Damage Mechanisms in Unconventional-Gas-Well Stimulation - New Look at an Old Problem
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 142479, ’Damage Mechanisms in Unconventional-Gas- Well Stimulation - A New Look at an Old Problem,’ by Josef Shaoul, SPE, StrataGen Delft; Lars van Zelm, SPE, Delft University of Technology; and Hans J. de Pater, SPE, StrataGen Delft, prepared for the 2011 SPE Middle East Unconventional Gas Conference and Exhibition, Muscat, Oman, 31 January- 2 February. The paper has not been peer reviewed.
After fracture stimulation, production often increases slowly instead of showing an early transient. This condition indicates either a severe reduction in fracture conductivity or reservoir damage. Little agreement exists about the most likely damage mechanism. New ideas were proposed that may better explain the behavior commonly observed in actual production data. These ideas include “permeability jail” in which relative permeability indicates that water and gas are both immobile at a given saturation, small-scale reservoir heterogeneity, and stress-sensitive matrix permeability at high drawdown. These effects on post-fracture production from an unconventional (0.001-md) gas well were studied by reservoir simulation. Realistic assumptions about proppant-pack cleanup showed a relation of poor cleanup and short effective fracture length to a reduction in contacted permeability-thickness (kh) and to connected reservoir volume. Simulation results showed 50% reduction of production in the first year(s) caused by these effects in unconventional reservoirs.
Introduction
Worldwide rising gas demand is creating opportunities to exploit low-permeability gas reservoirs outside North America, where a long history of tight-gas-reservoir development exists. In the absence of open natural fractures, economic development of tight gas reservoirs is possible only through the use of hydraulic fracturing, in either vertical or horizontal wells.
Production enhancement for any well, whether oil or gas, can be simulated by use of combined reservoir and fracture simulators. Generally, the well-productivity increase can be calculated to a certain degree. For tight gas wells, improved well productivity often is overestimated by simulation programs that use fracture characteristics estimated from fracture-simulation software. Several factors may result in unrealistic production forecasting. In tight reservoirs, it is very difficult to measure kh and reservoir pressure, which are needed for basic flow calculations and are crucial for evaluating stimulation success. The problem arises because of the long time required to measure these parameters in post-fracture well tests. Prefracture-treatment well tests also are time consuming, but have the further problem that it is difficult to know the height of the flowing zone, and it is not desirable to perforate the entire interval in a well that is going to be fracture stimulated. An additional problem in tight gas reservoirs is evaluating the performance of the propped fracture to optimize the stimulation design. Estimating productivity after stimulation requires use of estimated values for fracture dimensions (length, width, and height) and fracture conductivity, all of which are difficult to quantify from well-test or production data without an accurate estimate of the kh. Fracture diagnostics can provide an indication of the created height and length, but reveals nothing about the effective producing-fracture length or height. Estimating kh from diagnostic injection tests is possible, but this method suffers from not knowing the height of the formation being investigated.