Plains CO2 Reduction Partnership (PCORP) Phase II and Phase III


University of North Dakota
Award Number:  FC26-05NT42592
Project Duration:  10/01/2005 – 09/30/2017
Total Award Value:  $142,415,287.00
DOE Share:  $90,454,435.00
Performer Share:  $51,960,852.00
Technology Area:  Regional Carbon Sequestration Partnerships/Injection Projects
Key Technology: 

Project Description

Project Summary

The PCOR Partnership is planning two large-scale CO2 projects (Bell Creek site and Fort Nelson site) for the Development Phase, also known as Phase III (Figure 1).

Bell Creek Site. For the Bell Creek large-scale project, the PCOR Partnership is working with Denbury Onshore LLC (Denbury) to develop robust, practical, and targeted support programs to study incidental CO2 storage associated with a commercial-scale EOR operation. These programs include modeling and simulation; monitoring, verification, accounting (MVA), and assessment; and risk management programs of appropriate size for a commercial-scale injection of CO2. The project is being conducted in the Bell Creek Oil Field in Powder River County in southeastern Montana, and will provide insight into the relationship between successful incidental CO2 storage and tertiary recovery on oil production within a sandstone reservoir in the Cretaceous Muddy Formation. The Bell Creek project is a significant opportunity to develop a set of cost-effective MVA protocols for large-scale CO2 storage associated with a commercial-scale EOR operation.

Fort Nelson Site. The Fort Nelson Carbon Capture and Storage (CCS) Feasibility Project, an international collaboration led by Spectra Energy that includes industry, government, universities, and technologists, has initiated what may ultimately be the largest application of deep saline geologic storage in the world. If proven feasible, this project will provide permanent storage of up to 2 million metric tons of CO2 per year from the Fort Nelson gas processing facility, the largest processing facility in the region and the largest of its type in North America. The concept of the project is to capture sour CO2 (mixture of CO2 and hydrogen sulfide [H2S]) from one of the largest gas-processing plants in North America and inject it into a deep saline formation. The sour CO2 will be compressed and transported approximately 9 miles (15 kilometers) in a supercritical state via pipeline to the target injection location. The target zone will be a carbonate rock (limestone and dolomite) formation in the Devonian-age Elk Point Group. The injection location will be in relatively close proximity to the gas plant at a depth of >7,200 feet.

Injection Site Description

Bell Creek Site. The specific host site for the injection wells for the Bell Creek demonstration is located in the Bell Creek Oil Field approximately 30 miles southeast of Broadus, Montana.

Fort Nelson Site. The specific host site for the injection wells for the Fort Nelson demonstration will be located in northeastern British Columbia, approximately 9 miles west of the Fort Nelson gas plant (Figure 2).

Description of Geology

Bell Creek Site. CO2 is being injected into the oil-bearing sandstone reservoir in the Lower Cretaceous Muddy (Newcastle) Formation at a depth of approximately 4500 feet. Within the Bell Creek oil field, the Muddy Formation is dominated by high-porosity (25 percent–35 percent), high-permeability (150–1175 mD) sandstones deposited in a nearshore marine environment. The initial reservoir pressure was approximately 1200 psi, which is significantly lower than the regional hydrostatic pressure regime (2100 psi at 4500 ft) which provides evidence of effective seals above and below the reservoir. The oil field is located structurally on a shallow monocline with a 1°–2° dip to the northwest and with an axis trending southwest to northeast for a distance of approximately 20 miles. Stratigraphically, the Muddy Formation in the Bell Creek oil field features an updip sand facies pinchout into shale facies serving as a trap. The barrier bar sand bodies of the Muddy Formation strike southwest to northeast and lie on a regional structural high, which represents a local paleodrainage deposition. A deltaic siltstone overlaps the sandstone on an erosional barrier bar surface and, finally, is partially dissected and somewhat compartmentalized by intersecting shale-filled incisive erosional channels. The overlying Lower Cretaceous Mowry Shale provides the primary seal, preventing fluid migration to overlying aquifers and to the surface. On top of the Mowry Shale are several thousand feet of low-permeability formations, including the Belle Fourche, Greenhorn, Niobrara, and Pierre Shales, which will provide redundant layers of protection in the unlikely event that the primary seal fails to prevent upward fluid migration fieldwide.

Fort Nelson Site. The target zone for the Fort Nelson injection is a carbonate rock formation, known as the Elk Point Group, located at a depth of >7,200 feet. The Elk Point Group is composed of carbonate rocks with average porosities ranging from 8 percent to 12 percent, with permeability in the tens to hundreds of millidarcies range. These rocks were deposited in a series of reef-building events and have undergone extensive post-depositional alteration, resulting in a highly heterogeneous mixture of dolomites and limestones. Although highly variable in geology, formations within the Elk Point Group have held large natural gas fields locally and regionally, demonstrating their ability to hold large quantities of gas for geologic time periods. Thick, competent, laterally continuous shales of the Devonian Fort Simpson and Muskwa Formations act as the primary confining zone holding this gas in place and will also act as the primary confining zone for CO2 storage. These shales range in thickness between 1,310 and 1,970 feet in the Fort Nelson area and are characterized by low permeability and high geomechanical strength, and should make excellent seals for CO2 storage. Secondary confinement also exists above the Fort Simpson Formation, the most competent and massive being the Banff Formation, which is predominantly shale and is not less than 100 feet thick in the Fort Nelson area.

Source of CO2

Bell Creek Site. Carbon dioxide for the Bell Creek demonstration is being sourced from ConocoPhillips’ Lost Cabin Gas Plant, a gas-processing facility located in Fremont County, Wyoming. The Lost Cabin Gas Plant currently supplies approximately 50 million cubic feet of CO2 per day to the Bell Creek oil field. Denbury and Conoco Phillips have entered into a CO2 purchase-and-sale agreement, and compression facilities adjacent to the Lost Cabin Gas Plant pressurize the CO2 from approximately 50 to 2,200 psi, for transportation to the project site at a near-injection-ready pressure. This infrastructure includes a 232-mile pipeline that was completed in 2012 that is bringing CO2 to the injection site at a rate of approximately 1 million metric tons per year (Figure 3). Denbury commercial activities are estimated to recover approximately 30 million bbl of incremental oil over the operation’s 20- to 25-year life, but these commercial activities are outside the scope of the PCOR Partnership project.

Fort Nelson Site. The Fort Nelson demonstration will utilize sour CO2 from the Spectra Energy Fort Nelson Natural Gas-Processing Plant in northwestern British Columbia, Canada. The sour CO2 will be captured using an existing amine-based acid gas removal system, dried, compressed, and transported by pipeline as a supercritical fluid to a nearby injection site. Its composition will be approximately 95 percent CO2 and 5 percent H2S.

Injection Operations

Bell Creek Site. The injection strategy for Bell Creek was developed by Denbury, for the purposes of commercial CO2 EOR. Note that Denbury’s commercial CO2 EOR operations are independent for the PCOR research project. Under PCOR, the EERC is conducting site characterization, modeling and predictive simulation, and MVA to study the interrelationship of commercial CO2 EOR and incidental CO2 storage and to evaluate how various EOR injection strategies affect reservoir response, storage efficiencies, and storage capacities. Injection in the Bell Creek oil field began in May 2013. Since the Bell Creek Oil Field has undergone secondary recovery, much of the infrastructure necessary for a combined CO2 EOR and CO2 storage project was already in place. In addition, Denbury has constructed a 232-mile CO2 pipeline (known as the Greencore Pipeline) which is delivering CO2 from the ConocoPhillips Lost Cabin gas-processing plant to the Bell Creek Oil Field. The pipeline was completed in November 2012. Surface facilities and support infrastructure were constructed, and were commissioned in August 2013. These facilities allow for CO2 separation from produced hydrocarbons and subsequent reinjection into the Muddy Formation at a depth of approximately 4,500 feet and a temperature of 110°F. These pressures and temperatures will ensure that the CO2 remains in a supercritical state in the reservoir. Currently planned operations consist of a continuous CO2 flood followed by a water alternating gas (WAG) cycle utilizing both recycled CO2 from the processing facilities and incoming CO2 from the Greencore Pipeline.

Fort Nelson Site. For the Fort Nelson demonstration, if proven feasible, Spectra Energy will install significant infrastructure to transport the supercritical sour CO2 to the injection site, including construction of compressors, a dehydration system, a pipeline for the sour CO2 gas stream, and a pump. The target injection formation is at a depth of >7,200 feet. Formations in this depth range will be at temperatures and pressures that ensure the injected sour CO2 remains in a supercritical state.

Simulation and Monitoring of CO2

In the Development Phase, an emphasis has been placed on developing practical, site-specific, cost-effective, and risk-based MVA plans. This philosophy begins with a thorough site characterization, which is used to develop geologic models and perform injection simulations to predict the long-term fate of the injected CO2. Both the site characterization and the modeling and simulation then feed into a detailed and iterative risk assessment process which is used to identify potential leakage and migration risks, from which a detailed, site-specific, risk-based MVA plan is developed. This integrated approach will be repeated throughout the course of the project, and the cycle can be repeated and at any point if more data are required.

Project Benefits

The U.S. Department of Energy Regional Carbon Sequestration Partnership (RCSP) Initiative consists of seven partnerships. The purpose of these partnerships is to determine the best regional approaches for permanently storing carbon dioxide (CO2) in geologic formations. Each RCSP includes stakeholders comprised of state and local agencies, private companies, electric utilities, universities, and nonprofit organizations. These partnerships are the core of a nationwide network helping to establish the most suitable technologies, regulations, and infrastructure needs for carbon storage. The partnerships include more than 400 distinct organizations, spanning 43 states and four Canadian provinces, and are developing the framework needed to validate geologic carbon storage technologies. The RCSPs are unique in that each one is determining which of the numerous geologic carbon storage approaches are best suited for their specific regions of the country and are also identifying regulatory and infrastructure requirements needed for future commercial deployment. The RCSP Initiative is being implemented in three phases, the Characterization Phase, Validation Phase, and Development Phase. In September 2003, the Characterization Phase began with the seven partnerships working to determine the locations of CO2 sources and to assess suitable locations for CO2 storage. The Validation Phase (2005–2012) focused on evaluating promising CO2 storage opportunities through a series of small-scale field projects in the seven partnership regions. Finally, the Development Phase (2008-2020+) activities are proceeding and will continue evaluating how CO2 capture, transportation, injection, and storage can be achieved safely, permanently, and economically at large scales. These field projects are providing tremendous insight regarding injectivity, capacity, and containment of CO2 in the various geologic formations identified by the partnerships. Results and assessments from these efforts will assist commercialization efforts for future carbon  storage projects in North America.

The Plains CO2 Reduction (PCOR) Partnership, led by the University of North Dakota’s Energy & Environmental Research Center (EERC), includes all or part of the states of Iowa, Minnesota, Missouri, Montana, Nebraska, North Dakota, South Dakota, Wisconsin, and Wyoming and the Canadian provinces of Alberta, British Columbia, Manitoba, and Saskatchewan. The PCOR Partnership has received support from more than 100 organizations. The nine states in the PCOR Partnership account for about 11 percent of total U.S. CO2 emissions from stationary sources. Regional characterization activities conducted by the PCOR Partnership confirmed that while numerous large stationary CO2 sources are present, the region also has tremendous potential for CO2 storage. The varying natures of the sources and storage sites reflect the geographic and socioeconomic diversity across this nearly 1.4 million mi2 area of central North America. The region offers significant potential for storage in deep saline formations (both carbonate and clastic formations), unmineable coal seams, and depleted oil and natural gas fields. Of particular interest to this region of the U.S. is the optimization of CO2 for geologic storage in tandem with enhanced oil recovery (EOR).

The PCOR Partnership region, which covers over 1.4 million square miles, emits approximately 562 million metric tons of CO2 yearly from large stationary sources in the region. Research through the PCOR Partnership Development Phase projects can be used to ensure that geologic storage is not just an option for the distant future, but can be implemented on a large scale for both environmental and commercial reasons. Overall, based on the current geological formations characterized, the PCOR Partnership region has the storage resource of 313 billion metric tons of CO2 in saline formations, 3.2 billion metric tons in depleted oil fields, and 7.3 billion metric tons in unmineable coal seams, which is over four times the anticipated regional emissions over the next 100 years, assuming a static emission profile.

The integrated approach at the Bell Creek Oil Field helps meet the commonsense safety expectations of local landowners and communities. Further, by storing anthropogenic CO2 at the Bell Creek Oil Field, Denbury benefits the environment by offsetting the carbon footprint of its regional oil field operation. The results of the Bell Creek project will help future projects effectively implement a proven CO2 MVA system as part of a comprehensive approach to subsurface CO2 management, utilizing it for regional EOR operations.

While providing a substantial reduction in CO2 emissions, the Fort Nelson project will also facilitate the development of significant shale gas reserves in the Horn River Basin to provide North American markets with clean natural gas. Research aspects of the effort are being designed to provide proof of concept for geologic CO2 storage in deep saline formations, particularly for co-storage with sour gas, and serve as a model for follow-on CCS projects using geologic CO2 management at other gas-processing facilities in the region and around the world.

Goals and Objectives

The primary objective of the DOE’s Carbon Storage Program is to develop technologies to safely and permanently store CO2 and reduce greenhouse gas emissions without adversely affecting energy use or hindering economic growth. The programmatic goals of Carbon Storage research are to (1) develop and validate technologies to ensure 99 percent storage permanence; (2) develop technologies to improve reservoir storage efficiency while ensuring containment effectiveness; (3) support industry’s ability to predict CO2 storage capacity in geologic formations to within 30 percent; and (4) develop Best Practices Manuals (BPMs) for monitoring, verification, accounting, and assessment; site screening, selection, and initial characterization; public outreach, well management activities, and risk analysis and simulation.

The PCOR Partnership’s overall goal is to validate the information and technology developed under the Characterization and Validation Phases relative to research and field activities, public outreach efforts, and regional characterization. Specific objectives include the following:

Contact Information

Federal Project Manager 
Andrea Dunn:
Technology Manager 
Traci Rodosta:
Principal Investigator 

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