Module 7 Key steps involved in developing and implementing a CO2 capture and storage project

Original text: S. Bachu & W. D. Gunter, APEC Capacity Building in the APEC Region, Phase II Revised and updated by CO2CRC and ICF International


Carbon dioxide capture and storage projects are complex undertakings. By following a specific decisionmaking process, is possible to improve the CO2 source and storage site selection process, and manage costs. This module lays out a series of recommended steps for project proponents to follow to ensure that CO2 capture and storage project selection, design, implementation, operation and decommissioning are optimized.

Learning objectives

By the end of this module you will:

  • Be familiar the steps which must be undertaken in developing and implementing a CO2 capture and storage project, and what is involved in each step;
  • Understand how to establish a sequence and timelines for the various steps involved;
  • Know the type of expertise needed and potential partnerships; and
  • Know which major firms and economies can provide the expertise needed.

Steps to be undertaken in developing and implementing a CO2 geological storage project

The steps that should be undertaken to develop and implement a CO2 capture and storage project must ensure that the storage site:

  • Has the necessary capacity for storage;
  • Meets the conditions necessary for injectivity to introduce CO2 in the subsurface at the desired rate;
  • Provides for safe injection such that CO2 leakage is avoided, or, if it happens, it is minimized and benign;
  • Is economically viable - from cost effectiveness and life-cycle points of view the site has to store more CO2 than it is produced by the capture and storage operation itself, and must either produce a profit or avoid a regulatory penalty;
  • Is acceptable to the public;
  • Is constructed and operated in a safe manner; and
  • Is decommissioned in a safe manner.

There is a sequence of steps and actions in developing and implementing a CO2 storage project (illustrated in Figure 7.1 and Figure 7.2). Figure 7.2 provides more details on activities, along with the role of the government regulatory and permitting process.

These steps can be broadly split into the following major categories:

  • Site selection – this comprises all the steps necessary up to obtaining approval for construction of facilities, including in many cases data collection and analysis of suitable storage sites and CO2 sources;
  • Site construction – this occurs after all permits and leases have been secured and actual construction commences. During this phase, the capture, transportation, injection, and trapping methods and technologies will be implemented;
  • Site operation – during which active capture, compression, transportation and injection of CO2 occurs; and
  • Post-operation – comprising of preparing the CO2 storage site for decommissioning and abandonment, and preparing and implementing a long-term monitoring strategy.

Different organizations are best suited to undertake these various steps:

  • Government organizations, such as geological surveys and regulatory agencies, have a responsibility and natural capacity to undertake the work in identification and characterisation of sites (inventory of CO2 sources; basin-scale and regional-scale suitability analyses), broad identification of potential geological sinks for CO2, determination of immediate and ultimate capacity for CO2 storage, and broad screening of potential sites based mainly on safety criteria.
  • Research institutes and universities are the natural place for development of methods, tools and technology for the prediction and monitoring of the fate of the injected CO2 in the sub-surface.
  • Industry would be involved in the following steps: local-scale screening and selection of potential sites in the vicinity of the planned CO2 source(s) (this may include identification and characterisation of CO2 sources); specific site selection and detailed characterisation using geoscience, engineering, economic and safety methods and criteria; engineering and construction; site operation; and post-operation decommissioning and monitoring of CO2 fate. Development of monitoring methods and technology may be also be undertaken by industry.

These roles and the requirements of each step of the process are outlined in the following sections.

Figure 7.1: Flow chart of recommended steps to be taken in developing and implementing a CO2 capture and storage project (adapted from Bachu, 2002).

Figure 7.2: Stage-gate approach for goals, activities, and permitting steps for a CO2 storage project. Source: Global CCS Institute, 2010.

Site selection

The site-selection sequence comprises all the steps necessary up to obtaining approval for construction of facilities. This involves the following key steps:

  • Inventory of CO2 sources;
  • Basin-scale and regional-scale suitability analysis of potential CO2 storage sites within reach of CO2 sources (see Module 6);
  • Inventory of potential basins and estimation of their immediate and ultimate capacity (see Module 6);
  • Screening and ranking of sites based on economics and safety (see Modules 8 and 12);
  • Detailed analysis and evaluation of candidate sites;
  • Facilities engineering design; and
  • Permitting and leasing of storage site.

These are each described in more detail below; others are covered in more detail in Modules 8 and 12 as indicated.

Inventory of CO2 sources

This step involves analysis of both quantity and quality of the source CO2.Parameters to analyze include CO2 purity, and other components in the emission stream.

  • If the company has already identified a source, this step consists of characterising the CO2 source.
  • If the company has not identified a source, an inventory of potential sources needs to either be identified and purchased, or performed. In some jurisdictions, mandatory GHG reporting may facilitate the identification of sources. Where available, the company could purchase the reports of potential CO2 sources developed by the government.
  • When no inventory exists, creation of an inventory of CO2 sources is required. Fertilizer plants, petrochemical plants, gas processing plants, refineries, hydrogen plants and ethanol plants are attractive sources of CO2 because they have relatively pure waste streams of CO2 compared to coal-fired power plants, cogeneration plants and cement plants. In these latter plants, CO2 waste streams have CO2 concentrations less than 25%. The inventory of CO2 sources is a government responsibility, although this task can be contracted or delegated to various agencies or even the private sector. Occasionally, this step may involve conducting a broad economic analysis of capturing CO2 from large stationary sources, transporting it and injecting it into geological sinks, and this analysis may be performed either by government for establishing policy and regulations, or by the private sector.

The presence of impurities in the CO2 gas stream affects the engineering processes of capture, transportation and injection, as well as the trapping mechanisms and capacity for CO2 storage in geological media. Some contaminants in the CO2 stream, such as SOx, NOx and H2S, may classify the CO2 as hazardous. This would impose different requirements for injection and disposal than if the stream were pure (Bergman et al, 1997). In all cases, gas impurities in the CO2 stream affect the compressibility of the injected CO2, and hence the volume needed for storing a given amount. Gas impurities also reduce the capacity for storage in free phase in depleted hydrocarbon reservoirs and deep saline formations as some of the storage space is taken by these gases.

In addition, depending on the type of storage and on site-specific characteristics, the presence of impurities may have other, additional specific effects. For example:

  • In EOR operations, impurities affect the minimum miscibility pressure and oil recovery because they affect the solubility of CO2 in oil and the ability of CO2 to vaporize oil components (Metcalfe, 1982). Methane and nitrogen increase the minimum miscibility pressure and decrease oil recovery. Hydrogen sulphide, propane, and heavier hydrocarbons have opposite effects. However, the presence of SOx and NOx is unlikely to affect significantly oil recovery and/or well injectivity (Bryant and Lake, 2004).
  • In deep saline formations, the presence of gas impurities affects the rate and amount of CO2 storage through dissolution and precipitation. In addition, leaching of heavy metals from the minerals in the rock matrix by SO2 or O2 contaminants is possible. The acidic nature of some of the impurities may also enhance degradation of cement in the wells, which can lead to additional leakage pathways.
  • In coal seams, impurities may have a positive or negative effect, similarly to EOR operations. If a stream of gas containing H2S or SO2 is injected into coal beds, these will likely be preferentially adsorbed because of higher affinity to coal than CO2. This would act to reduce the storage capacity for CO2 (Chikatamarla and Bustin, 2003). If oxygen is present, it will react irreversibly with the coal, thus reducing the sorption surface and, hence, the adsorption capacity. On the other hand, some impure CO2 waste streams, such as coal-fired flue gas (i.e., primarily N2 + CO2), may be used for ECBMR because the CO2 is stripped out (retained) by the coal reservoir due to its higher sorption selectivity compared to N2 and CH4 (Mavor et al., 2002).

The Guidance Document 2 for the European CCS Directive suggests the following approach (Figure 7.3) for evaluating how the impurities may impact the health and safety aspects of a storage site (European Commission, 2011).

Figure 7.3: Flow chart of recommended steps to be taken for evaluating the impact of different components of a CO2 stream. Source: European Commission, 2011.

Basin-scale and regional-scale suitability analysis of potential CO2 storage sites within reach of CO2 sources

Project proponents should next review the geological environment within economical distance of the CO2 source(s) to establish its suitability for CO2 geological storage. This step involves identification of suitable geological media according to the basin-scale criteria described in Module 6.

At this stage it is important to identify if the storage is going to be onshore or offshore, because different jurisdictional and legal issues apply to the two cases (see Module 11).

Where available, project proponents can purchase the maps and reports of the storage resource assessments from government agencies or research organizations. Where no assessments have been done, determination of basin and regional-scale suitability for CO2 storage is required. This is a broad responsibility of government agencies, but it may be performed also by research organizations, including universities.

From the basin-scale and regional-scale storage assessment, CO2 storage sites within the reach of CO2 sources can be inventoried. This analysis includes the storage capacity of all known storage reservoirs based on adsorption calculations (coal beds) or dissolution calculations (saline aquifers/depleted oil and gas reservoirs) depending on the type of storage project (see Module 6).

Inventory of potential sites and estimation of their storage capacity

At this point, an inventory of CO2 source and sink options and the capacity of these reservoirs can be compiled. Only the most feasible sites with the highest potential should be retained. After the inventory is compiled, local-scale characterisation needs to be done for in situ pressure and temperature, oil and/or gas composition, water salinity, reservoir or aquifer porosity and permeability, stress regime and fracturing threshold and gas content (for coal beds).

Geological surveys and research organizations are best suited for developing the methodology and conducting the assessment of immediate and ultimate capacity for CO2 storage as outlined in Module 6, the capacity determination needs to be performed on a site-specific basis:

  • For EOR operations and depleted oil and gas reservoirs, the reservoir pore volume and spill point, the degree of water invasion as a result of production, and CO2 solubility are determining factors in estimating the CO2 storage capacity.
  • For deep saline aquifers, the critical parameters are CO2 solubility in brine and the migration path to determine how much will be dissolved in solution and how much will override at the top of the aquifer as a separate phase.
  • For coal beds, the coal thickness and adsorption capacity at the in situ conditions are the critical elements in estimating coal bed storage capacity.

Screening and ranking of sites based on economics and safety

The economic viability of a CO2 capture and storage project should be assessed by industry. This would include: source-sink matching, transportation options for the CO2, compression, and infrastructure requirements.

  • Source-Sink Matching (SSM) The resource assessments for storage are compared to the specifics of the emissions at sources and distance to an appropriate storage site. Included in this analysis, the capture technology must be considered. Currently, commercially available technology is solvent capture for post-combustion applications. For new plants, oxyfuel combustion or gasification might be chosen as they produce a purer CO2 waste stream but at the expense of requiring a pure oxygen stream in the process. These technologies also lower other harmful emissions such as NOx, SOx and particulate matter emissions. In an emission-constrained world, they are may be more competitive economically to the more conventional end post-combustion solutions.
  • A broad economic analysis, of the source-sink matching type, should be applied to rank the potential candidates based on the cost of CO2 storage. When a cluster of acceptable storage sites has been identified, the economic benefits of synergies with transportation and environment and economic factors should be considered.
  • Evaluating transportation options from the capture site to the storage site can be an important consideration. For example, some CO2 sources are located on the margins of the sedimentary basins or far away from any basin storage opportunities. In such cases, transportation costs can be a significant portion of the total capture and storage costs, and may help determine that a closer CO2 stream be selected even though it is more costly to purify. Offshore storage sites will have different economic considerations than land-based ones. See Module 4 for more detail.
  • Compression of the CO2 is required in order to transport it in a dense liquid form and in order to inject it into deep storage reservoir. Compression to pressures in the order of 14 MPa (2000 psi) are required. This represents a significant expense. Process integration may reduce costs if the high compression required for transportation and injection can be utilized in the capture technology so that the purified CO2 stream is already at high pressure (instead of atmospheric pressure) after capture. See Module 4 for more detail.
  • Infrastructure requirements. Much of the infrastructure for a commercial CO2 geological storage industry will have to be built. This is particularly the case for sedimentary basins which have stranded assets or are immature or barren with respect to their production of oil and gas. In mature sedimentary basins which are in a depletion stage with respect to oil and gas, it is possible that there will be existing pipelines which are not at full capacity. These could be used for transporting the CO2. Sites with no pre-existing infrastructure will face significant expenses in building facilities for injection and monitoring.
  • Evaluation of storage safety through an analysis of the long-term fate of the stored CO2 is a critical step at this stage. This assessment helps to narrow down potential sites to a small number of possible candidates for CO2 storage. It should be based on the methodology already developed or in process of development by research organizations for predicting the long-term fate of the injected CO2. If no such methodology exists, one should be developed by the project proponents in collaboration with appropriate government agencies and research organizations.
  • The screening process should be based on local-scale criteria (see Module 6). Unsafe sites automatically should be rejected. Currently, such analysis has been applied on a continental scale (see Bradshaw et al. 2003 for Australia, and Dooley et al, 2005 for North America), but it can be applied on a regional and local scale as well. Government and research organizations should develop the methodology for the safety assessment of CO2 storage sites.

    The immediate and ultimate safety of CO2 storage operations needs to be established on a case-by-case basis. Lack of safety will automatically exclude a site from consideration even if all other criteria are being met and the economics are favourable.

  • Immediate safety refers to the potential for CO2 upward migration and escape into other strata during or immediately after injection. This could happen through open faults and natural or man induced fractures, or through improperly completed and/or abandoned wells (Celia and Bachu, 2003).
  • Ultimate safety refers to CO2 lateral migration in aquifers with potential for cross formational flow, or in flow systems with a short residence time. Carbon dioxide could reach aquifers either directly, as a result of injection into deep saline aquifers, or indirectly, by exceeding the level of the spill point in hydrocarbon reservoirs and flowing into the underlying aquifers.

In both cases, CO2 may contaminate existing energy, mineral and water resources, and may even reach the surface. The assessment of storage site safety needs to be done on the basis of a better understanding of the in situ physical and chemical processes associated with CO2 injection and storage, improved numerical modelling of CO2 fate, and detailed knowledge of relevant site characteristics. The process of safety evaluation will further reduce the number of sites suitable for CO2 storage.

Detailed analysis and evaluation of candidate sites

After selection, based on transportation and other costs, the detailed characterisation includes site geology, hydrogeology, fluid characteristics (oil, gas, water/brine), geomechanical properties of the injection unit and confining strata, and running sophisticated models to predict the fate of the injected CO2.

Facilities Engineering Design

Design of the capture, transportation (often by pipeline) and injection facilities must be made. The capture facilities may be end of the pipe where the flue gas is purified so that a pure CO2 steam is available for pipelining (see Module 2 and Module 3 for more detail). Alternatively, a pure CO2 stream may already be available.

Pipeline design depends on the CO2 capacity and compression required for delivery to the injection site. Right of ways must be obtained, and the terrain to be crossed by the pipeline will affect the design (e.g. rivers, mountains) (see Module 4 for more detail).

A level of detail for the injection site must be developed sufficient to analyze the costs, economics and safety of the storage reservoir options, and satisfy the application requirements for licensing and approval. This phase may involve some back and forth with regulators and changes may need to be incorporated into the site plan. Only after approval is granted should the company proceed with more detailed site engineering design. Additional compression may be required at the injection site depending on the difference between the pipeline and reservoir pressures. Nominally, the pipeline gas may not require further treatment unless injection will be at reservoir temperatures. In this case, a heater would be required. If more than one well is used for injection, a distribution system is needed to partition the CO2 between the injection wells. If the project involves enhanced recovery, then an independent collection system is needed for the produced oil or gas, as well as a separate compression station to place the oil or gas in a pipeline to market.

Permitting and leasing of storage site

The final step in the site selection process is obtaining regulatory approval and public acceptance for the project. In some jurisdictions the two are inseparable because the public is involved in the regulatory process (see Module 13 and APEC publication entitled: Community Outreach Strategy for CO2 Capture and Storage for more information on proactively working with the public to enhance the CO2 capture project and gain their acceptance). The project proponents have to meet all the regulatory requirements within the respective jurisdiction, which may include intervention by third parties. Obtaining regulatory approval involves site-specific analysis and engineering; however, this is still at a pre-construction level.

Just as industry pays for leases and royalties for the production of oil and gas, it is assumed that the companies that want to develop an CO2 geological storage site would have to pay the owner of the mineral rights (usually, but not always, the government) some type of fee or royalty for the use or rental of the subsurface pore space in the reservoir into which they plan to inject the CO2. In addition, companies will need to obtain the right of way for new pipelines to be built, or enter into a contact with an existing pipeline company to transport the CO2 from the point of capture to the point of storage.

Site construction

Having obtained all the necessary permits and leases, construction of the CO2 capture and storage project can begin. The capture plant will need to be installed at the source (see Module 2 for more details).

For the pipeline, as well as compression at the plant gate for introduction of the CO2 into the pipeline, booster compressor stations would have to be built at regular intervals to maintain pressure for pipelines of extended length (i.e. tens to hundreds of kilometers) (see Module 4 for more details).

Roads have to be built and electric power has to be delivered to the storage site. Assuming an enhanced oil, gas or coalbed methane recovery project, both injection and production wells have to be drilled, completed and plumbed into the distribution or gathering system after it is built. Pumps have to be installed on the production wells and separators have to be built for separation of the produced oil, gas and water. The gas may be flared if produced in small quantities and the produced water would be injected into a deep waste disposal zone through a separate injection well.

For offshore storage sites, all operations take place from platforms, pipelines are under water and can be short if the oil is transported by tanker; and the number of wells are fewer than land-based storage sites because of their higher costs.

Permanent or non-permanent monitoring facilities must be installed to track the fate of the CO2. Dedicated monitoring wells may be drilled with provisions for sampling reservoir fluids, collecting seismic data and tiltmeter data. These tools may be cemented in or just hung in the casing or tubing of the monitoring well. In addition, periodic monitoring data may be collected by running wireline logs in the injection or producing wells as well as fluid chemistry from the production wells. Surface seismic, groundwater monitoring and atmospheric monitoring can be used to detect any movement of the CO2 from the storage depth to the surface (see Module 9 for more detail).

Site operation

Site operation involves all the activities involved in transporting, compressing and injecting CO2 into the storage reservoir.

Injection of CO2 into the storage reservoir can take place after the surface facilities have been constructed. The number of injection wells to be drilled depends on existing wells which are suitable for injection and the desired rate of injection. For a project planned to store a megatonne of CO2 per year, the daily rate of injection would be approximately 3000 tonnes (55MMcf) of CO2, requiring on the order of two to 20 injection wells, depending on permeability and reservoir thickness. Compression may or may not be needed, depending on the magnitude of the difference between the pipeline delivered pressure and reservoir pressure. If the storage reservoir is an EOR project, recycling of CO2 will be involved and the CO2 stored will be a fraction of the total CO2 injected. The net, or creditable CO2 will be even less as the additional energy used to capture the CO2, and compress it for reuse has to be subtracted from that stored. This is not a simple calculation, as the oil produced can be considered as an offset for oil that would have to be produced elsewhere if this supply wasn't available. However, if the reservoir is not being produced, and the CO2 is simply being injected into a depleted oil and gas reservoir or a deep saline aquifer, the calculation is straightforward. In this case, the injection operation consists of a distribution system to the injection wells and some means of monitoring the amount of CO2 injected at each well and for leakage.

Monitoring the fate of CO2. There are three levels of monitoring:

  • Operational monitoring is only carried out during injection of the CO2 and consists of measurements that are normally done in any oil or gas production and/or injection operation. They consist mainly of measuring temperature, pressure and fluid composition (including tracers) for the injection and producing wells, and wireline logs. These measurements are used to estimate the amount and rate of CO2 that is injected and/or produced, and to assess the movement of the CO2 front between injection wells and producers;
  • Verification monitoring, tracks the migration of the CO2 plume away from the wells either in the target storage zone or through leakage across the caprock. This can be through observation wells, geophysical methods and tiltmeters; and
  • Environmental monitoring is used to detect surface seepage into the shallow groundwater zone or into the atmosphere. The tools used here are water sampling in shallow groundwater wells, soil gas, and laser surface atmospheric analyses.

Project proponents may use one or a combination of operational monitoring, operational and verification, or all three levels during the site operational phase depending on the perceived risk. Module 9 provides more detail on risk assessment.

Post-operation (closure and post-closure)

After the reservoir reaches a predetermined pressure (the fill pressure) and/or capacity (depending on the licensing parameters), injection ceases and the post operational phase commences. If the site is to be abandoned, the wells will be cemented to act as a permanent seal at their entry into the reservoir, so that CO2 cannot escape.

Regulatory agencies will likely require a long-term monitoring phase of the project to be put in place as part of the closure plans. Research organizations and/or industry should develop the methodology for predicting the long-term fate of the injected CO2.

Monitoring of the CO2 fate is the responsibility of industry, utilizing technology which is being developed by research organizations and industry, and regulated by government. However, with time monitoring will likely become the responsibility of the government as it is the only agency which is assured of being in existence over such a long timeframe. Currently, these long-term liability issues have not been widely addressed.

The technologies used for monitoring would probably be some combination of surface seismic, vertical seismic in dedicated abandoned cemented observation wells, and aerial scans for anomalous CO2 concentrations in the atmosphere, together with sampling of formation water and groundwater where possible as deemed necessary. The frequency of the monitoring will most likely decrease with time. If a leak is observed, remedial measures will have to be taken.

The predictive modeling of the movement of CO2 plume using a reservoir simulator should be benchmarked against the monitoring data at periodic intervals. If the model predicts a different position of the plume than that estimated from the monitoring, then the model should be changed or improved, and/or the monitoring data reinterpreted. Once agreement is reached between predictions through modeling and observed data through monitoring, confidence can be gained that the position of the CO2 plume is known accurately (see Module 9).

If it is detected that the plume has broken through the caprock, the leak point should be determined and identified as a fracture/fault or a well, and a mitigation plan formulated. This usually takes one of two forms:

  • Faulty wellbore. If the leak is thought to be through a faulty wellbore, then a remedial cement job may be effective in plugging the well; and
  • Opening of fracture or fault by pressure build up. If the leak is thought to be caused by opening of a fracture or fault due to a buildup of pressure, then the pressure in the storage reservoir can be reduced to a pressure low enough that the fracture or fault closes back. If the position of the leak is accurately located, then a new well may be drilled down to the leakage point and the weak point in the caprock cemented. Alternatively, it may be decided to allow the storage reservoir to leak across the caprock into an adjacent deep aquifer, if that aquifer is known to have hydrodynamic or geologic trapping capacity.

If the CO2 manages to seep to the surface before it is discovered, it can be pumped out through shallow wells and reinjected. In most cases, if site selection, site construction and site operation are properly done, leakage or seepage of CO2 is unlikely.

Needed expertise and potential partnerships

The expertise needed for the development and implementation of a CO2 geological storage project is very vast. A more detailed enumeration of the expertise is provided in Appendix 2. The needed expertise can be broadly grouped into the following categories:

  • Geoscience (geology, hydrogeology, geochemistry, geophysics, etc.);
  • Engineering (reservoir engineering, facilities engineering, pipeline engineering, chemical engineering, mechanical engineering, etc.);
  • Economics;
  • Legal and regulatory; and
  • Public relations.

New projects are often proposed by industry partners to provide all of the expertise required for a CO2 capture and storage project. Typically, in today's business world, three types of companies would be involved: the producers of fossil fuels (oil and gas companies, coal producers), transporters (pipeline and shipping companies), and users of fossil fuels (power generating, refineries, cement plants, large industrial plants). The latter have potentially the highest liability with regard to CO2 emissions and would be the group that would be driving the search for opportunities to sell CO2 for capture and storage. Albeit, the former also would seek such opportunities.

Major firms and economies with expertise in developing a CO2 storage project

Currently the firms that possess the expertise and capacity for developing and implementing a large CO2 geological storage project are large energy companies with experience in oil and gas production, enhanced oil recovery, and disposal of acid gases. Firms active in CCS projects include Schlumberger, Chevron, Exxon Mobil, Total, Statoil, BP, Halliburton and Santos. Some associations with various projects are:

  • In Norway, Statoil which operates the Sleipner CO2 aquifer storage project in the North Sea;
  • In the United Kingdom, BP which operates the In-Salah gas field in Algeria;
  • In the United States: Chevron, Exxon, Penn West, Apache, Anadarko, Devon Energy, Kinder Morgan, Burlington Resources, and others, which operate CO2 EOR and acid gas disposal operations;
  • In Canada: Encana, Penn West, Apache, Devon Energy, Anadarko, Keyspan, ChevronTexaco, and others, which operate CO2 EOR and acid gas disposal operations; and
  • In Australia, Chevron which operates the offshore Gorgon LNG project, where the separated CO2 will be injected into an offshore aquifer beneath Barrow Island.

Investment Issues and Risks in developing a CO2 storage project (adapted from Senior et al. 2010)

In ensuring that a chosen site will allow for safe and secure storage, the regulatory and stakeholder requirements in the specific jurisdiction also needs to be considered. In this section, the impact of these issues on site selection and for the business case for investing in storage is summarized.

A key risk that is often not adequately considered by project developers is the risk that a viable storage site is not proved up by site evaluation and characterisation activity, including exploration and appraisal activities. Possible reasons this may occur could be because suitable trapping, seal and reservoir conditions are not confirmed and therefore storage integrity risk, capacity or injectivity is inadequate for the proposed project. Alternatively technical uncertainty may be too high. This can be considered broadly analogous to exploration and appraisal risk for oil and gas exploration, typically between 1 in 3 and 1 in 10 for commercial discoveries of oil and gas. To date the quantification of storage exploration risk has not yet been developed or calibrated, although it may be significant if it is comparable to oil and gas exploration risk. An example of this risk is beginning to emerge from proposed CCS projects where desktop screening fails to identify a suitable site (i.e. it has low geological integrity) even though pre-existing studies suggested potential storage capacity was available; just as happens in the oil and gas exploration industry. One significant difference between storage and oil and gas exploration risks is the continuing seal risk throughout the injection and post-injection stages of a storage project, unlike oil and gas exploration where seal risk is essentially proven by a discovery.

Another major consideration is the business and regulatory risk for the storage investor. Providing storage solutions for CCS deployment and capture by major emitters is widely described as new opportunity for the oil and gas industry or new entrants. New business models will need to be developed providing remuneration for the storage provider's investment from CCS value chains. There are sources of value from existing oil and gas assets, local geological data and knowhow, skills and capabilities. The oil industry's control of assets and data may impact the availability of storage sites, other stakeholder's ability to conduct assessments, costs and access and therefore wider deployment of CCS and opportunities for new entrants. In all cases developers will need to build confidence in the primary source of revenue from carbon abatement which is underpinned by Government policy.

However, there are a number of issues that impact the risk/reward balance and attractiveness of these as a business opportunity. These include the uncertainty surrounding climate change policies in various key countries, uncertain and long term nature of monitoring obligations, uncertainties around the management and transfer of long-term liabilities, exploration risk in saline reservoirs and potentially low or negative returns. There are also risks that storage sites will become unavailable as they are prioritised for other uses, such as gas storage or discovery of hydrocarbons, or for non-technical reasons. There will continue to be a significant risk for the storage provider during the operational and closure stages of any project, after any injection revenues cease. This will result from continued technical uncertainty and risk about exactly how the CO2 will behave in the reservoir and overburden, integrity risk and the impact of injection on surrounding resources and operations. These result in continued business risk and highlight the possible need for policy interventions. Insurance schemes for long term storage are at a very early stage of development and some companies doubt these will be a suitable alternative to managing the risk through the balance sheet or risk sharing with government. Finally, there may be issues around public acceptance of storage and specific projects, which have arisen as potential barriers for projects in other countries. Some regulatory risk will continue up until the final transfer of liability.

Overall, the business risk for storage investments by the private sector may be considered high. Furthermore, the overall risk profile and uncertainties are greater for saline reservoir prospects than oil and gas fields, however saline reservoirs offer a very much larger storage resource potential. For an integrated development of a power plant with capture, transport of the CO2, and geological storage, the need to prove a geological storage site first is both prudent and paramount to a successful outcome. Whilst most of the cost for a CCS project is with the capture and power plant, almost all of the risk of success and the uncertainty is in the storage, in the subsurface.

Proving a storage site will take several years, and just like oil and gas exploration there will be false starts and failure to prove a site; requiring new exploration activity. The oil and gas industry handle these outcomes by management of a portfolio of drilling opportunities in a range of sedimentary basins and countries, with a joint venture arrangement to share/spread the financial risks of geo-technical failure. For integrated CCS projects, pre-existing power plants suitable for retrofit obviously can't move, and locating new power plants require substantial time for specific site planning and approvals, as do pipeline developments. Thus, becoming "storage ready" as soon as possible in a project is critical for the timely and successful deployment of CCS. Developing storage sites may be an uncertain, potentially time-consuming, costly and risky business opportunity.


Effective site selection ensures that the storage site will meet all the required conditions:

  • Necessary capacity;
  • Injectivity at the desired rate;
  • Short and long-term safety;
  • Economic viability;
  • Acceptable to the public;
  • Safe operation; and
  • Safe decommissioning.

It is unlikely that any one organization will have all the expertise to undertake all the steps involved in a CO2 capture and storage project. Government organizations, research institutes and universities, and industry are each best suited to undertake different tasks.

Identifying a CO2 source is the first step to undertake. Potential CO2 sources must be analyzed for impurities (quality). Impurities will have specific affects on different types of storage options.

It is recommended that project proponents identify potential storage basins within an economical distance from the CO2 source early on in this process. Onshore and offshore storage options will have different jurisdictional and legal issues that must be considered.

From the basin-scale and regional-scale storage assessment, CO2 storage sites within the reach of CO2 sources can be inventoried. This analysis includes the storage capacity of all known storage reservoirs based on adsorption or dissolution calculations depending on the type of storage project.

After a short list of potential sites is established, local-scale characterisation of priority sites should be completed. Assessments of capacity for CO2 storage need to be performed on a site-specific basis (see Module 6).

Economic viability should consider source-sink matching, CO2 transportation options, compression of the CO2, and infrastructure requirements.

Both the immediate and ultimate safety of stored CO2 are important considerations. Immediate safety is the potential for leakage after injection. Ultimate safety is the potential for leakage over longer time periods. Both must be carefully considered to ensure that existing energy, mineral, water resources are not contaminated, or human or ecosystem life compromised.

Capture, transportation (often by pipeline) and injection facilities must be constructed. Capture design depends on the source CO2 stream. Pipeline design depends on the CO2 capacity and compression required for delivery to the injection site. A level of detail for the injection site must be developed sufficient to analyze the costs, economics and safety of the storage reservoir options, and satisfy the application requirements for licensing and approval.

A number of licenses and approvals will need to be obtained. This includes all jurisdictional regulator approvals and may include leasing fees for rental of subsurface pore space for storage. Site construction will then put in place the compression, transport and injection facilities required.

Construction of injection and monitoring facilities is now required. Operational monitoring must be carried out during CO2 injection. Verification and environmental monitoring may also be performed during CO2 injection

Regulator agencies will most likely require a long-term monitoring plan to be in place to ensure the safety of CO2 storage after site decommissioning. Monitoring will be the responsibility of the project proponents, but given the long lifetime of CCS projects, it is likely that the government will eventually be required to take over monitoring in the long-term.

A range of monitoring technologies will be required. The frequency of the monitoring will most likely decrease with time. Predictive modeling of the movement of the CO2 plume should be benchmarked against collected monitoring data periodically to verify its accuracy. Leaks must be addressed immediately. When done properly, site selection, construction and operation make the likelihood of any leaks very minimal.

Developing storage sites may be an uncertain, potentially time-consuming, costly and risky business opportunity. Hence, it is important for these issues to be rapidly resolved by policy makers and so provide industry with the appropriate incentives to proceed. Given that a large portion of the risk is often at the storage stage, it is important to develop "storage-ready" sites.

It is likely that a team of qualified experts will need to be involved to ensure the needed expertise is available for the project undertaking. Expertise will be required in:

  • Geoscience (geology, hydrogeology, geochemistry, geophysics, etc.);
  • Reservoir, facilities, pipeline, chemical, mechanical, etc. engineering;
  • Economics;
  • Legal and regulatory; and
  • Public relations.


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CO2 Capture Project:

Intergovernmental Panel on Climate Change:

IEA Greenhouse Gas R&D Programme:

IEA Greenhouse Gas R&D Programme - CO2 Sequestration Information:

Midcontinent Interactive Digital Carbon Atlas and Relational Database:

National Energy Technology Laboratory - Carbon Sequestration Web Site:

US Department of Energy - Carbon Sequestration Web Page:

European Carbon Dioxide Thematic Network, CO2NET:

The Weyburn CO2 Monitoring Project:

Carbon Mitigation Initiative at Princeton University: