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It has long been postulated that complicated problems can usually be solved with simple solutions. While this is not always the case, one might, at least, ask for a simple framework to guide a team through a technically difficult issue. When one private oil & gas operator was faced with the common industry challenge of Parent/Child well interactions in an unconventional, dry-gas shale, a collaborative team applied a simple workflow in the form of the scientific method. The iterative workflow provided a simple approach to utilize common data, clearly calculate economic risk and ultimately reveal major performance indicators of offset well development.
The study area focuses on the northeast region of Pennsylvania, specifically in the dry gas window of the Marcellus Shale. More specifically, five counties in Pennsylvania (Bradford, Sullivan, Susquehanna, Wyoming and Lycoming) are studied after the operating company moved into full time development and started offsetting older appraisal wells. The impact from these offset events were varied ranging from parents and children losing reserves to parents and children gaining reserves. However, value loss was more common. As this risk grew, management charged the technical team and service partners with the goal of empirically mitigating offset frac interference to 1) protect the Parent well's original completion and 2) maximize a Child well's completion effectiveness.
To accomplish these goals, the team employed the scientific method to observe offset events, measure the impact to reserves and experiment with mitigation techniques. To date, the team has cataloged > 70 offset events, classified over 350 frac hits and tested one mitigation technique. In addition to an offset frac workflow, this paper will highlight statistical correlations of high value variables and detail an economic Monte Carlo Simulator to quantify the risk of a parent/child event.
Abstract To investigate interwell interference in shale plays, a state-of-the-art modeling workflow was applied to a synthetic case based on known Eagle Ford shale geophysics and completion/development practices. A multidisciplinary approach was successfully rationalized and implemented to capture 3D formation properties, hydraulic fracture propagation and interaction with a discrete fracture network (DFN), reservoir production/depletion, and evolution of magnitude and azimuth of in-situ stresses using a 3D finite-element model. The integrated workflow begins with a geocellular model constructed using 3D seismic data, publicly available stratigraphic correlations from offset vertical pilot wells, and openhole well log data. The 3D seismic data were also used to characterize the spatial variability of natural fracture intensity and orientation to build the DFN model. A recently developed complex fracture model was used to simulate the hydraulic fracture network created with typical Eagle Ford pumping schedules. The initial production/depletion of the primary well was simulated using a state-of-the-art unstructured-grid reservoir simulator and known Eagle Ford shale pressure/volume/temperature (PVT) data, relative permeability curves, and pressure-dependent fracture conductivity. The simulated 3D reservoir pressure field was then imported into a geomechanical finite-element model to determine the spatial/temporal evolution of magnitude and azimuth of the in-situ stresses. Importing the simulated pressure field into the geomechanical model proved to be a critical step that revealed a significant coupling between the simulated depletion caused by the primary well and the morphology of the simulated fractures within the adjacent infill well. The modeling workflow can be used to assess the effect of interwell interferences that may occur in a shale field development, such as fracture hits on adjacent wells, sudden productivity losses, and drastic pressure/rate declines. The workflow addresses the complex challenges in field-scale development of shale prospects, including infilling and refracturing programs. The fundamental importance of this work is the ability to model pressure depletion and associated stress properties with respect to time (time between production of the primary well and fracturing of the infill well). The complex interaction between stress reduction, stress anisotropy, and stress reorientation with the DFN will determine if newly created fractures propagate toward the parent well or deflect away. The technique should be implemented in general development strategies, including the optimization of infilling and refracturing programs, child well lateral spacing, and control of fracture propagation to minimize undesired fracture hits or other interferences.
Maintaining production in the shale business is getting increasingly costly because new wells in major US shale plays are falling short of output from the parent wells. A study of 10 major US basins by Schlumberger (SPE 189875) found that while the parent and child wells looked comparable at first glance--about half of new wells outperform the older wells and vice a versa--the picture changes when the results are adjusted for the higher cost of drilling and fracturing new wells. This is a pressing issue in the shale sector where constant drilling is required to replace short-lived older wells, which is leading to increasingly dense development. When the results remove the benefit of the longer laterals and bigger loads of sand pumped now, the parent wells outperform the next generation about 70% of the time, according to the study discussed at the SPE Hydraulic Fracturing Technology Conference this week. It defined a child well as one drilled at least 1 year after the parent well.
Well Stimulation: Parent/Child Relationship - presented by Graham Janega
The interaction between parent and child wells during a fracture and post-fracture is an inevitability in today's Shale and Ultra-light resource development. As a result parent/child wellbore relationships will likely become one of the shale sector's most important learning tools going forward.
Recent industry analysis based on publicly available production data of most unconventional basins in the US have consistently highlighted the underperformance of child wells as compared to parent wells, although completion practices have continuously evolved. Industry publications have suggested that average productivity degradation of child wells can be up to 29% for some Delaware Basin operators. In some cases, the detrimental effects of parent-child relationships have also been observed on the parent wells after the stimulation of the child wells. In such an environment it is important to develop completion strategies to mitigate the negative effects of this parent-child relationship. In the Delaware Basin, the negative parent-child effect was successfully mitigated on two different zipper pads, with parent wells as close as 500 ft away from the zippered child wells. On the first pad, one parent well was completed and six months later two child wells were zippered with the closest child 1,000 ft away from the parent and pumped with far-field diversion. On the second pad, one parent well was completed and four months later three child wells were zippered with the closest child well 500 ft away from parent and far-field diversion pumped on the two closest child wells.
The stimulation treatment design was carefully designed to include far-field diverters on the stages near parent wells. Job size and far-field diverter quantity were determined using an integrated hydraulic fracture simulation software with an advanced particle transport model. Contingency scenarios were also prepared to facilitate real-time changes required when or if abnormal behavior was observed during the execution. The zipper sequence was also planned to help establish a stress-shadow effect near the parent well to further mitigate detrimental parent-child interactions. To monitor execution in real time and evaluate interactions between wells, high-frequency pressure gauges were installed on all observation wells including parent and child wells.
The completion design and far-field diversion treatment worked as planned for the first pad, with no significant well interference pressure signature observed on the monitoring well. For the second pad, the parent well saw pressure increases up to 700 psi during the treatment of a stage midway along the lateral of the closest child well which was completed with far-field diverter. Contingency plans were successfully executed, and no significant pressure increase was observed on the remainder of the lateral. Early production results indicate that the negative impacts of parent-child interactions were successfully mitigated on both pads, with the production of the parent wells quickly returned to their observed trends prior to child wells stimulation. Child wells production, when normalized both by lateral length and stimulation size, was on par with that of the parent well.