Illinois basin, Midwest carbon dioxide EOR challenges may be surmountable

Jan. 7, 2013
As a technology new to the Midwest, carbon dioxide enhanced oil recovery (CO2 EOR) has several barriers to overcome before it can gain a sustained presence in the region.

Scott M. Frailey
Robert J. Finley
Illinois State Geological Survey
Champaign, Ill.

John A. Rupp
Indiana Geological Survey
Bloomington, Ind.

As a technology new to the Midwest, carbon dioxide enhanced oil recovery (CO2 EOR) has several barriers to overcome before it can gain a sustained presence in the region.

First and foremost, this type of technology needs to be conceived as feasible and profitable. Cultivating interest among operators and oil field owners from the Midwest and other regions will create demand for CO2 on a commercial scale. The result of this will be increased interest in private investment aimed at developing large-scale CO2 EOR projects in the region.

Even with increased interest, the current lack of CO2 source and distribution infrastructure in the Midwest provides obstacles to the profitability and feasibility of such projects. Without any comparable large-scale CO2 EOR projects in the region, current owners and operators have no analog to ensure the economic viability of this technology for their fields.

During the validation phase, the Midwest Geological Sequestration Consortium's (MGSC) pilot projects showed successful results for small-scale EOR projects and provided possible solutions for some of the technical challenges, such as corrosion inhibition of wellbores and other equipment.1 2

Still, the lack of large-scale projects, such as those in the Permian basin, reinforces preconceived perceptions of what can and cannot be accomplished by Midwest CO2 EOR.

The perceived economic, technical, operational and regulatory risks can be addressed by improving the awareness of Midwest operators and owners of other CO2 EOR activities in the US.

Improved awareness of other EOR projects, such as the Salt Creek CO2 flood in Wyoming where drilling new wells was economically successful, will make operators and owners more open to projects in their fields. Moreover, improving outside operators' and owners' awareness of successful pilot activity and characteristics of Midwest fields will foster more interest in outside investment. Workshops and seminars are possible methods of achieving these goals.

Introduction

The current lack of CO2 source and distribution infrastructure for CO2 EOR in the Midwest is linked to the lack of CO2 demand. In order to raise CO2 demand, operators and owners both in and outside the Midwest must be convinced of the feasibility of commercial-scale CO2 EOR projects.

Workshops, seminars, documentation of field practices, and other methods are a way to increase awareness of successful pilot projects conducted in the Midwest as well as change the perception of regional barriers.

The MGSC's pilot projects are one such example of documented field tests that operators and owners could use to address technical and operational problems, such as solutions for preventing corrosion.1 2 Furthermore, workshops and seminars can document differences between Midwest projects and current large-scale projects, such as those in the Permian basin.

Increasing awareness of Midwest oil field characteristics among those unfamiliar with the region will change perceptions about the practicality of CO2 EOR projects. For example, the MGSC's characterization phase results show the CO2 storage and recovery potential of three different reservoir conditions in the Illinois basin (Table 1).

The predominance of sandstone over carbonate oil reservoirs and the regulatory and legal environment of oil producing states in the Midwest are also examples of aspects that could be addressed. If the practical issues faced by operators and owners can be addressed, greater interest will be shown in private investment.

This article discusses the resource, perception, technical, operational, and regulatory barriers to Midwest CO2 EOR and how perceptions can be changed to develop it as an industry in the region.

Initiating CO2 EOR in the Midwest

Successful long-term deployment following the introduction of a new technology to a specific industry or customer base requires a sustained demand for the technology.

Establishing a demand for CO2 from oil field owners and operators in the Midwest is no different. A demand for CO2 for use in commercial-scale CO2 EOR throughout the oil fields of the Midwest will lead to increased interest in private investment in capture and compression infrastructure.

There are two ways forward: (1) to develop the interest of current Midwest oil field owners and operators to initiate commercial-scale CO2 EOR and (2) to introduce Midwest oil fields and CO2 EOR opportunity to companies owning and operating current CO2 EOR fields outside of the Midwest.

These challenges can be grouped into five areas: oil field owner resources, perception, technical, operational, and regulatory (Fig. 1).

Oil field owner resources challenge

For the most part, no major oil companies and few or no large independent oil companies operate in the Midwest.

Most of the oil companies are small with predominantly field employees, few or no geoscientists and engineers, limited capital, and too few assets to commit to a large-scale CO2 EOR project and the long-term purchase of CO2.

To overcome these challenges, the apparent and perceived risk relative to companies of this size must be addressed and reduced so that it is manageable for these companies to seriously consider commercial-scale CO2 EOR.

CO2 EOR experienced staff. Because of the size and the typical responsibilities of their staff, CO2 experience internally to these companies is unlikely. Cursory knowledge of CO2 EOR concepts and basics may be known, but it is unlikely that any degree of specifics for implementing a CO2 field operation will be known.

While company owners and their staff are knowledgeable and skilled in traditional oil field activities, few have the resources for comprehensive studies or complex and expensive pilots. Companies of this size look for successful analogs to their producing properties; this could be in completion type, waterflood operations, or infill drilling.

A successful, commercial-scale demonstration project with data and field operations available and accessible to these operators would provide direct information and an analog to help determine the feasibility of success for a CO2 flood at their own properties.

CO2 EOR experienced service providers and consultants. Owners of companies with access to staff or consultants with expertise in surface equipment, CO2 EOR design criteria, related economics, scoping and screening criteria, EOR projections, and CO2 injection projections have a better perspective on the feasibility and perceived risk associated with CO2 EOR.

Providing workshops and short courses in technical and operational areas that include these types of professionals would improve Midwest oil field owners' and operators' working knowledge of CO2 EOR. Additionally, the opportunity to build relationships with consultants and service companies with CO2 EOR related expertise in other basins would start the necessary steps toward privately funded pilots, and advance interest in long-term commitments to a CO2-supply pipeline infrastructure.

Overcoming oil field owner resources challenge. Providing Midwest oil field owners and operators the opportunity to build relationships with professionals possessing CO2 EOR experience and company representatives that offer oil field services in CO2 EOR areas at workshops and short courses in technical and operational areas could make CO2 EOR seem more achievable for smaller companies. This could include a new session at existing conferences such as the annual CO2 EOR Flooding Conference in Midland, which emphasized networking opportunities between Midwest operators and professions working actively in CO2 EOR.

Specific business portfolios of oil companies operating in the Midwest is beyond the scope of this report. However, a general assertion is that seminars on the business aspects of finding capital or means of funding commercial-scale EOR projects would be necessary for many operators. This could include government loans. Direct experience from existing CO2 EOR as an analog would be invaluable.

Perception challenges

Through the course of learning more about CO2 EOR, there are some aspects of the Midwest operating environment that may be perceived differently compared with more mature areas, such as the Permian basin of West Texas.

These are that (1) CO2 related corrosion is uncontrollable, (2) shallow reservoirs cannot sustain miscible floods, (3) immiscible floods are not economic, and (4) drilling new injection and production wells is impractical.

Corrosion. The injection of CO2 into an oil reservoir that has brine-saturated pore space leads to an acidic fluid, carbonic acid.

Without a preventive corrosion plan, in a relatively short time into a CO2 EOR project, various degrees of corrosion can occur in wellbore tubulars, downhole equipment, surface production facilities, and related piping. Staffs operating oil fields with historical CO2 EOR have addressed the issue of corrosion by identifying and replacing key components with nonreactive materials and using chemical corrosion inhibitors.3

In the US Department of Energy (DOE) sponsored EOR pilots of the Midwest Geologic Sequestration Consortium (MGSC), commercially available corrosion inhibitors were applied to control CO2 related corrosion. In addition to controlling corrosion, the operator reported fewer downhole tubular and equipment failures during the CO2 EOR pilot compared with previous years.2

Shallower reservoirs. Compared with deeper formations, shallow reservoirs have relatively lower temperatures. CO2 density is higher at lower temperatures when compared with higher temperatures.

Some of the shallower oil fields operated as waterfloods in the Midwest can have higher injection pressures due to higher fracture pressure (and subsequent regulated pressure). For example in the Illinois basin, a 1.0 psi/ft fracture gradient is a common value to use.4

Consequently, a waterflood operated at 1,800 ft may have an average reservoir pressure exceeding 1,500 psi. Reservoir temperature and pressure combinations can lead to the opportunity for CO2 in a liquid phase, which is expected to be miscible with crude oil. This combination is not unusual.

As part of the validation phase site selection for CO2 EOR, Illinois basin operators provided current pressure and temperature (Fig. 2, green circles) for nominated reservoirs within oil fields for consideration. Eight of the 40 nominated reservoirs would sustain liquid CO2 and have the potential for miscibility at relatively shallow depths (1,500-2,500 ft). Moreover, the MGSC Mumford Hills pilot was miscible-liquid at 1,900 ft.

Immiscible floods. Like miscible floods, the mass transfer of intermediate hydrocarbons (C5 to C12) from the crude oil to the CO2 phase occurs in immiscible floods; however, there is a CO2-rich phase and a crude oil-rich phase5 that are distinct and identifiable.

In the mature CO2 EOR areas of the US, generally the use of the term "immiscible" is generally associated with a failed CO2 EOR pilot or an oil reservoir that would not be considered for EOR. As a result of early and-or large volume of CO2 production with uneconomically low or no oil production, the failure would increase for pilots projected to be miscible. These pilots would be at higher pressures and temperatures, which require large volumes of CO2 and high injection pressures.

For a planned low pressure, immiscible flood in a relatively shallow reservoir, less pressure and CO2 would be required. Illinois basin oil field modeling results show that compared with miscible CO2 EOR, an immiscible flood would have about 50% less oil production; however, it would take 70-80% less CO2 volume (Table 2).5

A single immiscible reservoir relatively far from a source may never result in a CO2 EOR project. However, for those fields with multiple oil productive reservoirs of which some would be miscible and others may be immiscible, these immiscible targets could provide low cost incremental oil production once the CO2 transportation infrastructure is in place for the miscible oil reservoir targets (Fig. 3).

Drilling new wells. There may be a misperception that new wells need to be drilled, and if so, a CO2 EOR project cannot be economic.

In many of the Permian basin CO2 EOR floods, infill drilling of injection wells occurred simultaneously with initiation of CO2 injection. This was to reduce spacing and increase oil production by decreasing the distance between injection and production wells. Drilling new wells was not a necessity from a CO2 EOR perspective but was from an economic perspective.

Consequently, there is field evidence of the practicality of drilling new CO2 injection wells and using existing oil production wells. The Salt Creek CO2 flood in Wyoming is an example of an economically successful CO2 flood that required all new injection and production wells in some areas of the field, including locating and properly plugging many of the previously abandoned wells.

Historically, CO2 EOR floods have proven that the costs associated with drilling and completing numerous new wells is economically feasible. Screening of CO2 flood candidates should not exclude those fields that require new wells without considering the economics.

Overcoming the perception challenges. Workshops and seminars addressing these issues are likely necessary to increase and improve awareness of preexisting perceptions of these aspects of CO2 EOR historical activities and case studies.

Technical challenges

Once operators in the Midwest area are more interested in CO2 EOR, technical and operational questions will arise. Differences between pre-CO2 EOR reservoir conditions in the Midwest and the Permian basin provide the basis for some of these technical questions.

Pre-CO2 flood oil recovery. A significant difference between many Midwest and Permian basin oil reservoirs is oil recovery prior to CO2 injection.

For example, in the Illinois basin, the sum of primary and waterflood recovery can be up to 50%; Permian basin estimates are generally between 10 and 20%. The impact of much lower oil-in-place prior to injecting CO2 is not known but definitely leaves less oil as a CO2 EOR resource.

Subcritical temperature: Gas and liquid CO2 floods. From numerical modeling and small-scale pilots, there are strong indications of CO2 EOR potential for immiscible and miscible-liquid floods in shallow reservoirs. However, operationally there is much less experience and practical knowledge of these types of floods.

Immiscible CO2 is likely to have low viscosity CO2 and unfavorable mobility, such that CO2 velocity is much greater than the in situ crude oil. This leads to early breakthrough of CO2, initially bypassed oil, and the need to capture and recycle CO2 much earlier than a traditional miscible flood.

There are methods of managing CO2 mobility in miscible floods such as injecting CO2 in alternate volumes with water. However, low pressure CO2 will result in lower volumes at the surface and the need for compression of CO2 to lower pressures. As such, these types of problems in miscible floods may be manageable in low pressure, immiscible floods.

For miscible-liquid CO2 floods, there is little or no documentation in the literature. Very few or no fields are reported to operate at reservoir temperatures and pressures required to carry out a liquid CO2 flood.

Solubility of CO2 in crude oil will be higher at lower temperatures. Crude oil viscosity will be higher due to lower temperatures. There is less associated gas in crude oils at lower pressures. The affect, if any, that lower temperature and pressure have on oil recovery is not well documented; this may not be a technical challenge but is presently technically uncertain.

Lithology: sandstone vs. carbonate. Historically, CO2 floods have been predominantly in carbonates. The Midwest has more sandstone than carbonate oil reservoirs (Fig. 4).6 7

Sandstones have different wettability characteristics than carbonates and may have different technical considerations. There is much less literature for CO2 flooding sandstones compared with carbonates. For example, the literature suggests continuous CO2 may yield higher oil recovery than water-alternating-gas injection (WAG) in strongly water-wet sandstones.8

There is general disagreement in the literature if there is any difference in oil recovery when rocks are water-wet but not considered strongly water-wet. The phenomenon of "water blocking" is thought to be responsible. This occurs when high water saturation is present and CO2 must diffuse through water to contact oil. It is a function of wettability and the pore structure.

Overcoming the perceived technical challenges. Fundamental research in basic fluid characterization and coreflood studies using crude oil and cores from oil fields in the Midwest could further enhanced oil recovery estimates for immiscible and miscible-liquid CO2 floods.

Characterization of crude oil and CO2 for gas and liquid CO2 at subcritical pressure-temperature could compliment the more extensive literature covering similar characterization at supercritical temperature.

Operational challenges

Once oil company resource and technical challenges are addressed, there are operational challenges directly related to field activities.

These include presence of well service providers with CO2 EOR experience, the integrity of casing and cement of wells, pre-law well (in general, pre-law wells refer to wells drilled, completed, and-or abandoned prior to regulations within a given state) completion types and locations, and maintaining reservoir pressure in a miscible-liquid CO2 flood.

Field well work support. In general, well work related to wells producing and injecting in CO2 EOR floods are identical. The only difference is the fluid being injected and produced is highly energized compared with water injection or associated gas production.

Well work may be routine, but working with and around CO2 is not. Local service companies will not have CO2 EOR experience or CO2-compatible equipment available until a market is present and adequate demand for services and equipment develops. Services required include pulling units, workover rigs, stimulation trucks and pumps, and cased hole logging tools.

Most all tools and downhole equipment used in the subsurface will need to be CO2 compatible or deemed safe to run in the downhole environment encountered in a CO2 EOR oil field. Equipment may include specific types of CO2-compatible equipment and parts on production and injection wellheads and surface separation equipment.

Casing and cement integrity of early wellbores. Age of existing wells is a consideration in most oil field activities and is of particular importance for CO2 EOR. There will be different regulatory requirements for production and injection wells.

While redrilling wells may be an acceptable solution, it is important to ensure integrity of the wellbores for older wells. Casing integrity for most operators is likely a relatively routine consideration under current operating conditions. However, surface pressure requirements for CO2 injection and production will likely be much higher.

Pre-law well completion types and locations. Pre-law wells had no requirements in the use of cement or steel casing, no plugging requirements on abandonment, and no notification or record filing requirements with regard to location or depth of the well.

Uncertainty of location and completion records of pre-law wells is an operational challenge only if the wells are known to exist or they are found subsequent to CO2 EOR and from a surface or subsurface release of reservoir fluids above the cap rock of the oil reservoir. Depending on the volume of fluids flowing, a previously unknown well can be dealt with on a case-by-case basis similar to how they would currently during a waterflood.

If CO2 reaches a well like this, it may be necessary to have a professional outside of the area to work on the problem well. Operators would need to have a risk management plan to deal with given events. Fortunately, most pre-law wells are very shallow (<1,000 ft) and will not penetrate "shallow" reservoirs considered for CO2 EOR.

Maintaining reservoir pressure in a miscible-liquid CO2 flood. Pure CO2 in reservoirs with temperatures that are below the critical temperature of CO2 (subcritical) must maintain a specific pressure or a phase change between liquid and gas will occur. Sustaining miscibility in shallow reservoirs is more difficult due to this possible phase change (Tres

Consequently, during periods that injection wells are shut in, a portion of the reservoir is at risk of losing miscibility. In general, this leads to reduced oil recovery and production rates. Operators will likely want to adapt practices of monitoring well pressure closely and consider temporarily shutting in producing wells in the area of the injection well.

Because miscible-liquid CO2 floods are not prevalent historically, maintaining pressure may be an operational uncertainty but could prove to be less of a challenge in practice.

Overcoming the operational challenges. Awareness of operational challenges can be discussed in properly designed workshops and seminars.

However, most solutions to operational challenges can only be addressed by testing and evaluating real-time field practices. A large-scale demonstration pilot would likely encounter many of these challenges, and documented solutions would be an outcome of such a pilot.

Regulatory challenges

Existing regulations and laws regarding oil and gas production have been documented for the oil producing states in the Midwest. The primary regulatory challenges for CO2 EOR flooding are Underground Injection Control injection well permitting, unitization, taxation, and severed mineral estate.

Permitting: UIC Class II. Applying for brine injection permits is routine for most oil field operators.

States or regions without previous CO2 injection may not have regulatory means of permitting a CO2 injection well or have very little practice in completing the necessary application. Injection permits typically have a maximum surface injection pressure and daily injection rate. So that downhole pressure gauges are not required, permits often include the surface injection pressure.

For brine injection, this is a relatively direct calculation using the density of the brine. For CO2 a similar calculation can be made; however, the density of CO2 is highly variable with the geothermal gradient and injection pressures encountered in most oil reservoirs. The primary difference is that higher surface CO2 injection pressure is required to achieve the equivalent bottomhole pressure via brine.

CO2 injection permits for the MGSC validation pilots stated both surface and subsurface injection pressure.1 2 The challenge will be to have permits that state surface pressures needed to achieve the desired bottomhole pressure. It is possible that an operator's only solution would be to include bottomhole pressure gauges, which would be atypical for most Midwest operators.

Unitization. When a water or CO2 flood is planned, one of the initial steps is to organize the operators in a specific field or geologic subset of the field (area or reservoir) into an agreement to share operating expenses and revenue; this process is called unitization.

Because it is a tedious process and can be difficult to get all parties in agreement, most states allow forced unitization, which requires only 51% of owners to agree to the unit and the other 49% are forced to participate. There has to be some type of hearing so that the minority interest owners and the royalty owners are treated fairly and equitably by the majority. In some states, while forced unitization is allowed, it has never been necessary to use it.

Because CO2 EOR would be relatively new, require significant capital expense, and long-term CO2 contracts, forced unitization in the Midwest may be a challenge compared with water injection only.

Mineral estate severed from real estate. In the mature oil fields of the Midwest, oil producing wells are plugged and abandoned as a result of uneconomic production rates.

If all wells on a lease or unit are plugged, the lease or leases expire. The mineral estate is now free to be sold or leased again by the mineral owner, for example, to an oil production company considering CO2 EOR on this acreage.

In older oil fields, it is likely that the surface estate owner and the mineral estate owner are not the same people; this is referred to as a severed mineral estate. When the estates are severed, the mineral owner may be heirs to the original owner; consequently, there are several more owners that must agree to the terms of a new lease or sale of the mineral estate.

County records of the most recent contact information for these owners may be incomplete or unavailable. In order to facilitate an operator to continue to develop CO2 EOR in areas like this, mechanisms need to be known and accessible such that after recognized due diligence, the oil company owners can set aside (e.g., escrow) the royalty owed to the unknown mineral estate owners.

Regulatory or assessing bodies need to exist at the county or state level to document the due diligence search and properly record and account that any unknown mineral estate owners' interest is protected.

Overcoming the regulatory challenges. Some states likely have current regulations that, with only slight modifications, are applicable to CO2 EOR.

Developing a guide for oil field operators that addresses the steps leading to a CO2 EOR flood, permitting, and unitizing, would be useful to operators unfamiliar with CO2 EOR and for new operators unfamiliar with the state's current regulations.

For those states that do not have regulations that offer solutions to these challenges, an organized effort should be made to offer assistance to states with primacy so that water-related UIC Class II permits are adaptable to CO2 EOR. Models or examples are available from other states (e.g., Texas) which have permitted CO2 injection for decades.

Outside interest in Midwest CO2 EOR opportunity

It is implied that owners and operators of existing CO2 EOR commercial projects have an understanding of the technical and operational challenges, risks, regulations, and resource requirements for this type of oil field activity.

Consequently, the challenge is to increase these owners' awareness of current and historical Midwest oil field activity, geology, remaining oil resources in-place, previous CO2 EOR related pilot activity, and anthropogenic CO2 sources.

As a result of recent interest in new oil shale plays and applications of horizontal drilling and fracture technology, numerous companies are acquainting or reacquainting themselves with the oil producing areas of the Midwest.9 While not necessarily in CO2 EOR, companies with acreage positions or knowledge of these areas is a positive step.

Workshops and seminars that were developed for Midwest operators could easily be changed to include only the Midwest-specific part. These refined workshops could be offered in key locations where current owners and their staff have offices, such as Houston and Midland, Tex.

Meetings could be initiated with management at these companies, and an informative meeting could be offered to the management and their staff so that they could make an assessment of the CO2 EOR opportunities in the Midwest that they may have overlooked.

Conclusion

By addressing the practical and economic concerns of Midwest operators and owners, interest in more large-scale CO2 EOR projects in the Illinois basin will be increased. In addition, improving outside operators' and owners' awareness will stimulate interest in similar projects in the Midwest. A large-scale demonstration project will show the technical and economic success of CO2 EOR in areas of the Midwest historically considered less favorable for CO2 EOR. As more operators and owners begin to see the successes of these projects, they will have consistent and reliable regional comparisons to act as benchmarks for their prospective projects. As a result, the increasing demand for CO2 could lead to investment in CO2 capture facilities and pipelines networks in the Midwest. CO2 EOR infrastructure could also thereby provide the foundation for CO2 sequestration in brine-saturated reservoirs in the proximity to these oil fields.

Acknowledgments

This publication was authorized by Dr. Donald E. McKay, director of the Illinois State Geological Survey, Prairie Research Institute, University of Illinois at Urbana-Champaign. The authors are grateful to Brad Richards, executive vice-president, Illinois Oil & Gas Association; Bill Hoback, deputy director, Illinois Department of Commerce & Economic Opportunity, Office of Coal Development; David C. Harris, head of Energy and Minerals Section, Kentucky Geological Survey, University of Kentucky; and Thomas M. Parris, geologist, Kentucky Geological Survey, University of Kentucky, for their review of this article, and Dan Klen, ISGS, for provided technical writing and editing.

The basis of this article was developed as part of the National Coal Council report, "Harnessing Coal's Carbon Content to Advance the Economy, Environment, and Energy Security," completed June 22, 2012.

The Midwest Geological Sequestration Consortium is funded by the US Department of Energy through the National Energy Technology Laboratory (NETL) via the Regional Carbon Sequestration Partnership Program (contract number DE-FC26-05NT42588) and the Illinois Department of Commerce and Economic Opportunity, Office of Coal Development through the Illinois Clean Coal Institute (cost share agreement).

References

1. Frailey, S.M., Krapac, I.G., Damico, J.R., Okwen, R.T., and McKaskle, R.W., "CO2 storage and enhanced oil recovery: Bald Unit test site, Mumford Hills oil field, Posey County, Ind.," Goodwin, J.H., and Monson, C.C., eds., Illinois State Geological Survey, Open File Series 2012-5, 2012, 172 pp.

2. Frailey, S.M., Parris, T.M., Damico, J.R., Okwen, R.T., and McKaskle, R.W., "CO2 storage and enhanced oil recovery: Sugar Creek oil field test site, Hopkins County, Ky., Monson, C.C., and Goodwin, J.H., eds., Illinois State Geological Survey, Open File Series 2012-4, 2012, 234 pp.

3. Jarrell, P.M., Fox, C.E., Stein, M.H., and Webb, S.L., "Practical aspects of CO2 flooding," SPE Monograph Vol. 22, Henry L. Doherty Memorial Fund of AIME, Society of Petroleum Engineers Inc., 2002.

4. Frailey, S.M., Grube, J.P., Seyler, B., and Finley, R.J., "Investigation of liquid CO2 sequestration and EOR in low temperature oil reservoirs in the Illinois basin," SPE 89342 presented at the SPE/DOE Symposium on Improved Oil Recovery, Tulsa, Apr. 17-21, 2004 (http://dx.doi.org/10.2118/89342-MS).

5. Midwest Geological Sequestration Consortium (MGSC), "An assessment of geological carbon sequestration options in the Illinois basin," DOE Report DE-FC26-03NT41994, 581 pp. (Issued Dec. 31, 2005.)

6. Howard, Richard H., "Hydrocarbon reservoir distribution in the Illinois basin," in Leighton, M.W., Kolata, D.R., Oltz D.F., and Eidel, J.J., eds., "Interior Cratonic Basins," AAPG Memoir 51, 1991, pp. 299-327.

7. Bell, A.H., Atherton, E., Buschbach, T.C., and Swann, D.H., "Deep oil possibilities of the Illinois basin, Illinois State Geological Survey, Circular 368, 1964, 38 pp.

8. Tiffin, D.L., and Yellig, W.F., "Effects of mobile water on multiple-contact miscible gas displacements," SPE Journal, Vol. 23, No. 3, 1983, pp. 447-55.

9. Richards, Brad, personal communication, 2012.

The authors

Scott M. Frailey ([email protected]) is a senior reservoir engineer with the Illinois State Geological Survey in Champaign, Ill. His primary responsibility is in carbon dioxide geologic sequestration including CO2 enhanced oil recovery and CO2 enhanced coalbed methane. He previously worked at Texas Tech University and BP Exploration. His degrees are in petroleum engineering from the University of Missouri-Rolla.

Robert J. Finley is a principal geologist with the Illinois State Geological Survey. He is the project director for the Midwest Geological Sequestration Consortium and heads the Advanced Energy Technology Initiative at ISGS. Previously, he worked at the Bureau of Economic Geology, University of Texas at Austin. His graduate degrees are in geology from Syracuse University and the University of South Carolina.

John Rupp is a senior research scientist in the Subsurface Geology Section at the Indiana Geological Survey. Previously, he was a production geologist with Exxon Co. USA. He has an MS in exploration geology from Eastern Washington University and a BS in geology from the University of Cincinnati.