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Abstract Shale formations have laminated structures which result in significant differences in mechanical properties along the orientations parallel to and perpendicular to laminations (bedding planes). These differences lead to anisotropic horizontal stresses. Failure to consider the effect of anisotropic behavior of shale can have severe consequences for drilling. In rocks with anisotropic mechanical properties and strength, there is a high risk of wellbore instability while building deviation angle from vertical sections. Conventional wellbore stability analysis approaches do not consider material anisotropy and laminated nature of shales, which can result in underestimated stresses leading to incorrect safe trajectory or mud-weights. Shale formations in the Horn River Basin (HRB) are strongly anisotropic with anisotropic ratios varying from 1.2 to 3.5. In this paper, the authors demonstrate the importance of considering anisotropy in estimation of in-situ stresses and wellbore stability analysis. Two field case study examples are presented to underscore the consequences of neglecting anisotropy in wellbore stability analysis.
Abstract The hydraulic fracturing stimulation of unconventional shale reservoirs requires the identification of sections along the well with good reservoir and completion quality. Completion quality depends on the poromechanical properties of the reservoir. Shales are known to exhibit anisotropic elastic properties. The elastic anisotropic of shales is of first order as it affects four key geomechanical steps: the in-situ stress field, the stress concentration around the borehole, the failure properties both in tension and compression and the geometry of the hydraulic fracture. Consequently, the initiation pressure of hydraulic fractures at the wellbore predicted by data and models taking into account the anisotropy can be lower or higher by up to 100% as compared to isotropic conditions. We performed a thorough sensitivity analysis of in-situ stress, material anisotropy and well orientation conditions for different scenarios for far field in-situ stress and near field borehole stress, under isotropic and anisotropic conditions. We consider three scenarios. Scenario-1 where both the far field in-situ stress and the near field borehole stress are computed under isotropic assumption. Scenario-2 where only the far field in-situ stress is computed using anisotropic assumption while keeping the isotropic solution for stress concentration is kept. Scenario-3 where both the far field in-situ stress and the stress concentration take into account the material anisotropy. In addition, for each scenario, we considered three different σH/σh cases. This study shows that the full anisotropic solution or scenario 3 is always the most appropriate one for predicting correct initiation pressures and the pressure is always lower for the anisotropic case. It is clear that the observed effects are magnified by the degree of anisotropy of the rock, i.e. each rock or formation will influence differently the initiation pressure. We conclude that the material anisotropy is affecting the in-situ stress model as well as the stress concentration around the borehole. Both effects need to be considered in order to account for the anisotropy. If the effect of the anisotropy is taken into account, for both the far and the near field, it will be possible to better predict the initiation pressure and better stimulate unconventional reservoirs.
Abstract Unconventional shale-gas reservoirs are complex systems with predominant layered heterogeneity. This results in high variability in material properties and in considerable contrast in mechanical and elastic properties along orientations parallel and perpendicular to bedding. Understanding the effect of this variability in strength and elastic properties with bed orientation, to hydraulic fracturing breakdown pressures, height containment, and long-term stability of wellbores and perforations, are of highest interest to unconventional, shale gas, reservoir applications. Successful hydraulic fracturing is fundamental for economic production from nano-darcy permeability gas shales. By incorporating anisotropic elastic deformation, to better represent the behavior of unconventional tight gas reservoirs, we facilitate the understanding of nearwellbore stress concentrations and their effect on fracture initiation. Results show that strong elastic anisotropy results in lower breakdown pressures and lower tortuosity at the wellbore face. As a consequence, selecting perforating intervals along sections with highest elastic anisotropy minimize fracture initiation problems, and results in lower treating pressures. In addition, elastic anisotropic behavior influences the magnitude of the minimum horizontal stress and the potential for fracture containment. Traditional isotropic-rock models do not capture this behavior. When applied in anisotropic formations these models misrepresent the potential of fracture containment. This leads to erroneous selections of perforation intervals (vertical completion) or landing depths of horizontal wellbores. A third consequence of strength and elastic anisotropy is the high risk of wellbore stability during drilling. In rocks with changing elastic moduli and strength with bed orientation, the highest risk of wellbore failure often occurs during building angle from the vertical to the horizontal directions. Along this path, there is a critical angle, defined by the strength anisotropy of the rock that will maximize the risk of failure. Minimizing this risk, e.g., by controlling the mud weight or well inclination, is of principal importance to the economic success of the play. In this paper we conduct numerical simulations on unconventional gas shales, exhibiting moderate to strong elastic and strength anisotropy, to evaluate the effect of their anisotropic behavior on well construction and completion. We also show that traditional isotropic models may lead to erroneous completion decisions, and underestimating the risk of wellbore failure. We conclude by suggesting that modeling and predicting near-wellbore effects of horizontal completions and wellbore stability in anisotropic shales is straightforward, provided that appropriate measurements of anisotropic strength and elastic properties are obtained on each of the various lithofacies present in the system.
Abstract Production from nanodarcy-range permeability shale formations requires extensive hydraulic fracturing, large volumes of water, and close-spaced wells. The current trend, which includes increasing lateral lengths, increasing the number of perforation stages, and increasing the volume of water and proppants pumped, is unsustainable. Comparing calculations of the possible surface area created during fracturing versus production results indicate that a large portion of the surface area is ineffective to production, resulting in ineffective use of resources and increased costs. This paper describes the fundamental understanding required to improve the efficiency of horizontal completions in oil- and gas-producing shales. Using extensive laboratory characterization of mechanical properties on core, core/log integration, and continuous mapping of these properties by logging-while-drilling (LWD) methods along the horizontal wellbore, appropriate guidelines are defined for effective perforation and fracturing to improve the efficiency and sustainability of horizontal completions. The objective of the study is to improve completion design and horizontal well completions efficiency. This objective is achieved by adequate selection of perforation intervals based on understanding the relevant physical processes and adequate rock characterization. Two reservoir regions, the near-wellbore and the far-wellbore, are defined and essential to completion design. Conditions at the far-wellbore region, which define the extent of the surface area in contact with the reservoir, are fundamental to well productivity. However, these conditions are often poorly understood. The near-wellbore region is the choking point to production, provided that ideal far-wellbore conditions exist. Properties along the near-wellbore region can be measured and are better understood. In this paper, these properties are used to minimize the near-wellbore choking effect by evaluating rock types that maximize near-wellbore fracture width, minimize breakdown pressures, and reduce the potential of solids production during the initial drawdown. The result is a nonsubjective and consistent methodology that defines the variability in near-well fracture performance along wellbores and allows selecting perforation stages based on measured or inferred rock properties (from LWD or drill cuttings analysis). Finally, the method that will be described provides a means for monitoring and comparing consistency between the predicted values and measured results by comparing the results to actual production data. The results of this study show the need to better understand the far-wellbore conditions as well as the near-wellbore conditions when making inferences about well production.
Abstract The placement of multiple hydraulic fractures along cased and cemented horizontal wellbores drilled in the direction of minimum horizontal stress is the most common completion methodology used in the development of organic shales today. Multiple perforation clusters are included in each stimulation treatment to optimize time and efficiency. This does not necessarily result in optimized productivity as many perforation clusters are frequently determined not to be contributing to production when these wellbores are evaluated with horizontal production logs. The ability to initiate, propagate and place proppant through the near-well region of a hydraulic fracture is a function of stresses around the borehole and the orientation of the borehole relative to the principle stress field. The near-well stresses are influenced by the anisotropic geomechanical medium pervasive in organic shales. This anisotropy can dramatically alter the stress field and must be taken into account if productivity is to be optimized along a horizontal wellbore. Field data from the Barnett Shale is evaluated to estimate the impact of this anisotropy on the ability to initiate and place hydraulic fractures through the near-well region. Fracture initiation and near-well closure pressures are measured and compared to those predicted by accounting for geomechanical anisotropy. These results are used to develop guidelines for effective perforation placement. Such techniques can be used to improve well productivity.