Multiple Transverse Fractures Research Articles

Optimizing in-situ CO2 mineralisation: geomechanics and scalability in dunite and serpentinite rocks – Examples from Australia and New Zealand

The collective drive towards achieving net-zero greenhouse gas emissions by 2050 has spurred interest in engineering solutions for carbon capture and storage worldwide. One such approach involves the permanent storage of CO2 in earth-abundant Ca-, Fe-, and Mg-bearing silicate rocks and minerals as carbonates via the process of CO2 mineralisation. This necessitates a thorough understanding of carbonate conversion under geologically relevant conditions. Nevertheless, research on CO2 injection for mineralisation via naturally fractured host rocks or induced fractures, with a research emphasis on rock mechanics and stimulated reservoir volumes (SRV) within geoengineering CO2 storage, is continuously expanding. This research addresses critical challenges related to identifying favourable geographic locations for CO2 mineralisation. It specifically focuses on the abundant availability of Mg, Ca, and Fe cations for exothermic CO2 reactions and their impact on fracture conductivity during in-situ mineralisation. A comprehensive analysis of 26 dunite and serpentinite samples from diverse locations in Australia and New Zealand, including 10 from a cored drilled hole, was conducted. Quantification of divalent cation (Mg, Ca, Fe) content and cation release capacity using XRF and XRD revealed higher cation percentages in dunite samples (approximately 30 %) compared to serpentinite samples (approximately 26 %). Additionally, the study estimated the stimulated rock mass-to-CO2 sequestered ratio, RCO2, with dunite samples averaging approximately 2.20 RCO2 values and serpentinite samples averaging approximately 2.53. Geomechanical testing enabled the prediction of fracture propagation pressures during aqueous CO2 injection for in-situ mineralisation and the estimation of fracture geometries, emphasizing the role of rock stiffness in determining fracture width (averaging 6.0 mm). Furthermore, the research estimated the rock volume exposed to CO2-laden fluid during injection, particularly focusing on the GHQ-3 sample, which theoretically amounted to approximately 600 kg of rock capable of sequestering around 300 kg of CO2 for a 10 m3 fluid volume with a CO2 concentration of 1molkg−1. The study established a relationship between injected volume and CO2 uptake, suggesting the potential for significant CO2 sequestration scalability by employing horizontal wells and fracturing additional zones, thereby creating and intersecting multiple transverse fractures along a single target zone.

Enhancing hydraulic fracturing for in-situ remediation in low-permeability soils: A comprehensive investigation of fracture propagation

Enhancing the complexity of the hydraulic fractures to provide a wide channel for the injection of the agent is crucial for remediating low-permeability contaminated sites. This study involved a physical simulation experiment of large-scale true triaxial hydraulic fracturing in undisturbed soil, as well as field fracturing tests, to investigate fracture initiation mechanisms and the influence of different factors on fracture propagation. The study revealed a unique failure mode for low-permeability soils characterized by impact splitting, involving simultaneous tensile and shear failure. Three typical fracture propagation patterns emerged: (1) horizontal fracture, (2) parallel fracture, and (3) complex fracture. Silty clay predominantly exhibited horizontal fractures, while mucky clay facilitated the formation of complex fractures dominated by multiple transverse fractures. As the vertical stress difference coefficient increased from 1.0 to 1.5, the pressure on the fracture surface enhanced the connection between hydraulic fractures and natural fractures. Hydraulic fracturing in low-permeability soils necessitated large displacements and high-viscosity fracturing fluids to sustain fracture propagation. The field fracturing test results underscored that soil type and in-situ stress were the primary factors governing hydraulic fracture initiation and propagation. Identifying the optimal fracturing location was critical for achieving the maximum stimulated formation volume.

Case Report-Traumatic L5-S1 Instability: Are Upright Radiographs Potentially Dangerous?

Traumatic lumbosacral instability is a rare but potentially devastating injury. These injuries are frequently associated with neurologic injury and often result in long-term disability. Despite their severity, radiographic findings can be subtle, and multiple reports exist in which these injuries were not recognized on initial imaging. Transverse process fractures, high-energy mechanisms, and other injury features have been suggested as indications for advanced imaging, which has a high degree of sensitivity in detecting unstable injuries. A 21-year-old man presented to our level I trauma center after being ejected in a rollover motor vehicle collision. He sustained multiple injuries, including multiple lumbar transverse process fractures and a unilateral superior articular facet fracture of S1. Initial supine computed tomography (CT) images showed no displacement of the fracture and no listhesis or instability. Subsequent upright imaging in a brace, however, demonstrated significant displacement of the fracture with dislocation of the contralateral L5-S1 facet joint and significant anterolisthesis. The patient underwent open posterior reduction and stabilization of L4-S1 followed by L5-S1 anterior lumbar interbody fusion. The patient demonstrated excellent alignment on postoperative imaging. At 3 months postoperatively, he had returned to work, was ambulating without assistance, and reported minimal back discomfort and no lower extremity pain, numbness, or weakness. This case serves as a warning that supine CT imaging alone may not be sufficient to rule out unstable lumbar spine injuries, such as traumatic L5-S1 instability, and that upright radiographs in these potentially unstable injuries may represent a hazard to patients. Fractures involving the pedicle, pars, or facet joints as well as multiple transverse process fractures and/or a high-energy mechanism of injury should all raise suspicion of instability and warrant additional imaging. This article provides guidance on approaching treatment for patients with potential traumatic lumbosacral instability.

Experimental study on the multiple fracture simultaneous propagation during extremely limited-entry fracturing

Horizontal well with multi-stage fracturing is one of the most effective stimulation methods for unconventional reservoirs, e.g. tight oil/gas or shale. To maximize reservoir stimulation volume (SRV), tighter fracture spacing and fewer perforations are distributed in one stage during extreme limited-entry fracturing (XLEF) in recent years. However, the fracture geometries and injection pressure curve are not clear when multiple fractures with close spacing were created simultaneously in the perforated wellbore during XLEF. This study investigated the multiple fracture simultaneous propagation in the XLEF perforated wellbore based on the true tri-axial fracturing experiments. Critical factors of horizontal stress difference (HSD), the number of perforation clusters, helical/in-plane perforated method, number of perforations per cluster and fracturing fluid flowrate were investigated in detail. The results showed that, firstly, compared to one fracture produced by the helical perforated method, XLEF with the in-plane perforated method has a higher breakdown pressure and could simultaneously create multiple transverse fractures. Secondly, longitudinal fractures and a small number of curved transverse fractures occurred simultaneously under lower HSD conditions, while multiple parallel transverse fractures could be created under high HSD conditions. Thirdly, increasing the number of perforations per cluster will reduce perforation cluster effectiveness, and increasing the number of clusters will lead to the merging of multiple fractures. Finally, three relationships between pressure response and fracture geometries during XLEF, e.g. single transverse fracture, multiple transverse fractures, co-existence of longitudinal and transverse fractures, have been revealed. This study provides a meaningful perspective for the multiple fracture propagation in the perforated wellbore, which could help the field fracturing design during XLEF.

Experimental study on plugging performance and diverted fracture geometry during different temporary plugging and diverting fracturing in Jimusar shale

Temporary plugging and diverting fracturing (TPDF) is one promising technology to form complex fracture networks in unconventional oil and gas resources, such as Jimusar shale in China. The key to the success of this technology depends on two processes: creating a tight plug within previously-created fractures using temporary plugging agents (TPA), and then forming diverted fractures after plugging. Many scholars have studied the plugging law of TPA under different channels aiming at the first process. However, the second process of fracture re-direct to form fracture networks after effective plugging has not been investigated clearly, especially in shale formations. Based on Jimusar shale, this paper investigated the plugging performance of fibers and particles and diverting fracturing behavior under three different TPDF application scenarios: near-wellbore in-plane TPDF, multistage TPDF in the horizontal wellbore, and far-field TPDF within fractures. A series of experiments were carried out under different stress difference conditions and TPA types using true tri-axial fracturing system. Experimental results show that: firstly, in near-wellbore TPDF experiments, the plugging pressure peaks would be increased with horizontal stress difference (HSD) while the deflection angle between the diverted fracture and the initial fracture would decrease with HSD. Once the HSD is over 7.5 MPa, the diverted fractures would be nearly parallel to the initial fractures. Secondly, in far-field TPDF within 2 mm propped fractures, 1 wt% pure fibers cannot form the effective plug in any fractures regardless of the HSD, while the combination of 1 wt% fibers and 1 wt% particles could effectively plug all fractures. The diverted fractures could be only created as branch fractures at the middle of the initial fractures, but the diverted fractures would be merged into the initial fractures when HSD is over 7.5 MPa. Thirdly, in multistage TPDF in the horizontal wellbore, the initial fracture almost initiates from only one slot and becomes one transverse fracture, but multiple parallel transverse fractures after plugging could happen but not always occur. The diverted fracture may also form a longitudinal fracture under low HSD because the slots have been plugged by TPAs. In addition, influenced by bedding and natural fractures, more bedding fractures are activated after plugging, which forms a more complex fracture network. Our experimental results could deepen the understanding of TPDF in Jimusar shale reservoir and also provide fundamental for field design in similar shale reservoirs.

Regenerative endodontic procedures for two traumatized mature anterior teeth with transverse root fractures

BackgroundRegenerative endodontic procedures (REPs) are an alternative treatment in immature traumatized teeth with necrotic pulp/apical periodontitis. However, this procedure has been infrequently reported in multiple transverse root fractures of mature teeth. This case report describes management of a patient with multiple horizontal root fractures in 2 maxillary central incisors that were successfully treated with REPs.Case presentationA 17-year-old girl had a history of traumatic injury to mature teeth 11 and tooth 21 resulting in multiple transverse root fractures. Clinical examination showed that both teeth responded to electric and thermal pulp sensibility tests with prolonged severe pain and were tender to percussion and palpation. Periapical radiographic examination showed both teeth were fully developed and had multiple transverse fractures in the mid-root. The pulp diagnosis was consistent with symptomatic irreversible pulpitis. REPs were initiated with only the coronal fragments treated to preserve pulp vitality in the apical fragment for potential pulp tissue regeneration. After REPs, clinical signs/symptoms subsided, and the two teeth were followed for 48 months when cone beam computed tomography (CBCT) imaging was also undertaken. At the last review, the case demonstrated root fractures healing with calcified tissue and pulp calcification in the apical fragments. Both teeth were stable and in function.ConclusionsREPs have the potential to be used to treat traumatized and symptomatic mature permanent teeth that have sustained transverse root fractures.

Experimental Study of Hydraulic Fracture Propagation Behavior during Multistage Fracturing in a Directional Well

Due to the limited space of offshore platform, it is unable to implement large-scale multistage hydraulic fracturing for the horizontal well in Lufeng offshore oilfield. Thus, multistage hydraulic fracturing technology in directional well was researched essentially to solve this problem. Modeling of fracture propagation during multistage fracturing in the directional and horizontal wells in artificial cores was carried out based on a true triaxial hydraulic fracturing simulation experiment system. The effects of horizontal stress difference, stage spacing, perforation depth, and well deviation angle on multifracture propagation were investigated in detail. Through the comparative analysis of the characteristics of postfrac rock and pressure curves, the following conclusions were obtained: (1) multistage fracturing in horizontal wells is conducive to create multiple transverse fractures. Under relatively high horizontal stress difference coefficient (1.0) and small stage spacing conditions, fractures tend to deflect and merge due to the strong stress interference among multiple stages. As a consequence, the initiation pressure for the subsequent stages increases by more than 8%, whereas in large stage spacing conditions, the interference is relatively lower, resulting in the relatively straight fractures. (2) Deepening perforation holes can reduce the initiation pressure and reduce the stress interference among stages. (3) When the projection trace of directional wellbore on horizontal plane is consistent with the direction of the minimum horizontal principal stress, fractures intersecting the wellbore obliquely are easily formed by multistage fracturing. With the decrease of well deviation angle, the angle between fracture surface and wellbore axis decreases, which is not conducive to the uniform distribution of multiple fractures. (4) When there is a certain angle between the projection trace of directional wellbore on horizontal plane and the direction of minimum horizontal principal stress, the growth of multiple fractures is extremely ununiform and the fracture paths are obviously tortuous.

Numerical simulation on the simultaneous stress interference of parallel multiple hydraulic fractures

During horizontal well staged fracturing, there is stress interference between multiple transverse fractures in the same perforation cluster. Theoretical analysis and numerical calculation methods are applied in this study. We analysed the mechanism of induced stress interference in a single fracture under different fracture spacings and principal stress ratios. We also investigated the hydraulic fracture morphology and synchronous expansion process under different fracture spacings and principal stress ratios. The results show that the essence of induced stress is the stress increment in the area around the hydraulic fracture. Induced stress had a dual role in the fracturing process. It created favourable ground stress conditions for the diversion of hydraulic fractures and the formation of complex fracture network systems, inhibited fracture expansion in local areas, stopped hydraulic fractures, and prevented the formation of effective fractures. The curves of the maximum principal stress, minimum principal stress, and induced principal stress difference with distance under different fracture lengths, different fracture spacings, and different principal stress ratios were consistent overall. With a small fracture spacing and a small principal stress ratio, intermediate hydraulic fractures were difficult to initiate or arrest soon after initiation, fractures did not expand easily, and the expansion speed of lateral hydraulic fractures was fast. Moreover, with a smaller fracture spacing and a smaller principal stress ratio, hydraulic fractures were more prone to steering, and even new fractures were produced in the minimum principal stress direction, which was beneficial to the fracture network communication in the reservoir. When the local stress and fracture spacing were appropriate, the intermediate fracture could expand normally, which could effectively increase the reservoir permeability.

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.

Characterising the application of horizontal wells and indirect hydraulic fracturing for improved coal seam gas drainage

Historically, horizontal wells in coal seam gas (CSG) producing areas of Australia have been limited in their ability to stimulate horizontal wellbores with hydraulic fractures, despite most basins being in favourable stress states capable of generating multiple transverse hydraulic fractures. In some cases, overlapping mining tenements limit the ability to effectively deploy steel casing completions to effectively manage multi-stage fracture stimulations along the lateral. In other cases, potential wellbore instabilities preclude the placement of laterals with adequate length to stage numerous fractures required to make a well economic. Strike Energy’s Jaws 1 well indicated well instability when drilling horizontally in the Patchawarra Vu Coal Seam in Petroleum Exploration Licence 96 of the Weena Trough in the Cooper Basin. To overcome this instability, Strike Energy introduced the application of an innovative process of deploying multiple, indirect hydraulic fractures in Jaws 1ST from a horizontal wellbore underlying the coal. Microseismic and surface deformation tiltmeter data acquired during the treatment confirmed the successful placement of fractures in the Patchawarra Vu Coal Seam. Further, chemical tracing and production testing provide further insight into the placement and effectiveness of the overall stimulation. Through analyses of data from the Jaws 1ST, we provide insight and recommendations regarding horizontal well placement to improve indirect hydraulic fracture effectiveness. These recommendations would be applicable for other Australian CSG basins where direct horizontal well drilling and fracture stimulation has been limited (e.g. overlapping mining tenements) or where horizontal well instabilities limit drilling within the seam (i.e. Cooper Basin, depleted coals).

Orientation prediction of fracture initiation from perforated horizontal wells: Application in shale reservoirs

For maximum productivity enhancement when targeting low permeability formations, horizontal wells must be made to induce multiple transverse fractures. An orientation criterion for fracture initiation is developed using analytically-derived approximations for the longitudinal and transverse fracturing stresses for perforated wellbores from the literature. The validity of the criterion is assessed numerically and is found to overestimate transverse fracture initiation, which occurs under a narrow range of conditions; pertaining to low breakdown pressure and low formation tensile strength.A three-dimensional numerical model shows that contrary to existing approximations, the transverse fracturing stress from perforated horizontal wells becomes more compressive as wellbore pressure increases. This shrinks the “breakdown pressure window,” which is the range of wellbore pressures over which transverse fracture initiation takes place. This creates a second constraint for transverse fracture initiation, which is the "critical tensile strength" value. This determines the maximum formation tensile strength at which transverse fracture initiation is possible for a given in-situ stress state and perforation direction.Sensitivity analyses are performed based on data from seven unconventional shale reservoirs (Barnett, Bakken, Fayetteville, Haynesville, Niobrara, Marcellus and Vaca Muerta) for horizontal wells drilled parallel to Shmin. The frequent longitudinal fracture initiation occurrence indicated suggests fracture reorientation in the near-wellbore region to be a common event, through which the propagating fractures become aligned with the preferred fracture plane (perpendicular to the least compressive principal stress). This induces near-wellbore fluid tortuosity, which in turn can lead to completions and production-related problems, such as early screenouts and post-stimulation well underperformance.

Study on the Interference Law of Staged Fracturing Crack Propagation in Horizontal Wells of Tight Reservoirs.

Horizontal well multistage fracturing technology is a high-efficiency method for tight oil and gas production, which increases the contact area between the wellbore and stratum by forming multiple transverse hydraulic fractures (HFs). The stress interference caused by the created HFs will affect the propagation geometries of the subsequent HFs, and then affect the overall fracturing treatment performance. In order to study the distribution of HFs and law of interference among multiple fractures during horizontal well multistage fracturing in tight reservoirs, in this paper, the effects of horizontal stress difference, perforation spacing, and net pressure in the created fracture on the initiation and propagation of multiple cracks were specially studied through large-scale hydraulic fracturing experiments and numerical simulation. The results showed that under high horizontal stress difference, multiple HFs with small spacing tended to coalesce at a place where the length has extended to a certain level. It was also found that the initiation pressures of HFs within subsequent stages increase with the rise of net pressure in created HFs, which causes the subsequent fractures to deviate from the direction perpendicular to the horizontal wellbore and then to gradually deflect toward it. Moreover, the ratio of fracture spacing to fracture height, and the net pressure are the key parameters to determine the deflection degree of HFs for multistage fracturing. In addition, the deflection degree of subsequent HFs was expected to enhance with the decreasing ratio of fracture spacing to fracture height and increasing net pressure in created HFs. It was useful for mitigating stress interference to lengthen the stage spacing, control the fracture height, and reduce the net pressure. The research results have a reference value for the optimal design of the fracture spacing for multistage fracturing.

A novel data-driven pressure/rate deconvolution algorithm to enhance production data analysis in unconventional reservoirs

Horizontal wells with hydraulic fractures enable economical hydrocarbon extraction from unconventional reservoirs, and the associated transient production data is a reliable source for reservoir characterization. However, the complicated convolution of rate-pressure-time history leads to a less informative analysis of true reservoir characteristics. This paper presents a novel data-driven deconvolution approach using physics-based superposition to reconstruct constant-rate-drawdown pressure response, which are further translated into diagnostic plots for efficient production analysis.Traditional deconvolution in pressure transient analysis is usually an ill-conditioned “inverse” process that requires systematic curve-fitting, and the deconvolution response is highly sensitive to noise. Our proposed approach uses superposition equations as training features to honor the transient physics, and further projects them into higher dimensional ‘reservoir’ space (kernel-space) for the purpose of rigorous regression. Additionally, by implementing Laplacian eigenmaps, our algorithm is relatively insensitive to noise owing to its locality-preserving character. After training, the constant-rate-drawdown pressure response is reconstructed and a diagnostic plot is generated to identify key reservoir characteristics such as flow regimes.We first validated our approach with two synthetic cases, a horizontal well with single and multiple transverse fractures (MTFW), and the drawdown pressure response was obtained through simulation using a highly variable flow rate history. Additionally, we added artificial white Gaussian noise to the simulation output to mimic measured signals collected in the field, and we input this data into our model for deconvolution. The model-reconstructed constant-rate-drawdown pressure response was used to determine flow regimes and reservoir properties such as permeability and stimulated reservoir volume (SRV) using traditional transient testing diagnostic tools and specialized plots. The deconvolved response for each case were in alignment with the fractured-basement reservoir model proposed by Kuchuk and Biryukov (2012), and the flow regimes identified during MTFW production followed the theory proposed by Song and Ehlig-Economides (2011). All deconvolved responses were further validated through comparison with both simulation results and analytical solutions. Through the inherent locality-preserving character, our proposed algorithm was able to handle a moderate level of noise in addition to the variation of pressure-rate signals. We then applied the methodology to a field case, and the outcomes were satisfactory.This study showed that our proposed methodology is a reliable diagnostic tool to interpret pressure-rate data using traditional pressure transient analysis for unconventional reservoirs. Rapid and accurate deconvolved pressure response greatly enhances the analysis of data with moderate noise and highly variable production histories, enabling engineers to recognize flow patterns and estimate reservoir properties. We demonstrated the versatility and applicability of our proposed approach with synthetic and field cases.

Geomechanics and Flow Parameters that Influence Shale Gas/Shale Oil’s Design

Unconventional reservoirs (NCR) have been responsible for an important revolution in the volume and profile of gas production in the USA and are now arousing interest of other countries e.g. China, Canada, Argentina and Australia. In most of the NCR, the development of production has been made possible through horizontal wells with multiple transverse fractures. In order to optimize the well hydraulic fracturing design for exploration and production’s development of shale gas/shale oil, is required to understand the key parameters that influence in the complex fractures network. In terms of reservoir stimulation through horizontal wells, the practice by smaller operators came before the theory, generating nice results and promoting theoretical development. The recent join of big operators into the unconventional reservoirs environment raised about the huge volumes of fluids and propping agents used in the complex fractures network, have generated some questions about shale gas/shale oil well stimulation. This work presents the main parameters that have influence on the complex fractures network built in shales, aiming to understand their effects in shale rock in order to avoid problems and optimize the hydraulic fracturing design.

Optimizing the Number of Fractures in a Horizontal Well

Summary Horizontal wells with multiple hydraulic fractures have become a standard completion for the development of tight oil and gas reservoirs. Successful optimization of multiple-fracture design on horizontal wells began empirically in the Barnett Shale in the late 1990s (Steward 2013; Gertner 2013). More recently, research has focused on further improving fracturing performance by developing a model-derived optimum. Some researchers have focused on an economic optimum on the basis of multiple runs of an analytical or numerical model (Zhang et al. 2012; Saputelli et al. 2014). With such an approach, a new set of model runs is necessary to optimize the design each time the input parameters change significantly. Running multiple simulations for every optimization case might not always be practical. An alternative approach is to develop well-performance curves with dimensionless variables on the basis of the performance model. Such an approach was the basis for unified fracture design (UFD) for a single fracture in a vertical well (Economides et al. 2002). However, a similar systemized method to calculate the optimum for a horizontal well with multiple hydraulic fractures was missing. The objective of this study was to develop a rigorous and unified dimensionless optimization technique with type curves for the case of multiple transverse fractures in a horizontal well—an extension of UFD. The mathematical problem was solved in dimensionless variables. Multiple fractures include the proppant number (NP), penetration ratio (Ix), dimensionless conductivity (CfD), and aspect ratio (yeD) for each fracture, which is inversely proportional to the number of fractures. The direct boundary element (DBE) method was used to generate the dimensionless productivity index (JD) for a given range of these parameters (28,000 runs) for the pseudosteady-state case. Finally, total well JD was plotted as a function of the number of fractures for various NP. The effect of minimum fracture width was studied, and the optimization curves were adjusted for three cases of minimum fracture width. The provided dimensionless type curves can be used to identify the optimized number of fractures and their geometry for a given set of parameters, without running a more complicated numerical model multiple times. First, the proppant mass (and hence, NP) used for the fracture design can be selected on the basis of economic or other considerations. For this purpose, a relationship between total JD and NP, which accounts for the minimum fracture width requirement, was provided. Then, the optimal number of fractures can be calculated for a given NP using the generated type curves with minimum width constraints. The following observations were made during the study on the basis of the performed runs: For a given volume or proppant, NP, total JD for multiple fractures increases to an asymptote as the number of fractures increases. This asymptote represents a technical potential for multiple fractures and for high proppant numbers (NP≥100), with a technical potential of 3πNP. Below this asymptote, the more fractures that are created for a fixed NP, the larger the JD. In practice, minimum fracture width constrains the fracture geometry, and therefore maximum JD. For the case when 20/40 sand is used for multiple hydraulic fracturing of a 0.01-md formation with square total area, the optimal number of factures is approximately NP25. Application of horizontal drilling technology with multiple fractures assumes the availability of high proppant numbers. It was shown mathematically that the alternative low proppant numbers (NP≤20 for the previous case) are impractical for multiple fractures, because total JD cannot be significantly higher than JD for an optimized single fracture in the same area. This means that low formation permeability and/or high proppant volumes are needed for multiple fracture treatments.

Comparison of Different Hydraulic Fracturing Scenarios in Horizontal Wells Using XFEM Based on the Cohesive Zone Method

Multistage hydraulic fracturing is a highly effective method for creating multiple transverse fractures to improve gas and oil reservoir production. It is critical to minimize the fracture spacing while also ensuring transverse propagation of fractures in multi-fractured horizontal wells. In this paper, a 3D fully coupled pore pressure-stress model based on the extended finite element method (XFEM) combined with the cohesive zone method is established to simulate five different fracturing scenarios in close spacing. The sensitivity of mesh size and the integration method are optimal, which are verified by the highly accurate traditional cohesive zone method. Then, the effect of five different fracturing scenarios on fracture geometries is compared. It is shown that spacing is a key parameter controlling fracture geometries in all fracturing scenarios. Alternative sequential and modified two-step fracturing can significantly reduce the influence of stress shadowing to generate more transverse fractures and form longer effective fractures. The sequential and two-step fracturing see an obvious improvement with increased fracture effective length when the spacing increases. The simultaneous fracturing technique can result in excessive closure of the middle fractures, which causes serious insertion of proppants. These results offer a new insight on optimization of hydraulic fracturing and can be a guidance for typical field cases.

Transient pressure analysis of horizontal well with nonorthogonal transverse fractures and drainage volume characterization using Fast Marching Method

Horizontal well drilling and multistage hydraulic fracturing are essential to economic recovery of unconventional tight/shale reservoirs. Multiple transverse fractures are ideally supposed to be perpendicular to the minimum stress direction, but nonorthogonal transverse fractures might be seen in practice, which might bring a better connection between wellbore and fractures. However, for the same fracture half-length, the stimulated reservoir area might be less. Thus, the well performance with these nonorthogonal transverse fractures is full of uncertainty. Little research work is currently conducted on the nonorthogonal transverse fracture scenario.Our transient pressure analysis of horizontal well performance with nonorthogonal transverse hydraulic fractures utilizes the concept of rate-normalized pressure and transient productivity index. The novel Fast Marching Method (FMM) is adopted to characterize the drainage volume evolution for multi-stage horizontal wells and validate the proposed methodology. Sensitivity studies contrast transient pressure behavior and productivity index for azimuth angles from 15 to 90°, e.g. from nearly longitudinal to truly transverse fracture angles. Additionally, transient pressure behavior and long-term reservoir performance of horizontal well for different scenarios are investigated, such as reservoir anisotropy and different proppant allocation strategies under the constraints of given horizontal well spacing and total proppant amount.Contrast to what we are usually expecting, results show that for the same fracture spacing, and the same total proppant amount, the well with nonorthogonal transverse fractures will have a higher productivity index than that for truly transverse fractures. Different from productivity index, the long-term reservoir performance, however, turns out to play a different game, given specific horizontal well spacing and the same total proppant amount. Reservoir performance for horizontal well with nonorthogonal transverse fractures can be significantly improved by optimally allocating the proppant and designing hydraulic fracture placement strategies through this research.

Do Multiple Isolated Vertebral Thoracolumbar Transverse Process Fractures Increase the Risk of Ligamentous Injury and Surgical Intervention in the Setting of Trauma?

Background: Isolated thoracolumbar vertebral transverse process fractures (TPF) are often considered a stable injury. However, the use of advanced imaging such as magnetic resonance imaging and spine specialist consultation are often ordered as part of the routine workup of these fractures. The routine ordering of advanced imaging, spine specialist consultation, and delayed mobilization causes unnecessary economic and clinical burdens to patients and the overall healthcare system. Purpose: To determine if a higher number of isolated TPFs (iTPFs) lead to an increase in ligamentous injury to the spine, and whether ligamentous injury—if present—requires surgical intervention. Methods: The retrospective review was performed from 2009 to 2015, using a surgical trauma database to identify patients with greater than 3 isolated TPF (iTPF) to determine if iTPF leads to an increase in ligamentous injury to the spine and if this increase leads to increased surgical intervention. Results: A total of 102 patients were identified with complete follow up at 6 - 8 weeks post injury. The majority of the included patients suffered from blunt trauma. There was a small rate of ligamentous injury (n = 7, 7%) that did not require additional treatment. None of the fractures included were considered unstable. None of the patients included required surgical intervention during their hospital visit or in follow up visits. Conclusion: iTPFs are a stable injury to the thoracolumbar spine. There is a small rate of associated ligamentous injury that does not change the management or require further interventions. Thoracolumbar iTPFs do not automatically need spine specialist consultation and advanced imaging techniques.

A review of stimulated reservoir volume characterization for multiple fractured horizontal well in unconventional reservoirs

Unconventional resource exploration has boosted U.S. oil and gas production, which is successfully by horizontal well drilling and hydraulic fracturing. The horizontal well with multiple transverse fractures has proven to be effective stimulation approach could increase reservoir contact significantly. Unlike the single fracture planes in typical low permeability sands, fractures in shales tends to generate more complex, branching networks. The concept of stimulated reservoir volume (SRV) was developed to quantitative measure of multistage fracture interact with natural fractures in unconventional reservoir. However, the simple fracture modeling of the past do not suitable for the complex scenarios simulation. This paper reviews the mainstream characterization method of stimulated reservoir volume in shale reservoirs, including microseismic interpretation, rate transient analysis method, analytical and semi-analytical method and numerical method. Finally, the systematic evaluation of application conditions with respect to each method and further research directions for characterization method are proposed.

Effect of discontinuity stress shadows on hydraulic fracture re-orientation

Hydraulic fracturing has been applied to the cave mining industry as a pre-conditioning method to improve rock mass caveability and fragmentation sizes. In theory, the hydraulic fracture orientation is dictated by and is perpendicular to the minimum in-situ stress orientation. Such orientations will not always result in the creation of a blocky rock mass to aid caveability. The understanding of hydraulic fracture re-orientation induced by the stress shadow effect is important for either avoiding the undesirable interaction between multiple transverse hydraulic fractures or taking advantage of this phenomenon to create prescribed hydraulic fractures that result in the creation of blocky rock masses. In this paper, the existing knowledge of the stress shadow effect around a pre-existing discontinuity is reviewed. A 3D numerical modelling code, Rock Failure Process Analysis (RFPA) is used to investigate factors influencing hydraulic fracture re-orientation. It is established that hydraulic fractures can be forced to propagate in desired directions if advantage is taken of the stress shadow effect in combination with knowledge of rock mass homogeneity and site far field stress conditions. Both the differential stresses between σ2 and σ3 and between σ1 and σ3 affect the hydraulic fracture re-orientation geometry. The minimum far field stress magnitude has no direct impact on hydraulic fracture re-orientation. Rock mass homogeneity significantly influences how far a hydraulic fracture propagates along its predefined orientation from its initiation point before re-orientation.