This article discusses estimation of stresses encountered during drilling that could cause fracturing or formation damage in the near wellbore area. Ballooning is a process that occurs when wells are drilled with equivalent static mud weights close to the leakoff pressure. It occurs because during drilling, the dynamic mud weight exceeds the leakoff pressure, leading to near-wellbore fracturing and seepage loss of small volumes of drilling fluid while the pumps are on. When the pumps are turned off, the pressure drops below the leakoff pressure, and the fluid is returned to the well as the fractures close. This process has been called "breathing" or "ballooning" because it looks like the well is expanding while circulating, and contracting once the pumps are turned off.
Borehole instability is the undesirable condition of an openhole interval that does not maintain its gauge size and shape and/or its structural integrity. Figure 1 illustrates hole-instability problems. Hole closure is a narrowing time-dependent process of borehole instability. It sometimes is referred to as creep under the overburden pressure, and it generally occurs in plastic-flowing shale and salt sections. Hole enlargements are commonly called washouts because the hole becomes undesirably larger than intended.
Casing and tubing strings are the main parts of the well construction. All wells drilled for the purpose of oil or gas production (or injecting materials into underground formations) must be cased with material with sufficient strength and functionality. Casing is the major structural component of a well. The cost of casing is a major part of the overall well cost, so selection of casing size, grade, connectors, and setting depth is a primary engineering and economic consideration. Conductor casing is the first string set below the structural casing (i.e., drive pipe or marine conductor run to protect loose near-surface formations and to enable circulation of drilling fluid).
Stress concentration around the wellbore can create breakouts, fractures, or failures. Understanding the stresses on rocks around wellbores is important to well design. Here, θ is measured from the azimuth of the maximum horizontal stress, SHmax SHmin is the minimum horizontal stress; Pp is the pore pressure; ΔP is the difference between the wellbore pressure (mud weight) and the pore pressure, and σΔT is the thermal stress induced by cooling of the wellbore by ΔT. At the point of minimum compression around the wellbore (i.e., at θ 0, parallel to SHmax), Eq. 1 reduces to The equations for σθθ; and σzz are illustrated in Figure 1 for a strike-slip/normal faulting stress regime (SHmax Sv SHmin) at a depth of 5 km, where the pore pressure is hydrostatic and both ΔP and σΔT are assumed to be zero for simplicity. As indicated in Eq. 4 and illustrated in Figure 1, at the point of maximum compression around the wellbore, the maximum principal horizontal stress is amplified appreciably.
Unconventional resources such as Bakken shale have made a significant impact on the global energy industry, but the primary recovery factor still lingers from 5% to 15 %. Over the past ten years, a number of pilot tests for both gas and water injection or their cyclic injection have been implemented to improve oil recovery in the Bakken Formation. The available public data show that the injectivity is not a problem, but only a small increase in production. The obvious reason is unexpected early breakthroughs even with a relatively low reservoir permeability of around 0.03 mD. Lots of experimental and simulation studies have been conducted to investigate different mechanisms behind these improved oil recoveries. However, no one has succeeded to clarify this early breakthrough.
In this study, a simulation reservoir model, including two wells, is developed, whose properties are based on public data. In terms of hydraulic fractures for each well, their geometry and conductivities are evenly built. Furthermore, our geomechanical module is applied to capture the evolution of stress field and rock failure, where a Barton-Bandis model and a Mohr–Coulomb failure criterion are applied to model tensile and shear failure, respectively. Our simulation model coupled with the geomechanical module is then implemented to explain the performance of injection pilot test.
The results of this initial study clearly show the new fractures (frac-hits) induced by water injection connect the injection and production wells, resulting in the early water breakthrough. The stress field has also been altered by the production process to favor the formation of these fractures. This study highlights the importance of geomechanics during an IOR process; identifies the reasons for the early breakthrough and provides an insight view about how to improve oil production in the Bakken Formation.
Analytically-derived criteria are presented for the orientation of fracture initiation from horizontal wellbores drilled in porous-permeable (poroelastic) media. This involves drilling-induced tensile fractures (DITFs) from non-perforated wellbores and completion-induced hydraulic fractures (CIHFs) from perforated wellbores with cylindrical perforation geometry. The criteria are developed considering the tangential stresses on two points (extremes) around the base of the perforation; one for the initiation of longitudinal fractures and another for the initiation of transverse fractures, with respect to the wellbore. In-situ stress state, wellbore pressure, and the formation's mechanical and poroelastic properties are independent variables that are shown to control the orientation of the initiated hydraulic fractures; the dependent variable.
The DITF orientation can be used to constrain the magnitude of the maximum horizontal stress; the most difficult aspect of the in-situ stress tensor to constrain. Transverse CIHF initiation only occurs over a narrow wellbore pressure-at-breakdown window, while longitudinal initiation occurs at comparatively higher wellbore pressures. However, transverse CIHF initiation occurs more frequently than transverse DITFs, because the presence of perforations aids transverse fracture initiation. The region of the in-situ stress states where transverse initiation is promoted is shown in dimensionless plots for perforated and non-perforated wellbores. Fracture initiation criteria for specific cases presented can be used to predict the orientation of fracture initiation in oilfield operations.
The orientation of CIHFs controls the productivity of hydrocarbon reservoirs. Productivity from low permeability formations is greatly improved having multiple fractures oriented transversely rather than longitudinally, relative to a horizontal wellbore. Fracture initiation often follows a plane different to the final fracture propagation plane. Stress re-orientation in the near-wellbore region may promote fracture initiation of different orientation than the orientation dictated by the far-field stresses. The range of in-situ stress states in which transverse fracture initiation is promoted increases as Biot's poroelastic coefficient,
Massive hydraulic fracturing requires an enormous consumption of water and introduces many potential environmental issues. In addition, water-based fluid tends to be trapped in formations, reducing oil/gas-phase relative permeability, and causes clay-mineral swelling, which lowers absolute permeability. Carbon dioxide (CO2) is seen as a promising alternative working fluid that poses no formation-damage risk, and it can stimulate more-complex and extensive fracture networks. However, very little, if any, extant research has quantitatively analyzed the effectiveness of CO2 fracturing, except for some qualitative fracturing experiments that are based on acoustic emissions. In this study, we systematically examine water and CO2 fracturing, and compare their performance on the basis of a rigorously coupled geomechanics and a fluid-heat-flow model. Parameters investigated include fluid viscosity, compressibility, in-situ stress, and rock permeability, illustrating how they affect breakdown pressure (BP) and leakoff, as well as fracturing effectiveness. It is found that (1) CO2 has the potential to lower BP, benefiting the propagation of fractures; (2) water fracturing tends to create wider and longer tensile fractures compared with CO2 fracturing, thereby facilitating proppant transport and placement; (3) CO2 fracturing could dramatically enhance the complexity of artificial fracture networks even under high-stress-anisotropy conditions; (4) thickened CO2 tends to generate simpler fracture networks than does supercritical CO2 (SC-CO2), but still more-complex fracture networks than fresh water; and (5) the alternative fracturing scheme (i.e., SC-CO2 fracturing followed by thickened-CO2 fracturing) can readily create complex fracture networks and carry proppant to keep hydraulic fractures open. This study reveals that, for intact reservoirs, water-based fracturing can achieve better fracturing performance than CO2 fracturing; however, for naturally fractured reservoirs, CO2 fracturing can constitute an effective way to stimulate tight/shale oil/gas reservoirs, thereby improving oil/gas production.
Non-metallic materials such as plastics and elastomers are widely used for sealing in downhole operations of the oil and gas industry. These materials are used because of their inherent elasticity and resilience over a wide range of deformation, and their non-corrosive nature compared to metals. Downhole non-metallic seal development is an exceptionally complicated task with huge uncertainties due to the hostile operating environment and service longevity. In addition, the field operation is expensive; failure of the downhole seals could cost millions of dollars. Therefore, prior to the release of a non-metallic seal product for downhole applications, extensive material tests should be done in every step in its development from the material selection/development, seal design, seal manufacture to the quality control of the final product to ensure the seal could be safely used in downhole conditions for the service time.
This paper presents a big data method based on tremendous amount of material data to accelerate the downhole seal development. Traditional seal development starts with previous experience to select the seal material and relies greatly on the engineering tool test to validate and optimize the seal design. In contrast, the materials big data method can speed up the development cycle, reduce the uncertainty of the design, minimize the engineering hours spent on data search, guarantee the source and qualify of data used, eliminate redundant testing, and secure the data storage and sharing, etc. Our business experience showed that the materials big data method could reduce 50% human resource while achieving multiple times of productivity.
Differential compaction is an inherent process in carbonate systems that is thought to produce early natural fractures prior to any significant burial. Such fractures can persist and can be major permeability pathways, including areas of minor tectonic overprint. We forward model differential compaction fracturing in a carbonate reservoir in effort to predict the location of fractures in the subsurface.
3D finite-element geomechanical models are created to simulate differential compaction fracturing at a carbonate platform scale (kilometers) and the smaller carbonate build-up scale (10s of meters) commonly present within carbonate platforms. Interpreted seismic surfaces of key reservoir horizons are used as an input for the platform-scale model. Geometry of carbonate build-up from an outcrop analog is used for the build-up scale models. In both type of models layers identified to be compaction prone are restored to their expected pre-compaction state. A simplified mechanical stratigraphy scheme is adopted to distribute mechanical properties within the models consistent with their expected pre-burial properties.
Geomechanical modeling in this study was applied to a field which includes two carbonate platforms at different stratigraphic levels. Modeling results predict increased fracture intensity at the windward margin of the carbonate platform. This coincides with increased windward-leeward asymmetry of an underlying older platform. Increased fracture intensity is predicted at the center of the platform where the underlying older platform displays significantly less asymmetry. Predicted fracture locations over the platform top also correspond with the location of carbonate build-ups identified from seismic data. Fracture observations from image logs and indirectly from mud loss data within the upper platform are consistent with our modeling results. Predicted areas of greatest fracture intensity correspond with the location of wells with the highest fracture intensity observed from image logs.
Build-up scale models suggest that the build-up shape exerts a major control on the resulting differential compaction fracture pattern. Elongate build-ups tend to produce fractures oriented parallel to their axes. Circular build-ups tends to produce radial fracture patterns. Fracture orientation from image logs along with build-up shape observed using the coherence seismic attribute are consistent with these findings.
This study offers a process-based fracture modeling approach that can enhance the predictability of the location and orientations of natural fractures in carbonate reservoirs.