Abstract

In this paper, we analyze and simulate the production data before and after an extended shut-in period from a horizontal well completed in the Montney Formation. After flowback and early post-flowback production, the well was shut-in for 7 months due to facility completion. When the well was reopened, the hydrocarbon production rates increased significantly compared to the values before the shut-in. To investigate the reasons behind this enhancement, we simulated three-phase production rates and bottom-hole pressure using the actual reservoir geological model.

To match the production data before the shut-in period, we had to account for the reduction in oil and gas relative permeabilities due to water blockage. This was done by using multipliers of interblock fluid-flow transmissibility near the matrix-fracture interface. We used these transmissibility multipliers as matching parameters, to achieve the match between measured and simulated production data. However, the best history match was achieved, when the values of transmissibility multipliers are increased by 6.5 times after the shut-in. This suggests a significant increase in oil and gas relative permeabilities due to reduction in water blockage near fracture-matrix interface during the extended shut-in period. Since the simulation model was not able to capture the imbibition process controlled by different driving forces, we used transmissibility multipliers to mimic this phenomenon and its corresponding effects on production rates. In addition, we performed sensitivity analyses to investigate the effects of shut-in on the well productivity and economic profitability in terms of net present value (NPV). The results show that for this well, a 6-month shut-in period is optimal for maximizing NPV and hydrocarbon production.

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