Carbon Storage Atlas

Plains CO2 Reduction Partnership



Site: Bell Creek Field


45.07 -105.11

Why This Location

The challenge faced by all partnerships for Phase III of the Regional Carbon Sequestration Partnerships (RCSP) Program was to find an opportunity to inject large-scale quantities (1 million metric tons or more) of carbon dioxide (CO2) for geological storage and/or collaborate with an industry partner already progressing a project of similar size. The Plains CO2 Reduction (PCOR) Partnership initially worked with Spectra Energy to investigate the potential for more than 2 million metric tons of CO2 storage per year, sourced from natural gas processing at the Fort Nelson site in northern British Columbia. The PCOR Partnership undertook detailed characterization, modeling, and risk assessment studies, gaining valuable learnings, but ultimately the project did not achieve operational status for commercial reasons. Plans for applying CO2 enhanced oil recovery (EOR) at the Bell Creek Field in Montana subsequently provided a perfectly timed opportunity for the PCOR Partnership to assess and monitor large-scale associated storage, with the invaluable support of Denbury Resources.


Research Q&As Discovered

During the course of the PCOR Partnership field program at Bell Creek, enhanced oil recovery (EOR) operations achieved more than 5 million metric tons of CO2 associated storage incidental to EOR operations. Assessment of this associated storage for the purposes of the RCSP Program was achieved through an adaptive management approach (AMA) comprising the following elements:

  • Detailed site characterization efforts, using oil field well records and production data, 3D seismic survey data, and drilling of a dedicated monitoring well.
  • Modeling and simulation, with history-matching of past oil production and recent EOR performance providing improved understanding of reservoir characteristics and refined predictive forecasting of associated storage.
  • Risk assessment, with demonstrable risk reduction over time with improvement in reservoir understanding and accumulation of monitoring data.
  • Monitoring of environmental receptors through a comprehensive program targeting shallow groundwater, surface water, and soils categorically showed no evidence of significant changes from baseline conditions, or any results that could be indicative of impacts from injected CO2.

Can we effectively monitor injected CO2? Yes!

The Phase III project provided an opportunity to test various technology options for monitoring injected CO2 in the reservoir. Repeat 3D surface seismic surveys achieved outstanding results, particularly considering the relatively thin reservoir. In combination with well logging, especially pulsed-neutron logs (PNL) showing CO2 saturations in the vicinity of wells, interpretation of 3D seismic surveys allowed detailed imaging of CO2 migration in the reservoir and improved understanding of pertinent geologic features, such as changes in rock-type influencing fluid flow.


Advice for Future Operators

The overall benefit of the Plains CO2 Reduction (PCOR) Partnership Phase III research at Bell Creek has been to demonstrate the secure and efficient nature of associated carbon dioxide (CO2) storage incidental to enhanced oil recovery (EOR) operations. Lessons learned and recommendations derived from the Phase III program, many of which are equally applicable to dedicated storage in a deep saline formation, have been incorporated into a series of five Best Practices Manuals (BPMs) published by the PCOR Partnership and summarized below.

An adaptive management approach (AMA) provides an iterative framework for the technical assessment and operation of storage projects. The four key technical elements of the AMA are described in the following separate BPMs:

  • Site Characterization: Existing data from published and (where accessible) private sources typically provide the basis for screening studies of potential storage formations and locations. Detailed characterization of a storage site may also utilize existing information; however, dedicated storage projects in deep saline formations typically require field investigation, such as exploratory wells or geophysical surveys.
  • Modeling and Simulation: A combination of measured subsurface data and geological interpretation informs the construction static base geologic models. Reservoir engineers then simulate CO2 injection and storage using state-of-the-art simulation software.
  • Risk Assessment: Site characterization data, in combination with modeling and simulation outputs, form the basis for applying engineering judgment to the assessment of environmental and operational risks.
  • Monitoring: Site-specific factors, including assessed risks, engineering judgment, and regulatory requirements, collectively influence the formulation of monitoring strategy and selection of techniques and technology options.



Field Site Story of Interest

Fieldwork Challenges

To meet the Plains CO2 Reduction (PCOR) Partnership Phase III research objectives, the Energy and Environmental Research Center (EERC) implemented an expansive program of fieldwork activities across a five-year period at the Bell Creek Field. Major work included:

  • Drilling and instrumentation of a dedicated monitoring well.
  • Repeat seismic surveys.
  • Fluid sampling from wells.
  • Monitoring of the environment, including groundwater, surface water, and soils.

John Hamling, Assistant Director for Integrated Projects at EERC, describes the importance of developing a relationship with the oil field operator: “Public-private partnerships are critical for advancing large integrated research projects like the one conducted at Bell Creek,” Hamling stated. “Denbury Onshore, LLC, provided tremendous support for our research program. Strict observation of all health and safety rules was imperative, and avoiding any impact from our research activity on commercial operations was an absolute priority for building and maintaining trust. We are proud to have fostered an excellent relationship with Denbury as we sought ways for our research results to add value for their support.”

EERC staff collectively spent many thousands of hours in the field at Bell Creek to help meet the research objectives of the PCOR Partnership. Situated in a relatively remote area, Bell Creek enjoys all of the weather variations typical of the northern Great Plains region. The combination of location, weather, and even local fauna and flora made for many interesting experiences and challenges for fieldwork. Staff endured subzero winter temperatures with extreme wind chills, 100°F summer heat with biting insects, occasional tornados, and flash floods from thunderstorms.

EERC Principal Geologist, Nick Bosshart, after spending a considerable amount of time at Bell Creek, recalled wildlife encounters onsite: “Deer and pronghorn antelope gave plenty of photo opportunities, but my favorite memory is of a particularly large and disagreeable porcupine that prevented vehicular access to a monitoring station for over half an hour.”


Geologist Rock-Fest

Muddy Formation – Bell Creek

The Lower Cretaceous Mowry Formation overlies the Muddy Formation (reservoir and carbon dioxide [CO2] injection target formation) and provides the primary seal, preventing the migration of fluid to overlying aquifers and to the surface. Overlying the Mowry, several thousand feet of low-permeability strata provides secondary seals that will retard, if not prevent, upward fluid migration in the unlikely event that the primary seal fails.

Deposited in nearshore marine environments, high-porosity, high-permeability sandstones dominate the Muddy Formation within the Bell Creek Field. The reservoir pressure, approximately 1,200 pounds per square inch (psi), is significantly lower than the regional hydrostatic pressure regime of 2,100 psi at approximately 1,370 meters (4,500 feet). Structurally, the field is on a shallow monocline dipping less than 2 degrees to the northwest, with a strike trending southwest to northeast. Stratigraphically, the Bell Creek sand interval pinches out in the updip direction against the overlying Springen Ranch Member and the underlying Rozet Member of the Muddy Formation.

Several modern technologies have been employed to characterize the Bell Creek Field, as well as monitor, verify, and account for the spread of CO2 after injection. Data and understanding have been generated from pulsed-neutron log (PNL) campaigns, interferometric synthetic aperture radar (InSAR) measurements, baseline and repeat 3D seismic surveys, 3D geologic modeling, and predictive simulations.


Project Introduction

The Plains CO2 Reduction (PCOR) Partnership, led by the Energy and Environmental Research Center (EERC), worked with Denbury Onshore, LLC (Denbury) to determine the effect of large-scale injection of carbon dioxide (CO2) into a deep clastic reservoir for the purpose of CO2 storage associated with a commercial CO2 enhanced oil recovery (EOR) project at Denbury’s Bell Creek Field.

Carbon dioxide for the project is sourced from the Lost Cabin and Shute Creek gas-processing facilities of Wyoming. The CO2 is transported to the field via the Greencore pipeline with a tie-in from the Anadarko pipeline. The CO2 is injected into an oil-bearing sandstone reservoir in the Muddy Formation at a depth of approximately 1,370 meters (4,500 feet). This collaborative project has demonstrated:

  • That CO2 storage can be safely and permanently achieved on a commercial scale in association with an EOR operation.
  • That oil-bearing sandstone formations are viable regional sinks for CO2.
  • That monitoring, verification, and accounting (MVA) methods can be used to effectively monitor associated CO2 storage incidental to commercial-scale CO2-EOR projects.


  • Associated storage of more than 6 million metric tons of CO2 (September 2019) since operations began at the Bell Creek site in May 2013.
  • Successful technical assessment of associated storage using an adaptive management approach (AMA), including the use of 3D repeat seismic surveys and other monitoring techniques to track CO2 in the reservoir.
  • Comprehensive environmental monitoring, including the establishment of baseline conditions, to show the secure nature of geological storage.



Site Operations

The Bell Creek project began injecting CO2 in May 2013. Carbon dioxide is delivered to the site via pipeline from the Lost Cabin and Shute Creek gas plants in Wyoming, where it is separated from the process stream during refinement of natural gas. The supplied CO2 is delivered at around more than 1.4 million cubic meters per day (50 million cubic feet per day) to the Bell Creek Field. Carbon dioxide is injected into the oil-bearing sandstone reservoir in the Lower Cretaceous Muddy (Newcastle) Formation at a depth of approximately 1,370 meters (4,500 feet). Carbon dioxide injection is occurring in a staged approach (nine planned CO2 developmental phases) across the field. The reservoir has been found to be suitable for miscible flooding conditions and is likely to meet the incremental oil production target of 40 to 50 million barrels.

Injection/production generally occurs via a typical five-spot pattern of 40-acre spacing. As with typical EOR procedures, recovered oil, CO2, and water are separated at the process/recycle facilities located onsite. Water and CO2 are separated from the oil and recycled and reinjected as part of the EOR operation.


Site Characterization

A robust and iterative site characterization program was initiated in 2010 to provide data necessary for the establishment of baseline reservoir characteristics and for modeling and simulation activities. Characterization activities provide a solid foundation for the other critical elements of the adaptive management approach (AMA; risk assessment; modeling and simulation; and monitoring, verification, and accounting [MVA]), resulting in an increased confidence in predicting and tracking carbon dioxide (CO2) movement.

Key activities include the following:

  • Vintage well log, core analysis, and well file data from more than 700 wells within and surrounding the Bell Creek Field were acquired and incorporated into the geologic model.
  • An approximately 194-square-kilometer (75-square-mile) lidar survey collected over the field in July 2011 was used to verify and correct well location and elevation data throughout the field, significantly improving structural interpretations of the reservoir.
  • A monitoring and characterization well was drilled in the Phase I development area in December 2011. A full suite of well logs, approximately 34 meters of 2.5-centimenter-diameter core (110 feet of 4-inch-diameter core), and 47 sidewall cores were acquired from the reservoir, along with top and bottom seals.
  • Three casing-conveying pressure/temperature gauges and a fiber-optic distributed temperature system were installed during completion of the monitoring well to provide reservoir characterization data prior to and during injection.
  • An approximately 104-square-kilometer (40-square-mile) 3D seismic survey was collected in August 2012 to further aid in structural interpretation and provides a baseline data set for future time-lapse CO2 monitoring.
  • Thirty-three pulsed-neutron logs (PNLs) were collected in summer 2013. PNLs provide data sets for determining CO2, water, and oil saturation changes in the reservoir. Three repeat acquisitions were performed on subsets of the wells, with more planned throughout the project.
  • Two 3D vertical seismic profile (VSP) seismic surveys were conducted in spring 2013, which included the installation of a permanent geophone array. These surveys and the geophone array allow for time-lapse data acquisitions for CO2 monitoring and passive seismic monitoring during injection. Repeat acquisitions occurred during spring 2014.

Risk Assessment

A wide variety of modeling activities have been conducted at the Bell Creek site, including multiple-sized geologic models, predictive multiphase fluid flow simulations, geomechanical modeling, and geochemical simulation. These models and simulations are used to interpret and analyze the geologic, reservoir, and fluid data and conduct predictive multiphase flow, geomechanical, and geochemical simulations to identify data gaps, identify potential risks, and guide the monitoring, verification, and accounting (MVA) program.

518-Square-Kilometer Static Geocellular Model
A 3D mesh representing upper and lower caprocks and the reservoir, this model was constructed to better understand the injection horizon, lateral pinch-outs, and overlying and underlying seals.

48-Square-Kilometer Numerical Flow Simulation Model
A 3D mesh centered on the Phase I area of the Bell Creek Field and spanning the reservoir interval, this model was history-matched to validate the geologic model and then used to run predictive simulations to evaluate reservoir performance, carbon dioxide (CO2) sweep and storage efficiencies, CO2 breakthrough time at various production wells, pressure response, and long-term CO2 plume migration. Subsequent efforts have been made to add Phase II to the numerical flow model.

518-Square-Kilometer 3D Mechanical Earth Model (MEM)
Centered on the Bell Creek Field and incorporating each formation from the lower seal to the surface, this model was constructed to predict geomechanical changes to the reservoir and surrounding formations as a result of injection and production activities and assess the local and regional stress regime.

Risk management; modeling; and monitoring, verification, and accounting (MVA) are interrelated processes, where the results of one become the inputs of the others. This creates an iterative process to manage the risks throughout the life of the project. In the initial risk assessment, the Energy and Environmental Research Center (EERC) project team identified and evaluated 120 potential subsurface technical risks that were grouped into broad categories (e.g., capacity, injectivity, and retention; lateral migration; vertical migration).

It was determined that the technical risks identified were adequately addressed by the current MVA program. Most risks are being monitored using more than one measurement, providing redundant lines of evidence for inferring migration of CO2 or other fluids beyond the reservoir.

Additionally, 24 strategic risks were identified (e.g., CO2 supply, management, or policy changes) and assessed. None were found to have significant potential to negatively impact the project.



The goal of the monitoring, verification, and accounting (MVA) program was to provide critical data to verify site security, evaluate reservoir behavior during injection, determine the ultimate fate of injected carbon dioxide (CO2), and investigate mechanisms that affect CO2 storage efficiency within the enhanced oil recovery (EOR) process, all while operating in a manner compatible with the commercial CO2-EOR operation. The MVA program uses time-lapse data acquisitions as part of a surface-, shallow-subsurface-, and deep-subsurface-monitoring effort guided by the Plains CO2 Reduction (PCOR) Partnership adaptive management approach (AMA).

The deep-subsurface MVA program focused on the storage reservoir interval as well as monitoring the entire interval from the reservoir, up to the deepest underground source of drinking water (USDW). The deep-subsurface MVA program used a combination of wellbore and geophysical technologies to track the vertical and lateral extent of fluid and CO2 during and after injection.

A shallow-subsurface monitoring program accounted for monitoring the interval between the deepest USDW and the surface, including surface water bodies. This program: (1) established baseline conditions for soil gas and water chemistries present in surface water, soil, and shallow groundwater aquifers in the vicinity of the CO2 injection site, and (2) provided data to confirm that surface environments remained unaffected by EOR operations.

MVA programs require selection of a suite of technology options, according to project objectives and site-specific subsurface and surface conditions. For this reason, the PCOR Partnership designed a monitoring program specific to the needs of associated storage assessment at the Bell Creek Field and, in keeping with the objectives of the Phase III Regional Carbon Sequestration Partnerships (RCSP) Program, using several commercially available technologies. The specific technologies selected operated in a complementary manner where an anomalous detection from one monitoring technique could be investigated using one or more of the remaining techniques to confirm whether an issue exists. Additionally, the PCOR Partnership evaluated each of these monitoring technologies to understand their benefits, limitations, and challenges when deployed in conjunction with a commercial CO2-EOR operation.