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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.
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 (
Huang, Jixiang (Lawrence Livermore National Laboratory) | Fu, Pengcheng (Lawrence Livermore National Laboratory) | Hao, Yue (Lawrence Livermore National Laboratory) | Morris, Joseph (Lawrence Livermore National Laboratory) | Settgast, Randolph (Lawrence Livermore National Laboratory) | Ryerson, Frederick (Lawrence Livermore National Laboratory)
Abstract Reservoir depletion and its influence on subsequent hydraulic fracture propagation are studied using a three-dimensional fully coupled geomechanics, fluid flow and hydraulic fracturing code. Pressure change and resultant stress alteration are captured through a rigorously developed poroelastic model, validated against analytical solutions. In the context of parent-child well interference, depletion-induced stress reduction will attract fracturing from nearby wells, unfavorably affecting production of the parent well in most cases by leaving the target region unstimulated or understimulated. One engineering practice to remedy this impact is to refracture the parent well before fracturing in child wells. How this treatment impacts the fracturing and to what extent it can prevent the attraction have been quantitatively studied using the geomechanics-flow coupling and hydraulic fracturing capabilities within a unified framework. Sensitivity studies of matrix permeability, production time and fracture spacing have been performed to explore the feasibility of controlled fracture growth into a depletion region. The amount of fluid required to refracture the producing well sufficiently to create a stress barrier that inhibits deletarious growth of child fractures depends on the degree of reservoir depletion. A complex scenario involving the interactions between reservoir depletion, refracturing and geologic factors such as stress barriers is also studied. The possibility for a subsequent fracturing to break through a stress barrier after a certain time of production, which would otherwise be impossible, is explored, indicating a potential parent-child well interference mechanism even when the parent and child wells are located in different formations. This phenomenon is essentially three dimensional and has not been captured by previous studies.
Abstract Frac hits are a persistent phenomenon that operators face periodically during unconventional field development. With basin maturity and infill drilling, frac hits play a major role in dictating overall production from multiwell pads. This paper focuses on the causes of frac hits and their subsequent impact on well EURs with solution methods to minimize negative impacts resulting from frac hits. A fully numerical model-based was built around a four-well pad in Mountrail County, N.D., by integrating high-tier data including 3D sonic logs, nuclear magnetic resonance imaging and downhole spectroscopy to build a mechanical earth model of the reservoir. The parent well(s) are history-matched and geomechanical properties recalculated to changes in in situ stresses from parent well production. Infill wells are evaluated for asymmetric frac propagation toward depleted wells, and EURs are estimated to compare with thosethat of the parent wells. The initial well stimulation program and the volume of production from the parent well has a huge impact on the degree of fracture asymmetry in infill wells. This preferential propagation creates additional stimulated surface area between wells. If the parent well was understimulated in the first place, the infill wells in general result in a positive frac hit, and additional barrels of oil are produced from the parent well with little or no impact on the infill well. However, if the parent well has been on production for a long period the hydraulic fracturing treatment deposits a huge volume of fluid and proppant in already depleted areas, and the reservoir pressure is not sufficient to flush out the excess water. This causes the parent well to experience a surge in water cut and reduction in oil rate for an extended period. In addition, the infill well's initial production will not metch the parent well IPs, and EUR can reduce drastically. This paper will categorically illustrate the timing, spacing and stimulation recommendations to minimize or mitigate these impacts. Quantifying frac hits requires a comprehensive multiwell approach incorporating geomechanics, fracturing and production. This paper showcases case studies from the Bakken, identifying fracture asymmetry and production forecast from multiple wells, carefully considering all the physics, rock and fluid interaction in the subsurface strata. This will be a valuable tool for the engineers and geologists in the oil and gas community to effectively plan future infill development programs in unconventional reservoirs.
In an era where capital markets are hitting the brakes on funding the US shale sector, operators have increasingly pivoted from production growth to maximizing the rates of return via lower-cost wells. One of the major challenges of this new era is the determination of optimal stage and well spacing for a drilling area. For much of the US, the trend has been toward increased job size and rapid downspacing of infill or “child” wells. The unintended consequence of this trend has been an increase in fracture interference and excessive cross-well communication, which results in an overcapitalization of acreage and underperforming child wells as the drainage areas of wells overlap and compete for depleted resources. Within the SCOOP/STACK play, child wells completed in 2017/2018 have been half as productive as their 2015/2016 parent wells, a trend theorized to be directly related to negative fracture interactions. Determining an optimal spacing between parent and infill wells is not a straightforward endeavor. An ideal development strategy is not just about well spacing, as decisions in completion design can exacerbate issues stemming from tight spacing. For this multivariate problem, operators have attempted to use bottomhole pressure measurements to extrapolate fracture interference or to use large data sets in a “trial-and-error” approach to understand well interference behavior. These approaches have significant downsides, relying either on data sets of questionable value or on extrapolating data to and from wells with significantly different geological conditions. One operator in the SCOOP/STACK has attempted to understand well interference with chemical tracer technology. Using liquid molecular tracers, this operator achieved a quantified understanding of flow between parent/child wells with a high degree of confidence. This inexpensive technology has allowed the operator to experiment with well spacing and repressurization of parent wells. This, in turn, permits the rapid evaluation of mitigation techniques to optimize its field development strategy based on an accurate measurement of interwell fluid movement. Tracer Selection Two categories of chemical tracer are commonly used in conjunction with hydraulic fracturing operations: infused solid particulate tracers and liquid molecular tracers. While both tracer products have their strengths and weaknesses, liquid molecular tracers were chosen as a best practice in this study as they allow for quantification of the traced fluid phase, unlike infused solid particulate tracers.