Module 6 Identification and selection of suitable CO2 storage sites
Adapted from: Storage Capacity Estimation, Site Selection and Characteristics for CO2 Storage Projects, CO2CRC
Technical appendices: S. Bachu, APEC Capacity Building in the APEC Region, Phase II
The selection of potential storage sites suitable for significant volumes of CO2 involves the consideration of geological, regulatory, environmental and social factors. It is essential that it is carried out carefully to minimise risks of leakage.
By the end of this module, you will:
- Understand the main criteria for the identification of a site for a geological storage of CO2 at the basin, regional and local scales;
- Understand the steps in selecting a site for geological storage of CO2;
- Identify the difference in selecting sites for different types of geological storage; and
- Be aware of the skills and expertise needed for site selection.
The initial stage in selecting possible storage sites involves screening of sedimentary basins which have the potential to store CO2 in pore space in rock such as limestone and sandstone or via adsorption onto coal. Following the basin screening, the next stage in selecting a CO2 storage site is a basin-scale assessment.
More detailed and localised assessments are carried out as indicated in the diagram, with the amount of data required to make a more accurate assessment of the storage capacity increasing at each stage.
Figure 6.1: The steps in selecting a site and refining the estimates of the amount of CO2 that can be stored at the site (courtesy of CO2CRC).
A summary of the steps required for identifying a site to store CO2 is shown in Figure 6.2.
As each step of the site selection is carried out, the storage capacity is refined until a final figure is determined - the operational storage capacity.
Figure 6.2: Steps in selecting a storage site (modified from Gibson-Poole, 2008).
Screening sedimentary basins
Appropriate sedimentary basins can be screened and ranked according to their suitability for CO2 storage. Existing geological information can be used to evaluate the size and thickness of the basin, the tectonic setting of the basin and the intensity of faulting within the basin. Other factors influential in producing a list of possible sites are hydrodynamic and geothermal regimes, accessibility, the existence of petroleum and coal resources and the level of maturity of the industry.
The steps are:
- Identify sedimentary basins;
- Screen sedimentary basins - review the characteristics of sedimentary basins; and
- Qualitatively rank sedimentary basins in order of suitability.
Screening sedimentary basins
Different basins can be compared and ranked as suitable CO2 storage basins by considering the following factors:
Tectonic setting or seismicity – the tectonic setting or seismicity of a basin should be considered because large earthquakes could lead to CO2 escaping from the storage reservoir. Although some areas that are seismically active contain large petroleum accumulations which suggests that CO2 storage is possible, so they should not be eliminated as potential storage areas. Instead, the site characterisation should be undertaken with particular emphasis on the impact of seismic activity (see also Appendix 1).
Basin size and depth – basin size and depth give an estimate of the overall storage volume achievable. The sedimentary basin needs to be deep enough to store CO2 in a supercritical phase (a depth of approximately 800m is needed for this), but not so deep that injection well drilling would be excessively costly. Coal seams can be considered for storage at depths of 300-800m. Saline formations are suitable at depths between 800 and 3500m
Faulting intensity – faulting intensity influences the capacity and the containment of the site. If an area contains extensive faults, there is the possibility that CO2 could leak out via faults and fractures. Alternatively, faults could seal individual reservoirs, so extensive faulting can break theinto compartments. Multiple wells may then need to be drilled to effectively use the storage capacity of the reservoir.
Hydrogeology/hydrodynamics – hydrogeology describes the dynamic flow system in the reservoir rock and is used to assess the potential of confined but extensive saline formations for hydrodynamic trapping. To keep the CO2 in the reservoir for long enough to enable residual trapping, solution trapping or mineral trapping, the saline formation needs a slow flow rate and/or a long migration pathway. Theof the reservoir needs to be a balance between reasonable injection rates and a slow flow rate for the CO2 once in the saline formation (see also Appendix 2).
Geothermal conditions – the geothermal conditions of a storage basin affect the density of the CO2. In colder basins, CO2 is denser, so that more CO2 can be contained in the same volume of rock (see also Appendix 3).
Reservoir seal pairs – a suitable storage site will have good reservoir-seal pairs. The reservoir will have high Figure 6.3). Evaporites provide the best caprock seals. They form when brackish-saline water evaporates, leaving behind a mineral sediment.and good permeability, and the seal will have low permeability. One way to determine the possible existence of reservoir-seal pairs is through examining stratigraphic columns (see
Coal seams and coal rank – coal seams can adsorb significant amounts of CO2. Coalbed methane (CBM) production usually involves pumping groundwater from the seam to reduce the pressure and release the methane. In enhanced coalbed methane production (ECBM), a gas is used to displace methane from the coal bed. If the gas used is CO2, CO2 is stored by adsorption onto the surface of the coal. CO2 would only be able to be stored in coal seams that were uneconomic to mine because of their depth or quality. While coals at a greater depth have good adsorption capacity, they generally have low permeabilities.
Hydrocarbon potential – rocks that are suitable for containing and producing oil and gas are likely to be suitable for storing CO2. The potential for storing CO2 will be dependent on the timing of possible hydrocarbon production.
Industry maturity – if there is a mature oil/gas industry in the area, there will be a larger amount of available geological information about the site. Most of the hydrocarbon and coal would have been discovered and there are likely to be depleted oil and gas reservoirs. Such areas are likely to have good infrastructure such as roads, pipelines and wells.
Location: onshore/offshore – onshore CO2 storage sites have economic and technical advantages but may have land use and tenure issues.
Climate – climate affects the surface temperatures, the depth of the water table and the ease of development of storage facilities.
Figure 6.3: Stratigraphic column of the storage site for theOtway Project with reservoir/seal pairs (courtesy of CO2CRC).
Summary table of criteria for screening sedimentary basins.
Table 6.1: Criteria for screening sedimentary basins for geological storage of CO2 (modified from Bachu, 2003).
Following the basin screening, the next stage in selecting a CO2 storage site is a basin-scale assessment. This involves reviewing the basin stratigraphy, mapping reservoir-seal pairs and coal seam distributions and assessing CO2 migration pathways and possible traps. At this scale, reservoir/seal pairs can be mapped using existing data such as geological and structural maps, seismic sections and well logs. The subsurface geometry of the reservoir and seal units can be determined using structural contour and isopach maps, reports on hydrocarbon resources and well completion reports.
The steps involved are:
- Review basin stratigraphy;
- Determine reservoir-seal pair and coal seam distribution;
- Assess CO2 migration pathways and possible traps; and
- Rank prospective sites.
The elements used to rank prospective sites are:
- Storage capacity
- Site logistics;
- Containment; and
- Existing natural resources.
The criteria and what is considered are outlined below for storage in saline formations and storage in coal seams.
Table 6.2: Ranking factors for saline formations and petroleum reservoirs as prospective CO2 storage sites (modified from Bradshaw & Rigg, 2001; Rigg et al., 2001; Bradshaw et al., 2002).
Table 6.3: Ranking factors for coal seams as potential CO2 storage sites (modified from Bradshaw et al., 2001).
Site characterisation – saline formations and petroleum reservoirs
Once a basin-scale assessment has been finished and a prospective storage site is identified, the site then needs to undergo increasing levels of detailed analysis in a process called site characterisation. Site characterisation is the analysis and interpretation of subsurface, surface and atmospheric data to assess whether or not an identified site is suitable to store a specific quantity of CO2 for a defined period of time and meet all required health, safety, environmental and regulatory standards.
Site characterisation is the most time consuming and costly part of site selection. It involves skills in reservoir engineering, structural geology, sedimentology, stratigraphy, hydrodynamics and geological modelling. In addition, the social setting, the economics of operation, the risks involved in storing the CO2 at the site and the requirements of a monitoring and verification regime need to be considered. Because of the wide range of expertise covered in a site characterisation, it is best carried out in a multidisciplinary environment. Where there is not enough existing data to successfully characterise the site, it is necessary to generate new data. The process involves:
- Geoscience characterisation – interpreting structural and stratigraphical information and building geological, geochemical, geomechanical and hydrodynamic models;
- Engineering characterisation – constructing numerical flow simulations to predict CO2 plume migration;
- Updating all models as additional data become available; and
- Socio – economic characterization: Risk assessment, economic modelling and community concerns.
Sources of data can include 2D and 3D seismic surveys, well log and core data, drill cuttings, biostratigraphy, field production and fluid data. Three key factors need further evaluation at this stage: injectivity, containment and capacity.
Injectivity is the rate at which CO2 can be injected into a given reservoir and the ability of the CO2 plume to migrate away from the injection well. Factors which affect injectivity include the viscosity ratio of CO2 to other formation fluids, the injection rate and the relative permeability of the reservoir.
Core samples can be used to determine the porosity and permeability of the reservoir rock.logs of existing wells give one dimensional data, so rock properties have to be inferred through the use of well log correlation, the use of analogues and seismic interpretation. Static reservoir models should be constructed to map reservoir distribution and horizontal and vertical connectivity.
CO2 dissolution into formation water can result in CO2-water-rock interactions which may alter the pore system of the rock, so the mineralogical composition of the reservoir should be included in evaluating injectivity.
In deep saline formations, which typically have low permeability, the ideal objective is high permeability near the wellbore to improve injectivity and lower permeability outside the radius of influence of the wellbore to increase residence times.
Supercritical CO2 is less dense than water and has the tendency to be driven upward due to buoyancy forces. Loss of CO2 can occur through migration through the top seal, faults and fractures or via wells. Factors that affect containment include:
The distribution and continuity of the seal: The top seal is called the cap rock. Good cap rock is uniform, regionally extensive, thick, strong and unlikely to be weakened though CO2–water–rock reactions.
The seal capacity (maximum CO2 column height retention): The seal capacity is dependent on the capillary pressure properties of the sealing rock and physio-chemical properties of CO2 and the formation water such as density, wettability and interfacial tension. Water pumping tests can be used to measure the rate of leakage across the cap rook. The sealing capacity of rock can also be estimated by mercury injection capillary pressure (MICP) analysis of core samples. This analysis determines the capillary pressure that is required to move mercury through the pore system of the sample. This pressure is converted to an equivalent CO2 brine pressure and then used to determine CO2 column height.
Integrity of reservoir and seal rock: When the CO2 is injected, it increases the pressure in the formation which can potentially reactivate pre-existing faults or generate new fractures. The maximum sustainable fluid pressure for CO2 injection can be determined through geomechanical modelling.
The potential for CO2-water-rock interaction: The injected CO2 may react chemically with the rock. Detailed reservoir petrology, water chemistry and pressure-temperature conditions enable mineral reactions with CO2 to be predicted. Mineral precipitation of CO2 can lead to mineral trapping and hence greater containment security. It can also clag pores and thereby decrease injectivity.
Migration pathways: The structural orientations and dips in the reservoir can be predicted using stratigraphic, subsurface wireline and seismic data. Because the injected CO2 is more buoyant than water, it will migrate vertically to the top of the reservoir. Once there, the geometry of the seal will have a strong influence on the subsequent migration direction and rate. Other characteristics that need to be identified are the trapping mechanisms.
Intraformational seals which act as localised barriers: The presence of siltstones and shales within the reservoir formation can reduce the vertical flow of the CO2 and create a more complex migration pathway. Such siltstones and shales contribute to the degree of stratigraphic heterogeneity of the formation. In a homogenous formation, the buoyant CO2 will migrate vertically up to the top of the reservoir.
Formation water flow direction and rate: Understanding the flow system of the existing formation water within a reservoir is important to determine how effective hydrodynamic trapping will be. Using hydrodynamic models, the impact of vertical connectivity, horizontal continuity and low permeability zones on the migrating CO2 plume can be assessed.
CO2 storage capacity is an estimate of the amount of CO2 that can be stored in subsurface geological formations. It is influenced by the density of CO2 at subsurface conditions, the amount of interconnected pore volume of the reservoir rock and the nature of the formation fluids.
Storage capacity estimation in saline formations
The mass estimate of CO2 storage capacity is a calculation based on:
- The geographical area that defines the region for storage;
- The thickness of the saline formation;
- The average total porosity of the entire saline formation;
- The density of CO2 at the relevant temperature and pressure;
- How much of the region has a suitable formation;
- How much of the formation meets minimum porosity and permeability requirements for injection;
- How interconnected the formation is;
- What area surrounding an injection well can be contacted by CO2;
- Porosity and permeability variation in sub layers in the formation;
- How much of the formation will be contacted by CO2 as CO2 rises due to a density difference with water; and
- How much of the water will be replaced by CO2 in the pore space.
Storage capacity estimation in depleted oil and gas formations
Unlike saline formations, oil and gas fields can be considered as discrete systems. The mass estimate of CO2 storage capacity is a calculation based on:
- The geographical area that defines the region for storage;
- The hydrocarbon column height in the reservoir;
- The type of trap;
- The average porosity over the column height;
- The density of CO2 at the relevant temperature and pressure; and
- The fraction of the pore volume from which oil/gas has been produced and can be filled by CO2.
Another method of estimating the storage capacity is to estimate the volume of CO2 which can be stored per stock tank barrel of original oil in place.
The equipment required to inject the CO2 into the subsurface is determined by injection rates, the presence of other gases in the CO2 stream and the pressure required to inject the gas in supercritical state. The number of wells required for a particular storage site depends on factors such as the permeability of the reservoir and the injection rates required. Models of the injection phase are used to determine the number of wells, the well design and the injection pattern. Modelling can also optimise injection strategies and predict the migration and distribution of the CO2. This helps to further refine the storage capacity of the reservoir.
Data sources to build and refine models and simulations
The early stage of site characterisation relies on processing and interpreting existing data, including an understanding of the uncertainty associated with the predictions based on the data. As the characterisation proceeds, gaps in the data may be filled through the acquisition of new data, a step which is costly. The sources for data include seismic data, well-log and core data and data from analogues. This final stage of site characterisation is outlined in greater detail in Module 7.
Socio- economic characterisation
The final stage of characterising a site is to determine the likely capital costs and the cost per tonne of CO2 avoided (see Module 12), to determine the acceptability of the site by the community and to complete a(see Module 8). Risk and uncertainty analysis are crucial in determining the suitability of a site as well as reassuring the community about the environmental impact of geological storage. A monitoring and verification program needs to be designed in such a way that it will be efficient and cost-effective. A monitoring and verification program (see Module 9), whilst fulfilling regulatory requirements, will also provide data to refine models of the behaviour of the subsurface CO2 and contribute to community reassurance.
Site characterisation for coal seams
Storage of CO2 in coal seams is different to storage in oil and gas reservoirs or in saline formations because CO2 is adsorbed onto coal and this is major way the CO2 is trapped. Solution trapping and mineral trapping are other means of trapping.
An important factor in determining the storage capacity is the ability of the coal to adsorb CO2 at a given depth and temperature, and will depend on the rank, grade and type of the coal. Another factor to consider is whether the coal would be considered for future mining.
The parameters which describe the storage capacity and injectivity in coal seams are seam thickness, adsorption capacity and permeabililty. Permeability depends on the amount of jointing and cleating and on the mineralized condition of the cleats. It generally decreases with depth, presenting a challenge for geological storage in deep unmineable coal seams.
Coal plasicisation due to CO2 injection may also reduce permeability, but recent research has shown that this may only occur in certain types of coal.
In addition to injection wells for CO2 sequestration in coal, wells may be needed to collect the coalbed methane if the coal bed has not previously been degassed. Horizontal wells may be considered to collect the coalbed methane that is displaced by the CO2 injected into the coal.
This characterisation is similar to that carried out for other storage options. There are different economics to storage and site monitoring in coal seams, particularly where coalbed methane is produced. In this case, the injection capital, operating costs are lower and site monitoring is cost-effective. The amount of CO2 avoided through this form sequestration is also calculated differently (Golding et al., 2008)
The selection of storage sites suitable for significant volumes of CO2 comprises mainly geological evaluation of the applicable storage system (e.g. saline formations, depleted or near-depleted oil and gas reservoirs and/or coal systems) on various levels of detail. These correspond to degrees of confidence in estimating storage capacity. Basin screening involves identification of appropriate sedimentary basins which can then be ranked as to their overall suitability for CO2 storage. Evaluation of the size and thickness of the basin gives an indication of total pore volume it may hold. More detailed basin assessment allows the estimation of the prospective storage capacity in each of the identified storage systems and trap types.
Site characterisation is the most time-consuming and costly part of the CO2 storage site selection process. Site characterisation typically involves collection and analysis of more detailed information than basin assessment investigations and may involve re-evaluation of regional geology and generation of new data and/or updating of existing data such as static (geologic and seismic) and dynamic (flow simulation and injection) data. The level of detail used in site characterisation allows the estimation of contingent pore capacity. The ultimate goal of a storage project is commercial site deployment, which requires all the geological, engineering, economic and regulatory considerations of a site being taken into account. Site deployment therefore requires estimation of operational storage capacity.
CO2CRC. Storage Capacity Estimation, Site Selection and Characterisation for CO2 Storage Projects. Cooperative Research Centre forTechnologies, Canberra. CO2CRC Report No. RPT08-1001. 52pp, 2008.
Bachu, S. Screening and ranking of sedimentary basins for sequestration of CO2 in geological media in response to climate change. Environmental Geology, vol 44, PP277-289, 2003.
Golding, S. D., Uysal, I. T., Esterle, J. S. Massarotto, P and Rudolph, V. A comparative review of carbon geosequestration options. Presentation at the 2008 Asia Pacific Coalbed Methane Symposium, Brisbane, Queensland, 22-24 September, 2008.
CO2 Capture Project:http://www.co2captureproject.org/index.htm
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