 Injected into the subsurface at the RGP is equal
to the sum of the mass of C02 received as calculated in Equation RR-3 of §98.443 and the mass of C02
recycled as calculated using measurements taken from the flow meter located at the output of the RCF.
The MRV plan states that using data at each injection well would give an inaccurate estimate of total
injection volume due to the large number of wells and the potential propagation of error due to
allowable calibration ranges for each meter.
The mass of C02 recycled will be determined using equation RR-5 as follows:
C02. - IC '/> *C, (Bq. RR-S)
/¦ I
where:
CO 2u Annual C02 mass injected (metric tons) as measured by flow meter u.
QP,u = Quarterly volumetric flow rate measurement for flow meter u in quarter p at
standard conditions (standard cubic meters per quarter).
D = Density of C02 at standard conditions (metric tons per standard cubic meter):
0.0018682.
Cco2,P,u = C02 concentration measurement in flow for flow meter u in quarter p (vol. percent
C02, expressed as a decimal fraction).
p = Quarter of the year.
15
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u = Flow meter.
The aggregate injection data will be calculated pursuant to the procedures specified in equation
RR-6 as follows:
CO21 = ]TCO: (i {Eq. RR-6)
U" 1
where:
CO21 = Total annual C02 mass injected (metric tons) through all injection wells.
C02,u = Annual C02 mass injected (metric tons) as measured by flow meter u.
u = Flow meter.
RGP provides an acceptable approach for calculating the mass of C02 injected under Subpart RR
requirements.
5.3 Mass of CO2 Produced
Section 7.3 of the MRV plan states that the mass of C02 produced at RGP will be calculated using the
measurements from the flow meters at the inlet to RCF, and for C02 entrained in the sales oil, the
custody transfer meters for oil sales rather than metered data from each production well. Again, using
the data at each production well would give an inaccurate estimate of total injection due to the large
number of wells and the potential for propagation of error due to allowable calibration ranges for each
meter.
Equation RR-8 in §98.443 will be used to calculate the mass of C02 produced from all production wells as
follows:
4
0°2,w = *CUK (Eq. RR-8)
i
where:
C02,w = Annual C02 mass produced (metric tons) through separator w.
Qp,w = Volumetric gas flow rate measurement for separator w in quarter p at standard
conditions (standard cubic meters).
D = Density of C02 at standard conditions (metric tons per standard cubic meter):
0.0018682.
16
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Cco2,Pw = C02 concentration measurement in flow for separator w in quarter p (vol. percent
C02, expressed as a decimal fraction).
p = Quarter of the year.
w = Separator.
Equation RR-9 in §98.443 will be used to aggregate the mass of C02 produced and the mass of C02
entrained in oil or other fluid leaving the Rangely Field as follows:
W
C02p = (1+X) * £CO,w (Eq. RR-9)
W=1
where:
C02p = Total annual C02 mass produced (metric tons) through all separators in the reporting
year.
C02,w = Annual C02 mass produced (metric tons) through separator w in the reporting year.
X = Entrained C02 in produced oil or other fluid divided by the C02 separated through all
separators in the reporting year (weight percent C02, expressed as a decimal fraction).
w = Separator.
RGP provides an acceptable approach for calculating the mass of C02 produced under Subpart RR
requirements.
5.4 Calculation of Mass of CO2 Emitted by Surface Leakage
Section 7.4 of the MRV Plan states that RGP will calculate and report the total annual Mass of C02
Emitted by Surface Leakage using an approach that relies on 40 CFR Part 98 Subpart W reports for
equipment leakage, and tailored calculations for all other surface leaks. Given the uncertainty
concerning the nature and characteristics of leaks that will be encountered, it is not clear the method
for quantifying the volume of leaked C02 that would be most appropriate. Estimates of the amount of
leaked to the surface will depend on a number of site-specific factors including measurements of
flowrate, pressure, size of leak opening, and duration of the leak. RGP states that engineering estimates
and emission factors will be used depending on the source and nature of the leakage. In the event
leakage to the surface occurs, RGP would quantify and report leakage amounts, and retain records that
describe the methods used to estimate or measure the volume leaked as reported in the Annual Subpart
RR Report.
17
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Equation RR-10 in §98.443 will be used to calculate the total annual mass of C02 emitted through
Surface Leakage as follows:
V
C°2E = XC O:- (EcI- RR-1C)
where:
C02e = Total annual C02 mass emitted by surface leakage (metric tons) in the reporting
year.
C02,x = Annual C02 mass emitted (metric tons) at leakage pathway x in the reporting year,
x = Leakage pathway.
RGP provides an acceptable approach for calculating the mass of C02 emitted by surface leakage under
Subpart RR requirements.
5.5 Calculation of Mass of CO2 Sequestered in Subsurface Geologic Formations
Section 7.5 of the MRV Plan states that Equation RR-11 in §98.443 will be used to calculate the mass of
C02 sequestered in subsurface geologic formations as follows:
CO2 = CO.21 - COip - CO2E - COifi - COifp (Eq. RR-11)
C02 = Total annual C02 mass sequestered in subsurface geologic formations (metric tons) at
the facility in the reporting year.
C02| = Total annual C02 mass injected (metric tons) in the well or group of wells covered by
this source category in the reporting year.
CO 2p Total annual CO2 mass produced (metric tons) in the reporting year.
CO 2E Total annual CO2 mass emitted (metric tons) by surface leakage in the reporting year.
CO 2fi - Total annual C02 mass emitted (metric tons) from equipment leaks and vented
emissions of C02 from equipment located on the surface between the flow meter used
to measure injection quantity and the injection wellhead, for which a calculation
procedure is provided in subpart W of this part.
CO 2fp Total annual C02 mass emitted (metric tons) from equipment leaks and vented
18
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emissions of C02 from equipment located on the surface between the production wellhead and
the flow meter used to measure production quantity, for which a calculation procedure is
provided in subpart W of this part.
RGP provides an acceptable approach for calculating the mass of C02 sequestered under Subpart RR
requirements.
6 Summary of Findings
The Subpart RR MRV plan for the Rangely Gas Plant meets the requirements of 40 CFR 98.448. The
regulatory provisions of 40 CFR 98.448(a), which specifies the requirements for MRV plans, are
summarized below along with a summary of relevant provisions in the RGP MRV plan.
Subpart RR MRV Plan Requirement
RGP MRV Plan
40 CFR 98.448(a)(1): Delineation of the
maximum monitoring area (MMA) and the
active monitoring areas (AMA).
Section 3.0 of the MRV plan delineates and describes
the MMA and AMA. RGP states that the maximum
extent of the projected C02 plume will be contained
within the Rangely Field, therefore the MMA and AMA
will be defined as the Rangely Field plus a one-half mile
buffer.
40 CFR 98.448(a)(2): Identification of
potential surface leakage pathways for C02
in the MMA and the likelihood, magnitude,
and timing, of surface leakage of C02
through these pathways.
Section 4.0 of the MRV plan identifies and evaluates
potential surface leakage pathways. The MRV plan
identifies the following potential pathways: existing
wellbores, faults and fractures, natural and induced
seismic activity, previous operations, pipelines/surface
equipment, lateral migration outside the Rangely Field,
drilling through the C02 area, and diffuse leakage
through the seal. The MRV plan analyzes the likelihood,
magnitude, and timing of surface leakage through
these pathways. RGP determined that leakage through
these pathways is not likely at the RGP.
40 CFR 98.448(a)(3): A strategy for
detecting and quantifying any surface
leakage of C02.
Sections 4.0 and 5.0 of the MRV plan describe the
strategy that RGP will used to detect and quantify
potential C02 leakage to the surface should it occur.
The MRV plan identifies the following detection and
quantification strategies: modeling, direct
measurements, MITs, SCADA systems, routine field
inspections, monitoring reservoir pressure in WAG
headers, engineering estimates, and emission factors.
19
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Section 5 of the MRV plan also states that an event-
driven process will be used to assess, address, track,
and if applicable quantify potential C02 leakage to the
surface.
40 CFR 98.448(a)(4): A strategy for
establishing the expected baselines for
monitoring C02 surface leakage.
Section 6.0 of the MRV plan describes the strategy that
RGP will use to establish baselines against which
monitoring results can be compared to assess potential
surface leakage. The MRV identifies the following
strategies: visual inspections, personal H2S monitors,
monitoring of injection rates, pressures, and volumes,
and monitoring of production volumes and
compositions.
40 CFR 98.448(a)(5): A summary of the
considerations you intend to use to
calculate site-specific variables for the mass
balance equation.
Section 7.0 of the MRV plan describes RGP's approach
to determining the total amount of C02 sequestered
using the Subpart RR mass balance equations, including
calculation of total annual mass emitted from
equipment leakage.
40 CFR 98.448(a)(6): For each injection
well, report the well identification number
used for the UIC permit (or the permit
application) and the UIC permit class.
Section 11.0 (Appendices) of the MRV plan provides
well identification number for all active wells in the
RGP. The MRV plan specifies that all injection wells in
the RGP are permitted by the COGCC as UIC Class II
wells.
40 CFR 98.448(a)(7): Proposed date to
begin collecting data for calculating total
amount sequestered according to equation
RR-11 or RR-12 of this subpart.
Section 8.0 of the MRV plan states that RGP will
commence collecting data for calculating the total
amount of C02 sequestered according to Equation RR-
11 of this subpart upon EPA approval.
20
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Appendix A: Final MRV Plan
-------
Scout Energy Management, LLC
Rangely Field
Subpart RR Monitoring, Reporting and Verification (MRV) Plan
-------
Table of Contents
Roadmap to the Monitoring, Reporting and Verification (MRV) Plan 3
1. Facility Information 4
2. Project Description 4
2.1 Project Characteristics 4
2.2 Environmental Setting 6
2.3 Description of C02 EOR Project Facilities and the Injection Process 13
3. Delineation of Monitoring Area and Timeframes 19
3.1 Active Monitoring Area 19
3.2 Maximum Monitoring Area 20
3.3 Monitoring Timeframes 20
4. Evaluation of Potential Pathways for Leakage to the Surface 20
4.1 Introduction 21
4.2 Existing Wellbores 21
4.3 Faults and Fractures 23
4.4 Natural or Induced Seismicity 23
4.5 Previous Operations 23
4.6 Pipeline / Surface Equipment 23
4.7 Lateral Migration Outside the Rangely Field 24
4.8 Drilling Through the C02 Area 24
4.9 Diffuse Leakage through the Seal 25
4.10 Monitoring, Response, and Reporting Plan for C02 Loss 25
4.11 Summary 26
5. Monitoring and Considerations for Calculating Site Specific Variables 26
5.1 For the Mass Balance Equation 26
5.2 To Demonstrate that Injected C02 is not Expected to Migrate to the Surface 30
6. Determination of Baselines 30
7. Determination of Sequestration Volumes Using Mass Balance Equations 31
7.1. Mass of C02 Received 32
7.2 Mass of C02 Injected into the Subsurface 32
7.3 Mass of C02 Produced 33
7.4 Mass of C02 emitted by Surface Leakage 34
7.5 Mass of C02 sequestered in subsurface geologic formations 34
7.6 Cumulative mass of C02 reported as sequestered in subsurface geologic formations.. 35
8. MRV Plan Implementation Schedule 35
9. Quality Assurance Program 35
9.1 Monitoring QA/QC 35
9.2 Missing Data Procedures 36
9.3 MRV Plan Revisions 36
10. Records Retention 36
11. Appendices 37
Appendix 5. Well Identification Numbers 43
2
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Roadmap to the Monitoring, Reporting and Verification (MRV) Plan
Scout Energy Management, LLC (SEM) operates the Rangely Weber Sand Unit (RWSU) and the
associated Raven Ridge pipeline (RRPC), (collectively referred to as the Rangely Field) in Northwest
Colorado for the primary purpose of enhanced oil recovery (EOR) using carbon dioxide (C02) flooding.
SEM has utilized, and intends to continue to utilize, injected C02 with a subsidiary purpose of establishing
long-term containment of a measurable quantity of C02 in subsurface geological formations at the Rangely
Field for a term referred to as the "Specified Period." The Specified Period includes all or some portion of
the period 2023 to 2060. During the Specified Period, SEM will inject C02 that is purchased (fresh C02)
from ExxonMobil's (XOM) Shute Creek Plant or third parties, as well as C02 that is recovered (recycled
C02) from the Rangely Field's C02 Recycle and Compression Facilities (RCF's). SEM has developed this
monitoring, reporting, and verification (MRV) plan in accordance with 40 CFR §98.440-449 (Subpart RR)
to provide for the monitoring, reporting and verification of the quantity of C02 sequestered at the Rangely
Field during the Specified Period.
SEM has chosen to submit this MRV plan to the EPA for approval according to 40 Code of Federal
Regulations (CFR) 98.440(c)(1), Subpart RR of the Greenhouse Gas Reporting Program for the purpose
of qualifying for the tax credit in section 45Q of the federal Internal Revenue Code.
This MRV plan contains eleven sections:
o Section 1 contains general facility information.
o Section 2 presents the project description. This section describes the planned injection volumes, the
environmental setting of the Rangely Field, the injection process, and reservoir modeling. It also illustrates
that the Rangely Field is well suited for secure storage of injected C02.
o Section 3 describes the monitoring area: the RWSU in Colorado.
o Section 4 presents the evaluation of potential pathways for C02 leakage to the surface. The assessment
finds that the potential for leakage through pathways other than the man-made wellbores and surface
equipment is minimal.
o Section 5 describes SEM's risk-based monitoring process. The monitoring process utilizes SEM's reservoir
management system to identify potential C02 leakage indicators in the subsurface. The monitoring process
also utilizes visual inspection of surface facilities and personal H2S monitors program as applied to
Rangely Field. SEM's MRV efforts will be primarily directed towards managing potential leaks through
wellbores and surface facilities.
o Section 6 describes the baselines against which monitoring results will be compared to assess whether
changes indicate potential leaks.
o Section 7 describes SEM's approach to determining the volume of C02 sequestered using the mass
balance equations in 40 CFR §98.440-449, Subpart RR of the Environmental Protection Agency's (EPA)
Greenhouse Gas Reporting Program (GHGRP). This section also describes the site-specific factors
considered in this approach.
o Section 8 presents the schedule for implementing the MRV plan.
o Section 9 describes the quality assurance program to ensure data integrity.
o Section 10 describes SEM's record retention program.
o Section 11 includes several Appendices.
3
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1. Facility Information
The Rangely Gas Plant, operated by SEM and a part of the Rangely Field, reports under Greenhouse Gas
Reporting Program Identification number 537787.
The Colorado Oil and Gas Conservation Commission (COGCC)1 regulates all oil, gas and geothermal
activity in Colorado. All wells in the Rangely Field (including production, injection and monitoring wells) are
permitted by COGCC through Code of Colorado Regulations (CCR) 2 CCR 404-1:301. Additionally,
COGCC has primacy to implement the Underground Injection Control (UIC) Class II program in the state
for injection wells. All injection wells in the Rangely Field are currently classified as UIC Class II wells.
Wells in the Rangely Field are identified by name, API number, status, and type. The list of wells as of April,
2023 is included in Appendix 5. Any new wells will be indicated in the annual report.
2. Project Description
This section describes the planned injection volumes, environmental setting of the Rangely Field, injection
process, and reservoir modeling conducted.
2.1 Project Characteristics
SEM utilized historic production and injection of the RWSU in order to create a production and injection
forecast, included here to provide an overview of the total amounts of C02 anticipated to be injected,
produced, and stored in the Rangely Field as a result of its current and planned C02 EOR operations during
the forecasted period. This forecast is based on historic and predicted data. Figure 1 shows the actual
(historic) C02 injection, production, and stored volumes in the Rangely Field from 1986, when Chevron
initiated C02 flooding, through 2022 (solid line) and the forecast for 2023 through 2060 (dotted line). It is
important to note that this is just a forecast; actual storage data will be collected, assessed, and reported as
indicated in Sections 5, 6, and 7 in this MRV Plan. The forecast does illustrate, however, the large potential
storage capacity at Rangely field.
1 Pursuant to Colorado SB21-285, effective July 1, 2023, the COGCC will become the Energy and Carbon
Management Commission.
4
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Rangely Field
Historical and Projected C02
6000
T3
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O
5000
ro
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ai
a.
4000
3000
2000
1000
uvAV
C02 Production
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C02 Stored
Forecast C02 Stored
u v
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C02 Injection
Forecast C02 Injection
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aiaiaiaiooooooooooooooo
*H*H*H*H(N(N(N(N(N(N(N(N(N(N(N(N(N(N(N
Year
Figure 1 - Rangely Field Historic and Forecast C02 Injection, Production, and Storage 1986-2060
The amount of C02 injected at Rangely Field is adjusted periodically to maintain reservoir pressure and to
increase recovery of oil by extending or expanding the EOR project. The amount of C02 injected is the
amount needed to balance the fluids removed from the reservoir and to increase oil recovery. While the
model output shows C02 injection and storage through 2060, this data is for planning purposes only and
may not necessarily represent the actual operational life of the Rangely Field EOR project. As of the end
of 2022, 2,320,000 million standard cubic feet (MMscf) (122.76 million metric tons (MMMT)) of C02 has
been injected into Rangely Field. Of that amount, 1,540,000 MMscf (81.48 MMMT) was produced and
recycled.
While tons of C02 injected and stored will be calculated using the mass balance equations described in
Section 7, the forecast described above reflects that the total amount of C02 injected and stored over the
modeled injection period to be 967,000 MMscf (51.2 MMMT). This represents approximately 35.7% of the
theoretical storage capacity of Rangely Field.
Figure 2 presents the cumulative annual forecasted volume of C02 stored by year through 2060, the
modeling period forthe projection in Figure 1. The cumulative amount stored is equal to the sum of the annual
storage volume for each year plus the sum of the total of the annual storage volume for each previous year.
As is typical with C02 EOR operations, the rate of accumulation of stored C02 tapers overtime as more
recycled C02 is used for injection. Figure 2 illustrates the total cumulative storage overthe modeling period,
projected to be 967,000 MMscf (51.2 MMMT) of C02.
5
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Rangely Field
Historical and Forecast Cumulative C02 Storage
60
i-
(0
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Figure 3 - Regional map showing Rangely's position between the Uinta and Piceance Basin.
The reservoir, Weber Sands, is comprised of clean eolian quartz deposited in an erg (sand sea)
depositional environment. Internally, these dune sands are separated into six main packages (odd
numbers, 1 to 11) with the fluvial Maroon Formation (even numbers, 2 to 10) interfingering the field from
the north. The Weber Formation is underlain by the fossiliferous Desmoinesian carbonates of the Morgan
Formation, and overlain by the siltstones and shales of the Phosphoria/Park City and Moenkopi
Formations.
For the majority of the region, the Phosphoria Formation acts as an impermeable barrier above the
Weber Formation and is a hydrocarbon source for the overlying strata. However, due to the large thrust
fault south and west of the field, the Phosphoria Formation was driven down to significantly deeper
depths, and below the reservoir Weber sands, allowing for maturation and expulsion of the hydrocarbons
to migrate upward into stratigraphically older, but structurally shallower reservoirs sometime during the
Jurassic. At Rangely, the Phosphoria Formation is almost entirely missing above the Weber Formation,
but the Moenkopi Formation sits directly above the sands creating the seal for the petroleum system.
Fresh water in and around the town/field of Rangely is sourced from the quaternary creeks and rivers that
cut across the region (data obtained from the Colorado Division of Water Resources). No confined fresh
water aquifers are present between the reservoir rock and the surface. Safety measures are still taken to
protect the shallowest of rocks that contain rain water seepage (unconfined aquifer) into the Mancos
Formation (surface exposure at Rangely) illustrated by the surface casing on Figure 4. The shallowest
point of the reservoir is 5,486 ft below the surface (4,986 ft below any possible fresh rain water seepage).
The mere presence of hydrocarbons and the successful implication of a C02 flood indicates the quality
and effectiveness of the seal to isolate this reservoir from higher strata.
7
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Uinta Basin
Douglas Creek
Arch
Piceance Basin
ichesne River and Uinta Fms
CoKon Fm
Wasatch Fr
Wasatch and
Fort Union Fms
k I r_.
rm
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Ferron Ss Mbr of Ma cos Sh and Frontu
Dakota Ss
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Morrison Fm
O Entrada Ss O
Glen Canyon Ss
Cftnle Fm
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Source
__ParY. City Fm
upper Weber Ss
Reservoir
Maroon
cr_ Fm
Round Valley Ls
Manning Canyon Sh
Doughnut Sh/Humbug Fm
Deseret Ls
Leadville Ls
Madison Ls
Pinyon.
-TfeniWU rf"
Dotsero Fm
Lodore Fm
Sawatch Ss
KEY
PETROLEUM
SYSTEMS:
I| Green River
system
I| Mesaverde
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l| Mancos/Mowry
system
I| Phosphoria
system SOUTCe
Grassy Trail
° Creek oil
~ Mtnturn system
,, SignFficant oil production
{indicating source rock)
v./ Significant gas production
^ (indicating source rock)
S Source rocks
(R) Rangely Field
Main reservoir
I I Hiatus
Stratigraphy
at Rangely
Figure 4. Stratigraphic Column of formations at the Rangely Field. Due to a large fault the source
rock (Phosphoria) is stratigraphically above the reservoir rock (Weber), but structurally, the
source lies below the reservoir, (from U.S. Geological Survey, 2003)
Figure 5 shows the doubly plunging anticline with the long axis along a northwest-southeast trend and the
short axis along a northeast-southwest trend. In 1949 the depth of a gas cap was established at -330 ft
subsea and an Oil Water Contact (OWC) at -1150 ft subsea. Many core analysis suggest that below this -
1150' OWC is a transition/residual oil zone. However, for the purpose of this analysis and all volumetrics
8
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the base of the reservoir will be at the -1150' subsea depth determined in 1949.
Geologically, the Weber Sands were deposited on top of the Morgan formation which is a combination of
interbedded shale, siltstone, and cherty limestone. Few wells are drilled deep enough to penetrate the
Morgan formation within the Rangely Field to gather porosity/permeability data locally. However, analysis
of the Morgan formation from other fields/outcrops indicate that it is a non-reservoir rock (low
porosity/permeability), and would be sufficient as a basial barrier for the field. The highest subsurface
elevation of the base of the Weber Sands is deeper than the -1150' used for the OWC. Meaning injected
C02 should not encounter the Morgan formation. Additionally, Section 4.7 explains how the Rangely
Field is confined laterally through the nature of the anticline's structure.
Figure 5. Structure map of the Weber 1 (top of reservoir). Colors illustrate the maximum aerial
coverage of the Gas Cap (Red), Main Reservoir (Green), and Transitional Reservoir (Blue). Cross
section A-A' is predominantly along the long axis of the field and B-B' is along the short axis.
The Rangely Field has one main field fault (MFF) and numerous smaller faults (isolated and joint) and
fractures that are present throughout the stratigraphic column between the base of the Weber reservoir
and surface. Faults within the reservoir were measured by well-to-well displacement, while the fractures
were measured and observed as calcite veins on the surface with no displacement. The MFF has a NE-
WSWtrend and cuts through the reservoir interval. In the 1960's Rangely residents began experiencing
felt earthquakes. Between 1969 and 1973, a joint investigation with the USGS installed seismic
monitoring stations in and around the town of Rangely and began recording activity. In 1971, a study was
conducted to evaluate the stress state in the vicinity of the fault which determined a critical fluid pressure
above which fault slippage may occur. Reservoir pressure was then manipulated and correlated with
increases or decreases in seismic activity. This study determined that the waterflood in Rangely was
inducing seismicity when reservoir pressure was raised above ~3730 psi.
In the 1990's, field reservoir pressure had built back up leading to the largest magnitude earthquake in
9
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Rangely which took place in 1995 (M 4.5), shortly after maximum reservoir pressure was reached in
1998. Pressure maintenance began and seismic activity dropped off after lowering the average field
reservoir pressure down to ~3100 psi. No other seismic activity was recorded around the field until 2015
and 2017 when there was a total of 5 seismic events (see Figure 6) around the northeastern portion of
the MFF. A new interpretation from the 3D seismic revealed a series of previously unknown joint faults
(perpendicular to the MFF). Investigation into this region revealed that the ~3730 psi threshold had been
crossed and triggered the seismic events. Since the 2017 seismic events, no other events have been
recorded of felt magnitude and continued pressure monitoring further reduces the risk of another event.
2017 Induced
Seismic Study*
Figure 6. USGS fault history map (1900-2023). Largest earthquake was the 1995 M 4.5 north of the
unit (2017 was a study to induce seismic activity along the MFF, and not caused by day-to-day
operations)
The natural fractures found within the field play a significant role in fluid flow. The subsurface natural
fractures are vertical and show an approximately ENE trend and their extension joints are orientated ESE.
Shallower portions of the reservoir show a distinctly higher density of fractures than deeper portions. On
the shallow dipping sides of the anticline, there does not appear to be a strong structural control on
fracture density. Most well-to-well rapid breakthrough of injected C02 is along these ENE fractures. It is
unknown if this is from natural or induced fractures. There is no evidence that these natural fractures
diminish the seals integrity.
10
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Figure 7. Cross section A-A' along the long axis of the field, and perpendicular to the MRR. The
MFF does not have much displacement and is near vertical.
The Rangely Field has approximately 1.9 billion barrels of Original Oil in Place (OOIP). Since first
discovered in 1933, Rangely Field has produced 920 million barrels of oil, or 48% of the OOIP. The
Rangely Field has an aerial extent of approximately 19,150 acres with an average gross thickness of 650
ft. The previously mentioned 11 internal layers of the reservoir, alternating zones of Weber and Maroon
Formations, can be simplified to only three sections. The Upper Weber contains intervals 1-3, the Middle
Weber contains intervals 4-7, and the Lower Weber contains intervals 8-approxamently 50 ft below the
11D marker (identified by the base of the yellow in Figure 7). These interval groupings were determined
by the extensive lateral continuingiy and thickness of the Weber 4 and Weber 8 which easily separate the
reservoir into the three zones. For the majority of the Rangely Field, the even Maroon Formations act as
flow barriers between the odd Weber Formations. Average porosity within the Weber Sands dune fades
is 10.3% and within the Maroon fluvial fades is 4.9%. However, the key factor that enables the Maroon
Formation to be a seal is its lack of permeability. The Weber dune fades have an average permeability of
2.44 millidarcy (Md), while the Maroon fluvial fades have an average permeability of 0.03 Md.
owe -1150'
Transition Zone & ROZ
11
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Figure 8. Cross section B-B' along the short axis of the field and parallel to the MFF. Used to
illustrate the variation of the Oil Water Contact (OWC).
Given that the Rangely Field is located at the highest subsurface elevations of the structure, that the
confining zone has proved competent over both millions of years and throughout decades of EOR
operations, and that the Rangely Field has ample storage capacity, SEM is confident that stored CQ2 will
be contained securely within the Weber Sands in the Rangely Field.
2.2.2 Operational History of the Rangely Field
The Rangely Field was discovered in 1933 but subsequently ceased production until World War II when oil
returned to high demand. Intensive development began, expanding from one well to 478 wells by 1949. It
is located in the northwestern portion of Colorado.
The Rangely Field was originally developed by Chevron. Following the initial discover in 1933,
Chevron imitated a 40-acre development in 1944, followed by hydrocarbon gas injection from
1950 to 1969. To improve efficiency, in 1957, the RWSU was formed. The boundaries of the RWSU are
reflected in Figure 9.
Rangely Well List
^ Active-Producer
yf 0 TA- Producer
~ Active-Injector
A TA-Injector
T Active 5WD
Collection Station / Facility
¦ Collection Station
$ Compressor Station
X ¦ Rangely Facility
(££) Rangely Plant General
A West End Water Injection
N -Rangely Weber Unit
23^^ Rangely Weber Unit
1 "l1 Rangely Weber Unit Half Mile Buffer
Mdien Htl
BIO BIANG& COuWv
± i iu* vOJ /
A (t'li *A-A*AV
u -
v^aV S
\ »> i
v TLtw.}
- >. /./~ WA i * a
2X102W
'Rio Blanco-
Rdpgely OiStnet
Hospital Hetip&i
River
itf N)2W
Moffat
0/HICJ blAnCO CO0NTY
Uintah
Rio Blanco
Garfield
Figure 9 - Rangely Field Map
12
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Chevron began C02 flooding of the Rangely Field in 1986 and has continued and expanded it since that
time. The experience of operating and refining the Rangely Field C02 floods over the past decade has
created a strong understanding of the reservoir and its capacity to store C02.
2.3 Description of C02 EOR Project Facilities and the injection Process
Figures 10 shows a simplified flow diagram of the project facilities and equipment in the Rangely Field.
C02 is delivered to the Rangely Field via the Raven Ridge Pipeline. The CG2 injected into the Rangely
Field is currently supplied by XOM's Shute Creek Plant into the pipeline system.
Once C02 enters the Rangely Field there are four main processes involved in EOR operations. These
processes are shown in Figure 10 and include:
1. C02 Distribution and Injection. Purchased C02 and recycled C02 from the RCF is sent through the main
C02 distribution system to various C02 injectors throughout the Field.
2. Produced Fluids Handling. Produced fluids gathered from the production wells are sent to collection
stations for separation into a gas/C02 mix and a produced fluids mix of water, oil, gas, and C02. The
produced fluids mix is sent to centralized water plants where oil is separated for sale into a pipeline, water
is recovered for reuse, and the remaining gas/C02 mix is merged with the output from the collection
stations. The combined gas/C02 mix is sent to the RCF and natural gas liquids (NGL) Plant. Produced oil
is metered and sold; water is forwarded to the water injection plants fortreatment and reinjection or disposal.
3. Produced Gas Processing. The gas/C02 mix separated at the satellite batteries goes to the RCF and
NGL Plant where the NGLs, and C02 streams are separated. The NGLs move to a commercial pipeline for
sale. The remaining C02 (e.g., the recycled C02) is returned to the C02 distribution system for reinjection.
4. Water Treatment and Injection. Water separated in the tank batteries is processed at water plants to
remove any remaining oil and then distributed throughout the Rangely Field for reinjection.
LaBarge Field/
Shute Creek Plant
Field and plant owned and
operated by ExxonMobil
Raven Ridge
Pipeline
123 mile, 16" steel pipeline
(200 MMcfd capacity)
56% CRRPC owned
(T) Rangely Field
Dehydration & NGL Extraction
RCF
1st/2nd Stage
Compression
Gasjt-,
A Custody Transfer Point for Assets
~ CO? Measurement Points
RCF
3rd/ 4th Stage
Compression
Oil/Water Liquids Liquid/Gas
Separation & ¦« Inlet
Water Plants Separation
Water T water] |_
Gas/Water
Injection
Wells
Water
Disposal
Wells
-f
Producing
Wells
Surface
Navajo Formation
COj +
Water +
Natural Gas
Oil
~ Natural Gas / NGL
+ Water
+ CO,
Weber Sands Reservoir
yv.
Figure 10 Rangely Field -General Production Flow Diagram
13
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2.3.1 C02 Distribution and Injection.
SEM purchases C02 from XOM and receives it via the Raven Ridge Pipeline through one custody transfer
metering point, as indicated in Figures 10. Purchased C02 and recycled C02 are sent through the C02
trunk lines to multiple distribution lines to individual injection wells. There are volume meters at the inlet and
outlet of the C02 Reinjection Facility.
As of April 2023, SEM has approximately 280 injection wells in the Rangely Field. Approximately 160 MMscf
of C02 is injected each day, of which approximately 15% is purchased C02, and the balance (85%) is
recycled. The ratio of purchased C02 to recycled C02 is expected to change overtime, and eventually the
percentage of recycled C02 will increase and purchases of fresh C02 will taper off as indicated in Section
2.1.
Each injection well is connected to a water alternating gas (WAG) manifold located at the well pad. WAG
manifolds are manually operated and can inject either C02 or water at various rates and injection pressures
as specified in the injection plans. The length of time spent injecting each fluid is a matter of continual
optimization that is designed to maximize oil recovery and minimize C02 utilization in each injection pattern.
A WAG manifold consists of a dual-purpose flow meter used to measure the injection rate of water or C02,
depending on what is being injected. Data from these meters is sent to the Supervisory Control and Data
Acquisition (SCADA) system where it is compared to the injection plan forthat well. As described in Sections
5 and 7, data from the WAG manifolds, visual inspections of the injection equipment, and use of the
procedures contained in 40 CFR §98.230-238 (Subpart W), will be gathered to complete the mass balance
equations necessary to determine annual and cumulative volumes of stored C02.
2.3.2 Wells in the Rangely Field
As of April 2023, there are 662 active wells that are completed in the Rangely Field, with roughly 40%
injection wells and 60% producing wells, as indicated in Figure 11,2 Table 1 shows these well counts in the
Rangely Field by status.
2 Wells that are not in use are deemed to be inactive, plugged and abandoned, temporarily abandoned, or shut in.
14
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Rangely Well List
# Active-Producer
TA-Producer
A Active-Injector
A TA-Injector
~ Active SWD
Rangely Weber Unit
I I Rangely Weber Unit
2N 103W
Metier Hill
00 RIO PLAN (9S COUN»7
2N 102W
.Rio Blanco
Ji) Rpven I
ftrfcjr li
Heliport
Moffat
I'tgely District
Vpitof Heppaf'
1N 102W
0RIO BLANCO CQ18NTY
Rio Blanco
iarfield
Figure 11 Rangely Field Wells - As of April 2023
Table 1 - Rangely Field Wells
<\ge/Completion of Well
Active
Shut-in
Temporarily
Abandoned
Plugged and
Abandoned
Drilled & Completed in the
1940's
265
5
55
149
Drilled 1950-1985
297
7
55
46
Completed after 1986
103
1
11
8
TOTAL
665
13
121
203
The wells in Table 1 are categorized in groups that relate to age and completion methods. Roughly 48%
of these wells were drilled in the 1940's and were generally completed with three strings of casing (with
surface and intermediate strings typically cemented to the surface). The production string was typically
installed to the top of the producing interval, otherwise known as the main oil column (MOC), which
extends to the producible oil/water contact (POWC). These wells were completed by stimulating the open
hole (OH), and are not typically cased through the MOC. While implementing the water flood from 1958-
1986, a partial liner would have been typically installed to allow for controlled injection intervals and this
liner would have been cemented to the top of the liner (TOL) that was installed. For example, a partial
liner would be installed from 5,700-6,500 ft, and the TOC would be at 5,700 ft. The casing weights used
15
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for the production string have varied between 7" 23 & 26#/ft. with 5" 18 #/ft. for the production liner.
The wells in Table 1 drilled during the period 1950-1986 typically were cased through the production
interval with 7" casing. Some wells were completed with 7" casing to the top of the MOC and then
completed with a 5" liner through the productive interval. The wells with liners were cemented to the TOL.
The remaining wells (roughly 12%) in Table 1 were drilled after 1986 when the C02 flood began. All of
these wells were completed with 7" casing through the POWC. Very few of these wells have experienced
any wellbore issues that would dictate the need for a remedial liner.
SEM reviews these categories along with full wellbore history when planning well maintenance projects.
Further, SEM keeps well workover crews on call to maintain all active wells and to respond to any
wellbore issues that arise. On average, in the Rangely Field there are two to three incidents per year in
which the well casing fails. SEM detects these incidents by monitoring changes in the surface pressure of
wells and by conducting Mechanical Integrity Tests (MITs), as explained later in this section and in the
relevant regulations cited. This rate of failure is less than 2% of wells per year and is considered
extremely low.
All wells in oilfields, including both injection and production wells described in Table 1, are regulated by
the COGCC under COGCC 100-1200 series rules. A list of wells, with well identification numbers, is
included in Appendix 5. The injection wells are subject to additional requirements promulgated by EPA -
the UIC Class II program - implementation of which has been delegated to the COGCC.
COGCC rules govern well siting, construction, operation, maintenance, and closure for all wells in oilfields.
Current rules require, among other provisions, that:
Class II UIC Wells will not be permitted in areas where they would inject into a formation that is
separated from any Underground Source of Drinking Water by a Confining Layer with known open
faults or fractures that would allow flow between the Injection Zone and Underground Source of Drinking
Water within the area of review.
Injection Zones will not be permitted within 300 feet in a vertical dimension from the top of any
Precambrian basement formation.
An Operator will not inject any Fluids or other contaminants into a UIC Aquifer that meets the
definition of an Underground Source of Drinking Water unless EPA has approved a UIC Aquifer
exemption as described in Rule 802.e.
In addition, SEM implements a corrosion protection program to protect and maintain the steel used in
injection and production wells from any C02-enriched fluids. SEM currently employs methods to mitigate
both internal and external corrosion of casing in wells in the Rangely Field. These methods generally protect
the downhole steel and the interior and exterior of wellbores through the use of special materials (e.g.
fiberglass tubing, corrosion resistant cements, nickel plated packers, corrosion resistant packer fluids) and
procedures (e.g. packer placement, use of annular leakage detection devices, cement bond logs, pressure
tests). These measures and procedures are typically included in the injection orders filed with the COGCC.
Corrosion protection methods and requirements may be enhanced overtime in response to improvements
in technology.
MIT
SEM complies with the MIT requirements implemented by COGCC and BLM to periodically inspect wells
and surface facilities to ensure that all wells and related surface equipment are in good repair and leak-
free, and that all aspects of the site and equipment conform with Division rules and permit conditions. All
active injection wells undergo an MIT at the following intervals:
Before injection operations begin
16
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Every 5 years as stated in the injection orders (COGCC 417.a. (1))
After any casing repair
After resetting the tubing or mechanical isolation device
Or whenever the tubing or mechanical isolation device is moved during workover operations
COGCC requires that the operator notify the COGCC district office prior to conducting an MIT. Operators
are required to use a pressure recorder and pressure gauge for the tests. The operator's field representative
must sign the pressure recorder chart along with the COGCC field representative and submit it with the MIT
form. The casing-tubing annulus must be tested to a minimum of 1200 psi for 15 minutes.
If a well fails an MIT, the operator must immediately shut the well in and provide notice to COGCC. Casing
leaks must be successfully repaired and retested or the well plugged and abandoned after submitting a
formal notice and obtaining approval from the COGCC.
Any well that fails an MIT cannot be returned to active status until it passes a new MIT
2.3.3 Produced Fluids Handling
As injected C02 and water move through the reservoir, a mixture of oil, gas, and water ("produced fluids")
flows to the production wells. Gathering lines bring the produced fluids from each production well to
collection stations. SEM has approximately 382 active production wells in the Rangely Field and production
from each is sent to one of 27 collection stations. Each collection station consists of a large vessel that
performs a gas - liquid separation. Each collection station also has well test equipment to measure
production rates of oil, water and gas from individual production wells. SEM has testing protocols for all
wells connected to a collection station. Most wells are tested twice per month. Some wells are prioritized
for more frequent testing because they are new or located in an important part of the Field; some wells with
mature, stable flow do not need to be tested as frequently; and finally, some wells will periodically need
repeat testing due to abnormal test results.
After separation, the gas phase is transported by pipeline to the C02 reinjection facility for processing as
described below. Currently the average composition of this gas mixture as it enters the facility is 92% C02
and 800ppm H2S; this composition will change overtime as C02 EOR operations mature.
The liquid phase, which is a mixture of oil and water, is sent to one of two centralized water plants where
oil is separated from water via two 3-phase separators. The water is then sent to water holding tanks where
further separation is done.
The separated oil is metered through the Lease Automatic Custody Transfer (LACT) unit located at the
custody transfer point between Chevron pipeline and SEM. The oil typically contains a small amount of
dissolved or entrained C02. Analysis of representative samples of oil is conducted once a year to assess
C02 content.
The water is removed from the bottom of the tanks at the water injection stations, where it is re-injected to
the WAG injectors.
Any gas that is released from the liquid phase rises to the top of the tanks and is collected by a Vapor
Recovery Unit (VRU) that compresses the gas and sends it to the C02 reinjection facility for processing.
17
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Rangely oil is slightly sour, containing small amounts of hydrogen sulfide (H2S), which is highly toxic. There
are approximately 25 workers on the ground in the Rangely Field at any given time, and all field personnel
are required to wear H2S monitors at all times. Although the primary purpose of H2S detectors is protecting
employees, monitoring will also supplement SEM's C02 leak detection practices as discussed in Sections
5 and 7.
In addition, the procedures in 40 CFR §98.230-238 (Subpart W) and the two-part visual inspection process
described in Section 5 are used to detect leakage from the produced fluids handling system. As described
in Sections 5 and 7, the volume of leaks, if any, will be estimated to complete the mass balance equations
to determine annual and cumulative volumes of stored C02.
2.3.4 Produced Gas Handling
Produced gas gathered from the collection stations, and water injection plants is sent to the C02 recycling
and compression facility. There is an operations meter at the facility inlet.
Once gas enters the C02 reinjection facility, it undergoes dehydration and compression. In the RWSU an
additional process separates NGLs for sale. At the end of these processes there is a C02 rich stream that
is recycled through re-injection. Meters at the C02 recycling and compression facility outlet are used to
determine the total volume of the C02 stream recycled back into the EOR operations.
As described in Section 2.3.4, data from 40 CFR §98.230-238 (Subpart W), the two-part visual inspection
process for production wells and areas described in Section 5, and information from the personal H2S
monitors are used to detect leakage from the produced gas handling system. This data will be gathered to
complete the mass balance equations necessary to determine annual and cumulative volumes of stored
C02 as described in Sections 5 and 7.
2.3.5 Water Treatment and Injection
Produced water collected from the collection stations is gathered through a pipeline system and moved to
one of two water injection plants. Each facility consists of 3-Phase separators and 79,500-barrels of
separation tanks where any remaining oil is skimmed from the water. Skimmed oil is combined with the oil
from the 3-Phase separators and sent to the LACT. The water is sent to an injection pump where it is
pressurized and distributed to the WAG injectors.
2.3.6 Facilities Locations
The current locations of the various facilities in the Rangely Field are shown in Figure 13. As indicated
above, there are two central water plants. There are twenty-seven collections stations that gather
production from surrounding wells. The two water plants are identified by the blue triangle and circle. The
twenty-seven collection stations are identified by red squares. The C02 Reinjection facility is indicated by
the green circle.
18
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Collection Station / Facility
I Collection Station
Compressor Station
¦ Rangely Facility
(££) Rangely Plant General
A West End Water Injection
Rangely Weber Unit
Rangely Weber Unit
" Men Hill
06 RIO BIANCSS COUN-1
Collection
Station 01
Collection
Station 03
Collection
Station 10m
,Rio Blanco
Collection
Station 08
Collection
2N 103W
Collection.^
Station 04
Collection
Station 20 2N 1021
Station 12
Collection
Station 05
Collection
Station 11
Collection
Station 27
West
End Water
Injection
Collection
Station 16
Heliport
Collection
Station 22
Collection Co"ec^,tV,
Station stat'°109
Collection
Station 17
Collection
Station 33
Collection
Station 28«
Collection
Station 29
Collection
Station 13
vCollection
Station 18 Main
¦ Treatment
I 37
Rangely [¦]
Plant ¦¦ Collection Collection
General Station 19 Station 24
Collection
Station 34
Collection
Station 30
Collection
Station 39
Collection
_Station_47_
Moffat
Rangely District
MOSfiittOi' HfiipOti
1N 102W
Uintah
ORIOi BLANCO CQBNTY
Rio Blanco
Garfield
Miles
Figure 13 Location of Surface Facilities at Rangely Field
3. Delineation of Monitoring Area and Timeframes
The current active monitoring area (AMA), future AMA and monitoring time frame of the AMA are
described below. Additionally, the maximum monitoring area (MMA) of the free phase C02 plume, its
buffer zone and the monitoring time frame for the MMA are described below.
3.1 Active Monitoring Area
Because C02 is present throughout the Rangely Field and retained within it, the Active Monitoring Area
(AMA) is defined by the boundary of the Rangely Field plus one-half mile buffer. This boundary is defined
in Figure 9. The following factors were considered in defining this boundary:
Free phase C02 is present throughout the Rangely Field: More than 2,320,000 MMscf (122.76 MMMT)
tons of C02 have been injected and recycled throughout the Rangely Field since 1986 and there has
been significant infill drilling in the Rangely Field, completing additional wells to further optimize
production. Operational results thus far indicate that there is C02 throughout the Rangely Field.
C02 injected into the Rangely Field remains contained within the Rangely Field AMA because of the
19
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fluid and pressure management results associated with C02 EOR. The maintenance of an IWR of 1.0
assures a stable reservoir pressure; managed lease line injection and production wells are used to
retain fluids in the Rangely Field as indicated in Section 4.7. Implementation of these methods over the
past decades have successfully contained C02 within the Rangely Field.
It is highly unlikely that injected C02 will migrate downdip and laterally outside the Rangely Field
because of the nature of the geology and the approach used for injection. As indicated in Section
2.2.1 "Geology of the Rangely Field," the Rangely Field is situated at the top of a dome structural
trap, with all directions pointing down-dip from the highest point. This means that over long periods of
time, injected C02 will tend to rise vertically towards the point in the Rangely Field with the highest
elevation.
Forecasted C02 injection volumes, shown in Figure 1, represent SEM's plan to not increase current
injection volumes and maintain an IWR of 1. Operations will not expand beyond the currently active C02-
EOR portion of the Rangely Field; therefore, the AMA is not expected to increase. Should such
expansions occur, they will be reported in the Subpart RR Annual Report for the Rangely Field, as
required by section 98.446.
3.2 Maximum Monitoring Area
The Maximum Monitoring Area (MMA) is defined in 40 CFR §98.440-449 (Subpart RR) as equal or greater
than the area expected to contain the free-phase C02 plume until the C02 plume has stabilized, plus an all-
around buffer zone of one-half mile. Section 3.1 states that the maximum extent of the injected C02 is expected
to be bounded by the Rangely Field Unit boundary shown in Figure 9. Therefore, the MMA is the Rangely Field
Unit boundary plus the one-half mile buffer as required by 40 CFR §98.440-449 (Subpart RR).
3.3 Monitoring Timeframes
SEM's primary purpose for injecting C02 is to produce oil that would otherwise remain trapped in the
reservoir and not, as in UIC Class VI, "specifically for the purpose of geologic storage."3 During a Specified
Period, SEM will have a subsidiary purpose of establishing the long-term containment of a measurable
quantity of C02 in the Weber Sands in the Rangely Field. The Specified Period will be shorter than the
period of production from the Rangely Field. This is in part because the purchase of new C02 for injection
is projected to taper off significantly before production ceases at Rangely Field, which is modeled through
2060. At the conclusion of the Specified Period, SEM will submit a request for discontinuation of reporting.
This request will be submitted when SEM can provide a demonstration that current monitoring and model(s)
show that the cumulative mass of C02 reported as sequestered during the Specified Period is not expected
to migrate in the future in a manner likely to result in surface leakage. It is expected that it will be possible to
make this demonstration within two to three years after injection for the Specified Period ceases based upon
predictive modeling supported by monitoring data. The demonstration will rely on two principles: 1) that just
as is the case for the monitoring plan, the continued process of fluid management during the years of C02
EOR operation after the Specified Period will contain injected fluids in the Rangely Field, and 2) that the
cumulative mass reported as sequestered during the Specified Period is a fraction of the theoretical storage
capacity of the Rangely Field See 40 C.F.R. § 98.441 (b)(2)(ii).
4. Evaluation of Potential Pathways for Leakage to the Surface
3 EPA UIC Class VI rule, EPA 75 FR 77291, December 10, 2010, section 146.81(b).
20
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4.1 Introduction
In the 90 years since the Rangely Field was discovered in 1933, extensive reservoir monitoring and
studies were performed. Based on the knowledge gained from historical practices, this section assesses
the following potential pathways for leakage of C02 to surface within Rangely Field.
Existing Wellbores
Faults and Fractures
Natural and Induced Seismic Activity
Previous Operations
Pipeline/Surface Equipment
Lateral Migration Outside the Rangely Field
Drilling Through the C02 Area
Diffuse Leakage Through the Seal
Detailed analysis of these potential pathways concluded that existing wellbores and pipeline/surface
equipment pose the only meaningful potential leakage pathways. Operating pressures are not expected
to increase overtime, therefore there is not a specific time period that would increase the likelihood of
pathways for leakage. SEM identifies these potential pathways for C02 leakage to be low risk, i.e., less
than 1% given the extensive operating history and monitoring program currently in place.
The monitoring program to detect and quantify leakage is based on the assessment discussed below.
4.2 Existing Wellbores
As of April 2023, there are approximately 662 active SEM operated wells in the Rangely Field - split roughly
evenly between production and injection wells. In addition, there are approximately 135 wells not in use, as
described in Section 2.3.2.
Leakage through existing wellbores is a potential risk at the Rangely Field that SEM works to prevent by
adhering to regulatory requirements for well drilling and testing; implementing best practices that SEM has
developed through its extensive operating experience; monitoring injection/production performance,
wellbores, and the surface; and maintaining surface equipment.
As discussed in Section 2.3.2, regulations governing wells in the Rangely Field require that wells be
completed and operated so that fluids are contained in the strata in which they are encountered and that
well operation does not pollute subsurface and surface waters. The regulations establish the requirements
that all wells (injection, production, disposal) must comply with. Depending upon the purpose of a well, the
requirements can include additional standards for evaluation and MIT. SEM's best practices include pattern
level analysis to guide injection pressures and performance expectations; utilizing diverse teams of experts
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to develop EOR projects based on specific site characteristics; and creating a culture where all field
personnel are trained to look for and address issues promptly. SEM's practices, which include corrosion
prevention techniques to protect the wellbore as needed, as discussed in Section 2.3.2, ensures that well
completion and operation procedures are designed not only to comply with regulations but also to ensure
that all fluids (e.g., oil, gas, C02) remain in the Rangely Field until they are produced through an SEM well.
As described in Section 5, continual and routine monitoring of SEM's wellbores and site operations will be
used to detect leaks, including those from non-SEM wells, or other potential well problems, as follows:
Well pressure in injection wells is monitored on a continual basis. The injection plans for each pattern
are programmed into the injection WAG controller, as discussed in Section 2.3.1, to govern the rate and
pressure of each injector. Pressure monitors on the injection wells are programmed to flag pressures
that significantly deviate from the plan. Leakage on the inside or outside of the injection wellbore would
affect pressure and be detected through this approach. If such excursions occur, they are investigated
and addressed. In the time SEM has operated the Rangely Field, there have been no C02 leakage
events from a wellbore.
In addition to monitoring well pressure and injection performance, SEM uses the experience gained
overtime to strategically approach well maintenance. SEM maintains well maintenance and workover
crews onsite for this purpose. For example, the well classifications by age and construction method
indicated in Table 1 inform SEM's plan for monitoring and updating wells. SEM uses all of the
information at hand including pattern performance, and well characteristics to determine well
maintenance schedules.
Production well performance is monitored using the production well test process conducted when
produced fluids are gathered and sent to a collection station. There is a routine cycle for each collection
station, with each well being tested approximately twice every month. During this cycle, each production
well is diverted to the well test equipment for a period of time sufficient to measure and sample produced
fluids (generally 24 hours). This test allows SEM to allocate a portion of the produced fluids measured
at the collection station to each production well, assess the composition of produced fluids by location,
and assess the performance of each well. Performance data are reviewed on a routine basis to ensure
that C02 flooding is optimized. If production is off plan, it is investigated and any identified issues
addressed. Leakage to the outside of production wells is not considered a major risk because of the
reduced pressure in the casing. Further, the personal H2S monitors are designed to detect leaked fluids
around production wells.
Finally, as indicated in Section 5, field inspections are conducted on a routine basis by field personnel.
On any day, SEM has approximately 25 personnel in the field. Leaking C02 is very cold and leads to
formation of bright white clouds and ice that are easily spotted. All field personnel are trained to identify
leaking C02 and other potential problems at wellbores and in the field. Any C02 leakage detected will
be documented and reported, quantified and addressed as described in Section 5.
Based on its ongoing monitoring activities and review of the potential leakage risks posed by wellbores,
SEM concludes that it is mitigating the risk of C02 leakage through wellbores by detecting problems as
they arise and quantifying any leakage that does occur. Section 4.10 summarizes how SEM will monitor
C02 leakage from various pathways and describes how SEM will respond to various leakage scenarios.
In addition, Section 5 describes how SEM will develop the inputs used in the Subpart RR mass-balance
equation (Equation RR-11). Any incidents that result in C02 leakage up the wellbore and into the
atmosphere will be quantified as described in Section 7.4.
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4.3 Faults and Fractures
After reviewing geologic, seismic, operating, and other evidence, SEM has concluded that there are no
known faults or fractures that transect the entirety of the Weber Sands in the project area. As described in
Section 2.2.1, the MFF is present below the reservoir and terminates within the Weber Sands without
breaching the upper seal. Additional faults have been identified in formations that are stratigraphically below
the Weber Sands, but this faulting has been shown not to affect the Weber Sands or to have created
potential leakage pathways given that they do not contact the Upper Pennsylvanian or Permian strata
(Weber Fm.).
SEM has extensive experience in designing and implementing EOR projects to ensure injection pressures
will not damage the oil reservoir by inducing new fractures or creating shear. As a safeguard, injection
satellites are set with automatic shutoff controls if injection pressures exceed fracture pressures.
4.4 Natural or Induced Seismicity
After reviewing literature and historic data, SEM concludes that there is no direct evidence that natural
seismic activity poses a significant risk for loss of C02 to the surface in the Rangely Field. Natural seismic
events are derived from the thrust fault to the west. Historically, Figure 6 in section 2.2.1 shows nine (9)
seismic events outside of the Rangely Field (including the 1993 M 3.5 event). The epicenter of these
earthquakes was far below the operating depths of the Rangely Field, and are associated with the thrust
fault to the west of the field. The operations of Rangely have zero impact on this thrust fault. Natural
earthquakes are not predictable, but these do not pose a threat to current operations. This is evidenced by
the fact that hydrocarbons are still within the anticline, meaning that there have been no major seismic
events in the last few million years capable of releasing these hydrocarbons to the surface.
Induced seismic events (non-natural) are tied to the MFF and its joint faults. These can be impacted by
Rangely Field operations. Section 2.2.1 explains how an increase in reservoir pressure can trigger seismic
events along and near the MFF. To prevent this from occurring bottom hole pressure surveys are collected
one (1) to two (2) times per year across the Rangely Field helping to monitor pressure changes along across
the Rangely Field. By keeping reservoir pressure from exceeding the threshold of ~3730 psi for extended
periods of time (multiple years), induced seismic events can be greatly mitigated. In the case that reservoir
pressures do exceed the threshold pressure, a reduction in injected volumes in the vicinity will bring down
the pressures back down gradually over a period of time.
4.5 Previous Operations
Chevron initiated C02 flooding in the Rangely Field in 1986. SEM and the prior operators have kept records
of the site and have completed numerous infill wells. SEM has not drilled any new wells in Rangely to date
but their standard practice for drilling new wells includes a rigorous review of nearby wells to ensure that
drilling will not cause damage to or interfere with existing wells. SEM will also follow AOR requirements
under the UIC Class II program, which require identification of all active and abandoned wells in the AOR
and implementation of procedures that ensure the integrity of those wells when applying for a permit for any
new injection well. These practices ensure that identified wells are sufficiently isolated and do not interfere
with the C02 EOR operations and reservoir pressure management. Consequently, SEM's operational
experience supports the conclusion that there are no unknown wells within the Rangely Field that penetrate
the Weber Sands and that it has sufficiently mitigated the risk of migration from older wells.
4.6 Pipeline / Surface Equipment
Damage to or failure of pipelines and surface equipment can result in unplanned losses of C02. SEM
reduces the risk of unplanned leakage from surface facilities, to the maximum extent practicable, by relying
on the use of prevailing design and construction practices and maintaining compliance with applicable
regulations. The facilities and pipelines currently utilize and will continue to utilize materials of construction
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and control processes that are standard for C02 EOR projects in the oil and gas industry. As described
above, all facilities in the Rangely Field are internally screened for proximity to the public. In the case of
pipeline and surface equipment, best engineering practices call for more robust metallurgy in wellhead
equipment, and pressure transducers with low pressure alarms monitored through the SCADA system to
prevent and detect leakage. Operating and maintenance practices currently follow and will continue to follow
demonstrated industry standards. C02 delivery via the Raven Ridge pipeline system will continue to
comply with all applicable regulations. Finally, frequent routine visual inspection of surface facilities by field
staff will provide an additional way to detect leaks and further support SEM's efforts to detect and remedy
any leaks in a timely manner. Should leakage be detected from pipeline or surface equipment, the volume
of released C02 will be quantified following the requirements of Subpart W of EPA's GHGRP.
4.7 Lateral Migration Outside the Rangely Field
It is highly unlikely that injected C02 will migrate downdip and laterally outside the Rangely Field because of
the nature of the geology and the approach used for injection. First, as indicated in Section 2.2.1 "Geology
of the Rangely Field," the Rangely Field is situated at the top of a dome structural trap, with all directions
pointing down-dip from the highest point. This means that over long periods of time, injected C02 will tend
to rise vertically towards the point in the Rangely Field with the highest elevation. Second, the planned
injection volumes and active fluid management during injection operations will prevent C02 from migrating
laterally stratigraphically (down-dip structurally) out of the structure. Finally, SEM will not be increasing the
total volume of fluids in the Rangely Field.
COGCC requires that injection pressures be limited to ensure injection fluids do not migrate outside the
permitted injection interval. In the Rangely Field, SEM uses two methods to contain fluids: reservoir
pressure management and the careful placement and operation of wells along the outer producing limits of
the units.
Reservoir pressure in the Rangely Field is managed by maintaining an injection to withdrawal ratio (IWR)
of approximately 1.0. To maintain the IWR, SEM monitors fluid injection to ensure that reservoir pressure
does not increase to a level that would fracture the reservoir seal or otherwise damage the oil field.
SEM also prevents injected fluids from migrating out of the injection interval by keeping injection pressure
below the formation fracture pressure, which is measured using historic step-rate tests. In these tests,
injection pressures are incrementally increased (e.g., in "steps") until injectivity increases abruptly, which
indicates that an opening or fracture has been created in the rock. SEM manages its operations to ensure
that injection pressures are kept below the formation fracture pressure so as to ensure that the valuable
fluid hydrocarbons and C02 remain in the reservoir.
There are a few small producer wells operated by third parties outside the boundary of Rangely Field. There
are currently no significant commercial operations surrounding the Rangely Field to interfere with SEM's
operations.
Based on site characterization and planned and projected operations SEM estimates the total volume of
stored C02 will be approximately 35.7% of calculated capacity.
4.8 Drilling Through the C02 Area
It is possible that at some point in the future, drilling through the containment zone into the Weber Sands
could occur and inadvertently create a leakage pathway. SEM's review of this issue concludes that this risk
is very low for two reasons. First, SEM's visual inspection process, including routine site visits, is designed
to identify unapproved drilling activity in the Rangely Field. Second, SEM plans to operate the C02 EOR
flood in the Rangely Field for several more years, and will continue to be vigilant about protecting the
integrity of its assets and maximizing the potential of resources (oil, gas, C02). In the unlikely event SEM
would sell the field to a new operator, provisions would result in a change to the reporting program and
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would be addressed at that time.
4.9 Diffuse Leakage through the Seal
Diffuse leakage through the seal formed by the Moenkopi Formation is highly unlikely. The presence of a
gas cap trapped over millions of years as discussed in Section 2.2.3 confirms that the seal has been
secure for a very long time. Injection pattern monitoring program referenced in Section 2.3.1 and detailed
in Section 5 assures that no breach of the seal will be created. The seal is highly impermeable where
unperforated, cemented across the horizon where perforated by wells, and unexplained changes in
injection pressure would trigger investigation as to the cause. Further, if C02 were to migrate through the
Moenkopi seal, it would migrate vertically until it encountered and was trapped by any of the numerous
shallower shale seals
4.10 Monitoring, Response, and Reporting Plan for C02 Loss
As discussed above, the potential sources of leakage include fairly routine issues, such as problems with
surface equipment (pumps, valves, etc.) or subsurface equipment (wellbores), and unique events such as
induced fractures. Table 3 summarizes some of these potential leakage scenarios, the monitoring activities
designed to detect those leaks, SEM's standard response, and other applicable regulatory programs
requiring similar reporting.
Sections 5.1.5 - 5.1.7 discuss the approaches envisioned for quantifying the volumes of leaked C02. Given
the uncertainty concerning the nature and characteristics of leaks that will be encountered, the most
appropriate methods for quantifying the volume of leaked C02 will be determined at the time. In the event
leakage occurs, SEM plans to determine the most appropriate methods for quantifying the volume leaked
and will report it as required as part of the annual Subpart RR submission.
Any volume of C02 detected leaking to surface will be quantified using acceptable emission factors such
as those found in 40 CFR Part 98 Subpart W or engineering estimates of leak amounts based on
measurements in the subsurface, SEM's field experience, and other factors such as the frequency of
inspection. As indicated in Sections 5.1 and 7.4, leaks will be documented, evaluated and addressed in a
timely manner. Records of leakage events will be retained in the electronic environmental documentation
and reporting system. Repairs requiring a work order will be documented in the electronic equipment
maintenance system.
Table 3 Response Plan for C02 Loss
Risk
Monitoring Plan
Response Plan
Parallel
Reporting (if
any)
Loss of Well Control
Tubing Leak
Monitor changes in tubing and
annulus pressure; MIT for injectors
Well is shut in and
Workover crews respond
within days
COGCC
Casing Leak
Routine Field inspection; monitor
changes in annulus pressure; MIT for
injectors; extra attention to high risk
wells
Well is shut in and
Workover crews respond
within days
COGCC
Wellhead Leak
Routine Field inspection
Well is shut in and
Workover crews respond
within days
COGCC
Loss of Bottom-
hole
pressure control
Blowout during well operations
Maintain well kill
procedures
COGCC
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Unplanned wells
drilled through
Weber Sands
Routine Field inspection to
prevent unapproved drilling;
compliance with COGCC permitting
for planned wells.
Assure compliance with
COGCC regulations
COGCC
Permitting
Loss of seal in
abandoned wells
Reservoir pressure in monitor wells;
high pressure found in new wells
Re-enter and reseal
abandoned wells
COGCC
Leaks in Surface Facilities
Pumps, valves, etc.
Routine Field inspection; SCADA
Maintenance crews
respond within days
Subpart W
Subsurface Leaks
Leakage along
faults
Reservoir pressure in monitor wells;
high pressure found in new wells
Shut in injectors near
faults
-
Overfill beyond
spill
points
Reservoir pressure in monitor wells;
high; pressure found in new wells
Fluid management
along
lease lines
-
Leakage through
induced fractures
Reservoir pressure in monitor wells;
high pressure found in new wells
Comply with rules for
keeping pressures
below
parting pressure
-
Leakage due to
seismic event
Reservoir pressure in monitor wells;
high
pressure found in new wells
Shut in injectors near
seismic event
-
Available studies of actual well leaks and natural analogs (e.g., naturally occurring C02 geysers) suggest
that the amount released from routine leaks would be small as compared to the amount of C02 that would
remain stored in the formation.
4.11 Summary
The structure and stratigraphy of the Weber Sands in the Rangely Field is ideally suited forthe injection and
storage of C02. The stratigraphy within the C02 injection zones is porous, permeable and very thick,
providing ample capacity for long-term C02 storage. The Weber Sands is overlain by several intervals of
impermeable geologic zones that form effective seals or "caps" to fluids in the Weber Sands (See Figure
4). After assessing potential risk of release from the subsurface and steps that have been taken to prevent
leaks, SEM has determined that the potential threat of leakage is extremely low.
In summary, based on a careful assessment of the potential risk of release of C02 from the subsurface, SEM
has determined that there are no leakage pathways at the Rangely Field that are likely to result in significant
loss of C02 to the atmosphere. Further, given the detailed knowledge of the Field and its operating
protocols, SEM concludes that it would be able to both detect and quantify any C02 leakage to the surface
that could arise through either identified or unexpected leakage pathways.
5. Monitoring and Considerations for Calculating Site Specific Variables
Monitoring will also be used to determine the quantities in the mass balance equation and to make the
demonstration that the C02 plume will not migrate to the surface after the time of discontinuation.
5.1 Forthe Mass Balance Equation
5.1.1 General Monitoring Procedures
As part of its ongoing operations, SEM monitors and collects flow, pressure, and gas composition data from
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the Rangely Field in centralized data management systems. These data are monitored continually by
qualified technicians who follow SEM response and reporting protocols when the systems deliver
notifications that data exceed statistically acceptable boundaries.
As indicated in Figures 10 and 11, custody-transfer meters are used at the point at which custody of the
C02 from the Raven Ridge pipeline delivery system is transferred to SEM, and at the points at which custody
of oil and NGLs are transferred to outside parties. Meters measure flow rate continually. Fluid composition
will be determined, at a minimum, quarterly, consistent with EPA GHGRP's Subpart RR, section 98.447(a).
All meter and composition data are documented, and records will be retained for at least three years.
Metering protocols used by SEM follow the prevailing industry standard(s) for custody transfer as currently
promulgated by the API, the American Gas Association (AGA), and the Gas Processors Association (GPA),
as appropriate. This approach is consistent with EPA GHGRP's Subpart RR, section 98.444(e)(3). These
meters will be maintained routinely, operated continually, and will feed data directly to the centralized data
collection systems. The meters meet the industry standard for custody transfer meter accuracy and
calibration frequency. These custody meters provide the most accurate way to measure mass flows.
SEM maintains in-field process control meters to monitor and manage in-field activities on a real time basis.
These are identified as operations meters in Figures 10 and 11. These meters provide information used to
make operational decisions but are not intended to provide the same level of accuracy as the custody-
transfer meters. The level of precision and accuracy for in-field meters currently satisfies the requirements
for reporting in existing UIC permits. Although these meters are accurate for operational purposes, it is
important to note that there is some variance between most commercial meters (on the order of 1-5%)
which is additive across meters. This variance is due to differences in factory settings and meter calibration,
as well as the operating conditions within a field. Meter elevation, changes in temperature (over the course
of the day), fluid composition (especially in multi-component or multi-phase streams), or pressure can affect
in-field meter readings. Unlike in a saline formation, where there are likely to be only a few injection wells
and associated meters, at C02 EOR operations in the Rangely Field there are currently 662 active injection
and production wells and a comparable number of meters, each with an acceptable range of error. This is
a site-specific factor that is considered in the mass balance calculations described in Section 7.
5.1.2 C02 Received
SEM measures the volume of received C02 using commercial custody transfer meters at the off-take point
from the Raven Ridge pipeline delivery system. This transfer is a commercial transaction that is
documented. C02 composition is governed by the contract and the gas is routinely sampled to determine
composition. No C02 is received in containers.
5.1.3 C02 Injected into the Subsurface
Injected C02 will be calculated using the flow metervolumes at the operations meter at the outlet of the C02
Reinjection Facility and the custody transfer meter at the C02 off-take points from the Raven Ridge pipeline
delivery system
5.1.4 C02 Produced, Entrained in Products, and Recycled
The following measurements are used for the mass balance equations in Section 7:
C02 produced is calculated using the volumetric flow meters at the inlet to the C02 Reinjection Facility.
These flow meters, as illustrated on Figure 10, are downstream of the field collection station separators
and bulk produced fluid separators at the water injection plants
C02 is produced as entrained or dissolved C02 in produced oil, as indicated in Figures 10 and 11. This is
calculated using volumetric flow through the custody transfer meter.
Recycled C02 is calculated using the volumetric flow meter at the outlet of the C02 Reinjection Facility,
which is an operations meter.
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5.1.5 C02 Emitted by Surface Leakage
As discussed in Section 5.1.6 and 5.1.7 below, SEM uses 40 CFR Part 98 Subpart Wto estimate surface
leaks from equipment at the Rangely Field. Subpart W uses a factor-driven approach to estimate equipment
leakage. In addition, SEM uses an event-driven process to assess, address, track, and if applicable quantify
potential C02 leakage to the surface.
The multi-layered, risk-based monitoring program for event-driven incidents has been designed to meet two
objectives, in accordance with the leakage risk assessment in Section 4: 1) to detect problems before C02
leaks to the surface; and 2) to detect and quantify any leaks that do occur. This section discusses how this
monitoring will be conducted and used to quantify the volumes of C02 leaked to the surface.
Monitoring for potential Leakage from the Injection/Production Zone:
SEM will monitor both injection into and production from the reservoir as a means of early identification of
potential anomalies that could indicate leakage from the subsurface.
SEM develops injection plans for each well and that is distributed to operations weekly. If injection pressure
or rate measurements are beyond the specified set points determined as part of each pattern injection plan,
the operations engineer will notify field personnel and they will investigate and resolve the problem. These
excursions will be reviewed by well-management personnel to determine if C02 leakage may be occurring.
Excursions are not necessarily indicators of leaks; they simply indicate that injection rates and pressures
are not conforming to the pattern injection plan. In many cases, problems are straightforward to fix (e.g., a
meter needs to be recalibrated or some other minor action is required), and there is no threat of C02
leakage. In the case of issues that are not readily resolved, more detailed investigation and response would
be initiated, and internal SEM support staff would provide additional assistance and evaluation. Such issues
would lead to the development of a work order in SEM's work order management system. This record
enables the company to track progress on investigating potential leaks and, if a leak has occurred, to
quantify its magnitude.
Likewise, SEM develops a forecast of the rate and composition of produced fluids. Each producer well is
assigned to one collection station and is isolated twice during each monthly cycle for a well production test.
This data is reviewed on a periodic basis to confirm that production is at the level forecasted. If there is a
significant deviation from the forecast, well management personnel investigate. If the issue cannot be
resolved quickly, more detailed investigation and response would be initiated. As in the case of the injection
pattern monitoring, if the investigation leads to a work order in the SEM work order management system,
this record will provide the basis for tracking the outcome of the investigation and if a leak has occurred. If
leakage in the flood zone were detected, SEM would use an appropriate method to quantify the involved
volume of C02. This might include use of material balance equations based on known injected quantities
and monitored pressures in the injection zone to estimate the volume of C02 involved.
A subsurface leak might not lead to a surface leak. In the event of a subsurface leak, SEM would determine
the appropriate approach for tracking subsurface leakage to determine and quantify leakage to the surface.
To quantify leakage to the surface, SEM would estimate the relevant parameters (e.g., the rate,
concentration, and duration of leakage) to quantify the leak volume. Depending on specific circumstances,
these determinations may rely on engineering estimates.
In the event leakage from the subsurface occurred diffusely through the seals, the leaked gas would include
H2S, which would trigger the alarm on the personal monitors worn by field personnel. Such a diffuse leak
from the subsurface has not occurred in the Rangely Field. In the event such a leak was detected, field
personnel from across SEM would determine how to address the problem. The team might use modeling,
engineering estimates, and direct measurements to assess, address, and quantify the leakage.
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Monitoring of Wellbores:
SEM monitors wells through continual, automated pressure monitoring in the injection zone (as described in
Section 4.2), monitoring of the annular pressure in wellheads, and routine maintenance and inspection.
Leaks from wellbores would be detected through the follow-up investigation of pressure anomalies, visual
inspection, or the use of personal H2S monitors.
Anomalies in injection zone pressure may not indicate a leak, as discussed above. However, if an
investigation leads to a work order, field personnel would inspect the equipment in question and determine
the nature of the problem. If it is a simple matter, the repair would be made and the volume of leaked C02
would be included in the 40 CFR Part 98 Subpart W report for the Rangely Field, as well as reported in
Subpart RR . If more extensive repair were needed, SEM would determine the appropriate approach for
quantifying leaked C02 using the relevant parameters (e.g., the rate, concentration, and duration of
leakage). The work order would serve as the basis for tracking the event for GHG reporting.
Anomalies in annular pressure or other issues detected during routine maintenance inspections would be
treated in the same way. Field personnel would inspect the equipment in question and determine the nature
of the problem. For simple matters the repair would be made at the time of inspection and the volume of
leaked C02 would be included in the 40 CFR Part 98 Subpart W report for the Rangely Field, as well as
reported in Subpart RR. If more extensive repairs were needed, a work order would be generated and SEM
would determine the appropriate approach for quantifying leaked C02 using the relevant parameters (e.g.,
the rate, concentration, and duration of leakage). The work order would serve as the basis for tracking the
event for GHG reporting.
Because leaking C02 at the surface is very cold and leads to formation of bright white clouds and ice that
are easily spotted, SEM also employs a two-part visual inspection process in the general area ofthe Rangely
Field to detect unexpected releases from wellbores. First, field personnel visit the surface facilities on a
routine basis. Inspections may include tank volumes, equipment status and reliability, lube oil levels,
pressures and flow rates in the facility, and valve leaks. Field personnel inspections also check that injectors
are on the proper WAG schedule and observe the facility for visible C02 or fluid line leaks.
Historically, SEM has not experienced any unexpected release events in the Rangely Field. An identified
need for repair or maintenance through visual inspections results in a work order being entered into SEM's
equipment and maintenance work order management system. The time to repair any leak is dependent on
several factors, such as the severity ofthe leak, available manpower, location ofthe leak, and availability
of materials required for the repair. Critical leaks are acted upon immediately.
Finally, SEM uses the data collected by the H2S monitors, which are worn by all field personnel at all times,
as a last method to detect leakage from wellbores. The H2S monitors detection limit is 10ppm; if an H2S
alarm is triggered, the first response is to protect the safety ofthe personnel, and the next step is to safely
investigate the source of the alarm. As noted previously, SEM considers H2S a proxy for potential C02
leaks in the field. Thus, detected H2S leaks will be investigated to determine if potential C02 leakage is
present, but not used to determine the leak volume. If the incident results in a work order, this will serve as
the basis for tracking the event for GHG reporting.
Other Potential Leakage at the Surface:
SEM will utilize the same visual inspection process and H2S monitoring system to detect other potential
leakage at the surface as it does for leakage from wellbores. SEM utilizes routine visual inspections to
detect significant loss of C02 to the surface. Field personnel routinely visit surface facilities to conduct a
visual inspection. Inspections may include review of tank level, equipment status, lube oil levels, pressures
and flow rates in the facility, valve leaks, ensuring that injectors are on the proper WAG schedule, and also
conducting a general observation ofthe facility for visible C02 or fluid line leaks. If problems are detected,
field personnel would investigate, and, if maintenance is required, generate a work order in the maintenance
system, which is tracked through completion. In addition to these visual inspections, SEM will use the results
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of the personal H2S monitors worn by field personnel as a supplement for smaller leaks that may escape
visual detection.
If C02 leakage to the surface is detected, it will be reported to surface operations personnel who will review
the reports and conduct a site investigation. If maintenance is required, a work order will be generated in
the work order management system. The work order will describe the appropriate corrective action and be
used to track completion of the maintenance action. The work order will also serve as the basis for tracking
the event for GHG reporting and quantifying any C02 emissions.
5.1.6 C02 emitted from equipment leaks and vented emissions of C02 from surface equipment
located between the injection flow meter and the injection wellhead.
SEM evaluates and estimates the mass of C02 emitted (in metric tons) annually from equipment leaks and
vented emissions of C02 from equipment located on the surface between the flow meter used to measure
injection quantity and the injection wellhead, as required under 40 CFR Part 98 Subpart W and 40 CFR
Part 98 Subpart RR.
5.1.7 Mass of C02 emissions from equipment leaks and vented emissions of C02 from surface
equipment located between the production flow meter and the production wellhead
SEM evaluates and estimates the mass of C02 emitted (in metric tons) annually from equipment leaks and
vented emissions of C02 from equipment located on the surface between the production wellhead and the
flow meter used to measure production quantity, as required under 40 CFR Part 98 Subpart W and 40 CFR
Part 98 Subpart RR.
5.2 To Demonstrate that Injected C02 is not Expected to Migrate to the Surface
At the end of the Specified Period, SEM intends to cease injecting C02 for the subsidiary purpose of
establishing the long-term storage of C02 in the Rangely Field. After the end of the Specified Period, SEM
anticipates that it will submit a request to discontinue monitoring and reporting. The request will demonstrate
that the amount of C02 reported under 40 CFR §98.440-449 (Subpart RR) is not expected to migrate in the
future in a manner likely to result in surface leakage. At that time, SEM will be able to support its request
with years of data collected during the Specified Period as well as two to three (or more, if needed) years
of data collected after the end of the Specified Period. This demonstration will provide the information
necessary for the EPA Administrator to approve the request to discontinue monitoring and reporting and
may include, but is not limited to:
i. Data comparing actual performance to predicted performance (purchase, injection, production)
over the monitoring period;
ii. An assessment of the C02 leakage detected, including discussion of the estimated amount of
C02 leaked and the distribution of emissions by leakage pathway;
iii. A demonstration that future operations will not release the volume of stored C02 to the surface;
iv. A demonstration that there has been no significant leakage of C02; and,
v. An evaluation of reservoir pressure in the Rangely Field that demonstrates that injected fluids are
not expected to migrate in a manner to create a potential leakage pathway.
6. Determination of Baselines
SEM intends to utilize existing automatic data systems to identify and investigate excursions from expected
performance that could indicate C02 leakage. SEM's data systems are used primarily for operational
control and monitoring and as such are set to capture more information than is necessary for reporting in the
Annual Subpart RR Report. SEM will develop the necessary system guidelines to capture the information that
is relevant to identify possible C02 leakage. The following describes SEM's approach to collecting this
information.
30
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Visual Inspections
As field personnel conduct routine inspections, work orders are generated in the electronic system for
maintenance activities that cannot be addressed on the spot. Methods to capture work orders that involve
activities that could potentially involve C02 leakage will be developed, if not currently in place. Examples
include occurrences of well workover or repair, as well as visual identification of vapor clouds or ice
formations. Each incident will be flagged for review by the person responsible for MRV documentation. The
responsible party will be provided in the monitoring plan, as required under Subpart A, 98.3(g). The Annual
Subpart RR Report will include an estimate of the amount of C02 leaked. Records of information used to
calculate emissions will be maintained on file for a minimum of three years.
Personal H2S Monitors
H2S monitors are worn by all field personnel. Any monitor alarm triggers an immediate response to ensure
personnel are not at risk and to verify the monitor is working properly. The person responsible for MRV
documentation will receive notice of all incidents where H2S is confirmed to be present. The Annual Subpart
RR Report will provide an estimate the amount of C02 emitted from any such incidents. Records of
information to calculate emissions will be maintained on file for a minimum of three years.
Injection Rates. Pressures and Volumes
SEM develops target injection rate and pressure for each injector, based on the results of ongoing pattern
modeling and within permitted limits. The injection targets are programmed into the WAG controllers. High
and low set points are also programmed into the SCADA, and flags whenever statistically significant
deviations from the targeted ranges are identified. The set points are designed to be conservative, because
it is preferable to have too many flags rather than too few. As a result, flags can occur frequently and are
often found to be insignificant. For purposes of Subpart RR reporting, flags (or excursions) will be screened
to determine if they could also lead to C02 leakage to the surface. The person responsible for the MRV
documentation will receive notice of excursions and related work orders that could potentially involve C02
leakage. The Annual Subpart RR Report will provide an estimate of C02 emissions. Records of information
to calculate emissions will be maintained on file for a minimum of three years.
Production Volumes and Compositions
SEM develops a general forecast of production volumes and composition which is used to periodically
evaluate performance and refine current and projected injection plans and the forecast. This information is
used to make operational decisions but is not recorded in an automated data system. Sometimes, this
review may result in the generation of a work order in the maintenance system. The MRV plan
implementation lead will review such work orders and identify those that could result in C02 leakage. Should
such events occur, leakage volumes would be calculated following the approaches described in Sections 4
and 5. Impact to Subpart RR reporting will be addressed, if deemed necessary.
7. Determination of Sequestration Volumes Using Mass Balance Equations
To account for the site conditions and complexity of a large, active EOR operation, SEM will utilize the
locations described below for obtaining volume data for the equations in Subpart RR §98.443 as indicated
below.
The selection of the utilized locations, more specifically described in this Section 7, address the propagation
of error that would result if volume data from meters at each injection well were utilized. This issue arises
because while each meter has a small but acceptable margin of error, this error would become significant
if data were taken from the approximately 284 meters within the Rangely Field. As such, SEM will use the
data from custody and operations meters on the main system pipelines to determine injection volumes used
in the mass balance. This satisfies the requirement in 40 CFR 98.444 (b) 1 that you must select a point or
points of measurement at which the C02 stream is representative of the C02 streams being injected.
The volumetric flow meters utilized for CQ2 produced are located at the inlet to the RCF. These flow
31
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meters, as illustrated on Figure 10, are directly downstream of the field collection station separators and
bulk produced fluid separators at the water injection plants. This satisfies the requirement in 40 CFR
98.444 (c)(1) for production, which states, "The point of measurement for the quantity of C02 produced
from oil or other fluid production wells is a flow meter directly downstream of each separator that sends a
stream of gas into a recycle or end use system."
The following sections describe how each element of the mass-balance equation (Equation RR-11) will be
calculated.
7.1. Mass of C02 Received
SEM will use equation RR-2 as indicated in Subpart RR §98.443 to calculate the mass of 0O2 received
from each delivery meter immediately upstream of the Raven Ridge pipeline delivery system on the Rangely
Field. The volumetric flow at standard conditions will be multiplied by the C02 concentration and the density
of C02 at standard conditions to determine mass.
where:
C02T,r = Net annual mass of C02 received through flow meter r (metric tons).
Qr,p = Quarterly volumetric flow through a receiving flow meter r in quarter p at standard conditions
(standard cubic meters).
Sr,p = Quarterly volumetric flow through a receiving flow meter r that is redelivered to another facility
without being injected into your well in quarter p (standard cubic meters).
D = Density of C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.
Cco2,P,r = Quarterly C02 concentration measurement in flow for flow meter r in quarter p (vol. percent
C02, expressed as a decimal fraction),
p = Quarter of the year,
r = Receiving flow meter.
Given SEM's method of receiving C02 and requirements at Subpart RR §98.444(a):
All delivery to the Rangely Field is used within the unit so quarterly flow redelivered, Sr,p , is
zero (0) and will not be included in the equation.
Quarterly C02 concentration will be taken from the gas measurement database SEM will sum to total
Mass of CQ2 Received using equation RR-3 in 98.443
where:
CO2 = Total net annual mass of C02 received (metric tons).
CC>2T,r = Net annual mass of C02 received (metric tons) as calculated in Equation RR-1 or RR-2 for flow
meter r.
r = Receiving flow meter.
7.2 Mass of C02 Injected into the Subsurface
The equation for calculating the Mass of C02 Injected into the Subsurface at the Rangely Field is equal to
the sum of the Mass of C02 Received as calculated in RR-3 of 98.443 (as described in Section 7.1) and the
Mass of C02 Recycled as calculated using measurements taken from the flow meter located at the output
of the RCF. As previously explained, using data at each injection well would give an inaccurate estimate of
4
CO2 = £CO:,r (Eq. RR-3)
32
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total injection volume due to the large number of wells and the potential for propagation of error due to
allowable calibration ranges for each meter.
The mass of C02 recycled will be determined using equation RR-5 as follows:
4
C02, li = X Qi>-« *D * Cco-,, (Ec3 - RR-5)
/'=!
where:
CO2.11 = Annual C02 mass injected (metric tons) as measured by flow meter u.
Qp.u = Quarterly volumetric flow rate measurement for flow meter u in quarter p at standard conditions
(standard cubic meters per quarter).
D = Density of C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.
Cco2,p,u = C02 concentration measurement in flow for flow meter u in quarter p (vol. percent C02,
expressed as a decimal fraction),
p = Quarter of the year,
u = Flow meter.
The aggregate injection data will be calculated pursuant to the procedures specified in equation RR-6 as
follows:
V
CO;,i = ]rC0lu (Eq. RR-6)
where:
CO21 = Total annual C02 mass injected (metric tons) through all injection wells.
CO2.11 = Annual C02 mass injected (metric tons) as measured by flow meter u.
u = Flow meter.
7.3 Mass of C02 Produced
The Mass of C02 Produced at the Rangely Field will be calculated using the measurements from the flow
meters at the inlet to RCF and for C02 entrained in the sales oil, the custody transfer meter for oil sales
rather than the metered data from each production well. Again, using the data at each production well would
give an inaccurate estimate of total injection due to the large number of wells and the potential for
propagation of error due to allowable calibration ranges for each meter.
Equation RR-8 in 98.443 will be used to calculate the mass of C02 produced from all injection wells as
follows:
4
C°2, w = £(?,, *D * Cca (Eq. RR-8)
Where:
C02,w = Annual C02 mass produced (metric tons) through separator w.
Qp,w = Volumetric gas flow rate measurement for separator w in quarter p at standard conditions
(standard cubic meters).
D = Density of C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.
Cco2,p,w = C02 concentration measurement in flow for separator w in quarter p (vol. percent C02,
expressed as a decimal fraction),
p = Quarter of the year,
w = Separator.
33
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Equation RR-9 in 98.443 will be used to aggregate the mass of C02 produced and the mass of C02
entrained in oil or other fluid leaving the Rangely Field as follows:
w
C02P = (l+X) * XC02,w (Eq. RR-9)
w=1
Where:
CO2P = Total annual C02 mass produced (metric tons) through all separators in the reporting year.
CO2W = Annual C02 mass produced (metric tons) through separator w in the reporting year.
X = Entrained C02 in produced oil or other fluid divided by the C02 separated through all separators in
the reporting year (weight percent C02, expressed as a decimal fraction),
w = Separator.
7.4 Mass of C02 emitted by Surface Leakage
SEM will calculate and report the total annual Mass of C02 emitted by Surface Leakage using an approach
that relies on 40 CFR Part 98 Subpart W reports for equipment leakage, and tailored calculations for all
other surface leaks. As described in Sections 4 and 5.1.5-5.1.7, SEM is prepared to address the potential
for leakage in a variety of settings. Given the uncertainty concerning the nature and characteristics of leaks
that will be encountered, it is not clear the method for quantifying the volume of leaked C02 that would be
most appropriate. Estimates of the amount of C02 leaked to the surface will depend on a number of site-
specific factors including measurements of flowrate, pressure, size of leak opening, and duration of the
leak. Engineering estimates, and emission factors, depending on the source and nature of the leakage will
also be used.
SEM's process for quantifying leakage will entail using best engineering principles or emission factors.
While it is not possible to predict in advance the types of leaks that will occur, SEM describes some
approaches for quantification in Section 5.1.5-5.1.7. In the event leakage to the surface occurs, SEM would
quantify and report leakage amounts, and retain records that describe the methods used to estimate or
measure the volume leaked as reported in the Annual Subpart RR Report.
Equation RR-10 in 48.433 will be used to calculate and report the Mass of CQ2 emitted by Surface Leakage:
x
C°2E = XC°2,x (Eq, RR-10)
l
where:
CO2E = Total annual C02 mass emitted by surface leakage (metric tons) in the reporting year.
C02,x = Annual C02 mass emitted (metric tons) at leakage pathway x in the reporting year,
x = Leakage pathway.
7.5 Mass of C02 sequestered in subsurface geologic formations.
SEM will use equation RR-11 in 98.443 to calculate the Mass of C02 Sequestered in Subsurface
Geologic Formations in the Reporting Year as follows:
CO2 = CO21 - CO2P - CO2E - C02Pi CO2FP {Ec[. RR-11)
where:
C02 = Total annual C02 mass sequestered in subsurface geologic formations (metric tons) at the facility
in the reporting year.
34
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C02| = Total annual CO2 mass injected (metric tons) in the well or group of wells covered by this source
category in the reporting year.
CO2P = Total annual C02 mass produced (metric tons) in the reporting year.
CO2E = Total annual C02 mass emitted (metric tons) by surface leakage in the reporting year.
CO2F1 = Total annual C02 mass emitted (metric tons) from equipment leaks and vented emissions of C02
from equipment located on the surface between the flow meter used to measure injection quantity and the
injection wellhead, for which a calculation procedure is provided in subpart W of this part.
CO2FP = Total annual C02 mass emitted (metric tons) from equipment leaks and vented emissions of
C02 from equipment located on the surface between the production wellhead and the flow meter used to
measure production quantity, for which a calculation procedure is provided in subpart W of this part.
7.6 Cumulative mass of C02 reported as sequestered in subsurface geologic formations
SEM will sum up the total annual volumes obtained using equation RR-11 in 98.443 to calculate the
Cumulative Mass of CQ2 Sequestered in Subsurface Geologic Formations.
8. MRV Plan Implementation Schedule
The activities described in this MRV Plan are in place, and reporting is planned to start upon EPA approval.
Other GHG reports are filed on March 31 of the year after the reporting year and it is anticipated that the
Annual Subpart RR Report will be filed at the same time. As described in Section 3.3 above, SEM anticipates
that the MRV program will be in effect during the Specified Period, during which time SEM will operate the
Rangely Field with the subsidiary purpose of establishing long-term containment of a measurable quantity
of C02 in subsurface geological formations at the Rangely Field. SEM anticipates establishing that a
measurable amount of C02 injected during the Specified Period will be stored in a manner not expected
to migrate resulting in future surface leakage. At such time, SEM will prepare a demonstration supporting
the long-term containment determination and submit a request to discontinue reporting under this MRV
plan. See 40 C.F.R. § 98.441 (b)(2)(ii).
9. Quality Assurance Program
9.1 Monitoring QA/QC
As indicated in Section 7, SEM has incorporated the requirements of §98.444 (a) - (d) in the discussion
of mass balance equations. These include the following provisions.
CQ2 Received and Injected
The quarterly flow rate of C02 received by pipeline is measured at the receiving custody
transfer meters.
The quarterly C02 flow rate for recycled C02 is measured at the flow meter located at the C02
Reinjection facility outlet.
CQ2 Produced
The point of measurement for the quantity of C02 produced is a flow meter at the C02 Reinjection
facility inlet. . C02 produced as entrained or dissolved C02 in produced oil is calculated using
volumetric flow through the custody transfer meter.
The produced gas stream is sampled at least once per quarter immediately downstream of the flow
meter used to measure flow rate of that gas stream and measure the C02 concentration of the
sample.
The quarterly flow rate of the produced gas is measured at the flow meters located at the C02
Reinjection facility inlet.
35
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C02 emissions from equipment leaks and vented emissions of C02
These volumes are measured in conformance with the monitoring and QA/QC requirements
specified in subpart W of 40 CFR Part 98.
Flow meter provisions
The flow meters used to generate date for the mass balance equations in Section 7 are:
Operated continuously except as necessary for maintenance and calibration.
Operated using the calibration and accuracy requirements in 40 CFR §98.3(i).
Operated in conformance with American Petroleum Institute (API) standards.
National Institute of Standards and Technology (NIST) traceable.
Concentration of CQ2
As indicated in Appendix 1, C02 concentration is measured using an appropriate standard method. Further,
all measured volumes of C02 have been converted to standard cubic meters at a temperature of 60
degrees Fahrenheit and at an absolute pressure of 1 atmosphere, including those used in Equations RR-
2, RR-5 and RR-8 in Section 7.
Missing Data Procedures
In the event SEM is unable to collect data needed for the mass balance calculations, procedures
for estimating missing data in §98.445 will be used as follows:
A quarterly flow rate of C02 received that is missing would be estimated using invoices or using a
representative flow rate value from the nearest previous time period.
A quarterly C02 concentration of a C02 stream received that is missing would be estimated using
invoices or using a representative concentration value from the nearest previous time period.
A quarterly quantity of C02 injected that is missing would be estimated using a representative quantity
of C02injected from the nearest previous period of time at a similar injection pressure.
For any values associated with C02 emissions from equipment leaks and vented emissions of C02
from surface equipment at the facility that are reported in this subpart, missing data estimation
procedures specified in subpart Wof 40 CFR Part 98 would be followed.
The quarterly quantity of C02 produced from subsurface geologic formations that is missing would be
estimated using a representative quantity of C02 produced from the nearest previous period of time.
MRV Plan Revisions
In the event there is a material change to the monitoring and/or operational parameters of the SEM C02
EOR operations in the Rangely Field that is not anticipated in this MRV plan, the MRV plan will be revised
and submitted to the EPA Administrator within 180 days as required in §98.448(d).
Records Retention
SEM will follow the record retention requirements specified by §98.3(g). In addition, it will follow the
requirements in Subpart RR §98.447 by maintaining the following records for at least three years:
Quarterly records of C02 received at standard conditions and operating conditions, operating
temperature and pressure, and concentration of these streams.
Quarterly records of produced C02, including volumetric flow at standard conditions and operating
36
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conditions, operating temperature and pressure, and concentration of these streams.
Quarterly records of injected C02 including volumetric flow at standard conditions and operating
conditions, operating temperature and pressure, and concentration of these streams.
Annual records of information used to calculate the C02 emitted by surface leakage from leakage
pathways.
Annual records of information used to calculate the C02 emitted from equipment leaks and vented
emissions of C02 from equipment located on the surface between the flow meter used to measure
injection quantity and the injection wellhead.
Annual records of information used to calculate the C02 emitted from equipment leaks and vented
emissions of C02 from equipment located on the surface between the production wellhead and the
flow meter used to measure production quantity.
These data will be collected as generated and aggregated as required for reporting purposes.
Appendices
37
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Appendix 1. Conversion Factors
SEM reports C02 volumes at standard conditions of temperature and pressure as defined in the State of
Colorado, which follows the international standard conditions for measuring C02 properties - 77 °F and
14.696 psi.
To convert these volumes into metric tonnes, a density is calculated using the Span and Wagner equation
of state as recommended by the EPA. Density was calculated using the database of thermodynamic
properties developed by the National Institute of Standards and Technology (NIST), available at
http://webbook.nist.gov/chemistrv/fluid/.
At EPA standard conditions of 77 °F and one atmosphere, the Span and Wagner equation of state gives a
density of 0.0026500 lb-moles per cubic foot. Using a molecular weight for C02 of 44.0095, 2204.62
lbs/metric ton and 35.314667 ft3/m3, gives a C02 density of 5.29003 x 10 5 MT/ft3 or 0.0018682 MT/m3.
The conversion factor 5.29003 x 10-5 MT/Mcf has been used throughout to convert SEM volumes to metric
tons.
38
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Appendix 2. Acronyms
AGA-American Gas Association
AMA - Active Monitoring Area
AoR - Area of Review
API-American Petroleum Institute
BCF - Billion Cubic Feet
bopd - barrels of oil per day
Cf- Cubic Feet
CCR - Code of Colorado Regulations
COGCC - Colorado Oil and Gas Conservation Commission
C02 - Carbon Dioxide
CRF - C02 Removal Facilities
EOR - Enhanced Oil Recovery
EPA - US Environmental Protection Agency
GHG - Greenhouse Gas
GHGRP - Greenhouse Gas Reporting Program
H2S - Hydrogen Sulfide
IWR - Injection to Withdrawal Ratio
LACT - Lease Automatic Custody Transfer meter
Md - Millidarcy
MIT - Mechanical Integrity Test
MFF - Main Field Fault
MMA - Maximum Monitoring Area
MMB - Million barrels
Mscf-Thousand standard cubic feet
MMscf- Million standard cubic feet
MMMT - Million metric tonnes
MMT -Thousand metric tonnes
MRV - Monitoring, Reporting, and Verification
MOC - Main oil column
MT - Metric Tonne
NGNatural Gas
NGLs - Natural Gas Liquids
NIST - National Institute of Standards and Technology
OOIP - Original Oil-ln-Place
OH - Open hole
POWC - Producible oil/water contact
PPM - Parts Per Million
RCF - Rangely Field C02 Recycling and Compression Facility
RRPC - Raven Ridge pipeline
RWSU - Rangely Weber Sand Unit
SCADA - Supervisory Control and Data Acquisition
SEM - Scout Energy Management, LLC
UIC - Underground Injection Control
VRU - Vapor Recovery Unit
WAG - Water Alternating Gas
XOM - ExxonMobil
39
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Appendix 3. References
Adams, L., 2006; Sequence and Mechanical Stratigraphy: An intergrated Reservoir Characterization of
the Weber Sandstone, Western Colorado. University of Texas at El Paso Ph.D. Dissertation.
Colorado Administrative Code Department 400 Division 404 Oil and Gas Conservation Commission
Section 2
Clark, Rory, Chevron North America E&P, Presentation to 6th Annual Wyoming C02 Conference, July 12,
2012, online: //www.uwyo.edu/eori/_files/C02conference12/rory_rangelycasehistory.pdf
Energy and Carbon Management Regulation in Colorado. May 22, 2023, online:
https://leg.colorado.gov/bills/sb23-285
US Department of Energy, National Energy Technology Laboratory. "Carbon Dioxide Enhanced Oil
Recovery - Untapped Domestic Energy Supply and Long Term Carbon Storage Solution," March 2010.
US Department of Energy, National Energy Technology Laboratory. "Carbon Sequestration Through
Enhanced Oil Recovery," April 2008.
Gale, Hoyt. Geology of the Rangely Oil District. Department of Interior United States Geological Survey,
Bulletin 350. 1908.
40
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Appendix 4. Glossary of Terms
This glossary describes some of the technical terms as they are used in this MRV plan. For additional
glossaries please see the U.S. EPA Glossary of UIC Terms
(http://water.epa.gov/tvpe/aroundwater/uic/alossarv.cfm') and the Schlumberger Oilfield Glossary
(http://www.glossary.oilfield.slb.com/).
Contain / Containment - having the effect of keeping fluids located within in a specified portion of a geologic
formation.
Dip-Very few, if any, geologic features are perfectly horizontal. They are almost always tilted. The direction
of tilt is called "dip." Dip is the angle of steepest descent measured from the horizontal plane. Moving higher
up structure is moving "updip." Moving lower is "downdip." Perpendicular to dip is "strike." Moving
perpendicular along a constant depth is moving along strike.
Downdip - See "dip."
Formation - A body of rock that is sufficiently distinctive and continuous that it can be mapped.
Infill Drilling - The drilling of additional wells within existing patterns. These additional wells decrease
average well spacing. This practice both accelerates expected recovery and increases estimated ultimate
recovery in heterogeneous reservoirs by improving the continuity between injectors and producers. As well
spacing is decreased, the shifting flow paths lead to increased sweep to areas where greater hydrocarbon
saturations remain.
Permeability - Permeability is the measure of a rock's ability to transmit fluids. Rocks that transmit fluids
readily, such as sandstones, are described as permeable and tend to have many large, well-connected
pores. Impermeable formations, such as shales and siltstones, tend to be finer grained or of a mixed grain
size, with smaller, fewer, or less interconnected pores.
Phase - Phase is a region of space throughout which all physical properties of a material are essentially
uniform. Fluids that don't mix together segregate themselves into phases. Oil, for example, does not mix
with water and forms a separate phase.
Pore Space - See porosity.
Porosity - Porosity is the fraction of a rock that is not occupied by solid grains or minerals. Almost all rocks
have spaces between rock crystals or grains that is available to be filled with a fluid, such as water, oil or
gas. This space is called "pore space."
Saturation - The fraction of pore space occupied by a given fluid. Oil saturation, for example, is the fraction
of pore space occupied by oil.
Seal - A geologic layer (or multiple layers) of impermeable rock that serve as a barrier to prevent fluids
from moving upwards to the surface.
Secondary recovery - The second stage of hydrocarbon production during which an external fluid such as
water or gas is injected into the reservoirthrough injection wells located in rock that has fluid communication
with production wells. The purpose of secondary recovery is to maintain reservoir pressure and to displace
hydrocarbons toward the wellbore. The most common secondary recovery techniques are gas injection and
waterflooding.
Stratigraphic section - A stratigraphic section is a sequence of layers of rocks in the order they were
deposited.
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Strike - See "dip.
Updip - See "dip.
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Appendix 5. Well Identification Numbers
The following table presents the well name, API number, status and type for the wells in the RWSU as of
April 2023. The table is subject to change overtime as new wells are drilled, existing wells change status,
or existing wells are repurposed. The following terms are used:
Well Status
Producing refers to a well that is actively producing
Injecting refers to a well that is actively injecting
P&A refers to wells that have been closed (plugged and abandoned) per COGCC regulations
Shut In refers to wells that have been temporarily idled or shut-in
Monitor refers to a well that is used to monitor bottom home pressure in the reservoir
Well Type
Water / Gas Inject refers to wells that inject water and C02 Gas
Water Injection Well refers to wells that inject water
Oil well refers to wells that produce oil
Salt Water Disposal refers to a well used to dispose of excess water
Name
API Number
Well Type
Well Status
AC MCLAUGHLIN 46
51030632300
Water Injection Well
P&A
AC MCLAUGHLIN 64X
51030771700
Oil well
Producing
ASSOCIATED A 2
51030571400
Water / Gas Inject
P&A
ASSOCIATED A1
51030571300
Oil well
Producing
ASSOCIATED A2ST
51030571401
Water / Gas Inject
Injecting
ASSOCIATED A3X
51030778600
Oil well
Producing
ASSOCIATED A4X
51030791600
Oil well
Producing
ASSOCIATED A5X
51030803400
Water / Gas Inject
Injecting
ASSOCIATED A6X
51030801100
Water / Gas Inject
Injecting
ASSOCIATED LARSON UNIT A1
51030600900
Oil well
Producing
ASSOCIATED LARSON UNIT A2X
51030881500
Oil well
Producing
ASSOCIATED LARSON UNIT B1
51030601100
Oil well
Producing
ASSOCIATED LARSON UNIT B2X
51030950200
Oil well
Producing
ASSOCIATED UNIT A1
51030602600
Oil well
Producing
ASSOCIATED UNIT A2X UN A-2X
51031053200
Oil well
Producing
ASSOCIATED UNIT A3X
51031072300
Oil well
Producing
ASSOCIATED UNIT A4X
51031072200
Water / Gas Inject
Injecting
ASSOCIATED UNIT C1
51030582700
Oil well
Producing
BEEZLEY 1X22AX
51031075400
Water / Gas Inject
Injecting
BEEZLEY 2-22
51030574200
Oil well
Producing
BEEZLEY 3X 3X22
51031054900
Oil well
Producing
BEEZLEY 4X 22
51031055300
Oil well
Producing
BEEZLEY 5X22
51031174200
Oil well
Producing
BEEZLEY 6X22
51031174300
Oil well
Producing
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CARNEY 22X-35
51030724500
Oil well
P&A
CARNEY CT 10-4
51030608600
Oil well
Monitor
CARNEY CT 11-4
51030545700
Oil well
Monitor
CARNEY CT 12AX5
51030917600
Water / Gas Inject
Monitor
CARNEY CT 13-4
51030545900
Oil well
Producing
CARNEY CT 1-34
51030548200
Oil well
Producing
CARNEY CT 14-34
51030103500
Oil well
Producing
CARNEY CT 15-35
51030103700
Water / Gas Inject
Injecting
CARNEY CT 16-35
51030103300
Water / Gas Inject
Monitor
CARNEY CT 17-35
51030103200
Oil well
Producing
CARNEY CT 18-35
51030629500
Water / Gas Inject
Injecting
CARNEY CT 19-34
51030604400
Oil well
Producing
CARNEY CT 20X35
51030641300
Oil well
Producing
CARNEY CT 21X35
51030703300
Water / Gas Inject
Injecting
CARNEY CT 22X35ST
51030724501
Oil well
Producing
CARNEY CT 2-34
51030551400
Oil well
Monitor
CARNEY CT 23X35
51030726200
Water / Gas Inject
Injecting
CARNEY CT 24X35
51030728300
Water / Gas Inject
Monitor
CARNEY CT 27X34
51030746600
Water / Gas Inject
Injecting
CARNEY CT 28X
51030747400
Water / Gas Inject
Monitor
CARNEY CT 29X
51030753700
Water / Gas Inject
Injecting
CARNEY CT 30X34 30X
51030752600
Water / Gas Inject
Injecting
CARNEY CT 32X34
51030758900
Water / Gas Inject
Injecting
CARNEY CT 3-34
51030103900
Oil well
Producing
CARNEY CT 33X34
51030759200
Water / Gas Inject
Injecting
CARNEY CT 35X34
51030759300
Water / Gas Inject
Injecting
CARNEY CT 37X4
51030856300
Oil well
Producing
CARNEY CT 38X4
51030881300
Water / Gas Inject
Monitor
CARNEY CT 39X4
51030881400
Oil well
Producing
CARNEY CT41Y34
51030914900
Oil well
Monitor
CARNEY CT 4-34
51030555900
Oil well
Producing
CARNEY CT 43Y34
51030914800
Oil well
Monitor
CARNEY CT 44Y34
51030915300
Oil well
Monitor
CARNEY CT 5-34
51030103800
Oil well
Producing
CARNEY CT 6-5
51030609100
Water / Gas Inject
Monitor
CARNEY CT 7-35
51030629300
Oil well
Producing
CARNEY CT 8-34
51030104000
Oil well
Producing
CARNEY CT 9-35
51030548600
Water / Gas Inject
Monitor
CARNEY UNIT 1
51030608700
Oil well
Producing
CARNEY UNIT 2X
51030719100
Water / Gas Inject
Injecting
COLTHARPJE 10X
51030869400
Oil well
Producing
44
-------
COLTHARP JE 2
51030602300
Water / Gas Inject
Monitor
COLTHARP JE 4
51030602200
Water / Gas Inject
Monitor
COLTHARP JE 5X
51030705700
Oil well
Producing
COLTHARP JE 7X
51030727900
Oil well
Producing
COLTHARP JE 8X
51030734300
Oil well
Producing
COLTHARP WH A1
51030601900
Water / Gas Inject
Injecting
COLTHARP WH A3
51030602100
Water / Gas Inject
Monitor
COLTHARP WH A4
51030102800
Water / Gas Inject
Injecting
COLTHARP WH A5X
51030725000
Oil well
Producing
COLTHARP WH A6X
51030744700
Oil well
Producing
COLTHARP WH A8X
51030909900
Oil well
Producing
COLTHARP WH B2X
51030859400
Oil well
Monitor
COLTHARP WH B3X
51030879300
Oil well
Shut In
COLTHARP WH C1
51030107700
Water / Gas Inject
Monitor
COLTHARP WH C2X
51030919800
Oil well
Producing
CT CARNEY 25X34
51030741500
Water / Gas Inject
Injecting
EMERALD 10
51030566200
Oil well
Producing
EMERALD 11
51030567100
Oil well
Producing
EMERALD13ST
51030563601
Water / Gas Inject
Injecting
EMERALD 14
51030556500
Water / Gas Inject
Injecting
EMERALD 16
51030625300
Oil well
Monitor
EMERALD 17
51030567700
Water / Gas Inject
Injecting
EMERALD18AX
51030920200
Oil well
Producing
EMERALD 19
51030624000
Oil well
Producing
EMERALD 2
51030566900
Oil well
Producing
EMERALD 20
51030555800
Water / Gas Inject
Injecting
EMERALD 22
51030625400
Water / Gas Inject
Injecting
EMERALD 23
51030558900
Water / Gas Inject
Injecting
EMERALD 25
51030548100
Water / Gas Inject
Injecting
EMERALD 26
51030624200
Water / Gas Inject
Injecting
EMERALD 27
51030565300
Oil well
Producing
EMERALD 28
51030562800
Water / Gas Inject
Injecting
EMERALD 29AX
51030924500
Water / Gas Inject
Injecting
EMERALD 30AX
51030920300
Water / Gas Inject
Injecting
EMERALD 31 AX
51030923600
Water / Gas Inject
Injecting
EMERALD 32
51030623800
Oil well
Producing
EMERALD 33AX
51030923900
Water / Gas Inject
Injecting
EMERALD 34
51030559500
Water / Gas Inject
Injecting
EMERALD 35
51030559400
Water / Gas Inject
Injecting
EMERALD 36
51030548800
Water / Gas Inject
Injecting
EMERALD 37
51030551200
Water / Gas Inject
Injecting
45
-------
EMERALD 38
51030624900
Water / Gas Inject
Injecting
EMERALD 39
51030625100
Water / Gas Inject
Injecting
EMERALD 3ST
51030559901
Water / Gas Inject
Injecting
EMERALD 3ST 3
51030559900
Water / Gas Inject
P&A
EMERALD 4
51030550500
Oil well
Producing
EMERALD 40
51030625000
Water / Gas Inject
Injecting
EMERALD 41
51030546300
Water / Gas Inject
Monitor
EMERALD 42D
51030634000
Salt Water Disposal
Injecting
EMERALD 44AX
51030918700
Water / Gas Inject
Injecting
EMERALD 46X
51030713000
Oil well
Producing
EMERALD 47X
51030720100
Oil well
Producing
EMERALD 48X
51030725700
Oil well
Monitor
EMERALD 49AX
51031068000
Oil well
Producing
EMERALD 50X
51030733100
Oil well
Producing
EMERALD 51X
51030733300
Oil well
Producing
EMERALD 52X
51030737100
Oil well
Producing
EMERALD 53X
51030737600
Oil well
Producing
EMERALD 54X
51030763700
Oil well
Producing
EMERALD 55X
51030763800
Oil well
Producing
EMERALD 56X
51030768700
Oil well
Producing
EMERALD 57XST
51030764901
Oil well
Producing
EMERALD 58X
51030773900
Oil well
Producing
EMERALD 59X
51030774000
Oil well
Producing
EMERALD 6
51030558800
Water / Gas Inject
Injecting
EMERALD 60X
51030779800
Oil well
Producing
EMERALD 61X
51030780300
Oil well
Producing
EMERALD 62X
51030781100
Oil well
Producing
EMERALD 63ST
51030804101
Water / Gas Inject
Injecting
EMERALD 63XST
51030804100
Water / Gas Inject
P&A
EMERALD 64X
51030799200
Water / Gas Inject
Injecting
EMERALD 65X
51030794800
Oil well
Producing
EMERALD 66X
51030786800
Oil well
Producing
EMERALD 67X
51030797400
Oil well
Producing
EMERALD 68X
51030797500
Oil well
Producing
EMERALD 69X
51030810300
Water / Gas Inject
Injecting
EMERALD 70X
51030807200
Water / Gas Inject
Injecting
EMERALD 71X
51030804600
Water / Gas Inject
Injecting
EMERALD 72X
51030810400
Water / Gas Inject
Monitor
EMERALD 73X
51030810500
Oil well
Monitor
EMERALD 74X
51030816900
Oil well
Producing
EMERALD 75X
51030843700
Oil well
Producing
46
-------
EMERALD 76X
51030848100
Oil well
Producing
EMERALD 77X
51030848000
Oil well
Producing
EMERALD 78X
51030849100
Oil well
Producing
EMERALD 79X
51030895500
Salt Water Disposal
Injecting
EMERALD 7 A
51030928500
Water / Gas Inject
Injecting
EMERALD 8
51030559000
Water / Gas Inject
P&A
EMERALD 80X
51030876900
Oil well
Producing
EMERALD 81X
51030888300
Oil well
Producing
EMERALD 82X
51030849200
Water / Gas Inject
Injecting
EMERALD 83X
51030876500
Oil well
Producing
EMERALD 84X
51030888500
Oil well
Producing
EMERALD 85X
51030877000
Oil well
Producing
EMERALD 86X
51030877200
Oil well
Producing
EMERALD 87X
51030877300
Oil well
Monitor
EMERALD 88X
51030876600
Oil well
Producing
EMERALD 89X
51030877100
Oil well
Producing
EMERALD 8ST
51030559001
Water / Gas Inject
Injecting
EMERALD 90X
51030914600
Water / Gas Inject
Injecting
EMERALD 91Y
51030914700
Water / Gas Inject
Injecting
EMERALD 92X
51030929500
Oil well
Producing
EMERALD 93X
51031185800
Oil well
Producing
EMERALD 94X
51031185500
Oil well
Producing
EMERALD 95X
51031191400
Oil well
Producing
EMERALD 96X
51031192200
Oil well
Producing
EMERALD 97X
51031191300
Oil well
Producing
EMERALD 98X
51031191500
Water / Gas Inject
Injecting
EMERALD 9ST
51030566101
Water / Gas Inject
Injecting
EMERALD 9ST 9
51030566100
Water / Gas Inject
P&A
FAIRFIELD KITTI A 4
51031101700
Oil well
P&A
FAIRFIELD KITTI A 5P
51031101000
Oil well
P&A
FAIRFIELD KITTI A1
51030611100
Water / Gas Inject
Injecting
FAIRFIELD KITTI A4
51031101701
Oil well
Producing
FAIRFIELD KITTI A5
51031101001
Oil well
Producing
FAIRFIELD KITTI B1
51030107800
Water / Gas Inject
Injecting
FE156X
51031033600
Oil well
Producing
FEE 1
51030563400
Oil well
Producing
FEE 1 162Y
51031194500
Water / Gas Inject
Injecting
FEE 10
51030566800
Water / Gas Inject
Injecting
FEE 100X
51030786900
Oil well
Producing
FEE 101X
51030787000
Oil well
Producing
FEE 102X
51030787700
Oil well
Producing
47
-------
FEE 103X
51030788500
Oil well
Monitor
FEE 104X
51030785700
Oil well
Producing
FEE 105X
51030785800
Oil well
Producing
FEE 106X
51030794600
Water / Gas Inject
Injecting
FEE 107X
51030803200
Water / Gas Inject
Injecting
FEE 108X
51030795200
Oil well
Producing
FEE 109X
51030798900
Water / Gas Inject
Injecting
FEE 11
51030559600
Oil well
Producing
FEE 11OX
51030802600
Water / Gas Inject
Injecting
FEE 111X
51030802700
Water / Gas Inject
Monitor
FEE 112X
51030802800
Water / Gas Inject
Injecting
FEE 113X
51030802900
Water / Gas Inject
Injecting
FEE 114X
51030803100
Water / Gas Inject
Injecting
FEE 115X
51030803300
Water / Gas Inject
Injecting
FEE 116X
51030829900
Water / Gas Inject
Injecting
FEE 117X
51030843800
Oil well
Producing
FEE 118AX
51030928300
Oil well
Monitor
FEE 12
51030565100
Oil well
Producing
FEE 121X
51030857500
Oil well
Producing
FEE 122X
51030866300
Water / Gas Inject
Injecting
FEE 124X
51030866400
Oil well
Producing
FEE 125X
51030868100
Oil well
Monitor
FEE 126X
51030868600
Oil well
Producing
FEE 127X
51030868700
Water / Gas Inject
Injecting
FEE 128X
51030868800
Oil well
Monitor
FEE 129X
51030868900
Oil well
Producing
FEE 13
51030622600
Oil well
Producing
FEE 130X
51030870400
Oil well
Monitor
FEE 133X
51030888400
Oil well
Producing
FEE 135X
51030876000
Oil well
Monitor
FEE 136X
51030874500
Water / Gas Inject
Injecting
FEE 137X
51030876100
Water / Gas Inject
Injecting
FEE 138X
51030876300
Oil well
Producing
FEE 139X
51030876200
Oil well
Producing
FEE 14
51030568700
Oil well
Producing
FEE 140Y
51030910600
Oil well
Monitor
FEE 141X
51030913300
Water / Gas Inject
Injecting
FEE 142X
51030913100
Oil well
Producing
FEE 143X
51030913000
Oil well
Producing
FEE 144Y
51030917500
Oil well
Shut In
FEE 145Y
51030917400
Oil well
Producing
48
-------
FEE 146X
51030946400
Oil well
Producing
FEE 15
51030556800
Oil well
Producing
FEE 153X
51030929700
Oil well
Producing
Fee154X
51031036500
Oil well
Producing
Fee155X
51031037300
Oil well
Producing
FEE 157X
51031101900
Oil well
Monitor
FEE 158 X
51031115900
Oil well
Producing
FEE 159 X
51031101100
Oil well
Producing
FEE 160X
51031186600
Oil well
Producing
FEE 163X
51031195100
Oil well
Producing
FEE16AX
51030923500
Water / Gas Inject
Monitor
FEE 17
51030580100
Water / Gas Inject
Injecting
FEE 18
51030623600
Water / Gas Inject
Monitor
FEE 19
51030622400
Oil well
Producing
FEE 1AX
51030924400
Water / Gas Inject
Monitor
FEE 20
51030616800
Oil well
Producing
FEE 21
51030620700
Oil well
Producing
FEE 22
51030616100
Water / Gas Inject
Injecting
FEE 23
51030615600
Oil well
Producing
FEE 24
51030611200
Water / Gas Inject
Injecting
FEE 25
51030614500
Oil well
Producing
FEE 26
51030615200
Oil well
Producing
FEE 27
51030617500
Oil well
Producing
FEE 28
51030613500
Water / Gas Inject
Injecting
FEE 29
51030614400
Water / Gas Inject
Injecting
FEE 2AX
51030924700
Water / Gas Inject
Injecting
FEE 3
51030565700
Oil well
Producing
FEE 30
51030621100
Water / Gas Inject
Monitor
FEE 31
51030611800
Water / Gas Inject
Injecting
FEE 32
51030614200
Oil well
Producing
FEE 33
51030614700
Oil well
Producing
FEE 34
51030624500
Oil well
Producing
FEE 35
51030611300
Oil well
Producing
FEE 36
51030617600
Oil well
Producing
FEE 37
51030611500
Water / Gas Inject
Injecting
FEE 38
51030625500
Water / Gas Inject
Injecting
FEE 39
51030623300
Water / Gas Inject
Injecting
FEE 4
51030576900
Oil well
Monitor
FEE 40
51030622300
Water / Gas Inject
Injecting
FEE 41
51030622200
Water / Gas Inject
Monitor
FEE 42
51030568800
Water / Gas Inject
Monitor
49
-------
FEE 43
51030614100
Water / Gas Inject
Injecting
FEE 44
51030624700
Water / Gas Inject
Injecting
FEE 45
51030617900
Oil well
Producing
FEE 47
51030616000
Water / Gas Inject
Injecting
FEE 48
51030625900
Water / Gas Inject
Injecting
FEE 49
51030611900
Water / Gas Inject
Injecting
FEE 5
51030574500
Oil well
Producing
FEE 51
51030614900
Water / Gas Inject
Injecting
FEE 52
51030567400
Water / Gas Inject
Injecting
FEE 53AX
51030861200
Water / Gas Inject
Injecting
FEE 55
51030615300
Water / Gas Inject
Injecting
FEE 56
51030615700
Water / Gas Inject
Injecting
FEE 58AX
51030924300
Water / Gas Inject
Injecting
FEE 59
51030616900
Water / Gas Inject
Injecting
FEE 6
51030572000
Oil well
Producing
FEE 60
51030622500
Water / Gas Inject
Injecting
FEE 61
51030620300
Oil well
Producing
FEE 62
51030614000
Oil well
Monitor
FEE 63
51030614600
Water / Gas Inject
Injecting
FEE 64
51030614800
Water / Gas Inject
Injecting
FEE 65
51030615000
Water / Gas Inject
Injecting
FEE 67A
51030929300
Water / Gas Inject
Injecting
FEE 68A
51030568300
Oil well
Producing
FEE 69
51030625600
Water / Gas Inject
Monitor
FEE 7
51030571600
Oil well
Producing
FEE 70AX
51030919100
Water / Gas Inject
Monitor
FEE 72X
51030718000
Oil well
Producing
FEE 73X
51030727400
Oil well
Producing
FEE 74X
51030730700
Oil well
Producing
FEE 75X
51030732600
Oil well
Producing
FEE 76X
51030733900
Oil well
Producing
FEE 78X
51030743400
Oil well
Producing
FEE 79X
51030742400
Water / Gas Inject
Injecting
FEE 8
51030563300
Water / Gas Inject
Injecting
FEE 80X
51030749100
Water / Gas Inject
Injecting
FEE 81X
51030751900
Oil well
Producing
FEE 82X
51030752900
Oil well
Producing
FEE 83X
51030757200
Oil well
Producing
FEE 84X
51030755400
Water / Gas Inject
Injecting
FEE 85X
51030758100
Water / Gas Inject
Injecting
FEE 86X
51030756900
Water Injection Well
P&A
50
-------
FEE 86XST
51030756901
Water / Gas Inject
Injecting
FEE 87X
51030754600
Water / Gas Inject
Monitor
FEE 88X
51030755900
Water / Gas Inject
Injecting
FEE 89X
51030755500
Water / Gas Inject
Injecting
FEE 9
51030551100
Oil well
P&A
FEE 90X
51030758000
Water / Gas Inject
Injecting
FEE 91X
51030757300
Water / Gas Inject
Injecting
FEE 92X
51030755600
Water / Gas Inject
Monitor
FEE 93X
51030759100
Water / Gas Inject
Injecting
FEE 94X
51030759400
Water / Gas Inject
Injecting
FEE 95X
51030764700
Oil well
Producing
FEE 96X
51030764800
Oil well
Producing
FEE 97X
51030779100
Oil well
Producing
FEE 98X
51030782700
Water / Gas Inject
Injecting
FEE 99X
51030784000
Oil well
Producing
FEE 9ST 9
51030551101
Oil well
Producing
GRAY A A17X
51030768900
Water / Gas Inject
Injecting
GRAY A A21X
51030830200
Water / Gas Inject
Injecting
GRAY A A8AX
51030919700
Water / Gas Inject
Injecting
GRAY A10
51030573400
Water / Gas Inject
Injecting
GRAY A12
51030613700
Oil well
Producing
GRAY A13
51030577800
Water / Gas Inject
Monitor
GRAY A14
51030613900
Oil well
Producing
GRAY A15
51030576200
Oil well
Producing
GRAY A16
51030613600
Water / Gas Inject
Injecting
GRAY A18X
51030789800
Oil well
Producing
GRAY A19X
51030787300
Oil well
Producing
GRAY A20X
51030803500
Water / Gas Inject
Injecting
GRAY A22X
51030831700
Oil well
Producing
GRAY A9
51030571500
Oil well
Producing
GRAY B10
51030612300
Water / Gas Inject
Injecting
GRAY B11
51030581800
Oil well
Producing
GRAY B12
51030612900
Oil well
Producing
GRAY B13
51030612600
Oil well
Producing
GRAY B14A
51030928900
Water / Gas Inject
Injecting
GRAY B15
51030579600
Oil well
Producing
GRAY B16
51030612700
Oil well
Producing
GRAY B17
51030582500
Oil well
Monitor
GRAY B18X
51030638600
Oil well
Monitor
GRAY B19X
51036639700
Oil well
Producing
GRAY B2
51030578700
Oil well
Producing
51
-------
GRAY B20X
51030101500
Water / Gas Inject
Injecting
GRAY B21X
51031035700
Oil well
Producing
GRAY B22X
51031036000
Oil well
Producing
GRAY B23X
51031033800
Oil well
Producing
GRAY B24X
51031033700
Oil well
Producing
GRAY B25X
51031057200
Oil well
Producing
GRAY B26X
51031057500
Oil well
Producing
GRAY B27X
51031057400
Oil well
Producing
GRAY B28X
51031101200
Oil well
Producing
GRAY B3
51030613200
Water / Gas Inject
Injecting
GRAY B4
51030613300
Water / Gas Inject
Injecting
GRAY B5
51030612400
Water / Gas Inject
Injecting
GRAY B6
51030613100
Water / Gas Inject
Injecting
GRAY B7
51030612800
Water / Gas Inject
Injecting
GRAY B8
51030581100
Water / Gas Inject
Injecting
GRAY B9
51030612500
Water / Gas Inject
Injecting
GUIBERSON SA 1
51030581300
Water / Gas Inject
Injecting
GUIBERSON SA 5 X
51031115600
Oil well
Producing
HAGOOD L N-A 17X
51030914200
Oil well
P&A
HAGOOD LN A1 OX
51030791300
Oil well
Shut In
HAGOOD LN A11X
51030794900
Water / Gas Inject
Injecting
HAGOOD LN A12X
51030793600
Oil well
Producing
HAGOOD LN A13X
51030799100
Water / Gas Inject
Injecting
HAGOOD LN A14X
51030795000
Water / Gas Inject
P&A
HAGOOD LN A14XST
51030795001
Water / Gas Inject
Injecting
HAGOOD LN A15X
51030829300
Oil well
Producing
HAGOOD LN A16X
51030830000
Water / Gas Inject
Injecting
HAGOOD LN A17XST
51030914201
Water / Gas Inject
Monitor
HAGOOD LN A2
51030574300
Oil well
Monitor
HAGOOD LN A3
51030576800
Oil well
Monitor
HAGOOD LN A5
51030573600
Water / Gas Inject
Injecting
HAGOOD LN A7
51030575700
Water / Gas Inject
Monitor
HAGOOD LN A9X
51030702200
Water / Gas Inject
Injecting
HAGOOD MC A1
51030632800
Water / Gas Inject
Injecting
HAGOOD MC A10X
51031041400
Oil well
Producing
HAGOOD MC A11X
51031041300
Oil well
Producing
HAGOOD MC A12X
51031053300
Oil well
Producing
HAGOOD MC A13X
51031053100
Oil well
Producing
HAGOOD MC A14X
51031054800
Oil well
Shut In
HAGOOD MC A15X
51031062800
Oil well
Producing
HAGOOD MC A16X
51031061200
Oil well
Producing
52
-------
HAGOOD MC A17X
51031062900
Oil well
Producing
HAGOOD MC A18X
51031061300
Oil well
Producing
HAGOOD MC A19X
51031067000
Water / Gas Inject
Injecting
HAGOOD MC A2
51030102300
Oil well
Producing
HAGOOD MC A21X
51031070900
Oil well
Producing
HAGOOD MC A3
51030633000
Water / Gas Inject
Injecting
HAGOOD MC A4
51030632600
Water / Gas Inject
Injecting
HAGOOD MC A5
51030633100
Water / Gas Inject
Injecting
HAGOOD MC A6
51030102400
Oil well
Producing
HAGOOD MC A7
51030106700
Oil well
Producing
HAGOOD MC A8 A 8
51030632500
Water / Gas Inject
Injecting
HAGOOD MC A9
51030632700
Water / Gas Inject
Injecting
HAGOOD MC B1A
51031102800
Oil well
Producing
HAGOOD MC B2
51031187000
Oil well
Producing
HEFLEY CS 4X
51030856200
Oil well
Producing
HEFLEY ME 2
51030545200
Water / Gas Inject
Monitor
HEFLEY ME 5X
51030719600
Oil well
Producing
HEFLEY ME 6X
51030729300
Oil well
Producing
HEFLEY ME 7X
51030873700
Oil well
Producing
HEFLEY ME 8X
51030869600
Oil well
Producing
L N HAGOOD A- 1
51030572100
Water / Gas Inject
Injecting
L N HAGOOD A-8 IJ A8
51030569100
Water / Gas Inject
Injecting
LACY SB 1
51030573200
Oil well
Producing
LACY SB 11Y
51030914400
Salt Water Disposal
Injecting
LACY SB 12Y
51030914500
Oil well
Producing
LACY SB 13Y
51031057000
Oil well
Producing
LACY SB 2AX
51030928200
Water / Gas Inject
Injecting
LACY SB 3
51030568900
Oil well
Producing
LACY SB 4
51030575800
Water / Gas Inject
Monitor
LACY SB 6X
51030794700
Oil well
Monitor
LACY SB 7X
51030797800
Water / Gas Inject
Injecting
LACY SB 9X
51030831800
Oil well
Monitor
LARSON FA 1
51030106600
Oil well
Producing
LARSON FA 2
51030107200
Water / Gas Inject
Injecting
LARSON FA 3X
51031071000
Oil well
Monitor
LARSON FVA1
51030547600
Oil well
Producing
LARSON FV A2X
51030721600
Water / Gas Inject
Monitor
LARSON FVB11
51030630200
Water / Gas Inject
Injecting
LARSON FVB12
51030100900
Oil well
Producing
LARSON FV B14X
51030641400
Oil well
Shut In
LARSON FV B15X
51030700800
Oil well
Producing
53
-------
LARSON FV B17X
51030707800
Oil well
Producing
LARSON FV B18X
51030708300
Oil well
Producing
LARSON FV B19X
51030710600
Oil well
Producing
LARSON FV B2
51030620200
Water / Gas Inject
Monitor
LARSON FV B20X
51030709900
Oil well
Producing
LARSON FVB21X
51030716500
Oil well
Producing
LARSON FV B22X
51030722700
Oil well
Producing
LARSON FV B23X
51030724200
Oil well
Producing
LARSON FV B24X
51030873800
Oil well
Producing
LARSON FV B25X
51030916500
Oil well
Producing
LARSON FV B27X
51030948800
Oil well
Producing
LARSON FV B4
51030629800
Water / Gas Inject
Injecting
LARSON FV B8
51030620100
Water / Gas Inject
Injecting
LARSON MB 10X25
51030715900
Oil well
Producing
LARSON MB 12X25
51030727000
Oil well
Producing
LARSON MB 2-26 A226
51030566300
Oil well
Producing
LARSON MB 3X26
51030711000
Oil well
Producing
LARSON MB 4X26
51030717700
Oil well
Monitor
LARSON MB 8X25
51030709300
Oil well
Producing
LARSON MB A1AX
51031075600
Water / Gas Inject
Monitor
LARSON MB A2
51030633200
Oil well
Producing
LARSON MB A3X
51031053400
Oil well
Producing
LARSON MB A4X
51031055200
Oil well
Producing
LARSON MB B1
51030576500
Water / Gas Inject
Injecting
LARSON MB B3AX
51031075500
Water / Gas Inject
Injecting
LARSON MB C1-25
51030618600
Water / Gas Inject
Monitor
LARSON MBC1AX
51031076300
Oil well
Producing
LARSON MB C2
51030569000
Water / Gas Inject
Injecting
LARSON MB C3
51030570800
Water / Gas Inject
Injecting
LARSON MB C3-25
51030618700
Water / Gas Inject
Injecting
LARSON MB C4
51031139700
Oil well
Producing
LARSON MB C5
51031142900
Oil well
Producing
LARSON MB C9X25
51030715500
Oil well
Producing
LARSON MB D1-26E
51030620000
Water / Gas Inject
Injecting
LEVI SON 10
51030621700
Oil well
Producing
LEVI SON 11
51030619800
Water / Gas Inject
Injecting
LEVI SON 12
51030103100
Water / Gas Inject
Injecting
LEVI SON 13
51030619400
Water / Gas Inject
Injecting
LEVI SON 14
51030619900
Water / Gas Inject
Injecting
LEVI SON 17
51030619500
Water / Gas Inject
Injecting
LEVI SON 18
51030618200
Oil well
Producing
54
-------
LEVISON 2
51030559300
Oil well
Producing
LEVI SON 21X
51030638700
Oil well
Producing
LEVISON 22X
51030708900
Oil well
Monitor
LEVISON 23X
51030712300
Oil well
Producing
LEVISON 24X
51030711400
Oil well
Producing
LEVISON 25X
51030722200
Oil well
Producing
LEVISON 26X
51030726700
Oil well
Producing
LEVISON 27X
51030728900
Oil well
Producing
LEVISON 28X
51030731600
Oil well
Monitor
LEVISON 29X
51030732000
Water / Gas Inject
Injecting
LEVISON 30X
51030735100
Water / Gas Inject
Injecting
LEVISON 31X
51030735300
Oil well
Monitor
LEVISON 32X
51030747500
Water / Gas Inject
Injecting
LEVISON 33X
51030752100
Oil well
Producing
LEVISON 34X
51030758600
Water / Gas Inject
Injecting
LEVISON 35X
51030868300
Oil well
Producing
LEVISON 6
51030106200
Oil well
Producing
LEVISON 7
51030619700
Oil well
Monitor
LEVISON 8
51030103000
Water / Gas Inject
Injecting
LEVISON 9
51030628600
Water / Gas Inject
Injecting
LEVSION 1
51030559100
Oil well
Producing
LN - HAGOOD A6
51030569400
Oil well
Producing
LN HAGOOD A-4
51030570700
Oil well
Shut In
MAGOR1A
51030989300
Water / Gas Inject
Injecting
MATTERN 1
51030580400
Water / Gas Inject
Injecting
MCLAUGHLIN AC 1
51030573100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 10
51030578000
Oil well
Monitor
MCLAUGHLIN AC 11
51030569300
Oil well
Producing
MCLAUGHLIN AC 12
51030579800
Water / Gas Inject
Injecting
MCLAUGHLIN AC 13
51030581000
Water / Gas Inject
Injecting
MCLAUGHLIN AC 14
51030105800
Oil well
Producing
MCLAUGHLIN AC 15
51030576700
Oil well
Producing
MCLAUGHLIN AC 16
51030105400
Oil well
Producing
MCLAUGHLIN AC 17
51030631700
Water / Gas Inject
Injecting
MCLAUGHLIN AC 18
51030105300
Water / Gas Inject
Injecting
MCLAUGHLIN AC 19
51030579400
Oil well
Producing
MCLAUGHLIN AC 2
51030573300
Oil well
Producing
MCLAUGHLIN AC 20
51030578200
Water / Gas Inject
Injecting
MCLAUGHLIN AC 21
51030578100
Oil well
Producing
MCLAUGHLIN AC 22
51030105500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 23
51030571800
Water / Gas Inject
Injecting
55
-------
MCLAUGHLIN AC 24
51030576300
Water / Gas Inject
Injecting
MCLAUGHLIN AC 25
51030631800
Oil well
Producing
MCLAUGHLIN AC 26
51030105000
Water / Gas Inject
Injecting
MCLAUGHLIN AC 27
51036005300
Oil well
Producing
MCLAUGHLIN AC 28
51030569900
Oil well
Producing
MCLAUGHLIN AC 29
51030581900
Oil well
Producing
MCLAUGHLIN AC 30
51030105100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 31
51030105200
Water / Gas Inject
Injecting
MCLAUGHLIN AC 32
51030581200
Water / Gas Inject
Injecting
MCLAUGHLIN AC 33
51030631500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 34
51030104700
Water / Gas Inject
Injecting
MCLAUGHLIN AC 35
51030581700
Oil well
Producing
MCLAUGHLIN AC 36
51030104800
Oil well
Producing
MCLAUGHLIN AC 37
51030633300
Oil well
Producing
MCLAUGHLIN AC 38
51030632200
Oil well
Producing
MCLAUGHLIN AC 39A
51031049300
Oil well
Producing
MCLAUGHLIN AC 3AX
51030920700
Water / Gas Inject
Injecting
MCLAUGHLIN AC 4
51030573800
Oil well
Producing
MCLAUGHLIN AC 41AX
51030920100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 42
51030579500
Water / Gas Inject
Monitor
MCLAUGHLIN AC 43
51030632400
Water / Gas Inject
Injecting
MCLAUGHLIN AC 44A
51031096100
Oil well
Producing
MCLAUGHLIN AC 44D
51030631600
Salt Water Disposal
Injecting
MCLAUGHLIN AC 45 AC
51030631900
Water / Gas Inject
Injecting
MCLAUGHLIN AC 46ST
51030632301
Water / Gas Inject
Monitor
MCLAUGHLIN AC 47X
51030107500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 49X
51030641700
Oil well
Monitor
MCLAUGHLIN AC 5
51030571200
Oil well
Monitor
MCLAUGHLIN AC 50X
51030632100
Oil well
Producing
MCLAUGHLIN AC 51X
51030641800
Oil well
Producing
MCLAUGHLIN AC 52X
51030642500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 53X
51030101400
Oil well
Producing
MCLAUGHLIN AC 54X
51030642600
Oil well
Producing
MCLAUGHLIN AC 55X
51030641900
Water / Gas Inject
Injecting
MCLAUGHLIN AC 56X
51030642000
Water / Gas Inject
Injecting
MCLAUGHLIN AC 57X
51030701000
Oil well
Monitor
MCLAUGHLIN AC 58X
51030701400
Oil well
Producing
MCLAUGHLIN AC 59AX
51030928800
Oil well
Producing
MCLAUGHLIN AC 6
51030579900
Oil well
Producing
MCLAUGHLIN AC 60X
51030769200
Water / Gas Inject
Injecting
MCLAUGHLIN AC 61X
51030769000
Oil well
Monitor
56
-------
MCLAUGHLIN AC 62X
51030771500
Oil well
Producing
MCLAUGHLIN AC 63X
51030771600
Water / Gas Inject
Injecting
MCLAUGHLIN AC 65X
51030771800
Oil well
Producing
MCLAUGHLIN AC 66X
51030773800
Water / Gas Inject
Injecting
MCLAUGHLIN AC 67X
51030817000
Oil well
Producing
MCLAUGHLIN AC 68X
51030829200
Oil well
Producing
MCLAUGHLIN AC 69X
51030829400
Water / Gas Inject
Injecting
MCLAUGHLIN AC 7
51030580900
Water / Gas Inject
Injecting
MCLAUGHLIN AC 70X
51030830100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 71X
51030829700
Oil well
Producing
MCLAUGHLIN AC 72X
51030832000
Water / Gas Inject
Injecting
MCLAUGHLIN AC 73X
51030831900
Oil well
Producing
MCLAUGHLIN AC 74X
51030832100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 75X
51030829800
Oil well
Producing
MCLAUGHLIN AC 76X
51030914100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 77X
51030915200
Oil well
Producing
MCLAUGHLIN AC 78X
51030915500
Oil well
Producing
MCLAUGHLIN AC 79X
51030930000
Oil well
Monitor
MCLAUGHLIN AC 8
51030573500
Oil well
Producing
MCLAUGHLIN AC 80X
51030930100
Oil well
Monitor
MCLAUGHLIN AC 81AX
51031064500
Oil well
Producing
MCLAUGHLIN AC 82X
51031054600
Oil well
Producing
MCLAUGHLIN AC 83X
51031059500
Oil well
Producing
MCLAUGHLIN AC 84Y
51031057300
Oil well
Producing
MCLAUGHLIN AC 86Y
51031058400
Oil well
Producing
MCLAUGHLIN AC 88X
51031070000
Oil well
Producing
MCLAUGHLIN AC 9
51030576600
Oil well
Monitor
MCLAUGHLIN AC 90X
51031069900
Oil well
Producing
MCLAUGHLIN AC 91X
51031072600
Water / Gas Inject
Injecting
MCLAUGHLIN AC 92X
51031070800
Oil well
Producing
MCLAUGHLIN AC 93X
51031072700
Water / Gas Inject
Injecting
MCLAUGHLIN AC 94X
51031072500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 95X
51031140800
Oil well
Producing
MCLAUGHLIN AC A1
51030609200
Oil well
Monitor
MCLAUGHLIN AC A3X
51030863000
Oil well
Producing
MCLAUGHLIN AC C2
51031104100
Oil well
Monitor
MCLAUGHLIN SW6
51030627800
Oil well
P&A
MCLAUGHLIN SHARPLES 10X28
51030749000
Oil well
Producing
MCLAUGHLIN SHARPLES 1-28
51030560300
Water / Gas Inject
Injecting
MCLAUGHLIN SHARPLES 12X33
51030759800
Oil well
Producing
MCLAUGHLIN SHARPLES 1-33
51030551300
Oil well
Producing
57
-------
MCLAUGHLIN SHARPLES 13X3
51030873900
Oil well
Producing
MCLAUGHLIN SHARPLES 14Y33
51030912300
Oil well
Producing
MCLAUGHLIN SHARPLES 15X32
51030885400
Oil well
Producing
MCLAUGHLIN SHARPLES 16X32
51030913200
Water / Gas Inject
Injecting
MCLAUGHLIN SHARPLES 2-28
51030560000
Oil well
Producing
MCLAUGHLIN SHARPLES 2-32
51030627300
Water / Gas Inject
Monitor
MCLAUGHLIN SHARPLES 2-33
51030106800
Water / Gas Inject
Injecting
MCLAUGHLIN SHARPLES 3-32
51030627000
Oil well
Monitor
MCLAUGHLIN SHARPLES 3-33
51030629000
Oil well
Producing
MCLAUGHLIN SHARPLES 4-33
51030629100
Water / Gas Inject
Injecting
MCLAUGHLIN SHARPLES 5-33
51030104500
Oil well
Monitor
MCLAUGHLIN SHARPLES 6-33
51030628800
Oil well
Monitor
MCLAUGHLIN SHARPLES 7-33
51030104600
Water / Gas Inject
Monitor
MCLAUGHLIN SHARPLES 8-33
51030628900
Water / Gas Inject
Monitor
MCLAUGHLIN SHARPLES 9X33
51030746500
Oil well
Producing
MCLAUGHLIN SW11X
51030759700
Water / Gas Inject
Injecting
MCLAUGHLIN SW12X
51030760100
Water / Gas Inject
Injecting
MCLAUGHLIN SW 1ST
51030548300
Oil well
P&A
MCLAUGHLIN SW 1 ST 1
51030548301
Water / Gas Inject
Monitor
MCLAUGHLIN SW2
51030627700
Oil well
Producing
MCLAUGHLIN SW 3
51030104400
Water / Gas Inject
Injecting
MCLAUGHLIN SW4
51030107600
Oil well
Producing
MCLAUGHLIN SW 5
51030627900
Oil well
Producing
MCLAUGHLIN SW6ST
51030627801
Water / Gas Inject
Injecting
MCLAUGHLIN SW7X
51030746100
Oil well
Producing
MCLAUGHLIN SW8X
51030753000
Water / Gas Inject
Injecting
MCLAUGHLIN UNIT A1
51030581600
Oil well
Producing
MCLAUGHLIN UNIT B1
51030582600
Oil well
Producing
MCLAUGHLIN UNIT B2X
51031057600
Water / Gas Inject
Injecting
MELLEN 3A
51031098100
Oil well
Producing
MELLEN WP 1
51036000300
Water / Gas Inject
Injecting
MELLEN WP 2
51030105600
Water / Gas Inject
Injecting
NEAL 2AX
51030920800
Water / Gas Inject
Injecting
NEAL4
51030565500
Water / Gas Inject
Injecting
NEAL 5A
51030565900
Oil well
Producing
NEAL 6X
51030790600
Oil well
Producing
NEAL 7X
51030804200
Water / Gas Inject
Injecting
NEAL 8X
51030804300
Water / Gas Inject
P&A
NEAL 8XST
51030804301
Water / Gas Inject
Injecting
NEAL 9Y
51030912000
Oil well
Producing
NEWTON ASSOC UNIT D2X
51030868500
Oil well
Monitor
58
-------
NIKKEL 3
51030619200
Water / Gas Inject
Injecting
PURDY 1-1
51030545300
Water / Gas Inject
Monitor
PURDY 2X1
51030881000
Oil well
Producing
RAVEN A1AX
51030917800
Water / Gas Inject
Injecting
RAVEN A2
51030625700
Water / Gas Inject
Injecting
RAVEN A3
51030624400
Water / Gas Inject
Injecting
RAVEN A4
51030625800
Water / Gas Inject
Injecting
RAVEN A5X
51030718800
Oil well
Producing
RAVEN B1
51030564900
Oil well
Producing
RAVEN B2AX
51030923800
Water / Gas Inject
Monitor
RECTOR 1
51030549400
Oil well
Producing
RECTOR 11X
51030867200
Oil well
Shut In
RECTOR 12X
51030919900
Oil well
Shut In
RECTOR 3
51030106000
Water / Gas Inject
Injecting
RECTOR 8X
51030704300
Oil well
Producing
RECTOR 9X
51030714700
Oil well
Shut In
RIGBY 1
51030569700
Oil well
Producing
RIGBY 5X
51030804700
Water / Gas Inject
Injecting
RIGBY 6Y
51030910700
Oil well
Producing
RIGBY A2AX
51030920000
Water / Gas Inject
Injecting
RIGBY A3X
51030791000
Oil well
Producing
RIGBY A4X
51030791100
Oil well
Monitor
RIGBY A7Y
51030915100
Oil well
Monitor
ROOTH DF 1
51030579700
Water / Gas Inject
Injecting
ROOTH DF 5 X
51031143000
Oil well
Producing
ROOTH DF 6 X
51031125000
Oil well
Producing
S B LACY 3
51030568900
Oil well
Monitor
STOFFER CR A1
51030562700
Water / Gas Inject
Injecting
STOFFER CR A2
51030559200
Water / Gas Inject
Injecting
STOFFER CR B1
51030567300
Oil well
Producing
SW MCLAUGHLIN 10X
51030754700
Oil well
Producing
SW MCLAUGHLIN 9X
51030753500
Oil well
Producing
U P 4829
51030623100
Water / Gas Inject
P&A
UNION PACIFIC 1 150X 16
51031150200
Oil well
Producing
UNION PACIFIC 1 151X 16
51031150100
Oil well
Producing
UNION PACIFIC 1 153X 16
51031146401
Water / Gas Inject
Injecting
UNION PACIFIC 100X20
51030788600
Oil well
Producing
UNION PACIFIC 101X20
51030797300
Oil well
Monitor
UNION PACIFIC 10-21
51030568501
Oil well
Monitor
UNION PACIFIC 102X20
51030797700
Water / Gas Inject
Injecting
UNION PACIFIC 103X20
51030799000
Water / Gas Inject
Injecting
59
-------
UNION PACIFIC 104X20
51030803000
Water / Gas Inject
Injecting
UNION PACIFIC 105X29
51030794500
Oil well
Producing
UNION PACIFIC 106X32
51030845000
Oil well
Producing
UNION PACIFIC 107X32
51030849800
Oil well
Producing
UNION PACIFIC 108X21
51030849500
Water / Gas Inject
Injecting
UNION PACIFIC 109X32
51030849700
Oil well
Producing
UNION PACIFIC 110X21
51030853000
Water / Gas Inject
Injecting
UNION PACIFIC 111X29
51030852200
Oil well
Producing
UNION PACIFIC 11-21
51030616200
Oil well
Producing
UNION PACIFIC 112X21
51030873500
Oil well
Monitor
UNION PACIFIC 113X22
51030860600
Oil well
Monitor
UNION PACIFIC 115X21
51030866600
Oil well
Producing
UNION PACIFIC 117X22
51030866700
Oil well
Producing
UNION PACIFIC 118X21
51030869700
Oil well
Producing
UNION PACIFIC 119X21
51030869800
Oil well
Producing
UNION PACIFIC 120X21
51030869900
Oil well
Producing
UNION PACIFIC 12-27
51030620400
Oil well
Producing
UNION PACIFIC 122X21
51030870000
Oil well
Monitor
UNION PACIFIC 126X32
51030885100
Oil well
Producing
UNION PACIFIC 127X31
51030884700
Oil well
Producing
UNION PACIFIC 128X31
51030910000
Oil well
Producing
UNION PACIFIC 129X31
51030885200
Oil well
Producing
UNION PACIFIC 130X32
51030885300
Oil well
Producing
UNION PACIFIC 131X32
51030885500
Oil well
Producing
UNION PACIFIC 1-32
51030556700
Water / Gas Inject
Injecting
UNION PACIFIC 13-28
51030622000
Water / Gas Inject
Injecting
UNION PACIFIC 132X21
51030874600
Oil well
Monitor
UNION PACIFIC 133X21
51030876400
Oil well
Producing
UNION PACIFIC 134X21
51030904100
Water / Gas Inject
Injecting
UNION PACIFIC 135Y28
51030910500
Oil well
Monitor
UNION PACIFIC 136X20
51030913800
Oil well
Producing
UNION PACIFIC 137X20
51030913900
Water / Gas Inject
Monitor
UNION PACIFIC 138Y28
51030917300
Oil well
Producing
UNION PACIFIC 139Y28
51030918500
Oil well
Monitor
UNION PACIFIC 140Y27
51030918800
Oil well
Producing
UNION PACIFIC 141Y28
51030918900
Oil well
Producing
UNION PACIFIC 14-20
51030615400
Oil well
Producing
UNION PACIFIC 142Y28
51030919000
Oil well
Monitor
UNION PACIFIC 143Y28
51030918600
Oil well
Monitor
UNION PACIFIC 15-28
51030102900
Oil well
Monitor
UNION PACIFIC 154Y29
51031172000
Oil well
Producing
60
-------
UNION PACIFIC 156Y29
51031172100
Oil well
Producing
UNION PACIFIC 16-27
51030620600
Oil well
Shut In
UNION PACIFIC 17-27
51030621400
Oil well
Producing
UNION PACIFIC 18-21
51030616400
Oil well
Producing
UNION PACIFIC 19-28
51030621900
Water / Gas Inject
Injecting
UNION PACIFIC 20-29
51030622800
Water / Gas Inject
Injecting
UNION PACIFIC 21-32
51030627100
Water / Gas Inject
Monitor
UNION PACIFIC 2-20
51030569200
Oil well
Producing
UNION PACIFIC 22-32
51030627500
Oil well
Producing
UNION PACIFIC 23-32
51030626900
Oil well
Producing
UNION PACIFIC 24-27
51030621200
Water / Gas Inject
Injecting
UNION PACIFIC 25-34
51030106900
Oil well
Shut In
UNION PACIFIC 26-31
51030626100
Water / Gas Inject
Injecting
UNION PACIFIC 27-20
51030577000
Oil well
Monitor
UNION PACIFIC 28-22
51030617300
Oil well
Producing
UNION PACIFIC 29-32
51030548700
Oil well
Monitor
UNION PACIFIC 31-21
51030616600
Oil well
Monitor
UNION PACIFIC 32-27
51030620800
Oil well
Monitor
UNION PACIFIC 33-32
51030626600
Water / Gas Inject
Injecting
UNION PACIFIC 3-34
51030551000
Oil well
Producing
UNION PACIFIC 34-31
51030626300
Water / Gas Inject
Injecting
UNION PACIFIC 35-32
51030626800
Water / Gas Inject
Injecting
UNION PACIFIC 36-32
51030627200
Water / Gas Inject
Injecting
UNION PACIFIC 37AX29
51030917700
Water / Gas Inject
Injecting
UNION PACIFIC 39-17
51030612100
Water / Gas Inject
Injecting
UNION PACIFIC 41-20
51030615800
Water / Gas Inject
Shut In
UNION PACIFIC 4-29
51030563200
Water / Gas Inject
Injecting
UNION PACIFIC 42AX28
51030925700
Water / Gas Inject
Injecting
UNION PACIFIC 43-28
51030622100
Water / Gas Inject
Monitor
UNION PACIFIC 44AX20
51030923300
Water / Gas Inject
Injecting
UNION PACIFIC 45-21
51030569600
Water / Gas Inject
Injecting
UNION PACIFIC 47-21
51030615900
Water / Gas Inject
Injecting
UNION PACIFIC 48-29ST
51030623101
Water / Gas Inject
Injecting
UNION PACIFIC 49-27
51030621300
Oil well
Producing
UNION PACIFIC 50-29
51030107100
Water / Gas Inject
Injecting
UNION PACIFIC 51AX20
51030892800
Water / Gas Inject
Injecting
UNION PACIFIC 5-28
51030563900
Oil well
Producing
UNION PACIFIC 52A-29
51030928400
Water / Gas Inject
Injecting
UNION PACIFIC 53-32
51030627600
Water / Gas Inject
Monitor
UNION PACIFIC 54-21
51030616300
Water / Gas Inject
Injecting
UNION PACIFIC 55-17
51030612200
Water / Gas Inject
Injecting
61
-------
UNION PACIFIC 56-21
51030616700
Water / Gas Inject
Injecting
UNION PACIFIC 58-27
51030620500
Water / Gas Inject
Injecting
UNION PACIFIC 59A-27
51031120700
Oil well
Producing
UNION PACIFIC 60-31
51030626200
Water / Gas Inject
Injecting
UNION PACIFIC 61-20
51030615500
Water / Gas Inject
Injecting
UNION PACIFIC 6-21
51030574100
Oil well
Producing
UNION PACIFIC 62AX32
51030919600
Water / Gas Inject
Injecting
UNION PACIFIC 65-5
51030608900
Water / Gas Inject
Monitor
UNION PACIFIC 67-32
51030626700
Water / Gas Inject
Injecting
UNION PACIFIC 68-32
51030628700
Water / Gas Inject
Injecting
UNION PACIFIC 69-27
51030621000
Oil well
Shut In
UNION PACIFIC 71X31
51030727600
Oil well
Producing
UNION PACIFIC 7-29
51030559700
Water / Gas Inject
Injecting
UNION PACIFIC 73X29
51030738600
Oil well
Producing
UNION PACIFIC 74X27
51030741600
Oil well
Monitor
UNION PACIFIC 75X32
51030740200
Oil well
Producing
UNION PACIFIC 76X21
51030742100
Oil well
Producing
UNION PACIFIC 77X32
51030745400
Oil well
Producing
UNION PACIFIC 78X21
51030742600
Water / Gas Inject
Injecting
UNION PACIFIC 79X32
51030744800
Oil well
Monitor
UNION PACIFIC 80X28
51030746000
Water / Gas Inject
Monitor
UNION PACIFIC 81X29
51030749900
Oil well
Producing
UNION PACIFIC 8-20
51030568600
Oil well
Producing
UNION PACIFIC 82X28
51030749400
Oil well
Producing
UNION PACIFIC 83X28
51030750000
Oil well
Producing
UNION PACIFIC 84X28
51030749500
Oil well
Producing
UNION PACIFIC 85X34
51030748100
Water / Gas Inject
Injecting
UNION PACIFIC 86X27
51030748200
Water / Gas Inject
Injecting
UNION PACIFIC 87X29
51030750900
Oil well
Producing
UNION PACIFIC 88X21
51030751400
Oil well
Producing
UNION PACIFIC 89X34
51030754800
Water / Gas Inject
Injecting
UNION PACIFIC 91X28
51030756000
Water / Gas Inject
Injecting
UNION PACIFIC 9-29
51030565600
Water / Gas Inject
Injecting
UNION PACIFIC 92X28
51030757400
Water / Gas Inject
Monitor
UNION PACIFIC 94X27
51030758800
Water / Gas Inject
Injecting
UNION PACIFIC 96X29
51030765000
Oil well
Producing
UNION PACIFIC 97X29
51030765100
Oil well
Producing
UNION PACIFIC 98X32
51030765200
Oil well
Producing
UNION PACIFIC 99X29
51030785600
Oil well
Producing
UNION PACIFIC B1-34
51030548900
Water / Gas Inject
Monitor
UNION PACIFIC B2-34
51030102700
Oil well
Monitor
62
-------
UNION PACIFIC B3X34
51030744000
Oil well
Producing
UNION PACIFIC B4X34
51030753600
Water / Gas Inject
Injecting
UNION PACIFIC B5X34
51030759900
Water / Gas Inject
Injecting
UNION PACIFIC B6X34
51030760200
Water / Gas Inject
Monitor
WALBRIDGE LB 1
51030607000
Water / Gas Inject
Monitor
WALBRIDGE UNIT 1
51030607200
Water / Gas Inject
Monitor
WALBRIDGE UNIT 2X
51030920500
Oil well
Producing
WALBRIDGE UNIT 3X
51030920600
Oil well
Monitor
WEYRAUCH 2-36
51030630600
Water / Gas Inject
Injecting
WEYRAUCH 4X36
51030707200
Oil well
Producing
WEYRAUCH 5X36
51030881900
Oil well
Producing
WEYRAUCH 6X36
51030916600
Oil well
Producing
WEYRAUCH 7X36
51030916300
Oil well
Producing
AC MCLAUGHLIN 39
51030582400
P&A
P&A
AC MCLAUGHLIN 3
51030578600
P&A
P&A
MCLAUGHLIN AC 40
51030632000
P&A
P&A
AC MCLAUGHLIN 41
51030575900
P&A
P&A
AC MCLAUGHLIN 48X
51030580300
P&A
P&A
AC MCLAUGHLIN 59X
51030769100
P&A
P&A
MCLAUGHLIN AC 81X
51031053000
P&A
P&A
A.C. MCLAUGHLIN A A2
51030609300
P&A
P&A
AC MCLAUGHLIN B 1
51030611000
P&A
P&A
AC MCLAUGHLIN B 2
51030610500
P&A
P&A
AC MCLAUGHLIN 1
51030612000
P&A
P&A
AC MCLAUGHLIN 1
51030757700
P&A
P&A
ASSOCIATED 4X
51030881200
P&A
P&A
ASSOCIATED B 1
51030601200
P&A
P&A
ASSOCIATED B 2
51030601000
P&A
P&A
ASSOCIATED B 3
51030601300
P&A
P&A
BEEZLEY 1 22
51030573900
P&A
P&A
CT CARNEY 12-5
51030107000
P&A
P&A
C T CARNEY 26X35
51030745000
P&A
P&A
CARNEY CT 31X4
51030760400
P&A
P&A
CARNEY C T 34X-4
51030760000
P&A
P&A
CARNEY CT 36X34
51030759500
P&A
P&A
CARNEY CT 40X35
51030911700
P&A
P&A
CARNEY CT 42Y34
51030915400
P&A
P&A
CHASE UNIT U 1
51030600800
P&A
P&A
HILL.C.E. 1
51030601800
P&A
P&A
HEFLEY C-S 1
51030104100
P&A
P&A
C-S HEFLEY 2
51030607700
P&A
P&A
63
-------
C-S HEFLEY 3
51030607800
P&A
P&A
C R STOFFER A 3
51030562600
P&A
P&A
EMERALD 12
51030566700
P&A
P&A
EMERALD 15
51030565400
P&A
P&A
EMERALD 18
51030104900
P&A
P&A
EMERALD 21
51030546400
P&A
P&A
EMERALD 24
51030563500
P&A
P&A
EMERALD 29
51030565800
P&A
P&A
EMERALD 30
51030563000
P&A
P&A
EMERALD 31
51030623700
P&A
P&A
EMERALD 33
51030623900
P&A
P&A
EMERALD OIL CO. 3M
51030724700
P&A
P&A
EMERALD 43
51030625200
P&A
P&A
EMERALD 44
51030633800
P&A
P&A
EMERALD 45
51030603000
P&A
P&A
EMERALD 49X
51030729600
P&A
P&A
EMERALD 5
51030566600
P&A
P&A
EMERALD 7
51030624100
P&A
P&A
E OLDLAND 4
51030715200
P&A
P&A
FAIRFIELD,KITTIE A 2
51030611400
P&A
P&A
FAIRFIELD,KITTIE A 3
51030611700
P&A
P&A
F V LARSON 116
51036652500
P&A
P&A
FEE 118X
51030843900
P&A
P&A
FEE 119X
51030849400
P&A
P&A
FEE 161X
51031185900
P&A
P&A
FEE 16
51030624600
P&A
P&A
FEE 2
51030558600
P&A
P&A
FEE 46
51030610700
P&A
P&A
FEE 53
51030617400
P&A
P&A
FEE 54
51030618000
P&A
P&A
FEE 57
51030622700
P&A
P&A
FEE 58
51030614300
P&A
P&A
FEE 66
51030610900
P&A
P&A
FEE 67
51030611600
P&A
P&A
FEE 70
51030626000
P&A
P&A
FEE 71
51030610800
P&A
P&A
FEE 77X
51030736000
P&A
P&A
FEDERAL ET AL 2M
51030719700
P&A
P&A
FEDERAL ET AL 5M
51030731700
P&A
P&A
LARSON FVB10
51030629900
P&A
P&A
LARSON FV B13X
51030557900
P&A
P&A
64
-------
LARSON FV B16X
51030702400
P&A
P&A
LARSON FV B1
51030629600
P&A
P&A
LARSON FV 26Y
51030948500
P&A
P&A
LARSON FV B3
51030630500
P&A
P&A
LARSON FV B5
51030630100
P&A
P&A
LARSON FV B6
51030630300
P&A
P&A
LARSON F V B7
51030630001
P&A
P&A
LARSON FV B9
51030102500
P&A
P&A
F V LARSON 1
51030539800
P&A
P&A
GENTRY 2D
51030543700
P&A
P&A
GENTRY 3D
51030608500
P&A
P&A
NEWTON 4-D
51030104300
P&A
P&A
GENTRY 4D
51030543700
P&A
P&A
GENTRY 5D
51030608300
P&A
P&A
GENTRY 6X
51030744200
P&A
P&A
GRAY A 11
51030613800
P&A
P&A
GRAY A 11 AX
51030927500
P&A
P&A
GRAY A 8
51030568100
P&A
P&A
GRAY B 14
51030613000
P&A
P&A
GUIBERSON,S.A. A 2
51030613400
P&A
P&A
HILDENBRANDT 1
51030608100
P&A
P&A
COLTHARP JE 1
51030602400
P&A
P&A
J E COLTHARP 3
51030602500
P&A
P&A
COLTHARP JE 6X
51030714800
P&A
P&A
COLTHARP JE 9X P 9X
51030853500
P&A
P&A
PEPPER,J.E. A 1
51030550200
P&A
P&A
J E PEPPER B 1
51030606300
P&A
P&A
LACY SB 10Y
51030914300
P&A
P&A
S B LACY 2
51030570600
P&A
P&A
F V LARSON 1
51030106500
P&A
P&A
LEVI SON 15
51030618100
P&A
P&A
LEVI SON 16
51030619600
P&A
P&A
LEVI SON 19
51030106300
P&A
P&A
LEVI SON 20
51030618300
P&A
P&A
LEVISON 3
51030621600
P&A
P&A
LEVISON 4
51030560400
P&A
P&A
LEVISON 5
51030621500
P&A
P&A
L N HAGOOD B 1
51030607300
P&A
P&A
L N HAGOOD B 2
51030607100
P&A
P&A
L N HAGOOD B 3
51030607400
P&A
P&A
WALBRIDGE LB 3
51030630800
P&A
P&A
65
-------
WALBRIDGE LB 4X
51030873600
P&A
P&A
WALBRIDGE LB 5Y
51030948300
P&A
P&A
MAGOR 1
51030580800
P&A
P&A
MCLAUGHLIN 3
51030556100
P&A
P&A
MELLEN,W.P. A 3
51030105700
P&A
P&A
HEFLEY ME 1
51030607500
P&A
P&A
HEFLEY ME 3
51030545400
P&A
P&A
HEFLEY ME 4
51030543300
P&A
P&A
M B LARSON C11 X 25
51030717300
P&A
P&A
MB LARSON A 1
51030632900
P&A
P&A
MB LARSON A3
51030576400
P&A
P&A
LARSON MB 1-35
51030555700
P&A
P&A
MB LARSON C 1
51030571900
P&A
P&A
LARSON MB C2-25
51030106400
P&A
P&A
M B LARSON C425
51030618900
P&A
P&A
LARSON MB D136
51030631000
P&A
P&A
LARSON MB D226
51030102600
P&A
P&A
M B LARSON D525
51030618500
P&A
P&A
M B LARSON D625
51030619000
P&A
P&A
M B LARSON D725
51030618400
P&A
P&A
NEAL2
51030566000
P&A
P&A
NEAL3
51030567200
P&A
P&A
NEWTON ASSOC A1
51030107300
P&A
P&A
NEWTON ASSOC B 1
51030101800
P&A
P&A
NEWTON ASSOC C 1
51030102100
P&A
P&A
NEWTON ASSOC D 1
51030102200
P&A
P&A
NIKKEL 1
51030619300
P&A
P&A
NIKKEL 2
51030619100
P&A
P&A
OLDLAND 1
51030102000
P&A
P&A
OLDLAND 2
51030106100
P&A
P&A
OLDLAND 3
51030630400
P&A
P&A
OLDLAND E 5X
51030853600
P&A
P&A
OLDLAND E 6X
51030947600
P&A
P&A
PURDY16
51030606200
P&A
P&A
PURDY 3X1
51030870300
P&A
P&A
RANGELY 2M-33-19B
51030939800
P&A
P&A
RAVEN A 1
51030562900
P&A
P&A
RAVEN B 2
51030624300
P&A
P&A
RECTOR 10X
51030760300
P&A
P&A
RECTOR 2
51030608400
P&A
P&A
RECTOR 4
51030629400
P&A
P&A
66
-------
RECTOR 5
51030629200
P&A
P&A
RECTOR 6
51030608200
P&A
P&A
RECTOR 7
51030105900
P&A
P&A
RIGBY A224
51030570000
P&A
P&A
ROOTH 3
51030564700
P&A
P&A
MCLAUGHLIN SHARPLES 11X 3
51030760500
P&A
P&A
SHARPLES MCLAUGHLIN 132
51030107400
P&A
P&A
SHARPLES MCLAUGHLIN 432
51030627400
P&A
P&A
UNION PACIFIC 121X21
51030870500
P&A
P&A
U P3016
51030578300
P&A
P&A
UNION PACIFIC 37-29
51030623200
P&A
P&A
U P 3822
51030574400
P&A
P&A
U P 4022
51030617800
P&A
P&A
U P 4228
51030621800
P&A
P&A
U P 4420
51030571000
P&A
P&A
UNION PACIFIC 46-21
51030573700
P&A
P&A
U P 5721
51030616500
P&A
P&A
U P 5927
51030620900
P&A
P&A
UNION PACIFIC 62-32
51030626500
P&A
P&A
UNION PACIFIC 63-31
51030623000
P&A
P&A
UNION PACIFIC 63-31
51030626400
P&A
P&A
UNION PACIFIC 63AX31
51030917900
P&A
P&A
U P 6422
51030617200
P&A
P&A
U P6616
51030610600
P&A
P&A
UNION PACIFIC 72X31
51030736400
P&A
P&A
UNION PACIFIC 90X29
51030758200
P&A
P&A
UNION PACIFIC 93X27
51030756100
P&A
P&A
U P 95X 34
51030759600
P&A
P&A
COLTHARP WH A2
51030602000
P&A
P&A
COLTHARP WH A7X
51030869300
P&A
P&A
COLTHARP WH B1
51030101900
P&A
P&A
WEYRAUCH 1-36
51030630700
P&A
P&A
WEYRAUCH 336
51030630900
P&A
P&A
WHITE 1
51030543500
P&A
P&A
WHITE 2
51030545100
P&A
P&A
67
-------
Appendix B: Submissions and Responses to Requests for Additional
Information
-------
Scout Energy Management, LLC
Rangely Field
Subpart RR Monitoring, Reporting and Verification (MRV) Plan
-------
Table of Contents
Roadmap to the Monitoring, Reporting and Verification (MRV) Plan 3
1. Facility Information 4
2. Project Description 4
2.1 Project Characteristics 4
2.2 Environmental Setting 6
2.3 Description of C02 EOR Project Facilities and the Injection Process 13
3. Delineation of Monitoring Area and Timeframes 19
3.1 Active Monitoring Area 19
3.2 Maximum Monitoring Area 20
3.3 Monitoring Timeframes 20
4. Evaluation of Potential Pathways for Leakage to the Surface 20
4.1 Introduction 21
4.2 Existing Wellbores 21
4.3 Faults and Fractures 23
4.4 Natural or Induced Seismicity 23
4.5 Previous Operations 23
4.6 Pipeline / Surface Equipment 23
4.7 Lateral Migration Outside the Rangely Field 24
4.8 Drilling Through the C02 Area 24
4.9 Diffuse Leakage through the Seal 25
4.10 Monitoring, Response, and Reporting Plan for C02 Loss 25
4.11 Summary 26
5. Monitoring and Considerations for Calculating Site Specific Variables 26
5.1 For the Mass Balance Equation 26
5.2 To Demonstrate that Injected C02 is not Expected to Migrate to the Surface 30
6. Determination of Baselines 30
7. Determination of Sequestration Volumes Using Mass Balance Equations 31
7.1. Mass of C02 Received 32
7.2 Mass of C02 Injected into the Subsurface 32
7.3 Mass of C02 Produced 33
7.4 Mass of C02 emitted by Surface Leakage 34
7.5 Mass of C02 sequestered in subsurface geologic formations 34
7.6 Cumulative mass of C02 reported as sequestered in subsurface geologic formations.. 35
8. MRV Plan Implementation Schedule 35
9. Quality Assurance Program 35
9.1 Monitoring QA/QC 35
9.2 Missing Data Procedures 36
9.3 MRV Plan Revisions 36
10. Records Retention 36
11. Appendices 37
Appendix 5. Well Identification Numbers 43
2
-------
Roadmap to the Monitoring, Reporting and Verification (MRV) Plan
Scout Energy Management, LLC (SEM) operates the Rangely Weber Sand Unit (RWSU) and the
associated Raven Ridge pipeline (RRPC), (collectively referred to as the Rangely Field) in Northwest
Colorado for the primary purpose of enhanced oil recovery (EOR) using carbon dioxide (C02) flooding.
SEM has utilized, and intends to continue to utilize, injected C02 with a subsidiary purpose of establishing
long-term containment of a measurable quantity of C02 in subsurface geological formations at the Rangely
Field for a term referred to as the "Specified Period." The Specified Period includes all or some portion of
the period 2023 to 2060. During the Specified Period, SEM will inject C02 that is purchased (fresh C02)
from ExxonMobil's (XOM) Shute Creek Plant or third parties, as well as C02 that is recovered (recycled
C02) from the Rangely Field's C02 Recycle and Compression Facilities (RCF's). SEM has developed this
monitoring, reporting, and verification (MRV) plan in accordance with 40 CFR §98.440-449 (Subpart RR)
to provide for the monitoring, reporting and verification of the quantity of C02 sequestered at the Rangely
Field during the Specified Period.
SEM has chosen to submit this MRV plan to the EPA for approval according to 40 Code of Federal
Regulations (CFR) 98.440(c)(1), Subpart RR of the Greenhouse Gas Reporting Program for the purpose
of qualifying for the tax credit in section 45Q of the federal Internal Revenue Code.
This MRV plan contains eleven sections:
o Section 1 contains general facility information.
o Section 2 presents the project description. This section describes the planned injection volumes, the
environmental setting of the Rangely Field, the injection process, and reservoir modeling. It also illustrates
that the Rangely Field is well suited for secure storage of injected C02.
o Section 3 describes the monitoring area: the RWSU in Colorado.
o Section 4 presents the evaluation of potential pathways for C02 leakage to the surface. The assessment
finds that the potential for leakage through pathways other than the man-made wellbores and surface
equipment is minimal.
o Section 5 describes SEM's risk-based monitoring process. The monitoring process utilizes SEM's reservoir
management system to identify potential C02 leakage indicators in the subsurface. The monitoring process
also utilizes visual inspection of surface facilities and personal H2S monitors program as applied to
Rangely Field. SEM's MRV efforts will be primarily directed towards managing potential leaks through
wellbores and surface facilities.
o Section 6 describes the baselines against which monitoring results will be compared to assess whether
changes indicate potential leaks.
o Section 7 describes SEM's approach to determining the volume of C02 sequestered using the mass
balance equations in 40 CFR §98.440-449, Subpart RR of the Environmental Protection Agency's (EPA)
Greenhouse Gas Reporting Program (GHGRP). This section also describes the site-specific factors
considered in this approach.
o Section 8 presents the schedule for implementing the MRV plan.
o Section 9 describes the quality assurance program to ensure data integrity.
o Section 10 describes SEM's record retention program.
o Section 11 includes several Appendices.
3
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1. Facility Information
The Rangely Gas Plant, operated by SEM and a part of the Rangely Field, reports under Greenhouse Gas
Reporting Program Identification number 537787.
The Colorado Oil and Gas Conservation Commission (COGCC)1 regulates all oil, gas and geothermal
activity in Colorado. All wells in the Rangely Field (including production, injection and monitoring wells) are
permitted by COGCC through Code of Colorado Regulations (CCR) 2 CCR 404-1:301. Additionally,
COGCC has primacy to implement the Underground Injection Control (UIC) Class II program in the state
for injection wells. All injection wells in the Rangely Field are currently classified as UIC Class II wells.
Wells in the Rangely Field are identified by name, API number, status, and type. The list of wells as of April,
2023 is included in Appendix 5. Any new wells will be indicated in the annual report.
2. Project Description
This section describes the planned injection volumes, environmental setting of the Rangely Field, injection
process, and reservoir modeling conducted.
2.1 Project Characteristics
SEM utilized historic production and injection of the RWSU in order to create a production and injection
forecast, included here to provide an overview of the total amounts of C02 anticipated to be injected,
produced, and stored in the Rangely Field as a result of its current and planned C02 EOR operations during
the forecasted period. This forecast is based on historic and predicted data. Figure 1 shows the actual
(historic) C02 injection, production, and stored volumes in the Rangely Field from 1986, when Chevron
initiated C02 flooding, through 2022 (solid line) and the forecast for 2023 through 2060 (dotted line). It is
important to note that this is just a forecast; actual storage data will be collected, assessed, and reported as
indicated in Sections 5, 6, and 7 in this MRV Plan. The forecast does illustrate, however, the large potential
storage capacity at Rangely field.
1 Pursuant to Colorado SB21-285, effective July 1, 2023, the COGCC will become the Energy and Carbon
Management Commission.
4
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Rangely Field
Historical and Projected C02
6000
T3
£
(O
LO
3
O
5000
ro
a>
>-
ai
a.
4000
3000
2000
1000
uvAV
C02 Production
try""
C02 Stored
Forecast C02 Stored
u v
JL
C02 Injection
Forecast C02 Injection
IDO^-OOINIDO^-OOINIDO^-OOINIDO^-OO
00CT>CT>CT>OO*H*H*H(N(Nr0r0r0^-^-L/lL/lL/l
aiaiaiaiooooooooooooooo
*H*H*H*H(N(N(N(N(N(N(N(N(N(N(N(N(N(N(N
Year
Figure 1 - Rangely Field Historic and Forecast C02 Injection, Production, and Storage 1986-2060
The amount of C02 injected at Rangely Field is adjusted periodically to maintain reservoir pressure and to
increase recovery of oil by extending or expanding the EOR project. The amount of C02 injected is the
amount needed to balance the fluids removed from the reservoir and to increase oil recovery. While the
model output shows C02 injection and storage through 2060, this data is for planning purposes only and
may not necessarily represent the actual operational life of the Rangely Field EOR project. As of the end
of 2022, 2,320,000 million standard cubic feet (MMscf) (122.76 million metric tons (MMMT)) of C02 has
been injected into Rangely Field. Of that amount, 1,540,000 MMscf (81.48 MMMT) was produced and
recycled.
While tons of C02 injected and stored will be calculated using the mass balance equations described in
Section 7, the forecast described above reflects that the total amount of C02 injected and stored over the
modeled injection period to be 967,000 MMscf (51.2 MMMT). This represents approximately 35.7% of the
theoretical storage capacity of Rangely Field.
Figure 2 presents the cumulative annual forecasted volume of C02 stored by year through 2060, the
modeling period forthe projection in Figure 1. The cumulative amount stored is equal to the sum of the annual
storage volume for each year plus the sum of the total of the annual storage volume for each previous year.
As is typical with C02 EOR operations, the rate of accumulation of stored C02 tapers overtime as more
recycled C02 is used for injection. Figure 2 illustrates the total cumulative storage overthe modeling period,
projected to be 967,000 MMscf (51.2 MMMT) of C02.
5
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Rangely Field
Historical and Forecast Cumulative C02 Storage
60
i-
(0
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Figure 3 - Regional map showing Rangely's position between the Uinta and Piceance Basin.
The reservoir, Weber Sands, is comprised of clean eolian quartz deposited in an erg (sand sea)
depositional environment. Internally, these dune sands are separated into six main packages (odd
numbers, 1 to 11) with the fluvial Maroon Formation (even numbers, 2 to 10) interfingering the field from
the north. The Weber Formation is underlain by the fossiliferous Desmoinesian carbonates of the Morgan
Formation, and overlain by the siltstones and shales of the Phosphoria/Park City and Moenkopi
Formations.
For the majority of the region, the Phosphoria Formation acts as an impermeable barrier above the
Weber Formation and is a hydrocarbon source for the overlying strata. However, due to the large thrust
fault south and west of the field, the Phosphoria Formation was driven down to significantly deeper
depths, and below the reservoir Weber sands, allowing for maturation and expulsion of the hydrocarbons
to migrate upward into stratigraphically older, but structurally shallower reservoirs sometime during the
Jurassic. At Rangely, the Phosphoria Formation is almost entirely missing above the Weber Formation,
but the Moenkopi Formation sits directly above the sands creating the seal for the petroleum system.
Fresh water in and around the town/field of Rangely is sourced from the quaternary creeks and rivers that
cut across the region (data obtained from the Colorado Division of Water Resources). No confined fresh
water aquifers are present between the reservoir rock and the surface. Safety measures are still taken to
protect the shallowest of rocks that contain rain water seepage (unconfined aquifer) into the Mancos
Formation (surface exposure at Rangely) illustrated by the surface casing on Figure 4. The shallowest
point of the reservoir is 5,486 ft below the surface (4,986 ft below any possible fresh rain water seepage).
The mere presence of hydrocarbons and the successful implication of a C02 flood indicates the quality
and effectiveness of the seal to isolate this reservoir from higher strata.
7
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Uinta Basin
Douglas Creek
Arch
Piceance Basin
ichesne River and Uinta Fms
CoKon Fm
Wasatch Fr
Wasatch and
Fort Union Fms
k I r_.
rm
Blackhawk Fm
Ferron Ss Mbr of Ma cos Sh and Frontu
Dakota Ss
Sue hem Cgl Mbr
Salt Wash Ss O O
Morrison Fm
O Entrada Ss O
Glen Canyon Ss
Cftnle Fm
Moenkep. Fm
Source
__ParY. City Fm
upper Weber Ss
Reservoir
Maroon
cr_ Fm
Round Valley Ls
Manning Canyon Sh
Doughnut Sh/Humbug Fm
Deseret Ls
Leadville Ls
Madison Ls
Pinyon.
-TfeniWU rf"
Dotsero Fm
Lodore Fm
Sawatch Ss
KEY
PETROLEUM
SYSTEMS:
I| Green River
system
I| Mesaverde
system
l| Mancos/Mowry
system
I| Phosphoria
system SOUTCe
Grassy Trail
° Creek oil
~ Mtnturn system
,, SignFficant oil production
{indicating source rock)
v./ Significant gas production
^ (indicating source rock)
S Source rocks
(R) Rangely Field
Main reservoir
I I Hiatus
Stratigraphy
at Rangely
Figure 4. Stratigraphic Column of formations at the Rangely Field. Due to a large fault the source
rock (Phosphoria) is stratigraphically above the reservoir rock (Weber), but structurally, the
source lies below the reservoir, (from U.S. Geological Survey, 2003)
Figure 5 shows the doubly plunging anticline with the long axis along a northwest-southeast trend and the
short axis along a northeast-southwest trend. In 1949 the depth of a gas cap was established at -330 ft
subsea and an Oil Water Contact (OWC) at -1150 ft subsea. Many core analysis suggest that below this -
1150' OWC is a transition/residual oil zone. However, for the purpose of this analysis and all volumetrics
8
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the base of the reservoir will be at the -1150' subsea depth determined in 1949.
Geologically, the Weber Sands were deposited on top of the Morgan formation which is a combination of
interbedded shale, siltstone, and cherty limestone. Few wells are drilled deep enough to penetrate the
Morgan formation within the Rangely Field to gather porosity/permeability data locally. However, analysis
of the Morgan formation from other fields/outcrops indicate that it is a non-reservoir rock (low
porosity/permeability), and would be sufficient as a basial barrier for the field. The highest subsurface
elevation of the base of the Weber Sands is deeper than the -1150' used for the OWC. Meaning injected
C02 should not encounter the Morgan formation. Additionally, Section 4.7 explains how the Rangely
Field is confined laterally through the nature of the anticline's structure.
Figure 5. Structure map of the Weber 1 (top of reservoir). Colors illustrate the maximum aerial
coverage of the Gas Cap (Red), Main Reservoir (Green), and Transitional Reservoir (Blue). Cross
section A-A' is predominantly along the long axis of the field and B-B' is along the short axis.
The Rangely Field has one main field fault (MFF) and numerous smaller faults (isolated and joint) and
fractures that are present throughout the stratigraphic column between the base of the Weber reservoir
and surface. Faults within the reservoir were measured by well-to-well displacement, while the fractures
were measured and observed as calcite veins on the surface with no displacement. The MFF has a NE-
WSWtrend and cuts through the reservoir interval. In the 1960's Rangely residents began experiencing
felt earthquakes. Between 1969 and 1973, a joint investigation with the USGS installed seismic
monitoring stations in and around the town of Rangely and began recording activity. In 1971, a study was
conducted to evaluate the stress state in the vicinity of the fault which determined a critical fluid pressure
above which fault slippage may occur. Reservoir pressure was then manipulated and correlated with
increases or decreases in seismic activity. This study determined that the waterflood in Rangely was
inducing seismicity when reservoir pressure was raised above ~3730 psi.
In the 1990's, field reservoir pressure had built back up leading to the largest magnitude earthquake in
9
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Rangely which took place in 1995 (M 4.5), shortly after maximum reservoir pressure was reached in
1998. Pressure maintenance began and seismic activity dropped off after lowering the average field
reservoir pressure down to ~3100 psi. No other seismic activity was recorded around the field until 2015
and 2017 when there was a total of 5 seismic events (see Figure 6) around the northeastern portion of
the MFF. A new interpretation from the 3D seismic revealed a series of previously unknown joint faults
(perpendicular to the MFF). Investigation into this region revealed that the ~3730 psi threshold had been
crossed and triggered the seismic events. Since the 2017 seismic events, no other events have been
recorded of felt magnitude and continued pressure monitoring further reduces the risk of another event.
2017 Induced
Seismic Study*
Figure 6. USGS fault history map (1900-2023). Largest earthquake was the 1995 M 4.5 north of the
unit (2017 was a study to induce seismic activity along the MFF, and not caused by day-to-day
operations)
The natural fractures found within the field play a significant role in fluid flow. The subsurface natural
fractures are vertical and show an approximately ENE trend and their extension joints are orientated ESE.
Shallower portions of the reservoir show a distinctly higher density of fractures than deeper portions. On
the shallow dipping sides of the anticline, there does not appear to be a strong structural control on
fracture density. Most well-to-well rapid breakthrough of injected C02 is along these ENE fractures. It is
unknown if this is from natural or induced fractures. There is no evidence that these natural fractures
diminish the seals integrity.
10
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Figure 7. Cross section A-A' along the long axis of the field, and perpendicular to the MRR. The
MFF does not have much displacement and is near vertical.
The Rangely Field has approximately 1.9 billion barrels of Original Oil in Place (OOIP). Since first
discovered in 1933, Rangely Field has produced 920 million barrels of oil, or 48% of the OOIP. The
Rangely Field has an aerial extent of approximately 19,150 acres with an average gross thickness of 650
ft. The previously mentioned 11 internal layers of the reservoir, alternating zones of Weber and Maroon
Formations, can be simplified to only three sections. The Upper Weber contains intervals 1-3, the Middle
Weber contains intervals 4-7, and the Lower Weber contains intervals 8-approxamently 50 ft below the
11D marker (identified by the base of the yellow in Figure 7). These interval groupings were determined
by the extensive lateral continuingiy and thickness of the Weber 4 and Weber 8 which easily separate the
reservoir into the three zones. For the majority of the Rangely Field, the even Maroon Formations act as
flow barriers between the odd Weber Formations. Average porosity within the Weber Sands dune fades
is 10.3% and within the Maroon fluvial fades is 4.9%. However, the key factor that enables the Maroon
Formation to be a seal is its lack of permeability. The Weber dune fades have an average permeability of
2.44 millidarcy (Md), while the Maroon fluvial fades have an average permeability of 0.03 Md.
owe -1150'
Transition Zone & ROZ
11
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Figure 8. Cross section B-B' along the short axis of the field and parallel to the MFF. Used to
illustrate the variation of the Oil Water Contact (OWC).
Given that the Rangely Field is located at the highest subsurface elevations of the structure, that the
confining zone has proved competent over both millions of years and throughout decades of EOR
operations, and that the Rangely Field has ample storage capacity, SEM is confident that stored CQ2 will
be contained securely within the Weber Sands in the Rangely Field.
2.2.2 Operational History of the Rangely Field
The Rangely Field was discovered in 1933 but subsequently ceased production until World War II when oil
returned to high demand. Intensive development began, expanding from one well to 478 wells by 1949. It
is located in the northwestern portion of Colorado.
The Rangely Field was originally developed by Chevron. Following the initial discover in 1933,
Chevron imitated a 40-acre development in 1944, followed by hydrocarbon gas injection from
1950 to 1969. To improve efficiency, in 1957, the RWSU was formed. The boundaries of the RWSU are
reflected in Figure 9.
Rangely Well List
^ Active-Producer
yf 0 TA- Producer
~ Active-Injector
A TA-Injector
T Active 5WD
Collection Station / Facility
¦ Collection Station
$ Compressor Station
X ¦ Rangely Facility
(££) Rangely Plant General
A West End Water Injection
N -Rangely Weber Unit
23^^ Rangely Weber Unit
1 "l1 Rangely Weber Unit Half Mile Buffer
Mdien Htl
BIO BIANG& COuWv
± i iu* vOJ /
A (t'li *A-A*AV
u -
v^aV S
\ »> i
v TLtw.}
- >. /./~ WA i * a
2X102W
'Rio Blanco-
Rdpgely OiStnet
Hospital Hetip&i
River
itf N)2W
Moffat
0/HICJ blAnCO CO0NTY
Uintah
Rio Blanco
Garfield
Figure 9 - Rangely Field Map
12
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Chevron began C02 flooding of the Rangely Field in 1986 and has continued and expanded it since that
time. The experience of operating and refining the Rangely Field C02 floods over the past decade has
created a strong understanding of the reservoir and its capacity to store C02.
2.3 Description of C02 EOR Project Facilities and the injection Process
Figures 10 shows a simplified flow diagram of the project facilities and equipment in the Rangely Field.
C02 is delivered to the Rangely Field via the Raven Ridge Pipeline. The CG2 injected into the Rangely
Field is currently supplied by XOM's Shute Creek Plant into the pipeline system.
Once C02 enters the Rangely Field there are four main processes involved in EOR operations. These
processes are shown in Figure 10 and include:
1. C02 Distribution and Injection. Purchased C02 and recycled C02 from the RCF is sent through the main
C02 distribution system to various C02 injectors throughout the Field.
2. Produced Fluids Handling. Produced fluids gathered from the production wells are sent to collection
stations for separation into a gas/C02 mix and a produced fluids mix of water, oil, gas, and C02. The
produced fluids mix is sent to centralized water plants where oil is separated for sale into a pipeline, water
is recovered for reuse, and the remaining gas/C02 mix is merged with the output from the collection
stations. The combined gas/C02 mix is sent to the RCF and natural gas liquids (NGL) Plant. Produced oil
is metered and sold; water is forwarded to the water injection plants fortreatment and reinjection or disposal.
3. Produced Gas Processing. The gas/C02 mix separated at the satellite batteries goes to the RCF and
NGL Plant where the NGLs, and C02 streams are separated. The NGLs move to a commercial pipeline for
sale. The remaining C02 (e.g., the recycled C02) is returned to the C02 distribution system for reinjection.
4. Water Treatment and Injection. Water separated in the tank batteries is processed at water plants to
remove any remaining oil and then distributed throughout the Rangely Field for reinjection.
LaBarge Field/
Shute Creek Plant
Field and plant owned and
operated by ExxonMobil
Raven Ridge
Pipeline
123 mile, 16" steel pipeline
(200 MMcfd capacity)
56% CRRPC owned
(T) Rangely Field
Dehydration & NGL Extraction
RCF
1st/2nd Stage
Compression
Gasjt-,
A Custody Transfer Point for Assets
~ CO? Measurement Points
RCF
3rd/ 4th Stage
Compression
Oil/Water Liquids Liquid/Gas
Separation & ¦« Inlet
Water Plants Separation
Water T water] |_
Gas/Water
Injection
Wells
Water
Disposal
Wells
-f
Producing
Wells
Surface
Navajo Formation
COj +
Water +
Natural Gas
Oil
~ Natural Gas / NGL
+ Water
+ CO,
Weber Sands Reservoir
yv.
Figure 10 Rangely Field -General Production Flow Diagram
13
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2.3.1 C02 Distribution and Injection.
SEM purchases C02 from XOM and receives it via the Raven Ridge Pipeline through one custody transfer
metering point, as indicated in Figures 10. Purchased C02 and recycled C02 are sent through the C02
trunk lines to multiple distribution lines to individual injection wells. There are volume meters at the inlet and
outlet of the C02 Reinjection Facility.
As of April 2023, SEM has approximately 280 injection wells in the Rangely Field. Approximately 160 MMscf
of C02 is injected each day, of which approximately 15% is purchased C02, and the balance (85%) is
recycled. The ratio of purchased C02 to recycled C02 is expected to change overtime, and eventually the
percentage of recycled C02 will increase and purchases of fresh C02 will taper off as indicated in Section
2.1.
Each injection well is connected to a water alternating gas (WAG) manifold located at the well pad. WAG
manifolds are manually operated and can inject either C02 or water at various rates and injection pressures
as specified in the injection plans. The length of time spent injecting each fluid is a matter of continual
optimization that is designed to maximize oil recovery and minimize C02 utilization in each injection pattern.
A WAG manifold consists of a dual-purpose flow meter used to measure the injection rate of water or C02,
depending on what is being injected. Data from these meters is sent to the Supervisory Control and Data
Acquisition (SCADA) system where it is compared to the injection plan forthat well. As described in Sections
5 and 7, data from the WAG manifolds, visual inspections of the injection equipment, and use of the
procedures contained in 40 CFR §98.230-238 (Subpart W), will be gathered to complete the mass balance
equations necessary to determine annual and cumulative volumes of stored C02.
2.3.2 Wells in the Rangely Field
As of April 2023, there are 662 active wells that are completed in the Rangely Field, with roughly 40%
injection wells and 60% producing wells, as indicated in Figure 11,2 Table 1 shows these well counts in the
Rangely Field by status.
2 Wells that are not in use are deemed to be inactive, plugged and abandoned, temporarily abandoned, or shut in.
14
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Rangely Well List
# Active-Producer
TA-Producer
A Active-Injector
A TA-Injector
~ Active SWD
Rangely Weber Unit
I I Rangely Weber Unit
2N 103W
Metier Hill
00 RIO PLAN (9S COUN»7
2N 102W
.Rio Blanco
Ji) Rpven I
ftrfcjr li
Heliport
Moffat
I'tgely District
Vpitof Heppaf'
1N 102W
0RIO BLANCO CQ18NTY
Rio Blanco
iarfield
Figure 11 Rangely Field Wells - As of April 2023
Table 1 - Rangely Field Wells
<\ge/Completion of Well
Active
Shut-in
Temporarily
Abandoned
Plugged and
Abandoned
Drilled & Completed in the
1940's
265
5
55
149
Drilled 1950-1985
297
7
55
46
Completed after 1986
103
1
11
8
TOTAL
665
13
121
203
The wells in Table 1 are categorized in groups that relate to age and completion methods. Roughly 48%
of these wells were drilled in the 1940's and were generally completed with three strings of casing (with
surface and intermediate strings typically cemented to the surface). The production string was typically
installed to the top of the producing interval, otherwise known as the main oil column (MOC), which
extends to the producible oil/water contact (POWC). These wells were completed by stimulating the open
hole (OH), and are not typically cased through the MOC. While implementing the water flood from 1958-
1986, a partial liner would have been typically installed to allow for controlled injection intervals and this
liner would have been cemented to the top of the liner (TOL) that was installed. For example, a partial
liner would be installed from 5,700-6,500 ft, and the TOC would be at 5,700 ft. The casing weights used
15
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for the production string have varied between 7" 23 & 26#/ft. with 5" 18 #/ft. for the production liner.
The wells in Table 1 drilled during the period 1950-1986 typically were cased through the production
interval with 7" casing. Some wells were completed with 7" casing to the top of the MOC and then
completed with a 5" liner through the productive interval. The wells with liners were cemented to the TOL.
The remaining wells (roughly 12%) in Table 1 were drilled after 1986 when the C02 flood began. All of
these wells were completed with 7" casing through the POWC. Very few of these wells have experienced
any wellbore issues that would dictate the need for a remedial liner.
SEM reviews these categories along with full wellbore history when planning well maintenance projects.
Further, SEM keeps well workover crews on call to maintain all active wells and to respond to any
wellbore issues that arise. On average, in the Rangely Field there are two to three incidents per year in
which the well casing fails. SEM detects these incidents by monitoring changes in the surface pressure of
wells and by conducting Mechanical Integrity Tests (MITs), as explained later in this section and in the
relevant regulations cited. This rate of failure is less than 2% of wells per year and is considered
extremely low.
All wells in oilfields, including both injection and production wells described in Table 1, are regulated by
the COGCC under COGCC 100-1200 series rules. A list of wells, with well identification numbers, is
included in Appendix 5. The injection wells are subject to additional requirements promulgated by EPA -
the UIC Class II program - implementation of which has been delegated to the COGCC.
COGCC rules govern well siting, construction, operation, maintenance, and closure for all wells in oilfields.
Current rules require, among other provisions, that:
Class II UIC Wells will not be permitted in areas where they would inject into a formation that is
separated from any Underground Source of Drinking Water by a Confining Layer with known open
faults or fractures that would allow flow between the Injection Zone and Underground Source of Drinking
Water within the area of review.
Injection Zones will not be permitted within 300 feet in a vertical dimension from the top of any
Precambrian basement formation.
An Operator will not inject any Fluids or other contaminants into a UIC Aquifer that meets the
definition of an Underground Source of Drinking Water unless EPA has approved a UIC Aquifer
exemption as described in Rule 802.e.
In addition, SEM implements a corrosion protection program to protect and maintain the steel used in
injection and production wells from any C02-enriched fluids. SEM currently employs methods to mitigate
both internal and external corrosion of casing in wells in the Rangely Field. These methods generally protect
the downhole steel and the interior and exterior of wellbores through the use of special materials (e.g.
fiberglass tubing, corrosion resistant cements, nickel plated packers, corrosion resistant packer fluids) and
procedures (e.g. packer placement, use of annular leakage detection devices, cement bond logs, pressure
tests). These measures and procedures are typically included in the injection orders filed with the COGCC.
Corrosion protection methods and requirements may be enhanced overtime in response to improvements
in technology.
MIT
SEM complies with the MIT requirements implemented by COGCC and BLM to periodically inspect wells
and surface facilities to ensure that all wells and related surface equipment are in good repair and leak-
free, and that all aspects of the site and equipment conform with Division rules and permit conditions. All
active injection wells undergo an MIT at the following intervals:
Before injection operations begin
16
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Every 5 years as stated in the injection orders (COGCC 417.a. (1))
After any casing repair
After resetting the tubing or mechanical isolation device
Or whenever the tubing or mechanical isolation device is moved during workover operations
COGCC requires that the operator notify the COGCC district office prior to conducting an MIT. Operators
are required to use a pressure recorder and pressure gauge for the tests. The operator's field representative
must sign the pressure recorder chart along with the COGCC field representative and submit it with the MIT
form. The casing-tubing annulus must be tested to a minimum of 1200 psi for 15 minutes.
If a well fails an MIT, the operator must immediately shut the well in and provide notice to COGCC. Casing
leaks must be successfully repaired and retested or the well plugged and abandoned after submitting a
formal notice and obtaining approval from the COGCC.
Any well that fails an MIT cannot be returned to active status until it passes a new MIT
2.3.3 Produced Fluids Handling
As injected C02 and water move through the reservoir, a mixture of oil, gas, and water ("produced fluids")
flows to the production wells. Gathering lines bring the produced fluids from each production well to
collection stations. SEM has approximately 382 active production wells in the Rangely Field and production
from each is sent to one of 27 collection stations. Each collection station consists of a large vessel that
performs a gas - liquid separation. Each collection station also has well test equipment to measure
production rates of oil, water and gas from individual production wells. SEM has testing protocols for all
wells connected to a collection station. Most wells are tested twice per month. Some wells are prioritized
for more frequent testing because they are new or located in an important part of the Field; some wells with
mature, stable flow do not need to be tested as frequently; and finally, some wells will periodically need
repeat testing due to abnormal test results.
After separation, the gas phase is transported by pipeline to the C02 reinjection facility for processing as
described below. Currently the average composition of this gas mixture as it enters the facility is 92% C02
and 800ppm H2S; this composition will change overtime as C02 EOR operations mature.
The liquid phase, which is a mixture of oil and water, is sent to one of two centralized water plants where
oil is separated from water via two 3-phase separators. The water is then sent to water holding tanks where
further separation is done.
The separated oil is metered through the Lease Automatic Custody Transfer (LACT) unit located at the
custody transfer point between Chevron pipeline and SEM. The oil typically contains a small amount of
dissolved or entrained C02. Analysis of representative samples of oil is conducted once a year to assess
C02 content.
The water is removed from the bottom of the tanks at the water injection stations, where it is re-injected to
the WAG injectors.
Any gas that is released from the liquid phase rises to the top of the tanks and is collected by a Vapor
Recovery Unit (VRU) that compresses the gas and sends it to the C02 reinjection facility for processing.
17
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Rangely oil is slightly sour, containing small amounts of hydrogen sulfide (H2S), which is highly toxic. There
are approximately 25 workers on the ground in the Rangely Field at any given time, and all field personnel
are required to wear H2S monitors at all times. Although the primary purpose of H2S detectors is protecting
employees, monitoring will also supplement SEM's C02 leak detection practices as discussed in Sections
5 and 7.
In addition, the procedures in 40 CFR §98.230-238 (Subpart W) and the two-part visual inspection process
described in Section 5 are used to detect leakage from the produced fluids handling system. As described
in Sections 5 and 7, the volume of leaks, if any, will be estimated to complete the mass balance equations
to determine annual and cumulative volumes of stored C02.
2.3.4 Produced Gas Handling
Produced gas gathered from the collection stations, and water injection plants is sent to the C02 recycling
and compression facility. There is an operations meter at the facility inlet.
Once gas enters the C02 reinjection facility, it undergoes dehydration and compression. In the RWSU an
additional process separates NGLs for sale. At the end of these processes there is a C02 rich stream that
is recycled through re-injection. Meters at the C02 recycling and compression facility outlet are used to
determine the total volume of the C02 stream recycled back into the EOR operations.
As described in Section 2.3.4, data from 40 CFR §98.230-238 (Subpart W), the two-part visual inspection
process for production wells and areas described in Section 5, and information from the personal H2S
monitors are used to detect leakage from the produced gas handling system. This data will be gathered to
complete the mass balance equations necessary to determine annual and cumulative volumes of stored
C02 as described in Sections 5 and 7.
2.3.5 Water Treatment and Injection
Produced water collected from the collection stations is gathered through a pipeline system and moved to
one of two water injection plants. Each facility consists of 3-Phase separators and 79,500-barrels of
separation tanks where any remaining oil is skimmed from the water. Skimmed oil is combined with the oil
from the 3-Phase separators and sent to the LACT. The water is sent to an injection pump where it is
pressurized and distributed to the WAG injectors.
2.3.6 Facilities Locations
The current locations of the various facilities in the Rangely Field are shown in Figure 13. As indicated
above, there are two central water plants. There are twenty-seven collections stations that gather
production from surrounding wells. The two water plants are identified by the blue triangle and circle. The
twenty-seven collection stations are identified by red squares. The C02 Reinjection facility is indicated by
the green circle.
18
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Collection Station / Facility
I Collection Station
Compressor Station
¦ Rangely Facility
(££) Rangely Plant General
A West End Water Injection
Rangely Weber Unit
Rangely Weber Unit
" Men Hill
06 RIO BIANCSS COUN-1
Collection
Station 01
Collection
Station 03
Collection
Station 10m
,Rio Blanco
Collection
Station 08
Collection
2N 103W
Collection.^
Station 04
Collection
Station 20 2N 1021
Station 12
Collection
Station 05
Collection
Station 11
Collection
Station 27
West
End Water
Injection
Collection
Station 16
Heliport
Collection
Station 22
Collection Co"ec^,tV,
Station stat'°109
Collection
Station 17
Collection
Station 33
Collection
Station 28«
Collection
Station 29
Collection
Station 13
vCollection
Station 18 Main
¦ Treatment
I 37
Rangely [¦]
Plant ¦¦ Collection Collection
General Station 19 Station 24
Collection
Station 34
Collection
Station 30
Collection
Station 39
Collection
_Station_47_
Moffat
Rangely District
MOSfiittOi' HfiipOti
1N 102W
Uintah
ORIOi BLANCO CQBNTY
Rio Blanco
Garfield
Miles
Figure 13 Location of Surface Facilities at Rangely Field
3. Delineation of Monitoring Area and Timeframes
The current active monitoring area (AMA), future AMA and monitoring time frame of the AMA are
described below. Additionally, the maximum monitoring area (MMA) of the free phase C02 plume, its
buffer zone and the monitoring time frame for the MMA are described below.
3.1 Active Monitoring Area
Because C02 is present throughout the Rangely Field and retained within it, the Active Monitoring Area
(AMA) is defined by the boundary of the Rangely Field plus one-half mile buffer. This boundary is defined
in Figure 9. The following factors were considered in defining this boundary:
Free phase C02 is present throughout the Rangely Field: More than 2,320,000 MMscf (122.76 MMMT)
tons of C02 have been injected and recycled throughout the Rangely Field since 1986 and there has
been significant infill drilling in the Rangely Field, completing additional wells to further optimize
production. Operational results thus far indicate that there is C02 throughout the Rangely Field.
C02 injected into the Rangely Field remains contained within the Rangely Field AMA because of the
19
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fluid and pressure management results associated with C02 EOR. The maintenance of an IWR of 1.0
assures a stable reservoir pressure; managed lease line injection and production wells are used to
retain fluids in the Rangely Field as indicated in Section 4.7. Implementation of these methods over the
past decades have successfully contained C02 within the Rangely Field.
It is highly unlikely that injected C02 will migrate downdip and laterally outside the Rangely Field
because of the nature of the geology and the approach used for injection. As indicated in Section
2.2.1 "Geology of the Rangely Field," the Rangely Field is situated at the top of a dome structural
trap, with all directions pointing down-dip from the highest point. This means that over long periods of
time, injected C02 will tend to rise vertically towards the point in the Rangely Field with the highest
elevation.
Forecasted C02 injection volumes, shown in Figure 1, represent SEM's plan to not increase current
injection volumes and maintain an IWR of 1. Operations will not expand beyond the currently active C02-
EOR portion of the Rangely Field; therefore, the AMA is not expected to increase. Should such
expansions occur, they will be reported in the Subpart RR Annual Report for the Rangely Field, as
required by section 98.446.
3.2 Maximum Monitoring Area
The Maximum Monitoring Area (MMA) is defined in 40 CFR §98.440-449 (Subpart RR) as equal or greater
than the area expected to contain the free-phase C02 plume until the C02 plume has stabilized, plus an all-
around buffer zone of one-half mile. Section 3.1 states that the maximum extent of the injected C02 is expected
to be bounded by the Rangely Field Unit boundary shown in Figure 9. Therefore, the MMA is the Rangely Field
Unit boundary plus the one-half mile buffer as required by 40 CFR §98.440-449 (Subpart RR).
3.3 Monitoring Timeframes
SEM's primary purpose for injecting C02 is to produce oil that would otherwise remain trapped in the
reservoir and not, as in UIC Class VI, "specifically for the purpose of geologic storage."3 During a Specified
Period, SEM will have a subsidiary purpose of establishing the long-term containment of a measurable
quantity of C02 in the Weber Sands in the Rangely Field. The Specified Period will be shorter than the
period of production from the Rangely Field. This is in part because the purchase of new C02 for injection
is projected to taper off significantly before production ceases at Rangely Field, which is modeled through
2060. At the conclusion of the Specified Period, SEM will submit a request for discontinuation of reporting.
This request will be submitted when SEM can provide a demonstration that current monitoring and model(s)
show that the cumulative mass of C02 reported as sequestered during the Specified Period is not expected
to migrate in the future in a manner likely to result in surface leakage. It is expected that it will be possible to
make this demonstration within two to three years after injection for the Specified Period ceases based upon
predictive modeling supported by monitoring data. The demonstration will rely on two principles: 1) that just
as is the case for the monitoring plan, the continued process of fluid management during the years of C02
EOR operation after the Specified Period will contain injected fluids in the Rangely Field, and 2) that the
cumulative mass reported as sequestered during the Specified Period is a fraction of the theoretical storage
capacity of the Rangely Field See 40 C.F.R. § 98.441 (b)(2)(ii).
4. Evaluation of Potential Pathways for Leakage to the Surface
3 EPA UIC Class VI rule, EPA 75 FR 77291, December 10, 2010, section 146.81(b).
20
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4.1 Introduction
In the 90 years since the Rangely Field was discovered in 1933, extensive reservoir monitoring and
studies were performed. Based on the knowledge gained from historical practices, this section assesses
the following potential pathways for leakage of C02 to surface within Rangely Field.
Existing Wellbores
Faults and Fractures
Natural and Induced Seismic Activity
Previous Operations
Pipeline/Surface Equipment
Lateral Migration Outside the Rangely Field
Drilling Through the C02 Area
Diffuse Leakage Through the Seal
Detailed analysis of these potential pathways concluded that existing wellbores and pipeline/surface
equipment pose the only meaningful potential leakage pathways. Operating pressures are not expected
to increase overtime, therefore there is not a specific time period that would increase the likelihood of
pathways for leakage. SEM identifies these potential pathways for C02 leakage to be low risk, i.e., less
than 1% given the extensive operating history and monitoring program currently in place.
The monitoring program to detect and quantify leakage is based on the assessment discussed below.
4.2 Existing Wellbores
As of April 2023, there are approximately 662 active SEM operated wells in the Rangely Field - split roughly
evenly between production and injection wells. In addition, there are approximately 135 wells not in use, as
described in Section 2.3.2.
Leakage through existing wellbores is a potential risk at the Rangely Field that SEM works to prevent by
adhering to regulatory requirements for well drilling and testing; implementing best practices that SEM has
developed through its extensive operating experience; monitoring injection/production performance,
wellbores, and the surface; and maintaining surface equipment.
As discussed in Section 2.3.2, regulations governing wells in the Rangely Field require that wells be
completed and operated so that fluids are contained in the strata in which they are encountered and that
well operation does not pollute subsurface and surface waters. The regulations establish the requirements
that all wells (injection, production, disposal) must comply with. Depending upon the purpose of a well, the
requirements can include additional standards for evaluation and MIT. SEM's best practices include pattern
level analysis to guide injection pressures and performance expectations; utilizing diverse teams of experts
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to develop EOR projects based on specific site characteristics; and creating a culture where all field
personnel are trained to look for and address issues promptly. SEM's practices, which include corrosion
prevention techniques to protect the wellbore as needed, as discussed in Section 2.3.2, ensures that well
completion and operation procedures are designed not only to comply with regulations but also to ensure
that all fluids (e.g., oil, gas, C02) remain in the Rangely Field until they are produced through an SEM well.
As described in Section 5, continual and routine monitoring of SEM's wellbores and site operations will be
used to detect leaks, including those from non-SEM wells, or other potential well problems, as follows:
Well pressure in injection wells is monitored on a continual basis. The injection plans for each pattern
are programmed into the injection WAG controller, as discussed in Section 2.3.1, to govern the rate and
pressure of each injector. Pressure monitors on the injection wells are programmed to flag pressures
that significantly deviate from the plan. Leakage on the inside or outside of the injection wellbore would
affect pressure and be detected through this approach. If such excursions occur, they are investigated
and addressed. In the time SEM has operated the Rangely Field, there have been no C02 leakage
events from a wellbore.
In addition to monitoring well pressure and injection performance, SEM uses the experience gained
overtime to strategically approach well maintenance. SEM maintains well maintenance and workover
crews onsite for this purpose. For example, the well classifications by age and construction method
indicated in Table 1 inform SEM's plan for monitoring and updating wells. SEM uses all of the
information at hand including pattern performance, and well characteristics to determine well
maintenance schedules.
Production well performance is monitored using the production well test process conducted when
produced fluids are gathered and sent to a collection station. There is a routine cycle for each collection
station, with each well being tested approximately twice every month. During this cycle, each production
well is diverted to the well test equipment for a period of time sufficient to measure and sample produced
fluids (generally 24 hours). This test allows SEM to allocate a portion of the produced fluids measured
at the collection station to each production well, assess the composition of produced fluids by location,
and assess the performance of each well. Performance data are reviewed on a routine basis to ensure
that C02 flooding is optimized. If production is off plan, it is investigated and any identified issues
addressed. Leakage to the outside of production wells is not considered a major risk because of the
reduced pressure in the casing. Further, the personal H2S monitors are designed to detect leaked fluids
around production wells.
Finally, as indicated in Section 5, field inspections are conducted on a routine basis by field personnel.
On any day, SEM has approximately 25 personnel in the field. Leaking C02 is very cold and leads to
formation of bright white clouds and ice that are easily spotted. All field personnel are trained to identify
leaking C02 and other potential problems at wellbores and in the field. Any C02 leakage detected will
be documented and reported, quantified and addressed as described in Section 5.
Based on its ongoing monitoring activities and review of the potential leakage risks posed by wellbores,
SEM concludes that it is mitigating the risk of C02 leakage through wellbores by detecting problems as
they arise and quantifying any leakage that does occur. Section 4.10 summarizes how SEM will monitor
C02 leakage from various pathways and describes how SEM will respond to various leakage scenarios.
In addition, Section 5 describes how SEM will develop the inputs used in the Subpart RR mass-balance
equation (Equation RR-11). Any incidents that result in C02 leakage up the wellbore and into the
atmosphere will be quantified as described in Section 7.4.
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4.3 Faults and Fractures
After reviewing geologic, seismic, operating, and other evidence, SEM has concluded that there are no
known faults or fractures that transect the entirety of the Weber Sands in the project area. As described in
Section 2.2.1, the MFF is present below the reservoir and terminates within the Weber Sands without
breaching the upper seal. Additional faults have been identified in formations that are stratigraphically below
the Weber Sands, but this faulting has been shown not to affect the Weber Sands or to have created
potential leakage pathways given that they do not contact the Upper Pennsylvanian or Permian strata
(Weber Fm.).
SEM has extensive experience in designing and implementing EOR projects to ensure injection pressures
will not damage the oil reservoir by inducing new fractures or creating shear. As a safeguard, injection
satellites are set with automatic shutoff controls if injection pressures exceed fracture pressures.
4.4 Natural or Induced Seismicity
After reviewing literature and historic data, SEM concludes that there is no direct evidence that natural
seismic activity poses a significant risk for loss of C02 to the surface in the Rangely Field. Natural seismic
events are derived from the thrust fault to the west. Historically, Figure 6 in section 2.2.1 shows nine (9)
seismic events outside of the Rangely Field (including the 1993 M 3.5 event). The epicenter of these
earthquakes was far below the operating depths of the Rangely Field, and are associated with the thrust
fault to the west of the field. The operations of Rangely have zero impact on this thrust fault. Natural
earthquakes are not predictable, but these do not pose a threat to current operations. This is evidenced by
the fact that hydrocarbons are still within the anticline, meaning that there have been no major seismic
events in the last few million years capable of releasing these hydrocarbons to the surface.
Induced seismic events (non-natural) are tied to the MFF and its joint faults. These can be impacted by
Rangely Field operations. Section 2.2.1 explains how an increase in reservoir pressure can trigger seismic
events along and near the MFF. To prevent this from occurring bottom hole pressure surveys are collected
one (1) to two (2) times per year across the Rangely Field helping to monitor pressure changes along across
the Rangely Field. By keeping reservoir pressure from exceeding the threshold of ~3730 psi for extended
periods of time (multiple years), induced seismic events can be greatly mitigated. In the case that reservoir
pressures do exceed the threshold pressure, a reduction in injected volumes in the vicinity will bring down
the pressures back down gradually over a period of time.
4.5 Previous Operations
Chevron initiated C02 flooding in the Rangely Field in 1986. SEM and the prior operators have kept records
of the site and have completed numerous infill wells. SEM has not drilled any new wells in Rangely to date
but their standard practice for drilling new wells includes a rigorous review of nearby wells to ensure that
drilling will not cause damage to or interfere with existing wells. SEM will also follow AOR requirements
under the UIC Class II program, which require identification of all active and abandoned wells in the AOR
and implementation of procedures that ensure the integrity of those wells when applying for a permit for any
new injection well. These practices ensure that identified wells are sufficiently isolated and do not interfere
with the C02 EOR operations and reservoir pressure management. Consequently, SEM's operational
experience supports the conclusion that there are no unknown wells within the Rangely Field that penetrate
the Weber Sands and that it has sufficiently mitigated the risk of migration from older wells.
4.6 Pipeline / Surface Equipment
Damage to or failure of pipelines and surface equipment can result in unplanned losses of C02. SEM
reduces the risk of unplanned leakage from surface facilities, to the maximum extent practicable, by relying
on the use of prevailing design and construction practices and maintaining compliance with applicable
regulations. The facilities and pipelines currently utilize and will continue to utilize materials of construction
23
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and control processes that are standard for C02 EOR projects in the oil and gas industry. As described
above, all facilities in the Rangely Field are internally screened for proximity to the public. In the case of
pipeline and surface equipment, best engineering practices call for more robust metallurgy in wellhead
equipment, and pressure transducers with low pressure alarms monitored through the SCADA system to
prevent and detect leakage. Operating and maintenance practices currently follow and will continue to follow
demonstrated industry standards. C02 delivery via the Raven Ridge pipeline system will continue to
comply with all applicable regulations. Finally, frequent routine visual inspection of surface facilities by field
staff will provide an additional way to detect leaks and further support SEM's efforts to detect and remedy
any leaks in a timely manner. Should leakage be detected from pipeline or surface equipment, the volume
of released C02 will be quantified following the requirements of Subpart W of EPA's GHGRP.
4.7 Lateral Migration Outside the Rangely Field
It is highly unlikely that injected C02 will migrate downdip and laterally outside the Rangely Field because of
the nature of the geology and the approach used for injection. First, as indicated in Section 2.2.1 "Geology
of the Rangely Field," the Rangely Field is situated at the top of a dome structural trap, with all directions
pointing down-dip from the highest point. This means that over long periods of time, injected C02 will tend
to rise vertically towards the point in the Rangely Field with the highest elevation. Second, the planned
injection volumes and active fluid management during injection operations will prevent C02 from migrating
laterally stratigraphically (down-dip structurally) out of the structure. Finally, SEM will not be increasing the
total volume of fluids in the Rangely Field.
COGCC requires that injection pressures be limited to ensure injection fluids do not migrate outside the
permitted injection interval. In the Rangely Field, SEM uses two methods to contain fluids: reservoir
pressure management and the careful placement and operation of wells along the outer producing limits of
the units.
Reservoir pressure in the Rangely Field is managed by maintaining an injection to withdrawal ratio (IWR)
of approximately 1.0. To maintain the IWR, SEM monitors fluid injection to ensure that reservoir pressure
does not increase to a level that would fracture the reservoir seal or otherwise damage the oil field.
SEM also prevents injected fluids from migrating out of the injection interval by keeping injection pressure
below the formation fracture pressure, which is measured using historic step-rate tests. In these tests,
injection pressures are incrementally increased (e.g., in "steps") until injectivity increases abruptly, which
indicates that an opening or fracture has been created in the rock. SEM manages its operations to ensure
that injection pressures are kept below the formation fracture pressure so as to ensure that the valuable
fluid hydrocarbons and C02 remain in the reservoir.
There are a few small producer wells operated by third parties outside the boundary of Rangely Field. There
are currently no significant commercial operations surrounding the Rangely Field to interfere with SEM's
operations.
Based on site characterization and planned and projected operations SEM estimates the total volume of
stored C02 will be approximately 35.7% of calculated capacity.
4.8 Drilling Through the C02 Area
It is possible that at some point in the future, drilling through the containment zone into the Weber Sands
could occur and inadvertently create a leakage pathway. SEM's review of this issue concludes that this risk
is very low for two reasons. First, SEM's visual inspection process, including routine site visits, is designed
to identify unapproved drilling activity in the Rangely Field. Second, SEM plans to operate the C02 EOR
flood in the Rangely Field for several more years, and will continue to be vigilant about protecting the
integrity of its assets and maximizing the potential of resources (oil, gas, C02). In the unlikely event SEM
would sell the field to a new operator, provisions would result in a change to the reporting program and
24
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would be addressed at that time.
4.9 Diffuse Leakage through the Seal
Diffuse leakage through the seal formed by the Moenkopi Formation is highly unlikely. The presence of a
gas cap trapped over millions of years as discussed in Section 2.2.3 confirms that the seal has been
secure for a very long time. Injection pattern monitoring program referenced in Section 2.3.1 and detailed
in Section 5 assures that no breach of the seal will be created. The seal is highly impermeable where
unperforated, cemented across the horizon where perforated by wells, and unexplained changes in
injection pressure would trigger investigation as to the cause. Further, if C02 were to migrate through the
Moenkopi seal, it would migrate vertically until it encountered and was trapped by any of the numerous
shallower shale seals
4.10 Monitoring, Response, and Reporting Plan for C02 Loss
As discussed above, the potential sources of leakage include fairly routine issues, such as problems with
surface equipment (pumps, valves, etc.) or subsurface equipment (wellbores), and unique events such as
induced fractures. Table 3 summarizes some of these potential leakage scenarios, the monitoring activities
designed to detect those leaks, SEM's standard response, and other applicable regulatory programs
requiring similar reporting.
Sections 5.1.5 - 5.1.7 discuss the approaches envisioned for quantifying the volumes of leaked C02. Given
the uncertainty concerning the nature and characteristics of leaks that will be encountered, the most
appropriate methods for quantifying the volume of leaked C02 will be determined at the time. In the event
leakage occurs, SEM plans to determine the most appropriate methods for quantifying the volume leaked
and will report it as required as part of the annual Subpart RR submission.
Any volume of C02 detected leaking to surface will be quantified using acceptable emission factors such
as those found in 40 CFR Part 98 Subpart W or engineering estimates of leak amounts based on
measurements in the subsurface, SEM's field experience, and other factors such as the frequency of
inspection. As indicated in Sections 5.1 and 7.4, leaks will be documented, evaluated and addressed in a
timely manner. Records of leakage events will be retained in the electronic environmental documentation
and reporting system. Repairs requiring a work order will be documented in the electronic equipment
maintenance system.
Table 3 Response Plan for C02 Loss
Risk
Monitoring Plan
Response Plan
Parallel
Reporting (if
any)
Loss of Well Control
Tubing Leak
Monitor changes in tubing and
annulus pressure; MIT for injectors
Well is shut in and
Workover crews respond
within days
COGCC
Casing Leak
Routine Field inspection; monitor
changes in annulus pressure; MIT for
injectors; extra attention to high risk
wells
Well is shut in and
Workover crews respond
within days
COGCC
Wellhead Leak
Routine Field inspection
Well is shut in and
Workover crews respond
within days
COGCC
Loss of Bottom-
hole
pressure control
Blowout during well operations
Maintain well kill
procedures
COGCC
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Unplanned wells
drilled through
Weber Sands
Routine Field inspection to
prevent unapproved drilling;
compliance with COGCC permitting
for planned wells.
Assure compliance with
COGCC regulations
COGCC
Permitting
Loss of seal in
abandoned wells
Reservoir pressure in monitor wells;
high pressure found in new wells
Re-enter and reseal
abandoned wells
COGCC
Leaks in Surface Facilities
Pumps, valves, etc.
Routine Field inspection; SCADA
Maintenance crews
respond within days
Subpart W
Subsurface Leaks
Leakage along
faults
Reservoir pressure in monitor wells;
high pressure found in new wells
Shut in injectors near
faults
-
Overfill beyond
spill
points
Reservoir pressure in monitor wells;
high; pressure found in new wells
Fluid management
along
lease lines
-
Leakage through
induced fractures
Reservoir pressure in monitor wells;
high pressure found in new wells
Comply with rules for
keeping pressures
below
parting pressure
-
Leakage due to
seismic event
Reservoir pressure in monitor wells;
high
pressure found in new wells
Shut in injectors near
seismic event
-
Available studies of actual well leaks and natural analogs (e.g., naturally occurring C02 geysers) suggest
that the amount released from routine leaks would be small as compared to the amount of C02 that would
remain stored in the formation.
4.11 Summary
The structure and stratigraphy of the Weber Sands in the Rangely Field is ideally suited forthe injection and
storage of C02. The stratigraphy within the C02 injection zones is porous, permeable and very thick,
providing ample capacity for long-term C02 storage. The Weber Sands is overlain by several intervals of
impermeable geologic zones that form effective seals or "caps" to fluids in the Weber Sands (See Figure
4). After assessing potential risk of release from the subsurface and steps that have been taken to prevent
leaks, SEM has determined that the potential threat of leakage is extremely low.
In summary, based on a careful assessment of the potential risk of release of C02 from the subsurface, SEM
has determined that there are no leakage pathways at the Rangely Field that are likely to result in significant
loss of C02 to the atmosphere. Further, given the detailed knowledge of the Field and its operating
protocols, SEM concludes that it would be able to both detect and quantify any C02 leakage to the surface
that could arise through either identified or unexpected leakage pathways.
5. Monitoring and Considerations for Calculating Site Specific Variables
Monitoring will also be used to determine the quantities in the mass balance equation and to make the
demonstration that the C02 plume will not migrate to the surface after the time of discontinuation.
5.1 Forthe Mass Balance Equation
5.1.1 General Monitoring Procedures
As part of its ongoing operations, SEM monitors and collects flow, pressure, and gas composition data from
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the Rangely Field in centralized data management systems. These data are monitored continually by
qualified technicians who follow SEM response and reporting protocols when the systems deliver
notifications that data exceed statistically acceptable boundaries.
As indicated in Figures 10 and 11, custody-transfer meters are used at the point at which custody of the
C02 from the Raven Ridge pipeline delivery system is transferred to SEM, and at the points at which custody
of oil and NGLs are transferred to outside parties. Meters measure flow rate continually. Fluid composition
will be determined, at a minimum, quarterly, consistent with EPA GHGRP's Subpart RR, section 98.447(a).
All meter and composition data are documented, and records will be retained for at least three years.
Metering protocols used by SEM follow the prevailing industry standard(s) for custody transfer as currently
promulgated by the API, the American Gas Association (AGA), and the Gas Processors Association (GPA),
as appropriate. This approach is consistent with EPA GHGRP's Subpart RR, section 98.444(e)(3). These
meters will be maintained routinely, operated continually, and will feed data directly to the centralized data
collection systems. The meters meet the industry standard for custody transfer meter accuracy and
calibration frequency. These custody meters provide the most accurate way to measure mass flows.
SEM maintains in-field process control meters to monitor and manage in-field activities on a real time basis.
These are identified as operations meters in Figures 10 and 11. These meters provide information used to
make operational decisions but are not intended to provide the same level of accuracy as the custody-
transfer meters. The level of precision and accuracy for in-field meters currently satisfies the requirements
for reporting in existing UIC permits. Although these meters are accurate for operational purposes, it is
important to note that there is some variance between most commercial meters (on the order of 1-5%)
which is additive across meters. This variance is due to differences in factory settings and meter calibration,
as well as the operating conditions within a field. Meter elevation, changes in temperature (over the course
of the day), fluid composition (especially in multi-component or multi-phase streams), or pressure can affect
in-field meter readings. Unlike in a saline formation, where there are likely to be only a few injection wells
and associated meters, at C02 EOR operations in the Rangely Field there are currently 662 active injection
and production wells and a comparable number of meters, each with an acceptable range of error. This is
a site-specific factor that is considered in the mass balance calculations described in Section 7.
5.1.2 C02 Received
SEM measures the volume of received C02 using commercial custody transfer meters at the off-take point
from the Raven Ridge pipeline delivery system. This transfer is a commercial transaction that is
documented. C02 composition is governed by the contract and the gas is routinely sampled to determine
composition. No C02 is received in containers.
5.1.3 C02 Injected into the Subsurface
Injected C02 will be calculated using the flow metervolumes at the operations meter at the outlet of the C02
Reinjection Facility and the custody transfer meter at the C02 off-take points from the Raven Ridge pipeline
delivery system
5.1.4 C02 Produced, Entrained in Products, and Recycled
The following measurements are used for the mass balance equations in Section 7:
C02 produced is calculated using the volumetric flow meters at the inlet to the C02 Reinjection Facility.
These flow meters, as illustrated on Figure 10, are downstream of the field collection station separators
and bulk produced fluid separators at the water injection plants
C02 is produced as entrained or dissolved C02 in produced oil, as indicated in Figures 10 and 11. This is
calculated using volumetric flow through the custody transfer meter.
Recycled C02 is calculated using the volumetric flow meter at the outlet of the C02 Reinjection Facility,
which is an operations meter.
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5.1.5 C02 Emitted by Surface Leakage
As discussed in Section 5.1.6 and 5.1.7 below, SEM uses 40 CFR Part 98 Subpart Wto estimate surface
leaks from equipment at the Rangely Field. Subpart W uses a factor-driven approach to estimate equipment
leakage. In addition, SEM uses an event-driven process to assess, address, track, and if applicable quantify
potential C02 leakage to the surface.
The multi-layered, risk-based monitoring program for event-driven incidents has been designed to meet two
objectives, in accordance with the leakage risk assessment in Section 4: 1) to detect problems before C02
leaks to the surface; and 2) to detect and quantify any leaks that do occur. This section discusses how this
monitoring will be conducted and used to quantify the volumes of C02 leaked to the surface.
Monitoring for potential Leakage from the Injection/Production Zone:
SEM will monitor both injection into and production from the reservoir as a means of early identification of
potential anomalies that could indicate leakage from the subsurface.
SEM develops injection plans for each well and that is distributed to operations weekly. If injection pressure
or rate measurements are beyond the specified set points determined as part of each pattern injection plan,
the operations engineer will notify field personnel and they will investigate and resolve the problem. These
excursions will be reviewed by well-management personnel to determine if C02 leakage may be occurring.
Excursions are not necessarily indicators of leaks; they simply indicate that injection rates and pressures
are not conforming to the pattern injection plan. In many cases, problems are straightforward to fix (e.g., a
meter needs to be recalibrated or some other minor action is required), and there is no threat of C02
leakage. In the case of issues that are not readily resolved, more detailed investigation and response would
be initiated, and internal SEM support staff would provide additional assistance and evaluation. Such issues
would lead to the development of a work order in SEM's work order management system. This record
enables the company to track progress on investigating potential leaks and, if a leak has occurred, to
quantify its magnitude.
Likewise, SEM develops a forecast of the rate and composition of produced fluids. Each producer well is
assigned to one collection station and is isolated twice during each monthly cycle for a well production test.
This data is reviewed on a periodic basis to confirm that production is at the level forecasted. If there is a
significant deviation from the forecast, well management personnel investigate. If the issue cannot be
resolved quickly, more detailed investigation and response would be initiated. As in the case of the injection
pattern monitoring, if the investigation leads to a work order in the SEM work order management system,
this record will provide the basis for tracking the outcome of the investigation and if a leak has occurred. If
leakage in the flood zone were detected, SEM would use an appropriate method to quantify the involved
volume of C02. This might include use of material balance equations based on known injected quantities
and monitored pressures in the injection zone to estimate the volume of C02 involved.
A subsurface leak might not lead to a surface leak. In the event of a subsurface leak, SEM would determine
the appropriate approach for tracking subsurface leakage to determine and quantify leakage to the surface.
To quantify leakage to the surface, SEM would estimate the relevant parameters (e.g., the rate,
concentration, and duration of leakage) to quantify the leak volume. Depending on specific circumstances,
these determinations may rely on engineering estimates.
In the event leakage from the subsurface occurred diffusely through the seals, the leaked gas would include
H2S, which would trigger the alarm on the personal monitors worn by field personnel. Such a diffuse leak
from the subsurface has not occurred in the Rangely Field. In the event such a leak was detected, field
personnel from across SEM would determine how to address the problem. The team might use modeling,
engineering estimates, and direct measurements to assess, address, and quantify the leakage.
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Monitoring of Wellbores:
SEM monitors wells through continual, automated pressure monitoring in the injection zone (as described in
Section 4.2), monitoring of the annular pressure in wellheads, and routine maintenance and inspection.
Leaks from wellbores would be detected through the follow-up investigation of pressure anomalies, visual
inspection, or the use of personal H2S monitors.
Anomalies in injection zone pressure may not indicate a leak, as discussed above. However, if an
investigation leads to a work order, field personnel would inspect the equipment in question and determine
the nature of the problem. If it is a simple matter, the repair would be made and the volume of leaked C02
would be included in the 40 CFR Part 98 Subpart W report for the Rangely Field, as well as reported in
Subpart RR . If more extensive repair were needed, SEM would determine the appropriate approach for
quantifying leaked C02 using the relevant parameters (e.g., the rate, concentration, and duration of
leakage). The work order would serve as the basis for tracking the event for GHG reporting.
Anomalies in annular pressure or other issues detected during routine maintenance inspections would be
treated in the same way. Field personnel would inspect the equipment in question and determine the nature
of the problem. For simple matters the repair would be made at the time of inspection and the volume of
leaked C02 would be included in the 40 CFR Part 98 Subpart W report for the Rangely Field, as well as
reported in Subpart RR. If more extensive repairs were needed, a work order would be generated and SEM
would determine the appropriate approach for quantifying leaked C02 using the relevant parameters (e.g.,
the rate, concentration, and duration of leakage). The work order would serve as the basis for tracking the
event for GHG reporting.
Because leaking C02 at the surface is very cold and leads to formation of bright white clouds and ice that
are easily spotted, SEM also employs a two-part visual inspection process in the general area ofthe Rangely
Field to detect unexpected releases from wellbores. First, field personnel visit the surface facilities on a
routine basis. Inspections may include tank volumes, equipment status and reliability, lube oil levels,
pressures and flow rates in the facility, and valve leaks. Field personnel inspections also check that injectors
are on the proper WAG schedule and observe the facility for visible C02 or fluid line leaks.
Historically, SEM has not experienced any unexpected release events in the Rangely Field. An identified
need for repair or maintenance through visual inspections results in a work order being entered into SEM's
equipment and maintenance work order management system. The time to repair any leak is dependent on
several factors, such as the severity ofthe leak, available manpower, location ofthe leak, and availability
of materials required for the repair. Critical leaks are acted upon immediately.
Finally, SEM uses the data collected by the H2S monitors, which are worn by all field personnel at all times,
as a last method to detect leakage from wellbores. The H2S monitors detection limit is 10ppm; if an H2S
alarm is triggered, the first response is to protect the safety ofthe personnel, and the next step is to safely
investigate the source of the alarm. As noted previously, SEM considers H2S a proxy for potential C02
leaks in the field. Thus, detected H2S leaks will be investigated to determine if potential C02 leakage is
present, but not used to determine the leak volume. If the incident results in a work order, this will serve as
the basis for tracking the event for GHG reporting.
Other Potential Leakage at the Surface:
SEM will utilize the same visual inspection process and H2S monitoring system to detect other potential
leakage at the surface as it does for leakage from wellbores. SEM utilizes routine visual inspections to
detect significant loss of C02 to the surface. Field personnel routinely visit surface facilities to conduct a
visual inspection. Inspections may include review of tank level, equipment status, lube oil levels, pressures
and flow rates in the facility, valve leaks, ensuring that injectors are on the proper WAG schedule, and also
conducting a general observation ofthe facility for visible C02 or fluid line leaks. If problems are detected,
field personnel would investigate, and, if maintenance is required, generate a work order in the maintenance
system, which is tracked through completion. In addition to these visual inspections, SEM will use the results
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of the personal H2S monitors worn by field personnel as a supplement for smaller leaks that may escape
visual detection.
If C02 leakage to the surface is detected, it will be reported to surface operations personnel who will review
the reports and conduct a site investigation. If maintenance is required, a work order will be generated in
the work order management system. The work order will describe the appropriate corrective action and be
used to track completion of the maintenance action. The work order will also serve as the basis for tracking
the event for GHG reporting and quantifying any C02 emissions.
5.1.6 C02 emitted from equipment leaks and vented emissions of C02 from surface equipment
located between the injection flow meter and the injection wellhead.
SEM evaluates and estimates the mass of C02 emitted (in metric tons) annually from equipment leaks and
vented emissions of C02 from equipment located on the surface between the flow meter used to measure
injection quantity and the injection wellhead, as required under 40 CFR Part 98 Subpart W and 40 CFR
Part 98 Subpart RR.
5.1.7 Mass of C02 emissions from equipment leaks and vented emissions of C02 from surface
equipment located between the production flow meter and the production wellhead
SEM evaluates and estimates the mass of C02 emitted (in metric tons) annually from equipment leaks and
vented emissions of C02 from equipment located on the surface between the production wellhead and the
flow meter used to measure production quantity, as required under 40 CFR Part 98 Subpart W and 40 CFR
Part 98 Subpart RR.
5.2 To Demonstrate that Injected C02 is not Expected to Migrate to the Surface
At the end of the Specified Period, SEM intends to cease injecting C02 for the subsidiary purpose of
establishing the long-term storage of C02 in the Rangely Field. After the end of the Specified Period, SEM
anticipates that it will submit a request to discontinue monitoring and reporting. The request will demonstrate
that the amount of C02 reported under 40 CFR §98.440-449 (Subpart RR) is not expected to migrate in the
future in a manner likely to result in surface leakage. At that time, SEM will be able to support its request
with years of data collected during the Specified Period as well as two to three (or more, if needed) years
of data collected after the end of the Specified Period. This demonstration will provide the information
necessary for the EPA Administrator to approve the request to discontinue monitoring and reporting and
may include, but is not limited to:
i. Data comparing actual performance to predicted performance (purchase, injection, production)
over the monitoring period;
ii. An assessment of the C02 leakage detected, including discussion of the estimated amount of
C02 leaked and the distribution of emissions by leakage pathway;
iii. A demonstration that future operations will not release the volume of stored C02 to the surface;
iv. A demonstration that there has been no significant leakage of C02; and,
v. An evaluation of reservoir pressure in the Rangely Field that demonstrates that injected fluids are
not expected to migrate in a manner to create a potential leakage pathway.
6. Determination of Baselines
SEM intends to utilize existing automatic data systems to identify and investigate excursions from expected
performance that could indicate C02 leakage. SEM's data systems are used primarily for operational
control and monitoring and as such are set to capture more information than is necessary for reporting in the
Annual Subpart RR Report. SEM will develop the necessary system guidelines to capture the information that
is relevant to identify possible C02 leakage. The following describes SEM's approach to collecting this
information.
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Visual Inspections
As field personnel conduct routine inspections, work orders are generated in the electronic system for
maintenance activities that cannot be addressed on the spot. Methods to capture work orders that involve
activities that could potentially involve C02 leakage will be developed, if not currently in place. Examples
include occurrences of well workover or repair, as well as visual identification of vapor clouds or ice
formations. Each incident will be flagged for review by the person responsible for MRV documentation. The
responsible party will be provided in the monitoring plan, as required under Subpart A, 98.3(g). The Annual
Subpart RR Report will include an estimate of the amount of C02 leaked. Records of information used to
calculate emissions will be maintained on file for a minimum of three years.
Personal H2S Monitors
H2S monitors are worn by all field personnel. Any monitor alarm triggers an immediate response to ensure
personnel are not at risk and to verify the monitor is working properly. The person responsible for MRV
documentation will receive notice of all incidents where H2S is confirmed to be present. The Annual Subpart
RR Report will provide an estimate the amount of C02 emitted from any such incidents. Records of
information to calculate emissions will be maintained on file for a minimum of three years.
Injection Rates. Pressures and Volumes
SEM develops target injection rate and pressure for each injector, based on the results of ongoing pattern
modeling and within permitted limits. The injection targets are programmed into the WAG controllers. High
and low set points are also programmed into the SCADA, and flags whenever statistically significant
deviations from the targeted ranges are identified. The set points are designed to be conservative, because
it is preferable to have too many flags rather than too few. As a result, flags can occur frequently and are
often found to be insignificant. For purposes of Subpart RR reporting, flags (or excursions) will be screened
to determine if they could also lead to C02 leakage to the surface. The person responsible for the MRV
documentation will receive notice of excursions and related work orders that could potentially involve C02
leakage. The Annual Subpart RR Report will provide an estimate of C02 emissions. Records of information
to calculate emissions will be maintained on file for a minimum of three years.
Production Volumes and Compositions
SEM develops a general forecast of production volumes and composition which is used to periodically
evaluate performance and refine current and projected injection plans and the forecast. This information is
used to make operational decisions but is not recorded in an automated data system. Sometimes, this
review may result in the generation of a work order in the maintenance system. The MRV plan
implementation lead will review such work orders and identify those that could result in C02 leakage. Should
such events occur, leakage volumes would be calculated following the approaches described in Sections 4
and 5. Impact to Subpart RR reporting will be addressed, if deemed necessary.
7. Determination of Sequestration Volumes Using Mass Balance Equations
To account for the site conditions and complexity of a large, active EOR operation, SEM will utilize the
locations described below for obtaining volume data for the equations in Subpart RR §98.443 as indicated
below.
The selection of the utilized locations, more specifically described in this Section 7, address the propagation
of error that would result if volume data from meters at each injection well were utilized. This issue arises
because while each meter has a small but acceptable margin of error, this error would become significant
if data were taken from the approximately 284 meters within the Rangely Field. As such, SEM will use the
data from custody and operations meters on the main system pipelines to determine injection volumes used
in the mass balance. This satisfies the requirement in 40 CFR 98.444 (b) 1 that you must select a point or
points of measurement at which the C02 stream is representative of the C02 streams being injected.
The volumetric flow meters utilized for CQ2 produced are located at the inlet to the RCF. These flow
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meters, as illustrated on Figure 10, are directly downstream of the field collection station separators and
bulk produced fluid separators at the water injection plants. This satisfies the requirement in 40 CFR
98.444 (c)(1) for production, which states, "The point of measurement for the quantity of C02 produced
from oil or other fluid production wells is a flow meter directly downstream of each separator that sends a
stream of gas into a recycle or end use system."
The following sections describe how each element of the mass-balance equation (Equation RR-11) will be
calculated.
7.1. Mass of C02 Received
SEM will use equation RR-2 as indicated in Subpart RR §98.443 to calculate the mass of 0O2 received
from each delivery meter immediately upstream of the Raven Ridge pipeline delivery system on the Rangely
Field. The volumetric flow at standard conditions will be multiplied by the C02 concentration and the density
of C02 at standard conditions to determine mass.
where:
C02T,r = Net annual mass of C02 received through flow meter r (metric tons).
Qr,p = Quarterly volumetric flow through a receiving flow meter r in quarter p at standard conditions
(standard cubic meters).
Sr,p = Quarterly volumetric flow through a receiving flow meter r that is redelivered to another facility
without being injected into your well in quarter p (standard cubic meters).
D = Density of C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.
Cco2,P,r = Quarterly C02 concentration measurement in flow for flow meter r in quarter p (vol. percent
C02, expressed as a decimal fraction),
p = Quarter of the year,
r = Receiving flow meter.
Given SEM's method of receiving C02 and requirements at Subpart RR §98.444(a):
All delivery to the Rangely Field is used within the unit so quarterly flow redelivered, Sr,p , is
zero (0) and will not be included in the equation.
Quarterly C02 concentration will be taken from the gas measurement database SEM will sum to total
Mass of CQ2 Received using equation RR-3 in 98.443
where:
CO2 = Total net annual mass of C02 received (metric tons).
CC>2T,r = Net annual mass of C02 received (metric tons) as calculated in Equation RR-1 or RR-2 for flow
meter r.
r = Receiving flow meter.
7.2 Mass of C02 Injected into the Subsurface
The equation for calculating the Mass of C02 Injected into the Subsurface at the Rangely Field is equal to
the sum of the Mass of C02 Received as calculated in RR-3 of 98.443 (as described in Section 7.1) and the
Mass of C02 Recycled as calculated using measurements taken from the flow meter located at the output
of the RCF. As previously explained, using data at each injection well would give an inaccurate estimate of
4
CO2 = £CO:,r (Eq. RR-3)
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total injection volume due to the large number of wells and the potential for propagation of error due to
allowable calibration ranges for each meter.
The mass of C02 recycled will be determined using equation RR-5 as follows:
4
C02, li = X Qi>-« *D * Cco-,, (Ec3 - RR-5)
/'=!
where:
CO2.11 = Annual C02 mass injected (metric tons) as measured by flow meter u.
Qp.u = Quarterly volumetric flow rate measurement for flow meter u in quarter p at standard conditions
(standard cubic meters per quarter).
D = Density of C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.
Cco2,p,u = C02 concentration measurement in flow for flow meter u in quarter p (vol. percent C02,
expressed as a decimal fraction),
p = Quarter of the year,
u = Flow meter.
The aggregate injection data will be calculated pursuant to the procedures specified in equation RR-6 as
follows:
V
CO;,i = ]rC0lu (Eq. RR-6)
where:
CO21 = Total annual C02 mass injected (metric tons) through all injection wells.
CO2.11 = Annual C02 mass injected (metric tons) as measured by flow meter u.
u = Flow meter.
7.3 Mass of C02 Produced
The Mass of C02 Produced at the Rangely Field will be calculated using the measurements from the flow
meters at the inlet to RCF and for C02 entrained in the sales oil, the custody transfer meter for oil sales
rather than the metered data from each production well. Again, using the data at each production well would
give an inaccurate estimate of total injection due to the large number of wells and the potential for
propagation of error due to allowable calibration ranges for each meter.
Equation RR-8 in 98.443 will be used to calculate the mass of C02 produced from all injection wells as
follows:
4
C°2, w = £(?,, *D * Cca (Eq. RR-8)
Where:
C02,w = Annual C02 mass produced (metric tons) through separator w.
Qp,w = Volumetric gas flow rate measurement for separator w in quarter p at standard conditions
(standard cubic meters).
D = Density of C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.
Cco2,p,w = C02 concentration measurement in flow for separator w in quarter p (vol. percent C02,
expressed as a decimal fraction),
p = Quarter of the year,
w = Separator.
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Equation RR-9 in 98.443 will be used to aggregate the mass of C02 produced and the mass of C02
entrained in oil or other fluid leaving the Rangely Field as follows:
w
C02P = (l+X) * XC02,w (Eq. RR-9)
w=1
Where:
CO2P = Total annual C02 mass produced (metric tons) through all separators in the reporting year.
CO2W = Annual C02 mass produced (metric tons) through separator w in the reporting year.
X = Entrained C02 in produced oil or other fluid divided by the C02 separated through all separators in
the reporting year (weight percent C02, expressed as a decimal fraction),
w = Separator.
7.4 Mass of C02 emitted by Surface Leakage
SEM will calculate and report the total annual Mass of C02 emitted by Surface Leakage using an approach
that relies on 40 CFR Part 98 Subpart W reports for equipment leakage, and tailored calculations for all
other surface leaks. As described in Sections 4 and 5.1.5-5.1.7, SEM is prepared to address the potential
for leakage in a variety of settings. Given the uncertainty concerning the nature and characteristics of leaks
that will be encountered, it is not clear the method for quantifying the volume of leaked C02 that would be
most appropriate. Estimates of the amount of C02 leaked to the surface will depend on a number of site-
specific factors including measurements of flowrate, pressure, size of leak opening, and duration of the
leak. Engineering estimates, and emission factors, depending on the source and nature of the leakage will
also be used.
SEM's process for quantifying leakage will entail using best engineering principles or emission factors.
While it is not possible to predict in advance the types of leaks that will occur, SEM describes some
approaches for quantification in Section 5.1.5-5.1.7. In the event leakage to the surface occurs, SEM would
quantify and report leakage amounts, and retain records that describe the methods used to estimate or
measure the volume leaked as reported in the Annual Subpart RR Report.
Equation RR-10 in 48.433 will be used to calculate and report the Mass of CQ2 emitted by Surface Leakage:
x
C°2E = XC°2,x (Eq, RR-10)
l
where:
CO2E = Total annual C02 mass emitted by surface leakage (metric tons) in the reporting year.
C02,x = Annual C02 mass emitted (metric tons) at leakage pathway x in the reporting year,
x = Leakage pathway.
7.5 Mass of C02 sequestered in subsurface geologic formations.
SEM will use equation RR-11 in 98.443 to calculate the Mass of C02 Sequestered in Subsurface
Geologic Formations in the Reporting Year as follows:
CO2 = CO21 - CO2P - CO2E - C02Pi CO2FP {Ec[. RR-11)
where:
C02 = Total annual C02 mass sequestered in subsurface geologic formations (metric tons) at the facility
in the reporting year.
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C02| = Total annual CO2 mass injected (metric tons) in the well or group of wells covered by this source
category in the reporting year.
CO2P = Total annual C02 mass produced (metric tons) in the reporting year.
CO2E = Total annual C02 mass emitted (metric tons) by surface leakage in the reporting year.
CO2F1 = Total annual C02 mass emitted (metric tons) from equipment leaks and vented emissions of C02
from equipment located on the surface between the flow meter used to measure injection quantity and the
injection wellhead, for which a calculation procedure is provided in subpart W of this part.
CO2FP = Total annual C02 mass emitted (metric tons) from equipment leaks and vented emissions of
C02 from equipment located on the surface between the production wellhead and the flow meter used to
measure production quantity, for which a calculation procedure is provided in subpart W of this part.
7.6 Cumulative mass of C02 reported as sequestered in subsurface geologic formations
SEM will sum up the total annual volumes obtained using equation RR-11 in 98.443 to calculate the
Cumulative Mass of CQ2 Sequestered in Subsurface Geologic Formations.
8. MRV Plan Implementation Schedule
The activities described in this MRV Plan are in place, and reporting is planned to start upon EPA approval.
Other GHG reports are filed on March 31 of the year after the reporting year and it is anticipated that the
Annual Subpart RR Report will be filed at the same time. As described in Section 3.3 above, SEM anticipates
that the MRV program will be in effect during the Specified Period, during which time SEM will operate the
Rangely Field with the subsidiary purpose of establishing long-term containment of a measurable quantity
of C02 in subsurface geological formations at the Rangely Field. SEM anticipates establishing that a
measurable amount of C02 injected during the Specified Period will be stored in a manner not expected
to migrate resulting in future surface leakage. At such time, SEM will prepare a demonstration supporting
the long-term containment determination and submit a request to discontinue reporting under this MRV
plan. See 40 C.F.R. § 98.441 (b)(2)(ii).
9. Quality Assurance Program
9.1 Monitoring QA/QC
As indicated in Section 7, SEM has incorporated the requirements of §98.444 (a) - (d) in the discussion
of mass balance equations. These include the following provisions.
CQ2 Received and Injected
The quarterly flow rate of C02 received by pipeline is measured at the receiving custody
transfer meters.
The quarterly C02 flow rate for recycled C02 is measured at the flow meter located at the C02
Reinjection facility outlet.
CQ2 Produced
The point of measurement for the quantity of C02 produced is a flow meter at the C02 Reinjection
facility inlet. . C02 produced as entrained or dissolved C02 in produced oil is calculated using
volumetric flow through the custody transfer meter.
The produced gas stream is sampled at least once per quarter immediately downstream of the flow
meter used to measure flow rate of that gas stream and measure the C02 concentration of the
sample.
The quarterly flow rate of the produced gas is measured at the flow meters located at the C02
Reinjection facility inlet.
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C02 emissions from equipment leaks and vented emissions of C02
These volumes are measured in conformance with the monitoring and QA/QC requirements
specified in subpart W of 40 CFR Part 98.
Flow meter provisions
The flow meters used to generate date for the mass balance equations in Section 7 are:
Operated continuously except as necessary for maintenance and calibration.
Operated using the calibration and accuracy requirements in 40 CFR §98.3(i).
Operated in conformance with American Petroleum Institute (API) standards.
National Institute of Standards and Technology (NIST) traceable.
Concentration of CQ2
As indicated in Appendix 1, C02 concentration is measured using an appropriate standard method. Further,
all measured volumes of C02 have been converted to standard cubic meters at a temperature of 60
degrees Fahrenheit and at an absolute pressure of 1 atmosphere, including those used in Equations RR-
2, RR-5 and RR-8 in Section 7.
Missing Data Procedures
In the event SEM is unable to collect data needed for the mass balance calculations, procedures
for estimating missing data in §98.445 will be used as follows:
A quarterly flow rate of C02 received that is missing would be estimated using invoices or using a
representative flow rate value from the nearest previous time period.
A quarterly C02 concentration of a C02 stream received that is missing would be estimated using
invoices or using a representative concentration value from the nearest previous time period.
A quarterly quantity of C02 injected that is missing would be estimated using a representative quantity
of C02injected from the nearest previous period of time at a similar injection pressure.
For any values associated with C02 emissions from equipment leaks and vented emissions of C02
from surface equipment at the facility that are reported in this subpart, missing data estimation
procedures specified in subpart Wof 40 CFR Part 98 would be followed.
The quarterly quantity of C02 produced from subsurface geologic formations that is missing would be
estimated using a representative quantity of C02 produced from the nearest previous period of time.
MRV Plan Revisions
In the event there is a material change to the monitoring and/or operational parameters of the SEM C02
EOR operations in the Rangely Field that is not anticipated in this MRV plan, the MRV plan will be revised
and submitted to the EPA Administrator within 180 days as required in §98.448(d).
Records Retention
SEM will follow the record retention requirements specified by §98.3(g). In addition, it will follow the
requirements in Subpart RR §98.447 by maintaining the following records for at least three years:
Quarterly records of C02 received at standard conditions and operating conditions, operating
temperature and pressure, and concentration of these streams.
Quarterly records of produced C02, including volumetric flow at standard conditions and operating
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conditions, operating temperature and pressure, and concentration of these streams.
Quarterly records of injected C02 including volumetric flow at standard conditions and operating
conditions, operating temperature and pressure, and concentration of these streams.
Annual records of information used to calculate the C02 emitted by surface leakage from leakage
pathways.
Annual records of information used to calculate the C02 emitted from equipment leaks and vented
emissions of C02 from equipment located on the surface between the flow meter used to measure
injection quantity and the injection wellhead.
Annual records of information used to calculate the C02 emitted from equipment leaks and vented
emissions of C02 from equipment located on the surface between the production wellhead and the
flow meter used to measure production quantity.
These data will be collected as generated and aggregated as required for reporting purposes.
Appendices
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Appendix 1. Conversion Factors
SEM reports C02 volumes at standard conditions of temperature and pressure as defined in the State of
Colorado, which follows the international standard conditions for measuring C02 properties - 77 °F and
14.696 psi.
To convert these volumes into metric tonnes, a density is calculated using the Span and Wagner equation
of state as recommended by the EPA. Density was calculated using the database of thermodynamic
properties developed by the National Institute of Standards and Technology (NIST), available at
http://webbook.nist.gov/chemistrv/fluid/.
At EPA standard conditions of 77 °F and one atmosphere, the Span and Wagner equation of state gives a
density of 0.0026500 lb-moles per cubic foot. Using a molecular weight for C02 of 44.0095, 2204.62
lbs/metric ton and 35.314667 ft3/m3, gives a C02 density of 5.29003 x 10 5 MT/ft3 or 0.0018682 MT/m3.
The conversion factor 5.29003 x 10-5 MT/Mcf has been used throughout to convert SEM volumes to metric
tons.
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Appendix 2. Acronyms
AGA-American Gas Association
AMA - Active Monitoring Area
AoR - Area of Review
API-American Petroleum Institute
BCF - Billion Cubic Feet
bopd - barrels of oil per day
Cf- Cubic Feet
CCR - Code of Colorado Regulations
COGCC - Colorado Oil and Gas Conservation Commission
C02 - Carbon Dioxide
CRF - C02 Removal Facilities
EOR - Enhanced Oil Recovery
EPA - US Environmental Protection Agency
GHG - Greenhouse Gas
GHGRP - Greenhouse Gas Reporting Program
H2S - Hydrogen Sulfide
IWR - Injection to Withdrawal Ratio
LACT - Lease Automatic Custody Transfer meter
Md - Millidarcy
MIT - Mechanical Integrity Test
MFF - Main Field Fault
MMA - Maximum Monitoring Area
MMB - Million barrels
Mscf-Thousand standard cubic feet
MMscf- Million standard cubic feet
MMMT - Million metric tonnes
MMT -Thousand metric tonnes
MRV - Monitoring, Reporting, and Verification
MOC - Main oil column
MT - Metric Tonne
NGNatural Gas
NGLs - Natural Gas Liquids
NIST - National Institute of Standards and Technology
OOIP - Original Oil-ln-Place
OH - Open hole
POWC - Producible oil/water contact
PPM - Parts Per Million
RCF - Rangely Field C02 Recycling and Compression Facility
RRPC - Raven Ridge pipeline
RWSU - Rangely Weber Sand Unit
SCADA - Supervisory Control and Data Acquisition
SEM - Scout Energy Management, LLC
UIC - Underground Injection Control
VRU - Vapor Recovery Unit
WAG - Water Alternating Gas
XOM - ExxonMobil
39
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Appendix 3. References
Adams, L., 2006; Sequence and Mechanical Stratigraphy: An intergrated Reservoir Characterization of
the Weber Sandstone, Western Colorado. University of Texas at El Paso Ph.D. Dissertation.
Colorado Administrative Code Department 400 Division 404 Oil and Gas Conservation Commission
Section 2
Clark, Rory, Chevron North America E&P, Presentation to 6th Annual Wyoming C02 Conference, July 12,
2012, online: //www.uwyo.edu/eori/_files/C02conference12/rory_rangelycasehistory.pdf
Energy and Carbon Management Regulation in Colorado. May 22, 2023, online:
https://leg.colorado.gov/bills/sb23-285
US Department of Energy, National Energy Technology Laboratory. "Carbon Dioxide Enhanced Oil
Recovery - Untapped Domestic Energy Supply and Long Term Carbon Storage Solution," March 2010.
US Department of Energy, National Energy Technology Laboratory. "Carbon Sequestration Through
Enhanced Oil Recovery," April 2008.
Gale, Hoyt. Geology of the Rangely Oil District. Department of Interior United States Geological Survey,
Bulletin 350. 1908.
40
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Appendix 4. Glossary of Terms
This glossary describes some of the technical terms as they are used in this MRV plan. For additional
glossaries please see the U.S. EPA Glossary of UIC Terms
(http://water.epa.gov/tvpe/aroundwater/uic/alossarv.cfm') and the Schlumberger Oilfield Glossary
(http://www.glossary.oilfield.slb.com/).
Contain / Containment - having the effect of keeping fluids located within in a specified portion of a geologic
formation.
Dip-Very few, if any, geologic features are perfectly horizontal. They are almost always tilted. The direction
of tilt is called "dip." Dip is the angle of steepest descent measured from the horizontal plane. Moving higher
up structure is moving "updip." Moving lower is "downdip." Perpendicular to dip is "strike." Moving
perpendicular along a constant depth is moving along strike.
Downdip - See "dip."
Formation - A body of rock that is sufficiently distinctive and continuous that it can be mapped.
Infill Drilling - The drilling of additional wells within existing patterns. These additional wells decrease
average well spacing. This practice both accelerates expected recovery and increases estimated ultimate
recovery in heterogeneous reservoirs by improving the continuity between injectors and producers. As well
spacing is decreased, the shifting flow paths lead to increased sweep to areas where greater hydrocarbon
saturations remain.
Permeability - Permeability is the measure of a rock's ability to transmit fluids. Rocks that transmit fluids
readily, such as sandstones, are described as permeable and tend to have many large, well-connected
pores. Impermeable formations, such as shales and siltstones, tend to be finer grained or of a mixed grain
size, with smaller, fewer, or less interconnected pores.
Phase - Phase is a region of space throughout which all physical properties of a material are essentially
uniform. Fluids that don't mix together segregate themselves into phases. Oil, for example, does not mix
with water and forms a separate phase.
Pore Space - See porosity.
Porosity - Porosity is the fraction of a rock that is not occupied by solid grains or minerals. Almost all rocks
have spaces between rock crystals or grains that is available to be filled with a fluid, such as water, oil or
gas. This space is called "pore space."
Saturation - The fraction of pore space occupied by a given fluid. Oil saturation, for example, is the fraction
of pore space occupied by oil.
Seal - A geologic layer (or multiple layers) of impermeable rock that serve as a barrier to prevent fluids
from moving upwards to the surface.
Secondary recovery - The second stage of hydrocarbon production during which an external fluid such as
water or gas is injected into the reservoirthrough injection wells located in rock that has fluid communication
with production wells. The purpose of secondary recovery is to maintain reservoir pressure and to displace
hydrocarbons toward the wellbore. The most common secondary recovery techniques are gas injection and
waterflooding.
Stratigraphic section - A stratigraphic section is a sequence of layers of rocks in the order they were
deposited.
41
-------
Strike - See "dip.
Updip - See "dip.
-------
Appendix 5. Well Identification Numbers
The following table presents the well name, API number, status and type for the wells in the RWSU as of
April 2023. The table is subject to change overtime as new wells are drilled, existing wells change status,
or existing wells are repurposed. The following terms are used:
Well Status
Producing refers to a well that is actively producing
Injecting refers to a well that is actively injecting
P&A refers to wells that have been closed (plugged and abandoned) per COGCC regulations
Shut In refers to wells that have been temporarily idled or shut-in
Monitor refers to a well that is used to monitor bottom home pressure in the reservoir
Well Type
Water / Gas Inject refers to wells that inject water and C02 Gas
Water Injection Well refers to wells that inject water
Oil well refers to wells that produce oil
Salt Water Disposal refers to a well used to dispose of excess water
Name
API Number
Well Type
Well Status
AC MCLAUGHLIN 46
51030632300
Water Injection Well
P&A
AC MCLAUGHLIN 64X
51030771700
Oil well
Producing
ASSOCIATED A 2
51030571400
Water / Gas Inject
P&A
ASSOCIATED A1
51030571300
Oil well
Producing
ASSOCIATED A2ST
51030571401
Water / Gas Inject
Injecting
ASSOCIATED A3X
51030778600
Oil well
Producing
ASSOCIATED A4X
51030791600
Oil well
Producing
ASSOCIATED A5X
51030803400
Water / Gas Inject
Injecting
ASSOCIATED A6X
51030801100
Water / Gas Inject
Injecting
ASSOCIATED LARSON UNIT A1
51030600900
Oil well
Producing
ASSOCIATED LARSON UNIT A2X
51030881500
Oil well
Producing
ASSOCIATED LARSON UNIT B1
51030601100
Oil well
Producing
ASSOCIATED LARSON UNIT B2X
51030950200
Oil well
Producing
ASSOCIATED UNIT A1
51030602600
Oil well
Producing
ASSOCIATED UNIT A2X UN A-2X
51031053200
Oil well
Producing
ASSOCIATED UNIT A3X
51031072300
Oil well
Producing
ASSOCIATED UNIT A4X
51031072200
Water / Gas Inject
Injecting
ASSOCIATED UNIT C1
51030582700
Oil well
Producing
BEEZLEY 1X22AX
51031075400
Water / Gas Inject
Injecting
BEEZLEY 2-22
51030574200
Oil well
Producing
BEEZLEY 3X 3X22
51031054900
Oil well
Producing
BEEZLEY 4X 22
51031055300
Oil well
Producing
BEEZLEY 5X22
51031174200
Oil well
Producing
BEEZLEY 6X22
51031174300
Oil well
Producing
43
-------
CARNEY 22X-35
51030724500
Oil well
P&A
CARNEY CT 10-4
51030608600
Oil well
Monitor
CARNEY CT 11-4
51030545700
Oil well
Monitor
CARNEY CT 12AX5
51030917600
Water / Gas Inject
Monitor
CARNEY CT 13-4
51030545900
Oil well
Producing
CARNEY CT 1-34
51030548200
Oil well
Producing
CARNEY CT 14-34
51030103500
Oil well
Producing
CARNEY CT 15-35
51030103700
Water / Gas Inject
Injecting
CARNEY CT 16-35
51030103300
Water / Gas Inject
Monitor
CARNEY CT 17-35
51030103200
Oil well
Producing
CARNEY CT 18-35
51030629500
Water / Gas Inject
Injecting
CARNEY CT 19-34
51030604400
Oil well
Producing
CARNEY CT 20X35
51030641300
Oil well
Producing
CARNEY CT 21X35
51030703300
Water / Gas Inject
Injecting
CARNEY CT 22X35ST
51030724501
Oil well
Producing
CARNEY CT 2-34
51030551400
Oil well
Monitor
CARNEY CT 23X35
51030726200
Water / Gas Inject
Injecting
CARNEY CT 24X35
51030728300
Water / Gas Inject
Monitor
CARNEY CT 27X34
51030746600
Water / Gas Inject
Injecting
CARNEY CT 28X
51030747400
Water / Gas Inject
Monitor
CARNEY CT 29X
51030753700
Water / Gas Inject
Injecting
CARNEY CT 30X34 30X
51030752600
Water / Gas Inject
Injecting
CARNEY CT 32X34
51030758900
Water / Gas Inject
Injecting
CARNEY CT 3-34
51030103900
Oil well
Producing
CARNEY CT 33X34
51030759200
Water / Gas Inject
Injecting
CARNEY CT 35X34
51030759300
Water / Gas Inject
Injecting
CARNEY CT 37X4
51030856300
Oil well
Producing
CARNEY CT 38X4
51030881300
Water / Gas Inject
Monitor
CARNEY CT 39X4
51030881400
Oil well
Producing
CARNEY CT41Y34
51030914900
Oil well
Monitor
CARNEY CT 4-34
51030555900
Oil well
Producing
CARNEY CT 43Y34
51030914800
Oil well
Monitor
CARNEY CT 44Y34
51030915300
Oil well
Monitor
CARNEY CT 5-34
51030103800
Oil well
Producing
CARNEY CT 6-5
51030609100
Water / Gas Inject
Monitor
CARNEY CT 7-35
51030629300
Oil well
Producing
CARNEY CT 8-34
51030104000
Oil well
Producing
CARNEY CT 9-35
51030548600
Water / Gas Inject
Monitor
CARNEY UNIT 1
51030608700
Oil well
Producing
CARNEY UNIT 2X
51030719100
Water / Gas Inject
Injecting
COLTHARPJE 10X
51030869400
Oil well
Producing
44
-------
COLTHARP JE 2
51030602300
Water / Gas Inject
Monitor
COLTHARP JE 4
51030602200
Water / Gas Inject
Monitor
COLTHARP JE 5X
51030705700
Oil well
Producing
COLTHARP JE 7X
51030727900
Oil well
Producing
COLTHARP JE 8X
51030734300
Oil well
Producing
COLTHARP WH A1
51030601900
Water / Gas Inject
Injecting
COLTHARP WH A3
51030602100
Water / Gas Inject
Monitor
COLTHARP WH A4
51030102800
Water / Gas Inject
Injecting
COLTHARP WH A5X
51030725000
Oil well
Producing
COLTHARP WH A6X
51030744700
Oil well
Producing
COLTHARP WH A8X
51030909900
Oil well
Producing
COLTHARP WH B2X
51030859400
Oil well
Monitor
COLTHARP WH B3X
51030879300
Oil well
Shut In
COLTHARP WH C1
51030107700
Water / Gas Inject
Monitor
COLTHARP WH C2X
51030919800
Oil well
Producing
CT CARNEY 25X34
51030741500
Water / Gas Inject
Injecting
EMERALD 10
51030566200
Oil well
Producing
EMERALD 11
51030567100
Oil well
Producing
EMERALD13ST
51030563601
Water / Gas Inject
Injecting
EMERALD 14
51030556500
Water / Gas Inject
Injecting
EMERALD 16
51030625300
Oil well
Monitor
EMERALD 17
51030567700
Water / Gas Inject
Injecting
EMERALD18AX
51030920200
Oil well
Producing
EMERALD 19
51030624000
Oil well
Producing
EMERALD 2
51030566900
Oil well
Producing
EMERALD 20
51030555800
Water / Gas Inject
Injecting
EMERALD 22
51030625400
Water / Gas Inject
Injecting
EMERALD 23
51030558900
Water / Gas Inject
Injecting
EMERALD 25
51030548100
Water / Gas Inject
Injecting
EMERALD 26
51030624200
Water / Gas Inject
Injecting
EMERALD 27
51030565300
Oil well
Producing
EMERALD 28
51030562800
Water / Gas Inject
Injecting
EMERALD 29AX
51030924500
Water / Gas Inject
Injecting
EMERALD 30AX
51030920300
Water / Gas Inject
Injecting
EMERALD 31 AX
51030923600
Water / Gas Inject
Injecting
EMERALD 32
51030623800
Oil well
Producing
EMERALD 33AX
51030923900
Water / Gas Inject
Injecting
EMERALD 34
51030559500
Water / Gas Inject
Injecting
EMERALD 35
51030559400
Water / Gas Inject
Injecting
EMERALD 36
51030548800
Water / Gas Inject
Injecting
EMERALD 37
51030551200
Water / Gas Inject
Injecting
45
-------
EMERALD 38
51030624900
Water / Gas Inject
Injecting
EMERALD 39
51030625100
Water / Gas Inject
Injecting
EMERALD 3ST
51030559901
Water / Gas Inject
Injecting
EMERALD 3ST 3
51030559900
Water / Gas Inject
P&A
EMERALD 4
51030550500
Oil well
Producing
EMERALD 40
51030625000
Water / Gas Inject
Injecting
EMERALD 41
51030546300
Water / Gas Inject
Monitor
EMERALD 42D
51030634000
Salt Water Disposal
Injecting
EMERALD 44AX
51030918700
Water / Gas Inject
Injecting
EMERALD 46X
51030713000
Oil well
Producing
EMERALD 47X
51030720100
Oil well
Producing
EMERALD 48X
51030725700
Oil well
Monitor
EMERALD 49AX
51031068000
Oil well
Producing
EMERALD 50X
51030733100
Oil well
Producing
EMERALD 51X
51030733300
Oil well
Producing
EMERALD 52X
51030737100
Oil well
Producing
EMERALD 53X
51030737600
Oil well
Producing
EMERALD 54X
51030763700
Oil well
Producing
EMERALD 55X
51030763800
Oil well
Producing
EMERALD 56X
51030768700
Oil well
Producing
EMERALD 57XST
51030764901
Oil well
Producing
EMERALD 58X
51030773900
Oil well
Producing
EMERALD 59X
51030774000
Oil well
Producing
EMERALD 6
51030558800
Water / Gas Inject
Injecting
EMERALD 60X
51030779800
Oil well
Producing
EMERALD 61X
51030780300
Oil well
Producing
EMERALD 62X
51030781100
Oil well
Producing
EMERALD 63ST
51030804101
Water / Gas Inject
Injecting
EMERALD 63XST
51030804100
Water / Gas Inject
P&A
EMERALD 64X
51030799200
Water / Gas Inject
Injecting
EMERALD 65X
51030794800
Oil well
Producing
EMERALD 66X
51030786800
Oil well
Producing
EMERALD 67X
51030797400
Oil well
Producing
EMERALD 68X
51030797500
Oil well
Producing
EMERALD 69X
51030810300
Water / Gas Inject
Injecting
EMERALD 70X
51030807200
Water / Gas Inject
Injecting
EMERALD 71X
51030804600
Water / Gas Inject
Injecting
EMERALD 72X
51030810400
Water / Gas Inject
Monitor
EMERALD 73X
51030810500
Oil well
Monitor
EMERALD 74X
51030816900
Oil well
Producing
EMERALD 75X
51030843700
Oil well
Producing
46
-------
EMERALD 76X
51030848100
Oil well
Producing
EMERALD 77X
51030848000
Oil well
Producing
EMERALD 78X
51030849100
Oil well
Producing
EMERALD 79X
51030895500
Salt Water Disposal
Injecting
EMERALD 7 A
51030928500
Water / Gas Inject
Injecting
EMERALD 8
51030559000
Water / Gas Inject
P&A
EMERALD 80X
51030876900
Oil well
Producing
EMERALD 81X
51030888300
Oil well
Producing
EMERALD 82X
51030849200
Water / Gas Inject
Injecting
EMERALD 83X
51030876500
Oil well
Producing
EMERALD 84X
51030888500
Oil well
Producing
EMERALD 85X
51030877000
Oil well
Producing
EMERALD 86X
51030877200
Oil well
Producing
EMERALD 87X
51030877300
Oil well
Monitor
EMERALD 88X
51030876600
Oil well
Producing
EMERALD 89X
51030877100
Oil well
Producing
EMERALD 8ST
51030559001
Water / Gas Inject
Injecting
EMERALD 90X
51030914600
Water / Gas Inject
Injecting
EMERALD 91Y
51030914700
Water / Gas Inject
Injecting
EMERALD 92X
51030929500
Oil well
Producing
EMERALD 93X
51031185800
Oil well
Producing
EMERALD 94X
51031185500
Oil well
Producing
EMERALD 95X
51031191400
Oil well
Producing
EMERALD 96X
51031192200
Oil well
Producing
EMERALD 97X
51031191300
Oil well
Producing
EMERALD 98X
51031191500
Water / Gas Inject
Injecting
EMERALD 9ST
51030566101
Water / Gas Inject
Injecting
EMERALD 9ST 9
51030566100
Water / Gas Inject
P&A
FAIRFIELD KITTI A 4
51031101700
Oil well
P&A
FAIRFIELD KITTI A 5P
51031101000
Oil well
P&A
FAIRFIELD KITTI A1
51030611100
Water / Gas Inject
Injecting
FAIRFIELD KITTI A4
51031101701
Oil well
Producing
FAIRFIELD KITTI A5
51031101001
Oil well
Producing
FAIRFIELD KITTI B1
51030107800
Water / Gas Inject
Injecting
FE156X
51031033600
Oil well
Producing
FEE 1
51030563400
Oil well
Producing
FEE 1 162Y
51031194500
Water / Gas Inject
Injecting
FEE 10
51030566800
Water / Gas Inject
Injecting
FEE 100X
51030786900
Oil well
Producing
FEE 101X
51030787000
Oil well
Producing
FEE 102X
51030787700
Oil well
Producing
47
-------
FEE 103X
51030788500
Oil well
Monitor
FEE 104X
51030785700
Oil well
Producing
FEE 105X
51030785800
Oil well
Producing
FEE 106X
51030794600
Water / Gas Inject
Injecting
FEE 107X
51030803200
Water / Gas Inject
Injecting
FEE 108X
51030795200
Oil well
Producing
FEE 109X
51030798900
Water / Gas Inject
Injecting
FEE 11
51030559600
Oil well
Producing
FEE 11OX
51030802600
Water / Gas Inject
Injecting
FEE 111X
51030802700
Water / Gas Inject
Monitor
FEE 112X
51030802800
Water / Gas Inject
Injecting
FEE 113X
51030802900
Water / Gas Inject
Injecting
FEE 114X
51030803100
Water / Gas Inject
Injecting
FEE 115X
51030803300
Water / Gas Inject
Injecting
FEE 116X
51030829900
Water / Gas Inject
Injecting
FEE 117X
51030843800
Oil well
Producing
FEE 118AX
51030928300
Oil well
Monitor
FEE 12
51030565100
Oil well
Producing
FEE 121X
51030857500
Oil well
Producing
FEE 122X
51030866300
Water / Gas Inject
Injecting
FEE 124X
51030866400
Oil well
Producing
FEE 125X
51030868100
Oil well
Monitor
FEE 126X
51030868600
Oil well
Producing
FEE 127X
51030868700
Water / Gas Inject
Injecting
FEE 128X
51030868800
Oil well
Monitor
FEE 129X
51030868900
Oil well
Producing
FEE 13
51030622600
Oil well
Producing
FEE 130X
51030870400
Oil well
Monitor
FEE 133X
51030888400
Oil well
Producing
FEE 135X
51030876000
Oil well
Monitor
FEE 136X
51030874500
Water / Gas Inject
Injecting
FEE 137X
51030876100
Water / Gas Inject
Injecting
FEE 138X
51030876300
Oil well
Producing
FEE 139X
51030876200
Oil well
Producing
FEE 14
51030568700
Oil well
Producing
FEE 140Y
51030910600
Oil well
Monitor
FEE 141X
51030913300
Water / Gas Inject
Injecting
FEE 142X
51030913100
Oil well
Producing
FEE 143X
51030913000
Oil well
Producing
FEE 144Y
51030917500
Oil well
Shut In
FEE 145Y
51030917400
Oil well
Producing
48
-------
FEE 146X
51030946400
Oil well
Producing
FEE 15
51030556800
Oil well
Producing
FEE 153X
51030929700
Oil well
Producing
Fee154X
51031036500
Oil well
Producing
Fee155X
51031037300
Oil well
Producing
FEE 157X
51031101900
Oil well
Monitor
FEE 158 X
51031115900
Oil well
Producing
FEE 159 X
51031101100
Oil well
Producing
FEE 160X
51031186600
Oil well
Producing
FEE 163X
51031195100
Oil well
Producing
FEE16AX
51030923500
Water / Gas Inject
Monitor
FEE 17
51030580100
Water / Gas Inject
Injecting
FEE 18
51030623600
Water / Gas Inject
Monitor
FEE 19
51030622400
Oil well
Producing
FEE 1AX
51030924400
Water / Gas Inject
Monitor
FEE 20
51030616800
Oil well
Producing
FEE 21
51030620700
Oil well
Producing
FEE 22
51030616100
Water / Gas Inject
Injecting
FEE 23
51030615600
Oil well
Producing
FEE 24
51030611200
Water / Gas Inject
Injecting
FEE 25
51030614500
Oil well
Producing
FEE 26
51030615200
Oil well
Producing
FEE 27
51030617500
Oil well
Producing
FEE 28
51030613500
Water / Gas Inject
Injecting
FEE 29
51030614400
Water / Gas Inject
Injecting
FEE 2AX
51030924700
Water / Gas Inject
Injecting
FEE 3
51030565700
Oil well
Producing
FEE 30
51030621100
Water / Gas Inject
Monitor
FEE 31
51030611800
Water / Gas Inject
Injecting
FEE 32
51030614200
Oil well
Producing
FEE 33
51030614700
Oil well
Producing
FEE 34
51030624500
Oil well
Producing
FEE 35
51030611300
Oil well
Producing
FEE 36
51030617600
Oil well
Producing
FEE 37
51030611500
Water / Gas Inject
Injecting
FEE 38
51030625500
Water / Gas Inject
Injecting
FEE 39
51030623300
Water / Gas Inject
Injecting
FEE 4
51030576900
Oil well
Monitor
FEE 40
51030622300
Water / Gas Inject
Injecting
FEE 41
51030622200
Water / Gas Inject
Monitor
FEE 42
51030568800
Water / Gas Inject
Monitor
49
-------
FEE 43
51030614100
Water / Gas Inject
Injecting
FEE 44
51030624700
Water / Gas Inject
Injecting
FEE 45
51030617900
Oil well
Producing
FEE 47
51030616000
Water / Gas Inject
Injecting
FEE 48
51030625900
Water / Gas Inject
Injecting
FEE 49
51030611900
Water / Gas Inject
Injecting
FEE 5
51030574500
Oil well
Producing
FEE 51
51030614900
Water / Gas Inject
Injecting
FEE 52
51030567400
Water / Gas Inject
Injecting
FEE 53AX
51030861200
Water / Gas Inject
Injecting
FEE 55
51030615300
Water / Gas Inject
Injecting
FEE 56
51030615700
Water / Gas Inject
Injecting
FEE 58AX
51030924300
Water / Gas Inject
Injecting
FEE 59
51030616900
Water / Gas Inject
Injecting
FEE 6
51030572000
Oil well
Producing
FEE 60
51030622500
Water / Gas Inject
Injecting
FEE 61
51030620300
Oil well
Producing
FEE 62
51030614000
Oil well
Monitor
FEE 63
51030614600
Water / Gas Inject
Injecting
FEE 64
51030614800
Water / Gas Inject
Injecting
FEE 65
51030615000
Water / Gas Inject
Injecting
FEE 67A
51030929300
Water / Gas Inject
Injecting
FEE 68A
51030568300
Oil well
Producing
FEE 69
51030625600
Water / Gas Inject
Monitor
FEE 7
51030571600
Oil well
Producing
FEE 70AX
51030919100
Water / Gas Inject
Monitor
FEE 72X
51030718000
Oil well
Producing
FEE 73X
51030727400
Oil well
Producing
FEE 74X
51030730700
Oil well
Producing
FEE 75X
51030732600
Oil well
Producing
FEE 76X
51030733900
Oil well
Producing
FEE 78X
51030743400
Oil well
Producing
FEE 79X
51030742400
Water / Gas Inject
Injecting
FEE 8
51030563300
Water / Gas Inject
Injecting
FEE 80X
51030749100
Water / Gas Inject
Injecting
FEE 81X
51030751900
Oil well
Producing
FEE 82X
51030752900
Oil well
Producing
FEE 83X
51030757200
Oil well
Producing
FEE 84X
51030755400
Water / Gas Inject
Injecting
FEE 85X
51030758100
Water / Gas Inject
Injecting
FEE 86X
51030756900
Water Injection Well
P&A
50
-------
FEE 86XST
51030756901
Water / Gas Inject
Injecting
FEE 87X
51030754600
Water / Gas Inject
Monitor
FEE 88X
51030755900
Water / Gas Inject
Injecting
FEE 89X
51030755500
Water / Gas Inject
Injecting
FEE 9
51030551100
Oil well
P&A
FEE 90X
51030758000
Water / Gas Inject
Injecting
FEE 91X
51030757300
Water / Gas Inject
Injecting
FEE 92X
51030755600
Water / Gas Inject
Monitor
FEE 93X
51030759100
Water / Gas Inject
Injecting
FEE 94X
51030759400
Water / Gas Inject
Injecting
FEE 95X
51030764700
Oil well
Producing
FEE 96X
51030764800
Oil well
Producing
FEE 97X
51030779100
Oil well
Producing
FEE 98X
51030782700
Water / Gas Inject
Injecting
FEE 99X
51030784000
Oil well
Producing
FEE 9ST 9
51030551101
Oil well
Producing
GRAY A A17X
51030768900
Water / Gas Inject
Injecting
GRAY A A21X
51030830200
Water / Gas Inject
Injecting
GRAY A A8AX
51030919700
Water / Gas Inject
Injecting
GRAY A10
51030573400
Water / Gas Inject
Injecting
GRAY A12
51030613700
Oil well
Producing
GRAY A13
51030577800
Water / Gas Inject
Monitor
GRAY A14
51030613900
Oil well
Producing
GRAY A15
51030576200
Oil well
Producing
GRAY A16
51030613600
Water / Gas Inject
Injecting
GRAY A18X
51030789800
Oil well
Producing
GRAY A19X
51030787300
Oil well
Producing
GRAY A20X
51030803500
Water / Gas Inject
Injecting
GRAY A22X
51030831700
Oil well
Producing
GRAY A9
51030571500
Oil well
Producing
GRAY B10
51030612300
Water / Gas Inject
Injecting
GRAY B11
51030581800
Oil well
Producing
GRAY B12
51030612900
Oil well
Producing
GRAY B13
51030612600
Oil well
Producing
GRAY B14A
51030928900
Water / Gas Inject
Injecting
GRAY B15
51030579600
Oil well
Producing
GRAY B16
51030612700
Oil well
Producing
GRAY B17
51030582500
Oil well
Monitor
GRAY B18X
51030638600
Oil well
Monitor
GRAY B19X
51036639700
Oil well
Producing
GRAY B2
51030578700
Oil well
Producing
51
-------
GRAY B20X
51030101500
Water / Gas Inject
Injecting
GRAY B21X
51031035700
Oil well
Producing
GRAY B22X
51031036000
Oil well
Producing
GRAY B23X
51031033800
Oil well
Producing
GRAY B24X
51031033700
Oil well
Producing
GRAY B25X
51031057200
Oil well
Producing
GRAY B26X
51031057500
Oil well
Producing
GRAY B27X
51031057400
Oil well
Producing
GRAY B28X
51031101200
Oil well
Producing
GRAY B3
51030613200
Water / Gas Inject
Injecting
GRAY B4
51030613300
Water / Gas Inject
Injecting
GRAY B5
51030612400
Water / Gas Inject
Injecting
GRAY B6
51030613100
Water / Gas Inject
Injecting
GRAY B7
51030612800
Water / Gas Inject
Injecting
GRAY B8
51030581100
Water / Gas Inject
Injecting
GRAY B9
51030612500
Water / Gas Inject
Injecting
GUIBERSON SA 1
51030581300
Water / Gas Inject
Injecting
GUIBERSON SA 5 X
51031115600
Oil well
Producing
HAGOOD L N-A 17X
51030914200
Oil well
P&A
HAGOOD LN A1 OX
51030791300
Oil well
Shut In
HAGOOD LN A11X
51030794900
Water / Gas Inject
Injecting
HAGOOD LN A12X
51030793600
Oil well
Producing
HAGOOD LN A13X
51030799100
Water / Gas Inject
Injecting
HAGOOD LN A14X
51030795000
Water / Gas Inject
P&A
HAGOOD LN A14XST
51030795001
Water / Gas Inject
Injecting
HAGOOD LN A15X
51030829300
Oil well
Producing
HAGOOD LN A16X
51030830000
Water / Gas Inject
Injecting
HAGOOD LN A17XST
51030914201
Water / Gas Inject
Monitor
HAGOOD LN A2
51030574300
Oil well
Monitor
HAGOOD LN A3
51030576800
Oil well
Monitor
HAGOOD LN A5
51030573600
Water / Gas Inject
Injecting
HAGOOD LN A7
51030575700
Water / Gas Inject
Monitor
HAGOOD LN A9X
51030702200
Water / Gas Inject
Injecting
HAGOOD MC A1
51030632800
Water / Gas Inject
Injecting
HAGOOD MC A10X
51031041400
Oil well
Producing
HAGOOD MC A11X
51031041300
Oil well
Producing
HAGOOD MC A12X
51031053300
Oil well
Producing
HAGOOD MC A13X
51031053100
Oil well
Producing
HAGOOD MC A14X
51031054800
Oil well
Shut In
HAGOOD MC A15X
51031062800
Oil well
Producing
HAGOOD MC A16X
51031061200
Oil well
Producing
52
-------
HAGOOD MC A17X
51031062900
Oil well
Producing
HAGOOD MC A18X
51031061300
Oil well
Producing
HAGOOD MC A19X
51031067000
Water / Gas Inject
Injecting
HAGOOD MC A2
51030102300
Oil well
Producing
HAGOOD MC A21X
51031070900
Oil well
Producing
HAGOOD MC A3
51030633000
Water / Gas Inject
Injecting
HAGOOD MC A4
51030632600
Water / Gas Inject
Injecting
HAGOOD MC A5
51030633100
Water / Gas Inject
Injecting
HAGOOD MC A6
51030102400
Oil well
Producing
HAGOOD MC A7
51030106700
Oil well
Producing
HAGOOD MC A8 A 8
51030632500
Water / Gas Inject
Injecting
HAGOOD MC A9
51030632700
Water / Gas Inject
Injecting
HAGOOD MC B1A
51031102800
Oil well
Producing
HAGOOD MC B2
51031187000
Oil well
Producing
HEFLEY CS 4X
51030856200
Oil well
Producing
HEFLEY ME 2
51030545200
Water / Gas Inject
Monitor
HEFLEY ME 5X
51030719600
Oil well
Producing
HEFLEY ME 6X
51030729300
Oil well
Producing
HEFLEY ME 7X
51030873700
Oil well
Producing
HEFLEY ME 8X
51030869600
Oil well
Producing
L N HAGOOD A- 1
51030572100
Water / Gas Inject
Injecting
L N HAGOOD A-8 IJ A8
51030569100
Water / Gas Inject
Injecting
LACY SB 1
51030573200
Oil well
Producing
LACY SB 11Y
51030914400
Salt Water Disposal
Injecting
LACY SB 12Y
51030914500
Oil well
Producing
LACY SB 13Y
51031057000
Oil well
Producing
LACY SB 2AX
51030928200
Water / Gas Inject
Injecting
LACY SB 3
51030568900
Oil well
Producing
LACY SB 4
51030575800
Water / Gas Inject
Monitor
LACY SB 6X
51030794700
Oil well
Monitor
LACY SB 7X
51030797800
Water / Gas Inject
Injecting
LACY SB 9X
51030831800
Oil well
Monitor
LARSON FA 1
51030106600
Oil well
Producing
LARSON FA 2
51030107200
Water / Gas Inject
Injecting
LARSON FA 3X
51031071000
Oil well
Monitor
LARSON FVA1
51030547600
Oil well
Producing
LARSON FV A2X
51030721600
Water / Gas Inject
Monitor
LARSON FVB11
51030630200
Water / Gas Inject
Injecting
LARSON FVB12
51030100900
Oil well
Producing
LARSON FV B14X
51030641400
Oil well
Shut In
LARSON FV B15X
51030700800
Oil well
Producing
53
-------
LARSON FV B17X
51030707800
Oil well
Producing
LARSON FV B18X
51030708300
Oil well
Producing
LARSON FV B19X
51030710600
Oil well
Producing
LARSON FV B2
51030620200
Water / Gas Inject
Monitor
LARSON FV B20X
51030709900
Oil well
Producing
LARSON FVB21X
51030716500
Oil well
Producing
LARSON FV B22X
51030722700
Oil well
Producing
LARSON FV B23X
51030724200
Oil well
Producing
LARSON FV B24X
51030873800
Oil well
Producing
LARSON FV B25X
51030916500
Oil well
Producing
LARSON FV B27X
51030948800
Oil well
Producing
LARSON FV B4
51030629800
Water / Gas Inject
Injecting
LARSON FV B8
51030620100
Water / Gas Inject
Injecting
LARSON MB 10X25
51030715900
Oil well
Producing
LARSON MB 12X25
51030727000
Oil well
Producing
LARSON MB 2-26 A226
51030566300
Oil well
Producing
LARSON MB 3X26
51030711000
Oil well
Producing
LARSON MB 4X26
51030717700
Oil well
Monitor
LARSON MB 8X25
51030709300
Oil well
Producing
LARSON MB A1AX
51031075600
Water / Gas Inject
Monitor
LARSON MB A2
51030633200
Oil well
Producing
LARSON MB A3X
51031053400
Oil well
Producing
LARSON MB A4X
51031055200
Oil well
Producing
LARSON MB B1
51030576500
Water / Gas Inject
Injecting
LARSON MB B3AX
51031075500
Water / Gas Inject
Injecting
LARSON MB C1-25
51030618600
Water / Gas Inject
Monitor
LARSON MBC1AX
51031076300
Oil well
Producing
LARSON MB C2
51030569000
Water / Gas Inject
Injecting
LARSON MB C3
51030570800
Water / Gas Inject
Injecting
LARSON MB C3-25
51030618700
Water / Gas Inject
Injecting
LARSON MB C4
51031139700
Oil well
Producing
LARSON MB C5
51031142900
Oil well
Producing
LARSON MB C9X25
51030715500
Oil well
Producing
LARSON MB D1-26E
51030620000
Water / Gas Inject
Injecting
LEVI SON 10
51030621700
Oil well
Producing
LEVI SON 11
51030619800
Water / Gas Inject
Injecting
LEVI SON 12
51030103100
Water / Gas Inject
Injecting
LEVI SON 13
51030619400
Water / Gas Inject
Injecting
LEVI SON 14
51030619900
Water / Gas Inject
Injecting
LEVI SON 17
51030619500
Water / Gas Inject
Injecting
LEVI SON 18
51030618200
Oil well
Producing
54
-------
LEVISON 2
51030559300
Oil well
Producing
LEVI SON 21X
51030638700
Oil well
Producing
LEVISON 22X
51030708900
Oil well
Monitor
LEVISON 23X
51030712300
Oil well
Producing
LEVISON 24X
51030711400
Oil well
Producing
LEVISON 25X
51030722200
Oil well
Producing
LEVISON 26X
51030726700
Oil well
Producing
LEVISON 27X
51030728900
Oil well
Producing
LEVISON 28X
51030731600
Oil well
Monitor
LEVISON 29X
51030732000
Water / Gas Inject
Injecting
LEVISON 30X
51030735100
Water / Gas Inject
Injecting
LEVISON 31X
51030735300
Oil well
Monitor
LEVISON 32X
51030747500
Water / Gas Inject
Injecting
LEVISON 33X
51030752100
Oil well
Producing
LEVISON 34X
51030758600
Water / Gas Inject
Injecting
LEVISON 35X
51030868300
Oil well
Producing
LEVISON 6
51030106200
Oil well
Producing
LEVISON 7
51030619700
Oil well
Monitor
LEVISON 8
51030103000
Water / Gas Inject
Injecting
LEVISON 9
51030628600
Water / Gas Inject
Injecting
LEVSION 1
51030559100
Oil well
Producing
LN - HAGOOD A6
51030569400
Oil well
Producing
LN HAGOOD A-4
51030570700
Oil well
Shut In
MAGOR1A
51030989300
Water / Gas Inject
Injecting
MATTERN 1
51030580400
Water / Gas Inject
Injecting
MCLAUGHLIN AC 1
51030573100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 10
51030578000
Oil well
Monitor
MCLAUGHLIN AC 11
51030569300
Oil well
Producing
MCLAUGHLIN AC 12
51030579800
Water / Gas Inject
Injecting
MCLAUGHLIN AC 13
51030581000
Water / Gas Inject
Injecting
MCLAUGHLIN AC 14
51030105800
Oil well
Producing
MCLAUGHLIN AC 15
51030576700
Oil well
Producing
MCLAUGHLIN AC 16
51030105400
Oil well
Producing
MCLAUGHLIN AC 17
51030631700
Water / Gas Inject
Injecting
MCLAUGHLIN AC 18
51030105300
Water / Gas Inject
Injecting
MCLAUGHLIN AC 19
51030579400
Oil well
Producing
MCLAUGHLIN AC 2
51030573300
Oil well
Producing
MCLAUGHLIN AC 20
51030578200
Water / Gas Inject
Injecting
MCLAUGHLIN AC 21
51030578100
Oil well
Producing
MCLAUGHLIN AC 22
51030105500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 23
51030571800
Water / Gas Inject
Injecting
55
-------
MCLAUGHLIN AC 24
51030576300
Water / Gas Inject
Injecting
MCLAUGHLIN AC 25
51030631800
Oil well
Producing
MCLAUGHLIN AC 26
51030105000
Water / Gas Inject
Injecting
MCLAUGHLIN AC 27
51036005300
Oil well
Producing
MCLAUGHLIN AC 28
51030569900
Oil well
Producing
MCLAUGHLIN AC 29
51030581900
Oil well
Producing
MCLAUGHLIN AC 30
51030105100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 31
51030105200
Water / Gas Inject
Injecting
MCLAUGHLIN AC 32
51030581200
Water / Gas Inject
Injecting
MCLAUGHLIN AC 33
51030631500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 34
51030104700
Water / Gas Inject
Injecting
MCLAUGHLIN AC 35
51030581700
Oil well
Producing
MCLAUGHLIN AC 36
51030104800
Oil well
Producing
MCLAUGHLIN AC 37
51030633300
Oil well
Producing
MCLAUGHLIN AC 38
51030632200
Oil well
Producing
MCLAUGHLIN AC 39A
51031049300
Oil well
Producing
MCLAUGHLIN AC 3AX
51030920700
Water / Gas Inject
Injecting
MCLAUGHLIN AC 4
51030573800
Oil well
Producing
MCLAUGHLIN AC 41AX
51030920100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 42
51030579500
Water / Gas Inject
Monitor
MCLAUGHLIN AC 43
51030632400
Water / Gas Inject
Injecting
MCLAUGHLIN AC 44A
51031096100
Oil well
Producing
MCLAUGHLIN AC 44D
51030631600
Salt Water Disposal
Injecting
MCLAUGHLIN AC 45 AC
51030631900
Water / Gas Inject
Injecting
MCLAUGHLIN AC 46ST
51030632301
Water / Gas Inject
Monitor
MCLAUGHLIN AC 47X
51030107500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 49X
51030641700
Oil well
Monitor
MCLAUGHLIN AC 5
51030571200
Oil well
Monitor
MCLAUGHLIN AC 50X
51030632100
Oil well
Producing
MCLAUGHLIN AC 51X
51030641800
Oil well
Producing
MCLAUGHLIN AC 52X
51030642500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 53X
51030101400
Oil well
Producing
MCLAUGHLIN AC 54X
51030642600
Oil well
Producing
MCLAUGHLIN AC 55X
51030641900
Water / Gas Inject
Injecting
MCLAUGHLIN AC 56X
51030642000
Water / Gas Inject
Injecting
MCLAUGHLIN AC 57X
51030701000
Oil well
Monitor
MCLAUGHLIN AC 58X
51030701400
Oil well
Producing
MCLAUGHLIN AC 59AX
51030928800
Oil well
Producing
MCLAUGHLIN AC 6
51030579900
Oil well
Producing
MCLAUGHLIN AC 60X
51030769200
Water / Gas Inject
Injecting
MCLAUGHLIN AC 61X
51030769000
Oil well
Monitor
56
-------
MCLAUGHLIN AC 62X
51030771500
Oil well
Producing
MCLAUGHLIN AC 63X
51030771600
Water / Gas Inject
Injecting
MCLAUGHLIN AC 65X
51030771800
Oil well
Producing
MCLAUGHLIN AC 66X
51030773800
Water / Gas Inject
Injecting
MCLAUGHLIN AC 67X
51030817000
Oil well
Producing
MCLAUGHLIN AC 68X
51030829200
Oil well
Producing
MCLAUGHLIN AC 69X
51030829400
Water / Gas Inject
Injecting
MCLAUGHLIN AC 7
51030580900
Water / Gas Inject
Injecting
MCLAUGHLIN AC 70X
51030830100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 71X
51030829700
Oil well
Producing
MCLAUGHLIN AC 72X
51030832000
Water / Gas Inject
Injecting
MCLAUGHLIN AC 73X
51030831900
Oil well
Producing
MCLAUGHLIN AC 74X
51030832100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 75X
51030829800
Oil well
Producing
MCLAUGHLIN AC 76X
51030914100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 77X
51030915200
Oil well
Producing
MCLAUGHLIN AC 78X
51030915500
Oil well
Producing
MCLAUGHLIN AC 79X
51030930000
Oil well
Monitor
MCLAUGHLIN AC 8
51030573500
Oil well
Producing
MCLAUGHLIN AC 80X
51030930100
Oil well
Monitor
MCLAUGHLIN AC 81AX
51031064500
Oil well
Producing
MCLAUGHLIN AC 82X
51031054600
Oil well
Producing
MCLAUGHLIN AC 83X
51031059500
Oil well
Producing
MCLAUGHLIN AC 84Y
51031057300
Oil well
Producing
MCLAUGHLIN AC 86Y
51031058400
Oil well
Producing
MCLAUGHLIN AC 88X
51031070000
Oil well
Producing
MCLAUGHLIN AC 9
51030576600
Oil well
Monitor
MCLAUGHLIN AC 90X
51031069900
Oil well
Producing
MCLAUGHLIN AC 91X
51031072600
Water / Gas Inject
Injecting
MCLAUGHLIN AC 92X
51031070800
Oil well
Producing
MCLAUGHLIN AC 93X
51031072700
Water / Gas Inject
Injecting
MCLAUGHLIN AC 94X
51031072500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 95X
51031140800
Oil well
Producing
MCLAUGHLIN AC A1
51030609200
Oil well
Monitor
MCLAUGHLIN AC A3X
51030863000
Oil well
Producing
MCLAUGHLIN AC C2
51031104100
Oil well
Monitor
MCLAUGHLIN SW6
51030627800
Oil well
P&A
MCLAUGHLIN SHARPLES 10X28
51030749000
Oil well
Producing
MCLAUGHLIN SHARPLES 1-28
51030560300
Water / Gas Inject
Injecting
MCLAUGHLIN SHARPLES 12X33
51030759800
Oil well
Producing
MCLAUGHLIN SHARPLES 1-33
51030551300
Oil well
Producing
57
-------
MCLAUGHLIN SHARPLES 13X3
51030873900
Oil well
Producing
MCLAUGHLIN SHARPLES 14Y33
51030912300
Oil well
Producing
MCLAUGHLIN SHARPLES 15X32
51030885400
Oil well
Producing
MCLAUGHLIN SHARPLES 16X32
51030913200
Water / Gas Inject
Injecting
MCLAUGHLIN SHARPLES 2-28
51030560000
Oil well
Producing
MCLAUGHLIN SHARPLES 2-32
51030627300
Water / Gas Inject
Monitor
MCLAUGHLIN SHARPLES 2-33
51030106800
Water / Gas Inject
Injecting
MCLAUGHLIN SHARPLES 3-32
51030627000
Oil well
Monitor
MCLAUGHLIN SHARPLES 3-33
51030629000
Oil well
Producing
MCLAUGHLIN SHARPLES 4-33
51030629100
Water / Gas Inject
Injecting
MCLAUGHLIN SHARPLES 5-33
51030104500
Oil well
Monitor
MCLAUGHLIN SHARPLES 6-33
51030628800
Oil well
Monitor
MCLAUGHLIN SHARPLES 7-33
51030104600
Water / Gas Inject
Monitor
MCLAUGHLIN SHARPLES 8-33
51030628900
Water / Gas Inject
Monitor
MCLAUGHLIN SHARPLES 9X33
51030746500
Oil well
Producing
MCLAUGHLIN SW11X
51030759700
Water / Gas Inject
Injecting
MCLAUGHLIN SW12X
51030760100
Water / Gas Inject
Injecting
MCLAUGHLIN SW 1ST
51030548300
Oil well
P&A
MCLAUGHLIN SW 1 ST 1
51030548301
Water / Gas Inject
Monitor
MCLAUGHLIN SW2
51030627700
Oil well
Producing
MCLAUGHLIN SW 3
51030104400
Water / Gas Inject
Injecting
MCLAUGHLIN SW4
51030107600
Oil well
Producing
MCLAUGHLIN SW 5
51030627900
Oil well
Producing
MCLAUGHLIN SW6ST
51030627801
Water / Gas Inject
Injecting
MCLAUGHLIN SW7X
51030746100
Oil well
Producing
MCLAUGHLIN SW8X
51030753000
Water / Gas Inject
Injecting
MCLAUGHLIN UNIT A1
51030581600
Oil well
Producing
MCLAUGHLIN UNIT B1
51030582600
Oil well
Producing
MCLAUGHLIN UNIT B2X
51031057600
Water / Gas Inject
Injecting
MELLEN 3A
51031098100
Oil well
Producing
MELLEN WP 1
51036000300
Water / Gas Inject
Injecting
MELLEN WP 2
51030105600
Water / Gas Inject
Injecting
NEAL 2AX
51030920800
Water / Gas Inject
Injecting
NEAL4
51030565500
Water / Gas Inject
Injecting
NEAL 5A
51030565900
Oil well
Producing
NEAL 6X
51030790600
Oil well
Producing
NEAL 7X
51030804200
Water / Gas Inject
Injecting
NEAL 8X
51030804300
Water / Gas Inject
P&A
NEAL 8XST
51030804301
Water / Gas Inject
Injecting
NEAL 9Y
51030912000
Oil well
Producing
NEWTON ASSOC UNIT D2X
51030868500
Oil well
Monitor
58
-------
NIKKEL 3
51030619200
Water / Gas Inject
Injecting
PURDY 1-1
51030545300
Water / Gas Inject
Monitor
PURDY 2X1
51030881000
Oil well
Producing
RAVEN A1AX
51030917800
Water / Gas Inject
Injecting
RAVEN A2
51030625700
Water / Gas Inject
Injecting
RAVEN A3
51030624400
Water / Gas Inject
Injecting
RAVEN A4
51030625800
Water / Gas Inject
Injecting
RAVEN A5X
51030718800
Oil well
Producing
RAVEN B1
51030564900
Oil well
Producing
RAVEN B2AX
51030923800
Water / Gas Inject
Monitor
RECTOR 1
51030549400
Oil well
Producing
RECTOR 11X
51030867200
Oil well
Shut In
RECTOR 12X
51030919900
Oil well
Shut In
RECTOR 3
51030106000
Water / Gas Inject
Injecting
RECTOR 8X
51030704300
Oil well
Producing
RECTOR 9X
51030714700
Oil well
Shut In
RIGBY 1
51030569700
Oil well
Producing
RIGBY 5X
51030804700
Water / Gas Inject
Injecting
RIGBY 6Y
51030910700
Oil well
Producing
RIGBY A2AX
51030920000
Water / Gas Inject
Injecting
RIGBY A3X
51030791000
Oil well
Producing
RIGBY A4X
51030791100
Oil well
Monitor
RIGBY A7Y
51030915100
Oil well
Monitor
ROOTH DF 1
51030579700
Water / Gas Inject
Injecting
ROOTH DF 5 X
51031143000
Oil well
Producing
ROOTH DF 6 X
51031125000
Oil well
Producing
S B LACY 3
51030568900
Oil well
Monitor
STOFFER CR A1
51030562700
Water / Gas Inject
Injecting
STOFFER CR A2
51030559200
Water / Gas Inject
Injecting
STOFFER CR B1
51030567300
Oil well
Producing
SW MCLAUGHLIN 10X
51030754700
Oil well
Producing
SW MCLAUGHLIN 9X
51030753500
Oil well
Producing
U P 4829
51030623100
Water / Gas Inject
P&A
UNION PACIFIC 1 150X 16
51031150200
Oil well
Producing
UNION PACIFIC 1 151X 16
51031150100
Oil well
Producing
UNION PACIFIC 1 153X 16
51031146401
Water / Gas Inject
Injecting
UNION PACIFIC 100X20
51030788600
Oil well
Producing
UNION PACIFIC 101X20
51030797300
Oil well
Monitor
UNION PACIFIC 10-21
51030568501
Oil well
Monitor
UNION PACIFIC 102X20
51030797700
Water / Gas Inject
Injecting
UNION PACIFIC 103X20
51030799000
Water / Gas Inject
Injecting
59
-------
UNION PACIFIC 104X20
51030803000
Water / Gas Inject
Injecting
UNION PACIFIC 105X29
51030794500
Oil well
Producing
UNION PACIFIC 106X32
51030845000
Oil well
Producing
UNION PACIFIC 107X32
51030849800
Oil well
Producing
UNION PACIFIC 108X21
51030849500
Water / Gas Inject
Injecting
UNION PACIFIC 109X32
51030849700
Oil well
Producing
UNION PACIFIC 110X21
51030853000
Water / Gas Inject
Injecting
UNION PACIFIC 111X29
51030852200
Oil well
Producing
UNION PACIFIC 11-21
51030616200
Oil well
Producing
UNION PACIFIC 112X21
51030873500
Oil well
Monitor
UNION PACIFIC 113X22
51030860600
Oil well
Monitor
UNION PACIFIC 115X21
51030866600
Oil well
Producing
UNION PACIFIC 117X22
51030866700
Oil well
Producing
UNION PACIFIC 118X21
51030869700
Oil well
Producing
UNION PACIFIC 119X21
51030869800
Oil well
Producing
UNION PACIFIC 120X21
51030869900
Oil well
Producing
UNION PACIFIC 12-27
51030620400
Oil well
Producing
UNION PACIFIC 122X21
51030870000
Oil well
Monitor
UNION PACIFIC 126X32
51030885100
Oil well
Producing
UNION PACIFIC 127X31
51030884700
Oil well
Producing
UNION PACIFIC 128X31
51030910000
Oil well
Producing
UNION PACIFIC 129X31
51030885200
Oil well
Producing
UNION PACIFIC 130X32
51030885300
Oil well
Producing
UNION PACIFIC 131X32
51030885500
Oil well
Producing
UNION PACIFIC 1-32
51030556700
Water / Gas Inject
Injecting
UNION PACIFIC 13-28
51030622000
Water / Gas Inject
Injecting
UNION PACIFIC 132X21
51030874600
Oil well
Monitor
UNION PACIFIC 133X21
51030876400
Oil well
Producing
UNION PACIFIC 134X21
51030904100
Water / Gas Inject
Injecting
UNION PACIFIC 135Y28
51030910500
Oil well
Monitor
UNION PACIFIC 136X20
51030913800
Oil well
Producing
UNION PACIFIC 137X20
51030913900
Water / Gas Inject
Monitor
UNION PACIFIC 138Y28
51030917300
Oil well
Producing
UNION PACIFIC 139Y28
51030918500
Oil well
Monitor
UNION PACIFIC 140Y27
51030918800
Oil well
Producing
UNION PACIFIC 141Y28
51030918900
Oil well
Producing
UNION PACIFIC 14-20
51030615400
Oil well
Producing
UNION PACIFIC 142Y28
51030919000
Oil well
Monitor
UNION PACIFIC 143Y28
51030918600
Oil well
Monitor
UNION PACIFIC 15-28
51030102900
Oil well
Monitor
UNION PACIFIC 154Y29
51031172000
Oil well
Producing
60
-------
UNION PACIFIC 156Y29
51031172100
Oil well
Producing
UNION PACIFIC 16-27
51030620600
Oil well
Shut In
UNION PACIFIC 17-27
51030621400
Oil well
Producing
UNION PACIFIC 18-21
51030616400
Oil well
Producing
UNION PACIFIC 19-28
51030621900
Water / Gas Inject
Injecting
UNION PACIFIC 20-29
51030622800
Water / Gas Inject
Injecting
UNION PACIFIC 21-32
51030627100
Water / Gas Inject
Monitor
UNION PACIFIC 2-20
51030569200
Oil well
Producing
UNION PACIFIC 22-32
51030627500
Oil well
Producing
UNION PACIFIC 23-32
51030626900
Oil well
Producing
UNION PACIFIC 24-27
51030621200
Water / Gas Inject
Injecting
UNION PACIFIC 25-34
51030106900
Oil well
Shut In
UNION PACIFIC 26-31
51030626100
Water / Gas Inject
Injecting
UNION PACIFIC 27-20
51030577000
Oil well
Monitor
UNION PACIFIC 28-22
51030617300
Oil well
Producing
UNION PACIFIC 29-32
51030548700
Oil well
Monitor
UNION PACIFIC 31-21
51030616600
Oil well
Monitor
UNION PACIFIC 32-27
51030620800
Oil well
Monitor
UNION PACIFIC 33-32
51030626600
Water / Gas Inject
Injecting
UNION PACIFIC 3-34
51030551000
Oil well
Producing
UNION PACIFIC 34-31
51030626300
Water / Gas Inject
Injecting
UNION PACIFIC 35-32
51030626800
Water / Gas Inject
Injecting
UNION PACIFIC 36-32
51030627200
Water / Gas Inject
Injecting
UNION PACIFIC 37AX29
51030917700
Water / Gas Inject
Injecting
UNION PACIFIC 39-17
51030612100
Water / Gas Inject
Injecting
UNION PACIFIC 41-20
51030615800
Water / Gas Inject
Shut In
UNION PACIFIC 4-29
51030563200
Water / Gas Inject
Injecting
UNION PACIFIC 42AX28
51030925700
Water / Gas Inject
Injecting
UNION PACIFIC 43-28
51030622100
Water / Gas Inject
Monitor
UNION PACIFIC 44AX20
51030923300
Water / Gas Inject
Injecting
UNION PACIFIC 45-21
51030569600
Water / Gas Inject
Injecting
UNION PACIFIC 47-21
51030615900
Water / Gas Inject
Injecting
UNION PACIFIC 48-29ST
51030623101
Water / Gas Inject
Injecting
UNION PACIFIC 49-27
51030621300
Oil well
Producing
UNION PACIFIC 50-29
51030107100
Water / Gas Inject
Injecting
UNION PACIFIC 51AX20
51030892800
Water / Gas Inject
Injecting
UNION PACIFIC 5-28
51030563900
Oil well
Producing
UNION PACIFIC 52A-29
51030928400
Water / Gas Inject
Injecting
UNION PACIFIC 53-32
51030627600
Water / Gas Inject
Monitor
UNION PACIFIC 54-21
51030616300
Water / Gas Inject
Injecting
UNION PACIFIC 55-17
51030612200
Water / Gas Inject
Injecting
61
-------
UNION PACIFIC 56-21
51030616700
Water / Gas Inject
Injecting
UNION PACIFIC 58-27
51030620500
Water / Gas Inject
Injecting
UNION PACIFIC 59A-27
51031120700
Oil well
Producing
UNION PACIFIC 60-31
51030626200
Water / Gas Inject
Injecting
UNION PACIFIC 61-20
51030615500
Water / Gas Inject
Injecting
UNION PACIFIC 6-21
51030574100
Oil well
Producing
UNION PACIFIC 62AX32
51030919600
Water / Gas Inject
Injecting
UNION PACIFIC 65-5
51030608900
Water / Gas Inject
Monitor
UNION PACIFIC 67-32
51030626700
Water / Gas Inject
Injecting
UNION PACIFIC 68-32
51030628700
Water / Gas Inject
Injecting
UNION PACIFIC 69-27
51030621000
Oil well
Shut In
UNION PACIFIC 71X31
51030727600
Oil well
Producing
UNION PACIFIC 7-29
51030559700
Water / Gas Inject
Injecting
UNION PACIFIC 73X29
51030738600
Oil well
Producing
UNION PACIFIC 74X27
51030741600
Oil well
Monitor
UNION PACIFIC 75X32
51030740200
Oil well
Producing
UNION PACIFIC 76X21
51030742100
Oil well
Producing
UNION PACIFIC 77X32
51030745400
Oil well
Producing
UNION PACIFIC 78X21
51030742600
Water / Gas Inject
Injecting
UNION PACIFIC 79X32
51030744800
Oil well
Monitor
UNION PACIFIC 80X28
51030746000
Water / Gas Inject
Monitor
UNION PACIFIC 81X29
51030749900
Oil well
Producing
UNION PACIFIC 8-20
51030568600
Oil well
Producing
UNION PACIFIC 82X28
51030749400
Oil well
Producing
UNION PACIFIC 83X28
51030750000
Oil well
Producing
UNION PACIFIC 84X28
51030749500
Oil well
Producing
UNION PACIFIC 85X34
51030748100
Water / Gas Inject
Injecting
UNION PACIFIC 86X27
51030748200
Water / Gas Inject
Injecting
UNION PACIFIC 87X29
51030750900
Oil well
Producing
UNION PACIFIC 88X21
51030751400
Oil well
Producing
UNION PACIFIC 89X34
51030754800
Water / Gas Inject
Injecting
UNION PACIFIC 91X28
51030756000
Water / Gas Inject
Injecting
UNION PACIFIC 9-29
51030565600
Water / Gas Inject
Injecting
UNION PACIFIC 92X28
51030757400
Water / Gas Inject
Monitor
UNION PACIFIC 94X27
51030758800
Water / Gas Inject
Injecting
UNION PACIFIC 96X29
51030765000
Oil well
Producing
UNION PACIFIC 97X29
51030765100
Oil well
Producing
UNION PACIFIC 98X32
51030765200
Oil well
Producing
UNION PACIFIC 99X29
51030785600
Oil well
Producing
UNION PACIFIC B1-34
51030548900
Water / Gas Inject
Monitor
UNION PACIFIC B2-34
51030102700
Oil well
Monitor
62
-------
UNION PACIFIC B3X34
51030744000
Oil well
Producing
UNION PACIFIC B4X34
51030753600
Water / Gas Inject
Injecting
UNION PACIFIC B5X34
51030759900
Water / Gas Inject
Injecting
UNION PACIFIC B6X34
51030760200
Water / Gas Inject
Monitor
WALBRIDGE LB 1
51030607000
Water / Gas Inject
Monitor
WALBRIDGE UNIT 1
51030607200
Water / Gas Inject
Monitor
WALBRIDGE UNIT 2X
51030920500
Oil well
Producing
WALBRIDGE UNIT 3X
51030920600
Oil well
Monitor
WEYRAUCH 2-36
51030630600
Water / Gas Inject
Injecting
WEYRAUCH 4X36
51030707200
Oil well
Producing
WEYRAUCH 5X36
51030881900
Oil well
Producing
WEYRAUCH 6X36
51030916600
Oil well
Producing
WEYRAUCH 7X36
51030916300
Oil well
Producing
AC MCLAUGHLIN 39
51030582400
P&A
P&A
AC MCLAUGHLIN 3
51030578600
P&A
P&A
MCLAUGHLIN AC 40
51030632000
P&A
P&A
AC MCLAUGHLIN 41
51030575900
P&A
P&A
AC MCLAUGHLIN 48X
51030580300
P&A
P&A
AC MCLAUGHLIN 59X
51030769100
P&A
P&A
MCLAUGHLIN AC 81X
51031053000
P&A
P&A
A.C. MCLAUGHLIN A A2
51030609300
P&A
P&A
AC MCLAUGHLIN B 1
51030611000
P&A
P&A
AC MCLAUGHLIN B 2
51030610500
P&A
P&A
AC MCLAUGHLIN 1
51030612000
P&A
P&A
AC MCLAUGHLIN 1
51030757700
P&A
P&A
ASSOCIATED 4X
51030881200
P&A
P&A
ASSOCIATED B 1
51030601200
P&A
P&A
ASSOCIATED B 2
51030601000
P&A
P&A
ASSOCIATED B 3
51030601300
P&A
P&A
BEEZLEY 1 22
51030573900
P&A
P&A
CT CARNEY 12-5
51030107000
P&A
P&A
C T CARNEY 26X35
51030745000
P&A
P&A
CARNEY CT 31X4
51030760400
P&A
P&A
CARNEY C T 34X-4
51030760000
P&A
P&A
CARNEY CT 36X34
51030759500
P&A
P&A
CARNEY CT 40X35
51030911700
P&A
P&A
CARNEY CT 42Y34
51030915400
P&A
P&A
CHASE UNIT U 1
51030600800
P&A
P&A
HILL.C.E. 1
51030601800
P&A
P&A
HEFLEY C-S 1
51030104100
P&A
P&A
C-S HEFLEY 2
51030607700
P&A
P&A
63
-------
C-S HEFLEY 3
51030607800
P&A
P&A
C R STOFFER A 3
51030562600
P&A
P&A
EMERALD 12
51030566700
P&A
P&A
EMERALD 15
51030565400
P&A
P&A
EMERALD 18
51030104900
P&A
P&A
EMERALD 21
51030546400
P&A
P&A
EMERALD 24
51030563500
P&A
P&A
EMERALD 29
51030565800
P&A
P&A
EMERALD 30
51030563000
P&A
P&A
EMERALD 31
51030623700
P&A
P&A
EMERALD 33
51030623900
P&A
P&A
EMERALD OIL CO. 3M
51030724700
P&A
P&A
EMERALD 43
51030625200
P&A
P&A
EMERALD 44
51030633800
P&A
P&A
EMERALD 45
51030603000
P&A
P&A
EMERALD 49X
51030729600
P&A
P&A
EMERALD 5
51030566600
P&A
P&A
EMERALD 7
51030624100
P&A
P&A
E OLDLAND 4
51030715200
P&A
P&A
FAIRFIELD,KITTIE A 2
51030611400
P&A
P&A
FAIRFIELD,KITTIE A 3
51030611700
P&A
P&A
F V LARSON 116
51036652500
P&A
P&A
FEE 118X
51030843900
P&A
P&A
FEE 119X
51030849400
P&A
P&A
FEE 161X
51031185900
P&A
P&A
FEE 16
51030624600
P&A
P&A
FEE 2
51030558600
P&A
P&A
FEE 46
51030610700
P&A
P&A
FEE 53
51030617400
P&A
P&A
FEE 54
51030618000
P&A
P&A
FEE 57
51030622700
P&A
P&A
FEE 58
51030614300
P&A
P&A
FEE 66
51030610900
P&A
P&A
FEE 67
51030611600
P&A
P&A
FEE 70
51030626000
P&A
P&A
FEE 71
51030610800
P&A
P&A
FEE 77X
51030736000
P&A
P&A
FEDERAL ET AL 2M
51030719700
P&A
P&A
FEDERAL ET AL 5M
51030731700
P&A
P&A
LARSON FVB10
51030629900
P&A
P&A
LARSON FV B13X
51030557900
P&A
P&A
64
-------
LARSON FV B16X
51030702400
P&A
P&A
LARSON FV B1
51030629600
P&A
P&A
LARSON FV 26Y
51030948500
P&A
P&A
LARSON FV B3
51030630500
P&A
P&A
LARSON FV B5
51030630100
P&A
P&A
LARSON FV B6
51030630300
P&A
P&A
LARSON F V B7
51030630001
P&A
P&A
LARSON FV B9
51030102500
P&A
P&A
F V LARSON 1
51030539800
P&A
P&A
GENTRY 2D
51030543700
P&A
P&A
GENTRY 3D
51030608500
P&A
P&A
NEWTON 4-D
51030104300
P&A
P&A
GENTRY 4D
51030543700
P&A
P&A
GENTRY 5D
51030608300
P&A
P&A
GENTRY 6X
51030744200
P&A
P&A
GRAY A 11
51030613800
P&A
P&A
GRAY A 11 AX
51030927500
P&A
P&A
GRAY A 8
51030568100
P&A
P&A
GRAY B 14
51030613000
P&A
P&A
GUIBERSON,S.A. A 2
51030613400
P&A
P&A
HILDENBRANDT 1
51030608100
P&A
P&A
COLTHARP JE 1
51030602400
P&A
P&A
J E COLTHARP 3
51030602500
P&A
P&A
COLTHARP JE 6X
51030714800
P&A
P&A
COLTHARP JE 9X P 9X
51030853500
P&A
P&A
PEPPER,J.E. A 1
51030550200
P&A
P&A
J E PEPPER B 1
51030606300
P&A
P&A
LACY SB 10Y
51030914300
P&A
P&A
S B LACY 2
51030570600
P&A
P&A
F V LARSON 1
51030106500
P&A
P&A
LEVI SON 15
51030618100
P&A
P&A
LEVI SON 16
51030619600
P&A
P&A
LEVI SON 19
51030106300
P&A
P&A
LEVI SON 20
51030618300
P&A
P&A
LEVISON 3
51030621600
P&A
P&A
LEVISON 4
51030560400
P&A
P&A
LEVISON 5
51030621500
P&A
P&A
L N HAGOOD B 1
51030607300
P&A
P&A
L N HAGOOD B 2
51030607100
P&A
P&A
L N HAGOOD B 3
51030607400
P&A
P&A
WALBRIDGE LB 3
51030630800
P&A
P&A
65
-------
WALBRIDGE LB 4X
51030873600
P&A
P&A
WALBRIDGE LB 5Y
51030948300
P&A
P&A
MAGOR 1
51030580800
P&A
P&A
MCLAUGHLIN 3
51030556100
P&A
P&A
MELLEN,W.P. A 3
51030105700
P&A
P&A
HEFLEY ME 1
51030607500
P&A
P&A
HEFLEY ME 3
51030545400
P&A
P&A
HEFLEY ME 4
51030543300
P&A
P&A
M B LARSON C11 X 25
51030717300
P&A
P&A
MB LARSON A 1
51030632900
P&A
P&A
MB LARSON A3
51030576400
P&A
P&A
LARSON MB 1-35
51030555700
P&A
P&A
MB LARSON C 1
51030571900
P&A
P&A
LARSON MB C2-25
51030106400
P&A
P&A
M B LARSON C425
51030618900
P&A
P&A
LARSON MB D136
51030631000
P&A
P&A
LARSON MB D226
51030102600
P&A
P&A
M B LARSON D525
51030618500
P&A
P&A
M B LARSON D625
51030619000
P&A
P&A
M B LARSON D725
51030618400
P&A
P&A
NEAL2
51030566000
P&A
P&A
NEAL3
51030567200
P&A
P&A
NEWTON ASSOC A1
51030107300
P&A
P&A
NEWTON ASSOC B 1
51030101800
P&A
P&A
NEWTON ASSOC C 1
51030102100
P&A
P&A
NEWTON ASSOC D 1
51030102200
P&A
P&A
NIKKEL 1
51030619300
P&A
P&A
NIKKEL 2
51030619100
P&A
P&A
OLDLAND 1
51030102000
P&A
P&A
OLDLAND 2
51030106100
P&A
P&A
OLDLAND 3
51030630400
P&A
P&A
OLDLAND E 5X
51030853600
P&A
P&A
OLDLAND E 6X
51030947600
P&A
P&A
PURDY16
51030606200
P&A
P&A
PURDY 3X1
51030870300
P&A
P&A
RANGELY 2M-33-19B
51030939800
P&A
P&A
RAVEN A 1
51030562900
P&A
P&A
RAVEN B 2
51030624300
P&A
P&A
RECTOR 10X
51030760300
P&A
P&A
RECTOR 2
51030608400
P&A
P&A
RECTOR 4
51030629400
P&A
P&A
66
-------
RECTOR 5
51030629200
P&A
P&A
RECTOR 6
51030608200
P&A
P&A
RECTOR 7
51030105900
P&A
P&A
RIGBY A224
51030570000
P&A
P&A
ROOTH 3
51030564700
P&A
P&A
MCLAUGHLIN SHARPLES 11X 3
51030760500
P&A
P&A
SHARPLES MCLAUGHLIN 132
51030107400
P&A
P&A
SHARPLES MCLAUGHLIN 432
51030627400
P&A
P&A
UNION PACIFIC 121X21
51030870500
P&A
P&A
U P3016
51030578300
P&A
P&A
UNION PACIFIC 37-29
51030623200
P&A
P&A
U P 3822
51030574400
P&A
P&A
U P 4022
51030617800
P&A
P&A
U P 4228
51030621800
P&A
P&A
U P 4420
51030571000
P&A
P&A
UNION PACIFIC 46-21
51030573700
P&A
P&A
U P 5721
51030616500
P&A
P&A
U P 5927
51030620900
P&A
P&A
UNION PACIFIC 62-32
51030626500
P&A
P&A
UNION PACIFIC 63-31
51030623000
P&A
P&A
UNION PACIFIC 63-31
51030626400
P&A
P&A
UNION PACIFIC 63AX31
51030917900
P&A
P&A
U P 6422
51030617200
P&A
P&A
U P6616
51030610600
P&A
P&A
UNION PACIFIC 72X31
51030736400
P&A
P&A
UNION PACIFIC 90X29
51030758200
P&A
P&A
UNION PACIFIC 93X27
51030756100
P&A
P&A
U P 95X 34
51030759600
P&A
P&A
COLTHARP WH A2
51030602000
P&A
P&A
COLTHARP WH A7X
51030869300
P&A
P&A
COLTHARP WH B1
51030101900
P&A
P&A
WEYRAUCH 1-36
51030630700
P&A
P&A
WEYRAUCH 336
51030630900
P&A
P&A
WHITE 1
51030543500
P&A
P&A
WHITE 2
51030545100
P&A
P&A
67
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Request for Additional Information: Rangely Gas Plant
March 15, 2024
Instructions: Please enter responses into this table and make corresponding revisions to the MRV Plan as necessary. Any long responses,
references, or supplemental information may be attached to the end of the table as an appendix. This table may be uploaded to the Electronic
Greenhouse Gas Reporting Tool (e-GGRT) in addition to any MRV Plan resubmissions.
No.
MRV Plan
EPA Questions
Responses
Section
Page
1.
7.3
34
"C02,w = Annual C02 mass produced (metric tons)."
This variable within RR-8 should be "CC>2,w = Annual CO2 mass produced
(metric tons) through separator w." Please revise this section and
ensure that all equations and variables listed are consistent with the
text in 40 CFR 98.443 (https://www.ecfr.gov/current/title-
40/chapter- l/subchapter- C/part-98/subpart-RR#98.443).
Section 7.3 has been revised to match RR-8.
2.
7.3
34
"w = inlet meter to RCF."
This variable within RR-8 should be "w = separator." Please revise
this section and ensure that all equations and variables listed are
consistent with the text in 40 CFR 98.443
(https://www.ecfr.gov/current/title-40/chapter- l/subchapter-
Section 7.3 has been revised to match RR-8.
C/part-98/subpart-RR#98.443).
3.
7.3
34
"C02P = Total annual C02 mass produced (metric tons) through all
meters in the reporting year."
This variable within RR-9 should be "CO2P = Total annual CO2 mass
produced (metric tons) through all separators in the reporting
year." Please revise this section and ensure that all equations and
variables listed are consistent with the text in 40 CFR 98.443
(https://www.ecfr.gov/current/title-40/chapter- l/subchapter-
Section 7.3 has been revised to match RR-9.
C/part-98/subpart-RR#98.443).
-------
No.
MRV Plan
EPA Questions
Responses
Section
Page
4.
7.3
34
"C02,w = Annual C02 mass produced (metric tons) through meter
w in the reporting year."
This variable within RR-9 should be "CC>2,w= Annual CO2 mass
produced (metric tons) through separator w in the reporting year."
Please revise this section and ensure that all equations and
variables listed are consistent with the text in 40 CFR 98.443
(https://www.ecfr.gov/current/title-40/chaoter- l/subchapter-
Section 7.3 has been revised to match RR-9.
C/part-98/subpart-RR#98.443).
-------
Scout Energy Management, LLC
Rangely Field
Subpart RR Monitoring, Reporting and Verification (MRV) Plan
February 2024
-------
Table of Contents
Roadmap to the Monitoring, Reporting and Verification (MRV) Plan 3
1. Facility Information 4
2. Project Description 4
2.1 Project Characteristics 4
2.2 Environmental Setting 6
2.3 Description of C02 EOR Project Facilities and the Injection Process 13
3. Delineation of Monitoring Area and Timeframes 19
3.1 Active Monitoring Area 19
3.2 Maximum Monitoring Area 20
3.3 Monitoring Timeframes 20
4. Evaluation of Potential Pathways for Leakage to the Surface 20
4.1 Introduction 21
4.2 Existing Wellbores 21
4.3 Faults and Fractures 23
4.4 Natural or Induced Seismicity 23
4.5 Previous Operations 23
4.6 Pipeline / Surface Equipment 23
4.7 Lateral Migration Outside the Rangely Field 24
4.8 Drilling Through the C02 Area 24
4.9 Diffuse Leakage through the Seal 25
4.10 Monitoring, Response, and Reporting Plan forC02 Loss 25
4.11 Summary 26
5. Monitoring and Considerations for Calculating Site Specific Variables 26
5.1 For the Mass Balance Equation 26
5.2 To Demonstrate that Injected C02 is not Expected to Migrate to the Surface 30
6. Determination of Baselines 30
7. Determination of Sequestration Volumes Using Mass Balance Equations 31
7.1. Mass of C02 Received 32
7.2 Mass of C02 Injected into the Subsurface 33
7.3 Mass of C02 Produced 34
7.4 Mass of C02 emitted by Surface Leakage 34
7.5 Mass of C02 sequestered in subsurface geologic formations 35
7.6 Cumulative mass of C02 reported as sequestered in subsurface geologic formations.. 36
8. MRV Plan Implementation Schedule 36
9. Quality Assurance Program 36
9.1 Monitoring QA/QC 36
9.2 Missing Data Procedures 37
9.3 MRV Plan Revisions 37
10. Records Retention 37
11. Appendices 38
Appendix 5. Well Identification Numbers 44
2
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Roadmap to the Monitoring, Reporting and Verification (MRV) Plan
Scout Energy Management, LLC (SEM) operates the Rangely Weber Sand Unit (RWSU) and the
associated Raven Ridge pipeline (RRPC), (collectively referred to as the Rangely Field) in Northwest
Colorado for the primary purpose of enhanced oil recovery (EOR) using carbon dioxide (C02) flooding.
SEM has utilized, and intends to continue to utilize, injected C02 with a subsidiary purpose of establishing
long-term containment of a measurable quantity of C02 in subsurface geological formations at the Rangely
Field for a term referred to as the "Specified Period." The Specified Period includes all or some portion of
the period 2023 to 2060. During the Specified Period, SEM will inject C02 that is purchased (fresh C02)
from ExxonMobil's (XOM) Shute Creek Plant or third parties, as well as C02 that is recovered (recycled
C02) from the Rangely Field's C02 Recycle and Compression Facilities (RCF's). SEM has developed this
monitoring, reporting, and verification (MRV) plan in accordance with 40 CFR §98.440-449 (Subpart RR)
to provide for the monitoring, reporting and verification of the quantity of C02 sequestered at the Rangely
Field during the Specified Period.
SEM has chosen to submit this MRV plan to the EPA for approval according to 40 Code of Federal
Regulations (CFR) 98.440(c)(1), Subpart RR of the Greenhouse Gas Reporting Program for the purpose
of qualifying for the tax credit in section 45Q of the federal Internal Revenue Code.
This MRV plan contains eleven sections:
o Section 1 contains general facility information.
o Section 2 presents the project description. This section describes the planned injection volumes, the
environmental setting of the Rangely Field, the injection process, and reservoir modeling. It also illustrates
that the Rangely Field is well suited for secure storage of injected C02.
o Section 3 describes the monitoring area: the RWSU in Colorado.
o Section 4 presents the evaluation of potential pathways for C02 leakage to the surface. The assessment
finds that the potential for leakage through pathways other than the man-made wellbores and surface
equipment is minimal.
o Section 5 describes SEM's risk-based monitoring process. The monitoring process utilizes SEM's reservoir
management system to identify potential C02 leakage indicators in the subsurface. The monitoring process
also utilizes visual inspection of surface facilities and personal H2S monitors program as applied to
Rangely Field. SEM's MRV efforts will be primarily directed towards managing potential leaks through
wellbores and surface facilities.
o Section 6 describes the baselines against which monitoring results will be compared to assess whether
changes indicate potential leaks.
o Section 7 describes SEM's approach to determining the volume of C02 sequestered using the mass
balance equations in 40 CFR §98.440-449, Subpart RR of the Environmental Protection Agency's (EPA)
Greenhouse Gas Reporting Program (GHGRP). This section also describes the site-specific factors
considered in this approach.
o Section 8 presents the schedule for implementing the MRV plan.
o Section 9 describes the quality assurance program to ensure data integrity.
o Section 10 describes SEM's record retention program.
o Section 11 includes several Appendices.
3
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1. Facility Information
The Rangely Gas Plant, operated by SEM and a part of the Rangely Field, reports under Greenhouse Gas
Reporting Program Identification number 537787.
The Colorado Oil and Gas Conservation Commission (COGCC)1 regulates all oil, gas and geothermal
activity in Colorado. All wells in the Rangely Field (including production, injection and monitoring wells) are
permitted by COGCC through Code of Colorado Regulations (CCR) 2 CCR 404-1:301. Additionally,
COGCC has primacy to implement the Underground Injection Control (UIC) Class II program in the state
for injection wells. All injection wells in the Rangely Field are currently classified as UIC Class II wells.
Wells in the Rangely Field are identified by name, API number, status, and type. The list of wells as of April,
2023 is included in Appendix 5. Any new wells will be indicated in the annual report.
2. Project Description
This section describes the planned injection volumes, environmental setting of the Rangely Field, injection
process, and reservoir modeling conducted.
2.1 Project Characteristics
SEM utilized historic production and injection of the RWSU in order to create a production and injection
forecast, included here to provide an overview of the total amounts of C02 anticipated to be injected,
produced, and stored in the Rangely Field as a result of its current and planned C02 EOR operations during
the forecasted period. This forecast is based on historic and predicted data. Figure 1 shows the actual
(historic) C02 injection, production, and stored volumes in the Rangely Field from 1986, when Chevron
initiated C02 flooding, through 2022 (solid line) and the forecast for 2023 through 2060 (dotted line). It is
important to note that this is just a forecast; actual storage data will be collected, assessed, and reported as
indicated in Sections 5, 6, and 7 in this MRV Plan. The forecast does illustrate, however, the large potential
storage capacity at Rangely field.
1 Pursuant to Colorado SB21-285, effective July 1, 2023, the COGCC will become the Energy and Carbon
Management Commission.
4
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Rangely Field
Historical and Projected C02
6000
~o
c
5000
T3
C
(D
(D
<1J
>
CT>CT>OO*H*H*H(N(Nr0r0r0^-^-L/lL/lL/l
aiaiaiaiooooooooooooooo
*H*H*H*H(N(N(N(N(N(N(N(N(N(N(N(N(N(N(N
Year
Figure 1 - Rangely Field Historic and Forecast C02 Injection, Production, and Storage 1986-2060
The amount of C02 injected at Rangely Field is adjusted periodically to maintain reservoir pressure and to
increase recovery of oil by extending or expanding the EOR project. The amount of C02 injected is the
amount needed to balance the fluids removed from the reservoir and to increase oil recovery. While the
model output shows C02 injection and storage through 2060, this data is for planning purposes only and
may not necessarily represent the actual operational life of the Rangely Field EOR project. As of the end
of 2022, 2,320,000 million standard cubic feet (MMscf) (122.76 million metric tons (MMMT)) of C02 has
been injected into Rangely Field. Of that amount, 1,540,000 MMscf (81.48 MMMT) was produced and
recycled.
While tons of C02 injected and stored will be calculated using the mass balance equations described in
Section 7, the forecast described above reflects that the total amount of C02 injected and stored over the
modeled injection period to be 967,000 MMscf (51.2 MMMT). This represents approximately 35.7% of the
theoretical storage capacity of Rangely Field.
Figure 2 presents the cumulative annual forecasted volume of C02 stored by year through 2060, the
modeling period forthe projection in Figure 1. The cumulative amount stored is equal to the sum of the annual
storage volume for each year plus the sum of the total of the annual storage volume for each previous year.
As is typical with C02 EOR operations, the rate of accumulation of stored C02 tapers overtime as more
recycled C02 is used for injection. Figure 2 illustrates the total cumulative storage overthe modeling period,
projected to be 967,000 MMscf (51.2 MMMT) of C02.
5
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Rangely Field
Historical and Forecast Cumulative C02 Storage
60
i-
(0
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Figure 3 - Regional map showing Rangely's position between the Uinta and Piceance Basin.
The reservoir, Weber Sands, is comprised of clean eolian quartz deposited in an erg (sand sea)
depositional environment. Internally, these dune sands are separated into six main packages (odd
numbers, 1 to 11) with the fluvial Maroon Formation (even numbers, 2 to 10) interfingering the field from
the north. The Weber Formation is underlain by the fossiliferous Desmoinesian carbonates of the Morgan
Formation, and overlain by the siltstones and shales of the Phosphoria/Park City and Moenkopi
Formations.
Forthe majority of the region, the Phosphoria Formation acts as an impermeable barrier above the
Weber Formation and is a hydrocarbon source forthe overlying strata. However, due to the large thrust
fault south and west of the field, the Phosphoria Formation was driven down to significantly deeper
depths, and below the reservoir Weber sands, allowing for maturation and expulsion of the hydrocarbons
to migrate upward into stratigraphically older, but structurally shallower reservoirs sometime during the
Jurassic. At Rangely, the Phosphoria Formation is almost entirely missing above the Weber Formation,
but the Moenkopi Formation sits directly above the sands creating the seal forthe petroleum system.
Fresh water in and around the town/field of Rangely is sourced from the quaternary creeks and rivers that
cut across the region (data obtained from the Colorado Division of Water Resources). No confined fresh
water aquifers are present between the reservoir rock and the surface. Safety measures are still taken to
protect the shallowest of rocks that contain rain water seepage (unconfined aquifer) into the Mancos
Formation (surface exposure at Rangely) illustrated by the surface casing on Figure 4. The shallowest
point of the reservoir is 5,486 ft below the surface (4,986 ft below any possible fresh rain water seepage).
The mere presence of hydrocarbons and the successful implication of a C02 flood indicates the quality
and effectiveness of the seal to isolate this reservoir from higher strata.
7
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Uinta Basin
Douglas Creek
Arch
Piceance Basin
ichesne River and Uinta Fms
CoKon Fm
Wasatch Fr
Wasatch and
Fort Union Fms
k I r_.
rm
Blackhawk Fm
Ferron Ss Mbr of Ma cos Sh and Frontu
Dakota Ss
Sue hem Cgl Mbr
Salt Wash Ss O O
Morrison Fm
O Entrada Ss O
Glen Canyon Ss
Cftnle Fm
Moenkep. Fm
Source
__ParY. City Fm
upper Weber Ss
Reservoir
Maroon
cr_ Fm
Round Valley Ls
Manning Canyon Sh
Doughnut Sh/Humbug Fm
Deseret Ls
Leadville Ls
Madison Ls
Pinyon.
-TfeniWU rf"
Dotsero Fm
Lodore Fm
Sawatch Ss
KEY
PETROLEUM
SYSTEMS:
I| Green River
system
I| Mesaverde
system
l| Mancos/Mowry
system
I| Phosphoria
system SOUTCe
Grassy Trail
° Creek oil
~ Mtnturn system
,, SignFficant oil production
{indicating source rock)
v./ Significant gas production
^ (indicating source rock)
S Source rocks
(R) Rangely Field
Main reservoir
I I Hiatus
Stratigraphy
at Rangely
Figure 4. Stratigraphic Column of formations at the Rangely Field. Due to a large fault the source
rock (Phosphoria) is stratigraphically above the reservoir rock (Weber), but structurally, the
source lies below the reservoir, (from U.S. Geological Survey, 2003)
Figure 5 shows the doubly plunging anticline with the long axis along a northwest-southeast trend and the
short axis along a northeast-southwest trend. In 1949 the depth of a gas cap was established at -330 ft
subsea and an Oil Water Contact (OWC) at -1150 ft subsea. Many core analysis suggest that below this -
1150' OWC is a transition/residual oil zone. However, for the purpose of this analysis and all volumetrics
8
-------
the base of the reservoir will be at the -1150' subsea depth determined in 1949.
Geologically, the Weber Sands were deposited on top of the Morgan formation which is a combination of
interbedded shale, siltstone, and cherty limestone. Few wells are drilled deep enough to penetrate the
Morgan formation within the Rangely Field to gather porosity/permeability data locally. However, analysis
of the Morgan formation from other fields/outcrops indicate that it is a non-reservoir rock (low
porosity/permeability), and would be sufficient as a basial barrier for the field. The highest subsurface
elevation of the base of the Weber Sands is deeper than the -1150' used for the OWC. Meaning injected
C02 should not encounter the Morgan formation. Additionally, Section 4.7 explains how the Rangely
Field is confined laterally through the nature of the anticline's structure.
Figure 5. Structure map of the Weber 1 (top of reservoir). Colors illustrate the maximum aerial
coverage of the Gas Cap (Red), Main Reservoir (Green), and Transitional Reservoir (Blue). Cross
section A-A' is predominantly along the long axis of the field and B-B' is along the short axis.
The Rangely Field has one main field fault (MFF) and numerous smaller faults (isolated and joint) and
fractures that are present throughout the stratigraphic column between the base of the Weber reservoir
and surface. Faults within the reservoir were measured by well-to-well displacement, while the fractures
were measured and observed as calcite veins on the surface with no displacement. The MFF has a NE-
WSW trend and cuts through the reservoir interval. In the 1960's Rangely residents began experiencing
felt earthquakes. Between 1969 and 1973, a joint investigation with the USGS installed seismic
monitoring stations in and around the town of Rangely and began recording activity. In 1971, a study was
conducted to evaluate the stress state in the vicinity of the fault which determined a critical fluid pressure
above which fault slippage may occur. Reservoir pressure was then manipulated and correlated with
increases or decreases in seismic activity. This study determined that the waterflood in Rangely was
inducing seismicity when reservoir pressure was raised above ~3730 psi.
In the 1990's, field reservoir pressure had built back up leading to the largest magnitude earthquake in
9
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Rangely which took place in 1995 (M 4.5), shortly after maximum reservoir pressure was reached in
1998. Pressure maintenance began and seismic activity dropped off after lowering the average field
reservoir pressure down to ~3100 psi. No other seismic activity was recorded around the field until 2015
and 2017 when there was a total of 5 seismic events (see Figure 6) around the northeastern portion of
the MFF. A new interpretation from the 3D seismic revealed a series of previously unknown joint faults
(perpendicular to the MFF). Investigation into this region revealed that the ~3730 psi threshold had been
crossed and triggered the seismic events. Since the 2017 seismic events, no other events have been
recorded of felt magnitude and continued pressure monitoring further reduces the risk of another event.
2017 Induced
Seismic Study*
Figure 6. USGS fault history map (1900-2023). Largest earthquake was the 1995 M 4.5 north of the
unit (2017 was a study to induce seismic activity along the MFF, and not caused by day-to-day
operations)
The natural fractures found within the field play a significant role in fluid flow. The subsurface natural
fractures are vertical and show an approximately ENE trend and their extension joints are orientated ESE.
Shallower portions of the reservoir show a distinctly higher density of fractures than deeper portions. On
the shallow dipping sides of the anticline, there does not appear to be a strong structural control on
fracture density. Most well-to-well rapid breakthrough of injected C02 is along these ENE fractures. It is
unknown if this is from natural or induced fractures. There is no evidence that these natural fractures
diminish the seals integrity.
10
-------
Figure 7. Cross section A-A' along the long axis of the field, and perpendicular to the MRR. The
MFF does not have much displacement and is near vertical.
The Rangely Field has approximately 1.9 billion barrels of Original Oil in Place (OOiP). Since first
discovered in 1933, Rangely Field has produced 920 million barrels of oil, or 48% of the OOiP. The
Rangely Field has an aerial extent of approximately 19,150 acres with an average gross thickness of 650
ft. The previously mentioned 11 internal layers of the reservoir, alternating zones of Weber and Maroon
Formations, can be simplified to only three sections. The Upper Weber contains intervals 1-3, the Middle
Weber contains intervals 4-7, and the Lower Weber contains intervals 8-approxamently 50 ft below the
11D marker (identified by the base of the yellow in Figure 7). These interval groupings were determined
by the extensive lateral continuingly and thickness of the Weber 4 and Weber 8 which easily separate the
reservoir into the three zones. For the majority of the Rangely Field, the even Maroon Formations act as
flow barriers between the odd Weber Formations. Average porosity within the Weber Sands dune fades
is 10.3% and within the Maroon fluvial fades is 4.9%. However, the key factor that enables the Maroon
Formation to be a seal is its lack of permeability. The Weber dune fades have an average permeability of
2.44 millidarcy (Md), while the Maroon fluvial fades have an average permeability of 0.03 Md.
owe -1150'
Transition Zone & ROZ
11
-------
Figure 8. Cross section B-B' along the short axis of the field and parallel to the MFF. Used to
illustrate the variation of the Oil Water Contact (OWC).
Given that the Rangely Field is located at the highest subsurface elevations of the structure, that the
confining zone has proved competent over both millions of years and throughout decades of EOR
operations, and that the Rangely Field has ample storage capacity, SEM is confident that stored C02 will
be contained securely within the Weber Sands in the Rangely Field.
2.2.2 Operational History of the Rangely Field
The Rangely Field was discovered in 1933 but subsequently ceased production until World War II when oil
returned to high demand. Intensive development began, expanding from one well to 478 wells by 1949. It
is located in the northwestern portion of Colorado.
The Rangely Field was originally developed by Chevron. Following the initial discover in 1933,
Chevron imitated a 40-acre development in 1944, followed by hydrocarbon gas injection from
1950 to 1969. To improve efficiency, in 1957, the RWSU was formed. The boundaries of the RWSU are
reflected in Figure 9.
Rangely Well List
^ Active-Producer
yf 0 TA- Producer
~ Active-Injector
A TA-Injector
T Active 5WD
Collection Station / Facility
¦ Collection Station
$ Compressor Station
X ¦ Rangely Facility
(££) Rangely Plant General
A West End Water Injection
N -Rangely Weber Unit
23^^ Rangely Weber Unit
1 "l1 Rangely Weber Unit Half Mile Buffer
Mdien Htl
BIO BIANG& COuWv
± i iu* vOJ /
A (t'li *A-A*AV
u -
v^aV S
\ »> i
v TLtw.}
- >. /./~ WA i * a
2X102W
'Rio Blanco-
Rdpgely OiStnet
Hospital Hetip&i
River
itf N)2W
Moffat
0/HICJ blAnCO CO0NTY
Uintah
Rio Blanco
Garfield
Figure 9 - Rangely Field Map
12
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Chevron began C02 flooding of the Rangely Field in 1986 and has continued and expanded it since that
time. The experience of operating and refining the Rangely Field C02 floods over the past decade has
created a strong understanding of the reservoir and its capacity to store C02.
2.3 Description of C02 EOR Project Facilities and the Injection Process
Figures 10 shows a simplified flow diagram of the project facilities and equipment in the Rangely Field.
C02 is delivered to the Rangely Field via the Raven Ridge Pipeline. The C02 injected into the Rangely
Field is currently supplied by XOM's Shute Creek Plant into the pipeline system.
Once C02 enters the Rangely Field there are four main processes involved in EOR operations. These
processes are shown in Figure 10 and include:
1. C02 Distribution and Injection. Purchased C02 and recycled C02 from the RCF is sent through the main
C02 distribution system to various C02 Injectors throughout the Field.
2. Produced Fluids Handling. Produced fluids gathered from the production wells are sent to collection
stations for separation into a gas/C02 mix and a produced fluids mix of water, oil, gas, and C02. The
produced fluids mix is sent to centralized water plants where oil is separated for sale into a pipeline, water
is recovered for reuse, and the remaining gas/C02 mix is merged with the output from the collection
stations. The combined gas/C02 mix is sent to the RCF and natural gas liquids (NGL) Plant. Produced oil
is metered and sold; water is forwarded to the water injection plants for treatment and reinjection or disposal.
3. Produced Gas Processing. The gas/C02 mix separated at the satellite batteries goes to the RCF and
NGL Plant where the NGLs, and C02 streams are separated. The NGLs move to a commercial pipeline for
sale. The remaining C02 (e.g., the recycled C02) is returned to the C02 distribution system for reinjection.
4. Water Treatment and Injection. Water separated in the tank batteries is processed at water plants to
remove any remaining oil and then distributed throughout the Rangely Field for reinjection.
LaBarge Field/
Shute Creek Plant
Field and plant owned and
operated by ExxonMobil
Raven Ridge
Pipeline
123 mile, 16" steel pipeline
(200 MMcfd capacity)
56% CRRPC owned
(T) Rangely Field
Dehydration & NGL Extraction
RCF
1st/2nd Stage
Compression
Gasjt-,
A Custody Transfer Point for Assets
~ CO? Measurement Points
RCF
3rd/ 4th Stage
Compression
Oil/Water Liquids Liquid/Gas
Separation & ¦« Inlet
Water Plants Separation
Water T water] |_
Gas/Water
Injection
Wells
Water
Disposal
Wells
-f
Producing
Wells
Surface
Navajo Formation
COj +
Water +
Natural Gas
Oil
~ Natural Gas / NGL
+ Water
+ CO,
Weber Sands Reservoir
yv.
Figure 10 Rangely Field -General Production Flow Diagram
13
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2.3.1 C02 Distribution and Injection.
SEM purchases C02 from XOM and receives it via the Raven Ridge Pipeline through one custody transfer
metering point, as indicated in Figures 10. Purchased C02 and recycled C02 are sent through the C02
trunk lines to multiple distribution lines to individual injection wells. There are volume meters at the inlet and
outlet of the C02 Reinjection Facility.
As of April 2023, SEM has approximately 280 injection wells in the Rangely Field. Approximately 160 MMscf
of C02 is injected each day, of which approximately 15% is purchased C02, and the balance (85%) is
recycled. The ratio of purchased C02 to recycled C02 is expected to change overtime, and eventually the
percentage of recycled C02 will increase and purchases of fresh C02 will taper off as indicated in Section
2.1.
Each injection well is connected to a water alternating gas (WAG) manifold located at the well pad. WAG
manifolds are manually operated and can inject either C02 or water at various rates and injection pressures
as specified in the injection plans. The length of time spent injecting each fluid is a matter of continual
optimization that is designed to maximize oil recovery and minimize C02 utilization in each injection pattern.
A WAG manifold consists of a dual-purpose flow meter used to measure the injection rate of water or C02,
depending on what is being injected. Data from these meters is sent to the Supervisory Control and Data
Acquisition (SCADA) system where it is compared to the injection plan forthat well. As described in Sections
5 and 7, data from the WAG manifolds, visual inspections of the injection equipment, and use of the
procedures contained in 40 CFR §98.230-238 (Subpart W), will be gathered to complete the mass balance
equations necessary to determine annual and cumulative volumes of stored C02.
2.3.2 Wells in the Rangely Field
As of April 2023, there are 662 active wells that are completed in the Rangely Field, with roughly 40%
injection wells and 60% producing wells, as indicated in Figure 11,2 Table 1 shows these well counts in the
Rangely Field by status.
2 Wells that are not in use are deemed to be inactive, plugged and abandoned, temporarily abandoned, or shut in.
14
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Rangely Well List
# Active-Producer
TA-Producer
A Active-Injector
A TA-Injector
~ Active SWD
Rangely Weber Unit
I I Rangely Weber Unit
2N 103W
Metier Hill
00 RIO PLAN (9S COUN»7
2N 102W
.Rio Blanco
Ji) Rpven I
ftrfcjr li
Heliport
Moffat
I'tgely District
Vpitof Heppaf'
1N 102W
0RIO BLANCO CQ18NTY
Rio Blanco
iarfield
Figure 11 Rangely Field Wells - As of April 2023
Table 1 - Rangely Field Wells
<\ge/Completion of Well
Active
Shut-in
Temporarily
Abandoned
Plugged and
Abandoned
Drilled & Completed in the
1940's
265
5
55
149
Drilled 1950-1985
297
7
55
46
Completed after 1986
103
1
11
8
TOTAL
665
13
121
203
The wells in Table 1 are categorized in groups that relate to age and completion methods. Roughly 48%
of these wells were drilled in the 1940's and were generally completed with three strings of casing (with
surface and intermediate strings typically cemented to the surface). The production string was typically
installed to the top of the producing interval, otherwise known as the main oil column (MOC), which
extends to the producible oil/water contact (POWC). These wells were completed by stimulating the open
hole (OH), and are not typically cased through the MOC. While implementing the water flood from 1958-
1986, a partial liner would have been typically installed to allow for controlled injection intervals and this
liner would have been cemented to the top of the liner (TOL) that was installed. For example, a partial
liner would be installed from 5,700-6,500 ft, and the TOG would be at 5,700 ft. The casing weights used
15
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for the production string have varied between 7" 23 & 26#/ft. with 5" 18 #/ft. for the production liner.
The wells in Table 1 drilled during the period 1950-1986 typically were cased through the production
interval with 7" casing. Some wells were completed with 7" casing to the top of the MOC and then
completed with a 5" liner through the productive interval. The wells with liners were cemented to the TOL.
The remaining wells (roughly 12%) in Table 1 were drilled after 1986 when the C02 flood began. All of
these wells were completed with 7" casing through the POWC. Very few of these wells have experienced
any wellbore issues that would dictate the need for a remedial liner.
SEM reviews these categories along with full wellbore history when planning well maintenance projects.
Further, SEM keeps well workover crews on call to maintain all active wells and to respond to any
wellbore issues that arise. On average, in the Rangely Field there are two to three incidents per year in
which the well casing fails. SEM detects these incidents by monitoring changes in the surface pressure of
wells and by conducting Mechanical Integrity Tests (MITs), as explained later in this section and in the
relevant regulations cited. This rate of failure is less than 2% of wells per year and is considered
extremely low.
All wells in oilfields, including both injection and production wells described in Table 1, are regulated by
the COGCC under COGCC 100-1200 series rules. A list of wells, with well identification numbers, is
included in Appendix 5. The injection wells are subject to additional requirements promulgated by EPA -
the UIC Class II program - implementation of which has been delegated to the COGCC.
COGCC rules govern well siting, construction, operation, maintenance, and closure for all wells in oilfields.
Current rules require, among other provisions, that:
Class II UIC Wells will not be permitted in areas where they would inject into a formation that is
separated from any Underground Source of Drinking Water by a Confining Layer with known open
faults or fractures that would allow flow between the Injection Zone and Underground Source of Drinking
Water within the area of review.
Injection Zones will not be permitted within 300 feet in a vertical dimension from the top of any
Precambrian basement formation.
An Operator will not inject any Fluids or other contaminants into a UIC Aquifer that meets the
definition of an Underground Source of Drinking Water unless EPA has approved a UIC Aquifer
exemption as described in Rule 802.e.
In addition, SEM implements a corrosion protection program to protect and maintain the steel used in
injection and production wells from any C02-enriched fluids. SEM currently employs methods to mitigate
both internal and external corrosion of casing in wells in the Rangely Field. These methods generally protect
the downhole steel and the interior and exterior of wellbores through the use of special materials (e.g.
fiberglass tubing, corrosion resistant cements, nickel plated packers, corrosion resistant packer fluids) and
procedures (e.g. packer placement, use of annular leakage detection devices, cement bond logs, pressure
tests). These measures and procedures are typically included in the injection orders filed with the COGCC.
Corrosion protection methods and requirements may be enhanced overtime in response to improvements
in technology.
MIT
SEM complies with the MIT requirements implemented by COGCC and BLM to periodically inspect wells
and surface facilities to ensure that all wells and related surface equipment are in good repair and leak-
free, and that all aspects of the site and equipment conform with Division rules and permit conditions. All
active injection wells undergo an MIT at the following intervals:
Before injection operations begin
16
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Every 5 years as stated in the injection orders (COGCC 417.a. (1))
After any casing repair
After resetting the tubing or mechanical isolation device
Or whenever the tubing or mechanical isolation device is moved during workover operations
COGCC requires that the operator notify the COGCC district office prior to conducting an MIT. Operators
are required to use a pressure recorder and pressure gauge for the tests. The operator's field representative
must sign the pressure recorder chart along with the COGCC field representative and submit it with the MIT
form. The casing-tubing annulus must be tested to a minimum of 1200 psi for 15 minutes.
If a well fails an MIT, the operator must immediately shut the well in and provide notice to COGCC. Casing
leaks must be successfully repaired and retested or the well plugged and abandoned after submitting a
formal notice and obtaining approval from the COGCC.
Any well that fails an MIT cannot be returned to active status until it passes a new MIT
2.3.3 Produced Fluids Handling
As injected C02 and water move through the reservoir, a mixture of oil, gas, and water ("produced fluids")
flows to the production wells. Gathering lines bring the produced fluids from each production well to
collection stations. SEM has approximately 382 active production wells in the Rangely Field and production
from each is sent to one of 27 collection stations. Each collection station consists of a large vessel that
performs a gas - liquid separation. Each collection station also has well test equipment to measure
production rates of oil, water and gas from individual production wells. SEM has testing protocols for all
wells connected to a collection station. Most wells are tested twice per month. Some wells are prioritized
for more frequent testing because they are new or located in an important part of the Field; some wells with
mature, stable flow do not need to be tested as frequently; and finally, some wells will periodically need
repeat testing due to abnormal test results.
After separation, the gas phase is transported by pipeline to the C02 reinjection facility for processing as
described below. Currently the average composition of this gas mixture as it enters the facility is 92% C02
and 800ppm H2S; this composition will change overtime as C02 EOR operations mature.
The liquid phase, which is a mixture of oil and water, is sent to one of two centralized water plants where
oil is separated from water via two 3-phase separators. The water is then sent to water holding tanks where
further separation is done.
The separated oil is metered through the Lease Automatic Custody Transfer (LACT) unit located at the
custody transfer point between Chevron pipeline and SEM. The oil typically contains a small amount of
dissolved or entrained C02. Analysis of representative samples of oil is conducted once a year to assess
C02 content.
The water is removed from the bottom of the tanks at the water injection stations, where it is re-injected to
the WAG injectors.
Any gas that is released from the liquid phase rises to the top of the tanks and is collected by a Vapor
Recovery Unit (VRU) that compresses the gas and sends it to the C02 reinjection facility for processing.
17
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Rangely oil is slightly sour, containing small amounts of hydrogen sulfide (H2S), which is highly toxic. There
are approximately 25 workers on the ground in the Rangely Field at any given time, and all field personnel
are required to wear H2S monitors at all times. Although the primary purpose of H2S detectors is protecting
employees, monitoring will also supplement SEM's C02 leak detection practices as discussed in Sections
5 and 7.
In addition, the procedures in 40 CFR §98.230-238 (Subpart W) and the two-part visual inspection process
described in Section 5 are used to detect leakage from the produced fluids handling system. As described
in Sections 5 and 7, the volume of leaks, if any, will be estimated to complete the mass balance equations
to determine annual and cumulative volumes of stored C02.
2.3.4 Produced Gas Handling
Produced gas gathered from the collection stations, and water injection plants is sent to the C02 recycling
and compression facility. There is an operations meter at the facility inlet.
Once gas enters the C02 reinjection facility, it undergoes dehydration and compression. In the RWSU an
additional process separates NGLs for sale. At the end of these processes there is a C02 rich stream that
is recycled through re-injection. Meters at the C02 recycling and compression facility outlet are used to
determine the total volume of the C02 stream recycled back into the EOR operations.
As described in Section 2.3.4, data from 40 CFR §98.230-238 (Subpart W), the two-part visual inspection
process for production wells and areas described in Section 5, and information from the personal H2S
monitors are used to detect leakage from the produced gas handling system. This data will be gathered to
complete the mass balance equations necessary to determine annual and cumulative volumes of stored
C02 as described in Sections 5 and 7.
2.3.5 Water Treatment and Injection
Produced water collected from the collection stations is gathered through a pipeline system and moved to
one of two water injection plants. Each facility consists of 3-Phase separators and 79,500-barrels of
separation tanks where any remaining oil is skimmed from the water. Skimmed oil is combined with the oil
from the 3-Phase separators and sent to the LACT. The water is sent to an injection pump where it is
pressurized and distributed to the WAG injectors.
2.3.6 Facilities Locations
The current locations of the various facilities in the Rangely Field are shown in Figure 13. As indicated
above, there are two central water plants. There are twenty-seven collections stations that gather
production from surrounding wells. The two water plants are identified by the blue triangle and circle. The
twenty-seven collection stations are identified by red squares. The C02 Reinjection facility is indicated by
the green circle.
18
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Collection Station / Facility
I Collection Station
Compressor Station
¦ Rangely Facility
(££) Rangely Plant General
A West End Water Injection
Rangely Weber Unit
Rangely Weber Unit
" Men Hill
06 RIO BIANCSS COUN-1
Collection
Station 01
Collection
Station 03
Collection
Station 10m
,Rio Blanco
Collection
Station 08
Collection
2N 103W
Collection.^
Station 04
Collection
Station 20 2N 1021
Station 12
Collection
Station 05
Collection
Station 11
Collection
Station 27
West
End Water
Injection
Collection
Station 16
Heliport
Collection
Station 22
Collection Co"ec^,tV,
Station stat'°109
Collection
Station 17
Collection
Station 33
Collection
Station 28«
Collection
Station 29
Collection
Station 13
vCollection
Station 18 Main
¦ Treatment
I 37
Rangely [¦]
Plant ¦¦ Collection Collection
General Station 19 Station 24
Collection
Station 34
Collection
Station 30
Collection
Station 39
Collection
_Station_47_
Moffat
Rangely District
MOSfiittOi' HfiipOti
1N 102W
Uintah
ORIOi BLANCO CQBNTY
Rio Blanco
Garfield
Miles
Figure 13 Location of Surface Facilities at Rangely Field
3. Delineation of Monitoring Area and Timeframes
The current active monitoring area (AMA), future AMA and monitoring time frame of the AMA are
described below. Additionally, the maximum monitoring area (MMA) of the free phase C02 plume, its
buffer zone and the monitoring time frame for the MMA are described below.
3.1 Active Monitoring Area
Because C02 is present throughout the Rangely Field and retained within it, the Active Monitoring Area
(AMA) is defined by the boundary of the Rangely Field plus one-half mile buffer. This boundary is defined
in Figure 9. The following factors were considered in defining this boundary:
Free phase C02 is present throughout the Rangely Field: More than 2,320,000 MMscf (122.76 MMMT)
tons of C02 have been injected and recycled throughout the Rangely Field since 1986 and there has
been significant infill drilling in the Rangely Field, completing additional wells to further optimize
production. Operational results thus far indicate that there is C02 throughout the Rangely Field.
C02 injected into the Rangely Field remains contained within the Rangely Field AMA because of the
19
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fluid and pressure management results associated with C02 EOR. The maintenance of an IWR of 1.0
assures a stable reservoir pressure; managed lease line injection and production wells are used to
retain fluids in the Rangely Field as indicated in Section 4.7. Implementation of these methods over the
past decades have successfully contained C02 within the Rangely Field.
It is highly unlikely that injected C02 will migrate downdip and laterally outside the Rangely Field
because of the nature of the geology and the approach used for injection. As indicated in Section
2.2.1 "Geology of the Rangely Field," the Rangely Field is situated at the top of a dome structural
trap, with all directions pointing down-dip from the highest point. This means that over long periods of
time, injected C02 will tend to rise vertically towards the point in the Rangely Field with the highest
elevation.
Forecasted C02 injection volumes, shown in Figure 1, represent SEM's plan to not increase current
injection volumes and maintain an IWR of 1. Operations will not expand beyond the currently active C02-
EOR portion of the Rangely Field; therefore, the AMA is not expected to increase. Should such
expansions occur, they will be reported in the Subpart RR Annual Report for the Rangely Field, as
required by section 98.446.
3.2 Maximum Monitoring Area
The Maximum Monitoring Area (MMA) is defined in 40 CFR §98.440-449 (Subpart RR) as equal or greater
than the area expected to contain the free-phase C02 plume until the C02 plume has stabilized, plus an all-
around buffer zone of one-half mile. Section 3.1 states that the maximum extent of the injected C02 is expected
to be bounded by the Rangely Field Unit boundary shown in Figure 9. Therefore, the MMA is the Rangely Field
Unit boundary plus the one-half mile buffer as required by 40 CFR §98.440-449 (Subpart RR).
3.3 Monitoring Timeframes
SEM's primary purpose for injecting C02 is to produce oil that would otherwise remain trapped in the
reservoir and not, as in UIC Class VI, "specifically for the purpose of geologic storage."3 During a Specified
Period, SEM will have a subsidiary purpose of establishing the long-term containment of a measurable
quantity of C02 in the Weber Sands in the Rangely Field. The Specified Period will be shorter than the
period of production from the Rangely Field. This is in part because the purchase of new C02 for injection
is projected to taper off significantly before production ceases at Rangely Field, which is modeled through
2060. At the conclusion of the Specified Period, SEM will submit a request for discontinuation of reporting.
This request will be submitted when SEM can provide a demonstration that current monitoring and model(s)
show that the cumulative mass of C02 reported as sequestered during the Specified Period is not expected
to migrate in the future in a manner likely to result in surface leakage. It is expected that it will be possible to
make this demonstration within two to three years after injection for the Specified Period ceases based upon
predictive modeling supported by monitoring data. The demonstration will rely on two principles: 1) that just
as is the case for the monitoring plan, the continued process of fluid management during the years of C02
EOR operation after the Specified Period will contain injected fluids in the Rangely Field, and 2) that the
cumulative mass reported as sequestered during the Specified Period is a fraction of the theoretical storage
capacity of the Rangely Field See 40 C.F.R. § 98.441 (b)(2)(ii).
4. Evaluation of Potential Pathways for Leakage to the Surface
3 EPA UIC Class VI rule, EPA 75 FR 77291, December 10, 2010, section 146.81(b).
20
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4.1 Introduction
In the 90 years since the Rangely Field was discovered in 1933, extensive reservoir monitoring and
studies were performed. Based on the knowledge gained from historical practices, this section assesses
the following potential pathways for leakage of C02 to surface within Rangely Field.
Existing Wellbores
Faults and Fractures
Natural and Induced Seismic Activity
Previous Operations
Pipeline/Surface Equipment
Lateral Migration Outside the Rangely Field
Drilling Through the C02 Area
Diffuse Leakage Through the Seal
Detailed analysis of these potential pathways concluded that existing wellbores and pipeline/surface
equipment pose the only meaningful potential leakage pathways. Operating pressures are not expected
to increase over time, therefore there is not a specific time period that would increase the likelihood of
pathways for leakage. SEM identifies these potential pathways for C02 leakage to be low risk, i.e., less
than 1% given the extensive operating history and monitoring program currently in place.
The monitoring program to detect and quantify leakage is based on the assessment discussed below.
4.2 Existing Wellbores
As of April 2023, there are approximately 662 active SEM operated wells in the Rangely Field - split roughly
evenly between production and injection wells. In addition, there are approximately 135 wells not in use, as
described in Section 2.3.2.
Leakage through existing wellbores is a potential risk at the Rangely Field that SEM works to prevent by
adhering to regulatory requirements for well drilling and testing; implementing best practices that SEM has
developed through its extensive operating experience; monitoring injection/production performance,
wellbores, and the surface; and maintaining surface equipment.
As discussed in Section 2.3.2, regulations governing wells in the Rangely Field require that wells be
completed and operated so that fluids are contained in the strata in which they are encountered and that
well operation does not pollute subsurface and surface waters. The regulations establish the requirements
that all wells (injection, production, disposal) must comply with. Depending upon the purpose of a well, the
requirements can include additional standards for evaluation and MIT. SEM's best practices include pattern
level analysis to guide injection pressures and performance expectations; utilizing diverse teams of experts
21
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to develop EOR projects based on specific site characteristics; and creating a culture where all field
personnel are trained to look for and address issues promptly. SEM's practices, which include corrosion
prevention techniques to protect the wellbore as needed, as discussed in Section 2.3.2, ensures that well
completion and operation procedures are designed not only to comply with regulations but also to ensure
that all fluids (e.g., oil, gas, C02) remain in the Rangely Field until they are produced through an SEM well.
As described in Section 5, continual and routine monitoring of SEM's wellbores and site operations will be
used to detect leaks, including those from non-SEM wells, or other potential well problems, as follows:
Well pressure in injection wells is monitored on a continual basis. The injection plans for each pattern
are programmed into the injection WAG controller, as discussed in Section 2.3.1, to govern the rate and
pressure of each injector. Pressure monitors on the injection wells are programmed to flag pressures
that significantly deviate from the plan. Leakage on the inside or outside of the injection wellbore would
affect pressure and be detected through this approach. If such excursions occur, they are investigated
and addressed. In the time SEM has operated the Rangely Field, there have been no C02 leakage
events from a wellbore.
In addition to monitoring well pressure and injection performance, SEM uses the experience gained
overtime to strategically approach well maintenance. SEM maintains well maintenance and workover
crews onsite for this purpose. For example, the well classifications by age and construction method
indicated in Table 1 inform SEM's plan for monitoring and updating wells. SEM uses all of the
information at hand including pattern performance, and well characteristics to determine well
maintenance schedules.
Production well performance is monitored using the production well test process conducted when
produced fluids are gathered and sent to a collection station. There is a routine cycle for each collection
station, with each well being tested approximately twice every month. During this cycle, each production
well is diverted to the well test equipment for a period of time sufficient to measure and sample produced
fluids (generally 24 hours). This test allows SEM to allocate a portion of the produced fluids measured
at the collection station to each production well, assess the composition of produced fluids by location,
and assess the performance of each well. Performance data are reviewed on a routine basis to ensure
that C02 flooding is optimized. If production is off plan, it is investigated and any identified issues
addressed. Leakage to the outside of production wells is not considered a major risk because of the
reduced pressure in the casing. Further, the personal H2S monitors are designed to detect leaked fluids
around production wells.
Finally, as indicated in Section 5, field inspections are conducted on a routine basis by field personnel.
On any day, SEM has approximately 25 personnel in the field. Leaking C02 is very cold and leads to
formation of bright white clouds and ice that are easily spotted. All field personnel are trained to identify
leaking C02 and other potential problems at wellbores and in the field. Any C02 leakage detected will
be documented and reported, quantified and addressed as described in Section 5.
Based on its ongoing monitoring activities and review of the potential leakage risks posed by wellbores,
SEM concludes that it is mitigating the risk of C02 leakage through wellbores by detecting problems as
they arise and quantifying any leakage that does occur. Section 4.10 summarizes how SEM will monitor
C02 leakage from various pathways and describes how SEM will respond to various leakage scenarios.
In addition, Section 5 describes how SEM will develop the inputs used in the Subpart RR mass-balance
equation (Equation RR-11). Any incidents that result in C02 leakage up the wellbore and into the
atmosphere will be quantified as described in Section 7.4.
22
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4.3 Faults and Fractures
After reviewing geologic, seismic, operating, and other evidence, SEM has concluded that there are no
known faults or fractures that transect the entirety of the Weber Sands in the project area. As described in
Section 2.2.1, the MFF is present below the reservoir and terminates within the Weber Sands without
breaching the upper seal. Additional faults have been identified in formations that are stratigraphically below
the Weber Sands, but this faulting has been shown not to affect the Weber Sands or to have created
potential leakage pathways given that they do not contact the Upper Pennsylvanian or Permian strata
(Weber Fm.).
SEM has extensive experience in designing and implementing EOR projects to ensure injection pressures
will not damage the oil reservoir by inducing new fractures or creating shear. As a safeguard, injection
satellites are set with automatic shutoff controls if injection pressures exceed fracture pressures.
4.4 Natural or Induced Seismicity
After reviewing literature and historic data, SEM concludes that there is no direct evidence that natural
seismic activity poses a significant risk for loss of C02 to the surface in the Rangely Field. Natural seismic
events are derived from the thrust fault to the west. Historically, Figure 6 in section 2.2.1 shows nine (9)
seismic events outside of the Rangely Field (including the 1993 M 3.5 event). The epicenter of these
earthquakes was far below the operating depths of the Rangely Field, and are associated with the thrust
fault to the west of the field. The operations of Rangely have zero impact on this thrust fault. Natural
earthquakes are not predictable, but these do not pose a threat to current operations. This is evidenced by
the fact that hydrocarbons are still within the anticline, meaning that there have been no major seismic
events in the last few million years capable of releasing these hydrocarbons to the surface.
Induced seismic events (non-natural) are tied to the MFF and its joint faults. These can be impacted by
Rangely Field operations. Section 2.2.1 explains how an increase in reservoir pressure can trigger seismic
events along and near the MFF. To prevent this from occurring bottom hole pressure surveys are collected
one (1) to two (2) times per year across the Rangely Field helping to monitor pressure changes along across
the Rangely Field. By keeping reservoir pressure from exceeding the threshold of ~3730 psi for extended
periods of time (multiple years), induced seismic events can be greatly mitigated. In the case that reservoir
pressures do exceed the threshold pressure, a reduction in injected volumes in the vicinity will bring down
the pressures back down gradually over a period of time.
4.5 Previous Operations
Chevron initiated C02 flooding in the Rangely Field in 1986. SEM and the prior operators have kept records
of the site and have completed numerous infill wells. SEM has not drilled any new wells in Rangely to date
but their standard practice for drilling new wells includes a rigorous review of nearby wells to ensure that
drilling will not cause damage to or interfere with existing wells. SEM will also follow AOR requirements
under the UIC Class II program, which require identification of all active and abandoned wells in the AOR
and implementation of procedures that ensure the integrity of those wells when applying for a permit for any
new injection well. These practices ensure that identified wells are sufficiently isolated and do not interfere
with the C02 EOR operations and reservoir pressure management. Consequently, SEM's operational
experience supports the conclusion that there are no unknown wells within the Rangely Field that penetrate
the Weber Sands and that it has sufficiently mitigated the risk of migration from older wells.
4.6 Pipeline / Surface Equipment
Damage to or failure of pipelines and surface equipment can result in unplanned losses of C02. SEM
reduces the risk of unplanned leakage from surface facilities, to the maximum extent practicable, by relying
on the use of prevailing design and construction practices and maintaining compliance with applicable
regulations. The facilities and pipelines currently utilize and will continue to utilize materials of construction
23
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and control processes that are standard for C02 EOR projects in the oil and gas industry. As described
above, all facilities in the Rangely Field are internally screened for proximity to the public. In the case of
pipeline and surface equipment, best engineering practices call for more robust metallurgy in wellhead
equipment, and pressure transducers with low pressure alarms monitored through the SCADA system to
prevent and detect leakage. Operating and maintenance practices currently follow and will continue to follow
demonstrated industry standards. C02 delivery via the Raven Ridge pipeline system will continue to
comply with all applicable regulations. Finally, frequent routine visual inspection of surface facilities by field
staff will provide an additional way to detect leaks and further support SEM's efforts to detect and remedy
any leaks in a timely manner. Should leakage be detected from pipeline or surface equipment, the volume
of released C02 will be quantified following the requirements of Subpart W of EPA's GHGRP.
4.7 Lateral Migration Outside the Rangely Field
It is highly unlikely that injected C02 will migrate downdip and laterally outside the Rangely Field because of
the nature of the geology and the approach used for injection. First, as indicated in Section 2.2.1 "Geology
of the Rangely Field," the Rangely Field is situated at the top of a dome structural trap, with all directions
pointing down-dip from the highest point. This means that over long periods of time, injected C02 will tend
to rise vertically towards the point in the Rangely Field with the highest elevation. Second, the planned
injection volumes and active fluid management during injection operations will prevent C02 from migrating
laterally stratigraphically (down-dip structurally) out of the structure. Finally, SEM will not be increasing the
total volume of fluids in the Rangely Field.
COGCC requires that injection pressures be limited to ensure injection fluids do not migrate outside the
permitted injection interval. In the Rangely Field, SEM uses two methods to contain fluids: reservoir
pressure management and the careful placement and operation of wells along the outer producing limits of
the units.
Reservoir pressure in the Rangely Field is managed by maintaining an injection to withdrawal ratio (IWR)
of approximately 1.0. To maintain the IWR, SEM monitors fluid injection to ensure that reservoir pressure
does not increase to a level that would fracture the reservoir seal or otherwise damage the oil field.
SEM also prevents injected fluids from migrating out of the injection interval by keeping injection pressure
below the formation fracture pressure, which is measured using historic step-rate tests. In these tests,
injection pressures are incrementally increased (e.g., in "steps") until injectivity increases abruptly, which
indicates that an opening or fracture has been created in the rock. SEM manages its operations to ensure
that injection pressures are kept below the formation fracture pressure so as to ensure that the valuable
fluid hydrocarbons and C02 remain in the reservoir.
There are a few small producer wells operated by third parties outside the boundary of Rangely Field. There
are currently no significant commercial operations surrounding the Rangely Field to interfere with SEM's
operations.
Based on site characterization and planned and projected operations SEM estimates the total volume of
stored C02 will be approximately 35.7% of calculated capacity.
4.8 Drilling Through the C02 Area
It is possible that at some point in the future, drilling through the containment zone into the Weber Sands
could occur and inadvertently create a leakage pathway. SEM's review of this issue concludes that this risk
is very low for two reasons. First, SEM's visual inspection process, including routine site visits, is designed
to identify unapproved drilling activity in the Rangely Field. Second, SEM plans to operate the C02 EOR
flood in the Rangely Field for several more years, and will continue to be vigilant about protecting the
integrity of its assets and maximizing the potential of resources (oil, gas, C02). In the unlikely event SEM
would sell the field to a new operator, provisions would result in a change to the reporting program and
24
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would be addressed at that time.
4.9 Diffuse Leakage through the Seal
Diffuse leakage through the seal formed by the Moenkopi Formation is highly unlikely. The presence of a
gas cap trapped over millions of years as discussed in Section 2.2.3 confirms that the seal has been
secure for a very long time. Injection pattern monitoring program referenced in Section 2.3.1 and detailed
in Section 5 assures that no breach of the seal will be created. The seal is highly impermeable where
unperforated, cemented across the horizon where perforated by wells, and unexplained changes in
injection pressure would trigger investigation as to the cause. Further, if C02 were to migrate through the
Moenkopi seal, it would migrate vertically until it encountered and was trapped by any of the numerous
shallower shale seals
4.10 Monitoring, Response, and Reporting Plan for C02 Loss
As discussed above, the potential sources of leakage include fairly routine issues, such as problems with
surface equipment (pumps, valves, etc.) or subsurface equipment (wellbores), and unique events such as
induced fractures. Table 3 summarizes some of these potential leakage scenarios, the monitoring activities
designed to detect those leaks, SEM's standard response, and other applicable regulatory programs
requiring similar reporting.
Sections 5.1.5 - 5.1.7 discuss the approaches envisioned for quantifying the volumes of leaked C02. Given
the uncertainty concerning the nature and characteristics of leaks that will be encountered, the most
appropriate methods for quantifying the volume of leaked C02 will be determined at the time. In the event
leakage occurs, SEM plans to determine the most appropriate methods for quantifying the volume leaked
and will report it as required as part of the annual Subpart RR submission.
Any volume of C02 detected leaking to surface will be quantified using acceptable emission factors such
as those found in 40 CFR Part 98 Subpart W or engineering estimates of leak amounts based on
measurements in the subsurface, SEM's field experience, and other factors such as the frequency of
inspection. As indicated in Sections 5.1 and 7.4, leaks will be documented, evaluated and addressed in a
timely manner. Records of leakage events will be retained in the electronic environmental documentation
and reporting system. Repairs requiring a work order will be documented in the electronic equipment
maintenance system.
Table 3 Response Plan for C02 Loss
Risk
Monitoring Plan
Response Plan
Parallel
Reporting (if
any)
Loss of Well Control
Tubing Leak
Monitor changes in tubing and
annulus pressure; MIT for injectors
Well is shut in and
Workover crews respond
within days
COGCC
Casing Leak
Routine Field inspection; monitor
changes in annulus pressure; MIT for
injectors; extra attention to high risk
wells
Well is shut in and
Workover crews respond
within days
COGCC
Wellhead Leak
Routine Field inspection
Well is shut in and
Workover crews respond
within days
COGCC
Loss of Bottom-
hole
pressure control
Blowout during well operations
Maintain well kill
procedures
COGCC
25
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Unplanned wells
drilled through
Weber Sands
Routine Field inspection to
prevent unapproved drilling;
compliance with COGCC permitting
for planned wells.
Assure compliance with
COGCC regulations
COGCC
Permitting
Loss of seal in
abandoned wells
Reservoir pressure in monitor wells;
high pressure found in new wells
Re-enter and reseal
abandoned wells
COGCC
Leaks in Surface Facilities
Pumps, valves, etc.
Routine Field inspection; SCADA
Maintenance crews
respond within days
Subpart W
Subsurface Leaks
Leakage along
faults
Reservoir pressure in monitor wells;
high pressure found in new wells
Shut in injectors near
faults
-
Overfill beyond
spill
points
Reservoir pressure in monitor wells;
high; pressure found in new wells
Fluid management
along
lease lines
-
Leakage through
induced fractures
Reservoir pressure in monitor wells;
high pressure found in new wells
Comply with rules for
keeping pressures
below
parting pressure
-
Leakage due to
seismic event
Reservoir pressure in monitor wells;
high
pressure found in new wells
Shut in injectors near
seismic event
-
Available studies of actual well leaks and natural analogs (e.g., naturally occurring C02 geysers) suggest
that the amount released from routine leaks would be small as compared to the amount of C02 that would
remain stored in the formation.
4.11 Summary
The structure and stratigraphy of the Weber Sands in the Rangely Field is ideally suited forthe injection and
storage of C02. The stratigraphy within the C02 injection zones is porous, permeable and very thick,
providing ample capacity for long-term C02 storage. The Weber Sands is overlain by several intervals of
impermeable geologic zones that form effective seals or "caps" to fluids in the Weber Sands (See Figure
4). After assessing potential risk of release from the subsurface and steps that have been taken to prevent
leaks, SEM has determined that the potential threat of leakage is extremely low.
In summary, based on a careful assessment of the potential risk of release 0fCO2 from the subsurface, SEM
has determined that there are no leakage pathways at the Rangely Field that are likely to result in significant
loss of C02 to the atmosphere. Further, given the detailed knowledge of the Field and its operating
protocols, SEM concludes that it would be able to both detect and quantify any C02 leakage to the surface
that could arise through either identified or unexpected leakage pathways.
5. Monitoring and Considerations for Calculating Site Specific Variables
Monitoring will also be used to determine the quantities in the mass balance equation and to make the
demonstration that the C02 plume will not migrate to the surface after the time of discontinuation.
5.1 Forthe Mass Balance Equation
5.1.1 General Monitoring Procedures
As part of its ongoing operations, SEM monitors and collects flow, pressure, and gas composition data from
26
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the Rangely Field in centralized data management systems. These data are monitored continually by
qualified technicians who follow SEM response and reporting protocols when the systems deliver
notifications that data exceed statistically acceptable boundaries.
As indicated in Figures 10 and 11, custody-transfer meters are used at the point at which custody of the
C02 from the Raven Ridge pipeline delivery system is transferred to SEM, and at the points at which custody
of oil and NGLs are transferred to outside parties. Meters measure flow rate continually. Fluid composition
will be determined, at a minimum, quarterly, consistent with EPA GHGRP's Subpart RR, section 98.447(a).
All meter and composition data are documented, and records will be retained for at least three years.
Metering protocols used by SEM follow the prevailing industry standard(s) for custody transfer as currently
promulgated by the API, the American Gas Association (AGA), and the Gas Processors Association (GPA),
as appropriate. This approach is consistent with EPA GHGRP's Subpart RR, section 98.444(e)(3). These
meters will be maintained routinely, operated continually, and will feed data directly to the centralized data
collection systems. The meters meet the industry standard for custody transfer meter accuracy and
calibration frequency. These custody meters provide the most accurate way to measure mass flows.
SEM maintains in-field process control meters to monitor and manage in-field activities on a real time basis.
These are identified as operations meters in Figures 10 and 11. These meters provide information used to
make operational decisions but are not intended to provide the same level of accuracy as the custody-
transfer meters. The level of precision and accuracy for in-field meters currently satisfies the requirements
for reporting in existing UIC permits. Although these meters are accurate for operational purposes, it is
important to note that there is some variance between most commercial meters (on the order of 1-5%)
which is additive across meters. This variance is due to differences in factory settings and meter calibration,
as well as the operating conditions within a field. Meter elevation, changes in temperature (over the course
of the day), fluid composition (especially in multi-component or multi-phase streams), or pressure can affect
in-field meter readings. Unlike in a saline formation, where there are likely to be only a few injection wells
and associated meters, at C02 EOR operations in the Rangely Field there are currently 662 active injection
and production wells and a comparable number of meters, each with an acceptable range of error. This is
a site-specific factor that is considered in the mass balance calculations described in Section 7.
5.1.2 C02 Received
SEM measures the volume of received C02 using commercial custody transfer meters at the off-take point
from the Raven Ridge pipeline delivery system. This transfer is a commercial transaction that is
documented. C02 composition is governed by the contract and the gas is routinely sampled to determine
composition. No C02 is received in containers.
5.1.3 C02 Injected into the Subsurface
Injected C02 will be calculated using the flow metervolumes at the operations meteratthe outlet of the C02
Reinjection Facility and the custody transfer meter at the C02 off-take points from the Raven Ridge pipeline
delivery system
5.1.4 C02 Produced, Entrained in Products, and Recycled
The following measurements are used for the mass balance equations in Section 7:
C02 produced is calculated using the volumetric flow meters at the inlet to the C02 Reinjection Facility.
These flow meters, as illustrated on Figure 10, are downstream of the field collection station separators
and bulk produced fluid separators at the water injection plants
C02 is produced as entrained or dissolved C02 in produced oil, as indicated in Figures 10 and 11. This is
calculated using volumetric flow through the custody transfer meter.
Recycled C02 is calculated using the volumetric flow meter at the outlet of the C02 Reinjection Facility,
which is an operations meter.
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5.1.5 C02 Emitted by Surface Leakage
As discussed in Section 5.1.6 and 5.1.7 below, SEM uses 40 CFR Part 98 Subpart Wto estimate surface
leaks from equipment at the Rangely Field. Subpart W uses a factor-driven approach to estimate equipment
leakage. In addition, SEM uses an event-driven process to assess, address, track, and if applicable quantify
potential C02 leakage to the surface.
The multi-layered, risk-based monitoring program for event-driven incidents has been designed to meet two
objectives, in accordance with the leakage risk assessment in Section 4: 1) to detect problems before C02
leaks to the surface; and 2) to detect and quantify any leaks that do occur. This section discusses how this
monitoring will be conducted and used to quantify the volumes of C02 leaked to the surface.
Monitoring for potential Leakage from the Injection/Production Zone:
SEM will monitor both injection into and production from the reservoir as a means of early identification of
potential anomalies that could indicate leakage from the subsurface.
SEM develops injection plans for each well and that is distributed to operations weekly. If injection pressure
or rate measurements are beyond the specified set points determined as part of each pattern injection plan,
the operations engineer will notify field personnel and they will investigate and resolve the problem. These
excursions will be reviewed by well-management personnel to determine if C02 leakage may be occurring.
Excursions are not necessarily indicators of leaks; they simply indicate that injection rates and pressures
are not conforming to the pattern injection plan. In many cases, problems are straightforward to fix (e.g., a
meter needs to be recalibrated or some other minor action is required), and there is no threat of C02
leakage. In the case of issues that are not readily resolved, more detailed investigation and response would
be initiated, and internal SEM support staff would provide additional assistance and evaluation. Such issues
would lead to the development of a work order in SEM's work order management system. This record
enables the company to track progress on investigating potential leaks and, if a leak has occurred, to
quantify its magnitude.
Likewise, SEM develops a forecast of the rate and composition of produced fluids. Each producer well is
assigned to one collection station and is isolated twice during each monthly cycle for a well production test.
This data is reviewed on a periodic basis to confirm that production is at the level forecasted. If there is a
significant deviation from the forecast, well management personnel investigate. If the issue cannot be
resolved quickly, more detailed investigation and response would be initiated. As in the case of the injection
pattern monitoring, if the investigation leads to a work order in the SEM work order management system,
this record will provide the basis for tracking the outcome of the investigation and if a leak has occurred. If
leakage in the flood zone were detected, SEM would use an appropriate method to quantify the involved
volume of C02. This might include use of material balance equations based on known injected quantities
and monitored pressures in the injection zone to estimate the volume of C02 involved.
A subsurface leak might not lead to a surface leak. In the event of a subsurface leak, SEM would determine
the appropriate approach for tracking subsurface leakage to determine and quantify leakage to the surface.
To quantify leakage to the surface, SEM would estimate the relevant parameters (e.g., the rate,
concentration, and duration of leakage) to quantify the leak volume. Depending on specific circumstances,
these determinations may rely on engineering estimates.
In the event leakage from the subsurface occurred diffusely through the seals, the leaked gas would include
H2S, which would trigger the alarm on the personal monitors worn by field personnel. Such a diffuse leak
from the subsurface has not occurred in the Rangely Field. In the event such a leak was detected, field
personnel from across SEM would determine how to address the problem. The team might use modeling,
engineering estimates, and direct measurements to assess, address, and quantify the leakage.
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Monitoring of Wellbores:
SEM monitors wells through continual, automated pressure monitoring in the injection zone (as described in
Section 4.2), monitoring of the annular pressure in wellheads, and routine maintenance and inspection.
Leaks from wellbores would be detected through the follow-up investigation of pressure anomalies, visual
inspection, or the use of personal H2S monitors.
Anomalies in injection zone pressure may not indicate a leak, as discussed above. However, if an
investigation leads to a work order, field personnel would inspect the equipment in question and determine
the nature of the problem. If it is a simple matter, the repair would be made and the volume of leaked C02
would be included in the 40 CFR Part 98 Subpart W report for the Rangely Field, as well as reported in
Subpart RR . If more extensive repair were needed, SEM would determine the appropriate approach for
quantifying leaked C02 using the relevant parameters (e.g., the rate, concentration, and duration of
leakage). The work order would serve as the basis for tracking the event for GHG reporting.
Anomalies in annular pressure or other issues detected during routine maintenance inspections would be
treated in the same way. Field personnel would inspect the equipment in question and determine the nature
of the problem. For simple matters the repair would be made at the time of inspection and the volume of
leaked C02 would be included in the 40 CFR Part 98 Subpart W report for the Rangely Field, as well as
reported in Subpart RR. If more extensive repairs were needed, a work order would be generated and SEM
would determine the appropriate approach for quantifying leaked C02 using the relevant parameters (e.g.,
the rate, concentration, and duration of leakage). The work order would serve as the basis for tracking the
event for GHG reporting.
Because leaking C02 at the surface is very cold and leads to formation of bright white clouds and ice that
are easily spotted, SEM also employs a two-part visual inspection process in the general area of the Rangely
Field to detect unexpected releases from wellbores. First, field personnel visit the surface facilities on a
routine basis. Inspections may include tank volumes, equipment status and reliability, lube oil levels,
pressures and flow rates in the facility, and valve leaks. Field personnel inspections also check that injectors
are on the proper WAG schedule and observe the facility for visible C02 or fluid line leaks.
Historically, SEM has not experienced any unexpected release events in the Rangely Field. An identified
need for repair or maintenance through visual inspections results in a work order being entered into SEM's
equipment and maintenance work order management system. The time to repair any leak is dependent on
several factors, such as the severity of the leak, available manpower, location of the leak, and availability
of materials required for the repair. Critical leaks are acted upon immediately.
Finally, SEM uses the data collected by the H2S monitors, which are worn by all field personnel at all times,
as a last method to detect leakage from wellbores. The H2S monitors detection limit is 10ppm; if an H2S
alarm is triggered, the first response is to protect the safety of the personnel, and the next step is to safely
investigate the source of the alarm. As noted previously, SEM considers H2S a proxy for potential C02
leaks in the field. Thus, detected H2S leaks will be investigated to determine if potential C02 leakage is
present, but not used to determine the leak volume. If the incident results in a work order, this will serve as
the basis for tracking the event for GHG reporting.
Other Potential Leakage at the Surface:
SEM will utilize the same visual inspection process and H2S monitoring system to detect other potential
leakage at the surface as it does for leakage from wellbores. SEM utilizes routine visual inspections to
detect significant loss of C02 to the surface. Field personnel routinely visit surface facilities to conduct a
visual inspection. Inspections may include review of tank level, equipment status, lube oil levels, pressures
and flow rates in the facility, valve leaks, ensuring that injectors are on the proper WAG schedule, and also
conducting a general observation of the facility for visible C02 or fluid line leaks. If problems are detected,
field personnel would investigate, and, if maintenance is required, generate a work order in the maintenance
system, which is tracked through completion. In addition to these visual inspections, SEM will use the results
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of the personal H2S monitors worn by field personnel as a supplement for smaller leaks that may escape
visual detection.
If C02 leakage to the surface is detected, it will be reported to surface operations personnel who will review
the reports and conduct a site investigation. If maintenance is required, a work order will be generated in
the work order management system. The work order will describe the appropriate corrective action and be
used to track completion of the maintenance action. The work order will also serve as the basis for tracking
the event for GHG reporting and quantifying any C02 emissions.
5.1.6 C02 emitted from equipment leaks and vented emissions of C02 from surface equipment
located between the injection flow meter and the injection wellhead.
SEM evaluates and estimates the mass of C02 emitted (in metric tons) annually from equipment leaks and
vented emissions of C02 from equipment located on the surface between the flow meter used to measure
injection quantity and the injection wellhead, as required under 40 CFR Part 98 Subpart W and 40 CFR
Part 98 Subpart RR.
5.1.7 Mass of C02 emissions from equipment leaks and vented emissions of C02 from surface
equipment located between the production flow meter and the production wellhead
SEM evaluates and estimates the mass of C02 emitted (in metric tons) annually from equipment leaks and
vented emissions of C02 from equipment located on the surface between the production wellhead and the
flow meter used to measure production quantity, as required under 40 CFR Part 98 Subpart W and 40 CFR
Part 98 Subpart RR.
5.2 To Demonstrate that Injected C02 is not Expected to Migrate to the Surface
At the end of the Specified Period, SEM intends to cease injecting C02 for the subsidiary purpose of
establishing the long-term storage of C02 in the Rangely Field. After the end of the Specified Period, SEM
anticipates that it will submit a request to discontinue monitoring and reporting. The request will demonstrate
that the amount of C02 reported under 40 CFR §98.440-449 (Subpart RR) is not expected to migrate in the
future in a manner likely to result in surface leakage. At that time, SEM will be able to support its request
with years of data collected during the Specified Period as well as two to three (or more, if needed) years
of data collected after the end of the Specified Period. This demonstration will provide the information
necessary for the EPA Administrator to approve the request to discontinue monitoring and reporting and
may include, but is not limited to:
i. Data comparing actual performance to predicted performance (purchase, injection, production)
over the monitoring period;
ii. An assessment of the C02 leakage detected, including discussion of the estimated amount of
C02 leaked and the distribution of emissions by leakage pathway;
iii. A demonstration that future operations will not release the volume of stored C02 to the surface;
iv. A demonstration that there has been no significant leakage of C02; and,
v. An evaluation of reservoir pressure in the Rangely Field that demonstrates that injected fluids are
not expected to migrate in a manner to create a potential leakage pathway.
6. Determination of Baselines
SEM intends to utilize existing automatic data systems to identify and investigate excursions from expected
performance that could indicate C02 leakage. SEM's data systems are used primarily for operational
control and monitoring and as such are set to capture more information than is necessary for reporting in the
Annual Subpart RR Report. SEM will develop the necessary system guidelines to capture the information that
is relevant to identify possible C02 leakage. The following describes SEM's approach to collecting this
information.
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Visual Inspections
As field personnel conduct routine inspections, work orders are generated in the electronic system for
maintenance activities that cannot be addressed on the spot. Methods to capture work orders that involve
activities that could potentially involve C02 leakage will be developed, if not currently in place. Examples
include occurrences of well workover or repair, as well as visual identification of vapor clouds or ice
formations. Each incident will be flagged for review by the person responsible for MRV documentation. The
responsible party will be provided in the monitoring plan, as required under Subpart A, 98.3(g). The Annual
Subpart RR Report will include an estimate of the amount of C02 leaked. Records of information used to
calculate emissions will be maintained on file for a minimum of three years.
Personal H2S Monitors
H2S monitors are worn by all field personnel. Any monitor alarm triggers an immediate response to ensure
personnel are not at risk and to verify the monitor is working properly. The person responsible for MRV
documentation will receive notice of all incidents where H2S is confirmed to be present. The Annual Subpart
RR Report will provide an estimate the amount of C02 emitted from any such incidents. Records of
information to calculate emissions will be maintained on file for a minimum of three years.
Injection Rates. Pressures and Volumes
SEM develops target injection rate and pressure for each injector, based on the results of ongoing pattern
modeling and within permitted limits. The injection targets are programmed into the WAG controllers. High
and low set points are also programmed into the SCADA, and flags whenever statistically significant
deviations from the targeted ranges are identified. The set points are designed to be conservative, because
it is preferable to have too many flags rather than too few. As a result, flags can occur frequently and are
often found to be insignificant. For purposes of Subpart RR reporting, flags (or excursions) will be screened
to determine if they could also lead to C02 leakage to the surface. The person responsible for the MRV
documentation will receive notice of excursions and related work orders that could potentially involve C02
leakage. The Annual Subpart RR Report will provide an estimate of C02 emissions. Records of information
to calculate emissions will be maintained on file for a minimum of three years.
Production Volumes and Compositions
SEM develops a general forecast of production volumes and composition which is used to periodically
evaluate performance and refine current and projected injection plans and the forecast. This information is
used to make operational decisions but is not recorded in an automated data system. Sometimes, this
review may result in the generation of a work order in the maintenance system. The MRV plan
implementation lead will review such work orders and identify those that could result in C02 leakage. Should
such events occur, leakage volumes would be calculated following the approaches described in Sections 4
and 5. Impact to Subpart RR reporting will be addressed, if deemed necessary.
7. Determination of Sequestration Volumes Using Mass Balance Equations
To account for the site conditions and complexity of a large, active EOR operation, SEM will utilize the
locations described below for obtaining volume data for the equations in Subpart RR §98.443 as indicated
below.
The selection of the utilized locations, more specifically described in this Section 7, address the propagation
of error that would result if volume data from meters at each injection well were utilized. This issue arises
because while each meter has a small but acceptable margin of error, this error would become significant
if data were taken from the approximately 284 meters within the Rangely Field. As such, SEM will use the
data from custody and operations meters on the main system pipelines to determine injection volumes used
in the mass balance. This satisfies the requirement in 40 CFR 98.444 (b) 1 that you must select a point or
points of measurement at which the C02 stream is representative of the C02 streams being injected.
The volumetric flow meters utilized for CQ2 produced are located at the inlet to the RCF. These flow
31
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meters, as illustrated on Figure 10, are directly downstream of the field collection station separators and
bulk produced fluid separators at the water injection plants. This satisfies the requirement in 40 CFR
98.444 (c)(1) for production, which states, "The point of measurement for the quantity of C02 produced
from oil or other fluid production wells is a flow meter directly downstream of each separator that sends a
stream of gas into a recycle or end use system."
The following sections describe how each element of the mass-balance equation (Equation RR-11) will be
calculated.
. Mass of C02 Received
SEM will use equation RR-2 as indicated in Subpart RR §98.443 to calculate the mass of 0O2 received
from each delivery meter immediately upstream of the Raven Ridge pipeline delivery system on the Rangely
Field. The volumetric flow at standard conditions will be multiplied by the C02 concentration and the density
of C02 at standard conditions to determine mass.
p=\
where:
C02T,r = Net annual mass of C02 received through flow meter r (metric tons).
Qr,p = Quarterly volumetric flow through a receiving flow meter r in quarter p at standard conditions
(standard cubic meters).
Sr,p = Quarterly volumetric flow through a receiving flow meter r that is redelivered to another facility without
being injected into a site well in quarter p (standard cubic meters).
D = Density of C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.
CC02,p,r = Quarterly C02 concentration measurement in flow for flow meter r in quarter p (vol. percent
C02, expressed as a decimal fraction).
p = Quarter of the year,
r = Receiving flow meters.
Given SEM's method of receiving C02 and requirements at Subpart RR §98.444(a):
All delivery to the Rangely Field is used within the unit so quarterly flow redelivered, Sr,p , is
zero (0) and will not be included in the equation.
Quarterly C02 concentration will be taken from the gas measurement database SEM will sum to total
Mass of CQ2 Received using equation RR-3 in 98.443
4
R
C02 = ]TCO,Tir (Eq. RR-3)
where:
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C02 = Total net annual mass of C02 received (metric tons).
C02T,r = Net annual mass of C02 received (metric tons) as calculated in Equation RR-2 for flow meter r.
r = Receiving flow meter.
7.2 Mass of C02 Injected into the Subsurface
The equation for calculating the Mass of C02 Injected into the Subsurface at the Rangely Field is equal to
the sum of the Mass of C02 Received as calculated in RR-3 of 98.443 (as described in Section 7.1) and the
Mass of C02 Recycled as calculated using measurements taken from the flow meter located at the output
of the RCF. As previously explained, using data at each injection well would give an inaccurate estimate of
total injection volume due to the large number of wells and the potential for propagation of error due to
allowable calibration ranges for each meter.
The mass of C02 recycled will be determined using equation RR-5 as follows:
4
C02 ,u = ]T QPJI * D * C"COi I( (Eq. RR-5)
p=\
where:
C02,u = Annual C02 mass injected (metric tons) as measured by flow meter u.
Qp,u = Quarterly volumetric flow rate measurement for flow meter u in quarter p at standard conditions
(standard cubic meters per quarter).
D = Density of C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.
C02,p,u = 0O2 concentration measurement in flow for flow meter u in quarter p (vol. percent C02,
expressed as a decimal fraction).
p = Quarter of the year, u = Flow meter.
The aggregate injection data will be calculated pursuant to the procedures specified in equation RR-6 as
follows:
£'
c°2i = XC0^ (Ec3- RR-6)
u~ 1
where:
C02I = Total annual C02 mass injected (metric tons) through all injection wells.
C02,u = Annual C02 mass injected (metric tons) as measured by flow meter u.
u = Flow meter.
33
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7.3 Mass of C02 Produced
The Mass of C02 Produced at the Rangely Field will be calculated using the measurements from the flow
meters at the inlet to RCF and for C02 entrained in the sales oil, the custody transfer meter for oil sales
rather than the metered data from each production well. Again, using the data at each production well would
give an inaccurate estimate of total injection due to the large number of wells and the potential for
propagation of error due to allowable calibration ranges for each meter.
Equation RR-8 in 98.443 will be used to calculate the mass of C02 produced from all injection wells as
follows:
Where:
C02,w = Annual C02 mass produced (metric tons) .
Qp,w = Volumetric gas flow rate measurement for separator w in quarter p at standard conditions
(standard cubic meters).
D = Density of C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.
CC02,p,w = 0O2 concentration measurement in flow for separator w in quarter p (vol. percent C02,
expressed as a decimal fraction).
p = Quarter of the year.
w = inlet meter to RCF.
Equation RR-9 in 98.443 will be used to aggregate the mass of C02 produced and the mass of C02
entrained in oil or other fluid leaving the Rangely Field as follows:
C02p = Total annual C02 mass produced (metric tons) through all meters in the reporting year.
C02,w = Annual C02 mass produced (metric tons) through meterw in the reporting year.
X = Entrained C02 in produced oil or other fluid divided by the C02 separated through all separators in the
reporting year (weight percent C02, expressed as a decimal fraction).
w = Separator.
7.4 Mass of C02 emitted by Surface Leakage
SEM will calculate and report the total annual Mass of C02 emitted by Surface Leakage using an approach
that relies on 40 CFR Part 98 Subpart W reports for equipment leakage, and tailored calculations for all
4
C02, w = *D * Cc0y _ (Eq. RR-8)
(Eq. RR-9)
Where:
34
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other surface leaks. As described in Sections 4 and 5.1.5-5.1.7, SEM is prepared to address the potential
for leakage in a variety of settings. Given the uncertainty concerning the nature and characteristics of leaks
that will be encountered, it is not clear the method for quantifying the volume of leaked C02 that would be
most appropriate. Estimates of the amount of C02 leaked to the surface will depend on a number of site-
specific factors including measurements of flowrate, pressure, size of leak opening, and duration of the
leak. Engineering estimates, and emission factors, depending on the source and nature of the leakage will
also be used.
SEM's process for quantifying leakage will entail using best engineering principles or emission factors.
While it is not possible to predict in advance the types of leaks that will occur, SEM describes some
approaches for quantification in Section 5.1.5-5.1.7. In the event leakage to the surface occurs, SEM would
quantify and report leakage amounts, and retain records that describe the methods used to estimate or
measure the volume leaked as reported in the Annual Subpart RR Report.
Equation RR-10 in 48.433 will be used to calculate and report the Mass of C02 emitted by Surface Leakage:
Jf
G02E = EC02,x (Eq, RR-10)
A-t
where:
C02E = Total annual C02 mass emitted by surface leakage (metric tons) in the reporting year.
C02,x = Annual C02 mass emitted (metric tons) at leakage pathway x in the reporting year,
x = Leakage pathway.
7.5 Mass of C02 sequestered in subsurface geologic formations.
SEM will use equation RR-11 in 98.443 to calculate the Mass of C02 Sequestered in Subsurface
Geologic Formations in the Reporting Year as follows:
C02 = CO21 - C02P - C02E - C02FI - CO2FP {Eq. RR-11)
where:
C02 = Total annual C02 mass sequestered in subsurface geologic formations (metric tons) at the facility
in the reporting year.
C02| = Total annual C02 mass injected (metric tons) in the well or group of wells covered by this source
category in the reporting year.
C02P = Total annual C02 mass produced (metric tons) in the reporting year.
C02E = Total annual C02 mass emitted (metric tons) by surface leakage in the reporting year.
C02FI = Total annual C02 mass emitted (metric tons) from equipment leaks and vented emissions of C02
from equipment located on the surface between the flow meter used to measure injection quantity and the
injection wellhead, for which a calculation procedure is provided in subpart W of this part.
C02FP = Total annual CQ2 mass emitted (metric tons) from equipment leaks and vented emissions of CQ2
35
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from equipment located on the surface between the production wellhead and the flow meter used to
measure production quantity, for which a calculation procedure is provided in subpart W of this part.
7.6 Cumulative mass of C02 reported as sequestered in subsurface geologic formations
SEM will sum up the total annual volumes obtained using equation RR-11 in 98.443 to calculate the
Cumulative Mass of CQ2 Sequestered in Subsurface Geologic Formations.
8. MRV Plan Implementation Schedule
The activities described in this MRV Plan are in place, and reporting is planned to start upon EPA approval.
Other GHG reports are filed on March 31 of the year after the reporting year and it is anticipated that the
Annual Subpart RR Report will be filed at the same time. As described in Section 3.3 above, SEM anticipates
that the MRV program will be in effect during the Specified Period, during which time SEM will operate the
Rangely Field with the subsidiary purpose of establishing long-term containment of a measurable quantity
of C02 in subsurface geological formations at the Rangely Field. SEM anticipates establishing that a
measurable amount of C02 injected during the Specified Period will be stored in a manner not expected
to migrate resulting in future surface leakage. At such time, SEM will prepare a demonstration supporting
the long-term containment determination and submit a request to discontinue reporting under this MRV
plan. See 40 C.F.R. § 98.441 (b)(2)(ii).
9. Quality Assurance Program
9.1 Monitoring QA/QC
As indicated in Section 7, SEM has incorporated the requirements of §98.444 (a) - (d) in the discussion
of mass balance equations. These include the following provisions.
CQ2 Received and Injected
The quarterly flow rate of C02 received by pipeline is measured at the receiving custody
transfer meters.
The quarterly C02 flow rate for recycled C02 is measured at the flow meter located at the C02
Reinjection facility outlet.
CQ2 Produced
The point of measurement for the quantity of C02 produced is a flow meter at the C02 Reinjection
facility inlet. . C02 produced as entrained or dissolved C02 in produced oil is calculated using
volumetric flow through the custody transfer meter.
The produced gas stream is sampled at least once per quarter immediately downstream of the flow
meter used to measure flow rate of that gas stream and measure the C02 concentration of the
sample.
The quarterly flow rate of the produced gas is measured at the flow meters located at the C02
Reinjection facility inlet.
C02 emissions from equipment leaks and vented emissions of C02
These volumes are measured in conformance with the monitoring and QA/QC requirements
specified in subpart W of 40 CFR Part 98.
Flow meter provisions
The flow meters used to generate date for the mass balance equations in Section 7 are:
36
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Operated continuously except as necessary for maintenance and calibration.
Operated using the calibration and accuracy requirements in 40 CFR §98.3(i).
Operated in conformance with American Petroleum Institute (API) standards.
National Institute of Standards and Technology (NIST) traceable.
Concentration of CQ2
As indicated in Appendix 1, C02 concentration is measured using an appropriate standard method. Further,
all measured volumes of C02 have been converted to standard cubic meters at a temperature of 60
degrees Fahrenheit and at an absolute pressure of 1 atmosphere, including those used in Equations RR-
2, RR-5 and RR-8 in Section 7.
Missing Data Procedures
In the event SEM is unable to collect data needed for the mass balance calculations, procedures
for estimating missing data in §98.445 will be used as follows:
A quarterly flow rate of C02 received that is missing would be estimated using invoices or using a
representative flow rate value from the nearest previous time period.
A quarterly C02 concentration of a C02 stream received that is missing would be estimated using
invoices or using a representative concentration value from the nearest previous time period.
A quarterly quantity of C02 injected that is missing would be estimated using a representative quantity
of C02injected from the nearest previous period of time at a similar injection pressure.
For any values associated with C02 emissions from equipment leaks and vented emissions of C02
from surface equipment at the facility that are reported in this subpart, missing data estimation
procedures specified in subpart Wof 40 CFR Part 98 would be followed.
The quarterly quantity of C02 produced from subsurface geologic formations that is missing would be
estimated using a representative quantity of C02 produced from the nearest previous period of time.
MRV Plan Revisions
In the event there is a material change to the monitoring and/or operational parameters of the SEM C02
EOR operations in the Rangely Field that is not anticipated in this MRV plan, the MRV plan will be revised
and submitted to the EPA Administrator within 180 days as required in §98.448(d).
Records Retention
SEM will follow the record retention requirements specified by §98.3(g). In addition, it will follow the
requirements in Subpart RR §98.447 by maintaining the following records for at least three years:
Quarterly records of C02 received at standard conditions and operating conditions, operating
temperature and pressure, and concentration of these streams.
Quarterly records of produced C02, including volumetric flow at standard conditions and operating
conditions, operating temperature and pressure, and concentration of these streams.
Quarterly records of injected C02 including volumetric flow at standard conditions and operating
conditions, operating temperature and pressure, and concentration of these streams.
Annual records of information used to calculate the C02 emitted by surface leakage from leakage
pathways.
Annual records of information used to calculate the C02 emitted from equipment leaks and vented
37
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emissions of C02 from equipment located on the surface between the flow meter used to measure
injection quantity and the injection wellhead.
Annual records of information used to calculate the C02 emitted from equipment leaks and vented
emissions of C02 from equipment located on the surface between the production wellhead and the
flow meter used to measure production quantity.
These data will be collected as generated and aggregated as required for reporting purposes.
Appendices
38
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Appendix 1. Conversion Factors
SEM reports C02 volumes at standard conditions of temperature and pressure as defined in the State of
Colorado, which follows the international standard conditions for measuring C02 properties - 77 °F and
14.696 psi.
To convert these volumes into metric tonnes, a density is calculated using the Span and Wagner equation
of state as recommended by the EPA. Density was calculated using the database of thermodynamic
properties developed by the National Institute of Standards and Technology (NIST), available at
http://webbook.nist.gov/chemistrv/fluid/.
At EPA standard conditions of 77 °F and one atmosphere, the Span and Wagner equation of state gives a
density of 0.0026500 lb-moles per cubic foot. Using a molecular weight for C02 of 44.0095, 2204.62
lbs/metric ton and 35.314667 ft3/m3, gives a C02 density of 5.29003 x 10"5 MT/ft3 or 0.0018682 MT/m3.
The conversion factor 5.29003 x 10 5 MT/Mcf has been used throughout to convert SEM volumes to metric
tons.
39
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Appendix 2. Acronyms
AGA - American Gas Association
AMA - Active Monitoring Area
AoR - Area of Review
API-American Petroleum Institute
BCF - Billion Cubic Feet
bopd - barrels of oil per day
Cf- Cubic Feet
CCR - Code of Colorado Regulations
COGCC - Colorado Oil and Gas Conservation Commission
C02 - Carbon Dioxide
CRF - C02 Removal Facilities
EOR - Enhanced Oil Recovery
EPA - US Environmental Protection Agency
GHG - Greenhouse Gas
GHGRP - Greenhouse Gas Reporting Program
H2S - Hydrogen Sulfide
IWR - Injection to Withdrawal Ratio
LACT - Lease Automatic Custody Transfer meter
Md - Millidarcy
MIT - Mechanical Integrity Test
MFF - Main Field Fault
MMA - Maximum Monitoring Area
MMB - Million barrels
Mscf- Thousand standard cubic feet
MMscf- Million standard cubic feet
MMMT - Million metric tonnes
MMT -Thousand metric tonnes
MRV-Monitoring, Reporting, and Verification
MOC - Main oil column
MT - Metric Tonne
NGNatural Gas
NGLs - Natural Gas Liquids
NIST - National Institute of Standards and Technology
OOIP - Original Oil-ln-Place
OH - Open hole
POWC - Producible oil/water contact
PPM - Parts Per Million
RCF - Rangely Field C02 Recycling and Compression Facility
RRPC - Raven Ridge pipeline
RWSU - Rangely Weber Sand Unit
SCADA - Supervisory Control and Data Acquisition
SEM - Scout Energy Management, LLC
UIC - Underground Injection Control
VRU - Vapor Recovery Unit
WAG - Water Alternating Gas
XOM - ExxonMobil
40
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Appendix 3. References
Adams, L., 2006; Sequence and Mechanical Stratigraphy: An intergrated Reservoir Characterization of
the Weber Sandstone, Western Colorado. University of Texas at El Paso Ph.D. Dissertation.
Colorado Administrative Code Department 400 Division 404 Oil and Gas Conservation Commission
Section 2
Clark, Rory, Chevron North America E&P, Presentation to 6th Annual Wyoming C02 Conference, July 12,
2012, online: //www.uwyo.edu/eori/_files/C02conference12/rory_rangelycasehistory.pdf
Energy and Carbon Management Regulation in Colorado. May 22, 2023, online:
https://leg.colorado.gov/bills/sb23-285
US Department of Energy, National Energy Technology Laboratory. "Carbon Dioxide Enhanced Oil
Recovery - Untapped Domestic Energy Supply and Long Term Carbon Storage Solution," March 2010.
US Department of Energy, National Energy Technology Laboratory. "Carbon Sequestration Through
Enhanced Oil Recovery," April 2008.
Gale, Hoyt. Geology of the Rangely Oil District. Department of Interior United States Geological Survey,
Bulletin 350. 1908.
41
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Appendix 4. Glossary of Terms
This glossary describes some of the technical terms as they are used in this MRV plan. For additional
glossaries please see the U.S. EPA Glossary of UIC Terms
(http://water.epa.gov/tvpe/qroundwater/uic/qlossarv.cfm') and the Schlumberger Oilfield Glossary
(http://www.glossary.oilfield.slb.com/).
Contain / Containment - having the effect of keeping fluids located within in a specified portion of a geologic
formation.
Dip-Very few, if any, geologic features are perfectly horizontal. They are almost always tilted. The direction
of tilt is called "dip." Dip is the angle of steepest descent measured from the horizontal plane. Moving higher
up structure is moving "updip." Moving lower is "downdip." Perpendicular to dip is "strike." Moving
perpendicular along a constant depth is moving along strike.
Downdip - See "dip."
Formation - A body of rock that is sufficiently distinctive and continuous that it can be mapped.
Infill Drilling - The drilling of additional wells within existing patterns. These additional wells decrease
average well spacing. This practice both accelerates expected recovery and increases estimated ultimate
recovery in heterogeneous reservoirs by improving the continuity between injectors and producers. As well
spacing is decreased, the shifting flow paths lead to increased sweep to areas where greater hydrocarbon
saturations remain.
Permeability - Permeability is the measure of a rock's ability to transmit fluids. Rocks that transmit fluids
readily, such as sandstones, are described as permeable and tend to have many large, well-connected
pores. Impermeable formations, such as shales and siltstones, tend to be finer grained or of a mixed grain
size, with smaller, fewer, or less interconnected pores.
Phase - Phase is a region of space throughout which all physical properties of a material are essentially
uniform. Fluids that don't mix together segregate themselves into phases. Oil, for example, does not mix
with water and forms a separate phase.
Pore Space - See porosity.
Porosity - Porosity is the fraction of a rock that is not occupied by solid grains or minerals. Almost all rocks
have spaces between rock crystals or grains that is available to be filled with a fluid, such as water, oil or
gas. This space is called "pore space."
Saturation - The fraction of pore space occupied by a given fluid. Oil saturation, for example, is the fraction
of pore space occupied by oil.
Seal - A geologic layer (or multiple layers) of impermeable rock that serve as a barrier to prevent fluids
from moving upwards to the surface.
Secondary recovery - The second stage of hydrocarbon production during which an external fluid such as
water or gas is injected into the reservoir through injection wells located in rock that has fluid communication
with production wells. The purpose of secondary recovery is to maintain reservoir pressure and to displace
hydrocarbons toward the wellbore. The most common secondary recovery techniques are gas injection and
waterflooding.
Stratigraphic section - A stratigraphic section is a sequence of layers of rocks in the order they were
deposited.
42
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Strike - See "dip.
Updip - See "dip.
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Appendix 5. Well Identification Numbers
The following table presents the well name, API number, status and type for the wells in the RWSU as of
April 2023. The table is subject to change overtime as new wells are drilled, existing wells change status,
or existing wells are repurposed. The following terms are used:
Well Status
Producing refers to a well that is actively producing
Injecting refers to a well that is actively injecting
P&A refers to wells that have been closed (plugged and abandoned) per COGCC regulations
Shut In refers to wells that have been temporarily idled or shut-in
Monitor refers to a well that is used to monitor bottom home pressure in the reservoir
Well Type
Water / Gas Inject refers to wells that inject water and C02 Gas
Water Injection Well refers to wells that inject water
Oil well refers to wells that produce oil
Salt Water Disposal refers to a well used to dispose of excess water
Name
API Number
Well Type
Well Status
A C MCLAUGHLIN 46
51030632300
Water Injection Well
P&A
AC MCLAUGHLIN 64X
51030771700
Oil well
Producing
ASSOCIATED A 2
51030571400
Water / Gas Inject
P&A
ASSOCIATED A1
51030571300
Oil well
Producing
ASSOCIATED A2ST
51030571401
Water / Gas Inject
Injecting
ASSOCIATED A3X
51030778600
Oil well
Producing
ASSOCIATED A4X
51030791600
Oil well
Producing
ASSOCIATED A5X
51030803400
Water / Gas Inject
Injecting
ASSOCIATED A6X
51030801100
Water / Gas Inject
Injecting
ASSOCIATED LARSON UNIT A1
51030600900
Oil well
Producing
ASSOCIATED LARSON UNIT A2X
51030881500
Oil well
Producing
ASSOCIATED LARSON UNIT B1
51030601100
Oil well
Producing
ASSOCIATED LARSON UNIT B2X
51030950200
Oil well
Producing
ASSOCIATED UNIT A1
51030602600
Oil well
Producing
ASSOCIATED UNIT A2X UN A-2X
51031053200
Oil well
Producing
ASSOCIATED UNIT A3X
51031072300
Oil well
Producing
ASSOCIATED UNIT A4X
51031072200
Water / Gas Inject
Injecting
ASSOCIATED UNIT C1
51030582700
Oil well
Producing
BEEZLEY 1X22AX
51031075400
Water / Gas Inject
Injecting
BEEZLEY 2-22
51030574200
Oil well
Producing
BEEZLEY 3X 3X22
51031054900
Oil well
Producing
BEEZLEY 4X 22
51031055300
Oil well
Producing
BEEZLEY 5X22
51031174200
Oil well
Producing
BEEZLEY 6X22
51031174300
Oil well
Producing
44
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CARNEY 22X-35
51030724500
Oil well
P&A
CARNEY CT 10-4
51030608600
Oil well
Monitor
CARNEY CT 11-4
51030545700
Oil well
Monitor
CARNEY CT12AX5
51030917600
Water / Gas Inject
Monitor
CARNEY CT 13-4
51030545900
Oil well
Producing
CARNEY CT 1-34
51030548200
Oil well
Producing
CARNEY CT 14-34
51030103500
Oil well
Producing
CARNEY CT 15-35
51030103700
Water / Gas Inject
Injecting
CARNEY CT 16-35
51030103300
Water / Gas Inject
Monitor
CARNEY CT 17-35
51030103200
Oil well
Producing
CARNEY CT 18-35
51030629500
Water / Gas Inject
Injecting
CARNEY CT 19-34
51030604400
Oil well
Producing
CARNEY CT 20X35
51030641300
Oil well
Producing
CARNEY CT 21X35
51030703300
Water / Gas Inject
Injecting
CARNEY CT 22X35ST
51030724501
Oil well
Producing
CARNEY CT 2-34
51030551400
Oil well
Monitor
CARNEY CT 23X35
51030726200
Water / Gas Inject
Injecting
CARNEY CT 24X35
51030728300
Water / Gas Inject
Monitor
CARNEY CT 27X34
51030746600
Water / Gas Inject
Injecting
CARNEY CT 28X
51030747400
Water / Gas Inject
Monitor
CARNEY CT 29X
51030753700
Water / Gas Inject
Injecting
CARNEY CT 30X34 30X
51030752600
Water / Gas Inject
Injecting
CARNEY CT 32X34
51030758900
Water / Gas Inject
Injecting
CARNEY CT 3-34
51030103900
Oil well
Producing
CARNEY CT 33X34
51030759200
Water / Gas Inject
Injecting
CARNEY CT 35X34
51030759300
Water / Gas Inject
Injecting
CARNEY CT 37X4
51030856300
Oil well
Producing
CARNEY CT 38X4
51030881300
Water / Gas Inject
Monitor
CARNEY CT 39X4
51030881400
Oil well
Producing
CARNEY CT 41Y34
51030914900
Oil well
Monitor
CARNEY CT 4-34
51030555900
Oil well
Producing
CARNEY CT 43Y34
51030914800
Oil well
Monitor
CARNEY CT 44Y34
51030915300
Oil well
Monitor
CARNEY CT 5-34
51030103800
Oil well
Producing
CARNEY CT 6-5
51030609100
Water / Gas Inject
Monitor
CARNEY CT 7-35
51030629300
Oil well
Producing
CARNEY CT 8-34
51030104000
Oil well
Producing
CARNEY CT 9-35
51030548600
Water / Gas Inject
Monitor
CARNEY UNIT 1
51030608700
Oil well
Producing
CARNEY UN IT 2X
51030719100
Water / Gas Inject
Injecting
COLTHARPJE 10X
51030869400
Oil well
Producing
45
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COLTHARP JE 2
51030602300
Water / Gas Inject
Monitor
COLTHARP JE 4
51030602200
Water / Gas Inject
Monitor
COLTHARP JE 5X
51030705700
Oil well
Producing
COLTHARP JE 7X
51030727900
Oil well
Producing
COLTHARP JE 8X
51030734300
Oil well
Producing
COLTHARP WH A1
51030601900
Water / Gas Inject
Injecting
COLTHARP WH A3
51030602100
Water / Gas Inject
Monitor
COLTHARP WH A4
51030102800
Water / Gas Inject
Injecting
COLTHARP WH A5X
51030725000
Oil well
Producing
COLTHARP WH A6X
51030744700
Oil well
Producing
COLTHARP WH A8X
51030909900
Oil well
Producing
COLTHARP WH B2X
51030859400
Oil well
Monitor
COLTHARP WH B3X
51030879300
Oil well
Shut In
COLTHARP WH C1
51030107700
Water / Gas Inject
Monitor
COLTHARP WH C2X
51030919800
Oil well
Producing
CT CARNEY 25X34
51030741500
Water / Gas Inject
Injecting
EMERALD 10
51030566200
Oil well
Producing
EMERALD 11
51030567100
Oil well
Producing
EMERALD13ST
51030563601
Water / Gas Inject
Injecting
EMERALD 14
51030556500
Water / Gas Inject
Injecting
EMERALD 16
51030625300
Oil well
Monitor
EMERALD 17
51030567700
Water / Gas Inject
Injecting
EMERALD 18AX
51030920200
Oil well
Producing
EMERALD 19
51030624000
Oil well
Producing
EMERALD 2
51030566900
Oil well
Producing
EMERALD 20
51030555800
Water / Gas Inject
Injecting
EMERALD 22
51030625400
Water / Gas Inject
Injecting
EMERALD 23
51030558900
Water / Gas Inject
Injecting
EMERALD 25
51030548100
Water / Gas Inject
Injecting
EMERALD 26
51030624200
Water / Gas Inject
Injecting
EMERALD 27
51030565300
Oil well
Producing
EMERALD 28
51030562800
Water / Gas Inject
Injecting
EMERALD 29AX
51030924500
Water / Gas Inject
Injecting
EMERALD 30AX
51030920300
Water / Gas Inject
Injecting
EMERALD 31 AX
51030923600
Water / Gas Inject
Injecting
EMERALD 32
51030623800
Oil well
Producing
EMERALD 33AX
51030923900
Water / Gas Inject
Injecting
EMERALD 34
51030559500
Water / Gas Inject
Injecting
EMERALD 35
51030559400
Water / Gas Inject
Injecting
EMERALD 36
51030548800
Water / Gas Inject
Injecting
EMERALD 37
51030551200
Water / Gas Inject
Injecting
46
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EMERALD 38
51030624900
Water / Gas Inject
Injecting
EMERALD 39
51030625100
Water / Gas Inject
Injecting
EMERALD 3ST
51030559901
Water / Gas Inject
Injecting
EMERALD 3ST3
51030559900
Water / Gas Inject
P&A
EMERALD 4
51030550500
Oil well
Producing
EMERALD 40
51030625000
Water / Gas Inject
Injecting
EMERALD 41
51030546300
Water / Gas Inject
Monitor
EMERALD 42D
51030634000
Salt Water Disposal
Injecting
EMERALD 44AX
51030918700
Water / Gas Inject
Injecting
EMERALD 46X
51030713000
Oil well
Producing
EMERALD 47X
51030720100
Oil well
Producing
EMERALD 48X
51030725700
Oil well
Monitor
EMERALD 49AX
51031068000
Oil well
Producing
EMERALD 50X
51030733100
Oil well
Producing
EMERALD 51X
51030733300
Oil well
Producing
EMERALD 52X
51030737100
Oil well
Producing
EMERALD 53X
51030737600
Oil well
Producing
EMERALD 54X
51030763700
Oil well
Producing
EMERALD 55X
51030763800
Oil well
Producing
EMERALD 56X
51030768700
Oil well
Producing
EMERALD 57XST
51030764901
Oil well
Producing
EMERALD 58X
51030773900
Oil well
Producing
EMERALD 59X
51030774000
Oil well
Producing
EMERALD 6
51030558800
Water / Gas Inject
Injecting
EMERALD 60X
51030779800
Oil well
Producing
EMERALD 61X
51030780300
Oil well
Producing
EMERALD 62X
51030781100
Oil well
Producing
EMERALD 63ST
51030804101
Water / Gas Inject
Injecting
EMERALD 63XST
51030804100
Water / Gas Inject
P&A
EMERALD 64X
51030799200
Water / Gas Inject
Injecting
EMERALD 65X
51030794800
Oil well
Producing
EMERALD 66X
51030786800
Oil well
Producing
EMERALD 67X
51030797400
Oil well
Producing
EMERALD 68X
51030797500
Oil well
Producing
EMERALD 69X
51030810300
Water / Gas Inject
Injecting
EMERALD 70X
51030807200
Water / Gas Inject
Injecting
EMERALD 71X
51030804600
Water / Gas Inject
Injecting
EMERALD 72X
51030810400
Water / Gas Inject
Monitor
EMERALD 73X
51030810500
Oil well
Monitor
EMERALD 74X
51030816900
Oil well
Producing
EMERALD 75X
51030843700
Oil well
Producing
47
-------
EMERALD 76X
51030848100
Oil well
Producing
EMERALD 77X
51030848000
Oil well
Producing
EMERALD 78X
51030849100
Oil well
Producing
EMERALD 79X
51030895500
Salt Water Disposal
Injecting
EMERALD 7 A
51030928500
Water / Gas Inject
Injecting
EMERALD 8
51030559000
Water / Gas Inject
P&A
EMERALD 80X
51030876900
Oil well
Producing
EMERALD 81X
51030888300
Oil well
Producing
EMERALD 82X
51030849200
Water / Gas Inject
Injecting
EMERALD 83X
51030876500
Oil well
Producing
EMERALD 84X
51030888500
Oil well
Producing
EMERALD 85X
51030877000
Oil well
Producing
EMERALD 86X
51030877200
Oil well
Producing
EMERALD 87X
51030877300
Oil well
Monitor
EMERALD 88X
51030876600
Oil well
Producing
EMERALD 89X
51030877100
Oil well
Producing
EMERALD 8ST
51030559001
Water / Gas Inject
Injecting
EMERALD 90X
51030914600
Water / Gas Inject
Injecting
EMERALD 91Y
51030914700
Water / Gas Inject
Injecting
EMERALD 92X
51030929500
Oil well
Producing
EMERALD 93X
51031185800
Oil well
Producing
EMERALD 94X
51031185500
Oil well
Producing
EMERALD 95X
51031191400
Oil well
Producing
EMERALD 96X
51031192200
Oil well
Producing
EMERALD 97X
51031191300
Oil well
Producing
EMERALD 98X
51031191500
Water / Gas Inject
Injecting
EMERALD 9ST
51030566101
Water / Gas Inject
Injecting
EMERALD 9ST9
51030566100
Water / Gas Inject
P&A
FAIRFIELD KITTI A 4
51031101700
Oil well
P&A
FAIRFIELD KITTI A 5P
51031101000
Oil well
P&A
FAIRFIELD KITTI A1
51030611100
Water / Gas Inject
Injecting
FAIRFIELD KITTI A4
51031101701
Oil well
Producing
FAIRFIELD KITTI A5
51031101001
Oil well
Producing
FAIRFIELD KITTI B1
51030107800
Water / Gas Inject
Injecting
FE156X
51031033600
Oil well
Producing
FEE 1
51030563400
Oil well
Producing
FEE 1 162Y
51031194500
Water / Gas Inject
Injecting
FEE 10
51030566800
Water / Gas Inject
Injecting
FEE 100X
51030786900
Oil well
Producing
FEE 101X
51030787000
Oil well
Producing
FEE 102X
51030787700
Oil well
Producing
48
-------
FEE 103X
51030788500
Oil well
Monitor
FEE 104X
51030785700
Oil well
Producing
FEE 105X
51030785800
Oil well
Producing
FEE 106X
51030794600
Water / Gas Inject
Injecting
FEE 107X
51030803200
Water / Gas Inject
Injecting
FEE 108X
51030795200
Oil well
Producing
FEE 109X
51030798900
Water / Gas Inject
Injecting
FEE 11
51030559600
Oil well
Producing
FEE 11 OX
51030802600
Water / Gas Inject
Injecting
FEE 111X
51030802700
Water / Gas Inject
Monitor
FEE 112X
51030802800
Water / Gas Inject
Injecting
FEE 113X
51030802900
Water / Gas Inject
Injecting
FEE 114X
51030803100
Water / Gas Inject
Injecting
FEE 115X
51030803300
Water / Gas Inject
Injecting
FEE 116X
51030829900
Water / Gas Inject
Injecting
FEE 117X
51030843800
Oil well
Producing
FEE 118AX
51030928300
Oil well
Monitor
FEE 12
51030565100
Oil well
Producing
FEE 121X
51030857500
Oil well
Producing
FEE 122X
51030866300
Water / Gas Inject
Injecting
FEE 124X
51030866400
Oil well
Producing
FEE 125X
51030868100
Oil well
Monitor
FEE 126X
51030868600
Oil well
Producing
FEE 127X
51030868700
Water / Gas Inject
Injecting
FEE 128X
51030868800
Oil well
Monitor
FEE 129X
51030868900
Oil well
Producing
FEE 13
51030622600
Oil well
Producing
FEE 130X
51030870400
Oil well
Monitor
FEE 133X
51030888400
Oil well
Producing
FEE 135X
51030876000
Oil well
Monitor
FEE 136X
51030874500
Water / Gas Inject
Injecting
FEE 137X
51030876100
Water / Gas Inject
Injecting
FEE 138X
51030876300
Oil well
Producing
FEE 139X
51030876200
Oil well
Producing
FEE 14
51030568700
Oil well
Producing
FEE 140Y
51030910600
Oil well
Monitor
FEE 141X
51030913300
Water / Gas Inject
Injecting
FEE 142X
51030913100
Oil well
Producing
FEE 143X
51030913000
Oil well
Producing
FEE 144Y
51030917500
Oil well
Shut In
FEE 145Y
51030917400
Oil well
Producing
49
-------
FEE 146X
51030946400
Oil well
Producing
FEE 15
51030556800
Oil well
Producing
FEE 153X
51030929700
Oil well
Producing
Fee154X
51031036500
Oil well
Producing
Fee155X
51031037300
Oil well
Producing
FEE 157X
51031101900
Oil well
Monitor
FEE 158 X
51031115900
Oil well
Producing
FEE 159 X
51031101100
Oil well
Producing
FEE 160X
51031186600
Oil well
Producing
FEE 163X
51031195100
Oil well
Producing
FEE16AX
51030923500
Water / Gas Inject
Monitor
FEE 17
51030580100
Water / Gas Inject
Injecting
FEE 18
51030623600
Water / Gas Inject
Monitor
FEE 19
51030622400
Oil well
Producing
FEE 1AX
51030924400
Water / Gas Inject
Monitor
FEE 20
51030616800
Oil well
Producing
FEE 21
51030620700
Oil well
Producing
FEE 22
51030616100
Water / Gas Inject
Injecting
FEE 23
51030615600
Oil well
Producing
FEE 24
51030611200
Water / Gas Inject
Injecting
FEE 25
51030614500
Oil well
Producing
FEE 26
51030615200
Oil well
Producing
FEE 27
51030617500
Oil well
Producing
FEE 28
51030613500
Water / Gas Inject
Injecting
FEE 29
51030614400
Water / Gas Inject
Injecting
FEE 2AX
51030924700
Water / Gas Inject
Injecting
FEE 3
51030565700
Oil well
Producing
FEE 30
51030621100
Water / Gas Inject
Monitor
FEE 31
51030611800
Water / Gas Inject
Injecting
FEE 32
51030614200
Oil well
Producing
FEE 33
51030614700
Oil well
Producing
FEE 34
51030624500
Oil well
Producing
FEE 35
51030611300
Oil well
Producing
FEE 36
51030617600
Oil well
Producing
FEE 37
51030611500
Water / Gas Inject
Injecting
FEE 38
51030625500
Water / Gas Inject
Injecting
FEE 39
51030623300
Water / Gas Inject
Injecting
FEE 4
51030576900
Oil well
Monitor
FEE 40
51030622300
Water / Gas Inject
Injecting
FEE 41
51030622200
Water / Gas Inject
Monitor
FEE 42
51030568800
Water / Gas Inject
Monitor
50
-------
FEE 43
51030614100
Water / Gas Inject
Injecting
FEE 44
51030624700
Water / Gas Inject
Injecting
FEE 45
51030617900
Oil well
Producing
FEE 47
51030616000
Water / Gas Inject
Injecting
FEE 48
51030625900
Water / Gas Inject
Injecting
FEE 49
51030611900
Water / Gas Inject
Injecting
FEE 5
51030574500
Oil well
Producing
FEE 51
51030614900
Water / Gas Inject
Injecting
FEE 52
51030567400
Water / Gas Inject
Injecting
FEE 53AX
51030861200
Water / Gas Inject
Injecting
FEE 55
51030615300
Water / Gas Inject
Injecting
FEE 56
51030615700
Water / Gas Inject
Injecting
FEE 58AX
51030924300
Water / Gas Inject
Injecting
FEE 59
51030616900
Water / Gas Inject
Injecting
FEE 6
51030572000
Oil well
Producing
FEE 60
51030622500
Water / Gas Inject
Injecting
FEE 61
51030620300
Oil well
Producing
FEE 62
51030614000
Oil well
Monitor
FEE 63
51030614600
Water / Gas Inject
Injecting
FEE 64
51030614800
Water / Gas Inject
Injecting
FEE 65
51030615000
Water / Gas Inject
Injecting
FEE 67A
51030929300
Water / Gas Inject
Injecting
FEE 68A
51030568300
Oil well
Producing
FEE 69
51030625600
Water / Gas Inject
Monitor
FEE 7
51030571600
Oil well
Producing
FEE 70AX
51030919100
Water / Gas Inject
Monitor
FEE 72X
51030718000
Oil well
Producing
FEE 73X
51030727400
Oil well
Producing
FEE 74X
51030730700
Oil well
Producing
FEE 75X
51030732600
Oil well
Producing
FEE 76X
51030733900
Oil well
Producing
FEE 78X
51030743400
Oil well
Producing
FEE 79X
51030742400
Water / Gas Inject
Injecting
FEE 8
51030563300
Water / Gas Inject
Injecting
FEE 80X
51030749100
Water / Gas Inject
Injecting
FEE 81X
51030751900
Oil well
Producing
FEE 82X
51030752900
Oil well
Producing
FEE 83X
51030757200
Oil well
Producing
FEE 84X
51030755400
Water / Gas Inject
Injecting
FEE 85X
51030758100
Water / Gas Inject
Injecting
FEE 86X
51030756900
Water Injection Well
P&A
51
-------
FEE 86XST
51030756901
Water / Gas Inject
Injecting
FEE 87X
51030754600
Water / Gas Inject
Monitor
FEE 88X
51030755900
Water / Gas Inject
Injecting
FEE 89X
51030755500
Water / Gas Inject
Injecting
FEE 9
51030551100
Oil well
P&A
FEE 90X
51030758000
Water / Gas Inject
Injecting
FEE 91X
51030757300
Water / Gas Inject
Injecting
FEE 92X
51030755600
Water / Gas Inject
Monitor
FEE 93X
51030759100
Water / Gas Inject
Injecting
FEE 94X
51030759400
Water / Gas Inject
Injecting
FEE 95X
51030764700
Oil well
Producing
FEE 96X
51030764800
Oil well
Producing
FEE 97X
51030779100
Oil well
Producing
FEE 98X
51030782700
Water / Gas Inject
Injecting
FEE 99X
51030784000
Oil well
Producing
FEE 9ST 9
51030551101
Oil well
Producing
GRAY A A17X
51030768900
Water / Gas Inject
Injecting
GRAY A A21X
51030830200
Water / Gas Inject
Injecting
GRAY A A8AX
51030919700
Water / Gas Inject
Injecting
GRAY A10
51030573400
Water / Gas Inject
Injecting
GRAY A12
51030613700
Oil well
Producing
GRAY A13
51030577800
Water / Gas Inject
Monitor
GRAY A14
51030613900
Oil well
Producing
GRAY A15
51030576200
Oil well
Producing
GRAY A16
51030613600
Water / Gas Inject
Injecting
GRAY A18X
51030789800
Oil well
Producing
GRAY A19X
51030787300
Oil well
Producing
GRAY A20X
51030803500
Water / Gas Inject
Injecting
GRAY A22X
51030831700
Oil well
Producing
GRAY A9
51030571500
Oil well
Producing
GRAY B10
51030612300
Water / Gas Inject
Injecting
GRAY B11
51030581800
Oil well
Producing
GRAY B12
51030612900
Oil well
Producing
GRAY B13
51030612600
Oil well
Producing
GRAY B14A
51030928900
Water / Gas Inject
Injecting
GRAY B15
51030579600
Oil well
Producing
GRAY B16
51030612700
Oil well
Producing
GRAY B17
51030582500
Oil well
Monitor
GRAY B18X
51030638600
Oil well
Monitor
GRAY B19X
51036639700
Oil well
Producing
GRAY B2
51030578700
Oil well
Producing
52
-------
GRAY B20X
51030101500
Water / Gas Inject
Injecting
GRAY B21X
51031035700
Oil well
Producing
GRAY B22X
51031036000
Oil well
Producing
GRAY B23X
51031033800
Oil well
Producing
GRAY B24X
51031033700
Oil well
Producing
GRAY B25X
51031057200
Oil well
Producing
GRAY B26X
51031057500
Oil well
Producing
GRAY B27X
51031057400
Oil well
Producing
GRAY B28X
51031101200
Oil well
Producing
GRAY B3
51030613200
Water / Gas Inject
Injecting
GRAY B4
51030613300
Water / Gas Inject
Injecting
GRAY B5
51030612400
Water / Gas Inject
Injecting
GRAY B6
51030613100
Water / Gas Inject
Injecting
GRAY B7
51030612800
Water / Gas Inject
Injecting
GRAY B8
51030581100
Water / Gas Inject
Injecting
GRAY B9
51030612500
Water / Gas Inject
Injecting
GUIBERSON SA 1
51030581300
Water / Gas Inject
Injecting
GUIBERSON SA 5 X
51031115600
Oil well
Producing
HAGOOD L N-A 17X
51030914200
Oil well
P&A
HAGOOD LN A10X
51030791300
Oil well
Shut In
HAGOOD LN A11X
51030794900
Water / Gas Inject
Injecting
HAGOOD LN A12X
51030793600
Oil well
Producing
HAGOOD LN A13X
51030799100
Water / Gas Inject
Injecting
HAGOOD LN A14X
51030795000
Water / Gas Inject
P&A
HAGOOD LN A14XST
51030795001
Water / Gas Inject
Injecting
HAGOOD LN A15X
51030829300
Oil well
Producing
HAGOOD LN A16X
51030830000
Water / Gas Inject
Injecting
HAGOOD LN A17XST
51030914201
Water / Gas Inject
Monitor
HAGOOD LN A2
51030574300
Oil well
Monitor
HAGOOD LN A3
51030576800
Oil well
Monitor
HAGOOD LN A5
51030573600
Water / Gas Inject
Injecting
HAGOOD LN A7
51030575700
Water / Gas Inject
Monitor
HAGOOD LN A9X
51030702200
Water / Gas Inject
Injecting
HAGOOD MC A1
51030632800
Water / Gas Inject
Injecting
HAGOOD MC A10X
51031041400
Oil well
Producing
HAGOOD MC A11X
51031041300
Oil well
Producing
HAGOOD MC A12X
51031053300
Oil well
Producing
HAGOOD MC A13X
51031053100
Oil well
Producing
HAGOOD MC A14X
51031054800
Oil well
Shut In
HAGOOD MC A15X
51031062800
Oil well
Producing
HAGOOD MC A16X
51031061200
Oil well
Producing
53
-------
HAGOOD MC A17X
51031062900
Oil well
Producing
HAGOOD MC A18X
51031061300
Oil well
Producing
HAGOOD MC A19X
51031067000
Water / Gas Inject
Injecting
HAGOOD MC A2
51030102300
Oil well
Producing
HAGOOD MC A21X
51031070900
Oil well
Producing
HAGOOD MC A3
51030633000
Water / Gas Inject
Injecting
HAGOOD MC A4
51030632600
Water / Gas Inject
Injecting
HAGOOD MC A5
51030633100
Water / Gas Inject
Injecting
HAGOOD MC A6
51030102400
Oil well
Producing
HAGOOD MC A7
51030106700
Oil well
Producing
HAGOOD MC A8 A 8
51030632500
Water / Gas Inject
Injecting
HAGOOD MC A9
51030632700
Water / Gas Inject
Injecting
HAGOOD MC B1A
51031102800
Oil well
Producing
HAGOOD MC B2
51031187000
Oil well
Producing
HEFLEY CS 4X
51030856200
Oil well
Producing
HEFLEY ME 2
51030545200
Water / Gas Inject
Monitor
HEFLEY ME 5X
51030719600
Oil well
Producing
HEFLEY ME 6X
51030729300
Oil well
Producing
HEFLEY ME 7X
51030873700
Oil well
Producing
HEFLEY ME 8X
51030869600
Oil well
Producing
L N HAGOOD A- 1
51030572100
Water / Gas Inject
Injecting
L N HAGOOD A-8 IJ A8
51030569100
Water / Gas Inject
Injecting
LACY SB 1
51030573200
Oil well
Producing
LACY SB 11Y
51030914400
Salt Water Disposal
Injecting
LACY SB 12Y
51030914500
Oil well
Producing
LACY SB 13Y
51031057000
Oil well
Producing
LACY SB 2AX
51030928200
Water / Gas Inject
Injecting
LACY SB 3
51030568900
Oil well
Producing
LACY SB 4
51030575800
Water / Gas Inject
Monitor
LACY SB 6X
51030794700
Oil well
Monitor
LACY SB 7X
51030797800
Water / Gas Inject
Injecting
LACY SB 9X
51030831800
Oil well
Monitor
LARSON FA 1
51030106600
Oil well
Producing
LARSON FA 2
51030107200
Water / Gas Inject
Injecting
LARSON FA 3X
51031071000
Oil well
Monitor
LARSON FV A1
51030547600
Oil well
Producing
LARSON FV A2X
51030721600
Water / Gas Inject
Monitor
LARSON FV B11
51030630200
Water / Gas Inject
Injecting
LARSON FV B12
51030100900
Oil well
Producing
LARSON FV B14X
51030641400
Oil well
Shut In
LARSON FV B15X
51030700800
Oil well
Producing
54
-------
LARSON FV B17X
51030707800
Oil well
Producing
LARSON FV B18X
51030708300
Oil well
Producing
LARSON FV B19X
51030710600
Oil well
Producing
LARSON FV B2
51030620200
Water / Gas Inject
Monitor
LARSON FV B20X
51030709900
Oil well
Producing
LARSON FVB21X
51030716500
Oil well
Producing
LARSON FV B22X
51030722700
Oil well
Producing
LARSON FV B23X
51030724200
Oil well
Producing
LARSON FV B24X
51030873800
Oil well
Producing
LARSON FV B25X
51030916500
Oil well
Producing
LARSON FV B27X
51030948800
Oil well
Producing
LARSON FV B4
51030629800
Water / Gas Inject
Injecting
LARSON FV B8
51030620100
Water / Gas Inject
Injecting
LARSON MB 10X25
51030715900
Oil well
Producing
LARSON MB 12X25
51030727000
Oil well
Producing
LARSON MB 2-26 A226
51030566300
Oil well
Producing
LARSON MB 3X26
51030711000
Oil well
Producing
LARSON MB 4X26
51030717700
Oil well
Monitor
LARSON MB 8X25
51030709300
Oil well
Producing
LARSON MB A1AX
51031075600
Water / Gas Inject
Monitor
LARSON MB A2
51030633200
Oil well
Producing
LARSON MB A3X
51031053400
Oil well
Producing
LARSON MB A4X
51031055200
Oil well
Producing
LARSON MB B1
51030576500
Water / Gas Inject
Injecting
LARSON MB B3AX
51031075500
Water / Gas Inject
Injecting
LARSON MB C1-25
51030618600
Water / Gas Inject
Monitor
LARSON MBC1AX
51031076300
Oil well
Producing
LARSON MB C2
51030569000
Water / Gas Inject
Injecting
LARSON MB C3
51030570800
Water / Gas Inject
Injecting
LARSON MB C3-25
51030618700
Water / Gas Inject
Injecting
LARSON MB C4
51031139700
Oil well
Producing
LARSON MB C5
51031142900
Oil well
Producing
LARSON MB C9X25
51030715500
Oil well
Producing
LARSON MB D1-26E
51030620000
Water / Gas Inject
Injecting
LEVISON 10
51030621700
Oil well
Producing
LEVISON 11
51030619800
Water / Gas Inject
Injecting
LEVISON 12
51030103100
Water / Gas Inject
Injecting
LEVISON 13
51030619400
Water / Gas Inject
Injecting
LEVISON 14
51030619900
Water / Gas Inject
Injecting
LEVISON 17
51030619500
Water / Gas Inject
Injecting
LEVISON 18
51030618200
Oil well
Producing
55
-------
LEVISON 2
51030559300
Oil well
Producing
LEVISON 21X
51030638700
Oil well
Producing
LEVISON 22X
51030708900
Oil well
Monitor
LEVISON 23X
51030712300
Oil well
Producing
LEVISON 24X
51030711400
Oil well
Producing
LEVISON 25X
51030722200
Oil well
Producing
LEVISON 26X
51030726700
Oil well
Producing
LEVISON 27X
51030728900
Oil well
Producing
LEVISON 28X
51030731600
Oil well
Monitor
LEVISON 29X
51030732000
Water / Gas Inject
Injecting
LEVISON 30X
51030735100
Water / Gas Inject
Injecting
LEVISON 31X
51030735300
Oil well
Monitor
LEVISON 32X
51030747500
Water / Gas Inject
Injecting
LEVISON 33X
51030752100
Oil well
Producing
LEVISON 34X
51030758600
Water / Gas Inject
Injecting
LEVISON 35X
51030868300
Oil well
Producing
LEVISON 6
51030106200
Oil well
Producing
LEVISON 7
51030619700
Oil well
Monitor
LEVISON 8
51030103000
Water / Gas Inject
Injecting
LEVISON 9
51030628600
Water / Gas Inject
Injecting
LEVSION 1
51030559100
Oil well
Producing
LN - HAGOOD A6
51030569400
Oil well
Producing
LN HAGOOD A-4
51030570700
Oil well
Shut In
MAGOR1A
51030989300
Water / Gas Inject
Injecting
MATTERN 1
51030580400
Water / Gas Inject
Injecting
MCLAUGHLIN AC 1
51030573100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 10
51030578000
Oil well
Monitor
MCLAUGHLIN AC 11
51030569300
Oil well
Producing
MCLAUGHLIN AC 12
51030579800
Water / Gas Inject
Injecting
MCLAUGHLIN AC 13
51030581000
Water / Gas Inject
Injecting
MCLAUGHLIN AC 14
51030105800
Oil well
Producing
MCLAUGHLIN AC 15
51030576700
Oil well
Producing
MCLAUGHLIN AC 16
51030105400
Oil well
Producing
MCLAUGHLIN AC 17
51030631700
Water / Gas Inject
Injecting
MCLAUGHLIN AC 18
51030105300
Water / Gas Inject
Injecting
MCLAUGHLIN AC 19
51030579400
Oil well
Producing
MCLAUGHLIN AC 2
51030573300
Oil well
Producing
MCLAUGHLIN AC 20
51030578200
Water / Gas Inject
Injecting
MCLAUGHLIN AC 21
51030578100
Oil well
Producing
MCLAUGHLIN AC 22
51030105500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 23
51030571800
Water / Gas Inject
Injecting
56
-------
MCLAUGHLIN AC 24
51030576300
Water / Gas Inject
Injecting
MCLAUGHLIN AC 25
51030631800
Oil well
Producing
MCLAUGHLIN AC 26
51030105000
Water / Gas Inject
Injecting
MCLAUGHLIN AC 27
51036005300
Oil well
Producing
MCLAUGHLIN AC 28
51030569900
Oil well
Producing
MCLAUGHLIN AC 29
51030581900
Oil well
Producing
MCLAUGHLIN AC 30
51030105100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 31
51030105200
Water / Gas Inject
Injecting
MCLAUGHLIN AC 32
51030581200
Water / Gas Inject
Injecting
MCLAUGHLIN AC 33
51030631500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 34
51030104700
Water / Gas Inject
Injecting
MCLAUGHLIN AC 35
51030581700
Oil well
Producing
MCLAUGHLIN AC 36
51030104800
Oil well
Producing
MCLAUGHLIN AC 37
51030633300
Oil well
Producing
MCLAUGHLIN AC 38
51030632200
Oil well
Producing
MCLAUGHLIN AC 39A
51031049300
Oil well
Producing
MCLAUGHLIN AC 3AX
51030920700
Water / Gas Inject
Injecting
MCLAUGHLIN AC 4
51030573800
Oil well
Producing
MCLAUGHLIN AC 41AX
51030920100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 42
51030579500
Water / Gas Inject
Monitor
MCLAUGHLIN AC 43
51030632400
Water / Gas Inject
Injecting
MCLAUGHLIN AC 44A
51031096100
Oil well
Producing
MCLAUGHLIN AC 44D
51030631600
Salt Water Disposal
Injecting
MCLAUGHLIN AC 45 AC
51030631900
Water / Gas Inject
Injecting
MCLAUGHLIN AC 46ST
51030632301
Water / Gas Inject
Monitor
MCLAUGHLIN AC 47X
51030107500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 49X
51030641700
Oil well
Monitor
MCLAUGHLIN AC 5
51030571200
Oil well
Monitor
MCLAUGHLIN AC 50X
51030632100
Oil well
Producing
MCLAUGHLIN AC 51X
51030641800
Oil well
Producing
MCLAUGHLIN AC 52X
51030642500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 53X
51030101400
Oil well
Producing
MCLAUGHLIN AC 54X
51030642600
Oil well
Producing
MCLAUGHLIN AC 55X
51030641900
Water / Gas Inject
Injecting
MCLAUGHLIN AC 56X
51030642000
Water / Gas Inject
Injecting
MCLAUGHLIN AC 57X
51030701000
Oil well
Monitor
MCLAUGHLIN AC 58X
51030701400
Oil well
Producing
MCLAUGHLIN AC 59AX
51030928800
Oil well
Producing
MCLAUGHLIN AC 6
51030579900
Oil well
Producing
MCLAUGHLIN AC 60X
51030769200
Water / Gas Inject
Injecting
MCLAUGHLIN AC 61X
51030769000
Oil well
Monitor
57
-------
MCLAUGHLIN AC 62X
51030771500
Oil well
Producing
MCLAUGHLIN AC 63X
51030771600
Water / Gas Inject
Injecting
MCLAUGHLIN AC 65X
51030771800
Oil well
Producing
MCLAUGHLIN AC 66X
51030773800
Water / Gas Inject
Injecting
MCLAUGHLIN AC 67X
51030817000
Oil well
Producing
MCLAUGHLIN AC 68X
51030829200
Oil well
Producing
MCLAUGHLIN AC 69X
51030829400
Water / Gas Inject
Injecting
MCLAUGHLIN AC 7
51030580900
Water / Gas Inject
Injecting
MCLAUGHLIN AC 70X
51030830100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 71X
51030829700
Oil well
Producing
MCLAUGHLIN AC 72X
51030832000
Water / Gas Inject
Injecting
MCLAUGHLIN AC 73X
51030831900
Oil well
Producing
MCLAUGHLIN AC 74X
51030832100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 75X
51030829800
Oil well
Producing
MCLAUGHLIN AC 76X
51030914100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 77X
51030915200
Oil well
Producing
MCLAUGHLIN AC 78X
51030915500
Oil well
Producing
MCLAUGHLIN AC 79X
51030930000
Oil well
Monitor
MCLAUGHLIN AC 8
51030573500
Oil well
Producing
MCLAUGHLIN AC 80X
51030930100
Oil well
Monitor
MCLAUGHLIN AC 81AX
51031064500
Oil well
Producing
MCLAUGHLIN AC 82X
51031054600
Oil well
Producing
MCLAUGHLIN AC 83X
51031059500
Oil well
Producing
MCLAUGHLIN AC 84Y
51031057300
Oil well
Producing
MCLAUGHLIN AC 86Y
51031058400
Oil well
Producing
MCLAUGHLIN AC 88X
51031070000
Oil well
Producing
MCLAUGHLIN AC 9
51030576600
Oil well
Monitor
MCLAUGHLIN AC 90X
51031069900
Oil well
Producing
MCLAUGHLIN AC 91X
51031072600
Water / Gas Inject
Injecting
MCLAUGHLIN AC 92X
51031070800
Oil well
Producing
MCLAUGHLIN AC 93X
51031072700
Water / Gas Inject
Injecting
MCLAUGHLIN AC 94X
51031072500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 95X
51031140800
Oil well
Producing
MCLAUGHLIN AC A1
51030609200
Oil well
Monitor
MCLAUGHLIN AC A3X
51030863000
Oil well
Producing
MCLAUGHLIN AC C2
51031104100
Oil well
Monitor
MCLAUGHLINS W6
51030627800
Oil well
P&A
MCLAUGHLIN SHARPLES 10X28
51030749000
Oil well
Producing
MCLAUGHLIN SHARPLES 1-28
51030560300
Water / Gas Inject
Injecting
MCLAUGHLIN SHARPLES 12X33
51030759800
Oil well
Producing
MCLAUGHLIN SHARPLES 1-33
51030551300
Oil well
Producing
58
-------
MCLAUGHLIN SHARPLES 13X3
51030873900
Oil well
Producing
MCLAUGHLIN SHARPLES 14Y33
51030912300
Oil well
Producing
MCLAUGHLIN SHARPLES 15X32
51030885400
Oil well
Producing
MCLAUGHLIN SHARPLES 16X32
51030913200
Water / Gas Inject
Injecting
MCLAUGHLIN SHARPLES 2-28
51030560000
Oil well
Producing
MCLAUGHLIN SHARPLES 2-32
51030627300
Water / Gas Inject
Monitor
MCLAUGHLIN SHARPLES 2-33
51030106800
Water / Gas Inject
Injecting
MCLAUGHLIN SHARPLES 3-32
51030627000
Oil well
Monitor
MCLAUGHLIN SHARPLES 3-33
51030629000
Oil well
Producing
MCLAUGHLIN SHARPLES 4-33
51030629100
Water / Gas Inject
Injecting
MCLAUGHLIN SHARPLES 5-33
51030104500
Oil well
Monitor
MCLAUGHLIN SHARPLES 6-33
51030628800
Oil well
Monitor
MCLAUGHLIN SHARPLES 7-33
51030104600
Water / Gas Inject
Monitor
MCLAUGHLIN SHARPLES 8-33
51030628900
Water / Gas Inject
Monitor
MCLAUGHLIN SHARPLES 9X33
51030746500
Oil well
Producing
MCLAUGHLIN SW11X
51030759700
Water / Gas Inject
Injecting
MCLAUGHLIN SW12X
51030760100
Water / Gas Inject
Injecting
MCLAUGHLIN SW 1ST
51030548300
Oil well
P&A
MCLAUGHLIN SW 1 ST 1
51030548301
Water / Gas Inject
Monitor
MCLAUGHLIN SW2
51030627700
Oil well
Producing
MCLAUGHLIN SW 3
51030104400
Water / Gas Inject
Injecting
MCLAUGHLIN SW4
51030107600
Oil well
Producing
MCLAUGHLIN SW 5
51030627900
Oil well
Producing
MCLAUGHLIN SW6ST
51030627801
Water / Gas Inject
Injecting
MCLAUGHLIN SW7X
51030746100
Oil well
Producing
MCLAUGHLIN SW8X
51030753000
Water / Gas Inject
Injecting
MCLAUGHLIN UNIT A1
51030581600
Oil well
Producing
MCLAUGHLIN UNIT B1
51030582600
Oil well
Producing
MCLAUGHLIN UNIT B2X
51031057600
Water / Gas Inject
Injecting
MELLEN 3A
51031098100
Oil well
Producing
MELLEN WP 1
51036000300
Water / Gas Inject
Injecting
MELLEN WP 2
51030105600
Water / Gas Inject
Injecting
NEAL 2AX
51030920800
Water / Gas Inject
Injecting
NEAL4
51030565500
Water / Gas Inject
Injecting
NEAL 5A
51030565900
Oil well
Producing
NEAL 6X
51030790600
Oil well
Producing
NEAL 7X
51030804200
Water / Gas Inject
Injecting
NEAL 8X
51030804300
Water / Gas Inject
P&A
NEAL 8XST
51030804301
Water / Gas Inject
Injecting
NEAL 9Y
51030912000
Oil well
Producing
NEWTON ASSOC UNIT D2X
51030868500
Oil well
Monitor
59
-------
NIKKEL 3
51030619200
Water / Gas Inject
Injecting
PURDY 1-1
51030545300
Water / Gas Inject
Monitor
PURDY 2X1
51030881000
Oil well
Producing
RAVEN A1AX
51030917800
Water / Gas Inject
Injecting
RAVEN A2
51030625700
Water / Gas Inject
Injecting
RAVEN A3
51030624400
Water / Gas Inject
Injecting
RAVEN A4
51030625800
Water / Gas Inject
Injecting
RAVEN A5X
51030718800
Oil well
Producing
RAVEN B1
51030564900
Oil well
Producing
RAVEN B2AX
51030923800
Water / Gas Inject
Monitor
RECTOR 1
51030549400
Oil well
Producing
RECTOR 11X
51030867200
Oil well
Shut In
RECTOR 12X
51030919900
Oil well
Shut In
RECTOR 3
51030106000
Water / Gas Inject
Injecting
RECTOR 8X
51030704300
Oil well
Producing
RECTOR 9X
51030714700
Oil well
Shut In
RIGBY 1
51030569700
Oil well
Producing
RIGBY 5X
51030804700
Water / Gas Inject
Injecting
RIGBY 6Y
51030910700
Oil well
Producing
RIGBY A2AX
51030920000
Water / Gas Inject
Injecting
RIGBY A3X
51030791000
Oil well
Producing
RIGBY A4X
51030791100
Oil well
Monitor
RIGBY A7Y
51030915100
Oil well
Monitor
ROOTH DF1
51030579700
Water / Gas Inject
Injecting
ROOTH DF 5 X
51031143000
Oil well
Producing
ROOTH DF 6 X
51031125000
Oil well
Producing
S B LACY 3
51030568900
Oil well
Monitor
STOFFER CR A1
51030562700
Water / Gas Inject
Injecting
STOFFER CR A2
51030559200
Water / Gas Inject
Injecting
STOFFER CR B1
51030567300
Oil well
Producing
SW MCLAUGHLIN 10X
51030754700
Oil well
Producing
SW MCLAUGHLIN 9X
51030753500
Oil well
Producing
U P 4829
51030623100
Water / Gas Inject
P&A
UNION PACIFIC 1 150X 16
51031150200
Oil well
Producing
UNION PACIFIC 1 151X 16
51031150100
Oil well
Producing
UNION PACIFIC 1 153X 16
51031146401
Water / Gas Inject
Injecting
UNION PACIFIC 100X20
51030788600
Oil well
Producing
UNION PACIFIC 101X20
51030797300
Oil well
Monitor
UNION PACIFIC 10-21
51030568501
Oil well
Monitor
UNION PACIFIC 102X20
51030797700
Water / Gas Inject
Injecting
UNION PACIFIC 103X20
51030799000
Water / Gas Inject
Injecting
60
-------
UNION PACIFIC 104X20
51030803000
Water / Gas Inject
Injecting
UNION PACIFIC 105X29
51030794500
Oil well
Producing
UNION PACIFIC 106X32
51030845000
Oil well
Producing
UNION PACIFIC 107X32
51030849800
Oil well
Producing
UNION PACIFIC 108X21
51030849500
Water / Gas Inject
Injecting
UNION PACIFIC 109X32
51030849700
Oil well
Producing
UNION PACIFIC 110X21
51030853000
Water / Gas Inject
Injecting
UNION PACIFIC 111X29
51030852200
Oil well
Producing
UNION PACIFIC 11-21
51030616200
Oil well
Producing
UNION PACIFIC 112X21
51030873500
Oil well
Monitor
UNION PACIFIC 113X22
51030860600
Oil well
Monitor
UNION PACIFIC 115X21
51030866600
Oil well
Producing
UNION PACIFIC 117X22
51030866700
Oil well
Producing
UNION PACIFIC 118X21
51030869700
Oil well
Producing
UNION PACIFIC 119X21
51030869800
Oil well
Producing
UNION PACIFIC 120X21
51030869900
Oil well
Producing
UNION PACIFIC 12-27
51030620400
Oil well
Producing
UNION PACIFIC 122X21
51030870000
Oil well
Monitor
UNION PACIFIC 126X32
51030885100
Oil well
Producing
UNION PACIFIC 127X31
51030884700
Oil well
Producing
UNION PACIFIC 128X31
51030910000
Oil well
Producing
UNION PACIFIC 129X31
51030885200
Oil well
Producing
UNION PACIFIC 130X32
51030885300
Oil well
Producing
UNION PACIFIC 131X32
51030885500
Oil well
Producing
UNION PACIFIC 1-32
51030556700
Water / Gas Inject
Injecting
UNION PACIFIC 13-28
51030622000
Water / Gas Inject
Injecting
UNION PACIFIC 132X21
51030874600
Oil well
Monitor
UNION PACIFIC 133X21
51030876400
Oil well
Producing
UNION PACIFIC 134X21
51030904100
Water / Gas Inject
Injecting
UNION PACIFIC 135Y28
51030910500
Oil well
Monitor
UNION PACIFIC 136X20
51030913800
Oil well
Producing
UNION PACIFIC 137X20
51030913900
Water / Gas Inject
Monitor
UNION PACIFIC 138Y28
51030917300
Oil well
Producing
UNION PACIFIC 139Y28
51030918500
Oil well
Monitor
UNION PACIFIC 140Y27
51030918800
Oil well
Producing
UNION PACIFIC 141Y28
51030918900
Oil well
Producing
UNION PACIFIC 14-20
51030615400
Oil well
Producing
UNION PACIFIC 142Y28
51030919000
Oil well
Monitor
UNION PACIFIC 143Y28
51030918600
Oil well
Monitor
UNION PACIFIC 15-28
51030102900
Oil well
Monitor
UNION PACIFIC 154Y29
51031172000
Oil well
Producing
61
-------
UNION PACIFIC 156Y29
51031172100
Oil well
Producing
UNION PACIFIC 16-27
51030620600
Oil well
Shut In
UNION PACIFIC 17-27
51030621400
Oil well
Producing
UNION PACIFIC 18-21
51030616400
Oil well
Producing
UNION PACIFIC 19-28
51030621900
Water / Gas Inject
Injecting
UNION PACIFIC 20-29
51030622800
Water / Gas Inject
Injecting
UNION PACIFIC 21-32
51030627100
Water / Gas Inject
Monitor
UNION PACIFIC 2-20
51030569200
Oil well
Producing
UNION PACIFIC 22-32
51030627500
Oil well
Producing
UNION PACIFIC 23-32
51030626900
Oil well
Producing
UNION PACIFIC 24-27
51030621200
Water / Gas Inject
Injecting
UNION PACIFIC 25-34
51030106900
Oil well
Shut In
UNION PACIFIC 26-31
51030626100
Water / Gas Inject
Injecting
UNION PACIFIC 27-20
51030577000
Oil well
Monitor
UNION PACIFIC 28-22
51030617300
Oil well
Producing
UNION PACIFIC 29-32
51030548700
Oil well
Monitor
UNION PACIFIC 31-21
51030616600
Oil well
Monitor
UNION PACIFIC 32-27
51030620800
Oil well
Monitor
UNION PACIFIC 33-32
51030626600
Water / Gas Inject
Injecting
UNION PACIFIC 3-34
51030551000
Oil well
Producing
UNION PACIFIC 34-31
51030626300
Water / Gas Inject
Injecting
UNION PACIFIC 35-32
51030626800
Water / Gas Inject
Injecting
UNION PACIFIC 36-32
51030627200
Water / Gas Inject
Injecting
UNION PACIFIC 37AX29
51030917700
Water / Gas Inject
Injecting
UNION PACIFIC 39-17
51030612100
Water / Gas Inject
Injecting
UNION PACIFIC 41-20
51030615800
Water / Gas Inject
Shut In
UNION PACIFIC 4-29
51030563200
Water / Gas Inject
Injecting
UNION PACIFIC 42AX28
51030925700
Water / Gas Inject
Injecting
UNION PACIFIC 43-28
51030622100
Water / Gas Inject
Monitor
UNION PACIFIC 44AX20
51030923300
Water / Gas Inject
Injecting
UNION PACIFIC 45-21
51030569600
Water / Gas Inject
Injecting
UNION PACIFIC 47-21
51030615900
Water / Gas Inject
Injecting
UNION PACIFIC 48-29ST
51030623101
Water / Gas Inject
Injecting
UNION PACIFIC 49-27
51030621300
Oil well
Producing
UNION PACIFIC 50-29
51030107100
Water / Gas Inject
Injecting
UNION PACIFIC 51AX20
51030892800
Water / Gas Inject
Injecting
UNION PACIFIC 5-28
51030563900
Oil well
Producing
UNION PACIFIC 52A-29
51030928400
Water / Gas Inject
Injecting
UNION PACIFIC 53-32
51030627600
Water / Gas Inject
Monitor
UNION PACIFIC 54-21
51030616300
Water / Gas Inject
Injecting
UNION PACIFIC 55-17
51030612200
Water / Gas Inject
Injecting
62
-------
UNION PACIFIC 56-21
51030616700
Water / Gas Inject
Injecting
UNION PACIFIC 58-27
51030620500
Water / Gas Inject
Injecting
UNION PACIFIC 59A-27
51031120700
Oil well
Producing
UNION PACIFIC 60-31
51030626200
Water / Gas Inject
Injecting
UNION PACIFIC 61-20
51030615500
Water / Gas Inject
Injecting
UNION PACIFIC 6-21
51030574100
Oil well
Producing
UNION PACIFIC 62AX32
51030919600
Water / Gas Inject
Injecting
UNION PACIFIC 65-5
51030608900
Water / Gas Inject
Monitor
UNION PACIFIC 67-32
51030626700
Water / Gas Inject
Injecting
UNION PACIFIC 68-32
51030628700
Water / Gas Inject
Injecting
UNION PACIFIC 69-27
51030621000
Oil well
Shut In
UNION PACIFIC 71X31
51030727600
Oil well
Producing
UNION PACIFIC 7-29
51030559700
Water / Gas Inject
Injecting
UNION PACIFIC 73X29
51030738600
Oil well
Producing
UNION PACIFIC 74X27
51030741600
Oil well
Monitor
UNION PACIFIC 75X32
51030740200
Oil well
Producing
UNION PACIFIC 76X21
51030742100
Oil well
Producing
UNION PACIFIC 77X32
51030745400
Oil well
Producing
UNION PACIFIC 78X21
51030742600
Water / Gas Inject
Injecting
UNION PACIFIC 79X32
51030744800
Oil well
Monitor
UNION PACIFIC 80X28
51030746000
Water / Gas Inject
Monitor
UNION PACIFIC 81X29
51030749900
Oil well
Producing
UNION PACIFIC 8-20
51030568600
Oil well
Producing
UNION PACIFIC 82X28
51030749400
Oil well
Producing
UNION PACIFIC 83X28
51030750000
Oil well
Producing
UNION PACIFIC 84X28
51030749500
Oil well
Producing
UNION PACIFIC 85X34
51030748100
Water / Gas Inject
Injecting
UNION PACIFIC 86X27
51030748200
Water / Gas Inject
Injecting
UNION PACIFIC 87X29
51030750900
Oil well
Producing
UNION PACIFIC 88X21
51030751400
Oil well
Producing
UNION PACIFIC 89X34
51030754800
Water / Gas Inject
Injecting
UNION PACIFIC 91X28
51030756000
Water / Gas Inject
Injecting
UNION PACIFIC 9-29
51030565600
Water / Gas Inject
Injecting
UNION PACIFIC 92X28
51030757400
Water / Gas Inject
Monitor
UNION PACIFIC 94X27
51030758800
Water / Gas Inject
Injecting
UNION PACIFIC 96X29
51030765000
Oil well
Producing
UNION PACIFIC 97X29
51030765100
Oil well
Producing
UNION PACIFIC 98X32
51030765200
Oil well
Producing
UNION PACIFIC 99X29
51030785600
Oil well
Producing
UNION PACIFIC B1-34
51030548900
Water / Gas Inject
Monitor
UNION PACIFIC B2-34
51030102700
Oil well
Monitor
63
-------
UNION PACIFIC B3X34
51030744000
Oil well
Producing
UNION PACIFIC B4X34
51030753600
Water / Gas Inject
Injecting
UNION PACIFIC B5X34
51030759900
Water / Gas Inject
Injecting
UNION PACIFIC B6X34
51030760200
Water / Gas Inject
Monitor
WALBRIDGE LB 1
51030607000
Water / Gas Inject
Monitor
WALBRIDGE UNIT 1
51030607200
Water / Gas Inject
Monitor
WALBRIDGE UNIT 2X
51030920500
Oil well
Producing
WALBRIDGE UNIT 3X
51030920600
Oil well
Monitor
WEYRAUCH 2-36
51030630600
Water / Gas Inject
Injecting
WEYRAUCH 4X36
51030707200
Oil well
Producing
WEYRAUCH 5X36
51030881900
Oil well
Producing
WEYRAUCH 6X36
51030916600
Oil well
Producing
WEYRAUCH 7X36
51030916300
Oil well
Producing
AC MCLAUGHLIN 39
51030582400
P&A
P&A
A C MCLAUGHLIN 3
51030578600
P&A
P&A
MCLAUGHLIN AC 40
51030632000
P&A
P&A
AC MCLAUGHLIN 41
51030575900
P&A
P&A
A C MCLAUGHLIN 48X
51030580300
P&A
P&A
A C MCLAUGHLIN 59X
51030769100
P&A
P&A
MCLAUGHLIN AC 81X
51031053000
P&A
P&A
A.C. MCLAUGHLIN A A2
51030609300
P&A
P&A
AC MCLAUGHLIN B 1
51030611000
P&A
P&A
AC MCLAUGHLIN B 2
51030610500
P&A
P&A
A C MCLAUGHLIN 1
51030612000
P&A
P&A
A C MCLAUGHLIN 1
51030757700
P&A
P&A
ASSOCIATED 4X
51030881200
P&A
P&A
ASSOCIATED B 1
51030601200
P&A
P&A
ASSOCIATED B 2
51030601000
P&A
P&A
ASSOCIATED B 3
51030601300
P&A
P&A
BEEZLEY 1 22
51030573900
P&A
P&A
CT CARNEY 12-5
51030107000
P&A
P&A
CT CARNEY 26X35
51030745000
P&A
P&A
CARNEY CT 31X4
51030760400
P&A
P&A
CARNEY C T 34X-4
51030760000
P&A
P&A
CARNEY CT 36X34
51030759500
P&A
P&A
CARNEY CT 40X35
51030911700
P&A
P&A
CARNEY CT 42Y34
51030915400
P&A
P&A
CHASE UNIT U 1
51030600800
P&A
P&A
HILL.C.E. 1
51030601800
P&A
P&A
HEFLEY C-S 1
51030104100
P&A
P&A
C-S HEFLEY 2
51030607700
P&A
P&A
64
-------
C-S HEFLEY 3
51030607800
P&A
P&A
C R STOFFER A 3
51030562600
P&A
P&A
EMERALD 12
51030566700
P&A
P&A
EMERALD 15
51030565400
P&A
P&A
EMERALD 18
51030104900
P&A
P&A
EMERALD 21
51030546400
P&A
P&A
EMERALD 24
51030563500
P&A
P&A
EMERALD 29
51030565800
P&A
P&A
EMERALD 30
51030563000
P&A
P&A
EMERALD 31
51030623700
P&A
P&A
EMERALD 33
51030623900
P&A
P&A
EMERALD OIL CO. 3M
51030724700
P&A
P&A
EMERALD 43
51030625200
P&A
P&A
EMERALD 44
51030633800
P&A
P&A
EMERALD 45
51030603000
P&A
P&A
EMERALD 49X
51030729600
P&A
P&A
EMERALD 5
51030566600
P&A
P&A
EMERALD 7
51030624100
P&A
P&A
E OLDLAND 4
51030715200
P&A
P&A
FAIRFIELD,KITTIE A 2
51030611400
P&A
P&A
FAIRFIELD,KITTIE A 3
51030611700
P&A
P&A
F V LARSON 116
51036652500
P&A
P&A
FEE 118X
51030843900
P&A
P&A
FEE 119X
51030849400
P&A
P&A
FEE161X
51031185900
P&A
P&A
FEE 16
51030624600
P&A
P&A
FEE 2
51030558600
P&A
P&A
FEE 46
51030610700
P&A
P&A
FEE 53
51030617400
P&A
P&A
FEE 54
51030618000
P&A
P&A
FEE 57
51030622700
P&A
P&A
FEE 58
51030614300
P&A
P&A
FEE 66
51030610900
P&A
P&A
FEE 67
51030611600
P&A
P&A
FEE 70
51030626000
P&A
P&A
FEE 71
51030610800
P&A
P&A
FEE 77X
51030736000
P&A
P&A
FEDERAL ET AL 2M
51030719700
P&A
P&A
FEDERAL ET AL 5M
51030731700
P&A
P&A
LARSON FV B10
51030629900
P&A
P&A
LARSON FV B13X
51030557900
P&A
P&A
65
-------
LARSON FV B16X
51030702400
P&A
P&A
LARSON FV B1
51030629600
P&A
P&A
LARSON FV 26Y
51030948500
P&A
P&A
LARSON FV B3
51030630500
P&A
P&A
LARSON FV B5
51030630100
P&A
P&A
LARSON FV B6
51030630300
P&A
P&A
LARSON F V B7
51030630001
P&A
P&A
LARSON FV B9
51030102500
P&A
P&A
F V LARSON 1
51030539800
P&A
P&A
GENTRY 2D
51030543700
P&A
P&A
GENTRY 3D
51030608500
P&A
P&A
NEWTON 4-D
51030104300
P&A
P&A
GENTRY 4D
51030543700
P&A
P&A
GENTRY 5D
51030608300
P&A
P&A
GENTRY 6X
51030744200
P&A
P&A
GRAY A 11
51030613800
P&A
P&A
GRAY A 11 AX
51030927500
P&A
P&A
GRAY A 8
51030568100
P&A
P&A
GRAY B 14
51030613000
P&A
P&A
GUIBERSON,S.A. A 2
51030613400
P&A
P&A
HILDENBRANDT 1
51030608100
P&A
P&A
COLTHARP JE 1
51030602400
P&A
P&A
J E COLTHARP 3
51030602500
P&A
P&A
COLTHARP JE 6X
51030714800
P&A
P&A
COLTHARP JE 9X P 9X
51030853500
P&A
P&A
PEPPER,J.E. A 1
51030550200
P&A
P&A
J E PEPPER B 1
51030606300
P&A
P&A
LACY SB 10Y
51030914300
P&A
P&A
S B LACY 2
51030570600
P&A
P&A
F V LARSON 1
51030106500
P&A
P&A
LEVISON 15
51030618100
P&A
P&A
LEVISON 16
51030619600
P&A
P&A
LEVISON 19
51030106300
P&A
P&A
LEVISON 20
51030618300
P&A
P&A
LEVISON 3
51030621600
P&A
P&A
LEVISON 4
51030560400
P&A
P&A
LEVISON 5
51030621500
P&A
P&A
LNHAGOODB 1
51030607300
P&A
P&A
L N HAGOOD B 2
51030607100
P&A
P&A
L N HAGOOD B 3
51030607400
P&A
P&A
WALBRIDGE LB 3
51030630800
P&A
P&A
66
-------
WALBRIDGE LB 4X
51030873600
P&A
P&A
WALBRIDGE LB 5Y
51030948300
P&A
P&A
MAGOR 1
51030580800
P&A
P&A
MCLAUGHLIN 3
51030556100
P&A
P&A
MELLEN,W.P. A 3
51030105700
P&A
P&A
HEFLEY ME 1
51030607500
P&A
P&A
HEFLEY ME 3
51030545400
P&A
P&A
HEFLEY ME 4
51030543300
P&A
P&A
M B LARSON C11 X 25
51030717300
P&A
P&A
M B LARSON A 1
51030632900
P&A
P&A
MB LARSON A3
51030576400
P&A
P&A
LARSON MB 1-35
51030555700
P&A
P&A
M B LARSON C 1
51030571900
P&A
P&A
LARSON MB C2-25
51030106400
P&A
P&A
M B LARSON C425
51030618900
P&A
P&A
LARSON MB D136
51030631000
P&A
P&A
LARSON MB D226
51030102600
P&A
P&A
M B LARSON D525
51030618500
P&A
P&A
M B LARSON D625
51030619000
P&A
P&A
M B LARSON D725
51030618400
P&A
P&A
NEAL2
51030566000
P&A
P&A
NEAL3
51030567200
P&A
P&A
NEWTON ASSOC A1
51030107300
P&A
P&A
NEWTON ASSOC B 1
51030101800
P&A
P&A
NEWTON ASSOC C 1
51030102100
P&A
P&A
NEWTON ASSOC D 1
51030102200
P&A
P&A
NIKKEL 1
51030619300
P&A
P&A
NIKKEL 2
51030619100
P&A
P&A
OLDLAND1
51030102000
P&A
P&A
OLDLAND 2
51030106100
P&A
P&A
OLDLAND 3
51030630400
P&A
P&A
OLDLAND E 5X
51030853600
P&A
P&A
OLDLAND E 6X
51030947600
P&A
P&A
PURDY 1 6
51030606200
P&A
P&A
PURDY 3X1
51030870300
P&A
P&A
RANGELY 2M-33-19B
51030939800
P&A
P&A
RAVEN A 1
51030562900
P&A
P&A
RAVEN B 2
51030624300
P&A
P&A
RECTOR 10X
51030760300
P&A
P&A
RECTOR 2
51030608400
P&A
P&A
RECTOR 4
51030629400
P&A
P&A
67
-------
RECTOR 5
51030629200
P&A
P&A
RECTOR 6
51030608200
P&A
P&A
RECTOR 7
51030105900
P&A
P&A
RIGBY A224
51030570000
P&A
P&A
ROOTH 3
51030564700
P&A
P&A
MCLAUGHLIN SHARPLES 11X 3
51030760500
P&A
P&A
SHARPLES MCLAUGHLIN 132
51030107400
P&A
P&A
SHARPLES MCLAUGHLIN 432
51030627400
P&A
P&A
UNION PACIFIC 121X21
51030870500
P&A
P&A
U P3016
51030578300
P&A
P&A
UNION PACIFIC 37-29
51030623200
P&A
P&A
U P 3822
51030574400
P&A
P&A
U P 4022
51030617800
P&A
P&A
U P 4228
51030621800
P&A
P&A
U P 4420
51030571000
P&A
P&A
UNION PACIFIC 46-21
51030573700
P&A
P&A
U P 5721
51030616500
P&A
P&A
U P 5927
51030620900
P&A
P&A
UNION PACIFIC 62-32
51030626500
P&A
P&A
UNION PACIFIC 63-31
51030623000
P&A
P&A
UNION PACIFIC 63-31
51030626400
P&A
P&A
UNION PACIFIC 63AX31
51030917900
P&A
P&A
U P 6422
51030617200
P&A
P&A
U P6616
51030610600
P&A
P&A
UNION PACIFIC 72X31
51030736400
P&A
P&A
UNION PACIFIC 90X29
51030758200
P&A
P&A
UNION PACIFIC 93X27
51030756100
P&A
P&A
U P 95X 34
51030759600
P&A
P&A
COLTHARP WH A2
51030602000
P&A
P&A
COLTHARP WH A7X
51030869300
P&A
P&A
COLTHARP WH B1
51030101900
P&A
P&A
WEYRAUCH 1-36
51030630700
P&A
P&A
WEYRAUCH 336
51030630900
P&A
P&A
WHITE 1
51030543500
P&A
P&A
WHITE 2
51030545100
P&A
P&A
68
-------
Request for Additional Information: Rangely Gas Plant
February 12, 2024
Instructions: Please enter responses into this table and make corresponding revisions to the MRV Plan as necessary. Any long responses,
references, or supplemental information may be attached to the end of the table as an appendix. This table may be uploaded to the Electronic
Greenhouse Gas Reporting Tool (e-GGRT) in addition to any MRV Plan resubmissions.
No.
MRV Plan
EPA Questions
Responses
Section
Page
1.
7.2
33
'The total Mass of C02 injected will be the sum of the Mass of C02
received (RR-3) and Mass of C02 recycled (modified RR-5)."
According to 40 CFR 98.443(c)(3), "to aggregate injection data for all
wells covered under this subpart, you must sum the mass of all C02
injected through all injection wells in accordance with the
procedure specified in Equation RR-6 of this section." Equations
and variables cannot be modified from the regulations. Please
revise this section and ensure that all equations listed are consistent
with the text in 40 CFR 98.443 (https://www.ecfr.gov/current/title-
40/chapter-l/subchapter-C/part-98/subpart-RR#98.443)
Equation variables revised to comply with 40 CFR 98.443
2.
7.3
34
"CC02,p,w = C02 concentration measurement in flow for meter w
in quarter p (vol. percent C02, expressed as a decimal fraction)."
This variable should be "C02 concentration measurement in flow for
separator w in quarter p (vol. percent C02, expressed as a decimal
fraction)." Please revise this section and ensure that all equations and
variables listed are consistent with the text in 40 CFR 98.443
(https://www.ecfr.gov/current/title-40/chapter- l/subchapter-
Equation variables revised to comply with 40 CFR 98.443
C/part-98/subpart-RR#98.443).
-------
No.
MRV Plan
EPA Questions
Responses
Section
Page
3.
7.3
34
In the previous RFAI, the following was asked:
'"Xoil = Mass of entrained C02 in oil in the reporting year
measured utilizing commercial meters and electronic flow-
measurement devices at each point of custody transfer. The mass
of C02 will be calculated by multiplying the total volumetric rate
by the C02 concentration.'
In Equation RR-9, this variable is "X = Entrained C02 in produced oil
or other fluid divided by the C02 separated through all separators
in the reporting year (weight percent C02, expressed as a decimal
fraction)". Equations and variables cannot be modified from the
regulations. Please revise this section and ensure that all
equations listed are consistent with the text in 40 CFR 98.443
(httDs://www.ecfr.gov/current/title-40/chaDter- l/subchaoter-
C/Dart-98/subDart-RR#98.443)."
While the variable X was revised, the introductory text to Equation
RR-9 may not be consistent with this change:
"Equation RR-9 in 98.443 will be used to aggregate the mass of C02
produced net of the mass of C02 entrained in oil leaving the
Rangely Field prior to treatment of the remaining gas fraction in RCF
as follows:"
Please ensure that all text related to equation RR-9 is consistent
throughout the MRV plan.
Equation variables revised to comply with 40 CFR 98.443
-------
Scout Energy Management, LLC
Rangely Field
Subpart RR Monitoring, Reporting and Verification (MRV) Plan
January 2024
-------
Table of Contents
Roadmap to the Monitoring, Reporting and Verification (MRV) Plan 3
1. Facility Information 4
2. Project Description 4
2.1 Project Characteristics 4
2.2 Environmental Setting 6
2.3 Description of C02 EOR Project Facilities and the Injection Process 13
3. Delineation of Monitoring Area and Timeframes 19
3.1 Active Monitoring Area 19
3.2 Maximum Monitoring Area 20
3.3 Monitoring Timeframes 20
4. Evaluation of Potential Pathways for Leakage to the Surface 20
4.1 Introduction 21
4.2 Existing Wellbores 21
4.3 Faults and Fractures 23
4.4 Natural or Induced Seismicity 23
4.5 Previous Operations 23
4.6 Pipeline / Surface Equipment 23
4.7 Lateral Migration Outside the Rangely Field 24
4.8 Drilling Through the C02 Area 24
4.9 Diffuse Leakage through the Seal 25
4.10 Monitoring, Response, and Reporting Plan for C02 Loss 25
4.11 Summary 26
5. Monitoring and Considerations for Calculating Site Specific Variables 26
5.1 For the Mass Balance Equation 26
5.2 To Demonstrate that Injected C02 is not Expected to Migrate to the Surface 30
6. Determination of Baselines 30
7. Determination of Sequestration Volumes Using Mass Balance Equations 31
7.1. Mass of C02 Received 32
7.2 Mass of C02 Injected into the Subsurface 33
7.3 Mass of C02 Produced 33
7.4 Mass of C02 emitted by Surface Leakage 34
7.5 Mass of C02 sequestered in subsurface geologic formations 35
7.6 Cumulative mass of C02 reported as sequestered in subsurface geologic formations.. 35
8. MRV Plan Implementation Schedule 35
9. Quality Assurance Program 36
9.1 Monitoring QA/QC 36
9.2 Missing Data Procedures 37
9.3 MRV Plan Revisions 37
10. Records Retention 37
11. Appendices 37
Appendix 5. Well Identification Numbers 43
2
-------
Roadmap to the Monitoring, Reporting and Verification (MRV) Plan
Scout Energy Management, LLC (SEM) operates the Rangely Weber Sand Unit (RWSU) and the
associated Raven Ridge pipeline (RRPC), (collectively referred to as the Rangely Field) in Northwest
Colorado for the primary purpose of enhanced oil recovery (EOR) using carbon dioxide (C02) flooding.
SEM has utilized, and intends to continue to utilize, injected C02 with a subsidiary purpose of establishing
long-term containment of a measurable quantity of C02 in subsurface geological formations at the Rangely
Field for a term referred to as the "Specified Period." The Specified Period includes all or some portion of
the period 2023 to 2060. During the Specified Period, SEM will inject C02 that is purchased (fresh C02)
from ExxonMobil's (XOM) Shute Creek Plant or third parties, as well as C02 that is recovered (recycled
C02) from the Rangely Field's C02 Recycle and Compression Facilities (RCF's). SEM has developed this
monitoring, reporting, and verification (MRV) plan in accordance with 40 CFR §98.440-449 (Subpart RR)
to provide for the monitoring, reporting and verification of the quantity of C02 sequestered at the Rangely
Field during the Specified Period.
SEM has chosen to submit this MRV plan to the EPA for approval according to 40 Code of Federal
Regulations (CFR) 98.440(c)(1), Subpart RR of the Greenhouse Gas Reporting Program for the purpose
of qualifying for the tax credit in section 45Q of the federal Internal Revenue Code.
This MRV plan contains eleven sections:
o Section 1 contains general facility information.
o Section 2 presents the project description. This section describes the planned injection volumes, the
environmental setting of the Rangely Field, the injection process, and reservoir modeling. It also illustrates
that the Rangely Field is well suited for secure storage of injected C02.
o Section 3 describes the monitoring area: the RWSU in Colorado.
o Section 4 presents the evaluation of potential pathways for C02 leakage to the surface. The assessment
finds that the potential for leakage through pathways other than the man-made wellbores and surface
equipment is minimal.
o Section 5 describes SEM's risk-based monitoring process. The monitoring process utilizes SEM's reservoir
management system to identify potential C02 leakage indicators in the subsurface. The monitoring process
also utilizes visual inspection of surface facilities and personal H2S monitors program as applied to
Rangely Field. SEM's MRV efforts will be primarily directed towards managing potential leaks through
wellbores and surface facilities.
o Section 6 describes the baselines against which monitoring results will be compared to assess whether
changes indicate potential leaks.
o Section 7 describes SEM's approach to determining the volume of C02 sequestered using the mass
balance equations in 40 CFR §98.440-449, Subpart RR of the Environmental Protection Agency's (EPA)
Greenhouse Gas Reporting Program (GHGRP). This section also describes the site-specific factors
considered in this approach.
o Section 8 presents the schedule for implementing the MRV plan.
o Section 9 describes the quality assurance program to ensure data integrity.
o Section 10 describes SEM's record retention program.
o Section 11 includes several Appendices.
3
-------
1. Facility Information
The Rangely Gas Plant, operated by SEM and a part of the Rangely Field, reports under Greenhouse Gas
Reporting Program Identification number 537787.
The Colorado Oil and Gas Conservation Commission (COGCC)1 regulates all oil, gas and geothermal
activity in Colorado. All wells in the Rangely Field (including production, injection and monitoring wells) are
permitted by COGCC through Code of Colorado Regulations (CCR) 2 CCR 404-1:301. Additionally,
COGCC has primacy to implement the Underground Injection Control (UIC) Class II program in the state
for injection wells. All injection wells in the Rangely Field are currently classified as UIC Class II wells.
Wells in the Rangely Field are identified by name, API number, status, and type. The list of wells as of April,
2023 is included in Appendix 5. Any new wells will be indicated in the annual report.
2. Project Description
This section describes the planned injection volumes, environmental setting of the Rangely Field, injection
process, and reservoir modeling conducted.
2.1 Project Characteristics
SEM utilized historic production and injection of the RWSU in order to create a production and injection
forecast, included here to provide an overview of the total amounts of C02 anticipated to be injected,
produced, and stored in the Rangely Field as a result of its current and planned C02 EOR operations during
the forecasted period. This forecast is based on historic and predicted data. Figure 1 shows the actual
(historic) C02 injection, production, and stored volumes in the Rangely Field from 1986, when Chevron
initiated C02 flooding, through 2022 (solid line) and the forecast for 2023 through 2060 (dotted line). It is
important to note that this is just a forecast; actual storage data will be collected, assessed, and reported as
indicated in Sections 5, 6, and 7 in this MRV Plan. The forecast does illustrate, however, the large potential
storage capacity at Rangely field.
1 Pursuant to Colorado SB21-285, effective July 1, 2023, the COGCC will become the Energy and Carbon
Management Commission.
4
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Rangely Field
Historical and Projected C02
6000
T3
£
(O
LO
3
O
5000
ro
a>
>-
ai
a.
4000
3000
2000
1000
uvAV
C02 Production
try""
C02 Stored
Forecast C02 Stored
u v
JL
C02 Injection
Forecast C02 Injection
IDO^-OOINIDO^-OOINIDO^-OOINIDO^-OO
00CT>CT>CT>OO*H*H*H(N(Nr0r0r0^-^-L/lL/lL/l
aiaiaiaiooooooooooooooo
*H*H*H*H(N(N(N(N(N(N(N(N(N(N(N(N(N(N(N
Year
Figure 1 - Rangely Field Historic and Forecast C02 Injection, Production, and Storage 1986-2060
The amount of C02 injected at Rangely Field is adjusted periodically to maintain reservoir pressure and to
increase recovery of oil by extending or expanding the EOR project. The amount of C02 injected is the
amount needed to balance the fluids removed from the reservoir and to increase oil recovery. While the
model output shows C02 injection and storage through 2060, this data is for planning purposes only and
may not necessarily represent the actual operational life of the Rangely Field EOR project. As of the end
of 2022, 2,320,000 million standard cubic feet (MMscf) (122.76 million metric tons (MMMT)) of C02 has
been injected into Rangely Field. Of that amount, 1,540,000 MMscf (81.48 MMMT) was produced and
recycled.
While tons of C02 injected and stored will be calculated using the mass balance equations described in
Section 7, the forecast described above reflects that the total amount of C02 injected and stored over the
modeled injection period to be 967,000 MMscf (51.2 MMMT). This represents approximately 35.7% of the
theoretical storage capacity of Rangely Field.
Figure 2 presents the cumulative annual forecasted volume of C02 stored by year through 2060, the
modeling period forthe projection in Figure 1. The cumulative amount stored is equal to the sum of the annual
storage volume for each year plus the sum of the total of the annual storage volume for each previous year.
As is typical with C02 EOR operations, the rate of accumulation of stored C02 tapers overtime as more
recycled C02 is used for injection. Figure 2 illustrates the total cumulative storage overthe modeling period,
projected to be 967,000 MMscf (51.2 MMMT) of C02.
5
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Rangely Field
Historical and Forecast Cumulative C02 Storage
60
i-
(0
-------
Figure 3 - Regional map showing Rangely's position between the Uinta and Piceance Basin.
The reservoir, Weber Sands, is comprised of clean eolian quartz deposited in an erg (sand sea)
depositional environment. Internally, these dune sands are separated into six main packages (odd
numbers, 1 to 11) with the fluvial Maroon Formation (even numbers, 2 to 10) interfingering the field from
the north. The Weber Formation is underlain by the fossiliferous Desmoinesian carbonates of the Morgan
Formation, and overlain by the siltstones and shales of the Phosphoria/Park City and Moenkopi
Formations.
For the majority of the region, the Phosphoria Formation acts as an impermeable barrier above the
Weber Formation and is a hydrocarbon source for the overlying strata. However, due to the large thrust
fault south and west of the field, the Phosphoria Formation was driven down to significantly deeper
depths, and below the reservoir Weber sands, allowing for maturation and expulsion of the hydrocarbons
to migrate upward into stratigraphically older, but structurally shallower reservoirs sometime during the
Jurassic. At Rangely, the Phosphoria Formation is almost entirely missing above the Weber Formation,
but the Moenkopi Formation sits directly above the sands creating the seal for the petroleum system.
Fresh water in and around the town/field of Rangely is sourced from the quaternary creeks and rivers that
cut across the region (data obtained from the Colorado Division of Water Resources). No confined fresh
water aquifers are present between the reservoir rock and the surface. Safety measures are still taken to
protect the shallowest of rocks that contain rain water seepage (unconfined aquifer) into the Mancos
Formation (surface exposure at Rangely) illustrated by the surface casing on Figure 4. The shallowest
point of the reservoir is 5,486 ft below the surface (4,986 ft below any possible fresh rain water seepage).
The mere presence of hydrocarbons and the successful implication of a C02 flood indicates the quality
and effectiveness of the seal to isolate this reservoir from higher strata.
7
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Uinta Basin
Douglas Creek
Arch
Piceance Basin
ichesne River and Uinta Fms
CoKon Fm
Wasatch Fr
Wasatch and
Fort Union Fms
k I r_.
rm
Blackhawk Fm
Ferron Ss Mbr of Ma cos Sh and Frontu
Dakota Ss
Sue hem Cgl Mbr
Salt Wash Ss O O
Morrison Fm
O Entrada Ss O
Glen Canyon Ss
Cftnle Fm
Moenkep. Fm
Source
__ParY. City Fm
upper Weber Ss
Reservoir
Maroon
cr_ Fm
Round Valley Ls
Manning Canyon Sh
Doughnut Sh/Humbug Fm
Deseret Ls
Leadville Ls
Madison Ls
Pinyon.
-TfeniWU rf"
Dotsero Fm
Lodore Fm
Sawatch Ss
KEY
PETROLEUM
SYSTEMS:
I| Green River
system
I| Mesaverde
system
l| Mancos/Mowry
system
I| Phosphoria
system SOUTCe
Grassy Trail
° Creek oil
~ Mtnturn system
,, SignFficant oil production
{indicating source rock)
v./ Significant gas production
^ (indicating source rock)
S Source rocks
(R) Rangely Field
Main reservoir
I I Hiatus
Stratigraphy
at Rangely
Figure 4. Stratigraphic Column of formations at the Rangely Field. Due to a large fault the source
rock (Phosphoria) is stratigraphically above the reservoir rock (Weber), but structurally, the
source lies below the reservoir, (from U.S. Geological Survey, 2003)
Figure 5 shows the doubly plunging anticline with the long axis along a northwest-southeast trend and the
short axis along a northeast-southwest trend. In 1949 the depth of a gas cap was established at -330 ft
subsea and an Oil Water Contact (OWC) at -1150 ft subsea. Many core analysis suggest that below this -
1150' OWC is a transition/residual oil zone. However, for the purpose of this analysis and all volumetrics
8
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the base of the reservoir will be at the -1150' subsea depth determined in 1949.
Geologically, the Weber Sands were deposited on top of the Morgan formation which is a combination of
interbedded shale, siltstone, and cherty limestone. Few wells are drilled deep enough to penetrate the
Morgan formation within the Rangely Field to gather porosity/permeability data locally. However, analysis
of the Morgan formation from other fields/outcrops indicate that it is a non-reservoir rock (low
porosity/permeability), and would be sufficient as a basial barrier for the field. The highest subsurface
elevation of the base of the Weber Sands is deeper than the -1150' used for the OWC. Meaning injected
C02 should not encounter the Morgan formation. Additionally, Section 4.7 explains how the Rangely
Field is confined laterally through the nature of the anticline's structure.
Figure 5. Structure map of the Weber 1 (top of reservoir). Colors illustrate the maximum aerial
coverage of the Gas Cap (Red), Main Reservoir (Green), and Transitional Reservoir (Blue). Cross
section A-A' is predominantly along the long axis of the field and B-B' is along the short axis.
The Rangely Field has one main field fault (MFF) and numerous smaller faults (isolated and joint) and
fractures that are present throughout the stratigraphic column between the base of the Weber reservoir
and surface. Faults within the reservoir were measured by well-to-well displacement, while the fractures
were measured and observed as calcite veins on the surface with no displacement. The MFF has a NE-
WSWtrend and cuts through the reservoir interval. In the 1960's Rangely residents began experiencing
felt earthquakes. Between 1969 and 1973, a joint investigation with the USGS installed seismic
monitoring stations in and around the town of Rangely and began recording activity. In 1971, a study was
conducted to evaluate the stress state in the vicinity of the fault which determined a critical fluid pressure
above which fault slippage may occur. Reservoir pressure was then manipulated and correlated with
increases or decreases in seismic activity. This study determined that the waterflood in Rangely was
inducing seismicity when reservoir pressure was raised above ~3730 psi.
In the 1990's, field reservoir pressure had built back up leading to the largest magnitude earthquake in
9
-------
Rangely which took place in 1995 (M 4.5), shortly after maximum reservoir pressure was reached in
1998. Pressure maintenance began and seismic activity dropped off after lowering the average field
reservoir pressure down to ~3100 psi. No other seismic activity was recorded around the field until 2015
and 2017 when there was a total of 5 seismic events (see Figure 6) around the northeastern portion of
the MFF. A new interpretation from the 3D seismic revealed a series of previously unknown joint faults
(perpendicular to the MFF). Investigation into this region revealed that the ~3730 psi threshold had been
crossed and triggered the seismic events. Since the 2017 seismic events, no other events have been
recorded of felt magnitude and continued pressure monitoring further reduces the risk of another event.
2017 Induced
Seismic Study*
Figure 6. USGS fault history map (1900-2023). Largest earthquake was the 1995 M 4.5 north of the
unit (2017 was a study to induce seismic activity along the MFF, and not caused by day-to-day
operations)
The natural fractures found within the field play a significant role in fluid flow. The subsurface natural
fractures are vertical and show an approximately ENE trend and their extension joints are orientated ESE.
Shallower portions of the reservoir show a distinctly higher density of fractures than deeper portions. On
the shallow dipping sides of the anticline, there does not appear to be a strong structural control on
fracture density. Most well-to-well rapid breakthrough of injected C02 is along these ENE fractures. It is
unknown if this is from natural or induced fractures. There is no evidence that these natural fractures
diminish the seals integrity.
10
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Figure 7. Cross section A-A' along the long axis of the field, and perpendicular to the MRR. The
MFF does not have much displacement and is near vertical.
The Rangely Field has approximately 1.9 billion barrels of Original Oil in Place (OOIP). Since first
discovered in 1933, Rangely Field has produced 920 million barrels of oil, or 48% of the OOIP. The
Rangely Field has an aerial extent of approximately 19,150 acres with an average gross thickness of 650
ft. The previously mentioned 11 internal layers of the reservoir, alternating zones of Weber and Maroon
Formations, can be simplified to only three sections. The Upper Weber contains intervals 1-3, the Middle
Weber contains intervals 4-7, and the Lower Weber contains intervals 8-approxamently 50 ft below the
11D marker (identified by the base of the yellow in Figure 7). These interval groupings were determined
by the extensive lateral continuingiy and thickness of the Weber 4 and Weber 8 which easily separate the
reservoir into the three zones. For the majority of the Rangely Field, the even Maroon Formations act as
flow barriers between the odd Weber Formations. Average porosity within the Weber Sands dune fades
is 10.3% and within the Maroon fluvial fades is 4.9%. However, the key factor that enables the Maroon
Formation to be a seal is its lack of permeability. The Weber dune fades have an average permeability of
2.44 millidarcy (Md), while the Maroon fluvial fades have an average permeability of 0.03 Md.
owe -1150'
Transition Zone & ROZ
11
-------
Figure 8. Cross section B-B' along the short axis of the field and parallel to the MFF. Used to
illustrate the variation of the Oil Water Contact (OWC).
Given that the Rangely Field is located at the highest subsurface elevations of the structure, that the
confining zone has proved competent over both millions of years and throughout decades of EOR
operations, and that the Rangely Field has ample storage capacity, SEM is confident that stored CQ2 will
be contained securely within the Weber Sands in the Rangely Field.
2.2.2 Operational History of the Rangely Field
The Rangely Field was discovered in 1933 but subsequently ceased production until World War II when oil
returned to high demand. Intensive development began, expanding from one well to 478 wells by 1949. It
is located in the northwestern portion of Colorado.
The Rangely Field was originally developed by Chevron. Following the initial discover in 1933,
Chevron imitated a 40-acre development in 1944, followed by hydrocarbon gas injection from
1950 to 1969. To improve efficiency, in 1957, the RWSU was formed. The boundaries of the RWSU are
reflected in Figure 9.
Rangely Well List
^ Active-Producer
yf 0 TA- Producer
~ Active-Injector
A TA-Injector
T Active 5WD
Collection Station / Facility
¦ Collection Station
$ Compressor Station
X ¦ Rangely Facility
(££) Rangely Plant General
A West End Water Injection
N -Rangely Weber Unit
23^^ Rangely Weber Unit
1 "l1 Rangely Weber Unit Half Mile Buffer
Mdien Htl
BIO BIANG& COuWv
± i iu* vOJ /
A (t'li *A-A*AV
u -
v^aV S
\ »> i
v TLtw.}
- >. /./~ WA i * a
2X102W
'Rio Blanco-
Rdpgely OiStnet
Hospital Hetip&i
River
itf N)2W
Moffat
0/HICJ blAnCO CO0NTY
Uintah
Rio Blanco
Garfield
Figure 9 - Rangely Field Map
12
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Chevron began C02 flooding of the Rangely Field in 1986 and has continued and expanded it since that
time. The experience of operating and refining the Rangely Field C02 floods over the past decade has
created a strong understanding of the reservoir and its capacity to store C02.
2.3 Description of C02 EOR Project Facilities and the injection Process
Figures 10 shows a simplified flow diagram of the project facilities and equipment in the Rangely Field.
C02 is delivered to the Rangely Field via the Raven Ridge Pipeline. The CG2 injected into the Rangely
Field is currently supplied by XOM's Shute Creek Plant into the pipeline system.
Once C02 enters the Rangely Field there are four main processes involved in EOR operations. These
processes are shown in Figure 10 and include:
1. C02 Distribution and Injection. Purchased C02 and recycled C02 from the RCF is sent through the main
C02 distribution system to various C02 injectors throughout the Field.
2. Produced Fluids Handling. Produced fluids gathered from the production wells are sent to collection
stations for separation into a gas/C02 mix and a produced fluids mix of water, oil, gas, and C02. The
produced fluids mix is sent to centralized water plants where oil is separated for sale into a pipeline, water
is recovered for reuse, and the remaining gas/C02 mix is merged with the output from the collection
stations. The combined gas/C02 mix is sent to the RCF and natural gas liquids (NGL) Plant. Produced oil
is metered and sold; water is forwarded to the water injection plants fortreatment and reinjection or disposal.
3. Produced Gas Processing. The gas/C02 mix separated at the satellite batteries goes to the RCF and
NGL Plant where the NGLs, and C02 streams are separated. The NGLs move to a commercial pipeline for
sale. The remaining C02 (e.g., the recycled C02) is returned to the C02 distribution system for reinjection.
4. Water Treatment and Injection. Water separated in the tank batteries is processed at water plants to
remove any remaining oil and then distributed throughout the Rangely Field for reinjection.
LaBarge Field/
Shute Creek Plant
Field and plant owned and
operated by ExxonMobil
Raven Ridge
Pipeline
123 mile, 16" steel pipeline
(200 MMcfd capacity)
56% CRRPC owned
(T) Rangely Field
Dehydration & NGL Extraction
RCF
1st/2nd Stage
Compression
Gasjt-,
A Custody Transfer Point for Assets
~ CO? Measurement Points
RCF
3rd/ 4th Stage
Compression
Oil/Water Liquids Liquid/Gas
Separation & ¦« Inlet
Water Plants Separation
Water T water] |_
Gas/Water
Injection
Wells
Water
Disposal
Wells
-f
Producing
Wells
Surface
Navajo Formation
COj +
Water +
Natural Gas
Oil
~ Natural Gas / NGL
+ Water
+ CO,
Weber Sands Reservoir
yv.
Figure 10 Rangely Field -General Production Flow Diagram
13
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2.3.1 C02 Distribution and Injection.
SEM purchases C02 from XOM and receives it via the Raven Ridge Pipeline through one custody transfer
metering point, as indicated in Figures 10. Purchased C02 and recycled C02 are sent through the C02
trunk lines to multiple distribution lines to individual injection wells. There are volume meters at the inlet and
outlet of the C02 Reinjection Facility.
As of April 2023, SEM has approximately 280 injection wells in the Rangely Field. Approximately 160 MMscf
of C02 is injected each day, of which approximately 15% is purchased C02, and the balance (85%) is
recycled. The ratio of purchased C02 to recycled C02 is expected to change overtime, and eventually the
percentage of recycled C02 will increase and purchases of fresh C02 will taper off as indicated in Section
2.1.
Each injection well is connected to a water alternating gas (WAG) manifold located at the well pad. WAG
manifolds are manually operated and can inject either C02 or water at various rates and injection pressures
as specified in the injection plans. The length of time spent injecting each fluid is a matter of continual
optimization that is designed to maximize oil recovery and minimize C02 utilization in each injection pattern.
A WAG manifold consists of a dual-purpose flow meter used to measure the injection rate of water or C02,
depending on what is being injected. Data from these meters is sent to the Supervisory Control and Data
Acquisition (SCADA) system where it is compared to the injection plan forthat well. As described in Sections
5 and 7, data from the WAG manifolds, visual inspections of the injection equipment, and use of the
procedures contained in 40 CFR §98.230-238 (Subpart W), will be gathered to complete the mass balance
equations necessary to determine annual and cumulative volumes of stored C02.
2.3.2 Wells in the Rangely Field
As of April 2023, there are 662 active wells that are completed in the Rangely Field, with roughly 40%
injection wells and 60% producing wells, as indicated in Figure 11,2 Table 1 shows these well counts in the
Rangely Field by status.
2 Wells that are not in use are deemed to be inactive, plugged and abandoned, temporarily abandoned, or shut in.
14
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Rangely Well List
# Active-Producer
TA-Producer
A Active-Injector
A TA-Injector
~ Active SWD
Rangely Weber Unit
I I Rangely Weber Unit
2N 103W
Metier Hill
00 RIO PLAN (9S COUN»7
2N 102W
.Rio Blanco
Ji) Rpven I
ftrfcjr li
Heliport
Moffat
I'tgely District
Vpitof Heppaf'
1N 102W
0RIO BLANCO CQ18NTY
Rio Blanco
iarfield
Figure 11 Rangely Field Wells - As of April 2023
Table 1 - Rangely Field Wells
<\ge/Completion of Well
Active
Shut-in
Temporarily
Abandoned
Plugged and
Abandoned
Drilled & Completed in the
1940's
265
5
55
149
Drilled 1950-1985
297
7
55
46
Completed after 1986
103
1
11
8
TOTAL
665
13
121
203
The wells in Table 1 are categorized in groups that relate to age and completion methods. Roughly 48%
of these wells were drilled in the 1940's and were generally completed with three strings of casing (with
surface and intermediate strings typically cemented to the surface). The production string was typically
installed to the top of the producing interval, otherwise known as the main oil column (MOC), which
extends to the producible oil/water contact (POWC). These wells were completed by stimulating the open
hole (OH), and are not typically cased through the MOC. While implementing the water flood from 1958-
1986, a partial liner would have been typically installed to allow for controlled injection intervals and this
liner would have been cemented to the top of the liner (TOL) that was installed. For example, a partial
liner would be installed from 5,700-6,500 ft, and the TOC would be at 5,700 ft. The casing weights used
15
-------
for the production string have varied between 7" 23 & 26#/ft. with 5" 18 #/ft. for the production liner.
The wells in Table 1 drilled during the period 1950-1986 typically were cased through the production
interval with 7" casing. Some wells were completed with 7" casing to the top of the MOC and then
completed with a 5" liner through the productive interval. The wells with liners were cemented to the TOL.
The remaining wells (roughly 12%) in Table 1 were drilled after 1986 when the C02 flood began. All of
these wells were completed with 7" casing through the POWC. Very few of these wells have experienced
any wellbore issues that would dictate the need for a remedial liner.
SEM reviews these categories along with full wellbore history when planning well maintenance projects.
Further, SEM keeps well workover crews on call to maintain all active wells and to respond to any
wellbore issues that arise. On average, in the Rangely Field there are two to three incidents per year in
which the well casing fails. SEM detects these incidents by monitoring changes in the surface pressure of
wells and by conducting Mechanical Integrity Tests (MITs), as explained later in this section and in the
relevant regulations cited. This rate of failure is less than 2% of wells per year and is considered
extremely low.
All wells in oilfields, including both injection and production wells described in Table 1, are regulated by
the COGCC under COGCC 100-1200 series rules. A list of wells, with well identification numbers, is
included in Appendix 5. The injection wells are subject to additional requirements promulgated by EPA -
the UIC Class II program - implementation of which has been delegated to the COGCC.
COGCC rules govern well siting, construction, operation, maintenance, and closure for all wells in oilfields.
Current rules require, among other provisions, that:
Class II UIC Wells will not be permitted in areas where they would inject into a formation that is
separated from any Underground Source of Drinking Water by a Confining Layer with known open
faults or fractures that would allow flow between the Injection Zone and Underground Source of Drinking
Water within the area of review.
Injection Zones will not be permitted within 300 feet in a vertical dimension from the top of any
Precambrian basement formation.
An Operator will not inject any Fluids or other contaminants into a UIC Aquifer that meets the
definition of an Underground Source of Drinking Water unless EPA has approved a UIC Aquifer
exemption as described in Rule 802.e.
In addition, SEM implements a corrosion protection program to protect and maintain the steel used in
injection and production wells from any C02-enriched fluids. SEM currently employs methods to mitigate
both internal and external corrosion of casing in wells in the Rangely Field. These methods generally protect
the downhole steel and the interior and exterior of wellbores through the use of special materials (e.g.
fiberglass tubing, corrosion resistant cements, nickel plated packers, corrosion resistant packer fluids) and
procedures (e.g. packer placement, use of annular leakage detection devices, cement bond logs, pressure
tests). These measures and procedures are typically included in the injection orders filed with the COGCC.
Corrosion protection methods and requirements may be enhanced overtime in response to improvements
in technology.
MIT
SEM complies with the MIT requirements implemented by COGCC and BLM to periodically inspect wells
and surface facilities to ensure that all wells and related surface equipment are in good repair and leak-
free, and that all aspects of the site and equipment conform with Division rules and permit conditions. All
active injection wells undergo an MIT at the following intervals:
Before injection operations begin
16
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Every 5 years as stated in the injection orders (COGCC 417.a. (1))
After any casing repair
After resetting the tubing or mechanical isolation device
Or whenever the tubing or mechanical isolation device is moved during workover operations
COGCC requires that the operator notify the COGCC district office prior to conducting an MIT. Operators
are required to use a pressure recorder and pressure gauge for the tests. The operator's field representative
must sign the pressure recorder chart along with the COGCC field representative and submit it with the MIT
form. The casing-tubing annulus must be tested to a minimum of 1200 psi for 15 minutes.
If a well fails an MIT, the operator must immediately shut the well in and provide notice to COGCC. Casing
leaks must be successfully repaired and retested or the well plugged and abandoned after submitting a
formal notice and obtaining approval from the COGCC.
Any well that fails an MIT cannot be returned to active status until it passes a new MIT
2.3.3 Produced Fluids Handling
As injected C02 and water move through the reservoir, a mixture of oil, gas, and water ("produced fluids")
flows to the production wells. Gathering lines bring the produced fluids from each production well to
collection stations. SEM has approximately 382 active production wells in the Rangely Field and production
from each is sent to one of 27 collection stations. Each collection station consists of a large vessel that
performs a gas - liquid separation. Each collection station also has well test equipment to measure
production rates of oil, water and gas from individual production wells. SEM has testing protocols for all
wells connected to a collection station. Most wells are tested twice per month. Some wells are prioritized
for more frequent testing because they are new or located in an important part of the Field; some wells with
mature, stable flow do not need to be tested as frequently; and finally, some wells will periodically need
repeat testing due to abnormal test results.
After separation, the gas phase is transported by pipeline to the C02 reinjection facility for processing as
described below. Currently the average composition of this gas mixture as it enters the facility is 92% C02
and 800ppm H2S; this composition will change overtime as C02 EOR operations mature.
The liquid phase, which is a mixture of oil and water, is sent to one of two centralized water plants where
oil is separated from water via two 3-phase separators. The water is then sent to water holding tanks where
further separation is done.
The separated oil is metered through the Lease Automatic Custody Transfer (LACT) unit located at the
custody transfer point between Chevron pipeline and SEM. The oil typically contains a small amount of
dissolved or entrained C02. Analysis of representative samples of oil is conducted once a year to assess
C02 content.
The water is removed from the bottom of the tanks at the water injection stations, where it is re-injected to
the WAG injectors.
Any gas that is released from the liquid phase rises to the top of the tanks and is collected by a Vapor
Recovery Unit (VRU) that compresses the gas and sends it to the C02 reinjection facility for processing.
17
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Rangely oil is slightly sour, containing small amounts of hydrogen sulfide (H2S), which is highly toxic. There
are approximately 25 workers on the ground in the Rangely Field at any given time, and all field personnel
are required to wear H2S monitors at all times. Although the primary purpose of H2S detectors is protecting
employees, monitoring will also supplement SEM's C02 leak detection practices as discussed in Sections
5 and 7.
In addition, the procedures in 40 CFR §98.230-238 (Subpart W) and the two-part visual inspection process
described in Section 5 are used to detect leakage from the produced fluids handling system. As described
in Sections 5 and 7, the volume of leaks, if any, will be estimated to complete the mass balance equations
to determine annual and cumulative volumes of stored C02.
2.3.4 Produced Gas Handling
Produced gas gathered from the collection stations, and water injection plants is sent to the C02 recycling
and compression facility. There is an operations meter at the facility inlet.
Once gas enters the C02 reinjection facility, it undergoes dehydration and compression. In the RWSU an
additional process separates NGLs for sale. At the end of these processes there is a C02 rich stream that
is recycled through re-injection. Meters at the C02 recycling and compression facility outlet are used to
determine the total volume of the C02 stream recycled back into the EOR operations.
As described in Section 2.3.4, data from 40 CFR §98.230-238 (Subpart W), the two-part visual inspection
process for production wells and areas described in Section 5, and information from the personal H2S
monitors are used to detect leakage from the produced gas handling system. This data will be gathered to
complete the mass balance equations necessary to determine annual and cumulative volumes of stored
C02 as described in Sections 5 and 7.
2.3.5 Water Treatment and Injection
Produced water collected from the collection stations is gathered through a pipeline system and moved to
one of two water injection plants. Each facility consists of 3-Phase separators and 79,500-barrels of
separation tanks where any remaining oil is skimmed from the water. Skimmed oil is combined with the oil
from the 3-Phase separators and sent to the LACT. The water is sent to an injection pump where it is
pressurized and distributed to the WAG injectors.
2.3.6 Facilities Locations
The current locations of the various facilities in the Rangely Field are shown in Figure 13. As indicated
above, there are two central water plants. There are twenty-seven collections stations that gather
production from surrounding wells. The two water plants are identified by the blue triangle and circle. The
twenty-seven collection stations are identified by red squares. The C02 Reinjection facility is indicated by
the green circle.
18
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Collection Station / Facility
I Collection Station
Compressor Station
¦ Rangely Facility
(££) Rangely Plant General
A West End Water Injection
Rangely Weber Unit
Rangely Weber Unit
" Men Hill
06 RIO BIANCSS COUN-1
Collection
Station 01
Collection
Station 03
Collection
Station 10m
,Rio Blanco
Collection
Station 08
Collection
2N 103W
Collection.^
Station 04
Collection
Station 20 2N 1021
Station 12
Collection
Station 05
Collection
Station 11
Collection
Station 27
West
End Water
Injection
Collection
Station 16
Heliport
Collection
Station 22
Collection Co"ec^,tV,
Station stat'°109
Collection
Station 17
Collection
Station 33
Collection
Station 28«
Collection
Station 29
Collection
Station 13
vCollection
Station 18 Main
¦ Treatment
I 37
Rangely [¦]
Plant ¦¦ Collection Collection
General Station 19 Station 24
Collection
Station 34
Collection
Station 30
Collection
Station 39
Collection
_Station_47_
Moffat
Rangely District
MOSfiittOi' HfiipOti
1N 102W
Uintah
ORIOi BLANCO CQBNTY
Rio Blanco
Garfield
Miles
Figure 13 Location of Surface Facilities at Rangely Field
3. Delineation of Monitoring Area and Timeframes
The current active monitoring area (AMA), future AMA and monitoring time frame of the AMA are
described below. Additionally, the maximum monitoring area (MMA) of the free phase C02 plume, its
buffer zone and the monitoring time frame for the MMA are described below.
3.1 Active Monitoring Area
Because C02 is present throughout the Rangely Field and retained within it, the Active Monitoring Area
(AMA) is defined by the boundary of the Rangely Field plus one-half mile buffer. This boundary is defined
in Figure 9. The following factors were considered in defining this boundary:
Free phase C02 is present throughout the Rangely Field: More than 2,320,000 MMscf (122.76 MMMT)
tons of C02 have been injected and recycled throughout the Rangely Field since 1986 and there has
been significant infill drilling in the Rangely Field, completing additional wells to further optimize
production. Operational results thus far indicate that there is C02 throughout the Rangely Field.
C02 injected into the Rangely Field remains contained within the Rangely Field AMA because of the
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fluid and pressure management results associated with C02 EOR. The maintenance of an IWR of 1.0
assures a stable reservoir pressure; managed lease line injection and production wells are used to
retain fluids in the Rangely Field as indicated in Section 4.7. Implementation of these methods over the
past decades have successfully contained C02 within the Rangely Field.
It is highly unlikely that injected C02 will migrate downdip and laterally outside the Rangely Field
because of the nature of the geology and the approach used for injection. As indicated in Section
2.2.1 "Geology of the Rangely Field," the Rangely Field is situated at the top of a dome structural
trap, with all directions pointing down-dip from the highest point. This means that over long periods of
time, injected C02 will tend to rise vertically towards the point in the Rangely Field with the highest
elevation.
Forecasted C02 injection volumes, shown in Figure 1, represent SEM's plan to not increase current
injection volumes and maintain an IWR of 1. Operations will not expand beyond the currently active C02-
EOR portion of the Rangely Field; therefore, the AMA is not expected to increase. Should such
expansions occur, they will be reported in the Subpart RR Annual Report for the Rangely Field, as
required by section 98.446.
3.2 Maximum Monitoring Area
The Maximum Monitoring Area (MMA) is defined in 40 CFR §98.440-449 (Subpart RR) as equal or greater
than the area expected to contain the free-phase C02 plume until the C02 plume has stabilized, plus an all-
around buffer zone of one-half mile. Section 3.1 states that the maximum extent of the injected C02 is expected
to be bounded by the Rangely Field Unit boundary shown in Figure 9. Therefore, the MMA is the Rangely Field
Unit boundary plus the one-half mile buffer as required by 40 CFR §98.440-449 (Subpart RR).
3.3 Monitoring Timeframes
SEM's primary purpose for injecting C02 is to produce oil that would otherwise remain trapped in the
reservoir and not, as in UIC Class VI, "specifically for the purpose of geologic storage."3 During a Specified
Period, SEM will have a subsidiary purpose of establishing the long-term containment of a measurable
quantity of C02 in the Weber Sands in the Rangely Field. The Specified Period will be shorter than the
period of production from the Rangely Field. This is in part because the purchase of new C02 for injection
is projected to taper off significantly before production ceases at Rangely Field, which is modeled through
2060. At the conclusion of the Specified Period, SEM will submit a request for discontinuation of reporting.
This request will be submitted when SEM can provide a demonstration that current monitoring and model(s)
show that the cumulative mass of C02 reported as sequestered during the Specified Period is not expected
to migrate in the future in a manner likely to result in surface leakage. It is expected that it will be possible to
make this demonstration within two to three years after injection for the Specified Period ceases based upon
predictive modeling supported by monitoring data. The demonstration will rely on two principles: 1) that just
as is the case for the monitoring plan, the continued process of fluid management during the years of C02
EOR operation after the Specified Period will contain injected fluids in the Rangely Field, and 2) that the
cumulative mass reported as sequestered during the Specified Period is a fraction of the theoretical storage
capacity of the Rangely Field See 40 C.F.R. § 98.441 (b)(2)(ii).
4. Evaluation of Potential Pathways for Leakage to the Surface
3 EPA UIC Class VI rule, EPA 75 FR 77291, December 10, 2010, section 146.81(b).
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4.1 Introduction
In the 90 years since the Rangely Field was discovered in 1933, extensive reservoir monitoring and
studies were performed. Based on the knowledge gained from historical practices, this section assesses
the following potential pathways for leakage of C02 to surface within Rangely Field.
Existing Wellbores
Faults and Fractures
Natural and Induced Seismic Activity
Previous Operations
Pipeline/Surface Equipment
Lateral Migration Outside the Rangely Field
Drilling Through the C02 Area
Diffuse Leakage Through the Seal
Detailed analysis of these potential pathways concluded that existing wellbores and pipeline/surface
equipment pose the only meaningful potential leakage pathways. Operating pressures are not expected
to increase overtime, therefore there is not a specific time period that would increase the likelihood of
pathways for leakage. SEM identifies these potential pathways for C02 leakage to be low risk, i.e., less
than 1% given the extensive operating history and monitoring program currently in place.
The monitoring program to detect and quantify leakage is based on the assessment discussed below.
4.2 Existing Wellbores
As of April 2023, there are approximately 662 active SEM operated wells in the Rangely Field - split roughly
evenly between production and injection wells. In addition, there are approximately 135 wells not in use, as
described in Section 2.3.2.
Leakage through existing wellbores is a potential risk at the Rangely Field that SEM works to prevent by
adhering to regulatory requirements for well drilling and testing; implementing best practices that SEM has
developed through its extensive operating experience; monitoring injection/production performance,
wellbores, and the surface; and maintaining surface equipment.
As discussed in Section 2.3.2, regulations governing wells in the Rangely Field require that wells be
completed and operated so that fluids are contained in the strata in which they are encountered and that
well operation does not pollute subsurface and surface waters. The regulations establish the requirements
that all wells (injection, production, disposal) must comply with. Depending upon the purpose of a well, the
requirements can include additional standards for evaluation and MIT. SEM's best practices include pattern
level analysis to guide injection pressures and performance expectations; utilizing diverse teams of experts
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to develop EOR projects based on specific site characteristics; and creating a culture where all field
personnel are trained to look for and address issues promptly. SEM's practices, which include corrosion
prevention techniques to protect the wellbore as needed, as discussed in Section 2.3.2, ensures that well
completion and operation procedures are designed not only to comply with regulations but also to ensure
that all fluids (e.g., oil, gas, C02) remain in the Rangely Field until they are produced through an SEM well.
As described in Section 5, continual and routine monitoring of SEM's wellbores and site operations will be
used to detect leaks, including those from non-SEM wells, or other potential well problems, as follows:
Well pressure in injection wells is monitored on a continual basis. The injection plans for each pattern
are programmed into the injection WAG controller, as discussed in Section 2.3.1, to govern the rate and
pressure of each injector. Pressure monitors on the injection wells are programmed to flag pressures
that significantly deviate from the plan. Leakage on the inside or outside of the injection wellbore would
affect pressure and be detected through this approach. If such excursions occur, they are investigated
and addressed. In the time SEM has operated the Rangely Field, there have been no C02 leakage
events from a wellbore.
In addition to monitoring well pressure and injection performance, SEM uses the experience gained
overtime to strategically approach well maintenance. SEM maintains well maintenance and workover
crews onsite for this purpose. For example, the well classifications by age and construction method
indicated in Table 1 inform SEM's plan for monitoring and updating wells. SEM uses all of the
information at hand including pattern performance, and well characteristics to determine well
maintenance schedules.
Production well performance is monitored using the production well test process conducted when
produced fluids are gathered and sent to a collection station. There is a routine cycle for each collection
station, with each well being tested approximately twice every month. During this cycle, each production
well is diverted to the well test equipment for a period of time sufficient to measure and sample produced
fluids (generally 24 hours). This test allows SEM to allocate a portion of the produced fluids measured
at the collection station to each production well, assess the composition of produced fluids by location,
and assess the performance of each well. Performance data are reviewed on a routine basis to ensure
that C02 flooding is optimized. If production is off plan, it is investigated and any identified issues
addressed. Leakage to the outside of production wells is not considered a major risk because of the
reduced pressure in the casing. Further, the personal H2S monitors are designed to detect leaked fluids
around production wells.
Finally, as indicated in Section 5, field inspections are conducted on a routine basis by field personnel.
On any day, SEM has approximately 25 personnel in the field. Leaking C02 is very cold and leads to
formation of bright white clouds and ice that are easily spotted. All field personnel are trained to identify
leaking C02 and other potential problems at wellbores and in the field. Any C02 leakage detected will
be documented and reported, quantified and addressed as described in Section 5.
Based on its ongoing monitoring activities and review of the potential leakage risks posed by wellbores,
SEM concludes that it is mitigating the risk of C02 leakage through wellbores by detecting problems as
they arise and quantifying any leakage that does occur. Section 4.10 summarizes how SEM will monitor
C02 leakage from various pathways and describes how SEM will respond to various leakage scenarios.
In addition, Section 5 describes how SEM will develop the inputs used in the Subpart RR mass-balance
equation (Equation RR-11). Any incidents that result in C02 leakage up the wellbore and into the
atmosphere will be quantified as described in Section 7.4.
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4.3 Faults and Fractures
After reviewing geologic, seismic, operating, and other evidence, SEM has concluded that there are no
known faults or fractures that transect the entirety of the Weber Sands in the project area. As described in
Section 2.2.1, the MFF is present below the reservoir and terminates within the Weber Sands without
breaching the upper seal. Additional faults have been identified in formations that are stratigraphically below
the Weber Sands, but this faulting has been shown not to affect the Weber Sands or to have created
potential leakage pathways given that they do not contact the Upper Pennsylvanian or Permian strata
(Weber Fm.).
SEM has extensive experience in designing and implementing EOR projects to ensure injection pressures
will not damage the oil reservoir by inducing new fractures or creating shear. As a safeguard, injection
satellites are set with automatic shutoff controls if injection pressures exceed fracture pressures.
4.4 Natural or Induced Seismicity
After reviewing literature and historic data, SEM concludes that there is no direct evidence that natural
seismic activity poses a significant risk for loss of C02 to the surface in the Rangely Field. Natural seismic
events are derived from the thrust fault to the west. Historically, Figure 6 in section 2.2.1 shows nine (9)
seismic events outside of the Rangely Field (including the 1993 M 3.5 event). The epicenter of these
earthquakes was far below the operating depths of the Rangely Field, and are associated with the thrust
fault to the west of the field. The operations of Rangely have zero impact on this thrust fault. Natural
earthquakes are not predictable, but these do not pose a threat to current operations. This is evidenced by
the fact that hydrocarbons are still within the anticline, meaning that there have been no major seismic
events in the last few million years capable of releasing these hydrocarbons to the surface.
Induced seismic events (non-natural) are tied to the MFF and its joint faults. These can be impacted by
Rangely Field operations. Section 2.2.1 explains how an increase in reservoir pressure can trigger seismic
events along and near the MFF. To prevent this from occurring bottom hole pressure surveys are collected
one (1) to two (2) times per year across the Rangely Field helping to monitor pressure changes along across
the Rangely Field. By keeping reservoir pressure from exceeding the threshold of ~3730 psi for extended
periods of time (multiple years), induced seismic events can be greatly mitigated. In the case that reservoir
pressures do exceed the threshold pressure, a reduction in injected volumes in the vicinity will bring down
the pressures back down gradually over a period of time.
4.5 Previous Operations
Chevron initiated C02 flooding in the Rangely Field in 1986. SEM and the prior operators have kept records
of the site and have completed numerous infill wells. SEM has not drilled any new wells in Rangely to date
but their standard practice for drilling new wells includes a rigorous review of nearby wells to ensure that
drilling will not cause damage to or interfere with existing wells. SEM will also follow AOR requirements
under the UIC Class II program, which require identification of all active and abandoned wells in the AOR
and implementation of procedures that ensure the integrity of those wells when applying for a permit for any
new injection well. These practices ensure that identified wells are sufficiently isolated and do not interfere
with the C02 EOR operations and reservoir pressure management. Consequently, SEM's operational
experience supports the conclusion that there are no unknown wells within the Rangely Field that penetrate
the Weber Sands and that it has sufficiently mitigated the risk of migration from older wells.
4.6 Pipeline / Surface Equipment
Damage to or failure of pipelines and surface equipment can result in unplanned losses of C02. SEM
reduces the risk of unplanned leakage from surface facilities, to the maximum extent practicable, by relying
on the use of prevailing design and construction practices and maintaining compliance with applicable
regulations. The facilities and pipelines currently utilize and will continue to utilize materials of construction
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and control processes that are standard for C02 EOR projects in the oil and gas industry. As described
above, all facilities in the Rangely Field are internally screened for proximity to the public. In the case of
pipeline and surface equipment, best engineering practices call for more robust metallurgy in wellhead
equipment, and pressure transducers with low pressure alarms monitored through the SCADA system to
prevent and detect leakage. Operating and maintenance practices currently follow and will continue to follow
demonstrated industry standards. C02 delivery via the Raven Ridge pipeline system will continue to
comply with all applicable regulations. Finally, frequent routine visual inspection of surface facilities by field
staff will provide an additional way to detect leaks and further support SEM's efforts to detect and remedy
any leaks in a timely manner. Should leakage be detected from pipeline or surface equipment, the volume
of released C02 will be quantified following the requirements of Subpart W of EPA's GHGRP.
4.7 Lateral Migration Outside the Rangely Field
It is highly unlikely that injected C02 will migrate downdip and laterally outside the Rangely Field because of
the nature of the geology and the approach used for injection. First, as indicated in Section 2.2.1 "Geology
of the Rangely Field," the Rangely Field is situated at the top of a dome structural trap, with all directions
pointing down-dip from the highest point. This means that over long periods of time, injected C02 will tend
to rise vertically towards the point in the Rangely Field with the highest elevation. Second, the planned
injection volumes and active fluid management during injection operations will prevent C02 from migrating
laterally stratigraphically (down-dip structurally) out of the structure. Finally, SEM will not be increasing the
total volume of fluids in the Rangely Field.
COGCC requires that injection pressures be limited to ensure injection fluids do not migrate outside the
permitted injection interval. In the Rangely Field, SEM uses two methods to contain fluids: reservoir
pressure management and the careful placement and operation of wells along the outer producing limits of
the units.
Reservoir pressure in the Rangely Field is managed by maintaining an injection to withdrawal ratio (IWR)
of approximately 1.0. To maintain the IWR, SEM monitors fluid injection to ensure that reservoir pressure
does not increase to a level that would fracture the reservoir seal or otherwise damage the oil field.
SEM also prevents injected fluids from migrating out of the injection interval by keeping injection pressure
below the formation fracture pressure, which is measured using historic step-rate tests. In these tests,
injection pressures are incrementally increased (e.g., in "steps") until injectivity increases abruptly, which
indicates that an opening or fracture has been created in the rock. SEM manages its operations to ensure
that injection pressures are kept below the formation fracture pressure so as to ensure that the valuable
fluid hydrocarbons and C02 remain in the reservoir.
There are a few small producer wells operated by third parties outside the boundary of Rangely Field. There
are currently no significant commercial operations surrounding the Rangely Field to interfere with SEM's
operations.
Based on site characterization and planned and projected operations SEM estimates the total volume of
stored C02 will be approximately 35.7% of calculated capacity.
4.8 Drilling Through the C02 Area
It is possible that at some point in the future, drilling through the containment zone into the Weber Sands
could occur and inadvertently create a leakage pathway. SEM's review of this issue concludes that this risk
is very low for two reasons. First, SEM's visual inspection process, including routine site visits, is designed
to identify unapproved drilling activity in the Rangely Field. Second, SEM plans to operate the C02 EOR
flood in the Rangely Field for several more years, and will continue to be vigilant about protecting the
integrity of its assets and maximizing the potential of resources (oil, gas, C02). In the unlikely event SEM
would sell the field to a new operator, provisions would result in a change to the reporting program and
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would be addressed at that time.
4.9 Diffuse Leakage through the Seal
Diffuse leakage through the seal formed by the Moenkopi Formation is highly unlikely. The presence of a
gas cap trapped over millions of years as discussed in Section 2.2.3 confirms that the seal has been
secure for a very long time. Injection pattern monitoring program referenced in Section 2.3.1 and detailed
in Section 5 assures that no breach of the seal will be created. The seal is highly impermeable where
unperforated, cemented across the horizon where perforated by wells, and unexplained changes in
injection pressure would trigger investigation as to the cause. Further, if C02 were to migrate through the
Moenkopi seal, it would migrate vertically until it encountered and was trapped by any of the numerous
shallower shale seals
4.10 Monitoring, Response, and Reporting Plan for C02 Loss
As discussed above, the potential sources of leakage include fairly routine issues, such as problems with
surface equipment (pumps, valves, etc.) or subsurface equipment (wellbores), and unique events such as
induced fractures. Table 3 summarizes some of these potential leakage scenarios, the monitoring activities
designed to detect those leaks, SEM's standard response, and other applicable regulatory programs
requiring similar reporting.
Sections 5.1.5 - 5.1.7 discuss the approaches envisioned for quantifying the volumes of leaked C02. Given
the uncertainty concerning the nature and characteristics of leaks that will be encountered, the most
appropriate methods for quantifying the volume of leaked C02 will be determined at the time. In the event
leakage occurs, SEM plans to determine the most appropriate methods for quantifying the volume leaked
and will report it as required as part of the annual Subpart RR submission.
Any volume of C02 detected leaking to surface will be quantified using acceptable emission factors such
as those found in 40 CFR Part 98 Subpart W or engineering estimates of leak amounts based on
measurements in the subsurface, SEM's field experience, and other factors such as the frequency of
inspection. As indicated in Sections 5.1 and 7.4, leaks will be documented, evaluated and addressed in a
timely manner. Records of leakage events will be retained in the electronic environmental documentation
and reporting system. Repairs requiring a work order will be documented in the electronic equipment
maintenance system.
Table 3 Response Plan for C02 Loss
Risk
Monitoring Plan
Response Plan
Parallel
Reporting (if
any)
Loss of Well Control
Tubing Leak
Monitor changes in tubing and
annulus pressure; MIT for injectors
Well is shut in and
Workover crews respond
within days
COGCC
Casing Leak
Routine Field inspection; monitor
changes in annulus pressure; MIT for
injectors; extra attention to high risk
wells
Well is shut in and
Workover crews respond
within days
COGCC
Wellhead Leak
Routine Field inspection
Well is shut in and
Workover crews respond
within days
COGCC
Loss of Bottom-
hole
pressure control
Blowout during well operations
Maintain well kill
procedures
COGCC
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Unplanned wells
drilled through
Weber Sands
Routine Field inspection to
prevent unapproved drilling;
compliance with COGCC permitting
for planned wells.
Assure compliance with
COGCC regulations
COGCC
Permitting
Loss of seal in
abandoned wells
Reservoir pressure in monitor wells;
high pressure found in new wells
Re-enter and reseal
abandoned wells
COGCC
Leaks in Surface Facilities
Pumps, valves, etc.
Routine Field inspection; SCADA
Maintenance crews
respond within days
Subpart W
Subsurface Leaks
Leakage along
faults
Reservoir pressure in monitor wells;
high pressure found in new wells
Shut in injectors near
faults
-
Overfill beyond
spill
points
Reservoir pressure in monitor wells;
high; pressure found in new wells
Fluid management
along
lease lines
-
Leakage through
induced fractures
Reservoir pressure in monitor wells;
high pressure found in new wells
Comply with rules for
keeping pressures
below
parting pressure
-
Leakage due to
seismic event
Reservoir pressure in monitor wells;
high
pressure found in new wells
Shut in injectors near
seismic event
-
Available studies of actual well leaks and natural analogs (e.g., naturally occurring C02 geysers) suggest
that the amount released from routine leaks would be small as compared to the amount of C02 that would
remain stored in the formation.
4.11 Summary
The structure and stratigraphy of the Weber Sands in the Rangely Field is ideally suited forthe injection and
storage of C02. The stratigraphy within the C02 injection zones is porous, permeable and very thick,
providing ample capacity for long-term C02 storage. The Weber Sands is overlain by several intervals of
impermeable geologic zones that form effective seals or "caps" to fluids in the Weber Sands (See Figure
4). After assessing potential risk of release from the subsurface and steps that have been taken to prevent
leaks, SEM has determined that the potential threat of leakage is extremely low.
In summary, based on a careful assessment of the potential risk of release of C02 from the subsurface, SEM
has determined that there are no leakage pathways at the Rangely Field that are likely to result in significant
loss of C02 to the atmosphere. Further, given the detailed knowledge of the Field and its operating
protocols, SEM concludes that it would be able to both detect and quantify any C02 leakage to the surface
that could arise through either identified or unexpected leakage pathways.
5. Monitoring and Considerations for Calculating Site Specific Variables
Monitoring will also be used to determine the quantities in the mass balance equation and to make the
demonstration that the C02 plume will not migrate to the surface after the time of discontinuation.
5.1 Forthe Mass Balance Equation
5.1.1 General Monitoring Procedures
As part of its ongoing operations, SEM monitors and collects flow, pressure, and gas composition data from
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the Rangely Field in centralized data management systems. These data are monitored continually by
qualified technicians who follow SEM response and reporting protocols when the systems deliver
notifications that data exceed statistically acceptable boundaries.
As indicated in Figures 10 and 11, custody-transfer meters are used at the point at which custody of the
C02 from the Raven Ridge pipeline delivery system is transferred to SEM, and at the points at which custody
of oil and NGLs are transferred to outside parties. Meters measure flow rate continually. Fluid composition
will be determined, at a minimum, quarterly, consistent with EPA GHGRP's Subpart RR, section 98.447(a).
All meter and composition data are documented, and records will be retained for at least three years.
Metering protocols used by SEM follow the prevailing industry standard(s) for custody transfer as currently
promulgated by the API, the American Gas Association (AGA), and the Gas Processors Association (GPA),
as appropriate. This approach is consistent with EPA GHGRP's Subpart RR, section 98.444(e)(3). These
meters will be maintained routinely, operated continually, and will feed data directly to the centralized data
collection systems. The meters meet the industry standard for custody transfer meter accuracy and
calibration frequency. These custody meters provide the most accurate way to measure mass flows.
SEM maintains in-field process control meters to monitor and manage in-field activities on a real time basis.
These are identified as operations meters in Figures 10 and 11. These meters provide information used to
make operational decisions but are not intended to provide the same level of accuracy as the custody-
transfer meters. The level of precision and accuracy for in-field meters currently satisfies the requirements
for reporting in existing UIC permits. Although these meters are accurate for operational purposes, it is
important to note that there is some variance between most commercial meters (on the order of 1-5%)
which is additive across meters. This variance is due to differences in factory settings and meter calibration,
as well as the operating conditions within a field. Meter elevation, changes in temperature (over the course
of the day), fluid composition (especially in multi-component or multi-phase streams), or pressure can affect
in-field meter readings. Unlike in a saline formation, where there are likely to be only a few injection wells
and associated meters, at C02 EOR operations in the Rangely Field there are currently 662 active injection
and production wells and a comparable number of meters, each with an acceptable range of error. This is
a site-specific factor that is considered in the mass balance calculations described in Section 7.
5.1.2 C02 Received
SEM measures the volume of received C02 using commercial custody transfer meters at the off-take point
from the Raven Ridge pipeline delivery system. This transfer is a commercial transaction that is
documented. C02 composition is governed by the contract and the gas is routinely sampled to determine
composition. No C02 is received in containers.
5.1.3 C02 Injected into the Subsurface
Injected C02 will be calculated using the flow metervolumes at the operations meter at the outlet of the C02
Reinjection Facility and the custody transfer meter at the C02 off-take points from the Raven Ridge pipeline
delivery system
5.1.4 C02 Produced, Entrained in Products, and Recycled
The following measurements are used for the mass balance equations in Section 7:
C02 produced is calculated using the volumetric flow meters at the inlet to the C02 Reinjection Facility.
These flow meters, as illustrated on Figure 10, are downstream of the field collection station separators
and bulk produced fluid separators at the water injection plants
C02 is produced as entrained or dissolved C02 in produced oil, as indicated in Figures 10 and 11. This is
calculated using volumetric flow through the custody transfer meter.
Recycled C02 is calculated using the volumetric flow meter at the outlet of the C02 Reinjection Facility,
which is an operations meter.
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5.1.5 C02 Emitted by Surface Leakage
As discussed in Section 5.1.6 and 5.1.7 below, SEM uses 40 CFR Part 98 Subpart Wto estimate surface
leaks from equipment at the Rangely Field. Subpart W uses a factor-driven approach to estimate equipment
leakage. In addition, SEM uses an event-driven process to assess, address, track, and if applicable quantify
potential C02 leakage to the surface.
The multi-layered, risk-based monitoring program for event-driven incidents has been designed to meet two
objectives, in accordance with the leakage risk assessment in Section 4: 1) to detect problems before C02
leaks to the surface; and 2) to detect and quantify any leaks that do occur. This section discusses how this
monitoring will be conducted and used to quantify the volumes of C02 leaked to the surface.
Monitoring for potential Leakage from the Injection/Production Zone:
SEM will monitor both injection into and production from the reservoir as a means of early identification of
potential anomalies that could indicate leakage from the subsurface.
SEM develops injection plans for each well and that is distributed to operations weekly. If injection pressure
or rate measurements are beyond the specified set points determined as part of each pattern injection plan,
the operations engineer will notify field personnel and they will investigate and resolve the problem. These
excursions will be reviewed by well-management personnel to determine if C02 leakage may be occurring.
Excursions are not necessarily indicators of leaks; they simply indicate that injection rates and pressures
are not conforming to the pattern injection plan. In many cases, problems are straightforward to fix (e.g., a
meter needs to be recalibrated or some other minor action is required), and there is no threat of C02
leakage. In the case of issues that are not readily resolved, more detailed investigation and response would
be initiated, and internal SEM support staff would provide additional assistance and evaluation. Such issues
would lead to the development of a work order in SEM's work order management system. This record
enables the company to track progress on investigating potential leaks and, if a leak has occurred, to
quantify its magnitude.
Likewise, SEM develops a forecast of the rate and composition of produced fluids. Each producer well is
assigned to one collection station and is isolated twice during each monthly cycle for a well production test.
This data is reviewed on a periodic basis to confirm that production is at the level forecasted. If there is a
significant deviation from the forecast, well management personnel investigate. If the issue cannot be
resolved quickly, more detailed investigation and response would be initiated. As in the case of the injection
pattern monitoring, if the investigation leads to a work order in the SEM work order management system,
this record will provide the basis for tracking the outcome of the investigation and if a leak has occurred. If
leakage in the flood zone were detected, SEM would use an appropriate method to quantify the involved
volume of C02. This might include use of material balance equations based on known injected quantities
and monitored pressures in the injection zone to estimate the volume of C02 involved.
A subsurface leak might not lead to a surface leak. In the event of a subsurface leak, SEM would determine
the appropriate approach for tracking subsurface leakage to determine and quantify leakage to the surface.
To quantify leakage to the surface, SEM would estimate the relevant parameters (e.g., the rate,
concentration, and duration of leakage) to quantify the leak volume. Depending on specific circumstances,
these determinations may rely on engineering estimates.
In the event leakage from the subsurface occurred diffusely through the seals, the leaked gas would include
H2S, which would trigger the alarm on the personal monitors worn by field personnel. Such a diffuse leak
from the subsurface has not occurred in the Rangely Field. In the event such a leak was detected, field
personnel from across SEM would determine how to address the problem. The team might use modeling,
engineering estimates, and direct measurements to assess, address, and quantify the leakage.
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Monitoring of Wellbores:
SEM monitors wells through continual, automated pressure monitoring in the injection zone (as described in
Section 4.2), monitoring of the annular pressure in wellheads, and routine maintenance and inspection.
Leaks from wellbores would be detected through the follow-up investigation of pressure anomalies, visual
inspection, or the use of personal H2S monitors.
Anomalies in injection zone pressure may not indicate a leak, as discussed above. However, if an
investigation leads to a work order, field personnel would inspect the equipment in question and determine
the nature of the problem. If it is a simple matter, the repair would be made and the volume of leaked C02
would be included in the 40 CFR Part 98 Subpart W report for the Rangely Field, as well as reported in
Subpart RR . If more extensive repair were needed, SEM would determine the appropriate approach for
quantifying leaked C02 using the relevant parameters (e.g., the rate, concentration, and duration of
leakage). The work order would serve as the basis for tracking the event for GHG reporting.
Anomalies in annular pressure or other issues detected during routine maintenance inspections would be
treated in the same way. Field personnel would inspect the equipment in question and determine the nature
of the problem. For simple matters the repair would be made at the time of inspection and the volume of
leaked C02 would be included in the 40 CFR Part 98 Subpart W report for the Rangely Field, as well as
reported in Subpart RR. If more extensive repairs were needed, a work order would be generated and SEM
would determine the appropriate approach for quantifying leaked C02 using the relevant parameters (e.g.,
the rate, concentration, and duration of leakage). The work order would serve as the basis for tracking the
event for GHG reporting.
Because leaking C02 at the surface is very cold and leads to formation of bright white clouds and ice that
are easily spotted, SEM also employs a two-part visual inspection process in the general area ofthe Rangely
Field to detect unexpected releases from wellbores. First, field personnel visit the surface facilities on a
routine basis. Inspections may include tank volumes, equipment status and reliability, lube oil levels,
pressures and flow rates in the facility, and valve leaks. Field personnel inspections also check that injectors
are on the proper WAG schedule and observe the facility for visible C02 or fluid line leaks.
Historically, SEM has not experienced any unexpected release events in the Rangely Field. An identified
need for repair or maintenance through visual inspections results in a work order being entered into SEM's
equipment and maintenance work order management system. The time to repair any leak is dependent on
several factors, such as the severity ofthe leak, available manpower, location ofthe leak, and availability
of materials required for the repair. Critical leaks are acted upon immediately.
Finally, SEM uses the data collected by the H2S monitors, which are worn by all field personnel at all times,
as a last method to detect leakage from wellbores. The H2S monitors detection limit is 10ppm; if an H2S
alarm is triggered, the first response is to protect the safety ofthe personnel, and the next step is to safely
investigate the source of the alarm. As noted previously, SEM considers H2S a proxy for potential C02
leaks in the field. Thus, detected H2S leaks will be investigated to determine if potential C02 leakage is
present, but not used to determine the leak volume. If the incident results in a work order, this will serve as
the basis for tracking the event for GHG reporting.
Other Potential Leakage at the Surface:
SEM will utilize the same visual inspection process and H2S monitoring system to detect other potential
leakage at the surface as it does for leakage from wellbores. SEM utilizes routine visual inspections to
detect significant loss of C02 to the surface. Field personnel routinely visit surface facilities to conduct a
visual inspection. Inspections may include review of tank level, equipment status, lube oil levels, pressures
and flow rates in the facility, valve leaks, ensuring that injectors are on the proper WAG schedule, and also
conducting a general observation ofthe facility for visible C02 or fluid line leaks. If problems are detected,
field personnel would investigate, and, if maintenance is required, generate a work order in the maintenance
system, which is tracked through completion. In addition to these visual inspections, SEM will use the results
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of the personal H2S monitors worn by field personnel as a supplement for smaller leaks that may escape
visual detection.
If C02 leakage to the surface is detected, it will be reported to surface operations personnel who will review
the reports and conduct a site investigation. If maintenance is required, a work order will be generated in
the work order management system. The work order will describe the appropriate corrective action and be
used to track completion of the maintenance action. The work order will also serve as the basis for tracking
the event for GHG reporting and quantifying any C02 emissions.
5.1.6 C02 emitted from equipment leaks and vented emissions of C02 from surface equipment
located between the injection flow meter and the injection wellhead.
SEM evaluates and estimates the mass of C02 emitted (in metric tons) annually from equipment leaks and
vented emissions of C02 from equipment located on the surface between the flow meter used to measure
injection quantity and the injection wellhead, as required under 40 CFR Part 98 Subpart W and 40 CFR
Part 98 Subpart RR.
5.1.7 Mass of C02 emissions from equipment leaks and vented emissions of C02 from surface
equipment located between the production flow meter and the production wellhead
SEM evaluates and estimates the mass of C02 emitted (in metric tons) annually from equipment leaks and
vented emissions of C02 from equipment located on the surface between the production wellhead and the
flow meter used to measure production quantity, as required under 40 CFR Part 98 Subpart W and 40 CFR
Part 98 Subpart RR.
5.2 To Demonstrate that Injected C02 is not Expected to Migrate to the Surface
At the end of the Specified Period, SEM intends to cease injecting C02 for the subsidiary purpose of
establishing the long-term storage of C02 in the Rangely Field. After the end of the Specified Period, SEM
anticipates that it will submit a request to discontinue monitoring and reporting. The request will demonstrate
that the amount of C02 reported under 40 CFR §98.440-449 (Subpart RR) is not expected to migrate in the
future in a manner likely to result in surface leakage. At that time, SEM will be able to support its request
with years of data collected during the Specified Period as well as two to three (or more, if needed) years
of data collected after the end of the Specified Period. This demonstration will provide the information
necessary for the EPA Administrator to approve the request to discontinue monitoring and reporting and
may include, but is not limited to:
i. Data comparing actual performance to predicted performance (purchase, injection, production)
over the monitoring period;
ii. An assessment of the C02 leakage detected, including discussion of the estimated amount of
C02 leaked and the distribution of emissions by leakage pathway;
iii. A demonstration that future operations will not release the volume of stored C02 to the surface;
iv. A demonstration that there has been no significant leakage of C02; and,
v. An evaluation of reservoir pressure in the Rangely Field that demonstrates that injected fluids are
not expected to migrate in a manner to create a potential leakage pathway.
6. Determination of Baselines
SEM intends to utilize existing automatic data systems to identify and investigate excursions from expected
performance that could indicate C02 leakage. SEM's data systems are used primarily for operational
control and monitoring and as such are set to capture more information than is necessary for reporting in the
Annual Subpart RR Report. SEM will develop the necessary system guidelines to capture the information that
is relevant to identify possible C02 leakage. The following describes SEM's approach to collecting this
information.
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Visual Inspections
As field personnel conduct routine inspections, work orders are generated in the electronic system for
maintenance activities that cannot be addressed on the spot. Methods to capture work orders that involve
activities that could potentially involve C02 leakage will be developed, if not currently in place. Examples
include occurrences of well workover or repair, as well as visual identification of vapor clouds or ice
formations. Each incident will be flagged for review by the person responsible for MRV documentation. The
responsible party will be provided in the monitoring plan, as required under Subpart A, 98.3(g). The Annual
Subpart RR Report will include an estimate of the amount of C02 leaked. Records of information used to
calculate emissions will be maintained on file for a minimum of three years.
Personal H2S Monitors
H2S monitors are worn by all field personnel. Any monitor alarm triggers an immediate response to ensure
personnel are not at risk and to verify the monitor is working properly. The person responsible for MRV
documentation will receive notice of all incidents where H2S is confirmed to be present. The Annual Subpart
RR Report will provide an estimate the amount of C02 emitted from any such incidents. Records of
information to calculate emissions will be maintained on file for a minimum of three years.
Injection Rates. Pressures and Volumes
SEM develops target injection rate and pressure for each injector, based on the results of ongoing pattern
modeling and within permitted limits. The injection targets are programmed into the WAG controllers. High
and low set points are also programmed into the SCADA, and flags whenever statistically significant
deviations from the targeted ranges are identified. The set points are designed to be conservative, because
it is preferable to have too many flags rather than too few. As a result, flags can occur frequently and are
often found to be insignificant. For purposes of Subpart RR reporting, flags (or excursions) will be screened
to determine if they could also lead to C02 leakage to the surface. The person responsible for the MRV
documentation will receive notice of excursions and related work orders that could potentially involve C02
leakage. The Annual Subpart RR Report will provide an estimate of C02 emissions. Records of information
to calculate emissions will be maintained on file for a minimum of three years.
Production Volumes and Compositions
SEM develops a general forecast of production volumes and composition which is used to periodically
evaluate performance and refine current and projected injection plans and the forecast. This information is
used to make operational decisions but is not recorded in an automated data system. Sometimes, this
review may result in the generation of a work order in the maintenance system. The MRV plan
implementation lead will review such work orders and identify those that could result in C02 leakage. Should
such events occur, leakage volumes would be calculated following the approaches described in Sections 4
and 5. Impact to Subpart RR reporting will be addressed, if deemed necessary.
7. Determination of Sequestration Volumes Using Mass Balance Equations
To account for the site conditions and complexity of a large, active EOR operation, SEM will utilize the
locations described below for obtaining volume data for the equations in Subpart RR §98.443 as indicated
below.
The selection of the utilized locations, more specifically described in this Section 7, address the propagation
of error that would result if volume data from meters at each injection well were utilized. This issue arises
because while each meter has a small but acceptable margin of error, this error would become significant
if data were taken from the approximately 284 meters within the Rangely Field. As such, SEM will use the
data from custody and operations meters on the main system pipelines to determine injection volumes used
in the mass balance. This satisfies the requirement in 40 CFR 98.444 (b) 1 that you must select a point or
points of measurement at which the C02 stream is representative of the C02 streams being injected.
The volumetric flow meters utilized for CQ2 produced are located at the inlet to the RCF. These flow
31
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meters, as illustrated on Figure 10, are directly downstream of the field collection station separators and
bulk produced fluid separators at the water injection plants. This satisfies the requirement in 40 CFR
98.444 (c)(1) for production, which states, "The point of measurement for the quantity of C02 produced
from oil or other fluid production wells is a flow meter directly downstream of each separator that sends a
stream of gas into a recycle or end use system."
The following sections describe how each element of the mass-balance equation (Equation RR-11) will be
calculated.
. Mass of C02 Received
SEM will use equation RR-2 as indicated in Subpart RR §98.443 to calculate the mass of 0O2 received
from each delivery meter immediately upstream of the Raven Ridge pipeline delivery system on the Rangely
Field. The volumetric flow at standard conditions will be multiplied by the C02 concentration and the density
of C02 at standard conditions to determine mass.
p=\
where:
C02T,r = Net annual mass of C02 received through flow meter r (metric tons).
Qr,p = Quarterly volumetric flow through a receiving flow meter r in quarter p at standard conditions
(standard cubic meters).
Sr,p = Quarterly volumetric flow through a receiving flow meter rthat is redelivered to another facility without
being injected into a site well in quarter p (standard cubic meters).
D = Density of C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.
CC02,p,r = Quarterly C02 concentration measurement in flow for flow meter r in quarter p (vol. percent
C02, expressed as a decimal fraction).
p = Quarter of the year,
r = Receiving flow meters.
Given SEM's method of receiving C02 and requirements at Subpart RR §98.444(a):
All delivery to the Rangely Field is used within the unit so quarterly flow redelivered, Sr,p , is
zero (0) and will not be included in the equation.
Quarterly C02 concentration will be taken from the gas measurement database SEM will sum to total
Mass of CQ2 Received using equation RR-3 in 98.443
4
R
C02 = ]TCO,Tir (Eq. RR-3)
where:
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C02 = Total net annual mass of C02 received (metric tons).
C02T,r = Net annual mass of C02 received (metric tons) as calculated in Equation RR-2 for flow meter r.
r = Receiving flow meter.
7.2 Mass of C02 Injected into the Subsurface
The equation for calculating the Mass of C02 Injected into the Subsurface at the Rangely Field is equal to
the sum of the Mass of C02 Received as calculated in RR-3 of 98.443 (as described in Section 7.1) and the
Mass of C02 Recycled as calculated using measurements taken from the flow meter located at the output
of the RCF. As previously explained, using data at each injection well would give an inaccurate estimate of
total injection volume due to the large number of wells and the potential for propagation of error due to
allowable calibration ranges for each meter.
The mass of C02 recycled will be determined using equations RR-5 as follows:
4
C02 ,u = ]T QPJI * D * C"COi I( (Eq. RR-5)
i>=\
where:
C02,u = Annual C02 mass injected (metric tons) as measured by flow meter u.
Qp,u = Quarterly volumetric flow rate measurement for flow meter u in quarter p at standard conditions
(standard cubic meters per quarter).
D = Density of C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.
C02,p,u = 0O2 concentration measurement in flow for flow meter u in quarter p (vol. percent C02,
expressed as a decimal fraction).
p = Quarter of the year, u = Flow meter.
The total Mass of C02 injected will be the sum of the Mass of C02 received (RR-3) and Mass of C02
recycled (modified RR-5).
CQ2| = C02 + C02,u
7.3 Mass of C02 Produced
The Mass of C02 Produced at the Rangely Field will be calculated using the measurements from the flow
meters at the inlet to RCF and for C02 entrained in the sales oil, the custody transfer meter for oil sales
rather than the metered data from each production well. Again, using the data at each production well would
give an inaccurate estimate of total injection due to the large number of wells and the potential for
propagation of error due to allowable calibration ranges for each meter.
Equation RR-8 in 98.443 will be used to calculate the mass of C02 produced from all injection wells as
follows:
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4
COa.w = ^QP*D *Cco?^ (Eq. RR-8)
Where:
C02,w = Annual C02 mass produced (metric tons) .
Qp,w = Volumetric gas flow rate measurement for separator w in quarter p at standard conditions
(standard cubic meters).
D = Density of C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.
CC02,p,w = 0O2 concentration measurement in flow for meter w in quarter p (vol. percent C02,
expressed as a decimal fraction).
p = Quarter of the year, w = inlet meter to RCF.
Equation RR-9 in 98.443 will be used to aggregate the mass of C02 produced net of the mass of C02
entrained in oil leaving the Rangely Field priorto treatment of the remaining gas fraction in RCF as follows:
C02p = Total annual C02 mass produced (metric tons) through all meters in the reporting year.
C02,w = Annual C02 mass produced (metric tons) through meter w in the reporting year.
X = Entrained C02 in produced oil or other fluid divided by the C02 separated through all separators in the
reporting year (weight percent C02, expressed as a decimal fraction),
w = Separator.
7.4 Mass of C02 emitted by Surface Leakage
SEM will calculate and report the total annual Mass of C02 emitted by Surface Leakage using an approach
that relies on 40 CFR Part 98 Subpart W reports for equipment leakage, and tailored calculations for all
other surface leaks. As described in Sections 4 and 5.1.5-5.1.7, SEM is prepared to address the potential
for leakage in a variety of settings. Given the uncertainty concerning the nature and characteristics of leaks
that will be encountered, it is not clear the method for quantifying the volume of leaked C02 that would be
most appropriate. Estimates of the amount of C02 leaked to the surface will depend on a number of site-
specific factors including measurements of flowrate, pressure, size of leak opening, and duration of the
leak. Engineering estimates, and emission factors, depending on the source and nature of the leakage will
also be used.
SEM's process for quantifying leakage will entail using best engineering principles or emission factors.
While it is not possible to predict in advance the types of leaks that will occur, SEM describes some
approaches for quantification in Section 5.1.5-5.1.7. In the event leakage to the surface occurs, SEM would
quantify and report leakage amounts, and retain records that describe the methods used to estimate or
measure the volume leaked as reported in the Annual Subpart RR Report.
(Eq. RR-9)
Where:
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Equation RR-10 in 48.433 will be used to calculate and report the Mass of C02 emitted by Surface Leakage:
A'"l
where:
C02E = Total annual C02 mass emitted by surface leakage (metric tons) in the reporting year.
C02,x = Annual C02 mass emitted (metric tons) at leakage pathway x in the reporting year,
x = Leakage pathway.
7.5 Mass of C02 sequestered in subsurface geologic formations.
SEM will use equation RR-11 in 98.443 to calculate the Mass of C02 Sequestered in Subsurface
Geologic Formations in the Reporting Year as follows:
CO2 = C02j CO2P - CO2E - CO2fi CO2FP {Ecj, RR~IX)
where:
C02 = Total annual C02 mass sequestered in subsurface geologic formations (metric tons) at the facility
in the reporting year.
C02| = Total annual C02 mass injected (metric tons) in the well or group of wells covered by this source
category in the reporting year.
C02P = Total annual C02 mass produced (metric tons) in the reporting year.
C02E = Total annual C02 mass emitted (metric tons) by surface leakage in the reporting year.
C02FI = Total annual C02 mass emitted (metric tons) from equipment leaks and vented emissions of C02
from equipment located on the surface between the flow meter used to measure injection quantity and the
injection wellhead, forwhich a calculation procedure is provided in subpart W of this part.
C02FP = Total annual C02 mass emitted (metric tons) from equipment leaks and vented emissions of C02
from equipment located on the surface between the production wellhead and the flow meter used to
measure production quantity, forwhich a calculation procedure is provided in subpart W of this part.
7.6 Cumulative mass of C02 reported as sequestered in subsurface geologic formations
SEM will sum up the total annual volumes obtained using equation RR-11 in 98.443 to calculate the
Cumulative Mass of C02 Sequestered in Subsurface Geologic Formations.
8. MRV Plan Implementation Schedule
The activities described in this MRV Plan are in place, and reporting is planned to start upon EPA approval.
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Other GHG reports are filed on March 31 of the year after the reporting year and it is anticipated that the
Annual Subpart RR Report will be filed at the same time. As described in Section 3.3 above, SEM anticipates
that the MRV program will be in effect during the Specified Period, during which time SEM will operate the
Rangely Field with the subsidiary purpose of establishing long-term containment of a measurable quantity
of C02 in subsurface geological formations at the Rangely Field. SEM anticipates establishing that a
measurable amount of C02 injected during the Specified Period will be stored in a manner not expected
to migrate resulting in future surface leakage. At such time, SEM will prepare a demonstration supporting
the long-term containment determination and submit a request to discontinue reporting under this MRV
plan. See 40 C.F.R. § 98.441 (b)(2)(ii).
9. Quality Assurance Program
9.1 Monitoring QA/QC
As indicated in Section 7, SEM has incorporated the requirements of §98.444 (a) - (d) in the discussion
of mass balance equations. These include the following provisions.
C02 Received and Injected
The quarterly flow rate of C02 received by pipeline is measured at the receiving custody
transfer meters.
The quarterly C02 flow rate for recycled C02 is measured at the flow meter located at the C02
Reinjection facility outlet.
C02 Produced
The point of measurement for the quantity of C02 produced is a flow meter at the C02 Reinjection
facility inlet. . C02 produced as entrained or dissolved C02 in produced oil is calculated using
volumetric flow through the custody transfer meter.
The produced gas stream is sampled at least once per quarter immediately downstream of the flow
meter used to measure flow rate of that gas stream and measure the 0O2 concentration of the
sample.
The quarterly flow rate of the produced gas is measured at the flow meters located at the C02
Reinjection facility inlet.
C02 emissions from equipment leaks and vented emissions of C02
These volumes are measured in conformance with the monitoring and QA/QC requirements
specified in subpart W of 40 CFR Part 98.
Flow meter provisions
The flow meters used to generate date for the mass balance equations in Section 7 are:
Operated continuously except as necessary for maintenance and calibration.
Operated using the calibration and accuracy requirements in 40 CFR §98.3(i).
Operated in conformance with American Petroleum Institute (API) standards.
National Institute of Standards and Technology (NIST) traceable.
Concentration of C02
As indicated in Appendix 1, C02 concentration is measured using an appropriate standard method. Further,
all measured volumes of C02 have been converted to standard cubic meters at a temperature of 60
degrees Fahrenheit and at an absolute pressure of 1 atmosphere, including those used in Equations RR-
2, RR-5 and RR-8 in Section 7.
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9.2 Missing Data Procedures
In the event SEM is unable to collect data needed for the mass balance calculations, procedures
for estimating missing data in §98.445 will be used as follows:
A quarterly flow rate of C02 received that is missing would be estimated using invoices or using a
representative flow rate value from the nearest previous time period.
A quarterly C02 concentration of a C02 stream received that is missing would be estimated using
invoices or using a representative concentration value from the nearest previous time period.
A quarterly quantity of C02 injected that is missing would be estimated using a representative quantity
of C02injected from the nearest previous period of time at a similar injection pressure.
For any values associated with C02 emissions from equipment leaks and vented emissions of C02
from surface equipment at the facility that are reported in this subpart, missing data estimation
procedures specified in subpart Wof 40 CFR Part 98 would be followed.
The quarterly quantity of C02 produced from subsurface geologic formations that is missing would be
estimated using a representative quantity of C02 produced from the nearest previous period of time.
9.3 MRV Plan Revisions
In the event there is a material change to the monitoring and/or operational parameters of the SEM C02
EOR operations in the Rangely Field that is not anticipated in this MRV plan, the MRV plan will be revised
and submitted to the EPA Administrator within 180 days as required in §98.448(d).
10. Records Retention
SEM will follow the record retention requirements specified by §98.3(g). In addition, it will follow the
requirements in Subpart RR §98.447 by maintaining the following records for at least three years:
Quarterly records of C02 received at standard conditions and operating conditions, operating
temperature and pressure, and concentration of these streams.
Quarterly records of produced C02, including volumetric flow at standard conditions and operating
conditions, operating temperature and pressure, and concentration of these streams.
Quarterly records of injected C02 including volumetric flow at standard conditions and operating
conditions, operating temperature and pressure, and concentration of these streams.
Annual records of information used to calculate the C02 emitted by surface leakage from leakage
pathways.
Annual records of information used to calculate the C02 emitted from equipment leaks and vented
emissions of C02 from equipment located on the surface between the flow meter used to measure
injection quantity and the injection wellhead.
Annual records of information used to calculate the C02 emitted from equipment leaks and vented
emissions of C02 from equipment located on the surface between the production wellhead and the
flow meter used to measure production quantity.
These data will be collected as generated and aggregated as required for reporting purposes.
11. Appendices
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Appendix 1. Conversion Factors
SEM reports C02 volumes at standard conditions of temperature and pressure as defined in the State of
Colorado, which follows the international standard conditions for measuring C02 properties - 77 °F and
14.696 psi.
To convert these volumes into metric tonnes, a density is calculated using the Span and Wagner equation
of state as recommended by the EPA. Density was calculated using the database of thermodynamic
properties developed by the National Institute of Standards and Technology (NIST), available at
http://webbook.nist.gov/chemistrv/fluid/.
At EPA standard conditions of 77 °F and one atmosphere, the Span and Wagner equation of state gives a
density of 0.0026500 lb-moles per cubic foot. Using a molecular weight for C02 of 44.0095, 2204.62
lbs/metric ton and 35.314667 ft3/m3, gives a C02 density of 5.29003 x 10 5 MT/ft3 or 0.0018682 MT/m3.
The conversion factor 5.29003 x 10-5 MT/Mcf has been used throughout to convert SEM volumes to metric
tons.
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Appendix 2. Acronyms
AGA-American Gas Association
AMA - Active Monitoring Area
AoR - Area of Review
API-American Petroleum Institute
BCF - Billion Cubic Feet
bopd - barrels of oil per day
Cf- Cubic Feet
CCR - Code of Colorado Regulations
COGCC - Colorado Oil and Gas Conservation Commission
C02 - Carbon Dioxide
CRF - C02 Removal Facilities
EOR - Enhanced Oil Recovery
EPA - US Environmental Protection Agency
GHG - Greenhouse Gas
GHGRP - Greenhouse Gas Reporting Program
H2S - Hydrogen Sulfide
IWR - Injection to Withdrawal Ratio
LACT - Lease Automatic Custody Transfer meter
Md - Millidarcy
MIT - Mechanical Integrity Test
MFF - Main Field Fault
MMA - Maximum Monitoring Area
MMB - Million barrels
Mscf-Thousand standard cubic feet
MMscf- Million standard cubic feet
MMMT - Million metric tonnes
MMT -Thousand metric tonnes
MRV - Monitoring, Reporting, and Verification
MOC - Main oil column
MT - Metric Tonne
NGNatural Gas
NGLs - Natural Gas Liquids
NIST - National Institute of Standards and Technology
OOIP - Original Oil-ln-Place
OH - Open hole
POWC - Producible oil/water contact
PPM - Parts Per Million
RCF - Rangely Field C02 Recycling and Compression Facility
RRPC - Raven Ridge pipeline
RWSU - Rangely Weber Sand Unit
SCADA - Supervisory Control and Data Acquisition
SEM - Scout Energy Management, LLC
UIC - Underground Injection Control
VRU - Vapor Recovery Unit
WAG - Water Alternating Gas
XOM - ExxonMobil
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Appendix 3. References
Adams, L., 2006; Sequence and Mechanical Stratigraphy: An intergrated Reservoir Characterization of
the Weber Sandstone, Western Colorado. University of Texas at El Paso Ph.D. Dissertation.
Colorado Administrative Code Department 400 Division 404 Oil and Gas Conservation Commission
Section 2
Clark, Rory, Chevron North America E&P, Presentation to 6th Annual Wyoming C02 Conference, July 12,
2012, online: //www.uwyo.edu/eori/_files/C02conference12/rory_rangelycasehistory.pdf
Energy and Carbon Management Regulation in Colorado. May 22, 2023, online:
https://leg.colorado.gov/bills/sb23-285
US Department of Energy, National Energy Technology Laboratory. "Carbon Dioxide Enhanced Oil
Recovery - Untapped Domestic Energy Supply and Long Term Carbon Storage Solution," March 2010.
US Department of Energy, National Energy Technology Laboratory. "Carbon Sequestration Through
Enhanced Oil Recovery," April 2008.
Gale, Hoyt. Geology of the Rangely Oil District. Department of Interior United States Geological Survey,
Bulletin 350. 1908.
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Appendix 4. Glossary of Terms
This glossary describes some of the technical terms as they are used in this MRV plan. For additional
glossaries please see the U.S. EPA Glossary of UIC Terms
(http://water.epa.gov/tvpe/aroundwater/uic/alossarv.cfm') and the Schlumberger Oilfield Glossary
(http://www.glossary.oilfield.slb.com/).
Contain / Containment - having the effect of keeping fluids located within in a specified portion of a geologic
formation.
Dip-Very few, if any, geologic features are perfectly horizontal. They are almost always tilted. The direction
of tilt is called "dip." Dip is the angle of steepest descent measured from the horizontal plane. Moving higher
up structure is moving "updip." Moving lower is "downdip." Perpendicular to dip is "strike." Moving
perpendicular along a constant depth is moving along strike.
Downdip - See "dip."
Formation - A body of rock that is sufficiently distinctive and continuous that it can be mapped.
Infill Drilling - The drilling of additional wells within existing patterns. These additional wells decrease
average well spacing. This practice both accelerates expected recovery and increases estimated ultimate
recovery in heterogeneous reservoirs by improving the continuity between injectors and producers. As well
spacing is decreased, the shifting flow paths lead to increased sweep to areas where greater hydrocarbon
saturations remain.
Permeability - Permeability is the measure of a rock's ability to transmit fluids. Rocks that transmit fluids
readily, such as sandstones, are described as permeable and tend to have many large, well-connected
pores. Impermeable formations, such as shales and siltstones, tend to be finer grained or of a mixed grain
size, with smaller, fewer, or less interconnected pores.
Phase - Phase is a region of space throughout which all physical properties of a material are essentially
uniform. Fluids that don't mix together segregate themselves into phases. Oil, for example, does not mix
with water and forms a separate phase.
Pore Space - See porosity.
Porosity - Porosity is the fraction of a rock that is not occupied by solid grains or minerals. Almost all rocks
have spaces between rock crystals or grains that is available to be filled with a fluid, such as water, oil or
gas. This space is called "pore space."
Saturation - The fraction of pore space occupied by a given fluid. Oil saturation, for example, is the fraction
of pore space occupied by oil.
Seal - A geologic layer (or multiple layers) of impermeable rock that serve as a barrier to prevent fluids
from moving upwards to the surface.
Secondary recovery - The second stage of hydrocarbon production during which an external fluid such as
water or gas is injected into the reservoirthrough injection wells located in rock that has fluid communication
with production wells. The purpose of secondary recovery is to maintain reservoir pressure and to displace
hydrocarbons toward the wellbore. The most common secondary recovery techniques are gas injection and
waterflooding.
Stratigraphic section - A stratigraphic section is a sequence of layers of rocks in the order they were
deposited.
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Strike - See "dip.
Updip - See "dip.
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Appendix 5. Well Identification Numbers
The following table presents the well name, API number, status and type for the wells in the RWSU as of
April 2023. The table is subject to change overtime as new wells are drilled, existing wells change status,
or existing wells are repurposed. The following terms are used:
Well Status
Producing refers to a well that is actively producing
Injecting refers to a well that is actively injecting
P&A refers to wells that have been closed (plugged and abandoned) per COGCC regulations
Shut In refers to wells that have been temporarily idled or shut-in
Monitor refers to a well that is used to monitor bottom home pressure in the reservoir
Well Type
Water / Gas Inject refers to wells that inject water and C02 Gas
Water Injection Well refers to wells that inject water
Oil well refers to wells that produce oil
Salt Water Disposal refers to a well used to dispose of excess water
Name
API Number
Well Type
Well Status
AC MCLAUGHLIN 46
51030632300
Water Injection Well
P&A
AC MCLAUGHLIN 64X
51030771700
Oil well
Producing
ASSOCIATED A 2
51030571400
Water / Gas Inject
P&A
ASSOCIATED A1
51030571300
Oil well
Producing
ASSOCIATED A2ST
51030571401
Water / Gas Inject
Injecting
ASSOCIATED A3X
51030778600
Oil well
Producing
ASSOCIATED A4X
51030791600
Oil well
Producing
ASSOCIATED A5X
51030803400
Water / Gas Inject
Injecting
ASSOCIATED A6X
51030801100
Water / Gas Inject
Injecting
ASSOCIATED LARSON UNIT A1
51030600900
Oil well
Producing
ASSOCIATED LARSON UNIT A2X
51030881500
Oil well
Producing
ASSOCIATED LARSON UNIT B1
51030601100
Oil well
Producing
ASSOCIATED LARSON UNIT B2X
51030950200
Oil well
Producing
ASSOCIATED UNIT A1
51030602600
Oil well
Producing
ASSOCIATED UNIT A2X UN A-2X
51031053200
Oil well
Producing
ASSOCIATED UNIT A3X
51031072300
Oil well
Producing
ASSOCIATED UNIT A4X
51031072200
Water / Gas Inject
Injecting
ASSOCIATED UNIT C1
51030582700
Oil well
Producing
BEEZLEY 1X22AX
51031075400
Water / Gas Inject
Injecting
BEEZLEY 2-22
51030574200
Oil well
Producing
BEEZLEY 3X 3X22
51031054900
Oil well
Producing
BEEZLEY 4X 22
51031055300
Oil well
Producing
BEEZLEY 5X22
51031174200
Oil well
Producing
BEEZLEY 6X22
51031174300
Oil well
Producing
43
-------
CARNEY 22X-35
51030724500
Oil well
P&A
CARNEY CT 10-4
51030608600
Oil well
Monitor
CARNEY CT 11-4
51030545700
Oil well
Monitor
CARNEY CT 12AX5
51030917600
Water / Gas Inject
Monitor
CARNEY CT 13-4
51030545900
Oil well
Producing
CARNEY CT 1-34
51030548200
Oil well
Producing
CARNEY CT 14-34
51030103500
Oil well
Producing
CARNEY CT 15-35
51030103700
Water / Gas Inject
Injecting
CARNEY CT 16-35
51030103300
Water / Gas Inject
Monitor
CARNEY CT 17-35
51030103200
Oil well
Producing
CARNEY CT 18-35
51030629500
Water / Gas Inject
Injecting
CARNEY CT 19-34
51030604400
Oil well
Producing
CARNEY CT 20X35
51030641300
Oil well
Producing
CARNEY CT 21X35
51030703300
Water / Gas Inject
Injecting
CARNEY CT 22X35ST
51030724501
Oil well
Producing
CARNEY CT 2-34
51030551400
Oil well
Monitor
CARNEY CT 23X35
51030726200
Water / Gas Inject
Injecting
CARNEY CT 24X35
51030728300
Water / Gas Inject
Monitor
CARNEY CT 27X34
51030746600
Water / Gas Inject
Injecting
CARNEY CT 28X
51030747400
Water / Gas Inject
Monitor
CARNEY CT 29X
51030753700
Water / Gas Inject
Injecting
CARNEY CT 30X34 30X
51030752600
Water / Gas Inject
Injecting
CARNEY CT 32X34
51030758900
Water / Gas Inject
Injecting
CARNEY CT 3-34
51030103900
Oil well
Producing
CARNEY CT 33X34
51030759200
Water / Gas Inject
Injecting
CARNEY CT 35X34
51030759300
Water / Gas Inject
Injecting
CARNEY CT 37X4
51030856300
Oil well
Producing
CARNEY CT 38X4
51030881300
Water / Gas Inject
Monitor
CARNEY CT 39X4
51030881400
Oil well
Producing
CARNEY CT41Y34
51030914900
Oil well
Monitor
CARNEY CT 4-34
51030555900
Oil well
Producing
CARNEY CT 43Y34
51030914800
Oil well
Monitor
CARNEY CT 44Y34
51030915300
Oil well
Monitor
CARNEY CT 5-34
51030103800
Oil well
Producing
CARNEY CT 6-5
51030609100
Water / Gas Inject
Monitor
CARNEY CT 7-35
51030629300
Oil well
Producing
CARNEY CT 8-34
51030104000
Oil well
Producing
CARNEY CT 9-35
51030548600
Water / Gas Inject
Monitor
CARNEY UNIT 1
51030608700
Oil well
Producing
CARNEY UNIT 2X
51030719100
Water / Gas Inject
Injecting
COLTHARPJE 10X
51030869400
Oil well
Producing
44
-------
COLTHARP JE 2
51030602300
Water / Gas Inject
Monitor
COLTHARP JE 4
51030602200
Water / Gas Inject
Monitor
COLTHARP JE 5X
51030705700
Oil well
Producing
COLTHARP JE 7X
51030727900
Oil well
Producing
COLTHARP JE 8X
51030734300
Oil well
Producing
COLTHARP WH A1
51030601900
Water / Gas Inject
Injecting
COLTHARP WH A3
51030602100
Water / Gas Inject
Monitor
COLTHARP WH A4
51030102800
Water / Gas Inject
Injecting
COLTHARP WH A5X
51030725000
Oil well
Producing
COLTHARP WH A6X
51030744700
Oil well
Producing
COLTHARP WH A8X
51030909900
Oil well
Producing
COLTHARP WH B2X
51030859400
Oil well
Monitor
COLTHARP WH B3X
51030879300
Oil well
Shut In
COLTHARP WH C1
51030107700
Water / Gas Inject
Monitor
COLTHARP WH C2X
51030919800
Oil well
Producing
CT CARNEY 25X34
51030741500
Water / Gas Inject
Injecting
EMERALD 10
51030566200
Oil well
Producing
EMERALD 11
51030567100
Oil well
Producing
EMERALD13ST
51030563601
Water / Gas Inject
Injecting
EMERALD 14
51030556500
Water / Gas Inject
Injecting
EMERALD 16
51030625300
Oil well
Monitor
EMERALD 17
51030567700
Water / Gas Inject
Injecting
EMERALD18AX
51030920200
Oil well
Producing
EMERALD 19
51030624000
Oil well
Producing
EMERALD 2
51030566900
Oil well
Producing
EMERALD 20
51030555800
Water / Gas Inject
Injecting
EMERALD 22
51030625400
Water / Gas Inject
Injecting
EMERALD 23
51030558900
Water / Gas Inject
Injecting
EMERALD 25
51030548100
Water / Gas Inject
Injecting
EMERALD 26
51030624200
Water / Gas Inject
Injecting
EMERALD 27
51030565300
Oil well
Producing
EMERALD 28
51030562800
Water / Gas Inject
Injecting
EMERALD 29AX
51030924500
Water / Gas Inject
Injecting
EMERALD 30AX
51030920300
Water / Gas Inject
Injecting
EMERALD 31 AX
51030923600
Water / Gas Inject
Injecting
EMERALD 32
51030623800
Oil well
Producing
EMERALD 33AX
51030923900
Water / Gas Inject
Injecting
EMERALD 34
51030559500
Water / Gas Inject
Injecting
EMERALD 35
51030559400
Water / Gas Inject
Injecting
EMERALD 36
51030548800
Water / Gas Inject
Injecting
EMERALD 37
51030551200
Water / Gas Inject
Injecting
45
-------
EMERALD 38
51030624900
Water / Gas Inject
Injecting
EMERALD 39
51030625100
Water / Gas Inject
Injecting
EMERALD 3ST
51030559901
Water / Gas Inject
Injecting
EMERALD 3ST 3
51030559900
Water / Gas Inject
P&A
EMERALD 4
51030550500
Oil well
Producing
EMERALD 40
51030625000
Water / Gas Inject
Injecting
EMERALD 41
51030546300
Water / Gas Inject
Monitor
EMERALD 42D
51030634000
Salt Water Disposal
Injecting
EMERALD 44AX
51030918700
Water / Gas Inject
Injecting
EMERALD 46X
51030713000
Oil well
Producing
EMERALD 47X
51030720100
Oil well
Producing
EMERALD 48X
51030725700
Oil well
Monitor
EMERALD 49AX
51031068000
Oil well
Producing
EMERALD 50X
51030733100
Oil well
Producing
EMERALD 51X
51030733300
Oil well
Producing
EMERALD 52X
51030737100
Oil well
Producing
EMERALD 53X
51030737600
Oil well
Producing
EMERALD 54X
51030763700
Oil well
Producing
EMERALD 55X
51030763800
Oil well
Producing
EMERALD 56X
51030768700
Oil well
Producing
EMERALD 57XST
51030764901
Oil well
Producing
EMERALD 58X
51030773900
Oil well
Producing
EMERALD 59X
51030774000
Oil well
Producing
EMERALD 6
51030558800
Water / Gas Inject
Injecting
EMERALD 60X
51030779800
Oil well
Producing
EMERALD 61X
51030780300
Oil well
Producing
EMERALD 62X
51030781100
Oil well
Producing
EMERALD 63ST
51030804101
Water / Gas Inject
Injecting
EMERALD 63XST
51030804100
Water / Gas Inject
P&A
EMERALD 64X
51030799200
Water / Gas Inject
Injecting
EMERALD 65X
51030794800
Oil well
Producing
EMERALD 66X
51030786800
Oil well
Producing
EMERALD 67X
51030797400
Oil well
Producing
EMERALD 68X
51030797500
Oil well
Producing
EMERALD 69X
51030810300
Water / Gas Inject
Injecting
EMERALD 70X
51030807200
Water / Gas Inject
Injecting
EMERALD 71X
51030804600
Water / Gas Inject
Injecting
EMERALD 72X
51030810400
Water / Gas Inject
Monitor
EMERALD 73X
51030810500
Oil well
Monitor
EMERALD 74X
51030816900
Oil well
Producing
EMERALD 75X
51030843700
Oil well
Producing
46
-------
EMERALD 76X
51030848100
Oil well
Producing
EMERALD 77X
51030848000
Oil well
Producing
EMERALD 78X
51030849100
Oil well
Producing
EMERALD 79X
51030895500
Salt Water Disposal
Injecting
EMERALD 7 A
51030928500
Water / Gas Inject
Injecting
EMERALD 8
51030559000
Water / Gas Inject
P&A
EMERALD 80X
51030876900
Oil well
Producing
EMERALD 81X
51030888300
Oil well
Producing
EMERALD 82X
51030849200
Water / Gas Inject
Injecting
EMERALD 83X
51030876500
Oil well
Producing
EMERALD 84X
51030888500
Oil well
Producing
EMERALD 85X
51030877000
Oil well
Producing
EMERALD 86X
51030877200
Oil well
Producing
EMERALD 87X
51030877300
Oil well
Monitor
EMERALD 88X
51030876600
Oil well
Producing
EMERALD 89X
51030877100
Oil well
Producing
EMERALD 8ST
51030559001
Water / Gas Inject
Injecting
EMERALD 90X
51030914600
Water / Gas Inject
Injecting
EMERALD 91Y
51030914700
Water / Gas Inject
Injecting
EMERALD 92X
51030929500
Oil well
Producing
EMERALD 93X
51031185800
Oil well
Producing
EMERALD 94X
51031185500
Oil well
Producing
EMERALD 95X
51031191400
Oil well
Producing
EMERALD 96X
51031192200
Oil well
Producing
EMERALD 97X
51031191300
Oil well
Producing
EMERALD 98X
51031191500
Water / Gas Inject
Injecting
EMERALD 9ST
51030566101
Water / Gas Inject
Injecting
EMERALD 9ST 9
51030566100
Water / Gas Inject
P&A
FAIRFIELD KITTI A 4
51031101700
Oil well
P&A
FAIRFIELD KITTI A 5P
51031101000
Oil well
P&A
FAIRFIELD KITTI A1
51030611100
Water / Gas Inject
Injecting
FAIRFIELD KITTI A4
51031101701
Oil well
Producing
FAIRFIELD KITTI A5
51031101001
Oil well
Producing
FAIRFIELD KITTI B1
51030107800
Water / Gas Inject
Injecting
FE156X
51031033600
Oil well
Producing
FEE 1
51030563400
Oil well
Producing
FEE 1 162Y
51031194500
Water / Gas Inject
Injecting
FEE 10
51030566800
Water / Gas Inject
Injecting
FEE 100X
51030786900
Oil well
Producing
FEE 101X
51030787000
Oil well
Producing
FEE 102X
51030787700
Oil well
Producing
47
-------
FEE 103X
51030788500
Oil well
Monitor
FEE 104X
51030785700
Oil well
Producing
FEE 105X
51030785800
Oil well
Producing
FEE 106X
51030794600
Water / Gas Inject
Injecting
FEE 107X
51030803200
Water / Gas Inject
Injecting
FEE 108X
51030795200
Oil well
Producing
FEE 109X
51030798900
Water / Gas Inject
Injecting
FEE 11
51030559600
Oil well
Producing
FEE 11OX
51030802600
Water / Gas Inject
Injecting
FEE 111X
51030802700
Water / Gas Inject
Monitor
FEE 112X
51030802800
Water / Gas Inject
Injecting
FEE 113X
51030802900
Water / Gas Inject
Injecting
FEE 114X
51030803100
Water / Gas Inject
Injecting
FEE 115X
51030803300
Water / Gas Inject
Injecting
FEE 116X
51030829900
Water / Gas Inject
Injecting
FEE 117X
51030843800
Oil well
Producing
FEE 118AX
51030928300
Oil well
Monitor
FEE 12
51030565100
Oil well
Producing
FEE 121X
51030857500
Oil well
Producing
FEE 122X
51030866300
Water / Gas Inject
Injecting
FEE 124X
51030866400
Oil well
Producing
FEE 125X
51030868100
Oil well
Monitor
FEE 126X
51030868600
Oil well
Producing
FEE 127X
51030868700
Water / Gas Inject
Injecting
FEE 128X
51030868800
Oil well
Monitor
FEE 129X
51030868900
Oil well
Producing
FEE 13
51030622600
Oil well
Producing
FEE 130X
51030870400
Oil well
Monitor
FEE 133X
51030888400
Oil well
Producing
FEE 135X
51030876000
Oil well
Monitor
FEE 136X
51030874500
Water / Gas Inject
Injecting
FEE 137X
51030876100
Water / Gas Inject
Injecting
FEE 138X
51030876300
Oil well
Producing
FEE 139X
51030876200
Oil well
Producing
FEE 14
51030568700
Oil well
Producing
FEE 140Y
51030910600
Oil well
Monitor
FEE 141X
51030913300
Water / Gas Inject
Injecting
FEE 142X
51030913100
Oil well
Producing
FEE 143X
51030913000
Oil well
Producing
FEE 144Y
51030917500
Oil well
Shut In
FEE 145Y
51030917400
Oil well
Producing
48
-------
FEE 146X
51030946400
Oil well
Producing
FEE 15
51030556800
Oil well
Producing
FEE 153X
51030929700
Oil well
Producing
Fee154X
51031036500
Oil well
Producing
Fee155X
51031037300
Oil well
Producing
FEE 157X
51031101900
Oil well
Monitor
FEE 158 X
51031115900
Oil well
Producing
FEE 159 X
51031101100
Oil well
Producing
FEE 160X
51031186600
Oil well
Producing
FEE 163X
51031195100
Oil well
Producing
FEE16AX
51030923500
Water / Gas Inject
Monitor
FEE 17
51030580100
Water / Gas Inject
Injecting
FEE 18
51030623600
Water / Gas Inject
Monitor
FEE 19
51030622400
Oil well
Producing
FEE 1AX
51030924400
Water / Gas Inject
Monitor
FEE 20
51030616800
Oil well
Producing
FEE 21
51030620700
Oil well
Producing
FEE 22
51030616100
Water / Gas Inject
Injecting
FEE 23
51030615600
Oil well
Producing
FEE 24
51030611200
Water / Gas Inject
Injecting
FEE 25
51030614500
Oil well
Producing
FEE 26
51030615200
Oil well
Producing
FEE 27
51030617500
Oil well
Producing
FEE 28
51030613500
Water / Gas Inject
Injecting
FEE 29
51030614400
Water / Gas Inject
Injecting
FEE 2AX
51030924700
Water / Gas Inject
Injecting
FEE 3
51030565700
Oil well
Producing
FEE 30
51030621100
Water / Gas Inject
Monitor
FEE 31
51030611800
Water / Gas Inject
Injecting
FEE 32
51030614200
Oil well
Producing
FEE 33
51030614700
Oil well
Producing
FEE 34
51030624500
Oil well
Producing
FEE 35
51030611300
Oil well
Producing
FEE 36
51030617600
Oil well
Producing
FEE 37
51030611500
Water / Gas Inject
Injecting
FEE 38
51030625500
Water / Gas Inject
Injecting
FEE 39
51030623300
Water / Gas Inject
Injecting
FEE 4
51030576900
Oil well
Monitor
FEE 40
51030622300
Water / Gas Inject
Injecting
FEE 41
51030622200
Water / Gas Inject
Monitor
FEE 42
51030568800
Water / Gas Inject
Monitor
49
-------
FEE 43
51030614100
Water / Gas Inject
Injecting
FEE 44
51030624700
Water / Gas Inject
Injecting
FEE 45
51030617900
Oil well
Producing
FEE 47
51030616000
Water / Gas Inject
Injecting
FEE 48
51030625900
Water / Gas Inject
Injecting
FEE 49
51030611900
Water / Gas Inject
Injecting
FEE 5
51030574500
Oil well
Producing
FEE 51
51030614900
Water / Gas Inject
Injecting
FEE 52
51030567400
Water / Gas Inject
Injecting
FEE 53AX
51030861200
Water / Gas Inject
Injecting
FEE 55
51030615300
Water / Gas Inject
Injecting
FEE 56
51030615700
Water / Gas Inject
Injecting
FEE 58AX
51030924300
Water / Gas Inject
Injecting
FEE 59
51030616900
Water / Gas Inject
Injecting
FEE 6
51030572000
Oil well
Producing
FEE 60
51030622500
Water / Gas Inject
Injecting
FEE 61
51030620300
Oil well
Producing
FEE 62
51030614000
Oil well
Monitor
FEE 63
51030614600
Water / Gas Inject
Injecting
FEE 64
51030614800
Water / Gas Inject
Injecting
FEE 65
51030615000
Water / Gas Inject
Injecting
FEE 67A
51030929300
Water / Gas Inject
Injecting
FEE 68A
51030568300
Oil well
Producing
FEE 69
51030625600
Water / Gas Inject
Monitor
FEE 7
51030571600
Oil well
Producing
FEE 70AX
51030919100
Water / Gas Inject
Monitor
FEE 72X
51030718000
Oil well
Producing
FEE 73X
51030727400
Oil well
Producing
FEE 74X
51030730700
Oil well
Producing
FEE 75X
51030732600
Oil well
Producing
FEE 76X
51030733900
Oil well
Producing
FEE 78X
51030743400
Oil well
Producing
FEE 79X
51030742400
Water / Gas Inject
Injecting
FEE 8
51030563300
Water / Gas Inject
Injecting
FEE 80X
51030749100
Water / Gas Inject
Injecting
FEE 81X
51030751900
Oil well
Producing
FEE 82X
51030752900
Oil well
Producing
FEE 83X
51030757200
Oil well
Producing
FEE 84X
51030755400
Water / Gas Inject
Injecting
FEE 85X
51030758100
Water / Gas Inject
Injecting
FEE 86X
51030756900
Water Injection Well
P&A
50
-------
FEE 86XST
51030756901
Water / Gas Inject
Injecting
FEE 87X
51030754600
Water / Gas Inject
Monitor
FEE 88X
51030755900
Water / Gas Inject
Injecting
FEE 89X
51030755500
Water / Gas Inject
Injecting
FEE 9
51030551100
Oil well
P&A
FEE 90X
51030758000
Water / Gas Inject
Injecting
FEE 91X
51030757300
Water / Gas Inject
Injecting
FEE 92X
51030755600
Water / Gas Inject
Monitor
FEE 93X
51030759100
Water / Gas Inject
Injecting
FEE 94X
51030759400
Water / Gas Inject
Injecting
FEE 95X
51030764700
Oil well
Producing
FEE 96X
51030764800
Oil well
Producing
FEE 97X
51030779100
Oil well
Producing
FEE 98X
51030782700
Water / Gas Inject
Injecting
FEE 99X
51030784000
Oil well
Producing
FEE 9ST 9
51030551101
Oil well
Producing
GRAY A A17X
51030768900
Water / Gas Inject
Injecting
GRAY A A21X
51030830200
Water / Gas Inject
Injecting
GRAY A A8AX
51030919700
Water / Gas Inject
Injecting
GRAY A10
51030573400
Water / Gas Inject
Injecting
GRAY A12
51030613700
Oil well
Producing
GRAY A13
51030577800
Water / Gas Inject
Monitor
GRAY A14
51030613900
Oil well
Producing
GRAY A15
51030576200
Oil well
Producing
GRAY A16
51030613600
Water / Gas Inject
Injecting
GRAY A18X
51030789800
Oil well
Producing
GRAY A19X
51030787300
Oil well
Producing
GRAY A20X
51030803500
Water / Gas Inject
Injecting
GRAY A22X
51030831700
Oil well
Producing
GRAY A9
51030571500
Oil well
Producing
GRAY B10
51030612300
Water / Gas Inject
Injecting
GRAY B11
51030581800
Oil well
Producing
GRAY B12
51030612900
Oil well
Producing
GRAY B13
51030612600
Oil well
Producing
GRAY B14A
51030928900
Water / Gas Inject
Injecting
GRAY B15
51030579600
Oil well
Producing
GRAY B16
51030612700
Oil well
Producing
GRAY B17
51030582500
Oil well
Monitor
GRAY B18X
51030638600
Oil well
Monitor
GRAY B19X
51036639700
Oil well
Producing
GRAY B2
51030578700
Oil well
Producing
51
-------
GRAY B20X
51030101500
Water / Gas Inject
Injecting
GRAY B21X
51031035700
Oil well
Producing
GRAY B22X
51031036000
Oil well
Producing
GRAY B23X
51031033800
Oil well
Producing
GRAY B24X
51031033700
Oil well
Producing
GRAY B25X
51031057200
Oil well
Producing
GRAY B26X
51031057500
Oil well
Producing
GRAY B27X
51031057400
Oil well
Producing
GRAY B28X
51031101200
Oil well
Producing
GRAY B3
51030613200
Water / Gas Inject
Injecting
GRAY B4
51030613300
Water / Gas Inject
Injecting
GRAY B5
51030612400
Water / Gas Inject
Injecting
GRAY B6
51030613100
Water / Gas Inject
Injecting
GRAY B7
51030612800
Water / Gas Inject
Injecting
GRAY B8
51030581100
Water / Gas Inject
Injecting
GRAY B9
51030612500
Water / Gas Inject
Injecting
GUIBERSON SA 1
51030581300
Water / Gas Inject
Injecting
GUIBERSON SA 5 X
51031115600
Oil well
Producing
HAGOOD L N-A 17X
51030914200
Oil well
P&A
HAGOOD LN A1 OX
51030791300
Oil well
Shut In
HAGOOD LN A11X
51030794900
Water / Gas Inject
Injecting
HAGOOD LN A12X
51030793600
Oil well
Producing
HAGOOD LN A13X
51030799100
Water / Gas Inject
Injecting
HAGOOD LN A14X
51030795000
Water / Gas Inject
P&A
HAGOOD LN A14XST
51030795001
Water / Gas Inject
Injecting
HAGOOD LN A15X
51030829300
Oil well
Producing
HAGOOD LN A16X
51030830000
Water / Gas Inject
Injecting
HAGOOD LN A17XST
51030914201
Water / Gas Inject
Monitor
HAGOOD LN A2
51030574300
Oil well
Monitor
HAGOOD LN A3
51030576800
Oil well
Monitor
HAGOOD LN A5
51030573600
Water / Gas Inject
Injecting
HAGOOD LN A7
51030575700
Water / Gas Inject
Monitor
HAGOOD LN A9X
51030702200
Water / Gas Inject
Injecting
HAGOOD MC A1
51030632800
Water / Gas Inject
Injecting
HAGOOD MC A10X
51031041400
Oil well
Producing
HAGOOD MC A11X
51031041300
Oil well
Producing
HAGOOD MC A12X
51031053300
Oil well
Producing
HAGOOD MC A13X
51031053100
Oil well
Producing
HAGOOD MC A14X
51031054800
Oil well
Shut In
HAGOOD MC A15X
51031062800
Oil well
Producing
HAGOOD MC A16X
51031061200
Oil well
Producing
52
-------
HAGOOD MC A17X
51031062900
Oil well
Producing
HAGOOD MC A18X
51031061300
Oil well
Producing
HAGOOD MC A19X
51031067000
Water / Gas Inject
Injecting
HAGOOD MC A2
51030102300
Oil well
Producing
HAGOOD MC A21X
51031070900
Oil well
Producing
HAGOOD MC A3
51030633000
Water / Gas Inject
Injecting
HAGOOD MC A4
51030632600
Water / Gas Inject
Injecting
HAGOOD MC A5
51030633100
Water / Gas Inject
Injecting
HAGOOD MC A6
51030102400
Oil well
Producing
HAGOOD MC A7
51030106700
Oil well
Producing
HAGOOD MC A8 A 8
51030632500
Water / Gas Inject
Injecting
HAGOOD MC A9
51030632700
Water / Gas Inject
Injecting
HAGOOD MC B1A
51031102800
Oil well
Producing
HAGOOD MC B2
51031187000
Oil well
Producing
HEFLEY CS 4X
51030856200
Oil well
Producing
HEFLEY ME 2
51030545200
Water / Gas Inject
Monitor
HEFLEY ME 5X
51030719600
Oil well
Producing
HEFLEY ME 6X
51030729300
Oil well
Producing
HEFLEY ME 7X
51030873700
Oil well
Producing
HEFLEY ME 8X
51030869600
Oil well
Producing
L N HAGOOD A- 1
51030572100
Water / Gas Inject
Injecting
L N HAGOOD A-8 IJ A8
51030569100
Water / Gas Inject
Injecting
LACY SB 1
51030573200
Oil well
Producing
LACY SB 11Y
51030914400
Salt Water Disposal
Injecting
LACY SB 12Y
51030914500
Oil well
Producing
LACY SB 13Y
51031057000
Oil well
Producing
LACY SB 2AX
51030928200
Water / Gas Inject
Injecting
LACY SB 3
51030568900
Oil well
Producing
LACY SB 4
51030575800
Water / Gas Inject
Monitor
LACY SB 6X
51030794700
Oil well
Monitor
LACY SB 7X
51030797800
Water / Gas Inject
Injecting
LACY SB 9X
51030831800
Oil well
Monitor
LARSON FA 1
51030106600
Oil well
Producing
LARSON FA 2
51030107200
Water / Gas Inject
Injecting
LARSON FA 3X
51031071000
Oil well
Monitor
LARSON FVA1
51030547600
Oil well
Producing
LARSON FV A2X
51030721600
Water / Gas Inject
Monitor
LARSON FVB11
51030630200
Water / Gas Inject
Injecting
LARSON FVB12
51030100900
Oil well
Producing
LARSON FV B14X
51030641400
Oil well
Shut In
LARSON FV B15X
51030700800
Oil well
Producing
53
-------
LARSON FV B17X
51030707800
Oil well
Producing
LARSON FV B18X
51030708300
Oil well
Producing
LARSON FV B19X
51030710600
Oil well
Producing
LARSON FV B2
51030620200
Water / Gas Inject
Monitor
LARSON FV B20X
51030709900
Oil well
Producing
LARSON FVB21X
51030716500
Oil well
Producing
LARSON FV B22X
51030722700
Oil well
Producing
LARSON FV B23X
51030724200
Oil well
Producing
LARSON FV B24X
51030873800
Oil well
Producing
LARSON FV B25X
51030916500
Oil well
Producing
LARSON FV B27X
51030948800
Oil well
Producing
LARSON FV B4
51030629800
Water / Gas Inject
Injecting
LARSON FV B8
51030620100
Water / Gas Inject
Injecting
LARSON MB 10X25
51030715900
Oil well
Producing
LARSON MB 12X25
51030727000
Oil well
Producing
LARSON MB 2-26 A226
51030566300
Oil well
Producing
LARSON MB 3X26
51030711000
Oil well
Producing
LARSON MB 4X26
51030717700
Oil well
Monitor
LARSON MB 8X25
51030709300
Oil well
Producing
LARSON MB A1AX
51031075600
Water / Gas Inject
Monitor
LARSON MB A2
51030633200
Oil well
Producing
LARSON MB A3X
51031053400
Oil well
Producing
LARSON MB A4X
51031055200
Oil well
Producing
LARSON MB B1
51030576500
Water / Gas Inject
Injecting
LARSON MB B3AX
51031075500
Water / Gas Inject
Injecting
LARSON MB C1-25
51030618600
Water / Gas Inject
Monitor
LARSON MBC1AX
51031076300
Oil well
Producing
LARSON MB C2
51030569000
Water / Gas Inject
Injecting
LARSON MB C3
51030570800
Water / Gas Inject
Injecting
LARSON MB C3-25
51030618700
Water / Gas Inject
Injecting
LARSON MB C4
51031139700
Oil well
Producing
LARSON MB C5
51031142900
Oil well
Producing
LARSON MB C9X25
51030715500
Oil well
Producing
LARSON MB D1-26E
51030620000
Water / Gas Inject
Injecting
LEVI SON 10
51030621700
Oil well
Producing
LEVI SON 11
51030619800
Water / Gas Inject
Injecting
LEVI SON 12
51030103100
Water / Gas Inject
Injecting
LEVI SON 13
51030619400
Water / Gas Inject
Injecting
LEVI SON 14
51030619900
Water / Gas Inject
Injecting
LEVI SON 17
51030619500
Water / Gas Inject
Injecting
LEVI SON 18
51030618200
Oil well
Producing
54
-------
LEVISON 2
51030559300
Oil well
Producing
LEVI SON 21X
51030638700
Oil well
Producing
LEVISON 22X
51030708900
Oil well
Monitor
LEVISON 23X
51030712300
Oil well
Producing
LEVISON 24X
51030711400
Oil well
Producing
LEVISON 25X
51030722200
Oil well
Producing
LEVISON 26X
51030726700
Oil well
Producing
LEVISON 27X
51030728900
Oil well
Producing
LEVISON 28X
51030731600
Oil well
Monitor
LEVISON 29X
51030732000
Water / Gas Inject
Injecting
LEVISON 30X
51030735100
Water / Gas Inject
Injecting
LEVISON 31X
51030735300
Oil well
Monitor
LEVISON 32X
51030747500
Water / Gas Inject
Injecting
LEVISON 33X
51030752100
Oil well
Producing
LEVISON 34X
51030758600
Water / Gas Inject
Injecting
LEVISON 35X
51030868300
Oil well
Producing
LEVISON 6
51030106200
Oil well
Producing
LEVISON 7
51030619700
Oil well
Monitor
LEVISON 8
51030103000
Water / Gas Inject
Injecting
LEVISON 9
51030628600
Water / Gas Inject
Injecting
LEVSION 1
51030559100
Oil well
Producing
LN - HAGOOD A6
51030569400
Oil well
Producing
LN HAGOOD A-4
51030570700
Oil well
Shut In
MAGOR1A
51030989300
Water / Gas Inject
Injecting
MATTERN 1
51030580400
Water / Gas Inject
Injecting
MCLAUGHLIN AC 1
51030573100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 10
51030578000
Oil well
Monitor
MCLAUGHLIN AC 11
51030569300
Oil well
Producing
MCLAUGHLIN AC 12
51030579800
Water / Gas Inject
Injecting
MCLAUGHLIN AC 13
51030581000
Water / Gas Inject
Injecting
MCLAUGHLIN AC 14
51030105800
Oil well
Producing
MCLAUGHLIN AC 15
51030576700
Oil well
Producing
MCLAUGHLIN AC 16
51030105400
Oil well
Producing
MCLAUGHLIN AC 17
51030631700
Water / Gas Inject
Injecting
MCLAUGHLIN AC 18
51030105300
Water / Gas Inject
Injecting
MCLAUGHLIN AC 19
51030579400
Oil well
Producing
MCLAUGHLIN AC 2
51030573300
Oil well
Producing
MCLAUGHLIN AC 20
51030578200
Water / Gas Inject
Injecting
MCLAUGHLIN AC 21
51030578100
Oil well
Producing
MCLAUGHLIN AC 22
51030105500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 23
51030571800
Water / Gas Inject
Injecting
55
-------
MCLAUGHLIN AC 24
51030576300
Water / Gas Inject
Injecting
MCLAUGHLIN AC 25
51030631800
Oil well
Producing
MCLAUGHLIN AC 26
51030105000
Water / Gas Inject
Injecting
MCLAUGHLIN AC 27
51036005300
Oil well
Producing
MCLAUGHLIN AC 28
51030569900
Oil well
Producing
MCLAUGHLIN AC 29
51030581900
Oil well
Producing
MCLAUGHLIN AC 30
51030105100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 31
51030105200
Water / Gas Inject
Injecting
MCLAUGHLIN AC 32
51030581200
Water / Gas Inject
Injecting
MCLAUGHLIN AC 33
51030631500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 34
51030104700
Water / Gas Inject
Injecting
MCLAUGHLIN AC 35
51030581700
Oil well
Producing
MCLAUGHLIN AC 36
51030104800
Oil well
Producing
MCLAUGHLIN AC 37
51030633300
Oil well
Producing
MCLAUGHLIN AC 38
51030632200
Oil well
Producing
MCLAUGHLIN AC 39A
51031049300
Oil well
Producing
MCLAUGHLIN AC 3AX
51030920700
Water / Gas Inject
Injecting
MCLAUGHLIN AC 4
51030573800
Oil well
Producing
MCLAUGHLIN AC 41AX
51030920100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 42
51030579500
Water / Gas Inject
Monitor
MCLAUGHLIN AC 43
51030632400
Water / Gas Inject
Injecting
MCLAUGHLIN AC 44A
51031096100
Oil well
Producing
MCLAUGHLIN AC 44D
51030631600
Salt Water Disposal
Injecting
MCLAUGHLIN AC 45 AC
51030631900
Water / Gas Inject
Injecting
MCLAUGHLIN AC 46ST
51030632301
Water / Gas Inject
Monitor
MCLAUGHLIN AC 47X
51030107500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 49X
51030641700
Oil well
Monitor
MCLAUGHLIN AC 5
51030571200
Oil well
Monitor
MCLAUGHLIN AC 50X
51030632100
Oil well
Producing
MCLAUGHLIN AC 51X
51030641800
Oil well
Producing
MCLAUGHLIN AC 52X
51030642500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 53X
51030101400
Oil well
Producing
MCLAUGHLIN AC 54X
51030642600
Oil well
Producing
MCLAUGHLIN AC 55X
51030641900
Water / Gas Inject
Injecting
MCLAUGHLIN AC 56X
51030642000
Water / Gas Inject
Injecting
MCLAUGHLIN AC 57X
51030701000
Oil well
Monitor
MCLAUGHLIN AC 58X
51030701400
Oil well
Producing
MCLAUGHLIN AC 59AX
51030928800
Oil well
Producing
MCLAUGHLIN AC 6
51030579900
Oil well
Producing
MCLAUGHLIN AC 60X
51030769200
Water / Gas Inject
Injecting
MCLAUGHLIN AC 61X
51030769000
Oil well
Monitor
56
-------
MCLAUGHLIN AC 62X
51030771500
Oil well
Producing
MCLAUGHLIN AC 63X
51030771600
Water / Gas Inject
Injecting
MCLAUGHLIN AC 65X
51030771800
Oil well
Producing
MCLAUGHLIN AC 66X
51030773800
Water / Gas Inject
Injecting
MCLAUGHLIN AC 67X
51030817000
Oil well
Producing
MCLAUGHLIN AC 68X
51030829200
Oil well
Producing
MCLAUGHLIN AC 69X
51030829400
Water / Gas Inject
Injecting
MCLAUGHLIN AC 7
51030580900
Water / Gas Inject
Injecting
MCLAUGHLIN AC 70X
51030830100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 71X
51030829700
Oil well
Producing
MCLAUGHLIN AC 72X
51030832000
Water / Gas Inject
Injecting
MCLAUGHLIN AC 73X
51030831900
Oil well
Producing
MCLAUGHLIN AC 74X
51030832100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 75X
51030829800
Oil well
Producing
MCLAUGHLIN AC 76X
51030914100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 77X
51030915200
Oil well
Producing
MCLAUGHLIN AC 78X
51030915500
Oil well
Producing
MCLAUGHLIN AC 79X
51030930000
Oil well
Monitor
MCLAUGHLIN AC 8
51030573500
Oil well
Producing
MCLAUGHLIN AC 80X
51030930100
Oil well
Monitor
MCLAUGHLIN AC 81AX
51031064500
Oil well
Producing
MCLAUGHLIN AC 82X
51031054600
Oil well
Producing
MCLAUGHLIN AC 83X
51031059500
Oil well
Producing
MCLAUGHLIN AC 84Y
51031057300
Oil well
Producing
MCLAUGHLIN AC 86Y
51031058400
Oil well
Producing
MCLAUGHLIN AC 88X
51031070000
Oil well
Producing
MCLAUGHLIN AC 9
51030576600
Oil well
Monitor
MCLAUGHLIN AC 90X
51031069900
Oil well
Producing
MCLAUGHLIN AC 91X
51031072600
Water / Gas Inject
Injecting
MCLAUGHLIN AC 92X
51031070800
Oil well
Producing
MCLAUGHLIN AC 93X
51031072700
Water / Gas Inject
Injecting
MCLAUGHLIN AC 94X
51031072500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 95X
51031140800
Oil well
Producing
MCLAUGHLIN AC A1
51030609200
Oil well
Monitor
MCLAUGHLIN AC A3X
51030863000
Oil well
Producing
MCLAUGHLIN AC C2
51031104100
Oil well
Monitor
MCLAUGHLIN SW6
51030627800
Oil well
P&A
MCLAUGHLIN SHARPLES 10X28
51030749000
Oil well
Producing
MCLAUGHLIN SHARPLES 1-28
51030560300
Water / Gas Inject
Injecting
MCLAUGHLIN SHARPLES 12X33
51030759800
Oil well
Producing
MCLAUGHLIN SHARPLES 1-33
51030551300
Oil well
Producing
57
-------
MCLAUGHLIN SHARPLES 13X3
51030873900
Oil well
Producing
MCLAUGHLIN SHARPLES 14Y33
51030912300
Oil well
Producing
MCLAUGHLIN SHARPLES 15X32
51030885400
Oil well
Producing
MCLAUGHLIN SHARPLES 16X32
51030913200
Water / Gas Inject
Injecting
MCLAUGHLIN SHARPLES 2-28
51030560000
Oil well
Producing
MCLAUGHLIN SHARPLES 2-32
51030627300
Water / Gas Inject
Monitor
MCLAUGHLIN SHARPLES 2-33
51030106800
Water / Gas Inject
Injecting
MCLAUGHLIN SHARPLES 3-32
51030627000
Oil well
Monitor
MCLAUGHLIN SHARPLES 3-33
51030629000
Oil well
Producing
MCLAUGHLIN SHARPLES 4-33
51030629100
Water / Gas Inject
Injecting
MCLAUGHLIN SHARPLES 5-33
51030104500
Oil well
Monitor
MCLAUGHLIN SHARPLES 6-33
51030628800
Oil well
Monitor
MCLAUGHLIN SHARPLES 7-33
51030104600
Water / Gas Inject
Monitor
MCLAUGHLIN SHARPLES 8-33
51030628900
Water / Gas Inject
Monitor
MCLAUGHLIN SHARPLES 9X33
51030746500
Oil well
Producing
MCLAUGHLIN SW11X
51030759700
Water / Gas Inject
Injecting
MCLAUGHLIN SW12X
51030760100
Water / Gas Inject
Injecting
MCLAUGHLIN SW 1ST
51030548300
Oil well
P&A
MCLAUGHLIN SW 1 ST 1
51030548301
Water / Gas Inject
Monitor
MCLAUGHLIN SW2
51030627700
Oil well
Producing
MCLAUGHLIN SW 3
51030104400
Water / Gas Inject
Injecting
MCLAUGHLIN SW4
51030107600
Oil well
Producing
MCLAUGHLIN SW 5
51030627900
Oil well
Producing
MCLAUGHLIN SW6ST
51030627801
Water / Gas Inject
Injecting
MCLAUGHLIN SW7X
51030746100
Oil well
Producing
MCLAUGHLIN SW8X
51030753000
Water / Gas Inject
Injecting
MCLAUGHLIN UNIT A1
51030581600
Oil well
Producing
MCLAUGHLIN UNIT B1
51030582600
Oil well
Producing
MCLAUGHLIN UNIT B2X
51031057600
Water / Gas Inject
Injecting
MELLEN 3A
51031098100
Oil well
Producing
MELLEN WP 1
51036000300
Water / Gas Inject
Injecting
MELLEN WP 2
51030105600
Water / Gas Inject
Injecting
NEAL 2AX
51030920800
Water / Gas Inject
Injecting
NEAL4
51030565500
Water / Gas Inject
Injecting
NEAL 5A
51030565900
Oil well
Producing
NEAL 6X
51030790600
Oil well
Producing
NEAL 7X
51030804200
Water / Gas Inject
Injecting
NEAL 8X
51030804300
Water / Gas Inject
P&A
NEAL 8XST
51030804301
Water / Gas Inject
Injecting
NEAL 9Y
51030912000
Oil well
Producing
NEWTON ASSOC UNIT D2X
51030868500
Oil well
Monitor
58
-------
NIKKEL 3
51030619200
Water / Gas Inject
Injecting
PURDY 1-1
51030545300
Water / Gas Inject
Monitor
PURDY 2X1
51030881000
Oil well
Producing
RAVEN A1AX
51030917800
Water / Gas Inject
Injecting
RAVEN A2
51030625700
Water / Gas Inject
Injecting
RAVEN A3
51030624400
Water / Gas Inject
Injecting
RAVEN A4
51030625800
Water / Gas Inject
Injecting
RAVEN A5X
51030718800
Oil well
Producing
RAVEN B1
51030564900
Oil well
Producing
RAVEN B2AX
51030923800
Water / Gas Inject
Monitor
RECTOR 1
51030549400
Oil well
Producing
RECTOR 11X
51030867200
Oil well
Shut In
RECTOR 12X
51030919900
Oil well
Shut In
RECTOR 3
51030106000
Water / Gas Inject
Injecting
RECTOR 8X
51030704300
Oil well
Producing
RECTOR 9X
51030714700
Oil well
Shut In
RIGBY 1
51030569700
Oil well
Producing
RIGBY 5X
51030804700
Water / Gas Inject
Injecting
RIGBY 6Y
51030910700
Oil well
Producing
RIGBY A2AX
51030920000
Water / Gas Inject
Injecting
RIGBY A3X
51030791000
Oil well
Producing
RIGBY A4X
51030791100
Oil well
Monitor
RIGBY A7Y
51030915100
Oil well
Monitor
ROOTH DF 1
51030579700
Water / Gas Inject
Injecting
ROOTH DF 5 X
51031143000
Oil well
Producing
ROOTH DF 6 X
51031125000
Oil well
Producing
S B LACY 3
51030568900
Oil well
Monitor
STOFFER CR A1
51030562700
Water / Gas Inject
Injecting
STOFFER CR A2
51030559200
Water / Gas Inject
Injecting
STOFFER CR B1
51030567300
Oil well
Producing
SW MCLAUGHLIN 10X
51030754700
Oil well
Producing
SW MCLAUGHLIN 9X
51030753500
Oil well
Producing
U P 4829
51030623100
Water / Gas Inject
P&A
UNION PACIFIC 1 150X 16
51031150200
Oil well
Producing
UNION PACIFIC 1 151X 16
51031150100
Oil well
Producing
UNION PACIFIC 1 153X 16
51031146401
Water / Gas Inject
Injecting
UNION PACIFIC 100X20
51030788600
Oil well
Producing
UNION PACIFIC 101X20
51030797300
Oil well
Monitor
UNION PACIFIC 10-21
51030568501
Oil well
Monitor
UNION PACIFIC 102X20
51030797700
Water / Gas Inject
Injecting
UNION PACIFIC 103X20
51030799000
Water / Gas Inject
Injecting
59
-------
UNION PACIFIC 104X20
51030803000
Water / Gas Inject
Injecting
UNION PACIFIC 105X29
51030794500
Oil well
Producing
UNION PACIFIC 106X32
51030845000
Oil well
Producing
UNION PACIFIC 107X32
51030849800
Oil well
Producing
UNION PACIFIC 108X21
51030849500
Water / Gas Inject
Injecting
UNION PACIFIC 109X32
51030849700
Oil well
Producing
UNION PACIFIC 110X21
51030853000
Water / Gas Inject
Injecting
UNION PACIFIC 111X29
51030852200
Oil well
Producing
UNION PACIFIC 11-21
51030616200
Oil well
Producing
UNION PACIFIC 112X21
51030873500
Oil well
Monitor
UNION PACIFIC 113X22
51030860600
Oil well
Monitor
UNION PACIFIC 115X21
51030866600
Oil well
Producing
UNION PACIFIC 117X22
51030866700
Oil well
Producing
UNION PACIFIC 118X21
51030869700
Oil well
Producing
UNION PACIFIC 119X21
51030869800
Oil well
Producing
UNION PACIFIC 120X21
51030869900
Oil well
Producing
UNION PACIFIC 12-27
51030620400
Oil well
Producing
UNION PACIFIC 122X21
51030870000
Oil well
Monitor
UNION PACIFIC 126X32
51030885100
Oil well
Producing
UNION PACIFIC 127X31
51030884700
Oil well
Producing
UNION PACIFIC 128X31
51030910000
Oil well
Producing
UNION PACIFIC 129X31
51030885200
Oil well
Producing
UNION PACIFIC 130X32
51030885300
Oil well
Producing
UNION PACIFIC 131X32
51030885500
Oil well
Producing
UNION PACIFIC 1-32
51030556700
Water / Gas Inject
Injecting
UNION PACIFIC 13-28
51030622000
Water / Gas Inject
Injecting
UNION PACIFIC 132X21
51030874600
Oil well
Monitor
UNION PACIFIC 133X21
51030876400
Oil well
Producing
UNION PACIFIC 134X21
51030904100
Water / Gas Inject
Injecting
UNION PACIFIC 135Y28
51030910500
Oil well
Monitor
UNION PACIFIC 136X20
51030913800
Oil well
Producing
UNION PACIFIC 137X20
51030913900
Water / Gas Inject
Monitor
UNION PACIFIC 138Y28
51030917300
Oil well
Producing
UNION PACIFIC 139Y28
51030918500
Oil well
Monitor
UNION PACIFIC 140Y27
51030918800
Oil well
Producing
UNION PACIFIC 141Y28
51030918900
Oil well
Producing
UNION PACIFIC 14-20
51030615400
Oil well
Producing
UNION PACIFIC 142Y28
51030919000
Oil well
Monitor
UNION PACIFIC 143Y28
51030918600
Oil well
Monitor
UNION PACIFIC 15-28
51030102900
Oil well
Monitor
UNION PACIFIC 154Y29
51031172000
Oil well
Producing
60
-------
UNION PACIFIC 156Y29
51031172100
Oil well
Producing
UNION PACIFIC 16-27
51030620600
Oil well
Shut In
UNION PACIFIC 17-27
51030621400
Oil well
Producing
UNION PACIFIC 18-21
51030616400
Oil well
Producing
UNION PACIFIC 19-28
51030621900
Water / Gas Inject
Injecting
UNION PACIFIC 20-29
51030622800
Water / Gas Inject
Injecting
UNION PACIFIC 21-32
51030627100
Water / Gas Inject
Monitor
UNION PACIFIC 2-20
51030569200
Oil well
Producing
UNION PACIFIC 22-32
51030627500
Oil well
Producing
UNION PACIFIC 23-32
51030626900
Oil well
Producing
UNION PACIFIC 24-27
51030621200
Water / Gas Inject
Injecting
UNION PACIFIC 25-34
51030106900
Oil well
Shut In
UNION PACIFIC 26-31
51030626100
Water / Gas Inject
Injecting
UNION PACIFIC 27-20
51030577000
Oil well
Monitor
UNION PACIFIC 28-22
51030617300
Oil well
Producing
UNION PACIFIC 29-32
51030548700
Oil well
Monitor
UNION PACIFIC 31-21
51030616600
Oil well
Monitor
UNION PACIFIC 32-27
51030620800
Oil well
Monitor
UNION PACIFIC 33-32
51030626600
Water / Gas Inject
Injecting
UNION PACIFIC 3-34
51030551000
Oil well
Producing
UNION PACIFIC 34-31
51030626300
Water / Gas Inject
Injecting
UNION PACIFIC 35-32
51030626800
Water / Gas Inject
Injecting
UNION PACIFIC 36-32
51030627200
Water / Gas Inject
Injecting
UNION PACIFIC 37AX29
51030917700
Water / Gas Inject
Injecting
UNION PACIFIC 39-17
51030612100
Water / Gas Inject
Injecting
UNION PACIFIC 41-20
51030615800
Water / Gas Inject
Shut In
UNION PACIFIC 4-29
51030563200
Water / Gas Inject
Injecting
UNION PACIFIC 42AX28
51030925700
Water / Gas Inject
Injecting
UNION PACIFIC 43-28
51030622100
Water / Gas Inject
Monitor
UNION PACIFIC 44AX20
51030923300
Water / Gas Inject
Injecting
UNION PACIFIC 45-21
51030569600
Water / Gas Inject
Injecting
UNION PACIFIC 47-21
51030615900
Water / Gas Inject
Injecting
UNION PACIFIC 48-29ST
51030623101
Water / Gas Inject
Injecting
UNION PACIFIC 49-27
51030621300
Oil well
Producing
UNION PACIFIC 50-29
51030107100
Water / Gas Inject
Injecting
UNION PACIFIC 51AX20
51030892800
Water / Gas Inject
Injecting
UNION PACIFIC 5-28
51030563900
Oil well
Producing
UNION PACIFIC 52A-29
51030928400
Water / Gas Inject
Injecting
UNION PACIFIC 53-32
51030627600
Water / Gas Inject
Monitor
UNION PACIFIC 54-21
51030616300
Water / Gas Inject
Injecting
UNION PACIFIC 55-17
51030612200
Water / Gas Inject
Injecting
61
-------
UNION PACIFIC 56-21
51030616700
Water / Gas Inject
Injecting
UNION PACIFIC 58-27
51030620500
Water / Gas Inject
Injecting
UNION PACIFIC 59A-27
51031120700
Oil well
Producing
UNION PACIFIC 60-31
51030626200
Water / Gas Inject
Injecting
UNION PACIFIC 61-20
51030615500
Water / Gas Inject
Injecting
UNION PACIFIC 6-21
51030574100
Oil well
Producing
UNION PACIFIC 62AX32
51030919600
Water / Gas Inject
Injecting
UNION PACIFIC 65-5
51030608900
Water / Gas Inject
Monitor
UNION PACIFIC 67-32
51030626700
Water / Gas Inject
Injecting
UNION PACIFIC 68-32
51030628700
Water / Gas Inject
Injecting
UNION PACIFIC 69-27
51030621000
Oil well
Shut In
UNION PACIFIC 71X31
51030727600
Oil well
Producing
UNION PACIFIC 7-29
51030559700
Water / Gas Inject
Injecting
UNION PACIFIC 73X29
51030738600
Oil well
Producing
UNION PACIFIC 74X27
51030741600
Oil well
Monitor
UNION PACIFIC 75X32
51030740200
Oil well
Producing
UNION PACIFIC 76X21
51030742100
Oil well
Producing
UNION PACIFIC 77X32
51030745400
Oil well
Producing
UNION PACIFIC 78X21
51030742600
Water / Gas Inject
Injecting
UNION PACIFIC 79X32
51030744800
Oil well
Monitor
UNION PACIFIC 80X28
51030746000
Water / Gas Inject
Monitor
UNION PACIFIC 81X29
51030749900
Oil well
Producing
UNION PACIFIC 8-20
51030568600
Oil well
Producing
UNION PACIFIC 82X28
51030749400
Oil well
Producing
UNION PACIFIC 83X28
51030750000
Oil well
Producing
UNION PACIFIC 84X28
51030749500
Oil well
Producing
UNION PACIFIC 85X34
51030748100
Water / Gas Inject
Injecting
UNION PACIFIC 86X27
51030748200
Water / Gas Inject
Injecting
UNION PACIFIC 87X29
51030750900
Oil well
Producing
UNION PACIFIC 88X21
51030751400
Oil well
Producing
UNION PACIFIC 89X34
51030754800
Water / Gas Inject
Injecting
UNION PACIFIC 91X28
51030756000
Water / Gas Inject
Injecting
UNION PACIFIC 9-29
51030565600
Water / Gas Inject
Injecting
UNION PACIFIC 92X28
51030757400
Water / Gas Inject
Monitor
UNION PACIFIC 94X27
51030758800
Water / Gas Inject
Injecting
UNION PACIFIC 96X29
51030765000
Oil well
Producing
UNION PACIFIC 97X29
51030765100
Oil well
Producing
UNION PACIFIC 98X32
51030765200
Oil well
Producing
UNION PACIFIC 99X29
51030785600
Oil well
Producing
UNION PACIFIC B1-34
51030548900
Water / Gas Inject
Monitor
UNION PACIFIC B2-34
51030102700
Oil well
Monitor
62
-------
UNION PACIFIC B3X34
51030744000
Oil well
Producing
UNION PACIFIC B4X34
51030753600
Water / Gas Inject
Injecting
UNION PACIFIC B5X34
51030759900
Water / Gas Inject
Injecting
UNION PACIFIC B6X34
51030760200
Water / Gas Inject
Monitor
WALBRIDGE LB 1
51030607000
Water / Gas Inject
Monitor
WALBRIDGE UNIT 1
51030607200
Water / Gas Inject
Monitor
WALBRIDGE UNIT 2X
51030920500
Oil well
Producing
WALBRIDGE UNIT 3X
51030920600
Oil well
Monitor
WEYRAUCH 2-36
51030630600
Water / Gas Inject
Injecting
WEYRAUCH 4X36
51030707200
Oil well
Producing
WEYRAUCH 5X36
51030881900
Oil well
Producing
WEYRAUCH 6X36
51030916600
Oil well
Producing
WEYRAUCH 7X36
51030916300
Oil well
Producing
AC MCLAUGHLIN 39
51030582400
P&A
P&A
AC MCLAUGHLIN 3
51030578600
P&A
P&A
MCLAUGHLIN AC 40
51030632000
P&A
P&A
AC MCLAUGHLIN 41
51030575900
P&A
P&A
AC MCLAUGHLIN 48X
51030580300
P&A
P&A
AC MCLAUGHLIN 59X
51030769100
P&A
P&A
MCLAUGHLIN AC 81X
51031053000
P&A
P&A
A.C. MCLAUGHLIN A A2
51030609300
P&A
P&A
AC MCLAUGHLIN B 1
51030611000
P&A
P&A
AC MCLAUGHLIN B 2
51030610500
P&A
P&A
AC MCLAUGHLIN 1
51030612000
P&A
P&A
AC MCLAUGHLIN 1
51030757700
P&A
P&A
ASSOCIATED 4X
51030881200
P&A
P&A
ASSOCIATED B 1
51030601200
P&A
P&A
ASSOCIATED B 2
51030601000
P&A
P&A
ASSOCIATED B 3
51030601300
P&A
P&A
BEEZLEY 1 22
51030573900
P&A
P&A
CT CARNEY 12-5
51030107000
P&A
P&A
C T CARNEY 26X35
51030745000
P&A
P&A
CARNEY CT 31X4
51030760400
P&A
P&A
CARNEY C T 34X-4
51030760000
P&A
P&A
CARNEY CT 36X34
51030759500
P&A
P&A
CARNEY CT 40X35
51030911700
P&A
P&A
CARNEY CT 42Y34
51030915400
P&A
P&A
CHASE UNIT U 1
51030600800
P&A
P&A
HILL.C.E. 1
51030601800
P&A
P&A
HEFLEY C-S 1
51030104100
P&A
P&A
C-S HEFLEY 2
51030607700
P&A
P&A
63
-------
C-S HEFLEY 3
51030607800
P&A
P&A
C R STOFFER A 3
51030562600
P&A
P&A
EMERALD 12
51030566700
P&A
P&A
EMERALD 15
51030565400
P&A
P&A
EMERALD 18
51030104900
P&A
P&A
EMERALD 21
51030546400
P&A
P&A
EMERALD 24
51030563500
P&A
P&A
EMERALD 29
51030565800
P&A
P&A
EMERALD 30
51030563000
P&A
P&A
EMERALD 31
51030623700
P&A
P&A
EMERALD 33
51030623900
P&A
P&A
EMERALD OIL CO. 3M
51030724700
P&A
P&A
EMERALD 43
51030625200
P&A
P&A
EMERALD 44
51030633800
P&A
P&A
EMERALD 45
51030603000
P&A
P&A
EMERALD 49X
51030729600
P&A
P&A
EMERALD 5
51030566600
P&A
P&A
EMERALD 7
51030624100
P&A
P&A
E OLDLAND 4
51030715200
P&A
P&A
FAIRFIELD,KITTIE A 2
51030611400
P&A
P&A
FAIRFIELD,KITTIE A 3
51030611700
P&A
P&A
F V LARSON 116
51036652500
P&A
P&A
FEE 118X
51030843900
P&A
P&A
FEE 119X
51030849400
P&A
P&A
FEE 161X
51031185900
P&A
P&A
FEE 16
51030624600
P&A
P&A
FEE 2
51030558600
P&A
P&A
FEE 46
51030610700
P&A
P&A
FEE 53
51030617400
P&A
P&A
FEE 54
51030618000
P&A
P&A
FEE 57
51030622700
P&A
P&A
FEE 58
51030614300
P&A
P&A
FEE 66
51030610900
P&A
P&A
FEE 67
51030611600
P&A
P&A
FEE 70
51030626000
P&A
P&A
FEE 71
51030610800
P&A
P&A
FEE 77X
51030736000
P&A
P&A
FEDERAL ET AL 2M
51030719700
P&A
P&A
FEDERAL ET AL 5M
51030731700
P&A
P&A
LARSON FVB10
51030629900
P&A
P&A
LARSON FV B13X
51030557900
P&A
P&A
64
-------
LARSON FV B16X
51030702400
P&A
P&A
LARSON FV B1
51030629600
P&A
P&A
LARSON FV 26Y
51030948500
P&A
P&A
LARSON FV B3
51030630500
P&A
P&A
LARSON FV B5
51030630100
P&A
P&A
LARSON FV B6
51030630300
P&A
P&A
LARSON F V B7
51030630001
P&A
P&A
LARSON FV B9
51030102500
P&A
P&A
F V LARSON 1
51030539800
P&A
P&A
GENTRY 2D
51030543700
P&A
P&A
GENTRY 3D
51030608500
P&A
P&A
NEWTON 4-D
51030104300
P&A
P&A
GENTRY 4D
51030543700
P&A
P&A
GENTRY 5D
51030608300
P&A
P&A
GENTRY 6X
51030744200
P&A
P&A
GRAY A 11
51030613800
P&A
P&A
GRAY A 11 AX
51030927500
P&A
P&A
GRAY A 8
51030568100
P&A
P&A
GRAY B 14
51030613000
P&A
P&A
GUIBERSON,S.A. A 2
51030613400
P&A
P&A
HILDENBRANDT 1
51030608100
P&A
P&A
COLTHARP JE 1
51030602400
P&A
P&A
J E COLTHARP 3
51030602500
P&A
P&A
COLTHARP JE 6X
51030714800
P&A
P&A
COLTHARP JE 9X P 9X
51030853500
P&A
P&A
PEPPER,J.E. A 1
51030550200
P&A
P&A
J E PEPPER B 1
51030606300
P&A
P&A
LACY SB 10Y
51030914300
P&A
P&A
S B LACY 2
51030570600
P&A
P&A
F V LARSON 1
51030106500
P&A
P&A
LEVI SON 15
51030618100
P&A
P&A
LEVI SON 16
51030619600
P&A
P&A
LEVI SON 19
51030106300
P&A
P&A
LEVI SON 20
51030618300
P&A
P&A
LEVISON 3
51030621600
P&A
P&A
LEVISON 4
51030560400
P&A
P&A
LEVISON 5
51030621500
P&A
P&A
L N HAGOOD B 1
51030607300
P&A
P&A
L N HAGOOD B 2
51030607100
P&A
P&A
L N HAGOOD B 3
51030607400
P&A
P&A
WALBRIDGE LB 3
51030630800
P&A
P&A
65
-------
WALBRIDGE LB 4X
51030873600
P&A
P&A
WALBRIDGE LB 5Y
51030948300
P&A
P&A
MAGOR 1
51030580800
P&A
P&A
MCLAUGHLIN 3
51030556100
P&A
P&A
MELLEN,W.P. A 3
51030105700
P&A
P&A
HEFLEY ME 1
51030607500
P&A
P&A
HEFLEY ME 3
51030545400
P&A
P&A
HEFLEY ME 4
51030543300
P&A
P&A
M B LARSON C11 X 25
51030717300
P&A
P&A
MB LARSON A 1
51030632900
P&A
P&A
MB LARSON A3
51030576400
P&A
P&A
LARSON MB 1-35
51030555700
P&A
P&A
MB LARSON C 1
51030571900
P&A
P&A
LARSON MB C2-25
51030106400
P&A
P&A
M B LARSON C425
51030618900
P&A
P&A
LARSON MB D136
51030631000
P&A
P&A
LARSON MB D226
51030102600
P&A
P&A
M B LARSON D525
51030618500
P&A
P&A
M B LARSON D625
51030619000
P&A
P&A
M B LARSON D725
51030618400
P&A
P&A
NEAL2
51030566000
P&A
P&A
NEAL3
51030567200
P&A
P&A
NEWTON ASSOC A1
51030107300
P&A
P&A
NEWTON ASSOC B 1
51030101800
P&A
P&A
NEWTON ASSOC C 1
51030102100
P&A
P&A
NEWTON ASSOC D 1
51030102200
P&A
P&A
NIKKEL 1
51030619300
P&A
P&A
NIKKEL 2
51030619100
P&A
P&A
OLDLAND 1
51030102000
P&A
P&A
OLDLAND 2
51030106100
P&A
P&A
OLDLAND 3
51030630400
P&A
P&A
OLDLAND E 5X
51030853600
P&A
P&A
OLDLAND E 6X
51030947600
P&A
P&A
PURDY16
51030606200
P&A
P&A
PURDY 3X1
51030870300
P&A
P&A
RANGELY 2M-33-19B
51030939800
P&A
P&A
RAVEN A 1
51030562900
P&A
P&A
RAVEN B 2
51030624300
P&A
P&A
RECTOR 10X
51030760300
P&A
P&A
RECTOR 2
51030608400
P&A
P&A
RECTOR 4
51030629400
P&A
P&A
66
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RECTOR 5
51030629200
P&A
P&A
RECTOR 6
51030608200
P&A
P&A
RECTOR 7
51030105900
P&A
P&A
RIGBY A224
51030570000
P&A
P&A
ROOTH 3
51030564700
P&A
P&A
MCLAUGHLIN SHARPLES 11X 3
51030760500
P&A
P&A
SHARPLES MCLAUGHLIN 132
51030107400
P&A
P&A
SHARPLES MCLAUGHLIN 432
51030627400
P&A
P&A
UNION PACIFIC 121X21
51030870500
P&A
P&A
U P3016
51030578300
P&A
P&A
UNION PACIFIC 37-29
51030623200
P&A
P&A
U P 3822
51030574400
P&A
P&A
U P 4022
51030617800
P&A
P&A
U P 4228
51030621800
P&A
P&A
U P 4420
51030571000
P&A
P&A
UNION PACIFIC 46-21
51030573700
P&A
P&A
U P 5721
51030616500
P&A
P&A
U P 5927
51030620900
P&A
P&A
UNION PACIFIC 62-32
51030626500
P&A
P&A
UNION PACIFIC 63-31
51030623000
P&A
P&A
UNION PACIFIC 63-31
51030626400
P&A
P&A
UNION PACIFIC 63AX31
51030917900
P&A
P&A
U P 6422
51030617200
P&A
P&A
U P6616
51030610600
P&A
P&A
UNION PACIFIC 72X31
51030736400
P&A
P&A
UNION PACIFIC 90X29
51030758200
P&A
P&A
UNION PACIFIC 93X27
51030756100
P&A
P&A
U P 95X 34
51030759600
P&A
P&A
COLTHARP WH A2
51030602000
P&A
P&A
COLTHARP WH A7X
51030869300
P&A
P&A
COLTHARP WH B1
51030101900
P&A
P&A
WEYRAUCH 1-36
51030630700
P&A
P&A
WEYRAUCH 336
51030630900
P&A
P&A
WHITE 1
51030543500
P&A
P&A
WHITE 2
51030545100
P&A
P&A
67
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Request for Additional Information: Rangely Gas Plant
January 8, 2024
Instructions: Please enter responses into this table and make corresponding revisions to the MRV Plan as necessary. Any long responses,
references, or supplemental information may be attached to the end of the table as an appendix. This table may be uploaded to the Electronic
Greenhouse Gas Reporting Tool (e-GGRT) in addition to any MRV Plan resubmissions.
No.
MRV Plan
EPA Questions
Responses
Section
Page
1.
2.1
5
"As of the end of 2022, 2,320,000 million standard cubic feet
(MMscF) (122.76 million metric tons (MMMT)) of C02 has been
injected into Rangely Field. Of that amount, 1,540 billion cubic feet
(BCF) (81.48 MMMT) was produced and recycled."
Please ensure that the units and values listed above are consistent.
Additionally, please check the remainder of the MRV plan to ensure
that all volumes and weights are consistent and that the values are
correct. For example, page 19 of the MRV plan states the weight as
122.76 MMT.
Corrected in several locations.
-------
No.
MRV Plan
EPA Questions
Responses
Section
Page
2.
7
31
'To account for the site conditions and complexity of a large, active
EOR operation, SEM proposes to modify the locations for obtaining
volume data for the equations in Subpart RR §98.443 as indicated
below.
The modification addresses the propagation of error that would
result if volume data from meters at each injection well were
utilized. This issue arises because while each meter has a small but
acceptable margin of error, this error would become significant if
data were taken from the approximately 284 meters within the
Rangely Field. As such, SEM proposes to use the data from custody
and operations meters on the main system pipelines to determine
injection volumes used in the mass balance. This satisfies the
requirement in 40 CFR 98.444 (b) 1 that you must select a point or
points of measurement at which the C02 stream is representative
of the C02 streams being injected, since the main line injection
stream is the same stream being injected into the wells."
While the MRV plan references 40 CFR 98.444 (b)(1) for injection,
please explain whether the identified locations are consistent with
40 CFR 98.444 (c)(1) for production, which states, 'The point of
measurement for the quantity of C02 produced from oil or other
fluid production wells is a flow meter directly downstream of each
separator that sends a stream of gas into a recycle or end use
system." Please note that subpart RR regulatory requirements
cannot be "modified," and we recommend adjusting the MRV plan
as necessary to reflect this.
Adjusted the MRV language to clarify that the equations are not
being modified. C02 production measurement is addressed in
Section 5.1.4 and is consistent with 40 CFR98.444 (c)(1) and now
further restated in Section 7.
-------
No.
MRV Plan
EPA Questions
Responses
Section
Page
3.
7.3
34
"QP,w = Volumetric gas flow rate measurement for meter w in
quarter p at standard conditions (standard cubic meters)."
In Equation RR-8, this variable is "QP,w = Volumetric gas flow rate
measurement for separator w in quarter p at standard conditions
(standard cubic meters)". Equations and variables cannot be
modified from the regulations. Please revise this section and ensure
that all equations listed are consistent with the text in 40 CFR
98.443 (https://www.ecfr.gov/current/title-40/chapter-
l/subchapter-C/part-98/subpart-RR#98.443).
Equation variables revised to comply with 40 CFR 98.443.
4.
7.3
34
"Xoil = Mass of entrained C02 in oil in the reporting year measured
utilizing commercial meters and electronic flow-measurement
devices at each point of custody transfer. The mass of C02 will be
calculated by multiplying the total volumetric rate by the C02
concentration."
In Equation RR-9, this variable is "X = Entrained CO2 in produced oil
or other fluid divided by the CO2 separated through all separators in
the reporting year (weight percent CO2, expressed as a decimal
fraction)". Equations and variables cannot be modified from the
regulations. Please revise this section and ensure that all equations
listed are consistent with the text in 40 CFR 98.443
(https://www.ecfr.gov/current/title-40/chapter- l/subchapter-
Equation variables revised to comply with 40 CFR 98.443.
C/part-98/subpart-RR#98.443).
-------
No.
MRV Plan
EPA Questions
Responses
Section
Page
5.
7.5
35
C02P = Total annual C02 mass produced (metric tons) net of C02
entrained in oil in the reporting year.
In equation RR-11, this variable is "CChp = Total annual CO2 mass
produced (metric tons) in the reporting year. Equations and
variables cannot be modified from the regulations. Please revise
this section and ensure that all equations listed are consistent with
the text in 40 CFR 98.443 (https://www.ecfr.gov/current/title-
40/chapter- l/subchapter-C/part-98/subpart-RR#98.443).
Additionally, please ensure that all instances of entrained CO2 is
addressed throughout the MRV plan.
Equation variables revised to comply with 40 CFR 98.443.
-------
Scout Energy Management, LLC
Rangely Field
Subpart RR Monitoring, Reporting and Verification (MRV) Plan
November 2023
-------
Table of Contents
Roadmap to the Monitoring, Reporting and Verification (MRV) Plan 3
1. Facility Information 4
2. Project Description 4
2.1 Project Characteristics 4
2.2 Environmental Setting 6
2.3 Description of C02 EOR Project Facilities and the Injection Process 13
3. Delineation of Monitoring Area and Timeframes 19
3.1 Active Monitoring Area 19
3.2 Maximum Monitoring Area 20
3.3 Monitoring Timeframes 20
4. Evaluation of Potential Pathways for Leakage to the Surface 20
4.1 Introduction 21
4.2 Existing Wellbores 21
4.3 Faults and Fractures 23
4.4 Natural or Induced Seismicity 23
4.5 Previous Operations 23
4.6 Pipeline / Surface Equipment 23
4.7 Lateral Migration Outside the Rangely Field 24
4.8 Drilling Through the C02 Area 24
4.9 Diffuse Leakage through the Seal 25
4.10 Monitoring, Response, and Reporting Plan for C02 Loss 25
4.11 Summary 26
5. Monitoring and Considerations for Calculating Site Specific Variables 26
5.1 For the Mass Balance Equation 26
5.2 To Demonstrate that Injected C02 is not Expected to Migrate to the Surface 30
6. Determination of Baselines 30
7. Determination of Sequestration Volumes Using Mass Balance Equations 31
7.1. Mass of C02 Received 32
7.2 Mass of C02 Injected into the Subsurface 33
7.3 Mass of C02 Produced 33
7.4 Mass of C02 emitted by Surface Leakage 34
7.5 Mass of C02 sequestered in subsurface geologic formations 35
7.6 Cumulative mass of C02 reported as sequestered in subsurface geologic formations.. 35
8. MRV Plan Implementation Schedule 35
9. Quality Assurance Program 36
9.1 Monitoring QA/QC 36
9.2 Missing Data Procedures 36
9.3 MRV Plan Revisions 37
10. Records Retention 37
11. Appendices 37
Appendix 5. Well Identification Numbers 43
2
-------
Roadmap to the Monitoring, Reporting and Verification (MRV) Plan
Scout Energy Management, LLC (SEM) operates the Rangely Weber Sand Unit (RWSU) and the
associated Raven Ridge pipeline (RRPC), (collectively referred to as the Rangely Field) in Northwest
Colorado for the primary purpose of enhanced oil recovery (EOR) using carbon dioxide (C02) flooding.
SEM has utilized, and intends to continue to utilize, injected C02 with a subsidiary purpose of establishing
long-term containment of a measurable quantity of C02 in subsurface geological formations at the Rangely
Field for a term referred to as the "Specified Period." The Specified Period includes all or some portion of
the period 2023 to 2060. During the Specified Period, SEM will inject C02 that is purchased (fresh C02)
from ExxonMobil's (XOM) Shute Creek Plant or third parties, as well as C02 that is recovered (recycled
C02) from the Rangely Field's C02 Recycle and Compression Facilities (RCF's). SEM has developed this
monitoring, reporting, and verification (MRV) plan in accordance with 40 CFR §98.440-449 (Subpart RR)
to provide for the monitoring, reporting and verification of the quantity of C02 sequestered at the Rangely
Field during the Specified Period.
SEM has chosen to submit this MRV plan to the EPA for approval according to 40 Code of Federal
Regulations (CFR) 98.440(c)(1), Subpart RR of the Greenhouse Gas Reporting Program for the purpose
of qualifying for the tax credit in section 45Q of the federal Internal Revenue Code.
This MRV plan contains eleven sections:
o Section 1 contains general facility information.
o Section 2 presents the project description. This section describes the planned injection volumes, the
environmental setting of the Rangely Field, the injection process, and reservoir modeling. It also illustrates
that the Rangely Field is well suited for secure storage of injected C02.
o Section 3 describes the monitoring area: the RWSU in Colorado.
o Section 4 presents the evaluation of potential pathways for C02 leakage to the surface. The assessment
finds that the potential for leakage through pathways other than the man-made wellbores and surface
equipment is minimal.
o Section 5 describes SEM's risk-based monitoring process. The monitoring process utilizes SEM's reservoir
management system to identify potential C02 leakage indicators in the subsurface. The monitoring process
also utilizes visual inspection of surface facilities and personal H2S monitors program as applied to
Rangely Field. SEM's MRV efforts will be primarily directed towards managing potential leaks through
wellbores and surface facilities.
o Section 6 describes the baselines against which monitoring results will be compared to assess whether
changes indicate potential leaks.
o Section 7 describes SEM's approach to determining the volume of C02 sequestered using the mass
balance equations in 40 CFR §98.440-449, Subpart RR of the Environmental Protection Agency's (EPA)
Greenhouse Gas Reporting Program (GHGRP). This section also describes the site-specific factors
considered in this approach.
o Section 8 presents the schedule for implementing the MRV plan.
o Section 9 describes the quality assurance program to ensure data integrity.
o Section 10 describes SEM's record retention program.
o Section 11 includes several Appendices.
3
-------
1. Facility Information
The Rangely Gas Plant, operated by SEM and a part of the Rangely Field, reports under Greenhouse Gas
Reporting Program Identification number 537787.
The Colorado Oil and Gas Conservation Commission (COGCC)1 regulates all oil, gas and geothermal
activity in Colorado. All wells in the Rangely Field (including production, injection and monitoring wells) are
permitted by COGCC through Code of Colorado Regulations (CCR) 2 CCR 404-1:301. Additionally,
COGCC has primacy to implement the Underground Injection Control (UIC) Class II program in the state
for injection wells. All injection wells in the Rangely Field are currently classified as UIC Class II wells.
Wells in the Rangely Field are identified by name, API number, status, and type. The list of wells as of April,
2023 is included in Appendix 5. Any new wells will be indicated in the annual report.
2. Project Description
This section describes the planned injection volumes, environmental setting of the Rangely Field, injection
process, and reservoir modeling conducted.
2.1 Project Characteristics
SEM utilized historic production and injection of the RWSU in order to create a production and injection
forecast, included here to provide an overview of the total amounts of C02 anticipated to be injected,
produced, and stored in the Rangely Field as a result of its current and planned C02 EOR operations during
the forecasted period. This forecast is based on historic and predicted data. Figure 1 shows the actual
(historic) C02 injection, production, and stored volumes in the Rangely Field from 1986, when Chevron
initiated C02 flooding, through 2022 (solid line) and the forecast for 2023 through 2060 (dotted line). It is
important to note that this is just a forecast; actual storage data will be collected, assessed, and reported as
indicated in Sections 5, 6, and 7 in this MRV Plan. The forecast does illustrate, however, the large potential
storage capacity at Rangely field.
1 Pursuant to Colorado SB21-285, effective July 1, 2023, the COGCC will become the Energy and Carbon
Management Commission.
4
-------
Rangely Field
Historical and Projected C02
6000
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O
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4000
3000
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C02 Production
try""
C02 Stored
Forecast C02 Stored
u v
JL
C02 Injection
Forecast C02 Injection
IDO^-OOINIDO^-OOINIDO^-OOINIDO^-OO
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aiaiaiaiooooooooooooooo
*H*H*H*H(N(N(N(N(N(N(N(N(N(N(N(N(N(N(N
Year
Figure 1 - Rangely Field Historic and Forecast C02 Injection, Production, and Storage 1986-2060
The amount of C02 injected at Rangely Field is adjusted periodically to maintain reservoir pressure and to
increase recovery of oil by extending or expanding the EOR project. The amount of C02 injected is the
amount needed to balance the fluids removed from the reservoir and to increase oil recovery. While the
model output shows C02 injection and storage through 2060, this data is for planning purposes only and
may not necessarily represent the actual operational life of the Rangely Field EOR project. As of the end
of 2022, 2,320,000 million standard cubic feet (MMscF) (122.76 million metric tons (MMMT)) of C02 has
been injected into Rangely Field. Of that amount, 1,540 billion cubic feet (BCF) (81.48 MMMT) was
produced and recycled.
While tons of C02 injected and stored will be calculated using the mass balance equations described in
Section 7, the forecast described above reflects that the total amount of C02 injected and stored over the
modeled injection period to be 967,000 MMscF (51.2 MMMT). This represents approximately 35.7% of the
theoretical storage capacity of Rangely Field.
Figure 2 presents the cumulative annual forecasted volume of C02 stored by year through 2060, the
modeling period forthe projection in Figure 1. The cumulative amount stored is equal to the sum of the annual
storage volume for each year plus the sum of the total of the annual storage volume for each previous year.
As is typical with C02 EOR operations, the rate of accumulation of stored C02 tapers overtime as more
recycled C02 is used for injection. Figure 2 illustrates the total cumulative storage overthe modeling period,
projected to be 967,000 MMscF (51.2 MMMT) of C02.
5
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Rangely Field
Historical and Forecast Cumulative C02 Storage
60
i-
(0
-------
Figure 3 - Regional map showing Rangely's position between the Uinta and Piceance Basin.
The reservoir, Weber Sands, is comprised of clean eolian quartz deposited in an erg (sand sea)
depositional environment. Internally, these dune sands are separated into six main packages (odd
numbers, 1 to 11) with the fluvial Maroon Formation (even numbers, 2 to 10) interfingering the field from
the north. The Weber Formation is underlain by the fossiliferous Desmoinesian carbonates of the Morgan
Formation, and overlain by the siltstones and shales of the Phosphoria/Park City and Moenkopi
Formations.
For the majority of the region, the Phosphoria Formation acts as an impermeable barrier above the
Weber Formation and is a hydrocarbon source for the overlying strata. However, due to the large thrust
fault south and west of the field, the Phosphoria Formation was driven down to significantly deeper
depths, and below the reservoir Weber sands, allowing for maturation and expulsion of the hydrocarbons
to migrate upward into stratigraphically older, but structurally shallower reservoirs sometime during the
Jurassic. At Rangely, the Phosphoria Formation is almost entirely missing above the Weber Formation,
but the Moenkopi Formation sits directly above the sands creating the seal for the petroleum system.
Fresh water in and around the town/field of Rangely is sourced from the quaternary creeks and rivers that
cut across the region (data obtained from the Colorado Division of Water Resources). No confined fresh
water aquifers are present between the reservoir rock and the surface. Safety measures are still taken to
protect the shallowest of rocks that contain rain water seepage (unconfined aquifer) into the Mancos
Formation (surface exposure at Rangely) illustrated by the surface casing on Figure 4. The shallowest
point of the reservoir is 5,486 ft below the surface (4,986 ft below any possible fresh rain water seepage).
The mere presence of hydrocarbons and the successful implication of a C02 flood indicates the quality
and effectiveness of the seal to isolate this reservoir from higher strata.
7
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Uinta Basin
Douglas Creek
Arch
Piceance Basin
ichesne River and Uinta Fms
CoKon Fm
Wasatch Fr
Wasatch and
Fort Union Fms
k I r_.
rm
Blackhawk Fm
Ferron Ss Mbr of Ma cos Sh and Frontu
Dakota Ss
Sue hem Cgl Mbr
Salt Wash Ss O O
Morrison Fm
O Entrada Ss O
Glen Canyon Ss
Cftnle Fm
Moenkep. Fm
Source
__ParY. City Fm
upper Weber Ss
Reservoir
Maroon
cr_ Fm
Round Valley Ls
Manning Canyon Sh
Doughnut Sh/Humbug Fm
Deseret Ls
Leadville Ls
Madison Ls
Pinyon.
-TfeniWU rf"
Dotsero Fm
Lodore Fm
Sawatch Ss
KEY
PETROLEUM
SYSTEMS:
I| Green River
system
I| Mesaverde
system
l| Mancos/Mowry
system
I| Phosphoria
system SOUTCe
Grassy Trail
° Creek oil
~ Mtnturn system
,, SignFficant oil production
{indicating source rock)
v./ Significant gas production
^ (indicating source rock)
S Source rocks
(R) Rangely Field
Main reservoir
I I Hiatus
Stratigraphy
at Rangely
Figure 4. Stratigraphic Column of formations at the Rangely Field. Due to a large fault the source
rock (Phosphoria) is stratigraphically above the reservoir rock (Weber), but structurally, the
source lies below the reservoir, (from U.S. Geological Survey, 2003)
Figure 5 shows the doubly plunging anticline with the long axis along a northwest-southeast trend and the
short axis along a northeast-southwest trend. In 1949 the depth of a gas cap was established at -330 ft
subsea and an Oil Water Contact (OWC) at -1150 ft subsea. Many core analysis suggest that below this -
1150' OWC is a transition/residual oil zone. However, for the purpose of this analysis and all volumetrics
8
-------
the base of the reservoir will be at the -1150' subsea depth determined in 1949.
Geologically, the Weber Sands were deposited on top of the Morgan formation which is a combination of
interbedded shale, siltstone, and cherty limestone. Few wells are drilled deep enough to penetrate the
Morgan formation within the Rangely Field to gather porosity/permeability data locally. However, analysis
of the Morgan formation from other fields/outcrops indicate that it is a non-reservoir rock (low
porosity/permeability), and would be sufficient as a basial barrier for the field. The highest subsurface
elevation of the base of the Weber Sands is deeper than the -1150' used for the OWC. Meaning injected
C02 should not encounter the Morgan formation. Additionally, Section 4.7 explains how the Rangely
Field is confined laterally through the nature of the anticline's structure.
Figure 5. Structure map of the Weber 1 (top of reservoir). Colors illustrate the maximum aerial
coverage of the Gas Cap (Red), Main Reservoir (Green), and Transitional Reservoir (Blue). Cross
section A-A' is predominantly along the long axis of the field and B-B' is along the short axis.
The Rangely Field has one main field fault (MFF) and numerous smaller faults (isolated and joint) and
fractures that are present throughout the stratigraphic column between the base of the Weber reservoir
and surface. Faults within the reservoir were measured by well-to-well displacement, while the fractures
were measured and observed as calcite veins on the surface with no displacement. The MFF has a NE-
WSWtrend and cuts through the reservoir interval. In the 1960's Rangely residents began experiencing
felt earthquakes. Between 1969 and 1973, a joint investigation with the USGS installed seismic
monitoring stations in and around the town of Rangely and began recording activity. In 1971, a study was
conducted to evaluate the stress state in the vicinity of the fault which determined a critical fluid pressure
above which fault slippage may occur. Reservoir pressure was then manipulated and correlated with
increases or decreases in seismic activity. This study determined that the waterflood in Rangely was
inducing seismicity when reservoir pressure was raised above ~3730 psi.
In the 1990's, field reservoir pressure had built back up leading to the largest magnitude earthquake in
9
-------
Rangely which took place in 1995 (M 4.5), shortly after maximum reservoir pressure was reached in
1998. Pressure maintenance began and seismic activity dropped off after lowering the average field
reservoir pressure down to ~3100 psi. No other seismic activity was recorded around the field until 2015
and 2017 when there was a total of 5 seismic events (see Figure 6) around the northeastern portion of
the MFF. A new interpretation from the 3D seismic revealed a series of previously unknown joint faults
(perpendicular to the MFF). Investigation into this region revealed that the ~3730 psi threshold had been
crossed and triggered the seismic events. Since the 2017 seismic events, no other events have been
recorded of felt magnitude and continued pressure monitoring further reduces the risk of another event.
2017 Induced
Seismic Study*
Figure 6. USGS fault history map (1900-2023). Largest earthquake was the 1995 M 4.5 north of the
unit (2017 was a study to induce seismic activity along the MFF, and not caused by day-to-day
operations)
The natural fractures found within the field play a significant role in fluid flow. The subsurface natural
fractures are vertical and show an approximately ENE trend and their extension joints are orientated ESE.
Shallower portions of the reservoir show a distinctly higher density of fractures than deeper portions. On
the shallow dipping sides of the anticline, there does not appear to be a strong structural control on
fracture density. Most well-to-well rapid breakthrough of injected C02 is along these ENE fractures. It is
unknown if this is from natural or induced fractures. There is no evidence that these natural fractures
diminish the seals integrity.
10
-------
Figure 7. Cross section A-A' along the long axis of the field, and perpendicular to the MRR. The
MFF does not have much displacement and is near vertical.
The Rangely Field has approximately 1.9 billion barrels of Original Oil in Place (OOIP). Since first
discovered in 1933, Rangely Field has produced 920 million barrels of oil, or 48% of the OOIP. The
Rangely Field has an aerial extent of approximately 19,150 acres with an average gross thickness of 650
ft. The previously mentioned 11 internal layers of the reservoir, alternating zones of Weber and Maroon
Formations, can be simplified to only three sections. The Upper Weber contains intervals 1-3, the Middle
Weber contains intervals 4-7, and the Lower Weber contains intervals 8-approxamently 50 ft below the
11D marker (identified by the base of the yellow in Figure 7). These interval groupings were determined
by the extensive lateral continuingiy and thickness of the Weber 4 and Weber 8 which easily separate the
reservoir into the three zones. For the majority of the Rangely Field, the even Maroon Formations act as
flow barriers between the odd Weber Formations. Average porosity within the Weber Sands dune fades
is 10.3% and within the Maroon fluvial fades is 4.9%. However, the key factor that enables the Maroon
Formation to be a seal is its lack of permeability. The Weber dune fades have an average permeability of
2.44 millidarcy (Md), while the Maroon fluvial fades have an average permeability of 0.03 Md.
owe -1150'
Transition Zone & ROZ
11
-------
Figure 8. Cross section B-B' along the short axis of the field and parallel to the MFF. Used to
illustrate the variation of the Oil Water Contact (OWC).
Given that the Rangely Field is located at the highest subsurface elevations of the structure, that the
confining zone has proved competent over both millions of years and throughout decades of EOR
operations, and that the Rangely Field has ample storage capacity, SEM is confident that stored CQ2 will
be contained securely within the Weber Sands in the Rangely Field.
2.2.2 Operational History of the Rangely Field
The Rangely Field was discovered in 1933 but subsequently ceased production until World War II when oil
returned to high demand. Intensive development began, expanding from one well to 478 wells by 1949. It
is located in the northwestern portion of Colorado.
The Rangely Field was originally developed by Chevron. Following the initial discover in 1933,
Chevron imitated a 40-acre development in 1944, followed by hydrocarbon gas injection from
1950 to 1969. To improve efficiency, in 1957, the RWSU was formed. The boundaries of the RWSU are
reflected in Figure 9.
Rangely Well List
^ Active-Producer
yf 0 TA- Producer
~ Active-Injector
A TA-Injector
T Active 5WD
Collection Station / Facility
¦ Collection Station
$ Compressor Station
X ¦ Rangely Facility
(££) Rangely Plant General
A West End Water Injection
N -Rangely Weber Unit
23^^ Rangely Weber Unit
1 "l1 Rangely Weber Unit Half Mile Buffer
Mdien Htl
BIO BIANG& COuWv
± i iu* vOJ /
A (t'li *A-A*AV
u -
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'Rio Blanco-
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Hospital Hetip&i
River
itf N)2W
Moffat
0/HICJ blAnCO CO0NTY
Uintah
Rio Blanco
Garfield
Figure 9 - Rangely Field Map
12
-------
Chevron began C02 flooding of the Rangely Field in 1986 and has continued and expanded it since that
time. The experience of operating and refining the Rangely Field C02 floods over the past decade has
created a strong understanding of the reservoir and its capacity to store C02.
2.3 Description of C02 EOR Project Facilities and the injection Process
Figures 10 shows a simplified flow diagram of the project facilities and equipment in the Rangely Field.
C02 is delivered to the Rangely Field via the Raven Ridge Pipeline. The CG2 injected into the Rangely
Field is currently supplied by XOM's Shute Creek Plant into the pipeline system.
Once C02 enters the Rangely Field there are four main processes involved in EOR operations. These
processes are shown in Figure 10 and include:
1. C02 Distribution and Injection. Purchased C02 and recycled C02 from the RCF is sent through the main
C02 distribution system to various C02 injectors throughout the Field.
2. Produced Fluids Handling. Produced fluids gathered from the production wells are sent to collection
stations for separation into a gas/C02 mix and a produced fluids mix of water, oil, gas, and C02. The
produced fluids mix is sent to centralized water plants where oil is separated for sale into a pipeline, water
is recovered for reuse, and the remaining gas/C02 mix is merged with the output from the collection
stations. The combined gas/C02 mix is sent to the RCF and natural gas liquids (NGL) Plant. Produced oil
is metered and sold; water is forwarded to the water injection plants fortreatment and reinjection or disposal.
3. Produced Gas Processing. The gas/C02 mix separated at the satellite batteries goes to the RCF and
NGL Plant where the NGLs, and C02 streams are separated. The NGLs move to a commercial pipeline for
sale. The remaining C02 (e.g., the recycled C02) is returned to the C02 distribution system for reinjection.
4. Water Treatment and Injection. Water separated in the tank batteries is processed at water plants to
remove any remaining oil and then distributed throughout the Rangely Field for reinjection.
LaBarge Field/
Shute Creek Plant
Field and plant owned and
operated by ExxonMobil
Raven Ridge
Pipeline
123 mile, 16" steel pipeline
(200 MMcfd capacity)
56% CRRPC owned
(T) Rangely Field
Dehydration & NGL Extraction
RCF
1st/2nd Stage
Compression
Gasjt-,
A Custody Transfer Point for Assets
~ CO? Measurement Points
RCF
3rd/ 4th Stage
Compression
Oil/Water Liquids Liquid/Gas
Separation & ¦« Inlet
Water Plants Separation
Water T water] |_
Gas/Water
Injection
Wells
Water
Disposal
Wells
-f
Producing
Wells
Surface
Navajo Formation
COj +
Water +
Natural Gas
Oil
~ Natural Gas / NGL
+ Water
+ CO,
Weber Sands Reservoir
yv.
Figure 10 Rangely Field -General Production Flow Diagram
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2.3.1 C02 Distribution and Injection.
SEM purchases C02 from XOM and receives it via the Raven Ridge Pipeline through one custody transfer
metering point, as indicated in Figures 10. Purchased C02 and recycled C02 are sent through the C02
trunk lines to multiple distribution lines to individual injection wells. There are volume meters at the inlet and
outlet of the C02 Reinjection Facility.
As of April 2023, SEM has approximately 280 injection wells in the Rangely Field. Approximately 160 MMscf
of C02 is injected each day, of which approximately 15% is purchased C02, and the balance (85%) is
recycled. The ratio of purchased C02 to recycled C02 is expected to change overtime, and eventually the
percentage of recycled C02 will increase and purchases of fresh C02 will taper off as indicated in Section
2.1.
Each injection well is connected to a water alternating gas (WAG) manifold located at the well pad. WAG
manifolds are manually operated and can inject either C02 or water at various rates and injection pressures
as specified in the injection plans. The length of time spent injecting each fluid is a matter of continual
optimization that is designed to maximize oil recovery and minimize C02 utilization in each injection pattern.
A WAG manifold consists of a dual-purpose flow meter used to measure the injection rate of water or C02,
depending on what is being injected. Data from these meters is sent to the Supervisory Control and Data
Acquisition (SCADA) system where it is compared to the injection plan forthat well. As described in Sections
5 and 7, data from the WAG manifolds, visual inspections of the injection equipment, and use of the
procedures contained in 40 CFR §98.230-238 (Subpart W), will be gathered to complete the mass balance
equations necessary to determine annual and cumulative volumes of stored C02.
2.3.2 Wells in the Rangely Field
As of April 2023, there are 662 active wells that are completed in the Rangely Field, with roughly 40%
injection wells and 60% producing wells, as indicated in Figure 11,2 Table 1 shows these well counts in the
Rangely Field by status.
2 Wells that are not in use are deemed to be inactive, plugged and abandoned, temporarily abandoned, or shut in.
14
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Rangely Well List
# Active-Producer
TA-Producer
A Active-Injector
A TA-Injector
~ Active SWD
Rangely Weber Unit
I I Rangely Weber Unit
2N 103W
Metier Hill
00 RIO PLAN (9S COUN»7
2N 102W
.Rio Blanco
Ji) Rpven I
ftrfcjr li
Heliport
Moffat
I'tgely District
Vpitof Heppaf'
1N 102W
0RIO BLANCO CQ18NTY
Rio Blanco
iarfield
Figure 11 Rangely Field Wells - As of April 2023
Table 1 - Rangely Field Wells
<\ge/Completion of Well
Active
Shut-in
Temporarily
Abandoned
Plugged and
Abandoned
Drilled & Completed in the
1940's
265
5
55
149
Drilled 1950-1985
297
7
55
46
Completed after 1986
103
1
11
8
TOTAL
665
13
121
203
The wells in Table 1 are categorized in groups that relate to age and completion methods. Roughly 48%
of these wells were drilled in the 1940's and were generally completed with three strings of casing (with
surface and intermediate strings typically cemented to the surface). The production string was typically
installed to the top of the producing interval, otherwise known as the main oil column (MOC), which
extends to the producible oil/water contact (POWC). These wells were completed by stimulating the open
hole (OH), and are not typically cased through the MOC. While implementing the water flood from 1958-
1986, a partial liner would have been typically installed to allow for controlled injection intervals and this
liner would have been cemented to the top of the liner (TOL) that was installed. For example, a partial
liner would be installed from 5,700-6,500 ft, and the TOC would be at 5,700 ft. The casing weights used
15
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for the production string have varied between 7" 23 & 26#/ft. with 5" 18 #/ft. for the production liner.
The wells in Table 1 drilled during the period 1950-1986 typically were cased through the production
interval with 7" casing. Some wells were completed with 7" casing to the top of the MOC and then
completed with a 5" liner through the productive interval. The wells with liners were cemented to the TOL.
The remaining wells (roughly 12%) in Table 1 were drilled after 1986 when the C02 flood began. All of
these wells were completed with 7" casing through the POWC. Very few of these wells have experienced
any wellbore issues that would dictate the need for a remedial liner.
SEM reviews these categories along with full wellbore history when planning well maintenance projects.
Further, SEM keeps well workover crews on call to maintain all active wells and to respond to any
wellbore issues that arise. On average, in the Rangely Field there are two to three incidents per year in
which the well casing fails. SEM detects these incidents by monitoring changes in the surface pressure of
wells and by conducting Mechanical Integrity Tests (MITs), as explained later in this section and in the
relevant regulations cited. This rate of failure is less than 2% of wells per year and is considered
extremely low.
All wells in oilfields, including both injection and production wells described in Table 1, are regulated by
the COGCC under COGCC 100-1200 series rules. A list of wells, with well identification numbers, is
included in Appendix 5. The injection wells are subject to additional requirements promulgated by EPA -
the UIC Class II program - implementation of which has been delegated to the COGCC.
COGCC rules govern well siting, construction, operation, maintenance, and closure for all wells in oilfields.
Current rules require, among other provisions, that:
Class II UIC Wells will not be permitted in areas where they would inject into a formation that is
separated from any Underground Source of Drinking Water by a Confining Layer with known open
faults or fractures that would allow flow between the Injection Zone and Underground Source of Drinking
Water within the area of review.
Injection Zones will not be permitted within 300 feet in a vertical dimension from the top of any
Precambrian basement formation.
An Operator will not inject any Fluids or other contaminants into a UIC Aquifer that meets the
definition of an Underground Source of Drinking Water unless EPA has approved a UIC Aquifer
exemption as described in Rule 802.e.
In addition, SEM implements a corrosion protection program to protect and maintain the steel used in
injection and production wells from any C02-enriched fluids. SEM currently employs methods to mitigate
both internal and external corrosion of casing in wells in the Rangely Field. These methods generally protect
the downhole steel and the interior and exterior of wellbores through the use of special materials (e.g.
fiberglass tubing, corrosion resistant cements, nickel plated packers, corrosion resistant packer fluids) and
procedures (e.g. packer placement, use of annular leakage detection devices, cement bond logs, pressure
tests). These measures and procedures are typically included in the injection orders filed with the COGCC.
Corrosion protection methods and requirements may be enhanced overtime in response to improvements
in technology.
MIT
SEM complies with the MIT requirements implemented by COGCC and BLM to periodically inspect wells
and surface facilities to ensure that all wells and related surface equipment are in good repair and leak-
free, and that all aspects of the site and equipment conform with Division rules and permit conditions. All
active injection wells undergo an MIT at the following intervals:
Before injection operations begin
16
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Every 5 years as stated in the injection orders (COGCC 417.a. (1))
After any casing repair
After resetting the tubing or mechanical isolation device
Or whenever the tubing or mechanical isolation device is moved during workover operations
COGCC requires that the operator notify the COGCC district office prior to conducting an MIT. Operators
are required to use a pressure recorder and pressure gauge for the tests. The operator's field representative
must sign the pressure recorder chart along with the COGCC field representative and submit it with the MIT
form. The casing-tubing annulus must be tested to a minimum of 1200 psi for 15 minutes.
If a well fails an MIT, the operator must immediately shut the well in and provide notice to COGCC. Casing
leaks must be successfully repaired and retested or the well plugged and abandoned after submitting a
formal notice and obtaining approval from the COGCC.
Any well that fails an MIT cannot be returned to active status until it passes a new MIT
2.3.3 Produced Fluids Handling
As injected C02 and water move through the reservoir, a mixture of oil, gas, and water ("produced fluids")
flows to the production wells. Gathering lines bring the produced fluids from each production well to
collection stations. SEM has approximately 382 active production wells in the Rangely Field and production
from each is sent to one of 27 collection stations. Each collection station consists of a large vessel that
performs a gas - liquid separation. Each collection station also has well test equipment to measure
production rates of oil, water and gas from individual production wells. SEM has testing protocols for all
wells connected to a collection station. Most wells are tested twice per month. Some wells are prioritized
for more frequent testing because they are new or located in an important part of the Field; some wells with
mature, stable flow do not need to be tested as frequently; and finally, some wells will periodically need
repeat testing due to abnormal test results.
After separation, the gas phase is transported by pipeline to the C02 reinjection facility for processing as
described below. Currently the average composition of this gas mixture as it enters the facility is 92% C02
and 800ppm H2S; this composition will change overtime as C02 EOR operations mature.
The liquid phase, which is a mixture of oil and water, is sent to one of two centralized water plants where
oil is separated from water via two 3-phase separators. The water is then sent to water holding tanks where
further separation is done.
The separated oil is metered through the Lease Automatic Custody Transfer (LACT) unit located at the
custody transfer point between Chevron pipeline and SEM. The oil typically contains a small amount of
dissolved or entrained C02. Analysis of representative samples of oil is conducted once a year to assess
C02 content.
The water is removed from the bottom of the tanks at the water injection stations, where it is re-injected to
the WAG injectors.
Any gas that is released from the liquid phase rises to the top of the tanks and is collected by a Vapor
Recovery Unit (VRU) that compresses the gas and sends it to the C02 reinjection facility for processing.
17
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Rangely oil is slightly sour, containing small amounts of hydrogen sulfide (H2S), which is highly toxic. There
are approximately 25 workers on the ground in the Rangely Field at any given time, and all field personnel
are required to wear H2S monitors at all times. Although the primary purpose of H2S detectors is protecting
employees, monitoring will also supplement SEM's C02 leak detection practices as discussed in Sections
5 and 7.
In addition, the procedures in 40 CFR §98.230-238 (Subpart W) and the two-part visual inspection process
described in Section 5 are used to detect leakage from the produced fluids handling system. As described
in Sections 5 and 7, the volume of leaks, if any, will be estimated to complete the mass balance equations
to determine annual and cumulative volumes of stored C02.
2.3.4 Produced Gas Handling
Produced gas gathered from the collection stations, and water injection plants is sent to the C02 recycling
and compression facility. There is an operations meter at the facility inlet.
Once gas enters the C02 reinjection facility, it undergoes dehydration and compression. In the RWSU an
additional process separates NGLs for sale. At the end of these processes there is a C02 rich stream that
is recycled through re-injection. Meters at the C02 recycling and compression facility outlet are used to
determine the total volume of the C02 stream recycled back into the EOR operations.
As described in Section 2.3.4, data from 40 CFR §98.230-238 (Subpart W), the two-part visual inspection
process for production wells and areas described in Section 5, and information from the personal H2S
monitors are used to detect leakage from the produced gas handling system. This data will be gathered to
complete the mass balance equations necessary to determine annual and cumulative volumes of stored
C02 as described in Sections 5 and 7.
2.3.5 Water Treatment and Injection
Produced water collected from the collection stations is gathered through a pipeline system and moved to
one of two water injection plants. Each facility consists of 3-Phase separators and 79,500-barrels of
separation tanks where any remaining oil is skimmed from the water. Skimmed oil is combined with the oil
from the 3-Phase separators and sent to the LACT. The water is sent to an injection pump where it is
pressurized and distributed to the WAG injectors.
2.3.6 Facilities Locations
The current locations of the various facilities in the Rangely Field are shown in Figure 13. As indicated
above, there are two central water plants. There are twenty-seven collections stations that gather
production from surrounding wells. The two water plants are identified by the blue triangle and circle. The
twenty-seven collection stations are identified by red squares. The C02 Reinjection facility is indicated by
the green circle.
18
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Collection Station / Facility
I Collection Station
Compressor Station
¦ Rangely Facility
(££) Rangely Plant General
A West End Water Injection
Rangely Weber Unit
Rangely Weber Unit
" Men Hill
06 RIO BIANCSS COUN-1
Collection
Station 01
Collection
Station 03
Collection
Station 10m
,Rio Blanco
Collection
Station 08
Collection
2N 103W
Collection.^
Station 04
Collection
Station 20 2N 1021
Station 12
Collection
Station 05
Collection
Station 11
Collection
Station 27
West
End Water
Injection
Collection
Station 16
Heliport
Collection
Station 22
Collection Co"ec^,tV,
Station stat'°109
Collection
Station 17
Collection
Station 33
Collection
Station 28«
Collection
Station 29
Collection
Station 13
vCollection
Station 18 Main
¦ Treatment
I 37
Rangely [¦]
Plant ¦¦ Collection Collection
General Station 19 Station 24
Collection
Station 34
Collection
Station 30
Collection
Station 39
Collection
_Station_47_
Moffat
Rangely District
MOSfiittOi' HfiipOti
1N 102W
Uintah
ORIOi BLANCO CQBNTY
Rio Blanco
Garfield
Miles
Figure 13 Location of Surface Facilities at Rangely Field
3. Delineation of Monitoring Area and Timeframes
The current active monitoring area (AMA), future AMA and monitoring time frame of the AMA are
described below. Additionally, the maximum monitoring area (MMA) of the free phase C02 plume, its
buffer zone and the monitoring time frame for the MMA are described below.
3.1 Active Monitoring Area
Because C02 is present throughout the Rangely Field and retained within it, the Active Monitoring Area
(AMA) is defined by the boundary of the Rangely Field plus one-half mile buffer. This boundary is defined
in Figure 9. The following factors were considered in defining this boundary:
Free phase C02 is present throughout the Rangely Field: More than 2,320,000 MMscF (122.76 MMT)
tons of C02 have been injected and recycled throughout the Rangely Field since 1986 and there has
been significant infill drilling in the Rangely Field, completing additional wells to further optimize
production. Operational results thus far indicate that there is C02 throughout the Rangely Field.
C02 injected into the Rangely Field remains contained within the Rangely Field AMA because of the
19
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fluid and pressure management results associated with C02 EOR. The maintenance of an IWR of 1.0
assures a stable reservoir pressure; managed lease line injection and production wells are used to
retain fluids in the Rangely Field as indicated in Section 4.7. Implementation of these methods over the
past decades have successfully contained C02 within the Rangely Field.
It is highly unlikely that injected C02 will migrate downdip and laterally outside the Rangely Field
because of the nature of the geology and the approach used for injection. As indicated in Section
2.2.1 "Geology of the Rangely Field," the Rangely Field is situated at the top of a dome structural
trap, with all directions pointing down-dip from the highest point. This means that over long periods of
time, injected C02 will tend to rise vertically towards the point in the Rangely Field with the highest
elevation.
Forecasted C02 injection volumes, shown in Figure 1, represent SEM's plan to not increase current
injection volumes and maintain an IWR of 1. Operations will not expand beyond the currently active C02-
EOR portion of the Rangely Field; therefore, the AMA is not expected to increase. Should such
expansions occur, they will be reported in the Subpart RR Annual Report for the Rangely Field, as
required by section 98.446.
3.2 Maximum Monitoring Area
The Maximum Monitoring Area (MMA) is defined in 40 CFR §98.440-449 (Subpart RR) as equal or greater
than the area expected to contain the free-phase C02 plume until the C02 plume has stabilized, plus an all-
around buffer zone of one-half mile. Section 3.1 states that the maximum extent of the injected C02 is expected
to be bounded by the Rangely Field Unit boundary shown in Figure 9. Therefore, the MMA is the Rangely Field
Unit boundary plus the one-half mile buffer as required by 40 CFR §98.440-449 (Subpart RR).
3.3 Monitoring Timeframes
SEM's primary purpose for injecting C02 is to produce oil that would otherwise remain trapped in the
reservoir and not, as in UIC Class VI, "specifically for the purpose of geologic storage."3 During a Specified
Period, SEM will have a subsidiary purpose of establishing the long-term containment of a measurable
quantity of C02 in the Weber Sands in the Rangely Field. The Specified Period will be shorter than the
period of production from the Rangely Field. This is in part because the purchase of new C02 for injection
is projected to taper off significantly before production ceases at Rangely Field, which is modeled through
2060. At the conclusion of the Specified Period, SEM will submit a request for discontinuation of reporting.
This request will be submitted when SEM can provide a demonstration that current monitoring and model(s)
show that the cumulative mass of C02 reported as sequestered during the Specified Period is not expected
to migrate in the future in a manner likely to result in surface leakage. It is expected that it will be possible to
make this demonstration within two to three years after injection for the Specified Period ceases based upon
predictive modeling supported by monitoring data. The demonstration will rely on two principles: 1) that just
as is the case for the monitoring plan, the continued process of fluid management during the years of C02
EOR operation after the Specified Period will contain injected fluids in the Rangely Field, and 2) that the
cumulative mass reported as sequestered during the Specified Period is a fraction of the theoretical storage
capacity of the Rangely Field See 40 C.F.R. § 98.441 (b)(2)(ii).
4. Evaluation of Potential Pathways for Leakage to the Surface
3 EPA UIC Class VI rule, EPA 75 FR 77291, December 10, 2010, section 146.81(b).
20
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4.1 Introduction
In the 90 years since the Rangely Field was discovered in 1933, extensive reservoir monitoring and
studies were performed. Based on the knowledge gained from historical practices, this section assesses
the following potential pathways for leakage of C02 to surface within Rangely Field.
Existing Wellbores
Faults and Fractures
Natural and Induced Seismic Activity
Previous Operations
Pipeline/Surface Equipment
Lateral Migration Outside the Rangely Field
Drilling Through the C02 Area
Diffuse Leakage Through the Seal
Detailed analysis of these potential pathways concluded that existing wellbores and pipeline/surface
equipment pose the only meaningful potential leakage pathways. Operating pressures are not expected
to increase overtime, therefore there is not a specific time period that would increase the likelihood of
pathways for leakage. SEM identifies these potential pathways for C02 leakage to be low risk, i.e., less
than 1% given the extensive operating history and monitoring program currently in place.
The monitoring program to detect and quantify leakage is based on the assessment discussed below.
4.2 Existing Wellbores
As of April 2023, there are approximately 662 active SEM operated wells in the Rangely Field - split roughly
evenly between production and injection wells. In addition, there are approximately 135 wells not in use, as
described in Section 2.3.2.
Leakage through existing wellbores is a potential risk at the Rangely Field that SEM works to prevent by
adhering to regulatory requirements for well drilling and testing; implementing best practices that SEM has
developed through its extensive operating experience; monitoring injection/production performance,
wellbores, and the surface; and maintaining surface equipment.
As discussed in Section 2.3.2, regulations governing wells in the Rangely Field require that wells be
completed and operated so that fluids are contained in the strata in which they are encountered and that
well operation does not pollute subsurface and surface waters. The regulations establish the requirements
that all wells (injection, production, disposal) must comply with. Depending upon the purpose of a well, the
requirements can include additional standards for evaluation and MIT. SEM's best practices include pattern
level analysis to guide injection pressures and performance expectations; utilizing diverse teams of experts
21
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to develop EOR projects based on specific site characteristics; and creating a culture where all field
personnel are trained to look for and address issues promptly. SEM's practices, which include corrosion
prevention techniques to protect the wellbore as needed, as discussed in Section 2.3.2, ensures that well
completion and operation procedures are designed not only to comply with regulations but also to ensure
that all fluids (e.g., oil, gas, C02) remain in the Rangely Field until they are produced through an SEM well.
As described in Section 5, continual and routine monitoring of SEM's wellbores and site operations will be
used to detect leaks, including those from non-SEM wells, or other potential well problems, as follows:
Well pressure in injection wells is monitored on a continual basis. The injection plans for each pattern
are programmed into the injection WAG controller, as discussed in Section 2.3.1, to govern the rate and
pressure of each injector. Pressure monitors on the injection wells are programmed to flag pressures
that significantly deviate from the plan. Leakage on the inside or outside of the injection wellbore would
affect pressure and be detected through this approach. If such excursions occur, they are investigated
and addressed. In the time SEM has operated the Rangely Field, there have been no C02 leakage
events from a wellbore.
In addition to monitoring well pressure and injection performance, SEM uses the experience gained
overtime to strategically approach well maintenance. SEM maintains well maintenance and workover
crews onsite for this purpose. For example, the well classifications by age and construction method
indicated in Table 1 inform SEM's plan for monitoring and updating wells. SEM uses all of the
information at hand including pattern performance, and well characteristics to determine well
maintenance schedules.
Production well performance is monitored using the production well test process conducted when
produced fluids are gathered and sent to a collection station. There is a routine cycle for each collection
station, with each well being tested approximately twice every month. During this cycle, each production
well is diverted to the well test equipment for a period of time sufficient to measure and sample produced
fluids (generally 24 hours). This test allows SEM to allocate a portion of the produced fluids measured
at the collection station to each production well, assess the composition of produced fluids by location,
and assess the performance of each well. Performance data are reviewed on a routine basis to ensure
that C02 flooding is optimized. If production is off plan, it is investigated and any identified issues
addressed. Leakage to the outside of production wells is not considered a major risk because of the
reduced pressure in the casing. Further, the personal H2S monitors are designed to detect leaked fluids
around production wells.
Finally, as indicated in Section 5, field inspections are conducted on a routine basis by field personnel.
On any day, SEM has approximately 25 personnel in the field. Leaking C02 is very cold and leads to
formation of bright white clouds and ice that are easily spotted. All field personnel are trained to identify
leaking C02 and other potential problems at wellbores and in the field. Any C02 leakage detected will
be documented and reported, quantified and addressed as described in Section 5.
Based on its ongoing monitoring activities and review of the potential leakage risks posed by wellbores,
SEM concludes that it is mitigating the risk of C02 leakage through wellbores by detecting problems as
they arise and quantifying any leakage that does occur. Section 4.10 summarizes how SEM will monitor
C02 leakage from various pathways and describes how SEM will respond to various leakage scenarios.
In addition, Section 5 describes how SEM will develop the inputs used in the Subpart RR mass-balance
equation (Equation RR-11). Any incidents that result in C02 leakage up the wellbore and into the
atmosphere will be quantified as described in Section 7.4.
22
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4.3 Faults and Fractures
After reviewing geologic, seismic, operating, and other evidence, SEM has concluded that there are no
known faults or fractures that transect the entirety of the Weber Sands in the project area. As described in
Section 2.2.1, the MFF is present below the reservoir and terminates within the Weber Sands without
breaching the upper seal. Additional faults have been identified in formations that are stratigraphically below
the Weber Sands, but this faulting has been shown not to affect the Weber Sands or to have created
potential leakage pathways given that they do not contact the Upper Pennsylvanian or Permian strata
(Weber Fm.).
SEM has extensive experience in designing and implementing EOR projects to ensure injection pressures
will not damage the oil reservoir by inducing new fractures or creating shear. As a safeguard, injection
satellites are set with automatic shutoff controls if injection pressures exceed fracture pressures.
4.4 Natural or Induced Seismicity
After reviewing literature and historic data, SEM concludes that there is no direct evidence that natural
seismic activity poses a significant risk for loss of C02 to the surface in the Rangely Field. Natural seismic
events are derived from the thrust fault to the west. Historically, Figure 6 in section 2.2.1 shows nine (9)
seismic events outside of the Rangely Field (including the 1993 M 3.5 event). The epicenter of these
earthquakes was far below the operating depths of the Rangely Field, and are associated with the thrust
fault to the west of the field. The operations of Rangely have zero impact on this thrust fault. Natural
earthquakes are not predictable, but these do not pose a threat to current operations. This is evidenced by
the fact that hydrocarbons are still within the anticline, meaning that there have been no major seismic
events in the last few million years capable of releasing these hydrocarbons to the surface.
Induced seismic events (non-natural) are tied to the MFF and its joint faults. These can be impacted by
Rangely Field operations. Section 2.2.1 explains how an increase in reservoir pressure can trigger seismic
events along and near the MFF. To prevent this from occurring bottom hole pressure surveys are collected
one (1) to two (2) times per year across the Rangely Field helping to monitor pressure changes along across
the Rangely Field. By keeping reservoir pressure from exceeding the threshold of ~3730 psi for extended
periods of time (multiple years), induced seismic events can be greatly mitigated. In the case that reservoir
pressures do exceed the threshold pressure, a reduction in injected volumes in the vicinity will bring down
the pressures back down gradually over a period of time.
4.5 Previous Operations
Chevron initiated C02 flooding in the Rangely Field in 1986. SEM and the prior operators have kept records
of the site and have completed numerous infill wells. SEM has not drilled any new wells in Rangely to date
but their standard practice for drilling new wells includes a rigorous review of nearby wells to ensure that
drilling will not cause damage to or interfere with existing wells. SEM will also follow AOR requirements
under the UIC Class II program, which require identification of all active and abandoned wells in the AOR
and implementation of procedures that ensure the integrity of those wells when applying for a permit for any
new injection well. These practices ensure that identified wells are sufficiently isolated and do not interfere
with the C02 EOR operations and reservoir pressure management. Consequently, SEM's operational
experience supports the conclusion that there are no unknown wells within the Rangely Field that penetrate
the Weber Sands and that it has sufficiently mitigated the risk of migration from older wells.
4.6 Pipeline / Surface Equipment
Damage to or failure of pipelines and surface equipment can result in unplanned losses of C02. SEM
reduces the risk of unplanned leakage from surface facilities, to the maximum extent practicable, by relying
on the use of prevailing design and construction practices and maintaining compliance with applicable
regulations. The facilities and pipelines currently utilize and will continue to utilize materials of construction
23
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and control processes that are standard for C02 EOR projects in the oil and gas industry. As described
above, all facilities in the Rangely Field are internally screened for proximity to the public. In the case of
pipeline and surface equipment, best engineering practices call for more robust metallurgy in wellhead
equipment, and pressure transducers with low pressure alarms monitored through the SCADA system to
prevent and detect leakage. Operating and maintenance practices currently follow and will continue to follow
demonstrated industry standards. C02 delivery via the Raven Ridge pipeline system will continue to
comply with all applicable regulations. Finally, frequent routine visual inspection of surface facilities by field
staff will provide an additional way to detect leaks and further support SEM's efforts to detect and remedy
any leaks in a timely manner. Should leakage be detected from pipeline or surface equipment, the volume
of released C02 will be quantified following the requirements of Subpart W of EPA's GHGRP.
4.7 Lateral Migration Outside the Rangely Field
It is highly unlikely that injected C02 will migrate downdip and laterally outside the Rangely Field because of
the nature of the geology and the approach used for injection. First, as indicated in Section 2.2.1 "Geology
of the Rangely Field," the Rangely Field is situated at the top of a dome structural trap, with all directions
pointing down-dip from the highest point. This means that over long periods of time, injected C02 will tend
to rise vertically towards the point in the Rangely Field with the highest elevation. Second, the planned
injection volumes and active fluid management during injection operations will prevent C02 from migrating
laterally stratigraphically (down-dip structurally) out of the structure. Finally, SEM will not be increasing the
total volume of fluids in the Rangely Field.
COGCC requires that injection pressures be limited to ensure injection fluids do not migrate outside the
permitted injection interval. In the Rangely Field, SEM uses two methods to contain fluids: reservoir
pressure management and the careful placement and operation of wells along the outer producing limits of
the units.
Reservoir pressure in the Rangely Field is managed by maintaining an injection to withdrawal ratio (IWR)
of approximately 1.0. To maintain the IWR, SEM monitors fluid injection to ensure that reservoir pressure
does not increase to a level that would fracture the reservoir seal or otherwise damage the oil field.
SEM also prevents injected fluids from migrating out of the injection interval by keeping injection pressure
below the formation fracture pressure, which is measured using historic step-rate tests. In these tests,
injection pressures are incrementally increased (e.g., in "steps") until injectivity increases abruptly, which
indicates that an opening or fracture has been created in the rock. SEM manages its operations to ensure
that injection pressures are kept below the formation fracture pressure so as to ensure that the valuable
fluid hydrocarbons and C02 remain in the reservoir.
There are a few small producer wells operated by third parties outside the boundary of Rangely Field. There
are currently no significant commercial operations surrounding the Rangely Field to interfere with SEM's
operations.
Based on site characterization and planned and projected operations SEM estimates the total volume of
stored C02 will be approximately 35.7% of calculated capacity.
4.8 Drilling Through the C02 Area
It is possible that at some point in the future, drilling through the containment zone into the Weber Sands
could occur and inadvertently create a leakage pathway. SEM's review of this issue concludes that this risk
is very low for two reasons. First, SEM's visual inspection process, including routine site visits, is designed
to identify unapproved drilling activity in the Rangely Field. Second, SEM plans to operate the C02 EOR
flood in the Rangely Field for several more years, and will continue to be vigilant about protecting the
integrity of its assets and maximizing the potential of resources (oil, gas, C02). In the unlikely event SEM
would sell the field to a new operator, provisions would result in a change to the reporting program and
24
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would be addressed at that time.
4.9 Diffuse Leakage through the Seal
Diffuse leakage through the seal formed by the Moenkopi Formation is highly unlikely. The presence of a
gas cap trapped over millions of years as discussed in Section 2.2.3 confirms that the seal has been
secure for a very long time. Injection pattern monitoring program referenced in Section 2.3.1 and detailed
in Section 5 assures that no breach of the seal will be created. The seal is highly impermeable where
unperforated, cemented across the horizon where perforated by wells, and unexplained changes in
injection pressure would trigger investigation as to the cause. Further, if C02 were to migrate through the
Moenkopi seal, it would migrate vertically until it encountered and was trapped by any of the numerous
shallower shale seals
4.10 Monitoring, Response, and Reporting Plan for C02 Loss
As discussed above, the potential sources of leakage include fairly routine issues, such as problems with
surface equipment (pumps, valves, etc.) or subsurface equipment (wellbores), and unique events such as
induced fractures. Table 3 summarizes some of these potential leakage scenarios, the monitoring activities
designed to detect those leaks, SEM's standard response, and other applicable regulatory programs
requiring similar reporting.
Sections 5.1.5 - 5.1.7 discuss the approaches envisioned for quantifying the volumes of leaked C02. Given
the uncertainty concerning the nature and characteristics of leaks that will be encountered, the most
appropriate methods for quantifying the volume of leaked C02 will be determined at the time. In the event
leakage occurs, SEM plans to determine the most appropriate methods for quantifying the volume leaked
and will report it as required as part of the annual Subpart RR submission.
Any volume of C02 detected leaking to surface will be quantified using acceptable emission factors such
as those found in 40 CFR Part 98 Subpart W or engineering estimates of leak amounts based on
measurements in the subsurface, SEM's field experience, and other factors such as the frequency of
inspection. As indicated in Sections 5.1 and 7.4, leaks will be documented, evaluated and addressed in a
timely manner. Records of leakage events will be retained in the electronic environmental documentation
and reporting system. Repairs requiring a work order will be documented in the electronic equipment
maintenance system.
Table 3 Response Plan for C02 Loss
Risk
Monitoring Plan
Response Plan
Parallel
Reporting (if
any)
Loss of Well Control
Tubing Leak
Monitor changes in tubing and
annulus pressure; MIT for injectors
Well is shut in and
Workover crews respond
within days
COGCC
Casing Leak
Routine Field inspection; monitor
changes in annulus pressure; MIT for
injectors; extra attention to high risk
wells
Well is shut in and
Workover crews respond
within days
COGCC
Wellhead Leak
Routine Field inspection
Well is shut in and
Workover crews respond
within days
COGCC
Loss of Bottom-
hole
pressure control
Blowout during well operations
Maintain well kill
procedures
COGCC
25
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Unplanned wells
drilled through
Weber Sands
Routine Field inspection to
prevent unapproved drilling;
compliance with COGCC permitting
for planned wells.
Assure compliance with
COGCC regulations
COGCC
Permitting
Loss of seal in
abandoned wells
Reservoir pressure in monitor wells;
high pressure found in new wells
Re-enter and reseal
abandoned wells
COGCC
Leaks in Surface Facilities
Pumps, valves, etc.
Routine Field inspection; SCADA
Maintenance crews
respond within days
Subpart W
Subsurface Leaks
Leakage along
faults
Reservoir pressure in monitor wells;
high pressure found in new wells
Shut in injectors near
faults
-
Overfill beyond
spill
points
Reservoir pressure in monitor wells;
high; pressure found in new wells
Fluid management
along
lease lines
-
Leakage through
induced fractures
Reservoir pressure in monitor wells;
high pressure found in new wells
Comply with rules for
keeping pressures
below
parting pressure
-
Leakage due to
seismic event
Reservoir pressure in monitor wells;
high
pressure found in new wells
Shut in injectors near
seismic event
-
Available studies of actual well leaks and natural analogs (e.g., naturally occurring C02 geysers) suggest
that the amount released from routine leaks would be small as compared to the amount of C02 that would
remain stored in the formation.
4.11 Summary
The structure and stratigraphy of the Weber Sands in the Rangely Field is ideally suited forthe injection and
storage of C02. The stratigraphy within the C02 injection zones is porous, permeable and very thick,
providing ample capacity for long-term C02 storage. The Weber Sands is overlain by several intervals of
impermeable geologic zones that form effective seals or "caps" to fluids in the Weber Sands (See Figure
4). After assessing potential risk of release from the subsurface and steps that have been taken to prevent
leaks, SEM has determined that the potential threat of leakage is extremely low.
In summary, based on a careful assessment of the potential risk of release of C02 from the subsurface, SEM
has determined that there are no leakage pathways at the Rangely Field that are likely to result in significant
loss of C02 to the atmosphere. Further, given the detailed knowledge of the Field and its operating
protocols, SEM concludes that it would be able to both detect and quantify any C02 leakage to the surface
that could arise through either identified or unexpected leakage pathways.
5. Monitoring and Considerations for Calculating Site Specific Variables
Monitoring will also be used to determine the quantities in the mass balance equation and to make the
demonstration that the C02 plume will not migrate to the surface after the time of discontinuation.
5.1 Forthe Mass Balance Equation
5.1.1 General Monitoring Procedures
As part of its ongoing operations, SEM monitors and collects flow, pressure, and gas composition data from
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the Rangely Field in centralized data management systems. These data are monitored continually by
qualified technicians who follow SEM response and reporting protocols when the systems deliver
notifications that data exceed statistically acceptable boundaries.
As indicated in Figures 10 and 11, custody-transfer meters are used at the point at which custody of the
C02 from the Raven Ridge pipeline delivery system is transferred to SEM, and at the points at which custody
of oil and NGLs are transferred to outside parties. Meters measure flow rate continually. Fluid composition
will be determined, at a minimum, quarterly, consistent with EPA GHGRP's Subpart RR, section 98.447(a).
All meter and composition data are documented, and records will be retained for at least three years.
Metering protocols used by SEM follow the prevailing industry standard(s) for custody transfer as currently
promulgated by the API, the American Gas Association (AGA), and the Gas Processors Association (GPA),
as appropriate. This approach is consistent with EPA GHGRP's Subpart RR, section 98.444(e)(3). These
meters will be maintained routinely, operated continually, and will feed data directly to the centralized data
collection systems. The meters meet the industry standard for custody transfer meter accuracy and
calibration frequency. These custody meters provide the most accurate way to measure mass flows.
SEM maintains in-field process control meters to monitor and manage in-field activities on a real time basis.
These are identified as operations meters in Figures 10 and 11. These meters provide information used to
make operational decisions but are not intended to provide the same level of accuracy as the custody-
transfer meters. The level of precision and accuracy for in-field meters currently satisfies the requirements
for reporting in existing UIC permits. Although these meters are accurate for operational purposes, it is
important to note that there is some variance between most commercial meters (on the order of 1-5%)
which is additive across meters. This variance is due to differences in factory settings and meter calibration,
as well as the operating conditions within a field. Meter elevation, changes in temperature (over the course
of the day), fluid composition (especially in multi-component or multi-phase streams), or pressure can affect
in-field meter readings. Unlike in a saline formation, where there are likely to be only a few injection wells
and associated meters, at C02 EOR operations in the Rangely Field there are currently 662 active injection
and production wells and a comparable number of meters, each with an acceptable range of error. This is
a site-specific factor that is considered in the mass balance calculations described in Section 7.
5.1.2 C02 Received
SEM measures the volume of received C02 using commercial custody transfer meters at the off-take point
from the Raven Ridge pipeline delivery system. This transfer is a commercial transaction that is
documented. C02 composition is governed by the contract and the gas is routinely sampled to determine
composition. No C02 is received in containers.
5.1.3 C02 Injected into the Subsurface
Injected C02 will be calculated using the flow metervolumes at the operations meter at the outlet of the C02
Reinjection Facility and the custody transfer meter at the C02 off-take points from the Raven Ridge pipeline
delivery system
5.1.4 C02 Produced, Entrained in Products, and Recycled
The following measurements are used for the mass balance equations in Section 7:
C02 produced is calculated using the volumetric flow meters at the inlet to the C02 Reinjection Facility.
These flow meters, as illustrated on Figure 10, are downstream of the field collection station separators
and bulk produced fluid separators at the water injection plants
C02 is produced as entrained or dissolved C02 in produced oil, as indicated in Figures 10 and 11. This is
calculated using volumetric flow through the custody transfer meter.
Recycled C02 is calculated using the volumetric flow meter at the outlet of the C02 Reinjection Facility,
which is an operations meter.
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5.1.5 C02 Emitted by Surface Leakage
As discussed in Section 5.1.6 and 5.1.7 below, SEM uses 40 CFR Part 98 Subpart Wto estimate surface
leaks from equipment at the Rangely Field. Subpart W uses a factor-driven approach to estimate equipment
leakage. In addition, SEM uses an event-driven process to assess, address, track, and if applicable quantify
potential C02 leakage to the surface.
The multi-layered, risk-based monitoring program for event-driven incidents has been designed to meet two
objectives, in accordance with the leakage risk assessment in Section 4: 1) to detect problems before C02
leaks to the surface; and 2) to detect and quantify any leaks that do occur. This section discusses how this
monitoring will be conducted and used to quantify the volumes of C02 leaked to the surface.
Monitoring for potential Leakage from the Injection/Production Zone:
SEM will monitor both injection into and production from the reservoir as a means of early identification of
potential anomalies that could indicate leakage from the subsurface.
SEM develops injection plans for each well and that is distributed to operations weekly. If injection pressure
or rate measurements are beyond the specified set points determined as part of each pattern injection plan,
the operations engineer will notify field personnel and they will investigate and resolve the problem. These
excursions will be reviewed by well-management personnel to determine if C02 leakage may be occurring.
Excursions are not necessarily indicators of leaks; they simply indicate that injection rates and pressures
are not conforming to the pattern injection plan. In many cases, problems are straightforward to fix (e.g., a
meter needs to be recalibrated or some other minor action is required), and there is no threat of C02
leakage. In the case of issues that are not readily resolved, more detailed investigation and response would
be initiated, and internal SEM support staff would provide additional assistance and evaluation. Such issues
would lead to the development of a work order in SEM's work order management system. This record
enables the company to track progress on investigating potential leaks and, if a leak has occurred, to
quantify its magnitude.
Likewise, SEM develops a forecast of the rate and composition of produced fluids. Each producer well is
assigned to one collection station and is isolated twice during each monthly cycle for a well production test.
This data is reviewed on a periodic basis to confirm that production is at the level forecasted. If there is a
significant deviation from the forecast, well management personnel investigate. If the issue cannot be
resolved quickly, more detailed investigation and response would be initiated. As in the case of the injection
pattern monitoring, if the investigation leads to a work order in the SEM work order management system,
this record will provide the basis for tracking the outcome of the investigation and if a leak has occurred. If
leakage in the flood zone were detected, SEM would use an appropriate method to quantify the involved
volume of C02. This might include use of material balance equations based on known injected quantities
and monitored pressures in the injection zone to estimate the volume of C02 involved.
A subsurface leak might not lead to a surface leak. In the event of a subsurface leak, SEM would determine
the appropriate approach for tracking subsurface leakage to determine and quantify leakage to the surface.
To quantify leakage to the surface, SEM would estimate the relevant parameters (e.g., the rate,
concentration, and duration of leakage) to quantify the leak volume. Depending on specific circumstances,
these determinations may rely on engineering estimates.
In the event leakage from the subsurface occurred diffusely through the seals, the leaked gas would include
H2S, which would trigger the alarm on the personal monitors worn by field personnel. Such a diffuse leak
from the subsurface has not occurred in the Rangely Field. In the event such a leak was detected, field
personnel from across SEM would determine how to address the problem. The team might use modeling,
engineering estimates, and direct measurements to assess, address, and quantify the leakage.
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Monitoring of Wellbores:
SEM monitors wells through continual, automated pressure monitoring in the injection zone (as described in
Section 4.2), monitoring of the annular pressure in wellheads, and routine maintenance and inspection.
Leaks from wellbores would be detected through the follow-up investigation of pressure anomalies, visual
inspection, or the use of personal H2S monitors.
Anomalies in injection zone pressure may not indicate a leak, as discussed above. However, if an
investigation leads to a work order, field personnel would inspect the equipment in question and determine
the nature of the problem. If it is a simple matter, the repair would be made and the volume of leaked C02
would be included in the 40 CFR Part 98 Subpart W report for the Rangely Field, as well as reported in
Subpart RR . If more extensive repair were needed, SEM would determine the appropriate approach for
quantifying leaked C02 using the relevant parameters (e.g., the rate, concentration, and duration of
leakage). The work order would serve as the basis for tracking the event for GHG reporting.
Anomalies in annular pressure or other issues detected during routine maintenance inspections would be
treated in the same way. Field personnel would inspect the equipment in question and determine the nature
of the problem. For simple matters the repair would be made at the time of inspection and the volume of
leaked C02 would be included in the 40 CFR Part 98 Subpart W report for the Rangely Field, as well as
reported in Subpart RR. If more extensive repairs were needed, a work order would be generated and SEM
would determine the appropriate approach for quantifying leaked C02 using the relevant parameters (e.g.,
the rate, concentration, and duration of leakage). The work order would serve as the basis for tracking the
event for GHG reporting.
Because leaking C02 at the surface is very cold and leads to formation of bright white clouds and ice that
are easily spotted, SEM also employs a two-part visual inspection process in the general area ofthe Rangely
Field to detect unexpected releases from wellbores. First, field personnel visit the surface facilities on a
routine basis. Inspections may include tank volumes, equipment status and reliability, lube oil levels,
pressures and flow rates in the facility, and valve leaks. Field personnel inspections also check that injectors
are on the proper WAG schedule and observe the facility for visible C02 or fluid line leaks.
Historically, SEM has not experienced any unexpected release events in the Rangely Field. An identified
need for repair or maintenance through visual inspections results in a work order being entered into SEM's
equipment and maintenance work order management system. The time to repair any leak is dependent on
several factors, such as the severity ofthe leak, available manpower, location ofthe leak, and availability
of materials required for the repair. Critical leaks are acted upon immediately.
Finally, SEM uses the data collected by the H2S monitors, which are worn by all field personnel at all times,
as a last method to detect leakage from wellbores. The H2S monitors detection limit is 10ppm; if an H2S
alarm is triggered, the first response is to protect the safety ofthe personnel, and the next step is to safely
investigate the source of the alarm. As noted previously, SEM considers H2S a proxy for potential C02
leaks in the field. Thus, detected H2S leaks will be investigated to determine if potential C02 leakage is
present, but not used to determine the leak volume. If the incident results in a work order, this will serve as
the basis for tracking the event for GHG reporting.
Other Potential Leakage at the Surface:
SEM will utilize the same visual inspection process and H2S monitoring system to detect other potential
leakage at the surface as it does for leakage from wellbores. SEM utilizes routine visual inspections to
detect significant loss of C02 to the surface. Field personnel routinely visit surface facilities to conduct a
visual inspection. Inspections may include review of tank level, equipment status, lube oil levels, pressures
and flow rates in the facility, valve leaks, ensuring that injectors are on the proper WAG schedule, and also
conducting a general observation ofthe facility for visible C02 or fluid line leaks. If problems are detected,
field personnel would investigate, and, if maintenance is required, generate a work order in the maintenance
system, which is tracked through completion. In addition to these visual inspections, SEM will use the results
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of the personal H2S monitors worn by field personnel as a supplement for smaller leaks that may escape
visual detection.
If C02 leakage to the surface is detected, it will be reported to surface operations personnel who will review
the reports and conduct a site investigation. If maintenance is required, a work order will be generated in
the work order management system. The work order will describe the appropriate corrective action and be
used to track completion of the maintenance action. The work order will also serve as the basis for tracking
the event for GHG reporting and quantifying any C02 emissions.
5.1.6 C02 emitted from equipment leaks and vented emissions of C02 from surface equipment
located between the injection flow meter and the injection wellhead.
SEM evaluates and estimates the mass of C02 emitted (in metric tons) annually from equipment leaks and
vented emissions of C02 from equipment located on the surface between the flow meter used to measure
injection quantity and the injection wellhead, as required under 40 CFR Part 98 Subpart W and 40 CFR
Part 98 Subpart RR.
5.1.7 Mass of C02 emissions from equipment leaks and vented emissions of C02 from surface
equipment located between the production flow meter and the production wellhead
SEM evaluates and estimates the mass of C02 emitted (in metric tons) annually from equipment leaks and
vented emissions of C02 from equipment located on the surface between the production wellhead and the
flow meter used to measure production quantity, as required under 40 CFR Part 98 Subpart W and 40 CFR
Part 98 Subpart RR.
5.2 To Demonstrate that Injected C02 is not Expected to Migrate to the Surface
At the end of the Specified Period, SEM intends to cease injecting C02 for the subsidiary purpose of
establishing the long-term storage of C02 in the Rangely Field. After the end of the Specified Period, SEM
anticipates that it will submit a request to discontinue monitoring and reporting. The request will demonstrate
that the amount of C02 reported under 40 CFR §98.440-449 (Subpart RR) is not expected to migrate in the
future in a manner likely to result in surface leakage. At that time, SEM will be able to support its request
with years of data collected during the Specified Period as well as two to three (or more, if needed) years
of data collected after the end of the Specified Period. This demonstration will provide the information
necessary for the EPA Administrator to approve the request to discontinue monitoring and reporting and
may include, but is not limited to:
i. Data comparing actual performance to predicted performance (purchase, injection, production)
over the monitoring period;
ii. An assessment of the C02 leakage detected, including discussion of the estimated amount of
C02 leaked and the distribution of emissions by leakage pathway;
iii. A demonstration that future operations will not release the volume of stored C02 to the surface;
iv. A demonstration that there has been no significant leakage of C02; and,
v. An evaluation of reservoir pressure in the Rangely Field that demonstrates that injected fluids are
not expected to migrate in a manner to create a potential leakage pathway.
6. Determination of Baselines
SEM intends to utilize existing automatic data systems to identify and investigate excursions from expected
performance that could indicate C02 leakage. SEM's data systems are used primarily for operational
control and monitoring and as such are set to capture more information than is necessary for reporting in the
Annual Subpart RR Report. SEM will develop the necessary system guidelines to capture the information that
is relevant to identify possible C02 leakage. The following describes SEM's approach to collecting this
information.
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Visual Inspections
As field personnel conduct routine inspections, work orders are generated in the electronic system for
maintenance activities that cannot be addressed on the spot. Methods to capture work orders that involve
activities that could potentially involve C02 leakage will be developed, if not currently in place. Examples
include occurrences of well workover or repair, as well as visual identification of vapor clouds or ice
formations. Each incident will be flagged for review by the person responsible for MRV documentation. The
responsible party will be provided in the monitoring plan, as required under Subpart A, 98.3(g). The Annual
Subpart RR Report will include an estimate of the amount of C02 leaked. Records of information used to
calculate emissions will be maintained on file for a minimum of three years.
Personal H2S Monitors
H2S monitors are worn by all field personnel. Any monitor alarm triggers an immediate response to ensure
personnel are not at risk and to verify the monitor is working properly. The person responsible for MRV
documentation will receive notice of all incidents where H2S is confirmed to be present. The Annual Subpart
RR Report will provide an estimate the amount of C02 emitted from any such incidents. Records of
information to calculate emissions will be maintained on file for a minimum of three years.
Injection Rates. Pressures and Volumes
SEM develops target injection rate and pressure for each injector, based on the results of ongoing pattern
modeling and within permitted limits. The injection targets are programmed into the WAG controllers. High
and low set points are also programmed into the SCADA, and flags whenever statistically significant
deviations from the targeted ranges are identified. The set points are designed to be conservative, because
it is preferable to have too many flags rather than too few. As a result, flags can occur frequently and are
often found to be insignificant. For purposes of Subpart RR reporting, flags (or excursions) will be screened
to determine if they could also lead to C02 leakage to the surface. The person responsible for the MRV
documentation will receive notice of excursions and related work orders that could potentially involve C02
leakage. The Annual Subpart RR Report will provide an estimate of C02 emissions. Records of information
to calculate emissions will be maintained on file for a minimum of three years.
Production Volumes and Compositions
SEM develops a general forecast of production volumes and composition which is used to periodically
evaluate performance and refine current and projected injection plans and the forecast. This information is
used to make operational decisions but is not recorded in an automated data system. Sometimes, this
review may result in the generation of a work order in the maintenance system. The MRV plan
implementation lead will review such work orders and identify those that could result in C02 leakage. Should
such events occur, leakage volumes would be calculated following the approaches described in Sections 4
and 5. Impact to Subpart RR reporting will be addressed, if deemed necessary.
7. Determination of Sequestration Volumes Using Mass Balance Equations
To account forthe site conditions and complexity of a large, active EOR operation, SEM proposes to modify
the locations for obtaining volume data forthe equations in Subpart RR §98.443 as indicated below.
The modification addresses the propagation of error that would result if volume data from meters at each
injection well were utilized. This issue arises because while each meter has a small but acceptable margin
of error, this error would become significant if data were taken from the approximately 284 meters within
the Rangely Field. As such, SEM proposes to use the data from custody and operations meters on the main
system pipelines to determine injection volumes used in the mass balance. This satisfies the requirement in
40 CFR 98.444 (b) 1 that you must select a point or points of measurement at which the C02 stream is
representative of the C02 streams being injected, since the main line injection stream is the same stream
being injected into the wells.
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The following sections describe how each element of the mass-balance equation (Equation RR-11) will be
calculated.
. Mass of C02 Received
SEM will use equation RR-2 as indicated in Subpart RR §98.443 to calculate the mass of 0O2 received
from each delivery meter immediately upstream of the Raven Ridge pipeline delivery system on the Rangely
Field. The volumetric flow at standard conditions will be multiplied by the C02 concentration and the density
of C02 at standard conditions to determine mass.
CG2T,r = X(Qr.P~-SrJ*D*C(n,^ (Eq, RR-3)
where:
C02 = Total net annual mass of C02 received (metric tons).
C02T,r = Net annual mass of C02 received (metric tons) as calculated in Equation RR-2 for flow meter r.
r = Receiving flow meter.
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7.2 Mass of C02 Injected into the Subsurface
The equation for calculating the Mass of C02 Injected into the Subsurface at the Rangely Field is equal to
the sum of the Mass of C02 Received as calculated in RR-3 of 98.443 (as described in Section 7.1) and the
Mass of C02 Recycled as calculated using measurements taken from the flow meter located at the output
of the RCF. As previously explained, using data at each injection well would give an inaccurate estimate of
total injection volume due to the large number of wells and the potential for propagation of error due to
allowable calibration ranges for each meter.
The mass of C02 recycled will be determined using equations RR-5 as follows:
4
C°2'u = X * D * C' <>¦ (Eq. RR-5)
/>=!
where:
C02,u = Annual C02 mass injected (metric tons) as measured by flow meter u.
Qp,u = Quarterly volumetric flow rate measurement for flow meter u in quarter p at standard conditions
(standard cubic meters per quarter).
D = Density of C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.
C02,p,u = 0O2 concentration measurement in flow for flow meter u in quarter p (vol. percent C02,
expressed as a decimal fraction).
p = Quarter of the year, u = Flow meter.
The total Mass of C02 injected will be the sum of the Mass of C02 received (RR-3) and Mass of C02
recycled (modified RR-5).
C02| = C02 + C02,u
7.3 Mass of C02 Produced
The Mass of C02 Produced at the Rangely Field will be calculated using the measurements from the flow
meters at the inlet to RCF and for C02 entrained in the sales oil, the custody transfer meter for oil sales
rather than the metered data from each production well. Again, using the data at each production well would
give an inaccurate estimate of total injection due to the large number of wells and the potential for
propagation of error due to allowable calibration ranges for each meter.
Equation RR-8 in 98.443 will be used to calculate the mass of C02 produced from all injection wells as
follows:
4
C02, w = X *D * C(v {Eq, RR-8)
i
Where:
CQ2,w = Annual CQ2 mass produced (metric tons) .
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Qp,w = Volumetric gas flow rate measurement for meter w in quarter p at standard conditions (standard
cubic meters).
D = Density of C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.
CC02,p,w = 0O2 concentration measurement in flow for meter w in quarter p (vol. percent C02,
expressed as a decimal fraction).
p = Quarter of the year, w = inlet meter to RCF.
Equation RR-9 in 98.443 will be used to aggregate the mass of C02 produced net of the mass of C02
entrained in oil leaving the Rangely Field priorto treatment of the remaining gas fraction in RCF as follows:
C02p = Total annual C02 mass produced (metric tons) through all meters in the reporting year.
C02,w = Annual C02 mass produced (metric tons) through meter w in the reporting year.
Xoil = Mass of entrained C02 in oil in the reporting year measured utilizing commercial meters and
electronic flow-measurement devices at each point of custody transfer. The mass of C02 will be calculated
by multiplying the total volumetric rate by the C02 concentration.
7.4 Mass of C02 emitted by Surface Leakage
SEM will calculate and report the total annual Mass of C02 emitted by Surface Leakage using an approach
that relies on 40 CFR Part 98 Subpart W reports for equipment leakage, and tailored calculations for all
other surface leaks. As described in Sections 4 and 5.1.5-5.1.7, SEM is prepared to address the potential
for leakage in a variety of settings. Given the uncertainty concerning the nature and characteristics of leaks
that will be encountered, it is not clear the method for quantifying the volume of leaked C02 that would be
most appropriate. Estimates of the amount of C02 leaked to the surface will depend on a number of site-
specific factors including measurements of flowrate, pressure, size of leak opening, and duration of the
leak. Engineering estimates, and emission factors, depending on the source and nature of the leakage will
also be used.
SEM's process for quantifying leakage will entail using best engineering principles or emission factors.
While it is not possible to predict in advance the types of leaks that will occur, SEM describes some
approaches for quantification in Section 5.1.5-5.1.7. In the event leakage to the surface occurs, SEM would
quantify and report leakage amounts, and retain records that describe the methods used to estimate or
measure the volume leaked as reported in the Annual Subpart RR Report.
Equation RR-10 in 48.433 will be used to calculate and report the Mass of CQ2 emitted by Surface Leakage:
(Eq. RR-9)
Where:
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C°2E = XC02..x (Eq- RR-10)
t=l
where:
C02E = Total annual C02 mass emitted by surface leakage (metric tons) in the reporting year.
C02,x = Annual C02 mass emitted (metric tons) at leakage pathway x in the reporting year,
x = Leakage pathway.
7.5 Mass of C02 sequestered in subsurface geologic formations.
SEM will use equation RR-11 in 98.443 to calculate the Mass of C02 Sequestered in Subsurface
Geologic Formations in the Reporting Year as follows:
CO2 = CO21 ~ CO2P - CO2E - CO:;fi CO2FP (Ecj. RR-11)
where:
C02 = Total annual C02 mass sequestered in subsurface geologic formations (metric tons) at the facility
in the reporting year.
C02| = Total annual C02 mass injected (metric tons) in the well or group of wells covered by this source
category in the reporting year.
C02p = Total annual C02 mass produced (metric tons) net of C02 entrained in oil in the reporting year.
C02E = Total annual C02 mass emitted (metric tons) by surface leakage in the reporting year.
C02FI = Total annual C02 mass emitted (metric tons) from equipment leaks and vented emissions of C02
from equipment located on the surface between the flow meter used to measure injection quantity and the
injection wellhead, forwhich a calculation procedure is provided in subpart W of this part.
C02FP = Total annual C02 mass emitted (metric tons) from equipment leaks and vented emissions of C02
from equipment located on the surface between the production wellhead and the flow meter used to
measure production quantity, forwhich a calculation procedure is provided in subpart W of this part.
7.6 Cumulative mass of C02 reported as sequestered in subsurface geologic formations
SEM will sum up the total annual volumes obtained using equation RR-11 in 98.443 to calculate the
Cumulative Mass of C02 Sequestered in Subsurface Geologic Formations.
8. MRV Plan Implementation Schedule
The activities described in this MRV Plan are in place, and reporting is planned to start upon EPA approval.
Other GHG reports are filed on March 31 of the year after the reporting year and it is anticipated that the
Annual Subpart RR Report will be filed at the same time. As described in Section 3.3 above, SEM anticipates
that the MRV program will be in effect during the Specified Period, during which time SEM will operate the
35
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Rangely Field with the subsidiary purpose of establishing long-term containment of a measurable quantity
of C02 in subsurface geological formations at the Rangely Field. SEM anticipates establishing that a
measurable amount of C02 injected during the Specified Period will be stored in a manner not expected
to migrate resulting in future surface leakage. At such time, SEM will prepare a demonstration supporting
the long-term containment determination and submit a request to discontinue reporting under this MRV
plan. See 40 C.F.R. § 98.441 (b)(2)(ii).
9. Quality Assurance Program
9.1 Monitoring QA/QC
As indicated in Section 7, SEM has incorporated the requirements of §98.444 (a) - (d) in the discussion
of mass balance equations. These include the following provisions.
C02 Received and Injected
The quarterly flow rate of C02 received by pipeline is measured at the receiving custody
transfer meters.
The quarterly C02 flow rate for recycled C02 is measured at the flow meter located at the C02
Reinjection facility outlet.
C02 Produced
The point of measurement for the quantity of C02 produced is a flow meter at the C02 Reinjection
facility inlet. . C02 produced as entrained or dissolved C02 in produced oil is calculated using
volumetric flow through the custody transfer meter.
The produced gas stream is sampled at least once per quarter immediately downstream of the flow
meter used to measure flow rate of that gas stream and measure the 0O2 concentration of the
sample.
The quarterly flow rate of the produced gas is measured at the flow meters located at the C02
Reinjection facility inlet.
C02 emissions from equipment leaks and vented emissions of C02
These volumes are measured in conformance with the monitoring and QA/QC requirements
specified in subpart W of 40 CFR Part 98.
Flow meter provisions
The flow meters used to generate date for the mass balance equations in Section 7 are:
Operated continuously except as necessary for maintenance and calibration.
Operated using the calibration and accuracy requirements in 40 CFR §98.3(i).
Operated in conformance with American Petroleum Institute (API) standards.
National Institute of Standards and Technology (NIST) traceable.
Concentration of C02
As indicated in Appendix 1, C02 concentration is measured using an appropriate standard method. Further,
all measured volumes of C02 have been converted to standard cubic meters at a temperature of 60
degrees Fahrenheit and at an absolute pressure of 1 atmosphere, including those used in Equations RR-
2, RR-5 and RR-8 in Section 7.
Missing Data Procedures
36
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In the event SEM is unable to collect data needed for the mass balance calculations, procedures
for estimating missing data in §98.445 will be used as follows:
A quarterly flow rate of C02 received that is missing would be estimated using invoices or using a
representative flow rate value from the nearest previous time period.
A quarterly C02 concentration of a C02 stream received that is missing would be estimated using
invoices or using a representative concentration value from the nearest previous time period.
A quarterly quantity of C02 injected that is missing would be estimated using a representative quantity
of C02injected from the nearest previous period of time at a similar injection pressure.
For any values associated with C02 emissions from equipment leaks and vented emissions of C02
from surface equipment at the facility that are reported in this subpart, missing data estimation
procedures specified in subpart Wof 40 CFR Part 98 would be followed.
The quarterly quantity of C02 produced from subsurface geologic formations that is missing would be
estimated using a representative quantity of C02 produced from the nearest previous period of time.
9.3 MRV Plan Revisions
In the event there is a material change to the monitoring and/or operational parameters of the SEM C02
EOR operations in the Rangely Field that is not anticipated in this MRV plan, the MRV plan will be revised
and submitted to the EPA Administrator within 180 days as required in §98.448(d).
10. Records Retention
SEM will follow the record retention requirements specified by §98.3(g). In addition, it will follow the
requirements in Subpart RR §98.447 by maintaining the following records for at least three years:
Quarterly records of C02 received at standard conditions and operating conditions, operating
temperature and pressure, and concentration of these streams.
Quarterly records of produced C02, including volumetric flow at standard conditions and operating
conditions, operating temperature and pressure, and concentration of these streams.
Quarterly records of injected C02 including volumetric flow at standard conditions and operating
conditions, operating temperature and pressure, and concentration of these streams.
Annual records of information used to calculate the C02 emitted by surface leakage from leakage
pathways.
Annual records of information used to calculate the C02 emitted from equipment leaks and vented
emissions of C02 from equipment located on the surface between the flow meter used to measure
injection quantity and the injection wellhead.
Annual records of information used to calculate the C02 emitted from equipment leaks and vented
emissions of C02 from equipment located on the surface between the production wellhead and the
flow meter used to measure production quantity.
These data will be collected as generated and aggregated as required for reporting purposes.
11. Appendices
37
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Appendix 1. Conversion Factors
SEM reports C02 volumes at standard conditions of temperature and pressure as defined in the State of
Colorado, which follows the international standard conditions for measuring C02 properties - 77 °F and
14.696 psi.
To convert these volumes into metric tonnes, a density is calculated using the Span and Wagner equation
of state as recommended by the EPA. Density was calculated using the database of thermodynamic
properties developed by the National Institute of Standards and Technology (NIST), available at
http://webbook.nist.gov/chemistrv/fluid/.
At EPA standard conditions of 77 °F and one atmosphere, the Span and Wagner equation of state gives a
density of 0.0026500 lb-moles per cubic foot. Using a molecular weight for C02 of 44.0095, 2204.62
lbs/metric ton and 35.314667 ft3/m3, gives a C02 density of 5.29003 x 10 5 MT/ft3 or 0.0018682 MT/m3.
The conversion factor 5.29003 x 10-5 MT/Mcf has been used throughout to convert SEM volumes to metric
tons.
38
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Appendix 2. Acronyms
AGA-American Gas Association
AMA - Active Monitoring Area
AoR - Area of Review
API-American Petroleum Institute
BCF - Billion Cubic Feet
bopd - barrels of oil per day
Cf- Cubic Feet
CCR - Code of Colorado Regulations
COGCC - Colorado Oil and Gas Conservation Commission
C02 - Carbon Dioxide
CRF - C02 Removal Facilities
EOR - Enhanced Oil Recovery
EPA - US Environmental Protection Agency
GHG - Greenhouse Gas
GHGRP - Greenhouse Gas Reporting Program
H2S - Hydrogen Sulfide
IWR - Injection to Withdrawal Ratio
LACT - Lease Automatic Custody Transfer meter
Md - Millidarcy
MIT - Mechanical Integrity Test
MFF - Main Field Fault
MMA - Maximum Monitoring Area
MMB - Million barrels
Mscf-Thousand standard cubic feet
MMscf- Million standard cubic feet
MMMT - Million metric tonnes
MMT -Thousand metric tonnes
MRV - Monitoring, Reporting, and Verification
MOC - Main oil column
MT - Metric Tonne
NGNatural Gas
NGLs - Natural Gas Liquids
NIST - National Institute of Standards and Technology
OOIP - Original Oil-ln-Place
OH - Open hole
POWC - Producible oil/water contact
PPM - Parts Per Million
RCF - Rangely Field C02 Recycling and Compression Facility
RRPC - Raven Ridge pipeline
RWSU - Rangely Weber Sand Unit
SCADA - Supervisory Control and Data Acquisition
SEM - Scout Energy Management, LLC
UIC - Underground Injection Control
VRU - Vapor Recovery Unit
WAG - Water Alternating Gas
XOM - ExxonMobil
39
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Appendix 3. References
Adams, L., 2006; Sequence and Mechanical Stratigraphy: An intergrated Reservoir Characterization of
the Weber Sandstone, Western Colorado. University of Texas at El Paso Ph.D. Dissertation.
Colorado Administrative Code Department 400 Division 404 Oil and Gas Conservation Commission
Section 2
Clark, Rory, Chevron North America E&P, Presentation to 6th Annual Wyoming C02 Conference, July 12,
2012, online: //www.uwyo.edu/eori/_files/C02conference12/rory_rangelycasehistory.pdf
Energy and Carbon Management Regulation in Colorado. May 22, 2023, online:
https://leg.colorado.gov/bills/sb23-285
US Department of Energy, National Energy Technology Laboratory. "Carbon Dioxide Enhanced Oil
Recovery - Untapped Domestic Energy Supply and Long Term Carbon Storage Solution," March 2010.
US Department of Energy, National Energy Technology Laboratory. "Carbon Sequestration Through
Enhanced Oil Recovery," April 2008.
Gale, Hoyt. Geology of the Rangely Oil District. Department of Interior United States Geological Survey,
Bulletin 350. 1908.
40
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Appendix 4. Glossary of Terms
This glossary describes some of the technical terms as they are used in this MRV plan. For additional
glossaries please see the U.S. EPA Glossary of UIC Terms
(http://water.epa.gov/tvpe/aroundwater/uic/alossarv.cfm') and the Schlumberger Oilfield Glossary
(http://www.glossary.oilfield.slb.com/).
Contain / Containment - having the effect of keeping fluids located within in a specified portion of a geologic
formation.
Dip-Very few, if any, geologic features are perfectly horizontal. They are almost always tilted. The direction
of tilt is called "dip." Dip is the angle of steepest descent measured from the horizontal plane. Moving higher
up structure is moving "updip." Moving lower is "downdip." Perpendicular to dip is "strike." Moving
perpendicular along a constant depth is moving along strike.
Downdip - See "dip."
Formation - A body of rock that is sufficiently distinctive and continuous that it can be mapped.
Infill Drilling - The drilling of additional wells within existing patterns. These additional wells decrease
average well spacing. This practice both accelerates expected recovery and increases estimated ultimate
recovery in heterogeneous reservoirs by improving the continuity between injectors and producers. As well
spacing is decreased, the shifting flow paths lead to increased sweep to areas where greater hydrocarbon
saturations remain.
Permeability - Permeability is the measure of a rock's ability to transmit fluids. Rocks that transmit fluids
readily, such as sandstones, are described as permeable and tend to have many large, well-connected
pores. Impermeable formations, such as shales and siltstones, tend to be finer grained or of a mixed grain
size, with smaller, fewer, or less interconnected pores.
Phase - Phase is a region of space throughout which all physical properties of a material are essentially
uniform. Fluids that don't mix together segregate themselves into phases. Oil, for example, does not mix
with water and forms a separate phase.
Pore Space - See porosity.
Porosity - Porosity is the fraction of a rock that is not occupied by solid grains or minerals. Almost all rocks
have spaces between rock crystals or grains that is available to be filled with a fluid, such as water, oil or
gas. This space is called "pore space."
Saturation - The fraction of pore space occupied by a given fluid. Oil saturation, for example, is the fraction
of pore space occupied by oil.
Seal - A geologic layer (or multiple layers) of impermeable rock that serve as a barrier to prevent fluids
from moving upwards to the surface.
Secondary recovery - The second stage of hydrocarbon production during which an external fluid such as
water or gas is injected into the reservoirthrough injection wells located in rock that has fluid communication
with production wells. The purpose of secondary recovery is to maintain reservoir pressure and to displace
hydrocarbons toward the wellbore. The most common secondary recovery techniques are gas injection and
waterflooding.
Stratigraphic section - A stratigraphic section is a sequence of layers of rocks in the order they were
deposited.
41
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Strike - See "dip.
Updip - See "dip.
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Appendix 5. Well Identification Numbers
The following table presents the well name, API number, status and type for the wells in the RWSU as of
April 2023. The table is subject to change overtime as new wells are drilled, existing wells change status,
or existing wells are repurposed. The following terms are used:
Well Status
Producing refers to a well that is actively producing
Injecting refers to a well that is actively injecting
P&A refers to wells that have been closed (plugged and abandoned) per COGCC regulations
Shut In refers to wells that have been temporarily idled or shut-in
Monitor refers to a well that is used to monitor bottom home pressure in the reservoir
Well Type
Water / Gas Inject refers to wells that inject water and C02 Gas
Water Injection Well refers to wells that inject water
Oil well refers to wells that produce oil
Salt Water Disposal refers to a well used to dispose of excess water
Name
API Number
Well Type
Well Status
AC MCLAUGHLIN 46
51030632300
Water Injection Well
P&A
AC MCLAUGHLIN 64X
51030771700
Oil well
Producing
ASSOCIATED A 2
51030571400
Water / Gas Inject
P&A
ASSOCIATED A1
51030571300
Oil well
Producing
ASSOCIATED A2ST
51030571401
Water / Gas Inject
Injecting
ASSOCIATED A3X
51030778600
Oil well
Producing
ASSOCIATED A4X
51030791600
Oil well
Producing
ASSOCIATED A5X
51030803400
Water / Gas Inject
Injecting
ASSOCIATED A6X
51030801100
Water / Gas Inject
Injecting
ASSOCIATED LARSON UNIT A1
51030600900
Oil well
Producing
ASSOCIATED LARSON UNIT A2X
51030881500
Oil well
Producing
ASSOCIATED LARSON UNIT B1
51030601100
Oil well
Producing
ASSOCIATED LARSON UNIT B2X
51030950200
Oil well
Producing
ASSOCIATED UNIT A1
51030602600
Oil well
Producing
ASSOCIATED UNIT A2X UN A-2X
51031053200
Oil well
Producing
ASSOCIATED UNIT A3X
51031072300
Oil well
Producing
ASSOCIATED UNIT A4X
51031072200
Water / Gas Inject
Injecting
ASSOCIATED UNIT C1
51030582700
Oil well
Producing
BEEZLEY 1X22AX
51031075400
Water / Gas Inject
Injecting
BEEZLEY 2-22
51030574200
Oil well
Producing
BEEZLEY 3X 3X22
51031054900
Oil well
Producing
BEEZLEY 4X 22
51031055300
Oil well
Producing
BEEZLEY 5X22
51031174200
Oil well
Producing
BEEZLEY 6X22
51031174300
Oil well
Producing
43
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CARNEY 22X-35
51030724500
Oil well
P&A
CARNEY CT 10-4
51030608600
Oil well
Monitor
CARNEY CT 11-4
51030545700
Oil well
Monitor
CARNEY CT 12AX5
51030917600
Water / Gas Inject
Monitor
CARNEY CT 13-4
51030545900
Oil well
Producing
CARNEY CT 1-34
51030548200
Oil well
Producing
CARNEY CT 14-34
51030103500
Oil well
Producing
CARNEY CT 15-35
51030103700
Water / Gas Inject
Injecting
CARNEY CT 16-35
51030103300
Water / Gas Inject
Monitor
CARNEY CT 17-35
51030103200
Oil well
Producing
CARNEY CT 18-35
51030629500
Water / Gas Inject
Injecting
CARNEY CT 19-34
51030604400
Oil well
Producing
CARNEY CT 20X35
51030641300
Oil well
Producing
CARNEY CT 21X35
51030703300
Water / Gas Inject
Injecting
CARNEY CT 22X35ST
51030724501
Oil well
Producing
CARNEY CT 2-34
51030551400
Oil well
Monitor
CARNEY CT 23X35
51030726200
Water / Gas Inject
Injecting
CARNEY CT 24X35
51030728300
Water / Gas Inject
Monitor
CARNEY CT 27X34
51030746600
Water / Gas Inject
Injecting
CARNEY CT 28X
51030747400
Water / Gas Inject
Monitor
CARNEY CT 29X
51030753700
Water / Gas Inject
Injecting
CARNEY CT 30X34 30X
51030752600
Water / Gas Inject
Injecting
CARNEY CT 32X34
51030758900
Water / Gas Inject
Injecting
CARNEY CT 3-34
51030103900
Oil well
Producing
CARNEY CT 33X34
51030759200
Water / Gas Inject
Injecting
CARNEY CT 35X34
51030759300
Water / Gas Inject
Injecting
CARNEY CT 37X4
51030856300
Oil well
Producing
CARNEY CT 38X4
51030881300
Water / Gas Inject
Monitor
CARNEY CT 39X4
51030881400
Oil well
Producing
CARNEY CT41Y34
51030914900
Oil well
Monitor
CARNEY CT 4-34
51030555900
Oil well
Producing
CARNEY CT 43Y34
51030914800
Oil well
Monitor
CARNEY CT 44Y34
51030915300
Oil well
Monitor
CARNEY CT 5-34
51030103800
Oil well
Producing
CARNEY CT 6-5
51030609100
Water / Gas Inject
Monitor
CARNEY CT 7-35
51030629300
Oil well
Producing
CARNEY CT 8-34
51030104000
Oil well
Producing
CARNEY CT 9-35
51030548600
Water / Gas Inject
Monitor
CARNEY UNIT 1
51030608700
Oil well
Producing
CARNEY UNIT 2X
51030719100
Water / Gas Inject
Injecting
COLTHARPJE 10X
51030869400
Oil well
Producing
44
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COLTHARP JE 2
51030602300
Water / Gas Inject
Monitor
COLTHARP JE 4
51030602200
Water / Gas Inject
Monitor
COLTHARP JE 5X
51030705700
Oil well
Producing
COLTHARP JE 7X
51030727900
Oil well
Producing
COLTHARP JE 8X
51030734300
Oil well
Producing
COLTHARP WH A1
51030601900
Water / Gas Inject
Injecting
COLTHARP WH A3
51030602100
Water / Gas Inject
Monitor
COLTHARP WH A4
51030102800
Water / Gas Inject
Injecting
COLTHARP WH A5X
51030725000
Oil well
Producing
COLTHARP WH A6X
51030744700
Oil well
Producing
COLTHARP WH A8X
51030909900
Oil well
Producing
COLTHARP WH B2X
51030859400
Oil well
Monitor
COLTHARP WH B3X
51030879300
Oil well
Shut In
COLTHARP WH C1
51030107700
Water / Gas Inject
Monitor
COLTHARP WH C2X
51030919800
Oil well
Producing
CT CARNEY 25X34
51030741500
Water / Gas Inject
Injecting
EMERALD 10
51030566200
Oil well
Producing
EMERALD 11
51030567100
Oil well
Producing
EMERALD13ST
51030563601
Water / Gas Inject
Injecting
EMERALD 14
51030556500
Water / Gas Inject
Injecting
EMERALD 16
51030625300
Oil well
Monitor
EMERALD 17
51030567700
Water / Gas Inject
Injecting
EMERALD18AX
51030920200
Oil well
Producing
EMERALD 19
51030624000
Oil well
Producing
EMERALD 2
51030566900
Oil well
Producing
EMERALD 20
51030555800
Water / Gas Inject
Injecting
EMERALD 22
51030625400
Water / Gas Inject
Injecting
EMERALD 23
51030558900
Water / Gas Inject
Injecting
EMERALD 25
51030548100
Water / Gas Inject
Injecting
EMERALD 26
51030624200
Water / Gas Inject
Injecting
EMERALD 27
51030565300
Oil well
Producing
EMERALD 28
51030562800
Water / Gas Inject
Injecting
EMERALD 29AX
51030924500
Water / Gas Inject
Injecting
EMERALD 30AX
51030920300
Water / Gas Inject
Injecting
EMERALD 31 AX
51030923600
Water / Gas Inject
Injecting
EMERALD 32
51030623800
Oil well
Producing
EMERALD 33AX
51030923900
Water / Gas Inject
Injecting
EMERALD 34
51030559500
Water / Gas Inject
Injecting
EMERALD 35
51030559400
Water / Gas Inject
Injecting
EMERALD 36
51030548800
Water / Gas Inject
Injecting
EMERALD 37
51030551200
Water / Gas Inject
Injecting
45
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EMERALD 38
51030624900
Water / Gas Inject
Injecting
EMERALD 39
51030625100
Water / Gas Inject
Injecting
EMERALD 3ST
51030559901
Water / Gas Inject
Injecting
EMERALD 3ST 3
51030559900
Water / Gas Inject
P&A
EMERALD 4
51030550500
Oil well
Producing
EMERALD 40
51030625000
Water / Gas Inject
Injecting
EMERALD 41
51030546300
Water / Gas Inject
Monitor
EMERALD 42D
51030634000
Salt Water Disposal
Injecting
EMERALD 44AX
51030918700
Water / Gas Inject
Injecting
EMERALD 46X
51030713000
Oil well
Producing
EMERALD 47X
51030720100
Oil well
Producing
EMERALD 48X
51030725700
Oil well
Monitor
EMERALD 49AX
51031068000
Oil well
Producing
EMERALD 50X
51030733100
Oil well
Producing
EMERALD 51X
51030733300
Oil well
Producing
EMERALD 52X
51030737100
Oil well
Producing
EMERALD 53X
51030737600
Oil well
Producing
EMERALD 54X
51030763700
Oil well
Producing
EMERALD 55X
51030763800
Oil well
Producing
EMERALD 56X
51030768700
Oil well
Producing
EMERALD 57XST
51030764901
Oil well
Producing
EMERALD 58X
51030773900
Oil well
Producing
EMERALD 59X
51030774000
Oil well
Producing
EMERALD 6
51030558800
Water / Gas Inject
Injecting
EMERALD 60X
51030779800
Oil well
Producing
EMERALD 61X
51030780300
Oil well
Producing
EMERALD 62X
51030781100
Oil well
Producing
EMERALD 63ST
51030804101
Water / Gas Inject
Injecting
EMERALD 63XST
51030804100
Water / Gas Inject
P&A
EMERALD 64X
51030799200
Water / Gas Inject
Injecting
EMERALD 65X
51030794800
Oil well
Producing
EMERALD 66X
51030786800
Oil well
Producing
EMERALD 67X
51030797400
Oil well
Producing
EMERALD 68X
51030797500
Oil well
Producing
EMERALD 69X
51030810300
Water / Gas Inject
Injecting
EMERALD 70X
51030807200
Water / Gas Inject
Injecting
EMERALD 71X
51030804600
Water / Gas Inject
Injecting
EMERALD 72X
51030810400
Water / Gas Inject
Monitor
EMERALD 73X
51030810500
Oil well
Monitor
EMERALD 74X
51030816900
Oil well
Producing
EMERALD 75X
51030843700
Oil well
Producing
46
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EMERALD 76X
51030848100
Oil well
Producing
EMERALD 77X
51030848000
Oil well
Producing
EMERALD 78X
51030849100
Oil well
Producing
EMERALD 79X
51030895500
Salt Water Disposal
Injecting
EMERALD 7 A
51030928500
Water / Gas Inject
Injecting
EMERALD 8
51030559000
Water / Gas Inject
P&A
EMERALD 80X
51030876900
Oil well
Producing
EMERALD 81X
51030888300
Oil well
Producing
EMERALD 82X
51030849200
Water / Gas Inject
Injecting
EMERALD 83X
51030876500
Oil well
Producing
EMERALD 84X
51030888500
Oil well
Producing
EMERALD 85X
51030877000
Oil well
Producing
EMERALD 86X
51030877200
Oil well
Producing
EMERALD 87X
51030877300
Oil well
Monitor
EMERALD 88X
51030876600
Oil well
Producing
EMERALD 89X
51030877100
Oil well
Producing
EMERALD 8ST
51030559001
Water / Gas Inject
Injecting
EMERALD 90X
51030914600
Water / Gas Inject
Injecting
EMERALD 91Y
51030914700
Water / Gas Inject
Injecting
EMERALD 92X
51030929500
Oil well
Producing
EMERALD 93X
51031185800
Oil well
Producing
EMERALD 94X
51031185500
Oil well
Producing
EMERALD 95X
51031191400
Oil well
Producing
EMERALD 96X
51031192200
Oil well
Producing
EMERALD 97X
51031191300
Oil well
Producing
EMERALD 98X
51031191500
Water / Gas Inject
Injecting
EMERALD 9ST
51030566101
Water / Gas Inject
Injecting
EMERALD 9ST 9
51030566100
Water / Gas Inject
P&A
FAIRFIELD KITTI A 4
51031101700
Oil well
P&A
FAIRFIELD KITTI A 5P
51031101000
Oil well
P&A
FAIRFIELD KITTI A1
51030611100
Water / Gas Inject
Injecting
FAIRFIELD KITTI A4
51031101701
Oil well
Producing
FAIRFIELD KITTI A5
51031101001
Oil well
Producing
FAIRFIELD KITTI B1
51030107800
Water / Gas Inject
Injecting
FE156X
51031033600
Oil well
Producing
FEE 1
51030563400
Oil well
Producing
FEE 1 162Y
51031194500
Water / Gas Inject
Injecting
FEE 10
51030566800
Water / Gas Inject
Injecting
FEE 100X
51030786900
Oil well
Producing
FEE 101X
51030787000
Oil well
Producing
FEE 102X
51030787700
Oil well
Producing
47
-------
FEE 103X
51030788500
Oil well
Monitor
FEE 104X
51030785700
Oil well
Producing
FEE 105X
51030785800
Oil well
Producing
FEE 106X
51030794600
Water / Gas Inject
Injecting
FEE 107X
51030803200
Water / Gas Inject
Injecting
FEE 108X
51030795200
Oil well
Producing
FEE 109X
51030798900
Water / Gas Inject
Injecting
FEE 11
51030559600
Oil well
Producing
FEE 11OX
51030802600
Water / Gas Inject
Injecting
FEE 111X
51030802700
Water / Gas Inject
Monitor
FEE 112X
51030802800
Water / Gas Inject
Injecting
FEE 113X
51030802900
Water / Gas Inject
Injecting
FEE 114X
51030803100
Water / Gas Inject
Injecting
FEE 115X
51030803300
Water / Gas Inject
Injecting
FEE 116X
51030829900
Water / Gas Inject
Injecting
FEE 117X
51030843800
Oil well
Producing
FEE 118AX
51030928300
Oil well
Monitor
FEE 12
51030565100
Oil well
Producing
FEE 121X
51030857500
Oil well
Producing
FEE 122X
51030866300
Water / Gas Inject
Injecting
FEE 124X
51030866400
Oil well
Producing
FEE 125X
51030868100
Oil well
Monitor
FEE 126X
51030868600
Oil well
Producing
FEE 127X
51030868700
Water / Gas Inject
Injecting
FEE 128X
51030868800
Oil well
Monitor
FEE 129X
51030868900
Oil well
Producing
FEE 13
51030622600
Oil well
Producing
FEE 130X
51030870400
Oil well
Monitor
FEE 133X
51030888400
Oil well
Producing
FEE 135X
51030876000
Oil well
Monitor
FEE 136X
51030874500
Water / Gas Inject
Injecting
FEE 137X
51030876100
Water / Gas Inject
Injecting
FEE 138X
51030876300
Oil well
Producing
FEE 139X
51030876200
Oil well
Producing
FEE 14
51030568700
Oil well
Producing
FEE 140Y
51030910600
Oil well
Monitor
FEE 141X
51030913300
Water / Gas Inject
Injecting
FEE 142X
51030913100
Oil well
Producing
FEE 143X
51030913000
Oil well
Producing
FEE 144Y
51030917500
Oil well
Shut In
FEE 145Y
51030917400
Oil well
Producing
48
-------
FEE 146X
51030946400
Oil well
Producing
FEE 15
51030556800
Oil well
Producing
FEE 153X
51030929700
Oil well
Producing
Fee154X
51031036500
Oil well
Producing
Fee155X
51031037300
Oil well
Producing
FEE 157X
51031101900
Oil well
Monitor
FEE 158 X
51031115900
Oil well
Producing
FEE 159 X
51031101100
Oil well
Producing
FEE 160X
51031186600
Oil well
Producing
FEE 163X
51031195100
Oil well
Producing
FEE16AX
51030923500
Water / Gas Inject
Monitor
FEE 17
51030580100
Water / Gas Inject
Injecting
FEE 18
51030623600
Water / Gas Inject
Monitor
FEE 19
51030622400
Oil well
Producing
FEE 1AX
51030924400
Water / Gas Inject
Monitor
FEE 20
51030616800
Oil well
Producing
FEE 21
51030620700
Oil well
Producing
FEE 22
51030616100
Water / Gas Inject
Injecting
FEE 23
51030615600
Oil well
Producing
FEE 24
51030611200
Water / Gas Inject
Injecting
FEE 25
51030614500
Oil well
Producing
FEE 26
51030615200
Oil well
Producing
FEE 27
51030617500
Oil well
Producing
FEE 28
51030613500
Water / Gas Inject
Injecting
FEE 29
51030614400
Water / Gas Inject
Injecting
FEE 2AX
51030924700
Water / Gas Inject
Injecting
FEE 3
51030565700
Oil well
Producing
FEE 30
51030621100
Water / Gas Inject
Monitor
FEE 31
51030611800
Water / Gas Inject
Injecting
FEE 32
51030614200
Oil well
Producing
FEE 33
51030614700
Oil well
Producing
FEE 34
51030624500
Oil well
Producing
FEE 35
51030611300
Oil well
Producing
FEE 36
51030617600
Oil well
Producing
FEE 37
51030611500
Water / Gas Inject
Injecting
FEE 38
51030625500
Water / Gas Inject
Injecting
FEE 39
51030623300
Water / Gas Inject
Injecting
FEE 4
51030576900
Oil well
Monitor
FEE 40
51030622300
Water / Gas Inject
Injecting
FEE 41
51030622200
Water / Gas Inject
Monitor
FEE 42
51030568800
Water / Gas Inject
Monitor
49
-------
FEE 43
51030614100
Water / Gas Inject
Injecting
FEE 44
51030624700
Water / Gas Inject
Injecting
FEE 45
51030617900
Oil well
Producing
FEE 47
51030616000
Water / Gas Inject
Injecting
FEE 48
51030625900
Water / Gas Inject
Injecting
FEE 49
51030611900
Water / Gas Inject
Injecting
FEE 5
51030574500
Oil well
Producing
FEE 51
51030614900
Water / Gas Inject
Injecting
FEE 52
51030567400
Water / Gas Inject
Injecting
FEE 53AX
51030861200
Water / Gas Inject
Injecting
FEE 55
51030615300
Water / Gas Inject
Injecting
FEE 56
51030615700
Water / Gas Inject
Injecting
FEE 58AX
51030924300
Water / Gas Inject
Injecting
FEE 59
51030616900
Water / Gas Inject
Injecting
FEE 6
51030572000
Oil well
Producing
FEE 60
51030622500
Water / Gas Inject
Injecting
FEE 61
51030620300
Oil well
Producing
FEE 62
51030614000
Oil well
Monitor
FEE 63
51030614600
Water / Gas Inject
Injecting
FEE 64
51030614800
Water / Gas Inject
Injecting
FEE 65
51030615000
Water / Gas Inject
Injecting
FEE 67A
51030929300
Water / Gas Inject
Injecting
FEE 68A
51030568300
Oil well
Producing
FEE 69
51030625600
Water / Gas Inject
Monitor
FEE 7
51030571600
Oil well
Producing
FEE 70AX
51030919100
Water / Gas Inject
Monitor
FEE 72X
51030718000
Oil well
Producing
FEE 73X
51030727400
Oil well
Producing
FEE 74X
51030730700
Oil well
Producing
FEE 75X
51030732600
Oil well
Producing
FEE 76X
51030733900
Oil well
Producing
FEE 78X
51030743400
Oil well
Producing
FEE 79X
51030742400
Water / Gas Inject
Injecting
FEE 8
51030563300
Water / Gas Inject
Injecting
FEE 80X
51030749100
Water / Gas Inject
Injecting
FEE 81X
51030751900
Oil well
Producing
FEE 82X
51030752900
Oil well
Producing
FEE 83X
51030757200
Oil well
Producing
FEE 84X
51030755400
Water / Gas Inject
Injecting
FEE 85X
51030758100
Water / Gas Inject
Injecting
FEE 86X
51030756900
Water Injection Well
P&A
50
-------
FEE 86XST
51030756901
Water / Gas Inject
Injecting
FEE 87X
51030754600
Water / Gas Inject
Monitor
FEE 88X
51030755900
Water / Gas Inject
Injecting
FEE 89X
51030755500
Water / Gas Inject
Injecting
FEE 9
51030551100
Oil well
P&A
FEE 90X
51030758000
Water / Gas Inject
Injecting
FEE 91X
51030757300
Water / Gas Inject
Injecting
FEE 92X
51030755600
Water / Gas Inject
Monitor
FEE 93X
51030759100
Water / Gas Inject
Injecting
FEE 94X
51030759400
Water / Gas Inject
Injecting
FEE 95X
51030764700
Oil well
Producing
FEE 96X
51030764800
Oil well
Producing
FEE 97X
51030779100
Oil well
Producing
FEE 98X
51030782700
Water / Gas Inject
Injecting
FEE 99X
51030784000
Oil well
Producing
FEE 9ST 9
51030551101
Oil well
Producing
GRAY A A17X
51030768900
Water / Gas Inject
Injecting
GRAY A A21X
51030830200
Water / Gas Inject
Injecting
GRAY A A8AX
51030919700
Water / Gas Inject
Injecting
GRAY A10
51030573400
Water / Gas Inject
Injecting
GRAY A12
51030613700
Oil well
Producing
GRAY A13
51030577800
Water / Gas Inject
Monitor
GRAY A14
51030613900
Oil well
Producing
GRAY A15
51030576200
Oil well
Producing
GRAY A16
51030613600
Water / Gas Inject
Injecting
GRAY A18X
51030789800
Oil well
Producing
GRAY A19X
51030787300
Oil well
Producing
GRAY A20X
51030803500
Water / Gas Inject
Injecting
GRAY A22X
51030831700
Oil well
Producing
GRAY A9
51030571500
Oil well
Producing
GRAY B10
51030612300
Water / Gas Inject
Injecting
GRAY B11
51030581800
Oil well
Producing
GRAY B12
51030612900
Oil well
Producing
GRAY B13
51030612600
Oil well
Producing
GRAY B14A
51030928900
Water / Gas Inject
Injecting
GRAY B15
51030579600
Oil well
Producing
GRAY B16
51030612700
Oil well
Producing
GRAY B17
51030582500
Oil well
Monitor
GRAY B18X
51030638600
Oil well
Monitor
GRAY B19X
51036639700
Oil well
Producing
GRAY B2
51030578700
Oil well
Producing
51
-------
GRAY B20X
51030101500
Water / Gas Inject
Injecting
GRAY B21X
51031035700
Oil well
Producing
GRAY B22X
51031036000
Oil well
Producing
GRAY B23X
51031033800
Oil well
Producing
GRAY B24X
51031033700
Oil well
Producing
GRAY B25X
51031057200
Oil well
Producing
GRAY B26X
51031057500
Oil well
Producing
GRAY B27X
51031057400
Oil well
Producing
GRAY B28X
51031101200
Oil well
Producing
GRAY B3
51030613200
Water / Gas Inject
Injecting
GRAY B4
51030613300
Water / Gas Inject
Injecting
GRAY B5
51030612400
Water / Gas Inject
Injecting
GRAY B6
51030613100
Water / Gas Inject
Injecting
GRAY B7
51030612800
Water / Gas Inject
Injecting
GRAY B8
51030581100
Water / Gas Inject
Injecting
GRAY B9
51030612500
Water / Gas Inject
Injecting
GUIBERSON SA 1
51030581300
Water / Gas Inject
Injecting
GUIBERSON SA 5 X
51031115600
Oil well
Producing
HAGOOD L N-A 17X
51030914200
Oil well
P&A
HAGOOD LN A1 OX
51030791300
Oil well
Shut In
HAGOOD LN A11X
51030794900
Water / Gas Inject
Injecting
HAGOOD LN A12X
51030793600
Oil well
Producing
HAGOOD LN A13X
51030799100
Water / Gas Inject
Injecting
HAGOOD LN A14X
51030795000
Water / Gas Inject
P&A
HAGOOD LN A14XST
51030795001
Water / Gas Inject
Injecting
HAGOOD LN A15X
51030829300
Oil well
Producing
HAGOOD LN A16X
51030830000
Water / Gas Inject
Injecting
HAGOOD LN A17XST
51030914201
Water / Gas Inject
Monitor
HAGOOD LN A2
51030574300
Oil well
Monitor
HAGOOD LN A3
51030576800
Oil well
Monitor
HAGOOD LN A5
51030573600
Water / Gas Inject
Injecting
HAGOOD LN A7
51030575700
Water / Gas Inject
Monitor
HAGOOD LN A9X
51030702200
Water / Gas Inject
Injecting
HAGOOD MC A1
51030632800
Water / Gas Inject
Injecting
HAGOOD MC A10X
51031041400
Oil well
Producing
HAGOOD MC A11X
51031041300
Oil well
Producing
HAGOOD MC A12X
51031053300
Oil well
Producing
HAGOOD MC A13X
51031053100
Oil well
Producing
HAGOOD MC A14X
51031054800
Oil well
Shut In
HAGOOD MC A15X
51031062800
Oil well
Producing
HAGOOD MC A16X
51031061200
Oil well
Producing
52
-------
HAGOOD MC A17X
51031062900
Oil well
Producing
HAGOOD MC A18X
51031061300
Oil well
Producing
HAGOOD MC A19X
51031067000
Water / Gas Inject
Injecting
HAGOOD MC A2
51030102300
Oil well
Producing
HAGOOD MC A21X
51031070900
Oil well
Producing
HAGOOD MC A3
51030633000
Water / Gas Inject
Injecting
HAGOOD MC A4
51030632600
Water / Gas Inject
Injecting
HAGOOD MC A5
51030633100
Water / Gas Inject
Injecting
HAGOOD MC A6
51030102400
Oil well
Producing
HAGOOD MC A7
51030106700
Oil well
Producing
HAGOOD MC A8 A 8
51030632500
Water / Gas Inject
Injecting
HAGOOD MC A9
51030632700
Water / Gas Inject
Injecting
HAGOOD MC B1A
51031102800
Oil well
Producing
HAGOOD MC B2
51031187000
Oil well
Producing
HEFLEY CS 4X
51030856200
Oil well
Producing
HEFLEY ME 2
51030545200
Water / Gas Inject
Monitor
HEFLEY ME 5X
51030719600
Oil well
Producing
HEFLEY ME 6X
51030729300
Oil well
Producing
HEFLEY ME 7X
51030873700
Oil well
Producing
HEFLEY ME 8X
51030869600
Oil well
Producing
L N HAGOOD A- 1
51030572100
Water / Gas Inject
Injecting
L N HAGOOD A-8 IJ A8
51030569100
Water / Gas Inject
Injecting
LACY SB 1
51030573200
Oil well
Producing
LACY SB 11Y
51030914400
Salt Water Disposal
Injecting
LACY SB 12Y
51030914500
Oil well
Producing
LACY SB 13Y
51031057000
Oil well
Producing
LACY SB 2AX
51030928200
Water / Gas Inject
Injecting
LACY SB 3
51030568900
Oil well
Producing
LACY SB 4
51030575800
Water / Gas Inject
Monitor
LACY SB 6X
51030794700
Oil well
Monitor
LACY SB 7X
51030797800
Water / Gas Inject
Injecting
LACY SB 9X
51030831800
Oil well
Monitor
LARSON FA 1
51030106600
Oil well
Producing
LARSON FA 2
51030107200
Water / Gas Inject
Injecting
LARSON FA 3X
51031071000
Oil well
Monitor
LARSON FVA1
51030547600
Oil well
Producing
LARSON FV A2X
51030721600
Water / Gas Inject
Monitor
LARSON FVB11
51030630200
Water / Gas Inject
Injecting
LARSON FVB12
51030100900
Oil well
Producing
LARSON FV B14X
51030641400
Oil well
Shut In
LARSON FV B15X
51030700800
Oil well
Producing
53
-------
LARSON FV B17X
51030707800
Oil well
Producing
LARSON FV B18X
51030708300
Oil well
Producing
LARSON FV B19X
51030710600
Oil well
Producing
LARSON FV B2
51030620200
Water / Gas Inject
Monitor
LARSON FV B20X
51030709900
Oil well
Producing
LARSON FVB21X
51030716500
Oil well
Producing
LARSON FV B22X
51030722700
Oil well
Producing
LARSON FV B23X
51030724200
Oil well
Producing
LARSON FV B24X
51030873800
Oil well
Producing
LARSON FV B25X
51030916500
Oil well
Producing
LARSON FV B27X
51030948800
Oil well
Producing
LARSON FV B4
51030629800
Water / Gas Inject
Injecting
LARSON FV B8
51030620100
Water / Gas Inject
Injecting
LARSON MB 10X25
51030715900
Oil well
Producing
LARSON MB 12X25
51030727000
Oil well
Producing
LARSON MB 2-26 A226
51030566300
Oil well
Producing
LARSON MB 3X26
51030711000
Oil well
Producing
LARSON MB 4X26
51030717700
Oil well
Monitor
LARSON MB 8X25
51030709300
Oil well
Producing
LARSON MB A1AX
51031075600
Water / Gas Inject
Monitor
LARSON MB A2
51030633200
Oil well
Producing
LARSON MB A3X
51031053400
Oil well
Producing
LARSON MB A4X
51031055200
Oil well
Producing
LARSON MB B1
51030576500
Water / Gas Inject
Injecting
LARSON MB B3AX
51031075500
Water / Gas Inject
Injecting
LARSON MB C1-25
51030618600
Water / Gas Inject
Monitor
LARSON MBC1AX
51031076300
Oil well
Producing
LARSON MB C2
51030569000
Water / Gas Inject
Injecting
LARSON MB C3
51030570800
Water / Gas Inject
Injecting
LARSON MB C3-25
51030618700
Water / Gas Inject
Injecting
LARSON MB C4
51031139700
Oil well
Producing
LARSON MB C5
51031142900
Oil well
Producing
LARSON MB C9X25
51030715500
Oil well
Producing
LARSON MB D1-26E
51030620000
Water / Gas Inject
Injecting
LEVI SON 10
51030621700
Oil well
Producing
LEVI SON 11
51030619800
Water / Gas Inject
Injecting
LEVI SON 12
51030103100
Water / Gas Inject
Injecting
LEVI SON 13
51030619400
Water / Gas Inject
Injecting
LEVI SON 14
51030619900
Water / Gas Inject
Injecting
LEVI SON 17
51030619500
Water / Gas Inject
Injecting
LEVI SON 18
51030618200
Oil well
Producing
54
-------
LEVISON 2
51030559300
Oil well
Producing
LEVI SON 21X
51030638700
Oil well
Producing
LEVISON 22X
51030708900
Oil well
Monitor
LEVISON 23X
51030712300
Oil well
Producing
LEVISON 24X
51030711400
Oil well
Producing
LEVISON 25X
51030722200
Oil well
Producing
LEVISON 26X
51030726700
Oil well
Producing
LEVISON 27X
51030728900
Oil well
Producing
LEVISON 28X
51030731600
Oil well
Monitor
LEVISON 29X
51030732000
Water / Gas Inject
Injecting
LEVISON 30X
51030735100
Water / Gas Inject
Injecting
LEVISON 31X
51030735300
Oil well
Monitor
LEVISON 32X
51030747500
Water / Gas Inject
Injecting
LEVISON 33X
51030752100
Oil well
Producing
LEVISON 34X
51030758600
Water / Gas Inject
Injecting
LEVISON 35X
51030868300
Oil well
Producing
LEVISON 6
51030106200
Oil well
Producing
LEVISON 7
51030619700
Oil well
Monitor
LEVISON 8
51030103000
Water / Gas Inject
Injecting
LEVISON 9
51030628600
Water / Gas Inject
Injecting
LEVSION 1
51030559100
Oil well
Producing
LN - HAGOOD A6
51030569400
Oil well
Producing
LN HAGOOD A-4
51030570700
Oil well
Shut In
MAGOR1A
51030989300
Water / Gas Inject
Injecting
MATTERN 1
51030580400
Water / Gas Inject
Injecting
MCLAUGHLIN AC 1
51030573100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 10
51030578000
Oil well
Monitor
MCLAUGHLIN AC 11
51030569300
Oil well
Producing
MCLAUGHLIN AC 12
51030579800
Water / Gas Inject
Injecting
MCLAUGHLIN AC 13
51030581000
Water / Gas Inject
Injecting
MCLAUGHLIN AC 14
51030105800
Oil well
Producing
MCLAUGHLIN AC 15
51030576700
Oil well
Producing
MCLAUGHLIN AC 16
51030105400
Oil well
Producing
MCLAUGHLIN AC 17
51030631700
Water / Gas Inject
Injecting
MCLAUGHLIN AC 18
51030105300
Water / Gas Inject
Injecting
MCLAUGHLIN AC 19
51030579400
Oil well
Producing
MCLAUGHLIN AC 2
51030573300
Oil well
Producing
MCLAUGHLIN AC 20
51030578200
Water / Gas Inject
Injecting
MCLAUGHLIN AC 21
51030578100
Oil well
Producing
MCLAUGHLIN AC 22
51030105500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 23
51030571800
Water / Gas Inject
Injecting
55
-------
MCLAUGHLIN AC 24
51030576300
Water / Gas Inject
Injecting
MCLAUGHLIN AC 25
51030631800
Oil well
Producing
MCLAUGHLIN AC 26
51030105000
Water / Gas Inject
Injecting
MCLAUGHLIN AC 27
51036005300
Oil well
Producing
MCLAUGHLIN AC 28
51030569900
Oil well
Producing
MCLAUGHLIN AC 29
51030581900
Oil well
Producing
MCLAUGHLIN AC 30
51030105100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 31
51030105200
Water / Gas Inject
Injecting
MCLAUGHLIN AC 32
51030581200
Water / Gas Inject
Injecting
MCLAUGHLIN AC 33
51030631500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 34
51030104700
Water / Gas Inject
Injecting
MCLAUGHLIN AC 35
51030581700
Oil well
Producing
MCLAUGHLIN AC 36
51030104800
Oil well
Producing
MCLAUGHLIN AC 37
51030633300
Oil well
Producing
MCLAUGHLIN AC 38
51030632200
Oil well
Producing
MCLAUGHLIN AC 39A
51031049300
Oil well
Producing
MCLAUGHLIN AC 3AX
51030920700
Water / Gas Inject
Injecting
MCLAUGHLIN AC 4
51030573800
Oil well
Producing
MCLAUGHLIN AC 41AX
51030920100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 42
51030579500
Water / Gas Inject
Monitor
MCLAUGHLIN AC 43
51030632400
Water / Gas Inject
Injecting
MCLAUGHLIN AC 44A
51031096100
Oil well
Producing
MCLAUGHLIN AC 44D
51030631600
Salt Water Disposal
Injecting
MCLAUGHLIN AC 45 AC
51030631900
Water / Gas Inject
Injecting
MCLAUGHLIN AC 46ST
51030632301
Water / Gas Inject
Monitor
MCLAUGHLIN AC 47X
51030107500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 49X
51030641700
Oil well
Monitor
MCLAUGHLIN AC 5
51030571200
Oil well
Monitor
MCLAUGHLIN AC 50X
51030632100
Oil well
Producing
MCLAUGHLIN AC 51X
51030641800
Oil well
Producing
MCLAUGHLIN AC 52X
51030642500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 53X
51030101400
Oil well
Producing
MCLAUGHLIN AC 54X
51030642600
Oil well
Producing
MCLAUGHLIN AC 55X
51030641900
Water / Gas Inject
Injecting
MCLAUGHLIN AC 56X
51030642000
Water / Gas Inject
Injecting
MCLAUGHLIN AC 57X
51030701000
Oil well
Monitor
MCLAUGHLIN AC 58X
51030701400
Oil well
Producing
MCLAUGHLIN AC 59AX
51030928800
Oil well
Producing
MCLAUGHLIN AC 6
51030579900
Oil well
Producing
MCLAUGHLIN AC 60X
51030769200
Water / Gas Inject
Injecting
MCLAUGHLIN AC 61X
51030769000
Oil well
Monitor
56
-------
MCLAUGHLIN AC 62X
51030771500
Oil well
Producing
MCLAUGHLIN AC 63X
51030771600
Water / Gas Inject
Injecting
MCLAUGHLIN AC 65X
51030771800
Oil well
Producing
MCLAUGHLIN AC 66X
51030773800
Water / Gas Inject
Injecting
MCLAUGHLIN AC 67X
51030817000
Oil well
Producing
MCLAUGHLIN AC 68X
51030829200
Oil well
Producing
MCLAUGHLIN AC 69X
51030829400
Water / Gas Inject
Injecting
MCLAUGHLIN AC 7
51030580900
Water / Gas Inject
Injecting
MCLAUGHLIN AC 70X
51030830100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 71X
51030829700
Oil well
Producing
MCLAUGHLIN AC 72X
51030832000
Water / Gas Inject
Injecting
MCLAUGHLIN AC 73X
51030831900
Oil well
Producing
MCLAUGHLIN AC 74X
51030832100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 75X
51030829800
Oil well
Producing
MCLAUGHLIN AC 76X
51030914100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 77X
51030915200
Oil well
Producing
MCLAUGHLIN AC 78X
51030915500
Oil well
Producing
MCLAUGHLIN AC 79X
51030930000
Oil well
Monitor
MCLAUGHLIN AC 8
51030573500
Oil well
Producing
MCLAUGHLIN AC 80X
51030930100
Oil well
Monitor
MCLAUGHLIN AC 81AX
51031064500
Oil well
Producing
MCLAUGHLIN AC 82X
51031054600
Oil well
Producing
MCLAUGHLIN AC 83X
51031059500
Oil well
Producing
MCLAUGHLIN AC 84Y
51031057300
Oil well
Producing
MCLAUGHLIN AC 86Y
51031058400
Oil well
Producing
MCLAUGHLIN AC 88X
51031070000
Oil well
Producing
MCLAUGHLIN AC 9
51030576600
Oil well
Monitor
MCLAUGHLIN AC 90X
51031069900
Oil well
Producing
MCLAUGHLIN AC 91X
51031072600
Water / Gas Inject
Injecting
MCLAUGHLIN AC 92X
51031070800
Oil well
Producing
MCLAUGHLIN AC 93X
51031072700
Water / Gas Inject
Injecting
MCLAUGHLIN AC 94X
51031072500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 95X
51031140800
Oil well
Producing
MCLAUGHLIN AC A1
51030609200
Oil well
Monitor
MCLAUGHLIN AC A3X
51030863000
Oil well
Producing
MCLAUGHLIN AC C2
51031104100
Oil well
Monitor
MCLAUGHLIN SW6
51030627800
Oil well
P&A
MCLAUGHLIN SHARPLES 10X28
51030749000
Oil well
Producing
MCLAUGHLIN SHARPLES 1-28
51030560300
Water / Gas Inject
Injecting
MCLAUGHLIN SHARPLES 12X33
51030759800
Oil well
Producing
MCLAUGHLIN SHARPLES 1-33
51030551300
Oil well
Producing
57
-------
MCLAUGHLIN SHARPLES 13X3
51030873900
Oil well
Producing
MCLAUGHLIN SHARPLES 14Y33
51030912300
Oil well
Producing
MCLAUGHLIN SHARPLES 15X32
51030885400
Oil well
Producing
MCLAUGHLIN SHARPLES 16X32
51030913200
Water / Gas Inject
Injecting
MCLAUGHLIN SHARPLES 2-28
51030560000
Oil well
Producing
MCLAUGHLIN SHARPLES 2-32
51030627300
Water / Gas Inject
Monitor
MCLAUGHLIN SHARPLES 2-33
51030106800
Water / Gas Inject
Injecting
MCLAUGHLIN SHARPLES 3-32
51030627000
Oil well
Monitor
MCLAUGHLIN SHARPLES 3-33
51030629000
Oil well
Producing
MCLAUGHLIN SHARPLES 4-33
51030629100
Water / Gas Inject
Injecting
MCLAUGHLIN SHARPLES 5-33
51030104500
Oil well
Monitor
MCLAUGHLIN SHARPLES 6-33
51030628800
Oil well
Monitor
MCLAUGHLIN SHARPLES 7-33
51030104600
Water / Gas Inject
Monitor
MCLAUGHLIN SHARPLES 8-33
51030628900
Water / Gas Inject
Monitor
MCLAUGHLIN SHARPLES 9X33
51030746500
Oil well
Producing
MCLAUGHLIN SW11X
51030759700
Water / Gas Inject
Injecting
MCLAUGHLIN SW12X
51030760100
Water / Gas Inject
Injecting
MCLAUGHLIN SW 1ST
51030548300
Oil well
P&A
MCLAUGHLIN SW 1 ST 1
51030548301
Water / Gas Inject
Monitor
MCLAUGHLIN SW2
51030627700
Oil well
Producing
MCLAUGHLIN SW 3
51030104400
Water / Gas Inject
Injecting
MCLAUGHLIN SW4
51030107600
Oil well
Producing
MCLAUGHLIN SW 5
51030627900
Oil well
Producing
MCLAUGHLIN SW6ST
51030627801
Water / Gas Inject
Injecting
MCLAUGHLIN SW7X
51030746100
Oil well
Producing
MCLAUGHLIN SW8X
51030753000
Water / Gas Inject
Injecting
MCLAUGHLIN UNIT A1
51030581600
Oil well
Producing
MCLAUGHLIN UNIT B1
51030582600
Oil well
Producing
MCLAUGHLIN UNIT B2X
51031057600
Water / Gas Inject
Injecting
MELLEN 3A
51031098100
Oil well
Producing
MELLEN WP 1
51036000300
Water / Gas Inject
Injecting
MELLEN WP 2
51030105600
Water / Gas Inject
Injecting
NEAL 2AX
51030920800
Water / Gas Inject
Injecting
NEAL4
51030565500
Water / Gas Inject
Injecting
NEAL 5A
51030565900
Oil well
Producing
NEAL 6X
51030790600
Oil well
Producing
NEAL 7X
51030804200
Water / Gas Inject
Injecting
NEAL 8X
51030804300
Water / Gas Inject
P&A
NEAL 8XST
51030804301
Water / Gas Inject
Injecting
NEAL 9Y
51030912000
Oil well
Producing
NEWTON ASSOC UNIT D2X
51030868500
Oil well
Monitor
58
-------
NIKKEL 3
51030619200
Water / Gas Inject
Injecting
PURDY 1-1
51030545300
Water / Gas Inject
Monitor
PURDY 2X1
51030881000
Oil well
Producing
RAVEN A1AX
51030917800
Water / Gas Inject
Injecting
RAVEN A2
51030625700
Water / Gas Inject
Injecting
RAVEN A3
51030624400
Water / Gas Inject
Injecting
RAVEN A4
51030625800
Water / Gas Inject
Injecting
RAVEN A5X
51030718800
Oil well
Producing
RAVEN B1
51030564900
Oil well
Producing
RAVEN B2AX
51030923800
Water / Gas Inject
Monitor
RECTOR 1
51030549400
Oil well
Producing
RECTOR 11X
51030867200
Oil well
Shut In
RECTOR 12X
51030919900
Oil well
Shut In
RECTOR 3
51030106000
Water / Gas Inject
Injecting
RECTOR 8X
51030704300
Oil well
Producing
RECTOR 9X
51030714700
Oil well
Shut In
RIGBY 1
51030569700
Oil well
Producing
RIGBY 5X
51030804700
Water / Gas Inject
Injecting
RIGBY 6Y
51030910700
Oil well
Producing
RIGBY A2AX
51030920000
Water / Gas Inject
Injecting
RIGBY A3X
51030791000
Oil well
Producing
RIGBY A4X
51030791100
Oil well
Monitor
RIGBY A7Y
51030915100
Oil well
Monitor
ROOTH DF 1
51030579700
Water / Gas Inject
Injecting
ROOTH DF 5 X
51031143000
Oil well
Producing
ROOTH DF 6 X
51031125000
Oil well
Producing
S B LACY 3
51030568900
Oil well
Monitor
STOFFER CR A1
51030562700
Water / Gas Inject
Injecting
STOFFER CR A2
51030559200
Water / Gas Inject
Injecting
STOFFER CR B1
51030567300
Oil well
Producing
SW MCLAUGHLIN 10X
51030754700
Oil well
Producing
SW MCLAUGHLIN 9X
51030753500
Oil well
Producing
U P 4829
51030623100
Water / Gas Inject
P&A
UNION PACIFIC 1 150X 16
51031150200
Oil well
Producing
UNION PACIFIC 1 151X 16
51031150100
Oil well
Producing
UNION PACIFIC 1 153X 16
51031146401
Water / Gas Inject
Injecting
UNION PACIFIC 100X20
51030788600
Oil well
Producing
UNION PACIFIC 101X20
51030797300
Oil well
Monitor
UNION PACIFIC 10-21
51030568501
Oil well
Monitor
UNION PACIFIC 102X20
51030797700
Water / Gas Inject
Injecting
UNION PACIFIC 103X20
51030799000
Water / Gas Inject
Injecting
59
-------
UNION PACIFIC 104X20
51030803000
Water / Gas Inject
Injecting
UNION PACIFIC 105X29
51030794500
Oil well
Producing
UNION PACIFIC 106X32
51030845000
Oil well
Producing
UNION PACIFIC 107X32
51030849800
Oil well
Producing
UNION PACIFIC 108X21
51030849500
Water / Gas Inject
Injecting
UNION PACIFIC 109X32
51030849700
Oil well
Producing
UNION PACIFIC 110X21
51030853000
Water / Gas Inject
Injecting
UNION PACIFIC 111X29
51030852200
Oil well
Producing
UNION PACIFIC 11-21
51030616200
Oil well
Producing
UNION PACIFIC 112X21
51030873500
Oil well
Monitor
UNION PACIFIC 113X22
51030860600
Oil well
Monitor
UNION PACIFIC 115X21
51030866600
Oil well
Producing
UNION PACIFIC 117X22
51030866700
Oil well
Producing
UNION PACIFIC 118X21
51030869700
Oil well
Producing
UNION PACIFIC 119X21
51030869800
Oil well
Producing
UNION PACIFIC 120X21
51030869900
Oil well
Producing
UNION PACIFIC 12-27
51030620400
Oil well
Producing
UNION PACIFIC 122X21
51030870000
Oil well
Monitor
UNION PACIFIC 126X32
51030885100
Oil well
Producing
UNION PACIFIC 127X31
51030884700
Oil well
Producing
UNION PACIFIC 128X31
51030910000
Oil well
Producing
UNION PACIFIC 129X31
51030885200
Oil well
Producing
UNION PACIFIC 130X32
51030885300
Oil well
Producing
UNION PACIFIC 131X32
51030885500
Oil well
Producing
UNION PACIFIC 1-32
51030556700
Water / Gas Inject
Injecting
UNION PACIFIC 13-28
51030622000
Water / Gas Inject
Injecting
UNION PACIFIC 132X21
51030874600
Oil well
Monitor
UNION PACIFIC 133X21
51030876400
Oil well
Producing
UNION PACIFIC 134X21
51030904100
Water / Gas Inject
Injecting
UNION PACIFIC 135Y28
51030910500
Oil well
Monitor
UNION PACIFIC 136X20
51030913800
Oil well
Producing
UNION PACIFIC 137X20
51030913900
Water / Gas Inject
Monitor
UNION PACIFIC 138Y28
51030917300
Oil well
Producing
UNION PACIFIC 139Y28
51030918500
Oil well
Monitor
UNION PACIFIC 140Y27
51030918800
Oil well
Producing
UNION PACIFIC 141Y28
51030918900
Oil well
Producing
UNION PACIFIC 14-20
51030615400
Oil well
Producing
UNION PACIFIC 142Y28
51030919000
Oil well
Monitor
UNION PACIFIC 143Y28
51030918600
Oil well
Monitor
UNION PACIFIC 15-28
51030102900
Oil well
Monitor
UNION PACIFIC 154Y29
51031172000
Oil well
Producing
60
-------
UNION PACIFIC 156Y29
51031172100
Oil well
Producing
UNION PACIFIC 16-27
51030620600
Oil well
Shut In
UNION PACIFIC 17-27
51030621400
Oil well
Producing
UNION PACIFIC 18-21
51030616400
Oil well
Producing
UNION PACIFIC 19-28
51030621900
Water / Gas Inject
Injecting
UNION PACIFIC 20-29
51030622800
Water / Gas Inject
Injecting
UNION PACIFIC 21-32
51030627100
Water / Gas Inject
Monitor
UNION PACIFIC 2-20
51030569200
Oil well
Producing
UNION PACIFIC 22-32
51030627500
Oil well
Producing
UNION PACIFIC 23-32
51030626900
Oil well
Producing
UNION PACIFIC 24-27
51030621200
Water / Gas Inject
Injecting
UNION PACIFIC 25-34
51030106900
Oil well
Shut In
UNION PACIFIC 26-31
51030626100
Water / Gas Inject
Injecting
UNION PACIFIC 27-20
51030577000
Oil well
Monitor
UNION PACIFIC 28-22
51030617300
Oil well
Producing
UNION PACIFIC 29-32
51030548700
Oil well
Monitor
UNION PACIFIC 31-21
51030616600
Oil well
Monitor
UNION PACIFIC 32-27
51030620800
Oil well
Monitor
UNION PACIFIC 33-32
51030626600
Water / Gas Inject
Injecting
UNION PACIFIC 3-34
51030551000
Oil well
Producing
UNION PACIFIC 34-31
51030626300
Water / Gas Inject
Injecting
UNION PACIFIC 35-32
51030626800
Water / Gas Inject
Injecting
UNION PACIFIC 36-32
51030627200
Water / Gas Inject
Injecting
UNION PACIFIC 37AX29
51030917700
Water / Gas Inject
Injecting
UNION PACIFIC 39-17
51030612100
Water / Gas Inject
Injecting
UNION PACIFIC 41-20
51030615800
Water / Gas Inject
Shut In
UNION PACIFIC 4-29
51030563200
Water / Gas Inject
Injecting
UNION PACIFIC 42AX28
51030925700
Water / Gas Inject
Injecting
UNION PACIFIC 43-28
51030622100
Water / Gas Inject
Monitor
UNION PACIFIC 44AX20
51030923300
Water / Gas Inject
Injecting
UNION PACIFIC 45-21
51030569600
Water / Gas Inject
Injecting
UNION PACIFIC 47-21
51030615900
Water / Gas Inject
Injecting
UNION PACIFIC 48-29ST
51030623101
Water / Gas Inject
Injecting
UNION PACIFIC 49-27
51030621300
Oil well
Producing
UNION PACIFIC 50-29
51030107100
Water / Gas Inject
Injecting
UNION PACIFIC 51AX20
51030892800
Water / Gas Inject
Injecting
UNION PACIFIC 5-28
51030563900
Oil well
Producing
UNION PACIFIC 52A-29
51030928400
Water / Gas Inject
Injecting
UNION PACIFIC 53-32
51030627600
Water / Gas Inject
Monitor
UNION PACIFIC 54-21
51030616300
Water / Gas Inject
Injecting
UNION PACIFIC 55-17
51030612200
Water / Gas Inject
Injecting
61
-------
UNION PACIFIC 56-21
51030616700
Water / Gas Inject
Injecting
UNION PACIFIC 58-27
51030620500
Water / Gas Inject
Injecting
UNION PACIFIC 59A-27
51031120700
Oil well
Producing
UNION PACIFIC 60-31
51030626200
Water / Gas Inject
Injecting
UNION PACIFIC 61-20
51030615500
Water / Gas Inject
Injecting
UNION PACIFIC 6-21
51030574100
Oil well
Producing
UNION PACIFIC 62AX32
51030919600
Water / Gas Inject
Injecting
UNION PACIFIC 65-5
51030608900
Water / Gas Inject
Monitor
UNION PACIFIC 67-32
51030626700
Water / Gas Inject
Injecting
UNION PACIFIC 68-32
51030628700
Water / Gas Inject
Injecting
UNION PACIFIC 69-27
51030621000
Oil well
Shut In
UNION PACIFIC 71X31
51030727600
Oil well
Producing
UNION PACIFIC 7-29
51030559700
Water / Gas Inject
Injecting
UNION PACIFIC 73X29
51030738600
Oil well
Producing
UNION PACIFIC 74X27
51030741600
Oil well
Monitor
UNION PACIFIC 75X32
51030740200
Oil well
Producing
UNION PACIFIC 76X21
51030742100
Oil well
Producing
UNION PACIFIC 77X32
51030745400
Oil well
Producing
UNION PACIFIC 78X21
51030742600
Water / Gas Inject
Injecting
UNION PACIFIC 79X32
51030744800
Oil well
Monitor
UNION PACIFIC 80X28
51030746000
Water / Gas Inject
Monitor
UNION PACIFIC 81X29
51030749900
Oil well
Producing
UNION PACIFIC 8-20
51030568600
Oil well
Producing
UNION PACIFIC 82X28
51030749400
Oil well
Producing
UNION PACIFIC 83X28
51030750000
Oil well
Producing
UNION PACIFIC 84X28
51030749500
Oil well
Producing
UNION PACIFIC 85X34
51030748100
Water / Gas Inject
Injecting
UNION PACIFIC 86X27
51030748200
Water / Gas Inject
Injecting
UNION PACIFIC 87X29
51030750900
Oil well
Producing
UNION PACIFIC 88X21
51030751400
Oil well
Producing
UNION PACIFIC 89X34
51030754800
Water / Gas Inject
Injecting
UNION PACIFIC 91X28
51030756000
Water / Gas Inject
Injecting
UNION PACIFIC 9-29
51030565600
Water / Gas Inject
Injecting
UNION PACIFIC 92X28
51030757400
Water / Gas Inject
Monitor
UNION PACIFIC 94X27
51030758800
Water / Gas Inject
Injecting
UNION PACIFIC 96X29
51030765000
Oil well
Producing
UNION PACIFIC 97X29
51030765100
Oil well
Producing
UNION PACIFIC 98X32
51030765200
Oil well
Producing
UNION PACIFIC 99X29
51030785600
Oil well
Producing
UNION PACIFIC B1-34
51030548900
Water / Gas Inject
Monitor
UNION PACIFIC B2-34
51030102700
Oil well
Monitor
62
-------
UNION PACIFIC B3X34
51030744000
Oil well
Producing
UNION PACIFIC B4X34
51030753600
Water / Gas Inject
Injecting
UNION PACIFIC B5X34
51030759900
Water / Gas Inject
Injecting
UNION PACIFIC B6X34
51030760200
Water / Gas Inject
Monitor
WALBRIDGE LB 1
51030607000
Water / Gas Inject
Monitor
WALBRIDGE UNIT 1
51030607200
Water / Gas Inject
Monitor
WALBRIDGE UNIT 2X
51030920500
Oil well
Producing
WALBRIDGE UNIT 3X
51030920600
Oil well
Monitor
WEYRAUCH 2-36
51030630600
Water / Gas Inject
Injecting
WEYRAUCH 4X36
51030707200
Oil well
Producing
WEYRAUCH 5X36
51030881900
Oil well
Producing
WEYRAUCH 6X36
51030916600
Oil well
Producing
WEYRAUCH 7X36
51030916300
Oil well
Producing
AC MCLAUGHLIN 39
51030582400
P&A
P&A
AC MCLAUGHLIN 3
51030578600
P&A
P&A
MCLAUGHLIN AC 40
51030632000
P&A
P&A
AC MCLAUGHLIN 41
51030575900
P&A
P&A
AC MCLAUGHLIN 48X
51030580300
P&A
P&A
AC MCLAUGHLIN 59X
51030769100
P&A
P&A
MCLAUGHLIN AC 81X
51031053000
P&A
P&A
A.C. MCLAUGHLIN A A2
51030609300
P&A
P&A
AC MCLAUGHLIN B 1
51030611000
P&A
P&A
AC MCLAUGHLIN B 2
51030610500
P&A
P&A
AC MCLAUGHLIN 1
51030612000
P&A
P&A
AC MCLAUGHLIN 1
51030757700
P&A
P&A
ASSOCIATED 4X
51030881200
P&A
P&A
ASSOCIATED B 1
51030601200
P&A
P&A
ASSOCIATED B 2
51030601000
P&A
P&A
ASSOCIATED B 3
51030601300
P&A
P&A
BEEZLEY 1 22
51030573900
P&A
P&A
CT CARNEY 12-5
51030107000
P&A
P&A
C T CARNEY 26X35
51030745000
P&A
P&A
CARNEY CT 31X4
51030760400
P&A
P&A
CARNEY C T 34X-4
51030760000
P&A
P&A
CARNEY CT 36X34
51030759500
P&A
P&A
CARNEY CT 40X35
51030911700
P&A
P&A
CARNEY CT 42Y34
51030915400
P&A
P&A
CHASE UNIT U 1
51030600800
P&A
P&A
HILL.C.E. 1
51030601800
P&A
P&A
HEFLEY C-S 1
51030104100
P&A
P&A
C-S HEFLEY 2
51030607700
P&A
P&A
63
-------
C-S HEFLEY 3
51030607800
P&A
P&A
C R STOFFER A 3
51030562600
P&A
P&A
EMERALD 12
51030566700
P&A
P&A
EMERALD 15
51030565400
P&A
P&A
EMERALD 18
51030104900
P&A
P&A
EMERALD 21
51030546400
P&A
P&A
EMERALD 24
51030563500
P&A
P&A
EMERALD 29
51030565800
P&A
P&A
EMERALD 30
51030563000
P&A
P&A
EMERALD 31
51030623700
P&A
P&A
EMERALD 33
51030623900
P&A
P&A
EMERALD OIL CO. 3M
51030724700
P&A
P&A
EMERALD 43
51030625200
P&A
P&A
EMERALD 44
51030633800
P&A
P&A
EMERALD 45
51030603000
P&A
P&A
EMERALD 49X
51030729600
P&A
P&A
EMERALD 5
51030566600
P&A
P&A
EMERALD 7
51030624100
P&A
P&A
E OLDLAND 4
51030715200
P&A
P&A
FAIRFIELD,KITTIE A 2
51030611400
P&A
P&A
FAIRFIELD,KITTIE A 3
51030611700
P&A
P&A
F V LARSON 116
51036652500
P&A
P&A
FEE 118X
51030843900
P&A
P&A
FEE 119X
51030849400
P&A
P&A
FEE 161X
51031185900
P&A
P&A
FEE 16
51030624600
P&A
P&A
FEE 2
51030558600
P&A
P&A
FEE 46
51030610700
P&A
P&A
FEE 53
51030617400
P&A
P&A
FEE 54
51030618000
P&A
P&A
FEE 57
51030622700
P&A
P&A
FEE 58
51030614300
P&A
P&A
FEE 66
51030610900
P&A
P&A
FEE 67
51030611600
P&A
P&A
FEE 70
51030626000
P&A
P&A
FEE 71
51030610800
P&A
P&A
FEE 77X
51030736000
P&A
P&A
FEDERAL ET AL 2M
51030719700
P&A
P&A
FEDERAL ET AL 5M
51030731700
P&A
P&A
LARSON FVB10
51030629900
P&A
P&A
LARSON FV B13X
51030557900
P&A
P&A
64
-------
LARSON FV B16X
51030702400
P&A
P&A
LARSON FV B1
51030629600
P&A
P&A
LARSON FV 26Y
51030948500
P&A
P&A
LARSON FV B3
51030630500
P&A
P&A
LARSON FV B5
51030630100
P&A
P&A
LARSON FV B6
51030630300
P&A
P&A
LARSON F V B7
51030630001
P&A
P&A
LARSON FV B9
51030102500
P&A
P&A
F V LARSON 1
51030539800
P&A
P&A
GENTRY 2D
51030543700
P&A
P&A
GENTRY 3D
51030608500
P&A
P&A
NEWTON 4-D
51030104300
P&A
P&A
GENTRY 4D
51030543700
P&A
P&A
GENTRY 5D
51030608300
P&A
P&A
GENTRY 6X
51030744200
P&A
P&A
GRAY A 11
51030613800
P&A
P&A
GRAY A 11 AX
51030927500
P&A
P&A
GRAY A 8
51030568100
P&A
P&A
GRAY B 14
51030613000
P&A
P&A
GUIBERSON,S.A. A 2
51030613400
P&A
P&A
HILDENBRANDT 1
51030608100
P&A
P&A
COLTHARP JE 1
51030602400
P&A
P&A
J E COLTHARP 3
51030602500
P&A
P&A
COLTHARP JE 6X
51030714800
P&A
P&A
COLTHARP JE 9X P 9X
51030853500
P&A
P&A
PEPPER,J.E. A 1
51030550200
P&A
P&A
J E PEPPER B 1
51030606300
P&A
P&A
LACY SB 10Y
51030914300
P&A
P&A
S B LACY 2
51030570600
P&A
P&A
F V LARSON 1
51030106500
P&A
P&A
LEVI SON 15
51030618100
P&A
P&A
LEVI SON 16
51030619600
P&A
P&A
LEVI SON 19
51030106300
P&A
P&A
LEVI SON 20
51030618300
P&A
P&A
LEVISON 3
51030621600
P&A
P&A
LEVISON 4
51030560400
P&A
P&A
LEVISON 5
51030621500
P&A
P&A
L N HAGOOD B 1
51030607300
P&A
P&A
L N HAGOOD B 2
51030607100
P&A
P&A
L N HAGOOD B 3
51030607400
P&A
P&A
WALBRIDGE LB 3
51030630800
P&A
P&A
65
-------
WALBRIDGE LB 4X
51030873600
P&A
P&A
WALBRIDGE LB 5Y
51030948300
P&A
P&A
MAGOR 1
51030580800
P&A
P&A
MCLAUGHLIN 3
51030556100
P&A
P&A
MELLEN,W.P. A 3
51030105700
P&A
P&A
HEFLEY ME 1
51030607500
P&A
P&A
HEFLEY ME 3
51030545400
P&A
P&A
HEFLEY ME 4
51030543300
P&A
P&A
M B LARSON C11 X 25
51030717300
P&A
P&A
MB LARSON A 1
51030632900
P&A
P&A
MB LARSON A3
51030576400
P&A
P&A
LARSON MB 1-35
51030555700
P&A
P&A
MB LARSON C 1
51030571900
P&A
P&A
LARSON MB C2-25
51030106400
P&A
P&A
M B LARSON C425
51030618900
P&A
P&A
LARSON MB D136
51030631000
P&A
P&A
LARSON MB D226
51030102600
P&A
P&A
M B LARSON D525
51030618500
P&A
P&A
M B LARSON D625
51030619000
P&A
P&A
M B LARSON D725
51030618400
P&A
P&A
NEAL2
51030566000
P&A
P&A
NEAL3
51030567200
P&A
P&A
NEWTON ASSOC A1
51030107300
P&A
P&A
NEWTON ASSOC B 1
51030101800
P&A
P&A
NEWTON ASSOC C 1
51030102100
P&A
P&A
NEWTON ASSOC D 1
51030102200
P&A
P&A
NIKKEL 1
51030619300
P&A
P&A
NIKKEL 2
51030619100
P&A
P&A
OLDLAND 1
51030102000
P&A
P&A
OLDLAND 2
51030106100
P&A
P&A
OLDLAND 3
51030630400
P&A
P&A
OLDLAND E 5X
51030853600
P&A
P&A
OLDLAND E 6X
51030947600
P&A
P&A
PURDY16
51030606200
P&A
P&A
PURDY 3X1
51030870300
P&A
P&A
RANGELY 2M-33-19B
51030939800
P&A
P&A
RAVEN A 1
51030562900
P&A
P&A
RAVEN B 2
51030624300
P&A
P&A
RECTOR 10X
51030760300
P&A
P&A
RECTOR 2
51030608400
P&A
P&A
RECTOR 4
51030629400
P&A
P&A
66
-------
RECTOR 5
51030629200
P&A
P&A
RECTOR 6
51030608200
P&A
P&A
RECTOR 7
51030105900
P&A
P&A
RIGBY A224
51030570000
P&A
P&A
ROOTH 3
51030564700
P&A
P&A
MCLAUGHLIN SHARPLES 11X 3
51030760500
P&A
P&A
SHARPLES MCLAUGHLIN 132
51030107400
P&A
P&A
SHARPLES MCLAUGHLIN 432
51030627400
P&A
P&A
UNION PACIFIC 121X21
51030870500
P&A
P&A
U P3016
51030578300
P&A
P&A
UNION PACIFIC 37-29
51030623200
P&A
P&A
U P 3822
51030574400
P&A
P&A
U P 4022
51030617800
P&A
P&A
U P 4228
51030621800
P&A
P&A
U P 4420
51030571000
P&A
P&A
UNION PACIFIC 46-21
51030573700
P&A
P&A
U P 5721
51030616500
P&A
P&A
U P 5927
51030620900
P&A
P&A
UNION PACIFIC 62-32
51030626500
P&A
P&A
UNION PACIFIC 63-31
51030623000
P&A
P&A
UNION PACIFIC 63-31
51030626400
P&A
P&A
UNION PACIFIC 63AX31
51030917900
P&A
P&A
U P 6422
51030617200
P&A
P&A
U P6616
51030610600
P&A
P&A
UNION PACIFIC 72X31
51030736400
P&A
P&A
UNION PACIFIC 90X29
51030758200
P&A
P&A
UNION PACIFIC 93X27
51030756100
P&A
P&A
U P 95X 34
51030759600
P&A
P&A
COLTHARP WH A2
51030602000
P&A
P&A
COLTHARP WH A7X
51030869300
P&A
P&A
COLTHARP WH B1
51030101900
P&A
P&A
WEYRAUCH 1-36
51030630700
P&A
P&A
WEYRAUCH 336
51030630900
P&A
P&A
WHITE 1
51030543500
P&A
P&A
WHITE 2
51030545100
P&A
P&A
67
-------
Request for Additional Information: Rangely Gas Plant
October 16, 2023
Instructions: Please enter responses into this table and make corresponding revisions to the MRV Plan as necessary. Any long responses, references, or
supplemental information may be attached to the end of the table as an appendix. This table may be uploaded to the Electronic Greenhouse Gas Reporting
Tool (e-GGRT) in addition to any MRV Plan resubmissions.
No.
MRV Plan
EPA Questions
Responses
Section
Page
1.
N/A
N/A
There is a lack of consistency with hyphens, holding, quotation
marks, spelling, and capitalization throughout the MRV plan.
Examples include but are not limited to:
MMF vs. MFF
Weber Sands vs. Weber sands vs. Weber Formation
TOC vs. TOL
We recommend reviewing the formatting in the MRV plan for
consistency. Furthermore, we recommend doing an additional
review for spelling, grammar, etc.
Page 23) typo, MMF should be MFF
Edit)
"As described in Section 2.2.1, the MFF is present below the
reservoir and terminates within the Weber Sands without breaching
the upper seal."
Add MFF - Main Field Fault to Appendix 2. Acronyms
2.
N/A
N/A
The MRV plan mentions the "Rangely Field C02", "Rangely Field",
and "Rangely Gas Plant".
Please clarify how these three names relate to each other. For
instance, the facility name listed in e-GGRT is "Rangely Gas Plant"
but the title of the MRV plan states "Rangely Field C02". We
recommend reviewing the MRV plan to ensure consistency when
referencing the facility in the MRV plan.
Title of MRV plan has been updated to Rangely Field. The Rangely
Gas Plant is a part of the overall Rangely Field.
3.
N/A
N/A
Please ensure that all acronyms are defined during the first use
within the MRV plan. For example, "BCF", "MMscf", and "WAG" are
not defined during their first use within the text.
Reviewed and revised throughout.
-------
No.
MRV Plan
EPA Questions
Responses
Section
Page
4.
2.2.1
7
"No large fresh water aquifers are present between the reservoir
rock and the surface. Safety measures are still taken to protect the
shallowest of rocks that contain rain water seepage into the Mancos
Formation (surface exposure at Rangely) illustrated by the surface
casing on Figure 4. The shallowest point of the reservoir is 5,486 ft
below the surface (4,986 ft below any possible fresh water)."
This statement suggests that there are no freshwater aquifers
between the surface and the shallowest point of the reservoir
which is 5,486 feet below surface. However, the passage then states
that the shallowest point is only 4,986 feet below fresh water.
Please clarify whether there are fresh water aquifers between the
injection reservoir and the surface.
This is a nomenclature misunderstanding from a geology
perspective. Clarification will add "Confined" Aquifer and
"Unconfined" Aquifer. Similar to the oil reservoir, a confined aquifer
contains a porous rock saturated with groundwater that is below a
non-porous/permeable confining rock (the Weber reservoir is
below the Moenkopi seal and saturated with oil, making it a
confined reservoir). An unconfined aquifer is missing the non-
porous/permeable rock, allowing groundwater to reach the surface.
The top few feet from surface are considered an unconfined
aquifer. Rain water will seep into the soil and ground as it makes its
way to a river, this occurs everywhere that gets rain. This interval is
protected by the 500 ft surface casing and is the depth referred to
by the 4,986 ft above the Rangely field.
Sentence Edit)
"No confined fresh water aquifers are present between the
reservoir rock and the surface. Safety measures are still taken to
protect the shallowest of rocks that contain rain water seepage
(unconfined aquifer) into the Mancos Formation (surface exposure
at Rangely) illustrated by the surface casing on Figure 4. The
shallowest point of the reservoir is 5,486 ft below the surface (4,986
ft below any possible fresh rain water seepage)."
-------
No.
MRV Plan
EPA Questions
Responses
Section
Page
5.
2.2.1
9
The MRV plan states:
'This study determined that the waterflood in Rangely was inducing
seismicity when reservoir pressure was raised above ~3730 psi."
and "Investigation into this region revealed that the ~3750 psi
threshold had been crossed and triggered the seismic events."
Please review the MRV plan to ensure that pressure values are
consistent throughout.
Use 3730 psi. Since the pressure is an approximation the 3750 was a
rounded "clean" number.
"Investigation into this region revealed that the ~3730 psi threshold
had been crossed and triggered the seismic events."
Correct in section 4.4 as well
6.
2.2.2
12
"Operational History of the Rangely Field and Rangely Field"
Please consider revising the above section heading.
Revised heading.
"Operational History of the Rangely Field"
7.
2.3
13
"Purchased CO2 and recycled CO2 from the RCF is sent through..."
The above text mentions the RCF, but the RCF is not found in the
process flow diagram in Figure 10. Please label and clearly show the
RCF in Figure 10.
Updated Figure 10 to highlight that ist/2nd Stage Compression and
also 3rd/4th Stage compression is the RCF.
8.
2.3.1
14
"Approximately 160 MMscf of CO2 is injected each day..."
Throughout the MRV plan, injection volumes are described in terms
of MMSCF vs. BCF and MMT vs. MMMT. Please ensure that units
are used consistently within the MRV plan with regards to injection
volumes.
Eliminated BCF and converted to MMscf
Eliminated MMT and converted to MMMT
-------
No.
MRV Plan
EPA Questions
Responses
Section
Page
9.
2.3.4
18
"Once gas enters the CO2 reinjection facility, it undergoes
dehydration and compression. In the RWSU an additional process
separates NGLs for sale. At the end of these processes there is a CO2
rich stream that is recycled through re-injection. Meters at the
facility outlet are used to determine the total volume of the CO2
stream recycled back into the EOR operations."
Please clarify whether "Meters at the facility outlet" refers to the
CO2 recycling and compression facility - not the Rangely Field
facility.
"Once gas enters the CO2 reinjection facility, it undergoes
dehydration and compression. In the RWSU an additional process
separates NGLs for sale. At the end of these processes there is a CO2
rich stream that is recycled through re-injection. Meters at the C02
recycling and compression facility outlet are used to determine the
total volume of the CO2 stream recycled back into the EOR
operations."
Also reworded previous paragraph to align with C02 recycling and
compression wording
10.
3.1
19-20
Per 40 CFR 98.449, active monitoring area is defined as the area
that will be monitored over a specific time interval from the first
year of the period (n) to the last year in the period (t). The
boundary of the active monitoring area is established by
superimposing two areas:
(1) The area projected to contain the free phase C02 plume at
the end of year t, plus an all around buffer zone of one-half mile
or greater if known leakage pathways extend laterally more than
one- half mile.
(2) The area projected to contain the free phase CO2 plume at
the end of year t + 5.
Please specify whether the AMA includes the Zi mile buffer as
described in criterion (1)?
"Because C02 is present throughout the Rangely Field and retained
within it, the Active Monitoring Area (AMA) is defined by the
boundary of the Rangely Field plus one-half mile buffer."
-------
11.
4.3
23
Section 4.3 of the MRV plan states:
"Additional large faults have been identified in formations that are
thousands of feet bellow the Weber Sands, but this faulting has
been shown not to affect the Weber Sands or to have created
potential leakage pathways."
However, Section 2.2.1 of the MRV plan states:
"The Rangely Field has one main field fault ("MFF") and numerous
smaller faults and fractures that are present throughout the
stiratiigiraphlie column between the base of the reservoir and
surface."
Please clarify the relationship between these two statements and
ensure that the classification of faults, fractures, and leakage
through faults and fractures is consistent throughout the MRV
plan.
The non-MFF faults discussed in these two sections are two
different fault groups. The large faults referred to in section 4.3 are
below the Weber reservoir and observed via 3D seismic. This
seismic survey is unable to detect small to medium size faults with
minimal displacement. The presence of these smaller faults is likely,
but without evidence, no conclusion can be made. Finally, the lower
faults do not extend into the Upper Pennsylvanian or Permian
strata, meaning there is no possible interference with Rangely
operations.
The faults referred to in section 2.2.1 were determined from well
logs within the field while the fractures were measured on the
surface. It is difficult to distinguish between a fault and a fracture
within the reservoir. Rapid well-to-well break through is used to
determine fault vs fracture.
A fault is a fracture with displacement, while a fracture is just a
crack in the host rock.
Edits)
"Additional faults have been identified in formations that are
stratigraphically below the Weber Sands, but this faulting has been
shown not to affect the Weber Sands or to have created potential
leakage pathways given that they do not contact the Upper
Pennsylvanian or Permian strata (Weber Fm.),"
"The Rangely Field has one main field fault (MFF) and numerous
smaller faults (isolated and joint) and fractures that are present
throughout the stratigraphic column between the base of the
Weber reservoir and surface. Faults within the reservoir were
measured by well-to-well displacement, while the fractures were
measured and observed as calcite veins on the surface with no
displacement."
12.
5.1.5
29
"Anomalies in injection zone pressure may not indicate a leak, as
discussed above. However, if an investigation leads to a work
order, field personnel would inspect the equipment in question
Updated several sections to clarify that any C02 quantities from
leaks and emissions would be reported in Subpart RR.
-------
No.
MRV Plan
EPA Questions
Responses
Section
Page
and determine the nature of the problem. If it is a simple matter,
the repair would be made and the volume of leaked CO2 would be
included in the 40 CFR Part 98 Subpart W report for the Rangely
Field. If more extensive repair were needed, SEM would determine
the appropriate approach for quantifying leaked CO2 using the
relevant parameters (e.g., the rate, concentration, and duration of
leakage). The work order would serve as the basis for tracking the
event for GHG reporting."
Although CO2 leaks from surface equipment within the boundaries
of the Subpart W facility are reported under Subpart W, you must
also separately report to Subpart RR quantities of leaks and
emissions from surface equipment between the injection flow
meter used to measure injection quantities and the injection well.
Leaks and emissions from equipment between the producing well
and the separator flow meter used to measure produced CO2
quantities must also be separately reported to Subpart RR.
Note that CO2 quantities from leaks and emissions reported in
Subpart RR are used to determine the mass balance of CO2
sequestered and do not roll up into total facility emissions as is the
case with emissions reported to Subpart W. Please clarify the MRV
plan language as necessary.
13.
5.1.5
30
"...detected H2S leaks will be investigated to determine potential
CO2 leakage is present..."
Please consider rewording the above text.
Thus, detected H2S leaks will be investigated to determine if
potential C02 leakage is present, but not used to determine the
leak volume.
-------
No.
MRV Plan
EPA Questions
Responses
Section
Page
14.
5.1.6
30
"SEM evaluates and estimates leaks from equipment, the CO2
content of produced oil, and vented CO2, as required under 40 CFR
Part 98 Subpart W."
40 CFR 98.446(f)(3)(i) requires reporting of:
'The mass of CO2 emitted (in metric tons) annually from equipment
leaks and vented emissions of CO2 from equipment located on the
surface between the flow meter used to measure injection quantity
and the injection wellhead."
Entrained CO2 in produced oil is reported separately under 40 CFR
98.446(f)(5). Please revise the MRV plan as necessary to reflect this
distinction.
Please note that this would also apply to Section 5.1.7.
Removed language about the C02 content of produced oil. Updated
paragraph to be clearer.
-------
No.
MRV Plan
EPA Questions
Responses
Section
Page
15.
7
31
'To account for the site conditions and complexity of a large,
active EOR operation, SEM proposes to modify the locations for
obtaining volume data for the equations in Subpart RR §98.443 as
indicated below.
The first modification addresses the propagation of error that
would result if volume data from meters at each injection and
production well were utilized. This issue arises because while
each meter has a small but acceptable margin of error, this error
would become significant if data were taken from the
approximately 284 meters within the Rangely Field. As such, SEM
proposes to use the data from custody and operations meters on
the main system pipelines to determine injection and production
volumes used in the mass balance."
You must calculate geologic sequestration, CO2 injected, CO2
recycled, and CO2 produced according to the methods/equations
prescribed in the regulations at 40 CFR 98.443. Please explain
whether the proposed calculation methodologies follow the
Subpart RR regulations, and/or revise this section of the MRV plan
as necessary. Please also ensure that the locations/flowmeters
you identify for use in the calculations are consistent with the
requirements at 40 CFR 98.443 and 98.444.
Clarified to add that it follows 40 CFR 98.444.
The modification addresses the propagation of error that would
result if volume data from meters at each injection well were
utilized. This issue arises because while each meter has a small but
acceptable margin of error, this error would become significant if
data were taken from the approximately 284 meters within the
Rangely Field. As such, SEM proposes to use the data from custody
and operations meters on the main system pipelines to determine
injection volumes used in the mass balance. This satisfies the
requirement in 40 CFR 98.444 (b) 1 that you must select a point or
points of measurement at which the C02 stream is representative
of the C02 streams being injected, since the main line injection
stream is the same stream being injected into the wells.
-------
No.
MRV Plan
EPA Questions
Responses
Section
Page
16.
7.0
31
'The second modification addresses the NGL sales from the
Rangely Field. As indicated in Figure 10, NGL is separated from the
fluid mix at the Rangely Field after it has been measured at the
RCF inlet and before measurement at the RCF outlet. As a result
the amount of CO2 recycled already accounts for the amount
entrained in NGL and therefore is not factored separately into the
mass balance calculation."
Although the CO2 in the NGL stream would be included in the
quantity of CO2 measured downstream of the separator, any CO2
entrained in NGLs sold or transferred offsite must still be reported
as required by 40 CFR 98.446(f)(5) because entrained CO2 in NGLs
transferred offsite will not be measured at the outlet of the RCF
according to Figure 10. Please clarify or revise the MRV plan as
necessary.
Deleted paragraph. Will calculate C02 entrained in NGLs into
equation RR-9 per 40 CFR 98.446(f)(5)
17.
7.3
33
"C02,u = Annual CO2 mass recycled (metric tons) as measured by
flow meter u."
In Equation RR-5, this variable is "CC>2,u = Annual CO2 mass injected
(metric tons) through flow meter". Equations and variables cannot
be modified from the regulations. Please revise this section and
ensure that all equations listed are consistent with the text in 40
CFR 98.443 (httDs://www.ecfr.gov/current/title-40/chaDter-
l/subchapter-C/part-98/subpart-RR#98.443).
Fixed to state injected.
-------
No.
MRV Plan
EPA Questions
Responses
Section
Page
18.
7.4
34
"Further, SEM will reconcile the Subpart W report and results
from any event-driven quantification to assure that surface leaks
are not double counted."
Emissions reported to Subpart RR that are also reported under
Subpart W do not present a double counting of emissions.
Emissions reported to Subpart RR are used only as inputs to the
Subpart RR mass balance equation, and do not roll up into total
facility emissions if the facility reports to other emission subparts,
such as Subpart W. Please revise the MRV plan as necessary to
reflect this.
Sentence Deleted
-------
Scout Energy Management, LLC
Rangely Field C02
Subpart RR Monitoring, Reporting and Verification (MRV) Plan
September 2023
-------
Table of Contents
Roadmap to the Monitoring, Reporting and Verification (MRV) Plan 3
1. Facility Information 4
2. Project Description 4
2.1 Project Characteristics 4
2.2 Environmental Setting 6
2.3 Description of C02 EOR Project Facilities and the Injection Process 13
3. Delineation of Monitoring Area and Timeframes 19
3.1 Active Monitoring Area 19
3.2 Maximum Monitoring Area 20
3.3 Monitoring Timeframes 20
4. Evaluation of Potential Pathways for Leakage to the Surface 20
4.1 Introduction 21
4.2 Existing Wellbores 21
4.3 Faults and Fractures 23
4.4 Natural or Induced Seismicity 23
4.5 Previous Operations 23
4.6 Pipeline / Surface Equipment 23
4.7 Lateral Migration Outside the Rangely Field 24
4.8 Drilling Through the C02 Area 24
4.9 Diffuse Leakage through the Seal 25
4.10 Monitoring, Response, and Reporting Plan forC02 Loss 25
4.11 Summary 26
5. Monitoring and Considerations for Calculating Site Specific Variables 26
5.1 For the Mass Balance Equation 26
5.2 To Demonstrate that Injected C02 is not Expected to Migrate to the Surface 30
6. Determination of Baselines 30
7. Determination of Sequestration Volumes Using Mass Balance Equations 31
7.1. Mass of C02 Received 32
7.2 Mass of C02 Injected into the Subsurface 33
7.3 Mass of C02 Produced 33
7.4 Mass of C02 emitted by Surface Leakage 34
7.5 Mass of C02 sequestered in subsurface geologic formations 35
7.6 Cumulative mass of C02 reported as sequestered in subsurface geologic formations.. 35
8. MRV Plan Implementation Schedule 35
9. Quality Assurance Program 36
9.1 Monitoring QA/QC 36
9.2 Missing Data Procedures 36
9.3 MRV Plan Revisions 37
10. Records Retention 37
11. Appendices 37
Appendix 5. Well Identification Numbers 43
2
-------
Roadmap to the Monitoring, Reporting and Verification (MRV) Plan
Scout Energy Management, LLC ("SEM") operates the Rangely Weber Sand Unit ("RWSU") and the
associated Raven Ridge pipeline ("RRPC"), (collectively referred to as the Rangely Field) in Northwest
Colorado for the primary purpose of enhanced oil recovery (EOR) using carbon dioxide ("C02") flooding.
SEM has utilized, and intends to continue to utilize, injected C02 with a subsidiary purpose of establishing
long-term containment of a measurable quantity of C02 in subsurface geological formations at the Rangely
Field for a term referred to as the "Specified Period." The Specified Period includes all or some portion of
the period 2023 to 2060. During the Specified Period, SEM will inject C02 that is purchased (fresh C02)
from ExxonMobil's ("XOM") Shute Creek Plant or third parties, as well as C02 that is recovered (recycled
C02) from the Rangely Field's C02 Recycle and Compression Facilities ("RCF's"). SEM has developed
this monitoring, reporting, and verification (MRV) plan in accordance with 40 CFR §98.440-449 (Subpart
RR) to provide for the monitoring, reporting and verification of the quantity of C02 sequestered at the
Rangely Field during the Specified Period.
SEM has chosen to submit this MRV plan to the EPA for approval according to 40 Code of Federal
Regulations (CFR) 98.440(c)(1), Subpart RR of the Greenhouse Gas Reporting Program for the purpose
of qualifying for the tax credit in section 45Q of the federal Internal Revenue Code.
This MRV plan contains eleven sections:
o Section 1 contains general facility information.
o Section 2 presents the project description. This section describes the planned injection volumes, the
environmental setting of the Rangely Field, the injection process, and reservoir modeling. It also illustrates
that the Rangely Field is well suited for secure storage of injected C02.
o Section 3 describes the monitoring area: the RWSU in Colorado.
o Section 4 presents the evaluation of potential pathways for C02 leakage to the surface. The assessment
finds that the potential for leakage through pathways other than the man-made wellbores and surface
equipment is minimal.
o Section 5 describes SEM's risk-based monitoring process. The monitoring process utilizes SEM's reservoir
management system to identify potential C02 leakage indicators in the subsurface. The monitoring process
also utilizes visual inspection of surface facilities and personal H2S monitors program as applied to
Rangely Field. SEM's MRV efforts will be primarily directed towards managing potential leaks through
wellbores and surface facilities.
o Section 6 describes the baselines against which monitoring results will be compared to assess whether
changes indicate potential leaks.
o Section 7 describes SEM's approach to determining the volume of C02 sequestered using the mass
balance equations in 40 CFR §98.440-449, Subpart RR of the Environmental Protection Agency's (EPA)
Greenhouse Gas Reporting Program (GHGRP). This section also describes the site-specific factors
considered in this approach.
o Section 8 presents the schedule for implementing the MRV plan.
o Section 9 describes the quality assurance program to ensure data integrity.
o Section 10 describes SEM's record retention program.
o Section 11 includes several Appendices.
3
-------
1. Facility Information
The Rangely Gas Plant, operated by SEM, reports under Greenhouse Gas Reporting Program Identification
number 537787.
The Colorado Oil and Gas Conservation Commission ("COGCC")1 regulates all oil, gas and geothermal
activity in Colorado. All wells in the Rangely Field (including production, injection and monitoring wells) are
permitted by COGCC through Code of Colorado Regulations ("CCR") 2 CCR 404-1:301. Additionally,
COGCC has primacy to implement the Underground Injection Control ("UIC") Class II program in the state
for injection wells. All injection wells in the Rangely Field are currently classified as UIC Class II wells.
Wells in the Rangely Field are identified by name, API number, status, and type. The list of wells as of April,
2023 is included in Appendix 5. Any new wells will be indicated in the annual report.
2. Project Description
This section describes the planned injection volumes, environmental setting of the Rangely Field, injection
process, and reservoir modeling conducted.
2.1 Project Characteristics
SEM utilized historic production and injection of the RWSU in order to create a production and injection
forecast, included here to provide an overview of the total amounts of C02 anticipated to be injected,
produced, and stored in the Rangely Field as a result of its current and planned C02 EOR operations during
the forecasted period. This forecast is based on historic and predicted data. Figure 1 shows the actual
(historic) C02 injection, production, and stored volumes in the Rangely Field from 1986, when Chevron
initiated C02 flooding, through 2022 (solid line) and the forecast for 2023 through 2060 (dotted line). It is
important to note that this is just a forecast; actual storage data will be collected, assessed, and reported as
indicated in Sections 5, 6, and 7 in this MRV Plan. The forecast does illustrate, however, the large potential
storage capacity at Rangely field.
1 Pursuant to Colorado SB21-285, effective July 1, 2023, the COGCC will become the Energy and Carbon
Management Commission.
4
-------
Rangely Field
Historical and Projected C02
6000
~o
c
5000
T3
C
(D
(D
<1J
>
CT>CT>OO*H*H*H(N(Nr0r0r0^-^-L/lL/lL/l
aiaiaiaiooooooooooooooo
*H*H*H*H(N(N(N(N(N(N(N(N(N(N(N(N(N(N(N
Year
Figure 1 - Rangely Field Historic and Forecast C02 Injection, Production, and Storage 1986-2060
The amount of C02 injected at Rangely Field is adjusted periodically to maintain reservoir pressure and to
increase recovery of oil by extending or expanding the EOR project. The amount of C02 injected is the
amount needed to balance the fluids removed from the reservoir and to increase oil recovery. While the
model output shows C02 injection and storage through 2060, this data is for planning purposes only and
may not necessarily represent the actual operational life of the Rangely Field EOR project. As of the end
of 2022, 2,320 BCF (122.76 million metric tons (MMMT)) of C02 has been injected into Rangely Field. Of
that amount, 1,540 BCF (81.48 MMMT) was produced and recycled.
While tons of C02 injected and stored will be calculated using the mass balance equations described in
Section 7, the forecast described above reflects that the total amount of C02 injected and stored over the
modeled injection period to be 967 BCF (51.2 MMMT). This represents approximately 35.7% of the
theoretical storage capacity of Rangely Field.
Figure 2 presents the cumulative annual forecasted volume of C02 stored by year through 2060, the
modeling period forthe projection in Figure 1. The cumulative amount stored is equal to the sum of the annual
storage volume for each year plus the sum of the total of the annual storage volume for each previous year.
As is typical with C02 EOR operations, the rate of accumulation of stored C02 tapers overtime as more
recycled C02 is used for injection. Figure 2 illustrates the total cumulative storage overthe modeling period,
projected to be 967 BCF (51.2 MMMT) of C02.
5
-------
TS
0)
i_
o
+-»
to
(N
o
u
Rangely Field
Historical and Forecast Cumulative C02 Storage
60000
~o
c
50000
(0
-------
Figure 3 - Regional map showing Rangely's position between the Uinta and Piceance Basin.
The reservoir, Weber Sands, is comprised of clean eolian quartz deposited in an erg (sand sea)
depositional environment. Internally, these dune sands are separated into six main packages (odd
numbers, 1 to 11) with the fluvial Maroon Formation (even numbers, 2 to 10) interfingering the field from
the north. The Weber Formation is underlain by the fossiliferous Desmoinesian carbonates of the Morgan
Formation, and overlain by the siltstones and shales of the Phosphoria/Park City and Moenkopi
Formations.
Forthe majority of the region, the Phosphoria Formation acts as an impermeable barrier above the
Weber Formation and is a hydrocarbon source forthe overlying strata. However, due to the large thrust
fault south and west of the field, the Phosphoria Formation was driven down to significantly deeper
depths, and below the reservoir Weber sands, allowing for maturation and expulsion of the hydrocarbons
to migrate upward into stratigraphically older, but structurally shallower reservoirs sometime during the
Jurassic. At Rangely, the Phosphoria Formation is almost entirely missing above the Weber Formation,
but the Moenkopi Formation sits directly above the sands creating the seal forthe petroleum system.
Fresh water in and around the town/field of Rangely is sourced from the quaternary creeks and rivers that
cut across the region (data obtained from the Colorado Division of Water Resources). No large fresh
water aquifers are present between the reservoir rock and the surface. Safety measures are still taken to
protect the shallowest of rocks that contain rain water seepage into the Mancos Formation (surface
exposure at Rangely) illustrated by the surface casing on Figure 4. The shallowest point of the reservoir is
5,486 ft below the surface (4,986 ft below any possible fresh water). The mere presence of hydrocarbons
and the successful implication of a C02 flood indicates the quality and effectiveness of the seal to isolate
this reservoir from higher strata.
7
-------
Uinta Basin
Douglas Creek
Arch
Piceance Basin
ichesne River and Uinta Fms
CoKon Fm
Wasatch Fr
Wasatch and
Fort Union Fms
k I r_.
rm
Blackhawk Fm
Ferron Ss Mbr of Ma cos Sh and Frontu
Dakota Ss
Sue hem Cgl Mbr
Salt Wash Ss O O
Morrison Fm
O Entrada Ss O
Glen Canyon Ss
Cftnle Fm
Moenkep. Fm
Source
__ParY. City Fm
upper Weber Ss
Reservoir
Maroon
cr_ Fm
Round Valley Ls
Manning Canyon Sh
Doughnut Sh/Humbug Fm
Deseret Ls
Leadville Ls
Madison Ls
Pinyon.
-TfeniWU rf"
Dotsero Fm
Lodore Fm
Sawatch Ss
KEY
PETROLEUM
SYSTEMS:
I| Green River
system
I| Mesaverde
system
l| Mancos/Mowry
system
I| Phosphoria
system SOUTCe
Grassy Trail
° Creek oil
~ Mtnturn system
,, SignFficant oil production
{indicating source rock)
v./ Significant gas production
^ (indicating source rock)
S Source rocks
(R) Rangely Field
Main reservoir
I I Hiatus
Stratigraphy
at Rangely
Figure 4. Stratigraphic Column of formations at the Rangely Field. Due to a large fault the source
rock (Phosphoria) is stratigraphically above the reservoir rock (Weber), but structurally, the
source lies below the reservoir, (from U.S. Geological Survey, 2003)
Figure 5 shows the doubly plunging anticline with the long axis along a northwest-southeast trend and the
short axis along a northeast-southwest trend. In 1949 the depth of a gas cap was established at -330 ft
subsea and an Oil Water Contact (OWC) at -1150 ft subsea. Many core analysis suggest that below this -
1150' OWC is a transition/residual oil zone. However, for the purpose of this analysis and all volumetrics
8
-------
the base of the reservoir will be at the -1150' subsea depth determined in 1949.
Geologically, the Weber Sands were deposited on top of the Morgan formation which is a combination of
interbedded shale, siltstone, and cherty limestone. Few wells are drilled deep enough to penetrate the
Morgan formation within the Rangely Field to gather porosity/permeability data locally. However, analysis
of the Morgan formation from other fields/outcrops indicate that it is a non-reservoir rock (low
porosity/permeability), and would be sufficient as a basial barrier for the field. The highest subsurface
elevation of the base of the Weber Sands is deeper than the -1150' used for the OWC. Meaning injected
C02 should not encounter the Morgan formation. Additionally, Section 4.7 explains how the Rangely
Field is confined laterally through the nature of the anticline's structure.
Figure 5. Structure map of the Weber 1 (top of reservoir). Colors illustrate the maximum aerial
coverage of the Gas Cap (Red), Main Reservoir (Green), and Transitional Reservoir (Blue). Cross
section A-A' is predominantly along the long axis of the field and B-B' is along the short axis.
The Rangely Field has one main field fault ("MFF") and numerous smaller faults and fractures that are
present throughout the stratigraphic column between the base of the reservoir and surface. The MFF has
a NE-WSW trend and cuts through the reservoir interval. In the 1960's Rangely residents began
experiencing felt earthquakes. Between 1969 and 1973, a joint investigation with the USGS installed
seismic monitoring stations in and around the town of Rangely and began recording activity. In 1971, a
study was conducted to evaluate the stress state in the vicinity of the fault which determined a critical fluid
pressure above which fault slippage may occur. Reservoir pressure was then manipulated and correlated
with increases or decreases in seismic activity. This study determined that the waterflood in Rangely was
inducing seismicity when reservoir pressure was raised above ~3730 psi.
In the 1990's, field reservoir pressure had built back up leading to the largest magnitude earthquake in
Rangely which took place in 1995 (M 4.5), shortly after maximum reservoir pressure was reached in
1998. Pressure maintenance began and seismic activity dropped off after lowering the average field
9
-------
reservoir pressure down to ~3100 psi. No other seismic activity was recorded around the field until 2015
and 2017 when there was a total of 5 seismic events (see Figure 6) around the northeastern portion of
the MFF. A new interpretation from the 3D seismic revealed a series of previously unknown joint faults
(perpendicular to the MFF). Investigation into this region revealed that the ~3750 psi threshold had been
crossed and triggered the seismic events. Since the 2017 seismic events, no other events have been
recorded of felt magnitude and continued pressure monitoring further reduces the risk of another event.
2017 Induced
Seismic Study*
Figure 6. USGS fault history map (1900-2023). Largest earthquake was the 1995 M 4.5 north of the
unit (2017 was a study to induce seismic activity along the MFF, and not caused by day-to-day
operations)
The natural fractures found within the field play a significant role in fluid flow. The subsurface natural
fractures are vertical and show an approximately ENE trend and their extension joints are orientated ESE.
Shallower portions of the reservoir show a distinctly higher density of fractures than deeper portions. On
the shallow dipping sides of the anticline, there does not appear to be a strong structural control on
fracture density. Most well-to-well rapid breakthrough of injected C02 is along these ENE fractures. It is
unknown if this is from natural or induced fractures. There is no evidence that these natural fractures
diminish the seals integrity.
10
-------
Figure 7. Cross section A-A' along the long axis of the field, and perpendicular to the MRR. The
MFF does not have much displacement and is near vertical.
The Rangely Field has approximately 1.9 billion barrels of Original Oil in Place ("OOIP"). Since first
discovered in 1933, Rangely Field has produced 920 million barrels of oii, or 48% of the OOIP. The
Rangely Field has an aerial extent of approximately 19,150 acres with an average gross thickness of 650
ft. The previously mentioned 11 internal layers of the reservoir, alternating zones of Weber and Maroon
Formations, can be simplified to only three sections. The Upper Weber contains intervals 1-3, the Middle
Weber contains intervals 4-7, and the Lower Weber contains intervals 8-approxamently 50 ft below the
11D marker (identified by the base of the yellow in Figure 7). These interval groupings were determined
by the extensive lateral continuingly and thickness of the Weber 4 and Weber 8 which easily separate the
reservoir into the three zones. For the majority of the Rangely Field, the even Maroon Formations act as
flow barriers between the odd Weber Formations. Average porosity within the Weber Sands dune fades
is 10.3% and within the Maroon fluvial fades is 4.9%. However, the key factor that enables the Maroon
Formation to be a seal is its lack of permeability. The Weber dune fades have an average permeability of
2.44 md, while the Maroon fluvial fades have an average permeability of 0.03 md.
owe -1150'
Transition Zone & ROZ
11
-------
Figure 8. Cross section B-B' along the short axis of the field and parallel to the MFF. Used to
illustrate the variation of the Oil Water Contact ("OWC").
Given that the Rangely Field is located at the highest subsurface elevations of the structure, that the
confining zone has proved competent over both millions of years and throughout decades of EOR
operations, and that the Rangely Field has ample storage capacity, SEM is confident that stored C02 will
be contained securely within the Weber Sands in the Rangely Field.
2.2.2 Operational History of the Rangely Field and Rangely Field
The Rangely Field was discovered in 1933 but subsequently ceased production until World War II when oil
returned to high demand. Intensive development began, expanding from one well to 478 wells by 1949. It
is located in the northwestern portion of Colorado.
The Rangely Field was originally developed by Chevron. Following the initial discover in 1933,
Chevron imitated a 40-acre development in 1944, followed by hydrocarbon gas injection from
1950 to 1969. To improve efficiency, in 1957, the RWSU was formed. The boundaries of the RWSU are
reflected in Figure 9.
2N 102W
' y V V v I I ^ w j* # rwmytsiy rauiiLy
A# A^ C^. A ± Blanco & Rangely Plant Gener
A West End Water Inje
\ *« > /AI Rangely Weber L
*"1
jl A#. ^ # i V A. M# % t A A
w> v y a A y.vv h
-lVAV'* IAV> S »y.W. / .* /.
hK'A&v . W ;.v.* t
CvA*-v, .v y«*.
* v'v>.* g
. i town
Rartgeiy District
7?Mp7fi?T Heiipori'
1N 102W
OXIO BLANCO CQMNTY
Garfield
Rangely Well List
0 Active-Producer
TA-Producer
~ Active-Injector
A TA-Injector
- ~ Active SWD
Collection Station / Facility
| Collection Station
($$ Compressor Station
0 Rangely Facility
(££) Rangely Plant General
A West End Water Injection
Rangely Weber Unit
J Rangely Weber Unit
2N 103W
Melieri Hit
09 ^
RIO BLANC# COUNTY
Blanco
Moffat
Uintah
UT
~ CO
Rio Blanco
Figure 9 - Rangely Field Map
12
-------
Chevron began C02 flooding of the Rangely Field in 1986 and has continued and expanded it since that
time. The experience of operating and refining the Rangely Field C02 floods over the past decade has
created a strong understanding of the reservoir and its capacity to store C02.
2.3 Description of C02 EOR Project Facilities and the Injection Process
Figures 10 shows a simplified flow diagram of the project facilities and equipment in the Rangely Field.
C02 is delivered to the Rangely Field via the Raven Ridge Pipeline. The C02 injected into the Rangely
Field is currently supplied by XOM's Shute Creek Plant into the pipeline system.
Once C02 enters the Rangely Field there are four main processes involved in EOR operations. These
processes are shown in Figure 10 and include:
1. C02 Distribution and Injection. Purchased C02 and recycled C02 from the RCF is sent through the main
C02 distribution system to various C02 injectors throughout the Field.
2. Produced Fluids Handling. Produced fluids gathered from the production wells are sent to collection
stations for separation into a gas/C02 mix and a produced fluids mix of water, oil, gas, and C02. The
produced fluids mix is sent to centralized water plants where oil is separated for sale into a pipeline, water
is recovered for reuse, and the remaining gas/C02 mix is merged with the output from the collection
stations. The combined gas/C02 mix is sent to the RCF and natural gas liquids ("NGL") Plant. Produced
oil is metered and sold; water is forwarded to the water injection plants for treatment and reinjection or
disposal.
3. Produced Gas Processing. The gas/C02 mix separated at the satellite batteries goes to the RCF and
NGL Plant where the NGLs, and C02 streams are separated. The NGLs move to a commercial pipeline for
sale. The remaining C02 (e.g., the recycled C02) is returned to the C02 distribution system for reinjection.
4. Water Treatment and Injection. Water separated in the tank batteries is processed at water plants to
remove any remaining oil and then distributed throughout the Rangely Field for reinjection.
LaBarge Field/
Shute Creek Plant
Field and plant owned and
operated by ExxonMobil
Raven Ridge
Pipeline
123 mile, 16" steel pipeline
(200 MMcfd capacity)
56% CRRPC owned
Custody Transfer Point for Assets
^ COn Measurement Points
(T) Rangely Field
Dehydration & NGL Extraction
1st/ 2nd Stage
Compression
Gas,
3rd/4m Stage
Compression
Oil/Water Liquids Liquid/Gas
Separation & ¦« Inlet
Water Plants Separation
Waler I Water!
Gas/Water
-*¦ Injection
Wells
Water
Disposal
Wells
4-
Producing
Wells
Surface ¦
Navajo Formation
C02 +
Water +
Natural Gas
Oil
+ Natural Gas I NGL
+ Water
+ CO,
Weber Sands Reservoir
Figure 10 Rangely Field -General Production Flow Diagram
13
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2.3.1 C02 Distribution and Injection.
SEM purchases C02 from XOM and receives it via the Raven Ridge Pipeline through one custody transfer
metering point, as indicated in Figures 10. Purchased C02 and recycled C02 are sent through the C02
trunk lines to multiple distribution lines to individual injection wells. There are volume meters at the inlet and
outlet of the C02 Reinjection Facility.
As of April 2023, SEM has approximately 280 injection wells in the Rangely Field. Approximately 160 MMscf
of C02 is injected each day, of which approximately 15% is purchased C02, and the balance (85%) is
recycled. The ratio of purchased C02 to recycled C02 is expected to change overtime, and eventually the
percentage of recycled C02 will increase and purchases of fresh C02 will taper off as indicated in Section
2.1.
Each injection well is connected to a WAG manifold located at the well pad. WAG manifolds are manually
operated and can inject either C02 or water at various rates and injection pressures as specified in the
injection plans. The length of time spent injecting each fluid is a matter of continual optimization that is
designed to maximize oil recovery and minimize C02 utilization in each injection pattern. A WAG manifold
consists of a dual-purpose flow meter used to measure the injection rate of water or C02, depending on
what is being injected. Data from these meters is sent to the Supervisory Control and Data Acquisition
("SCADA") system where it is compared to the injection plan for that well. As described in Sections 5 and
7, data from the WAG manifolds, visual inspections of the injection equipment, and use of the procedures
contained in 40 CFR §98.230-238 (Subpart W), will be gathered to complete the mass balance equations
necessary to determine annual and cumulative volumes of stored C02.
2.3.2 Wells in the Rangely Field
As of April 2023, there are 662 active wells that are completed in the Rangely Field, with roughly 40%
injection wells and 60% producing wells, as indicated in Figure 11,2 Table 1 shows these well counts in the
Rangely Field by status.
2 Wells that are not in use are deemed to be inactive, plugged and abandoned, temporarily abandoned, or shut in.
14
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Rangely Well List
# Active-Producer
TA-Producer
A Active-Injector
A TA-Injector
~ Active SWD
Rangely Weber Unit
I I Rangely Weber Unit
2N 103W
Metier Hill
00 RIO PLAN (9S COUN»7
2N 102W
.Rio Blanco
Ji) Rpven I
ftrfcjr li
Heliport
Moffat
I'tgely District
Vpitof Heppaf'
1N 102W
0RIO BLANCO CQ18NTY
Rio Blanco
iarfield
Figure 11 Rangely Field Wells - As of April 2023
Table 1 - Rangely Field Wells
<\ge/Completion of Well
Active
Shut-in
Temporarily
Abandoned
Plugged and
Abandoned
Drilled & Completed in the
1940's
265
5
55
149
Drilled 1950-1985
297
7
55
46
Completed after 1986
103
1
11
8
TOTAL
665
13
121
203
The wells in Table 1 are categorized in groups that relate to age and completion methods. Roughly 48%
of these wells were drilled in the 1940's and were generally completed with three strings of casing (with
surface and intermediate strings typically cemented to the surface). The production string was typically
installed to the top of the producing interval, otherwise known as the main oil column ("MOC"), which
extends to the producible oil/water contact ("POWC"). These wells were completed by stimulating the
open hole ("OH"), and are not typically cased through the MOC. While implementing the water flood from
1958-1986, a partial liner would have been typically installed to allow for controlled injection intervals and
this liner would have been cemented to the top of the liner ("TOL") that was installed. For example, a
partial liner would be installed from 5,700-6,500 ft, and the TOC would be at 5,700 ft. The casing weights
15
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used for the production string have varied between 7" 23 & 26#/ft. with 5" 18 #/ft. for the production liner.
The wells in Table 1 drilled during the period 1950-1986 typically were cased through the production
interval with 7" casing. Some wells were completed with 7" casing to the top of the MOC and then
completed with a 5" liner through the productive interval. The wells with liners were cemented to the TOL.
The remaining wells (roughly 12%) in Table 1 were drilled after 1986 when the C02 flood began. All of
these wells were completed with 7" casing through the POWC. Very few of these wells have experienced
any wellbore issues that would dictate the need for a remedial liner.
SEM reviews these categories along with full wellbore history when planning well maintenance projects.
Further, SEM keeps well workover crews on call to maintain all active wells and to respond to any
wellbore issues that arise. On average, in the Rangely Field there are two to three incidents per year in
which the well casing fails. SEM detects these incidents by monitoring changes in the surface pressure of
wells and by conducting Mechanical Integrity Tests ("MIT's), as explained later in this section and in the
relevant regulations cited. This rate of failure is less than 2% of wells per year and is considered
extremely low.
All wells in oilfields, including both injection and production wells described in Table 1, are regulated by
the COGCC under COGCC 100-1200 series rules. A list of wells, with well identification numbers, is
included in Appendix 5. The injection wells are subject to additional requirements promulgated by EPA -
the UIC Class II program - implementation of which has been delegated to the COGCC.
COGCC rules govern well siting, construction, operation, maintenance, and closure for all wells in oilfields.
Current rules require, among other provisions, that:
Class II UIC Wells will not be permitted in areas where they would inject into a formation that is
separated from any Underground Source of Drinking Water by a Confining Layer with known open
faults or fractures that would allow flow between the Injection Zone and Underground Source of Drinking
Water within the area of review.
Injection Zones will not be permitted within 300 feet in a vertical dimension from the top of any
Precambrian basement formation.
An Operator will not inject any Fluids or other contaminants into a UIC Aquifer that meets the
definition of an Underground Source of Drinking Water unless EPA has approved a UIC Aquifer
exemption as described in Rule 802.e.
In addition, SEM implements a corrosion protection program to protect and maintain the steel used in
injection and production wells from any C02-enriched fluids. SEM currently employs methods to mitigate
both internal and external corrosion of casing in wells in the Rangely Field. These methods generally protect
the downhole steel and the interior and exterior of wellbores through the use of special materials (e.g.
fiberglass tubing, corrosion resistant cements, nickel plated packers, corrosion resistant packer fluids) and
procedures (e.g. packer placement, use of annular leakage detection devices, cement bond logs, pressure
tests). These measures and procedures are typically included in the injection orders filed with the COGCC.
Corrosion protection methods and requirements may be enhanced overtime in response to improvements
in technology.
MIT
SEM complies with the MIT requirements implemented by COGCC and BLM to periodically inspect wells
and surface facilities to ensure that all wells and related surface equipment are in good repair and leak-
free, and that all aspects of the site and equipment conform with Division rules and permit conditions. All
active injection wells undergo an MIT at the following intervals:
Before injection operations begin
16
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Every 5 years as stated in the injection orders (COGCC 417.a. (1))
After any casing repair
After resetting the tubing or mechanical isolation device
Or whenever the tubing or mechanical isolation device is moved during workover operations
COGCC requires that the operator notify the COGCC district office prior to conducting an MIT. Operators
are required to use a pressure recorder and pressure gauge for the tests. The operator's field representative
must sign the pressure recorder chart along with the COGCC field representative and submit it with the MIT
form. The casing-tubing annulus must be tested to a minimum of 1200 psi for 15 minutes.
If a well fails an MIT, the operator must immediately shut the well in and provide notice to COGCC. Casing
leaks must be successfully repaired and retested or the well plugged and abandoned after submitting a
formal notice and obtaining approval from the COGCC.
Any well that fails an MIT cannot be returned to active status until it passes a new MIT
2.3.3 Produced Fluids Handling
As injected C02 and water move through the reservoir, a mixture of oil, gas, and water ("produced fluids")
flows to the production wells. Gathering lines bring the produced fluids from each production well to
collection stations. SEM has approximately 382 active production wells in the Rangely Field and production
from each is sent to one of 27 collection stations. Each collection station consists of a large vessel that
performs a gas - liquid separation. Each collection station also has well test equipment to measure
production rates of oil, water and gas from individual production wells. SEM has testing protocols for all
wells connected to a collection station. Most wells are tested twice per month. Some wells are prioritized
for more frequent testing because they are new or located in an important part of the Field; some wells with
mature, stable flow do not need to be tested as frequently; and finally, some wells will periodically need
repeat testing due to abnormal test results.
After separation, the gas phase is transported by pipeline to the C02 reinjection facility for processing as
described below. Currently the average composition of this gas mixture as it enters the facility is 92% C02
and 800ppm H2S; this composition will change overtime as C02 EOR operations mature.
The liquid phase, which is a mixture of oil and water, is sent to one of two centralized water plants where
oil is separated from water via two 3-phase separators. The water is then sent to water holding tanks where
further separation is done.
The separated oil is metered through the Lease Automatic Custody Transfer ("LACT") unit located at the
custody transfer point between Chevron pipeline and SEM. The oil typically contains a small amount of
dissolved or entrained C02. Analysis of representative samples of oil is conducted once a year to assess
C02 content.
The water is removed from the bottom of the tanks at the water injection stations, where it is re-injected to
the WAG injectors.
Any gas that is released from the liquid phase rises to the top of the tanks and is collected by a Vapor
Recovery Unit ("VRU") that compresses the gas and sends it to the C02 reinjection facility for processing.
17
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Rangely oil is slightly sour, containing small amounts of hydrogen sulfide ("H2S"), which is highly toxic.
There are approximately 25 workers on the ground in the Rangely Field at any given time, and all field
personnel are required to wear H2S monitors at all times. Although the primary purpose of H2S detectors
is protecting employees, monitoring will also supplement SEM's C02 leak detection practices as discussed
in Sections 5 and 7.
In addition, the procedures in 40 CFR §98.230-238 (Subpart W) and the two-part visual inspection process
described in Section 5 are used to detect leakage from the produced fluids handling system. As described
in Sections 5 and 7, the volume of leaks, if any, will be estimated to complete the mass balance equations
to determine annual and cumulative volumes of stored C02.
2.3.4 Produced Gas Handling
Produced gas gathered from the collection stations, and water injection plants is sent to the C02 reinjection
facility. There is an operations meter at the facility inlet.
Once gas enters the C02 reinjection facility, it undergoes dehydration and compression. In the RWSU an
additional process separates NGLs for sale. At the end of these processes there is a C02 rich stream that
is recycled through re-injection. Meters at the facility outlet are used to determine the total volume of the
C02 stream recycled back into the EOR operations.
As described in Section 2.3.4, data from 40 CFR §98.230-238 (Subpart W), the two-part visual inspection
process for production wells and areas described in Section 5, and information from the personal H2S
monitors are used to detect leakage from the produced gas handling system. This data will be gathered to
complete the mass balance equations necessary to determine annual and cumulative volumes of stored
C02 as described in Sections 5 and 7.
2.3.5 Water Treatment and Injection
Produced water collected from the collection stations is gathered through a pipeline system and moved to
one of two water injection plants. Each facility consists of 3-Phase separators and 79,500-barrels of
separation tanks where any remaining oil is skimmed from the water. Skimmed oil is combined with the oil
from the 3-Phase separators and sent to the LACT. The water is sent to an injection pump where it is
pressurized and distributed to the WAG injectors.
2.3.6 Facilities Locations
The current locations of the various facilities in the Rangely Field are shown in Figure 13. As indicated
above, there are two central water plants. There are twenty-seven collections stations that gather
production from surrounding wells. The two water plants are identified by the blue triangle and circle. The
twenty-seven collection stations are identified by red squares. The C02 Reinjection facility is indicated by
the green circle.
18
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Collection Station / Facility
I Collection Station
Compressor Station
¦ Rangely Facility
(££) Rangely Plant General
A West End Water Injection
Rangely Weber Unit
Rangely Weber Unit
" Men Hill
06 RIO BIANCSS COUN-1
Collection
Station 01
Collection
Station 03
Collection
Station 10m
,Rio Blanco
Collection
Station 08
Collection
2N 103W
Collection.^
Station 04
Collection
Station 20 2N 1021
Station 12
Collection
Station 05
Collection
Station 11
Collection
Station 27
West
End Water
Injection
Collection
Station 16
Heliport
Collection
Station 22
Collection Co"ec^,tV,
Station stat'°109
Collection
Station 17
Collection
Station 33
Collection
Station 28«
Collection
Station 29
Collection
Station 13
vCollection
Station 18 Main
¦ Treatment
I 37
Rangely [¦]
Plant ¦¦ Collection Collection
General Station 19 Station 24
Collection
Station 34
Collection
Station 30
Collection
Station 39
Collection
_Station_47_
Moffat
Rangely District
MOSfiittOi' HfiipOti
1N 102W
Uintah
ORIOi BLANCO CQBNTY
Rio Blanco
Garfield
Miles
Figure 13 Location of Surface Facilities at Rangely Field
3. Delineation of Monitoring Area and Timeframes
The current active monitoring area (AMA), future AMA and monitoring time frame of the AMA are
described below. Additionally, the maximum monitoring area (MMA) of the free phase C02 plume, its
buffer zone and the monitoring time frame for the MMA are described below.
3.1 Active Monitoring Area
Because C02 is present throughout the Rangely Field and retained within it, the Active Monitoring Area
(AMA) is defined by the boundary of the Rangely Field. This boundary is defined in Figure 9. The following
factors were considered in defining this boundary:
Free phase C02 is present throughout the Rangely Field: More than 2,320 BCF (122.76 MMT) tons of
C02 have been injected and recycled throughout the Rangely Field since 1986 and there has been
significant infill drilling in the Rangely Field, completing additional wells to further optimize production.
Operational results thus far indicate that there is C02 throughout the Rangely Field.
C02 injected into the Rangely Field remains contained within the Rangely Field AMA because of the
19
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fluid and pressure management results associated with C02 EOR. The maintenance of an IWR of 1.0
assures a stable reservoir pressure; managed lease line injection and production wells are used to
retain fluids in the Rangely Field as indicated in Section 4.7. Implementation of these methods over the
past decades have successfully contained C02 within the Rangely Field.
It is highly unlikely that injected C02 will migrate downdip and laterally outside the Rangely Field
because of the nature of the geology and the approach used for injection. As indicated in Section
2.2.1 "Geology of the Rangely Field," the Rangely Field is situated at the top of a dome structural
trap, with all directions pointing down-dip from the highest point. This means that over long periods of
time, injected C02 will tend to rise vertically towards the point in the Rangely Field with the highest
elevation.
Forecasted C02 injection volumes, shown in Figure 1, represent SEM's plan to not increase current
injection volumes and maintain an IWR of 1. Operations will not expand beyond the currently active C02-
EOR portion of the Rangely Field; therefore, the AMA is not expected to increase. Should such
expansions occur, they will be reported in the Subpart RR Annual Report for the Rangely Field, as
required by section 98.446.
3.2 Maximum Monitoring Area
The Maximum Monitoring Area ("MMA") is defined in 40 CFR §98.440-449 (Subpart RR) as equal or greater
than the area expected to contain the free-phase C02 plume until the C02 plume has stabilized, plus an all-
around buffer zone of one-half mile. Section 3.1 states that the maximum extent of the injected C02 is expected
to be bounded by the Rangely Field Unit boundary shown in Figure 9. Therefore, the MMA is the Rangely Field
Unit boundary plus the one-half mile buffer as required by 40 CFR §98.440-449 (Subpart RR).
3.3 Monitoring Timeframes
SEM's primary purpose for injecting C02 is to produce oil that would otherwise remain trapped in the
reservoir and not, as in UIC Class VI, "specifically for the purpose of geologic storage."3 During a Specified
Period, SEM will have a subsidiary purpose of establishing the long-term containment of a measurable
quantity of C02 in the Weber Sands in the Rangely Field. The Specified Period will be shorter than the
period of production from the Rangely Field. This is in part because the purchase of new C02 for injection
is projected to taper off significantly before production ceases at Rangely Field, which is modeled through
2060. At the conclusion of the Specified Period, SEM will submit a request for discontinuation of reporting.
This request will be submitted when SEM can provide a demonstration that current monitoring and model(s)
show that the cumulative mass of C02 reported as sequestered during the Specified Period is not expected
to migrate in the future in a manner likely to result in surface leakage. It is expected that it will be possible to
make this demonstration within two to three years after injection for the Specified Period ceases based upon
predictive modeling supported by monitoring data. The demonstration will rely on two principles: 1) that just
as is the case for the monitoring plan, the continued process of fluid management during the years of C02
EOR operation after the Specified Period will contain injected fluids in the Rangely Field, and 2) that the
cumulative mass reported as sequestered during the Specified Period is a fraction of the theoretical storage
capacity of the Rangely Field See 40 C.F.R. § 98.441 (b)(2)(ii).
4. Evaluation of Potential Pathways for Leakage to the Surface
3 EPA UIC Class VI rule, EPA 75 FR 77291, December 10, 2010, section 146.81(b).
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4.1 Introduction
In the 90 years since the Rangely Field was discovered in 1933, extensive reservoir monitoring and
studies were performed. Based on the knowledge gained from historical practices, this section assesses
the following potential pathways for leakage of C02 to surface within Rangely Field.
Existing Wellbores
Faults and Fractures
Natural and Induced Seismic Activity
Previous Operations
Pipeline/Surface Equipment
Lateral Migration Outside the Rangely Field
Drilling Through the C02 Area
Diffuse Leakage Through the Seal
Detailed analysis of these potential pathways concluded that existing wellbores and pipeline/surface
equipment pose the only meaningful potential leakage pathways. Operating pressures are not expected
to increase over time, therefore there is not a specific time period that would increase the likelihood of
pathways for leakage. SEM identifies these potential pathways for C02 leakage to be low risk, i.e., less
than 1% given the extensive operating history and monitoring program currently in place.
The monitoring program to detect and quantify leakage is based on the assessment discussed below.
4.2 Existing Wellbores
As of April 2023, there are approximately 662 active SEM operated wells in the Rangely Field - split roughly
evenly between production and injection wells. In addition, there are approximately 135 wells not in use, as
described in Section 2.3.2.
Leakage through existing wellbores is a potential risk at the Rangely Field that SEM works to prevent by
adhering to regulatory requirements for well drilling and testing; implementing best practices that SEM has
developed through its extensive operating experience; monitoring injection/production performance,
wellbores, and the surface; and maintaining surface equipment.
As discussed in Section 2.3.2, regulations governing wells in the Rangely Field require that wells be
completed and operated so that fluids are contained in the strata in which they are encountered and that
well operation does not pollute subsurface and surface waters. The regulations establish the requirements
that all wells (injection, production, disposal) must comply with. Depending upon the purpose of a well, the
requirements can include additional standards for evaluation and MIT. SEM's best practices include pattern
level analysis to guide injection pressures and performance expectations; utilizing diverse teams of experts
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to develop EOR projects based on specific site characteristics; and creating a culture where all field
personnel are trained to look for and address issues promptly. SEM's practices, which include corrosion
prevention techniques to protect the wellbore as needed, as discussed in Section 2.3.2, ensures that well
completion and operation procedures are designed not only to comply with regulations but also to ensure
that all fluids (e.g., oil, gas, C02) remain in the Rangely Field until they are produced through an SEM well.
As described in Section 5, continual and routine monitoring of SEM's wellbores and site operations will be
used to detect leaks, including those from non-SEM wells, or other potential well problems, as follows:
Well pressure in injection wells is monitored on a continual basis. The injection plans for each pattern
are programmed into the injection WAG controller, as discussed in Section 2.3.1, to govern the rate and
pressure of each injector. Pressure monitors on the injection wells are programmed to flag pressures
that significantly deviate from the plan. Leakage on the inside or outside of the injection wellbore would
affect pressure and be detected through this approach. If such excursions occur, they are investigated
and addressed. In the time SEM has operated the Rangely Field, there have been no C02 leakage
events from a wellbore.
In addition to monitoring well pressure and injection performance, SEM uses the experience gained
overtime to strategically approach well maintenance. SEM maintains well maintenance and workover
crews onsite for this purpose. For example, the well classifications by age and construction method
indicated in Table 1 inform SEM's plan for monitoring and updating wells. SEM uses all of the
information at hand including pattern performance, and well characteristics to determine well
maintenance schedules.
Production well performance is monitored using the production well test process conducted when
produced fluids are gathered and sent to a collection station. There is a routine cycle for each collection
station, with each well being tested approximately twice every month. During this cycle, each production
well is diverted to the well test equipment for a period of time sufficient to measure and sample produced
fluids (generally 24 hours). This test allows SEM to allocate a portion of the produced fluids measured
at the collection station to each production well, assess the composition of produced fluids by location,
and assess the performance of each well. Performance data are reviewed on a routine basis to ensure
that C02 flooding is optimized. If production is off plan, it is investigated and any identified issues
addressed. Leakage to the outside of production wells is not considered a major risk because of the
reduced pressure in the casing. Further, the personal H2S monitors are designed to detect leaked fluids
around production wells.
Finally, as indicated in Section 5, field inspections are conducted on a routine basis by field personnel.
On any day, SEM has approximately 25 personnel in the field. Leaking C02 is very cold and leads to
formation of bright white clouds and ice that are easily spotted. All field personnel are trained to identify
leaking C02 and other potential problems at wellbores and in the field. Any C02 leakage detected will
be documented and reported, quantified and addressed as described in Section 5.
Based on its ongoing monitoring activities and review of the potential leakage risks posed by wellbores,
SEM concludes that it is mitigating the risk of C02 leakage through wellbores by detecting problems as
they arise and quantifying any leakage that does occur. Section 4.10 summarizes how SEM will monitor
C02 leakage from various pathways and describes how SEM will respond to various leakage scenarios.
In addition, Section 5 describes how SEM will develop the inputs used in the Subpart RR mass-balance
equation (Equation RR-11). Any incidents that result in C02 leakage up the wellbore and into the
atmosphere will be quantified as described in Section 7.4.
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4.3 Faults and Fractures
After reviewing geologic, seismic, operating, and other evidence, SEM has concluded that there are no
known faults or fractures that transect the entirety of the Weber Sands in the project area. As described in
Section 2.2.1, the MMF is presented below the reservoir and terminates within the Weber Sands without
interacting with the upper seal. Additional large faults have been identified in formations that are thousands
of feet below the Weber Sands, but this faulting has been shown not to affect the Weber Sands or to have
created potential leakage pathways.
SEM has extensive experience in designing and implementing EOR projects to ensure injection pressures
will not damage the oil reservoir by inducing new fractures or creating shear. As a safeguard, injection
satellites aresetwith automatic shutoff controls if injection pressures exceed fracture pressures.
4.4 Natural or Induced Seismicity
After reviewing literature and historic data, SEM concludes that there is no direct evidence that natural
seismic activity poses a significant risk for loss of C02 to the surface in the Rangely Field. Natural seismic
events are derived from the thrust fault to the west. Historically, Figure 6 in section 2.2.1 shows nine (9)
seismic events outside of the Rangely Field (including the 1993 M 3.5 event). The epicenter of these
earthquakes was far below the operating depths of the Rangely Field, and are associated with the thrust
fault to the west of the field. The operations of Rangely have zero impact on this thrust fault. Natural
earthquakes are not predictable, but these do not pose a threat to current operations. This is evidenced by
the fact that hydrocarbons are still within the anticline, meaning that there have been no major seismic
events in the last few million years capable of releasing these hydrocarbons to the surface.
Induced seismic events (non-natural) are tied to the MFF and its joint faults. These can be impacted by
Rangely Field operations. Section 2.2.1 explains how an increase in reservoir pressure can trigger seismic
events along and near the MFF. To prevent this from occurring bottom hole pressure surveys are collected
one (1) to two (2) times per year across the Rangely Field helping to monitor pressure changes along across
the Rangely Field. By keeping reservoir pressure from exceeding the threshold of ~3750 psi for extended
periods of time (multiple years), induced seismic events can be greatly mitigated. In the case that reservoir
pressures do exceed the threshold pressure, a reduction in injected volumes in the vicinity will bring down
the pressures back down gradually over a period of time.
4.5 Previous Operations
Chevron initiated C02 flooding in the Rangely Field in 1986. SEM and the prior operators have kept records
of the site and have completed numerous infill wells. SEM has not drilled any new wells in Rangely to date
but their standard practice for drilling new wells includes a rigorous review of nearby wells to ensure that
drilling will not cause damage to or interfere with existing wells. SEM will also follow AOR requirements
under the UIC Class II program, which require identification of all active and abandoned wells in the AOR
and implementation of procedures that ensure the integrity of those wells when applying for a permit for any
new injection well. These practices ensure that identified wells are sufficiently isolated and do not interfere
with the C02 EOR operations and reservoir pressure management. Consequently, SEM's operational
experience supports the conclusion that there are no unknown wells within the Rangely Field that penetrate
the Weber Sands and that it has sufficiently mitigated the risk of migration from older wells.
4.6 Pipeline / Surface Equipment
Damage to or failure of pipelines and surface equipment can result in unplanned losses of C02. SEM
reduces the risk of unplanned leakage from surface facilities, to the maximum extent practicable, by relying
on the use of prevailing design and construction practices and maintaining compliance with applicable
regulations. The facilities and pipelines currently utilize and will continue to utilize materials of construction
and control processes that are standard for C02 EOR projects in the oil and gas industry. As described
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above, all facilities in the Rangely Field are internally screened for proximity to the public. In the case of
pipeline and surface equipment, best engineering practices call for more robust metallurgy in wellhead
equipment, and pressure transducers with low pressure alarms monitored through the SCADA system to
prevent and detect leakage. Operating and maintenance practices currently follow and will continue to follow
demonstrated industry standards. C02 delivery via the Raven Ridge pipeline system will continue to
comply with all applicable regulations. Finally, frequent routine visual inspection of surface facilities by field
staff will provide an additional way to detect leaks and further support SEM's efforts to detect and remedy
any leaks in a timely manner. Should leakage be detected from pipeline or surface equipment, the volume
of released C02 will be quantified following the requirements of Subpart W of EPA's GHGRP.
4.7 Lateral Migration Outside the Rangely Field
It is highly unlikely that injected C02 will migrate downdip and laterally outside the Rangely Field because of
the nature of the geology and the approach used for injection. First, as indicated in Section 2.2.1 "Geology
of the Rangely Field," the Rangely Field is situated at the top of a dome structural trap, with all directions
pointing down-dip from the highest point. This means that over long periods of time, injected C02 will tend
to rise vertically towards the point in the Rangely Field with the highest elevation. Second, the planned
injection volumes and active fluid management during injection operations will prevent C02 from migrating
laterally stratigraphically (down-dip structurally) out of the structure. Finally, SEM will not be increasing the
total volume of fluids in the Rangely Field.
COGCC requires that injection pressures be limited to ensure injection fluids do not migrate outside the
permitted injection interval. In the Rangely Field, SEM uses two methods to contain fluids: reservoir
pressure management and the careful placement and operation of wells along the outer producing limits of
the units.
Reservoir pressure in the Rangely Field is managed by maintaining an injection to withdrawal ratio ("IWR")
of approximately 1.0. To maintain the IWR, SEM monitors fluid injection to ensure that reservoir pressure
does not increase to a level that would fracture the reservoir seal or otherwise damage the oil field.
SEM also prevents injected fluids from migrating out of the injection interval by keeping injection pressure
below the formation fracture pressure, which is measured using historic step-rate tests. In these tests,
injection pressures are incrementally increased (e.g., in "steps") until injectivity increases abruptly, which
indicates that an opening or fracture has been created in the rock. SEM manages its operations to ensure
that injection pressures are kept below the formation fracture pressure so as to ensure that the valuable
fluid hydrocarbons and C02 remain in the reservoir.
There are a few small producer wells operated by third parties outside the boundary of Rangely Field. There
are currently no significant commercial operations surrounding the Rangely Field to interfere with SEM's
operations.
Based on site characterization and planned and projected operations SEM estimates the total volume of
stored C02 will be approximately 35.7% of calculated capacity.
4.8 Drilling Through the C02 Area
It is possible that at some point in the future, drilling through the containment zone into the Weber Sands
could occur and inadvertently create a leakage pathway. SEM's review of this issue concludes that this risk
is very low for two reasons. First, SEM's visual inspection process, including routine site visits, is designed
to identify unapproved drilling activity in the Rangely Field. Second, SEM plans to operate the C02 EOR
flood in the Rangely Field for several more years, and will continue to be vigilant about protecting the
integrity of its assets and maximizing the potential of resources (oil, gas, C02). In the unlikely event SEM
would sell the field to a new operator, provisions would result in a change to the reporting program and
would be addressed at that time.
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4.9 Diffuse Leakage through the Seal
Diffuse leakage through the seal formed by the Moenkopi Formation is highly unlikely. The presence of a
gas cap trapped over millions of years as discussed in Section 2.2.3 confirms that the seal has been
secure for a very long time. Injection pattern monitoring program referenced in Section 2.3.1 and detailed
in Section 5 assures that no breach of the seal will be created. The seal is highly impermeable where
unperforated, cemented across the horizon where perforated by wells, and unexplained changes in
injection pressure would trigger investigation as to the cause. Further, if C02 were to migrate through the
Moenkopi seal, it would migrate vertically until it encountered and was trapped by any of the numerous
shallower shale seals
4.10 Monitoring, Response, and Reporting Plan for C02 Loss
As discussed above, the potential sources of leakage include fairly routine issues, such as problems with
surface equipment (pumps, valves, etc.) or subsurface equipment (wellbores), and unique events such as
induced fractures. Table 3 summarizes some of these potential leakage scenarios, the monitoring activities
designed to detect those leaks, SEM's standard response, and other applicable regulatory programs
requiring similar reporting.
Sections 5.1.5 - 5.1.7 discuss the approaches envisioned for quantifying the volumes of leaked C02. Given
the uncertainty concerning the nature and characteristics of leaks that will be encountered, the most
appropriate methods for quantifying the volume of leaked C02 will be determined at the time. In the event
leakage occurs, SEM plans to determine the most appropriate methods for quantifying the volume leaked
and will report it as required as part of the annual Subpart RR submission.
Any volume of C02 detected leaking to surface will be quantified using acceptable emission factors such
as those found in 40 CFR Part 98 Subpart W or engineering estimates of leak amounts based on
measurements in the subsurface, SEM's field experience, and other factors such as the frequency of
inspection. As indicated in Sections 5.1 and 7.4, leaks will be documented, evaluated and addressed in a
timely manner. Records of leakage events will be retained in the electronic environmental documentation
and reporting system. Repairs requiring a work order will be documented in the electronic equipment
maintenance system.
Table 3 Response Plan for C02 Loss
Risk
Monitoring Plan
Response Plan
Parallel
Reporting (if
any)
Loss of Well Control
Tubing Leak
Monitor changes in tubing and
annulus pressure; MIT for injectors
Well is shut in and
Workover crews respond
within days
COGCC
Casing Leak
Routine Field inspection; monitor
changes in annulus pressure; MIT for
injectors; extra attention to high risk
wells
Well is shut in and
Workover crews respond
within days
COGCC
Wellhead Leak
Routine Field inspection
Well is shut in and
Workover crews respond
within days
COGCC
Loss of Bottom-
hole
pressure control
Blowout during well operations
Maintain well kill
procedures
COGCC
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Unplanned wells
drilled through
Weber Sands
Routine Field inspection to
prevent unapproved drilling;
compliance with COGCC permitting
for planned wells.
Assure compliance with
COGCC regulations
COGCC
Permitting
Loss of seal in
abandoned wells
Reservoir pressure in monitor wells;
high pressure found in new wells
Re-enter and reseal
abandoned wells
COGCC
Leaks in Surface Facilities
Pumps, valves, etc.
Routine Field inspection; SCADA
Maintenance crews
respond within days
Subpart W
Subsurface Leaks
Leakage along
faults
Reservoir pressure in monitor wells;
high pressure found in new wells
Shut in injectors near
faults
-
Overfill beyond
spill
points
Reservoir pressure in monitor wells;
high; pressure found in new wells
Fluid management
along
lease lines
-
Leakage through
induced fractures
Reservoir pressure in monitor wells;
high pressure found in new wells
Comply with rules for
keeping pressures
below
parting pressure
-
Leakage due to
seismic event
Reservoir pressure in monitor wells;
high
pressure found in new wells
Shut in injectors near
seismic event
-
Available studies of actual well leaks and natural analogs (e.g., naturally occurring C02 geysers) suggest
that the amount released from routine leaks would be small as compared to the amount of C02 that would
remain stored in the formation.
4.11 Summary
The structure and stratigraphy of the Weber Sands in the Rangely Field is ideally suited forthe injection and
storage of C02. The stratigraphy within the C02 injection zones is porous, permeable and very thick,
providing ample capacity for long-term C02 storage. The Weber Sands is overlain by several intervals of
impermeable geologic zones that form effective seals or "caps" to fluids in the Weber Sands (See Figure
4). After assessing potential risk of release from the subsurface and steps that have been taken to prevent
leaks, SEM has determined that the potential threat of leakage is extremely low.
In summary, based on a careful assessment of the potential risk of release 0fCO2 from the subsurface, SEM
has determined that there are no leakage pathways at the Rangely Field that are likely to result in significant
loss of C02 to the atmosphere. Further, given the detailed knowledge of the Field and its operating
protocols, SEM concludes that it would be able to both detect and quantify any C02 leakage to the surface
that could arise through either identified or unexpected leakage pathways.
5. Monitoring and Considerations for Calculating Site Specific Variables
Monitoring will also be used to determine the quantities in the mass balance equation and to make the
demonstration that the C02 plume will not migrate to the surface after the time of discontinuation.
5.1 Forthe Mass Balance Equation
5.1.1 General Monitoring Procedures
As part of its ongoing operations, SEM monitors and collects flow, pressure, and gas composition data from
26
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the Rangely Field in centralized data management systems. These data are monitored continually by
qualified technicians who follow SEM response and reporting protocols when the systems deliver
notifications that data exceed statistically acceptable boundaries.
As indicated in Figures 10 and 11, custody-transfer meters are used at the point at which custody of the
C02 from the Raven Ridge pipeline delivery system is transferred to SEM, and at the points at which custody
of oil and NGLs are transferred to outside parties. Meters measure flow rate continually. Fluid composition
will be determined, at a minimum, quarterly, consistent with EPA GHGRP's Subpart RR, section 98.447(a).
All meter and composition data are documented, and records will be retained for at least three years.
Metering protocols used by SEM follow the prevailing industry standard(s) for custody transfer as currently
promulgated by the API, the American Gas Association ("AGA"), and the Gas Processors Association
("GPA"), as appropriate. This approach is consistent with EPA GHGRP's Subpart RR, section 98.444(e)(3).
These meters will be maintained routinely, operated continually, and will feed data directly to the centralized
data collection systems. The meters meet the industry standard for custody transfer meter accuracy and
calibration frequency. These custody meters provide the most accurate way to measure mass flows.
SEM maintains in-field process control meters to monitor and manage in-field activities on a real time basis.
These are identified as operations meters in Figures 10 and 11. These meters provide information used to
make operational decisions but are not intended to provide the same level of accuracy as the custody-
transfer meters. The level of precision and accuracy for in-field meters currently satisfies the requirements
for reporting in existing UIC permits. Although these meters are accurate for operational purposes, it is
important to note that there is some variance between most commercial meters (on the order of 1-5%)
which is additive across meters. This variance is due to differences in factory settings and meter calibration,
as well as the operating conditions within a field. Meter elevation, changes in temperature (over the course
of the day), fluid composition (especially in multi-component or multi-phase streams), or pressure can affect
in-field meter readings. Unlike in a saline formation, where there are likely to be only a few injection wells
and associated meters, at C02 EOR operations in the Rangely Field there are currently 662 active injection
and production wells and a comparable number of meters, each with an acceptable range of error. This is
a site-specific factor that is considered in the mass balance calculations described in Section 7.
5.1.2 C02 Received
SEM measures the volume of received C02 using commercial custody transfer meters at the off-take point
from the Raven Ridge pipeline delivery system. This transfer is a commercial transaction that is
documented. C02 composition is governed by the contract and the gas is routinely sampled to determine
composition. No C02 is received in containers.
5.1.3 C02 Injected into the Subsurface
Injected C02 will be calculated using the flow metervolumes at the operations meteratthe outlet of the C02
Reinjection Facility and the custody transfer meter at the C02 off-take points from the Raven Ridge pipeline
delivery system
5.1.4 C02 Produced, Entrained in Products, and Recycled
The following measurements are used for the mass balance equations in Section 7:
C02 produced is calculated using the volumetric flow meters at the inlet to the C02 Reinjection Facility.
These flow meters, as illustrated on Figure 10, are downstream of the field collection station separators
and bulk produced fluid separators at the water injection plants
C02 is produced as entrained or dissolved C02 in produced oil, as indicated in Figures 10 and 11. This is
calculated using volumetric flow through the custody transfer meter.
Recycled C02 is calculated using the volumetric flow meter at the outlet of the C02 Reinjection Facility,
which is an operations meter.
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5.1.5 C02 Emitted by Surface Leakage
As discussed in Section 5.1.6 and 5.1.7 below, SEM uses 40 CFR Part 98 Subpart Wto estimate surface
leaks from equipment at the Rangely Field. Subpart W uses a factor-driven approach to estimate equipment
leakage. In addition, SEM uses an event-driven process to assess, address, track, and if applicable quantify
potential C02 leakage to the surface. SEM will reconcile the Subpart W report and results from any event-
driven quantification to assure that surface leaks are not double counted.
The multi-layered, risk-based monitoring program for event-driven incidents has been designed to meet two
objectives, in accordance with the leakage risk assessment in Section 4: 1) to detect problems before C02
leaks to the surface; and 2) to detect and quantify any leaks that do occur. This section discusses how this
monitoring will be conducted and used to quantify the volumes of C02 leaked to the surface.
Monitoring for potential Leakage from the Injection/Production Zone:
SEM will monitor both injection into and production from the reservoir as a means of early identification of
potential anomalies that could indicate leakage from the subsurface.
SEM develops injection plans for each well and that is distributed to operations weekly. If injection pressure
or rate measurements are beyond the specified set points determined as part of each pattern injection plan,
the operations engineer will notify field personnel and they will investigate and resolve the problem. These
excursions will be reviewed by well-management personnel to determine if C02 leakage may be occurring.
Excursions are not necessarily indicators of leaks; they simply indicate that injection rates and pressures
are not conforming to the pattern injection plan. In many cases, problems are straightforward to fix (e.g., a
meter needs to be recalibrated or some other minor action is required), and there is no threat of C02
leakage. In the case of issues that are not readily resolved, more detailed investigation and response would
be initiated, and internal SEM support staff would provide additional assistance and evaluation. Such issues
would lead to the development of a work order in SEM's work order management system. This record
enables the company to track progress on investigating potential leaks and, if a leak has occurred, to
quantify its magnitude.
Likewise, SEM develops a forecast of the rate and composition of produced fluids. Each producer well is
assigned to one collection station and is isolated twice during each monthly cycle for a well production test.
This data is reviewed on a periodic basis to confirm that production is at the level forecasted. If there is a
significant deviation from the forecast, well management personnel investigate. If the issue cannot be
resolved quickly, more detailed investigation and response would be initiated. As in the case of the injection
pattern monitoring, if the investigation leads to a work order in the SEM work order management system,
this record will provide the basis for tracking the outcome of the investigation and if a leak has occurred. If
leakage in the flood zone were detected, SEM would use an appropriate method to quantify the involved
volume of C02. This might include use of material balance equations based on known injected quantities
and monitored pressures in the injection zone to estimate the volume of C02 involved.
A subsurface leak might not lead to a surface leak. In the event of a subsurface leak, SEM would determine
the appropriate approach for tracking subsurface leakage to determine and quantify leakage to the surface.
To quantify leakage to the surface, SEM would estimate the relevant parameters (e.g., the rate,
concentration, and duration of leakage) to quantify the leak volume. Depending on specific circumstances,
these determinations may rely on engineering estimates.
In the event leakage from the subsurface occurred diffusely through the seals, the leaked gas would include
H2S, which would trigger the alarm on the personal monitors worn by field personnel. Such a diffuse leak
from the subsurface has not occurred in the Rangely Field. In the event such a leak was detected, field
personnel from across SEM would determine how to address the problem. The team might use modeling,
engineering estimates, and direct measurements to assess, address, and quantify the leakage.
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Monitoring of Wellbores:
SEM monitors wells through continual, automated pressure monitoring in the injection zone (as described in
Section 4.2), monitoring of the annular pressure in wellheads, and routine maintenance and inspection.
Leaks from wellbores would be detected through the follow-up investigation of pressure anomalies, visual
inspection, or the use of personal H2S monitors.
Anomalies in injection zone pressure may not indicate a leak, as discussed above. However, if an
investigation leads to a work order, field personnel would inspect the equipment in question and determine
the nature of the problem. If it is a simple matter, the repair would be made and the volume of leaked C02
would be included in the 40 CFR Part 98 Subpart W report for the Rangely Field. If more extensive repair
were needed, SEM would determine the appropriate approach forquantifying leaked C02 using the relevant
parameters (e.g., the rate, concentration, and duration of leakage). The work order would serve as the basis
for tracking the event for GHG reporting.
Anomalies in annular pressure or other issues detected during routine maintenance inspections would be
treated in the same way. Field personnel would inspect the equipment in question and determine the nature
of the problem. For simple matters the repair would be made at the time of inspection and the volume of
leaked C02 would be included in the 40 CFR Part 98 Subpart W report for the Rangely Field. If more
extensive repairs were needed, a work order would be generated and SEM would determine the appropriate
approach for quantifying leaked C02 using the relevant parameters (e.g., the rate, concentration, and
duration of leakage). The work order would serve as the basis for tracking the event for GHG reporting.
Because leaking C02 at the surface is very cold and leads to formation of bright white clouds and ice that
are easily spotted, SEM also employs a two-part visual inspection process in the general area of the Rangely
Field to detect unexpected releases from wellbores. First, field personnel visit the surface facilities on a
routine basis. Inspections may include tank volumes, equipment status and reliability, lube oil levels,
pressures and flow rates in the facility, and valve leaks. Field personnel inspections also check that injectors
are on the proper WAG schedule and observe the facility for visible C02 or fluid line leaks.
Historically, SEM has not experienced any unexpected release events in the Rangely Field. An identified
need for repair or maintenance through visual inspections results in a work order being entered into SEM's
equipment and maintenance work order management system. The time to repair any leak is dependent on
several factors, such as the severity of the leak, available manpower, location of the leak, and availability
of materials required for the repair. Critical leaks are acted upon immediately.
Finally, SEM uses the data collected by the H2S monitors, which are worn by all field personnel at all times,
as a last method to detect leakage from wellbores. The H2S monitors detection limit is 10ppm; if an H2S
alarm is triggered, the first response is to protect the safety of the personnel, and the next step is to safely
investigate the source of the alarm. As noted previously, SEM considers H2S a proxy for potential C02
leaks in the field. Thus, detected H2S leaks will be investigated to determine potential C02 leakage is
present, but not used to determine the leak volume. If the incident results in a work order, this will serve as
the basis for tracking the event for GHG reporting.
Other Potential Leakage at the Surface:
SEM will utilize the same visual inspection process and H2S monitoring system to detect other potential
leakage at the surface as it does for leakage from wellbores. SEM utilizes routine visual inspections to
detect significant loss of C02 to the surface. Field personnel routinely visit surface facilities to conduct a
visual inspection. Inspections may include review of tank level, equipment status, lube oil levels, pressures
and flow rates in the facility, valve leaks, ensuring that injectors are on the proper WAG schedule, and also
conducting a general observation of the facility for visible C02 or fluid line leaks. If problems are detected,
field personnel would investigate, and, if maintenance is required, generate a work order in the maintenance
system, which is tracked through completion. In addition to these visual inspections, SEM will use the results
29
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of the personal H2S monitors worn by field personnel as a supplement for smaller leaks that may escape
visual detection.
If C02 leakage to the surface is detected, it will be reported to surface operations personnel who will review
the reports and conduct a site investigation. If maintenance is required, a work order will be generated in
the work order management system. The work order will describe the appropriate corrective action and be
used to track completion of the maintenance action. The work order will also serve as the basis for tracking
the event for GHG reporting and quantifying any C02 emissions.
5.1.6 C02 emitted from equipment leaks and vented emissions of C02 from surface equipment
located between the injection flow meter and the injection wellhead.
SEM evaluates and estimates leaks from equipment, the C02 content of produced oil, and vented C02,
as required under 40 CFR Part 98 Subpart W.
5.1.7 Mass of C02 emissions from equipment leaks and vented emissions of C02 from surface
equipment located between the production flow meter and the production wellhead
SEM evaluates and estimates leaks from equipment, the C02 content of produced oil, and vented C02,
as required under 40 CFR Part 98 Subpart W.
5.2 To Demonstrate that Injected C02 is not Expected to Migrate to the Surface
At the end of the Specified Period, SEM intends to cease injecting C02 for the subsidiary purpose of
establishing the long-term storage of C02 in the Rangely Field. After the end of the Specified Period, SEM
anticipates that it will submit a request to discontinue monitoring and reporting. The request will demonstrate
that the amount of C02 reported under 40 CFR §98.440-449 (Subpart RR) is not expected to migrate in the
future in a manner likely to result in surface leakage. At that time, SEM will be able to support its request
with years of data collected during the Specified Period as well as two to three (or more, if needed) years
of data collected after the end of the Specified Period. This demonstration will provide the information
necessary for the EPA Administrator to approve the request to discontinue monitoring and reporting and
may include, but is not limited to:
i. Data comparing actual performance to predicted performance (purchase, injection, production)
over the monitoring period;
ii. An assessment of the C02 leakage detected, including discussion of the estimated amount of
C02 leaked and the distribution of emissions by leakage pathway;
iii. A demonstration that future operations will not release the volume of stored C02 to the surface;
iv. A demonstration that there has been no significant leakage of C02; and,
v. An evaluation of reservoir pressure in the Rangely Field that demonstrates that injected fluids are
not expected to migrate in a manner to create a potential leakage pathway.
6. Determination of Baselines
SEM intends to utilize existing automatic data systems to identify and investigate excursions from expected
performance that could indicate C02 leakage. SEM's data systems are used primarily for operational
control and monitoring and as such are set to capture more information than is necessary for reporting in the
Annual Subpart RR Report. SEM will develop the necessary system guidelines to capture the information that
is relevant to identify possible C02 leakage. The following describes SEM's approach to collecting this
information.
Visual Inspections
As field personnel conduct routine inspections, work orders are generated in the electronic system for
maintenance activities that cannot be addressed on the spot. Methods to capture work orders that involve
activities that could potentially involve C02 leakage will be developed, if not currently in place. Examples
30
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include occurrences of well workover or repair, as well as visual identification of vapor clouds or ice
formations. Each incident will be flagged for review by the person responsible for MRV documentation. The
responsible party will be provided in the monitoring plan, as required under Subpart A, 98.3(g). The Annual
Subpart RR Report will include an estimate of the amount of C02 leaked. Records of information used to
calculate emissions will be maintained on file for a minimum of three years.
Personal H2S Monitors
H2S monitors are worn by all field personnel. Any monitor alarm triggers an immediate response to ensure
personnel are not at risk and to verify the monitor is working properly. The person responsible for MRV
documentation will receive notice of all incidents where H2S is confirmed to be present. The Annual Subpart
RR Report will provide an estimate the amount of C02 emitted from any such incidents. Records of
information to calculate emissions will be maintained on file for a minimum of three years.
Injection Rates. Pressures and Volumes
SEM develops target injection rate and pressure for each injector, based on the results of ongoing pattern
modeling and within permitted limits. The injection targets are programmed into the WAG controllers. High
and low set points are also programmed into the SCADA, and flags whenever statistically significant
deviations from the targeted ranges are identified. The set points are designed to be conservative, because
it is preferable to have too many flags rather than too few. As a result, flags can occur frequently and are
often found to be insignificant. For purposes of Subpart RR reporting, flags (or excursions) will be screened
to determine if they could also lead to C02 leakage to the surface. The person responsible for the MRV
documentation will receive notice of excursions and related work orders that could potentially involve C02
leakage. The Annual Subpart RR Report will provide an estimate of C02 emissions. Records of information
to calculate emissions will be maintained on file for a minimum of three years.
Production Volumes and Compositions
SEM develops a general forecast of production volumes and composition which is used to periodically
evaluate performance and refine current and projected injection plans and the forecast. This information is
used to make operational decisions but is not recorded in an automated data system. Sometimes, this
review may result in the generation of a work order in the maintenance system. The MRV plan
implementation lead will review such work orders and identify those that could result in C02 leakage. Should
such events occur, leakage volumes would be calculated following the approaches described in Sections 4
and 5. Impact to Subpart RR reporting will be addressed, if deemed necessary.
7. Determination of Sequestration Volumes Using Mass Balance Equations
To account forthe site conditions and complexity of a large, active EOR operation, SEM proposes to modify
the locations for obtaining volume data forthe equations in Subpart RR §98.443 as indicated below.
The first modification addresses the propagation of error that would result if volume data from meters at
each injection and production well were utilized. This issue arises because while each meter has a small
but acceptable margin of error, this error would become significant if data were taken from the
approximately 284 meters within the Rangely Field. As such, SEM proposes to use the data from custody
and operations meters on the main system pipelines to determine injection and production volumes used
in the mass balance.
The second modification addresses the NGL sales from the Rangely Field. As indicated in Figure 10, NGL
is separated from the fluid mix at the Rangely Field after it has been measured at the RCF inlet and before
measurement at the RCF outlet. As a result the amount of C02 recycled already accounts for the amount
entrained in NGL and therefore is not factored separately into the mass balance calculation.
The following sections describe how each element of the mass-balance equation (Equation RR-11) will be
calculated.
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. Mass of C02 Received
SEM will use equation RR-2 as indicated in Subpart RR §98.443 to calculate the mass of 0O2 received
from each delivery meter immediately upstream of the Raven Ridge pipeline delivery system on the Rangely
Field. The volumetric flow at standard conditions will be multiplied by the C02 concentration and the density
of C02 at standard conditions to determine mass.
c02T,r = Sr.,<£q. RR-2)
P=1
where:
C02T,r = Net annual mass of C02 received through flow meter r (metric tons).
Qr,p = Quarterly volumetric flow through a receiving flow meter r in quarter p at standard conditions
(standard cubic meters).
Sr,p = Quarterly volumetric flow through a receiving flow meter r that is redelivered to another facility without
being injected into a site well in quarter p (standard cubic meters).
D = Density of C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.
CC02,p,r = Quarterly C02 concentration measurement in flow for flow meter r in quarter p (vol. percent
C02, expressed as a decimal fraction).
p = Quarter of the year,
r = Receiving flow meters.
Given SEM's method of receiving C02 and requirements at Subpart RR §98.444(a):
All delivery to the Rangely Field is used within the unit so quarterly flow redelivered, Sr,p , is
zero ("0") and will not be included in the equation.
Quarterly C02 concentration will be taken from the gas measurement database SEM will sum to total
Mass of CQ2 Received using equation RR-3 in 98.443
R
CO, = XC°2T,r (Eq. RR-3)
r-l
where:
C02 = Total net annual mass of C02 received (metric tons).
C02T,r = Net annual mass of C02 received (metric tons) as calculated in Equation RR-2 for flow meter r.
r = Receiving flow meter.
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7.2 Mass of C02 Injected into the Subsurface
The equation for calculating the Mass of C02 Injected into the Subsurface at the Rangely Field is equal to
the sum of the Mass of C02 Received as calculated in RR-3 of 98.443 (as described in Section 7.1) and the
Mass of C02 Recycled as calculated using measurements taken from the flow meter located at the output
of the RCF. As previously explained, using data at each injection well would give an inaccurate estimate of
total injection volume due to the large number of wells and the potential for propagation of error due to
allowable calibration ranges for each meter.
The mass of C02 recycled will be determined using equations RR-5 as follows:
C02,u = ]££,, *D *Cco^ CEq. RR-5)
ii=i
where:
C02,u = Annual C02 mass recycled (metric tons) as measured by flow meter u.
Qp,u = Quarterly volumetric flow rate measurement for flow meter u in quarter p at standard conditions
(standard cubic meters per quarter).
D = Density of C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.
C02,p,u = 0O2 concentration measurement in flow for flow meter u in quarter p (vol. percent C02,
expressed as a decimal fraction).
p = Quarter of the year, u = Flow meter.
The total Mass of C02 injected will be the sum of the Mass of C02 received (RR-3) and Mass of C02
recycled (modified RR-5).
C02| = C02 + C02,u
7.3 Mass of C02 Produced
The Mass of C02 Produced at the Rangely Field will be calculated using the measurements from the flow
meters at the inlet to RCF and for C02 entrained in the sales oil, the custody transfer meter for oil sales
rather than the metered data from each production well. Again, using the data at each production well would
give an inaccurate estimate of total injection due to the large number of wells and the potential for
propagation of error due to allowable calibration ranges for each meter.
Equation RR-8 in 98.443 will be used to calculate the mass of C02 produced from all injection wells as
follows:
4
C02lW = £ *D *Ca>? ^ (Eq. RR-8)
P=t
Where:
C02,w = Annual C02 mass produced (metric tons) .
Qp,w = Volumetric gas flow rate measurement for meter w in quarter p at standard conditions (standard
cubic meters).
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D = Density of C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.
CC02,p,w = 0O2 concentration measurement in flow for meter w in quarter p (vol. percent C02,
expressed as a decimal fraction).
p = Quarter of the year, w = inlet meter to RCF.
Equation RR-9 in 98.443 will be used to aggregate the mass of C02 produced net of the mass of C02
entrained in oil leaving the Rangely Field prior to treatment of the remaining gas fraction in RCF as follows:
C02p = Total annual C02 mass produced (metric tons) through all meters in the reporting year.
C02,w = Annual C02 mass produced (metric tons) through meter w in the reporting year.
Xoil = Mass of entrained C02 in oil in the reporting year measured utilizing commercial meters and
electronic flow-measurement devices at each point of custody transfer. The mass of C02 will be calculated
by multiplying the total volumetric rate by the C02 concentration.
7.4 Mass of C02 emitted by Surface Leakage
SEM will calculate and report the total annual Mass of C02 emitted by Surface Leakage using an approach
that relies on 40 CFR Part 98 Subpart W reports for equipment leakage, and tailored calculations for all
other surface leaks. As described in Sections 4 and 5.1.5-5.1.7, SEM is prepared to address the potential
for leakage in a variety of settings. Given the uncertainty concerning the nature and characteristics of leaks
that will be encountered, it is not clear the method for quantifying the volume of leaked C02 that would be
most appropriate. Estimates of the amount of C02 leaked to the surface will depend on a number of site-
specific factors including measurements of flowrate, pressure, size of leak opening, and duration of the
leak. Engineering estimates, and emission factors, depending on the source and nature of the leakage will
also be used.
SEM's process for quantifying leakage will entail using best engineering principles or emission factors.
While it is not possible to predict in advance the types of leaks that will occur, SEM describes some
approaches for quantification in Section 5.1.5-5.1.7. In the event leakage to the surface occurs, SEM would
quantify and report leakage amounts, and retain records that describe the methods used to estimate or
measure the volume leaked as reported in the Annual Subpart RR Report. Further, SEM will reconcile the
Subpart W report and results from any event-driven quantification to assure that surface leaks are not
double counted.
Equation RR-10 in 48.433 will be used to calculate and report the Mass of CQ2 emitted by Surface Leakage:
w
(Eq. RR-9)
Where:
CG2E = XC02.x (Eg - RR-10)
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where:
C02E = Total annual C02 mass emitted by surface leakage (metric tons) in the reporting year.
C02,x = Annual C02 mass emitted (metric tons) at leakage pathway x in the reporting year,
x = Leakage pathway.
7.5 Mass of C02 sequestered in subsurface geologic formations.
SEM will use equation RR-11 in 98.443 to calculate the Mass of C02 Sequestered in Subsurface
Geologic Formations in the Reporting Year as follows:
CO2 = C02j CO2P - CO2E - CO'2pi CO2FP {Eq. RR-11)
where:
C02 = Total annual C02 mass sequestered in subsurface geologic formations (metric tons) at the facility
in the reporting year.
C02| = Total annual C02 mass injected (metric tons) in the well or group of wells covered by this source
category in the reporting year.
C02p = Total annual C02 mass produced (metric tons) net of C02 entrained in oil in the reporting year.
C02e = Total annual C02 mass emitted (metric tons) by surface leakage in the reporting year.
C02FI = Total annual C02 mass emitted (metric tons) from equipment leaks and vented emissions of C02
from equipment located on the surface between the flow meter used to measure injection quantity and the
injection wellhead, for which a calculation procedure is provided in subpart W of this part.
C02FP = Total annual C02 mass emitted (metric tons) from equipment leaks and vented emissions of C02
from equipment located on the surface between the production wellhead and the flow meter used to
measure production quantity, for which a calculation procedure is provided in subpart W of this part.
7.6 Cumulative mass of C02 reported as sequestered in subsurface geologic formations
SEM will sum up the total annual volumes obtained using equation RR-11 in 98.443 to calculate the
Cumulative Mass of C02 Sequestered in Subsurface Geologic Formations.
8. MRV Plan Implementation Schedule
The activities described in this MRV Plan are in place, and reporting is planned to start upon EPA approval.
Other GHG reports are filed on March 31 of the year after the reporting year and it is anticipated that the
Annual Subpart RR Report will be filed at the same time. As described in Section 3.3 above, SEM anticipates
that the MRV program will be in effect during the Specified Period, during which time SEM will operate the
Rangely Field with the subsidiary purpose of establishing long-term containment of a measurable quantity
of C02 in subsurface geological formations at the Rangely Field. SEM anticipates establishing that a
measurable amount of CQ2 injected during the Specified Period will be stored in a manner not expected
35
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to migrate resulting in future surface leakage. At such time, SEM will prepare a demonstration supporting
the long-term containment determination and submit a request to discontinue reporting under this MRV
plan. See 40 C.F.R. § 98.441 (b)(2)(H).
9. Quality Assurance Program
9.1 Monitoring QA/QC
As indicated in Section 7, SEM has incorporated the requirements of §98.444 (a) - (d) in the discussion
of mass balance equations. These include the following provisions.
CQ2 Received and Injected
The quarterly flow rate of C02 received by pipeline is measured at the receiving custody
transfer meters.
The quarterly C02 flow rate for recycled C02 is measured at the flow meter located at the C02
Reinjection facility outlet.
C02 Produced
The point of measurement for the quantity of C02 produced is a flow meter at the C02 Reinjection
facility inlet. . C02 produced as entrained or dissolved C02 in produced oil is calculated using
volumetric flow through the custody transfer meter.
The produced gas stream is sampled at least once per quarter immediately downstream of the flow
meter used to measure flow rate of that gas stream and measure the 0O2 concentration of the
sample.
The quarterly flow rate of the produced gas is measured at the flow meters located at the C02
Reinjection facility inlet.
C02 emissions from equipment leaks and vented emissions of C02
These volumes are measured in conformance with the monitoring and QA/QC requirements
specified in subpart W of 40 CFR Part 98.
Flow meter provisions
The flow meters used to generate date for the mass balance equations in Section 7 are:
Operated continuously except as necessary for maintenance and calibration.
Operated using the calibration and accuracy requirements in 40 CFR §98.3(i).
Operated in conformance with American Petroleum Institute ("API") standards.
National Institute of Standards and Technology ("NIST") traceable.
Concentration of C02
As indicated in Appendix 1, C02 concentration is measured using an appropriate standard method. Further,
all measured volumes of C02 have been converted to standard cubic meters at a temperature of 60
degrees Fahrenheit and at an absolute pressure of 1 atmosphere, including those used in Equations RR-
2, RR-5 and RR-8 in Section 7.
Missing Data Procedures
In the event SEM is unable to collect data needed for the mass balance calculations, procedures
for estimating missing data in §98.445 will be used as follows:
36
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A quarterly flow rate of C02 received that is missing would be estimated using invoices or using a
representative flow rate value from the nearest previous time period.
A quarterly C02 concentration of a C02 stream received that is missing would be estimated using
invoices or using a representative concentration value from the nearest previous time period.
A quarterly quantity of C02 injected that is missing would be estimated using a representative quantity
of C02injected from the nearest previous period of time at a similar injection pressure.
For any values associated with C02 emissions from equipment leaks and vented emissions of C02
from surface equipment at the facility that are reported in this subpart, missing data estimation
procedures specified in subpart Wof 40 CFR Part 98 would be followed.
The quarterly quantity of C02 produced from subsurface geologic formations that is missing would be
estimated using a representative quantity of C02 produced from the nearest previous period of time.
9.3 MRV Plan Revisions
In the event there is a material change to the monitoring and/or operational parameters of the SEM C02
EOR operations in the Rangely Field that is not anticipated in this MRV plan, the MRV plan will be revised
and submitted to the EPA Administrator within 180 days as required in §98.448(d).
10. Records Retention
SEM will follow the record retention requirements specified by §98.3(g). In addition, it will follow the
requirements in Subpart RR §98.447 by maintaining the following records for at least three years:
Quarterly records of C02 received at standard conditions and operating conditions, operating
temperature and pressure, and concentration of these streams.
Quarterly records of produced C02, including volumetric flow at standard conditions and operating
conditions, operating temperature and pressure, and concentration of these streams.
Quarterly records of injected C02 including volumetric flow at standard conditions and operating
conditions, operating temperature and pressure, and concentration of these streams.
Annual records of information used to calculate the C02 emitted by surface leakage from leakage
pathways.
Annual records of information used to calculate the C02 emitted from equipment leaks and vented
emissions of C02 from equipment located on the surface between the flow meter used to measure
injection quantity and the injection wellhead.
Annual records of information used to calculate the C02 emitted from equipment leaks and vented
emissions of C02 from equipment located on the surface between the production wellhead and the
flow meter used to measure production quantity.
These data will be collected as generated and aggregated as required for reporting purposes.
11. Appendices
37
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Appendix 1. Conversion Factors
SEM reports C02 volumes at standard conditions of temperature and pressure as defined in the State of
Colorado, which follows the international standard conditions for measuring C02 properties - 77 °F and
14.696 psi.
To convert these volumes into metric tonnes, a density is calculated using the Span and Wagner equation
of state as recommended by the EPA. Density was calculated using the database of thermodynamic
properties developed by the National Institute of Standards and Technology (NIST), available at
http://webbook.nist.gov/chemistrv/fluid/.
At EPA standard conditions of 77 °F and one atmosphere, the Span and Wagner equation of state gives a
density of 0.0026500 lb-moles per cubic foot. Using a molecular weight for C02 of 44.0095, 2204.62
lbs/metric ton and 35.314667 ft3/m3, gives a C02 density of 5.29003 x 10"5 MT/ft3 or 0.0018682 MT/m3.
The conversion factor 5.29003 x 10 5 MT/Mcf has been used throughout to convert SEM volumes to metric
tons.
38
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Appendix 2. Acronyms
AGA - American Gas Association
AMA - Active Monitoring Area
AoR - Area of Review
API-American Petroleum Institute
BCF - billion standard cubic feet
bopd - barrels of oil per day cf - cubic feet
CCR - Code of Colorado Regulations
COGCC - Colorado Oil and Gas Conservation Commission
C02 - Carbon Dioxide
CRF - C02 Removal Facilities
EOR - Enhanced Oil Recovery
EPA - US Environmental Protection Agency
GHG - Greenhouse Gas
GHGRP - Greenhouse Gas Reporting Program
H2S - Hydrogen Sulfide
IWR - Injection to Withdrawal Ratio
LACT - Lease Automatic Custody Transfer meter
MIT - Mechanical Integrity Test
MMA - Maximum Monitoring Area
MMB - Million barrels
Mscf- Thousand standard cubic feet
MMscf- Million standard cubic feet
MMMT - Million metric tonnes
MMT -Thousand metric tonnes
MRV- Monitoring, Reporting, and Verification
MOC - Main oil column
MT - Metric Tonne
NGNatural Gas
NGLs - Natural Gas Liquids
NIST - National Institute of Standards and Technology
OOIP - Original Oil-ln-Place
OH - Open hole
POWC - Producible oil/water contact
PPM - Parts Per Million
RCF - Rangely Field C02 Recycling and Compression Facility
RRPC - Raven Ridge pipeline
RWSU - Rangely Weber Sand Unit
SCADA - Supervisory Control and Data Acquisition
SEM - Scout Energy Management, LLC
UIC - Underground Injection Control
VRU - Vapor Recovery Unit
WAG - Water Alternating Gas
XOM - ExxonMobil
39
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Appendix 3. References
Adams, L., 2006; Sequence and Mechanical Stratigraphy: An intergrated Reservoir Characterization of
the Weber Sandstone, Western Colorado. University of Texas at El Paso Ph.D. Dissertation.
Colorado Administrative Code Department 400 Division 404 Oil and Gas Conservation Commission
Section 2
Clark, Rory, Chevron North America E&P, Presentation to 6th Annual Wyoming C02 Conference, July 12,
2012, online: //www.uwyo.edu/eori/_files/C02conference12/rory_rangelycasehistory.pdf
Energy and Carbon Management Regulation in Colorado. May 22, 2023, online:
https://leg.colorado.gov/bills/sb23-285
US Department of Energy, National Energy Technology Laboratory. "Carbon Dioxide Enhanced Oil
Recovery - Untapped Domestic Energy Supply and Long Term Carbon Storage Solution," March 2010.
US Department of Energy, National Energy Technology Laboratory. "Carbon Sequestration Through
Enhanced Oil Recovery," April 2008.
Gale, Hoyt. Geology of the Rangely Oil District. Department of Interior United States Geological Survey,
Bulletin 350. 1908.
40
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Appendix 4. Glossary of Terms
This glossary describes some of the technical terms as they are used in this MRV plan. For additional
glossaries please see the U.S. EPA Glossary of UIC Terms
(http://water.epa.gov/tvpe/qroundwater/uic/qlossarv.cfm') and the Schlumberger Oilfield Glossary
(http://www.glossary.oilfield.slb.com/).
Contain / Containment - having the effect of keeping fluids located within in a specified portion of a geologic
formation.
Dip-Very few, if any, geologic features are perfectly horizontal. They are almost always tilted. The direction
of tilt is called "dip." Dip is the angle of steepest descent measured from the horizontal plane. Moving higher
up structure is moving "updip." Moving lower is "downdip." Perpendicular to dip is "strike." Moving
perpendicular along a constant depth is moving along strike.
Downdip - See "dip."
Formation - A body of rock that is sufficiently distinctive and continuous that it can be mapped.
Infill Drilling - The drilling of additional wells within existing patterns. These additional wells decrease
average well spacing. This practice both accelerates expected recovery and increases estimated ultimate
recovery in heterogeneous reservoirs by improving the continuity between injectors and producers. As well
spacing is decreased, the shifting flow paths lead to increased sweep to areas where greater hydrocarbon
saturations remain.
Permeability - Permeability is the measure of a rock's ability to transmit fluids. Rocks that transmit fluids
readily, such as sandstones, are described as permeable and tend to have many large, well-connected
pores. Impermeable formations, such as shales and siltstones, tend to be finer grained or of a mixed grain
size, with smaller, fewer, or less interconnected pores.
Phase - Phase is a region of space throughout which all physical properties of a material are essentially
uniform. Fluids that don't mix together segregate themselves into phases. Oil, for example, does not mix
with water and forms a separate phase.
Pore Space - See porosity.
Porosity - Porosity is the fraction of a rock that is not occupied by solid grains or minerals. Almost all rocks
have spaces between rock crystals or grains that is available to be filled with a fluid, such as water, oil or
gas. This space is called "pore space."
Saturation - The fraction of pore space occupied by a given fluid. Oil saturation, for example, is the fraction
of pore space occupied by oil.
Seal - A geologic layer (or multiple layers) of impermeable rock that serve as a barrier to prevent fluids
from moving upwards to the surface.
Secondary recovery - The second stage of hydrocarbon production during which an external fluid such as
water or gas is injected into the reservoir through injection wells located in rock that has fluid communication
with production wells. The purpose of secondary recovery is to maintain reservoir pressure and to displace
hydrocarbons toward the wellbore. The most common secondary recovery techniques are gas injection and
waterflooding.
Stratigraphic section - A stratigraphic section is a sequence of layers of rocks in the order they were
deposited.
41
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Strike - See "dip.
Updip - See "dip.
-------
Appendix 5. Well Identification Numbers
The following table presents the well name, API number, status and type for the wells in the RWSU as of
April 2023. The table is subject to change overtime as new wells are drilled, existing wells change status,
or existing wells are repurposed. The following terms are used:
Well Status
Producing refers to a well that is actively producing
Injecting refers to a well that is actively injecting
P&A refers to wells that have been closed (plugged and abandoned) per COGCC regulations
Shut In refers to wells that have been temporarily idled or shut-in
Monitor refers to a well that is used to monitor bottom home pressure in the reservoir
Well Type
Water / Gas Inject refers to wells that inject water and C02 Gas
Water Injection Well refers to wells that inject water
Oil well refers to wells that produce oil
Salt Water Disposal refers to a well used to dispose of excess water
Name
API Number
Well Type
Well Status
A C MCLAUGHLIN 46
51030632300
Water Injection Well
P&A
AC MCLAUGHLIN 64X
51030771700
Oil well
Producing
ASSOCIATED A 2
51030571400
Water / Gas Inject
P&A
ASSOCIATED A1
51030571300
Oil well
Producing
ASSOCIATED A2ST
51030571401
Water / Gas Inject
Injecting
ASSOCIATED A3X
51030778600
Oil well
Producing
ASSOCIATED A4X
51030791600
Oil well
Producing
ASSOCIATED A5X
51030803400
Water / Gas Inject
Injecting
ASSOCIATED A6X
51030801100
Water / Gas Inject
Injecting
ASSOCIATED LARSON UNIT A1
51030600900
Oil well
Producing
ASSOCIATED LARSON UNIT A2X
51030881500
Oil well
Producing
ASSOCIATED LARSON UNIT B1
51030601100
Oil well
Producing
ASSOCIATED LARSON UNIT B2X
51030950200
Oil well
Producing
ASSOCIATED UNIT A1
51030602600
Oil well
Producing
ASSOCIATED UNIT A2X UN A-2X
51031053200
Oil well
Producing
ASSOCIATED UNIT A3X
51031072300
Oil well
Producing
ASSOCIATED UNIT A4X
51031072200
Water / Gas Inject
Injecting
ASSOCIATED UNIT C1
51030582700
Oil well
Producing
BEEZLEY 1X22AX
51031075400
Water / Gas Inject
Injecting
BEEZLEY 2-22
51030574200
Oil well
Producing
BEEZLEY 3X 3X22
51031054900
Oil well
Producing
BEEZLEY 4X 22
51031055300
Oil well
Producing
BEEZLEY 5X22
51031174200
Oil well
Producing
BEEZLEY 6X22
51031174300
Oil well
Producing
43
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CARNEY 22X-35
51030724500
Oil well
P&A
CARNEY CT 10-4
51030608600
Oil well
Monitor
CARNEY CT 11-4
51030545700
Oil well
Monitor
CARNEY CT12AX5
51030917600
Water / Gas Inject
Monitor
CARNEY CT 13-4
51030545900
Oil well
Producing
CARNEY CT 1-34
51030548200
Oil well
Producing
CARNEY CT 14-34
51030103500
Oil well
Producing
CARNEY CT 15-35
51030103700
Water / Gas Inject
Injecting
CARNEY CT 16-35
51030103300
Water / Gas Inject
Monitor
CARNEY CT 17-35
51030103200
Oil well
Producing
CARNEY CT 18-35
51030629500
Water / Gas Inject
Injecting
CARNEY CT 19-34
51030604400
Oil well
Producing
CARNEY CT 20X35
51030641300
Oil well
Producing
CARNEY CT 21X35
51030703300
Water / Gas Inject
Injecting
CARNEY CT 22X35ST
51030724501
Oil well
Producing
CARNEY CT 2-34
51030551400
Oil well
Monitor
CARNEY CT 23X35
51030726200
Water / Gas Inject
Injecting
CARNEY CT 24X35
51030728300
Water / Gas Inject
Monitor
CARNEY CT 27X34
51030746600
Water / Gas Inject
Injecting
CARNEY CT 28X
51030747400
Water / Gas Inject
Monitor
CARNEY CT 29X
51030753700
Water / Gas Inject
Injecting
CARNEY CT 30X34 30X
51030752600
Water / Gas Inject
Injecting
CARNEY CT 32X34
51030758900
Water / Gas Inject
Injecting
CARNEY CT 3-34
51030103900
Oil well
Producing
CARNEY CT 33X34
51030759200
Water / Gas Inject
Injecting
CARNEY CT 35X34
51030759300
Water / Gas Inject
Injecting
CARNEY CT 37X4
51030856300
Oil well
Producing
CARNEY CT 38X4
51030881300
Water / Gas Inject
Monitor
CARNEY CT 39X4
51030881400
Oil well
Producing
CARNEY CT 41Y34
51030914900
Oil well
Monitor
CARNEY CT 4-34
51030555900
Oil well
Producing
CARNEY CT 43Y34
51030914800
Oil well
Monitor
CARNEY CT 44Y34
51030915300
Oil well
Monitor
CARNEY CT 5-34
51030103800
Oil well
Producing
CARNEY CT 6-5
51030609100
Water / Gas Inject
Monitor
CARNEY CT 7-35
51030629300
Oil well
Producing
CARNEY CT 8-34
51030104000
Oil well
Producing
CARNEY CT 9-35
51030548600
Water / Gas Inject
Monitor
CARNEY UNIT 1
51030608700
Oil well
Producing
CARNEY UN IT 2X
51030719100
Water / Gas Inject
Injecting
COLTHARPJE 10X
51030869400
Oil well
Producing
44
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COLTHARP JE 2
51030602300
Water / Gas Inject
Monitor
COLTHARP JE 4
51030602200
Water / Gas Inject
Monitor
COLTHARP JE 5X
51030705700
Oil well
Producing
COLTHARP JE 7X
51030727900
Oil well
Producing
COLTHARP JE 8X
51030734300
Oil well
Producing
COLTHARP WH A1
51030601900
Water / Gas Inject
Injecting
COLTHARP WH A3
51030602100
Water / Gas Inject
Monitor
COLTHARP WH A4
51030102800
Water / Gas Inject
Injecting
COLTHARP WH A5X
51030725000
Oil well
Producing
COLTHARP WH A6X
51030744700
Oil well
Producing
COLTHARP WH A8X
51030909900
Oil well
Producing
COLTHARP WH B2X
51030859400
Oil well
Monitor
COLTHARP WH B3X
51030879300
Oil well
Shut In
COLTHARP WH C1
51030107700
Water / Gas Inject
Monitor
COLTHARP WH C2X
51030919800
Oil well
Producing
CT CARNEY 25X34
51030741500
Water / Gas Inject
Injecting
EMERALD 10
51030566200
Oil well
Producing
EMERALD 11
51030567100
Oil well
Producing
EMERALD13ST
51030563601
Water / Gas Inject
Injecting
EMERALD 14
51030556500
Water / Gas Inject
Injecting
EMERALD 16
51030625300
Oil well
Monitor
EMERALD 17
51030567700
Water / Gas Inject
Injecting
EMERALD 18AX
51030920200
Oil well
Producing
EMERALD 19
51030624000
Oil well
Producing
EMERALD 2
51030566900
Oil well
Producing
EMERALD 20
51030555800
Water / Gas Inject
Injecting
EMERALD 22
51030625400
Water / Gas Inject
Injecting
EMERALD 23
51030558900
Water / Gas Inject
Injecting
EMERALD 25
51030548100
Water / Gas Inject
Injecting
EMERALD 26
51030624200
Water / Gas Inject
Injecting
EMERALD 27
51030565300
Oil well
Producing
EMERALD 28
51030562800
Water / Gas Inject
Injecting
EMERALD 29AX
51030924500
Water / Gas Inject
Injecting
EMERALD 30AX
51030920300
Water / Gas Inject
Injecting
EMERALD 31 AX
51030923600
Water / Gas Inject
Injecting
EMERALD 32
51030623800
Oil well
Producing
EMERALD 33AX
51030923900
Water / Gas Inject
Injecting
EMERALD 34
51030559500
Water / Gas Inject
Injecting
EMERALD 35
51030559400
Water / Gas Inject
Injecting
EMERALD 36
51030548800
Water / Gas Inject
Injecting
EMERALD 37
51030551200
Water / Gas Inject
Injecting
45
-------
EMERALD 38
51030624900
Water / Gas Inject
Injecting
EMERALD 39
51030625100
Water / Gas Inject
Injecting
EMERALD 3ST
51030559901
Water / Gas Inject
Injecting
EMERALD 3ST3
51030559900
Water / Gas Inject
P&A
EMERALD 4
51030550500
Oil well
Producing
EMERALD 40
51030625000
Water / Gas Inject
Injecting
EMERALD 41
51030546300
Water / Gas Inject
Monitor
EMERALD 42D
51030634000
Salt Water Disposal
Injecting
EMERALD 44AX
51030918700
Water / Gas Inject
Injecting
EMERALD 46X
51030713000
Oil well
Producing
EMERALD 47X
51030720100
Oil well
Producing
EMERALD 48X
51030725700
Oil well
Monitor
EMERALD 49AX
51031068000
Oil well
Producing
EMERALD 50X
51030733100
Oil well
Producing
EMERALD 51X
51030733300
Oil well
Producing
EMERALD 52X
51030737100
Oil well
Producing
EMERALD 53X
51030737600
Oil well
Producing
EMERALD 54X
51030763700
Oil well
Producing
EMERALD 55X
51030763800
Oil well
Producing
EMERALD 56X
51030768700
Oil well
Producing
EMERALD 57XST
51030764901
Oil well
Producing
EMERALD 58X
51030773900
Oil well
Producing
EMERALD 59X
51030774000
Oil well
Producing
EMERALD 6
51030558800
Water / Gas Inject
Injecting
EMERALD 60X
51030779800
Oil well
Producing
EMERALD 61X
51030780300
Oil well
Producing
EMERALD 62X
51030781100
Oil well
Producing
EMERALD 63ST
51030804101
Water / Gas Inject
Injecting
EMERALD 63XST
51030804100
Water / Gas Inject
P&A
EMERALD 64X
51030799200
Water / Gas Inject
Injecting
EMERALD 65X
51030794800
Oil well
Producing
EMERALD 66X
51030786800
Oil well
Producing
EMERALD 67X
51030797400
Oil well
Producing
EMERALD 68X
51030797500
Oil well
Producing
EMERALD 69X
51030810300
Water / Gas Inject
Injecting
EMERALD 70X
51030807200
Water / Gas Inject
Injecting
EMERALD 71X
51030804600
Water / Gas Inject
Injecting
EMERALD 72X
51030810400
Water / Gas Inject
Monitor
EMERALD 73X
51030810500
Oil well
Monitor
EMERALD 74X
51030816900
Oil well
Producing
EMERALD 75X
51030843700
Oil well
Producing
46
-------
EMERALD 76X
51030848100
Oil well
Producing
EMERALD 77X
51030848000
Oil well
Producing
EMERALD 78X
51030849100
Oil well
Producing
EMERALD 79X
51030895500
Salt Water Disposal
Injecting
EMERALD 7 A
51030928500
Water / Gas Inject
Injecting
EMERALD 8
51030559000
Water / Gas Inject
P&A
EMERALD 80X
51030876900
Oil well
Producing
EMERALD 81X
51030888300
Oil well
Producing
EMERALD 82X
51030849200
Water / Gas Inject
Injecting
EMERALD 83X
51030876500
Oil well
Producing
EMERALD 84X
51030888500
Oil well
Producing
EMERALD 85X
51030877000
Oil well
Producing
EMERALD 86X
51030877200
Oil well
Producing
EMERALD 87X
51030877300
Oil well
Monitor
EMERALD 88X
51030876600
Oil well
Producing
EMERALD 89X
51030877100
Oil well
Producing
EMERALD 8ST
51030559001
Water / Gas Inject
Injecting
EMERALD 90X
51030914600
Water / Gas Inject
Injecting
EMERALD 91Y
51030914700
Water / Gas Inject
Injecting
EMERALD 92X
51030929500
Oil well
Producing
EMERALD 93X
51031185800
Oil well
Producing
EMERALD 94X
51031185500
Oil well
Producing
EMERALD 95X
51031191400
Oil well
Producing
EMERALD 96X
51031192200
Oil well
Producing
EMERALD 97X
51031191300
Oil well
Producing
EMERALD 98X
51031191500
Water / Gas Inject
Injecting
EMERALD 9ST
51030566101
Water / Gas Inject
Injecting
EMERALD 9ST9
51030566100
Water / Gas Inject
P&A
FAIRFIELD KITTI A 4
51031101700
Oil well
P&A
FAIRFIELD KITTI A 5P
51031101000
Oil well
P&A
FAIRFIELD KITTI A1
51030611100
Water / Gas Inject
Injecting
FAIRFIELD KITTI A4
51031101701
Oil well
Producing
FAIRFIELD KITTI A5
51031101001
Oil well
Producing
FAIRFIELD KITTI B1
51030107800
Water / Gas Inject
Injecting
FE156X
51031033600
Oil well
Producing
FEE 1
51030563400
Oil well
Producing
FEE 1 162Y
51031194500
Water / Gas Inject
Injecting
FEE 10
51030566800
Water / Gas Inject
Injecting
FEE 100X
51030786900
Oil well
Producing
FEE 101X
51030787000
Oil well
Producing
FEE 102X
51030787700
Oil well
Producing
47
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FEE 103X
51030788500
Oil well
Monitor
FEE 104X
51030785700
Oil well
Producing
FEE 105X
51030785800
Oil well
Producing
FEE 106X
51030794600
Water / Gas Inject
Injecting
FEE 107X
51030803200
Water / Gas Inject
Injecting
FEE 108X
51030795200
Oil well
Producing
FEE 109X
51030798900
Water / Gas Inject
Injecting
FEE 11
51030559600
Oil well
Producing
FEE 11 OX
51030802600
Water / Gas Inject
Injecting
FEE 111X
51030802700
Water / Gas Inject
Monitor
FEE 112X
51030802800
Water / Gas Inject
Injecting
FEE 113X
51030802900
Water / Gas Inject
Injecting
FEE 114X
51030803100
Water / Gas Inject
Injecting
FEE 115X
51030803300
Water / Gas Inject
Injecting
FEE 116X
51030829900
Water / Gas Inject
Injecting
FEE 117X
51030843800
Oil well
Producing
FEE 118AX
51030928300
Oil well
Monitor
FEE 12
51030565100
Oil well
Producing
FEE 121X
51030857500
Oil well
Producing
FEE 122X
51030866300
Water / Gas Inject
Injecting
FEE 124X
51030866400
Oil well
Producing
FEE 125X
51030868100
Oil well
Monitor
FEE 126X
51030868600
Oil well
Producing
FEE 127X
51030868700
Water / Gas Inject
Injecting
FEE 128X
51030868800
Oil well
Monitor
FEE 129X
51030868900
Oil well
Producing
FEE 13
51030622600
Oil well
Producing
FEE 130X
51030870400
Oil well
Monitor
FEE 133X
51030888400
Oil well
Producing
FEE 135X
51030876000
Oil well
Monitor
FEE 136X
51030874500
Water / Gas Inject
Injecting
FEE 137X
51030876100
Water / Gas Inject
Injecting
FEE 138X
51030876300
Oil well
Producing
FEE 139X
51030876200
Oil well
Producing
FEE 14
51030568700
Oil well
Producing
FEE 140Y
51030910600
Oil well
Monitor
FEE 141X
51030913300
Water / Gas Inject
Injecting
FEE 142X
51030913100
Oil well
Producing
FEE 143X
51030913000
Oil well
Producing
FEE 144Y
51030917500
Oil well
Shut In
FEE 145Y
51030917400
Oil well
Producing
48
-------
FEE 146X
51030946400
Oil well
Producing
FEE 15
51030556800
Oil well
Producing
FEE 153X
51030929700
Oil well
Producing
Fee154X
51031036500
Oil well
Producing
Fee155X
51031037300
Oil well
Producing
FEE 157X
51031101900
Oil well
Monitor
FEE 158 X
51031115900
Oil well
Producing
FEE 159 X
51031101100
Oil well
Producing
FEE 160X
51031186600
Oil well
Producing
FEE 163X
51031195100
Oil well
Producing
FEE16AX
51030923500
Water / Gas Inject
Monitor
FEE 17
51030580100
Water / Gas Inject
Injecting
FEE 18
51030623600
Water / Gas Inject
Monitor
FEE 19
51030622400
Oil well
Producing
FEE 1AX
51030924400
Water / Gas Inject
Monitor
FEE 20
51030616800
Oil well
Producing
FEE 21
51030620700
Oil well
Producing
FEE 22
51030616100
Water / Gas Inject
Injecting
FEE 23
51030615600
Oil well
Producing
FEE 24
51030611200
Water / Gas Inject
Injecting
FEE 25
51030614500
Oil well
Producing
FEE 26
51030615200
Oil well
Producing
FEE 27
51030617500
Oil well
Producing
FEE 28
51030613500
Water / Gas Inject
Injecting
FEE 29
51030614400
Water / Gas Inject
Injecting
FEE 2AX
51030924700
Water / Gas Inject
Injecting
FEE 3
51030565700
Oil well
Producing
FEE 30
51030621100
Water / Gas Inject
Monitor
FEE 31
51030611800
Water / Gas Inject
Injecting
FEE 32
51030614200
Oil well
Producing
FEE 33
51030614700
Oil well
Producing
FEE 34
51030624500
Oil well
Producing
FEE 35
51030611300
Oil well
Producing
FEE 36
51030617600
Oil well
Producing
FEE 37
51030611500
Water / Gas Inject
Injecting
FEE 38
51030625500
Water / Gas Inject
Injecting
FEE 39
51030623300
Water / Gas Inject
Injecting
FEE 4
51030576900
Oil well
Monitor
FEE 40
51030622300
Water / Gas Inject
Injecting
FEE 41
51030622200
Water / Gas Inject
Monitor
FEE 42
51030568800
Water / Gas Inject
Monitor
49
-------
FEE 43
51030614100
Water / Gas Inject
Injecting
FEE 44
51030624700
Water / Gas Inject
Injecting
FEE 45
51030617900
Oil well
Producing
FEE 47
51030616000
Water / Gas Inject
Injecting
FEE 48
51030625900
Water / Gas Inject
Injecting
FEE 49
51030611900
Water / Gas Inject
Injecting
FEE 5
51030574500
Oil well
Producing
FEE 51
51030614900
Water / Gas Inject
Injecting
FEE 52
51030567400
Water / Gas Inject
Injecting
FEE 53AX
51030861200
Water / Gas Inject
Injecting
FEE 55
51030615300
Water / Gas Inject
Injecting
FEE 56
51030615700
Water / Gas Inject
Injecting
FEE 58AX
51030924300
Water / Gas Inject
Injecting
FEE 59
51030616900
Water / Gas Inject
Injecting
FEE 6
51030572000
Oil well
Producing
FEE 60
51030622500
Water / Gas Inject
Injecting
FEE 61
51030620300
Oil well
Producing
FEE 62
51030614000
Oil well
Monitor
FEE 63
51030614600
Water / Gas Inject
Injecting
FEE 64
51030614800
Water / Gas Inject
Injecting
FEE 65
51030615000
Water / Gas Inject
Injecting
FEE 67A
51030929300
Water / Gas Inject
Injecting
FEE 68A
51030568300
Oil well
Producing
FEE 69
51030625600
Water / Gas Inject
Monitor
FEE 7
51030571600
Oil well
Producing
FEE 70AX
51030919100
Water / Gas Inject
Monitor
FEE 72X
51030718000
Oil well
Producing
FEE 73X
51030727400
Oil well
Producing
FEE 74X
51030730700
Oil well
Producing
FEE 75X
51030732600
Oil well
Producing
FEE 76X
51030733900
Oil well
Producing
FEE 78X
51030743400
Oil well
Producing
FEE 79X
51030742400
Water / Gas Inject
Injecting
FEE 8
51030563300
Water / Gas Inject
Injecting
FEE 80X
51030749100
Water / Gas Inject
Injecting
FEE 81X
51030751900
Oil well
Producing
FEE 82X
51030752900
Oil well
Producing
FEE 83X
51030757200
Oil well
Producing
FEE 84X
51030755400
Water / Gas Inject
Injecting
FEE 85X
51030758100
Water / Gas Inject
Injecting
FEE 86X
51030756900
Water Injection Well
P&A
50
-------
FEE 86XST
51030756901
Water / Gas Inject
Injecting
FEE 87X
51030754600
Water / Gas Inject
Monitor
FEE 88X
51030755900
Water / Gas Inject
Injecting
FEE 89X
51030755500
Water / Gas Inject
Injecting
FEE 9
51030551100
Oil well
P&A
FEE 90X
51030758000
Water / Gas Inject
Injecting
FEE 91X
51030757300
Water / Gas Inject
Injecting
FEE 92X
51030755600
Water / Gas Inject
Monitor
FEE 93X
51030759100
Water / Gas Inject
Injecting
FEE 94X
51030759400
Water / Gas Inject
Injecting
FEE 95X
51030764700
Oil well
Producing
FEE 96X
51030764800
Oil well
Producing
FEE 97X
51030779100
Oil well
Producing
FEE 98X
51030782700
Water / Gas Inject
Injecting
FEE 99X
51030784000
Oil well
Producing
FEE 9ST 9
51030551101
Oil well
Producing
GRAY A A17X
51030768900
Water / Gas Inject
Injecting
GRAY A A21X
51030830200
Water / Gas Inject
Injecting
GRAY A A8AX
51030919700
Water / Gas Inject
Injecting
GRAY A10
51030573400
Water / Gas Inject
Injecting
GRAY A12
51030613700
Oil well
Producing
GRAY A13
51030577800
Water / Gas Inject
Monitor
GRAY A14
51030613900
Oil well
Producing
GRAY A15
51030576200
Oil well
Producing
GRAY A16
51030613600
Water / Gas Inject
Injecting
GRAY A18X
51030789800
Oil well
Producing
GRAY A19X
51030787300
Oil well
Producing
GRAY A20X
51030803500
Water / Gas Inject
Injecting
GRAY A22X
51030831700
Oil well
Producing
GRAY A9
51030571500
Oil well
Producing
GRAY B10
51030612300
Water / Gas Inject
Injecting
GRAY B11
51030581800
Oil well
Producing
GRAY B12
51030612900
Oil well
Producing
GRAY B13
51030612600
Oil well
Producing
GRAY B14A
51030928900
Water / Gas Inject
Injecting
GRAY B15
51030579600
Oil well
Producing
GRAY B16
51030612700
Oil well
Producing
GRAY B17
51030582500
Oil well
Monitor
GRAY B18X
51030638600
Oil well
Monitor
GRAY B19X
51036639700
Oil well
Producing
GRAY B2
51030578700
Oil well
Producing
51
-------
GRAY B20X
51030101500
Water / Gas Inject
Injecting
GRAY B21X
51031035700
Oil well
Producing
GRAY B22X
51031036000
Oil well
Producing
GRAY B23X
51031033800
Oil well
Producing
GRAY B24X
51031033700
Oil well
Producing
GRAY B25X
51031057200
Oil well
Producing
GRAY B26X
51031057500
Oil well
Producing
GRAY B27X
51031057400
Oil well
Producing
GRAY B28X
51031101200
Oil well
Producing
GRAY B3
51030613200
Water / Gas Inject
Injecting
GRAY B4
51030613300
Water / Gas Inject
Injecting
GRAY B5
51030612400
Water / Gas Inject
Injecting
GRAY B6
51030613100
Water / Gas Inject
Injecting
GRAY B7
51030612800
Water / Gas Inject
Injecting
GRAY B8
51030581100
Water / Gas Inject
Injecting
GRAY B9
51030612500
Water / Gas Inject
Injecting
GUIBERSON SA 1
51030581300
Water / Gas Inject
Injecting
GUIBERSON SA 5 X
51031115600
Oil well
Producing
HAGOOD L N-A 17X
51030914200
Oil well
P&A
HAGOOD LN A10X
51030791300
Oil well
Shut In
HAGOOD LN A11X
51030794900
Water / Gas Inject
Injecting
HAGOOD LN A12X
51030793600
Oil well
Producing
HAGOOD LN A13X
51030799100
Water / Gas Inject
Injecting
HAGOOD LN A14X
51030795000
Water / Gas Inject
P&A
HAGOOD LN A14XST
51030795001
Water / Gas Inject
Injecting
HAGOOD LN A15X
51030829300
Oil well
Producing
HAGOOD LN A16X
51030830000
Water / Gas Inject
Injecting
HAGOOD LN A17XST
51030914201
Water / Gas Inject
Monitor
HAGOOD LN A2
51030574300
Oil well
Monitor
HAGOOD LN A3
51030576800
Oil well
Monitor
HAGOOD LN A5
51030573600
Water / Gas Inject
Injecting
HAGOOD LN A7
51030575700
Water / Gas Inject
Monitor
HAGOOD LN A9X
51030702200
Water / Gas Inject
Injecting
HAGOOD MC A1
51030632800
Water / Gas Inject
Injecting
HAGOOD MC A10X
51031041400
Oil well
Producing
HAGOOD MC A11X
51031041300
Oil well
Producing
HAGOOD MC A12X
51031053300
Oil well
Producing
HAGOOD MC A13X
51031053100
Oil well
Producing
HAGOOD MC A14X
51031054800
Oil well
Shut In
HAGOOD MC A15X
51031062800
Oil well
Producing
HAGOOD MC A16X
51031061200
Oil well
Producing
52
-------
HAGOOD MC A17X
51031062900
Oil well
Producing
HAGOOD MC A18X
51031061300
Oil well
Producing
HAGOOD MC A19X
51031067000
Water / Gas Inject
Injecting
HAGOOD MC A2
51030102300
Oil well
Producing
HAGOOD MC A21X
51031070900
Oil well
Producing
HAGOOD MC A3
51030633000
Water / Gas Inject
Injecting
HAGOOD MC A4
51030632600
Water / Gas Inject
Injecting
HAGOOD MC A5
51030633100
Water / Gas Inject
Injecting
HAGOOD MC A6
51030102400
Oil well
Producing
HAGOOD MC A7
51030106700
Oil well
Producing
HAGOOD MC A8 A 8
51030632500
Water / Gas Inject
Injecting
HAGOOD MC A9
51030632700
Water / Gas Inject
Injecting
HAGOOD MC B1A
51031102800
Oil well
Producing
HAGOOD MC B2
51031187000
Oil well
Producing
HEFLEY CS 4X
51030856200
Oil well
Producing
HEFLEY ME 2
51030545200
Water / Gas Inject
Monitor
HEFLEY ME 5X
51030719600
Oil well
Producing
HEFLEY ME 6X
51030729300
Oil well
Producing
HEFLEY ME 7X
51030873700
Oil well
Producing
HEFLEY ME 8X
51030869600
Oil well
Producing
L N HAGOOD A- 1
51030572100
Water / Gas Inject
Injecting
L N HAGOOD A-8 IJ A8
51030569100
Water / Gas Inject
Injecting
LACY SB 1
51030573200
Oil well
Producing
LACY SB 11Y
51030914400
Salt Water Disposal
Injecting
LACY SB 12Y
51030914500
Oil well
Producing
LACY SB 13Y
51031057000
Oil well
Producing
LACY SB 2AX
51030928200
Water / Gas Inject
Injecting
LACY SB 3
51030568900
Oil well
Producing
LACY SB 4
51030575800
Water / Gas Inject
Monitor
LACY SB 6X
51030794700
Oil well
Monitor
LACY SB 7X
51030797800
Water / Gas Inject
Injecting
LACY SB 9X
51030831800
Oil well
Monitor
LARSON FA 1
51030106600
Oil well
Producing
LARSON FA 2
51030107200
Water / Gas Inject
Injecting
LARSON FA 3X
51031071000
Oil well
Monitor
LARSON FV A1
51030547600
Oil well
Producing
LARSON FV A2X
51030721600
Water / Gas Inject
Monitor
LARSON FV B11
51030630200
Water / Gas Inject
Injecting
LARSON FV B12
51030100900
Oil well
Producing
LARSON FV B14X
51030641400
Oil well
Shut In
LARSON FV B15X
51030700800
Oil well
Producing
53
-------
LARSON FV B17X
51030707800
Oil well
Producing
LARSON FV B18X
51030708300
Oil well
Producing
LARSON FV B19X
51030710600
Oil well
Producing
LARSON FV B2
51030620200
Water / Gas Inject
Monitor
LARSON FV B20X
51030709900
Oil well
Producing
LARSON FVB21X
51030716500
Oil well
Producing
LARSON FV B22X
51030722700
Oil well
Producing
LARSON FV B23X
51030724200
Oil well
Producing
LARSON FV B24X
51030873800
Oil well
Producing
LARSON FV B25X
51030916500
Oil well
Producing
LARSON FV B27X
51030948800
Oil well
Producing
LARSON FV B4
51030629800
Water / Gas Inject
Injecting
LARSON FV B8
51030620100
Water / Gas Inject
Injecting
LARSON MB 10X25
51030715900
Oil well
Producing
LARSON MB 12X25
51030727000
Oil well
Producing
LARSON MB 2-26 A226
51030566300
Oil well
Producing
LARSON MB 3X26
51030711000
Oil well
Producing
LARSON MB 4X26
51030717700
Oil well
Monitor
LARSON MB 8X25
51030709300
Oil well
Producing
LARSON MB A1AX
51031075600
Water / Gas Inject
Monitor
LARSON MB A2
51030633200
Oil well
Producing
LARSON MB A3X
51031053400
Oil well
Producing
LARSON MB A4X
51031055200
Oil well
Producing
LARSON MB B1
51030576500
Water / Gas Inject
Injecting
LARSON MB B3AX
51031075500
Water / Gas Inject
Injecting
LARSON MB C1-25
51030618600
Water / Gas Inject
Monitor
LARSON MBC1AX
51031076300
Oil well
Producing
LARSON MB C2
51030569000
Water / Gas Inject
Injecting
LARSON MB C3
51030570800
Water / Gas Inject
Injecting
LARSON MB C3-25
51030618700
Water / Gas Inject
Injecting
LARSON MB C4
51031139700
Oil well
Producing
LARSON MB C5
51031142900
Oil well
Producing
LARSON MB C9X25
51030715500
Oil well
Producing
LARSON MB D1-26E
51030620000
Water / Gas Inject
Injecting
LEVISON 10
51030621700
Oil well
Producing
LEVISON 11
51030619800
Water / Gas Inject
Injecting
LEVISON 12
51030103100
Water / Gas Inject
Injecting
LEVISON 13
51030619400
Water / Gas Inject
Injecting
LEVISON 14
51030619900
Water / Gas Inject
Injecting
LEVISON 17
51030619500
Water / Gas Inject
Injecting
LEVISON 18
51030618200
Oil well
Producing
54
-------
LEVISON 2
51030559300
Oil well
Producing
LEVISON 21X
51030638700
Oil well
Producing
LEVISON 22X
51030708900
Oil well
Monitor
LEVISON 23X
51030712300
Oil well
Producing
LEVISON 24X
51030711400
Oil well
Producing
LEVISON 25X
51030722200
Oil well
Producing
LEVISON 26X
51030726700
Oil well
Producing
LEVISON 27X
51030728900
Oil well
Producing
LEVISON 28X
51030731600
Oil well
Monitor
LEVISON 29X
51030732000
Water / Gas Inject
Injecting
LEVISON 30X
51030735100
Water / Gas Inject
Injecting
LEVISON 31X
51030735300
Oil well
Monitor
LEVISON 32X
51030747500
Water / Gas Inject
Injecting
LEVISON 33X
51030752100
Oil well
Producing
LEVISON 34X
51030758600
Water / Gas Inject
Injecting
LEVISON 35X
51030868300
Oil well
Producing
LEVISON 6
51030106200
Oil well
Producing
LEVISON 7
51030619700
Oil well
Monitor
LEVISON 8
51030103000
Water / Gas Inject
Injecting
LEVISON 9
51030628600
Water / Gas Inject
Injecting
LEVSION 1
51030559100
Oil well
Producing
LN - HAGOOD A6
51030569400
Oil well
Producing
LN HAGOOD A-4
51030570700
Oil well
Shut In
MAGOR1A
51030989300
Water / Gas Inject
Injecting
MATTERN 1
51030580400
Water / Gas Inject
Injecting
MCLAUGHLIN AC 1
51030573100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 10
51030578000
Oil well
Monitor
MCLAUGHLIN AC 11
51030569300
Oil well
Producing
MCLAUGHLIN AC 12
51030579800
Water / Gas Inject
Injecting
MCLAUGHLIN AC 13
51030581000
Water / Gas Inject
Injecting
MCLAUGHLIN AC 14
51030105800
Oil well
Producing
MCLAUGHLIN AC 15
51030576700
Oil well
Producing
MCLAUGHLIN AC 16
51030105400
Oil well
Producing
MCLAUGHLIN AC 17
51030631700
Water / Gas Inject
Injecting
MCLAUGHLIN AC 18
51030105300
Water / Gas Inject
Injecting
MCLAUGHLIN AC 19
51030579400
Oil well
Producing
MCLAUGHLIN AC 2
51030573300
Oil well
Producing
MCLAUGHLIN AC 20
51030578200
Water / Gas Inject
Injecting
MCLAUGHLIN AC 21
51030578100
Oil well
Producing
MCLAUGHLIN AC 22
51030105500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 23
51030571800
Water / Gas Inject
Injecting
55
-------
MCLAUGHLIN AC 24
51030576300
Water / Gas Inject
Injecting
MCLAUGHLIN AC 25
51030631800
Oil well
Producing
MCLAUGHLIN AC 26
51030105000
Water / Gas Inject
Injecting
MCLAUGHLIN AC 27
51036005300
Oil well
Producing
MCLAUGHLIN AC 28
51030569900
Oil well
Producing
MCLAUGHLIN AC 29
51030581900
Oil well
Producing
MCLAUGHLIN AC 30
51030105100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 31
51030105200
Water / Gas Inject
Injecting
MCLAUGHLIN AC 32
51030581200
Water / Gas Inject
Injecting
MCLAUGHLIN AC 33
51030631500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 34
51030104700
Water / Gas Inject
Injecting
MCLAUGHLIN AC 35
51030581700
Oil well
Producing
MCLAUGHLIN AC 36
51030104800
Oil well
Producing
MCLAUGHLIN AC 37
51030633300
Oil well
Producing
MCLAUGHLIN AC 38
51030632200
Oil well
Producing
MCLAUGHLIN AC 39A
51031049300
Oil well
Producing
MCLAUGHLIN AC 3AX
51030920700
Water / Gas Inject
Injecting
MCLAUGHLIN AC 4
51030573800
Oil well
Producing
MCLAUGHLIN AC 41AX
51030920100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 42
51030579500
Water / Gas Inject
Monitor
MCLAUGHLIN AC 43
51030632400
Water / Gas Inject
Injecting
MCLAUGHLIN AC 44A
51031096100
Oil well
Producing
MCLAUGHLIN AC 44D
51030631600
Salt Water Disposal
Injecting
MCLAUGHLIN AC 45 AC
51030631900
Water / Gas Inject
Injecting
MCLAUGHLIN AC 46ST
51030632301
Water / Gas Inject
Monitor
MCLAUGHLIN AC 47X
51030107500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 49X
51030641700
Oil well
Monitor
MCLAUGHLIN AC 5
51030571200
Oil well
Monitor
MCLAUGHLIN AC 50X
51030632100
Oil well
Producing
MCLAUGHLIN AC 51X
51030641800
Oil well
Producing
MCLAUGHLIN AC 52X
51030642500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 53X
51030101400
Oil well
Producing
MCLAUGHLIN AC 54X
51030642600
Oil well
Producing
MCLAUGHLIN AC 55X
51030641900
Water / Gas Inject
Injecting
MCLAUGHLIN AC 56X
51030642000
Water / Gas Inject
Injecting
MCLAUGHLIN AC 57X
51030701000
Oil well
Monitor
MCLAUGHLIN AC 58X
51030701400
Oil well
Producing
MCLAUGHLIN AC 59AX
51030928800
Oil well
Producing
MCLAUGHLIN AC 6
51030579900
Oil well
Producing
MCLAUGHLIN AC 60X
51030769200
Water / Gas Inject
Injecting
MCLAUGHLIN AC 61X
51030769000
Oil well
Monitor
56
-------
MCLAUGHLIN AC 62X
51030771500
Oil well
Producing
MCLAUGHLIN AC 63X
51030771600
Water / Gas Inject
Injecting
MCLAUGHLIN AC 65X
51030771800
Oil well
Producing
MCLAUGHLIN AC 66X
51030773800
Water / Gas Inject
Injecting
MCLAUGHLIN AC 67X
51030817000
Oil well
Producing
MCLAUGHLIN AC 68X
51030829200
Oil well
Producing
MCLAUGHLIN AC 69X
51030829400
Water / Gas Inject
Injecting
MCLAUGHLIN AC 7
51030580900
Water / Gas Inject
Injecting
MCLAUGHLIN AC 70X
51030830100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 71X
51030829700
Oil well
Producing
MCLAUGHLIN AC 72X
51030832000
Water / Gas Inject
Injecting
MCLAUGHLIN AC 73X
51030831900
Oil well
Producing
MCLAUGHLIN AC 74X
51030832100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 75X
51030829800
Oil well
Producing
MCLAUGHLIN AC 76X
51030914100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 77X
51030915200
Oil well
Producing
MCLAUGHLIN AC 78X
51030915500
Oil well
Producing
MCLAUGHLIN AC 79X
51030930000
Oil well
Monitor
MCLAUGHLIN AC 8
51030573500
Oil well
Producing
MCLAUGHLIN AC 80X
51030930100
Oil well
Monitor
MCLAUGHLIN AC 81AX
51031064500
Oil well
Producing
MCLAUGHLIN AC 82X
51031054600
Oil well
Producing
MCLAUGHLIN AC 83X
51031059500
Oil well
Producing
MCLAUGHLIN AC 84Y
51031057300
Oil well
Producing
MCLAUGHLIN AC 86Y
51031058400
Oil well
Producing
MCLAUGHLIN AC 88X
51031070000
Oil well
Producing
MCLAUGHLIN AC 9
51030576600
Oil well
Monitor
MCLAUGHLIN AC 90X
51031069900
Oil well
Producing
MCLAUGHLIN AC 91X
51031072600
Water / Gas Inject
Injecting
MCLAUGHLIN AC 92X
51031070800
Oil well
Producing
MCLAUGHLIN AC 93X
51031072700
Water / Gas Inject
Injecting
MCLAUGHLIN AC 94X
51031072500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 95X
51031140800
Oil well
Producing
MCLAUGHLIN AC A1
51030609200
Oil well
Monitor
MCLAUGHLIN AC A3X
51030863000
Oil well
Producing
MCLAUGHLIN AC C2
51031104100
Oil well
Monitor
MCLAUGHLINS W6
51030627800
Oil well
P&A
MCLAUGHLIN SHARPLES 10X28
51030749000
Oil well
Producing
MCLAUGHLIN SHARPLES 1-28
51030560300
Water / Gas Inject
Injecting
MCLAUGHLIN SHARPLES 12X33
51030759800
Oil well
Producing
MCLAUGHLIN SHARPLES 1-33
51030551300
Oil well
Producing
57
-------
MCLAUGHLIN SHARPLES 13X3
51030873900
Oil well
Producing
MCLAUGHLIN SHARPLES 14Y33
51030912300
Oil well
Producing
MCLAUGHLIN SHARPLES 15X32
51030885400
Oil well
Producing
MCLAUGHLIN SHARPLES 16X32
51030913200
Water / Gas Inject
Injecting
MCLAUGHLIN SHARPLES 2-28
51030560000
Oil well
Producing
MCLAUGHLIN SHARPLES 2-32
51030627300
Water / Gas Inject
Monitor
MCLAUGHLIN SHARPLES 2-33
51030106800
Water / Gas Inject
Injecting
MCLAUGHLIN SHARPLES 3-32
51030627000
Oil well
Monitor
MCLAUGHLIN SHARPLES 3-33
51030629000
Oil well
Producing
MCLAUGHLIN SHARPLES 4-33
51030629100
Water / Gas Inject
Injecting
MCLAUGHLIN SHARPLES 5-33
51030104500
Oil well
Monitor
MCLAUGHLIN SHARPLES 6-33
51030628800
Oil well
Monitor
MCLAUGHLIN SHARPLES 7-33
51030104600
Water / Gas Inject
Monitor
MCLAUGHLIN SHARPLES 8-33
51030628900
Water / Gas Inject
Monitor
MCLAUGHLIN SHARPLES 9X33
51030746500
Oil well
Producing
MCLAUGHLIN SW11X
51030759700
Water / Gas Inject
Injecting
MCLAUGHLIN SW12X
51030760100
Water / Gas Inject
Injecting
MCLAUGHLIN SW 1ST
51030548300
Oil well
P&A
MCLAUGHLIN SW 1 ST 1
51030548301
Water / Gas Inject
Monitor
MCLAUGHLIN SW2
51030627700
Oil well
Producing
MCLAUGHLIN SW 3
51030104400
Water / Gas Inject
Injecting
MCLAUGHLIN SW4
51030107600
Oil well
Producing
MCLAUGHLIN SW 5
51030627900
Oil well
Producing
MCLAUGHLIN SW6ST
51030627801
Water / Gas Inject
Injecting
MCLAUGHLIN SW7X
51030746100
Oil well
Producing
MCLAUGHLIN SW8X
51030753000
Water / Gas Inject
Injecting
MCLAUGHLIN UNIT A1
51030581600
Oil well
Producing
MCLAUGHLIN UNIT B1
51030582600
Oil well
Producing
MCLAUGHLIN UNIT B2X
51031057600
Water / Gas Inject
Injecting
MELLEN 3A
51031098100
Oil well
Producing
MELLEN WP 1
51036000300
Water / Gas Inject
Injecting
MELLEN WP 2
51030105600
Water / Gas Inject
Injecting
NEAL 2AX
51030920800
Water / Gas Inject
Injecting
NEAL4
51030565500
Water / Gas Inject
Injecting
NEAL 5A
51030565900
Oil well
Producing
NEAL 6X
51030790600
Oil well
Producing
NEAL 7X
51030804200
Water / Gas Inject
Injecting
NEAL 8X
51030804300
Water / Gas Inject
P&A
NEAL 8XST
51030804301
Water / Gas Inject
Injecting
NEAL 9Y
51030912000
Oil well
Producing
NEWTON ASSOC UNIT D2X
51030868500
Oil well
Monitor
58
-------
NIKKEL 3
51030619200
Water / Gas Inject
Injecting
PURDY 1-1
51030545300
Water / Gas Inject
Monitor
PURDY 2X1
51030881000
Oil well
Producing
RAVEN A1AX
51030917800
Water / Gas Inject
Injecting
RAVEN A2
51030625700
Water / Gas Inject
Injecting
RAVEN A3
51030624400
Water / Gas Inject
Injecting
RAVEN A4
51030625800
Water / Gas Inject
Injecting
RAVEN A5X
51030718800
Oil well
Producing
RAVEN B1
51030564900
Oil well
Producing
RAVEN B2AX
51030923800
Water / Gas Inject
Monitor
RECTOR 1
51030549400
Oil well
Producing
RECTOR 11X
51030867200
Oil well
Shut In
RECTOR 12X
51030919900
Oil well
Shut In
RECTOR 3
51030106000
Water / Gas Inject
Injecting
RECTOR 8X
51030704300
Oil well
Producing
RECTOR 9X
51030714700
Oil well
Shut In
RIGBY 1
51030569700
Oil well
Producing
RIGBY 5X
51030804700
Water / Gas Inject
Injecting
RIGBY 6Y
51030910700
Oil well
Producing
RIGBY A2AX
51030920000
Water / Gas Inject
Injecting
RIGBY A3X
51030791000
Oil well
Producing
RIGBY A4X
51030791100
Oil well
Monitor
RIGBY A7Y
51030915100
Oil well
Monitor
ROOTH DF1
51030579700
Water / Gas Inject
Injecting
ROOTH DF 5 X
51031143000
Oil well
Producing
ROOTH DF 6 X
51031125000
Oil well
Producing
S B LACY 3
51030568900
Oil well
Monitor
STOFFER CR A1
51030562700
Water / Gas Inject
Injecting
STOFFER CR A2
51030559200
Water / Gas Inject
Injecting
STOFFER CR B1
51030567300
Oil well
Producing
SW MCLAUGHLIN 10X
51030754700
Oil well
Producing
SW MCLAUGHLIN 9X
51030753500
Oil well
Producing
U P 4829
51030623100
Water / Gas Inject
P&A
UNION PACIFIC 1 150X 16
51031150200
Oil well
Producing
UNION PACIFIC 1 151X 16
51031150100
Oil well
Producing
UNION PACIFIC 1 153X 16
51031146401
Water / Gas Inject
Injecting
UNION PACIFIC 100X20
51030788600
Oil well
Producing
UNION PACIFIC 101X20
51030797300
Oil well
Monitor
UNION PACIFIC 10-21
51030568501
Oil well
Monitor
UNION PACIFIC 102X20
51030797700
Water / Gas Inject
Injecting
UNION PACIFIC 103X20
51030799000
Water / Gas Inject
Injecting
59
-------
UNION PACIFIC 104X20
51030803000
Water / Gas Inject
Injecting
UNION PACIFIC 105X29
51030794500
Oil well
Producing
UNION PACIFIC 106X32
51030845000
Oil well
Producing
UNION PACIFIC 107X32
51030849800
Oil well
Producing
UNION PACIFIC 108X21
51030849500
Water / Gas Inject
Injecting
UNION PACIFIC 109X32
51030849700
Oil well
Producing
UNION PACIFIC 110X21
51030853000
Water / Gas Inject
Injecting
UNION PACIFIC 111X29
51030852200
Oil well
Producing
UNION PACIFIC 11-21
51030616200
Oil well
Producing
UNION PACIFIC 112X21
51030873500
Oil well
Monitor
UNION PACIFIC 113X22
51030860600
Oil well
Monitor
UNION PACIFIC 115X21
51030866600
Oil well
Producing
UNION PACIFIC 117X22
51030866700
Oil well
Producing
UNION PACIFIC 118X21
51030869700
Oil well
Producing
UNION PACIFIC 119X21
51030869800
Oil well
Producing
UNION PACIFIC 120X21
51030869900
Oil well
Producing
UNION PACIFIC 12-27
51030620400
Oil well
Producing
UNION PACIFIC 122X21
51030870000
Oil well
Monitor
UNION PACIFIC 126X32
51030885100
Oil well
Producing
UNION PACIFIC 127X31
51030884700
Oil well
Producing
UNION PACIFIC 128X31
51030910000
Oil well
Producing
UNION PACIFIC 129X31
51030885200
Oil well
Producing
UNION PACIFIC 130X32
51030885300
Oil well
Producing
UNION PACIFIC 131X32
51030885500
Oil well
Producing
UNION PACIFIC 1-32
51030556700
Water / Gas Inject
Injecting
UNION PACIFIC 13-28
51030622000
Water / Gas Inject
Injecting
UNION PACIFIC 132X21
51030874600
Oil well
Monitor
UNION PACIFIC 133X21
51030876400
Oil well
Producing
UNION PACIFIC 134X21
51030904100
Water / Gas Inject
Injecting
UNION PACIFIC 135Y28
51030910500
Oil well
Monitor
UNION PACIFIC 136X20
51030913800
Oil well
Producing
UNION PACIFIC 137X20
51030913900
Water / Gas Inject
Monitor
UNION PACIFIC 138Y28
51030917300
Oil well
Producing
UNION PACIFIC 139Y28
51030918500
Oil well
Monitor
UNION PACIFIC 140Y27
51030918800
Oil well
Producing
UNION PACIFIC 141Y28
51030918900
Oil well
Producing
UNION PACIFIC 14-20
51030615400
Oil well
Producing
UNION PACIFIC 142Y28
51030919000
Oil well
Monitor
UNION PACIFIC 143Y28
51030918600
Oil well
Monitor
UNION PACIFIC 15-28
51030102900
Oil well
Monitor
UNION PACIFIC 154Y29
51031172000
Oil well
Producing
60
-------
UNION PACIFIC 156Y29
51031172100
Oil well
Producing
UNION PACIFIC 16-27
51030620600
Oil well
Shut In
UNION PACIFIC 17-27
51030621400
Oil well
Producing
UNION PACIFIC 18-21
51030616400
Oil well
Producing
UNION PACIFIC 19-28
51030621900
Water / Gas Inject
Injecting
UNION PACIFIC 20-29
51030622800
Water / Gas Inject
Injecting
UNION PACIFIC 21-32
51030627100
Water / Gas Inject
Monitor
UNION PACIFIC 2-20
51030569200
Oil well
Producing
UNION PACIFIC 22-32
51030627500
Oil well
Producing
UNION PACIFIC 23-32
51030626900
Oil well
Producing
UNION PACIFIC 24-27
51030621200
Water / Gas Inject
Injecting
UNION PACIFIC 25-34
51030106900
Oil well
Shut In
UNION PACIFIC 26-31
51030626100
Water / Gas Inject
Injecting
UNION PACIFIC 27-20
51030577000
Oil well
Monitor
UNION PACIFIC 28-22
51030617300
Oil well
Producing
UNION PACIFIC 29-32
51030548700
Oil well
Monitor
UNION PACIFIC 31-21
51030616600
Oil well
Monitor
UNION PACIFIC 32-27
51030620800
Oil well
Monitor
UNION PACIFIC 33-32
51030626600
Water / Gas Inject
Injecting
UNION PACIFIC 3-34
51030551000
Oil well
Producing
UNION PACIFIC 34-31
51030626300
Water / Gas Inject
Injecting
UNION PACIFIC 35-32
51030626800
Water / Gas Inject
Injecting
UNION PACIFIC 36-32
51030627200
Water / Gas Inject
Injecting
UNION PACIFIC 37AX29
51030917700
Water / Gas Inject
Injecting
UNION PACIFIC 39-17
51030612100
Water / Gas Inject
Injecting
UNION PACIFIC 41-20
51030615800
Water / Gas Inject
Shut In
UNION PACIFIC 4-29
51030563200
Water / Gas Inject
Injecting
UNION PACIFIC 42AX28
51030925700
Water / Gas Inject
Injecting
UNION PACIFIC 43-28
51030622100
Water / Gas Inject
Monitor
UNION PACIFIC 44AX20
51030923300
Water / Gas Inject
Injecting
UNION PACIFIC 45-21
51030569600
Water / Gas Inject
Injecting
UNION PACIFIC 47-21
51030615900
Water / Gas Inject
Injecting
UNION PACIFIC 48-29ST
51030623101
Water / Gas Inject
Injecting
UNION PACIFIC 49-27
51030621300
Oil well
Producing
UNION PACIFIC 50-29
51030107100
Water / Gas Inject
Injecting
UNION PACIFIC 51AX20
51030892800
Water / Gas Inject
Injecting
UNION PACIFIC 5-28
51030563900
Oil well
Producing
UNION PACIFIC 52A-29
51030928400
Water / Gas Inject
Injecting
UNION PACIFIC 53-32
51030627600
Water / Gas Inject
Monitor
UNION PACIFIC 54-21
51030616300
Water / Gas Inject
Injecting
UNION PACIFIC 55-17
51030612200
Water / Gas Inject
Injecting
61
-------
UNION PACIFIC 56-21
51030616700
Water / Gas Inject
Injecting
UNION PACIFIC 58-27
51030620500
Water / Gas Inject
Injecting
UNION PACIFIC 59A-27
51031120700
Oil well
Producing
UNION PACIFIC 60-31
51030626200
Water / Gas Inject
Injecting
UNION PACIFIC 61-20
51030615500
Water / Gas Inject
Injecting
UNION PACIFIC 6-21
51030574100
Oil well
Producing
UNION PACIFIC 62AX32
51030919600
Water / Gas Inject
Injecting
UNION PACIFIC 65-5
51030608900
Water / Gas Inject
Monitor
UNION PACIFIC 67-32
51030626700
Water / Gas Inject
Injecting
UNION PACIFIC 68-32
51030628700
Water / Gas Inject
Injecting
UNION PACIFIC 69-27
51030621000
Oil well
Shut In
UNION PACIFIC 71X31
51030727600
Oil well
Producing
UNION PACIFIC 7-29
51030559700
Water / Gas Inject
Injecting
UNION PACIFIC 73X29
51030738600
Oil well
Producing
UNION PACIFIC 74X27
51030741600
Oil well
Monitor
UNION PACIFIC 75X32
51030740200
Oil well
Producing
UNION PACIFIC 76X21
51030742100
Oil well
Producing
UNION PACIFIC 77X32
51030745400
Oil well
Producing
UNION PACIFIC 78X21
51030742600
Water / Gas Inject
Injecting
UNION PACIFIC 79X32
51030744800
Oil well
Monitor
UNION PACIFIC 80X28
51030746000
Water / Gas Inject
Monitor
UNION PACIFIC 81X29
51030749900
Oil well
Producing
UNION PACIFIC 8-20
51030568600
Oil well
Producing
UNION PACIFIC 82X28
51030749400
Oil well
Producing
UNION PACIFIC 83X28
51030750000
Oil well
Producing
UNION PACIFIC 84X28
51030749500
Oil well
Producing
UNION PACIFIC 85X34
51030748100
Water / Gas Inject
Injecting
UNION PACIFIC 86X27
51030748200
Water / Gas Inject
Injecting
UNION PACIFIC 87X29
51030750900
Oil well
Producing
UNION PACIFIC 88X21
51030751400
Oil well
Producing
UNION PACIFIC 89X34
51030754800
Water / Gas Inject
Injecting
UNION PACIFIC 91X28
51030756000
Water / Gas Inject
Injecting
UNION PACIFIC 9-29
51030565600
Water / Gas Inject
Injecting
UNION PACIFIC 92X28
51030757400
Water / Gas Inject
Monitor
UNION PACIFIC 94X27
51030758800
Water / Gas Inject
Injecting
UNION PACIFIC 96X29
51030765000
Oil well
Producing
UNION PACIFIC 97X29
51030765100
Oil well
Producing
UNION PACIFIC 98X32
51030765200
Oil well
Producing
UNION PACIFIC 99X29
51030785600
Oil well
Producing
UNION PACIFIC B1-34
51030548900
Water / Gas Inject
Monitor
UNION PACIFIC B2-34
51030102700
Oil well
Monitor
62
-------
UNION PACIFIC B3X34
51030744000
Oil well
Producing
UNION PACIFIC B4X34
51030753600
Water / Gas Inject
Injecting
UNION PACIFIC B5X34
51030759900
Water / Gas Inject
Injecting
UNION PACIFIC B6X34
51030760200
Water / Gas Inject
Monitor
WALBRIDGE LB 1
51030607000
Water / Gas Inject
Monitor
WALBRIDGE UNIT 1
51030607200
Water / Gas Inject
Monitor
WALBRIDGE UNIT 2X
51030920500
Oil well
Producing
WALBRIDGE UNIT 3X
51030920600
Oil well
Monitor
WEYRAUCH 2-36
51030630600
Water / Gas Inject
Injecting
WEYRAUCH 4X36
51030707200
Oil well
Producing
WEYRAUCH 5X36
51030881900
Oil well
Producing
WEYRAUCH 6X36
51030916600
Oil well
Producing
WEYRAUCH 7X36
51030916300
Oil well
Producing
AC MCLAUGHLIN 39
51030582400
P&A
P&A
A C MCLAUGHLIN 3
51030578600
P&A
P&A
MCLAUGHLIN AC 40
51030632000
P&A
P&A
AC MCLAUGHLIN 41
51030575900
P&A
P&A
A C MCLAUGHLIN 48X
51030580300
P&A
P&A
A C MCLAUGHLIN 59X
51030769100
P&A
P&A
MCLAUGHLIN AC 81X
51031053000
P&A
P&A
A.C. MCLAUGHLIN A A2
51030609300
P&A
P&A
AC MCLAUGHLIN B 1
51030611000
P&A
P&A
AC MCLAUGHLIN B 2
51030610500
P&A
P&A
A C MCLAUGHLIN 1
51030612000
P&A
P&A
A C MCLAUGHLIN 1
51030757700
P&A
P&A
ASSOCIATED 4X
51030881200
P&A
P&A
ASSOCIATED B 1
51030601200
P&A
P&A
ASSOCIATED B 2
51030601000
P&A
P&A
ASSOCIATED B 3
51030601300
P&A
P&A
BEEZLEY 1 22
51030573900
P&A
P&A
CT CARNEY 12-5
51030107000
P&A
P&A
CT CARNEY 26X35
51030745000
P&A
P&A
CARNEY CT 31X4
51030760400
P&A
P&A
CARNEY C T 34X-4
51030760000
P&A
P&A
CARNEY CT 36X34
51030759500
P&A
P&A
CARNEY CT 40X35
51030911700
P&A
P&A
CARNEY CT 42Y34
51030915400
P&A
P&A
CHASE UNIT U 1
51030600800
P&A
P&A
HILL.C.E. 1
51030601800
P&A
P&A
HEFLEY C-S 1
51030104100
P&A
P&A
C-S HEFLEY 2
51030607700
P&A
P&A
63
-------
C-S HEFLEY 3
51030607800
P&A
P&A
C R STOFFER A 3
51030562600
P&A
P&A
EMERALD 12
51030566700
P&A
P&A
EMERALD 15
51030565400
P&A
P&A
EMERALD 18
51030104900
P&A
P&A
EMERALD 21
51030546400
P&A
P&A
EMERALD 24
51030563500
P&A
P&A
EMERALD 29
51030565800
P&A
P&A
EMERALD 30
51030563000
P&A
P&A
EMERALD 31
51030623700
P&A
P&A
EMERALD 33
51030623900
P&A
P&A
EMERALD OIL CO. 3M
51030724700
P&A
P&A
EMERALD 43
51030625200
P&A
P&A
EMERALD 44
51030633800
P&A
P&A
EMERALD 45
51030603000
P&A
P&A
EMERALD 49X
51030729600
P&A
P&A
EMERALD 5
51030566600
P&A
P&A
EMERALD 7
51030624100
P&A
P&A
E OLDLAND 4
51030715200
P&A
P&A
FAIRFIELD,KITTIE A 2
51030611400
P&A
P&A
FAIRFIELD,KITTIE A 3
51030611700
P&A
P&A
F V LARSON 116
51036652500
P&A
P&A
FEE 118X
51030843900
P&A
P&A
FEE 119X
51030849400
P&A
P&A
FEE161X
51031185900
P&A
P&A
FEE 16
51030624600
P&A
P&A
FEE 2
51030558600
P&A
P&A
FEE 46
51030610700
P&A
P&A
FEE 53
51030617400
P&A
P&A
FEE 54
51030618000
P&A
P&A
FEE 57
51030622700
P&A
P&A
FEE 58
51030614300
P&A
P&A
FEE 66
51030610900
P&A
P&A
FEE 67
51030611600
P&A
P&A
FEE 70
51030626000
P&A
P&A
FEE 71
51030610800
P&A
P&A
FEE 77X
51030736000
P&A
P&A
FEDERAL ET AL 2M
51030719700
P&A
P&A
FEDERAL ET AL 5M
51030731700
P&A
P&A
LARSON FV B10
51030629900
P&A
P&A
LARSON FV B13X
51030557900
P&A
P&A
64
-------
LARSON FV B16X
51030702400
P&A
P&A
LARSON FV B1
51030629600
P&A
P&A
LARSON FV 26Y
51030948500
P&A
P&A
LARSON FV B3
51030630500
P&A
P&A
LARSON FV B5
51030630100
P&A
P&A
LARSON FV B6
51030630300
P&A
P&A
LARSON F V B7
51030630001
P&A
P&A
LARSON FV B9
51030102500
P&A
P&A
F V LARSON 1
51030539800
P&A
P&A
GENTRY 2D
51030543700
P&A
P&A
GENTRY 3D
51030608500
P&A
P&A
NEWTON 4-D
51030104300
P&A
P&A
GENTRY 4D
51030543700
P&A
P&A
GENTRY 5D
51030608300
P&A
P&A
GENTRY 6X
51030744200
P&A
P&A
GRAY A 11
51030613800
P&A
P&A
GRAY A 11 AX
51030927500
P&A
P&A
GRAY A 8
51030568100
P&A
P&A
GRAY B 14
51030613000
P&A
P&A
GUIBERSON,S.A. A 2
51030613400
P&A
P&A
HILDENBRANDT 1
51030608100
P&A
P&A
COLTHARP JE 1
51030602400
P&A
P&A
J E COLTHARP 3
51030602500
P&A
P&A
COLTHARP JE 6X
51030714800
P&A
P&A
COLTHARP JE 9X P 9X
51030853500
P&A
P&A
PEPPER,J.E. A 1
51030550200
P&A
P&A
J E PEPPER B 1
51030606300
P&A
P&A
LACY SB 10Y
51030914300
P&A
P&A
S B LACY 2
51030570600
P&A
P&A
F V LARSON 1
51030106500
P&A
P&A
LEVISON 15
51030618100
P&A
P&A
LEVISON 16
51030619600
P&A
P&A
LEVISON 19
51030106300
P&A
P&A
LEVISON 20
51030618300
P&A
P&A
LEVISON 3
51030621600
P&A
P&A
LEVISON 4
51030560400
P&A
P&A
LEVISON 5
51030621500
P&A
P&A
LNHAGOODB 1
51030607300
P&A
P&A
L N HAGOOD B 2
51030607100
P&A
P&A
L N HAGOOD B 3
51030607400
P&A
P&A
WALBRIDGE LB 3
51030630800
P&A
P&A
65
-------
WALBRIDGE LB 4X
51030873600
P&A
P&A
WALBRIDGE LB 5Y
51030948300
P&A
P&A
MAGOR 1
51030580800
P&A
P&A
MCLAUGHLIN 3
51030556100
P&A
P&A
MELLEN,W.P. A 3
51030105700
P&A
P&A
HEFLEY ME 1
51030607500
P&A
P&A
HEFLEY ME 3
51030545400
P&A
P&A
HEFLEY ME 4
51030543300
P&A
P&A
M B LARSON C11 X 25
51030717300
P&A
P&A
M B LARSON A 1
51030632900
P&A
P&A
MB LARSON A3
51030576400
P&A
P&A
LARSON MB 1-35
51030555700
P&A
P&A
M B LARSON C 1
51030571900
P&A
P&A
LARSON MB C2-25
51030106400
P&A
P&A
M B LARSON C425
51030618900
P&A
P&A
LARSON MB D136
51030631000
P&A
P&A
LARSON MB D226
51030102600
P&A
P&A
M B LARSON D525
51030618500
P&A
P&A
M B LARSON D625
51030619000
P&A
P&A
M B LARSON D725
51030618400
P&A
P&A
NEAL2
51030566000
P&A
P&A
NEAL3
51030567200
P&A
P&A
NEWTON ASSOC A1
51030107300
P&A
P&A
NEWTON ASSOC B 1
51030101800
P&A
P&A
NEWTON ASSOC C 1
51030102100
P&A
P&A
NEWTON ASSOC D 1
51030102200
P&A
P&A
NIKKEL 1
51030619300
P&A
P&A
NIKKEL 2
51030619100
P&A
P&A
OLDLAND1
51030102000
P&A
P&A
OLDLAND 2
51030106100
P&A
P&A
OLDLAND 3
51030630400
P&A
P&A
OLDLAND E 5X
51030853600
P&A
P&A
OLDLAND E 6X
51030947600
P&A
P&A
PURDY 1 6
51030606200
P&A
P&A
PURDY 3X1
51030870300
P&A
P&A
RANGELY 2M-33-19B
51030939800
P&A
P&A
RAVEN A 1
51030562900
P&A
P&A
RAVEN B 2
51030624300
P&A
P&A
RECTOR 10X
51030760300
P&A
P&A
RECTOR 2
51030608400
P&A
P&A
RECTOR 4
51030629400
P&A
P&A
66
-------
RECTOR 5
51030629200
P&A
P&A
RECTOR 6
51030608200
P&A
P&A
RECTOR 7
51030105900
P&A
P&A
RIGBY A224
51030570000
P&A
P&A
ROOTH 3
51030564700
P&A
P&A
MCLAUGHLIN SHARPLES 11X 3
51030760500
P&A
P&A
SHARPLES MCLAUGHLIN 132
51030107400
P&A
P&A
SHARPLES MCLAUGHLIN 432
51030627400
P&A
P&A
UNION PACIFIC 121X21
51030870500
P&A
P&A
U P3016
51030578300
P&A
P&A
UNION PACIFIC 37-29
51030623200
P&A
P&A
U P 3822
51030574400
P&A
P&A
U P 4022
51030617800
P&A
P&A
U P 4228
51030621800
P&A
P&A
U P 4420
51030571000
P&A
P&A
UNION PACIFIC 46-21
51030573700
P&A
P&A
U P 5721
51030616500
P&A
P&A
U P 5927
51030620900
P&A
P&A
UNION PACIFIC 62-32
51030626500
P&A
P&A
UNION PACIFIC 63-31
51030623000
P&A
P&A
UNION PACIFIC 63-31
51030626400
P&A
P&A
UNION PACIFIC 63AX31
51030917900
P&A
P&A
U P 6422
51030617200
P&A
P&A
U P6616
51030610600
P&A
P&A
UNION PACIFIC 72X31
51030736400
P&A
P&A
UNION PACIFIC 90X29
51030758200
P&A
P&A
UNION PACIFIC 93X27
51030756100
P&A
P&A
U P 95X 34
51030759600
P&A
P&A
COLTHARP WH A2
51030602000
P&A
P&A
COLTHARP WH A7X
51030869300
P&A
P&A
COLTHARP WH B1
51030101900
P&A
P&A
WEYRAUCH 1-36
51030630700
P&A
P&A
WEYRAUCH 336
51030630900
P&A
P&A
WHITE 1
51030543500
P&A
P&A
WHITE 2
51030545100
P&A
P&A
67
-------
Request for Additional Information: Rangely Gas Plant
July 20, 2023
Instructions: Please enter responses into this table and make corresponding revisions to the MRV Plan as necessary. Any long responses,
references, or supplemental information may be attached to the end of the table as an appendix. This table may be uploaded to the Electronic
Greenhouse Gas Reporting Tool (e-GGRT) in addition to any MRV Plan resubmissions.
No.
MRV Plan
EPA Questions
Responses
Section
Page
1.
N/A
N/A
There is a lack of consistency with hyphens, holding, quotation
marks, spelling, and capitalization throughout the MRV plan.
Examples include but are not limited to:
C02 vs. C02
Weber Sands vs. weber sands
BCF vs. Bscf
Well bore vs. wellbore
We recommend reviewing the formatting in the MRV plan for
consistency. Furthermore, we recommend doing an additional
review for spelling, grammar, etc.
The MRV plan has been reviewed for consistency and grammar, and
updates have been made accordingly.
2.
N/A
N/A
Please review the figures included in the MRV plan to ensure that all
text is legible, scale bars and legends are scaled appropriately, etc.
For example, the legend in Figure 9 is small and difficult to read.
The figures included in the MRV plan have been reviewed and
revised where applicable to make more legible.
3.
N/A
N/A
The MRV plan mentions a "Specified Period". Please clarify what
timeline this is referring to.
Specified Period has been clarified as "... all or some portion of the
period 2023 to 2060." Specified Period added to Figures 1 and 2 as
clarification.
-------
No.
MRV Plan
EPA Questions
Responses
Section
Page
4.
N/A
N/A
Please ensure that all acronyms are defined during the first use
within the MRV plan. For example, "SCADA" is not defined within
the text.
The MRV Plan has been reviewed for acronyms and definitions, and
updates have been made accordingly.
5.
TOC
2
We recommend reviewing the table of contents and section
headers for clarity. For example, Section 2.2.2 header reads,
"Operational History of the Rangely Field and Rangely Field".
The MRV Plan has been reviewed for formatting and consistency,
and updates have been made accordingly.
6.
2.2
6
Section 2.2 states, "...the Rangley Field, located on the Douglas
Creek Arch between the Uinta basin and the Piceance basin in
Colorado."
However, Section 2.2.1 states, "The field is located within the Rocky
Mountain province between the Douglas Creek Arch (south) and
the Uinta Mountains (north)."
Please ensure that the description of the project site is consistent
within the MRV plan.
Section 2.2 remains unchanged. Section 2.2.1 has been revised to
state "The field is located within the Rocky Mountain province along
the structural high of the Douglas Creek Arch, which separates the
Uinta Basin to the west and Piceance Basin to the east (see Figure
3). More locally, north..."
-------
No.
MRV Plan
EPA Questions
Responses
Section
Page
7.
2.2.1
7
Please ensure that a lower confining unit is identified and described
within the MRV plan, if applicable.
Section 2.2.1 has been revised to include the following:
"Geologically, the Weber sandstones were deposited on top of the
Morgan Formation which is a combination of interbedded shale,
siltstone, and cherty limestone. Few wells are drilled deep enough
to penetrate the Morgan Formation within the Rangely Field to
gather porosity/permeability data locally. However, analysis of the
Morgan Formation from other fields/outcrops indicate that it is a
non-reservoir rock (low porosity/permeability), and would be
sufficient as a basial barrier for the field. The highest subsurface
elevation of the base of the Weber Formation is deeper than the -
1150' used for the OWC. Meaning injected C02 should not
encounter the Morgan Formation. Additionally, section 4.7, explains
how the Rangely Field is confined laterally through the nature of the
anticline's structure."
8.
2.3
14
We recommend including flow meter locations (those used for
subpart RR measurements) in Figure 10.
Figure 10 has been updated to include C02 measurement points.
9.
2.3.2
15
"As of April 2023, there are 662 active wells that are completed in
the Rangely Field, roughly evenly split between production and
injection wells, as indicated in Figure 11.2 Table 1 shows these well
counts in the Rangely Field by status."
Section 2.3.1 indicates that there are 280 injection wells which is
closer to 40% of all wells. Please ensure that the number of wells is
consistent throughout the MRV plan.
The MRV Plan has been reviewed and updates to percentages and
well counts have been made accordingly.
10.
2.3.2
16
'The wells with liners ran would have had cement to the TOL"
Please clarify the above sentence.
The sentence has been reworded to 'The wells with liners were
cemented to TOL"
-------
No.
MRV Plan
EPA Questions
Responses
Section
Page
11.
2.3.3
18
"...some wells do not yield solid test results necessitating review or
repeat testing."
Please clarify the above sentence.
The sentence has been reworded to "... some wells will periodically
need repeat testing due to abnormal test results."
12.
3.1
20
Per 40 CFR 98.449, active monitoring area is defined as the area
that will be monitored over a specific time interval from the first
year of the period (n) to the last year in the period (t). The boundary
of the active monitoring area is established by superimposing two
areas:
(1) The area projected to contain the free phase C02 plume at the
end of year t, plus an all around buffer zone of one-half mile or
greater if known leakage pathways extend laterally more than one-
half mile.
(2) The area projected to contain the free phase C02 plume at the
end of year t + 5.
While the MRV plan identifies the AMA, please provide further
explanation of whether the AMA meets the definitions in 40 CFR
98.449.
For example, please specify whether C02 will remain in the unit
boundaries at year t and year t+5. Does the AMA include the % mile
buffer as described in criterion (1)?
Updated Section 3.1 to clarify the AMA and MMA areas. The area
projected to contain the free phase C02 plume at year 2060 is the
AMA, defined by the RWSU Boundary. Provided supporting
argument and referenced supporting material within the document.
-------
No.
MRV Plan
EPA Questions
Responses
Section
Page
13.
3.2
20
Per 40 CFR 98.449, maximum monitoring area is defined as equal to
or greater than the area expected to contain the free phase C02
plume until the C02 plume has stabilized plus an all-around buffer
zone of at least one-half mile.
While the MRV plan identifies the MMA, please provide further
explanation of whether the MMA meets the definitions in 40 CFR
98.449. For example, what is the expected timeframe and boundary
of the stablized C02 plume? What will happen to the C02 plume
when the facility is no longer producing fluids?
Updated wording to clarify the MMA is equal to the AMA plus the
required half mile buffer. Noted reference to Section 3.1 defining
the AMA and why it meets the definitions.
14.
4.2
22
Bullet #1: "In the time that the Rangely Field has been under
injection both water and C02, very few excursions result in fluid
migration out of the intended zone and that leakage to the surface
is very rare."
Please clarify this sentence and elaborate on what is meant by "very
rare".
This sentence has been replaced with " In the time SEM has
operated the RWSU, there have been no C02 leakage events from a
wellbore."
15.
4.3
23
"...SEM has concluded that there are no known faults or fractures
that transect the Weber Sands reservoir in the project area. As
described in Section 2.2.1, faults have been identified in formations
that are thousands of feet below the Weber Sands formation, but
this faulting has been shown not to affect the Weber Sands or to
have created potential leakage pathways."
However, Section 2.2.1 states that, "The Rangely Field has one main
field fault (MFF) and numerous smaller faults and fractures that are
present throughout the stratigraphic column between the base of
the reservoir and surface."
Please ensure that the classification of faults and fractures is
consistent within the MRV plan.
Section 4.3 has been revised to include the following:
"... no known faults or fractures that transect the entirety of the
Weber Sands in the project area. As described in section 2.2.1, the
MMF is presented below the reservoir and terminates within the
Weber Sands without interacting with the upper seal. Additional
large faults have been identified in formations..."
-------
No.
MRV Plan
EPA Questions
Responses
Section
Page
16.
4
N/A
In addition to listing the possible leakage pathways and their
monitoring strategies, please provide a clear characterization of
the likelihood, magnitude, and timing of leakage for each potential
leakage pathway (not just a description the facility's construction
and how leakage would be monitored/detected).
For example, the format of such a characterization might look like:
"leakage from XYZ pathway is unlikely but possible. If it did occur, it
would be most likely when pressures are highest during XYZ
timeframe, and the leakage could result in XYZ kgs/metric tons
before being addressed..."
Section 4 has been revised to include the following:
"Detailed analysis of these potential pathways concluded that
existing wellbores and pipeline/surface equipment pose the only
meaningful potential leakage pathways. Operating pressures are
not expected to increase over time, therefore there is not a specific
time period that would increase the likelihood of pathways for
leakage. SEM identifies these potential pathways for C02 leakage to
be low risk, i.e. less than 1% given the extensive operating history
and monitoring program currently in place.
The monitoring program to detect and quantify leakage is based on
the assessment discussed below."
-------
17.
4.4
23
"After reviewing the literature and actual operating experience,
SEIVI concludes that there is no direct evidence that natural seismic
Rangely Field,
Since the 201? seismic events, no other events have been recorded
of felt magnitude and continued pressure monitoring further
aware of any reported loss of injectant (waste water or C02) to the
surface associated with any seismic activity, natural or induced,"
Please provide additional information on seismicity in the area
(some of the discussion on page 9 may be relevant to include here).
Have there been natural seismic events recorded? What
operational measures will the facility take to ensure that seismicity
is not induced?
Section 4.4 has been replaced with the following:
"After reviewing literature and historic data, SEM concludes that
there is no direct evidence that natural seismic activity poses a
significant risk for loss of C02 to the surface in the Rangely Field.
Natural seismic events are derived from the thrust fault to the west.
Historically, Figure 6 in section 2.2.1 shows nine seismic events
outside of the Rangely Field (including the 1993 M 3.5 event). The
epicenter of these earthquakes were far below the operating
depths of the Rangely Field, and are associated with the thrust fault
to the west of the field. The operations of Rangely have zero impact
on this thrust fault. Natural earthquakes are not predictable, but
these do not pose a threat to current operations. Again, due to the
fact that hydrocarbons are still within the anticline means that
there have now major seismic events in the last few million years
capable of releasing these hydrocarbons to the surface.
Induced seismic events (non-natural) are tied to the main field fault
(MFF) and its joint faults. These can be impacted by Rangely
operations. Section 2.2.1 explains how an increase in reservoir
pressure can trigger seismic events along and near the MFF. To
prevent this from occurring bottom hole pressure surveys are
collected 1-2 times a year from across the field helping to monitor
pressure changes along across the field. By keeping reservoir
pressure from exceeding the threshold of ~3750 psi for extended
periods of time (multiple years), induced seismic events can be
greatly mitigated. In the case that reservoir pressures do exceed the
threshold pressure, a reduction in injected volumes in the vicinity
will bring down the pressures back down gradually over a period of
time."
18.
4.6
23
call for more robust design and operating requirements to prevent
The referenced sentence has been replaced with the following:
"In the case of pipeline and surface equipment, best engineering
practices call for more robust metallurgy in wellhead equipment,
-------
No.
MRV Plan
EPA Questions
Responses
Section
Page
Please clarify what is meant by "more robust" design.
and pressure transducers with low pressure alarms monitored
through the SCADA system to prevent and detect leakage."
19.
5.1.4
28
"C02 produced is calculated using the volumetric flow meters at the
inlet to the C02 Reinjection Facility."
Please explain or show in the process flow diagram whether this
description meets the requirements of 40 CFR 98.444(c)(1) which
states that 'The point of measurement for the quantity of C02
produced from oil or other fluid production wells is a flow meter
directly downstream of each separator that sends a stream of gas
into a recycle or end use system."
Clarification has been added "These flow meters are downstream of
the field collection station separators and bulk produced fluid
separators at the water injection plants."
20.
5.1.5
30
"As noted previously, SEM considers H2S a proxy for potential C02
leaks in the field. Thus, detected H2S leaks will be investigated to
determine and, if needed, quantify potential C02 leakage. If the
incident results in a work order, this will serve as the basis for
tracking the event for GHG reporting."
Please clarify whether and how the H2S monitoring data will be
used for quantifying C02 leakage.
The sentence has been reworded. "Thus, detected H2S leaks will be
investigated to determine if a potential C02 leakage is present, but
not used to determine the leak volume.
21.
7.2
33
C02,u = Annual C02 mass recycled (metric tons) as measured by
flow meter u."
In Equation RR-5, this variable is "COz.u = Annual C02 mass injected
(metric tons) through flow meter" Equations and variables cannot
be modified from the regulations. Please revise this section and
ensure that all equations listed are consistent with the text in 40
CFR 98.443 (https://www.ecfr.gov/current/title-40/chapter-
l/subchapter-C/part-98/subpart-RR#98.443). Please also note that
equation variables cannot be removed even if the term itself is
expected to be zero.
The equations included in the MRV Plan directly referenced 40 CFR
98.443. We have revised the equations for legibility, but believe
they are a direct reference to the equations listed in 40 CFR 98.443.
-------
No.
MRV Plan
EPA Questions
Responses
Section
Page
22.
"SEM will calculate and report the total annual Mass of C02 emitted
by Surface Leakage using an approach that is tailored to specific
leakage events and relies on 40 CFR Part 98 Subpart W reports of
equipment leakage."
Please elaborate how potential C02 leakage would be quantified
from the identified potential surface leakage pathways. Please note
that subpart W procedures apply only to equipment leaks, and
quantification strategies for other types of leakage pathways should
be identified in the MRV plan. Please provide example
quantification strategies that might be used to calculate leakage
from the various identified pathways.
Additionally, please note that surface leakage as described in RR-10
is different from equipment leaks (C02fl and C02FP in equation RR-
11). Please revise this section as necessary to reflect this.
Clarified that 40 CFR Part 98 Subpart W would be used for
equipment leaks only. Some items that will be taken into account
for quantification are flow rate, pressures, size of leak opening, and
duration of the leak to help calculate the quantity of C02 leakage.
-------
No.
MRV Plan
EPA Questions
Responses
Section
Page
23.
9
37
'The point of measurement for the quantity of C02 produced from
oil or other fluid production wells is a flow meter directly
downstream of each separator that sends a stream of gas into a
recycle or end use system."
However, Section 5.1.4 states that, "C02 produced is calculated
using the volumetric flow meters at the inlet to the C02 Reinjection
Facility."
Also, Section 7.3 states that, "The Mass of C02 Produced at the
Rangely Field will be calculated using the measurements from the
flow meters at the inlet to RCF and the custody transfer meter for
oil sales rather than the metered data from each production well."
Please ensure that flow meter locations are consistent throughout
the MRV plan. Flow meter locations cannot be modified from the
regulations (e.g., C02 produced must be measured from a
flowmeter "downstream of each separator"). Please revise this
section and ensure that all flow meter locations are consistent with
the text in 40 CFR 98.444 (https://www.ecfr.gov/current/title-
40/chapter-l/subchapter-C/part-98/subpart-RR#98.444).
The MRV Plan has been reviewed and Section 9.1 has been revised
for consistency.
-------
No.
MRV Plan
EPA Questions
Responses
Section
Page
24.
8
N/A
Per 40 CFR 98.448(7), MRV plans are required to provide:
"Proposed date to begin collecting data for calculating total amount
sequestered according to equation RR-11 or RR-12 of this subpart.
This date must be after expected baselines as required by
paragraph (a)(4) of this section are established and the leakage
detection and quantification strategy as required by paragraph
(a)(3) of this section is implemented in the initial AMA."
Please clarify whether the MRV plan includes such a date. For
reference, see https://www.ecfr.gov/current/title-40/chapter-
l/subchapter-C/part-98/subpart-RR#98.448.
Section 8 of the MRV Plan identifies that "The activities described in
this MRV Plan are in place, and reporting is planned to start upon
EPA approval."
-------
Scout Energy Management, LLC
Rangely Field CO2
Subpart RR Monitoring, Reporting and Verification (MRV) Plan
-------
Table of Contents
Roadmap to the Monitoring, Reporting and Verification (MRV) Plan 3
1. Facility Information 4
2. Project Description 4
2.1 Project Characteristics 4
2.2 Environmental Setting 6
2.3 Description of C02 EOR Project Facilities and the Injection Process 13
Table 1 - Rangely Field Wells 16
3. Delineation of Monitoring Area and Timeframes 20
3.1 Active Monitoring Area 20
3.2 Maximum Monitoring Area 20
3.3 Monitoring Timeframes 20
4. Evaluation of Potential Pathways for Leakage to the Surface 21
4.1 Introduction 21
4.2 Existing Well Bores 21
4.3 Faults and Fractures 23
4.4 Natural or Induced Seismicity 23
4.5 Previous Operations 23
4.6 Pipeline / Surface Equipment 23
4.7 Lateral Migration Outside the Rangely Field 24
4.8 Drilling Through the C02 Area 24
4.9 Diffuse Leakage through the Seal 24
4.10 Monitoring, Response, and Reporting Plan for C02 Loss 24
4.11 Summary 26
5. Monitoring and Considerations for Calculating Site Specific Variables 26
5.1 For the Mass Balance Equation 27
5.2 To Demonstrate that Injected C02 is not Expected to Migrate to the Surface... 30
6. Determination of Baselines 31
7. Determination of Sequestration Volumes Using Mass Balance Equations 32
7.1. Mass of C02 Received 32
7.2 Mass of C02 Injected into the Subsurface 33
7.3 Mass of C02 Produced 34
7.4 Mass of C02 emitted by Surface Leakage 35
7.5 Mass of C02 sequestered in subsurface geologic formations 35
7.6 Cumulative mass of C02 reported as sequestered in subsurface geologic
formations 36
8. MRV Plan Implementation Schedule 36
9. Quality Assurance Program 36
9.1 Monitoring QA/QC 36
9.2 Missing Data Procedures 37
9.3 MRV Plan Revisions 38
10. Records Retention 38
11.Appendice s 38
2
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Roadmap to the Monitoring, Reporting and Verification (MRV) Plan
Scout Energy Management, LLC ("SEM") operates the Rangely Weber Sand Unit ("RWSU") and the
associated Raven Ridge pipeline ("RRPC"), (collectively referred to as the Rangely Field) in
Northwest Colorado for the primary purpose of enhanced oil recovery (EOR) using carbon dioxide
("C02") flooding. SEM has utilized, and intends to continue to utilize, injected C02 with a subsidiary
purpose of establishing long-term containment of a measurable quantity of C02 in subsurface
geological formations at the Rangely Field for a term referred to as the "Specified Period." During
the Specified Period, SEM will inject C02 that is purchased (fresh C02) from ExxonMobil's ("XOM")
Shute Creek Plant or third parties, as well as C02 that is recovered (recycled C02) from the Rangely
Field's C02 Recycle and Compression Facilities ("RCF's"). SEM has developed this monitoring,
reporting, and verification (MRV) plan in accordance with 40 CFR §98.440-449 (Subpart RR) to
provide for the monitoring, reporting and verification of the quantity of C02 sequestered at the
Rangely Field during the Specified Period.
SEM has chosen to submit this MRV plan to the EPA for approval according to 40 Code of Federal
Regulations (CFR) 98.440(c)(1), Subpart RR of the Greenhouse Gas Reporting Program for the
purpose of qualifying for the tax credit in section 45Q of the federal Internal Revenue Code.
This MRV plan contains eleven sections:
o Section 1 contains general facility information.
o Section 2 presents the project description. This section describes the planned injection volumes,
the environmental setting of the Rangely Field, the injection process, and reservoir modeling. It also
illustrates that the Rangely Field is well suited for secure storage of injected C02-
o Section 3 describes the monitoring area: the RWSU in Colorado.
o Section 4 presents the evaluation of potential pathways for C02 leakage to the surface. The
assessment finds that the potential for leakage through pathways other than the man-made well
bores and surface equipment is minimal.
o Section 5 describes SEM's risk-based monitoring process. The monitoring process utilizes SEM's
reservoir management system to identify potential C02 leakage indicators in the subsurface. The
monitoring process also utilizes visual inspection of surface facilities and personal H2S monitors
program as applied to Rangely Field. SEM's MRV efforts will be primarily directed towards managing
potential leaks through well bores and surface facilities.
o Section 6 describes the baselines against which monitoring results will be compared to assess
whether changes indicate potential leaks.
o Section 7 describes SEM's approach to determining the volume of C02 sequestered using the mass
balance equations in 40 CFR §98.440-449, Subpart RR of the Environmental Protection Agency's
(EPA) Greenhouse Gas Reporting Program (GHGRP). This section also describes the site-specific
factors considered in this approach.
o Section 8 presents the schedule for implementing the MRV plan.
o Section 9 describes the quality assurance program to ensure data integrity.
o Section 10 describes SEM's record retention program.
o Section 11 includes several Appendices.
3
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1. Facility Information
The Rangely Gas Plant, operated by SEM, reports under Greenhouse Gas Reporting Program
Identification number 537787.
The Colorado Oil and Gas Conservation Commission ("COGCC")1 regulates all oil, gas and geothermal
activity in Colorado. All wells in the Rangely Field (including production, injection and monitoring
wells) are permitted by COGCC through Code of Colorado Regulations ("CCR") 2 CCR 404-1:301.
Additionally, COGCC has primacy to implement the Underground Injection Control ("UIC") Class II
program in the state for injection wells. All injection wells in the Rangely Field are currently classified
as UIC Class II wells.
Wells in the Rangely Field are identified by name, API number, status, and type. The list of wells as
of April, 2023 is included in Appendix 5. Any new wells will be indicated in the annual report.
2. Project Description
This section describes the planned injection volumes, environmental setting of the Rangely Field,
injection process, and reservoir modeling conducted.
2.1 Project Characteristics
SEM utilized historic production and injection of the RWSU in order to create a production and
injection forecast, included here to provide an overview of the total amounts of C02 anticipated to
be injected, produced, and stored in the Rangely Field as a result of its current and planned C02
EOR operations during the forecasted period. This forecast is based on historic and predicted data.
Figure 1 shows the actual (historic) C02 injection, production, and stored volumes in the Rangely
Field from 1986, when Chevron initiated C02 flooding, through 2022 (solid line) and the forecast for
2023 through 2060 (dotted line). It is important to note that this is just a forecast; actual storage data
will be collected, assessed, and reported as indicated in Sections 5, 6, and 7 in this MRV Plan. The
forecast does illustrate, however, the large potential storage capacity at Rangely field.
1 Pursuant to Colorado SB21-285, effective July 1, 2023, the COGCC will become the Energy and Carbon
Management Commission.
4
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Rangely Field
Historical and Projected C02
6000
T3
£
(O
LO
3
O
5000
ro
a>
>-
ai
a.
4000
3000
2000
1000
uvAV
C02 Production
try""
C02 Stored
Forecast C02 Stored
u v
JL
C02 Injection
Forecast C02 Injection
IDO^-OOINIDO^-OOINIDO^-OOINIDO^-OO
00CT>CT>CT>OO*H*H*H(N(Nr0r0r0^-^-L/lL/lL/l
aiaiaiaiooooooooooooooo
*H*H*H*H(N(N(N(N(N(N(N(N(N(N(N(N(N(N(N
Year
Figure 1 - Rangely Field Historic and Forecast C02 Injection, Production, and Storage
The amount of C02 injected at Rangely Field is adjusted periodically to maintain reservoir pressure
and to increase recovery of oil by extending or expanding the EOR project. The amount of C02
injected is the amount needed to balance the fluids removed from the reservoir and to increase oil
recovery. While the model output shows C02 injection and storage through 2060, this data is for
planning purposes only and may not necessarily represent the actual operational life of the Rangely
Field EOR project. As of the end of 2022, 2,320 BCF (122.76 million metric tons (MMMT)) of C02
has been injected into Rangely Field. Of that amount, 1,540 BCF (81.48 MMMT) was produced and
recycled.
While tons of 002 injected and stored will be calculated using the mass balance equations described
in Section 7, the forecast described above reflects that the total amount of 002 injected and stored
over the modeled injection period to be 967 BCF (51.2 MMMT). This represents approximately 35.7%
of the theoretical storage capacity of Rangely Field.
Figure 2 presents the cumulative annual forecasted volume of C02 stored by year through 2060,
the modeling period for the projection in Figure 1. The cumulative amount stored is equal to the sum
of the annual storage volume for each year plus the sum of the total of the annual storage volume for
each previous year. As is typical with C02 EOR operations, the rate of accumulation of stored C02
tapers over time as more recycled C02 is used for injection. Figure 2 illustrates the total cumulative
storage over the modeling period, projected to be 967 Bscf (51.2 MMMT) of 002-
5
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Rangely Field
Historical and Forecast Cumulative C02 Storage
60000
to
T3
C
ro
to
° 50000
40000
30000
20000
10000
. .ill
lDCT>(NL/100*H^-|^Or0lDCT>(NL/100*-l^-|^Or0lDCT>(NL/100
00 00CT>CT>CT>OOO*H*H*H*H(N(N(Nr0r0r0^-^-^-^-L/lL/lL/l
aiaiaiaiaioooooooooooooooooooo
*H*H*H*H*H(N(N(N(N(N(N(N(N(N(N(N(N(N(N(N(N(N(N(N(N
Years
Figure 2 - Rangely Field Cumulative C02 Storage
2.2 Environmental Setting
The project site for this MRV plan is the Rangely Field, located on the Douglas Creek Arch between
the Uinta Basin and Piceance Basin in Colorado.
2.2.1 Geology of the Rangely Field
The Rangely Field is a Pennsylvanian-Permian age (~310-275 Mya) sandstone reservoir (Weber)
located in the northwest corner of Colorado in Rio Blanco County. The field is located within the
Rocky Mountain province between the Douglas Creek Arch (south) and the Uinta Mountains
(north). To the east and west are the Piceance and Uinta Basins respectfully (see Figure 3). More
locally, north of the Douglas Creek Arch and around the Rangely filed are a series of large thrust
faults which shaped the overall structure of the subsurface. These asymmetrical anticlines are
doubly plunging creating a dome shape trap allowing for the vast amounts of hydrocarbons to
accumulate within.
6
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Figure 3 - Regional map showing Rangely's position between the Uinta and Piceance Basin.
The reservoir, Weber sandstone, is comprised of clean eolian quartz deposited in an erg (sand
sea) depositional environment. Internally, these dune sands are separated into six main packages
(odd numbers, 1 to 11) with the fluvial Maroon Formation (even numbers, 2 to 10) interfingering the
field from the north. The Weber Formation is underlain by the fossiliferous Desmoinesian
carbonates of the Morgan Formation, and overlain by the siltstones and shales of the
Phosphoria/Park City and Moenkopi Formations.
For the majority of the region, the Phosphoria Formation acts as an impermeable barrier above the
Weber Formation and is a hydrocarbon source for the overlying strata. However, due to the large
thrust fault south and west of the field, the Phosphoria Formation was driven down to significantly
deeper depths, and below the reservoir Weber sands, allowing for maturation and expulsion of the
hydrocarbons to migrate upward into stratigraphically older, but structurally shallower reservoirs
sometime during the Jurassic. At Rangely, the Phosphoria Formation is almost entirely missing
above the Weber Formation, but the Moenkopi Formation sits directly above the sands creating
the seal for the petroleum system.
Fresh water in and around the town/field of Rangely is sourced from the quaternary creeks and
rivers that cut across the region (data obtained from the Colorado Division of Water Resources).
No large fresh water aquifers are present between the reservoir rock and the surface. Safety
measures are still taken to protect the shallowest of rocks that contain rain water seepage into the
Mancos Formation (surface exposure at Rangely) illustrated by the surface casing on Figure 4. The
shallowest point of the reservoir is 5,486 ft below the surface (4,986 ft below any possible fresh
water). The mere presence of hydrocarbons and the successful implication of a C02 flood
indicates the quality and effectiveness of the seal to isolate this reservoir from higher strata.
7
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Uinta Basin
Douglas Creek
Arch
Piceance Basin
ichesne River and Uinta Fms
CoKon Fm
Wasatch Fr
Wasatch and
Fort Union Fms
k I r_.
rm
Blackhawk Fm
Ferron Ss Mbr of Ma cos Sh and Frontu
Dakota Ss
Sue hem Cgl Mbr
Salt Wash Ss O O
Morrison Fm
O Entrada Ss O
Glen Canyon Ss
Cftnle Fm
Moenkep. Fm
Source
__ParY. City Fm
upper Weber Ss
Reservoir
Maroon
cr_ Fm
Round Valley Ls
Manning Canyon Sh
Doughnut Sh/Humbug Fm
Deseret Ls
Leadville Ls
Madison Ls
Pinyon.
-TfeniWU rf"
Dotsero Fm
Lodore Fm
Sawatch Ss
KEY
PETROLEUM
SYSTEMS:
I| Green River
system
I| Mesaverde
system
l| Mancos/Mowry
system
I| Phosphoria
system SOUTCe
Grassy Trail
° Creek oil
~ Mtnturn system
,, SignFficant oil production
{indicating source rock)
v./ Significant gas production
^ (indicating source rock)
S Source rocks
(R) Rangely Field
Main reservoir
I I Hiatus
Stratigraphy
at Rangely
Figure 4. Stratigraphic Column of formations at the Rangely Field. Due to a large fault the source
rock (Phosphoria) is stratigraphically above the reservoir rock (Weber), but structurally, the
source lies below the reservoir, (from U.S. Geological Survey, 2003)
Figure 5 shows the doubly plunging anticline with the long axis along a northwest-southeast trend
and the short axis along a northeast-southwest trend. In 1949 the depth of a gas cap was
established at -330 ft subsea and an Oil Water Contact (OWC) at -1150 ft subsea. Many core
analysis suggest that below this -1150' OWC is a transition/residual oil zone. However, for the
8
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purpose of this analysis and all volumetrics the base of the reservoir will be at the -1150' subsea
depth determined in 1949,
Figure 5. Structure map of the Weber 1 (top of reservoir). Colors illustrate the maximum aerial
coverage of the Gas Cap (Red), Main Reservoir (Green), and Transitional Reservoir (Blue). Cross
section A-A' is predominantly along the long axis of the field and B-B' is along the short axis.
The Rangely Field has one main field fault (MFF) and numerous smaller faults and fractures that
are present throughout the stratigraphic column between the base of the reservoir and surface.
The MFF has a NE-WSW trend and cuts through the reservoir interval. In the 1960's Rangely
residents began experiencing felt earthquakes. Between 1969 and 1973, a joint investigation with
the USGS installed seismic monitoring stations in and around the town of Rangely and began
recording activity. In 1971, a study was conducted to evaluate the stress state in the vicinity of the
fault which determined a critical fluid pressure above which fault slippage may occur. Reservoir
pressure was then manipulated and correlated with increases or decreases in seismic activity. This
study determined that the waterflood in Rangely was inducing seismicity when reservoir pressure
was raised above ~373Q psi.
In the 1990's, field reservoir pressure had built back up leading to the largest magnitude
earthquake in Rangely which took place in 1995 (M 4.5), shortly after maximum reservoir pressure
was reached in 1998. Pressure maintenance began and seismic activity dropped off after lowering
the average field reservoir pressure down to ~3100 psi. No other seismic activity was recorded
around the field until 2015 and 2017 when there was a total of 5 seismic events (see Figure 6)
around the northeastern portion of the MFF. A new interpretation from the 3D seismic revealed a
series of previously unknown joint faults (perpendicular to the MFF). Investigation into this region
revealed that the -3750 psi threshold had been crossed and triggered the seismic events. Since
the 2017 seismic events, no other events have been recorded of felt magnitude and continued
9
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pressure monitoring further reduces the risk of another event.
2017 Induced
Seismic Study*
Figure 6. USGS fault history map (1900-2023). Largest earthquake was the 1995 M 4.5 north of
the unit. (*2017 was a study to induce seismic activity along the Main Field Fault, and not
caused by day-to-day operations)
The natural fractures found within the field play a significant role in fluid flow. The subsurface
natural fractures are vertical and show an approximately ENE trend and their extension joints are
orientated ESE. Shallower portions of the reservoir show a distinctly higher density of fractures
than deeper portions. On the shallow dipping sides of the anticline, there does not appear to be a
strong structural control on fracture density. Most well-to-weii rapid breakthrough of injected CO2
is along these ENE fractures. It is unknown if this is from natural or induced fractures. There is no
evidence that these natural fractures diminish the seals integrity.
10
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Transition Zone & ROZ
Figure 7. Cross section A-A' along the long axis of the field, and perpendicular to the main field
fault (MFF). The MFF does not have much displacement and is near vertical.
The Rangeiy Field has approximately 1.9 billion barrels of Original Oil in Place (OOIP). Since first
discovered in 1933, Rangeiy Field has produced 920 million barrels of oil, or 48% of the OOIP. The
Rangeiy Field has an aerial extent of approximately 19,150 acres with an average gross thickness
of 650 ft. The previously mentioned 11 internal layers of the reservoir, alternating zones of Weber
and Maroon Formations, can be simplified to only three sections. The Upper Weber contains
intervals 1-3, the Middle Weber contains intervals 4-7, and the Lower Weber contains intervals 8-
approxamently 50 ft below the 11D marker (identified by the base of the yellow in Figure 7). These
interval groupings were determined by the extensive lateral continuingly and thickness of the
Weber 4 and Weber 8 which easily separate the reservoir into the three zones. For the majority of
the Rangeiy Field, the even Maroon Formations act as flow barriers between the odd Weber
Formations. Average porosity within the Weber sand dune facies is 10.3% and within the Maroon
fluvial facies is 4.9%. However, the key factor that enables the Maroon Formation to be a seal is its
lack of permeability. The Weber dune facies have an average permeability of 2.44 md, while the
Maroon fluvial facies have an average permeability of 0.03 md.
11
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B -SW
SuM««
Depenfflf-
B' - NE
Figure 8. Cross section B-B' along the short axis of the field and parallel to the MFF. Used to
illustrate the variation of the Oil Water Contact (OWC).
Given that the Rangely Field is located at the highest subsurface elevations of the structure, that the
confining zone has proved competent over both millions of years and throughout decades of EOR
operations, and that the Rangely Field has ample storage capacity, SEM is confident that stored C02
will be contained securely within the Weber Sands reservoir in the Rangely Field.
2.2.2 Operational History of the Rangely Field and Rangely Field
The Rangely Field was discovered in 1933 but subsequently ceased production until World War I!
when oil returned to high demand. Intensive development began, expanding from one well to 478
wells by 1949. It is located in the northwestern portion of Colorado.
The Rangely Field was originally developed by Chevron. Following the initial discover in 1933,
Chevron imitated a 40-acre development in 1944, followed by hydrocarbon gas injection
from 1950 to 1969. To improve efficiency, in 1957, the Rangely Unit was formed (See Figure 9).
12
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Figure 9 - Rangely Field Map
Chevron began C02 flooding of the Rangely Field in 1986 and has continued and expanded it since
that time. The experience of operating and refining the Rangely Field C02 floods over the past
decade has created a strong understanding of the reservoir and its capacity to store C02.
2.3 Description of C02 EOR Project Facilities and the Injection Process
Figures 10 shows a simplified flow diagram of the project facilities and equipment in the Rangely
Field. C02 is delivered to the Rangely Field via the Raven Ridge Pipeline. The C02 injected into the
Rangely Field is currently supplied by XOM's Shute Creek Plant into the pipeline system.
Once C02 enters the Rangely Field there are four main processes involved in EOR operations. These
processes are shown in Figure 10 and include:
1. C02 Distribution and Injection. Purchased C02 and recycled C02 from the RCF is sent through the
main C02 distribution system to various C02 injectors throughout the Field.
2. Produced Fluids Handling. Produced fluids gathered from the production wells are sent to collection
stations for separation into a gas/C02 mix and a produced fluids mix of water, oil, gas, and C02.
The produced fluids mix is sent to centralized water plants where oil is separated for sale into a
pipeline, water is recovered for reuse, and the remaining gas/C02 mix is merged with the output
from the collection stations. The combined gas/C02 mix is sent to the RCF and natural gas liquids
13
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(NGL) Plant, Produced oil is metered and sold; water is forwarded to the water injection plants for
treatment and reinjection or disposal,
3. Produced Gas Processing. The gas/C02 mix separated at the satellite batteries goes to the RCF
and NGL Plant where the NGLs, and C02 streams are separated. The NGLs move to a commercial
pipeline for sale. The remaining C02 (e.g., the recycled C02) is returned to the C02 distribution
system for reinjection.
4. Water Treatment and Injection, Water separated in the tank batteries is processed at water plants
to remove any remaining oil and then distributed throughout the Rangely Field for reinjection.
LaBarge Field/
Shute Creek Plant
(T) Rangely Field
1st/2nd Stage
Compression
Figure 10 Rangely Field -General Production Flow Diagram
2.3.1 CO2 Distribution and Injection.
SEM purchases CQ2 from XOM and receives it via the Raven Ridge Pipeline through one custody
transfer metering point, as indicated in Figures 10, Purchased CG2 and recycled C02 are sent
through the CG2 trunk lines to multiple distribution lines to individual injection wells. There are
volume meters at the inlet and outlet of the C02 Reinjection Facility.
As of April 2023, SEM has approximately 280 injection wells in the Rangely Field. Approximately 160
MMscf of CG2 is injected each day, of which approximately 15% is purchased C02, and the balance
(85%) is recycled. The ratio of purchased C02 to recycled C02 is expected to change over time,
and eventually the percentage of recycled CG2 will increase and purchases of fresh C02 will taper
off as indicated in Section 2,1.
Each injection well is connected to a WAG manifold located at the well pad. WAG manifolds are
manually operated and can inject either C02 or water at various rates and injection pressures as
specified in the injection plans. The length of time spent injecting each fluid is a matter of continual
optimization that is designed to maximize oil recovery and minimize CG2 utilization in each injection
pattern. A WAG manifold consists of a dual-purpose flow meter used to measure the injection rate
14
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of water or C02, depending on what is being injected. Data from these meters is sent to the SCADA
system where it is compared to the injection plan for that well, As described in Sections 5 and 7,
data from the WAG manifolds, visual inspections of the injection equipment, and use of the
procedures contained in 40 CFR §98.230-238 (Subpart W), wili be gathered to complete the mass
balance equations necessary to determine annual and cumulative volumes of stored C02.
2.3.2 Wells in the Ran gely Field
As of April 2023, there are 662 active wells that are completed in the Rangely Field, roughly evenly
split between production and injection wells, as indicated in Figure 11.2 Table 1 shows these well
counts in the Rangely Field by status.
Figure 11 Rarigely Field Wells-As of April 2023
2 Wells that are not in use are deemed to be inactive, plugged and abandoned, temporarily
abandoned, or shut in.
15
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Table 1 - Rangely Field Wells
Age/Completion of Well
Active
Shut-in
Temporarily
Abandoned
Plugged and
Abandoned
Drilled & Completed in the
1940's
263
6
55
147
Drilled 1950-1985
296
7
55
40
Completed after 1986
103
1
11
7
TOTAL
662
14
121
194
The wells in Table 1 are categorized in groups that relate to age and completion methods. Roughly
48% of these wells were drilled in the 1940's and were generally completed with three strings of
casing (with surface and intermediate strings typically cemented to the surface). The production
string was typically installed to the top of the producing interval, otherwise known as the main oil
column (MOC), which extends to the producible oil/water contact (POWC). These wells were
completed by stimulating the open hole (OH), and are not typically cased through the MOC. While
implementing the water flood from 1958-1986, a partial liner would have been typically installed to
allow for controlled injection intervals and this liner would have been cemented to the top of the
liner (TOL) that was installed. For example, a partial liner would be installed from 5,700-6,500 ft,
and the TOO would be at 5,700 ft. The casing weights used for the production string have varied
between 7" 23 & 26#/ft. with 5 " 18 #/ft. for the production liner.
The wells in Table 1 drilled during the period 1950-1986 typically were cased through the
production interval with 7" casing. Some wells were completed with 7" casing to the top of the
MOC and then completed with a 5" liner through the productive interval. The wells with liners ran
would have had cement to the TOL.
The remaining wells (roughly 12%) in Table 1 were drilled after 1986 when the C02 flood began. All
of these wells were completed with 7" casing through the POWC. Very few of these wells have
experienced any wellbore issues that would dictate the need for a remedial liner.
SEM reviews these categories along with full wellbore history when planning well maintenance
projects. Further, SEM keeps well workover crews on call to maintain all active wells and to
respond to any wellbore issues that arise. On average, in the Rangely Field there are two to three
incidents per year in which the well casing fails. SEM detects these incidents by monitoring
changes in the surface pressure of wells and by conducting Mechanical Integrity Tests (MITs), as
explained later in this section and in the relevant regulations cited. This rate of failure is less than
2% of wells per year and is considered extremely low.
All wells in oilfields, including both injection and production wells described in Table 1, are
regulated by the COGCC under COGCC 100-1200 series rules. A list of wells, with well
identification numbers, is included in Appendix 5. The injection wells are subject to additional
requirements promulgated by EPA - the UIC Class II program - implementation of which has been
delegated to the COGCC.
COGCC rules govern well siting, construction, operation, maintenance, and closure for all wells in
oilfields. Current rules require, among other provisions, that:
Class II UIC Wells will not be permitted in areas where they would inject into a formation that
is separated from any Underground Source of Drinking Water by a Confining Layer with
known open faults or fractures that would allow flow between the Injection Zone and
16
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Underground Source of Drinking Water within the area of review.
Injection Zones will not be permitted within 300 feet in a vertical dimension from the top of
any Precambrian basement formation.
An Operator will not inject any Fluids or other contaminants into a UIC Aquifer that meets
the definition of an Underground Source of Drinking Water unless EPA has approved a UIC
Aquifer exemption as described in Rule 802.e.
In addition, SEM implements a corrosion protection program to protect and maintain the steel used
in injection and production wells from any C02-enriched fluids. SEM currently employs methods to
mitigate both internal and external corrosion of casing in wells in the Rangely Field. These methods
generally protect the downhole steel and the interior and exterior of well bores through the use of
special materials (e.g. fiberglass tubing, corrosion resistant cements, nickel plated packers,
corrosion resistant packer fluids) and procedures (e.g. packer placement, use of annular leakage
detection devices, cement bond logs, pressure tests). These measures and procedures are typically
included in the injection orders filed with the COGCC. Corrosion protection methods and
requirements may be enhanced over time in response to improvements in technology.
Mechanical Integrity Testing (MIT)
SEM complies with the MIT requirements implemented by COGCC and BLM to periodically inspect
wells and surface facilities to ensure that all wells and related surface equipment are in good repair
and leak-free, and that all aspects of the site and equipment conform with Division rules and permit
conditions. All active injection wells undergo an MIT at the following intervals:
Before injection operations begin;
Every 5 years as stated in the injection orders (COGCC 417.a. (1));
After any casing repair
After resetting the tubing or mechanical isolation device
Or whenever the tubing or mechanical isolation device is moved during workover operations
COGCC requires that the operator notify the COGCC district office prior to conducting an MIT.
Operators are required to use a pressure recorder and pressure gauge for the tests. The operator's
field representative must sign the pressure recorder chart along with the COGCC field
representative and submit it with the MIT form. The casing-tubing annulus must be tested to a
minimum of 1200 psi for 15 minutes.
If a well fails an MIT, the operator must immediately shut the well in and provide notice to COGCC.
Casing leaks must be successfully repaired and retested or the well plugged and abandoned after
submitting a formal notice and obtaining approval from the COGCC.
Any well that fails an MIT cannot be returned to active status until it passes a new MIT
2.3.3 Produced Fluids Handling
As injected C02 and water move through the reservoir, a mixture of oil, gas, and water (referred to
as "produced fluids") flows to the production wells. Gathering lines bring the produced fluids from
each production well to collection stations. SEM has approximately 382 active production wells in
the Rangely Field and production from each is sent to one of 27 collection stations. Each collection
station consists of a large vessel that performs a gas - liquid separation. Each collection station also
has well test equipment to measure production rates of oil, water and gas from individual production
wells. SEM has testing protocols for all wells connected to a collection station. Most wells are tested
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twice per month. Some wells are prioritized for more frequent testing because they are new or
located in an important part of the Field; some wells with mature, stable flow do not need to be
tested as frequently; and finally, some wells do not yield solid test results necessitating review or
repeat testing.
After separation, the gas phase is transported by pipeline to the C02 reinjection facility for
processing as described below. Currently the average composition of this gas mixture as it enters
the facility is 92% C02 and 800ppm H2S; this composition will change over time as C02 EOR
operations mature.
The liquid phase, which is a mixture of oil and water, is sent to one of two centralized water plants
where oil is separated from water via two 3-phase separators. The water is then sent to water
holding tanks where further separation is done.
The separated oil is metered through the Lease Automatic Custody Transfer (LACT) unit located at
the custody transfer point between Chevron pipeline and SEM. The oil typically contains a small
amount of dissolved or entrained C02. Analysis of representative samples of oil is conducted once
a year to assess C02 content.
The water is removed from the bottom of the tanks at the water injection stations, where it is re-
injected to the WAG injectors.
Any gas that is released from the liquid phase rises to the top of the tanks and is collected by a
Vapor Recovery Unit (VRU) that compresses the gas and sends it to the C02 reinjection facility for
processing.
Rangely oil is slightly sour, containing small amounts of hydrogen sulfide (H2S), which is highly toxic.
There are approximately 25 workers on the ground in the Rangely Field at any given time, and all
field personnel are required to wear H2S monitors at all times. Although the primary purpose of H2S
detectors is protecting employees, monitoring will also supplement SEM's C02 leak detection
practices as discussed in Sections 5 and 7.
In addition, the procedures in 40 CFR §98.230-238 (Subpart W) and the two-part visual inspection
process described in Section 5 are used to detect leakage from the produced fluids handling system.
As described in Sections 5 and 7, the volume of leaks, if any, will be estimated to complete the mass
balance equations to determine annual and cumulative volumes of stored C02.
2.3.4 Produced Gas Handling
Produced gas gathered from the collection stations, and water injection plants is sent to the C02
reinjection facility. There is an operations meter at the facility inlet.
Once gas enters the C02 reinjection facility, it undergoes dehydration and compression. In the
RWSU an additional process separates NGLs for sale. At the end of these processes there is a C02
rich stream that is recycled through re-injection. Meters at the facility outlet are used to determine
the total volume of the C02 stream recycled back into the EOR operations.
As described in Section 2.3.4, data from 40 CFR §98.230-238 (Subpart W), the two-part visual
inspection process for production wells and areas described in Section 5, and information from the
personal H2S monitors are used to detect leakage from the produced gas handling system. This
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data will be gathered to complete the mass balance equations necessary to determine annual and
cumulative volumes of stored C02 as described in Sections 5 and 7.
2.3.5 Water Treatment and Injection
Produced water collected from the collection stations is gathered through a pipeline system and
moved to one of two water injection plants. Each facility consists of 3-Phase separators and 79,500-
barrels of separation tanks where any remaining oil is skimmed from the water. Skimmed oil is
combined with the oil from the 3-Phase separators and sent to the LACT. The water is sent to an
injection pump where it is pressurized and distributed to the WAG injectors.
2.3.6 Facilities L ocations
The current locations of the various facilities in the Rangely Field are shown in Figure 13. As indicated
above, there are two central water plants. There are twenty-seven collections stations that gather
production from surrounding wells. The two water plants are identified by the blue triangle and circle.
The twenty-seven collection stations are identified by red squares. The C02 Reinjection facility is
indicated by the green circle.
COGCC requires that injection pressures be limited to ensure injection fluids do not migrate outside
the permitted injection interval. In the Rangely Field, SEM uses two methods to contain fluids:
reservoir pressure management and the careful placement and operation of wells along the outer
producing limits of the units.
Reservoir pressure in the Rangely Field is managed by maintaining an injection to withdrawal ratio
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(IWR) of approximately 1.0. To maintain the IWR, SEM monitors fluid injection to ensure that reservoir
pressure does not increase to a level that would fracture the reservoir seal or otherwise damage the
oil field.
SEM also prevents injected fluids from migrating out of the injection interval by keeping injection
pressure below the formation fracture pressure, which is measured using historic step-rate tests. In
these tests, injection pressures are incrementally increased (e.g., in "steps") until injectivity
increases abruptly, which indicates that an opening (fracture) has been created in the rock. SEM
manages its operations to ensure that injection pressures are kept below the formation fracture
pressure so as to ensure that the valuable fluid hydrocarbons and C02 remain in the reservoir.
There are a few small producer wells operated by third parties outside the boundary of Rangely
Field. There are currently no significant commercial operations surrounding the Rangely Field to
interfere with SEM's operations.
3. Delineation of Monitoring Area and Timeframes
3.1 Active Monitoring Area
Because C02 is present throughout the Rangely Field and retained within it, the Active Monitoring
Area (AMA) is defined by the boundary of the Rangely Field. The following factors were considered
in defining this boundary:
Free phase C02 is present throughout the Rangely Field: More than 2,320 Bscf (122.76 MMMT) tons
of C02 have been injected and recycled throughout the Rangely Field since 1986 and there has
been significant infill drilling in the Rangely Field, completing additional wells to further optimize
production. Operational results thus far indicate that there is C02 throughout the Rangely Field.
C02 injected into the Rangely Field remains contained within the field because of the fluid and
pressure management approaches associated with C02 EOR. Namely, maintenance of an IWR of
1.0 assures a stable reservoir pressure; managed leaseline injection and production wells are used
to retain fluids in the Rangely Field as indicated in Section 2.3.6; and operational results indicate that
injected C02 is retained in the Rangely Field.
Furthermore, over geologic timeframes, stored C02 will remain in the Rangely Field and will not
migrate downdip as described in Section 2.2.3, because the Rangely Field contains the area with
the highest elevation.
3.2 Maximum Monitoring Area
The Maximum Monitoring Area (MMA) is defined in 40 CFR §98.440-449 (Subpart RR) as including
the maximum extent of the injected C02 and a half-mile buffer bordering that area. As described in
the AMA section (Section 3.1), the maximum extent of the injected C02 is anticipated to be bounded
by the Rangely Field. Therefore, the MMA is the Rangely Field plus the half-mile buffer as required
by 40 CFR §98.440-449 (Subpart RR).
3.3 Monitoring Timeframes
SEM's primary purpose for injecting C02 is to produce oil that would otherwise remain trapped in
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the reservoir and not, as in UIC Class VI, "specifically for the purpose of geologic storage."3 During
a Specified Period, SEM will have a subsidiary purpose of establishing the long-term containment of
a measurable quantity of C02 in the Weber Sands formation in the Rangely Field. The Specified
Period will be shorter than the period of production from the Rangely Field. This is in part because the
purchase of new C02 for injection is projected to taper off significantly before production ceases
at Rangely Field, which is modeled through 2060. At the conclusion of the Specified Period, SEM
will submit a request for discontinuation of reporting. This request will be submitted when SEM can
provide a demonstration that current monitoring and model(s) show that the cumulative mass of C02
reported as sequestered during the Specified Period is not expected to migrate in the future in a
manner likely to result in surface leakage. It is expected that it will be possible to make this
demonstration within two to three years after injection for the Specified Period ceases based upon
predictive modeling supported by monitoring data. The demonstration will rely on two principles: 1)
that just as is the case for the monitoring plan, the continued process of fluid management during
the years of C02 EOR operation after the Specified Period will contain injected fluids in the Rangely
Field, and 2) that the cumulative mass reported as sequestered during the Specified Period is a
fraction of the theoretical storage capacity of the Rangely Field See 40 C.F.R. § 98.441 (b)(2)(H).
4. Evaluation of Potential Pathways for Leakage to the Surface
4.1 Introduction
Existing Well Bores
Faults and Fractures
Natural and Induced Seismic Activity
Previous Operations
Pipeline/Surface Equipment
Lateral Migration Outside the Rangely Field
Drilling Through the 002 Area
Diffuse Leakage Through the Seal
4.2 Existing Well Bores
As of April 2023, there are approximately 662 active SEM operated wells in the Rangely Field - split
roughly evenly between production and injection wells. In addition, there are approximately 135 wells
not in use, as described in Section 2.3.2.
Leakage through existing well bores is a potential risk at the Rangely Field that SEM works to prevent
by adhering to regulatory requirements for well drilling and testing; implementing best practices that
SEM has developed through its extensive operating experience; monitoring injection/production
performance, wellbores, and the surface; and maintaining surface equipment.
As discussed in Section 2.3.2, regulations governing wells in the Rangely Field require that wells be
completed and operated so that fluids are contained in the strata in which they are encountered and
that well operation does not pollute subsurface and surface waters. The regulations establish the
requirements that all wells (injection, production, disposal) must comply with. Depending upon the
purpose of a well, the requirements can include additional standards for evaluation and MIT. SEM's
3 EPA UIC Class VI rule, EPA 75 FR 77291, December 10, 2010, section 146.81(b).
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best practices include pattern level analysis to guide injection pressures and performance
expectations; utilizing diverse teams of experts to develop EOR projects based on specific site
characteristics; and creating a culture where all field personnel are trained to look for and address
issues promptly. SEM's practices, which include corrosion prevention techniques to protect the
wellbore as needed, as discussed in Section 2.3.2, ensures that well completion and operation
procedures are designed not only to comply with regulations but also to ensure that all fluids (e.g.,
oil, gas, C02) remain in the Rangely Field until they are produced through an SEM well.
As described in Section 5, continual and routine monitoring of SEM's well bores and site operations
will be used to detect leaks, including those from non-SEM wells, or other potential well problems,
as follows:
Well pressure in injection wells is monitored on a continual basis. The injection plans for each pattern
are programmed into the injection WAG controller, as discussed in Section 2.3.1, to govern the rate
and pressure of each injector. Pressure monitors on the injection wells are programmed to flag
pressures that significantly deviate from the plan. Leakage on the inside or outside of the injection
wellbore would affect pressure and be detected through this approach. If such excursions occur,
they are investigated and addressed. In the time that the Rangely Field has been under injection
both water and C02, very few excursions result in fluid migration out of the intended zone and that
leakage to the surface is very rare.
In addition to monitoring well pressure and injection performance, SEM uses the experience gained
over time to strategically approach well maintenance. SEM maintains well maintenance and
workover crews onsite for this purpose. For example, the well classifications by age and
construction method indicated in Table 1 inform SEM's plan for monitoring and updating wells. SEM
uses all of the information at hand including pattern performance, and well characteristics to
determine well maintenance schedules.
Production well performance is monitored using the production well test process conducted when
produced fluids are gathered and sent to a collection station. There is a routine cycle for each
collection station, with each well being tested approximately twice every month. During this cycle,
each production well is diverted to the well test equipment for a period of time sufficient to measure
and sample produced fluids (generally 24 hours). This test allows SEM to allocate a portion of the
produced fluids measured at the collection station to each production well, assess the composition
of produced fluids by location, and assess the performance of each well. Performance data are
reviewed on a routine basis to ensure that C02 flooding is optimized. If production is off plan, it is
investigated and any identified issues addressed. Leakage to the outside of production wells is not
considered a major risk because of the reduced pressure in the casing. Further, the personal H2S
monitors are designed to detect leaked fluids around production wells.
Finally, as indicated in Section 5, field inspections are conducted on a routine basis by field personnel.
On any day, SEM has approximately 25 personnel in the field. Leaking C02 is very cold and leads to
formation of bright white clouds and ice that are easily spotted. All field personnel are trained to
identify leaking C02 and other potential problems at wellbores and in the field. Any C02 leakage
detected will be documented and reported, quantified and addressed as described in Section 5.
Based on its ongoing monitoring activities and review of the potential leakage risks posed by well
bores, SEM concludes that it is mitigating the risk of C02 leakage through well bores by detecting
problems as they arise and quantifying any leakage that does occur. Section 4.10 summarizes how
SEM will monitor C02 leakage from various pathways and describes how SEM will respond to
various leakage scenarios. In addition, Section 5 describes how SEM will develop the inputs used in
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the Subpart RR mass-balance equation (Equation RR-11). Any incidents that result in C02 leakage
up the wellbore and into the atmosphere will be quantified as described in Section 7.4.
4.3 Faults and Fractures
After reviewing geologic, seismic, operating, and other evidence, SEM has concluded that there are
no known faults or fractures that transect the Weber Sands reservoir in the project area. As
described in Section 2.2.1, faults have been identified in formations that are thousands of feet below
the Weber Sands formation, but this faulting has been shown not to affect the Weber Sands or to
have created potential leakage pathways.
SEM has extensive experience in designing and implementing EOR projects to ensure injection
pressures will not damage the oil reservoir by inducing new fractures or creating shear. As a
safeguard, injection satellites are set with automatic shutoff controls if injection pressures exceed
fracture pressures.
4.4 Natural or Induced Seismicity
After reviewing the literature and actual operating experience, SEM concludes that there is no direct
evidence that natural seismic activity poses a significant risk for loss of C02 to the surface in the
Rangely Field.
Since the 2017 seismic events, no other events have been recorded of felt magnitude and continued
pressure monitoring further reduces the risk of another induced event. Moreover, SEM is not aware
of any reported loss of injectant (waste water or C02) to the surface associated with any seismic
activity, natural or induced.
4.5 Previous Operations
Chevron initiated C02 flooding in the Rangely Field in 1986. SEM and the prior operators have kept
records of the site and have completed numerous infill wells. SEM has not drilled any new wells in
Rangely to date but their standard practice for drilling new wells includes a rigorous review of nearby
wells to ensure that drilling will not cause damage to or interfere with existing wells. SEM will also
follow AOR requirements under the UIC Class II program, which require identification of all active
and abandoned wells in the AOR and implementation of procedures that ensure the integrity of those
wells when applying for a permit for any new injection well. These practices ensure that identified
wells are sufficiently isolated and do not interfere with the C02 EOR operations and reservoir
pressure management. Consequently, SEM's operational experience supports the conclusion that
there are no unknown wells within the Rangely Field that penetrate the weber sands and that it has
sufficiently mitigated the risk of migration from older wells.
4.6 Pipeline/Surface Equipment
Damage to or failure of pipelines and surface equipment can result in unplanned losses of C02. SEM
reduces the risk of unplanned leakage from surface facilities, to the maximum extent practicable, by
relying on the use of prevailing design and construction practices and maintaining compliance with
applicable regulations. The facilities and pipelines currently utilize and will continue to utilize
materials of construction and control processes that are standard for C02 EOR projects in the oil and
gas industry. As described above, all facilities in the Rangely Field are internally screened for
proximity to the public. In the case of pipeline and surface equipment, internal guidelines call for
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more robust design and operating requirements to prevent and detect leakage. Operating and
maintenance practices currently follow and will continue to follow demonstrated industry standards.
C02 delivery via the Raven Ridge pipeline system will continue to comply with all applicable
regulations. Finally, frequent routine visual inspection of surface facilities by field staff will provide
an additional way to detect leaks and further support SEM's efforts to detect and remedy any leaks
in a timely manner. Should leakage be detected from pipeline or surface equipment, the volume of
released C02 will be quantified following the requirements of Subpart W of EPA's GHGRP.
4.7 Lateral Migration Outside the Rangely Field
It is highly unlikely that injected C02 will migrate downdip and laterally outside the Rangely Field
because of the nature of the geology and the approach used for injection. First, as indicated in
Section 2.2.1 "Geology of the Rangely Field," the Rangely Field is situated at the top of a dome
structural trap, with all directions pointing down-dip from the highest point. This means that over
long periods of time, injected C02 will tend to rise vertically towards the point in the Rangely Field
with the highest elevation. Second, the planned injection volumes and active fluid management
during injection operations will prevent C02 from migrating laterally stratigraphically (down-dip
structurally) out of the structure. Finally, SEM will not be increasing the total volume of fluids in the
Rangely Field. Based on site characterization and planned and projected operations SEM estimates
the total volume of stored C02 will be approximately 35.7% of calculated capacity.
4.8 Drilling Through the C02 Area
It is possible that at some point in the future, drilling through the containment zone into the Weber
Sands could occur and inadvertently create a leakage pathway. SEM's review of this issue concludes
that this risk is very low for two reasons. First, SEM's visual inspection process, including routine
site visits, is designed to identify unapproved drilling activity in the Rangely Field. Second, SEM plans
to operate the C02 EOR flood in the Rangely Field for several more years, and will continue to be
vigilant about protecting the integrity of its assets and maximizing the potential of resources (oil,
gas, C02). In the unlikely event SEM would sell the field to a new operator, provisions would result
in a change to the reporting program and would be addressed at that time.
4.9 Diffuse Leakage through the Seal
Diffuse leakage through the seal formed by the Moenkopi Formation is highly unlikely. The
presence of a gas cap trapped over millions of years as discussed in Section 2.2.3 confirms that
the seal has been secure for a very long time. Injection pattern monitoring program referenced in
Section 2.3.1 and detailed in Section 5 assures that no breach of the seal will be created. The seal
is highly impermeable where unperforated, cemented across the horizon where perforated by
wells, and unexplained changes in injection pressure would trigger investigation as to the cause.
Further, if C02 were to migrate through the Moenkopi seal, it would migrate vertically until it
encountered and was trapped by any of the numerous shallower shale seals
4.10 Monitoring, Response, and Reporting Plan for C02 Loss
As discussed above, the potential sources of leakage include fairly routine issues, such as problems
with surface equipment (pumps, valves, etc.) or subsurface equipment (well bores), and unique
events such as induced fractures. Table 3 summarizes some of these potential leakage scenarios,
the monitoring activities designed to detect those leaks, SEM's standard response, and other
applicable regulatory programs requiring similar reporting.
Sections 5.1.5 - 5.1.7 discuss the approaches envisioned for quantifying the volumes of leaked C02-
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Given the uncertainty concerning the nature and characteristics of leaks that will be encountered,
the most appropriate methods for quantifying the volume of leaked C02 will be determined at the
time. In the event leakage occurs, SEM plans to determine the most appropriate methods for
quantifying the volume leaked and will report it as required as part of the annual Subpart RR
submission.
Any volume of C02 detected leaking to surface will be quantified using acceptable emission factors
such as those found in 40 CFR Part 98 Subpart W or engineering estimates of leak amounts based on
measurements in the subsurface, SEM's field experience, and other factors such as the frequency of
inspection. As indicated in Sections 5.1 and 7.4, leaks will be documented, evaluated and addressed
in a timely manner. Records of leakage events will be retained in the electronic environmental
documentation and reporting system. Repairs requiring a work order will be documented in the
electronic equipment maintenance system.
Table 3 Response Plan for C02 Loss
Risk
Monitoring Plan
Response Plan
Parallel
Reporting (if
any)
Loss of Well Control
Tubing Leak
Monitor changes in tubing and
annulus pressure; MIT for injectors
Well is shut in and
Workover crews
respond within days
COGCC
Casing Leak
Routine Field inspection; monitor
changes in annulus pressure; MIT
for injectors; extra attention to high
risk wells
Well is shut in and
Workover crews
respond within days
COGCC
Wellhead Leak
Routine Field inspection
Well is shut in and
Workover crews
respond within days
COGCC
Loss of Bottom-
hole
pressure control
Blowout during well operations
Maintain well kill
procedures
COGCC
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Unplanned wells
drilled through
Weber Sands
Routine Field inspection to
prevent unapproved drilling;
compliance with COGCC
permitting for planned wells.
Assure compliance with
COGCC regulations
COGCC
Permitting
Loss of seal in
abandoned wells
Reservoir pressure in monitor
wells; high pressure found in new
wells
Re-enter and
reseal
abandoned wells
COGCC
Leaks in Surface Facilities
Pumps, valves,
etc.
Routine Field inspection; SCADA
Maintenance crews
respond within days
Subpart W
Subsurface Leaks
Leakage along
faults
Reservoir pressure in monitor
wells; high pressure found in new
wells
Shut in injectors near
faults
-
Overfill beyond
spill
points
Reservoir pressure in monitor
wells; high; pressure found in new
wells
Fluid management
along
lease lines
-
Leakage through
induced fractures
Reservoir pressure in monitor
wells; high pressure found in new
wells
Comply with rules for
keeping pressures
below
parting pressure
-
Leakage due to
seismic event
Reservoir pressure in monitor
wells; high
pressure found in new wells
Shut in injectors near
seismic event
-
Available studies of actual well leaks and natural analogs (e.g., naturally occurring C02 geysers)
suggest that the amount released from routine leaks would be small as compared to the amount of
C02 that would remain stored in the formation.
4.11 Summary
The structure and stratigraphy of the Weber Sands reservoir in the Rangely Field is ideally suited for
the injection and storage of C02- The stratigraphy within the C02 injection zones is porous,
permeable and very thick, providing ample capacity for long-term C02 storage. The Weber Sands
formation is overlain by several intervals of impermeable geologic zones that form effective seals or
"caps" to fluids in the Weber Sands formation (See Figure 4). After assessing potential risk of release
from the subsurface and steps that have been taken to prevent leaks, SEM has determined that the
potential threat of leakage is extremely low.
In summary, based on a careful assessment of the potential risk of release of C02 from the
subsurface, SEM has determined that there are no leakage pathways at the Rangely Field that are
likely to result in significant loss of C02 to the atmosphere. Further, given the detailed knowledge of
the Field and its operating protocols, SEM concludes that it would be able to both detect and quantify
any C02 leakage to the surface that could arise through either identified or unexpected leakage
pathways.
5. Monitoring and Considerations for Calculating Site Specific Variables
Monitoring will also be used to determine the quantities in the mass balance equation and to make
the demonstration that the C02 plume will not migrate to the surface after the time of
discontinuation.
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5.1 For the Mass Balance Equation
5.1.1 General Monitoring Procedures
As part of its ongoing operations, SEM monitors and collects flow, pressure, and gas composition
data from the Rangely Field in centralized data management systems. These data are monitored
continually by qualified technicians who follow SEM response and reporting protocols when the
systems deliver notifications that data exceed statistically acceptable boundaries.
As indicated in Figures 10 and 11, custody-transfer meters are used at the point at which custody of
the C02 from the Raven Ridge pipeline delivery system is transferred to SEM, and at the points at
which custody of oil and NGLs are transferred to outside parties. Meters measure flow rate
continually. Fluid composition will be determined, at a minimum, quarterly, consistent with EPA
GHGRP's Subpart RR, section 98.447(a). All meter and composition data are documented, and
records will be retained for at least three years.
Metering protocols used by SEM follow the prevailing industry standard(s) for custody transfer as
currently promulgated by the API, the American Gas Association (AGA), and the Gas Processors
Association (GPA), as appropriate. This approach is consistent with EPA GHGRP's Subpart RR,
section 98.444(e)(3). These meters will be maintained routinely, operated continually, and will feed
data directly to the centralized data collection systems. The meters meet the industry standard for
custody transfer meter accuracy and calibration frequency. These custody meters provide the most
accurate way to measure mass flows.
SEM maintains in-field process control meters to monitor and manage in-field activities on a real time
basis. These are identified as operations meters in Figures 10 and 11. These meters provide
information used to make operational decisions but are not intended to provide the same level of
accuracy as the custody-transfer meters. The level of precision and accuracy for in-field meters
currently satisfies the requirements for reporting in existing UIC permits. Although these meters are
accurate for operational purposes, it is important to note that there is some variance between
most commercial meters (on the order of 1-5%) which is additive across meters. This variance is
due to differences in factory settings and meter calibration, as well as the operating conditions
within a field. Meter elevation, changes in temperature (over the course of the day), fluid
composition (especially in multi-component or multi-phase streams), or pressure can affect in-field
meter readings. Unlike in a saline formation, where there are likely to be only a few injection wells
and associated meters, at C02 EOR operations in the Rangely Field there are currently 662 active
injection and production wells and a comparable number of meters, each with an acceptable range
of error. This is a site-specific factor that is considered in the mass balance calculations described
in Section 7.
5.1.2 CO2 Received
SEM measures the volume of received C02 using commercial custody transfer meters at the off-
take point from the Raven Ridge pipeline delivery system. This transfer is a commercial transaction
that is documented. C02 composition is governed by the contract and the gas is routinely sampled
to determine composition. No C02 is received in containers.
5.1.3 C02 injected into the Subsurface
Injected C02 will be calculated using the flow meter volumes at the operations meter at the outlet of
the C02 Reinjection Facility and the custody transfer meter at the C02 off-take points from the
Raven Ridge pipeline delivery system
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5.1.4 CO2 Produced, Entrained in Products, and Recycled
The following measurements are used for the mass balance equations in Section 7:
C02 produced is calculated using the volumetric flow meters at the inlet to the C02 Reinjection
Facility.
C02 is produced as entrained or dissolved C02 in produced oil, as indicated in Figures 10 and 11.
This is calculated using volumetric flow through the custody transfer meter.
Recycled C02 is calculated using the volumetric flow meter at the outlet of the C02 Reinjection
Facility, which is an operations meter.
5.1.5 C02 Emitted by Surface Leakage
As discussed in Section 5.1.6 and 5.1.7 below, SEM uses 40 CFR Part 98 Subpart W to estimate
surface leaks from equipment at the Rangely Field. Subpart W uses a factor-driven approach to
estimate equipment leakage. In addition, SEM uses an event-driven process to assess, address,
track, and if applicable quantify potential C02 leakage to the surface. SEM will reconcile the Subpart
W report and results from any event-driven quantification to assure that surface leaks are not double
counted.
The multi-layered, risk-based monitoring program for event-driven incidents has been designed to
meet two objectives, in accordance with the leakage risk assessment in Section 4: 1) to detect
problems before C02 leaks to the surface; and 2) to detect and quantify any leaks that do occur.
This section discusses how this monitoring will be conducted and used to quantify the volumes of
C02 leaked to the surface.
Monitoring for potential Leakage from the Injection/Production Zone:
SEM will monitor both injection into and production from the reservoir as a means of early
identification of potential anomalies that could indicate leakage from the subsurface.
SEM develops injection plans for each well and that is distributed to operations weekly. If injection
pressure or rate measurements are beyond the specified set points determined as part of each
pattern injection plan, the operations engineer will notify field personnel and they will investigate
and resolve the problem. These excursions will be reviewed by well-management personnel to
determine if C02 leakage may be occurring. Excursions are not necessarily indicators of leaks; they
simply indicate that injection rates and pressures are not conforming to the pattern injection plan.
In many cases, problems are straightforward to fix (e.g., a meter needs to be recalibrated or some
other minor action is required), and there is no threat of C02 leakage. In the case of issues that are
not readily resolved, more detailed investigation and response would be initiated, and internal SEM
support staff would provide additional assistance and evaluation. Such issues would lead to the
development of a work order in SEM's work order management system. This record enables the
company to track progress on investigating potential leaks and, if a leak has occurred, to quantify
its magnitude.
Likewise, SEM develops a forecast of the rate and composition of produced fluids. Each producer
well is assigned to one collection station and is isolated twice during each monthly cycle for a well
production test. This data is reviewed on a periodic basis to confirm that production is at the level
forecasted. If there is a significant deviation from the forecast, well management personnel
investigate. If the issue cannot be resolved quickly, more detailed investigation and response would
be initiated. As in the case of the injection pattern monitoring, if the investigation leads to a work
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order in the SEM work order management system, this record will provide the basis for tracking the
outcome of the investigation and if a leak has occurred. If leakage in the flood zone were detected,
SEM would use an appropriate method to quantify the involved volume of C02- This might include
use of material balance equations based on known injected quantities and monitored pressures in
the injection zone to estimate the volume of C02 involved.
A subsurface leak might not lead to a surface leak. In the event of a subsurface leak, SEM would
determine the appropriate approach for tracking subsurface leakage to determine and quantify
leakage to the surface. To quantify leakage to the surface, SEM would estimate the relevant
parameters (e.g., the rate, concentration, and duration of leakage) to quantify the leak volume.
Depending on specific circumstances, these determinations may rely on engineering estimates.
In the event leakage from the subsurface occurred diffusely through the seals, the leaked gas would
include H2S, which would trigger the alarm on the personal monitors worn by field personnel. Such
a diffuse leak from the subsurface has not occurred in the Rangely Field. In the event such a leak
was detected, field personnel from across SEM would determine how to address the problem.
The team might use modeling, engineering estimates, and direct measurements to assess, address,
and quantify the leakage.
Monitoring of Wellbores.'
SEM monitors wells through continual, automated pressure monitoring in the injection zone (as
described in Section 4.2), monitoring of the annular pressure in wellheads, and routine maintenance
and inspection.
Leaks from wellbores would be detected through the follow-up investigation of pressure anomalies,
visual inspection, or the use of personal H2S monitors.
Anomalies in injection zone pressure may not indicate a leak, as discussed above. However, if an
investigation leads to a work order, field personnel would inspect the equipment in question and
determine the nature of the problem. If it is a simple matter, the repair would be made and the volume
of leaked C02 would be included in the 40 CFR Part 98 Subpart W report for the Rangely Field. If more
extensive repair were needed, SEM would determine the appropriate approach for quantifying leaked
C02 using the relevant parameters (e.g., the rate, concentration, and duration of leakage). The work
order would serve as the basis for tracking the event for GHG reporting.
Anomalies in annular pressure or other issues detected during routine maintenance inspections
would be treated in the same way. Field personnel would inspect the equipment in question and
determine the nature of the problem. For simple matters the repair would be made at the time of
inspection and the volume of leaked C02 would be included in the 40 CFR Part 98 Subpart W report
for the Rangely Field. If more extensive repairs were needed, a work order would be generated and
SEM would determine the appropriate approach for quantifying leaked C02 using the relevant
parameters (e.g., the rate, concentration, and duration of leakage). The work order would serve as
the basis for tracking the event for GHG reporting.
Because leaking C02 at the surface is very cold and leads to formation of bright white clouds and
ice that are easily spotted, SEM also employs a two-part visual inspection process in the general
area of the Rangely Field to detect unexpected releases from wellbores. First, field personnel visit the
surface facilities on a routine basis. Inspections may include tank volumes, equipment status and
reliability, lube oil levels, pressures and flow rates in the facility, and valve leaks. Field personnel
inspections also check that injectors are on the proper WAG schedule and observe the facility for
visible C02 or fluid line leaks.
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Historically, SEM has not experienced any unexpected release events in the Rangely Field. An
identified need for repair or maintenance through visual inspections results in a work order being
entered into SEM's equipment and maintenance work order management system. The time to repair
any leak is dependent on several factors, such as the severity of the leak, available manpower,
location of the leak, and availability of materials required for the repair. Critical leaks are acted upon
immediately.
Finally, SEM uses the data collected by the H2S monitors, which are worn by all field personnel at
all times, as a last method to detect leakage from wellbores. The H2S monitors detection limit is
10ppm; if an H2S alarm is triggered, the first response is to protect the safety of the personnel, and
the next step is to safely investigate the source of the alarm. As noted previously, SEM considers
H2S a proxy for potential C02 leaks in the field. Thus, detected H2S leaks will be investigated to
determine and, if needed, quantify potential C02 leakage. If the incident results in a work order, this
will serve as the basis for tracking the event for GHG reporting.
Other Potential Leakage at the Surface:
SEM will utilize the same visual inspection process and H2S monitoring system to detect other
potential leakage at the surface as it does for leakage from wellbores. SEM utilizes routine visual
inspections to detect significant loss of C02 to the surface. Field personnel routinely visit surface
facilities to conduct a visual inspection. Inspections may include review of tank level, equipment
status, lube oil levels, pressures and flow rates in the facility, valve leaks, ensuring that injectors are
on the proper WAG schedule, and also conducting a general observation of the facility for visible
C02 or fluid line leaks. If problems are detected, field personnel would investigate, and, if
maintenance is required, generate a work order in the maintenance system, which is tracked through
completion. In addition to these visual inspections, SEM will use the results of the personal H2S
monitors worn by field personnel as a supplement for smaller leaks that may escape visual detection.
If C02 leakage to the surface is detected, it will be reported to surface operations personnel who will
review the reports and conduct a site investigation. If maintenance is required, a work order will be
generated in the work order management system. The work order will describe the appropriate
corrective action and be used to track completion of the maintenance action. The work order will
also serve as the basis for tracking the event for GHG reporting and quantifying any C02 emissions.
5.1.6 C02 emitted from equipment leaks and vented emissions of C02 from surface
equipment located between the injection flow meter and the injection wellhead.
SEM evaluates and estimates leaks from equipment, the C02 content of produced oil, and vented
C02, as required under 40 CFR Part 98 Subpart W.
5.1.7 Mass ofC02 emissions from equipment leaks and vented emissions ofC02 from surface
equipment located between the production flow meter and the production wellhead
SEM evaluates and estimates leaks from equipment, the C02 content of produced oil, and vented
C02, as required under 40 CFR Part 98 Subpart W.
5.2 To Demonstrate that Injected C02 is not Expected to Migrate to the Surface
At the end of the Specified Period, SEM intends to cease injecting C02 for the subsidiary purpose
of establishing the long-term storage of C02 in the Rangely Field. After the end of the Specified
Period, SEM anticipates that it will submit a request to discontinue monitoring and reporting. The
request will demonstrate that the amount of C02 reported under 40 CFR §98.440-449 (Subpart RR)
is not expected to migrate in the future in a manner likely to result in surface leakage. At that time,
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SEM will be able to support its request with years of data collected during the Specified Period as
well as two to three (or more, if needed) years of data collected after the end of the Specified Period.
This demonstration will provide the information necessary for the EPA Administrator to approve the
request to discontinue monitoring and reporting and may include, but is not limited to:
i. Data comparing actual performance to predicted performance (purchase, injection,
production) over the monitoring period;
ii. An assessment of the C02 leakage detected, including discussion of the estimated
amount of C02 leaked and the distribution of emissions by leakage pathway;
iii. A demonstration that future operations will not release the volume of stored C02 to the
surface;
iv. A demonstration that there has been no significant leakage of C02; and,
v. An evaluation of reservoir pressure in the Rangely Field that demonstrates that injected
fluids are not expected to migrate in a manner to create a potential leakage pathway.
6. Determination of Baselines
SEM intends to utilize existing automatic data systems to identify and investigate excursions from
expected performance that could indicate C02 leakage. SEM's data systems are used primarily for
operational control and monitoring and as such are set to capture more information than is necessary
for reporting in the Annual Subpart RR Report. SEM will develop the necessary system guidelines to
capture the information that is relevant to identify possible C02 leakage. The following describes
SEM's approach to collecting this information.
Visual Inspections
As field personnel conduct routine inspections, work orders are generated in the electronic system
for maintenance activities that cannot be addressed on the spot. Methods to capture work orders
that involve activities that could potentially involve C02 leakage will be developed, if not currently
in place. Examples include occurrences of well workover or repair, as well as visual identification of
vapor clouds or ice formations. Each incident will be flagged for review by the person responsible for
MRV documentation. (The responsible party will be provided in the monitoring plan, as required
under Subpart A, 98.3(g).) The Annual Subpart RR Report will include an estimate of the amount of
C02 leaked. Records of information used to calculate emissions will be maintained on file for a
minimum of three years.
Personal H2S Monitors
H2S monitors are worn by all field personnel. Any monitor alarm triggers an immediate response to
ensure personnel are not at risk and to verify the monitor is working properly. The person responsible
for MRV documentation will receive notice of all incidents where H2S is confirmed to be present.
The Annual Subpart RR Report will provide an estimate the amount of C02 emitted from any such
incidents. Records of information to calculate emissions will be maintained on file for a minimum of
three years.
Injection Rates. Pressures and Volumes
SEM develops target injection rate and pressure for each injector, based on the results of ongoing
pattern modeling and within permitted limits. The injection targets are programmed into the WAG
controllers. High and low set points are also programmed into the SCADA, and flags whenever
statistically significant deviations from the targeted ranges are identified. The set points are
designed to be conservative, because it is preferable to have too many flags rather than too few. As
a result, flags can occur frequently and are often found to be insignificant. For purposes of Subpart
RR reporting, flags (or excursions) will be screened to determine if they could also lead to C02
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leakage to the surface. The person responsible for the MRV documentation will receive notice of
excursions and related work orders that could potentially involve C02 leakage. The Annual Subpart
RR Report will provide an estimate of C02 emissions. Records of information to calculate emissions
will be maintained on file for a minimum of three years.
Production Volumes and Compositions
SEM develops a general forecast of production volumes and composition which is used to
periodically evaluate performance and refine current and projected injection plans and the forecast.
This information is used to make operational decisions but is not recorded in an automated data
system. Sometimes, this review may result in the generation of a work order in the maintenance
system. The MRV plan implementation lead will review such work orders and identify those that could
result in C02 leakage. Should such events occur, leakage volumes would be calculated following the
approaches described in Sections 4 and 5. Impact to Subpart RR reporting will be addressed, if
deemed necessary.
7. Determination of Sequestration Volumes Using Mass Balance Equations
To account for the site conditions and complexity of a large, active EOR operation, SEM proposes
to modify the locations for obtaining volume data for the equations in Subpart RR §98.443 as
indicated below.
The first modification addresses the propagation of error that would result if volume data from
meters at each injection and production well were utilized. This issue arises because while each
meter has a small but acceptable margin of error, this error would become significant if data were
taken from the approximately 284 meters within the Rangely Field. As such, SEM proposes to use
the data from custody and operations meters on the main system pipelines to determine injection
and production volumes used in the mass balance.
The second modification addresses the NGL sales from the Rangely Field. As indicated in Figure 10,
NGL is separated from the fluid mix at the Rangely Field after it has been measured at the RCF inlet
and before measurement at the RCF outlet. As a result the amount of C02 recycled already accounts
for the amount entrained in NGL and therefore is not factored separately into the mass balance
calculation.
The following sections describe how each element of the mass-balance equation (Equation RR-11)
will be calculated.
7.1. Mass of C02 Received
SEM will use equation RR-2 as indicated in Subpart RR §98.443 to calculate the mass of C02
received from each delivery meter immediately upstream of the Raven Ridge pipeline delivery
system on the Rangely Field. The volumetric flow at standard conditions will be multiplied by the
C02 concentration and the density of C02 at standard conditions to determine mass.
C V i : r {Eq, RE-2)
where:
C02T,r = Net annual mass of C02 received through flow meter r (metric tons).
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Qr,p = Quarterly volumetric flow through a receiving flow meter r in quarter p at standard
conditions (standard cubic meters).
Sr,p = Quarterly volumetric flow through a receiving flow meter r that is redelivered to another facility
without being injected into a site well in quarter p (standard cubic meters).
D = Density of C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.
CC02,p,r = Quarterly C02 concentration measurement in flow for flow meter r in quarter p (vol.
percent C02, expressed as a decimal fraction).
p = Quarter of the year,
r = Receiving flow meters.
Given SEM's method of receiving C02 and requirements at Subpart RR §98.444(a):
All delivery to the Rangely Field is used within the unit so quarterly flow redelivered, Sr,p ,
is zero ("0") and will not be included in the equation.
Quarterly C02 concentration will be taken from the gas measurement database SEM will
sum to total Mass of C02 Received using equation RR-3 in 98.443
CO* = (iq. Hi?, s}
where:
C02 = Total net annual mass of C02 received (metric tons).
C02T,r = Net annual mass of C02 received (metric tons) as calculated in Equation RR-2 for flow
meter r.
r = Receiving flow meter.
7.2 MassofC02 Injected into the Subsurface
The equation for calculating the Mass of C02 Injected into the Subsurface at the Rangely Field is
equal to the sum of the Mass of C02 Received as calculated in RR-3 of 98.443 (as described in
Section 7.1) and the Mass of C02 Recycled as calculated using measurements taken from the flow
meter located at the output of the RCF. As previously explained, using data at each injection well
would give an inaccurate estimate of total injection volume due to the large number of wells and the
potential for propagation of error due to allowable calibration ranges for each meter.
The mass of C02 recycled will be determined using equations RR-5 as follows:
ca , I D*c:r0;i r (Sq. RR-5)
where:
CQ2,u = Annual CQ2 mass recycled (metric tons) as measured by flow meter u.
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Qp,u = Quarterly volumetric flow rate measurement for flow meter u in quarter p at standard
conditions (standard cubic meters per quarter).
D = Density of C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.
CC02,p,u = C02 concentration measurement in flow for flow meter u in quarter p (vol. percent
C02, expressed as a decimal fraction).
p = Quarter of the year, u = Flow meter.
The total Mass of C02 injected will be the sum of the Mass of C02 received (RR-3) and Mass of
C02 recycled (modified RR-5).
C02I = C02 + C02,u
7.3 MassofC02 Produced
The Mass of C02 Produced at the Rangely Field will be calculated using the measurements from the
flow meters at the inlet to RCF and the custody transfer meter for oil sales rather than the metered
data from each production well. Again, using the data at each production well would give an
inaccurate estimate of total injection due to the large number of wells and the potential for
propagation of error due to allowable calibration ranges for each meter.
Equation RR-8 in 98.443 will be used to calculate the mass of C02 produced from all injection wells
as follows:
^ D * c;c& _ _ (Bq. RR - a)
Where:
C02,w = Annual C02 mass produced (metric tons) .
Qp,w = Volumetric gas flow rate measurement for meter w in quarter p at standard conditions
(standard cubic meters).
D = Density of C02 at standard conditions (metric tons per standard cubic meter): 0.0018682.
CC02,p,w = C02 concentration measurement in flow for meter w in quarter p (vol. percent C02,
expressed as a decimal fraction).
p = Quarter of the year, w = inlet meter to RCF.
Equation RR-9 in 98.443 will be used to aggregate the mass of C02 produced net of the mass of
C02 entrained in oil leaving the Rangely Field prior to treatment of the remaining gas fraction in RCF
as follows:
W
C02P = I C02,w + Xoil (Eq. RR-9)
w=1
Where:
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C02P = Total annual C02 mass produced (metric tons) through all meters in the reporting year.
C02,w = Annual C02 mass produced (metric tons) through meter w in the reporting year.
Xoil = Mass of entrained C02 in oil in the reporting year measured utilizing commercial meters and
electronic flow-measurement devices at each point of custody transfer. The mass of C02
will be calculated by multiplying the total volumetric rate by the C02 concentration.
7.4 Mass of C02 emitted by Surface Leakage
SEM will calculate and report the total annual Mass of C02 emitted by Surface Leakage using an
approach that is tailored to specific leakage events and relies on 40 CFR Part 98 Subpart W reports
of equipment leakage. As described in Sections 4 and 5.1.5-5.1.7, SEM is prepared to address the
potential for leakage in a variety of settings. Estimates of the amount of C02 leaked to the surface
will likely depend on a number of site-specific factors including measurements, engineering
estimates, and emission factors, depending on the source and nature of the leakage.
SEM's process for quantifying leakage will entail using best engineering principles or emission
factors. While it is not possible to predict in advance the types of leaks that will occur, SEM describes
some approaches for quantification in Section 5.1.5-5.1.7. In the event leakage to the surface occurs,
SEM would quantify and report leakage amounts, and retain records that describe the methods used
to estimate or measure the volume leaked as reported in the Annual Subpart RR Report. Further,
SEM will reconcile the Subpart W report and results from any event-driven quantification to assure
that surface leaks are not double counted.
Equation RR-10 in 48.433 will be used to calculate and report the Mass of C02 emitted by Surface
Leakage:
D': -Mn (Eq. F? " i «
where:
C02E = Total annual C02 mass emitted by surface leakage (metric tons) in the reporting year.
C02,x = Annual C02 mass emitted (metric tons) at leakage pathway x in the reporting year,
x = Leakage pathway.
7.5 MassofC02 sequestered in subsurface geologic formations.
SEM will use equation RR-11 in 98.443 to calculate the Mass of C02 Sequestered in
Subsurface Geologic Formations in the Reporting Year as follows:
C'J C'J ¦ CO , CC-, _ CD r, - COarfc : t-i- RE 111
where:
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C02 = Total annual C02 mass sequestered in subsurface geologic formations (metric tons) at the
facility in the reporting year.
C02I = Total annual C02 mass injected (metric tons) in the well or group of wells covered by this
source category in the reporting year.
C02P = Total annual C02 mass produced (metric tons) net of C02 entrained in oil in the reporting
year.
C02E = Total annual C02 mass emitted (metric tons) by surface leakage in the reporting year.
C02FI = Total annual C02 mass emitted (metric tons) from equipment leaks and vented emissions
of C02 from equipment located on the surface between the flow meter used to measure
injection quantity and the injection wellhead, for which a calculation procedure is provided in
subpart W of this part.
C02FP = Total annual C02 mass emitted (metric tons) from equipment leaks and vented emissions
of C02 from equipment located on the surface between the production wellhead and the
flow meter used to measure production quantity, for which a calculation procedure is
provided in subpart W of this part.
7.6 Cumulative mass of C02 reported as sequestered in subsurface geologic formations
SEM will sum up the total annual volumes obtained using equation RR-11 in 98.443 to calculate the
Cumulative Mass of C02 Sequestered in Subsurface Geologic Formations.
8. MRV Plan Implementation Schedule
The activities described in this MRV Plan are in place, and reporting is planned to start upon EPA
approval. Other GHG reports are filed on March 31 of the year after the reporting year and it is
anticipated that the Annual Subpart RR Report will be filed at the same time. As described in Section
3.3 above, SEM anticipates that the MRV program will be in effect during the Specified Period, during
which time SEM will operate the Rangely Units with the subsidiary purpose of establishing long-term
containment of a measurable quantity of C02 in subsurface geological formations at the Rangely
Field. SEM anticipates establishing that a measurable amount of C02 injected during the Specified
Period will be stored in a manner not expected to migrate resulting in future surface leakage. At such
time, SEM will prepare a demonstration supporting the long-term containment determination and
submit a request to discontinue reporting under this MRV plan. See 40 C.F.R. § 98.441(b)(2)(H).
9. Quality Assurance Program
9.1 Monitoring QA/QC
As indicated in Section 7, SEM has incorporated the requirements of §98.444 (a) - (d) in the
discussion of mass balance equations. These include the following provisions.
CO2 Received and Injected
The quarterly flow rate of C02 received by pipeline is measured at the receiving custody
transfer meters.
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The quarterly C02 flow rate for recycled C02 is measured at the flow meter located at the C02
Reinjection facility outlet.
CO2 Produced
The point of measurement for the quantity of C02 produced from oil or other fluid production wells
is a flow meter directly downstream of each separator that sends a stream of gas into a recycle or
end use system.
The produced gas stream is sampled at least once per quarter immediately downstream of the flow
meter used to measure flow rate of that gas stream and measure the C02 concentration of
the sample.
The quarterly flow rate of the produced gas is measured at the flow meters located at the C02
Reinjection facility inlet.
CO2 emissions from equipment leaks and vented emissions of CO2
These volumes are measured in conformance with the monitoring and QA/QC
requirements specified in subpart W of 40 CFR Part 98.
Fio w meter pro visions
The flow meters used to generate date for the mass balance equations in Section 7 are:
Operated continuously except as necessary for maintenance and calibration.
Operated using the calibration and accuracy requirements in 40 CFR §98.3(i).
Operated in conformance with American Petroleum Institute (API) standards.
National Institute of Standards and Technology (NIST) traceable.
Concentration of CO2
As indicated in Appendix 1, 002 concentration is measured using an appropriate standard method.
Further, all measured volumes of 002 have been converted to standard cubic meters at a
temperature of 60 degrees Fahrenheit and at an absolute pressure of 1 atmosphere, including those
used in Equations RR-2, RR-5 and RR-8 in Section 7.
Missing Data Procedures
In the event SEM is unable to collect data needed for the mass balance calculations,
procedures for estimating missing data in §98.445 will be used as follows:
A quarterly flow rate of 002 received that is missing would be estimated using invoices or using a
representative flow rate value from the nearest previous time period.
A quarterly 002 concentration of a 002 stream received that is missing would be estimated using
invoices or using a representative concentration value from the nearest previous time period.
A quarterly quantity of 002 injected that is missing would be estimated using a representative
quantity of C02injected from the nearest previous period of time at a similar injection pressure.
For any values associated with 002 emissions from equipment leaks and vented emissions of 002
from surface equipment at the facility that are reported in this subpart, missing data estimation
procedures specified in subpart W of 40 CFR Part 98 would be followed.
The quarterly quantity of C02 produced from subsurface geologic formations that is missing would
be estimated using a representative quantity of C02 produced from the nearest previous period of
time.
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MRV Plan Revisions
In the event there is a material change to the monitoring and/or operational parameters of the SEM
C02 EOR operations in the Rangely Field that is not anticipated in this MRV plan, the MRV plan will
be revised and submitted to the EPA Administrator within 180 days as required in §98.448(d).
Records Retention
SEM will follow the record retention requirements specified by §98.3(g). In addition, it will follow the
requirements in Subpart RR §98.447 by maintaining the following records for at least three years:
Quarterly records of C02 received at standard conditions and operating conditions, operating
temperature and pressure, and concentration of these streams.
Quarterly records of produced C02, including volumetric flow at standard conditions and operating
conditions, operating temperature and pressure, and concentration of these streams.
Quarterly records of injected C02 including volumetric flow at standard conditions and operating
conditions, operating temperature and pressure, and concentration of these streams.
Annual records of information used to calculate the C02 emitted by surface leakage from leakage
pathways.
Annual records of information used to calculate the C02 emitted from equipment leaks and vented
emissions of C02 from equipment located on the surface between the flow meter used to measure
injection quantity and the injection wellhead.
Annual records of information used to calculate the C02 emitted from equipment leaks and vented
emissions of C02 from equipment located on the surface between the production wellhead and the
flow meter used to measure production quantity.
These data will be collected as generated and aggregated as required for reporting purposes.
11. Appendices
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Appendix 1. Conversion Factors
SEM reports C02 volumes at standard conditions of temperature and pressure as defined in the
State of Colorado, which follows the international standard conditions for measuring C02 properties
- 77 °F and 14.696 psi.
To convert these volumes into metric tonnes, a density is calculated using the Span and Wagner
equation of state as recommended by the EPA. Density was calculated using the database of
thermodynamic properties developed by the National Institute of Standards and Technology (NIST),
available at http://webbook.nist.gov/chemistrv/fluid/.
At EPA standard conditions of 77 °F and one atmosphere, the Span and Wagner equation of state
gives a density of 0.0026500 lb-moles per cubic foot. Using a molecular weight for C02 of 44.0095,
2204.62 lbs/metric ton and 35.314667 ft3/m3, gives a C02 density of 5.29003 x 10~5 MT/ft3 or
0.0018682 MT/m3.
The conversion factor 5.29003 x 10~5 MT/Mcf has been used throughout to convert SEM volumes to
metric tons.
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Appendix 2. A cronyms
AGA-American Gas Association AMA-Active Monitoring Area
AoR - Area of Review
API-American Petroleum Institute
Bscf- billion standard cubic feet
bopd - barrels of oil per day cf - cubic feet
CCR - Code of Colorado Regulations
COGCC - Colorado Oil and Gas Conservation Commission
C02 - Carbon Dioxide
CRF-C02 Removal Facilities
EOR- Enhanced Oil Recovery
EPA - US Environmental Protection Agency
GHG - Greenhouse Gas
GHGRP - Greenhouse Gas Reporting Program
H2S - Hydrogen Sulfide
IWR - Injection to Withdrawal Ratio
LACT - Lease Automatic Custody Transfer meter
MIT - Mechanical Integrity Test
MMA- Maximum Monitoring Area
MMB - Million barrels
Mscf-Thousand standard cubic feet
MMscf - Million standard cubic feet
MMMT - Million metric tonnes
MMT - Thousand metric tonnes
MRV- Monitoring, Reporting, and Verification
MOC - Main oil column
MT - Metric Tonne
NGNatural Gas
NGLs - Natural Gas Liquids
OOlP-Original Oil-ln-Place
OH - Open hole
POWC - Producible oil/water contact
PPM - Parts Per Million
RCF - Rangely Field C02 Recycling and Compression Facility
RRPC - Raven Ridge pipeline
RWSU - Rangely Weber Sand Unit
SEM - Scout Energy Management, LLC
UIC- Underground Injection Control
VRU - Vapor Recovery Unit
WAG - Water Alternating Gas
XOM - ExxonMobil
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Appendix 3. References
Adams, L., 2006; Sequence and Mechanical Stratigraphy: An Intergrated Reservoir
Characterization of the Weber Sandstone, Western Colorado. University of Texas at El Paso Ph.D.
Dissertation.
Colorado Administrative Code Department 400 Division 404 Oil and Gas Conservation Commission
Section 2
Clark, Rory, Chevron North America E&P, Presentation to 6th Annual Wyoming C02 Conference,
July 12, 2012, online: //www.uwyo.edu/eori/_files/co2conference12/rory_rangelycasehistory.pdf
Energy and Carbon Management Regulation in Colorado. May 22, 2023, online:
https://leg.colorado.gov/bills/sb23-285
US Department of Energy, National Energy Technology Laboratory. "Carbon Dioxide Enhanced Oil
Recovery - Untapped Domestic Energy Supply and Long Term Carbon Storage Solution," March
2010.
US Department of Energy, National Energy Technology Laboratory. "Carbon Sequestration
Through Enhanced Oil Recovery," April 2008.
Gale, Hoyt. Geology of the Rangeiy Oil District. Department of Interior United States Geological
Survey, Bulletin 350.1908.
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Appendix 4. Glossary of Terms
This glossary describes some of the technical terms as they are used in this MRV plan. For
additional glossaries please see the U.S. EPA Glossary of UIC Terms
(http://water.epa.gov/tvpe/qroundwater/uic/qlossary.cfm) and the Schlumberger Oilfield Glossary
(http://www.glossary.oilfield.slb.com/).
Contain / Containment - having the effect of keeping fluids located within in a specified portion of a
geologic formation.
Dip -- Very few, if any, geologic features are perfectly horizontal. They are almost always tilted. The
direction of tilt is called "dip." Dip is the angle of steepest descent measured from the horizontal
plane. Moving higher up structure is moving "updip." Moving lower is "downdip." Perpendicular to
dip is "strike." Moving perpendicular along a constant depth is moving along strike.
Downdip -- See "dip."
Formation -- A body of rock that is sufficiently distinctive and continuous that it can be mapped.
Infill Drilling -- The drilling of additional wells within existing patterns. These additional wells
decrease average well spacing. This practice both accelerates expected recovery and increases
estimated ultimate recovery in heterogeneous reservoirs by improving the continuity between
injectors and producers. As well spacing is decreased, the shifting flow paths lead to increased
sweep to areas where greater hydrocarbon saturations remain.
Permeability -- Permeability is the measure of a rock's ability to transmit fluids. Rocks that transmit
fluids readily, such as sandstones, are described as permeable and tend to have many large, well-
connected pores. Impermeable formations, such as shales and siltstones, tend to be finer grained or
of a mixed grain size, with smaller, fewer, or less interconnected pores.
Phase -- Phase is a region of space throughout which all physical properties of a material are
essentially uniform. Fluids that don't mix together segregate themselves into phases. Oil, for
example, does not mix with water and forms a separate phase.
Pore Space -- See porosity.
Porosity -- Porosity is the fraction of a rock that is not occupied by solid grains or minerals. Almost all
rocks have spaces between rock crystals or grains that is available to be filled with a fluid, such as
water, oil or gas. This space is called "pore space."
Saturation -- The fraction of pore space occupied by a given fluid. Oil saturation, for example, is the
fraction of pore space occupied by oil.
Seal - A geologic layer (or multiple layers) of impermeable rock that serve as a barrier to prevent
fluids from moving upwards to the surface.
Secondary recovery -- The second stage of hydrocarbon production during which an external fluid
such as water or gas is injected into the reservoir through injection wells located in rock that has
fluid communication with production wells. The purpose of secondary recovery is to maintain
reservoir pressure and to displace hydrocarbons toward the wellbore. The most common secondary
recovery techniques are gas injection and waterflooding.
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Stratigraphic section -- A stratigraphic section is a sequence of layers of rocks in the order they
were deposited.
Strike -- See "dip."
Updip -- See "dip."
43
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Appendix 5. Well Identification Numbers
The following table presents the well name, API number, status and type for the wells in the Rangely
Units as of April 2023. The table is subject to change over time as new wells are drilled, existing
wells change status, or existing wells are repurposed. The following terms are used:
Well Status
o Producing refers to a well that is actively producing
o Injecting refers to a well that is actively injecting
o P&A refers to wells that have been closed (plugged and abandoned) per COGCC regulations
o Shut In refers to wells that have been temporarily idled or shut-in
o Monitor refers to a well that is used to monitor bottom home pressure in the reservoir
Well Type
o Water / Gas Inject refers to wells that inject water and C02 Gas
o Water Injection Well refers to wells that inject water
o Oil well refers to wells that produce oil
o Salt Water Disposal refers to a well used to dispose of excess water
Name
API Number
Well Type
Well Status
AC MCLAUGHLIN 46
51030632300
Water Injection Well
Monitor
AC MCLAUGHLIN 64X
51030771700
Oil well
Producing
ASSOCIATED A 2
51030571400
Water / Gas Inject
Monitor
ASSOCIATED A1
51030571300
Oil well
Producing
ASSOCIATED A2ST
51030571401
Water / Gas Inject
Injecting
ASSOCIATED A3X
51030778600
Oil well
Producing
ASSOCIATED A4X
51030791600
Oil well
Producing
ASSOCIATED A5X
51030803400
Water / Gas Inject
Injecting
ASSOCIATED A6X
51030801100
Water / Gas Inject
Injecting
ASSOCIATED LARSON UNIT A1
51030600900
Oil well
Producing
ASSOCIATED LARSON UNIT A2X
51030881500
Oil well
Producing
ASSOCIATED LARSON UNIT B1
51030601100
Oil well
Producing
ASSOCIATED LARSON UNIT B2X
51030950200
Oil well
Producing
ASSOCIATED UNIT A1
51030602600
Oil well
Producing
ASSOCIATED UNIT A2X UN A-2X
51031053200
Oil well
Producing
ASSOCIATED UNIT A3X
51031072300
Oil well
Producing
ASSOCIATED UNIT A4X
51031072200
Water / Gas Inject
Injecting
ASSOCIATED UNIT CI
51030582700
Oil well
Producing
BEEZLEY 1X22AX
51031075400
Water / Gas Inject
Injecting
BEEZLEY 2-22
51030574200
Oil well
Producing
BEEZLEY 3X3X22
51031054900
Oil well
Producing
BEEZLEY 4X22
51031055300
Oil well
Producing
BEEZLEY 5X22
51031174200
Oil well
Producing
BEEZLEY 6X22
51031174300
Oil well
Producing
44
-------
CARNEY 22X-35
51030724500
Oil well
Monitor
CARNEY CT 10-4
51030608600
Oil well
Monitor
CARNEY CT 11-4
51030545700
Oil well
Monitor
CARNEY CT 12AX5
51030917600
Water / Gas Inject
Monitor
CARNEY CT 13-4
51030545900
Oil well
Producing
CARNEY CT 1-34
51030548200
Oil well
Producing
CARNEY CT 14-34
51030103500
Oil well
Producing
CARNEY CT 15-35
51030103700
Water / Gas Inject
Injecting
CARNEY CT 16-35
51030103300
Water / Gas Inject
Monitor
CARNEY CT 17-35
51030103200
Oil well
Producing
CARNEY CT 18-35
51030629500
Water / Gas Inject
Injecting
CARNEY CT 19-34
51030604400
Oil well
Producing
CARNEY CT 20X35
51030641300
Oil well
Producing
CARNEY CT 21X35
51030703300
Water / Gas Inject
Injecting
CARNEY CT22X35ST
51030724501
Oil well
Producing
CARNEY CT 2-34
51030551400
Oil well
Monitor
CARNEY CT 23X35
51030726200
Water / Gas Inject
Injecting
CARNEY CT 24X35
51030728300
Water / Gas Inject
Monitor
CARNEY CT 27X34
51030746600
Water / Gas Inject
Injecting
CARNEY CT28X
51030747400
Water / Gas Inject
Monitor
CARNEY CT29X
51030753700
Water / Gas Inject
Injecting
CARNEY CT 30X34 30X
51030752600
Water / Gas Inject
Injecting
CARNEY CT 32X34
51030758900
Water / Gas Inject
Injecting
CARNEY CT 3-34
51030103900
Oil well
Producing
CARNEY CT 33X34
51030759200
Water / Gas Inject
Injecting
CARNEY CT 35X34
51030759300
Water / Gas Inject
Injecting
CARNEY CT 37X4
51030856300
Oil well
Producing
CARNEY CT 38X4
51030881300
Water / Gas Inject
Monitor
CARNEY CT 39X4
51030881400
Oil well
Producing
CARNEY CT41Y34
51030914900
Oil well
Monitor
CARNEY CT 4-34
51030555900
Oil well
Producing
CARNEY CT43Y34
51030914800
Oil well
Monitor
CARNEY CT44Y34
51030915300
Oil well
Monitor
CARNEY CT 5-34
51030103800
Oil well
Producing
CARNEY CT 6-5
51030609100
Water / Gas Inject
Monitor
CARNEY CT 7-35
51030629300
Oil well
Producing
CARNEY CT 8-34
51030104000
Oil well
Producing
CARNEY CT 9-35
51030548600
Water / Gas Inject
Monitor
CARNEY UNIT 1
51030608700
Oil well
Producing
CARNEY UNIT 2X
51030719100
Water / Gas Inject
Injecting
COLTHARPJE10X
51030869400
Oil well
Producing
45
-------
COLTHARP JE 2
51030602300
Water / Gas Inject
Monitor
COLTHARP JE 4
51030602200
Water / Gas Inject
Monitor
COLTHARP JE 5X
51030705700
Oil well
Producing
COLTHARP JE 7X
51030727900
Oil well
Producing
COLTHARP JE 8X
51030734300
Oil well
Producing
COLTHARP WH A1
51030601900
Water / Gas Inject
Injecting
COLTHARP WH A3
51030602100
Water / Gas Inject
Monitor
COLTHARP WH A4
51030102800
Water / Gas Inject
Injecting
COLTHARP WH A5X
51030725000
Oil well
Producing
COLTHARP WH A6X
51030744700
Oil well
Producing
COLTHARP WH A8X
51030909900
Oil well
Producing
COLTHARP WH B2X
51030859400
Oil well
Monitor
COLTHARP WH B3X
51030879300
Oil well
Shut In
COLTHARP WH CI
51030107700
Water / Gas Inject
Monitor
COLTHARP WH C2X
51030919800
Oil well
Producing
CT CARNEY 25X34
51030741500
Water / Gas Inject
Injecting
EMERALD 10
51030566200
Oil well
Producing
EMERALD 11
51030567100
Oil well
Producing
EMERALD 13ST
51030563601
Water / Gas Inject
Injecting
EMERALD 14
51030556500
Water / Gas Inject
Injecting
EMERALD 16
51030625300
Oil well
Monitor
EMERALD 17
51030567700
Water / Gas Inject
Injecting
EMERALD 18AX
51030920200
Oil well
Producing
EMERALD 19
51030624000
Oil well
Producing
EMERALD 2
51030566900
Oil well
Producing
EMERALD 20
51030555800
Water / Gas Inject
Injecting
EMERALD 22
51030625400
Water / Gas Inject
Injecting
EMERALD 23
51030558900
Water / Gas Inject
Injecting
EMERALD 25
51030548100
Water / Gas Inject
Injecting
EMERALD 26
51030624200
Water / Gas Inject
Injecting
EMERALD 27
51030565300
Oil well
Producing
EMERALD 28
51030562800
Water / Gas Inject
Injecting
EMERALD 29AX
51030924500
Water / Gas Inject
Injecting
EMERALD 30AX
51030920300
Water / Gas Inject
Injecting
EMERALD 31 AX
51030923600
Water / Gas Inject
Injecting
EMERALD 32
51030623800
Oil well
Producing
EMERALD 33AX
51030923900
Water / Gas Inject
Injecting
EMERALD 34
51030559500
Water / Gas Inject
Injecting
EMERALD 35
51030559400
Water / Gas Inject
Injecting
EMERALD 36
51030548800
Water / Gas Inject
Injecting
EMERALD 37
51030551200
Water / Gas Inject
Injecting
46
-------
EMERALD 38
51030624900
Water / Gas Inject
Injecting
EMERALD 39
51030625100
Water / Gas Inject
Injecting
EMERALD 3ST
51030559901
Water / Gas Inject
Injecting
EMERALD 3ST 3
51030559900
Water / Gas Inject
Monitor
EMERALD 4
51030550500
Oil well
Producing
EMERALD 40
51030625000
Water / Gas Inject
Injecting
EMERALD 41
51030546300
Water / Gas Inject
Monitor
EMERALD 42D
51030634000
Salt Water Disposal
Injecting
EMERALD 44AX
51030918700
Water / Gas Inject
Injecting
EMERALD 46X
51030713000
Oil well
Producing
EMERALD 47X
51030720100
Oil well
Producing
EMERALD 48X
51030725700
Oil well
Monitor
EMERALD 49AX
51031068000
Oil well
Producing
EMERALD 50X
51030733100
Oil well
Producing
EMERALD 51X
51030733300
Oil well
Producing
EMERALD 52X
51030737100
Oil well
Producing
EMERALD 53X
51030737600
Oil well
Producing
EMERALD 54X
51030763700
Oil well
Producing
EMERALD 55X
51030763800
Oil well
Producing
EMERALD 56X
51030768700
Oil well
Producing
EMERALD 57XST
51030764901
Oil well
Producing
EMERALD 58X
51030773900
Oil well
Producing
EMERALD 59X
51030774000
Oil well
Producing
EMERALD 6
51030558800
Water / Gas Inject
Injecting
EMERALD 60X
51030779800
Oil well
Producing
EMERALD 61X
51030780300
Oil well
Producing
EMERALD 62X
51030781100
Oil well
Producing
EMERALD 63ST
51030804101
Water / Gas Inject
Injecting
EMERALD 63XST
51030804100
Water / Gas Inject
Monitor
EMERALD 64X
51030799200
Water / Gas Inject
Injecting
EMERALD 65X
51030794800
Oil well
Producing
EMERALD 66X
51030786800
Oil well
Producing
EMERALD 67X
51030797400
Oil well
Producing
EMERALD 68X
51030797500
Oil well
Producing
EMERALD 69X
51030810300
Water / Gas Inject
Injecting
EMERALD 70X
51030807200
Water / Gas Inject
Injecting
EMERALD 71X
51030804600
Water / Gas Inject
Injecting
EMERALD 72X
51030810400
Water / Gas Inject
Monitor
EMERALD 73X
51030810500
Oil well
Monitor
EMERALD 74X
51030816900
Oil well
Producing
EMERALD 75X
51030843700
Oil well
Producing
47
-------
EMERALD 76X
51030848100
Oil well
Producing
EMERALD 77X
51030848000
Oil well
Producing
EMERALD 78X
51030849100
Oil well
Producing
EMERALD 79X
51030895500
Salt Water Disposal
Injecting
EMERALD 7A
51030928500
Water / Gas Inject
Injecting
EMERALD 8
51030559000
Water / Gas Inject
Monitor
EMERALD 80X
51030876900
Oil well
Producing
EMERALD 81X
51030888300
Oil well
Producing
EMERALD 82X
51030849200
Water / Gas Inject
Injecting
EMERALD 83X
51030876500
Oil well
Producing
EMERALD 84X
51030888500
Oil well
Producing
EMERALD 85X
51030877000
Oil well
Producing
EMERALD 86X
51030877200
Oil well
Producing
EMERALD 87X
51030877300
Oil well
Monitor
EMERALD 88X
51030876600
Oil well
Producing
EMERALD 89X
51030877100
Oil well
Producing
EMERALD 8ST
51030559001
Water / Gas Inject
Injecting
EMERALD 90X
51030914600
Water / Gas Inject
Injecting
EMERALD 91Y
51030914700
Water / Gas Inject
Injecting
EMERALD 92X
51030929500
Oil well
Producing
EMERALD 93X
51031185800
Oil well
Producing
EMERALD 94X
51031185500
Oil well
Producing
EMERALD 95X
51031191400
Oil well
Producing
EMERALD 96X
51031192200
Oil well
Producing
EMERALD 97X
51031191300
Oil well
Producing
EMERALD 98X
51031191500
Water / Gas Inject
Injecting
EMERALD 9ST
51030566101
Water / Gas Inject
Injecting
EMERALD 9ST 9
51030566100
Water / Gas Inject
Monitor
FAIRFIELD KITTI A 4
51031101700
Oil well
Monitor
FAIRFIELD KITTI A 5P
51031101000
Oil well
Monitor
FAIRFIELD KITTI A1
51030611100
Water / Gas Inject
Injecting
FAIRFIELD KITTI A4
51031101700
Oil well
Producing
FAIRFIELD KITTI A5
51031101001
Oil well
Producing
FAIRFIELD KITTI B1
51030107800
Water / Gas Inject
Injecting
FE156X
51031033600
Oil well
Producing
FEE 1
51030563400
Oil well
Producing
FEE 1162Y
51031194500
Water / Gas Inject
Injecting
FEE 10
51030566800
Water / Gas Inject
Injecting
FEE100X
51030786900
Oil well
Producing
FEE101X
51030787000
Oil well
Producing
FEE102X
51030787700
Oil well
Producing
48
-------
FEE103X
51030788500
Oil well
Monitor
FEE104X
51030785700
Oil well
Producing
FEE105X
51030785800
Oil well
Producing
FEE106X
51030794600
Water / Gas Inject
Injecting
FEE107X
51030803200
Water / Gas Inject
Injecting
FEE108X
51030795200
Oil well
Producing
FEE109X
51030798900
Water / Gas Inject
Injecting
FEE 11
51030559600
Oil well
Producing
FEE110X
51030802600
Water / Gas Inject
Injecting
FEE111X
51030802700
Water / Gas Inject
Monitor
FEE112X
51030802800
Water / Gas Inject
Injecting
FEE113X
51030802900
Water / Gas Inject
Injecting
FEE114X
51030803100
Water / Gas Inject
Injecting
FEE115X
51030803300
Water / Gas Inject
Injecting
FEE116X
51030829900
Water / Gas Inject
Injecting
FEE117X
51030843800
Oil well
Producing
FEE 118 AX
51030928300
Oil well
Monitor
FEE 12
51030565100
Oil well
Producing
FEE121X
51030857500
Oil well
Producing
FEE122X
51030866300
Water / Gas Inject
Injecting
FEE124X
51030866400
Oil well
Producing
FEE125X
51030868100
Oil well
Monitor
FEE126X
51030868600
Oil well
Producing
FEE127X
51030868700
Water / Gas Inject
Injecting
FEE128X
51030868800
Oil well
Monitor
FEE129X
51030868900
Oil well
Producing
FEE 13
51030622600
Oil well
Producing
FEE130X
51030870400
Oil well
Monitor
FEE133X
51030888400
Oil well
Producing
FEE135X
51030876000
Oil well
Monitor
FEE136X
51030874500
Water / Gas Inject
Injecting
FEE137X
51030876100
Water / Gas Inject
Injecting
FEE138X
51030876300
Oil well
Producing
FEE139X
51030876200
Oil well
Producing
FEE 14
51030568700
Oil well
Producing
FEE 140Y
51030910600
Oil well
Monitor
FEE 14IX
51030913300
Water / Gas Inject
Injecting
FEE142X
51030913100
Oil well
Producing
FEE143X
51030913000
Oil well
Producing
FEE 144Y
51030917500
Oil well
Shut In
FEE 145Y
51030917400
Oil well
Producing
49
-------
FEE146X
51030946400
Oil well
Producing
FEE 15
51030556800
Oil well
Producing
FEE153X
51030929700
Oil well
Producing
Fee 154X
51031036500
Oil well
Producing
Fee 155X
51031037300
Oil well
Producing
FEE157X
51031101900
Oil well
Monitor
FEE 158 X
51031115900
Oil well
Producing
FEE 159 X
51031101100
Oil well
Producing
FEE160X
51031186600
Oil well
Producing
FEE163X
51031195100
Oil well
Producing
FEE 16 AX
51030923500
Water / Gas Inject
Monitor
FEE 17
51030580100
Water / Gas Inject
Injecting
FEE 18
51030623600
Water / Gas Inject
Monitor
FEE 19
51030622400
Oil well
Producing
FEE 1AX
51030924400
Water / Gas Inject
Monitor
FEE 20
51030616800
Oil well
Producing
FEE 21
51030620700
Oil well
Producing
FEE 22
51030616100
Water / Gas Inject
Injecting
FEE 23
51030615600
Oil well
Producing
FEE 24
51030611200
Water / Gas Inject
Injecting
FEE 25
51030614500
Oil well
Producing
FEE 26
51030615200
Oil well
Producing
FEE 27
51030617500
Oil well
Producing
FEE 28
51030613500
Water / Gas Inject
Injecting
FEE 29
51030614400
Water / Gas Inject
Injecting
FEE 2AX
51030924700
Water / Gas Inject
Injecting
FEE 3
51030565700
Oil well
Producing
FEE 30
51030621100
Water / Gas Inject
Monitor
FEE 31
51030611800
Water / Gas Inject
Injecting
FEE 32
51030614200
Oil well
Producing
FEE 33
51030614700
Oil well
Producing
FEE 34
51030624500
Oil well
Producing
FEE 35
51030611300
Oil well
Producing
FEE 36
51030617600
Oil well
Producing
FEE 37
51030611500
Water / Gas Inject
Injecting
FEE 38
51030625500
Water / Gas Inject
Injecting
FEE 39
51030623300
Water / Gas Inject
Injecting
FEE 4
51030576900
Oil well
Monitor
FEE 40
51030622300
Water / Gas Inject
Injecting
FEE 41
51030622200
Water / Gas Inject
Monitor
FEE 42
51030568800
Water / Gas Inject
Monitor
50
-------
FEE 43
51030614100
Water / Gas Inject
Injecting
FEE 44
51030624700
Water / Gas Inject
Injecting
FEE 45
51030617900
Oil well
Producing
FEE 47
51030616000
Water / Gas Inject
Injecting
FEE 48
51030625900
Water / Gas Inject
Injecting
FEE 49
51030611900
Water / Gas Inject
Injecting
FEE 5
51030574500
Oil well
Producing
FEE 51
51030614900
Water / Gas Inject
Injecting
FEE 52
51030567400
Water / Gas Inject
Injecting
FEE 53AX
51030861200
Water / Gas Inject
Injecting
FEE 55
51030615300
Water / Gas Inject
Injecting
FEE 56
51030615700
Water / Gas Inject
Injecting
FEE 58AX
51030924300
Water / Gas Inject
Injecting
FEE 59
51030616900
Water / Gas Inject
Injecting
FEE 6
51030572000
Oil well
Producing
FEE 60
51030622500
Water / Gas Inject
Injecting
FEE 61
51030620300
Oil well
Producing
FEE 62
51030614000
Oil well
Monitor
FEE 63
51030614600
Water / Gas Inject
Injecting
FEE 64
51030614800
Water / Gas Inject
Injecting
FEE 65
51030615000
Water / Gas Inject
Injecting
FEE 67A
51030929300
Water / Gas Inject
Injecting
FEE 68A
51030568300
Oil well
Producing
FEE 69
51030625600
Water / Gas Inject
Monitor
FEE 7
51030571600
Oil well
Producing
FEE 70AX
51030919100
Water / Gas Inject
Monitor
FEE 72X
51030718000
Oil well
Producing
FEE 73X
51030727400
Oil well
Producing
FEE 74X
51030730700
Oil well
Producing
FEE 75X
51030732600
Oil well
Producing
FEE 76X
51030733900
Oil well
Producing
FEE 78X
51030743400
Oil well
Producing
FEE 79X
51030742400
Water / Gas Inject
Injecting
FEE 8
51030563300
Water / Gas Inject
Injecting
FEE 80X
51030749100
Water / Gas Inject
Injecting
FEE 81X
51030751900
Oil well
Producing
FEE 82X
51030752900
Oil well
Producing
FEE 83X
51030757200
Oil well
Producing
FEE 84X
51030755400
Water / Gas Inject
Injecting
FEE 85X
51030758100
Water / Gas Inject
Injecting
FEE 86X
51030756900
Water Injection Well
Monitor
51
-------
FEE 86XST
51030756901
Water / Gas Inject
Injecting
FEE 87X
51030754600
Water / Gas Inject
Monitor
FEE 88X
51030755900
Water / Gas Inject
Injecting
FEE 89X
51030755500
Water / Gas Inject
Injecting
FEE 9
51030551100
Oil well
Monitor
FEE 90X
51030758000
Water / Gas Inject
Injecting
FEE 9IX
51030757300
Water / Gas Inject
Injecting
FEE 92X
51030755600
Water / Gas Inject
Monitor
FEE 93X
51030759100
Water / Gas Inject
Injecting
FEE 94X
51030759400
Water / Gas Inject
Injecting
FEE 95X
51030764700
Oil well
Producing
FEE 96X
51030764800
Oil well
Producing
FEE 97X
51030779100
Oil well
Producing
FEE 98X
51030782700
Water / Gas Inject
Injecting
FEE 99X
51030784000
Oil well
Producing
FEE 9ST9
51030551101
Oil well
Producing
GRAY A A17X
51030768900
Water / Gas Inject
Injecting
GRAY A A21X
51030830200
Water / Gas Inject
Injecting
GRAY A A8AX
51030919700
Water / Gas Inject
Injecting
GRAY A10
51030573400
Water / Gas Inject
Injecting
GRAY A12
51030613700
Oil well
Producing
GRAY A13
51030577800
Water / Gas Inject
Monitor
GRAY A14
51030613900
Oil well
Producing
GRAY A15
51030576200
Oil well
Producing
GRAY A16
51030613600
Water / Gas Inject
Injecting
GRAY A18X
51030789800
Oil well
Producing
GRAY A19X
51030787300
Oil well
Producing
GRAY A20X
51030803500
Water / Gas Inject
Injecting
GRAY A22X
51030831700
Oil well
Producing
GRAY A9
51030571500
Oil well
Producing
GRAY BIO
51030612300
Water / Gas Inject
Injecting
GRAY Bll
51030581800
Oil well
Producing
GRAY B12
51030612900
Oil well
Producing
GRAY B13
51030612600
Oil well
Producing
GRAY B14A
51030928900
Water / Gas Inject
Injecting
GRAY B15
51030579600
Oil well
Producing
GRAY B16
51030612700
Oil well
Producing
GRAY B17
51030582500
Oil well
Monitor
GRAY B18X
51030638600
Oil well
Monitor
GRAY B19X
51036639700
Oil well
Producing
GRAY B2
51030578700
Oil well
Producing
52
-------
GRAY B20X
51030101500
Water / Gas Inject
Injecting
GRAY B21X
51031035700
Oil well
Producing
GRAY B22X
51031036000
Oil well
Producing
GRAY B23X
51031033800
Oil well
Producing
GRAY B24X
51031033700
Oil well
Producing
GRAY B25X
51031057200
Oil well
Producing
GRAY B26X
51031057500
Oil well
Producing
GRAY B27X
51031057400
Oil well
Producing
GRAY B28X
51031101200
Oil well
Producing
GRAY B3
51030613200
Water / Gas Inject
Injecting
GRAY B4
51030613300
Water / Gas Inject
Injecting
GRAY B5
51030612400
Water / Gas Inject
Injecting
GRAY B6
51030613100
Water / Gas Inject
Injecting
GRAY B7
51030612800
Water / Gas Inject
Injecting
GRAY B8
51030581100
Water / Gas Inject
Injecting
GRAY B9
51030612500
Water / Gas Inject
Injecting
GUIBERSON SA 1
51030581300
Water / Gas Inject
Injecting
GUIBERSON SA 5 X
51031115600
Oil well
Producing
HAGOOD L N-A 17X
51030914200
Oil well
Monitor
HAGOOD LN A10X
51030791300
Oil well
Shut In
HAGOOD LN A11X
51030794900
Water / Gas Inject
Injecting
HAGOOD LN A12X
51030793600
Oil well
Producing
HAGOOD LN A13X
51030799100
Water / Gas Inject
Injecting
HAGOOD LN A14XST
51030795000
Water / Gas Inject
Monitor
HAGOOD LN A14XST
51030795001
Water / Gas Inject
Injecting
HAGOOD LN A15X
51030829300
Oil well
Producing
HAGOOD LN A16X
51030830000
Water / Gas Inject
Injecting
HAGOOD LN A17XST
51030914201
Water / Gas Inject
Monitor
HAGOOD LN A2
51030574300
Oil well
Monitor
HAGOOD LN A3
51030576800
Oil well
Monitor
HAGOOD LN A5
51030573600
Water / Gas Inject
Injecting
HAGOOD LN A7
51030575700
Water / Gas Inject
Monitor
HAGOOD LN A9X
51030702200
Water / Gas Inject
Injecting
HAGOOD MC A1
51030632800
Water / Gas Inject
Injecting
HAGOOD MC A10X
51031041400
Oil well
Producing
HAGOOD MC A11X
51031041300
Oil well
Producing
HAGOOD MC A12X
51031053300
Oil well
Producing
HAGOOD MC A13X
51031053100
Oil well
Producing
HAGOOD MC A14X
51031054800
Oil well
Shut In
HAGOOD MC A15X
51031062800
Oil well
Producing
HAGOOD MC A16X
51031061200
Oil well
Producing
53
-------
HAGOOD MC A17X
51031062900
Oil well
Producing
HAGOOD MC A18X
51031061300
Oil well
Producing
HAGOOD MC A19X
51031067000
Water / Gas Inject
Injecting
HAGOOD MC A2
51030102300
Oil well
Producing
HAGOOD MC A21X
51031070900
Oil well
Producing
HAGOOD MC A3
51030633000
Water / Gas Inject
Injecting
HAGOOD MC A4
51030632600
Water / Gas Inject
Injecting
HAGOOD MC A5
51030633100
Water / Gas Inject
Injecting
HAGOOD MC A6
51030102400
Oil well
Producing
HAGOOD MC A7
51030106700
Oil well
Producing
HAGOOD MC A8 A 8
51030632500
Water / Gas Inject
Injecting
HAGOOD MC A9
51030632700
Water / Gas Inject
Injecting
HAGOOD MC B1A
51031102800
Oil well
Producing
HAGOOD MCB2
51031187000
Oil well
Producing
HEFLEY CS 4X
51030856200
Oil well
Producing
HEFLEY ME 2
51030545200
Water / Gas Inject
Monitor
HEFLEY ME 5X
51030719600
Oil well
Producing
HEFLEY ME 6X
51030729300
Oil well
Producing
HEFLEY ME 7X
51030873700
Oil well
Producing
HEFLEY ME 8X
51030869600
Oil well
Producing
L N HAGOOD A-1
51030572100
Water / Gas Inject
Injecting
L N HAGOOD A-8 IJ A8
51030569100
Water / Gas Inject
Injecting
LACY SB 1
51030573200
Oil well
Producing
LACY SB 11Y
51030914400
Salt Water Disposal
Injecting
LACY SB 12Y
51030914500
Oil well
Producing
LACY SB 13Y
51031057000
Oil well
Producing
LACY SB 2AX
51030928200
Water / Gas Inject
Injecting
LACY SB 3
51030568900
Oil well
Producing
LACY SB 4
51030575800
Water / Gas Inject
Monitor
LACY SB 6X
51030794700
Oil well
Monitor
LACY SB 7X
51030797800
Water / Gas Inject
Injecting
LACY SB 9X
51030831800
Oil well
Monitor
LARSON FA 1
51030106600
Oil well
Producing
LARSON FA 2
51030107200
Water / Gas Inject
Injecting
LARSON FA 3X
51031071000
Oil well
Monitor
LARSON FV A1
51030547600
Oil well
Producing
LARSON FV A2X
51030721600
Water / Gas Inject
Monitor
LARSON FV Bll
51030630200
Water / Gas Inject
Injecting
LARSON FV B12
51030100900
Oil well
Producing
LARSON FV B14X
51030641400
Oil well
Shut In
LARSON FV B15X
51030700800
Oil well
Producing
54
-------
LARSON FV B17X
51030707800
Oil well
Producing
LARSON FV B18X
51030708300
Oil well
Producing
LARSON FV B19X
51030710600
Oil well
Producing
LARSON FV B2
51030620200
Water / Gas Inject
Monitor
LARSON FV B20X
51030709900
Oil well
Producing
LARSON FV B21X
51030716500
Oil well
Producing
LARSON FV B22X
51030722700
Oil well
Producing
LARSON FV B23X
51030724200
Oil well
Producing
LARSON FV B24X
51030873800
Oil well
Producing
LARSON FV B25X
51030916500
Oil well
Producing
LARSON FV B27X
51030948800
Oil well
Producing
LARSON FV B4
51030629800
Water / Gas Inject
Injecting
LARSON FV B8
51030620100
Water / Gas Inject
Injecting
LARSON MB 10X25
51030715900
Oil well
Producing
LARSON MB 12X25
51030727000
Oil well
Producing
LARSON MB 2-26 A226
51030566300
Oil well
Producing
LARSON MB 3X26
51030711000
Oil well
Producing
LARSON MB 4X26
51030717700
Oil well
Monitor
LARSON MB 8X25
51030709300
Oil well
Producing
LARSON MB A1AX
51031075600
Water / Gas Inject
Monitor
LARSON MB A2
51030633200
Oil well
Producing
LARSON MB A3X
51031053400
Oil well
Producing
LARSON MB A4X
51031055200
Oil well
Producing
LARSON MB B1
51030576500
Water / Gas Inject
Injecting
LARSON MB B3AX
51031075500
Water / Gas Inject
Injecting
LARSON MB Cl-25
51030618600
Water / Gas Inject
Monitor
LARSON MB C1AX
51031076300
Oil well
Producing
LARSON MB C2
51030569000
Water / Gas Inject
Injecting
LARSON MB C3
51030570800
Water / Gas Inject
Injecting
LARSON MB C3-25
51030618700
Water / Gas Inject
Injecting
LARSON MB C4
51031139700
Oil well
Producing
LARSON MB C5
51031142900
Oil well
Producing
LARSON MB C9X25
51030715500
Oil well
Producing
LARSON MB D1-26E
51030620000
Water / Gas Inject
Injecting
LEVISON 10
51030621700
Oil well
Producing
LEVISON 11
51030619800
Water / Gas Inject
Injecting
LEVISON 12
51030103100
Water / Gas Inject
Injecting
LEVISON 13
51030619400
Water / Gas Inject
Injecting
LEVISON 14
51030619900
Water / Gas Inject
Injecting
LEVISON 17
51030619500
Water / Gas Inject
Injecting
LEVISON 18
51030618200
Oil well
Producing
55
-------
LEVISON 2
51030559300
Oil well
Producing
LEVISON 2IX
51030638700
Oil well
Producing
LEVISON 22X
51030708900
Oil well
Monitor
LEVISON 23X
51030712300
Oil well
Producing
LEVISON 24X
51030711400
Oil well
Producing
LEVISON 25X
51030722200
Oil well
Producing
LEVISON 26X
51030726700
Oil well
Producing
LEVISON 27X
51030728900
Oil well
Producing
LEVISON 28X
51030731600
Oil well
Monitor
LEVISON 29X
51030732000
Water / Gas Inject
Injecting
LEVISON 30X
51030735100
Water / Gas Inject
Injecting
LEVISON 3IX
51030735300
Oil well
Monitor
LEVISON 32X
51030747500
Water / Gas Inject
Injecting
LEVISON 33X
51030752100
Oil well
Producing
LEVISON 34X
51030758600
Water / Gas Inject
Injecting
LEVISON 35X
51030868300
Oil well
Producing
LEVISON 6
51030106200
Oil well
Producing
LEVISON 7
51030619700
Oil well
Monitor
LEVISON 8
51030103000
Water / Gas Inject
Injecting
LEVISON 9
51030628600
Water / Gas Inject
Injecting
LEVSION 1
51030559100
Oil well
Producing
LN - HAGOOD A6
51030569400
Oil well
Producing
LN HAGOOD A-4
51030570700
Oil well
Shut In
MAGOR1A
51030989300
Water / Gas Inject
Injecting
MATTERN 1
51030580400
Water / Gas Inject
Injecting
MCLAUGHLIN AC 1
51030573100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 10
51030578000
Oil well
Monitor
MCLAUGHLIN AC 11
51030569300
Oil well
Producing
MCLAUGHLIN AC 12
51030579800
Water / Gas Inject
Injecting
MCLAUGHLIN AC 13
51030581000
Water / Gas Inject
Injecting
MCLAUGHLIN AC 14
51030105800
Oil well
Producing
MCLAUGHLIN AC 15
51030576700
Oil well
Producing
MCLAUGHLIN AC 16
51030105400
Oil well
Producing
MCLAUGHLIN AC 17
51030631700
Water / Gas Inject
Injecting
MCLAUGHLIN AC 18
51030105300
Water / Gas Inject
Injecting
MCLAUGHLIN AC 19
51030579400
Oil well
Producing
MCLAUGHLIN AC 2
51030573300
Oil well
Producing
MCLAUGHLIN AC 20
51030578200
Water / Gas Inject
Injecting
MCLAUGHLIN AC 21
51030578100
Oil well
Producing
MCLAUGHLIN AC 22
51030105500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 23
51030571800
Water / Gas Inject
Injecting
56
-------
MCLAUGHLIN AC 24
51030576300
Water / Gas Inject
Injecting
MCLAUGHLIN AC 25
51030631800
Oil well
Producing
MCLAUGHLIN AC 26
51030105000
Water / Gas Inject
Injecting
MCLAUGHLIN AC 27
51036005300
Oil well
Producing
MCLAUGHLIN AC 28
51030569900
Oil well
Producing
MCLAUGHLIN AC 29
51030581900
Oil well
Producing
MCLAUGHLIN AC 30
51030105100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 31
51030105200
Water / Gas Inject
Injecting
MCLAUGHLIN AC 32
51030581200
Water / Gas Inject
Injecting
MCLAUGHLIN AC 33
51030631500
Water / Gas Inject
Injecting
MCLAUGHLIN AC 34
51030104700
Water / Gas Inject
Injecting
MCLAUGHLIN AC 35
51030581700
Oil well
Producing
MCLAUGHLIN AC 36
51030104800
Oil well
Producing
MCLAUGHLIN AC 37
51030633300
Oil well
Producing
MCLAUGHLIN AC 38
51030632200
Oil well
Producing
MCLAUGHLIN AC 39A
51031049300
Oil well
Producing
MCLAUGHLIN AC 3AX
51030920700
Water / Gas Inject
Injecting
MCLAUGHLIN AC 4
51030573800
Oil well
Producing
MCLAUGHLIN AC41AX
51030920100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 42
51030579500
Water / Gas Inject
Monitor
MCLAUGHLIN AC 43
51030632400
Water / Gas Inject
Injecting
MCLAUGHLIN AC 44A
51031096100
Oil well
Producing
MCLAUGHLIN AC 44D
51030631600
Salt Water Disposal
Injecting
MCLAUGHLIN AC 45 AC
51030631900
Water / Gas Inject
Injecting
MCLAUGHLIN AC46ST
51030632301
Water / Gas Inject
Monitor
MCLAUGHLIN AC47X
51030107500
Water / Gas Inject
Injecting
MCLAUGHLIN AC49X
51030641700
Oil well
Monitor
MCLAUGHLIN AC 5
51030571200
Oil well
Monitor
MCLAUGHLIN AC50X
51030632100
Oil well
Producing
MCLAUGHLIN AC 5IX
51030641800
Oil well
Producing
MCLAUGHLIN AC52X
51030642500
Water / Gas Inject
Injecting
MCLAUGHLIN AC53X
51030101400
Oil well
Producing
MCLAUGHLIN AC54X
51030642600
Oil well
Producing
MCLAUGHLIN AC55X
51030641900
Water / Gas Inject
Injecting
MCLAUGHLIN AC56X
51030642000
Water / Gas Inject
Injecting
MCLAUGHLIN AC57X
51030701000
Oil well
Monitor
MCLAUGHLIN AC58X
51030701400
Oil well
Producing
MCLAUGHLIN AC 59AX
51030928800
Oil well
Producing
MCLAUGHLIN AC 6
51030579900
Oil well
Producing
MCLAUGHLIN AC60X
51030769200
Water / Gas Inject
Injecting
MCLAUGHLIN AC 6IX
51030769000
Oil well
Monitor
57
-------
MCLAUGHLIN AC62X
51030771500
Oil well
Producing
MCLAUGHLIN AC63X
51030771600
Water / Gas Inject
Injecting
MCLAUGHLIN AC65X
51030771800
Oil well
Producing
MCLAUGHLIN AC66X
51030773800
Water / Gas Inject
Injecting
MCLAUGHLIN AC67X
51030817000
Oil well
Producing
MCLAUGHLIN AC68X
51030829200
Oil well
Producing
MCLAUGHLIN AC69X
51030829400
Water / Gas Inject
Injecting
MCLAUGHLIN AC 7
51030580900
Water / Gas Inject
Injecting
MCLAUGHLIN AC70X
51030830100
Water / Gas Inject
Injecting
MCLAUGHLIN AC 7IX
51030829700
Oil well
Producing
MCLAUGHLIN AC72X
51030832000
Water / Gas Inject
Injecting
MCLAUGHLIN AC73X
51030831900
Oil well
Producing
MCLAUGHLIN AC 74X
51030832100
Water / Gas Inject
Injecting
MCLAUGHLIN AC75X
51030829800
Oil well
Producing
MCLAUGHLIN AC76X
51030914100
Water / Gas Inject
Injecting
MCLAUGHLIN AC77X
51030915200
Oil well
Producing
MCLAUGHLIN AC78X
51030915500
Oil well
Producing
MCLAUGHLIN AC79X
51030930000
Oil well
Monitor
MCLAUGHLIN AC 8
51030573500
Oil well
Producing
MCLAUGHLIN AC 80X
51030930100
Oil well
Monitor
MCLAUGHLIN AC 81AX
51031064500
Oil well
Producing
MCLAUGHLIN AC82X
51031054600
Oil well
Producing
MCLAUGHLIN AC 83X
51031059500
Oil well
Producing
MCLAUGHLIN AC 84Y
51031057300
Oil well
Producing
MCLAUGHLIN AC 86Y
51031058400
Oil well
Producing
MCLAUGHLIN AC 88X
51031070000
Oil well
Producing
MCLAUGHLIN AC 9
51030576600
Oil well
Monitor
MCLAUGHLIN AC90X
51031069900
Oil well
Producing
MCLAUGHLIN AC 9IX
51031072600
Water / Gas Inject
Injecting
MCLAUGHLIN AC92X
51031070800
Oil well
Producing
MCLAUGHLIN AC93X
51031072700
Water / Gas Inject
Injecting
MCLAUGHLIN AC 94X
51031072500
Water / Gas Inject
Injecting
MCLAUGHLIN AC95X
51031140800
Oil well
Producing
MCLAUGHLIN AC A1
51030609200
Oil well
Monitor
MCLAUGHLIN AC A3X
51030863000
Oil well
Producing
MCLAUGHLIN AC C2
51031104100
Oil well
Monitor
MCLAUGHLIN SW6
51030627800
Oil well
Monitor
MCLAUGHLIN SHARPLES 10X28
51030749000
Oil well
Producing
MCLAUGHLIN SHARPLES 1-28
51030560300
Water / Gas Inject
Injecting
MCLAUGHLIN SHARPLES 12X33
51030759800
Oil well
Producing
MCLAUGHLIN SHARPLES 1-33
51030551300
Oil well
Producing
58
-------
MCLAUGHLIN SHARPLES 13X3
51030873900
Oil well
Producing
MCLAUGHLIN SHARPLES 14Y33
51030912300
Oil well
Producing
MCLAUGHLIN SHARPLES 15X32
51030885400
Oil well
Producing
MCLAUGHLIN SHARPLES 16X32
51030913200
Water / Gas Inject
Injecting
MCLAUGHLIN SHARPLES 2-28
51030560000
Oil well
Producing
MCLAUGHLIN SHARPLES 2-32
51030627300
Water / Gas Inject
Monitor
MCLAUGHLIN SHARPLES 2-33
51030106800
Water / Gas Inject
Injecting
MCLAUGHLIN SHARPLES 3-32
51030627000
Oil well
Monitor
MCLAUGHLIN SHARPLES 3-33
51030629000
Oil well
Producing
MCLAUGHLIN SHARPLES4-33
51030629100
Water / Gas Inject
Injecting
MCLAUGHLIN SHARPLES 5-33
51030104500
Oil well
Monitor
MCLAUGHLIN SHARPLES 6-33
51030628800
Oil well
Monitor
MCLAUGHLIN SHARPLES 7-33
51030104600
Water / Gas Inject
Monitor
MCLAUGHLIN SHARPLES 8-33
51030628900
Water / Gas Inject
Monitor
MCLAUGHLIN SHARPLES 9X33
51030746500
Oil well
Producing
MCLAUGHLIN SW 11X
51030759700
Water / Gas Inject
Injecting
MCLAUGHLIN SW 12X
51030760100
Water / Gas Inject
Injecting
MCLAUGHLIN SW 1ST
51030548300
Oil well
Monitor
MCLAUGHLIN SW 1ST 1
51030548301
Water / Gas Inject
Monitor
MCLAUGHLIN SW 2
51030627700
Oil well
Producing
MCLAUGHLIN SW 3
51030104400
Water / Gas Inject
Injecting
MCLAUGHLIN SW 4
51030107600
Oil well
Producing
MCLAUGHLIN SW 5
51030627900
Oil well
Producing
MCLAUGHLIN SW 6ST
51030627801
Water / Gas Inject
Injecting
MCLAUGHLIN SW 7X
51030746100
Oil well
Producing
MCLAUGHLIN SW 8X
51030753000
Water / Gas Inject
Injecting
MCLAUGHLIN UNIT A1
51030581600
Oil well
Producing
MCLAUGHLIN UNIT B1
51030582600
Oil well
Producing
MCLAUGHLIN UNIT B2X
51031057600
Water / Gas Inject
Injecting
MELLEN 3A
51031098100
Oil well
Producing
MELLEN WP 1
51036000300
Water / Gas Inject
Injecting
MELLEN WP 2
51030105600
Water / Gas Inject
Injecting
NEAL2AX
51030920800
Water / Gas Inject
Injecting
NEAL4
51030565500
Water / Gas Inject
Injecting
NEAL5A
51030565900
Oil well
Producing
NEAL 6X
51030790600
Oil well
Producing
NEAL 7X
51030804200
Water / Gas Inject
Injecting
NEAL8XST
51030804300
Water / Gas Inject
Monitor
NEAL8XST
51030804301
Water / Gas Inject
Injecting
NEAL 9Y
51030912000
Oil well
Producing
NEWTON ASSOC UNIT D2X
51030868500
Oil well
Monitor
59
-------
NIKKEL 3
51030619200
Water / Gas Inject
Injecting
PURDY 1-1
51030545300
Water / Gas Inject
Monitor
PURDY 2X1
51030881000
Oil well
Producing
RAVEN A1AX
51030917800
Water / Gas Inject
Injecting
RAVEN A2
51030625700
Water / Gas Inject
Injecting
RAVEN A3
51030624400
Water / Gas Inject
Injecting
RAVEN A4
51030625800
Water / Gas Inject
Injecting
RAVEN A5X
51030718800
Oil well
Producing
RAVEN B1
51030564900
Oil well
Producing
RAVEN B2AX
51030923800
Water / Gas Inject
Monitor
RECTOR 1
51030549400
Oil well
Producing
RECTOR 11X
51030867200
Oil well
Shut In
RECTOR 12X
51030919900
Oil well
Shut In
RECTOR 3
51030106000
Water / Gas Inject
Injecting
RECTOR 8X
51030704300
Oil well
Producing
RECTOR 9X
51030714700
Oil well
Shut In
RIGBY1
51030569700
Oil well
Producing
RIGBY5X
51030804700
Water / Gas Inject
Injecting
RIG BY 6Y
51030910700
Oil well
Producing
RIGBY A2AX
51030920000
Water / Gas Inject
Injecting
RIG BY A3X
51030791000
Oil well
Producing
RIGBY A4X
51030791100
Oil well
Monitor
RIGBY A7Y
51030915100
Oil well
Monitor
ROOTH DF 1
51030579700
Water / Gas Inject
Injecting
ROOTH DF 5 X
51031143000
Oil well
Producing
ROOTH DF 6 X
51031125000
Oil well
Producing
S B LACY 3
51030568900
Oil well
Monitor
STOFFERCRA1
51030562700
Water / Gas Inject
Injecting
STOFFER CR A2
51030559200
Water / Gas Inject
Injecting
STOFFERCRB1
51030567300
Oil well
Producing
SW MCLAUGHLIN 10X
51030754700
Oil well
Producing
SW MCLAUGHLIN 9X
51030753500
Oil well
Producing
U P 4829
51030623100
Water / Gas Inject
Monitor
UNION PACIFIC 1 150X16
51031150200
Oil well
Producing
UNION PACIFIC 1 151X16
51031150100
Oil well
Producing
UNION PACIFIC 1 153X16
51031146401
Water / Gas Inject
Injecting
UNION PACIFIC 100X20
51030788600
Oil well
Producing
UNION PACIFIC 101X20
51030797300
Oil well
Monitor
UNION PACIFIC 10-21
51030568501
Oil well
Monitor
UNION PACIFIC 102X20
51030797700
Water / Gas Inject
Injecting
UNION PACIFIC 103X20
51030799000
Water / Gas Inject
Injecting
60
-------
UNION PACIFIC 104X20
51030803000
Water / Gas Inject
Injecting
UNION PACIFIC 105X29
51030794500
Oil well
Producing
UNION PACIFIC 106X32
51030845000
Oil well
Producing
UNION PACIFIC 107X32
51030849800
Oil well
Producing
UNION PACIFIC 108X21
51030849500
Water / Gas Inject
Injecting
UNION PACIFIC 109X32
51030849700
Oil well
Producing
UNION PACIFIC 110X21
51030853000
Water / Gas Inject
Injecting
UNION PACIFIC 111X29
51030852200
Oil well
Producing
UNION PACIFIC 11-21
51030616200
Oil well
Producing
UNION PACIFIC 112X21
51030873500
Oil well
Monitor
UNION PACIFIC 113X22
51030860600
Oil well
Monitor
UNION PACIFIC 115X21
51030866600
Oil well
Producing
UNION PACIFIC 117X22
51030866700
Oil well
Producing
UNION PACIFIC 118X21
51030869700
Oil well
Producing
UNION PACIFIC 119X21
51030869800
Oil well
Producing
UNION PACIFIC 120X21
51030869900
Oil well
Producing
UNION PACIFIC 12-27
51030620400
Oil well
Producing
UNION PACIFIC 122X21
51030870000
Oil well
Monitor
UNION PACIFIC 126X32
51030885100
Oil well
Producing
UNION PACIFIC 127X31
51030884700
Oil well
Producing
UNION PACIFIC 128X31
51030910000
Oil well
Producing
UNION PACIFIC 129X31
51030885200
Oil well
Producing
UNION PACIFIC 130X32
51030885300
Oil well
Producing
UNION PACIFIC 131X32
51030885500
Oil well
Producing
UNION PACIFIC 1-32
51030556700
Water / Gas Inject
Injecting
UNION PACIFIC 13-28
51030622000
Water / Gas Inject
Injecting
UNION PACIFIC 132X21
51030874600
Oil well
Monitor
UNION PACIFIC 133X21
51030876400
Oil well
Producing
UNION PACIFIC 134X21
51030904100
Water / Gas Inject
Injecting
UNION PACIFIC 135Y28
51030910500
Oil well
Monitor
UNION PACIFIC 136X20
51030913800
Oil well
Producing
UNION PACIFIC 137X20
51030913900
Water / Gas Inject
Monitor
UNION PACIFIC 138Y28
51030917300
Oil well
Producing
UNION PACIFIC 139Y28
51030918500
Oil well
Monitor
UNION PACIFIC 140Y27
51030918800
Oil well
Producing
UNION PACIFIC 141Y28
51030918900
Oil well
Producing
UNION PACIFIC 14-20
51030615400
Oil well
Producing
UNION PACIFIC 142Y28
51030919000
Oil well
Monitor
UNION PACIFIC 143Y28
51030918600
Oil well
Monitor
UNION PACIFIC 15-28
51030102900
Oil well
Monitor
UNION PACIFIC 154Y29
51031172000
Oil well
Producing
61
-------
UNION PACIFIC 156Y29
51031172100
Oil well
Producing
UNION PACIFIC 16-27
51030620600
Oil well
Shut In
UNION PACIFIC 17-27
51030621400
Oil well
Producing
UNION PACIFIC 18-21
51030616400
Oil well
Producing
UNION PACIFIC 19-28
51030621900
Water / Gas Inject
Injecting
UNION PACIFIC 20-29
51030622800
Water / Gas Inject
Injecting
UNION PACIFIC 21-32
51030627100
Water / Gas Inject
Monitor
UNION PACIFIC 2-20
51030569200
Oil well
Producing
UNION PACIFIC 22-32
51030627500
Oil well
Producing
UNION PACIFIC 23-32
51030626900
Oil well
Producing
UNION PACIFIC 24-27
51030621200
Water / Gas Inject
Injecting
UNION PACIFIC 25-34
51030106900
Oil well
Shut In
UNION PACIFIC 26-31
51030626100
Water / Gas Inject
Injecting
UNION PACIFIC 27-20
51030577000
Oil well
Monitor
UNION PACIFIC 28-22
51030617300
Oil well
Producing
UNION PACIFIC 29-32
51030548700
Oil well
Monitor
UNION PACIFIC 31-21
51030616600
Oil well
Monitor
UNION PACIFIC 32-27
51030620800
Oil well
Monitor
UNION PACIFIC 33-32
51030626600
Water / Gas Inject
Injecting
UNION PACIFIC 3-34
51030551000
Oil well
Producing
UNION PACIFIC 34-31
51030626300
Water / Gas Inject
Injecting
UNION PACIFIC 35-32
51030626800
Water / Gas Inject
Injecting
UNION PACIFIC 36-32
51030627200
Water / Gas Inject
Injecting
UNION PACIFIC 37AX29
51030917700
Water / Gas Inject
Injecting
UNION PACIFIC 39-17
51030612100
Water / Gas Inject
Injecting
UNION PACIFIC 41-20
51030615800
Water / Gas Inject
Shut In
UNION PACIFIC4-29
51030563200
Water / Gas Inject
Injecting
UNION PACIFIC 42AX28
51030925700
Water / Gas Inject
Injecting
UNION PACIFIC 43-28
51030622100
Water / Gas Inject
Monitor
UNION PACIFIC 44AX20
51030923300
Water / Gas Inject
Injecting
UNION PACIFIC 45-21
51030569600
Water / Gas Inject
Injecting
UNION PACIFIC 47-21
51030615900
Water / Gas Inject
Injecting
UNION PACIFIC 48-29ST
51030623101
Water / Gas Inject
Injecting
UNION PACIFIC 49-27
51030621300
Oil well
Producing
UNION PACIFIC 50-29
51030107100
Water / Gas Inject
Injecting
UNION PACIFIC 51AX20
51030892800
Water / Gas Inject
Injecting
UNION PACIFIC 5-28
51030563900
Oil well
Producing
UNION PACIFIC 52A-29
51030928400
Water / Gas Inject
Injecting
UNION PACIFIC 53-32
51030627600
Water / Gas Inject
Monitor
UNION PACIFIC 54-21
51030616300
Water / Gas Inject
Injecting
UNION PACIFIC 55-17
51030612200
Water / Gas Inject
Injecting
62
-------
UNION PACIFIC 56-21
51030616700
Water / Gas Inject
Injecting
UNION PACIFIC 58-27
51030620500
Water / Gas Inject
Injecting
UNION PACIFIC 59A-27
51031120700
Oil well
Producing
UNION PACIFIC 60-31
51030626200
Water / Gas Inject
Injecting
UNION PACIFIC 61-20
51030615500
Water / Gas Inject
Injecting
UNION PACIFIC 6-21
51030574100
Oil well
Producing
UNION PACIFIC 62AX32
51030919600
Water / Gas Inject
Injecting
UNION PACIFIC 65-5
51030608900
Water / Gas Inject
Monitor
UNION PACIFIC 67-32
51030626700
Water / Gas Inject
Injecting
UNION PACIFIC 68-32
51030628700
Water / Gas Inject
Injecting
UNION PACIFIC 69-27
51030621000
Oil well
Shut In
UNION PACIFIC 71X31
51030727600
Oil well
Producing
UNION PACIFIC 7-29
51030559700
Water / Gas Inject
Injecting
UNION PACIFIC 73X29
51030738600
Oil well
Producing
UNION PACIFIC 74X27
51030741600
Oil well
Monitor
UNION PACIFIC 75X32
51030740200
Oil well
Producing
UNION PACIFIC 76X21
51030742100
Oil well
Producing
UNION PACIFIC 77X32
51030745400
Oil well
Producing
UNION PACIFIC 78X21
51030742600
Water / Gas Inject
Injecting
UNION PACIFIC 79X32
51030744800
Oil well
Monitor
UNION PACIFIC 80X28
51030746000
Water / Gas Inject
Monitor
UNION PACIFIC 81X29
51030749900
Oil well
Producing
UNION PACIFIC 8-20
51030568600
Oil well
Producing
UNION PACIFIC 82X28
51030749400
Oil well
Producing
UNION PACIFIC 83X28
51030750000
Oil well
Producing
UNION PACIFIC 84X28
51030749500
Oil well
Producing
UNION PACIFIC 85X34
51030748100
Water / Gas Inject
Injecting
UNION PACIFIC 86X27
51030748200
Water / Gas Inject
Injecting
UNION PACIFIC 87X29
51030750900
Oil well
Producing
UNION PACIFIC 88X21
51030751400
Oil well
Producing
UNION PACIFIC 89X34
51030754800
Water / Gas Inject
Injecting
UNION PACIFIC 91X28
51030756000
Water / Gas Inject
Injecting
UNION PACIFIC 9-29
51030565600
Water / Gas Inject
Injecting
UNION PACIFIC 92X28
51030757400
Water / Gas Inject
Monitor
UNION PACIFIC 94X27
51030758800
Water / Gas Inject
Injecting
UNION PACIFIC 96X29
51030765000
Oil well
Producing
UNION PACIFIC 97X29
51030765100
Oil well
Producing
UNION PACIFIC 98X32
51030765200
Oil well
Producing
UNION PACIFIC 99X29
51030785600
Oil well
Producing
UNION PACIFIC Bl-34
51030548900
Water / Gas Inject
Monitor
UNION PACIFIC B2-34
51030102700
Oil well
Monitor
63
-------
UNION PACIFIC B3X34
51030744000
Oil well
Producing
UNION PACIFIC B4X34
51030753600
Water / Gas Inject
Injecting
UNION PACIFIC B5X34
51030759900
Water / Gas Inject
Injecting
UNION PACIFIC B6X34
51030760200
Water / Gas Inject
Monitor
WALBRIDGE LB 1
51030607000
Water / Gas Inject
Monitor
WALBRIDGE UNIT 1
51030607200
Water / Gas Inject
Monitor
WALBRIDGE UNIT 2X
51030920500
Oil well
Producing
WALBRIDGE UNIT 3X
51030920600
Oil well
Monitor
WEBER UNIT 57X
51030764900
Oil well
Monitor
WEYRAUCH 2-36
51030630600
Water / Gas Inject
Injecting
WEYRAUCH 4X36
51030707200
Oil well
Producing
WEYRAUCH 5X36
51030881900
Oil well
Producing
WEYRAUCH 6X36
51030916600
Oil well
Producing
WEYRAUCH 7X36
51030916300
Oil well
Producing
AC MCLAUGHLIN 39
51030582400
P&A
P&A
AC MCLAUGHLIN 3
51030578600
P&A
P&A
MCLAUGHLIN AC 40
51030632000
P&A
P&A
AC MCLAUGHLIN 41
51030575900
P&A
P&A
AC MCLAUGHLIN 48X
51030580300
P&A
P&A
AC MCLAUGHLIN 59X
51030769100
P&A
P&A
MCLAUGHLIN AC81X
51031053000
P&A
P&A
A.C. MCLAUGHLIN A A2
51030609300
P&A
P&A
AC MCLAUGHLIN B 1
51030611000
P&A
P&A
AC MCLAUGHLIN B 2
51030610500
P&A
P&A
AC MCLAUGHLIN 1
51030612000
P&A
P&A
AC MCLAUGHLIN 1
51030757700
P&A
P&A
ASSOCIATED 4X
51030881200
P&A
P&A
ASSOCIATED B 1
51030601200
P&A
P&A
ASSOCIATED B 2
51030601000
P&A
P&A
ASSOCIATED B 3
51030601300
P&A
P&A
BEEZLEY 1 22
51030573900
P&A
P&A
CT CARNEY 12-5
51030107000
P&A
P&A
CT CARNEY 26X35
51030745000
P&A
P&A
CARNEY CT 31X4
51030760400
P&A
P&A
CARNEY CT34X-4
51030760000
P&A
P&A
CARNEY CT 36X34
51030759500
P&A
P&A
CARNEY CT 40X35
51030911700
P&A
P&A
CARNEY CT42Y34
51030915400
P&A
P&A
CHASE UNIT U 1
51030600800
P&A
P&A
HILL,C.E. 1
51030601800
P&A
P&A
HEFLEY C-Sl
51030104100
P&A
P&A
64
-------
C-S HEFLEY 2
51030607700
P&A
P&A
C-S HEFLEY3
51030607800
P&A
P&A
C R STOFFER A 3
51030562600
P&A
P&A
EMERALD 12
51030566700
P&A
P&A
EMERALD 15
51030565400
P&A
P&A
EMERALD 18
51030104900
P&A
P&A
EMERALD 21
51030546400
P&A
P&A
EMERALD 24
51030563500
P&A
P&A
EMERALD 29
51030565800
P&A
P&A
EMERALD 30
51030563000
P&A
P&A
EMERALD 31
51030623700
P&A
P&A
EMERALD 33
51030623900
P&A
P&A
EMERALD OIL CO. 3M
51030724700
P&A
P&A
EMERALD 43
51030625200
P&A
P&A
EMERALD 44
51030633800
P&A
P&A
EMERALD 45
51030603000
P&A
P&A
EMERALD 49X
51030729600
P&A
P&A
EMERALD 5
51030566600
P&A
P&A
EMERALD 7
51030624100
P&A
P&A
E OLDLAND 4
51030715200
P&A
P&A
FAIRFIELD,KITTIE A 2
51030611400
P&A
P&A
FAIRFIELD,KITTIE A 3
51030611700
P&A
P&A
F V LARSON 116
51036652500
P&A
P&A
FEE118X
51030843900
P&A
P&A
FEE119X
51030849400
P&A
P&A
FEE 16IX
51031185900
P&A
P&A
FEE 16
51030624600
P&A
P&A
FEE 2
51030558600
P&A
P&A
FEE 46
51030610700
P&A
P&A
FEE 53
51030617400
P&A
P&A
FEE 54
51030618000
P&A
P&A
FEE 57
51030622700
P&A
P&A
FEE 58
51030614300
P&A
P&A
FEE 66
51030610900
P&A
P&A
FEE 67
51030611600
P&A
P&A
FEE 70
51030626000
P&A
P&A
FEE 71
51030610800
P&A
P&A
FEE 77X
51030736000
P&A
P&A
FEDERAL ETAL 2M
51030719700
P&A
P&A
FEDERAL ETAL 5M
51030731700
P&A
P&A
LARSON FV BIO
51030629900
P&A
P&A
65
-------
LARSON FV B13X
51030557900
P&A
P&A
LARSON FV B16X
51030702400
P&A
P&A
LARSON FV B1
51030629600
P&A
P&A
LARSON FV 26Y
51030948500
P&A
P&A
LARSON FV B3
51030630500
P&A
P&A
LARSON FV B5
51030630100
P&A
P&A
LARSON FV B6
51030630300
P&A
P&A
LARSON F V B7
51030630001
P&A
P&A
LARSON FV B9
51030102500
P&A
P&A
F V LARSON 1
51030539800
P&A
P&A
GENTRY 2D
51030543700
P&A
P&A
GENTRY 3D
51030608500
P&A
P&A
NEWTON 4-D
51030104300
P&A
P&A
GENTRY4D
51030544400
P&A
P&A
GENTRY5D
51030608300
P&A
P&A
GENTRY6X
51030744200
P&A
P&A
GRAY A 11
51030613800
P&A
P&A
GRAY A 11 AX
51030927500
P&A
P&A
GRAY A 8
51030568100
P&A
P&A
GRAY B 14
51030613000
P&A
P&A
GUIBERSON,S.A. A 2
51030613400
P&A
P&A
HILDENBRANDT 1
51030608100
P&A
P&A
COLTHARP JE 1
51030602400
P&A
P&A
J E COLTHARP 3
51030602500
P&A
P&A
COLTHARP JE 6X
51030714800
P&A
P&A
COLTHARP JE 9X P 9X
51030853500
P&A
P&A
PEPPER,J.E. A 1
51030550200
P&A
P&A
J E PEPPER B1
51030606300
P&A
P&A
LACY SB 10Y
51030914300
P&A
P&A
S B LACY 2
51030570600
P&A
P&A
F V LARSON 1
51030106500
P&A
P&A
LEVISON 15
51030618100
P&A
P&A
LEVISON 16
51030619600
P&A
P&A
LEVISON 19
51030106300
P&A
P&A
LEVISON 20
51030618300
P&A
P&A
LEVISON 3
51030621600
P&A
P&A
LEVISON 4
51030560400
P&A
P&A
LEVISON 5
51030621500
P&A
P&A
L N HAGOOD B 1
51030607300
P&A
P&A
L N HAGOOD B 2
51030607100
P&A
P&A
L N HAGOOD B 3
51030607400
P&A
P&A
66
-------
WALBRIDGE LB 3
51030630800
P&A
P&A
WALBRIDGE LB 4X
51030873600
P&A
P&A
WALBRIDGE LB 5Y
51030948300
P&A
P&A
MAGOR 1
51030580800
P&A
P&A
MCLAUGHLIN 3
51030556100
P&A
P&A
MELLEN,W.P. A 3
51030105700
P&A
P&A
HEFLEYME 1
51030607500
P&A
P&A
HEFLEY ME 3
51030545400
P&A
P&A
HEFLEYME 4
51030543300
P&A
P&A
M B LARSON C11X 25
51030717300
P&A
P&A
M B LARSON A 1
51030632900
P&A
P&A
MB LARSON A3
51030576400
P&A
P&A
LARSON MB 1-35
51030555700
P&A
P&A
M B LARSON C 1
51030571900
P&A
P&A
LARSON MB C2-25
51030106400
P&A
P&A
M B LARSON C425
51030618900
P&A
P&A
LARSON MB D136
51030631000
P&A
P&A
LARSON MB D226
51030102600
P&A
P&A
M B LARSON D525
51030618500
P&A
P&A
M B LARSON D625
51030619000
P&A
P&A
M B LARSON D725
51030618400
P&A
P&A
NEAL2
51030566000
P&A
P&A
NEAL3
51030567200
P&A
P&A
NEWTON ASSOC A1
51030107300
P&A
P&A
NEWTON ASSOC B 1
51030101800
P&A
P&A
NEWTON ASSOC C 1
51030102100
P&A
P&A
NEWTON ASSOC D 1
51030102200
P&A
P&A
NIKKEL 1
51030619300
P&A
P&A
NIKKEL2
51030619100
P&A
P&A
OLDLAND 1
51030102000
P&A
P&A
OLDLAND 2
51030106100
P&A
P&A
OLDLAND 3
51030630400
P&A
P&A
OLDLAND E5X
51030853600
P&A
P&A
OLDLAND E6X
51030947600
P&A
P&A
PURDY16
51030606200
P&A
P&A
PURDY3X1
51030870300
P&A
P&A
RANGELY 2M-33-19B
51030939800
P&A
P&A
RAVEN A 1
51030562900
P&A
P&A
RAVEN B 2
51030624300
P&A
P&A
RECTOR 10X
51030760300
P&A
P&A
RECTOR 2
51030608400
P&A
P&A
67
-------
RECTOR 2
51030728000
P&A
P&A
RECTOR 4
51030629400
P&A
P&A
RECTOR 5
51030629200
P&A
P&A
RECTOR 6
51030608200
P&A
P&A
RECTOR 7
51030105900
P&A
P&A
RIGBY A224
51030570000
P&A
P&A
ROOTH 3
51030564700
P&A
P&A
MCLAUGHLIN SHARPLES 11X 3
51030760500
P&A
P&A
SHARPLES MCLAUGHLIN 132
51030107400
P&A
P&A
SHARPLES MCLAUGHLIN 432
51030627400
P&A
P&A
UNION PACIFIC 121X21
51030870500
P&A
P&A
U P 3016
51030578300
P&A
P&A
UNION PACIFIC 37-29
51030623200
P&A
P&A
U P 3822
51030574400
P&A
P&A
U P 4022
51030617800
P&A
P&A
U P 4228
51030621800
P&A
P&A
U P 4420
51030571000
P&A
P&A
UNION PACIFIC 46-21
51030573700
P&A
P&A
U P 5721
51030616500
P&A
P&A
U P 5927
51030620900
P&A
P&A
UNION PACIFIC 62-32
51030626500
P&A
P&A
UNION PACIFIC 63-31
51030623000
P&A
P&A
UNION PACIFIC 63-31
51030626400
P&A
P&A
UNION PACIFIC 63AX31
51030917900
P&A
P&A
U P 6422
51030617200
P&A
P&A
U P 6616
51030610600
P&A
P&A
UNION PACIFIC 72X31
51030736400
P&A
P&A
UNION PACIFIC 90X29
51030758200
P&A
P&A
UNION PACIFIC 93X27
51030756100
P&A
P&A
U P 95X 34
51030759600
P&A
P&A
COLTHARP WH A2
51030602000
P&A
P&A
COLTHARP WH A7X
51030869300
P&A
P&A
COLTHARP WH B1
51030101900
P&A
P&A
WEYRAUCH 1-36
51030630700
P&A
P&A
WEYRAUCH 336
51030630900
P&A
P&A
WHITE 1
51030543500
P&A
P&A
WHITE 2
51030545100
P&A
P&A
68
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