Integrated surveillance is critical for understanding reservoir dynamics and improving field management. A key component of the surveillance is areal monitoring of subsurface changes by use of time-lapse geophysical surveys such as 4D seismic. The purpose of the complete paper is to create a performance-based reservoir characterization by use of production data (measured rates and pressures) from a selected gas-condensate region within the Eagle Ford Shale.
Zafar is a strategy consultant with Accenture and is based out of Mumbai. Before Accenture, he worked for 5 years at Halliburton designing drill bits for oil and gas companies in South Asia. He has been a volunteer with TWA since 2013 supporting multiple sections prior to transitioning to a leadership role in 2018. He is a keen technophile, an avid debater, and a passionate Toastmaster. He has participated in and won several public speaking and debate competitions. His hobbies include running, collecting key-rings, building robots, and keeping abreast of global geopolitics. Kristin Cook is the Advisor to TWA. She is an MS candidate in Energy and Earth Resources at the University of Texas at Austin. Her interests include energy policy, oil and gas project development, and energy security and geopolitics. Prior to starting graduate school, Cook worked for 5 years as a production engineer in the San Juan Basin, a natural gas field in northwestern New Mexico.
Growth in a number of newly drilled wells in unconventional reservoir development results in tightly spaced horizontal wells, which consequently creates well interference (fracture hits) between parent and infill wells as a result of stress redistribution from localized pressure sink zone in parent wells. This directly affects the production performance of both parent and infill wells. In order to minimize this effect, it is sometimes more preferable to place an infill well in a different pay zone. However; due to poroelastic effect, pressure depletion from the parent well also affects stress distribution in different pay zones and yet only a few literatures focus on this effect. The main objective of this paper is to predict temporal and spatial evolution of stress field for Permian basin using an in-house 3D reservoir-geomechanics model and propose guidelines for determining lateral and vertical drilling sequence of infill wells to mitigate well interference.
Embedded discrete fracture model (EDFM) is coupled with a sequentially coupled reservoir-geomechanics model to gain capability in simulating complex fracture geometries and high-density fracture system. Different scenarios with and without natural fractures were studied including a case where two parent wells are located in different layers (Wolfcamp A2 and B2) and a case where two parents are located in the same layer (Wolfcamp A2 and B2). Stress redistribution is then observed to determine the completion sequence of infill wells in different layers.
Producing two parent wells in the same pay zone results in large stress redistribution mostly in the area close to fracture tips at an early time. As time progresses, stress redistribution area becomes larger and covers almost entire infill well zone in Wolfcamp B2. Stress changes can also be observed in Wolfcamp A2 and A3 despite producing wells are only located in Wolfcamp B2. However, when producing two parent wells in different pay zones, stress redistribution can only be observed near fracture tips in both Wolfcamp A2 and B2 with minimum stress change in the infill zone even at a later time in all Wolfcamps A2, A3, and B2. This allows the possibility of producing infill well in the un-depleted layers (i.e. A3) enhancing efficiency of infill well completion. Fracture penetration and larger fracture length also play a significant effect in stress reorientation and evolution. Presence of natural fractures causes stress reorientation to occur at an earlier time due to higher depletion rate. This paper presents the possibility of changing the sequence of stacked pay from lateral well layout to vertical well layout in order to mitigate well inference and improve production performance of both parent and infill wells. Less stress change in the infill zone for vertical well layout makes it become superior to lateral well layout in which large stress redistribution can be observed.
Determination of proper well spacing is a key factor in successful resource play development. The objective is to optimize the spacing between wells that effectively stimulates the reservoir rock volume, increases overall recoveries and minimizes interference between wells. Recent work by Pioneer Natural Resources, Inc. (PXD) to optimize well spacing along the Eagle Ford Shale trend has resulted in reduced lateral spacing as well as vertical staggering of wells within the reservoir interval. Numerous tools are used to aid the determination of well spacing across the play, and it is critical to integrate data from all the tools available when establishing a spacing recommendation. The workflow presented is used to establish spacing recommendations through integration and analysis of multi-source data collected during the lifecycle of an unconventional resource play.
The well spacing toolkit includes data collected from multiple disciplines in the asset. Microseismic data is integrated with 3D seismic data and fracture models to derive stimulated rock volumes. RA tracer and chemical fluid tracer data collected during well stimulation provide information on propped fracture length and height and inter-well communication, respectively. Pressure data recorded during well stimulation and interference tests performed after stimulation are used to help understand changes in well communication over time. Oil and gas geochemistry data from wells drilled in multiple stratigraphic intervals are used to provide insight on fracture height growth.
The ability to integrate and analyze multi-source data is essential when establishing a recommendation on a complex problem such as proper well spacing; the workflow presented allows for the manipulation and visualization of these data in 4D that can be interpreted and edited by multiple users.
Portis, Douglas H. (Pioneer Natural Resources ) | Bello, Hector (Pioneer Natural Resources) | Murray, Mark (Pioneer Natural Resources) | Barzola, Gervasio (Pioneer Natural Resources) | Clarke, Paul (Pioneer Natural Resources) | Canan, Katy (Pioneer Natural Resources)
Four years after the "discovery?? of the Eagle Ford shale play, most operators have shifted their efforts from appraisal and delineation, to full-field development. This commonly involves drilling multiple (three to four) horizontal wells, simultaneously from one common surface location (or pad). Inter-well spacing ranges from 330 - 1000 feet across the trend as industry searches for the optimism well spacing for a range Eagle Ford shale thickness, rock-quality, pressure and thermal maturity windows. Pioneer Natural Resources (PXD) has followed this same transition and routinely drills three well pads with approximately 500 foot spacing between wells, which are completed with "zipper-frac?? treatments. This paper presents a tool-kit designed in-house and currently employed to monitor well interference, communication and pad performance/drainage efficiency. The ultimate goal of this project is to better understand the reservoir response during hydraulic fracture treatments (at 500 foot. spacing) and use these learnings to positively impact the full field development and by achieving an optimum well spacing.
A multidisciplinary technical team has designed an integrated data acquisition "tool-kit?? to address the above issues. Essential to the tool-kit are chemical and radioactive tracers, pumped during the stimulation of one or more wells in a given pad. These data help our interpretation of fracture generation, fracture growth and fluid flow/ proppant placement (i.e. proppant distances, fluid distances, and fracture geometry). Several microseismic surveys also assist in the recognition, quantification and distribution of stimulated rock volume. A major portion of this tool-kit includes the monitoring of pressure communication in offset wells during fracture stimulation and flowback/production. Subsequent interference tests over a period of several months allow for a better understanding of the changes in fracture conductivity and effectively propped fractures.
Collectively, these data are helping refine our geologic model and confirming the significance of attributes extracted from our 3D seismic data-set. We detail design parameters and practical applications of these tools, while discussing pitfalls and learning from project to date. Our findings have implications for development well planning, well spacing and frac-design.