Abstract Estimating average-reservoir pressure (pav) and its evolution with time is critical to analyzing and optimizing reservoir performance. Conventionally, selected wells are shut in periodically for buildup tests to determine pav over time. Unfortunately, shutting-in wells leads to loss of production. Today, however, real-time surveillance—the continuous measurement of flowing pressures and rate data from the oil and gas wells—offers an attractive alternative technique to obtain average-reservoir pressure while avoiding revenue loss. A direct method for estimating pav from flowing pressures and rate data is available. However, the method is for an idealized case that assumes constant production rate during pseudosteady-state (PSS) flow, which is not generally true for real wells. This paper extends that approach so that it can be used to analyze field data with variable rates/variable pressure during PSS flow. This approach is based on a combination of rate-normalized pressure and superposition-time function. The mathematical basis is presented in support of this approach, and the method is validated with synthetic examples and verified with field data. This modified approach is used to make direct estimation of average-reservoir pressure that uses flowing pressures and production rates during PSS flow, allowing the classical material balance calculations to be performed. These calculations, in turn help determine the reserves, recovery factor, and reservoir drive mechanisms, allowing the reservoir performance and management to be properly evaluated. Furthermore, this method can be used to calculate both connected oil volume and reservoir drainage area as a function of time. Finally, this approach provides a reasonable estimation of the reservoir's shape factor.