Model for Determining Average Reservoir Pressure for Gas Reservoirs from Variable Rate Drawdown Test Data Using Direct Synthesis Method

Abstract Accurate estimation of average reservoir pressure is vital for calculating reserves, improving well performance, planning and assessing water flooding, implementing enhanced oil recovery (EOR) techniques, and executing effective pressure management strategies. Traditional methods for determining average reservoir pressure typically rely on pressure buildup test data obtained during well tests. However, these conventional techniques present significant challenges. They often require extended shut-in periods, which can result in the loss of valuable production time and incur substantial economic costs for operators. In gas wells producing significant quantities of water, prolonged shut-ins may lead to irreversible formation damage, further complicating the process. Moreover, estimating average reservoir from drawdown test using pseudosteady-state pressure equations are based on constant rate assumptions. This paper presents an improved method for estimating average reservoir pressure using variable rate drawdown test data. The existing conventional method was enhanced using the direct synthesis technique to account for continuously changing flowrate and the pressure dependent behaviour of gas properties by employing the pseudotime and pseudopressure term and its derivative together with equivalent time principle. This paper applies the use of characteristic points on a log log plot of normalised pseudopressure and pseudopressure derivatives vs equivalent pseudotimesuch to estimate average reservoir pressure from variable rate drawdown test data. The results of this paper showed that this method was effective in estimating average reservoir from variable rate drawdown tests in gas reserviors. This paper will benefit reservoir engineers in making informed decisions regarding extraction techniques and overall reservoir management.