Estimation of permeability in the Stimulated Reservoir Volume (SRV) is a vital input in any completion optimization workflow. One method to estimate the stimulated permeability in the SRV is to couple geomechanical modeling of the interaction between hydraulic and natural fractures with hydraulic fracture mechanics commonly used to design frac jobs. The proposed approach starts by deriving strain resulting from the integration of geological, geophysical and geomechanical modeling of interacting hydraulic and natural fractures. A unique feature of this approach is its ability to predict microseismicity, thus confirming the validity of the input natural fracture model and the geomechanical approach used to evaluate its interaction with the hydraulic fractures. The optimum validated geomechanical asymmetric half-lengths are then estimated from the derived strain map. These estimated geomechanical half lengths are used as a constraint in a frac design model which is able to incorporate this information and optimize stage treatments according to the variable SRV. The frac design parameters then need to be adjusted in order to approximately match the geomechanical half-lengths provided by the strain map.A new analytical asymmetric frac design model is developed, validated with existing commercial frac design software, and used in this study. The new asymmetric analytical frac design model is a pseudo 3D model that accounts for the variation in height in an iterative approach along with considering the asymmetric half lengths due to the lateral stress gradients in a heterogeneous reservoir. The new asymmetric analytical frac design model was compared to existing commercial frac design software and was found to provide similar estimations of frac heights but in a fraction of the time needed to run the commercial frac design software. The ability to combine these models and simultaneously solve for the optimum fracture height is provided by the constraints of the geomechanical half lengths derived from the strain map. In order to guide the engineer designing a frac job an optimum selection of the design parameters to get the target fracture geometry, this paper also presents a parametric analysis using experimental design of various fracing parameters used in our asymmetric hydraulic fracture model.In this study, the workflow was successfully applied to a complex Eagle Ford well. The frac design tool optimizes important parameters such as the injection rate, fluid viscosity, proppant type, proppant size, proppant specific gravity and leak-off coefficient in order to honor the interaction of natural and hydraulic fractures accounted for in geomechanics. The frac design model also provides vital information such as the proppant schedule to be pumped and the variation of propped length, width, and net pressure as a function of time. The results of this workflow are the fracture conductivity and proppant concentration along the fracture length and their interpolation between the stages so they can be exported to any reservoir...

This paper presents a new integrated workflow that couples geology, geomechanics and geophysics (3G) with a constrained asymmetric frac model as applied to a Wolfcamp well to address the concerns of well interference. The proposed workflow enables the ability to adapt the frac design of each stage based on the in-situ geologic and geomechanical variability. The objective of this approach is to identify the variable treatment parameters required to overcome the stress heterogeneity and estimate the impact of the adaptive frac design on the final fracture geometry. The lateral stress gradients resulting from the pressure depletion due to a nearby producing well and the fluid leak-off due to opening of natural fractures are fine-tuned to account for asymmetry observed in the geomechanical modeling. The role of the natural fractures is emphasized and practical approaches to estimate a validated natural fracture model are described and illustrated. A validation well is used to highlight the importance of the input natural fracture model in calculating validated differential stress and strain that reproduce the main features of the microseismic. With this validated strain model, a constrained frac design provides the proper asymmetric fracture geometry able to pinpoint the poor and good frac stages. Once the workflow is extensively validated, it can be used on target wells to avoid frac hits. In this Wolfcamp example, the challenge was to find the optimal frac design to minimize interference of an infill well with existing offset producers. To address the possible zones of interference, the stage spacing was locally increased to 152 m (500 ft), and the treatment was especially modified in the middle stages of the well. This resulted in reducing the number of stages from 40 to 34, specifically in zones indicating high probability of interference. The design was altered from pumping a mixture of 320,000 lb of 100 mesh and 40/70 mesh sand to 220,000 lb of 40/70 mesh sand, and the injected fluid viscosity was increased from 10 centipoise (cP) for slick water to 30 cP for linear gel as better carrying capacity was required to pump only 40/70 mesh sand. Additonally, the injection rate was reduced from 105 bbl/min to 80 bbl/min. The integrated approach allows for the ability to adapt the frac design to in-situ conditions including heterogeneity in the stress fields and the pressure depletion from existing producers. Adaptive frac design significantly reduces the probability of frac hits and well interference. The proposed modeling workflow enables greater investment efficiency and overall field development optimization.

Predictable well performance is a key factor for the economic development of unconventional reservoirs including tight sands, tight carbonates and shales. A factory approach to developing unconventional reservoirs has resulted in unpredictable and highly variable well performance, much of which has been uneconomic. Minimizing the uncertainty in production forecasting and reservoir simulation necessitates an accurate model, which captures the interaction of induced hydraulic fractures with existing natural fractures. One method to achieve this is by using a 3G workflow, which leverages the synthesis of geophysical and geological information through geomechanical techniques to model the hydraulic fracturing of unconventional reservoirs. A complete workflow is presented for modeling and simulation of unconventional reservoirs, which incorporates the characterization of natural fractures and their interaction with hydraulic fracture stimulation. The 3G workflow is applied to an unconventional well in the Wolfcamp Shale, Permian Basin. The geomechanical modeling results are exported to a standard commercial numerical reservoir simulator using two different approaches; strain volume and constrained asymmetric hydraulic fractures. A third reservoir simulation case is created in which commonly used symmetric hydraulic fractures are generated without any external geomechanical model. An automated history matching tool is used to find the hydraulic fracture parameters for this over simplistic and unrealistic case. The production forecast and pressure depletion profiles are compared for all three cases. The proposed unconventional modeling workflow is not only fast but also significantly reduces uncertainty in the reservoir simulation results, improving reliability of the production forecast as well as the pressure depletion profile. These constrained simulations provide the information necessary to make better decisions in field development planning.