Shayan Tavassoli

Well Screen and Optimal Time of Refracturing: A Barnett Shale Well

Gas-production decline in hydraulically fractured wells in shale formations necessitates refracturing. However, the vast number of wells in a field makes selection of the right well challenging. Additionally, the success of a refracturing job depends on the time to refracture a shale-gas well during its production life. In this paper we present a numerical simulation approach to development of a methodology for screening a well and to determine the optimal time of refracturing. We implemented our methodology for a well in the Barnett Shale, where we had access to data. The success of a refracturing job depends on reservoir characteristics and the initial induced fracture network. Systematic sensitivity analyses were performed so that the characteristics of a shale-gas horizontal well could be specified as to the possibility of its candidacy for a successful refracturing job. Different refracturing scenarios must be studied in detail so that the optimal design might be determined. Given the studied trends and implications for a production indicator, the optimal time for refracturing can then be suggested for the studied well. Numerical-simulation results indicate significant improvement (on the order of 30%) in estimated ultimate recovery (EUR) after refracturing, given presented screen criteria and optimal-time selection.

Selection of Candidate Horizontal Wells and Determination of the Optimal Time of Refracturing in Barnett Shale (Johnson County)

The observed uneconomic production performance in many shale gas horizontal wells suggests refracturing as a restimulation treatment to revive economic gas production. To achieve high-performance re-stimulation, it is critical to select the right well among many other wells in the area and determine the proper time of refracturing. Well selection is challenging in shale gas horizontal wells because of the complexity of natural and induced fracture networks and in many cases due to insufficient reservoir and completion data. Selection of the candidate well and the time of refracturing can be made based on a thorough numerical simulation study developed by precise modeling of hydraulic fractures and refracturing process. Accurate modeling can only be accomplished by considering formation of fracture networks. Induced fracture networks are formed by an altered stress-field as a consequence of the fracturing process and are evidenced by micro-seismic hydraulic fracture monitoring techniques. Tavassoli et al. (2013) modeled gas production of a refractured well in the Barnett formation and validated their simulation methodology with the available field data. The validated model was used to predict gas production after refracturing the well. They then performed systematic sensitivity analyses to specify the characteristics of shale gas horizontal well suitable for refracturing and defined well screening criteria and optimal time of refracturing. In this study we extend their original work to study 188 horizontal wells in Barnett (Johnson County) to identify wells with potentials for refracturing. We found that among these 188 wells only 11 wells are suitable for refracturing and the best time to perform hydraulic fracturing is between 31⁄2 to 51⁄2 years after initial production. Introduction Shale-gas resources are an ever-increasing component of North American gas supply. Based on Gas Technology Institute (GTI) study, shales are considered the largest component of Western Canadian Sedimentary Basin (WCBS) with an estimated cumulative hydrocarbon shale volume in the order of 86 tcf. WSB shales have many similarities to US shale producing reservoirs (Faraj et al. 2004; Shaw et al. 2006). Barnett is amongst the largest shale gas resources in the US. Determining the hydraulic fracturing potential in this formation will contribute to production enhancement in all other shale plays. The Barnett Shale is a Mississippian-age marine shelf deposit with estimated ultimate gas recovery of 1-10 Bcf/well. It extends over 3.2 million acres with a thickness of 100-600 ft. The formation has ultra-low permeability (in the range of 10100 nanodarcies), total porosity of 4-5%, total organic content of 4.5%, and estimated 50-200 Bcf/ft of original gas in place (Cipolla 2010a, Potapenko et al. 2009). These resources are predominantly lithified clays with low permeability and classified as unconventional gas reservoirs. Despite their extremely low-permeability, gas production from these resources is much greater than anticipated owing to non-Darcy flows and different sources of gas in their formations. Gas flow is sourced from stored gas in nanopore networks and adsorbed gas on organic materials in the shale formations (Javadpour et al. 2007; Javadpour 2009; Swami et al. 2012; Rubin 2010). Recent advances in directional drilling and hydraulic-fracturing techniques have resulted in economic production from shale-gas reservoirs. There have been more than 12,000 horizontal wells drilled in the Barnett Shale since 2001 (IHS 2013). Effective fracturing techniques make for successful economic production from extremely low (on the order of nanodarcies) permeability formations. New fracturing techniques significantly improve reservoir-wellbore connectivity by creating a large, stimulated reservoir volume (Warpinski et al. 2009; Soliman et al. 2012). Gas production from these reservoirs declines in the very first years of production after the initial fracturing due to fracture conductivity impairments. Closure stress and long-

Frontal-Stability Analysis of Surfactant Floods

Recent surfactant-flooding experiments have shown that very-efficient oil recovery can be obtained without mobility control when the surfactant solution is injected at less than the critical velocity required for a gravity-stable displacement. The purpose of this study was to develop a method to predict the stability of surfactant floods at the reservoir scale on the basis of gravity-stable surfactant-flooding experiments at the laboratory scale. The scaleup process involves calculation of the appropriate average frontal velocity for the reservoir flood. The frontal velocity depends on the well configuration. We have performed systematic numerical simulations to study the effect of key scaling groups on the performance of gravity-stable surfactant floods. We simulated 3D heterogeneous reservoirs by use of a fine grid and a third-order finite-difference method to ensure numerical accuracy. These simulations have provided new insight into the behavior of gravitystable surfactant floods, and in particular the importance of the microemulsion properties. The capability to predict when and under what reservoir conditions a gravity-stable surfactant flood can be performed at a reasonable velocity is highly significant. When a surfactant flood can be performed without polymer (or foam) for mobility control, cost and complexity are significantly reduced. Advantages are especially significant when the reservoir temperature is high and the use of polymer becomes increasingly difficult. Our simulations show that gravity-stable surfactant floods can be very efficient using horizontal wells in reservoirs with high vertical permeability.

Investigation of the Critical Velocity Required for a Gravity-Stable Surfactant Flood

Classical stability theory predicts the critical velocity for a miscible fluid to be stabilized by gravity forces. This theory was tested for surfactant floods with ultralow interfacial tension (IFT) and was found to be optimistic compared with both laboratory displacement experiments and fine-grid simulations. The inaccurate prediction of instabilities on the basis of available analytical models is because of the complex physics of surfactant floods. First, we simulated vertical sandpack experiments to validate the numerical model. Then, we performed systematic numerical simulations in two and three dimensions to predict formation of instabilities in surfactant floods and to determine the velocity required to prevent instabilities by taking advantage of buoyancy. The 3D numerical grid was refined until the numerical results converged. A third-order total-variation-diminishing (TVD) finite-difference method was used for these simulations. We investigated the effects of dispersion, heterogeneity, oil viscosity, relative permeability, and microemulsion viscosity. These results indicate that it is possible to design a very efficient surfactant flood without any mobility control if the surfactant solution is injected at a low velocity in horizontal wells at the bottom of the geological zone and the oil is captured in horizontal wells at the top of the zone. This approach is practical only if the vertical permeability of the geological zone is high. These experiments and simulations have provided new insight into how a gravity-stable, low-tension displacement behaves and in particular the importance of the microemulsion phase and its properties, especially its viscosity. Numerical simulations show high oil-recovery efficiencies on the order of 60% of waterflood residual oil saturation (ROS) for gravity-stable surfactant floods by use of horizontal wells. Thus, under favorable reservoir conditions, gravity-stable surfactant floods are very attractive alternatives to surfactant/polymer floods. Some of the world’s largest oil reservoirs are deep, high-temperature, high-permeability, light-oil reservoirs, and thus candidates for gravity-stable surfactant floods.