Fracture Design Research Articles

Modeling the spreading and remediation efficiency of slow-release oxidants in a fractured and contaminated low-permeability stratum

Traditional remediation technologies cannot well remediate the low permeability contaminated stratums due to the limitation in the transport capacity of solute. The technology that integrates the fracturing and/or slow-released oxidants can be a new alternative, and its remediation efficiency remains unknown. In this study, an explicit dissolution-diffusion solution for the oxidants in control release beads (CRBs) was developed to describe the time-varying release of oxidants. Together with advection, diffusion, dispersion and the reactions with oxidants and natural oxidants, a two-dimensional axisymmetric model of solute transport in a fracture-soil matrix system was established to compare the removal efficiencies of CRB oxidants and liquid oxidants and to identify the main factors that can significantly affect the remediation of fractured low-permeability matrix. The results show that CRB oxidants can achieve a more effective remediation than liquid oxidants under the same condition due to the more uniform distribution of oxidants in the fracture and hence a higher utilization rate. Increasing the dose of the embedded oxidants can benefit the remediation to some extent, while at small doses the release time over 20 d has little impact. For extremely low-permeability contaminated stratums, the remediation effect can be significantly improved if the average permeability of the fractured soil can be enhanced to more than 10−7 m/s. Increasing the injection pressure at a single fracture during the treatment can enlarge the influence distance of the slow-released oxidants above the fracture (e.g., 0.3–0.9 m in this study) rather than below the fracture (e.g., 0.3 m in this study). In general, this work is expected to provide some meaningful guidance for the design of fracturing and remediating low permeability contaminated stratums.

Prediction of Tensile Strength in Tight Sandstone Based on Well Logging Data

The tensile strength of tight sandstone reservoirs has a direct impact on crack initiation, hydraulic fracture propagation, and the connectivity between hydraulic fractures and natural fractures during hydraulic fracturing processes. To overcome the limitations of experimental testing methods and field hydraulic fracturing techniques, this study conducted Brazilian tensile strength tests to obtain tensile strength data for 16 sets of tight sandstone samples. By comparing these experimental results with well logging data, a predictive model for the tensile strength of tight sandstone was established based on geophysical well logging data, with a correlation coefficient exceeding 0.92. The research findings indicate a positive correlation between tensile strength and sample density. This study provides support for fracture design, assesses fracturability, and aids in the selection of optimal drilling locations for hydraulic fracturing operations.

Application of Micro-Seismic Monitoring in Post-Fracturing Evaluation of Shale Gas: A Case Study of Well X from Puguang Area, China

Multi-stage fracturing of horizontal wells is an indispensable technology to create complex fracture networks, which can unlock production potential and enable commercial productivity for shale gas with low porosity and permeability. Real-time monitoring of fracture networks is essential for adjusting key parameters, mitigating fracturing risks, and achieving optimal fracturing effects. Micro-seismic monitoring technology accurately captures and describes the development of fracture networks by detecting micro-seismic waves generated through rock ruptures, providing valuable insights into the evaluation of post-fracturing. In this study, we first introduced the basic parameters of well X that were obtained by laboratory experiments and logging interpretation, including porosity, gas-bearing properties, mineral composition, rock mechanics, and crustal stress. Then, the hydraulic fracturing scheme was designed on the basis of the geological engineering characteristics of well X. Finally, we conducted a comprehensive analysis of various factors that can affect hydraulic fracturing. This included an examination of the impact of pre-fluid temporary plugging and fracture complexity on the overall effectiveness of the operation. Based on the laboratory experiments and theoretical analysis, the following conclusions can be drawn: (1) fracture size is essentially formed when the fluid strength exceeds 35 m3/m; (2) both preflush with high viscosity and the amount of power sand exceeding 20 cubic meters are conducive to the propagation of fracture height; (3) temporary plugging balls facilitate the balanced propagation of multiple fracture clusters within a stage, whereas temporary plugging particles promote the formation of complex fractures; and (4) geological conditions are a prerequisite for creating a complex network of fractures, and only engineering techniques can facilitate the appropriate enhancement of fracture complexity. This study provides an essential method for the fracturing design of shale gas.

Experimental investigation on the propagation of hydraulic fractures in massive hydrate-bearing sediments

Hydraulic fracturing is regarded as one of the potential technical means to realize efficient development of natural gas hydrate. Massive-distributed hydrates are widespread around the world, although the solid fluidization method has been proposed to develop this kind of reservoir, the process of this method is complex, and there are still a lot of key problems need to be solved. Meanwhile, when the hydrate decomposed during production, how to maintain formation stability is still an unsolved key problem. Therefore, we consider using hydraulic fracturing technology to exploit this kind of reservoir. On the one hand, the fractures formed by high viscosity fracturing fluid can improve the reservoir permeability. On the other hand, the proppant added during fracturing can play a good supporting role to the formation. In this work, a series of large-size (300 × 300 × 300 mm) hydraulic fracturing physical simulation experiments were conducted under true triaxial stress states to investigate hydraulic fracture propagation law in massive-distributed hydrate-bearing reservoir. The effects of massive hydrate size, approaching angle and fracturing fluid displacement on the fracture propagation were studied. The experimental results indicated that massive hydrate exerts an important influence on hydraulic fracture propagation. Two main massive hydrate-hydraulic fracture interaction modes were observed in our experiments: (a) When the massive hydrate size is small, the hydraulic fractures mainly propagated along the interface between the sediment matrix and the massive hydrate. (b) The hydraulic fractures penetrated the massive hydrate, which usually occurs when hydraulic fracture encountered large-size massive hydrate, and the penetrated position moves from both sides to the central position of the massive hydrate. The approaching angle has a significant effect on the massive hydrate-hydraulic fracture interaction law. Under the condition of high approaching angle, hydraulic fractures easily penetrated the massive hydrate. The influence of fracturing fluid displacement on massive hydrate-hydraulic fracture interaction is closely related to massive hydrate size. When hydraulic fractures encountered the small-size massive hydrate, increasing the displacement has a limited effect on massive hydrate-hydraulic fracture interaction, and the hydraulic fractures still mainly propagated along the interface. When large-size massive hydrates are distributed in the sample, increasing the displacement has a significant effect on the massive hydrate-hydraulic fracture interaction, and hydraulic fractures tend to branch, the complex fracture geometry would be formed. In this study, a new large-size massive hydrate sample preparation method was proposed, and the effects of various factors on the hydraulic fracture propagation law were investigated experimentally, which can provide guidance for the fracturing design of massive hydrate-bearing reservoir.

Automatic Optimization of Multi-Well Multi-Stage Fracturing Treatments Combining Geomechanical Simulation, Reservoir Simulation and Intelligent Algorithm

Shale reserves have become an ever-increasing component of the world’s energy map. The optimal design of multi-well multi-stage fracturing (MMF) treatments is essential to the economic development of such resources. However, optimizing MMF treatments is a complex process. It requires geomechanical simulation, reservoir simulation, and automatic optimization. In this work, an integrated workflow is proposed to optimize MMF treatments in an unconventional reservoir, and the net present value (NPV) of reserves was treated as the objective function. The forward model consists of two submodels: a hydraulic fracturing model and a reservoir simulation model. The stochastic simplex approximation gradient (StoSAG) is used with the steepest ascent algorithm to maximize the NPV function. The computational results show that optimizing the fracture design can achieve a 20% higher NPV than that obtained with the field reference case. The drainage area of the optimal design is larger than that of the initial design. The maximum gas production rate increases from 23.75 MMSCF/day to 34.43 MMSCF/day and the maximum oil production rate increases from 497 STB/day to 692 STB/day. Therefore, new optimization paths can accelerate fracture design and help increase well production. This paper innovatively proposes a coupled workflow that can reduce the waste of manpower and improve the optimization results.

Numerical simulation of near wellbore fracture propagation in interbedded continental shales with competing perforations

To reduce near wellbore fracture complexity in continental laminated shales, in-plane perforations completion technology is introduced. The global embedded cohesive elements are capable to simulating arbitrary fracture propagation growth while the laminae effects on fracture propagation path can be considered in established finite element model. Numerical simulations reflect that the existence of weak micro fractures only locally alter the fracture propagation path but laminae can change the fracture propagation path greatly. Furthermore, the in-situ stress anisotropy, pump rate, perforation intersection angle and perforation angle with laminae are critical factors for affecting the fracture propagation path and breakdown pressure. There is a great impact of laminae on the fracture branching at the contact interface and hydraulic fracture tends to cross laminae at high approaching angle but propagate horizontally along laminae at low approaching angle. In most cases, hydraulic fracture tends to propagate along the laminae rather than across the laminae. The adjustment of pump rate, fluid viscosity, perforation intersection angle and perforation angle with laminae can enhance the possibilities of hydraulic fracture across laminae. It was also found that hydraulic fractures induced from different perforations can interact and overlap with each other, resulting in different fracture geometry and pressure behavior for individual fracture. The fracture width of interior fracture is almost close at the near wellbore zone at the end of pumping, and exterior fractures generally deviated away from the perforation tunnel direction because of stress interference of neighboring fractures. Additionally, although a fracture initiated initially from a perforation tunnel to short distance, hydraulic fractures still finally would reorient itself to maximum principle in-situ stress direction, thus increase more chances of creating one large and main fracture along the maximum principle in-situ stress orientation with larger horizontal stress contrast. Therefore, the existence of laminae can enhance the potential of fracture complexity near wellbore but the selection of suitable perforation scenarios in one defining plane can increase the possibility of form a main fracture. The simulation results from this study offer some important insights to hydraulic fracturing design with multiple perforations on interbedded continental shales stimulation.

In-situ stress analysis in the Chang 7 reservoir of northern Shannxi region

The Shaanbei Chang 7 shale oil reservoir in the Ordos Basin develops vertically with multiple lithologic superimpositions. The interlayer stress of sand-mud-shale thin interbeds is different, and the stress within the small layer is variable, resulting in high hydraulic pressure fractures and short extension distances. The effective retrofit volume did not meet expectations. Based on the in-situ stress of key layers tested by the Kaiser in-situ stress test, the in-situ stress distribution law of vertical multi-interbedded layers with different lithologies was obtained by finely interpreting the single-well in-situ stress logging results, combined with the geological, structural and sedimentary characteristics of the block, established a three-dimensional in-situ stress regional model of complex lithologic reservoirs based on fine geological bodies, simulated the regional in-situ stress distribution law of sand-mud-shale multi-thin interbedded lithology, and mastered the geological The spatial lateral and vertical differences of the stress field. The calculation results show that the overall three-dimensional stress of the block is σV>σH>σh, the maximum principal stress range of the longitudinal upper interlayer is 35∼58 MPa, the minimum principal stress range is 28∼55 MPa, and the horizontal stress difference range is 6∼8 MPa, the stress value of sandstone in the lateral upper layer is greater than that of shale and that of mudstone, and the difference of horizontal stress in the vertical direction increases with the increase of depth. By analyzing the in-situ stress distribution of different interlayer depths and bedding lithologies, it provides parameter guidance for the fracturing design of complex lithologic reservoirs in the Chang 7 Member in northern Shaanxi, Ordos Basin.

Practice and development suggestions of hydraulic fracturing technology in the Gulong shale oil reservoirs of Songliao Basin, NE China

This paper reviews the multiple rounds of upgrades of the hydraulic fracturing technology used in the Gulong shale oil reservoirs and gives suggestions about stimulation technology development in relation to the production performance of Gulong shale oil wells. Under the control of high-density bedding fractures, fracturing in the Gulong shale results in a complex fracture morphology, yet with highly suppressed fracture height and length. Hydraulic fracturing fails to generate artificial fractures with sufficient lengths and heights, which is a main restraint on the effective stimulation in the Gulong shale oil reservoirs. In this regard, the fracturing design shall follow the strategy of “controlling near-wellbore complex fractures and maximizing the extension of main fractures”. Increasing the proportions of guar gum fracturing fluids, reducing perforation clusters within one fracturing stage, raising pump rates and appropriately exploiting stress interference are conducive to fracture propagation and lead to a considerably expanded stimulated reservoir volume (SRV). The upgraded main hydraulic fracturing technology is much more applicable to the Gulong shale oil reservoirs. It accelerates the oil production with a low flowback rate and lifts oil cut during the initial production of well groups, which both help to improve well production. It is suggested to optimize the hydraulic fracturing technology in six aspects, namely, suppressing propagation of near-wellbore microfractures, improving the pumping scheme of CO2, managing the perforating density, enhancing multi-proppant combination, reviewing well pattern/spacing, and discreetly applying fiber-assisted injection, so as to improve the SRV, the distal fracture complexity and the long-term fracture conductivity.

Study Investigates Ineffectiveness of Acid Fracturing for Tight Reservoir Rock

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209264, “Ineffectiveness of Acid Fracturing for Stimulating a Tight Fractured Reservoir Rock: A Case Study,” by Huda R. Al-Enezi, Kuwait Oil Company, and Iraj Ershaghi, SPE, University of Southern California. The paper has not been peer reviewed. _ The complete paper describes the analysis of actual performance data for acid fracturing in a tight carbonate formation and the ineffectiveness of the process as measured by the performance responses of the producing wells. An included case study relates to a tight formation that is considered a reservoir rather than a source rock. The formation permeability is in the range of 0.1–5 md. Development has been through numerous horizontal wells with limited multistage acid stimulation. Analysis of performance data for more than 30 wells indicates no fracture flow and very limited stimulated production. Background A category of tight conventional reservoir rocks exists that has not been subjected to horizontal drilling and multistage fracturing. The objective of the authors’ study is to analyze the ineffectiveness of treatment response under acid fracturing and explore the potential of implementing multistage fracturing for a tight reservoir rock using experience gained from unconventional resources. The subject reservoir is a tight carbonate of the Middle Cretaceous age with porosity ranges between 15 and 19% and an average thickness of approximately 90 ft. Oil viscosity ranges between 2.06 and 2.54 cp and average oil gravity is 25° API. The reservoir is a depletion-drive type where the main natural energy is provided by gas in solution. Among the initial wells, only six were successful. The field is very complex, based on stratigraphic and structural characteristics. The first horizontal well was drilled during 2015–16 and was subjected to seven-stage acid fracturing. This resulted in a substantial increase of well cumulative production compared with that of vertical wells. The development plan of this field was implemented with horizontal wells with laterals extending approximately 3,000 ft. Each well was subjected to multistage acid fracturing. Examination of performance data indicated that producing wells suffered from rapid pressure depletion after a production period of 3–6 months. Wells cease natural flow and cannot sustain production even after what is considered acid fracturing without the help of artificial lift. Conventional production plots show that typical performance begins with a high initial rate for a short duration followed by a sharp decline before a stabilization period. To improve and recommend a proper hydraulic fracture design, the authors studied the effectiveness of current stimulation to develop alternative improvement procedures. Methodology The effectiveness of acid stimulation was analyzed and evaluated by using historical production for 4 years. To study the initial rates seen on these horizontal wells, a productivity-prediction tool was used to inversely compute the effective formation-permeability responsible or the observed initial production on these wells. Production data were used to inversely calculate the geometrical averaged permeability from initial field-production data assuming that the initial conditions followed a steady-state regime.

Investigation on the anisotropy of mechanical properties and brittleness characteristics of deep laminated sandstones

Rock brittleness is a crucial mechanical property and essential for fracability evaluation and fracturing scheme design in unconventional reservoirs. However, the influence of inherent anisotropy on deep laminated sandstone’s mechanical properties and brittleness characteristics is rarely investigated. The energy transformation and damage evolution reflected by complete stress–strain curves are analyzed during the entire process of rock rupture under compressions. A new brittleness index is established based on energy evolution during sandstone failure. Its advantages involve comprehensively considering the energy transformation characteristics at both pre-peak and post-peak stages and the capability to characterize the effect of confining pressure and bedding plane (BP) geometry on sandstone brittleness. The triaxial compression tests on sandstones are conducted to validate the reliability and accuracy of the new brittleness index. Numerical simulations are then performed to further investigate the manner in which BP angle, BP density, and confining pressure control the brittleness anisotropy of deep laminated sandstones based on the finite element method. Then the acoustic emission (AE) characteristics of anisotropic sandstone and correlations between AE mode and brittleness index are discussed. The results indicated that the anisotropy of mechanical properties and brittleness of deep laminated sandstones were significantly affected by BP angle, BP density, and confining pressure. With the increase of BP angle, the brittleness index of deep laminated sandstone decreases first and then increases, showing a U-shape variation law, whose maximum and minimum values are obtained at φ = 0° and φ = 45°, respectively. The AE characteristics were closely related to rock brittleness, which was jointly controlled by BP geometry and confining pressure. The results provide a basis for the brittleness and fracability evaluation and optimum hydraulic fracturing design in deep laminated sandstones.

Numerical study of hydraulic fracturing in the sectorial well-factory considering well interference and stress shadowing

In the Changqing Oilfield in northwest China, when traditional petroleum exploitation encounters forestry reserves or water source protection areas, sectorial well-factory design is proposed. The most distinct feature of a sectorial well-factory is the deviation of the well from the minimum horizontal principal stress, resulting in hydraulic fracture deflection after the initiation, along with possible well interference (i.e., fracture hit) and fracture coalescence in the oblique wells. Four indexes describing well deflection are then proposed according to fracture morphology. Several fracturing designs, including stage arrangement, fracturing sequences, and fracturing techniques are applied to study the feasibility of the sectorial well-factory design. The results show that the “gradual” or “sparse” stage arrangement, large injection rate, and simultaneous multifracture treatment can help to optimize the fracture morphology and stimulation design. However, the subsequent stress shadowing effect usually adversely affects the fracturing of adjacent wells. With a small initial horizontal stress difference, large injection rate and staggered stage arrangement can achieve ideal stimulation performance. Our results can provide a guidance for optimizing stimulation design in unconventional well-factory while taking into account environmental protection.

Enhanced delivery of amendments in contaminated low-permeability soils by hydraulic fracturing

In-situ remediation of contaminated low-permeability sites remains to be a critical challenge due to severe mass transfer limitations. This work developed an analytical model for enhanced in-situ remediation by hydraulic fracturing in low permeability sites, considering the mechanisms of convection, diffusion, adsorption, and degradation of amendments. In this model, amendment-filled fractures were conceptualized as mass release sources, with the release process controlled by a dissolution-diffusion equation. Combining the Laplace and Fourier-cosine transformation techniques, the semi-analytic solutions in the two-dimensional spatial domain were obtained and then validated by COMSOL Multiphysics 6.0. Based on this model, the influence range, effective longevity, degradability, amendment reserves, and fracture spacing design of reactive fractures were investigated. Results show that (1) three reaction zones with different degradability will potentially form around the reactive fractures; (2) a larger reservoir of amendments effectively increases the influence range and effective longevity of reactive fractures; (3) the synergy of multiple fracture systems outweigh the sum of individual fracture properties, but the reasonable spacing design is decisive; (4) ignoring adsorption in low-permeability site remediation may overestimate the influence range of reactive fractures, leading to remediation failure. This work comprehensively analyzed the properties of reactive fractures, providing practitioners with a reference for the enhanced remediation of low-permeability contaminated sites.

An Improved Acid Fracturing Design through RoqSCAN Technology: A Case Study from Daniudi Gas Field in Ordos Basin, China

The concept of geological engineering-integrated fracturing is widely applied in the conventional and unconventional reservoirs, aiming to achieve efficient and economic development. There is no doubt that fine reservoir evaluation is the basis and core of geological engineering-integrated fracturing. Therefore, in this paper, we performed a series of investigations on the basis of formation fine evaluation by using RoqScan technology. Firstly, the physical parameters of the target well located in Daniudi Gas Field were evaluated by a laboratory test and logging interpretation. Next, the composition and function of the RoqSCAN tool were introduce in detail. Furthermore, the elements, minerals, and rock mechanical parameters of the target well were evaluated by the RoqSCAN tool. Finally, the fine reservoir model was established on the basis of fine formation evaluation. Moreover, we conducted a series of research on porosity and principal stress of the target formation to compare the difference between the fine model and the conventional model. Based on the fine reservoir model, the acid-fracturing design and numerical simulation were further investigated. The results of experiments and numerical simulation mainly achieved the following findings: 1. The porosity and permeability of the target formation indicated that it was a tight, low-permeability reservoir; 2. According to the comparison of the distribution for different parameters in the target well, the modeling with fine reservoir evaluation had higher accuracy than the traditional modeling; 3. Based on the fine evaluation results, acid fracturing is recommended as a stimulation method to enhance the productivity of the target formation. This study provides an essential method for the integrated fracturing design of geological engineering.

Experimental evaluation and optimization of improved conductivity of gelling acid etched fractures in deep, low-permeability reservoirs

Stimulation technology is the key to efficient development of deep low-permeability carbonate reservoirs. For such reservoirs, where the porosity and permeability are low, or where the reservoir is far from the borehole. An efficient production increase can only be achieved by using a deep percolation gelling acid fracture technique, maximizing the length of the acid etched fracture to expand the percolation area, and improving the conductivity of the acid etched fracture. A quantitative experimental study of the conductivity of acid etch fracture based on an acid rock tiling instrument, a 3D laser scanner, and an acid etch fracture conductivity evaluation device identified three typical supporting morphologies of gelling acid etch fracture walls: spot, line, and sheet. A systematic quantitative description and evaluation of the etch morphology of rocks etched by acid has been performed. The fracture morphology of acid etchings has been quantitatively evaluated under various experimental conditions such as fracture width, temperature, acid fluid consumption, displacement, and different acid fracture processes and their laws affecting fracture conductivity. The conductivity of acid corrosion fracture increases with the decrease of fracture width, and decreases with the increase of closure stress. The greater the amount of acid used, the higher the fracture conductivity; With the increase of flow Reynolds number, the conductivity of acid corrosion fracture shows a trend of increasing first and then decreasing. The fracture conductivity was compared and analyzed for different property placement conditions under the acid sand carrying technique, and the main effect of the acid etch fracture conductivity was identified. Optimization of high conductivity and deep penetration gelling acid fracturing techniques can help guide the design of acid fracturing and improve stimulation and recovery effects, thus achieving the goal of efficient development of deep, low permeability carbonate reservoirs to increase reserves and production.

Numerical investigation on hydraulic fracture propagation and multi-perforation fracturing for horizontal well in Longmaxi shale reservoir

Hydraulic fracturing is one of the key technologies of shale gas extraction. Deeply comprehending the distribution characteristics of hydraulic fracture networks in shale reservoirs is significant for the shale gas fracturing design and production estimation. The efficient description of fluid–solid coupling is essential for modeling the hydraulic fracturing process. In this paper, based on the mechanical parameters from the laboratory test results, the fluid–solid coupling model in PFC2D is improved and employed to establish a DEM model for the hydraulic fracturing of shale reservoirs. The key factors affecting the hydraulic fracture propagation characteristic are investigated, furthermore, based on the geological parameters of Changning shale gas production areas, a multi-perforation fracturing numerical model of the shale reservoir horizontal well is established, and the distribution characteristics of the hydraulic fracture network in staged fracturing are analyzed and revealed. The results indicate that the main factor affecting the formation of a fracture network in the vertical section of the shale reservoirs is the coalescence of interbedding fractures. A large number of secondary interbedding fractures generated by the primary through-bedding fracture can form a complex fracture network, which is exactly the fracture morphology required for hydraulic fracturing in shale gas exploitation. According to the results of hydraulic fracture distribution characteristics under different perforation spacings, the optimal perforation spacing requires that the fractures extend to the maximum range under the premise of hydraulic fracture coalescence can form an effective network and guarantee low economic cost and construction technical difficulties.

Weighting Failure Mechanisms of Pre-Driven Recovery Rooms and Evaluation of Hydraulic Fracturing Applications: A Case Study

Roof weighting failures of pre-driven recovery rooms may cause huge economic losses and even casualties. The excessive dynamic load from the sliding of the broken main roof rock block causes the recovery room roof and inner supports to lose their support capacity during the last weighting. Discrete element software UDEC was used to investigate the surrounding rock deformation of the pre-driven recovery room with the main roof break at different positions. The results show that when the recovery room’s length from the main roof rock layer’s fracture region is short, the immediate roof is subjected to high deviatoric stress and the occurrence of horizontal stress concentration due to the deflection of the fractured rocks, and eventually the roof supports fail owing to the development of macroscopic shear crack zones. In this research, the hydraulic fracturing technique was applied to pretreat the main roof (fine-grained sandstone) of the 31108 panel at Huoluowan Coal Mine. Field observations suggest that the strength and duration of the periodic weighting after hydraulic fracturing treatment are both significantly reduced, effectively maintaining the bearing layer performance of the roof of the recovery room and coal pillar walls. The proposed fracturing design offers an effective method of ground control to the coal mines facing roof weighting failures of recovery rooms.

Integrated simulation of three-dimensional hydraulic fracture propagation and Lagrangian proppant transport in multilayered reservoirs

The numerical simulation of hydraulic fractures is a critical yet challenging computational problem due to its multi-physics nature. This paper develops an integrated hydraulic fracturing simulator by coupling a planar three-dimensional (PL3D) fracture propagation model with an efficient Eulerian–Lagrangian (E–L) proppant transport model. The fracture propagation model uses the finite volume method (FVM) and displacement discontinuity method (DDM) to solve the fluid flow and rock deformation, respectively. For proppant transport, we develop a pseudo-3D multiphase particle-in-cell (P3D MP-PIC) model, in which the fluid flow is addressed by FVM as a continuum, but the particles are tracked in a Lagrangian fashion as discrete phases. In contrast to Eulerian–Eulerian (E–E) proppant transport models, the P3D MP-PIC can efficiently deal with multi-modal particle simulations (i.e., particles of different sizes or materials) and avoid the problem of numerical diffusion. The fracture propagation and proppant transport models are validated by analytical solutions and laboratory experiments. We adopt a one-way coupling strategy to consider the effect of complex fracture propagation and fluid leak-off on slurry transport, in which the dynamic fracture geometry and fluid leak-off is first computed via the fracture propagation model, followed by the fully coupled fluid–particle simulation using the P3D MP-PIC. The integrated model can simulate the fracturing treatments in multilayered reservoirs with varying confining stresses at an industrial field scale. The simulation results can improve the prediction of effective/propped fracture geometries and better the fracturing designs.

Optimization of Hydraulic Fracture Treatment Parameters for Normally Pressured Longmaxi and Wufeng Shales in the Southeastern Sichuan Basin in China

Lower Silurian Longmaxi and Upper Ordovician Wufeng shales are gas-producing formations. These formations have ultralow porosity and permeability in the southeastern Sichuan Basin and have normal formation pressures with pressure coefficients of less than 1.2. Hydraulic fracturing has been proven as the best development strategy to produce gas. But choosing hydraulic fracture treatment parameters becomes challenging due to strong reservoir heterogeneity, significant horizontal stress contrast and high in situ stress in this region. We employed the pseudo-three-dimensional (P3D) model to study fracturing fluid types, injection rates, and proppant sizes to optimize the fracturing design of these shale formations. First, this model was solved in the simulator by the finite element method (FEM) to obtain the fracture height, length, and width. Then the results were validated by 3D Tip dominated model, and the perkins-kern-nordgren (PKN) and khristianovic-geertsma-deklerk (KGD) analytical models, which are popular and most used in designing hydraulic fractures. It was found that as the volumetric injection rate and gel loading in the fracturing fluid rise, so do the generated fracture length and width. Furthermore, the formations’ stress contrast affected the shape of the fracture, the interval with lower stress had a wider fracture compared to the interval with higher stress. Also, the higher stress in the layers above and below the shale formations contained the fracture height, which favored the growth of fracture in the shale formations. Lastly, it is suggested that a fluid with gel loading of 60 ppgt, proppant with 12/20 mesh size and an injection rate of 6.36 m3/min be used in these shale formations with normal reservoir pressure. These parameters’ combinations created the most extended propped fracture length of 264.8 m, and the average width was 1.06 cm.

Influence of gravel content and cement on conglomerate fracture

Tight reservoirs are typically developed by horizontal wells and multi-stage hydraulic fracturing. The conglomerate reservoir is one type of tight reservoirs, which is different from homogeneous rock, such as tight sandstone. This is because that the existence of gravels makes conglomerate have strong heterogeneity. Thus, it is difficult to grasp the fracture mechanism and the law of fracture propagation of conglomerate, which limits the efficient development of the conglomerate reservoir. In this paper, the fracture characteristics and factors influencing the fracturing of Mahu conglomerate were studied by uniaxial compression, acoustic emission monitoring and X-ray computed tomography (CT) scanning experiments. The results show that the fracture characteristics of conglomerates are influenced by the gravel content and cement. The conglomerate in the study area is mainly divided into carbonate cemented conglomerate and clay cemented conglomerate. The fracture complexity of carbonate cemented conglomerate first increases and then decreases with increasing gravel content. However, for clay cemented conglomerates, the fracture complexity increases over the gravel content. The crack development stress is a significant parameter in the crack assessment of conglomerates. This study is useful to understand the influence of meso-fabric characteristics of conglomerates on their fracturing and crack evolution and guides the design of hydraulic fracturing.

Uniquely determine fracture dimension and formation permeability from diagnostic fracture injection test

Estimating formation permeability is crucial for production estimation, hydraulic fracturing design optimization and rate transient analysis. Laboratory experiments can be used to measure the permeability of rock samples, but the results may not be representative at a field scale because of reservoir heterogeneity and pre-existing natural fracture systems. Diagnostic Fracture Injection Tests (DFIT) have now become standard practice to estimate formation pore pressure and formation permeability. However, in low permeability reservoirs, after-closure radial flow is often absent, which can cast significant uncertainties in interpreting DFIT data. Without knowing the fracture dimension prior, open fracture stiffness/compliance can't be determined, which is required for formation permeability estimation. Previous work has to assume a fracture radius or fracture height in order to estimate formation permeability, thus dent the confidence in the interpretation results. In the study, we present a new approach to determine fracture dimension, leak-off coefficient and formation permeability uniquely based on material balance and basic fracture mechanics, using data from shut-in to after-closure linear flow. Field examples are also presented to demonstrate the simplicity and effectiveness of this new approach.