State-of-the-Art Summary

sequestration technologies. These partnerships will characterize each region's CO2 sources and sinks, evaluate alternative sequestration approaches, study regulatory and infrastructure requirements, and develop public involvement and education mechanisms. The timeframe for this effort is two years and DOE funding is roughly $2 MM per partnership, with co-funding by the partners at about one-third of the total. The largest representation of the oil and gas E&P industry in the membership of the regional partnerships is found in the West Coast and Southwest regions. Eleven producing companies and five industry associations are represented overall (see Table 1 page 7).

One product of the partnership program is an online GIS database (www.natcarb.org) that contains data on CO2 sources (refineries, power plants, chemical plants, etc.) nationwide. The map layers also depict oil and gas fields, Federal lands, aquifer areas, and a wealth of information (you will need a little patience and a high-speed internet connection). Individual CO2 emissions sources can be clicked on to reveal plant information. The database is best populated in the Illinois Basin as far as oil and gas fields, but the online system is being added to on a regular basis.

According to Robert Finley of the University of Illinois, the Midwest Geologic Sequestration Consortium (www.sequestration.org) has submitted a proposal to DOE for Phase II of the partnership program that includes potential field tests with 10 operators in the Illinois Basin. The list of companies included: Bretagne GP, Continental Resources, Gallagher Drilling, Covington Oil & Gas, Shakespeare Oil, Murvin Oil, Oelze Production, Team Energy, and Howard Energy. A utility, Ameren Corp., also proposed two coalbed methane injection tests. If this Phase II project is approved, only four field tests will be selected. However, the level of interest from independent producers was strong. DOE is currently evaluating all of the Phase II proposals received from the partnerships.

Carbon Dioxide Sequestration and Oil and Gas Recovery
CO2 can, of course, be injected into depleted oil reservoirs as part of an enhanced oil recovery (EOR) process. This has been successfully carried out for decades in a number of Permian Basin carbonate reservoirs, primarily using purchased CO2 produced and piped from naturally occurring reservoirs in Colorado and New Mexico. The driver here is recovery of a portion

 of the 30 to 40 percent of the reservoirs' oil remaining in place after secondary waterflood operations, not CO2 sequestration. Supercritical CO2 can become miscible with the oil, acting as a solvent to reduce residual saturation. Naturally, EOR operations have been focused on minimizing the amount of CO2 that remains sequestered per barrel of oil recovered (about 2000 scf or less per barrel), as this CO2 is a purchased injectant.

Alternatively, CO2 could be injected into a reservoir that is still producing primary oil but which is nearing the end of its producing life. A credit for CO2 storage would shift the economics of enhanced oil recovery and alter field practices to optimizing CO2 storage. Use of depleting oil reservoirs amenable to CO2 EOR as a sequestration option, could provide a value-added benefit in terms of incremental revenue from enhanced oil production which could partially offset the cost of CO2 capture, which currently is not insignificant.

Captured carbon dioxide could also be injected and sequestered in depleted gas reservoirs. The fact that gas was trapped in such reservoirs over geologic time supports the notion that they are safe repositories for carbon dioxide over the long term. In many cases the infrastructure for injection (surface piping compressors, wells) still exists.

The CO2 storage capacity of domestic oil and gas formations has been estimated at roughly 150 billion metric tons of CO2, or roughly 30 years worth of current U.S. emissions (ARI, 2003). Depleting oil reservoirs can't meet all potential CO2 sequestration needs, but they could provide an early opportunity for sequestration at relatively low cost. Some of DOE's core R&D is investigating trapping mechanisms for CO2 and developing reservoir management strategies that simultaneously maximize CO2 sequestration and oil recovery.

Another option also aligned with the oil and gas industry is sequestration in coal seams that are too deep or too thin to be mined economically but are candidates for methane extraction. Primary "coal bed methane" recovery methods, dewatering and depressurization, leave a fair amount of the methane in the reservoir. Enhanced methane

recovery can be achieved by sweeping the coal seam with nitrogen or CO2. The CO2 preferentially adsorbs onto the surface of the coal, releasing the methane. Two to three molecules of CO2 are adsorbed for each molecule of methane released. The maximum domestic capacity for CO2 sequestration in coal seams has been estimated at 90 billion metric tons CO2, 40 billion metric tons of which is in Alaska (ARI, 2003). Like depleting oil reservoirs, unmineable coal seams could be a good early alternative for CO2 storage. One potential problem however, is coal swelling. It has been observed that when coal adsorbs CO2 it swells in volume, restricting the flow of CO2 into and the flow of methane out of the coal. Work is underway toward minimizing these negative effects.

In addition, the potential for CO2 storage in formations saturated with brine is enormous compared to oil reservoirs and coal beds and potentially could contain hundreds of year's worth of CO2 emissions. However, much less is known about injecting into saline formations than is known about injecting into oil reservoirs and coal seams. A portion of DOE's core R&D is focused on improving our understanding of these saline formations.

Field Experience With Oilfield CO2 Sequestration
Two large CO2 sequestration projects have been underway for a number of years: an EOR project at Weyburn Oil Field in Canada and injection into a deep saline formation in the Sleipner Gas Field in the North Sea. In addition, a relatively small-scale (one days' worth of CO2 from an average coal-fired power plant) field test supported by the DOE program is also underway.

The Weyburn project began in 1999. It involves the transport of CO2 through a 202-mile pipeline from a coal gasification plant north of Beulah, ND to the Weyburn oil field near Regina Saskatchewan. Before building the pipeline, the Dakota Gasification Company released most of the CO2 into the atmosphere. The CO2 (96 % pure) is compressed to 2200 psi before being delivered to the pipeline. At Weyburn, the gas is injected into the producing zone, a 100-ft thick Mississippian carbonate at a depth of about 4700 ft. The 70-square mile field area contains more than 1000 wells.

 

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