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Because of autogenous shrinkage of cement and the subsequent reduction in radial contact stress between the borehole wall and the cement, a micro-annulus may develop that creates a pathway by which natural gas may rise outside the casing. This gas may become evident as sustained casing pressure (SCP) in the US, or in Canada as surface casing vent flow (SCVF) or as gas migration (GM), i.e., that which occurs outside the casing strings. GM may emit at ground surface as a greenhouse gas or penetrate shallow aquifers causing groundwater contamination. Several observers have noted that gas emissions recorded as surface casing vent releases display a pulsing or periodic nature, which is of consequence if such emissions are to be monitored. We hypothesize that these pulses are due to the formation of Taylor bubbles, i.e., gas slugs, which are created by the coalescence of small bubbles. Their displacement pressure is sufficient to overcome the capillary entry pressure posed by shallow aquifers and thus cause groundwater contamination.
Hydraulic fracturing (HF) may lead to practical stress management possibilities by creating opportunities to control stress redistribution, or protecting locations where high stresses pose a threat to operations. These possibilities have application in petroleum engineering as well as mining. Understanding naturally fractured rock (NFR) behavior leads to better predictions of rock mass response to HF treatment and induced fracture initiation and propagation. Natural fractures exist in many different states, are reactivated by stress and pressure changes, and have alterable mechanical properties (e.g. stiffness, shear strength), leading to complex behavior in shear, opening, and closing reactions to stress changes. This article presents some attempts to understand and address simulation of HF interacting with a NFR using the Distinct Element Method (DEM) to represent the NFR. To this end, a coupled hydro-mechanical analysis is applied via the Universal Distinct Element Code (UDEC™) software to model both rock and fracture behavior in the HF/NFR system. In the current study, a Voronoi tessellated continuum has been generated to evaluate the effect of the stress ratio on flow into the joints by changing the differential principal compressive stresses. Given the difference in in situ stresses, pore pressure distribution is monitored and the distribution of slip and opening of fractures at different stress field anisotropy is investigated during pressurized hydraulic injection. Based on simulations, pore pressure decreases in a uniform pattern around the injection point in the isotropic stress state; however, the pressure distribution tends to become strongly anisotropic under a stronger differential stress. In addition, both normal and shear displacements show an increasing trend toward anisotropy under stronger stress differences. Applications may ensue with better understanding, such that HF strategies for strongly differential stress fields may evolve to be substantially different than for near-isotropic stress fields, and similar conclusions may ensue for random NFR fabrics, compared to cases with strongly oriented natural fracture fabric.
: Knowledge of the in situ stress state is an essential element of a geomechanics study. Current methods of evaluating in situ stress are based on direct and indirect measurements on the centimeter to kilometer scale. A new core-based technique to estimate in situ stress magnitudes and orientations is tested in this study. The method is based on the nanometer to micrometer scale study of samples to identify nano-features and micro-features that have a direct or indirect relation to in situ stress magnitudes and orientations. A dense dolomite core was divided into three parts; each sample was loaded with a different uniaxial load ranging from 0-45MPa, and then scanning electron microscope (SEM) images were taken and analyzed for sections from each of the samples. More specifically, microcracks and micro-laminations were detected, classified, and quantified at the nano- to micro-scale. Lastly, the surface roughness of the sample sections was studied by taking advantage of Profilometer scanning microscope images in relation to the applied stress load. This paper details the experimental procedures used and the results obtained to date.
Abstract: This study focuses on productivity of low-permeability shallow biogenic gas reservoirs of the Upper Cretaceous Milk River Formation. This formation is one of the major producing intervals of biogenic gas in southeastern Alberta and southwestern Saskatchewan, Canada. We show in situ stress measurements for shallow depths in this region that indicate a cross-over between the vertical stress and minimum horizontal stress at about 370 m depth; shallower than 370 m, the vertical stress is the minimum principal stress. In situ stresses have a profound effect on the orientation of induced hydraulic fractures and stress information can be used to predict whether induced hydraulic fractures are vertical or horizontal. This information is helpful in designing an optimum completion strategy for multi-layered compartmentalized shallow reservoirs and on choosing the best assets to develop. A vertical in situ stress map is constructed for the top of the Milk River Formation to examine possible relationships between the overburden stress and the productivity of the Milk River Formation reservoirs. We demonstrate that a strong relationship exists between the in situ stress and productivity: better well performance is observed in the regions where the vertical stress is lowest. Hence, vertical in situ stress mapping is helpful to delineate areas of best productivity “sweet spots”.
Shafiei, A. (Department of Earth & Environmental Sciences, University of Waterloo) | Parsaei, H. (Department of Systems Design Engineering, University of Waterloo) | Dusseault, M.B. (Department of Earth & Environmental Sciences, University of Waterloo)
Large hydrocarbon reserves are trapped in fractured reservoirs where fluid flux is far more rapid along fractures and joints than through the porous matrix, even though the matrix pore volume may be a hundred times greater than the fractures’ pore volume. Accurate recovery prediction in these reservoirs is challenging because of complexity and heterogeneity. Transport properties of the interconnected fractures in such reservoirs are severely affected by production and injection activities that change pore pressures, temperatures, saturations, and effective stresses. Reservoir geomechanics thus must take a significant role in the management of such reservoirs, considering coupled flow-geomechanics responses of the reservoir rocks. In this paper, a coupling approach between fluid-flow and geomechanics in an isothermal continuum using a hybrid FDM/DDM is considered to model the influence of reservoir activities, such as fluid injection or production, on the permeability of partially closed fractures among impermeable matrix blocks. Fracture pressure, aperture, and horizontal and vertical stress variation in a single horizontal fracture is shown as an example for the FDM/DDM model. Also, a geomechanical sensitivity analysis is done to evaluate the effect of Young’s modulus, Poisson’s ratio, fracture normal stiffness, and contact porosity on the fracture pressure and aperture changes.
In reservoir flow analysis, physical processes such as transport (fluid, heat, chemical flux) and geomechanics (i.e. stress-deformation) should be simultaneously considered to account for important coupling effects. Coupled is required to analyze most natural processes, but uncoupled models may meet engineering needs in cases with one dominant physical phenomenon, such as conductive heat flow in hot dry rocks (HDRs) and fluid flow in shallow aquifers with moderate matrix compressibilities. Uncoupled models are insufficient to model oil and gas reservoir behavior in stress-sensitive cases such as tectonically stressed, massively compacting, or fractured reservoirs. In such cases, we must also deal with complexity and heterogeneity.
Production and injection rates in naturally fractured reservoirs are sensitive to pressure and temperature variations, and such reservoirs are also characterized by heterogeneity of fabric. In isothermal, non-reactive processes, pore pressure and deformation of fractures and matrix blocks are the dominant physical parameters in coupled fractured reservoir models. Injection and production are associated with pore pressure changes which induce matrix and fracture deformation. As a result, fracture deformation affects fracture permeability more than the other petrophysical properties.
Conventional reservoir simulators consider pore compressibility as the only geomechanical parameter with a pressure-dependent porosity and permeability. From the discussion, this assumption is insufficient for fractured reservoir simulation as fracture permeability is a strong function of effective stress and pressure (ΔT = 0). In this paper, a hydro-mechanical (HM) coupled approach is used to model fracture behavior in an impermeable matrix block under fluid injection. Hydro-mechanical coupling is based on the concept of effective stress, introduced by Terzaghi (1923) in his one-dimensional consolidation theory. His work was generalized by Biot (1941) into a three-dimensional theory of consolidation, later called the “Theory of Poroelasticity”. This work was oriented toward rock mechanics rather than fluid flow, so there remain issues in the application of Biot’s theory to conventional fluidflow models.