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Reduced production from child wells has been observed due to prior depletion around the parent well. In this work, a systematic simulation study is conducted to understand the effects of parent well depletion on child well fracture growth and production.
A three-dimensional hydraulic fracturing simulator based on the displacement discontinuity method is used to simulate parent well fracturing. The created hydraulic fractures are transferred into a finite volume-based geomechanical reservoir simulator for production simulation. The pressure and stress profiles in the reservoir after production simulation are then used in the hydraulic fracturing simulator to capture the effect of depletion on child well fracturing. Infill timing (parent well production duration before child well stimulation) is varied, and its impact on child well fracture geometry and the production (from the child and parent wells) is investigated.
The depletion of the reservoir due to production from the parent well can have a significant effect on the child well fracture growth. Asymmetric fracture growth, the tendency of the fractures to grow towards the depleted region, is clearly observed. The effect of the extent of depletion (infill timing) on asymmetric fracture growth for different reservoir diffusivities (
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.
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 With increasing demand for natural gas, higher product prices and the availability of improved extraction technologies, there is increasing focus on infill drilling in tight gas reservoirs. However, quantification of incremental recovery (one of the key value generators) is often challenging particularly in commingled multi-layered heterogeneous fluvial reservoirs with a paucity of data collection. The issues related to the volume and quality of data collected are magnified when low cost infill development is undertaken. This paper demonstrates a new technique using production data (in isolation) to estimate incremental and accelerated recovery for such a development. For infill development, various methods have been proposed to quantify incremental recovery. The most common range from simple reservoir continuity models, Arps Decline Curves, Material Balance, field analogue studies, to complex reservoir simulation. This paper discusses a new methodology termed ‘Progressive Multi-well Blasingame Analysis’ based on Blasingame type curves which successively compares boundary-dominated responses from each infill phase to distinguish incremental from accelerated recovery achieved from each phase of infill development. The paper reviews the theoretical support for the Progressive Multi-well Blasingame Analysis method via a numerical simulation study. Demonstration of this methodology is performed using a field case study to quantify incremental recovery and identify additional infill opportunities in an environment where limited reservoir surveillance was conducted. The paper concludes by discussing the applicability and the pros and cons of this technique. In essence, this paper addresses an existing knowledge gap in industry as it provides a method to efficiently evaluate a group of wells and distinguish incremental from accelerated recovery using only the production rate and flowing tubing head pressure data.
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.