Fracture Design Research Articles

Supercritical CO2-driven intersections of multi-well fracturing fracture network and induced microseismic events in naturally fractured reservoir

PurposeSupercritical CO2 (SC–CO2) fracturing is a potential technology that creates a complex fracturing fracture network to improve reservoir permeability. SC–CO2-driven intersections of the fracturing fracture network are influenced by some key factors, including the disturbances generated form natural fractures, adjacent multi-wells and adjacent fractures, which increase the challenges in evaluation, control and optimization of the SC–CO2 fracturing fracture networks. If the evaluation of the fracture network is not accurate and effective, the risk of oil and gas development will increase due to the microseismicity induced by multi-well SC–CO2 fracturing, which makes it challenging to control the on-site engineering practices.Design/methodology/approachThe numerical models considering the thermal-hydro-mechanical coupling effect in multi-well SC–CO2 fracturing were established, and the typical cases considering naturally fracture and multi-wells were proposed to investigate the intersections and connections of fracturing fracture network, shear stress shadows and induced microseismic events. The quantitative results from the typical cases, such as fracture length, volume, fluid rate, pore pressure and the maximum and accumulated magnitudes of induced microseismic events, were derived.FindingsIn naturally fractured reservoirs, SC–CO2 fracturing fractures will deflect and propagate along the natural fractures, eventually intersect and connect with fractures from other wells. The quantitative results indicate that SC–CO2 fracturing in naturally fractured reservoirs produces larger fractures than the slick water as fracturing fluid, due to the ability of SC–CO2 to connect macroscopic and microscopic fractures. Compared with slick water fracturing, SC–CO2 fracturing can increase the length of fractures, but it will not increase microseismic events; therefore, SC–CO2 fracturing can improve fracturing efficiency and increase productivity, but it may not simultaneously lead to additional microseismic events.Originality/valueThe results of this study on the multi-well SC–CO2 fracturing may provide references for the fracturing design of deep oil and gas resource extraction, and provide some beneficial supports for the induced microseismic event disasters, promoting the next step of engineering application of multi-well SC–CO2 fracturing.

Simultaneous use of disulphide oil for chemical‐enhanced oil recovery by emulsion formation and stability with asphaltene deposition control

AbstractDisulphide oil (DSO) is a by‐product of oil and gas refining processes that is generated during the removal of mercaptans and the sweetening of light hydrocarbons. Asphalt deposition, especially asphaltene deposition during enhanced oil recovery methods, reduces oil recovery from the reservoir, so the use of a substance such as DSO, which has the ability to control and reduce asphaltene deposition, can be effective in increasing oil recovery from the reservoir. In this research, a micromodel with a fracture design and a matrix that represents fracture reservoirs was utilized. These tests were conducted in two groups. The first group of tests is related to adding DSO to crude oil and using 70 to 30 vol.% oil–water emulsion containing salt, surfactant, and nanoparticles. The second group involved adding DSO to both crude oil and emulsion. The first group aimed at stimulation and the second group aimed at chemical enhanced oil recovery (C‐EOR). The formation and stability of water‐in‐oil emulsion was done by analyzing the average droplet size. As a result, in the first group of tests with the presence of DSO in the oil, by measuring the average diameter before and after injection of AOS surfactant, it was observed that the average droplet size decreased from 6.89 to 4.01 μm, which indicates an increase in the emulsion stability. In the second group, where DSO was present in both oil and water emulsion in injected oil, it can be seen that the average diameter of the droplets in the surfactant decreased from 5.12 to 3.21 μm.

Numerical investigation into the acid flow and reaction behavior in the tight, naturally fractured carbonate reservoir during acid fracturing

Tight naturally fractured carbonate reservoirs require acid fracturing to build the connectivity between the wellbore and natural fractures (NFs), where hydrocarbon is stored. The high leakoff nature of the NF complicates the acid flow and etching pattern, raising the difficulty in acid fracturing design and optimization. To explore the acid flow and reaction behavior in such reservoirs, an acid fracturing model accounting for the NF distribution is developed, which consists of a fracture surface characterization model, a fracture propagation model, and an acid-etching model. Based on the model, the effects of injection parameters and the NF properties on the effectiveness of acid fracturing are investigated. Then, strategies for acid fracturing the tight naturally fractured carbonate reservoirs are proposed. Results show that high pumping rates and retarded acids with low hydrogen ion (H+) diffusion coefficient is conducive to achieving a long acid penetration distance, while a low pumping rate and acids with a high H+ diffusion coefficient facilitates the NF etching. Therefore, a large stimulated area can be achieved by applying a multi-stage alternating injection of the crosslinked acid with a high pumping rate followed by the gelled acid with a low injection rate. NFs impact acid fracturing in two distinct ways: enhancing the non-uniform etching of the fracture surface and reducing the effective acid-etched fracture length through high leakoff. When NF density is high, leakoff control techniques should be employed; and when the NF inclination is high, non-uniform etching techniques should be used to generate acid-etched channels in flow barriers.

Numerical simulation on multi-well fracturing considering multiple thin layers in vertical direction

Multiwell fracturing is a key technology for developing shale gas and shale oil reservoirs. In this study, a multiple planar 3D (PL3D) fracture simulator that can capture multiple thin layers was developed to examine the propagation of multiple fractures during multicluster fracturing in multiple horizontal wells. The simulator considers multiple thin layers in the vertical direction. The results of the model are validated against the analytical solution of a single radial fracture and the implicit level set algorithm (ILSA). Using the simulator, a series of numerical simulations based on the field case are performed to investigate the fracture propagation mechanism of multiwell fracturing. The completion sequence, well placement pattern, well spacing, and cluster spacing are investigated to optimize the treatment parameters. The effective fracture area is used to quantitatively describe the stimulation effect. The adaptability of the completion sequence and well placement pattern is also analysed from the perspective of “frac hits”. The results show that the completion sequence has a critical influence on the stimulation effect and fracture geometry. From the perspective of avoiding “frac-hit” fractures, fracturing the low-stress layer can form an “artificial stress barrier”, which slightly protects the well from interference from other fractures. The staggered well pattern is better than the stacked well pattern. Compared with the stacked pattern, the staggered pattern can reduce the overlap area of fractures by 80 %, which greatly reduces the probability of “frac-hits”. With increasing well spacing from 200 m to 500 m, the fracture area increases by 25 %, and the degree of uneven stimulation between the two pay zones also increases by 6 %. Considering that a small well spacing is prone to “frac hits”, a large well spacing leads to an unstimulated area between two wells, and a 350 m well spacing is optimal. The effective fracture area decreases slightly with increasing perforation cluster spacing, but the fracture geometry becomes much more regular. The results can be helpful for the field design of multiwell fracturing.

Integrated study of hydraulic/CO2 fracturing and production coupled with a THM-D process in ultra-shallow shale reservoirs

To explore fracturing technology for vertical wells in ultra-shallow shale gas reservoirs, a coupled thermo-hydro-mechanical-damage (THM-D) fracturing and production integration model is established in this study. In addition, a new coupled hydro-mechanical damage model is established to calculate fracture evolution. These two models are validated through theoretical models and field data, respectively. Based on these models, the quality of fracturing under different geological parameters, fracturing parameters, and fracturing technology is compared and analyzed. The results show that the distribution of natural fractures significantly influences fracturing and production. In addition, due to the high leak-off in the ultra-shallow shale reservoir, the total fracture length and cumulative production after 720 days of carbon dioxide fracturing are only 70.35% and 77.26% of the values achieved by hydraulic fracturing, respectively. Therefore, it is necessary to consider reducing carbon dioxide leak-off in the design of carbon dioxide fracturing in ultra-shallow shale reservoirs. Fracturing efficiency also should be considered when designing fracturing time. When the injection rate is 5 m3/min, the efficiency drops sharply if the fracturing time exceeds 67.45 min. The production of hydraulic fracturing and carbon dioxide fractured wells has also been studied when fracturing methods without proppant are used. This study found that a satisfactory production rate can also be achieved in ultra-shallow shale gas reservoirs when fracturing without proppant.

Optimising Neural Networks for Enhanced Fracture Density Prediction in Surrounding Rock of Coalbed Methane Reservoir

ABSTRACTFractures influence the mechanical strength of coal roof and floor, constraining the design of hydraulic fracturing for coalbed methane production. Currently, the predominant approach involves the integration of petrophysical logging with machine learning for fracture prediction. Nevertheless, challenges exist regarding the model's accuracy. In this study, we present a novel approach to predict fracture density. Our method optimises a back‐propagation (BP) neural network and utilises principal component analysis for feature extraction. We employ logging parameters (density, compensated neutron and acoustic time difference) obtained from Shouyang Block well SY‐1 and fracture density data from electrical imaging logging to construct the FVDC model's dataset. The BP neural network model is optimised using the Sparrow Search algorithm and Tent Chaotic Mapping. The results demonstrate a substantial enhancement over the BP neural network model, with reductions of 80.102% in mean absolute error, 94.182% in mean square error, 75.879% in root mean square error and 79.764% in mean absolute percentage error. When considering accuracy, the optimised model (97.098%) surpasses the support vector regression model (96.478%), the random forest model (94.404%) and the BP neural network model (85.657%). Scalability testing for the optimised model was conducted using data from well SY‐2, yielding a remarkable prediction accuracy of 96.775%. This performance exceeds that of the BP neural network (with an accuracy of 85.102%), as well as the random forest and support vector regression models (with accuracies of 91.234% and 90.384%, respectively). These results underscore the potential of well logging and machine learning in FVDC prediction.

Mechanical properties of shale during pyrolysis: Atomic force microscopy and nano-indentation study

Quantitative characterization of the geo-mechanical properties of shale and organic matter (OM) holds paramount significance in the assessment of shale gas reserves and the design of hydraulic fracturing. However, the mechanical evolution processes during shale hydrocarbon generation and its influencing factors have received limited attention. This study examines the changes in shale mechanical properties during pyrolysis at high temperatures (415–600 °C) and high pressure (50–125 MPa) for mature to over-mature stages. The nanoindentation and in-situ AFM-QNM analysis are utilized to characterize the changes in mechanical properties during evolution. Subsequently, gas adsorption, Fourier Transform infrared spectroscopy (FTIR), and laser Raman spectroscopy (Raman) are used to investigate the factors influencing the mechanical properties of shale and the associated OM, and establish a model for the evolution of the mechanical properties. The results demonstrate that with increasing maturity, the overall Young's modulus of the bulk shale gradually increases from 42.8 GPa to 58.4 GPa for the temperature increment from 415 °C to 600 °C. During the thermal maturation process, the mesopore structure and quartz content of the shale significantly influence its mechanical properties. Young's modulus of OM shows an S-shaped trend, with variations in the micromechanical properties of OM corresponding to stages of hydrocarbon generation. In particular, two peaks of Young's modulus increase are observed during the mature and over-mature stages. In the mature stage, the aromatization of the kerogen leads to substantial detachment of aliphatic side chains and oxygenated functional groups, resulting in a higher degree of aromatization. This reduces the kerogen spacing and consequently increases the Young's modulus. In the over-matured stage, the process of aromatics condensation leads to the orientation and arrangement of aromatic rings, reducing the number of key site vacancies and crystal defects, thereby forming large aromatic clusters and significantly increasing the graphite-like structure. This study will facilitate the analysis of shale matrix deformation mechanisms at the microscale, providing a fundamental theoretical and scientific basis for shale fracturing design, exploration, and development.

Technology and Research on Improving Oil Recovery by Volume Fracturing with Phase Change Permeability in Ultra-low Permeability Reservoirs

Abstract The conventional water injection development production wells in ultra-low permeability reservoirs have low efficiency, low production and low liquid content, and poor economic benefits. Traditional water drive development techniques are difficult to adapt to the requirements of economically effective development in ultra-low permeability reservoirs. Therefore, it is urgent to adjust development ideas and transform water injection development methods. A major development experiment was carried out in the Y284 area of Huaqing Oilfield to transform the water injection development method. Based on the mechanism of reverse osmosis flooding in oil recovery wells, this article uses dynamic monitoring technologies such as downhole microseismic to achieve three-dimensional reservoir transformation, and establishes a large-scale fracturing technology of “collaborative permeability flooding, volume fracturing, and multi-stage temporary plugging” for reverse osmosis wells in ultra-low permeability reservoirs. Research has shown that large-scale fracturing technology for water injection wells can improve single well oil recovery speed by increasing the complexity of fracture networks. The important factors affecting the effectiveness of water injection wells include reservoir properties, fracturing transformation scale, cumulative water injection volume, remaining oil distribution, and heterogeneity of aquifers. At the same time, the construction parameters of large-scale volume fracturing for water injection wells, namely 140-170m, are quantitatively determined based on the actual situation of the mining field ³ The amount of sand added, a sand ratio of 17-22%, and a large displacement of 8-10m3/min, 1400-2000m ³ The amount of liquid entering the ground can most effectively achieve the conditions for reservoir transformation. The conclusion is that large-scale fracturing technology for conversion wells provides technical support for volume fracturing and optimization design of fracturing parameters for low production wells in ultra-low permeability reservoirs, and can provide guidance and reference for the efficient development of other similar ultra-low permeability reservoirs.

Fracture propagation behavior via multi-cluster fracturing in sandstone-shale interbedded reservoirs

Initiation and propagation of fractures in multi-layered formations has been a topic of interest for the efficient utilization of hydrocarbon resources. Although there is a reasonable body of knowledge to facilitate the design and development of hydraulic fracture, the understanding of initiation and propagation of fracture clusters in layered formation is limited. This paper discusses the findings from controlled laboratory experiments and numerical modeling to understand the initiation and propagation of hydraulic fracturing operations. True triaxial tests were carried out on samples extracted from outcrop representative of Lianggaoshan formation in China. It was noted that the differential stress between the layers is critical for the initiation and propagation of multiple fracture. It was also noted that the viscosity of the fracturing fluid influences the propagation of fractures across lamina and interfaces. The intermediatory response of rocks due to the injected fluid was studied through numerical modeling of the physical process using modified cohesive zone model, which was then validated by the output from the laboratory experiments. It was noted that the increase in the fracture cluster has the potential to constrain the extent of fracture propagation whereas decrease in the cluster size increases the extent of fracture propagation. Compared to sandstone, the fracture height in shale is 30% lower. For sandstone, early-stage fracture flow distribution stabilizes more quickly, and higher fluid pressure within fractures significantly increases fracture height and effective stimulation volume.

Identification of Nearly Pure Leakoff Phase from Pressure Falloff Curve and Its Interpretation on Stimulated Fracture Areas

Summary Evaluation of fractures post-hydraulic fracturing is crucial for optimizing fracturing designs. Pressure falloff analysis methods, due to their cost-effectiveness and ease of data acquisition, have been widely used in oil fields. However, traditional pressure falloff analysis methods are based on the assumption of simple double-wing fractures and often overlook the impact of early-time abnormal leakoff behaviors. While some scholars have proposed pressure falloff equations for individual abnormal leakoff behavior, establishing pressure falloff models that consider the coupling of multiple abnormal leakoff behaviors is challenging, making the assessment of complex fracture networks difficult. This paper proposes a method that identifies the phase of nearly pure leakoff pressure falloff through continuous wavelet transform (CWT) and utilizes this phase for fracture inversion. Additionally, the fracture inversion model considers the differences in closure pressure and fracture compliance between main and secondary fractures. This method is applied to a shale horizontal well, and the results show that the inversion fracture areas are 20.3% smaller on average than the traditional method after removing the disturbance of abnormal leakoff behaviors. The new method is verified by the production data of each stage. The correlation between the main fracture area of new method and the production of each stage is better than that of the traditional method, and the correlation coefficient is 0.767. It is also found that the development degree of natural fractures affects the proportion of main and secondary fractures. In addition, it is found from the time-frequency diagram after CWT that the stages with higher secondary fracture proportions have more high-frequency components in the time-frequency diagram.

Influence of bedding on fracture toughness and failure patterns of anisotropic shale

The initiation and propagation of hydraulic fractures are closely related to the fracture ability of rocks. Such processes in shale reservoirs are, to a certain extent, controlled by bedding. However, the control mechanism of bedding on the anisotropy of fracture toughness and fracturing behavior remains unclear. In this study, a series of numerical notched semi-circular bend (NSCB) tests are conducted using the discrete element method (DEM) to investigate the influence of bedding properties on the anisotropy of fracture toughness and fracture patterns. Based on the DEM framework, a novel simulation method is proposed to accurately identify two key fracture indicators, the fracture process zone (FPZ) and crack tip opening displacement (CTOD), to reveal the fracture driving mechanism. The results show that the fracture toughness of shale is negatively correlated with bedding angles β but positively correlated with bedding spacing and bedding strength. Both the bedding strength and spacing significantly influence the fracture pattern of the specimens with β = 0°–60°, whereas the specimen with β = 90° is scarcely affected by the bedding planes. The evolution of the CTOD and FPZ in shale exhibits distinct phased characteristics. Due to the strong suppression effect of low-angle bedding planes on pre-peak crack deflection, the CTOD and FPZ exhibit opposite trends with respect to bedding angles before and after the peak load. This study facilitates the understanding of the fracture propagation process of anisotropic shale and could provide guidance for hydraulic fracturing design in shale reservoirs.

High-Order Models for Gas Transport in Multiscale Coal Rock.

The coal reservoirs exhibit great heterogeneity and strong anisotropy in multiscale pore/fracture structures. Developing highly accurate multiscale models for real-time prediction of microgaseous flow in complicated porous media with pronounced contrast in transport coefficients is crucial but not yet available, which is time-consuming, expensive, and even computationally impossible. In this study, a multiscale approximate solution of the gas flow and pressure field is derived in this paper for predicting coalbed methane (CBM) transport in macro-microscopic two-scale porous media of typical coal rocks in Guizhou Province, China, and the detailed finite element algorithm is established. The multiscale approximate solutions are constructed from the first- and second-order auxiliary cell functions and low- or high-order derivatives of the homogenized pressure field, which can accurately approximate the solution of the original problem to a certain extent. The numerical accuracy and validity of the multiscale approximate solutions under various working conditions are analyzed in detail by comparing and verifying the results with the direct numerical simulation results of fine-mesh high-precision finite elements. The results show that the homogenized approximate solution can only roughly capture the characteristics of the macroscopic pressure evolution, the first-order approximate solution can partially reproduce the macro-microscopic pressure oscillation phenomenon, and the second-order approximate solution can accurately predict the pressure profile and its evolution law with time in porous media with macro-micro configuration under various complex conditions. The second- and high-order two-scale approximate solutions constructed in this paper exhibit high numerical accuracy and excellent computational efficiency. We also develop multiscale approximate solutions for predicting microgaseous flow at a low reservoir pressure where the slippage effects are very pronounced. Potential applications of our high-order models to the coal reservoirs with a hierarchical matrix and fractures are discussed. The developed multiscale models exhibit excellent applicability to investigating the crossflow effects and coupling mechanisms between the matrix and cleats or fractures with multiple configurations in the CBM and shale gas reservoirs, which is crucial for the effective implementation of hydraulic fracturing technology. This study provides a fundamental understanding of gas transport in multiscale matrix-fracture networks, which helps to improve the optimization design of hydraulic fracturing in tight reservoirs.

A general framework to optimize fracture parameters in tight gas reservoir of heterogeneous channel sand bodies

Optimizing fracture parameters can unlock the potential of tight gas reservoirs. Various frameworks have been proposed as efficient optimization tools. However, current frameworks are mostly aimed at regular rectangular oil or gas reservoirs. The effect of heterogenous channel sand bodies on fracture parameter optimization has not been discussed. Here, we proposed a general optimization framework. The first step is to establish a heterogeneous channel sand bodies model based on image processing and data interpolation methods. The second step is to couple optimization algorithm and reservoir simulator to optimize fracture parameters. Then the framework is applied to two actual wells in Shaximiao Formation in Sichuan Basin in China. Results show that, the effect of channel sand body on the fracture optimization cannot been ignored. The optimal fractures tend to be concentrated in areas with good physical properties and large control areas. The sand body boundary has a significant control effect on the fracture half-length. For both fracture length and conductivity, double dumbbell shape is better than uniform shape. Our general framework serves as an efficient tool to optimize fracture design in heterogeneous channel sand body, which plays a growing role in enhancing tight gas recovery.

The in situ stress prediction of a fractured shale reservoir based on amplitude variation with angle and azimuth inversion: A case study from Southwest China

In situ stress estimation of a shale reservoir is critical for the design of shale hydraulic fracturing and wellbore stability analysis. Fractured shales have orthogonal anisotropy (OA) because of the presence of vertical fractures and lamination. However, the existing in situ stress estimation method mainly focuses on transversely isotropic media. To accommodate orthogonally anisotropic media, an in situ stress estimation method is developed by using amplitude variation with angle and azimuth inversion and linear-slip theory. First, an orthogonal anisotropic medium is introduced to characterize the fractured shale by using a linear-slip model, and then we formulate a reflection coefficient approximation for OA media to perform the seismic inversion. Next, a fracture weakness inversion strategy that incorporates the vertically transverse isotropic background is developed to obtain the stiffness matrix of the media. Finally, the in situ stresses of the OA medium are formulated by using a stress-strain relationship. Inversion tests and a real data application indicate that our method is effective.

Optimization of Supercritical CO2 Fracturing Based on Random Forest-Particle Swarm Optimization Model and Pre-existing Fracture Network

Summary On a global scale, shale oil/gas has become an important alternative energy source for conventional oil and gas. The potential advantages of supercritical CO2 (ScCO2) make it an ideal alternative to hydraulic fracturing, used for shale reservoir transformation and production increase while also promoting the geological storage of CO2, which is in-line with today’s carbon capture, utilization, and storage technology and helps to address the challenges of global climate change. To further study the fracture propagation and optimization of a complex fracture network (CFN) in ScCO2 fracturing under complex geological conditions using the cohesive module of ABAQUS to establish a fluid structure coupling model and completing indoor and field experimental verification, we introduce the global embedded cohesion zone model (CZM) combined with Python to generate two natural-fracture (NF) distribution models, conjugate and power law, to establish a dispersed mesh model. Based on this model, we studied the fracture propagation problem of ScCO2 fracturing under different engineering and geological conditions. The simulation results will be used as data-driven data to establish an optimization model of the random forest-particle swarm optimization algorithm (RF-PSO) and optimize the CFN. Research has shown that (1) ScCO2 is more inclined to pass through NFs and propagate in the rock matrix, and hydraulic fractures (HFs) combine better with NFs. Compared with hydraulic fracturing, ScCO2 fracturing has significant advantages (only the fracture width is lower than hydraulic fracturing, its initiation pressure and fracture length are much better than hydraulic fracturing, and there are more small fractures, making it easier to form a CFN). (2) During the process of fracture propagation, once dominant fractures form, the trend of the “Matthew effect” is inevitable. The process of fracture propagation is influenced by multiple factors, especially the distribution of NFs; the larger the reservoir filtration coefficient is, the more ScCO2 fracturing fluid that is lost, which is more unfavorable for fracturing construction. While maintaining the same amount of fracturing fluid injection, as the displacement increases, the fracture complexity increases, and the fracturing control range expands. Compared with other parameters, the effect of fracturing fluid temperature (FFT) on the expansion of ScCO2 fracturing fractures is not significant. (3) The established RF-PSO optimization model has an error of 2.89%, which can well adapt to CFN optimization problems under complex NF conditions and reduce uncertainty. We propose in this article a research method for fracture network optimization from fracture modeling, dynamic simulation, and optimization modeling. By combining numerical simulation and machine learning, the CFN optimization design of ScCO2 fracturing under CFN conditions is achieved, providing a research approach for the optimization of fracturing in fractured reservoirs.

A New Correlation for Estimating Static Elastic Properties of Sandstone Formations: Case Study from Rumaila Oilfield

Evaluating the elastic characteristics of reservoir's rocks is crucial for the oil and gas sector to reduce risks throughout drilling and production operations. Elastic parameters are essential for prediction of wellbore stability, estimation of in-situ stresses, optimization of drilling performance and design of hydraulic fracturing. Depending on the type of formation, Elastic parameter is varied dramatically. Thus, a precise way to identify these characteristics is needed. Inaccurate assessment of elastic characteristics can result in excessive expenditure and inappropriate field development plans. Static elastic modulus (Est) can be determined through laboratory testing. Although laboratory measurement is the most precise approach to determine the elastic modulus, it requires a continuous core sample to acquire a complete profile of the formation's elastic characteristics. However, just a portion of the well is typically sampled for cores. On the other hand, wireline log data is applied to determine the dynamic modulus (Edyn), allowing for continuous assessment of elastic properties. Numerous characteristics of the rock, including consolidation, pore pressure and lithology affect the dynamic modulus. Thus, it needs to be converted to Static elastic modulus by empirical formulae. Several empirical equations have been proposed to convert dynamic Young's modulus to static Elastic modulus. Nevertheless, the validity of these relationships is restricted and exclusive to certain areas. This research seeks to establish a relationship between Dynamic modulus and static Elastic modulus for sandstone formation of Rumaila oil field. The suggested correlation provides accurate predictions of the static elastic modulus for the complete sandstone segment. The newly created correlation performed better than the previous correlations in predicting static elastic modulus with average absolute error of 8.69 %, and correlation coefficient of 0.9848. The newly established empirical correlation can assist geo-mechanical engineers in estimating continuous profile of the sandstone formation's static modulus.

A New Approach to a Fracturing Sweet Spot Evaluation Method Based on Combined Weight Coefficient Method—A Case Study in the BZ Oilfield, China

The Sha3 member of the BZ Oilfield in Bohai Sea represents a typical ultra-low permeability thin interbedding reservoir. Hydraulic fracturing is an effective method for increasing oil and gas production. However, the complex geological conditions make it difficult to screen out the optimal frac spot. Consequently, the design of hydraulic fracturing exhibits certain limitations. A novel method for evaluating sweet spots is proposed, based on a refined geological reservoir model that considers the varying degrees of influence that geological and engineering factors have on fracturing effectiveness. This method utilizes grey correlation and hierarchical analysis to quantify and characterize the weight coefficients of each factor, ultimately leading to a combined weight coefficient approach. The results indicate that permeability and fracturing scale are the primary factors that impact the post-frac production of the BZ oilfield, with their respective combined weights being 0.33 and 0.25. The average weight for geological factors is 0.18, while for engineering factors it is 0.15. This suggests that geological factors have a greater influence on production than engineering factors. Furthermore, the correlation coefficient between the dual sweet spot index and the production is 0.96, indicating a strong positive correlation between the two variables. After comparing the predicted and actual production of each well, it was determined that the anastomosis rate is 80%. This finding holds significant guiding significance for selecting the optimal fracturing spot.

Research on Horizontal Well Multi-Fracture Propagation Law under the Synergistic Effect of Complex Natural Fracture and Reservoir Heterogeneity

Conventional fracturing design generally only considers the propagation of a single fracture in homogeneous storage, but the heterogeneity characteristics of the reservoir and the development of complex natural fractures will affect the fracturing effect. In order to study the horizontal well fracture propagation law under the synergistic effect of complex natural fracture reservoir heterogeneity, the globally embedded cohesive element finite model is established, and the heterogeneous reservoirs are built by Python programming. The influencing factors of multi-fracture propagation with heterogeneous reservoirs are analyzed, including the in situ stress difference, the injection rate of fracturing fluid, the perforation spacing, and the perforating clusters number. The results show that the heterogeneity and the natural fracture of the reservoir will affect the in situ stress distribution and propagation direction. When the in situ stress difference is low, the reservoir heterogeneity and natural fractures have a great influence on the fracture morphology. With the increase in injection rate, the fracture length and fracture width increase. With the in situ stress difference increase, the fracture deflection angle decreases. With the increase in fracturing fluid injection rate, the fracture length increases. The number of hydraulic fractures communicating with natural fractures increases with the natural fracture number and the number of perforation clusters under the synergistic effect of complex natural fracture and reservoir heterogeneity.

Analysis of Critical Instability Conditions for Solid-Phase Plugging of Natural Fractures during Temporary Plugging and Fracturing.

Hydraulic fracturing has become a key technology for the development of unconventional oil and gas resources, such as deep shale. Due to the development of natural fractures in deep shale reservoirs, the opening of natural fractures during the fracturing process can cause a significant loss of fracturing fluid, resulting in a reduction in the width of the main fracture and construction risks, such as sand plugging. It is important to improve the fracturing effect of deep shale reservoirs by plugging natural fractures with solid phases, reducing filtration, and improving the efficiency of the fracturing fluid. Ensuring the effectiveness of solid plugging is key to optimizing the fracturing design and improving the stimulation effect after fracturing. In this study, solid plugging technology is introduced into the filtration control process of natural fractures. By setting a plugging zone with a certain length and permeability inside the natural fracture, a stability prediction model for the plugging zone of natural fractures is established, and the instability conditions of the plugging zone are analyzed. The simulation results indicate that the instability of the plugging zone is related to permeability and there is a critical permeability. When the permeability of the plugging zone is greater than this value, expansion instability will occur, and when it is less than or equal to this value, shear slip instability may occur. The strength of shear slip instability is mainly determined by the length of the plugging zone, the friction angle of the natural fracture surface, the friction angle between the plugging particles, and the porosity of the plugging zone. The friction angle of natural fracture surfaces affects only the strength of slip instability, while the friction angle of plugging particles and porosity mainly affect the strength of shear instability. The research results provide a theoretical basis for the optimization of fracturing construction parameters in deep shale reservoirs.

Real-time monitoring of rock fracture by true triaxial test using fiber-optic strain monitoring in adjacent wells

The real-time monitoring of fracture propagation during hydraulic fracturing is crucial for obtaining a deeper understanding of fracture morphology and optimizing hydraulic fracture designs. Accurate measurements of key fracture parameters, such as the fracture height and width, are particularly important to ensure efficient oilfield development and precise fracture diagnosis. This study utilized the optical frequency domain reflectometer (OFDR) technique in physical simulation experiments to monitor fractures during indoor true triaxial hydraulic fracturing experiments. The results indicate that the distributed fiber optic strain monitoring technology can efficiently capture the initiation and expansion of fractures. In horizontal well monitoring, the fiber strain waterfall plot can be used to interpret the fracture width, initiation location, and expansion speed. The fiber response can be divided into three stages: strain contraction convergence, strain band formation, and postshutdown strain rate reversal. When the fracture does not contact the fiber, a dual peak strain phenomenon occurs in the fiber and gradually converges as the fracture approaches. During vertical well monitoring in adjacent wells, within the effective monitoring range of the fiber, the axial strain produced by the fiber can represent the fracture height with an accuracy of 95.6% relative to the actual fracture height. This study provides a new perspective on real-time fracture monitoring. The response patterns of fiber-induced strain due to fractures can help us better understand and assess the dynamic fracture behavior, offering significant value for the optimization of oilfield development and fracture diagnostic techniques.