Grand Challenges

Society of Petroleum Engineers Grand Challenge: Carbon Capture and Sequestration

George J. Koperna, Jr.1, Neeraj Gupta2, Michael Godec1, Owain Tucker3, David Riestenberg 1, Lydia Cumming2

1Advanced Resources International, Inc., 2Battelle Memorial Institute, 3Shell Services Company

1) Introduction

Carbon Capture and Sequestration (CCS) is a geologic and engineering enterprise designed to reduce atmospheric emissions of greenhouse gases (GHGs). Extensive research links the GHG concentration in the atmosphere to the observed change in global temperature patterns (IPCC, 2013; Cox et al., 2000; Parmesean and Yohe, 2003). CCS technology could play an important role in efforts to limit the global average temperature rise to below 2°C, by removing carbon dioxide originating from fossil fuel use in power generation and industrial plants.

The Intergovernmental Panel on Climate Change, in its November 2014 Fifth Assessment Summary for Policymakers report, highlighted the following points in the event CCS is not available or its implementation is delayed:

  • Without CCS, the cost of achieving 450 parts per million (ppm) CO2-eq concentrations by 2100 could be 138% more (compared to scenarios that include CCS).
  • Only a minority of climate models could successfully produce a 450 ppm scenario in the absence of CCS.
  • Many climate models indicate a temporary ‘overshoot’ of atmospheric concentrations, which requires the world needing to achieve ‘net negative emissions’ to meet climate goals. The availability and widespread deployment of bioenergy with CCS is important in a world where ‘net negative emissions’ are required.

The integrated 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 – typically in saline reservoirs or depleted oil and gas fields.

From the perspective of the Society of Petroleum Engineers (SPE), the transport and injection of gases into the subsurface is relatively well-understood, particularly in regards to pressure maintenance, natural gas storage, and enhanced oil recovery (EOR). In fact, the injection of CO2 for EOR has been taking place in the U.S. for nearly 40 years, with an annual injection of around 60 million tonnes (metric). This experience provides a strong technical and business foundation for the SPE members to play a key role in enabling geologic storage of CO2 for climate mitigation purposes.

The challenge to reduce GHGs in the atmosphere has become a world-wide, public-policy issue. In December of 2015, the United Nations Framework Convention on Climate Change, held in Paris, came to an agreement for countries to work together to limit the increase in global temperature to between 1.5 and 2 degrees Celsius (above pre-industrial levels) by reducing GHG emissions into the atmosphere (UNFCCC, 2015). Research has shown that CO2 remains in the atmosphere and that a cumulative CO2 budget of 1 trillion tonnes of carbon (3.67 trillion tonnes of CO2) is commensurate with 2 degrees Celsius of warming (Mathews et. al., 2009). Recent calculations by Carbon Brief ( suggest that it would take between 20 and 30 years to exceed this budget at current emissions levels. The 1.5 degree Celsius target places a tighter constraint on this with about 10 years of emissions giving only a 50% chance of staying under 1.5 degrees Celsius. It is important to note that recent measurements show that the average global temperature is now 1 degree Celsius above the pre-industrial levels. The international agreement in Paris coupled with the scientific evidence emphasizes the need for transparent, accurate, and consistent accounting of GHG emissions and GHG reductions by storage in sinks, including geologic formations.

No single technology can address the increase in atmospheric GHG concentrations. This increase in atmospheric GHG concentrations is a challenge that must be met with a diverse array of currently available technologies and approaches (e.g. Pacala and Socolow, 2004; IEA, 2015), which can be represented as a series of equivalent CO2 mass “stabilization wedges, or emissions reductions strategies” (see Figure 1). While a variety of strategies can help meet GHG reduction goals, including increased efficiency and fuel switching, CCS has been found to be an essential technology for lowering the cost of GHG mitigation

Figure 1. A Portfolio of Technologies is required to Achieve Targeted Emission Reductions (source: IEA Energy Technology Perspectives, 2015). Percentages reflect cumulative contributions to emission reductions. Note: 6DS is the 6°C scenario which is an extension of current trends. The 2DS is the 2°C Scenario.

As petroleum engineers, assessing the data and gauging the effectiveness of current efforts at GHG reduction is important. As shown in Figure 2, current efforts have not effectively reduced the atmospheric concentration of CO2, and since 2012 the growth rate has been above 2 ppm per year. Therefore, we need to do more, and if we were managing an oil field, we would likely say that we need to do something different. To date, CCS has not seen wide scale deployment, yet, projects like Quest in Alberta show that it is feasible and can make a substantial contribution to reducing CO2 emissions. Since start up in August 2015, Quest has injected over 0.75 million tonnes of CO2, and the project aims to inject 1 million tonnes each year. CCS has huge potential to stop large quantities of CO2 from reaching the atmosphere. In fact, studies suggest that wide-scale deployment of CCS would save hundreds of billions of dollars to the economy (USDOE-NETL, 2012) when compared to alternative mitigation techniques. Furthermore, CCS is the only option available to significantly reduce direct emissions from many industrial processes, such as currently operating coal-fired power plants. A recent report by the Sustainable Gas Institute of Imperial College London (SGI, 2016) states that if CCS technology can be refined, it will enable the world to use more of its ‘unburnable carbon’, by which it means that the world can continue to use and benefit from oil and gas.

Over the last two decades, significant progress has been made in all aspects of CCS, and many key questions regarding the potential capacity and technical aspects of deployment have been addressed. The Intergovernmental Panel on Climate Change ( provides an in-depth view of the current state of scientific knowledge relevant to climate change. IPCC assessments provide a scientific basis for governments at all levels to develop climate related policies. Recognizing the potential role of CCS in climate mitigation, the IPCC issued a special report on CCS (IPCC, 2005). Recently Gale et al., (2015) summarized the extensive progress made since the special report publication. Despite the recent progress, large-scale deployment of CCS yields numerous challenges that require additional research to overcome existing hurdles to widespread adoption. These include reducing the cost of industrial CO2 capture, developing effective ways to demonstrate long-term storage security, and overcoming potential regulatory and public policy hurdles.

Although the public policy, regulatory, and business framework for CCS is still in an emerging stage, it is clear that CCS has the potential to bolster the whole oil and gas industry, and its supply chain, creating many new jobs and driving innovation. This can come about in two ways: (1) direct jobs in delivering CO2 injection: characterization of storage formations and sites, developing and operating the sites, and monitoring of the storage system; and (2) associated stimulus provided by CO2-EOR as a result of the increase in CO2 that can be used to facilitate incremental production while at the same time benefiting from associated storage. In both cases, the petroleum engineering content is large as CO2 storage, be it dedicated storage or associated CO2 storage, involves a higher degree of subsurface modelling, analysis, and monitoring than simple hydrocarbon extraction.

As a result, all the geological and engineering expertise of the Society of Petroleum Engineers would be required to advance innovation in CCS. Ultimately, the Society might be renamed The Society of Petroleum and CO2 Engineers!
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. This review identifies the key challenges to enable CCS, which 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, dissemination of best practices, and the role the members of the SPE may play in addressing these challenges.

2) Challenges of CCS

a) Cost Effective Capture of Power Sector and Industrial CO2

In the United States, emissions from fossil fueled electric generation account for nearly 40% of all anthropogenic sources of CO2, representing approximately 2 gigatonnes of CO2 per annum (US EPA, 2016) within the post-combustion flue gas stream. Electrical generating plants are generally large, stationary sources of CO2 which present single-point opportunities for carbon capture. Within the U.S. and globally, electrical generation is by far the largest contributor to industrial CO2 emissions when those from transportation (vehicles, air and maritime travel, and rail) are excluded.

Capturing and compressing CO2 requires energy in the form of steam (for many technologies) and electricity. This reduces the efficiency of an industrial process or power generation when compared to not capturing the CO2 – especially CO2 at a low concentration in flue gas – and releasing the CO2 into the atmosphere. Fitting CCS to a gas power generating plant increases the levelized cost of electricity by 50% or more depending on local factors. This has led many commentators to state that CCS is too expensive.

Recent analysis by the Clean Air Task Force (CATF, 2016) has pointed out that the costs of CCS-equipped power plants are competitive when compared to the “all-in” cost of intermittent generating sources, such as wind and solar. However, owing to the structure of the market where grid strengthening and the maintenance of a spinning reserve is often funded separately from the direct power installation, these facts are not incorporated into policy.

Reducing the energy penalty for capture and compression would undoubtedly make CCS more attractive. Current CCS plants are first generation designs – these have large engineering margins. A major technical challenge facing CCS is that the CO2 concentration in power generation facilities’ flue streams is quite low (typically less than 15%), while the volume of flue gas streams is very high. Therefore, a large volume of emitted gas must be processed to separate the CO2 from the flue gas. 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 (parasitic load) and the energy penalty associated with capture process drives up costs. 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. This increase in size can present difficulties at the tightly constructed plants, where space is often at a premium.

here space is available, post-combustion capture facilities can be installed on existing coal-fired power plants. Two current examples of million tonne per year scale-ups at full operation are the SaskPower’s Boundary Dam Project and NRG’s Petro Nova Facility. A third example close to operation is the Southern Company integrated gas combined cycle (IGCC) plant, with pre-combustion CO2 capture, in Kemper County, Mississippi (Figure 3). However, each of these capture plants are first-of-a-kind installations at this scale and have encountered numerous technical and operational issues that have led to delays in rolling out the facilities, and in some cases, significant cost increases (Esposito, 2016).

Figure 3. Kemper County Energy Facility (source: photo taken in February 2015, Mississippi Power Company)

That the first demonstrations of commercial capture would result in unexpected challenges and delays should have been expected. However, this Edisonian approach of “learning while doing” will likely pay dividends for subsequent power plants. The learning curves for these technologies should mirror those for other energy technologies, such as wind, photovoltaics, and gas turbines. Figure 4 depicts the cost reduction, in terms of dollars per kilowatt, for each of the subsequent installations. The learning rate was shown to be a 20% reduction in capital costs for each doubling of cumulative megawatts installed (Nakicenovic et al., 1998). Second-of-a-kind facilities could realize up to 30% cost reductions based on experience learned from first-of-a-kind plants.

Figure 4 – Learning Curves for power generation technologies (WETO, 2003)

Even with the wider deployment of current generation technologies, additional reductions in cost, energy, water, and space requirements will be needed to make CCS more attractive when compared to other electric generation options. Further cost reductions are expected through 2nd generation and transformational technologies (such as chemical looping), under various stages of development across the world. For example, the U.S. Department of Energy’s R&D goals for the 2nd generation and transformational technologies, respectively, are $40 and $10 per tonne (USDOE-NETL, 2013).

In solvent-based capture facilities, the greatest capital cost is the capture unit itself, while ongoing operating and maintenance costs are often dictated by the efficiency of stripping CO2 from the solvent. Additionally, the cost of CO2 compression – to bring CO2 from near-atmospheric, gaseous pressures to pipeline-quality, liquid pressures – is a significant demand on the cost structure of capture facilities. Unlike those deployed in oil and gas operations, there is likely no natural gas fuel stock to run compressors at coal-fired power generation facilities. Therefore, their large power demands are met by the power plant itself (an increased parasitic load), driving down the plant’s generating efficiency, and ultimately increasing operational costs.

To overcome these operational challenges, the deployment of numerous new and retrofitted power installations is necessary to accelerate the learning curve and bring down the costs of capture. The commercialization of these technologies could accelerate by the institution of robust R&D and technology transfer programs, and the sharing of test and performance data. However, to date, the pace of deployment has been too slow to facilitate rapid learning and cost reductions.

While commercial CO2 capture at power plants is still a work in progress, existing, relatively high purity point sources of CO2, requiring only dehydration and compression, at gas processing, petrochemical, ethanol, cement, and fertilizer facilities can be attractive targets for CO2 capture in the near term. While generally small in terms of the total volume of CO2 emissions; in total these facilities emit approximately a tenth of the CO2 per annum that electric generating facilities do (US EPA, 2016), collectively still making them a significant potential source for CO2 emissions reductions. The challenge with these smaller, often higher purity, sources is that they commonly require significant pipeline infrastructure to deliver the CO2 to the large oil basins in the U.S., where CO2-EOR is currently ongoing. While this may not be relevant in other corners of the world, the opportunities presented by these types of sources in the U.S. may pave the way for the infrastructure development that electric generating facilities would also require for CO2 delivery to the EOR market. This, in turn, drives interest from the oil industry as a (future) potentially inexpensive source of CO2 for widespread use in EOR projects around the globe. Furthermore, given the appropriate incentives on carbon emission reductions, these small sources could be used for storage in nearby saline reservoirs, thus helping prove such reservoirs for larger-scale storage.

b) CO2 Storage in Geologic Formations – The Challenges of Scale and Pore Space Access

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 providing a plan to maximize the value proposition offered across the acreage. Also, there is typically a state or federal permitting or oversight agency to ensure the project complies with established environmental requirements.

A clear royalty system is employed by the oil and gas industry to compensate the mineral owner (who may or may not be the surface owner) with a direct economic benefit from the hydrocarbon extraction. In cases where mineral and surface rights are severed, the surface owner may be remunerated for access. Generally, these royalty and access payments generate public “good will” and acceptance, provided the operator offers good project oversight.

Providing the same type of economic incentives for the stakeholders associated with a pure CO2 storage project remains a challenge. In the case of storage, no uniform framework to financially compensate the landowner has been settled upon. As a result, CO2 storage continues to be seen as a “waste management” activity with little public buy-in or benefit to the local population, particularly in areas with little to no hydrocarbon extraction industry presence. In the U.S., this is further exacerbated by the fact that hydrocarbon extraction leases may not functionally allow the act of storing CO2. Generally, the pore space in which storage would occur is retained by the surface owner and the hydrocarbons are maintained by the mineral owner/lessee. As such, conventional oil and gas leases generally preclude storage activities, which creates some difficulties in utilizing depleting oil and gas fields as storage repositories, regardless of their attractive geologic/engineering characteristics.

Internationally, the ability to access the pore space rights may be controlled by the central, regional, or local governments and thus would require approvals from such authorities. This continues to provide challenges to international CCS projects, particularly in Europe, as lack of public acceptance of storage projects, as well as low cost and low risk sequestration geology, has derailed a number of proposed efforts (Global CCS Institute, 2015). A well-conceived outreach strategy combined with mechanism for ensuring both local benefits and trustworthy environmental stewardship are required to obtain local public acceptance of the storage projects.

Another option to ameliorate public acceptance and pore-space access issues is to consider subsea 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 role public acceptance and leasing issues play in derailing a project. Furthermore, in many areas, such as the Gulf of Mexico or the North Sea, depleted oil and gas fields and the existing infrastructure could be used for CO2 storage, thus reducing the cost of new exploration and construction. While offshore storage is being evaluated in many parts of the world, Norway, in particular, has led the way. Statoil’s Sleipner project in the North Sea has injected more than 20 million tonnes of CO2 since 1996, becoming a global standard for storage in saline formations. In the United States, the USDOE-NETL has recently funded efforts to evaluate prospective offshore storage resources in the Atlantic and Gulf of Mexico regions.

While the Sleipner project demonstrates offshore CCS can be implemented at a large scale, it still does not quite reach the volumes injected for large-scale CO2-EOR projects or required for mitigating emissions from the power generation industry. In fact, the volumes stored only account for two to three years of CO2 emissions from one 1,000 megawatt coal-fired power plant, which could emit as much as 400 MMscfd (8 million tonnes per year) of CO2. As a result, much still needs to be learned about large-scale injection operations.

A major difference between CO2 injection and hydrocarbon production is the fact that injected CO2 has to be accommodated in the subsurface by compression of the formation and formation water. This increases the pressure. The rate of pressure increase limits the injection rate and total amounts that can be stored. The first challenge in saline storage is therefore appraisal. This includes determining the connectivity at distance without drilling too many costly appraisal wells, along with the potential primary (pressure accommodated) storage capacity?

The knowledge of reservoir contact and fluid movement is essential to all CO2 storage projects. This allows engineers to understand plume growth and to control any potential surface access/rights trespass issues. In water flooding and CO2-EOR, the E&P industry typically refers to these as reservoir conformance and sweep efficiency. CO2 has a much higher mobility than water, and with a lower density also shows strong gravity segregation. Plume modelling strategies, coupled with advanced geophysical techniques for calibration, are an area of continuing focus, particularly since there has not been any long-term, commercial scale injection projects where CO2 plumes could approach several kilometers in radius.

Once the primary pressure accommodation space has been used, the challenge is to develop reservoir engineering strategies to use the pore space more efficiently for storage. Extraction of water will increase storage efficiency, and will reduce the area affected by a pressure plume, however, CO2 breakthrough to production wells is a limiting factor. This will require R&D in both subsurface modelling and in water treatment and handling. There is also significant interest in reusing the water, especially in arid areas.

Fortunately, regardless of the storage reservoir type, the petroleum industry is well-positioned to help. Drilling, production, reservoir, and facility engineers will be required to transition CCS projects from pilot scale to commercial scale operations. Geoscientists will be needed to describe the subsurface. Within current petroleum curricula, academicians are already training the next wave of engineers and geoscientists in preparation for a burgeoning CO2 storage industry.

c) Reusing old fields and infrastructure, well engineering operations and design

Depleted oil and gas fields offer proven secure storage – the capacity is well understood, the storage security is proven. However, they introduce some challenges. When a gas field is highly depleted, the CO2 will be in the gas phase, yet it is transported in the dense phase. Upon expansion, CO2 cools more rapidly than methane. The CO2-EOR industry is aware of this and has some experience, but has never had to inject into highly depleted fields. 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 novel petroleum engineering solutions.

Cooling can also effect the design of down hole components. In an offshore environment, and increasingly in onshore fields, it is important to include a subsurface safety value (SSSV) or a non-return valve (NRV) in well construction. If the SSSV or NRV is called upon, modelling shows that the temperature above the valve can drop to around -25 degree Celsius, and in some cases the value can cool to -78 degrees Celsius. This is a new regime for subsurface components as manufacturers have often concentrated on high pressure, high temperature performance – experience from the LNG industry will need be brought to bear on the design of the well components.

The assessment, monitoring and repair or legacy wells is also important when dealing with depleted fields, especially depleted oil fields. Effective and efficient techniques will help to reduce the cost of reusing these assets.

As CCS begins to be deployed around the world, it is important to transfer the well engineering expertise from the CO2 EOR industry to the CO2 storage industry. CO2 can damage certain types of elastomers, CO2 expansion across chokes can cause cooling, and, in the presence of water, forms hydrates, CO2 escaping from lubricators can freeze the grease, and CO2 kicks have different characteristic from gas kicks. All these effects are well known, understood and managed in the CO2-EOR industry, but they are not experienced in the wider hydrocarbon industry. This learning needs to be shared widely.

d) Demonstrating that Storage is Secure

The single largest challenge facing CO2 storage is scaling up the technology to the magnitude necessary to address climate change challenges, while demonstrating to stakeholders that the process is safe and secure. While large scale CO2-EOR operations have been conducted for decades, the CO2 stored is a secondary advantage. In the case of purely geologic storage, there have been relatively few sites where large amounts of CO2 have been injected into geologic brine formations. Billions of barrels of produced water have been injected for years, however, the public has – until recently – been unaware of this.

In the CO2-EOR process, CO2 is injected into the target oil reservoir to boost oil recovery. While some of the CO2 is recovered during the production of oil (and subsequently separated and reused), a portion remains permanently sequestered in the reservoir. The continued injection of CO2 following the extraction of recoverable oil yields the opportunity to increase the permanently stored volume of CO2 in the reservoir. In addition, it may also be possible to expand the injection operations into adjacent geologic horizons accessible from the same CO2 injection wells and surface infrastructure used for the CO2-EOR operations. Thus, the combination of CO2-EOR and permanent CO2 storage in oil reservoirs has the added potential to enable a significant, near-term solution for reducing CO2 emissions, while also providing a boost to crude oil production. The storage of CO2 in saline formations, on the other hand, relies on injection in brine-filled deep reservoirs that are overlain by suitable containment zones. While the EOR processes offer a concurrent economic benefit and can be a suitable bridge to long-term storage where applicable, the estimated storage resources are significantly greater and widespread in saline reservoirs. Therefore, both options merit continued research and development for future implementation.

The 40-plus years of experience gained by petroleum engineers in designing and operating CO2-EOR projects provides the primary foundation for establishing a comparable understanding for the issues and operational considerations associated with CO2 storage. Moreover, most of the CCS research projects currently underway or planned will use CO2-EOR operations as the primary mechanism for CO2 storage.

In most respects, the technologies and processes around geologic storage of CO2 are mature technologies. However, the continued evolution and application of innovations are necessary to further advance the capabilities of CCS. For decades, activities such as drilling wells, subsurface mapping, fluid injection, reservoir management, and many monitoring methods have been performed safely and successfully with a high degree of accuracy. However, CCS specific monitoring, permitting and long-term care programs must be developed and applied to develop commercial sites and assure environmental protection. In many regions, CO2 storage locations may coincide with other subsurface resources activities in the same geologic column, such as oil and gas production often with hydraulic fracturing, EOR, water production, coal mining, gas storage, and brine disposal. Storage evaluations must consider the potential impacts or interactions with such other basin resources and increasingly this will require integrated subsurface resource planning.

CCS projects commonly generate a degree of public concern associated with the risk of storage. The perceived risk of leakage and induced seismicity are among the biggest challenges facing CCS, and most remaining issues regarding regulations for CCS are storage-related, particularly the issue of long-term liability. Therefore, the application of robust risk assessment tools is critical. 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 or risks are highly site-specific, the main perceived risks are of potential CO2 or brine leakage (primarily from existing and abandoned wells, and potential faults and fractures), induced seismicity and ground displacement, and their potential impact on health, environment, resources, and resource value. While storage-related risk assessments and risk management processes have matured as more projects are implemented or near final investment decisions, continued and systematic diligence will be necessary to characterize and quantify potential risks. The ability of the hydrobarbon industry to insure for risk has evolved along with that industry over the past century, whereas the CCS industry is new as there is little performance history. We therefore observe a significant aversion to CCS risks owing to the perceived novelty of the industry. It is up to petroleum engineers to make the bridge between more than a century of subsurface experience in oil and gas and the injection of CO2.

CCS operations and post-injection monitoring activities may last several decades. It is therefore key to address long-term data archiving and the technology evolution/obsolescence need to be carefully considered. For example, it is possible that the instruments or even companies used for baseline monitoring may not be available for post-injection monitoring. Experience from long-term oil industry projects may be useful to address such issues.

Development of regulatory regimes for CO2 storage is necessary to ensure public health and safety; and to prevent environmental damage, particularly damage to underground sources of drinking water. Such regimes should: (1) provide a mechanism for stakeholder engagement that addresses local concerns, potential community impacts, as well as allows for stakeholder participation during project development and implementation; (2) establish a level playing field for project developers and operators; (3) provide transparency that can support market confidence, address financial assurance, and facilitate credit for CO2 storage; and (4) address ownership, property rights, and liability considerations.

A considerable amount of worldwide CCS regulatory framework development has occurred over the past several years. In most cases, these efforts build upon existing frameworks for regulating oil and gas activities. For example, the U.S. Environmental Protection Agency (EPA) has published Underground Injection Control (UIC) well (Class VI) requirements for 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, many are concerned that substantial legal and regulatory obstacles still exist. Internationally, an effort is underway by the International Standards Organization (ISO TC265) to develop standards for the design, construction, operation, environmental planning and management, risk management, quantification, monitoring and verification, and related activities in CO2 capture, transportation, and geological storage, including CO2-EOR.

e) Dealing with the Availability of Much More CO2

Transportation challenges

Should CO2 capture become cost effective, whether via technology advances or credit offsets, the volume of CO2 available for transportation and injection would require significant expansion of the current infrastructure. For example, if all 2 billion metric tonnes (gigatonnes) of CO2 sourced from U.S. coal-fired power plants per year were to be effectively captured, it would equate to roughly 100 billion cubic feet per day of CO2 that would require compression, transportation and storage. Today, 50 individual CO2 pipelines and with a combined length over 4,500 miles exist in the United States (USDOE-NETL, 2015). Even if only ten percent of emissions are captured, it would far exceed the current available infrastructure’s ability to transport the CO2, despite the U.S. having the largest CO2 transportation system in the World (Figure 4). For perspective, the infrastructure development that would be necessary for such an effort would need to mirror that of the natural gas storage industry’s transportation infrastructure, which includes 300,000 miles of interstate and intrastate transmission pipelines (US EIA, 2016).

Figure 4. Pipeline and Inject Site Infrastructure includes about 4,500 miles of pipeline (source: Melzer Consulting, 2015)

However, should development of this infrastructure occur, CO2 would be widely available, likely at a low cost due to the potential large volumes. Such low-cost CO2 would present new opportunities, particularly considering early targets would probably be CO2-EOR amenable oil fields and large tracks of greenfield residual oil zones (also amenable to EOR), like those of the Permian basin. These fields have the potential to readily absorb a large portion of this available CO2 volume. Development of such infrastructure would also support CO2 storage in saline formations, where the demand for EOR fields is not sufficient.

To meet the transportation needs for the captured CO2, considerable development in infrastructure is needed. Early targets for the CO2 would include areas where well infrastructure systems are already in place, such as giant oil fields, while areas with minimal development, such as green field residual oil zones and saline reservoirs, would be developed in parallel or subsequent to for future CO2 storage. While the capabilities exist to build the infrastructure, the task will require a tremendous influx of capital, personnel, and regulatory cooperation to meet this need.

New flooding paradigms

The increased availability of high volumes of low-cost CO2 could allow for the development of new flooding paradigms for EOR. This could in effect make it attractive to use CO2 in excess of current practice. These techniques could include vertical or gravity stable flooding protocols that use large volumes of CO2 and 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 in fields might be adopted in lieu of waterflooding. New best practices for these cases would need to be developed and shared within the industry. This is a position that is well suited for SPE’s technology transfer mission.

f) Development and Dissemination of Best Practices

The need for timely and efficient dissemination of best practices from ongoing CO2 storage projects is key to the efficient development and deployment of the technology. While the U.S. and international governments and industry partners have significantly invested in CO2 storage research over the past twenty years, relatively few examples of large storage demonstrations exist. Small to medium-scale CO2 storage pilots have been performed in a variety of basins and reservoir types, notably those led by the U.S. DOE’s Regional Carbon Sequestration Partnership programs, with findings and lessons learned summarized in the best practices manuals published by the USDOE-NETL.

Large-scale CO2 injection projects remain primarily in the realm of commercial CO2-EOR projects. An example of a large-scale CO2-EOR project with extensive monitoring is the Weyburn-Midale project in Saskatchewan, Canada (Hitchon, 2012). This plant has successfully stored over 30 million metric tonnes of CO2 sourced from Dakota Gasification Company’s Great Plains Synfuels Plant located in North Dakota since the onset of operations in 2000. While large-scale CO2-EOR serves as an analogue for large-scale 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 (in the absence of a local income stream) and pressure/plume management in the absence of production wells. Projects such as Weyburn and Kemper also highlight the need for the oil industry to work more closely with the coal industry in that much of the CO2 for CCS will be generated from coal-fired power generation sources.

SPE has a role to play in the documentation and dissemination of best practices from CO2 storage efforts through support of publications and conferences/forums. There are numerous CO2 storage-focused technical conferences with the most notable in size and history being the Greenhouse Gas Control Technologies (GHGT) series which began in 1992. Bridging the learnings from CO2-EOR and CO2 storage demonstrations has become a recent focus of the SPE with its involvement with the Carbon Management Technology Conference.

g) Summary - encouraging R&D policies/efforts to address the Challenges

CO2 storage at the scale necessary to support U.S. and global climate change initiatives presents a “Grand Challenge”, one which the SPE and its members can help to address. Current U.S. electric power generation facilities generate 2 gigatonnes of CO2 per year. Capture, transportation and storage of even a small fraction of this mass will require:

  • Cost-effective capture technologies. While early movers are developing large-scale capture demonstrations, we are still very early on the “learning curve”. Support for more development of next generation of 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.
  • Safe, secure CO2 storage on a large scale. Decades of experience with CO2-EOR has provided a head start on this challenge. However, unique aspects of CO2 storage, including containment, regulations, pore ownership, liability, public outreach, and pressure/plume management require large-scale CO2 storage demonstrations to realize this technology.
  • Access to pore space. Understanding CO2 plume growth where CO2 plumes could approach several kilometers in radius and controlling any potential surface access/rights trespass issues is essential. Developing reservoir engineering strategies will require R&D to inform best practices.
  • Infrastructure buildout. Pipelines and surface facilities will require permitting and construction at an unprecedented rate, requiring a tremendous influx of capital and personnel.
  • Technology transfer. Timely and efficient dissemination of best practices from ongoing CO2 storage projects will only increase as rapid deployment of CCS becomes more urgent. Unfortunately while the EOR experience is robust, much of the information on field practices is not published. There are relatively few large storage-only projects from which to glean learnings.
    Further government support of R&D on CO2 capture and storage, particularly at the “power plant scale” are critical towards accelerating our preparedness to meet this challenge.

SPE has several roles to play to address this Grand Challenge. First, it should support documentation and dissemination of CO2 storage best practices by publishing studies and participating in industry forums. A robust workforce is also required. Engineers and geologists educated at traditional petroleum programs can fill this role provided that the current downturn does not result in a dramatic reduction in young professionals in the petroleum industry and graduating with petroleum engineering degrees. SPE’s continued support of young professionals is key. For obvious reasons, much of the SPE expertise and interest is in using CO2 for EOR. However, it is important to realize that an emphasis is also needed for saline storage to meet climate change mitigation goals in a timely manner. Thus, opportunities must be sought for combined EOR and storage or stand-alone storage, where needed. The skill sets available to SPE members from oil and gas experience are directly aligned with the needs of CCS, across the entire value chain. Thus, the challenges posed by CO2 storage both with and without EOR should be seen as a new business opportunity for next several decades, rather than just a short-term research and development curiosity.

3) Acknowledgements

The authors wish to thank the editorial contributions made to this Grand Challenge, specifically Shawna Cyphers (Advanced Resources International, Inc.), Richard Esposito (Southern Company), Scott Frailey (Illinois State Geological Survey), Olga Koper (Battelle Memorial Institute), Mike Surface (Dominion). Also we extend thanks to Any Santos (Society of Petroleum Engineers) for her efforts in overseeing this work.

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