Integration of Petrophysical and Geomechanical Properties for Enhanced Fracture Design
Abstract: Shale reservoirs retain significant natural gas reserves, which are more challenging to recover than in conventional reservoirs. Production from these unconventional resources became economically feasible as a result of advances in both horizontal drilling and hydraulic fracturing technologies. Stimulation technologies continue to improve through the combining of advanced logging, geomechanics, microseismic and frac fluids. This has led to further optimization of hydraulic fracture treatments and higher recove… Show more
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Cited by 4 publications
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Innovation and advances in technology have enabled the industry to exploit lower-permeability and more-complex reservoirs around the world. Approaches such as horizontal drilling and multistage hydraulic fracturing have expanded the envelope for economic viability. However, along with enabling economic viability in new basins come new challenges. Such is the case in the Middle East and North Africa regions, where basin complexity arising from tectonics and complicated geology is creating a difficult geomechanical environment that is impacting the success of hydraulic fracturing operations in tight reservoirs and unconventional resources. The impact has been significant, including the inability to initiate hydraulic fractures, fracture placement issues, fracture connectivity limitations, casing deformation problems, and production impairment challenges. Completion quality (CQ) relates to the ability to generate the required hydraulic fracture surface area and sustained fracture conductivity that will permit hydrocarbon flow from the formation to the wellbore at economic rates. It groups parameters related to the in-situ state of stress (including ordering, orientation, and amount of anisotropy), elastic properties (e.g., Young's modulus and Poisson's ratio), pore pressure, and the presence of natural fractures and faults. Collectively, this group of properties impacts many key aspects determining the geometry of the fracture, particularly lateral extent and vertical containment. Heterogeneity in CQ often necessitates customizing well placement and completion designs based on regional or local variability. This customization is particularly important to address local heterogeneity in the stress state and horizontal features in the rock fabric (e.g., laminations, weak interfaces, and natural fractures) that have been identified as key contributors impacting the success of hydraulic fracture treatments. Given the observation that a wide range of CQ heterogeneity was creating a complex impact on hydraulic fracture performance, CQ classes were introduced to characterize the risk of developing hydraulic fracture complexity in the horizontal plane and the associated impact on well delivery and production performance. They indicate the expected hydraulic fracture geometry at a given location and are analyzed in the context of a wellbore trajectory in a given local stress state. CQ class 1 denotes locations where conditions lead to the formation of vertical hydraulic fractures, CQ class 2 denotes locations where conditions lead to the formation of a T-shaped or twist/turn in the hydraulic fracture, and CQ class 3 denotes locations where conditions lead to the formation of hydraulic fracture with predominantly horizontal components. Wellbore measurements indicate that these CQ classes can vary along the length of the wellbore, and 3D geomechanical studies indicate that they can vary spatially across a basin. By understanding this variability in CQ class, well placement and completion design strategies can be optimized to overcome reservoirheterogeneity and enable successful hydraulic fracturing in more challenging environments. This paper introduces the novel concept of CQ class to characterize basin complexity; shows examples of CQ class variability from around the world; and provides integrated drilling, completion, and stimulation strategies to mitigate the risks to hydraulic fracturing operations and optimize production performance.
Innovation and advances in technology have enabled the industry to exploit lower-permeability and more-complex reservoirs around the world. Approaches such as horizontal drilling and multistage hydraulic fracturing have expanded the envelope for economic viability. However, along with enabling economic viability in new basins come new challenges. Such is the case in the Middle East and North Africa regions, where basin complexity arising from tectonics and complicated geology is creating a difficult geomechanical environment that is impacting the success of hydraulic fracturing operations in tight reservoirs and unconventional resources. The impact has been significant, including the inability to initiate hydraulic fractures, fracture placement issues, fracture connectivity limitations, casing deformation problems, and production impairment challenges. Completion quality (CQ) relates to the ability to generate the required hydraulic fracture surface area and sustained fracture conductivity that will permit hydrocarbon flow from the formation to the wellbore at economic rates. It groups parameters related to the in-situ state of stress (including ordering, orientation, and amount of anisotropy), elastic properties (e.g., Young's modulus and Poisson's ratio), pore pressure, and the presence of natural fractures and faults. Collectively, this group of properties impacts many key aspects determining the geometry of the fracture, particularly lateral extent and vertical containment. Heterogeneity in CQ often necessitates customizing well placement and completion designs based on regional or local variability. This customization is particularly important to address local heterogeneity in the stress state and horizontal features in the rock fabric (e.g., laminations, weak interfaces, and natural fractures) that have been identified as key contributors impacting the success of hydraulic fracture treatments. Given the observation that a wide range of CQ heterogeneity was creating a complex impact on hydraulic fracture performance, CQ classes were introduced to characterize the risk of developing hydraulic fracture complexity in the horizontal plane and the associated impact on well delivery and production performance. They indicate the expected hydraulic fracture geometry at a given location and are analyzed in the context of a wellbore trajectory in a given local stress state. CQ class 1 denotes locations where conditions lead to the formation of vertical hydraulic fractures, CQ class 2 denotes locations where conditions lead to the formation of a T-shaped or twist/turn in the hydraulic fracture, and CQ class 3 denotes locations where conditions lead to the formation of hydraulic fracture with predominantly horizontal components. Wellbore measurements indicate that these CQ classes can vary along the length of the wellbore, and 3D geomechanical studies indicate that they can vary spatially across a basin. By understanding this variability in CQ class, well placement and completion design strategies can be optimized to overcome reservoirheterogeneity and enable successful hydraulic fracturing in more challenging environments. This paper introduces the novel concept of CQ class to characterize basin complexity; shows examples of CQ class variability from around the world; and provides integrated drilling, completion, and stimulation strategies to mitigate the risks to hydraulic fracturing operations and optimize production performance.
Understanding the created fracture geometry is key to the effectiveness of any stimulation program, as fracture surface area directly impacts production performance. Microseismic monitoring of hydraulic stimulations can provide in real-time extensive diagnostic information on fracture development and geometry. Thus, it can help with the immediate needs of optimizing the stimulation program for production performance and long-term concerns associated to field development. However, microseismic monitoring is often underutilized at the expense of productivity in the exploration and appraisal phases of a field. Geology is a fundamental element in the design of a stimulation program and the interpretation of its results. Rock properties and geomechanics govern the achievable fracture geometry and influence the type of fluids to be injected in the formation and the pumping schedule. Rock layering controls the location of the monitoring device, guides the depth at which perforations should be located, and influences how hydrocarbons flow within the formation. Despite this importance, the impact geology may have on the stimulation results is often overlooked as it is all too common to see assumed laterally homogeneous formations, invariant stress field (both laterally and vertically), stimulated fractures having a symmetric planar geometry, etc. As exploration and appraisal moves toward active tectonics areas (as opposed to relatively quiet passive margins and depositional basins), understanding the impact of complex geology and the stress field on fracture geometry is critical to optimizing stimulation treatments and establishing robust field development plans. Mapping of hypocenters detected using microseismic monitoring is an ideal tool to help understand near- and far-field fracture geometry. Additionally, moment tensor inversion performed on mapped hypocenters can contribute to understanding the rock failure mechanisms and help with evaluating asymmetric and complex fracture geometry. Understanding this fracture complexity helps address key uncertainties such as achievable fracture coverage of the reservoir. We present the results of several hydraulic fracture stimulations in various geological environments that have been monitored using microseismic data. We illustrate with these case studies that in some rare cases, simple radial and planar fracture system (often mislabeled penny shape-like fracture) may be generated as predicted using simple modeling techniques. However, in most cases, the final fracture system geometry is complex and asymmetric, largely governed by stress, geologic discontinuities, rock fabric, etc. Understanding this impact and optimizing the well design to enhance productivity is key to evaluating reservoir potential and commercial viability during exploration and appraisal phases and for maximizing return on investment during development.
Standard laboratory techniques for determining petrophysical and geomechanical properties (e.g. porosity/permeability, Young's modulus, unconfined compressive strength) of tight rocks routinely require perfectly-cylindrical core plugs and/or large amounts (30+ g) of crushed-rock materials. Further, these measurements are time-consuming and expensive to perform. Therefore, indirect approaches for estimating rock petrophysical and geomechanical properties using small amounts of drill cuttings, which are usually the only reservoir samples available from multi-fractured horizontal wells (MFHWs), have recently received attention. Using an integrated, multidisciplinary approach that combines a customized image analysis software developed in-house with non-destructive microscopic techniques, practical laboratory-based workflows are generated to determine a variety of rock petrophysical properties including mineralogical composition, cementation, and porosity using drill cuttings. An "artificial" cuttings sample suite (core plugs crushed/sieved to 20/35 US mesh size), obtained from a prolific liquid-rich tight siltstone reservoir within the Montney Formation (Alberta, Canada), is analyzed in this study. Using a scanning electron microscope (SEM), back scattered electron (BSE) images, energy-dispersive X-ray spectroscopy (EDS) and cathodoluminescence (CL) images are collected to be used as inputs for an in-house image analysis software. Elemental maps obtained from EDS allow for the distribution of the mineral assemblage to be computed. Experimental observations indicate that rock petrophysical and geomechanical properties are partly controlled by the rock microstructure/microfabric in the studied Montney samples. Using a cathodoluminescence (CL) microscope and image processing, the detrital quartz grain is resolved from surrounding cement to determine the total percentage of cement in the samples. The cement content in the sixteen samples ranges from 14.5% to 23.7%, with an average overall cement content of 19.5%. For the analyzed samples, the porosity values estimated from microscopic images ranges from 3.5% to 10.4%, averaging 5.8%. The developed algorithms for indirect estimation of mineralogical composition, cementation and porosity from drill cuttings have significant practical applications for characterization of the Montney. Performing non-destructive microscopic observations using drill cuttings, these algorithms can be used as an alternative tool to provide quantitative estimates of rock fabric/texture and reservoir quality along any vertical/lateral intervals of interest within the Montney. In absence of core plugs and/or large amounts (30+ g) of crushed-rock material, the application of this integrated workflow could be of significant interest to the Montney operators, at least at the preliminary stage of stimulation treatment, to selectively target intervals along the vertical/lateral sections of the reservoir for improving performance.
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