This report compiles and reviews published guidelines on the selection and management of a geological CO2 storage site as constrained by the existing regulatory environments.

Storage site selection is the first step for CCS to proceed to a full-chain technology solution to greenhouse gas emissions reduction. Detailed characterisation and monitoring of the site is required for ensuring and demonstrating safety and integrity of the storage project. In essence, a site selection process should demonstrate that the site has: sufficient capacity to accept the expected CO2 volume, sufficient injectivity for the expected rate of CO2 capture and supply; and sufficient containment to store the injected CO2 for the period of time required by the regulatory authority, so as not to pose unacceptable risks to the environment, human health or other uses of the subsurface.

This report considers a stepwise progression of studies through geological characterisation to flow and geomechanical modelling, and also includes environmental risk and economic assessments. Bibliographic coverage is also provided for the area of public awareness and acceptance.

Geological characterization of the site

Geological characterization requires a progressive approach from regional screening to successive refinement through data acquisition and modelling to produce capacity assessment and ranking, leading to selection of the optimal storage site for a CCS project. The process must take account of legal and regulatory regimes, environmental constraints, and economic aspects pertaining to the site.

The biggest knowledge gaps and uncertainties generally exist for storage in saline aquifers, where often few data are available to evaluate the sites against principal screening criteria and drilling new, exploratory wells and acquiring new seismic and other geophysical surveys will be required. For depleted hydrocarbon fields, many exploration and production data will be available to assist with an accurate storage assessment.

Conflicts of the use of subsurface must also be managed. There may be competing interests in natural gas storage, geothermal energy or other uses of the same reservoir system.

Flow modelling

During site assessment and the pre-operational phase, simulation models are used to predict CO2 plume migration and the effectiveness of solubility, residual gas (capillary) and mineral trapping. During operations, comparison between simulated and monitored plume migration is used to refine and calibrate the model and update forecasts of plume migration. This iterative approach is required to develop confidence in the prediction of plume behaviour. During the post-operational phase, a similar iterative approach is used to predict post-injection plume behaviour - with a primary focus on quantifying the secondary trapping mechanisms that will eventually immobilise the CO2.

Several numerical modelling packages are available for flow modelling in CO2 storage. The accuracy of flow models depends on the quality of the input parameters and their capability in handling the various flow and transport processes that control the spread of CO2 in the storage medium: fluid flow in response to natural hydraulic gradients or pressure gradients created by the injection process; buoyancy; diffusion; and the various trapping mechanisms.

The results of flow modelling versus monitored plume migration in several CO2 storage projects and injection pilot studies have been reviewed.

Reactive flow modelling

Reactive flow modelling combines hydrodynamic modelling and geochemical modelling to provide a complete calculation over time of the amount of CO2 trapped through a combination of structural, dissolution or mineral trapping. The storage site can be modelled through its different operational phases: pre-injection, injection and post-injection, to assess the geochemical impact of CO2 on injectivity and long-term integrity of the site. The uncertainties affecting the modelled results are strongly influenced by the chemical parameters such as the mineral phases, their kinetics and the reactive surface area. One should, therefore, carefully select the codes for modelling with reference to the specific conditions in the selected site (see, for example, results from the Sleipner site as discussed by Gaus et al., 2008).

Coupled geomechanical and flow modelling

Injection of a large volume of fluid in the subsurface over a period of time can have geomechanical effects. Changes in pore pressure during injection will change the effective stress and cause rock to deform. If the injection-induced pressure increase is too large, shear slip or tensile opening of pre-existing faults in the storage reservoir/caprock may occur, and a previously sealing fault may become conductive, leading to leakage. Induced shear-stress changes may also induce micro-seismicity and even earthquakes of moderate local magnitudes. Different situations will pertain to injection into a depleted, underpressured hydrocarbon reservoir and a previously undisturbed saline aquifer.

Geomechanical data, such as the elastic properties of the storage formation and caprock, pre-existing fault strength properties, and in situ stress state need to be included in coupled geomechanical-fluid flow numerical models for rigorous CO2 storage evaluation and risk during site characterisation. The interplay of geochemical and geomechanical processes within the reservoir and the caprock can strongly influence storage containment, capacity and the CO2 plume distribution. The coupling of geomechanical codes with flow-transport codes for numerical modelling remains a challenge fully; coupled thermal-hydraulic-chemical-mechanical codes are still in the development stage. Examples of coupled simulations using different codes and their results at specific sites are reviewed in Chapter 5.

Environmental impact and risk

It may be stated that the overriding global risk is that without geological storage of CO2, emissions will continue to reach the atmosphere and contribute significantly to climate change.

Risks from geological storage of CO2 primarily result from the consequences of unintended leakage from the storage formation. Leakage can range between short-term potentially large leakages (injection well failures or leakage up abandoned wells) and long-term, more diffuse leakages through undetected faults, fractures or through leaking wells. Potential risks can also be distinguished between onshore and offshore storage settings. Hazards to humans, ecosystems and groundwater include: elevated gas-phase CO2 concentrations in the shallow subsurface and near-surface environment effecting humans and other living organisms; acidification of soils and displacement of oxygen in soils; undetected accumulations of CO2-supersaturated water or gaseous CO2 in shallow traps that might be a risk for future drilling; possible groundwater contamination both from CO2 leaking directly into an aquifer or displaced brines entering the aquifer during the injection process.

Other risks arise from CO2 injection into the deep subsurface, including fault activation and induced microseismicity, changes in the geomechanical stress field and vertical uplift above large reservoirs, and surface geotechnical effects caused by unexpected migration of CO2 or water through faults and fractures.

Risk for CO2 storage is the process that examines and evaluates the potential for adverse health, safety and environmental effects on human health, the environment, and potentially other receptors resulting from CO2 exposure and leakage of injected or displaced fluids via wells, faults, fractures, and seismic events. The identification of potential leakage pathways is integrated with a MMV (Measurement, Monitoring and Verification) plan. Risk is used to ensure the safety and acceptability of geological storage and it involves determining both the consequences and likelihood of an event. Risk mitigation is the planning for and implementationof contingency plans, should the need arise, to remediate adverseimpacts. A good monitoring and mitigation plan will decrease the risk and uncertainty associated with many potential consequences.

Many of the ongoing risk efforts are cooperating to identify, classify and screen all factors that may influence the safety of storage facilities, using the Features, Events and Processes (FEP) methodology. Because the future evolution of a geologic system cannot be precisely determined, various possible scenarios for possible evolutions of the system and situations of particular interest are developed. Most risk assessments involve the use of scenarios that describe possible future states of the storage facility and events that result in leakage of CO2 or other risks. The FEP assessment methodology is useful but still has gaps in knowledge and there is some discussion as to whether a 'bottom-up' (identifying every conceivable FEP and then building scenarios from these) or 'top-down' (identifying a limited number of key risk Scenarios and developing a limited FEP listing from these) approach is best.

In the evaluation of consequences versus environmental criteria, the criteria must correspond to amounts or concentrations that are measurable and acceptable levels and limit values must therefore be determined.

Economic analysis

According to the ZEP report "The Costs of CO2 Capture, Transport and Storage: Post-demonstration CCS in the EU", the cost of CO2 storage will range from €1 to €7 per tonne CO2 stored for a depleted oil or gas field with re-usable wells to €6 to €20 per tonne CO2 stored for offshore saline aquifers. Uncertainty ranges within each case are due to the natural variability of the storage-limiting parameters, reservoir capacity and injectivity, and structural factors such as site location, level of existing data and availability of re-usable infrastructure and wells. Costs will be higher for smaller and poorer quality reservoirs, for offshore sites, and where significant data collection or infrastructural development is required. The effect of the learning rate was found to be negligible (implying that existing knowledge can anticipate the technological issues involved).

Cost sensitivity analysis reveals that the top two factors for all cases are storage capacity and injectivity. Therefore, exploration and reservoir characterisationare vital activities for CO2 storage as they allow selection of a storage reservoir with lowest storage costs. Capacity is of particular importance in the case of offshore saline aquifers, where the use of larger reservoirs results in considerably lower costs than for smaller ones (economy of scale benefit). Well capacity is the top second contributor to variations of cost for onshore cases and thus the design and placement of wells is a basic activity for such cases. Well completion costs are the succeeding most important factor for offshore cases, highlighting the specificities of that offshore environment. The assumed cost of liability is equal for all cases when reported per tonne of CO2 stored. Therefore its relative weight is the largest for cases where the total cost of storage per CO2 tonne stored is the smallest (probably onshore).

Regarding demonstration projects, the ZEP study concludes that it is very likely that the costs per tonne of CO2 stored will be significantly higher than those of projects in the early commercial phase.This should be taken into account when financing demonstration projects and when comparing the actual costs of demonstration projects with those of early commercial projects.