Estimated Ultimate Recovery (EUR) as a Function of Production Practices in the Haynesville Shale

Recent developments in well completion technologies have transformed the unconventional reservoir systems into economically feasible reservoirs. However, the uncertainty associated with production forecasts and non-uniqueness related with well/reservoir parameter estimation, are the main issues in future development of these reservoirs. In addition, recent operational methods such as restricting rates by decreasing the choke size add up to the uncertainty in production forecasts. This work attempts to investigate the effect of production practices on ultimate recovery. It is observed that wells producing in the Haynesville shale gas play exhibit severe productivity loss throughout their producing life. Production practices such as controlling the drawdown or restricting rates by decreasing the choke size are employed by several operators to deal with the severe productivity loss. In this work our main objective is to investigate the issues (such as stress dependent permeability, proppant embedment, operational problems, etc.) contributing to decreasing well productivity over time. In particular, from modeling standpoint, we focus on stress-dependent permeability as a mechanism, which affects well performance over time. Using a horizontal well with multiple fractures numerical simulation model coupled with geomechanics, we generate synthetic simulation cases including several drawdown scenarios. It is shown that high drawdown cases result in higher effective stress fields around the well and fracture system. We therefore infer that higher effective stress fields result in lower well productivity over time. Based on this hypothesis and diagnostics of field data, we model two different scenarios (i.e., high drawdown and low drawdown cases) for a horizontal well with multiple fractures using two different permeability decay functions and same well/formation model parameters. Our modelling results indicate that low drawdown case yields higher recovery suggesting that rate restriction could be a mitigating factor in decreasing well productivity over time. Introduction Hydrocarbon production from unconventional reservoir systems (e.g., tight gas sands, shale gas, tight/shale oil, etc.) has become significant in recent years due to recent advances in the technology allowing to drill and complete wells in these complex reservoir systems at lower costs. The developments in the technology to develop and produce complex unconventional reservoir systems such as shale gas reservoirs bring the difficulties and uncertainty associated with well performance. The uncertainty is mainly due to the lack of our complete understanding of the production mechanisms and behavior of these reservoir systems. And the difficulty is therefore associated with establishing the long term production decline in these reservoirs. In simple terms this study focuses on the factors affecting well performance and productivity in the Haynesville shale. Significant amount of natural gas has been produced from the Haynesville shale since 2008 and the Haynesville shale is considered as one of the largest natural gas fields in the United States. The Haynesville shale is a black, organic rich shale of Upper Jurassic age located in east Texas and northwest Louisiana, which is deposited with mainly heavier clay minerals, silica, and calcite. The depth of the Haynesville shale ranges from approximately 10,000 ft in the northwest part to 14,000 ft in the southeast (Buller et al. 2010). It is overpressured with pressure gradients higher than 0.9 psi/ft. Due to high reservoir pressure of the Haynesville shale, production practices has been shifted to control drawdown or to restrict the rates by the operators to avoid any damage occuring in the well/reservoir during production.