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Summary Drilling depleted reservoirs often encounters a host of problems leading to increases in cost and nonproductive time. One of these problems faced by drillers is lost circulation of drilling fluids, which can lead to greater issues such as differential sticking and well-control events. Field applications show that wellbore strengthening effectively helps reduce mud-loss volume by increasing the safe mud-weight window. Wellbore-strengthening applications are usually designed on the basis of induced-fracture characteristics (i.e., fracture length, fracture width, and stress-intensity factor). In general, these fracture characteristics depend on several parameters, including in-situ stress magnitude, in-situ stress anisotropy, mechanical properties, rock texture, wellbore geometry, mud weight, wellbore trajectory, pore pressure, natural fractures, and formation anisotropy. Analytical models available in the literature oversimplify the fracture-initiation and fracture-propagation process with assumptions such as isotropic stress field, no near-wellbore stress-perturbation effects, vertical or horizontal wells only (no deviation/inclination), constant fracture length, and constant pressure within the fracture. For more-accurate predictions, different numerical methods, such as finite element and boundary element, have been used to determine fracture-width distribution. However, these calculations can be computationally costly or difficult to implement in near-real time. The aim of this study is to provide a fast-running, semianalytical work flow to accurately predict fracture-width distribution and fracture-reinitiation pressure (FRIP). The algorithm and work flow can account for near-wellbore-stress perturbations, far-field-stress anisotropy, and wellbore inclination/deviation. The semianalytical algorithm is modeled after singular integral formulation of stress field and solved by use of Gauss-Chebyshev polynomials. The proposed model is computationally efficient and accurate. The model also provides a comprehensive perspective on formation-strengthening scenarios; a tool for improved lost-circulation-materials design; and an explanation of how they are applicable during drilling operation (in particular, through depleted zones). Sensitivity analysis included in this paper quantifies the effect of different rock properties, in-situ-stress field/anisotropy, and wellbore geometry/deviation on the fracture-width distribution and FRIP. In addition, the case study presented in this paper demonstrates the applicability of the proposed work flow in the field.
Abstract Drilling depleted reservoirs is often encountered with a host of problems leading to increase in cost and non-productive time. One of these faced by drillers is lost circulation of drilling fluids which can lead to bigger issues such as differential sticking and well control events. Field applications show that wellbore strengthening effectively helps reduce mud loss volume by increasing the safe mud weight window. Wellbore strengthening applications are usually designed based on induced fracture characteristics (i.e., fracture length, fracture width and plug location within fracture). In general, these fracture characteristics depend on several parameters, e.g., in-situ stress magnitude, in-situ stress anisotropy, mechanical properties, rock texture, wellbore geometry, mud weight, wellbore trajectory, pore pressure, natural fractures, formation anisotropy and among others. Analytical models available in the literature oversimplify fracture initiation and propagation process with assumptions such as: isotropic stress field, no near wellbore stress perturbation effects, vertical or horizontal wells only (no deviation/inclination), constant fracture length and constant pressure within the fracture. For more accurate predictions, different numerical methods, i.e., finite element, boundary element, etc., have been utilized to determine fracture width distribution. However these calculations can be computationally costly or hard to implement in near real time. The aim of this study is to provide a fast running, semi-analytical workflow to accurately predict fracture width distribution and fracture re-initiation pressure (FRIP). The algorithm and workflow can account for near wellbore stress perturbations, far field stress anisotropy, and wellbore inclination/deviation. The semi-analytical algorithm is based on singular integral formulation of stress field and solved using Gauss-Chebyshev polynomials. Proposed model is computationally efficient and accurate. The model also provides a comprehensive perspective on the formation strengthening scenarios; a tool for improved LCM design and how they are applicable during drilling operation (in particular through depleted zones). Sensitivity analysis included in this paper quantifies the effect of different rock property, in-situ stress field/anisotropy and wellbore geometry/deviation on the fracture width distribution and FRIP. Additionally, the case study presented in this paper demonstrates the applicability of the proposed workflow in the field.
Abstract Lost circulation caused by low fracture gradients is the cause of many drilling related problems. Typically the operational practice when lost circulation occurs is to add loss circulation materials (LCM) to stop mud from flowing into the formations. To improve the treatment for lost circulation caused by low fracture gradients, especially designed materials in mud system are used to seal the induced fractures around the wellbore. This operation is in the literature referred to as wellbore strengthening that has been found to be a very effective in cutting Non-Productive Time (NPT) when drilling deep offshore wells. Size, type and geometry of sealing materials are debating issues when different techniques are applied. Also the phenomenon is not truly understood when these techniques applied in different sedimentary basins. This paper presents development and simulation results of a three-dimensional Finite-Element Model (FEM) for investigating wellbore strengthening mechanism. This study also describes a procedure for designing Particle Size Distribution (PSD) in field applications. To better understand the numerical results, the paper also reviews the connection between Leak of Tests (LOTs) and wellbore hoop stress and how these LOTs can mislead in fracture gradient determination. A comprehensive field database was collected from different sedimentary basins for this study. Results demonstrate that the maximum attainable wellbore pressure achieved by wellbore strengthening is strongly controlled by stress anisotropy. Results also show that Particle Size Distribution (PSD) of wellbore strengthening should be designed in order to seal the fractures close to the mouth and at fracture tip. This will result both in maximizing hoop stress restoration and tip-screening effects. In addition this model is able to show the exact fracture geometry formed around the wellbore that will help to optimize the sealing materials design in wellbore strengthening pills. To support numerical modeling results, near wellbore fracture lab experiments on Sandstone and Dolomite samples were also presented. Laboratory experiments results reveal importance of rock permeability, tensile strength and fluid leak-off in wellbore strengthening applications.
Abstract Hydraulic fracturing is recognized as a successful stimulation technique for enhanced hydrocarbon recovery from unconventional tight reservoirs. Technological advancement in directional drilling has led the petroleum industry to drill arbitrarily oriented wellbores for exploitation of reservoirs, which otherwise could not be economically produced. Prediction of fracture initiation from such wellbores is therefore essential for petroleum industries to undertake efficient hydraulic fracturing stimulation tasks. In a hydraulic fracturing process, fluid is injected under pressure through the wellbore in order to overcome native stresses and to cause failure of rocks, thus creating fractures in a reservoir. These fractures create a passage through which hydrocarbon flows into the well from the shale formation. Based on the superposition principle and elasticity theory, a total stress field mathematical model while staged fracturing for horizontal well is abstractly presented in this paper, considering systematically influencing factors such as wellbore pressure, in-situ stress distribution, seepage effect of fracturing fluid, and induced stress produced by hydraulic fracture. The law of initial and subsequent fractures initiation is studied. The results show that the initial fracture initiation is affected by the wellbore azimuth angle, and it is easy for transverse fractures to form when the minimum in-situ horizontal stress along the wellbore direction. The stress distribution around wellbore is influenced by induced stress field, and when the initial fracture height is constant, the effect decreases gradually along wellbore direction until the combined stress field tends to the in-situ stress field. In a certain position from the initial fracture, the bigger the fracture height, the greater the induced stress, and in particular, the influence on induced stress along the wellbore direction is more obvious. Induced stress can increase subsequent fractures initiation pressure, whose level will reach 30% and increase as the fracture height increases. When fracture height is constant, the increase level of initiation pressure decreases rapidly with the increase of fracture spacing. There is well coincidence between computational solution and measured result. Results from the analytical and numerical models used in this study are interpreted with a particular effort to enlighten the causes of abnormally high treating pressures during hydraulic fracture treatments, as well as engineers study recovery techniques.