CCS and Power Systems

Carbon Storage - Regional Carbon Sequestration Partnerships/Injection Projects

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

Performer: University of North Dakota

Project No: FC26-05NT42592

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 Details