Pore-scale mechanisms of gas flow in tight sand reservoirs

Silin, D. ; Kneafsey, T.J. ; Ajo-Franklin, J.B. ; Nico, P.

关键词: 54;    58;    BRINES;    CONDENSATES;    DRAINAGE;    GAS CONDENSATES;    GAS FLOW;    GAS INJECTION;    GEOMETRY;    HEATING;    HYDROCARBONS;    MICROSCOPY;    NATURAL GAS;    PERMEABILITY;    POROSITY;    PRESSURE GRADIENTS;    PRESSURIZATION;    SANDSTONES;    SATURATION;    SCALARS;    TWO-PHASE FLOW;   

DOI  :  10.2172/1001046
RP-ID  :  LBNL-4103E
PID  :  OSTI ID: 1001046
Others  :  TRN: US201102%%393

美国|英语

来源: SciTech Connect

【 摘 要 】

Tight gas sands are unconventional hydrocarbon energy resource storing large volume of natural gas. Microscopy and 3D imaging of reservoir samples at different scales and resolutions provide insights into the coaredo not significantly smaller in size than conventional sandstones, the extremely dense grain packing makes the pore space tortuous, and the porosity is small. In some cases the inter-granular void space is presented by micron-scale slits, whose geometry requires imaging at submicron resolutions. Maximal Inscribed Spheres computations simulate different scenarios of capillary-equilibrium two-phase fluid displacement. For tight sands, the simulations predict an unusually low wetting fluid saturation threshold, at which the non-wetting phase becomes disconnected. Flow simulations in combination with Maximal Inscribed Spheres computations evaluate relative permeability curves. The computations show that at the threshold saturation, when the nonwetting fluid becomes disconnected, the flow of both fluids is practically blocked. The nonwetting phase is immobile due to the disconnectedness, while the permeability to the wetting phase remains essentially equal to zero due to the pore space geometry. This observation explains the Permeability Jail, which was defined earlier by others. The gas is trapped by capillarity, and the brine is immobile due to the dynamic effects. At the same time, in drainage, simulations predict that the mobility of at least one of the fluids is greater than zero at all saturations. A pore-scale model of gas condensate dropout predicts the rate to be proportional to the scalar product of the fluid velocity and pressure gradient. The narrowest constriction in the flow path is subject to the highest rate of condensation. The pore-scale model naturally upscales to the Panfilov's Darcy-scale model, which implies that the condensate dropout rate is proportional to the pressure gradient squared. Pressure gradient is the greatest near the matrix-fracture interface. The distinctive two-phase flow properties of tight sand imply that a small amount of gas condensate can seriously affect the recovery rate by blocking gas flow. Dry gas injection, pressure maintenance, or heating can help to preserve the mobility of gas phase. A small amount of water can increase the mobility of gas condensate.