Modeling Fracture Fluid Cleanup in Tight Gas Wells Conference Paper uri icon


  • ABSTRACT On occasion, a hydraulically fractured tight gas well does not perform up to its potential because of slow or incomplete fracture fluid cleanup. A number of papers have been written to address individual factors related to fracture fluid cleanup, but there are still many unanswered questions as to which factors mostly affect gas production from such wells. Numerical reservoir simulation is one of the best methods to study the fracture fluid cleanup problem. Continuing from our previous publication (SPE 117444) on the impact of gel damage on fracture cleanup, we used reservoir simulation to analyze systematically the factors that affect fracture fluid cleanup and gas recovery from tight gas wells. We first developed a comprehensive data set for typical tight gas reservoirs, and then ran single-phase flow cases for each reservoir and fracture scenario to establish the idealized base-case gas recovery. We then systematically evaluated the following factors: multiphase gas and water flow, proppant crushing, polymer filter cake, and finally yield stress of concentrated gel in the fracture. The gel in the fracture is concentrated due to fluid leakoff during the fracture treatment. We evaluated these factors additively in the order listed. We found that the most important factor that reduces fracture fluid cleanup and gas recovery is the gel strength of the fluid that remains in the fracture at the end of the treatment. This paper illustrates the complexity of the fracture fluid cleanup problem and points out the need to use reservoir simulation and to include all the pertinent factors in order to rigorously model fracture fluid cleanup. The procedures presented can provide a useful, systematic guide to engineers in conducting a numerical simulation study of fracture fluid cleanup. INTRODUCTION A tight gas reservoir is a low-porosity, low-permeability formation that must be fracture treated to flow at economic gas rates and to recover economic volumes of gas. As the propped fracture length increases, the well will produce more gas at higher flow rates provided that adequate fracture conductivity is also created. Hydraulic fractures usually increase well productivity by a factor of 36 with a successful treatment. Because tight gas reservoirs have low permeability (> 0.1 md), the key to produce gas at economic flow rates is to create a long, highly conductive flow path (a hydraulic fracture) to stimulate flow from the reservoir to the wellbore. To maintain conductivity in the fracture, sufficient quantities and qualities of propping agent need to be pumped into the fracture. To carry high concentrations of proppant deep into the fracture, we use viscous fluids and/or pump the fluids at high injection rates. However, these same viscous fluids need to break back to thin fluids after the treatment is over so that the fracture fluid can clean up. For either water or gel fracture treatments, fracture fluid cleanup has a significant impact on the treatment effectiveness and well productivity. This issue was present with early fracture treatments in the 1950s, and it is still here in 2008.

name of conference

  • SPE Hydraulic Fracturing Technology Conference

published proceedings

  • All Days

author list (cited authors)

  • Wang, J. Y., Holditch, S. A., & McVay, D.

citation count

  • 15

complete list of authors

  • Wang, John Yilin||Holditch, Stephen A||McVay, Duane

publication date

  • January 2009