Ravi Shekhar

Numerical simulation of fluid-flow processes in a 3D high-resolution carbonate reservoir analogue

A high-resolution three-dimensional (3D) outcrop model of a Jurassic carbonate ramp was used in order to perform a series of detailed and systematic flow simulations. The aim of this study was to test the impact of small- and large-scale geological features on reservoir performance and oil recovery. The digital outcrop model contains a wide range of sedimentological, diagenetic and structural features, including discontinuity surfaces, shoal bodies, mud mounds, oyster bioherms and fractures. Flow simulations are performed for numerical well testing and secondary oil recovery. Numerical well testing enables synthetic but systematic pressure responses to be generated for different geological features observed in the outcrops. This allows us to assess and rank the relative impact of specific geological features on reservoir performance. The outcome documents that, owing to the realistic representation of matrix heterogeneity, most diagenetic and structural features cannot be linked to a unique pressure signature. Instead, reservoir performance is controlled by subseismic faults and oyster bioherms acting as thief zones. Numerical simulations of secondary recovery processes reveal strong channelling of fluid flow into high-permeability layers as the primary control for oil recovery. However, appropriate reservoir-engineering solutions, such as optimizing well placement and injection fluid, can reduce channelling and increase oil recovery.

The Impact of Hierarchical Fracture Networks on Flow Partitioning in Carbonate Reservoirs: Examples Based on a Jurassic Carbonate Ramp Analog from the High Atlas

Hydrocarbon reservoirs commonly contain an array of fine-scale structures that are below the resolution of seismic images. These features may impact flow behavior and recovery, but their specific impacts may be obscured by the upscaling process for sector and field-scale reservoir simulations. It is therefore important to identify those situations in which subseismic structures can introduce significant departures from full-field flow predictions. Using exposures of Jurassic carbonate outcrops near the village of Amellago in the High Atlas Mountains of Morocco, we have developed a series of flow simulations to explore the interactions of a hierarchical fracture network with the rock matrix of carbonate ramp strata. Model geometries were constructed in CAD software using field interpretations and LiDAR1 data of an outcrop area that is 350 m long by 100 m high. The impact of water injection on oil recovery between an injector and producer pair was investigated. Simulations were performed by a single medium reservoir simulator using a single mesh to represent fracture planes as well as rock-matrix volumes. The effects of changing scenarios for rock permeability and porosity as well as facture permeability distributions were investigated. First-order results show that the best recovery was achieved by a model with a high permeability, homogeneous matrix combined with a heterogeneous fracture network. The worst recovery scenario was given by a model with low, homogeneous permeability and high fracture permeabilities. The results highlight the importance of the permeability contrasts between the matrix and the fractures for overall recovery and the very significant impact that fractures can have on recovery by creating shadow zones and providing critical connections between permeable layers. The presence of the hierarchical fracture network developed strong fingering even in homogeneous matrix cases and evolving velocity patterns reveal competing fluid pathways among matrix and fracture routes. Insights from these models can help to develop production strategies to improve recovery from fractured carbonate reservoirs and provide an initial platform from which to extend further evaluations of different populations of conductive and baffling structures, spatial variations in wettability and capillary pressures and well positions.

Modelling and simulation of a Jurassic carbonate ramp outcrop, Amellago, High Atlas Mountains, Morocco

Carbonate reservoirs pose significant challenges for reservoir modelling and flow prediction due to heterogeneities in rock properties, limits to seismic resolution and limited constraints on subsurface data. Hence, a systematic and streamlined approach is needed to construct geological models and to quickly evaluate key sensitivities in the flow models. This paper discusses results from a reservoir analogue study of a Middle Jurassic carbonate ramp in the High Atlas Mountains of Morocco that has stratigraphic and structural similarities to selected Middle East reservoirs. For this purpose, high-resolution geological models were constructed from the integration of sedimentological, diagenetic and structural studies in the area. The models are approximately 1200×1250 m in size, and only faults (no fractures) with offsets greater than 1 m are included. Novel methods have been applied to test the response of flow simulations to the presence or absence of specific geological features, including proxies for hardgrounds, stylolites, patch reefs, and mollusc banks, as a way to guide the level of detail that is suitable for modelling objectives. Our general conclusion from the study is that the continuity of any geological feature with extreme permeability (high or low) has the most significant impact on flow.

Modeling Time Lapse Seismic Monitoring of CO2 Sequestration in Hydrocarbon Reservoirs Including Compositional and Geochemical Effects

Abstract The sequestration of CO2 into geologic formations, specifically existing and depleted oil and gas reservoirs, is a promising solution for reducing environmental hazards from the release of greenhouse gases into the earths atmosphere. A critical component of long-term sequestration will be our ability to adequately monitor the movement of CO2 fronts in the subsurface. In this article, we examine the viability of time-lapse seismic monitoring using an integrated modeling of fluid flow, including chemical reactions and seismic response. Modeling of CO2 injection is complicated by the various interactions between CO2, reservoir fluids, and the minerals in the formation. These interactions change fluid and bulk rock properties with time, which in turn impact the seismic signatures. We perform a comprehensive simulation of the gas injection process accounting for the phase behavior of CO2-reservoir fluids, the associated precipitation/dissolution reactions, and the accompanying changes in porosity and permeability. The simulation results are then used to model the changes in seismic response with time. The general observation is that gas injection decreases bulk density and wave velocity of the host rock system. Seismic amplitude attributes therefore change with time as well, and these effects provide a tool for tracking the movement of the CO2 front. Analysis of the results also confirms that much of the change can be attributed to chemical effects that should therefore be considered in studies of long-term sequestration projects.

Fracture analysis in the Amellago outcrop and permeability predictions

Field observations from several outcrops in the Eastern High Atlas Mountains, near Amellago (Morocco), are used to determine fracture-network model parameters, such as the aspect ratio of the fractures represented as rectangles whose longer side is horizontal, the volumetric area of fracture surfaces, the fracture mean size and the fracture density. The fracture orientations can be roughly approximated by Fisher distributions, where the parameters are determined by outcrop measurements. The permeability of the fracture networks can be calculated by application of the Snow equation for infinite fractures or by numerical resolution of the flow equation for fracture networks generated with the parameters deduced from the outcrop measurements. These two permeability estimations are shown to be in good agreement, which suggests that theoretical or semi-empirical solutions may provide reasonable approximations of fracture-network permeability in some carbonate reservoirs when conditioned to appropriate outcrop and subsurface data.

Correlated Fracture Network Modeling Using Simulated Annealing

Knowledge of the orientation and spatial distribution of fractures in rocks is important for predicting the flow of fluids. Masihi et al. (2007) developed a new method of modeling these distributions beginning with theoretical results from the physics of fracturing. We implemented and extended this modeling technique to generate models that better incorporate field observations. The method starts with an energy function based on the pair-wise spatial correlation of fractures that also serves as an objective function for a simulated annealing algorithm (SA) that generates realizations of correlated fracture networks. We improved this technique by incorporating periodic boundary conditions, including criteria to limit maximum range of the pair-wise calculations, and by suggesting methods to constrain models to match field data. For most subsurface rocks (with Poisson ratio ν = 0.25), this method generates orthogonal sets of fractures, a pattern that is commonly observed during basin formation or subsidence. This new method is compared with conventional discrete fracture network (DFN) modeling by computing the fractal dimension of the networks. We also examine the implications for seismic reservoir characterization by computing effective seismic velocities and the resulting synthetic seismograms. The new approach can be considered better than DFN as DFN generates realizations based on only statistical distributions, without any knowledge of physics of fracturing.

Seismic Modeling of Compositional And Geochemical Effects In CO 2 Sequestration

Summary Time-lapse seismic monitoring of CO2 injection into a hydrocarbon reservoir can be important for either enhanced recovery or CO2 sequestration tasks. In the latter case, over long time periods, the interaction of CO2 with in-situ brine and host rock minerals generates a variety of geochemical reactions that significantly aect reservoir rock properties and reservoir fluid properties. Dissolution of CO2 in brine to attain gas-brine equilibria alters brine density, which changes the bulk properties of reservoir fluids. Furthermore, slow mineral reactions between CO2 reservoir fluids and host rock minerals change porosity and the salinity of the reservoir fluids. Here we present results of a modeling study that combines direct simulation of geochemical processes with fluid flow and seismic models. The results show that the CO2 injection leads to P-wave velocity reduction of up to 12% for the first 10 years, while chemical eects largely associated with salinity changes become observable seismically only after longer time periods of hundreds of years, producing small velocity changes of about 2%. In general, the results suggest that it will be dicult to distinguish mineral reactions and intra-aqueous reactions from the reduction in bulk modulus caused by injection of CO2 into brine, especially with noisy data. Therefore, this type of geochemical reaction may not be too important for monitoring of sequestration eorts.