• Energy Research

AbstractSubsurface monitoring is essential for the successful implementation and public acceptance of CO2 storage. Injected CO2 will need to be monitored to verify the successful containment within its intended formation, and to ensure no loss of containment within the storage complex. The ability for seismic techniques to monitor structurally trapped CO2 has been successfully demonstrated due to the changes in the acoustic properties of the reservoir produced by the displacement of brine by less dense and more compressible CO2. However, the ability for seismic methods to detect free-phase migrating CO2 is still moderately understood. In order to assess the feasibility for seismic monitoring of a migrating front, we estimate the time-lapse signal over a theoretical, clean, homogeneous sandstone reservoir through the application of a three-stage model-driven workflow consisting of fluid-flow, rock physics and seismic forward modelling. To capture the range of responses which could be encountered, two end-member fluid distribution models were used: uniform saturation and the modified patchy saturation model. Analysis of the time- lapse survey highlights the importance of determining and understanding the fluid distribution model impacting the range of velocities prior to generating and interpreting the seismic response. This change in velocity is shown to be directly related to the volume of CO2 occupying the pore-space of a migrating plume front. This highlights the fact that the detectability of a migrating front is a site specific issue which not only depends on the geophysical parameters of the seismic survey but also on the geological variations and spatial distribution in the reservoir.

SummaryCarbon dioxide (CO2) enhanced oil recovery (EOR) has long been practiced in the US as an efficient mean for enhancing oil production. Many of the US CO2-EOR developments have been designed horizontally. This is because of a viscous-dominated CO2 flow regime that is prevalent in these developments driven by thin and low-permeability reservoirs. Reservoirs and fluid properties are different in the North Sea. Pays are usually thicker with better petrophysical properties. Lighter oils can also be found in North Sea reservoirs. This suggests that a dissimilar flow regime might prevail CO2 displacements in the North Sea developments, which could favor a dissimilar CO2-EOR process design. This study thus compares CO2 flow regimes between several North Sea and US reservoirs. We use scaling analysis to characterize and compare CO2 flow regimes between these two classes of reservoirs. Scaling analysis characterizes CO2 displacement in each reservoir system using three dimensionless numbers: gravity, effective aspect ratio, and mobility ratio. Displacement experiments conducted in stochastically generated permeability fields, under exactly matched magnitudes of the derived dimensionless numbers, reveal the prevailing CO2 flow regime in each reservoir system. Results of scaling analysis indicate that CO2 flooding in the North Sea reservoirs can be generally characterized with a larger gravity number, smaller effective aspect ratio, and smaller mobility ratio than the average US CO2 flooded reservoirs. Flow regime analysis indicates that unlike the majority of the US CO2 flooded reservoirs, CO2 flow regimes tend to be more gravity-dominated in the North Sea class of reservoirs. CO2 flow regimes in the North Sea systems are expected to suffer from a higher degree of instability because of thicker North Sea pays, which limit effective crossflow. Understanding the differences and characteristics of CO2 flow regimes in the North Sea prospects can help operators design their CO2 flooding more efficiently, which could increase the recovery factor (RF) as well as address CO2 storage requirements, a necessary consideration for CO2-EOR deployment in the North Sea.

Abstract Carbonate reservoirs are of great importance, due to their large hydrocarbon reserves. However, their complex structure makes them challenging targets to develop. In order to predict reservoir performance, we need to be able to model the effects of heterogeneity at a variety of scales. In this study, we have constructed a detailed geological model using published data for an outcrop in the San Andres Formation. The resolution of the model is 1.2 m × 0.6 m, much finer than a conventional reservoir simulation model. The aim of this work was to consider various upscaling methods and various modelling methods to understand the current limitations and challenges. A number of single-phase upscaling methods were tested, including averaging (arithmetic/harmonic), and flow-based upscaling with local and extended boundary conditions. In addition the Well Drive Upscaling (WDU) method, a relatively new method, was applied. In this method a single-phase global simulation is performed with appropriate boundary conditions: high pressure at injection wells, low pressure at producers. The flows are then summed and the pressures averaged in order to calculate the effective transmissibilities between the coarse cells. The upscaling methods were tested by simulating a waterflood. Cases with single and multiple relative permeabilities were examined. The upscaling factor in each case was 65 by 5. In general, the coarse-scale models gave late breakthrough, and overestimated the recovery. The WDU method was consistently better than the other methods, because it was able to preserve the correct flow between coarse cells. On the contrary, the conventional flow-based methods with local boundary conditions gave poor results, sometimes worse than averaging. We then applied the WDU method to upscale various carbonate models that had been constructed using the Porosity Derived System approach (PODS). The results of this specific 2D study show that upscaling in a complex carbonate reservoir is feasible, providing a suitable method, such as the WDU method, is applied.

This paper evaluates key parameters in CO 2 storage in saline aquifers. A reservoir simulator was used to simulate 30 years of CO 2 injection followed by 470 years of shut in. Two retention mechanisms were modelled: hydrodynamic and solubility trapping. Solubility trapping was found to be the most important means for storing CO 2 . This effect was enhanced by the creation of convective flow patterns which lead to a greater dissolution of CO 2 . Tests were carried out on a homogeneous model, and the effects of CO 2 diffusion in brine, vertical to horizontal permeability ratio, residual saturations, salinity and injection well completion interval were investigated. Results were compared with those from other studies to develop a more general understanding of factors affecting CO 2 storage. To increase the realism of this study, the effect of geological heterogeneity was also examined. Three types of heterogeneity were investigated: low level random variations in sandstone permeability, stochastic shale layers and a fault. The low level heterogeneity did not have a large effect, although it distorted the convective pattern, while the presence of shales did have a large effect. CO 2 tends to become trapped beneath the shale layers increasing the lateral migration. The amount of dissolved CO 2 was largest in the models with an intermediate amount of shale. It was found that the fault did not affect the pressure distribution in the aquifer, unless the transmissibility was very low. However, the distribution of CO 2 was affected by the location of the well relative to the fault.

AbstractThe migration of CO2 stored in deep saline aquifers depends on the morphology of the top of the aquifer. Topographical highs, such as anticlines, may trap CO2 and limit the distance migrated, or elevated ridges may provide pathways enabling CO2 to migrate further from the injector. For example, seismic data of the Utsira formation at the Sleipner storage site indicates that a branch of the CO2 plume is moving to the north [1]. It is therefore important to study the interface between the aquifer and the caprock when assessing risk as CO2 storage sites.Undulations in the top surface of an aquifer may either be caused by sedimentary structures [2], or by folding. In addition, irregularities may be generated by faulting [2]. Large-scale features are detected using seismic data (i.e. structures with amplitudes greater than 10 m), and such structures will generally be included in reservoir or aquifer models. However, smaller- scale features could also have an effect on a CO2 plume migration, and this is the topic of our study. We have conducted simulations in models with a range of top-surface morphology, and have examined the distance migrated and the amount of dissolution.The results from this study suggest that the effects of sub-seismic variations in the topography of the aquifer/caprock interface are unlikely to have a significant impact on the migration and dissolution of CO2 in a saline aquifer, compared with tilt or permeability anisotropy. The results were most sensitive to the kv/kh ratio during the injection period.

Abstract Assessing the pressure buildup in CO 2 storage sites and especially the vertical propagation is vital for evaluation of site behavior and security. Vedsted structure in the Northern part of Jylland in Denmark consists of 290 m thick Gassum Formation at 2100 m depth forming the primary reservoir and is sealed by the 530 m thick Fjerritslev Formation which is mainly shale lithology with very low permeability. Overlying the caprock is a number of formations forming secondary reservoirs and seals including a 420 m thick Chalk Group which is overlain by 20–50 m Quaternary deposits. Seismic profiling of the structure shows the presence of northwest-southeast trending faults of which some originate in the upper layer of the Gassum reservoir and some reach the base Chalk Group layer. Two faults in the upper Gassum reservoir have been interpreted to be connected to the base Chalk Group. In order to evaluate potential risks associated with vertical pressure transmission via the faults through the caprock, a number of simulation cases have been run with various fault permeabilities spanning orders of magnitude to represent both the worst and best case scenarios. Fault rock permeability data were obtained from a literature study and range from 1000 mD (maximum value reported from sedimentary rock environment) for the worst case scenario down to 0.001 mD (sealing faults in sedimentary rock environment) for the best case scenario. The results show that after injecting 60 million tons (Mt) of CO 2 at a rate of 1.5 Mt/year for 40 years, overpressure is developed in the reservoir and about 5 bar is transmitted to the base Chalk Group for the 1000 mD fault permeability (open fault) case, while for the 0.001 mD (sealing fault) case the pressure buildup is confined within the primary caprock. The results also show that, approximately 0.3–5.0 bar overpressure can be transmitted to the base Chalk Group when the fault permeability is above 1.0 mD.

Abstract We combine reservoir simulation with 2D synthetic seismic reflection time-lapse data to assess the ability of seismic methods to image plume growth, evolution, and migration within a heterogeneous saline reservoir. The incorporation of reservoir heterogeneity results in a range of saturations due to the tortuous migration around the intra-reservoir baffles. To account for the disruptive nature of the injected CO2, and the uncertainties regarding the fluid saturation distribution, we use two end-member models, uniform and patchy, to generate the widest range of seismic velocity distributions to understand the range of velocity-saturation behaviour which could be encountered. The generated seismic sections show clear differences between the two models while also providing confidence in the ability to detect CO2 plume growth and evolution in the reservoir. A free-phase migrating front of CO2 appears to be difficult to detect, however. The ability to image a front is shown to be dependent not only on the pore-fluid saturation distribution – patchy or uniform – but also on its larger-scale spatial geometry. As the subtle change in amplitude is directly related to the concentration of CO2 within each accumulation, it suggests that the saturation model has important implications for CO2 detectability and for quantifying the volume of CO2 injected into the reservoir.

University of Bergen, Department of Mathematics, PB 7800, 5020 Bergen, Norway University of Stuttgart, Department of Hydromechanics and Modelling of Hydrosystems, Pfaffenwaldring 61, 70569 Stuttgart, Germany Center for Integrated Petroleum Research (CIPR), Uni Research, Bergen, Norway Department for Applied Mathematics, Sintef, Oslo, Norway Shell Oil Company, Houston, TX 77079, USA Institute of Petroleum Engineering, Heriot-Watt University, Riccarton, Edinburgh EH14 4AS, Scotland, UK Helmholtz Centre Potsdam, GFZ German Research Centre for Geosciences, Centre for CO2 Storage, Telegrafenberg, 14473 Potsdam, Germany Department of Civil and Environmental Engineering, Princeton University, Princeton, NJ 08544, USA Perecon AS, Bergen, Norway Earth Sciences Division, Lawrence Berkeley National Laboratory, Berkeley, CA 94720, USA