Hydraulic Fracture Containment Research Articles

Rock Anisotropy Promotes Hydraulic Fracture Containment at Depth

AbstractWe report laboratory experiments and numerical simulations demonstrating that the anisotropic characteristics of rocks play a major role in the elongation of hydraulic fractures (HFs) propagating in a plane perpendicular to the rocks' inherent layering (the bedding planes in sedimentary rocks and foliation planes in metamorphic rocks). Transverse anisotropy leads to larger HF extension in the parallel‐to‐layers/divider direction compared to the perpendicular‐to‐layers/arrester direction. This directly promotes vertical containment of HFs in most sedimentary basins worldwide even in the absence of any favorable in‐situ stress contrasts or other material heterogeneities. More importantly, the ratio of the energy dissipated in fluid viscous flow in the fracture to the energy dissipated in the creation of new surfaces is found to play a critical role on fracture elongation, with fracture‐energy dominated HFs being the most elongated while the viscous dominated ones remain more circular. These results open the door to a better engineering and control of HFs containment at depth in view of the competition between material anisotropy (both elastic stiffnesses and fracture toughness anisotropy) and injection parameters (fluid viscosity and rate of injection).

Geomechanical insights on the importance of mechanical stratigraphy to hydraulic fracture containment

Geomechanical insights on the importance of mechanical stratigraphy to hydraulic fracture containment

Laboratory demonstration of the impact of weak interfaces and layered rock properties on hydraulic fracture containment and height growth

Hydraulic fracturing and waterflooding are both widely applied methods for improving the recovery of oil and gas resources. These methods have increasing commonality because many waterfloods are being carried out at high enough pressure to generate hydraulic fractures. Even so, it is challenging for engineers to make an optimal wellbore pressure design for layered and otherwise complex underground formations. An overly aggressive injection pressure may lead to uncontrollable fracture height growth into non-producing layers adjacent to the reservoir. In contrast, when using classical but highly simplified height growth models, the pressure limits can be far too conservative which may lead to lower recovery rates and inefficient use of resources invested in developing producing reservoirs. Therefore, it is necessary to investigate the mechanism of fracture height growth while considering the coupling effect from multiple dominated factors. This research contributes an experimental approach to evaluating the role of stresses, weak interfaces, and mechanical properties of a three-layer system in promoting or containing hydraulic fracture height growth from a central reservoir into neighboring barrier layers. In all cases, the experiments agree that the pressure required to induce substantial height growth exceeds the stress applied to the barrier layers and is far above classical predictions. Additionally, when the reservoir layer is softer than the barriers, the containment is sustained to even higher pressures than for layers with similar material properties. Finally, the experiments show that permeability of the barrier layer can induce a more sudden transition to uncontrolled height growth when fracture reaches the bedding interfaces. Hydraulic fracture height growth is mitigated by weak interfaces between layers. Unstable height growth typically requires fluid pressure to exceed the in-situ stress in the bounding layer(s). Contrasting layer stiffness and permeability often leads to further mitigation of height growth.

The Impact of Layering and Permeable Frictional Interfaces on Hydraulic Fracturing in Unconventional Reservoirs

Summary The impacts of formation layering on hydraulic fracture containment and on pumping energy are critical factors in a successful stimulation treatment. Conventionally, it is considered that the in-situ stress is the dominant factor controlling the fracture height. The influence of mechanical properties on fracture height growth is often ignored or is limited to consideration of different Young’s moduli. Also, it is commonly assumed that the interfaces between different layers are perfectly bounded without slippage, and interface permeability is not considered. In-situ experiments have demonstrated that variation of modulus and in-situ stress alone cannot explain the containment of hydraulic fractures observed in the field (Warpinski et al. 1998). Enhanced toughness, in-situ stress, interface slip, and energy dissipation in the layered rocks should be combined to contribute to the fracture containment analysis. In this study, we consider these factors in a fully coupled 3D hydraulic fracture simulator developed based on the finite element method. We use laboratory and numerical simulations to investigate these factors and how they affect hydraulic fracture propagation, height growth, and injection pressure. The 3D fully coupled hydromechanical model uses a special zero-thickness interface element and the cohesive zone model (CZM) to simulate fracture propagation, interface slippage, and fluid flow in fractures. The nonlinear mechanical behavior of frictional sliding along interface surfaces is considered. The hydromechanical model has been verified successfully through benchmarked analytical solutions. The influence of layered Young’s modulus on fracture height growth in layered formations is analyzed. The formation interfaces between different layers are simulated explicitly through the use of the hydromechanical interface element. The impacts of mechanical and hydraulic properties of the formation interfaces on hydraulic fracture propagation are studied. Hydraulic fractures tend to propagate in the layer with lower Young’s modulus so that soft layers could potentially act as barriers to limit the height growth of hydraulic fractures. Contrary to the conventional view, the location of hydraulic fracturing (in softer vs. stiffer layers) does affect fracture geometry evolution. In addition, depending on the mechanical properties and the conductivity of the interfaces, the shear slippage and/or opening along the formation interfaces could result in flow along the interface surfaces and terminate the fracture growth. The frictional slippage along the interfaces can serve as an effective mechanism of containment of hydraulic fractures in layered formations. It is suggested that whether a hydraulic fracture would cross a discontinuity depends not only on the layers’ mechanical properties but also on the hydraulic properties of the discontinuity; both the frictional slippage and fluid pressure along horizontal formation interfaces contribute to the reinitiation of a hydraulic fracture from a pre-existing flaw along the interfaces, producing an offset from the interception point to the reinitiation point.

Lattice simulation of hydraulic fracture containment in the North Perth Basin

The results of numerical simulations of hydraulic fracturing based on the concept of lattice, a grain based method, are presented. Five cases of numerical simulations were conducted to analyze the effects of changing rock properties and in-situ stresses on hydraulic fracture propagation and its containment. The study was done based on the data from one of the shale gas wells in the North Perth Basin (NPB) in Western Australia and the hydraulic fracturing lab experimental data on a 50 mm cubical sample. The hydraulic fracturing initiates and propagates within Carynginia Formation surrounded by the Irwin River Coal Measures (IRCM) Formation from the top and Kockatea Formation at the base. The lab experiments were upscaled to both intermediate and field scales to simulate fracture propagation in the viscosity dominated regime. Penetration parameters, including the depth and area of the fracture crossing the interface, were proposed to characterize fracture containment capacity. It was observed that the fracture is contained by both IRCM and Kockatea Formations due to the large contrast between the minimum horizontal stresses in these layers and that of the Carynginia formation. However, as quantified by the penetration parameters, the fracture propagates more easily into the IRCM Formation with higher brittleness than Carynginia Formation. Kockatea Formation with lower brittleness than that of Carynginia Formation inhibits vertical migration of the fracture, i.e. results in more visible fracture containment. The results suggest that decrease in rock brittleness inhibits fracture propagation and lower minimum horizontal stress contrast leads to fracture containment.

Three dimensional finite element simulations of hydraulic fracture height growth in layered formations using a coupled hydro-mechanical model

In this paper, we treat the important problem of hydraulic fracturing in the presence of elastic modulus and stress contrast in layered rock systems encountered in petroleum resources development using a fully coupled 3D hydro-mechanical model. First, the model is validated by simulating a laboratory hydraulic fracturing experiment dealing with the influence of stress contrast. Good agreements in the distribution of fracture aperture, injection pressure and fracture footprint have been achieved. Then, numerical analyses are performed to investigate the influence of in-situ stress and formation layer properties, such as Young's modulus and fracture energy release rate on the height growth and containment of hydraulic fractures. Comparing the results of simulations using conventional thickness-weighted Young's modulus to those from explicit modeling of layers' Young's moduli, it is found given that for the same amount of injection volume, the thickness-weighted modulus generates a higher injection pressure. Explicit modeling of the layers influences the hydraulic fracture aperture distribution in the pay zone as well as in the surrounding layers. A relatively large fracture aperture is observed in the layer with the lower Young's modulus. Also, the hydraulic fracture tends to propagates mainly in the lower Young's modulus layers which could facilitate containment of the hydraulic fracture by limiting height growth in the stiffer layers. When considering the influence of stress contrast on height growth, the conventional equilibrium height model produces a relatively large aperture and overestimates the fracture height. Simulations using typical injection rate, fluid viscosity, and in-situ stress, show stress contrast larger than a certain value, for example 30% of the in-situ minimum horizontal stress, can effectively inhibit height growth. When the payzone is bounded by ductile layers, the injection pressure is higher and the corresponding aperture at the injection point is larger than those obtained using uniform rock properties.

Xfem modeling of stress shadowing in multiple hydraulic fractures in multi-layered formations

One of the challenges of hydraulic fracturing operations is the determination of the fluid-driven vertical fracture extent. Fracture breakout into overlaying or underlying formations with water-bearing zones can lead to irreparable water damage to the formation. In multiple fracture stimulation, stress shadowing can affect fracture geometry: length, aperture, height, and propagation direction. In this work, the Extended Finite Element Method (XFEM) was implemented in a fully coupled hydro-mechanical framework to simulate hydraulic fracturing processes considering the propagation of several vertical non-planar fluid-driven fractures. This paper focuses on the containment of multiple hydraulic fractures within the pay zone of multilayered formations. Stress shadowing effects on the required pressure for crack propagation and on the resulting fracture geometry are investigated in depth. Sequential and simultaneous fracturing schemes are considered. Our numerical results are compared to analytical solutions for fracture propagation in single and multi-layered formations under homogeneous and heterogeneous stress conditions. The predicted fracture pressure for propagation exhibits good agreement with analytical solutions for a single fracture. However, for multiple clusters this pressure must increase due to stress shadowing effects. As a result, the risk of breaking into adjacent layers is increased. Our study optimizes the injection volumes by taking into account variations of fracture spacing, reservoir thickness, fluid leak-off, formation toughness and stress contrast between layers to guarantee containment of multiple fractures into the pay zone. Moreover, strategically chosen injection times between stages maximize the operation profitability while avoiding possible aquifers contamination.

What we know, what we don’t know, and things we do not know we don’t know about hydraulic fracturing in high stress environments

Hydraulic fracturing in many Australian Basins, particularly the Cooper Basin has been successful in higher permeability, structured conventional plays. However, adaptation of North American strategies to Australia’s complex, and highly stressed unconventional areas has resulted in less than adequate performance to progress further investment into widespread development these resources. This presentation will explore the obvious differences between Australian and North American stress settings, and the problems manifested by those differences in hydraulic fracture containment and behaviour. Further, as more unconventional targets are attempted, complementary strategies need to be considered based on fundamental geomechanical principles, relative to these basinal environments. This presentation will explore several problems, emerging potential solutions, and areas of ongoing research with the purpose of aiding Australia to tap into a vast supply of potential unconventional resources, which are currently under-appraised.

Effect of in-situ stress contrast on fracture containment during single- and multi-stage hydraulic fracturing

Hydraulic fracture containment behaviour under varying in-situ stress conditions was studied for single- and multi-stage hydraulic fracturing using a fully coupled hydro-mechanical model. Single-stage fracturing under varying and non-varying minor principal stress conditions showed good agreement with the corresponding analytical predictions. Multi-stage fracturing under non-varying stress conditions displayed a strong stress shadow-induced asymmetry of fracture propagation about the injection well. As the fluid pressure dissipation after fracturing in the numerical simulations is assumed to be negligible before the subsequent fracturing stage, it was observed that the fractures can extend even after the actual injection time as a result of the stress shadow generated during subsequent fracturing stages. The stress contrast between adjoining layers and the pay zone was found to be somewhat effective in containing fractures within the pay zone, although the asymmetry of fracture profiles was still apparent. It was also observed that the stress shadow effect is sufficiently significant in some cases that the fractures have the preference to penetrate into higher stress adjoining layers than propagating within the initially lower-stress pay zone, which is generally unfavourable. Fluid injection time was found to have a major influence on overall fracture propagation during multi-stage fracturing and the fractures were observed to be fully and only within the pay zone, delineating the effective containment, for simulations with optimized injection times. In addition, our simulations show that, based on the fact that fractures can be further driven by the stress shadows of subsequent fracturing stages, strategically-selected injection times for each fracturing stage can produce fractures that fully and only occupy the pay zone, which can save a considerable amount of injection fluid. This has direct positive implications for project economics and will help minimize potential issues associated with deep fluid injection, such as groundwater contamination and induced seismicity.

Lattice simulation of laboratory hydraulic fracture containment in layered reservoirs

Hydraulic fracture containment in layered reservoirs is simulated using a numerical model that couples fluid flow with a lattice representation of the solid with quasi-random distributed nodes connected by springs. We consider the influence of horizontal stress contrasts between layers, vertical stress, material fracture toughness, and the presence of horizontal weak interfaces. Observed results define distinct regions in a parametric space characterized by height growth, containment, and growth along the horizontal weak interface (T-shape growth). These numerical results match well to laboratory experimental benchmarks, and they extend the parametric study beyond what can be considered in the laboratory.

Pore pressure effects on fracture net pressure and hydraulic fracture containment: Insights from an empirical and simulation approach

Pore pressure and its relationship with fracture net pressure has been reported qualitatively from both field and experimental observations. From a modeling perspective, the ubiquitously used pseudo 3D (P3D) models that are based on linear elastic fracture mechanics (LEFM) do not include the effect of reservoir depletion (or overpressure). Models that utilize effective stress as propagation criteria with a cohesive zone description, introduce the pore pressure directly into the simulation and hence can potentially capture the effect of pore pressure on fracture propagation. This work investigates the effect of pore pressure on hydraulic fracturing net pressure and geometry using empirical and numerical simulation approaches. We carried out an analysis of more than 400 datafrac injections spanning a wide range of geological ages and depositional environments in order to investigate the relationship between observed net pressure and reservoir pore pressure. The net fracture propagation pressure from the fracture treatment analysis was seen to be correlated with the effective stress in the reservoir. Fracture propagation simulations were performed using a coupled finite element – finite difference fracture simulator. The code uses a cohesive zone model (CZM) to describe fracture propagation. Four different effective stress scenarios were used to study the effect of effective stress on net pressure. The simulation results closely match the empirical relation between net pressure and effective stress as obtained from the analysis of actual frac treatment data. It is observed from the simulations that the magnitude of the effective stress also has an effect on the fracture geometry with a high effective stress leading to wider, shorter and more radial fractures. The derived empirical correlation is hence useful as a fracture design parameter. The datafrac net pressure diagnostics workflow in the pseudo 3D models can incorporate local tip pore pressure as a new pressure matching parameter. The pore pressure effect can thus explain high net pressures routinely observed in frac operations and also as a containment mechanism.

A quick and energy consistent analytical method for predicting hydraulic fracture propagation through heterogeneous layered media and formations with natural fractures: The use of an effective fracture toughness

An effective fracture toughness, based on equivalent energy release-rate hypothesis is presented for homogenizing heterogeneous layered media. Using crack closure method, the energy released when a mode-1 fracture propagates through an equivalent homogenized layer is equated to the sum of the energies released in the heterogeneous layered media. And from extensive numerical experiments, the predictions of fracture tips' positions through this proposed method are of the same range of accuracy as the known linear blend rule; the weakest link arguments technique performed poorly when compared to the other two methods. Therefore, homogenizing heterogeneous layered media with energy consistent approach will reduce the complexities associated with modeling fracture propagation in multi-layer without losing accuracy. Furthermore, an effective fracture toughness, based on equivalent energy release rate, equivalent strain energy, and modified Kachanov's damage theory is presented in this study. The proposed approach will reduce the computation time required in predicting fracture containment potential in formations with opened or sealed natural fractures. And comparing the proposed phenomenological model with the rigorous solution provided by Mori-Tanaka, it was observed that the margin of error was negligible. The benefit of the proposed phenomenological model over the Mori-Tanaka's effective shear modulus model is the ease of estimating the effective fracture toughness. Thus, these models can be applied to quickly estimate the potential for hydraulic fracture containment or broaching possibilities during oil and gas blowouts and fracturing operations.

Hydraulic Fracture Propagation under Varying In-situ Stress Conditions of Reservoirs

In-situ stress state in deep reservoirs is highly variable due to many factors and it markedly influence the propagation behavior of hydraulic fractures. The direction and extent of hydraulic fracture propagation are predominantly controlled by the in-situ stress state of reservoirs. We conducted distinct element method-based numerical simulations to explore the behavior of hydraulic fracture propagation and containment under varying in-situ stress conditions and fluid injection rates. The results revealed that even a small contrast of minor principal stress between pay-zone and adjacent bounding zones can cause a significant hydraulic fracture containment. Simulations performed under different injection rates showed that the hydraulic fracture containment is also influenced by the injection rate and higher injection rates tend to increase the hydraulic fracture penetration into the adjacent bounding zones. Overall, the results of the present study generally suggest that the fracture propagation during hydraulic fracturing is not an unconstrained event as one would imagine and natural barriers such as varying in-situ stresses, which are common in deep reservoirs, often limit fracture propagation to a certain finite extent. In addition, operational conditions such as fluid injection rate can be selected appropriately to control the hydraulic fracture propagation into unproductive bounding strata.

Influence of mechanical stratigraphy on clastic injectite growth at Sheep Mountain anticline, Wyoming: A case study of natural hydraulic fracture containment

Sandstone injectites ranging from 1 km in outcrop length intrude the Cretaceous Mowry Formation in the vicinity of Sheep Mountain anticline (Bighorn Basin, Wyoming, USA). These injectites were sourced from the Peay Sandstone Member of the overlying Cretaceous Frontier Formation and represent a significant possible fluid pathway through impermeable shales. Sand injection occurred along dikes and sills, interacting with bedding discontinuities and preexisting joints in the Mowry Formation during the early folding of Sheep Mountain anticline. We argue that, in contrast to the passive sweeping of sediments into fissures characteristic of Neptunian dike formation, downward intrusion of the Peay sand was forceful and made possible by a highly stratified horizontal stress field resulting from the deposition, burial, and lithification history of the rock units in the area. The internal structure of the injectites is dominated by two sets of mutually offsetting deformation bands. The deformation bands have shear and compaction components, exhibiting significant porosity loss, as well as cataclasis and minor pressure solution. After formation of the deformation bands, subsequent faulting was localized along the margins of deformation bands, evidenced in the field by slickensided surfaces. A detailed kinematic analysis of slickenline lineations yields shortening and extension axes consistent with deformation band formation during early Laramide–oriented shortening, and continuing through the folding of Sheep Mountain anticline. Beyond the formation and deformation of these sandstone injectites, this study highlights the importance of mechanical stratigraphy in the containment of hydraulic fractures.

Monitoring hydraulic fracturing complexity and containment with time-lapse, multi-component and microseismic data, Pouce Coupe, Alberta

Fracture complexity occurs when the hydraulic fracturing process causes multiple sets of natural fractures to open in a reservoir. Keeping these sets open is another problem as they must be propped to stay open and communicate with the well bore. Fracture complexity can be monitored and it could have a significant effect on well orientations and completions. Stresses and natural fractures can create conditions favourable for generating multiple fracture sets. Generally, if we can tell where the natural fractures are prior to the drilling and completions, we can take advantage of the natural fractures to increase effective permeability and create greater conductivity to the well bore. Monitoring to see if the fractures are propped and remain conductive over time can be accomplished with shear wave splitting and birefringence. Hydraulic fracture containment during the hydraulic fracturing process is especially relevant to optimizing the effectiveness of hydraulic fracture treatments. Many reservoirs have issues related to height growth and containment within the zone. Monitoring containment is important for purposes of increasing the recovery factor in shale reservoirs. Monitoring technologies can be used to assess containment issues associated with reservoirs affected by fault and natural fracture systems.

Micro/minifrac test procedures and interpretation for in situ stress determination

An assessment of the magnitude of the minimum in situ total stress in rock formations is of major importance in various areas of petroleum engineering including wellbore stability and fracture geometry prediction in well stimulation applications. Microfrac and minifrac tests remain the most reliable method for determining the minimum (usually horizontal) in situ total stress. They enable an estimate to be made of injected fluid loss rates under field conditions and yield valuable information about the main parameters governing the propagation, geometry and containment of massive hydraulic fractures. In this paper, micro/minifrac test procedures are described, including extended shut-in, fracture reopening, tuned injection rate and pump-in/ flowback tests. In addition, a model is presented for pressure decline curve analysis, focussing on the short post shut-in times relevant to micro- and minifrac tests. This model enables the post shut-in pressure profile before and after fracture closure to be plotted as a straight line, the different slopes giving a well-defined fracture closure pressure (FCP), which provides a direct measure of the magnitude of the in situ minimum total stress. The approach requires two pre- and/or post-fracturing leak -off tests at different shut -in pressures, from which a “filtration power index” can be calculated. A “pressure decline function” is also introduced, and this takes on a form that depends on the type of fracture growth assumed during fluid injection. The calculated filtration power index and pressure decline function are then used to generate curves based on pressure-time data after shut-in, from which a well-defined FCP can be determined.

In-Situ Stress Measurements at U. S. DOE's Multiwell Experiment Site, Mesaverde Group, Rifle, Colorado

Summary Vertical distribution measurements of the minimumprincipal in-situ stress in the lower Mesaverde group principal in-situ stress in the lower Mesaverde group (7,300- to 8,100-ft [2225- to 2470-m] depth) at the U.S. DOE'sMultiwell Experiment (MWX) site have been made by conducting small-volume, hydraulic-fracture stress teststhrough perforations. Accurate, reproducible results wereobtained by conducting repeated injections in each zoneof interest with a specially designed pump system, modified high-resolution electronic equipment, and adownhole shut-off tool with a bottomhole pressure (BHP)transducer. Stress tests were conducted in marines and stones and shales as well as in coal, mudstone, andsandstone in a paludal depositional environment; these testsprovide a detailed stress distribution in this region. provide a detailed stress distribution in this region. The stress magnitudes were found to depend on lithology. Marine shales above and below the blanket sands have large horizontal stresses that are nearlylithostatic, with a fracture gradient greater than 1.0 psi/ft[23 kPa/m]. This indicates that these rocks do not behaveelastically and processes such as creep and possibly fracturing are the dominant mechanisms controlling the stressstate. Sandstones and siltstones have much lower stresses. with a fracture gradient of 0.85 to 0.9 psi/ft [19 to 20kPa/m]. Containment of hydraulic fractures would beexpected under these conditions. Only three data points wereobtained from the paludal interval; no significant stressdifferences were observed in the different lithologies. Introduction The vertical distribution of the minimum principalhorizontal in-situ stress, has a significant influenceon hydraulic fracture geometry. Perkins and Kern notedits importance with respect to fracture height, and Simonson et al demonstrated how to calculate fracture heightin a nonuniform, but symmetric, stress field. Laboratory and mineback experiments have provedthe effect of differences on fracture height, but, as yet, field experiments have not yielded conclusive results. This results primarily from the lack of detailedin-situ stress data and viable fracture height measurement techniques. In addition, few in-situ stress measurementshave been obtained in intervals where core is availableso that stress/rock-property correlations can be attempted. The present work on in-situ stress measurements is partof DOE's MWX program, which is being conducted inthe Piceance basin near Rifle, CO. In-situ stressmeasurements currently are planned throughout the entire4,000 ft [1200 m] of Mesaverde rocks encountered at thislocation, with particular emphasis on obtaining detailedstress measurements around formations to be stimulated. Over 4,000 ft [1200 m] of core have been obtained from three closely spaced wells (130 to 180 ft [40 to 65 m])so an abundance of core data is available. Complete conventional log suites, as well as various advanced and experimental logs including the long-space sonic logs, havebeen run. This paper presents the results of the initial series of in-situ stress tests, which were conducted at thebase of the Mesaverde in marine sandstones and shales and at various horizons in a paludal zone. These data willbe used to design hydraulic fracture treatments and aidin the analysis of postfracture performance. In-Situ Stress Measurements At present, the only reliable method of obtaining distribution is by measurement with small-volume hydraulic fractures. Two techniques are currently in use. The step-rate/flowback procedure, pioneered by Nolteand Smith, yields a reliable, reproducible estimate ofand typically is conducted in an interval soon tobe stimulated. These tests have been called "minifraes"because they use small volumes of fluid (500 to 10,000gal [2.0 to 40 M ]) compared with conventional fracture treatments. The technique used in this study also is calleda "minifrac, "although it uses much smaller pumped volumes (1 to 250 gal [0.004 to 1.0 m ]). Minifracsusually are conducted by injecting a small volume intothe formation, shutting in, and measuring the instantaneous shut-in pressure (ISIP). For openhole tests, several authors have discussed the technique'sdetails, and it is clear that when adequately conducted, the test yields an accurate, reproducible estimate ofand a somewhat less reliable estimate of the maximum horizontal in-situ stress,. For most oil and gas applications, however, it isimpossible or impractical to conduct these tests in anopenhole environment. Problems with hole stability, gaspressure, cementing, and cost factors usually require that pressure, cementing, and cost factors usually require that the tests be conducted in cased holes through perforations. This causes additional complications because of casing, cement annulus, explosive perforation damage, andrandom perforation orientation effects. JPT p. 527

Fracture Penetration Through an Interface

Abstract This paper presents a combined theoretical and experimental investigation of fracture penetration through an interface. The results have application to hydraulic-fracture containment in sandstone or limestone reservoir strata bounded by shale layers. Several simplifying assumptions and approximations are made. We assume that the interface separates dissimilar but adhering materials that are elastic to first order. We consider only differences in material properties and take stresses to be locally uniform. Approximations are made that reduce the fourth-order equation of plane strain elasticity to the second-order Laplace equation. Crack shape is taken to be sinusoidal and fluid leakoff is ignored. Additional simplifying assumptions are made about the shape of the crack tip as it passes through the interface. Using a virtual work analysis, we derive a relation for internal fluid pressure required to extend the crack through the interface. This pressure is related to the equilibrium pressure needed to hold the crack barely open. A simple relation is obtained involving only the shear modulus and surface energy of the materials on either side of the interface. The theory was tested in laboratory experiments with Plexiglas™/resin bonds. Test blocks of several configurations were used with various kinds of external loading. Cracks were initiated by applying grease pressure in thin notches. Pressures required to hold cracks in equilibrium were compared with those required to penetrate interfaces. Results were consistent with the theory within limits of precision in measuring surface energy. We conclude that the theory explains field observations of containment in a number of reservoirs that have been fractured hydrualically. However, practical value is limited by inability to estimate surface energies from logging or other wellbore data.

In-situ Stresses And Hydraulic Fracturing In the Deep Basin

Abstract Hydraulic fracturing is a means of developing low-permeability gas sands. The most significant parameter controlling created fracture geometry is in-situ stress slate. Measurements in the Deep Basin have demonstrated differences of 6 MPa in the minimum horizontal in-situ stress over 15 – 30 m with distributions which are both favourable and unfavourable to fracture containment within a producing zone. Conversely, stress variations less than 2 MPa have been observed over a 90 m depth range which contained both a producing interval and thick bounding shale beds. The degree of hydraulic fracture containment has been observed to be related to the vertical profile of the minimum horizontal Stress. In this region the maximum horizontal principal stress is estimated to be nearly equal to the vertical stress at depths below 2 km. It is about 1.4 times the minimum principal stress. This large contrast suggests that fracture azimuth should be controlled completely by the in-situ stress state in the Deep Basin. Introduction Low-permeability reservoirs such as tight gas sands in the Deep Basin of Western Canada are generally uneconomic because of low production rates, not insufficient hydrocarbon reserves. Current technology for increasing these rates relies on hydraulic fracturing. Effective hydraulic fracturing creates a highly conductive channel contained primarily within the productive zone and extending as far as possible away from the wellbore. When a fracture is not contained primarily within the productive zone, an excessive amount of fracturing fluid is used. This has some potentially serious consequences. Increased formation damage may result from excessive fluid leak-off(1), improper proppant placement, such as settling below the zone is possible, and excessive fracture conductivity damage can occur from having to recover extra fracturing fluid(2,3). The in-situ stress state is the most significant parameter controlling fracture containment. An induced fracture can be contained within a zone having a lower stress than that in the bounding layers. Laboratory experiments have shown that under appropriate conditions stress differences of 2–3 MPa are sufficient to contain a fracture(4,5). Field observations have shown stress variations of 6–8 MPa over short" vertical distances(6,7). Fracture containment was observed under appropriate conditions. This paper presents data pertinent to the in-situ stress state and its influence on hydraulic fracturing in the Deep Basin of Alberta. As pan of an extensive research program conducted by Esso Resources Canada Limited in support of its investment in tight gas sands, the vertical distribution of the minimum principal stress was determined over three intervals in two wells in the Deep Basin. Two of these intervals contained zones with sufficient productive promise to warrant hydraulic fracture treatments. These were monitored to a sufficient extent to relate the measured vertical profiles of minimum horizontal stress to the behaviour of the induced hydraulic fractures. Stress Determinations Although many methods exist for determining in-situ stresses, the use of hydraulic fracturing is the only practical technique for deep wellbores. During the hydraulic fracturing process a fracture is initiated or reopened by increasing wellbore pressure as fluid is pumped into the well and then closes after pumping stops.

In-situ stresses: The predominant influence on hydraulic fracture containment : J Pet Technol, V34, N3, March 1982, P653–664

In-situ stresses: The predominant influence on hydraulic fracture containment : J Pet Technol, V34, N3, March 1982, P653–664