We extend the multiphase flowing material balance (FMB) method proposed by Thompson & Ruddick (2020) to multi-well problems, i.e., multiple wells draining one reservoir volume. As in the original method, analysis of well groups for the total pore volume drained and initial in-place volumes relies only on commonly available production data as well as black oil PVT data.
Estimation of original hydrocarbons in place is a fundamental responsibility of a practicing reservoir engineer and is essential for constraining production forecasts and reserves estimates within physically reasonable bounds. In traditional reservoir engineering, most non-empirical reserves estimation techniques are based on single-phase pseudo-steady-state flow theory. Many researchers have extended these single-phase techniques to multiphase flow through the introduction of pseudo-pressure and pseudo-time transformations. For multiphase flow, definition of these transformations is not unique, and different researchers have proposed alternative methods of computing pseudo-functions with varying degrees of success. A major difficulty with the pseudo-function approach is that a relative permeability-saturation model must be selected for the system of interest; in our experience, system relative permeability curves are seldom known.
Most modern wells drilled and completed in tight unconventional reservoirs communicate, or interfere, with other offset wells, however, few methods exist to deal with the combination of multiphase flow and multiple well problems. Our proposed method addresses both these issues. We illustrate the method by applying it to both synthetically generated data and actual field data form the Permian basin.
Flowing material balance (FMB) techniques can be used to estimate a well’s contacted pore volume from production and PVT data. Accurate determination of this volume is crucial for the planning and optimization of production from oil and gas reservoirs. In complex reservoirs, such as those with multiple wells producing in close proximity to each other, it can be challenging to accurately estimate this due to well interference.
In this paper, we aim to extend the multiphase flowing material balance method developed by Thompson & Ruddick (2022) to account for well interference and adjust the drainage volume as operating conditions change. Our motivation stems from the observation that many wells appear to share drainage volume with their neighbors, and their production performance can be influenced by each other.
