Fracturing In Unconventional Reservoirs Research Articles

Numerical simulation study on evolution law of three-dimensional fracture network in unconventional reservoirs

It has become a consensus that large-scale hydraulic fracturing is adopted to achieve the stimulation of unconventional oil and gas reservoir. The complex fracture network formed by fracturing is closely related to the effect of reservoir stimulation, which has extremely complicated evolution process. Therefore, it is necessary to study the evolution law of fracture network in large-scale hydraulic fracturing of unconventional reservoirs. In this article, the geological engineering parameters of horizontal well H in shale gas reservoir in southern Sichuan are taken as an example, a three-dimensional fracture network expansion model is established based on the boundary element method and finite volume method, and the simulation of the complex fracture network in a whole well section is carried out to analyze the evolution law of reservoir fracture network under different geological and engineering parameters. The results show that the horizontal stress field distribution has a significant effect on fracture geometric form. Hydraulic fractures in reservoirs with larger horizontal stress difference have stronger directivity, while the horizontal wellbore tends to obtain better reservoir stimulation results when it is parallel to the minimum horizontal principal stress setting. The conjugated natural fracture developed in the reservoir inhibits the hydraulic expansion fractures in both directions. Although it increases the complexity of the fractures, it is not necessarily conducive to improving the reservoir stimulation effectiveness. The lower the strength of natural fracture is, the more complex the fracture geometric form becomes, and the smaller the stimulated reservoir volume is. Correspondingly, the higher the strength of natural fracture is, the simpler the fracture geometric form becomes, and the larger the stimulated reservoir volume is. Suitable fracturing construction displacement can not only contribute to form a more complex fracture distribution, but also help to obtain a larger stimulated reservoir volume. The optimal construction displacement ranges from 10 to 14 m3/min. Low viscosity fracturing fluids are suitable for the formation of long-narrow fractures and able to connect with the remote reservoir and form complex fracture networks. Lower viscosity fluids can be used to achieve better reservoir stimulation effectiveness when sand-carrying capacity is met.

Identifying nonuniform distributions of rock properties and hydraulic fracture trajectories through deep learning in unconventional reservoirs

Predicting the trajectories of hydraulic fractures in unconventional reservoirs poses a significant challenge due to the heterogeneous nature of the rock matrix. Obtaining an accurate distribution of rock properties from limited measurements of rock samples near wellbores is difficult. In this study, we propose a deep learning framework that utilizes observations of hydraulic fracture patterns to identify nonuniform distributions of rock properties. Our approach utilizes the deep operator network (DeepONet) to map elastic properties to fracture geometries, and establishes an inverse problem to map fracture geometries back to elastic properties. Our results demonstrate a high level of accuracy in predicting nonplanar paths of single and multiple hydraulic fractures in heterogeneous formations. The well-trained model can rapidly evaluate numerous fracture patterns within seconds, surpassing the efficiency of finite element-based methods. Furthermore, fracture trajectories enable the identification of nonuniform distributions of rock properties. The maximum point-wise error of predicted Young's modulus compared to the ground truth is less than 20 %, with accurate identification of distribution patterns. Only a few regions exhibit relatively large errors, approaching 20 %. The presented approach provides valuable insights for the identification of reservoir properties in engineering applications.

Study on the pump schedule impact in hydraulic fracturing of unconventional reservoirs on proppant transport law

In unconventional reservoir hydraulic fracturing, using a pump schedule with proppant concentration constant (PCC) instead of the proppant concentration stepwise increasing (PCSI) is considered an innovative approach to reduce operation costs and risks. However, the large-scale application of PCC lacks sufficient theoretical support. This study investigates the impact of two pump schedules on proppant transport behavior through visualized proppant transport experiments and the model that couples fracture propagation with proppant transport. The experiments demonstrate that PCC facilitates proppant transport and reduces flow fluctuations in complex fractures, while PCSI enhances the filling of near-well fractures. The proppant concentration (the ratio of proppant volume to fracturing fluid volume) reaches 20 % or when a combination of 40/70-mesh and 20/40-mesh quartz sands is used for injection, the pump schedule influence becomes negligible. An increase in fracture complexity, proppant size, and proppant concentration all lead to a reduced influence of the pump schedule on the dune shape. Numerical simulation reveal that the fracture area and average fracture conductivity is similar for different pump schedules, but PCC yields a slightly larger propped fracture area (ranging from 1 % to 4 %) and results in a more uniform conductivity. PCC could achieve similar fracture filling when the proppant concentration is more than 15 % or there is no significant demand for near-well conductivity. Overall, both two pump schedules have a relatively insignificant impact on the transport process of proppants and the final sand dune shape. By comparing pressure curves during hydraulic fracturing, it was evident that PCC resulted in fewer fluctuations. Analyzing production data from 93 wells with PCSI and 59 wells with PCC, it was observed that PCC enhances production and reduces proppant flowback post-fracturing. This research provides a theoretical foundation for the application of PCC pump schedule in hydraulic fracturing.

Intricate unconventional fracture networks provide fluid diffusion pathways to reactivate pre-existing faults in unconventional reservoirs

Hydraulic fracturing-induced earthquakes are typically triggered via a hydraulic connection between stimulated wells and pre-existing faults. Despite this, relatively little modeling has focused on fluid migration along fractures and faults in shale reservoirs. The experimental measurements and logging data were collected first to create a high-resolution 3D petrophysical and geomechanical model of a Duvernay reservoir. To simulate the real-time growth of complex hydraulic-natural fracture networks, an unconventional fracture model (UFM) is constructed that considers fluid flow, interactions between hydraulic and natural fractures, reservoir petrophysics, and geomechanics. Coupled poroelastic modeling quantifies the well-fault hydraulic connection in terms of spatiotemporal stress and pressure changes, assessing the fault stability during hydraulic fracturing. The UFM model is applied to three field case studies, and the findings are evaluated against those of induced earthquake clusters. The non-uniform intricate fracture networks are discovered to provide fluid diffusion pathways for hydraulic fracturing-induced earthquakes. To reduce possible seismic risks, fault stability must be assessed prior to hydraulic fracturing in unconventional reservoirs.

Experimental study of the rheology of cellulose nanocrystals-enhanced C22-tailed zwitterionic wormlike micelles

Nano-materials enhanced zwitterionic surfactants fracturing fluids with greatly improved rheological properties are extensively employed in foam fracturing to stimulate unconventional gas/oil reservoirs. In this study, a novel worm-like micelles (WLMs) system composed of erucyl dimethyl amidopropyl betaine (EDAB, C22), alkyl polyglucoside (APG) and cellulose nanocrystals (CNC) is proposed. A series of rheology and dynamic light scattering tests were conducted to determine the optimal concentration, and the influence of various factors, including temperature, pH, and inorganic salts, on the viscoelasticity and structural morphology of WLMs systems were also analyzed. The results show that a 0.3 wt% EDAB/APG/CNC system exhibits optimal viscosity and viscoelastic fluid behavior. The increase of temperature accelerates the breaking rate of WLMs, resulting in a decrease in viscosity, but its shear viscosity can still maintain 87.42 mPa·s at 90 °C and is an order of magnitude greater than that of other systems. The change of pH can disturb the equilibrium state under the electrostatic interaction of EDAB and CNC, and the negative ions in EDAB and CNC molecules are easily protonated in acid medium, resulting in a lower viscosity than alkaline medium and much lower than neutral medium. The viscosity of the EDAB/APG/CNC system increases first and then decreases with the increase of inorganic salt concentration, and reaches a peak at 2.5 wt%. Proppant critical settling velocity tests show that the CNC improves the proppant-carrying capacity of the EDAB/APG/CNC system with favourable critical settling velocity. The CNC enhanced C22-tailed EDAB system provides a basis for optimizing foaming fracturing in unconventional reservoirs.

Influence of natural fractures on hydraulic fracture propagation behaviour

The propagation behaviour of hydraulic fractures is affected by natural fractures in unconventional reservoirs and determines the effect of reservoir reconstruction to a certain extent. Using the splitting mode of mesh nodes and zero-thickness cohesive elements, we established a hydraulic fracture random propagation method. The KGD model and Blanton’s experiment were used to verify the reliability of this method, and the cohesive element parameters of the natural shale core were obtained using three-point bending and digital image correlation methods. Finally, the model was used to simulate the propagation behaviour of hydraulic fractures in natural fracture–developed formations. The results show that even if the hydraulic fracture does not come into contact with the natural fracture, the natural fracture will open, accompanied by the shear slip of the natural fracture surface. The propagation of hydraulic fractures generates a stress shadow effect, causing an increase in the local formation pore pressure and minimum horizontal stress. When the horizontal stress difference was more than 2 MPa, the hydraulic fracture expanded along the direction of the maximum horizontal stress, and the fracture morphology was simple. A formation with a high elastic modulus and high injection rate can contribute to increasing the hydraulic fracture complexity. Hydraulic fracture propagation can be captured using natural fractures. Simultaneously, owing to the stress shadow effect, the stress state at the tip of the hydraulic fractures may change from tensile stress to compressive stress, eventually leading to the stop propagation of hydraulic fractures and the formation of asymmetric hydraulic fractures. The research results are helpful for improving the understanding of the geometric shape of the propagation behaviour of hydraulic fractures in natural fractures that develop formations.

Numerical Simulation of Hydraulic Fracturing in Unconventional Reservoirs

Hydraulic fracturing is a well-stimulation technique that uses a large amount of water mixed with proppants at high pressure to enhance and boost oil and gas production. Proppants, in conjunction with water, facilitate the cracking process, acting as a catalyst for the oil and gas to pass through the formation and into the producing well. The primary goal of this research is to look into the parameters that influence hydraulic fracturing quality. Moreover, such parameters that improve the productivity of oil in unconventional reservoirs are evaluated. The field properties of the Eagle Ford Shale were used to create a geological model on the Navigator software for this purpose. This software is used to simulate three different horizontal and vertical wells to observe the production of oil and gas. Then, hydraulic fracturing is performed on the same wells with different scenarios using three parameters, namely the length of fracture, the width of fracture, and the height of fracture. These parameters are selected because the usage of proppants can be dependent on them. The findings are quite convincing and demonstrate the importance of hydraulic fracturing in an unconventional reservoir. Besides, it is observed that the greater the width, length, or height of the fracture, the greater the productivity of oil and gas in an unconventional reservoir due to the increment of the seepage area of the hydrocarbons. Thus, hydraulic fracturing can make any potential unconventional reservoir economically viable.

Nanomaterials and Technology Applications for Hydraulic Fracturing of Unconventional Oil and Gas Reservoirs: A State-of-the-Art Review of Recent Advances and Perspectives.

The application of hydraulic fracturing stimulation technology to improve the productivity of unconventional oil and gas reservoirs is a well-established practice. With the increasing exploration and development of unconventional oil and gas resources, the associated geological conditions and physical properties are gradually becoming more and more complex. Therefore, it is necessary to develop technologies that can improve the development benefits to meet these challenges. In recent years, improving the effect of hydraulic fracturing stimulation in unconventional oil and gas reservoirs through the use of nanomaterials and technologies has attracted increasing attention. In this paper, we review the current status and research progress of the application of nanomaterials and technologies in various aspects of hydraulic fracturing in unconventional oil and gas reservoirs, expound the mechanism and advantages of these nanomaterials and technologies in detail, and provide future research directions. The reviewed literature indicates that nanomaterials and technologies show exciting potential applications in the hydraulic fracturing of unconventional reservoirs; for example, the sand-carrying and rheological properties of fracturing fluids can be significantly enhanced through the addition of nanomaterials. The use of nanomaterials to modify proppants can improve their compressive strength, thus meeting the needs of different reservoir conditions. The fracturing flowback fluid treatment efficiency and purification effect can be improved through the use of nanophotocatalysis and nanomembrane technologies, while degradable fracturing completion tools developed based on nanomaterials can effectively improve the efficiency of fracturing operations. Nanorobots and magnetic nanoparticles can be used to more efficiently monitor hydraulic fracturing and to accurately map the hydraulic fracture morphology. However, due to the complex preparation process and high cost of nanomaterials, more work is needed to fully investigate the application mechanisms of nanomaterials and technologies, as well as to evaluate the economic feasibility of these exciting technologies. The main research objective of this review is to comprehensively summarize the application and research progress of nanomaterials and technologies in various aspects of hydraulic fracturing in unconventional oil and gas reservoirs, analyze the existing problems and challenges, and propose some targeted forward-looking recommendations, which may be helpful for future research and applications.

Mitigating risks from hydraulic fracturing-induced seismicity in unconventional reservoirs: case study

The recent remarkable increase in induced seismicity in Western Canada has been largely attributed to hydraulic fracturing in unconventional reservoirs. The nucleation of large magnitude events has been demonstrated to be closely linked to site-specific geological and operational factors. A mitigation strategy of fracturing-induced seismicity concerning both factors has not been well investigated. In this paper, a comprehensive investigation of risk mitigations from induced seismicity is conducted based on the formation overpressure, distance to Precambrian basement, proximity to faults, fracturing job size and safe hydraulic fracture-fault distance. It is found that the middle-south region near Crooked Lake is an optimal region for fracturing operations with low formation pressure, a great distance to the basement and relatively fewer pre-existing faults. A field case study suggests that fracturing operations of three new horizontal wells are successful with low magnitude induced events and with high production performance, demonstrating the applicability of a comprehensive approach of seismicity risk mitigations. Such an approach can be applied to other field cases to mitigate the potential fracturing-induced seismicity in unconventional reservoirs.

Research Advance on Prediction and Optimization for Fracture Propagation in Stimulated Unconventional Reservoirs

Abstract Multistage stimulation horizontal wells are prerequisite technologies for efficient development of unconventional reservoir. However, the induced fracture network morphology from hydraulic fracturing is very complex and affected by many factors, such as the in situ stress, rock mechanical properties, and natural fracture distribution. The large numbers of natural fractures and strong reservoir heterogeneity in unconventional reservoirs result in enhanced complexity of induced fractures from hydraulic fracturing. Accurate description of fracture network morphology and the flow capacity in different fractures form an important basis for production forecasting, evaluation (or optimization) of stimulation design, and development plan optimization. This paper focuses on hydraulic fracturing in unconventional reservoirs and discusses the current research advances from four aspects: (1) the prediction of induced fracture propagation, (2) the simulation of fluid flow in complex fracture networks, (3) the inversion of fracture parameter (fracture porosity, fracture permeability, etc.), and (4) the optimization of hydraulic fracturing in unconventional reservoirs. In addition, this paper provides comparative analysis of the characteristics and shortcomings of the current research by outlining the key technical problems in the study of flow characterization, parameter inversion, and optimization methods for stimulation in unconventional reservoirs. This work can provide a certain guiding role for further research.

Experimental Study on the Stability of a Novel Nanocomposite-Enhanced Viscoelastic Surfactant Solution as a Fracturing Fluid under Unconventional Reservoir Stimulation

Fe3O4@ZnO nanocomposites (NCs) were synthesized to improve the stability of the wormlike micelle (WLM) network structure of viscoelastic surfactant (VES) fracturing fluid and were characterized by Fourier transform infrared spectrometry (FT-IR), scanning electron microscopy (SEM), energy dispersive spectrometry (EDS), X-ray diffraction (XRD) and vibrating sample magnetometry (VSM). Then, an NC-enhanced viscoelastic surfactant solution as a fracturing fluid (NC-VES) was prepared, and its properties, including settlement stability, interactions between NCs and WLMs, proppant-transporting performance and gel-breaking properties, were systematically studied. More importantly, the influences of the NC concentration, shear rate, temperature and pH level on the stability of NC-VES were systematically investigated. The experimental results show that the NC-VES with a suitable content of NCs (0.1 wt.%) shows superior stability at 95 °C or at a high shear rate. Meanwhile, the NC-VES has an acceptable wide pH stability range of 6–9. In addition, the NC-VES possesses good sand-carrying performance and gel-breaking properties, while the NCs can be easily separated and recycled by applying a magnetic field. The temperature-resistant, stable and environmentally friendly fracturing fluid opens an opportunity for the future hydraulic fracturing of unconventional reservoirs.

Fully 3D Simulation of Hydraulic Fracture Propagation in Naturally Fractured Reservoirs Using Displacement Discontinuity Method

Summary The shape, size, and orientation of natural fractures significantly impact the geometry of hydraulic fractures in unconventional reservoirs, such as shale gas/oil, tight gas, and enhanced geothermal system. The behaviors after the hydraulic fracture encounters natural fractures have been summarized as crossing, diverting, step over, and stopping based on a great number of numerical and experimental analysis with plain strain assumptions. However, under practical situations, the geometries of natural and hydraulic fractures are much more complex than the vertical and rectangular shape assumed by 2D models. The experimental studies on the role of height and inclination of natural fractures have revealed some other phenomena (e.g., bypassing process that the fluid-driven hydraulic fracture propagates up the back side of the natural fracture), which are unable to be captured in 2D. To better describe the intersection behaviors among different kind of fractures, a fully 3D model based on the displacement discontinuity method (DDM) is developed on top of our previous models, which only considered the propagation of hydraulic fractures. A novel crossing criterion to judge whether the hydraulic fracture will cross the cemented natural fracture in 3D is proposed. The successive node snapping scheme is adopted to construct conforming meshes for the evolving intersected curves between hydraulic and natural fracture surfaces, which only alters the location of a small fraction of nodes without changing the nodal connectivity. With this model, the evolution of fracture geometry after the hydraulic fracture intersects with the natural fractures of different toughness, size, orientation, and number is investigated. Because an extra dimension is considered, the fractures are allowed to propagate in more directions, resulting in a series of complex fracture geometries. The dynamic grid evolution method proposed in this work can promote the development of DDM in modeling fully 3D fracture networks in naturally fractured reservoirs.

Predicting variations of the least principal stress with depth: Application to unconventional oil and gas reservoirs using a log-based viscoelastic stress relaxation model

Knowledge of layer-to-layer variations of the least principal stress, S hmin, with depth is essential for optimization of multi-stage hydraulic fracturing in unconventional reservoirs. Utilizing a geomechanical model based on viscoelastic stress relaxation in relatively clay rich rocks, we present a new method for predicting continuous S hmin variations with depth. The method utilizes geophysical log data and S hmin measurements from routine diagnostic fracture injection tests (DFITs) at several depths for calibration. We consider a case study in the Wolfcamp formation in the Midland Basin, where both geophysical logs and values of S hmin from DFITs are available. We compute a continuous stress profile as a function of the well logs that fits all of the DFITs well. We utilized several machine learning technologies, such as bootstrap aggregation (or bagging), to improve the generalization of the model and demonstrate that the excellent fit between predicted and observed stress values is not the result of over-fitting the calibration points. The model is then validated by accurately predicting hold-out stress measurements from four wells within the study area and, without recalibration, accurately predicting stress as a function of depth in an offset pad about 6 miles away.

An Integrated Approach of Numerical Well Test for Well Intersecting Fractures Based on FMI Image

Abstract Fluid flow is strongly affected by fractures in unconventional reservoirs. It is essential to deeply understand the flow characteristics with fractures for improving the production and efficiency of unconventional reservoir exploitation. The purpose of this work is to develop an accurate numerical model to evaluate the transient-pressure response for well intersecting fractures. The meshes generated from Fullbore Formation Micro-Imager (FMI) images ensure an efficient numerical description of the geometries for fractures and interlayers. The numerical simulation is implemented by an inhouse finite element method-based code and benchmarked with drill stem test (DST) data. The results show that three flow regimes appear in the reservoir with fractures within the test period: wellbore afterflow, pseudolinear flow, and radial flow. In contrast, only the wellbore afterflow and radial flow appear for the wells without fractures. The results also reveal that fractures dominate the flow near the wellbore. Verification and application of the model show the practicability of the integrated approach for investigating the transient-pressure behaviors in the unconventional reservoir.

Supramolecular dynamic binary complexes with pH and salt-responsive properties for use in unconventional reservoirs.

Hydraulic fracturing of unconventional reservoirs has seen a boom in the last century, as a means to fulfill the growing energy demand in the world. The fracturing fluid used in the process plays a substantial role in determining the results. Hence, several research and development efforts have been geared towards developing more sustainable, efficient, and improved fracturing fluids. Herein, we present a dynamic binary complex (DBC) solution, with potential to be useful in the hydraulic fracturing domain. It has a supramolecular structure formed by the self-assembly of low molecular weight viscosifiers (LMWVs) oleic acid and diethylenetriamine into an elongated entangled network under alkaline conditions. With less than 2 wt% constituents dispersed in aqueous solution, a viscous gel that exhibits high viscosities even under shear was formed. Key features include responsiveness to pH and salinity, and a zero-shear viscosity that could be tuned by a factor of ~280 by changing the pH. Furthermore, its viscous properties were more pronounced in the presence of salt. Sand settling tests revealed its potential to hold up sand particles for extended periods of time. In conclusion, this DBC solution system has potential to be utilized as a smart salt-responsive, pH-switchable hydraulic fracturing fluid.

Technology Focus: EOR Operations (November 2021)

As the discovery rate of new hydrocarbon resources decreases, the need for more-efficient enhanced-oil-recovery (EOR) processes increases. Unlike in the past, however, when the efficiency was defined in terms of maximizing the recovery factor (RF), the new interpretation of efficiency is based on optimizing the balance between RF and the reduction of carbon footprint. This is done through an integrated approach in which both surface and subsurface elements of the oil-production systems are used to determine energy efficiency and carbon footprint of a unit volume of oil produced by EOR methods. When choosing traditional EOR methods, new innovations may be needed to arrive at new injectant composition to reduce emissions or make the process more efficient. Adding chemicals to the injectant gas to improve the mobility ratio and increase the sweep efficiency is desirable. One example is the use of hydrogels. These are hydrophilic structures that swell when hydrated. Hydrogels are of interest in EOR because of their ability to respond to stimuli such as pH, temperature, light, and ionic strength. EOR methods that involve use of fresh water are also switching to alternative methods that reduce or remove its usage as part of water sustainability. The produced water could be treated properly to make it suitable for injection. Alternatively, polymers that are effective under high salinity or temperature could be used to deal with injecting saline water. For unconventional reservoirs, waterless fracturing techniques are progressing. Paper SPE 201609 discusses the application of a reversible hydrogel that can be added to the injected carbon dioxide (CO2) stream in order to make it a more-efficient injectant for EOR and, hence, create more opportunity for CO2 storage. Paper SPE 202809 deals with utility of new polymers that are suitable for injection into carbonate reservoirs under high-temperature and ultrahigh-salinity conditions. Finally, paper OTC 30437 discusses ways of mitigating safety risks associated with CO2 waterless fracturing in unconventional reservoirs as part of water sustainability as well as prevention of environmental pollution. Recommended additional reading at OnePetro: www.onepetro.org. SPE 200357 - Fundamental Investigation of Auto-Emulsification of Water in Crude Oil: An Interfacial Phenomenon and Its Pertinence for Low-Salinity EOR by Duboué Jennifer, TotalEnergies, et al. SPE 205118 - Experimental Design and Evaluation of Surfactant Polymer for a Heavy-Oil Field in South of Sultanate of Oman by Ali Reham Al-Jabri, Petroleum Development of Oman, et al. SPE 200256 - Chemical Enhanced Oil Recovery and the Dilemma of More and Cleaner Energy by Rouhi Farajzadeh, Delft University of Technology, et al.

Role of Fluid Diffusivity in the Spatiotemporal Migration of Induced Earthquakes during Hydraulic Fracturing in Unconventional Reservoirs

Role of Fluid Diffusivity in the Spatiotemporal Migration of Induced Earthquakes during Hydraulic Fracturing in Unconventional Reservoirs

Description of Fracture Network of Hydraulic Fracturing Vertical Wells in Unconventional Reservoirs

Based on the distribution of complex fractures after volume fracturing in unconventional reservoirs, the fractal theory is used to describe the distribution of volume fracture network in unconventional reservoirs. The method for calculating the fractal parameters of the fracture network is given. The box dimension method is used to analyze a fracturing core, and the fractal dimension is calculated. The fractal index of fracture network in fracturing vertical wells are also firstly calculated by introducing an analysis method. On this basis, the conventional dual-media model and the fractal dual-media model are compared, and the distribution of reservoir permeability and porosity are analyzed. The results show that the fractal porosity/permeability can be used to describe the reservoir physical properties more accurately. At the same time, the flow rate calculating by conventional dual-media model and the fractal dual-media model were calculated and compared. The comparative analysis found that the flow rate calculated by the conventional dual-media model was relatively high in the early stage, but the flow rate was not much different in the later stage. The research results provide certain guiding significance for the description of fracture network of volume fracturing vertical well in unconventional reservoirs.

Transient temperature‐pressure field model of supercritical CO2 fracturing wellbore with tubing and annulus co‐injection

AbstractThe physical parameters of supercritical carbon dioxide (SC‐CO2) fracturing fluid are sensitive to temperature and pressure. Accurate prediction of wellbore temperature and pressure during injection is critical for the fracturing efficiency. In this paper, a transient pressure‐field model of SC‐CO2 fracturing wellbore with tubing and annulus co‐injection was established, which was adjusted to consider the Joule–Thomson effect, axial heat conduction, expansion/compression heat, and friction heat. The model predicted the variation patterns of wellbore temperature and pressure, comparing them with those under tubing injection conditions. Effects of tubing‐annulus injection ratios and endothermic mode on bottom‐hole temperature (BHT) and wellhead pressure (WHP) were analyzed in detail. Compared with pure tubing injection, co‐injection provided higher BHT and lower WHP. At constant BHP, WHP dropped with time in the processes of tubing injection or co‐injection, while the former provided a larger WHP drop. With an increase in tubing injection ratio, the difference between tubing and annulus BHT values slightly grew. When the tubing and annulus injection displacements were allocated according to their cross‐sectional area ratio, their WHP was minimal. If CO2 was assumed to absorb all the friction heat, overestimation of BHT and WHP would be observed, which was more pronounced at larger injection displacements. This study's findings are considered instrumental in the design optimization and field application of SC‐CO2 fracturing in unconventional reservoirs. © 2021 Society of Chemical Industry and John Wiley & Sons, Ltd.

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

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