Optimization of hydraulic fracture treatments and landing zone intervals within the Eagle Ford

Abstract

The current evolution in unconventional reservoirs occurred due to technological breakthroughs in the oil and gas industry. Currently, technologies allow extraction of economical volumes of hydrocarbon from unconventional resources via the assistance of special technologies or massive stimulation treatments. Since new formation development depends on their economics, it is critical to optimize each step within the well stimulation treatments in order to make the development economical. The Eagle Ford shale play has been under development since 2008. Initially, trial and error methods were used to hydraulically fracture wells in the play. These methods provided both good and poor results. This research focuses on optimizing future well landing zones and their corresponding well stimulation treatments within the studied area. Data provided by the Reservoir Characterization Project (RCP) were utilized to develop full geological and geomechanical models using the Grid Oriented Hydraulic Fracture Extension Replicator (GOHFER®) software package. The developed model was calibrated with available field data to ensure that the generated model matches the studied area’s geological and geomechanical characteristics. Base fracture models for two wells, Well B and Well C, were created using the developed geological and geomechanical model. Pressure and production matches for both wells were performed to guarantee that the generated base models reflect what was actually done in the field. The base fracture models were utilized to perform landing zone sensitivity, as well as well stimulation treatment sensitivity analyses. The Austin Chalk and the Eagle Ford formations were examined. Fracturing fluids and their volume, proppant selection, and cluster spacing were sensitized to determine the optimum hydraulic fracture treatment. GOHFER® was utilized to run production analysis for each sensitivity in order to compare the sensitized parameters. Five landing zones within the Austin Chalk and the Eagle Ford were analyzed. The analyses showed that the Eagle Ford had higher oil production potential than the Austin Chalk. 104% and 29% were the increases in the estimated production when the Eagle Ford was targeted instead of the Austin Chalk using slickwater and gel treatments, respectively. Based on the landing zones analyses, the highest oil production, around 326 Mbbl, was obtained from the Pepper Shale formation using a gel treatment. The induced fractures from the slickwater treatment in the Pepper Shale was contained by the Lower Eagle Ford and Buda, while the gel treatment was capable of breaking into the Lower Eagle Ford and accessing additional net pay. Well stimulation treatment sensitivities within the Pepper Shale were also studied. Introducing gel to the slickwater treatment and creating a hybrid treatment improved the oil production; and 70% gel with 30% slickwater yielded the optimum oil production. Larger proppant size performed better than smaller proppant due to conductivity damaging mechanisms. Increasing the fracturing fluid volumes from 175,000 gallons to 300,000 gallons per stage provided negligible increase, around 1%, in the oil production from the Pepper Shale; hence the optimum volume to create the fractures was 175,000 gallons. Thirty foot cluster spacing generated the optimum fracture density and had minimal impact to the production due to stress shadowing. Overall, this research demonstrated that oil production may be increased when the optimized well stimulation treatment is used to hydraulically fracture the Pepper Shale formation.