Importance of Inclined Velocity Measurements and Variable Biot’s Poroelasticity for Anisotropic Stresses in Predicting Fracture Geometry in Unconventional Plays
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In the current low commodity price environment, several operators have chosen to return to their mature fields to re-fracture the reservoirs to improve overall recovery of reserves. Although modelling remains challenging, re-fracturing treatments have been successfully executed on multiple wells worldwide. This study compares three different approaches to model re-fracturing in tight sands as a means of reducing the overall uncertainty. Multi-domain integration was utilised in which geomechanical data was coupled with petrophysical analysis to build a three-dimensional (3D) hydraulic fracture model. Fracture pressure history matching was performed and the model was validated using calibration data available from microseismic analysis and extended leakoff tests. Production history matching was performed to validate the reservoir simulation model and estimate the resulting depletion around the wellbore. Geomechanical properties and the resulting minimum in-situ horizontal stress were re-calculated incorporating the results of depletion using three different approaches: Pore Pressure Model, Scale Model and Non-Scale Model. Finally, the hydraulic fracture models were re-constructed using the revised geomechanical properties to simulate re-fracturing using various pumping treatments. The fracture geometries obtained from re-fracture simulations were dependent on the model used for re-computation of geomechanical properties post-production as well as the fluid volume pumped. These properties were also validated using laboratory testing. Comparison of the three approaches indicated consistent geometries when small volumes of fluid or typical ‘Plug and Perf’ designs were pumped. Upon pumping larger volumes or typical ‘Sliding Sleeve’ treatments, major differences were observed using the three approaches indicating larger uncertainty and warranting the use of the more rigorous Non-Scale Model. Validated models are important tools for designing hydraulic fracturing treatments to avoid risks of sub-optimisation of fracture designs or undesirable bashing of offset parent wells. Good understanding of re-fracture models helps oil companies make informed decisions regarding their completion programme, hence improving overall hydrocarbon recovery. Modelling of re-fracture treatments continue to pose a challenge for engineers due to added subsurface static and dynamic complexities. This study presents basic guidelines to follow for modelling, with results verified from laboratory testing.
In the current low commodity price environment, several operators have chosen to return to their mature fields to re-fracture the reservoirs to improve overall recovery of reserves. Although modelling remains challenging, re-fracturing treatments have been successfully executed on multiple wells worldwide. This study compares three different approaches to model re-fracturing in tight sands as a means of reducing the overall uncertainty. Multi-domain integration was utilised in which geomechanical data was coupled with petrophysical analysis to build a three-dimensional (3D) hydraulic fracture model. Fracture pressure history matching was performed and the model was validated using calibration data available from microseismic analysis and extended leakoff tests. Production history matching was performed to validate the reservoir simulation model and estimate the resulting depletion around the wellbore. Geomechanical properties and the resulting minimum in-situ horizontal stress were re-calculated incorporating the results of depletion using three different approaches: Pore Pressure Model, Scale Model and Non-Scale Model. Finally, the hydraulic fracture models were re-constructed using the revised geomechanical properties to simulate re-fracturing using various pumping treatments. The fracture geometries obtained from re-fracture simulations were dependent on the model used for re-computation of geomechanical properties post-production as well as the fluid volume pumped. These properties were also validated using laboratory testing. Comparison of the three approaches indicated consistent geometries when small volumes of fluid or typical ‘Plug and Perf’ designs were pumped. Upon pumping larger volumes or typical ‘Sliding Sleeve’ treatments, major differences were observed using the three approaches indicating larger uncertainty and warranting the use of the more rigorous Non-Scale Model. Validated models are important tools for designing hydraulic fracturing treatments to avoid risks of sub-optimisation of fracture designs or undesirable bashing of offset parent wells. Good understanding of re-fracture models helps oil companies make informed decisions regarding their completion programme, hence improving overall hydrocarbon recovery. Modelling of re-fracture treatments continue to pose a challenge for engineers due to added subsurface static and dynamic complexities. This study presents basic guidelines to follow for modelling, with results verified from laboratory testing.
Anisotropy measurements in unconventional rocks require fully characterized azimuthal rock properties. Accurate characterization of the minimum in situ horizontal stress plays a vital role in fracture modeling. Underestimation of stresses from applying the assumptions of isotropy leads to poor drilling and completion design. On the other hand, applying a simplified tensors’ assumption and assuming a constant Biot's Poroelastic Coefficient of one overestimates the stresses leading to costly drilling issues and incorrect proppant placement. First step involves obtaining high frequency directional core samples i.e. vertical (0°), inclined (45°) and horizontal (90°) to derive five independent and continuous velocity profiles (including vertical shear and vertical compressional velocities) and mechanical properties for anisotropic models. Importance of core testing is imperative to deriving pseudo velocity profiles and for dynamic to static conversion of Young's Moduli and Poisson's Ratios. Rock physics govern static core based properties (stress-strain measurements) be used as opposed to dynamic properties measured directly from velocities for accurate characterization of stresses. Obtaining an inclined ASTM (American Standard Testing Material) standard core plug for rock testing is one of the biggest challenges the industry is facing due to the fragile nature of shale material. Shorter core plugs lead to end-cap friction and scaling related errors by increasing uncertainty in rock properties. These challenges have forces the industry to make a simplified assumption on tenors (i.e. C12=C13) that are imperative to deriving anisotropic mechanical properties from measured azimuthal velocities. Second challenge is the characterization and validation of Biot's poroelasticity theory. Building pore pressure to measure grain compressibility to calculate Biot's constant in unconventional rock types is time consuming and costly. Therefore, many standard models assume a constant Biot's of one. The tensor and Biot's assumptions were investigated independently and fracture modeling was performed to predict the fracture geometry that was also compared with the available calibration data. It was determined that the both tensor and Biot's of one models overestimated the stresses, resulting in an inaccurate fracture geometry prediction. Finally, a variable Biot's model without the simplified tensor assumption derived using inclined velocity measurements was proposed, that composed of fully integrated anisotropic core based rock properties. The proposed model is a useful tool to accurately characterize the geomechanical properties of unconventional rocks and hence accurately predict the resulting fracture geometry. Good understanding of the stress field around a wellbore allows operators to make informed decision regarding the drilling and completion program of the in-fill wells leading to optimum field development strategies and significant cost savings.
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