Hydraulic Fracturing Treatment Research Articles

Numerical investigation on hydraulic fracture propagation mechanism in fault-karst carbonate reservoir

The fault-karst reservoir takes the fault-controlled fracture-cavity system as storage space, which is surrounded by a large number of high permeability zones. The distribution of reservoir seepage field has an important influence on fracture propagation behavior during the hydraulic fracturing process. Based on statistical damage mechanics theory and finite element method, this paper established a seepage-stress coupling numerical model of fracture propagation under the complex medium condition of matrix-cave-natural fracture in fault-karst carbonate reservoir. This new model innovatively considers the effects of matrix seepage, which is generally ignored by the traditional numerical models, for simulating the fluid–solid coupled fracture propagation behavior. The communication mechanism between fracture and cave is first revealed. The influence of geologic and engineering factors, e.g., permeability in high permeability zone around cave and injection rate etc., on hydraulic fracture propagation in fault-karst reservoir is studied. The results show that the high permeability zone around cave can provide sufficient infiltration capacity to communicate fracture with cave in the form of fluid pressure through fluid flow and fluid pressure conduction, even if hydraulic fracture does not directly communicate the cave. Hydraulic fracture is deflected to the direction of cave under the influence of seepage field, but the deflection angle is mostly within 10°. The high permeability of high permeability zone around cave and the short cave offset distance are conducive to the virtual communication between fracture and cave. Communicating fracture with cave in the non-principal stress direction can be accomplished by fluid flow and fluid pressure conduction, optimizing hydraulic fracturing treatment parameters should be performed by choosing lower injection rates and lower fracturing fluid viscosities. This study can provide key technical support and theoretical guidance for oil and gas development in fault-karst reservoir.

Coupled THMC model-based prediction of hydraulic fracture geometry and size under self-propping phase-transition fracturing

The Self-Propping Phase-transition Fracturing Technology (SPFT) represents a novel and environmentally friendly approach for a cost-effective and efficient development of the world’s abundant unconventional resources, especially in the context of a carbon-constrained sustainable future. SPFT involves the coupling of Thermal, Hydraulic, Mechanical, and Chemical (THMC) fields, which makes it challenging to understand the mechanism and path of hydraulic fracture propagation. This study addresses these challenges by developing a set of THMC multifield coupling models based on SPFT parameters and the physical/chemical characteristics of the Phase-transition Fracturing Fluid System (PFFS). An algorithm, integrating the Finite Element Method, Discretized Virtual Internal Bonds, and Element Partition Method (FEM-DVIB-EPM), is proposed and validated through a case study. The results demonstrate that the FEM-DVIB-EPM coupling algorithm reduces complexity and enhances solving efficiency. The length of the hydraulic fracture increases with the quantity and displacement of PFFS, and excessive displacement may result in uncontrolled fracture height. Within the parameters considered, a minimal difference in fracture length is observed when the PFFS amount exceeds 130 m3, that means the fracture length tends to stabilize. This study contributes to understanding the hydraulic fracture propagation mechanism induced by SPFT, offering insights for optimizing hydraulic fracturing technology and treatment parameters.

Numerical simulation of hydraulic fracture propagation from recompletion in refracturing with dynamic stress modeling

Owing to the rapid decline of oil production from tight oil reservoirs after primary hydraulic fracturing treatment on the horizontal well, a refracturing stimulation is proposed for tight oil recovery. In this study, a fully coupled dynamic stress computational method with a finite-element method is presented, and depletion-induced dynamic stress is simulated by coupled numerical modeling. In addition, the extended finite-element method (XFEM) approach is used to investigate the effect of different parameters on fracture dynamic propagation in recompletion from refracturing. The results highlight the effects of production-induced stress changes following hydraulic fracture propagation. When multiple fractures are stimulated simultaneously from recompletion during refracturing, curved fractures are commonly observed, and the deflected fractures generally divert toward the primary stimulated area with low pore pressure. The results indicate that comprehensive factors can affect the hydraulic fractures propagation from recompletion. The optimal refracturing time window can be determined using the dynamic stress condition and stimulated area. The initial completion spacing, initial fracture length, and recompletion perforation cluster spacing can also affect the fracture geometry from the recompletion. A larger initial fracture length can induce a larger stress change area, whereas a larger distance between the new perforations in recompletion and the old perforations can decrease the depletion-induced stress effect. A high horizontal stress contrast can increase the depletion-induced stress effect because a long fracture extends the area. Owing to the nonuniform pressure and stress distributions, more nonuniform fractures are commonly generated in the refracturing treatment. Thus, temporary plugging injection and proppant inertia must be designed while reducing the number of perforations near the initial perforation positions. This can help decrease the possibility of strong curved fractures and screen out problems.

Data-driven multiscale geomechanical modeling of unconventional shale gas reservoirs: a case study of Duvernay Formation, Alberta, West Canadian Basin

The Duvernay Formation in Canada is one of the major oil and gas source formations in the Western Canadian Sedimentary Basin, located at its deepest point. While it demonstrates promising development potential, challenges arise in the urgent need for integration of geology and engineering models, as well as in optimizing sweet spots, particularly as infill wells and pads become central operational objectives for the shale gas field. A lack of the geomechanical understanding of shale gas reservoirs presents a significant obstacle in addressing these challenges. To overcome this, we implemented data acquisition and prepared historical models and profiles, resulting in an extended high-resolution geological and reservoir property model with a fine grid system. Subsequently, a 3D full-field multi-scale geomechanical model was constructed for the main district by integrating seismic data (100 m), geological structures (km), routine logs (m), core data (cm), and borehole imaging (0.25 m), following a well-designed workflow. The predicted fracturability index (brittleness) ranges from 0.6 to 0.78, and a lower horizontal stress difference (STDIFF) is anticipated in the target formation, Upper Duvernay_D, making it a favorable candidate for hydraulic fracturing treatment. Post-analysis of the multi-disciplinary models and various data types provides guidelines for establishing a specific big database, which serves as the foundation for production performance analysis and aggregate sweet spot analysis. Fourteen geological and geomechanical candidate parameters are selected for the subsequent sweet spot analysis. This study highlights the effectiveness of multi-scale geomechanical modeling as a tool for the integration of multi-disciplinary data sources, providing a bridge between geological understanding and future field development decisions. The workflows also offer a data-driven framework for selecting parameters for sweet spot analysis and production dynamic analysis.

Quantitative multistage fracturing efficiency evaluation using cross-well strain measurements

Cross-well strain measurements acquired through low-frequency distributed acoustic sensing (LF-DAS) is a maturing technique used to monitor and diagnose the efficiency of hydraulic fracturing treatments. Although LF-DAS has demonstrated potential in characterizing far-field fracture communication and geometry, the prevailing analysis in this field has historically relied on qualitative interpretations, focusing on the timing and location of frac hits. In response to the evolving landscape of quantitative studies in this area, we present an advanced quantitative technique using our novel Green-function based inversion algorithm to calculate time-dependent far-field fracture width. The adopted algorithm uses the 3D displacement discontinuity method to relate fracture aperture to strains measured by LF-DAS along a monitor well during stimulation treatments. This approach is demonstrated on a subset of four treatment stages where distributed acoustic sensing (DAS) and distributed temperature sensing (DTS) were acquired within the injection well, alongside LF-DAS from a nearby monitor well. LF-DAS inversion results indicate the loss of zonal isolation in three of the monitored stages, leading to significantly smaller fracture widths at the monitor well for targeted treatment stages, and reactivated fractures in the adjacent previous stages. These interpretations are cross validated through the integration of in-well DAS and DTS analysis, where severe interstage fluid communication is observed. The inverted fracture widths quantify the impact on far-field fracture geometry associated with poor stage isolation and decreased fracturing efficiency. This new approach demonstrates the potential of LF-DAS for quantitative analysis and interpretation, facilitating improved understanding and optimization of hydraulic stimulation, going beyond its conventional qualitative role in fracturing diagnostics.

Implication of fast shear wave azimuth and critically stressed fractures in a coalbed methane reservoir

The orientation of the fractures and stresses within coal seams plays a critical role in gas production from coalbed methane reservoirs. In this study, we used resistivity images and sonic logs to investigate these parameters, aiming to (1) establish the relationship between fracture orientations and the polarization angles of fast shear waves and (2) detect active fractures in the coal seam. Shear waves in anisotropic formations are split into fast and slow components, with Alford’s rotation method used to determine the polarization angles of the fast shear wave. We found that the fast shear wave aligns with the direction of higher fracture intensity. Subsequently, we incorporated the poroelastic strain model to estimate the vertical ([Formula: see text]), maximum horizontal ([Formula: see text]), and minimum horizontal ([Formula: see text]) stresses in the wellbore. These stress magnitudes aided in identifying the faulting regime and were corroborated by vertical opening mode fractures. Validation of [Formula: see text] and [Formula: see text] involved comparisons with the breakout width in image logs and the closure pressure observed during hydraulic fracturing treatments. Applying Mohr’s Coulomb criteria, the stress model discerned the state of the fractures, transforming the stress magnitudes into shear and effective normal stress on each fracture plane. Our observations indicated that the identified fractures existed in a noncritically stressed condition, suggesting a lack of interconnectivity among them. These findings correspond to the absence of gas production to date, providing insights into the dynamics of fractures and their impact on production behavior.

Sealing faults and fluid-induced seismicity.

Sealing faults are nearly impermeable barriers that can form boundaries between subsurface pore-pressure domains. In hydrocarbon systems, sealing faults commonly form part of a structural trap; they are thus important elements for future storage of CO2 and other gases in depleted reservoirs. The Triassic Montney Formation in western Canada hosts low-permeability gas reservoirs containing sealing faults that have previously been assumed to compartmentalize pressure domains. In this study, we show that the distribution of induced seismicity associated with hydraulic fracturing (HF) exhibits a statistically significant spatial correlation with zones of high lateral gradient in pore pressure. These high-gradient zones are interpreted as sealing fault systems. The largest induced seismicity sequence, including a 4.5 ML mainshock on 30 November 2018, occurred during HF treatments in two horizontal wells, between which there is an exceptionally large contrast (~10 MPa) in measured pore pressure. Numerical simulation of a simplified model of a hydraulic fracture intersecting a nearby vertical fault, followed by fault rupture using rate-and-state friction rheology, generates results that are in good agreement with observed strike-slip faulting near one of the HF wells. Our study demonstrates that sealing faults exhibit previously unrecognized behaviour that may be important for understanding induced seismicity risk. This article is part of the theme issue 'Induced seismicity in coupled subsurface systems'.

Investigation of Grewia mollis Gum as Biopolymer Drag Reducing Agent

The hydraulic fracturing treatment relies heavy on fracturing fluid. Finding inexpensive polymer that lowers the pressure gradient in turbulent flow systems during hydraulic fracturing is crucial for the development of shale gas. Most researches focused on investigating the effects of polymers such as partially hydrolysed polyacrylamide, polyethylene oxide, guar gum, xanthan gum and synergies of mixtures as friction reducing polymers. The use of Grewia Mollis mucilage as the natural polymer as a potential friction reducer in slickwater fracturing treatment was the main focus of this study. The sample of Grewia gum was obtained and the mucilage was extracted from the inner stem bark by maceration in water at ambient temperature. The mucilage was the oven-dried at a temperature of 50 oC. Atomic Absorption spectrophotometer (AAS) and Fourier Transform Infrared (FT-IR) were employed to identify the elemental composition and the functional groups of the plant. The FT-IR spectrum exhibited typical peaks and bands characteristics of polysaccharide, while the ASS result shows the presence of minute quantity (0.219 mg/100 g) of lead (Pb) in the plant may show contamination (toxicity). The rheological measurements of the mucilage plotted on the shear viscosity graph exhibit shear-thinning or pseudo-plastic behaviour. Formulated slickwater fracturing fluid at various concentrations ranging from 200 to 500 ppm, were run in a constructed closed flow loop of 0.01905 m diameter of galvanised steel pipe, test section length of 2 m and entrance length of 2 m. Drag reduction was measured at flow rates (2.3, 2.8, 3.2, 3.6 and 4.0) m3/hour at different concentrations (200 to 500) ppm. Percentage friction reduction of 37% was achieved at Reynolds number of 74269 by addition of 200 ppm of the fluid while 56% was achieved at Reynolds number 74269 by addition of 500 ppm. This indicates that Grewia mollis mucilage exhibit drag reducing potential and can be applied in slickwater hydraulic fracturing application.

Precise relative magnitude measurement improves fracture characterization during hydraulic fracturing

SUMMARY Microseismic monitoring is an important technique to obtain detailed knowledge of in-situ fracture size and orientation during stimulation to maximize fluid flow throughout the rock volume and optimize production. Furthermore, considering that the frequency of earthquake magnitudes empirically follows a power law (i.e. Gutenberg–Richter), the accuracy of microseismic event magnitude distributions is potentially crucial for seismic risk management. In this study, we analyse microseismicity observed during four hydraulic fracture treatments of the legacy Cotton Valley experiment in 1997 at the Carthage gas field of East Texas, where fractures were activated at the base of the sand-shale Upper Cotton Valley formation. We perform waveform cross-correlation to detect similar event clusters, measure relative amplitude from aligned waveform pairs with a principal component analysis, then measure precise relative magnitudes. The new magnitudes significantly reduce the deviations between magnitude differences and relative amplitudes of event pairs. This subsequently reduces the magnitude differences between clusters located at different depths. Reduction in magnitude differences between clusters suggests that some attenuation-related biases could be effectively mitigated with relative magnitude measurements. The maximum likelihood method is applied to understand the magnitude frequency distributions and quantify the seismogenic index of the clusters. Statistical analyses with new magnitudes suggest that fractures that are more favourably oriented for shear failure have lower b-value and higher seismogenic index, suggesting higher potential for relatively larger earthquakes, rather than fractures subparallel to maximum horizontal principal stress orientation.

Advanced Deep Learning for microseismic events prediction for hydraulic fracture treatment via Continuous Wavelet Transform

Understanding hydraulic fracture propagation events would enable operators to estimate the fracture geometry, understand formation/fracture interactions, and estimate the total microseismic events cloud. This paper introduces a new method for understanding the dynamic fracture propagation events using a signal processing technique. Detection of the dynamic fracture event using continuous wavelet transform (CWT) is used to train a deep learning model with microseismic events to predict this cloud for every hydraulic fracture job. The deep learning model is used for the same formation. The CWT for treatment pressure is a convolution process that involves the application of a wavelet signal to the acquired pressure signal in a continuous manner. The wavelet is stretched, or compressed, and is moved along the acquired pressure signal, acting as a generic microscope to highlight small changes in the treating pressure signal. Using CWT as a mathematical microscope to discern diverse signals has been adopted by numerous engineering and medical applications since the 1990s.A normalized CWT scalogram for fracture-treating pressure is thus created as a unique representation of each fracture propagation mode in the hydraulic fracturing job. The new technique is calibrated with several fracture simulation runs and real field data using the previous techniques like moving reference point (MRP). That previous technique which has been previously validated through fracture simulation, is used as a calibration for the new normalized CWT scalogram technique. The technique was finally calibrated by comparing it with micro-seismic events recorded by the Marcellus Shale Energy and Environment Laboratory (MSEEL).The results of this comparison were exceptionally accurate. It can be used to train a deep learning model that can be used to estimate the cloud of microseismic events for hydraulic fracture jobs in Marcellus shale. The new deep learning framework uses CWT to convert the treating pressure during hydraulic fracture propagation to dimensionless representation (normalized CWT scalogram) which acts as a mathematical microscope for the fracture treating pressure on different wavelet stretch or compressions, enabling the detection of the major changes in the treating pressure then train the deep learning model to estimate microseismic events cloud.

Identifying perforation locations for hydraulic fracturing treatment in deep and tight sandstone gas reservoirs

Fracture initiation has been a challenging issue for fracturing deep and tight gas reservoirs, which generally requires a high breakdown pressure for hydraulic fracturing treatment. In this situation, fluid injections frequently have to terminate at the very beginning. Toward predicting and solving this issue, a novel fracturing system for deep and tight sandstone gas reservoirs was developed. The key components of the fracturing system and some criterion will be introduced, which can be used to optimize the ideal perforation locations along the landing part and select the right perforation strategy accordingly. The main components of the fracturing system include: (1) evaluating the log-based diagenetic rock typing and flow index; (2) 1D mechanical earth model; (3) calculating the breakdown pressure envelope along the well trajectory of the landing part; (4) calculating the optimal perforation directions along the landing part; (5) select the first set of perforation locations based on the log-based diagenetic rock typing and flow index; (6) narrowing down the first set of perforation locations to a second set of perforation locations based on the breakdown pressure envelope; (7) determining a perforation strategy based on breakdown pressure envelope and wellhead pressure safety limit in the second set of perforation locations. The computational framework to calculate the breakdown pressure envelope and optimal perforation directions is applicable to arbitrary well trajectory. The fracturing system has been used to provide pre-fracturing suggestions for wells landed in deep and tight sandstone reservoirs, which is very efficient for identifying locations with good rock typing and relatively low breakdown pressure. Also, it can indicate whether oriented perforation should be used further for alleviating breakdown issue. By taking these efforts and procedures, the fracturing success rate for deep and tight sandstone gas reservoirs can be improved, which has been verified in practice. Example studies from the field will be provided to demonstrate the fracturing system's performance and applicability.

Quantitative characterization of imbibition in fractured porous media based on fractal theory

In low-permeability reservoirs, such as shale and tight sandstone, imbibition is an important mechanism for enhancing oil recovery. After hydraulic fracturing treatment, these reservoirs create a network of fracture pathways for fluid flow. Therefore, understanding the imbibition mechanisms in fractured porous media and quantitatively characterizing oil–water distribution are crucial for the development of low-permeability reservoirs. In this study, a mathematical model of two-phase flow in porous media with branching fractures was established. The phase-field method was employed to track the oil–water interface, and quantitative characterization of imbibition was conducted based on fractal theory, and the effects of wetting phase injection rate, the number of disconnected fractures, fracture spacing, and fracture morphology on imbibition in branched fracture porous media were discussed. The research findings indicate that in branched fracture porous media, both co-current and countercurrent imbibition processes occur simultaneously, and there exists a diffusion interface layer with a certain thickness at the oil–water interface. The hydraulic pressure generated by the wetting phase injection rate provides the driving force for imbibition oil recovery, but it also affects the contact time between the wetting and non-wetting phases. The presence of disconnected fractures hinders the propagation of hydraulic pressure, reducing the effectiveness of imbibition. The imbibition displacement zone is limited and occurs only within a certain range near the fractures. As the number of branching fractures increases, the channels for the wetting phase to enter matrix pores are enhanced, resulting in higher efficiency of imbibition displacement of the oil phase. The results of this research can provide guidance for the design of fracturing programs and recovery prediction in low-permeability reservoirs.

Numerical investigation of mechanical responses and failure features of coal measure strata using combined finite-discrete element method

Investigating the mechanical responses and failure features of the deep coal measure strata (CMS) is essential for designing hydraulic fracturing treatments and preventing geological dynamic hazards in underground engineering. In this paper, a three-dimensional CMS model is established by the combined finite-discrete element method (FDEM). The mechanical properties, stress evolutions and failure features of the CMS with different lithological combinations (sandstone-coal-sandstone (SCS), sandstone-coal-mudstone (SCM) and mudstone-coal-mudstone (MCM)) and thickness ratios are investigated under the uniaxial compressive condition. Results indicate that the SCS combination exhibits the highest uniaxial compressive strength (UCS) and elastic modulus, followed by the SCM and MCM combinations. The mechanical properties of the CMS are predominantly determined by the softer coal layer. The mechanical contrasts in elastic modulus and Poisson’s ratio between adjacent layers cause the generation of additional compressive stress in the softer layer and additional tensile stress in the stiffer layer. Therefore, the softer coal layer exhibits the shear-dominated failure pattern while the stiffer sandstone/mudstone layer displays the tensile-dominated failure pattern in the CMS. Furthermore, as the thickness ratio of the coal layer increases, the UCS, elastic modulus, and interfacial constraint stress decrease in the CMS. Additionally, the UCS and stress–strain relationship in the post-peak stage exhibit the noticeable size effect, whereas the mechanical behaviors in the pre-peak stage and the ultimate fracture patterns show the opposite. The elastic modulus and interfacial constraint stress obtained by the FDEM simulation match well with those calculated by theoretical models. The key findings of this paper can provide fundamental understanding and reliable parameters for multi-scale geomechanical modeling in petroleum and mining engineering.

Analysis of Fluid-Injection-Induced Seismicity Using a Dynamic Sliding Model Incorporating the Rate- and State-Dependent Friction Law

Summary Earthquakes can be triggered by fluid injection into underground formations. Fluid injection can cause large changes in the underground volume that exert stresses on nearby preexisting faults, leading to seismic activity. Assuming an increase in underground development activities in the future, our understanding of the mechanism underlying induced seismicity must be improved, and methods must be developed to properly assess the risk of seismic events. The objective of this study is to develop a seismicity prediction model that calculates the magnitude and timing of triggered earthquakes or seismic events occurring during various subsurface fluid injection activities. We developed an injection-induced seismicity analysis model that predicts the dynamic earthquake nucleation caused by changes in stress and pore pressure that occur during various subsurface activities. The governing equations consisting of the dynamic motion of the poroelastic spring-slider system, rate and state friction laws and pore pressure diffusion equation were solved using the embedded semi-implicit Runge-Kutta (SIRK) method. The dynamic sliding model was also incorporated into the finite element method (FEM) model, considering the variations in the stresses and pore pressures in the formation. A field case study was also conducted to compare the model results with typical microseismicity responses observed from hydraulic fracturing treatments in shale fields. Contrary to the popular understanding derived from Amonton’s law, the dynamic friction model revealed that a large normal stress on the fault leads to rapid sliding. A larger normal stress accumulates a large amount of elastic energy until it slips owing to fluid injection, nucleating large seismic waves. The poroelastic spring-slider model estimated reasonable microseismic magnitudes for hydraulic fracturing treatment but overestimated the time required to trigger a microseismic event under field conditions. To improve the analysis results, the poroelastic spring-slider model was coupled with a linear elastic FEM that considered the complex interplay of stress changes from hydraulic fracturing and the associated pore pressure variation in the formation. Compared with the field data, the coupled simulation model estimated a reasonable timing for the induced microseismic events when the increasing pore pressure during hydraulic fracturing penetrated deep into the formation. These findings suggest the existence of permeable natural fractures in the formation, which intensify early frictional sliding during treatment. The seismicity prediction model presented in this study simulates the magnitude and timing of seismic nucleation, helping to manage and mitigate the environmental impacts of induced seismicity during various subsurface development activities, such as oil and gas extraction, hydraulic fracturing, geothermal, and carbon dioxide sequestration. Moreover, the case study results imply that the time series of seismic events predicted by the model can be used to understand the possible fracture geometry and extent of fluid invasion for field applications. Key Terms and Phrases induced seismicity, subsurface fluid injection, rate- and state-dependent friction law, embedded semi-implicit Runge-Kutta method, finite element analysis

Cyclical hydraulic pressure pulses reduce breakdown pressure and initiate staged fracture growth in PMMA

Using unique experimental equipment on large bench-scale samples of Polymethylmethacrylate, used in the literature as an analogue for shale, we investigate the potential benefits of applying cyclical hydraulic pressure pulses to enhance the near-well connectivity through hydraulic fracturing treatment. Under unconfined and confined stresses, equivalent to a depth of up to 530 m, we use dynamic high-resolution strain measurements from fibre optic cables, complemented by optical recordings of fracture development, and investigate the impact of cyclical hydraulic pressure pulses on the number of cycles to failure in Polymethylmethacrylate at different temperatures. Our results indicate that a significant reduction in breakdown pressure can be achieved. This suggests that cyclic pressure pulses could require lower power consumption, as well as reduced fluid injection volumes and injection rates during stimulation, which could minimise the occurrence of the largest induced seismic events. Our results show that fractures develop in stages under repeated pressure cycles. This suggests that Cyclic Fluid Pressurization Systems could be effective in managing damage build-up and increasing permeability. This is achieved by forming numerous small fractures and reducing the size and occurrence of large fracturing events that produce large seismic events. Our results offer new insight into cyclical hydraulic fracturing treatments and provide a unique data set for benchmarking numerical models of fracture initiation and propagation.

Fracture Height Quantification from Vertical and Horizontal Section Fiber Measurements: A Comprehensive Study Using LF-DAS Measurements from HFTS-2 Data Set

Summary Understanding fracture height growth is critical for optimizing hydraulic fracture treatments and field development. In recent years, low-frequency distributed acoustic sensing (LF-DAS) has become a popular tool for monitoring strain changes during hydraulic fracturing. While LF-DAS data from vertical monitoring wells (VMWs) can be used to determine fracture height, measurements from the vertical section of horizontal wells may have the potential to capture fracture height growth. The objectives of this study are (1) to apply three methods—(a) using the vertical section of horizontal fiber measurements, (b) using the vertical fiber measurements, and (c) using the horizontal section of horizontal fiber measurements—to determine the fracture height using the Hydraulic Fracturing Test Site 2 (HFTS-2) data set and (2) to demonstrate the reliability of using LF-DAS measurements from the vertical section of horizontal fibers for fracture height determination. In an effort to determine the fracture height from the HFTS-2 data set using the three methods, we demonstrate the reliability of the height prediction using strain measurements in the vertical section of the horizontal monitoring well (VS-HMW). First, we analyze the measurements from the vertical section of the horizontal fiber (B3H) during the stimulation of the heel-most stages of the horizontal wells (B1H, B2H, and B4H). Second, we analyze the measurements from the VMW (B5PH) during the stimulations of B1H, B2H, and B4H. Third, we use a geomechanical inversion algorithm to obtain height estimates from the horizontal section of the LF-DAS measurements at B3H during B1H, B2H, and B4H stimulations. The fracture height is determined based on the transition of the extension-compression zone in the LF-DAS measurements from the vertical sections. The height estimates obtained using the three methods are compared and found to be consistent in the six well pairs we analyzed. The LF-DAS measurements from the vertical well B5PH provide a complete height profile, while measurements from the vertical section capture fracture growth from the upper tip of the fracture to the landing depth of the horizontal well. The fracture height estimates obtained from our inversion algorithm represent the average height value of all fracture hits at the chosen stage. This study demonstrates the potential to determine fracture height growth using LF-DAS measurements in the vertical section of a horizontal well, thus avoiding the cost associated with drilling VMWs to obtain fracture heights.

Numerical study of hydraulic fractures propagation in deep fracture-cavity reservoir based on continuous damage theory

Natural fractures and cavities are the primary spaces for oil and gas accumulation in fracture-cavity carbonate reservoirs. Establishing the connection between these spaces and the wellbore through hydraulic fracturing treatment is important for oil and gas extraction from such reservoirs. Due to the discontinuity and heterogeneity of the existing natural fracture-cavity system, anticipating the viability of hydraulic fracturing treatment is troublesome. A new method to simulate the hydraulic fracturing propagation in fracture-cavity reservoirs is proposed based on the continuous damage theory. The method considers the random spatial distribution of fractures and cavities and can simulate the arbitrary expansion of hydraulic fractures in the three-dimensional direction. Based on this method, the influence of different geological and engineering factors on the propagation patterns of hydraulic fractures in the fracture-cavity reservoirs is investigated. It is found that the increase of reservoir burial depth significantly limits the propagation ranges of hydraulic fractures. The propagation modes of hydraulic fractures encountering natural fractures change with increasing burial depth, undergoing a transition from “penetrate and deflect” to ”defect” and then to ”penetrate”. The reduction of horizontal stress difference increases the complexity of hydraulic fractures, but it is not conducive for hydraulic fractures to connect more natural fractures and cavities. The increase in fracturing pump rate is significantly beneficial for hydraulic fractures to connect more natural fractures and cavities. The viscosity of fracturing fluid has a significant impact on the morphology of hydraulic fracture propagation, which undergoes a transition from simple to complex, and then to simple with the change of the fracturing fluid viscosity from low to high. either too high or too low viscosity of the fracturing fluid is not conducive to the connection of more natural fractures and cavities by hydraulic fractures. The obtained conclusions can provide a reference for the design of hydraulic fracturing treatment for fracture-cavity carbonate reservoirs.

Numerical Simulation Study on the Effect of Preinjected CO2 on the Hydraulic Fracturing Behavior of Shale Oil Reservoirs.

Due to the low permeability and apparent mechanical anisotropy of shale reservoirs, shale oil production highly depends on the performance of hydraulic fracturing of the tight reservoir. Pre-injection of CO2 before hydraulic fracturing treatment has been proven beneficial to enhance shale oil production. A comprehensive understanding of the effect of changes in the properties of shale reservoirs after preinjected CO2 on the hydraulic fracturing behavior of shale reservoirs is essential to improve the stimulated reservoir volume (SRV) of shale oil reservoirs. In this study, comprehensive evaluating parameters were proposed to specify the variation of mechanical properties of shale rock at different soaking times of CO2 based on published testing parameters of shale. Accordingly, a three-dimensional (3D) numerical model was established and three groups of horizontal well fracturing cases with different cluster spacings were conducted based on the adaptive FE-DE method to simulate and compare the hydraulic fracturing behavior in the reservoirs with different mechanical properties. We established a quantitative relationship between the alterations in reservoir properties and the stimulated reservoir volume. The results indicate that both the brittleness and conductivity properties of shale rock are dramatically improved as the increment of soaking time of CO2. It is beneficial to improve the SRV, and the initiation pressure is reduced with the increment of soaking time of CO2. However, as the stress shadow effect is involved in the horizontal well fracturing, the complexity of the hydrofracturing crack is significantly enhanced to restrain the development of hydrofracturing crack. When the cluster spacing is larger, the stress shadow effect is weakened, and the weakening effect of CO2 soaking on reservoir is more obvious.

Natural fractures at depth in shale reservoirs: new insights from the southern Sichuan Basin marine shales

Natural fractures are pervasive in southern Sichuan Basin marine shales, China, and provide a useful opportunity to try to understand subsurface fracture networks in shale reservoirs. Based on cores and electrical imaging logs from vertical and horizontal petroleum wells in the southern Sichuan Basin, four types of natural fractures were identified in terms of orientation, size, filling properties and spatial distribution. Uncemented bed-parallel shear fractures develop at or in the vicinity of mechanical interfaces and are inclined to present in shale layers with a dip angle greater than 12°. Cemented bed-parallel fractures are characterized by a crack-seal texture marked by multiple bands of fibrous cement, and their intensity decreases upwards and shows a positive relationship with total organic carbon (TOC) values. Uncemented bed-oblique fractures are a type of fracture that rarely develops, and accommodate limited open space. Cemented bed-oblique/perpendicular fractures are the most developed fracture type and are distributed on a regional scale and are subdivided into two types. The results imply that these shale fractures could be formed sequentially by local and regional tectonic deformation, and by abnormally high pressure. Most natural fractures cannot contribute to reservoir storage or efficiently enhance its permeability, yet can act as planes of weakness and be potentially reactivated during hydraulic fracture treatments.

Advances in hydraulic fracture characterization via borehole microseismic and strain monitoring

We analyze the impact and challenges associated with microseismic monitoring in the development of unconventional reservoirs. We detail advanced methods that address some of these challenges and discuss emerging data analysis and acquisition technologies such as those provided by fiber-optic monitoring. During the development of unconventional resources, it is important to understand the stimulated rock volume obtained from the hydraulic fracturing treatment. Microseismic monitoring is one of the sources of information for estimating stimulated rock volume in which accurate hypocenter calculations provide the horizontal and vertical fracture geometry and extent. We developed hypocenter waveform-based relocation and collapsing techniques and demonstrated these on synthetic and field data to obtain an enhanced description of the fracture geometry. We further provide the initial analysis of a recently acquired data set composed of multiple monitoring wells instrumented with geophones and fiber optics operating simultaneously. Microseismic events recorded by the multiwell dual geophone/fiber setup show meaningful signal-to-noise ratio to enable a joint interpretation. Additional strain and temperature data provided by dynamic fiber-optic measurements extend the interpretation capabilities of the hydraulic fracturing phenomenon while providing an avenue for advanced research on fracture characterization.