Coupled Reservoir-Geomechanics Model with Sand Erosion for Sand Rate and Enhanced Production Prediction

Abstract

A fully coupled reservoir-geomechanics model is developed to simulate the enhanced production phenomena both in heavy-oil reservoirs (i.e. Northwestern Canada) and conventional oil reservoirs (i.e. North Sea). The model is implemented numerically by fully coupling an extended geomechanics model to a two-phase reservoir flow model. A sand erosion model is postulated after the onset of sand production, which is determined based on the degree of plastic deformation inside the reservoir formation calculated by the coupled reservoir-geomechanics model. Both the enhanced production and the ranges of the enhanced or sanding zone are calculated, the effect of solid production on oil recovery and enhancement are analyzed. Field data for solid production and enhanced oil production from Frog Lake (Lloydminster, Canada) are used to validate the model for the sand rate and sand production. Our studies indicate that the enhanced oil production can be contributed by eitherthe a large-scale reservoir formation mobility improvement, (i.e. wormhole type model), bya higher fluid velocity due to the movement of the sand particles according to the modified Darcy's flow, or byan effective well radius increase or negative skin development due to sand erosion if formation does not permit an extensive erosional zone. Such an improvement on productivity reduces the near well pressure gradient so that the sanding potential is weakened, but permits an easier path for oil to flow into the well due to an enhanced permeability. Two-phase flow can affect pressure gradient and formation residual cohesion due to capillary pressure buildup. Indirectly, production enhancement strategy can be controlled by the water saturation distribution and development, as the success and economic value of a field operation can depend on if sand production can be induced or not. Such an analogy can also be used for a completion strategy by allowing a certain amount of sand production before gravel pack in high flow-rate reservoir. Introduction Sand production is a phenomenon that occurs during aggressive production induced by the in-situ stress concentration near a wellbore and perforation tips in poorly cemented formations. Such a solid production compromises oil production, increases completion costs, and reduces the life cycles of equipment down hole and on the surface. Sand production has been a major concern to production engineers for decades, either in poorly consolidated reservoirs or from those formation with cement. These sanding effects often are associated with high production rates, and the issue is becoming more critical these days as operators are following more aggressive production schedules. Sand production, on the other hand, has been proven a most effective way to increase well productivity both in heavy oil and light oil reservoirs1,7. A typical 4–10 fold increase in oil production is normal in heavy oil reservoirs (Cold Production)1,6, and up to a 44% increase in sand-free rate after a certain amount of sand production in conventional oil reservoirs has been reported8,9. For conventional oil producers, both enhanced production and improved sand-free rate are highly desirable. Whereas for the heavy crude operators, other than the improved productivity, operating cost reduction is vital for a profitable operation, because the price margin between heavy oil and light oil is high (this is particularly important for cold production operators in northwestern Canada). The costs associated with such an operation are usually a result of high work-over frequency, short PC-pump life, sand disposal vs. potential enhancement, in-filled drilling costs, pump down-time, and production decline after well shut-in, etc. In attempt to maximize oil production and minimize costs during cold production, operators depend on experience and empirical models to evaluate cold production performance because of the complex nature of the fluid/solid slurry flow processes involved. A quantitative model will allow producers to understand this unique production process, evaluate the impact of sand production on reservoir enhancement, and provide an efficient tool to reduce unnecessary costs during the field operations.

Experimental Investigation on Dilation Mechanisms of Land-Facies Karamay Oil Sand Reservoirs under Water Injection

“…Moreover, the value of p 0 was zero at the end of isotropic unloading, rendering any increase in pore pressure for measuring permeability problematic. Therefore, the permeability evolution caused by tensile parting was achieved based on other laboratory data through the Kozeny-Poiseuille correlation (Tortike and Farouq Ali 1993;Wang and Xue 2002;Du and Wong 2007):…”

Simulating Cold Production by a Coupled Reservoir-Geomechanics Model With Sand Erosion

“…Below a bubble point, free gases may be released from the oil phase, forming the so-called solution-gas phase (foamy oil) with a higher compressibility for the oil-gas mixture. The saturation of each component (oil or gas) in the solution-gas phase is changing with reservoir pressure in the foamy zone, which is presented in Tables for heavy oil 16 . This oil and gas ratio change inside the foamy phase under bubble point pressure does not change the relative permeability of the foamy oil phase, nor it will change the nature of the water/oil two-phase flow, as they remains as a single phase flow.…”

“…Significant error either on the pore pressure and deformation calculations can be induced if such a component is removed from the coupled formation 16 . Producing oil from poorly consolidated reservoirs when a large skeleton deformation is expected, the contribution of the solid velocity to the coupled flow system must be included.…”

“…Coupled Water/oil Phase Flow: For an oil/water twophase flow, an expansion of fluid mass balance equation gives 16 : can also be alternatively used 8,9,6, , in which the subscript 0 denotes to the initial states. Considering a simple two-phase system with water and oil, the gas-phase flow is assumed insignificant for a conventional oil case, but is defined as part of the foamy oil flow in heavy-oil reservoirs.…”

“…A formulation by Vardoulakis et al, on sand erosion 16 , is based on fundamental fluid/solid transport process for predicting the volumetric sand rate in a continuum framework. A coupled geomechanics model with a single-phase steady-state flow was also developed including the sand erosion model.…”