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Collaborating Authors
Well Completion
Abstract Hydraulic fracturing is a widely used technique in oil and gas production to increase the permeability of near-well reservoir and enhance hydrocarbon recovery. Modeling hydraulic fracturing involves solving coupled multi-physics equations in a robust numerical solution scheme. We present a generalized finite element framework to simulate the propagation of fluid-driven fractures in a linear elastic medium. The fluid flow within the fracture is described by the Reynolds lubrication equation, where the classical cubic law links the fluid pressure gradient and the flow rate in the fracture plane. The GFEM framework allows fractures to propagate inside the cells, and thus finite element discretization can be non-conforming with fracture geometry. The fluid front is tracked to permit fluid lag during the simulations. A unified traction-separation law is proposed to model the mechanical behavior of the fracture faces, including contact, cohesion and interface strength softening. The traction-separation law on the fracture faces is enforced by a penalty method. The coupled nonlinear system is solved by a standard Newton-Raphson method. Several 3D numerical studies and benchmarking examples are presented to demonstrate the capability of the proposed framework in modeling fluid-driven fracture propagation. 1. INTRODUCTION Hydraulic fracturing is a technique widely used in the oil and gas industry to enhance hydrocarbon recovery from underground reservoirs. The process often results in the initiation and growth of tensile fractures, typically driven by viscous fluid that is injected into the rock with relatively high flow rate and high pressure. After the fracture is generated, certain sand-like propping agents (also called ’proppants’) are introduced into the newlyformed fracture to prevent full closure after the fluid pressure is released. Studies on hydraulic fracturing can also be found in other geomechanical applications such as geothermal energy recovery [1], transportation of magma through earth’s crust [2], sequestration of CO2 [3], embankment dam failures [4], and induced caving in mining [5].
- North America > United States (1.00)
- Europe (0.68)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (0.88)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (0.54)
Abstract The interaction of hydraulic fractures with the pre-existing natural fractures may play a major role in increasing productivity from unconventional formations. When a hydraulic fracture meets a natural fracture, the hydraulic fracture can cross the natural fracture or be arrested. If the natural fracture is permeable, fracturing fluid can leak from the hydraulic fracture into the natural fracture causing elevation of pore pressure in the natural fracture and reducing the effective normal stress acting on the natural fracture, which could then lead to shear failure or slippage along the natural fracture plane. Shear-slip causes dilation, potentially increasing fracture conductivity and enhancing fluid flow deeper into the natural fracture. The conductivity of unpropped shear-induced fractures can play an important role in enhancing the productivity from ultralow-permeability formations like shale. In this paper, we first evaluate analytically the shear-slip condition and its propagation along a natural fracture under remote normal and shear stresses, when it is exposed to the fluid pressure in a hydraulic fracture. Analytical approximations under some limiting conditions are considered. A rigorous 2D numerical model based on coupling between fluid flow and rock deformation using displacement discontinuity method and fluid flow in the fracture is then described. The results of numerical simulations are presented to illustrate the effect of rock stress anisotropy, initial natural fracture conductivity, and fluid properties on the evolution of the fluid and slip fronts along the natural fracture and the associated permeability enhancement. 1. INTRODUCTION In the last decade, following the success of horizontal drilling and multistage fracturing in the Barnett Shale, exploration and drilling activities in shale gas and shale oil reservoirs have skyrocketed in the US and abroad. Economic production from these reservoirs depends greatly on the effectiveness of hydraulic fracturing stimulation treatment. Microseismic measurements and other evidence suggest that creation of complex fracture networks during fracturing treatments may be a common occurrence in many unconventional reservoirs [1-3]. The created complexity is strongly influenced by the preexisting natural fractures and in-situ stresses in the formation. To optimize the fracture and completion design to maximize the production from these reservoirs, engineers must have a good understanding of the fracturing process and be able to simulate it to obtain information such as the induced overall fracture length and height, propped versus unpropped fracture surface areas, proppant distribution and its conductivity, and potential enhanced permeability through stimulation of the natural fractures.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.95)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Mississippi > Woodlands Field (0.89)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
Experimental Demonstration of Delayed Initiation of Hydraulic Fractures below Breakdown Pressure in Granite
Lu, G. (University of Pittsburgh) | Uwaifo, E. C. (University of Pittsburgh) | Ames, B. C. (University of Pittsburgh) | Ufondu, A. (University of Pittsburgh) | Bunger, A. P. (University of Pittsburgh) | Prioul, R. (Schlumberger Doll Research) | Aidagulov, G. (Schlumberger Dhahran Carbonate Research)
Abstract A laboratory investigation has been carried out to investigate delayed initiation of hydraulic fractures where wellbore pressures are insufficient to induce instantaneous breakdown. The delayed initiation process we are investigating is related to so-called static fatigue, which refers to a property of many brittle/quasi-brittle materials, including rocks, to fail in a delayed manner when subjected to an applied stress that does not exceed the material strength. In this paper, we experimentally verify a limiting case of a theoretically predicted delay time of initiation for given wellbore pressures. The investigation has two parts: characterization of the static fatigue behavior of a given rock and hydraulic fracture initiation experiments. For rock characterization, three-point and four-point bending tests are used to obtain time to failure versus applied tensile stress relationships for Coldspring Charcoal Granite specimens. Then, using an apparently geometry-independent static fatigue parameter and classical hydraulic fracture breakdown theories, we predict and subsequently test the time to failure for different wellbore pressures in the laboratory. We present our laboratory observations and measurements on delayed failure of axially oriented hydraulic fracture initiation. Our results verify the existence of delayed initiation of hydraulic fractures, and they demonstrate the ability of straightforward theoretical considerations to predict the initiation time. Comparison between experimental data and prediction also suggests that the effect of fluid penetration plays an important role in delayed initiation, evidenced by the tendency for the longer-time initiations at lower pressures to fall below the theoretical prediction. 1. INTRODUCTION Most approaches to stimulation of horizontal wellbores rely on initiation and growth of more than one hydraulic fracture. Past studies on the topic of initiation of hydraulic fractures predict the wellbore pressure at which initiation will occur [1-6]. In the classical hydraulic fracture breakdown models (Hubbert and Willis [1] and Haimson and Fairhurst [2]), initiation will not occur if the near-wellbore tensile stress induced by fluid pressure is less than the tensile strength of the rock formation. However, it has been observed in many laboratory experiments that brittle/quasi-brittle materials, including rocks, can be caused to fail after a period of time when subjected to a sustained static load that is lower than its strength [7, 8]. This behavior is referred to as "static fatigue." In one recent example, Kear and Bunger [8] show that for a crystalline gabbroic rock, applying a load as low as 75% of its nominal tensile strength onto the sample can cause failure within a few hours. Therefore, the concept of tensile static fatigue in brittle/quasi-brittle rocks leads to the central question of this paper: Is it possible for a hydraulic fracture to be initiated under wellbore pressure less than critical breakdown pressure? We seek an answer by theoretical study and laboratory experimentations.
- North America > United States (1.00)
- Asia (0.93)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Igneous Rock > Granite (0.63)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Well Drilling > Wellbore Design > Wellbore integrity (0.86)
Abstract This research examines stress variations with depth in the Permian Basin Spraberry/Dean/Wolfcamp Shale to understand why many microseismic events occur at upper formations when we hydraulically fracture the lower formations. An interesting phenomenon of drilling-induced tensile fractures is observed in the image log. That is, there are drilling-induced tensile fractures in the Spraberry and Dean formations, but there are no drilling-induced tensile fractures in the Wolfcamp formation. This brings out a question: how variable is the stress state with depth? We estimate the pore pressure and the three principal stresses with depth to answer this question. The pore pressures and minimum principal stresses are analyzed from the Diagnostic Fracture Injection Test, which are consistent with literatures. Maximum horizontal stress in the Spraberry formation is constrained by observation of drilling-induced tensile fractures, while maximum horizontal stress in the Wolfcamp formation is constrained through the estimation of Uniaxial Compressive Strength. We find the stresses in the Wolfcamp formation are more isotropic than those in the Spraberry formation. More importantly, the decreasing of the pore pressure gradient and the frac gradient when going from the lower formation to the upper formation leads to many out-of-zone microseismic events. 1. INTRODUCTION The Permian Basin represents one of the nation’s oldest and most widely recognized hydrocarbon bearing regions. Unlike other plays such as the Bakken and Eagle Ford, the Permian shows much greater geologic complexity, consisting of several unique sub-basins (Fig. 1), each with its own unique characteristics [1]. The specific area studied in this research is in Midland Basin, which is east of the Central Basin Platform, west of the Eastern Shelf, and north of the Val Verde Basin. The formations discussed in this paper are the Spraberry, Dean, and Wolfcamp series, which are at the bottom of the Permian system. The three formations are mainly shale facies, but with high mechanical complexity. Fig. 2 shows the wells we studied, which are drilled in the Spraberry/Dean/Wolfcamp formations. Most data, including sonic log data, Formation Microresistivity Image (FMI) data, and core test data, come from the monitor well M. Besides, we analyze the Diagnostic Fracture Injection Test (DFIT) in four horizontal wells, A, B, C, and D.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.83)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.61)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (0.97)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (30 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract The paper describes the principal geomechanical approaches to ensuring stability and integrity in mining salt deposits. The various dimensioning methods usually applied are subjected to a comparative analysis. Geomechanical discontinuum models are identified as essential physical models for examining how the collapse of working fields in potash mining areas can occur. A visco-elasto-plastic material model with strain softening, dilatancy and creep is used to describe the time-dependent softening behaviour of the salt pillars. The pillar stability critically depends on the shear conditions of the bedding planes to the overlying and underlying beds. Therefore, a shear model is introduced, describing interface properties, i.e. velocity-dependent adhesive friction with shear displacement-dependent softening for the bedding planes and discontinuities in the contact zone of the pillars with the surrounding salt rocks. As an outcome, the fundamental mechanical and hydraulic conditions that lead to an integrity loss of saliferous barriers are derived. Several examples of worldwide events of flooded salt mines are back-analysed with coupled hydro-mechanical calculations, demonstrating the prominent role of fluid-pressure-driven generation of hydraulic flow paths as a failure mechanism of saliferous barriers. 1. INTRODUCTION For a long time, the dimensioning of underground openings in salt rocks was primarily based on mining experience. Only in the last century, analytical and numerical calculation methods of geomechanics have been increasingly used. This was not least due to some catastrophic collapses of mining fields (rock bursts) with a strong mining-induced energy release [1], and the loss of potash and rock salt mines by flooding. Both practical experience and geomechanical calculations are essential for an economical and sustainable salt extraction at high recovery rates and complement each other. The fundamental requirements of safe dimensioning for potash or rock salt mining are the guarantee of stability of the mining system integrity and protection of the hydraulic protection layers or geological barriers. For the collapse of mining fields insufficient pillar dimensioning and the brittle fracture behaviour of the mined rock salt played a particularly crucial role [2]. The tendency of brittle fracture decreases from carnallitite, hard salt, trona, sylvinite to rock salt. Therefore, rock bursts occurred primarily in potash mines where carnallitite was mined. In sylvinite and rock salt mines few rock bursts are known worldwide, only if extremely high recovery rate and, accordingly, very slender pillars were realised. The analysis of in situ collapses provides a basis to check dimensioning approaches and to derive empirical relationships for the necessary ratio of pillar width to pillar height (slenderness ratio), which is required ensure the viability and stability of pillars in salt rocks.
- Europe (1.00)
- North America > United States > Kansas > Butler County (0.24)
- Geology > Mineral > Halide > Halite (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Materials > Metals & Mining (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.93)
- North America > United States > North Dakota > Williston Basin > Dawson Bay Formation (0.99)
- North America > Canada > Alberta > French Field > Arl French 16-26-64-1 Well (0.98)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (0.95)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (0.67)
Abstract In this paper we summarize and compare numerical simulation results of injection-induced fault reactivation and seismicity associated with underground CO2 injection and hydraulic fracturing of shale-gas reservoirs. Overall, the analysis shows that while the CO2 geologic sequestration in deep sedimentary formations are capable of producing notable events (e.g. magnitude 3 or 4); the likelihood for such felt events is much smaller in the case of shale-gas fracturing. The reason is that CO2 geological sequestration involves injection and pressure disturbances at much larger scale and duration than in the case of shale-gas fracturing. In the case of shale-gas fracturing, the expected low permeability of faults intersecting gas-saturated shales is clearly a limiting factor for the possible rupture length and seismic magnitude. For a fault that is initially impermeable, the only possibility of larger fault slip events would be opening by hydraulic fracturing allowing pressure to permeate along the fault causing a reduction in the frictional strength over a sufficiently large fault surface patch and very brittle fault properties that would allow sudden (seismic) shear slip to develop over a sufficient large rupture area. In both CO2 sequestration and shale-gas fracturing, the brittleness of the rock is an important factor, which is a site-specific factor and it should be considered when assessing the likelihood of felt seismicity. 1. INTRODUCTION The potential for fault reactivation and induced seismicity are issues of concern related to both geologic CO2 sequestration and shale-gas fracturing [1-7]. It is well known that underground injection may cause induced seismicity depending on site-specific conditions, such as stress and rock properties and injection parameters. In the case of shale-gas fracturing, only three cases of felt seismicity have been documented out of hundreds of thousands of hydraulic fracturing stimulation stages performed to-date [5]. So far no sizeable seismic event that could be felt by humans on the ground surface has been documented associated with CO2 sequestration activities [2, 7]. However, at future industrial scale projects for CO2 sequestration, a much larger rates and volumes than current pilot scale projects would be required to mitigate the global emission of greenhouse gases.
- Europe (1.00)
- North America > United States > Oklahoma (0.47)
- North America > United States > California (0.47)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (11 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
Abstract During a previous solute transport study (TRUE Block Scale) at the Äspö Hard Rock Laboratory in Oskarshamn, Sweden, an extensive characterization of a 100m scale rock volume was undertaken with an emphasis on fracture and deformation zone geometry and connectivity. The construction of a new experimental tunnel (TASS) adjacent to the TRUE Block allowed the opportunity for the detailed characterization of one of the key hydraulic conductors, a brittle-ductile shear zone named Structure #20. Utilizing high-resolution HDR and UV digital images alongside hydraulic interference analysis, borehole core and image log analysis, tunnel wall mapping and mineralogical analysis of fracture fillings, this study focused on understanding the geometric, mineralogical, structural and hydraulic heterogeneity of Structure #20 at a scale (centimeter to decimeter) important to radionuclide transport understanding. The result was a greater understanding of the in-plane variability of an important class of structural features in rock types typical for proposed high-level spent nuclear fuel repositories in the Nordic countries. 1. THE ÄSPÖ HARD ROCK LABORATORY The Äspö Hard Rock Laboratory (HRL) is a key element in the research and design of geological spent nuclear fuel repositories in Sweden. Seated approximately 450 m beneath the island of Äspö off the eastern coast of Sweden near the city of Oskarshamn, construction of the Äspö HRL began in 1990 and ended in 1995, though the excavation of new experimental niches and tunnels continues [1]. The geology of Äspö HRL is dominated by granitoids of the Trans-Scandinavian Igneous Belt, but also includes fine-grained granite dikes and sheets, mafic inclusions and xenoliths [2]. The age (1.85 Ga), mineralogy and chemistry of the rocks at Äspö are similar to those at the candidate sites (Forsmark, Laxemar and Olkiluoto) for spent nuclear fuel repositories elsewhere in the Nordic countries. Äspö is run by the Swedish Nuclear Fuel and Waste Management Company (SKB), an organization tasked with the disposal and safety of the legacy of Sweden’s nuclear power program. Äspö HRL is used for the development of systems and processes for safe long-term storage of spent nuclear fuel using the KBS-3 concept.
- Geology > Geological Subdiscipline > Mineralogy (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.69)
- Geology > Rock Type > Igneous Rock > Granite (0.55)
- Water & Waste Management > Solid Waste Management (1.00)
- Energy > Power Industry > Utilities > Nuclear (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (0.93)
- (2 more...)
Abstract Elastic parameters of rocks are typically used for design purposes in open pit and underground mining, underground spaces and rock-cutting projects. However, the ultimate strength of rocks is strongly influenced by their micro-fractures, preexisting cracks, and anisotropy due to inhomogeneity, discontinuities, and differing particle sizes or shapes and orientations. Since the fracture behaviour of rocks is important to geotechnical engineers concerned with the design of excavations and underground spaces, it is obvious that laboratory investigations of their anisotropic parameters are necessary for safe designs. The main objective of this paper is to investigate the effect of different orientations of the anisotropy of Brisbane sandstone specimens subjected to diametral compressive (indirect tensile) loading that influences their fracture toughness. To obtain the fracture toughness values of anisotropic Brisbane sandstone, Cracked Chevron Notch Brazilian Disc (CCNBD) specimens were prepared and tested according to International Society for Rock Mechanics (ISRM) standards. The fracture toughness of Brisbane sandstone was found to increase with increasing angle of anisotropy. Based on the experimental results, a statistical regression analysis was conducted to obtain the optimum orientation angle to obtain the highest strength under indirect tensile loading. Statistical analysis showed anisotropy orientations of 45° gave the highest fracture toughness value. 1. INTRODUCTION Rocks exhibit different types of anisotropy and discontinuities that affect their fracturing and strength behaviour. The anisotropy of sandstone has been recognised for about 70 years [1], and fracture propagation in sandstone and other anisotropic rocks is preferentially oriented [2]. Anisotropy also plays a dominant role in determining the velocity of elastic waves in sedimentary rocks. The most critical measure of elastic wave velocity in rocks that exhibit anisotropy is the horizontal velocity [3]. The elastic wave velocity is reduced by the opening of micro-fractures, ultimately resulting in failure [4, 5]. The uniaxial compressive strengths of anisotropic rocks parallel and normal to the orientation of the anisotropy are different, and the most reliable estimates of their resistance to fracturing and their strength is obtained when rock cores are drilled normal or near-normal to the weakest plane [6]. To determine design parameters for anisotropic rocks from laboratory test results, both maximum and minimum strengths must be measured. In addition, it has been observed that the strength of rock joints, another example of rock anisotropy, are a function of the orientation of the applied loading [7]. Generally, the effect of anisotropy decreases with increasing applied vertical stress on the rock joints. The roughness of the joint is another significant parameter that effects their strength.
- North America > United States (0.47)
- Oceania > Australia (0.29)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (0.89)
Abstract Measurement of the shear to normal compliance ratio is one of the few remote sensing techniques available for estimating the in situ properties of fractures. We present an accurate yet efficient method for predicting the normal and shear compliance of fractures using an asperity-based approach. The resultant capabilities provide an efficient, versatile tool for predicting the normal and shear compliance of fractures with arbitrary roughness under a given level of closure stress. We apply the method to the prediction of evolving shear compliance under closure stress. We also calculate the corresponding anisotropic conductivity of the deformed fractures and find that the direction of highest shear compliance correlates well with the direction of highest fracture conductivity. This suggests that the degree of shear compliance anisotropy may be an indicator of conductivity anisotropy in natural fractures over a range of stresses. 1. INTRODUCTION Seismic and acoustic measurements are the most readily available methods for inferring the mechanical properties of fractures and faults in the field. As a consequence, many authors have sought to develop approaches that can relate the geometric properties of a fracture to its seismic or acoustic signature. In particular, the ratio of shear compliance to the normal compliance has been pursued as an indicator of the microstructure within a fracture or as an indicator of fluid content [1]. Kachanov et al. [2] studied the similarities and difference between treating fractures as surfaces with discrete points of contact versus traction-free cracks. They found that although the resulting formulas for the fracture compliances have similar form, the microstructural parameters controlling the magnitude of the results were different. Sayers et al. [3] pointed out that such approximations obtain very different results because fundamentally distinct assumptions are made regarding the way the fracture surface interact. Sayers et al. [3] concluded that such discrepancies can be avoided if more realistic geometries and deformation models are utilized for the asperities or cemententation within the fracture. Sayers et al. [3] went on to demonstrate that 2-D finite element calculation can address asperity deformation directly and provide more reliable insight into the shear and normal compliance of fractures. In theory, more representative results could be inferred through the use of 3-D finite elements, however, it is currently impractical to use such an approach for large fractures or within extensive parameter studies
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (0.89)
Abstract Geomechanical modelling of stress changes during multi-stage hydraulic fracturing (MSHF) can help optimize the design of hydrocarbon extraction operations in unconventional low permeability low porosity reservoirs. Stress changes which occur during a single stage of MSHF have been known to affect subsequent fracturing stages. If an understanding and modeling capability of the effects of induced stress changes can be achieved, optimization of hydraulic fracture operations becomes feasible. Given uncertainty and limited monitoring data, calibration and history matching with reservoir models are used to help design MSHF operations. Data from "similar" wells to those that will be later encountered are used to create a semi-empirical "model" that may have predictive value in design, but because the basis in physics of such models is weak, their predictive capabilities rapidly disappear if conditions are significantly different from those used to develop the empirical calibration factors. This paper will examine the stress shadow effects during MSHF in unconventional reservoirs and the possibility of fracture spacing optimization. The study aims to examine previous stress shadow models to identify the most commonly agreed upon effects of stress shadowing, as well as any noted differences in stress changes during different completion methods. Field data is then examined to identify any of these effects, including but not limited to, increase in instantaneous shut in pressure which may indicate an increase in minimum horizontal stress, and fluctuations in treatment pressure which could show stress changes during the fracture propagation. Both a complex mathematical model and a simple two dimensional model are introduced which will be used to compare efficiency and results in future studies. Recommendations are made concerning simplifying assumptions when it comes to MSHF and reservoir modelling in tight formations. 1. INTRODUCTION Massive multistage hydraulic fracturing in low permeability formations using horizontal wells has become one of the most commonly used method to extract natural gas in Canada. The use of horizontal wells has improved the efficiency of resource extraction by increasing the numbering of hydraulic fracture stages within a single well along several hundred meters of a producing formation.
- North America > United States (1.00)
- North America > Canada > Alberta (1.00)
- North America > Canada > British Columbia (0.96)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation Field > Montney Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Montney Formation (0.99)
- (3 more...)
- Information Technology > Modeling & Simulation (0.48)
- Information Technology > Data Science > Data Mining (0.34)