Breakdown Pressure Research Articles

Anisotropic failure behaviour and breakdown pressure interpretation of hydraulic fracturing experiments on shale

Shales with a laminated structure typically exhibit inherent anisotropy and strong brittleness, resulting in complex failure patterns and fracture evolution during hydraulic fracturing. To investigate the fracturing mechanism and layer effect of Longmaxi shale from southwest China, a novel testing setup with a high-efficiency sealing method was developed for laboratory hydraulic fracturing, based on which a series of fracturing tests was conducted on shale samples under different confining pressures. The anisotropic mechanical behaviour due to the shale lamination effect was considered by drilling samples at seven different inclinations with reference to the bedding plane. The results showed apparent brittle failure characteristics and anisotropic phenomena both in strength and failure patterns. Three main failure patterns can be identified as split, split-bending and slip along the bedding plane. The corresponding fracture roughness was further analyzed by laser scanning, which shows that the slip mode with shale layer activation can provide a relatively smooth channel. Of particular interest is that anomalously high breakdown pressure, which fluctuates in the samples at different layer orientations and cannot be explained by conventional models, was also observed in our fracturing tests. Inspired by the nonlocal treatment of line stress criterion, an average tensile stress-based model by introducing an equivalent characteristic length was then proposed for interpreting such unusual breakdown pressures, and the inherent mechanism behind hydraulic fracturing was discussed. Comparison analysis showed that the proposed criterion not only predicts the testing data quite well, but can also be degenerated to conventional models in specific cases. The knowledge achieved in this study may provide practical implications for perforation design and breakdown pressure evaluation in field hydraulic fracturing operations.

Effect of Seepage Force on the Wellbore Breakdown of a Vertical Wellbore

As a fluid flows through a porous media, a drag force, called seepage force in the paper, will be formed on the matrix of the media in the fluid flowing direction. However, the seepage force is normally ignored in the analysis of wellbore fracturing during hydraulic fracturing operation. In this paper, an analytical model for seepage force around a vertical wellbore is presented based on linear elasticity theory, and the effect of the seepage force on wellbore breakdown has been analyzed. Also studied are the effects of the two horizontal principal stresses and the reservoir permeability on the action of seepage force. The paper proves that seepage force lowers formation breakdown pressure of a vertical wellbores; the deeper a formation is, the greater action of the seepage force; seepage force contributes more to breakdown formation with small difference of the two horizontal stresses such as unconventional reservoirs; seepage force increases as rock permeability decreases, and it should not be ignored in hydraulic fracturing analysis, especially for low-permeability formation.

Effect of the Triaxial State of Stress in the Hydraulic Fracturing Processes of Granite: Part 1—Visual Observations and Interpretation

A set of hydraulic fracturing tests were conducted in prismatic granite specimens to investigate the influence of the triaxial state of stress on the cracking processes. The tests considered three states of stress, in which the horizontal and out-of-plane loads were 2 MPa, while the vertical loads were either 1 MPa, 2 MPa, or 4 MPa. A hydraulic pressure inside pre-fabricated flaws was increased at a constant injection rate until hydraulic fractures initiated and propagated. In order to materialize this state of stress, a test setup was developed to independently apply and control three orthogonal stresses in the prismatic granite specimens while simultaneously applying a hydraulic pressure inside pre-fabricated flaws. More importantly, the setup also allowed one to observe the damage processes visually and through acoustic emission monitoring. This paper (the first of two) looks into the visual (macroscopic) observations, whereas the companion paper focuses on the acoustic emission monitoring. In particular, the present paper looks into the white patching (micro-damage) development, crack initiation, propagation and coalescence, and relates these with fracture initiation and breakdown pressures. From the tests, it was observed that the initiation of visible cracks is, generally, preceded by white patching and occurs at or near the pre-fabricated flaws. The visual analysis showed that the induced fractures were primarily intragranular when the triaxial stresses were same in the three orthogonal directions and intergranular otherwise. Additionally, micro-fracture initiation pressures were obtained based on white patch initiation pressures (visually) and using a graphical method which relates the changes in pressurization rate to fracture initiation. It was observed that the graphical method identifies when the initial damage occurred significantly earlier than the visual method, which indicates that important micro-damage processes may occur without macroscopic evidence. Most importantly, the coalescence patterns and the ratio between the breakdown pressure and the vertical stress are stress-state dependent. In fact, for lower vertical loads (VL = 1 MPa), the ratio between the breakdown pressure and vertical load is approximately 10 and for higher vertical loads (VL = 4 MPa) approaches 1.0, which is in agreement with data observed in the field.

Geomechanical Measurements and Machine Learning Help Predict Trouble Stages

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201699, “Predicting Trouble Stages With Geomechanical Measurements and Machine Learning: A Case Study of Southern Midland Basin Horizontal Completions,” by Eric Romberg, SPE, Keban Engineering; Aaron Fisher, Tracker Resources; and Joel Mazza, SPE, Fracture ID, et al., prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, 5–7 October. The paper has not been peer reviewed. Unexpected problems during completion create costs that can cause a well to be outside its planned authorization for expenditure, even uneconomic. These problems range from experiencing abnormally high pressures during treatment to casing failures. The authors of the complete paper use machine-learning methods combined with geomechanical, wellbore-trajectory, and completion data sets to develop models that predict which stages will experience difficulties during completion. Field Modeling and Well Planning The operator’s acreage is in the southeastern portion of the Midland Basin. In this area of the basin, the Wolfcamp B and C intervals often contain a significant amount of slope sediments and carbonate debris flows because of the proximity of the eastern shelf. These intervals cause significant drilling and completion issues. During the past 5 years, the operator acquired and licensed approximately 130 sq mile of 3D seismic data. In addition, the operator cored three wells, drilled six pilot wells with complete log suites, licensed 40 wells with a triple/quad combination, acquired data and surveys on 112 existing horizontal wells, and has 347 vertical wells with formation tops for depth control. This rich data set yielded a robust 3D reservoir model that was used to map a sequence of stacked, high-quality landing targets. Model-Aided Well-Completion Strategy. The operator often encountered difficult stages in the form of high breakdown pressures, high pumping pressures, and the inability to place proppant. On a few occasions, drilling out all plugs was not possible because of casing obstructions possibly related to fault activation during the stimulation. The operator began analyzing curvature and similarity volumes for potential fault/fracture identification near the difficult completion stages and compromised casing intervals. Drillbit geomechanics data collection was planned for all lateral wells. The geomechanical properties recorded were used to reduce risks during completions further by informing the plug and perforation stage design. Stages were planned to reduce variation in minimum horizontal stress (Shmin) within each stage. The geomechanical data also identified carbonate debris flows within the well path, allowing completion engineers to bypass rock considered unproductive. Completion Issues and Other Factors Contributing to Casing Deformation. From February 2017 through November 2019, the operator drilled and completed 28 Wolfcamp horizontal wells. The plug-and-perforation completion technique was used on all 28 wells. While drilling out composite fracturing plugs, casing obstruction was encountered in six of 28 wells. These obstructions limited the working internal diameter of the production casing and either prevented or inhibited access beyond the obstruction. In two of the Phase 1 wells, conventional drillout assemblies were not able to pass the obstructions.

Verification of Coupled Hydraulic Fracturing Simulators Using Laboratory-Scale Experiments

In this work, we aim to verify the predictions of the numerical simulators, which are used for designing field-scale hydraulic stimulation experiments. Although a strong theoretical understanding of this process has been gained over the past few decades, numerical predictions of fracture propagation in low-permeability rocks still remains a challenge. Against this background, we performed controlled laboratory-scale hydraulic fracturing experiments in granite samples, which not only provides high-quality experimental data but also a well-characterized experimental set-up. Using the experimental pressure responses and the final fracture sizes as benchmark, we compared the numerical predictions of two coupled hydraulic fracturing simulators—CSMP and GEOS. Both the simulators reproduced the experimental pressure behavior by implementing the physics of Linear Elastic Fracture Mechanics (LEFM) and lubrication theory within a reasonable degree of accuracy. The simulation results indicate that even in the very low-porosity (1–2 %) and low-permeability ({10}^{-18} {mathrm{m}}^{2}- {10}^{-19} {mathrm{m}}^{2}) crystalline rocks, which are usually the target of EGS, fluid-loss into the matrix and unsaturated flow impacts the formation breakdown pressure and the post-breakdown pressure trends. Therefore, underestimation of such parameters in numerical modeling can lead to significant underestimation of breakdown pressure. The simulation results also indicate the importance of implementing wellbore solvers for considering the effect of system compressibility and pressure drop due to friction in the injection line. The varying injection rate as a result of decompression at the instant of fracture initiation affects the fracture size, while the entry friction at the connection between the well and the initial notch may cause an increase in the measured breakdown pressure.

Geomechanical analysis of formation deformation and permeability enhancement due to low-temperature CO2 injection in subsurface oil reservoirs

Several benefits of CO2 injection are reported in the literature such as its ability to mitigate greenhouse gas emissions and the increase in oil recovery at a low cost. However, the correlated reservoir-engineering problems with low-temperature CO2 injection including formation damage and leakage risk are still uncertain and has not been comprehensively investigated. This research examines the effect of low-temperature CO2 on lowering of formation breakdown pressure, and the associated formation damage from a geomechanical prospective. This study presents the coupling of the equilibrium stress equation, the system energy balance equation, continuity equation, and saturation equation to develop thermoporoelastic model for the reservoir rock. We determined the cooling-induced formation damage due to decrease in temperature and thermal stresses, formation contraction and tensile stresses, and examine its effects on formation properties, stresses, joint and fracture stability. We observed that low-temperature CO2 would create a low thermal stress region and thus the formation could fail in tension. This process might increase formation permeability but it would decrease the stability of reservoir, basement and caprock. We analyzed several factors affecting formation deformation such as injection rate for both miscible and immiscible CO2 flooding, formation porosity, depth, temperature, and formation breakdown pressure. We also compared our results and findings with experimental data, finding excellent match and similar consequences. Furthermore, as a sequence of low-temperature CO2 injection, the initial formation breakdown pressure was initially at 2560 psi and it reduced to 1928 for immiscible case and 1270 psi for miscible case in the selected case study. We also propose that shallow reservoirs should be avoided for CO2 capture and storage because of stability issues.

Relaxation damage control via fatigue-hydraulic fracturing in granitic rock as inferred from laboratory-, mine-, and field-scale experiments

The ability to control induced seismicity in energy technologies such as geothermal heat and shale gas is an important factor in improving the safety and reducing the seismic hazard of reservoirs. As fracture propagation can be unavoidable during energy extraction, we propose a new approach that optimises the radiated seismicity and hydraulic energy during fluid injection by using cyclic- and pulse-pumping schemes. We use data from laboratory-, mine-, and field-scale injection experiments performed in granitic rock and observe that both the seismic energy and the permeability-enhancement process strongly depend on the injection style and rock type. Replacing constant-flow-rate schemes with cyclic pulse injections with variable flow rates (1) lowers the breakdown pressure, (2) modifies the magnitude-frequency distribution of seismic events, and (3) has a fundamental impact on the resulting fracture pattern. The concept of fatigue hydraulic fracturing serves as a possible explanation for such rock behaviour by making use of depressurisation phases to relax crack-tip stresses. During hydraulic fatigue, a significant portion of the hydraulic energy is converted into rock damage and fracturing. This finding may have significant implications for managing the economic and physical risks posed to communities affected by fluid-injection-induced seismicity.

Comparison of fracturing unconventional gas reservoirs using CO2 and water: An experimental study

CO2-based fracturing (CBF) has been regarded as the most promising alternative to water-based fracturing (WBF) in water-sensitive unconventional gas reservoirs, and the fracture initiation and propagation at different in-site stresses created by CBF is crucial to the flow conductivity of fracture network. The main aim of this study is to compare the fracturing efficiency of WBF and CBF by conducting a series of fracturing tests on siltstone samples. According to the experimental results, the breakdown pressure linearly increases with the confining pressure, and the slope is 1.3928 and 1.6422 for CBF and WBF, respectively, and the much lower breakdown pressure for CBF is because of the fast penetration of CO2 through the rock matrix, which significantly reduces the effective stress around the borehole. Importantly, the observed fracture aperture for CBF is much greater than that for WBF, the maximum fracture aperture for CBF is around 2 to 5 times greater than that for WBF under the same test conditions. The difference in fracture aperture depends on the presence of discrete blocks and particles, and CBF can create greater and more loose particles in both mechanically-created method and hydraulically-created method to keep the created fractures open after the release of the injection pressure. The greater fracture aperture of CBF is favourable for the flow capacity of the fractures and therefore reservoir productivity, which is verified by the permeability tests with 190.43 times of permeability than that of WBF. Interestingly, the greater fracture width expansion for CBF perpendicular to the major principal pressure promotes the generation of horizontal fractures, even when the injection pressure is smaller than the major principal pressure, and the probability of horizontal fracture for CBF is 4–5 times of that for WBF, which reflect its great potential to create complex fracture network in unconventional gas reservoirs. The test results reveal that CBF is superior to the WBF since it is capable to create much more complex and efficient fracture networks. The findings are beneficial to understand the difference of fracturing behaviours at different in-site stresses between WBF and CBF, and provide experimental guidance for the exploitation of water-sensitive unconventional gas reservoirs by CBF.

Preparatory acoustic emission activity of hydraulic fracture in granite with various viscous fluids revealed by deep learning technique

SUMMARYTo investigate the influence of fluid viscosity on the fracturing process, we conducted hydraulic fracturing experiments on Kurokami-jima granite specimens with resins of various viscosities. We monitored the acoustic emission (AE) activity during fracturing and estimated the moment tensor (MT) solutions for 54 727 AE events using a deep learning technique. We observed the breakdown at 14–22 MPa of borehole pressure, which was dependent on the viscosity, as well as two preparatory phases accompanying the expansion of AE-active regions. The first expansion phase typically began at 10–30 per cent of the breakdown pressure, where AEs occurred three-dimensionally surrounding the wellbore and their active region expanded with time towards the external boundaries of the specimen. The MT solutions of these AEs corresponded to crack-opening (tensile) events in various orientations. The second expansion phase began at 90–99 per cent of the breakdown pressure. During this phase, a new planar AE distribution emerged from the borehole and expanded along the maximum compression axis, and the focal mechanisms of these AEs corresponded to the tensile events on the AE-delineating plane. We interpreted that the first phase was induced by fluid penetration into pre-existing microcracks, such as grain boundaries, and the second phase corresponded to the main fracture formation. Significant dependences on fluid viscosity were observed in the borehole pressure at the time of main fracture initiation and in the speed of the fracture propagation in the second phase. The AE activity observed in the present study was fairly complex compared to that observed in previous experiments conducted on tight shale samples. This difference indicates the importance of the interaction between the fracturing fluid and pre-existing microcracks in the fracturing process.

Modeling hydraulic fracture propagation in a saturated porous rock media based on EPHF method

Hydraulic fracture propagation in a porous rock media is complex. This paper presents an extended permeability-based hydraulic fracture (EPHF) modeling method for porous rock media. The EPHF model is a smeared crack model that is based on a fully-coupled, fluid-solid formulation. The pre-failure deformation of the solid phase is modeled by poroelasticity and the Drucker-Prager plasticity model is used for the post-fracture process. The flow liquid phase is described by Darcy's law. An extra material parameter that characterizes the onset of cracking for the brittle material is integrated into the smeared equation. Three models are integrated into the EPHF method for calculating the relative permeability when considering the mixture feature of the in-situ fluid and injected fluid. In addition to simulating fracture propagation in a homogeneous porous rock media, the EPHF model is good for simulating the fracture propagation in various heterogeneous rocks when incorporating static level set functions to describe material interfaces. An approximate method is discussed for estimating the effective hydro-fracture features; i.e., the equivalent fracture zone, fracture path and fracture aperture. Influence factors, e.g., the material properties and effective stress ratio for breakdown pressure and propagation pressure, are studied in a homogeneous fully saturated porous rock. Comparison with analytical results indicates that the EPHF method is capable of being used to model these characteristics and the hydraulic fracture propagation in a porous rock media with or without heterogeneity included.

Complexity and tortuosity hydraulic fracture morphology due to near-wellbore nonplanar propagation from perforated horizontal wells

Perforated fracturing enhances single well production in the tight sandstones formations with low porosity and permeability effectively, however, some issues are caused after such achievements, such as high breakdown pressure, short fracture length, and limited proppant migration. All are tightly related to hydraulic fracture complex propagation behavior near wellbore. To understand its mechanism, a 3D near-wellbore fracture propagation model is established based on the combination of finite element method and post-failure damage mechanism. The model is applied on a cased and perforated horizontal well to investigate fracture initiation characteristics, near-wellbore fracture non-planar propagation behavior, and torturous hydraulic fracture morphology. Moreover, the effects of stress shadow and perforation parameters are discussed. Based on induced hydraulic fracture initiation position and propagation speed, three main fracture propagation behaviors are observed under the stress shadow effect in simulation results: limited propagation, nonuniform circular propagation, and opposite direction propagation. These nonplanar propagation behaviors cause complexity and tortuosity hydraulic fracture morphologies near the wellbore, which could be mainly divided into four types: spiral-shaped fracture, multi-spiral shaped fracture, horizontal-vertical crossing shaped fracture, and multi-layered shaped fracture. In addition, the reasonable perforation parameter design could reduce torturous fracture surface, resulting in a near flat fracture. The increase in perforation density or perforation diameter could shorten perforation spacing to provide a small diversion angle for induced fractures to interact with each other and form a small spiral degree fracture geometry. However, increased perforation phase causes many perforations in the same direction to create a longitudinal fracture that has a short fracture length for the horizontal well. Therefore, based on above analyses, high perforation density, small perforation phase, and large perforation diameter are suggested to be an effective perforation parameter combination to conduct the perforated fracturing in tight sandstone formation, in order to create a near flat fracture surface with a minimum tortuosity as well as to increase hydraulic fracture propagation area.

The breakdown process of low-permeable shale and high-permeable sandstone rocks due to non-aqueous fracturing: the role of fluid infiltration

Hydraulic fracturing operations have been widely used to enhance reservoir permeability during the extraction of oil, shale gas and tight sandstone gas. Recently, non-aqueous fracturing fluids, such as supercritical carbon dioxide and nitrogen, have been proposed as the potential fracturing fluid candidates due to their advantages of decreasing formation damage, conserving water resources and avoiding injection-induced seismicity. However, the breakdown process of the non-aqueous fracturing process and the breakdown mechanism remain mysteries. In this research, we report a series of hydraulic fracturing experiments with low-permeable shale samples and high-permeable sandstone samples by water, supercritical carbon dioxide, and nitrogen gas under different injection rates. Moreover, we use a coupled fluid-rock interaction model to visualize the distribution of fluid pressure near the injection borehole during hydraulic fracturing before the sample breakdown. The results indicate that the fluid infiltration decreases the breakdown pressure by increasing the pore pressure and decreasing the effective stress, especially for high-permeable sandstone rock and low-viscosity fracturing fluid. Also, breakdown pressure increases with increasing fluid injection rate, and the conventional Hubbert-Willis and Haimson-Fairhust equations can still effectively determine the upper and lower limits in predicting the breakdown pressure. Our results suggest that lower viscosity fluid with a lower injection rate leads to a lower breakdown pressure, which is suitable to be implemented for the reservoirs with high intrinsic permeability.

Effect of different types of stimulation fluids on fracture propagation behavior in naturally fractured carbonate rock through CT scan

Acid fracturing of carbonate rock starts with formation breakdown and fracture propagation caused by stimulation fluids. The effectiveness of acid fracturing largely depends on the behavior of fracture propagation. While fracture propagation of fractured carbonate rock is greatly influenced by natural fractures and fluid types. So far, some scholars have studied the influence of nonreactive fracturing fluid on fracture propagation, but the comparison of effect between nonreactive fracturing fluid and reactive fracturing fluid on fracture propagation is rarely noticed. In this paper, true tri-axial experiments on carbonate rock (200 mm × 200 mm × 200 mm) are presented; the experiment made a comparative study on the effect of nonreactive fracturing fluid (water, guar fracturing fluid) and reactive fracturing fluid (self-generated acid, gelled acid, VES acid) on fracture propagation in fractured carbonate rock. Besides, fracture morphology was revealed through CT scan and 3D reconstruction technology. In this way, influence of natural fractures and fluid types on hydraulic fracture propagation during acid fracturing was quantitatively analyzed. Results show that these two factors indeed exert great impact on fracture propagation behavior. As acid is more conducive to connection of natural fractures, hydraulic fractures induced by acid can propagate along natural fractures after initiating from natural fractures, and the process would not be restricted by maximum horizontal stress. As a result, a longitudinal fracture parallel to the wellbore is formed. Compared with self-generated acid and gelled acid, VES acid is more liable to connect natural fractures and form complex fracture network during acid fracturing. No matter reactive or nonreactive fracturing fluid is applied to conduct fracturing experiments, hydraulic fracture propagation in carbonate rock with few natural fractures would be restricted by maximum horizontal stress, and transverse fractures perpendicular to the wellbore would be formed after fracturing. In addition, breakdown pressure of rock samples is also affected by natural fractures and fluid types. To be specific, gelled acid decreases rock's breakdown pressure to the greatest extent when numerous natural fractures exist in the rock; the breakdown pressure caused by gelled acid is only 56.7% of which caused by water. However, the gelled acid has little contribution to decrease the breakdown pressure of the carbonate rock with few natural fractures. In a word, the experiment reveals effect of stimulation fluid types on hydraulic fracture propagation in fractured carbonate rock, which provides some guidance for acid-fracturing treatment in carbonate reservoir.

A prediction of breakdown pressure from damaged deviated well

It has been proved that formation damage is an important reason of abnormal high breakdown pressure (BP), but few quantitative prediction model considering formation damage has been established. In this paper, formation is considered as homogeneous linear elastic small deformation material, an arbitrary deviated well is taken as the research object, in-situ stress and the wellbore injection pressure in the surroundings of borehole wall are calculated on the base of elastic mechanics. Additional fracturing fluid infiltration pressure is calculated based on the empirical relationship of permeability and porosity combined with Darcy’s law of fracturing fluid in poro-elastic media. Based on the stress superposition principle as well as the tensile stress failure criterion, the breakdown pressure prediction model of deviated open hole well with damage is established for the first time, and influence of formation damage on breakdown pressure is quantitatively simulated. For a given in-situ stress regime, the results display breakdown pressure of both damaged well and undamaged well increases with the increase of deviation angle and azimuth angle, the former is always higher than the latter. Moreover, the BP and additional BP Increment is not large when deviation or azimuth angle is less than 30°. On the other hand, additional BP increment rapidly rises more when damaged permeability ratio is less than 0.135 and it can even reach 10MPa in this example.

Numerical model of CO2 fracturing in naturally fractured reservoirs

Hydraulic fracturing becomes a key technology for unconventional oil and gas development. As a fracturing fluid, CO2 displays considerable advantages, particularly in shale gas exploitation. However, little research has quantitatively analyzed the effectiveness and efficiency of CO2 fracturing in naturally fractured reservoirs. In this study, a CO2 fracturing model is established in naturally fractured reservoirs. A series of fracturing cases in single- and multiple- fracture(s) are conducted based on the simplified three-dimensional displacement-discontinuity-method. Compared to induced fractures by slickwater and gel, the results show that CO2 fracturing can generate relatively longer but narrower fractures due to the low breakdown pressure and pressure drop in fractures. The pressure drop in the single fracture by CO2 fracturing is respectively 60.48% and 78.88% lower than that by slickwater and gel fracturing at the same injection time. Simultaneously, in naturally fractured reservoirs, CO2 fracturing can activate more natural fractures to connect with each other and create a larger stimulated reservoir volume. For a single fracturing, the active natural fractures volume of CO2 fracturing is 3.7 and 9.2 times that of slickwater and gel fracturing, respectively. For multiple fracturing, the active natural fractures volume of CO2 fracturing is 2.5 and 4.4 times that of slickwater and gel fracturing, respectively. Additionally, the sensitivity analyses in natural fracture spacing and length show that both natural fracture spacing and length can significantly determine natural fractures' distribution and connectivity. By CO2 fracturing, a reservoir with relatively smaller natural fracture spacing and longer natural fracture length can be activated more natural fractures. The present work can help the scholars and the readers better understand the effectiveness and efficiency of CO2 fracturing, especially in naturally fractured reservoirs.

Experimental investigation on the breakdown behaviours of sandstone due to liquid nitrogen fracturing

Liquid nitrogen (LN) fracturing is an efficient technology for the development of unconventional gas resources. Due to continuous injection of cryogenic LN, the reservoir temperature decreases and then cooled rock regions are gradually generated during fracturing process. To investigate the breakdown behaviours of sandstone induced by LN fracturing, laboratory simulation experiments were performed with a self-designed setup. The experimental results showed that rising initial rock temperature greatly reduced the breakdown pressure of sandstone, whereas hardly affected the fracture complexity. Under cryogenic conditions, both the compaction and cracking effects exerted influence on the pore structure of sandstone. Thus, the change in breakdown pressure depended on which effect played a domain role. Although the cryogenic conditions probably made the breakdown pressure of sandstone increase, the fracture complexity was expected to be significantly improved. In addition, the initial rock temperature increasing played a positive role in improving the fracture complexity under cryogenic conditions. For initial or heating sandstone samples, the fracture pattern mainly presented in the form of bi-wing fractures. However, for cryogenic samples, the fracture patterns contained both local fractures and complex fractures. The former was generated with lower breakdown pressure while the latter was generated with higher breakdown pressure. Additionally, the gas leak regions were observed in cryogenic samples during LN fracturing. Under cryogenic conditions, the sandstone used was favourable to generate more complex fractures and the permeability of rock matrix in unbroken region was proved to be improved due to LN fracturing. Collectively, fracturing with LN could improve the fracture complexity and the permeability of rock, which was very beneficial for well production.

A comparative study of oriented perforating and fracture initiation in seven shale gas plays

Oriented perforating strategies have been proposed as a method of suppressing fracture initiation pressures and optimizing the orientation of the initiated fractures, including a semi-empirical approach for predicting the fracture initiation pressure for given in-situ stress conditions and the orientation of fracture initiation (longitudinal or transverse-to-the-wellbore). In this study, a comparative analysis is made on the fracture initiation in stress conditions found in seven prolific shale gas plays, Barnett, Bakken, Fayetteville, Haynesville, Niobrara, Marcellus and Vaca Muerta, for cases of horizontal wells drilled parallel to the least horizontal principal stress. The developed semi-empirical approach is employed to determine the optimal perforation direction for each play, targeting transverse fracture initiation and fracture initiation pressure minimization. This involves a numerical model used to derive correction factors for closed-form analytical approximations from the literature, which are used to evaluate the stresses acting on the perforation base. While the leak-off and breakdown pressures can easily be pointed out from pressure monitoring, the fracture initiation pressures are not easily distinguishable. Reliable fracture initiation pressure estimations are of importance to stimulation engineers planning a treatment, as it controls the number and capacity of the injection pumps needed as well as being a major input for computational modeling. For normal faulting stress states, transverse fracture initiation is best promoted by perforations on the side of the hole, while for strike-slip faulting stress states, by perforations on the top of the hole. When only longitudinal fracture initiation is possible, the fracture initiation pressure is minimized from perforations on top of the borehole in normal faulting stress states and from the side of the borehole for strike-slip faulting stress states. Fracturing fluid leakage around the wellbore makes transverse fracture initiation harder and can also impact the fracture initiation pressures.

A Semianalytical Modeling Approach for Hydraulic Fracture Initiation and Orientation from Perforated Wells

Summary Accurate prediction of fracture initiation pressure and orientation is paramount to the design of a hydraulic fracture stimulation treatment and is a major factor in the treatment's eventual success. In this study, closed-form analytical approximations of the fracturing stresses are used to develop orientation criteria for relative-to-the-wellbore (longitudinal or transverse) fracture initiation from perforated wells. These criteria were assessed numerically and found to overestimate the occurrence of transverse fracture initiation, which only takes place under a narrow range of conditions in which the tensile strength of the rock formation is lower than a critical value, and the breakdown pressure falls within a “window.” For a case study performed on the Barnett Shale, transverse fracture initiation is shown to take place for breakdown pressures below 4,762 psi, provided that the formation's tensile strength is below 2,482 psi. A robust 3D finite volume numerical model is used to evaluate solutions for the longitudinal and transverse fracturing stresses for a variable wellbore pressure, hence developing correction factors for the existing closed-form approximations. Geomechanical inputs from the Barnett Shale are considered for a horizontal well aligned parallel to the direction of the least compressive horizontal principal stress. The corrected numerically derived expressions can predict initiation pressures for a specific orientation of fracture initiation. Similarly, at known breakdown pressures, the corrected expressions are used to predict the orientation of fracture initiation. Besides wellbore trajectory, the results depend on the perforation direction. For the Barnett Shale case study, which is under a normal faulting stress regime, the perforations on the side of the borehole yield a wider breakdown pressure window by 71% and higher critical tensile strength by 32.5%, compared to perforations on top of the borehole, implying better promotion of transverse fracture initiation. Leakage of fracturing fluid around the wellbore, between the cemented casing and the surrounding rock, reduces the breakdown pressure window by 11% and the critical tensile strength by 65%. Dimensionless plots are employed to present the range of in-situ stress states in which longitudinal or transverse hydraulic fracture initiation is promoted. This is useful for completion engineers; when targeting low permeability formations such as shale reservoirs, multiple transverse fractures must be induced from the horizontal wells, as opposed to longitudinal fracture initiation, which is desired in higher permeability reservoirs or “frac-and-pack” operations.

Investigation on the time-dependent characterization of stimulation behaviors for the shale under fracturing fluid invading

In order to understand the time-dependent characteristics of stimulation behaviors during hydraulic fracturing, the self-developed hydraulic fracturing monitoring system under triaxial loading was employed to investigate the cracks' propagation under shale-fluid coupling process. The results reveal that with different duration of fracturing fluid invasion, the pressurization rate of fluid pressure and breakdown pressure (BP) value are obviously varied, and the tensile crack is the dominant crack type, the amounts of shear cracks change accordingly, as well as the failure mode's evolution includes radial split, oblique shear, and combination of oblique shear and radial split. Moreover, the stress regime evolution rules around the cracks are obtained based on the Mohr-Coulomb criterion. This investigation will provide theoretical support for the fracturing's implement in the field, also can be as the laboratory evidence for the interpretation of microseism induced by long-term hydraulic fracturing.

Fracture toughness interpretation from breakdown pressure

One of the tests used to assess the possible dependence of the fracture toughness on stress relies on injecting fluid into a slotted borehole within a cylindrical rock sample subject to confining pressure and interpreting the toughness from the observed breakdown pressure. There is a wealth of experimental evidence that the so-measured toughness indeed increases with the confining stress. However, the interpretation of the observed breakdown pressure relies critically on assuming that the fluid pressure in the slots and the cracks ahead is uniform and on identifying the peak (breakdown) pressure with the fracture initiation pressure. The model described in this paper challenges these assumptions by considering the existence of a fluid lag at the tip of the hydraulic fracture and by incorporating the hydraulic compliance of the injection system. Numerical simulations indicate that there is an episode of stable crack growth, which is reflected by a continuous increase of the injection pressure after fracture initiation until the fracture becomes unstable. This model suggests that the actual toughness is generally overestimated, when it is interpreted from the breakdown pressure under the assumption of a uniform fluid pressure in the crack. Furthermore, this interpretation results in an artificial dependence of the toughness on the confining pressure. The overestimation depends essentially on two numbers, a scaled toughness and a scaled confining stress.