Geologic CO2 sequestration may benefit upstream industry

CO₂ sequestration already occurs on a significant commercial scale, unintentionally, within the enhanced oil recovery (EOR) floods of the Permian and a few other mature oil basins (Fig. 1). More than 25 million tonnes of CO₂ are effectively sequestered annually in the Permian basin to recover nearly 150,000 bo/d (Fig. 2).²

Several EOR projects sequester CO₂ supplied by anthropogenic (manmade) sources, such as gas processing and fertilizer plants (Table 1).

Depleted natural gas fields are also feasible sequestration targets. Without offsetting revenues from enhanced recovery, however, these are more costly settings.

Of particular promise is the potential to apply existing petroleum technologies to sequestration projects, with relatively minor adaptation (Fig. 3). Three mature industry activities have such off-the-shelf potential:

1. Enhanced oil recovery. EOR projects can sequester CO₂ at a net profit in favorable reservoir settings.

Major CO₂-EOR areas include the Permian and Rocky Mountain basins, in which the industry has more than 25 years of continuous operational experience. CO₂ floods are still rare outside North America, but geologic conditions are appropriate in many of the world's depleted oil fields.

Technologies particularly relevant to sequestration include CO₂ processing and injection, field screening and flood design, reservoir simulation, observation wells, tracers, and 4D seismic monitoring.^3-5

On average, EOR projects consume 4-8 Mcf of CO₂/bbl of enhanced oil recovered.

2. Underground gas storage. UGS is an integral component of natural gas pipeline delivery systems. Originally configured for methane storage, many UGS technologies, such as reservoir management, injection strategies, and slim-hole observation wells, have cross-over potential to sequestration.⁶

Most UGS sites are depleted natural gas fields, a reservoir class with an estimated 800 billion tons of CO₂ storage capacity. Others are aquifers or depleted oil fields.

More than 400 UGS facilities are currently in operation in North America and another 100 facilities in Europe.^{7 8}

3. CO₂ production. Pure, naturally occurring CO₂ deposits, such as McElmo dome in Colorado and Jackson dome in Mississippi, currently supply most of the injectant used in EOR projects, about 1.5 bcfd.

These deposits are unique natural laboratories for investigating the long-term physical and geochemical effects of CO₂ sequestration on reservoirs and aquifers.

The specialized production and monitoring techniques and equipment developed to handle corrosive CO₂ safely and to understand its movement in a reservoir could be adapted for future sequestration operations.⁹

Best practices for adapting these three existing technologies for sequestration are still under development. Pioneering R&D is under way by the US Department of Energy, the IEA Greenhouse Gas R&D Programme, the Australian Petroleum Cooperative Research Center, as well as other research groups and individual operators.

A coordinated set of research-quality field pilots and demonstrations could greatly accelerate the availability of efficient, low-cost sequestration technology.

Incentives spark projects

Norway is the only country that directly taxes CO₂ emissions and then only for offshore oil and gas operations. Currently, this tax amounts to $53/tonne, which is considerably higher than market alternatives for disposing of CO₂.

Norway's emissions tax has encouraged Statoil to capture, process, and reinject CO₂ at its Sleipner field in the North Sea. The Sleipner program is the first dedicated geologic sequestration project in the petroleum industry.

Since 1996, Statoil has injected nearly 4 million tonnes of by-product CO₂ into the Utsira formation, a regional aquifer. An international consortium is monitoring the project to optimize aquifer sequestration technology.¹⁰

In Canada, the Greenhouse Gas Emission Reduction Trading (GERT) pilot, a partnership of government and industry, is testing the mechanics of a future national trading system.

Also in Canada, a major new EOR project is under development at the Weyburn oil field in Saskatchewan.¹¹ While not the first EOR project to sequester anthropogenic CO₂, nor the largest, Weyburn represents a major advancement in monitoring and monitizing sequestration.

Operator PanCanadian Resources plans to sequester 20 million tonnes of CO₂ to recover an estimated 130 million bbl of oil. CO₂ will come from the Great Plains coal-gasification plant in Beulah, ND. A 330-km pipeline is nearly complete. CO₂ injection is scheduled to begin in October 2000.

The US accounts for more than 90% of CO₂-EOR production, but no emissions incentives exist to reward operators. House Bill HR2520 (and previous Senate Bills S547 and S2617), introduced in 1999, proposes to provide operators with tradable credits for reducing greenhouse-gas emissions under future and as yet unspecified regulations.¹²

The free market is already determining the value of emission credits. In one recent transaction, Ontario Power Generation Inc. purchased the rights to emit 2.3 million tonnes of CO₂ equivalent from a US landfill methane operator. Credits were valued at about $9/tonne or $0.50/Mcf.¹³

At this transaction price, emissions credits could offset much of the supply cost for CO₂ at a typical EOR project, where CO₂ purchase is the largest operating expense.

Costs, potential

The costs or profits of sequestering CO₂ in depleted oil and gas fields can be attractive, compared with alternative disposal options. Costs are expected to range widely, depending on reservoir conditions and proximity to CO₂ sources.

In the most favorable areas, such as Permian basin EOR projects, CO₂ can be sequestered at substantial net profit. For example, based on the current price of $0.65/Mcf for high-pressure CO₂ and 1999 oil prices of $15/bbl, operators are sequestering CO₂ at a profit, thanks to incremental oil recovery (Table 2).

Other settings, however, such as oil fields remote from CO₂ sources and depleted natural gas fields, represent more-costly sequestration targets. These fields may incur sequestration costs of $20-40/tonne, still moderate compared with other disposal alternatives.

The ARI study estimated the worldwide capacity and costs of CO₂ sequestration. In the study, a global economic model of the largest 155 petroleum provinces, was constructed using petroleum resource databases recently developed by the US Geological Survey.¹⁴ Cost data were based on actual Permian basin CO₂ flood costs,¹ adjusted for market conditions in each province.

Key assumptions included:

• CO₂-to-EOR ratios of 6.0 Mcf/bbl (miscible) to 10 Mcf/bbl (immiscible).
• $15/bbl oil price.
• Empirical EOR recovery to oil gravity and CO₂:methane volume and pressure ratios.

Given the long-term time frame of sequestration (several centuries), petroleum recovery infrastructure was assumed to develop in most worldwide basins.

Global sequestration capacity in depleted oil and gas fields is substantial, an estimated 923 gigatonnes (10⁹ tonnes). This equates to 125 years of current worldwide CO₂ emissions from fossil fuel-fired power plants.

Fig. 3 shows the distribution of sequestration capacity and costs for all 155 provinces, while Table 2 highlights selected provinces. Natural gas fields have larger capacity than oil fields because the resource base is larger and gas fields are deeper on average.

The largest cost for sequestration is to capture, process, and compress anthropogenic CO₂ to prepare it for use by the oil or gas field operator.

Power-plant flue gas is the most costly source to process, estimated at $53/tonne ($3.00/Mcf) with current technology. Waste CO₂ from natural gas processing or fertilizer plants is less expensive ($18/tonne or $1/Mcf). But both are more costly than natural CO₂ prices (about $0.65/Mcf).

Capture technology, however, is considered immature and costs could fall rapidly with R&D.¹⁶

Barriers to implementation

Despite the promise of geologic sequestration, a number of barriers confront more widespread implementation of this environmentally benign technology in depleted oil and gas fields. These barriers include:

• High capture costs. The most important barrier is the high cost of capturing and processing CO₂ from anthropogenic sources, estimated at $1-3/Mcf.

R&D is under way in advanced amine, membrane, and cryogenic separation to reduce costs. Reconfiguring future power plants to concentrate CO₂ in flue gas would dramatically reduce capture costs.¹⁷

• Incomplete reservoir understanding. The near-term (10-30 years) view of EOR and UGS need expanding to the thousand-to-million year time scale required for sequestration. A study of natural CO₂ fields could provide insight into cap-rock integrity and long-term interaction between CO₂ and reservoir rock and fluids.
• Monitoring and verification. For emissions-reduction credits to count, rigorous monitoring and verification of sequestration is essential. EOR and UGR monitoring technologies, such as geochemical tracers, reservoir simulation, observation wells, and advanced 4D seismic, could form a basis. The excellent safety record of industry in handling CO₂ deserves recognition.
• Emissions trading. The most efficient means for achieving emissions reductions is a globally functioning trading system. Such a system currently does not exist and industry has a proactive role in shaping it.
• Sequestration and production conflicts. The objectives of sequestration may clash with production operations (such as optimizing the CO₂-to-EOR ratio). Injecting CO₂ earlier in the life of the oil field is unconventional but could enhance both sequestration and oil recovery. Such conflicts need further study.

Acknowledgment

The authors thank the IEA Greenhouse Gas R&D Programme and the US Department of Energy for funding this study. We also wish to thank numerous petroleum operators who contributed ideas and data for the study.

References

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11. Weyburn Monitoring Workshop, University of Regina, Sask., Aug. 26-27, 1999.
12. "Credit for Voluntary Actions Act," US House of Representatives, HR2520, introduced by Rep R. Lazio, July 14, 1999.
13. McKay, P.A., "U.S. Landfill Concern, Ontario Utility Agree to Swap Gas-Emission Rights," Wall Street Journal, Oct. 26, 1999.
14. Masters, C.D., Root, D.H., and Turner, R.M., "World Conventional Crude Oil and Natural Gas: Identified Reserves, Undiscovered Resources and Futures," US Geological Survey Open-File Report 98-468, 1998.
15. Fox, C., "The Permian Basin CO₂ Supply," CO₂ Oil Recovery Forum, New Mexico Institute of Mining & Technology, Socorro, NM, Oct. 23-24, 1996.
16. Herzog, H., "The Economics of CO₂ Capture," Fourth International Conference on Greenhouse Gas Control Technologies, Interlaken, Switzerland, Aug. 30-Sept. 2, 1998.
17. "CO₂ Capture and Geologic Sequestration: Progress Through Partnership-Workshop Report," BP Amoco, Houston, Sept. 28-30, 1999.

The authors-

John Gale is project manager responsible for geologic sequestration technology development with the International Energy Agency's Greenhouse Gas R&D Programme.