A. J. L. Crook

Reservoir stress path characterization and its implications for fluid-flow production simulations

ABSTRACT The reduction of fluid pressure during reservoir production promotes changes in the effective and total stress distribution within the reservoir and the surrounding strata. This stress evolution is responsible for many problems encountered during production (e.g. fault reactivation, casing deformation). This work presents the results of an extensive series of 3D numerical hydro-mechanical coupled analyses that study the influence of reservoir geometry and material properties on the reservoir stress path. The stress path is defined in terms of parameters that quantify the amount of stress arching and stress anisotropy that occur during reservoir production. The coupled simulations are performed by explicitly coupling independent commercial geomechanical and flow simulators. It is shown that stress arching is important in reservoirs with low aspect ratios that are less stiff than the bounding material. In such cases, the stresses will not significantly evolve in the reservoir, and stress evolution occurs in the over- and sideburden. Stiff reservoirs, relative to the bounding rock, exhibit negligible stress arching regardless of the geometry. Stress anisotropy reduces with reduction of the Youngs modulus of the bounding material, especially for low aspect ratio reservoirs, but as the reservoir extends in either or both of the horizontal directions, the reservoir deforms uniaxially and the horizontal stress evolution is governed by the Poissons ratio of the reservoir. Furthermore, the effect of the stress path parameters is introduced in the calculation of pore volume multiplier tables to improve non-coupled simulations, which otherwise overestimate the average reservoir pore pressure drawdown when stress arching is taking place.

Direct and Inverse Methods for Determining Gas Flow Properties of Shale

Gas flow in shale is a poorly understood and potentially complex phenomenon. It is currently being investigated using a variety of techniques including the analysis of transient experiments conducted on full core and crushed shale using a range of gases. A range of gas flow mechanisms may operate including continuum flow, slippage, transitional flow and Knudsen diffusion. These processes as well as gas sorption need to be taken into account when interpreting experimental data and extrapolating the results to the subsurface. A finite volume method is developed in this paper to mathematically model gas flow in shale. The finite volume method combines the efficiency/simplicity of finite difference methods with the geometric flexibility of the finite element approach. The model is applicable to non-linear diffusion problems, in which the permeability and fluid density both depend on the scalar variable, pressure. The governing equation incorporates the Knudsen number, allowing different flow mechanisms to be addressed, as well as the gas adsorption isotherm. The method is validated for unsteady-state problems for which analytical or numerical solutions are available. The method is then applied for solving a pressure-pulse decay test and a comparison with an alternative finite-difference numerical solution is made. An inverse numerical formulation is generated, using a minimisation iterative algorithm, to estimate different number of unknown parameters. Both numerically simulated noisy and experimental data are input into the formulation of the inverse problem. Error analysis is undertaken to investigate the accuracy of results. A good agreement between inverted and exact parameter values is obtained. Results for inversions done for practical laboratory pressure-pulse decay tests of samples with very low permeability are also presented.

Linking Coupled Fluid-Flow and Geomechanical Models with Rock Physics Derived Elastic Models for Reservoir Seismic Forward Modelling Applications

D006 Linking Coupled Fluid-Flow and Geomechanical Models with Rock Physics Derived Elastic Models for Reservoir Seismic Forward Modelling Applications D.A. Angus* (University of Bristol) J.M. Kendall (University of Bristol) Q. Fisher (University of Leeds) M. Dutko (Rockfield Software Ltd) A.J.L. Crook (Rockfield Software Ltd) S.A. Hall (CRNS Grenoble) & J. Verdon (University of Bristol) SUMMARY In this study we present some results on linking coupled fluid-flow and geomechanical modelling with seismic modelling. This work represents some of the research being conducted for the IPEGG (Integrated Petroleum Engineering Geomechanics and Geophysics) consortium a research partnership between the University of Bristol University

Hydro-mechanical modelling of stress, pore pressure and porosity evolution in fold-and-thrust belt systems.

We present coupled, critical state, geomechanical-fluid flow simulations of the evolution of a fold-and-thrust belt in NW Borneo. Our modelling is the first to include the effects of both syntectonic sedimentation and transient pore pressure on the development of a fold-and-thrust belt. The present-day structure predicted by the model contains the key first order structural features observed in the field in terms of thrust fault and anticline architectures. Stress predictions in the sediments show two compressive zones aligned with the shortening direction located at the thrust front and back limb. Between the compressive zones, near to the axial plane of the anticline, the modelled stress field represents an extensional regime. The predicted overpressure distribution is strongly influenced by tectonic compaction, with the maximum values located in the two laterally compressive regions. We compared the results at three notional well locations with their corresponding uniaxial strain models: the 2D thrust model predicted porosities which are as much as 7.5% lower at 2.5 km depth and overpressures which are up to 6.4 MPa higher at 3 km depth. These results show that one-dimensional methods are not sufficient to model the evolution of pore pressure and porosity in contractional settings. Finally, we performed a drained simulation during which pore pressures were kept hydrostatic. The predicted geological structures differ substantially from those of the coupled simulation, with no thrust faulting. These results demonstrate that pore pressure is a key control on structural development.

Reservoir stress path and induced seismic anisotropy: results from linking coupled fluid-flow/geomechanical simulation with seismic modelling

Abstract We present a workflow linking coupled fluid-flow and geomechanical simulation with seismic modelling to predict seismic anisotropy induced by non-hydrostatic stress changes. We generate seismic models from coupled simulations to examine the relationship between reservoir geometry, stress path and seismic anisotropy. The results indicate that geometry influences the evolution of stress, which leads to stress-induced seismic anisotropy. Although stress anisotropy is high for the small reservoir, the effect of stress arching and the ability of the side-burden to support the excess load limit the overall change in effective stress and hence seismic anisotropy. For the extensive reservoir, stress anisotropy and induced seismic anisotropy are high. The extensive and elongate reservoirs experience significant compaction, where the inefficiency of the developed stress arching in the side-burden cannot support the excess load. The elongate reservoir displays significant stress asymmetry, with seismic anisotropy developing predominantly along the long-edge of the reservoir. We show that the link between stress path parameters and seismic anisotropy is complex, where the anisotropic symmetry is controlled not only by model geometry but also the nonlinear rock physics model used. Nevertheless, a workflow has been developed to model seismic anisotropy induced by non-hydrostatic stress changes, allowing field observations of anisotropy to be linked with geomechanical models.

Influence of fault transmissibility on seismic attributes based on coupled fluid‐flow and geomechanical simulation

In this study, we present results from linked fluid–flow, geomechanical and seismic modeling to examine the influence of fault transmissibility on seismic attributes. The model is a graben structure with two normal faults subdividing a sandstone reservoir into three compartments. The predicted seismic traveltime differences are consistent with reservoir compaction and overburden extension. For the case of high transmissibility we observe a large spatial extent in traveltime anomalies as well as a fault related stress guide effect. For lower transmissibilities, the influence of production on seismic attributes becomes more localized around the well reservoir compartment. Anisotropy predictions show perturbations associated with the faults as well as the production induced stress redistribution in the overburden.

Stresses, Porosity and Overpressure Modelling in Tectonic Regimes

Pore pressure prediction in shales is typically addressed using 1D compaction methods. However, this approach is only valid in basins where disequilibrium compaction is the dominant overpressure generation mechanism. For basins subjected to tectonic deformation, the predictions made by 1D methods are likely to be deficient due to the impact of lateral stresses on compaction and overpressure generation. In this research, we use a coupled fluid flow-geomechanical approach that accounts for the full 3D stress tensor to model the mechanical compaction of mudstones where tectonic regimes are significant. We use a 2D plain strain column to investigate the effect of different factors of basin burial and tectonic histories on stress, porosity and overpressure. From the different cases analysed the models predicted an increase in overpressure of up to 16 MPa at 3.5 km dept and a porosity loss of up to 6 porosity units due to the tectonic deformation.

Finite Volume Method for Modelling Gas Flow in Shale

Gas flow in shale is a complex phenomenon and is currently being investigated using a variety of modelling and experimental approaches. A range of flow mechanisms need to be taken into account when describing gas flow in shale including continuum, slip, transitional flow and Knudsen diffusion. A finite volume method (FVM) is presented to mathematically model these flow mechanisms. The approach incorporates the Knudsen number as well as the gas adsorption isotherm, allowing different flow mechanisms to be taken into account as well as methane sorption on organic matter. The approach is applicable to non-linear diffusion problems, in which the permeability and fluid density both depend on the scalar variable, the pressure. The FVM is fully conservative, as it obeys exact conservation laws in a discrete sense integrated over finite volumes. The method is validated first on unsteady-state problems for which analytical or numerical solutions are available. The approach is then applied for solving pressure-pulse decay tests and a comparison with an alternative finite element numerical solution is made. Results for practical laboratory pressure-pulse decay tests of samples with very low permeability are also presented.