Using Basin Modelling to Understand Injected CO2 Migration and Trapping Mechanisms: A Case Study from the Sleipner CO2 Storage Operation

CO2 migration and trapping in saline aquifers involves the injection of a non-wetting fluid that displaces the in-situ brine, a process that is often termed ‘drainage’ in reservoir flow dynamics. With respect to simulation, however, this process is more typical of regional basin modelling and percolating hydrocarbon migration. In this study, we applied the invasion percolation method commonly used in hydrocarbon migration modelling to the CO2 injection operation at the Sleipner storage site. We applied a CO2 migration model that was simulated using a modified invasion percolation algorithm, based upon the Young-Laplace principle of fluid flow. This algorithm assumes that migration occurs in a state of capillary equilibrium in a flow regime dominated by buoyancy (driving) and capillary (restrictive) forces. Entrapment occurs when rock capillary threshold pressure exceeds fluid buoyancy pressure. Leaking occurs when fluid buoyancy pressure exceeds rock capillary threshold pressure. This is now widely understood to be an accurate description of basin-scale hydrocarbon migration and reservoir filling. The geological and geophysical analysis of the Sleipner CO2 plume anatomy, as observed from the seismic data, suggested that the distribution of CO2 was strongly affected by the geological heterogeneity of the storage formation. In the simulation model, the geological heterogeneity were honored by taking the original resolution of the seismic volume as the base grid. The model was then run at an ultra-fast simulation time in a matter of seconds or minutes per realization, which allowed multiple scenarios to be performed for uncertainty analysis. It was then calibrated to the CO2 plume distribution observed on seismic, and achieved an accurate match. The paper establishes that the physical principle of CO2 flow dynamics follows the Young-Laplace flow physics. It is then argued that this method is most suitable for the regional site screening and characterization, as well as for site-specific injectivity and containment analysis in saline aquifers.

Numerical Simulations of Surfactant Flooding in Carbonate Reservoirs: The Impact of Geological Heterogeneities Across Scales

We demonstrate how geological heterogeneity impacts the effectiveness of surfactant-based enhanced oil recovery (EOR) at larger (inter-well and sector) scales when upscaling small (core) scale heterogeneity and physicochemical processes. We used two experimental datasets of surfactant-based EOR where spontaneous imbibition and viscous displacement, respectively dominate recovery. We built 3D core-scale simulation models to match the data and parameterize surfactant models. The results were deployed in high-resolution models that preserve the complexity and heterogeneity of carbonate formations in the inter-well and sector scale. These larger-scale models were based on two outcrop analogues from France and Morroco, respectively, which capture the reservoir architectures inherent to the productive carbonate reservoir systems in the Middle East. We then assessed and quantified the error in production forecast that arises due to upscaling, upgridding, and simplification of geological heterogeneity. Simulation results showed a broad range of recovery predictions. The variability arises from the choice of surfactant model parameterization (i.e., spontaneous imbibition vs viscous displacement) and the way the heterogeneity in the inter-well and sector models was upscaled and simplified. We found that the parameterization of surfactant models has a significant impact on recovery predictions. Oil recovery at the larger scale was observed to be higher when using the parametrization derived from viscous displacement experiments compared to parameterization from spontaneous imbibition experiments. This observation clearly demonstrated how core-scale processes impact recovery predictions at the larger scales. Also, the variability in recovery prediction due to the choice of surfactant model was as large as the variability arising from upscaling and upgridding. Upscaled and upgridded models overestimated recovery because of the simplified geology. Grid coarsening exacerbated this effect because of the increased numerical dispersion. These results emphasize the need to use correctly configured surfactant models, appropriate grid resolution that minimizes numerical dispersion, and properly upscaled reservoir models to accurately forecast surfactant floods. Our findings present new insights into how the uncertainty in production forecasts during surfactant flooding depends on the way surfactant models are parameterized, how the reservoir geology is upscaled, and how numerical dispersion is impacted by grid coarsening.

Fault rock heterogeneity produces fault weakness and promotes unstable slip

Geological heterogeneity is abundant in crustal fault zones; however, its role in controlling the mechanical behaviour of faults is poorly constrained. Here, we present laboratory friction experiments on laterally heterogeneous faults, with patches of strong, rate-weakening quartz gouge and weak, rate-strengthening clay gouge. The experiments show that the heterogeneity leads to a significant strength reduction and decrease in frictional stability in comparison to compositionally identical faults with homogeneously mixed gouges typically used in the lab. We identify a combination of weakening effects, including smearing of the weak clay; differential compaction of the two gouges redistributing normal stress; and shear localization producing stress concentrations in the strong quartz patches. The results demonstrate that small-scale geological heterogeneity has pronounced effects on fault strength and stability, and by extension on the occurrence of slow-slip transients versus earthquake ruptures and the characteristics of the resulting events, and should be incorporated in lab experiments, fault friction laws, and earthquake source modelling.

Hydrogeological controls on stream discharge dynamics in bedrock catchments: exploring the combined effects of seepage development and heterogeneity

<p>Surface/subsurface interactions and geological heterogeneity have important effects on the dynamics of streamflows. Surface/subsurface interactions speed up transfers through the development of seepage zones, which reduce the response time of the aquifer and increase the proportion of rapid infiltration excess overland flow. On top of it, geological heterogeneity modulates spatially the extent of the seepage zones as well as the intensity of drainage of the underlying aquifer.</p><p>We investigated the combined effect of the surface/subsurface interactions and geological heterogeneity in a crystalline basement region under temperate climate (Brittany, France), where the limited aquifer capacities, the hydraulic conductivity enhanced by weathering and fracturing and the significant recharge rate promote surface/subsurface interactions. We analysed 40-year of discharge data monitored on two catchments (Arguenon 104 km<sup>2</sup> and Aber Plabennec 27.4 km<sup>2</sup>) using 1D hillslope models (hs1D). The hs1D hillslope model resolves the vertically integrated Boussinesq subsurface flows with a spatially and temporally varying saturation-limited boundary condition on equivalent 1D hillslope structures. We specifically analysed the effect of accounting for heterogeneity on improving the discharge predictions, accounting for the presence of 2 equivalent hillslope with different hydraulic properties. This heterogeneity was defined based of the presence of two main geological lithologies in the catchments. Calibration was performed by a systematic parameter space exploration.</p><p>The calibrated models display significant differences between the two catchments. In the Aber Plabennec catchment, the homogeneous and heterogeneous hillslope models had very close performances showing an effective geological homogenization of the hydraulic conductivity and porosity. In the Arguenon catchment, the heterogeneous model outperformed the homogeneous model with a 46% increase of the Nash-log criterion showing persistant and significant differences in hydraulic conductivities and porosity. Successful calibration in both cases demonstrated by Nash-log values larger than 0.75-0.8 showed the overall relevance of the hillslope approach and its capacity to check for the presence of hydraulic heterogeneity at the catchment scale. Differences between catchments hints on the potential identification of hydrogeological properties at the regional scale by the combined use of the geological map and stream discharges.</p>

Effects of geological heterogeneity on fluid distribution and pressure propagation in a shallow, stacked aquifer system at the ECCSEL Svelvik CO2 Field Lab, Norway

<p>The ECCSEL Svelvik CO2 Field Lab is a test site for shallow CO2 injection operated by SINTEF, where the aim is to improve monitoring techniques and extend the knowledge base for storing CO2 underground in deep saline aquifers as a climate mitigation strategy. The test site is located in a Holocene ice contact deposit near Drammen in the Oslofjord. Test injection is possible at 65 m depth. There has been extensive research focused on increasing the understanding of monitoring methods for deep injection of CO2 and the (short term) migration of CO2, based on experiments performed in this shallow aquifer. To maximize the value of data collected in the shallow experiments a solid geological model is fundamental to enable prediction of how water and gas will behave in the reservoir. Various thicknesses of reservoir layers and degree of internal heterogeneity (clinoforms, unconformities, faults) are observed. Analysis of new data from wells (cuttings sediment samples, wire line logs) and comparison with existing data (e.g. seismic lines, georadar profiles) indicate upwards shallowing and upwards freshening trends through the stratigraphic succession, i.e. variation in palynomorph assemblages. Groundwater flux and aquifer connectivity was evaluated through comparison of water chemistry, noble gas content (the ICO2P project) as well as resistivity- and pressure-logging in upper (fresh) and lower (saline) parts. Analysis of the tidal pressure signal in the deep part of the aquifer gives an indication of the degree of communication between the layers of the aquifer. The areal extent of (semi-)sealing layers of mud, as well as intra-reservoir geological heterogeneity (inclined, graded sandy beds with thin, muddy lamina) affects CO2 distribution in the test reservoir, and is likely to lead buoyant fluids along preferential flow paths. Facies models include North-South progradational patterns and are represented in anisotropic property distributions (Petrel - Schlumberger) for fluid flow simulations (Eclipse - Schlumberger). Predicted CO2 flux is towards the North, below what appears to be locally extensive flow baffles. Integrated data analysis has improved the geological understanding of the Svelvik stacked aquifer system, which may be utilized in future applications to improve monitoring methods for safe large-scale CO2 storage.</p>