Determining Effective Drainage Area for Tight Gas Wells
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 98035, "Determination of Effective Drainage Area for Tight Gas Wells," by S.A. Cox, R.P. Sutton, and R.P. Stoltz, Marathon Oil Co., and T. Knobloch, James Engineering Inc., prepared for the 2005 SPE Eastern Regional Meeting, Morgantown, WV, 14–16 September.
The effective drainage area of a tight gas well is controlled primarily by rock and fluid properties, reservoir geometry, and well-completion efficiency. This work focused on the relationship between effective gas permeability, porosity, reservoir geometry, and fracture half-length for dry-gas reservoirs.

Introduction
The effective drainage area of tight gas reservoirs can be determined best with production analysis. Two methods of determining the effective area for dry-gas reservoirs were studied. In tight gas reservoirs (reservoirs with effective gas permeability less than 0.1 md), a significant amount of time is required before the pressure transient is affected by all of the boundaries of the reservoir. The no-flow boundaries affecting the well's pressure-transient behavior can be physical or caused by offset production. Therefore, the effective drainage area of a tight gas producer will be a function of natural boundaries, drilled-well spacing, effective gas permeability, and completion efficiency.
The efficient well spacing for tight gas producers can be defined in many ways. For the purpose of this paper, efficient spacing is the well spacing required to attain 80% recovery of the gas in place over a 30-year life. An alternative definition was the well spacing required to maximize the well's 30-year recovery. However, these cases resulted in very low recovery of the in-place volume.
For the same reservoir geometry, efficient well spacing increases with both permeability and fracture half-length. This work demonstrated that as a system becomes more linear in nature, the effective drainage area is reduced for the same reservoir and completion parameters.

Background
Determining the effective drainage area of a producing well was accomplished by first estimating the well's drainage volume. Then, this volume was used in the volumetric equation to estimate the well's drainage area. Both methods described below combine gas-material-balance and flow equations to estimate the well's effective drainage volume. The assumptions common to both methods are as follows.Well production rates and pressures are accurate.The flowing bottomhole pressure can be estimated accurately from surface pressures, if not measured.The reservoir drive mechanism is volumetric depletion.
The full-length paper details both methods.

El-Banbi and Wattenbarger Method
This method combines gas-material-balance and stabilized-flow equations for gas wells into an iterative method that can be used to estimate the drainage volume of a well during boundary-dominated flow (BDF). Results then can be combined with the reservoir properties in the volumetric equation to estimate the well's effective drainage area.
To perform the analysis, an initial-gas-in-place value is assumed, and the real-gas-pseudo pressure function is calculated and plotted vs. time. If the assumed in-place volume is too large, the plot will have a positive slope at late time. If the assumed volume is too small, the slope will be negative. The correct estimate of gas in place will result in a late-time slope of zero. If the system is evaluated during transient flow, the effective drainage area will be under-estimated and will increase through time. Once boundary-dominated flow is achieved, this method will predict the well's drainage volume accurately.