Production from unconventional gas resources (UGRs) has received great attentions because of their large reserves as well as technical advances in developing these reservoirs. The fluid flow in ultralow permeability porous media cannot be considered in the range of conventional Darcy flow as it undergoes a transition from a Darcy regime to slip flow and free molecule flow regimes. Understanding fluid flow inside the matrix and how the matrix permeability evolves over depletion are among the major challenges to unconventional gas reservoirs characterization. Considering different flow regimes in UGRs and time dependent permeability during the production of reservoir, the applicability of the availabe numerical simulatior to predict the production from unconventional reservoirs is questionable.In this paper, a numerical approach is proposed for simulation of gas production of UGRs including geomechanical effect, slippage effect and non-Darcy flow. In this simulation, gas production is calculated using a pseudo-pressure integral for well inflow performance and material-balance for reservoir depletion. The numerical approach has been verified by comparing with the results of fine-grid compositional simulation for a typical conventional gas reservoir. The pseudo pressure-integral has been extended to include the geomechanical effect and time dependent matrix permeability. The flow regime is distinguished by Knudsen number for each regions of the reservoir during the reservoir depletion.According to the numerical results, the matrix permeability changes depending on the flow regime determined by Knudsen dimensionless number. Slip flow and Knudsen diffusion which are dependent on net pore pressure can play important roles in the gas production. Higher-than-expected matrix permeability becomes more highlighted when the permeability of the matrix decreases and dimensionless Knudsen number is higher than 0.1. This higher permeability enhances the gas production. On the other side, the matrix permeability decrease as the net overburden stress increases during the production life of the reservoirs. This decrease in matrix permeability clearly decreases the rate of gas production.The presented numerical simulation evaluates the significance of different flow regimes, time dependent permeability and geomechnical effect in production from UGRs. It also offers a rapid and simple tool for prediction of gas deliverability of UGRs well.
Simulation of many enhanced oil recovery (EOR) methods such as water alternative gas (WAG) requires accurate determination of relative permeability (kr) data under different saturation histories. Relative permeability is a function of several factors such as wettability, spreading coefficient and fluid pore occupancy. Experimental measurements of three phase kr data are time consuming and difficult considering infinite possible flow paths in the three-phase flow regime. There are several models in the literature to estimate the oil relative permeability data in three phase systems (3P-Kr models). However, the available models can not accurately estimate the oil production in low oil saturation region observed in WAG experiments. In this paper, Stone I model has been modified to improve the estimation of oil kr data. To this aim, the behaviors of three phase flow in immiscible and near miscible WAG experiments were considered. It was shown that the Stone model overestimates the oil relative permeability data in the low oil saturation regions. In addition, it was revealed that Stone's exponent model cannot simulate the gradual decreace in the oil kr data. To improve the results, a new coefficient is incorporated into the model to consider the impacts of the disconnected oil clusters during the cyclic injection. In addition, the end-of-cycle residual oil saturation (Som), which was required based on the Stone model, is no longer needed in this modified model.
The saturation history dependent relative permeability (kr) data have been reported frequently in the laboratory investigations. Accurate estimation of kr data with hysteresis effects is crucial, specifically in Water Alternating Gas (WAG) injection which involves a sequence of drainage and imbibition cycles. Although there are a few methods to model the hysteresis effects in three-phase systems, the predicted values are still not adequate to simulate the hysteresis observed in experiments. In this study, a generalized three-phase hysteresis model was developed to simulate the observed hysteresis in the WAG experiments performed at Heriot-Watt University. It is discussed that the use of Land trapping coefficient in the hysteresis models is doubtful since it originates from the observed behaviour in two-phase systems which reach residual saturations. Hence, the new hysteresis model is developed based on innovative techniques to predict the oil and water saturation at the end of each injection cycle. Moreover, in the developed model, the formulations for estimation of hysteresis in water and gas kr data are updated to capture the observed behaviors in WAG experiments. The suggested hysteresis model was evaluated by comparing the simulation results with the available experimental data. The results showed that the developed model is able to simulate oil, water and gas production more accurately. Based on the results, the model can simulate the pressure behaviours observed in the experiments with dominated hysteresis. In addition, the developed model can predict the oil, water and gas saturations at the end of each cycle with higher accuracy compared to the available methods in the literature. The significant impacts of the hysteresis phenomenon on designing the best WAG injection scenario require a reliable hysteresis model for performing accurate reservoir simulations. The use of the suggested model elevates the accuracy of any feasibility analysis performed to evaluate the WAG injection scenario.
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