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At South Arne a highly repeatable time-lapse seismic survey (normalized root-mean-square error or NRMS of less than 0.1) allowed us to reliably monitor reservoir production processes during five years of reservoir depletion. Time-lapse AVO (amplitude v. offset) inversion and rock-physics analysis enables accurate monitoring of fluid pathways. On the crest of the field, water injection results in a heterogeneous sweep of the reservoir, whereby the majority of the injected water intrudes into a highly porous body. This is in contrast to a pre-existing reservoir simulation model predicting a homogeneous sweep. On the SW flank, time-lapse AVO inversion to changes in water saturation Δ S w reveals that the drainage pattern is fault controlled. Time-lapse seismic data furthermore explain the lack of production from the far end of a horizontal producer (as observed by production logging), by showing that the injected water does not result in the expected pressure support. On the highly porous crest of the reservoir compaction occurs. Time-lapse time shifts in the overburden are used as a measure for compaction and are compared with predictions of reservoir compaction from reservoir geomechanical modelling. In areas where compaction observations and predictions disagree, time-lapse seismic data give the necessary insight to validate, calibrate and update the reservoir geomechanical model. The information contained in time-lapse seismic data can only be fully extracted and used when the reservoir simulation model, the reservoir geomechanical model and the time-lapse seismic inversion models are co-visualized and available in the same software application with one set of coordinates. This allows for easy and reliable investigation of reservoir depletion and gives deeper insight than using reservoir simulation or time-lapse seismic individually.

The paper addresses the modeling of geomechanical effects induced by reservoir production and their influence on fluid flow in the reservoir. Geomechanical effects induced by reservoir production can be particularly pronounced in stress sensitive reservoirs, such as poorly compacted reservoirs and fractured reservoirs. The authors review the main coupled mechanisms associated with the production of these reservoirs, and describe the different approaches that can be used to solve the coupling between fluid flow and geomechanical problems. A field case study is then presented. A stress dependent reservoir simulator-ATH2VIS-was used to quantify effects associated with the production of a highly heterogeneous and compartmentalized limestone reservoir. This simulator relies on a partial coupling approach with different time steps for reservoir and geomechanical simulations and manages data exchanges at given time intervals between the ATHOSTM reservoir simulator developed at IFP and the VISAGETM geomechanical simulator (VIPS Ltd. , 2001). The results of the coupled reservoir geomechanical simulations indicate that perturbation of the reservoir mechanical equilibrium specifically leads to progressive strain localization on a limited number of faults. Only specific parts of these faults are critically stressed, depending on pore pressure variations in their vicinity, temperature variations, and fault strikes compared with stress orientation. The normal strains resulting from geomechanical computations are interpreted in terms of permeability variations using a fracture and fault permeability model to improve the dynamic description of fluid flow and history matching.

We employ numerical stress simulation techniques to evaluate the most likely present-day geomechanical scenario. This is performed on seismic-driven elastically-heterogeneous models, which are then used to predict potential wellbore stability hazards on large spatial scales. We present an example of this approach in a field of the Gulf of Mexico. A post-processing stage is used to generate a series of geomechanical attributes that provide insights on the optimum operational parameters for well placement and drilling stability.

Fracture models, including connected fracture networks, fracture corridors, unconnected fractures and nonconductive fractures, are presented, using different dual-permeability models that have been developed. To simulate the dynamic response of fractured reservoirs, the opening of nonconductive fractures is simulated based on either fracture dilation due to shearing or fracture opening due to tensile failure. Once the opening of nonconductive fractures occurs, the permeability of all fractures (both conductive and nonconductive) changes dynamically according to the changes in the effective stresses that occur due to reservoir depletion and/or injection. Dual-permeability reservoir models developed on the basis of the proposed fracture models improve reservoir simulations. The newly developed dual-permeability modeling was applied to produced-water reinjection scenarios in a field in Southeast Asia and realistically simulated the dynamic behavior of the reservoir during injection. Such modeling reveals the ongoing interaction among pressure, rate, permeability, and deformation in the reservoir. This approach assists in the design of an optimal water-injection schedule to maximize production with a reduced risk of cap rock damage and water leakage into overburden.

Time-lapse seismic timeshifts are now widely used to study reservoir compaction. This is possible since (overburden) time-lapse timeshifts can be attributed to compaction-induced overburden stretching, increasing the length of the seismic ray-path, and associated velocity slowdown. Both path-length increase and velocity slowdown cause an increase in traveltime in a seismic monitor survey compared to a base-line survey.

Oil/gas exploration is an expensive, high-risk operation. The understanding of the stress regime and geological structures in a field plays a critical role in selecting exploration wells to determine the presence or absence of oil/gas in field exploration.