The Grand Challenge of Carbon Capture and Sequestration

Editor’s Note: In 2011, the SPE R&D Committee identified five grand challenges facing the oil and gas industry. A series of articles focusing on each of these challenges was published in JPT in 2011 and 2012. This is a condensed version of a 2016 follow-up paper examining the current status of one of the grand challenges: carbon capture and sequestration. The full paper can be found here: www.spe.org/industry/carbon-capture-sequestration-2016.php. This collaborative paper is authored by steering committee and at-large members of the SPE Carbon Dioxide Capture and Utilization and the SPE R&D technical sections. 

Carbon capture and sequestration (CCS) is designed to reduce atmospheric emissions of greenhouse gases (GHGs). The CCS process captures carbon dioxide (CO₂) generated at large-scale industrial sources (power plants, refineries, gasification facilities, etc.) and transports it to an injection site to be permanently stored in the subsurface. With extensive research linking GHG concentrations in the atmosphere to observed changes in global temperature patterns, CCS technology could play an important role in policy efforts to limit the global average temperature rise.

Even with the wealth of experience already in place within the oil and gas industry, the obstacles to advancing CCS to the forefront of GHG mitigation technologies remain significant. Large-scale CO₂ injection projects remain primarily in the realm of commercial CO₂-EOR (enhanced oil recovery) projects. The key challenges to enabling CCS include cost-effective capture and transport of industrial CO₂, clear access to pore space for CO₂ storage in geologic formations, proven methodologies for demonstrating storage integrity, and dissemination of best practices. SPE members can play a significant role in addressing these challenges.

Cost-Effective Capture of Power Sector and Industrial CO2

A major technical challenge facing capture at electric generating facilities is that the CO₂ concentration in large-­volume flue streams is quite low. Current removal technologies include techniques that apply amines, chilled ammonia, membranes, and ionic liquids to strip the CO₂ from the flue stream. How­ever, these technologies were developed to handle smaller-scale operations and ­higher-CO₂-purity streams. When applied to large electric generating plants, process efficiency is reduced, and the energy penalty associated with the capture process drives up costs, increasing the levelized cost of electricity by 50% or more, depending on local factors. Also, to accommodate the substantial volumes of the CO₂ and flue gas at full-scale industrial sources, the removal technologies require significant scale up and footprint for deployment.

While early movers are developing large-scale capture demonstrations such as SaskPower’s Boundary Dam Project, Southern Company’s Kemper Energy Facility (Fig. 1 above), and NRG’s Petro Nova Facility, we are still very early on the “learning curve.” Support for more development of next-generation capture technologies and large demonstrations is required to push us down the cost curve. This involves reducing the cost of materials and construction, parasitic costs related to energy for operations, compression, and operation and maintenance costs.

Government Oversight Challenges

Many of the aspects of a CO₂ storage project mirror those of CO₂-EOR projects. The land department is in charge of securing the acreage position, geoscientists describe the reservoir and seal, and engineers design the surface and subsurface equipment as well as provide a plan to maximize the value proposition offered across the acreage. In addition, some type of unitization may be required of disparate mineral and pore space owners. Finally, there is typically a state or federal permitting or oversight agency to ensure the project complies with established environmental requirements.

However, CO₂ storage is currently viewed as a “waste management” activity, with perhaps little public buy-in or perceived economic benefit to the local population, particularly in areas with little to no hydrocarbon extraction industry presence. In the US, this is further exacerbated by the fact that ownership of pore space in which storage would occur is generally retained by the surface owner and the hydrocarbons are maintained by the mineral owner/lessee, and multiple owners/lessees may be involved. A well-conceived outreach strategy combined with mechanisms for ensuring both local benefits and trustworthy environmental stewardship are required to obtain local public and stakeholder acceptance of the storage projects.

Because of this disparate ownership, an alternative option to ameliorate pore-space access issues is to consider offshore storage using existing or new platforms. While the offshore drilling and operations cost is considerably higher, the government commonly holds the pore and mineral rights, diminishing the number of stakeholders potentially involved.

Safe, Secure, Large-Scale CO2 Storage

A major difference between CO₂ injection and hydrocarbon production is the fact that injected CO₂ has to be accommodated in the subsurface by compression into the formation and pore water, increasing reservoir pressure. Determining the reservoir continuity at distance without drilling many costly appraisal wells and the resultant pressure accommodated storage capacity is a saline formation challenge. In addition, CO₂ has a much higher mobility than water, and with a lower density shows strong gravity segregation. Plume modeling strategies, coupled with advanced geophysical techniques for calibration, are an area of continuing focus, particularly where laterally extensive CO₂ plumes develop. Once the primary pressure accommodation space has been used, the challenge may be to develop reservoir engineering strategies to use the remaining pore space more efficiently for storage. Extraction of brine could increase storage efficiency and reduce the area affected by a pressure plume.

Depleted Fields and Existing Infrastructure

Depleted oil and gas fields offer proven secure storage—the capacity is well understood and the storage security is proven. However, they introduce some challenges. When a gas field is highly depleted, the CO₂ will initially be in the gas phase, yet it is transported in the dense phase. There are a number of potential solutions that include heating, starting in gas phase, or introducing methane or nitrogen. Management of the movement of the fluid through the phase envelope is therefore key, and requires the exploitation of CO₂-EOR expertise coupled with potentially novel petroleum engineering solutions. The assessment, monitoring, and repair of legacy wells is also important when dealing with depleted fields.

Demonstrating Secure Storage

Scaling up CO₂ storage technology to address climate change, while demonstrating to stakeholders that the process is safe and secure, is a significant challenge. The 40-plus years of experience gained in the design and operation of CO₂-EOR projects provides the primary foundation for establishing a com­parable understanding for the issues associated with CO₂ storage. CCS-­specific monitoring, permitting, and long-term care programs must be ­established and applied to develop commercial sites. Risk assessment is an essential activity during the selection and qualification of sites for long-term storage of CO₂, for the development of a risk management strategy, and in establishing guidelines for safe and effective operations. While geologic uncertainties/risks are highly site-specific, the main perceived risks are of potential CO₂ or brine leakage from wells and ­geologic pathways, and induced seismicity and  ground displacement.

Worldwide, a considerable amount of CCS regulatory framework development has occurred. In most cases, these efforts build upon existing frameworks for regulating oil and gas activities. For example, the US Environmental Protection Agency (EPA) has published underground injection control well requirements for the geologic storage of CO₂, based on protection of underground drinking water sources, and has established reporting requirements under its Greenhouse Gas Reporting Program for facilities that inject CO₂ underground for both CO₂-EOR and geologic storage. Importantly, EPA guidance confirms that CO₂-EOR can result in stored CO₂. Nonetheless, substantial legal and regulatory concerns remain.

Dealing With Abundant CO2

Should CO₂ capture become cost-effective, the volume of CO₂ available for transportation and injection would require significant expansion of the current infrastructure. Today, 50 individual CO₂ pipelines with a combined length of more than 7,250 km (4,500 miles) exist in the United States. Should 10% of total emissions be captured, it would far exceed the transport ability of this infrastructure. To bridge this gap, considerable infrastructure development is needed. Early delivery targets for CO₂ would include areas where well infrastructure is already in place, such as large oil fields, while areas with minimal oil and gas development would be developed later for CO₂ storage. While the capabilities exist to build the infrastructure, the task will require a tremendous influx of capital and personnel, and regulatory cooperation.

Large volumes of low-cost, readily available CO₂ could allow for the development of new EOR strategies, using CO₂ in excess of traditional practice. These techniques could include vertical or gravity-stable flooding protocols that may effectively recover the bulk of the remaining oil, while also using less water. Also, larger hydrocarbon pore volume injections in traditional horizontal floods, and possibly earlier application of CO₂-EOR, might be adopted in lieu of waterflooding. New best practices for these cases would need to be developed and shared within the industry.

Development and Dissemination of Best Practices

The need for timely dissemination of CO₂ storage projects best practices is key to the widespread deployment of the technology. While CO₂-EOR serves as an analogue for CO₂ storage, and many best practices are transferable, notable differences exist. These include regulations and regulatory entities, ownership issues, short- and long-term liability, public outreach and pressure/plume management. We believe that SPE has a role to play in the documentation and dissemination of CO₂ storage best practices through support of publications and conferences/forums.

George Koperna is vice president and reservoir engineering manager with Advanced Resources International, specializing in unconventional resources, enhanced recovery applications, and carbon storage. He is chairperson of SPE’s Carbon Capture, Utilization, and Storage Technical Section and a former member of the SPE International Board of Directors. He holds MSc and BSc degrees in petroleum and natural gas engineering from West Virginia University.

Michael L. Godec, a vice president with Advanced Resources International, has prepared numerous assessments of the potential sequestration capacity and economic potential associated with geologic storage in oil and gas fields, deep saline aquifers, gas shales, and unmineable coal seams. He has examined CO₂ storage and possible CO₂-EOR opportunities for numerous proposed power plants and other industrial facilities, both in the US and internationally. For 2009–2010, Godec was an SPE Distinguished Lecturer on the subject of “Environmental Performance of the Exploration and Production Industry: Past, Present, and Future.”  He holds an MS degree in technology and human affairs from Washington University in St. Louis, Missouri, and a BS degree in chemical engineering from the University of Colorado, Boulder.

Neeraj Gupta, a senior research leader/Battelle Fellow at Battelle Institute, provides technical and program development leadership for Battelle’s subsurface resources work. He has more than 25 years of domestic and international experience in CO₂ storage, CO₂-EOR, and other subsurface projects. He has led several field programs and research projects on CO₂ storage technology. He holds a PhD in geological sciences from Ohio State University, an MS degree in geochemistry from George Washington University, and MS and BSc degrees in geology from Panjab University, India.

David E. Riestenberg is a project manager with Advanced Resources International. He has more than 15 years of experience in the energy sector, with emphasis on the geologic aspects of unconventional resources and the use of carbon dioxide for both enhanced recovery and sequestration. He is the project manager and monitoring lead for the SECARB RCSP Phase III Anthropogenic Test CO₂ storage demonstration in Mobile County, Alabama. Riestenberg holds a BS degree in biology from the College of Mount St. Joseph, Cincinnati, and an MS degree in geology from the University of Tennessee, Knoxville.

Owain Tucker is Shell’s global deployment lead for carbon storage. He leads storage projects and is responsible for technical assurance, integration, and informing the CCS research agenda, along with the development of capability within Shell. He cochairs the Oil and Gas Climate Initiative work group on CO₂ storage capacity and the Zero Emissions Platform task force on transport and storage business models, and is a board member of the UK Carbon Capture and Storage Research Centre. He studied physics and geophysics at the University of Witwatersrand and holds a DPhil in experimental physics from the University of Oxford.

Lydia Cumming is a principal research scientist at Battelle, the world’s largest independent research and development organization. She has been engaged in a number of government and industry projects focused on investigating technical, policy, and public acceptance issues associated with geologic storage of carbon dioxide. She is currently performing technical and outreach activities for the Midwest Regional Carbon Sequestration Partnership. She also is the project manager for the Mid-Atlantic US Offshore Carbon Resource Assessment Project. Cumming earned a bachelor’s degree in geology from Ohio State University.