Phase III - Department of Mines and Petroleum

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opposed to the 10 samples recommended by the American Society for Testing and Materials) suggest that the variability in tensile strength and S Hmax will not be fully represented in the results. The stress regime beneath Barrow Island is now considered more likely to be normal (S hmin < S Hmax < S v ), rather than strike slip (S hmin < S v < S Hmax ), with S Hmax trending approximately E-W, which is consistent with the regional neotectonics. The change in interpretation of the stress regime resulted from the decrease in S Hmax from pre- to post-Data Well. The GJV should consider using Chevron’s GeoMechanical_Reservoir Simulator (GMRS) code to conduct reservoir-geomechanical simulations to better understand the stress path that will be followed during CO 2 injection and use those results to conduct a series of triaxial tests to confirm the behaviour of the Dupuy Massive Sand formations. Reservoir-geomechanical simulations will also provide insight into whether the pore volume change under shear will have a positive or negative impact on injectivity. Geomechanical Impact on Seals Injection of CO 2 has the potential to produce local and regional over-pressurisation of the reservoir and surrounding rock. Such increases of pressure decrease injectivity and effective permeability while elevating the likelihood of fracture generation and reactivation of fault slip. The possibility of local overpressurisation occurring is dependent on a number of factors including; i) pre-injection stress conditions in the reservoir, ii) rate of injection, iii) permeability of the injection reservoir and iv) the depth of the injection point from the base of the seal. Over-pressurisation of a reservoir into which CO 2 is being injected is not desirable where it significantly reduces injectivity and produces new fractures and/or reactivation of slip on existing faults. Predictions of slip on existing faults are expressed in terms of the differential (i.e., increase relative to pre-injection) pressure that can be exerted on the reservoir or seal rocks before failure is likely. The formation of new fractures, most likely close to injection wells, can be induced by pressure and/or temperature changes arising from CO 2 injection. The effect of CO 2 injection on reservoir pressure, and the possible impact this may have on containment have been examined. The differential pressure, or critical delta pressure, has been assessed by GeoMechanics International (GMI) for the Main Barrow, Godwit, Plato, Triller, P18J and U22J faults. The critical delta pressure is partly dependent on the co-efficient of friction assigned to each fault. Our analysis of the critical delta pressures presented in the GMI geomechanics report, in combination with the assumption that certain faults (i.e., Main Barrow, Godwit and Triller faults) are not predicted to intersect the CO 2 plume, suggests that slip on these faults (i.e., Main Barrow, Godwit, Plato, Triller, P18J and U22J faults), induced by increases in pore pressure due to injection of CO 2 beneath Barrow Island, is unlikely to elevate the risk to CO 2 containment. Rock strength measurements and analysis of the stress data indicate that fracturing initiated in the Upper Massive Sand could grow preferentially in the overlying seal. Our analysis of the stress changes expected to occur in the Upper Massive Sand during injection also suggests that shear failure (i.e., stress conditions that satisfy the Mohr Coulomb failure criterion) could occur in this unit. Continued investigation is suggested on the potential for shear failure in the reservoir and seal, and should include reservoirgeomechanical simulations to fully understand the stress changes within the reservoir and to estimate the magnitude of potential stress changes within the seals. Operational aspects of the CO 2 injection process include the limitation of bottom-hole pressure to avoid fracturing close to the injection wells, and the possible use of pressure relief wells. The GJV currently expects to have 675 psi of working pressure available when injection commences. We anticipate the impact of mechanical and thermal effects in the determination of the maximum bottom-hole pressure will come under further scrutiny. The Due Diligence Team supports the use of pressure-relief wells as a mitigation strategy and encourage the GJV to use coupled geomechanics and fluid flow simulators for the prediction of post-injection reservoir pressures. xxvii
Geochemical Modelling Comprehensive characterisation of formation water samples and of twelve selected rock samples from the Dupuy Formation has been documented and these data are used for the geochemical modelling of CO 2 /water/rock reactions during and following CO 2 injection. However, there has been no attempt to relate the petrography of the rock samples used for the geochemical modelling to the petrology and facies of the reservoir. Although the geochemical modelling predicts specific outcomes for the rock samples characterised from reaction with CO 2 -enriched fluids, it is difficult to import these results to the reservoir model without integration of the petrology and facies work. Dehydration of an annular region around the wellbore due to injection of a CO 2 stream undersaturated with water is a potential near-wellbore issue. Such drying-out of the near-wellbore region can increase the relative permeability to CO 2 , decrease the absolute permeability due to salt precipitation and inhibit waterrock reactions (which may release fines and cause plugging). This process should be assessed through simulation runs and core-flood experiments. Reactive transport modelling in the far-field Dupuy reservoir predicts porosity changes to be less than 1% over the first 100 years. Generally the accompanying permeability changes are predicted to be slight over the same time period. In the post-injection phase, between 100 and 10,000 years, the Dupuy Formation would approach a closed system with the total amount of CO 2 in the reservoir fixed. During this time silicates would react and approach chemical equilibrium. This time period is important for the assessment of final trapping modes for the CO 2 in the Dupuy Formation. Porosity changes over the 10,000 year time frame were predicted to be as high as 10% (in carbonate-rich rocks) but typically tended to be less than a few per cent. Even though predicted porosity changes were generally small, significant amounts of waterrock reaction occurred resulting in significant changes in water chemistry, particularly with regard to bicarbonate. These results have important implications for monitoring techniques using geochemical sampling. Effect of Fluid Geochemistry on Seals The GJV has a comprehensive MICP programme in place for the Data Well to evaluate the transmissivity through the primary top seal (i.e., the Basal Barrow Group Shale). As expected, the Basal Barrow Group Shale exhibited the properties of a good seal based on the samples examined (Figure 6). Consequently, the potential for existing fractures and faults that cut across the seal to leak, fracturing of the seal due to overpressuring, weakening of the seal due to permeability increases from geochemical reactions, interfacial tension effects due to the increased acidity of the formation water and leakage via wells are considered the only possible mechanisms for breaching of the Basal Barrow Group Shale. The GJV is currently performing a comprehensive core flood program to determine the impact of CO 2 saturated fluid interacting at a sand/shale interface (i.e., Dupuy sands and Basal Barrow Group Shale). The geochemical modelling was focused on predicting geochemical reactions in the Dupuy Formation and their effect on the transport properties of the reservoir. Only one sample from the Basal Barrow Group Shale primary seal was considered, and it was reacted with Dupuy Formation water. As the main thrust of the GJV geochemical reports was on short term reactions in the Dupuy reservoir, the modelling done using one Basal Barrow Group Shale primary seal sample was inadequate. The Dupuy formation water is predicted to be very reactive with the Basal Barrow Group Shale due to its high clay fraction (approximately 40%), although the system is rock buffered because of the low porosity (
Page 1 and 2: Executive Summary Overview The Grea
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Phase III - Department of Mines and Petroleum

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