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The low-oil-price environment continues to challenge and pressure our industry to reduce costs and optimize production. While cost reductions and efficiency improvements are always the primary focus during downturns such as we are now experiencing, history tells us that many technology and application breakthroughs have been developed in such periods. This is also a time for conducting or supporting technical studies that can provide insight on how operators can optimize production--especially from unconventional-resource developments. In the meantime, major operators are increasingly stepping out, supporting development of alternative, unconventional energy sources, such as natural gas production from gas hydrates, as the industry looks to the future. With reduced new unconventional well activity, practices such as frac-hit mitigation--pressurization of parent wells during child-well fracture stimulation--have become increasingly important to reduce parent-well proppant cleanouts as well as to maximize production from both parent and child wells.
Abstract In horizontal well shale completions, multiple stages, each often with multiple clusters, are used to provide sufficient stimulated area to make an economic well. Each created hydraulic fracture alters the stress field around it. When hydraulic fractures are placed close enough together, the well-known stress shadow effect occurs in which subsequent fractures are affected by the stress field from the previous fractures. The effects include higher net pressures, smaller fracture widths and changes in the associated complexity of the stimulation. The level of microseismicity is also altered by stress shadow effects. For example, it is commonly seen that the number of microseismic events is significantly reduced from the toe to the heal of the well, where the first frac stage is conducted at the toe of the well. In this paper, we present the results of a numerical evaluation of the effect of multiple hydraulic fractures on stress shadowing as a function of fracture spacing, shale rock mechanical properties, and the in-situ stress ratio. In addition, utilizing the inherent ability of discrete element models to evaluate shear and tensile failure along fracture surfaces, shear failure, as a proxy for microseismicity, is evaluated as a function of fracture-induced stress and stress shadowing. The results of the study provide a means to optimize shale completions by understanding the effect of stress ratio, rock mechanical parameters, and hydraulic fracture spacing on the stress shadow effect and the potential for changing fracture complexity.
Miller, Camron (Schlumberger) | Hamilton, Daniel (Schlumberger) | Sturm, Stephen (Schlumberger) | Waters, George (Schlumberger) | Taylor, Thomas (Schlumberger) | Le Calvez, Joel (Schlumberger) | Singh, Manish (Schlumberger)
Abstract The objective of this study is to better understand the impact of mineralogy, in-situ stress and natural fractures on hydraulically-induced fracture system geometry within horizontal organic shale wells. Vertical heterogeneity within organic shale occurs at a much smaller scale than that in the lateral direction. Previous studies involving borehole image analyses suggest that the lateral variability observed in most horizontal shale wells is the result of the wellbore traversing multiple layers of different rock properties (i.e., vertical heterogeneity). Results have shown that a more efficient and effective hydraulic fracture stimulation is possible when this variability is addressed in the completion design. Borehole micro -resistivity image data from horizontal wells in multiple U.S. shale basins are analyzed and compared to borehole -based micro -seismic data. Natural and drilling-induced fracture type, spacing and orientation are analyzed in order to reveal their impact on hydraulic fracture initiation and geometry. Natural fracture orientation relative to the maximum horizontal stress has been shown to influence hydraulically-induced fracture system geometry. Drilling-induced fractures are essentially miniature hydraulic fractures and provide information about near wellbore in-situ stresses that can be used to predict relative hydraulically -induced fracture initiation pressures and geometry. Previous studies have shown that fracture initiation pressure is directly proportional to clay content within organic shale reservoirs. This study provides an improved understanding of factors that ultimately control the economics of horizontal shale wells. Horizontal measurements collected during drilling or post-drill allow for (i) understanding where the wellbore is in section (i.e., well placement), (ii) visualization of how the reservoir characteristics are changing along the lateral wellbore (i.e., heterogeneity) and, (iii) planning the stimulation accordingly (i.e., treatment design). These data allow operators to predict how certain reservoir properties impact reservoir stimulation. Such correlations should lead to improved operational efficiency and better well performance, thereby increasing return on investment.
Abstract Appraisal wells in unconventional, very low permeability, resource plays require large hydraulic fracture treatments to assess economic viability. In many cases, drainage area and hydrocarbon recovery are defined by the areal extent and effectiveness of the hydraulic fracture treatment. To increase the drainage area and recovery per well, multiple hydraulic fracture treatments in horizontal and vertical wells are now common, resulting in more complex and expensive completions. Therefore, appraising the completion and hydraulic fracture treatment are just as important as appraising the reservoir. Unlike conventional reservoirs, the complexity and heterogeneity of unconventional resources can make reliable reservoir characterization difficult, which can result in significant uncertainty when evaluating appraisal well performance. Therefore, applying the appropriate technologies for unconventional reservoirs and a holistic approach are essential to properly separate reservoir quality from completion effectiveness. This paper details technologies and workflows that are essential to the reliable appraisal of unconventional resources, with an emphasis on appraising resources outside of North America. Due to the high cost of appraisal wells in most environments outside North America, operators must assess the viability of unconventional resources using as few wells as possible. The North American model of assessing unconventional reservoirs by drilling and completing a large number of wells may not be economically feasible in areas with insufficient hydraulic fracturing, drilling, and completion infrastructure. Due to the variability of both hydraulic fracture growth and reservoir characteristics in unconventional reservoirs, properly assessing new plays and subsequently optimizing fracture treatments and completions has historically been a ?trial and error? process requiring a large number of wells and significant capital risk. However, efficient evaluation of stimulation treatments and completions is now possible by combining microseismic mapping and other hydraulic fracture diagnostics with advanced logs, specialized core tests, 3D seismic, and newly developed ?unconventional? hydraulic fracture models. This holistic approach reduces the number of wells required to assess the economic viability of unconventional resources and reliably separates reservoir quality from completion effectiveness. The application of these unconventional-reservoir-specific technologies, newly developed hydraulic fracture models, and specialized workflows are illustrated using examples from North America. Introduction There are significant differences between the evaluation of unconventional resources and conventional plays. The exploitation of unconventional reservoirs requires large hydraulic fracture stimulations that contact a huge reservoir surface area and effectively connect this surface area back to the wellbore. Contacting a large reservoir surface area significantly increases hydrocarbon production rates and recovery, enabling economic development. In fact, the effectiveness of the hydraulic fracture treatment will control both well productivity and drainage area in unconventional reservoirs (Cipolla et al., 2008a). The very low matrix permeability of these reservoirs necessitates a large number of wells to effectively develop the resource base. In recent years the application of horizontal drilling has dominated unconventional reservoir development, accessing much more reservoir volume than vertical wells and reducing the number of wells required to develop the resource. The combination of multi-stage hydraulic fracture stimulation and horizontal drilling has enabled exploitation of vast North American shale resources (Arthur et al. 2008; Jenkins and Boyer 2008) and improved the economics of developing some tight gas resources (Baihly et al. 2009). However, the application of horizontal drilling and the need to perform multiple hydraulic fracture treatments adds to the complexity of the completion and results in much more uncertainty when evaluating well performance and optimizing stimulation designs and completion strategies.
Abstract This paper addresses the challenges that sub-surface and asset managers face when evaluating shale and tight gas developments during the E&A stage of a project, of having limited confidence in the production predictions, and consequently the potential revenue stream, whilst needing to quantify the sub-surface uncertainties through the commitment of a large number of wells—and costs—to assess and develop the resource. Conventional field developments rely upon both well production tools and dynamic reservoir models to estimate the production from development wells through the life of the field. In sharp contrast, the development of unconventional resources, in practice, is less reliant on these models as they currently lack the underlying physics and functionality to model the additional complexity associated with unconventional resources. Additionally, much of the required input data for these models (such as the desorption isotherms, the hydraulic fracture geometry and performance as well as the natural fracture geometries and conductivities) are absent particularly during early appraisal and development. The approach commonly used to reduce the uncertainty of these developments at the evaluation stage is a modification of the stage-gate process, through the inclusion of structured pilot projects. This provides a commercial basis for full field developments in the absence of reliable ‘class A’ production models. The paper also considers key technical uncertainties for shale gas and tight gas developments which can be assessed through pilot projects, in order to quickly evaluate the viability of a development: Of primary importance in these unconventional resources is the absence of a significant natural permeability and lateral and vertical heterogeneity, the economic consequences of which affect the methods by which these resources are assessed and developed. Sub-surface and project uncertainties that may impact the viability of developments are discussed including; water and fluid management and environmental impact assessments. Data gathering and monitoring and surveillance requirements are reviewed based on current technology in the context of reducing project and development uncertainties. The paper describes the approaches through which the production potential for an unconventional resource is evaluated through a multi-well commitment, while limiting the risk and cost exposure for the operating company.