Determine magnitude of present and future emissions
Screen and select potential sites
Determine magnitude of present and future emissions
Screen and select potential sites
1 Characterize geology 1 Build numerical models 1 Reservoir simulation ' Risk assessment
• Develop monitoring plan
• Develop risk mitigation strategy
• Develop well remediation program
• Perform economic analysis
• Engage stakeholders__J
1 Dialogue with licencing authority 1 Baseline monitoring f • Monitor mass distribution of C02
• Monitor for potential migration of C02 outside containment area
• Carry out simulations history matching
• Update mitigation plan etc
• Engage stakeholders
■ Continue monitoring 1 Continue history matching 1 Finalize closure strategy 1 Engage stakeholders
• Confirm site behaviour matches conditions of licence
• Site remediation
• Periodic monitoring by state ^ regulators
Figure 5.19 Life cycle of a CO2 storage project showing the importance of integrating site characterization with a range of regulatory, monitoring, economic, risking and engineering issues.
Table 5.3 Types of data that are used to characterize and select geological CO2 storage sites.
Seismic profiles across the area of interest, preferably three-dimensional or closely spaced two-dimensional surveys; Structure contour maps of reservoirs, seals and aquifers;
Detailed maps of the structural boundaries of the trap where the CO2 will accumulate, especially highlighting potential spill points; Maps of the predicted pathway along which the CO2 will migrate from the point of injection; Documentation and maps of faults and fault;
Facies maps showing any lateral facies changes in the reservoirs or seals; Core and drill cuttings samples from the reservoir and seal intervals;
Well logs, preferably a consistent suite, including geological, geophysical and engineering logs;
Fluid analyses and tests from downhole sampling and production testing;
Oil and gas production data (if a hydrocarbon field);
Pressure transient tests for measuring reservoir and seal permeability;
Petrophysical measurements, including porosity, permeability, mineralogy (petrography), seal capacity, pressure, temperature, salinity and laboratory rock strength testing; Pressure, temperature, water salinity;
In situ stress analysis to determine potential for fault reactivation and fault slip tendency and thus identify the maximum sustainable pore fluid pressure during injection in regard to the reservoir, seal and faults;
Hydrodynamic analysis to identify the magnitude and direction of water flow, hydraulic interconnectivity of formations and pressure decrease associated with hydrocarbon production;
Seismological data, geomorphological data and tectonic investigations to indicate neotectonic activity.
potential CO2-water-rock reactions that could weaken the seal rock or increase its porosity and permeability.
Methods have been described for making field-scale measurements of the permeability of caprocks for formation gas storage projects, based on theoretical developments in the 1950s and 1960s (Hantush and Jacobs, 1955; Hantush, 1960). These use water-pumping tests to measure the rate of leakage across the caprock (Witherspoon et al., 1968). A related type of test, called a pressure 'leak-off' test, can be used to measure caprock permeability and in situ stress. The capacity of a seal rock to hold back fluids can also be estimated from core samples by mercury injection capillary pressure (MICP) analysis, a method widely used in the oil and gas industry (Vavra et al., 1992). MICP analysis measures the pressures required to move mercury through the pore network system of a seal rock. The resulting data can be used to derive the height of a column of reservoir rock saturated by a particular fluid (e.g., CO2) that the sealing strata would be capable of holding back (Gibson-Poole et al., 2002).
18.104.22.168 Geomechanical factors affecting site integrity When CO2 is injected into a porous and permeable reservoir rock, it will be forced into pores at a pressure higher than that in the surrounding formation. This pressure could lead to deformation of the reservoir rock or the seal rock, resulting in the opening of fractures or failure along a fault plane. Geomechanical modelling of the subsurface is necessary in any storage site assessment and should focus on the maximum formation pressures that can be sustained in a storage site. As an example, at Weyburn, where the initial reservoir pressure is 14.2 MPa, the maximum injection pressure (90% of fracture pressure) is in the range of 25-27 MPa and fracture pressure is in the range of 29-31 MPa. Coupled geomechanical-geochemical modelling may also be needed to document fracture sealing by precipitation of carbonates in fractures or pores. Modelling these will require knowledge of pore fluid composition, mineralogy, in situ stresses, pore fluid pressures and pre-existing fault orientations and their frictional properties (Streit and Hillis, 2003; Johnson et al., 2005). These estimates can be made from conventional well and seismic data and leak-off tests, but the results can be enhanced by access to physical measurements of rock strength. Application of this methodology at a regional scale is documented by Gibson-Poole et al. (2002).
The efficacy of an oil or gas field seal rock can be characterized by examining its capillary entry pressure and the potential hydrocarbon column height that it can sustain (see above). However, Jimenez and Chalaturnyk (2003) suggest that the geomechanical processes, during depletion and subsequent CO2 injection, may affect the hydraulic integrity of the seal rock in hydrocarbon fields. Movement along faults can be produced in a hydrocarbon field by induced changes in the pre-production stress regime. This can happen when fluid pressures are substantially depleted during hydrocarbon production (Streit and Hillis, 2003). Determining whether the induced stress changes result in compaction or pore collapse is critical in assessment of a depleted field. If pore collapse occurs, then it might not be possible to return a pressure-depleted field to its original pore pressure without the risk of induced failure. By having a reduced maximum pore fluid pressure, the total volume of CO2 that can be stored in a depleted field could be substantially less than otherwise estimated.
22.214.171.124 Geochemical factors affecting site integrity The mixing of CO2 and water in the pore system of the reservoir rock will create dissolved CO2, carbonic acid and bicarbonate ions. The acidification of the pore water reduces the amount of CO2 that can be dissolved. As a consequence, rocks that buffer the pore water pH to higher values (reducing the acidity) facilitate the storage of CO2 as a dissolved phase (Section 5.2). The CO2-rich water may react with minerals in the reservoir rock or caprock matrix or with the primary pore fluid. Importantly, it may also react with borehole cements and steels (see discussion below). Such reactions may cause either mineral dissolution and potential breakdown of the rock (or cement) matrix or mineral precipitation and plugging of the pore system (and thus, reduction in permeability).
A carbonate mineral formation effectively traps stored CO2 as an immobile solid phase (Section 5.2). If the mineralogical composition of the rock matrix is strongly dominated by quartz, geochemical reactions will be dominated by simple dissolution into the brine and CO2-water-rock reactions can be neglected. In this case, complex geochemical simulations of rock-water interactions will not be needed. However, for more complex mineralogies, sophisticated simulations, based on laboratory experimental data that use reservoir and caprock samples and native pore fluids, may be necessary to fully assess the potential effects of such reactions in more complex systems (Bachu et al., 1994; Czernichowski-Lauriol et al., 1996; Rochelle et al., 1999, 2004; Gunter et al., 2000). Studies of rock samples recovered from natural systems rich in CO2 can provide indications of what reactions might occur in the very long term (Pearce et al., 1996). Reactions in boreholes are considered by Crolet (1983), Rochelle et al. (2004) and Schremp and Roberson (1975). Natural CO2 reservoirs also allow sampling of solid and fluid reactants and reaction products, thus allowing formulation of geochemical models that can be verified with numerical simulations, further facilitating quantitative predictions of water-CO2-rock reactions (May, 1998).
126.96.36.199 Anthropogenic factors affecting storage integrity As discussed at greater length in Section 5.7.2, anthropogenic factors such as active or abandoned wells, mine shafts and subsurface production can impact storage security. Abandoned wells that penetrate the storage formation can be of particular concern because they may provide short circuits for CO2 to leak from the storage formation to the surface (Celia and Bachu, 2003; Gasda et al., 2004). Therefore, locating and assessing the condition of abandoned and active wells is an important component of site characterization. It is possible to locate abandoned wells with airborne magnetometer surveys. In most cases, abandoned wells will have metal casings, but this may not be the case for wells drilled long ago or those never completed for oil or gas production. Countries with oil and gas production will have at least some records of the more recently drilled wells, depth of wells and other information stored in a geographic database. The consistency and quality of record keeping of drilled wells (oil and gas, mining exploration and water) varies considerably, from excellent for recent wells to nonexistent, particularly for older wells (Stenhouse et al., 2004).
5.4.2 Performance prediction and optimization modelling
Computer simulation also has a key role in the design and operation of field projects for underground injection of CO2. Predictions of the storage capacity of the site or the expected incremental recovery in enhanced recovery projects, are vital to an initial assessment of economic feasibility. In a similar vein, simulation can be used in tandem with economic assessments to optimize the location, number, design and depth of injection wells. For enhanced recovery projects, the timing of CO2 injection relative to production is vital to the success of the operation and the effect of various strategies can be assessed by simulation. Simulations of the long-term distribution of CO2 in the subsurface (e.g., migration rate and direction and rate of dissolution in the formation water) are important for the design of cost-effective monitoring programmes, since the results will influence the location of monitoring wells and the frequency of repeat measurements, such as for seismic, soil gas or water chemistry. During injection and monitoring operations, simulation models can be adjusted to match field observations and then used to assess the impact of possible operational changes, such as drilling new wells or altering injection rates, often with the goal of further improving recovery (in the context of hydrocarbon extraction) or of avoiding migration of CO2 past a likely spill-point.
Section 5.2 described the important physical, chemical and geomechanical processes that must be considered when evaluating a storage project. Numerical simulators currently in use in the oil, gas and geothermal energy industries provide important subsets of the required capabilities. They have served as convenient starting points for recent and ongoing development efforts specifically targeted at modelling the geological storage of CO2. Many simulation codes have been used and adapted for this purpose (White, 1995; Nitao, 1996; White and Oostrom, 1997; Pruess et al., 1999; Lichtner, 2001; Steefel, 2001; Xu et al, 2003).
Simulation codes are available for multiphase flow processes, chemical reactions and geomechanical changes, but most codes account for only a subset of these processes. Capabilities for a comprehensive treatment of different processes are limited at present. This is especially true for the coupling of multiphase fluid flow, geochemical reactions and (particularly) geomechanics, which are very important for the integrity of potential geological storage sites (Rutqvist and Tsang, 2002). Demonstrating that they can model the important physical and chemical processes accurately and reliably is necessary for establishing credibility as practical engineering tools. Recently, an analytical model developed for predicting the evolution of a plume of CO2 injected into a deep saline formation, as well as potential CO2 leakage rates through abandoned wells, has shown good matching with results obtained from the industry numerical simulator ECLIPSE (Celia et al., 2005; Nordbotten et al., 2005b).
A code intercomparison study involving ten research groups from six countries was conducted recently to evaluate the capabilities and accuracy of numerical simulators for geological storage of greenhouse gases (Pruess et al., 2004). The test problems addressed CO2 storage in saline formations and oil and gas reservoirs. The results of the intercomparison were encouraging in that substantial agreement was found between results obtained with different simulators. However, there were also areas with only fair agreement, as well as some significant discrepancies. Most discrepancies could be traced to differences in fluid property descriptions, such as fluid densities and viscosities and mutual solubility of CO2 and water. The study concluded that 'although code development work undoubtedly must continue . . . codes are available now that can model the complex phenomena accompanying geological storage of CO2 in a robust manner and with quantitatively similar results' (Pruess et al, 2004).
Another, similar intercomparison study was conducted for simulation of storage of CO2 in coal beds, considering both pure CO2 injection and injection of flue gases (Law et al., 2003). Again, there was good agreement between the simulation results from different codes. Code intercomparisons are useful for checking mathematical methods and numerical approximations and to provide insight into relevant phenomena by using the different descriptions of the physics (or chemistry) implemented. However, establishing the realism and accuracy of physical and chemical process models is a more demanding task, one that requires carefully controlled and monitored field and laboratory experiments. Only after simulation models have been shown to be capable of adequately representing real-world observations can they be relied upon for engineering design and analysis. Methods for calibrating models to complex engineered subsurface systems are available, but validating them requires field testing that is time consuming and expensive.
The principal difficulty is that the complex geological models on which the simulation models are based are subject to considerable uncertainties, resulting both from uncertainties in data interpretation and, in some cases, sparse data sets. Measurements taken at wells provide information on rock and fluid properties at that location, but statistical techniques must be used to estimate properties away from the wells. When simulating a field in which injection or production is already occurring, a standard approach in the oil and gas industry is to adjust some parameters of the geological model to match selected field observations. This does not prove that the model is correct, but it does provide additional constraints on the model parameters. In the case of saline formation storage, history matching is generally not feasible for constraining uncertainties, due to a lack of underground data for comparison. Systematic parameter variation routines and statistical functions should be included in future coupled simulators to allow uncertainty estimates for numerical reservoir simulation results.
Field tests of CO2 injection are under way or planned in several countries and these tests provide opportunities to validate simulation models. For example, in Statoil's Sleipner project, simulation results have been matched to information on the distribution of CO2 in the subsurface, based on the interpretation of repeat three-dimensional seismic surveys (Lindeberg et al., 2001; van der Meer et al, 2001; see also Section 5.4.3. At the Weyburn project in Canada, repeat seismic surveys and water chemistry sampling provide information on CO2 distribution that can likewise be used to adjust the simulation models (Moberg et al, 2003; White et al, 2004).
Predictions of the long-term distribution of injected CO2, including the effects of geochemical reactions, cannot be directly validated on a field scale because these reactions may take hundreds to thousands of years. However, the simulation of important mechanisms, such as the convective mixing of dissolved CO2, can be tested by comparison to laboratory analogues (Ennis-King and Paterson, 2003). Another possible route is to match simulations to the geochemical changes that have occurred in appropriate natural underground accumulations of CO2, such as the precipitation of carbonate minerals, since these provide evidence for the slow processes that affect the long-term distribution of CO2 (Johnson et al., 2005). It is also important to have reliable and accurate data regarding the thermophysical properties of CO2 and mixtures of CO2 with methane, water and potential contaminants such as H2S and SO2. Similarly, it is important to have data on relative permeability and capillary pressure under drainage and imbibition conditions. Code comparison studies show that the largest discrepancies between different simulators can be traced to uncertainties in these parameters (Pruess et al., 2004). For sites where few, if any, CO2-water-rock interactions occur, reactive chemical transport modelling may not be needed and simpler simulations that consider only CO2-water reactions will suffice.
5.4.3 Examples of storage site characterization and performance prediction
Following are examples and lessons learned from two case studies of characterization of a CO2 storage site: one of an actual operating CO2 storage site (Sleipner Gas Field in the North Sea) and the other of a potential or theoretical site (Petrel Sub-basin offshore northwest Australia). A common theme throughout these studies is the integration and multidisciplinary approach required to adequately document and monitor any injection site. There are lessons to be learned from these studies, because they have identified issues that in hindsight should be examined prior to any CO2 injection.
Studies of the Sleipner CO2 Injection Project (Box 5.1) highlighted the advantages of detailed knowledge of the reservoir stratigraphy (Chadwick et al., 2003). After the initial CO2 injection, small layers of low-permeability sediments within the saline formation interval and sandy lenses near the base of the seal were clearly seen to be exercising an important control on the distribution of CO2 within the reservoir rock (Figure 5.16a,b). Time-lapse three-dimensional seismic imaging of the developing CO2 plume also identified the need for precision depth mapping of the bottom of the caprock interval. At Sleipner, the top of the reservoir is almost flat at a regional scale. Hence, any subtle variance in the actual versus predicted depth could substantially affect migration patterns and rate. Identification and mapping of a sand lens above what was initially interpreted as the top of the reservoir resulted in a significant change to the predicted migration direction of the CO2 (Figure 5.16a,b). These results show the benefit of repeated three-dimensional seismic monitoring and integration of monitoring results into modelling during the injection phase of the project. Refinement of the storage-site characterization continues after injection has started.
A theoretical case study of the Petrel Sub-basin offshore northwest Australia examined the basin-wide storage potential of a combined hydrodynamic and solution trapping mechanism and identified how sensitive a reservoir simulation will be to the collected data and models built during the characterization of a storage site (Gibson-Poole et al., 2002; Ennis-King et al., 2003). As at Sleipner, the Petrel study identified that vertical permeability and shale beds within the reservoir interval of the geological model strongly influenced the vertical CO2 migration rate. In the reservoir simulation, use of coarser grids overestimated the dissolution rate of CO2 during the injection period, but underestimated it during the long-term migration period. Lower values of residual CO2 saturation led to faster dissolution during the long-term migration period and the rate of complete dissolution depended on the vertical permeability. Migration distance depended on the rate of dissolution and residual CO2 trapping. The conclusion of the characterization and performance prediction studies is that the Petrel Sub-basin has a regionally extensive reservoir-seal pair suitable for hydrodynamic trapping (Section 5.2). While the characterization was performed on the basis of only a few wells with limited data, analogue studies helped define the characteristics of the formation. Although this is not the ideal situation, performing a reservoir simulation by using geological analogues may often be the only option. However, understanding which elements will be the most sensitive in the simulation will help geoscientists to understand where to prioritize their efforts in data collection and interpretation.
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