Table 1: DOE Regional Sequestration Partnerships
Region	States	Lead Organization	E&P Industry Partners	Total Partners	Total Funding
Midwest	IN, KY, MI, MD, OH, PA, WV	Battelle Mem. Inst.	BP DTE Energy	31	$3.51MM
Southeast	AL, AR, FL, GA, LA, MS, NC, SC, TN, TX, VA	Southern States Energy Board	Advanced Resources Intl.	13	$2 MM
Southwest	AZ, CO, KS, NE, NM, OK, TX, UT, WY	New Mexico Tech	Advanced Resources Intl. Burlington Resources ChevronTexaco ERTC ChevronTexaco Permian BU ConocoPhillips KinderMorgan CO2 Marathon Oil Co. Oxy Permian Ltd. Yates Petroleum Corp.	25	$2.15 MM
West Coast	AK, AZ, CA, NV, OR, WA	California Energy Commission	Amerada Hess Eagle Operating, Inc. Fischer Oil and Gas North Dakota Pet. Council	47	$2.15 MM
Big Sky	ID, MT, SD, WY	Montana State University		14	$2 MM
Plains	IA, MO, MN, ND, NE, MT, SD, WI, WY	University North Dakota	Amerada Hess Eagle Operating, Inc. Fischer Oil and Gas North Dakota Pet. Council	29	$2.75 MM
Midwest Geologic Sequestration Consortium	IL, IN, KY	Univ. Illinois and IL Geol. Survey	IOGCC KY Oil and Gas Assoc. IN Oil and Gas Assoc. IL Oil and Gas Assoc.	21	$3.25 MM

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.

On a daily basis, about 100 MMcf (5000 metric tons) of CO₂ are transported and injected. As of March 2004, about 106 Bcf of CO₂ had been injected and over the project's lifetime a total of 466 Bcf (22 million metric tons) will be sequestered. The operator, EnCana Corporation, estimates that an additional 130 million barrels of oil will be recovered over the next 30 years as a result of the CO₂ injection.

The world's first CO₂ capture and storage project actually began in 1996 in the Sleipner gas field offshore Norway. The operator (Statoil) processes the produced gas to reduce its CO₂ content from 9% to 2.5% before sale. If the extracted CO₂ were released to the atmosphere, Statoil would be required to pay a tax of about US$45 per metric ton, so the company injects the CO₂ into a regional saline aquifer via a single, highly deviated injection well. Over the past nine years the Sleipner operation has injected over 7 million metric tons of CO₂ and the operational plan is to continue to inject for another 15 years. The saline aquifer has the potential to sequester 600 billion tons of CO₂.

A more recent injection project funded by DOE (part of the core R&D program mentioned earlier) is underway in the South Liberty oil field northeast of Houston. The brine-filled injection zone in this field is a sandstone zone within the Frio formation, at a depth of about 5000 ft, on the flank of a salt dome. The site was selected due to its proximity to a large concentration of power plants, refineries and chemical manufacturing plants that emit CO₂. The Gulf Coast region emits roughly 520 million metric tons of CO₂ each year. The Frio sands in this region have been estimated to be capable of storing between 200 and 358 billion metric tons. For this project, injection of about 3000 metric tons from a nearby refinery took place over a three-week period. A number of monitoring, diagnostic and modeling activities have taken place or are underway.

The project aims to test these tools and techniques for characterizing a CO₂ injection operation, as well as to demonstrate that CO₂ can be safely injected and securely stored.

Regional Strategies for CO₂-EOR
Anticipating a time when economics will support the simultaneous capture and storage of CO₂2 and the enhancement of oil production, DOE has undertaken a fresh look at the potential for enhanced oil recovery from CO2 injection in the nation's older reservoirs. Using the CO₂-PROPHET model developed by Texaco for DOE, Advanced Resources International (ARI) evaluated major reservoirs in six regions of the country: Oklahoma, onshore Gulf Coast, Illinois, onshore California, offshore Louisiana and Alaska. The model was used to determine the economic (>15% ROR BFIT) resource. For each region, the analysts evaluated alternative oil recovery strategies and scenarios. The first scenario assumed CO₂-EOR technology as applied in the past (Traditional Practices Scenario). The second scenario assumed that all of the lessons of past CO₂-EOR technology are applied using state-of-the-art technology and oil price averages $25/Bbl, but CO₂ supply costs remain high at a per MCF cost of about 5% of oil price (State-of-the-Art Scenario). The third scenario examines how the potential for CO₂-EOR could be increased through a strategy involving state tax reductions, federal tax credits, royalty relief and/or higher oil prices that would together be equivalent to a $10 per barrel lift in oil price (to $35) received by the producer (Risk Mitigation Scenario). In the fourth scenario low-cost CO₂ is assumed to be available at a per Mcf cost of about 2% of oil price (kept at $35/Bbl), from existing natural sources and industrial sources via CO₂ capture technologies (Ample Supplies of CO₂ Scenario).

The results for the four areas of interest to most independent producers (onshore lower-48 states) show that at reasonable long-term oil prices of $25-$35 per barrel, there are substantial potential recoverable reserves obtainable from CO₂-EOR if a reliable, reasonably priced source of CO₂ can be found (Table 2).
 

Given that some believe that oil prices might move considerably higher than that range, and that up to 30% of the total resource was not evaluated, these totals could be conservative. On the other hand, the lack of existing CO₂ gathering and distribution infrastructure in these areas will make it costly to deliver CO₂ at prices in the 2 to 5% of oil price range, even if new technology lowers the cost of CO₂ capture and separation. Some sort of favorable tax treatment could help to alleviate this risk.

So, while the idea of widespread application of CO₂-EOR outside of the traditional Permian Basin area may seem farfetched, a radical change in the cost of capturing EOR-ready CO₂ or a radical shift in the value assigned to removing CO₂ from the atmosphere could change the picture. The resource remains there, waiting for the right set of circumstances.

Note: This article was prepared with input from three primary sources: The NETL Carbon Sequestration website at www.netl.doe.gov/, an article by Kamel Bennaceur (and others) in the Autumn 2004 issue of Schlumberger's Oilfield Review available at www.slb.com/, and draft copies of ARI's reports: Basin Oriented Strategies for CO₂ Enhanced Oil Recovery. These reports are expected to be published in the near future and will be available on the DOE website at www.doe.gov/.