Southeast Regional Carbon Sequestration Partnership (SECARB) - Phase II and Phase III Email Page
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Performer: 
Southern States Energy Board

Website: 
Award Number:  FC26-05NT42590
Project Duration:  10/01/2005 – 10/01/2016
Total Award Value:  $138,300,949.00
DOE Share:  $95,059,185.00
Performer Share:  $43,241,764.00
Technology Area:  Regional Carbon Sequestration Partnerships/Injection Projects
Key Technology: 
Location: 

Project Description

Project Summary

SECARB is conducting two large-volume injection field projects; one in the lower Tuscaloosa Formation (Cranfield Site) and one in the Paluxy Formation (Citronelle Site). These formations are key components of a larger, regional group of similar formations, called the Gulf Coast Wedge.

Cranfield Site. The "Early Test," which was the first Development Phase field test to begin CO2 injection operations, injects CO2 into the lower Tuscaloosa Formation. The Early Test began injection in April 2009 after a successful Validation Phase field project that injected 627,744 metric tons of CO2 into the Tuscaloosa and the same site. The Cranfield Site has injected a cumulative 8,461,864 metric tons through September 30, 2013. Denbury Resources, Inc. is scheduled to continue CO2 injection while SECARB monitors the additional injection operations until September 2014.

Citronelle Site. The second SECARB project, the "Anthropogenic Test," is the world’s largest fully integrated carbon capture and storage project utilizing anthropogenic CO2 from a coal-fired power plant. The project became fully operational on August 20, 2012. Over the life of the project, 100,000 to 200,000 metric tons of CO2 will be injected into the Paluxy Formation. The CO2 is supplied by a pilot unit capturing CO2 from flue gas produced from Alabama Power Company’s (a Southern Company subsidiary) Plant James M. Berry Electric Generating Facility located in Bucks, Alabama (Figure 1). The CO2 is transported 12 miles by a dedicated CO2 pipeline to the Citronelle Field injection site (Figure 2). As of October 29, 2013, more than 100,000 metric tons of CO2 have been injected and stored at the site (Figure 3).

Injection Site Description

Cranfield Site. This project is focused on the down dip "water leg" of the Cranfield Unit, operated by Denbury Resources, Inc. in Adams and Franklin Counties, Mississippi, about 15 miles east of Natchez, Mississippi, and one and one-half miles north of Cranfield, Mississippi. The area selected for the Early Test is immediately north of SECARB’s Validation Phase "Stacked Storage" study in the Cranfield oil field near Natchez.

Citronelle Site. This project will be conducted approximately 12 miles northwest of Southern Company’s Plant Barry in a saline formation within the Citronelle Oil Field in Mobile County, Alabama. CO2 would be transported to the Citronelle Field from a capture unit located at Plant Barry via a 4-inch pipeline that Denbury Resources has proposed for construction.

Description of Geology

Cranfield Site. The lower Tuscaloosa Formation is one of the named stacked sandstone formations of the Gulf Coast Wedge. It is a Cretaceous-age, sandstone saline formation that occurs in the subsurface along the Gulf of Mexico Coastal Plain from western Florida to Texas (where it is defined as the Woodbine Formation). The Tuscaloosa Formation contains an upper section of alternating shales and sands and a basal section, the Massive Sand Unit, which contains a thick layer of clean, coarse-grained sand. The formation was deposited during a major period of global sea level rise, and its deposition has been interpreted as an upward gradation from fluvial and deltaic sedimentation (the Massive Sand) to shelf deposition (alternating sands and shales). The reservoir is in the lower Tuscaloosa, above a regional unconformity, in valley-fill-fluvial conglomerates and sandstones separated by alluvial and overbank within-unit seals. The reservoir is composed of stacked and incised channel fills and is highly heterogeneous, with flow unit average porosities of 25 percent and permeability averaging 50 millidarcy (mD), ranging to a Darcy (D). Chlorite is the major cement in these relatively immature sediments. The well-sorted, clean, coarse-grained nature of the Massive Sand, a result of this environment, makes it an ideal candidate for CO2 injection due to its high permeability and porosity. As the sea level continued to rise, the valley-fill depositional environment gave way to a deep marine environment, during which the overlying middle (Marine) Tuscaloosa Formation was deposited. This formation consists of about 500 feet of low-permeability shale, providing an excellent confining zone for CO2 injection into the lower Tuscaloosa Formation (Figure 4).

Shale is also found in the lower portion of the Tuscaloosa Formation acting as a barrier to the vertical migration of sandy substrates. Deposition that occurred during the early Cretaceous Period was based on a cycle of marine and delta sedimentation and deposition. The high porosity and permeability of the sandstones in the region are due to the cycles of deposition throughout time.

Citronelle Site. The injection horizon is the Lower Cretaceous-age Paluxy Formation. The Paluxy is a 1,150 feet thick package of sand, silt and shale strata, which occurs at a depth of about 9,800 feet at the project site. The porous and permeable sands of the Paluxy Formation represent a typical fluvial deposition reservoir in terms of their areal extent and petrophysical characteristics. There are approximately 475 feet of net sand in the Paluxy Formation, which occurs in over 20 sand units that range in thickness from 9 – 80 feet. The Paluxy appears to contain a mix of continental, fluvial and marginal marine deposits. Relationships between sand units within the formation are complex. The average core porosity of the lower Paluxy sandstones is 18 percent. Sandstone permeability ranges from 0.6 to 167.5 millidarcies and averages 17.4 millidarcies. Several of the Paluxy sand units appear to be laterally extensive, and are targeted as the injection zones for the Anthropogenic Test.

Following this deposition was another marine transgression, which deposited the shales, limestones, and sandstones that are known as the Washita-Fredericksburg Shale. This shale would be the primary confining zone for carbon dioxide stored in the Paluxy Formation. The shale appears to possess the appropriate criteria (lateral continuity, low permeability) to act as an effective CO2 seal. In addition to the basal Washita-Fredericksburg shale, there are secondary overlying confining units including the Middle (Marine) Tuscaloosa Formation, the Selma Group, and the Midway Shale, which occur stratigraphically between the injection zone and the base of the lower-most underground source of drinking water (USDW). As such, a vertical interval of over 8,000 feet with numerous low permeability barriers occurs between the proposed CO2 injection zone and the base of the lowermost USDW.

Source of CO2

Cranfield Site. The naturally occurring CO2 for the Early Test will be provided by Denbury Resources’ CO2 pipeline from the Jackson Dome near Jackson, Mississippi. The source is commercially available, high purity, highly reliable, and low cost. 

Citronelle Site. The CO2 for the Anthropogenic Test will be supplied from a pilot unit capturing CO2 from flue gas using amine capture technology from a 25 megawatt (MW) slipstream from Unit #5 of Southern Company’s Plant Barry power plant.

Injection Operations

Injections will occur at a scale sufficient to successfully address issues of injection rate and cumulative injection impacts that may be factors in the design of future large-scale, commercial carbon storage deployments.

Cranfield Site. CO2 from Jackson Dome is supplied to the Cranfield Site via pipeline and delivered to the center of Cranfield where the CO2 is accurately measured at the purchase pump. Injection pressure is boosted to a constant 2,900 psi and the CO2 distributed across the field via a buried pipeline system. Injection volumes and pressure is measured several times daily at each wellhead. Injection initiation was phased across the field. Injection began in the "High Volume Injection Test" (HiVIT) in a few wells in 2008 as part of the Validation Phase field project, and the 1 million metric tons per year rate for the HiVIT was obtained in December 2009 when the Detailed Area of Study (DAS) well injection rate was stepped up. The 1.5 million metric tons stored goal was reached in early 2011 (Figure 5). CO2 injection for the Cranfield Site commenced in April 2009.

Citronelle Site. The CO2, once captured, will be dehydrated and compressed to approximately 2,000 pounds per square inch gauge (psig). It will be transported over a short distance (~12 miles) via 4-inch carbon steel pipe to the injection site at Citronelle, Alabama. Three new wells have been drilled for the project—a reservoir characterization well, a characterization/observation/backup injection well, and a dedicated CO2 injection well. The fully integrated project began operations on August 20, 2012. As of October 29, 2013, more than 100,000 metric tons of CO2 have been injected and stored at the site. In addition to the new wells, the project utilizes several existing oilfield wells surrounding the CO2 injection site to monitor injection operations and to ensure public safety.

Simulation and Monitoring of CO2

SECARB will adhere to a vigorous monitoring, verification, accounting (MVA) and assessment program during the 10-year Development Phase project. Each site will be well instrumented with multiple sensor arrays. For the Cranfield Site, sweep efficiency is monitored by saturation measurements along well bores, crosswell measurements, and vertical seismic profiling (VSP) and/or surface seismic methods. Proposed monitoring activities for the Citronelle Site includes: well bore integrity assessed through Ultrasonic Imaging Tool (USIT) logging, annular pressure monitoring, and tracer injection; assessment of areal extent of the plume through drilling and monitoring up-gradient wells, seismic surveys (3-D and VSP), and Reservoir Saturation Tool (RST) logs in observation wells; monitoring for formation leakage through RST logging and using the VSP geophones to map and trace potential CO2 leakage; and potential CO2 seepage through shallow subsurface monitoring for CO2, carbon isotopes, and tracers. To help predict plume movement and assess the ultimate fate of the injected CO2, the project team utilized Computer Modeling Group’s GEM-GHG reservoir flow simulator.

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 Southeast Regional Carbon Sequestration Partnership (SECARB), led by the Southern States Energy Board (SSEB), represents the 11 southeastern states of Alabama, Arkansas, Florida, Georgia, Louisiana, Mississippi, North Carolina, South Carolina, Tennessee, Texas, and Virginia, and counties in Kentucky and West Virginia. SECARB is comprised of more than 100 partners and stakeholders. In the SECARB region, there are more than 900 large, stationary CO2 sources with annual CO2 emissions in excess of 1 billion metric tons. SECARB’s deep saline formations offer significant safe and permanent storage capacity for these emissions. Moreover, SECARB, along with the other RCSPs, continues to develop best practices to support the wide-scale transfer and advancement of information and technology derived from its projects.

The lower Tuscaloosa Formation, which is representative of the Gulf Coast geology, could be used to store 50 percent of the CO2 produced in the SECARB region during the next 100 years—an estimated 50 billion metric tons. The Gulf Coast Wedge includes the largest saline storage reservoir (in terms of areal extent and capacity) for the SECARB region, as well as the United States. Annual stationary point source emissions of CO2 have been estimated to be 1 billion metric tons. Using the range of reported capacity, the Gulf Coast Wedge can accommodate these emissions for approximately 300 to nearly 1,200 years, using capture and storage technologies. These volumes are sufficient to support commercialization of this CO2 storage reservoir and demonstrate that CO2 capture and sequestration can be a viable option for mitigating the region’s GHG emissions.

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 (GHG) emissions without adversely affecting energy use or hindering economic growth. The Programmatic goals of Carbon Storage research are: (1) develop and validate technologies to ensure for 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) developing Best Practices Manuals (BPMs) for monitoring, verification, accounting (MVA), and assessment; site screening, selection, and initial characterization; public outreach; well management activities; and risk analysis and simulation. SECARB’s overall goal is to validate the efforts of the public outreach, research, and field activities implemented under the Characterization and Validation Phases. Specific objectives include:

  • Conducting a large-volume, high-pressure injection field project that benefits from existing CO2 infrastructure and reasonable CO2 costs.

  • Assessing the viability and logistics of injecting over 1 million metric tons (1.1 million tons) of CO2 per year into a regionally significant saline formation in the Gulf Coast.

  • Achieving a more thorough understanding of the science, technology, regulatory framework, risk factors, and public opinion issues associated with large-scale injection operations.

  • Executing a geologic storage field project that covers all aspects of capture, separation, and storage, while fulfilling technical, regulatory, social, and economic considerations.

  • Refining capacity estimates of the formation using results of the field project.

Contact Information

Federal Project Manager 
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Technology Manager 
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Principal Investigator 
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