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Transient analytical solutions for temperature and pore pressure changes near a circular borehole under instantaneous temperature and fluid pressure changes inside the borehole are presented. The solutions couple conductive heat transfer with Darcy fluid flow, and a borehole under a nonhydrostatic far-field stress state is simulated. The heat conduction equation is decoupled from the coupled system of isothermal governing equations, and the complete solution is obtained by superimposing this decoupled solution on the isothermal one. The solution is therefore applicable to low-permeability media, where heat transfer is dominated by conduction only. Both cold and warm injection processes are studied, and the applications to hydraulic fracture initiation and thermally induced fluid flow are discussed. Taking Westerly granite as an example, it is concluded that the maximum thermally induced pore pressure inside the rock formation can be 30% higher than the isothermal pore pressure, with a borehole temperature and fluid pressure change ratio (AT/Ap) = IøC/MPa. It is emphasized that the thermally induced pore pressure change can be significant inside a low-permeability porous medium, and a coupled solution must be obtained to address the mechanical, hydraulic, and thermal responses appropriately.

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.

Continuous sand production and foamy oil behavior are both believed to be key factors for the enhanced non-thermal fluid production in unconsolidated heavy oil reservoirs in Canada (Alberta and Saskatchewan). The same mechanisms are likely to be active in similar heavy oil strata in Venezuela (Faja del Orinoco), Oman, China (Bohai Bay), and elsewhere. Field experience indicates that fundamental understanding of sand production mechanisms, reservoir fabric alteration, foamy oil behavior, pressure gradient changes, and stress changes are key to successful operations involving massive continuous sanding. Inter-relating these factors requires coupling of geomechanics and fluid flow processes. An integrated approach incorporating a three-phase, three-dimensional black-oil model coupled with a geomechanics model is introduced in this article. Piping channels ("wormholes") are postulated to develop from perforations when pressure gradients exceed the residual cohesion of the sand. An elastoplastic constitutive model is used to describe the reservoir material before seepage forces liquefy and suspend the sand particles at the advancing tips of wormholes. The hemispherical wormhole tip is postulated to propagate as long as a critical tip pressure gradient is exceeded. A slurry transport model is used to describe the flow inside the wormholes. Field data from Frog Lake, Alberta are used to validate the model, and it appears that the simulation can match the field data remarkably well. Introduction Enhanced heavy oil production can be achieved by heating, which reduces oil viscosity and facilitates flow. However, because CH4 is commonly used to generate steam, thermal operating costs are high and rising (CDN$10–15/bbl). It is less well-known that under the right conditions formation flow characteristics can be improved through non-thermal massive sand co-production, referred to as CHOP (Cold Heavy Oil Production). CHOP has been widely used for a decade in Alberta and Saskatchewan,1,2,3,4,5,6,7,8 and operating costs have now been cut to CDN$4–7/bbl. However, poor understanding of the CHOP process, a recovery rate limited to ~12–20% in appropriately screened reservoirs, and difficulties in well management (i.e. repeated workovers) have been weak points for this technology. Improving these aspects, particularly the understanding of CHOP mechanisms, can lead to direct economic benefits. This article introduces a model that includes reservoir fluid mobility changes arising from sanding and pressure drive changes arising from foamy-oil flow. Simulations are based on a general three-dimensional, three-phase, black-oil production model coupled to a one-dimensional slurry flow model. The latter represents the wormholes (or slurry transport zone), and the material balance for solids transport is established based on a two-dimensional classic geomechanics model. In the discussions to follow, comparisons are made between primary production without sand and production with sand influx allowed (CHOP).