Fractured Tight Reservoirs Research Articles

Investigation of In Situ Gelation Behavior and Enhanced Oil Recovery Ability of Polymer Gel Used for Controlling CO2 Channeling in Tight Fractured Reservoir.

Polymer gels are one of the most common plugging agents used for controlling CO2 channeling and improving sweep efficiency and oil recovery in tight fractured reservoirs. However, the in situ gelation behavior and enhanced oil recovery ability of polymer gel in fractured porous media is still unclear. Thus, in this study, the bulk and in situ gelation behavior of crosslinked phenolic resin gel in a long stainless microtube as the fractured porous media was investigated. The enhanced oil recovery ability of phenolic resin gel used for CO2 channeling was investigated by means of a fractured core model. Results show that, with the increase of polymer and crosslinker concentrations, the bulk gelation time shortens and gel strength improves during the static gelation process. With the increase of polymer concentration and temperature, the in situ static gelation time and dynamic gelation time of the gel system in the microtube are shortened, and the breakthrough pressure gradient increases after gelation. Compared with the in situ static gelation behavior, the in situ dynamic gelation time is prolonged and the breakthrough pressure gradient decreases after gelation. The in situ static gelation time in the microtube is 1.2 times that of bulk gelation time in an ampoule bottle, and the in situ dynamic gelation time is nearly 3 times that of ampoule bottles. When the injected slug volume was 1.0 FV (fracture volume), as the polymer concentration increased from 3000 mg·L-1 to 4000 mg·L-1, the incremental oil recovery increased from 3.53% to 4.73%.

Comparative Study on Artificial Fracture Modeling Schemes in Tight Reservoirs—For Enhancing the Production Efficiency of Tight Oil and Gas

In order to improve the reliability of the deployment of production schemes after artificial fracturing in tight reservoirs, it is urgent to carry out research on the description of fractures after artificial fracturing. In this study, taking the Chang 61 oil formation group in the Wangyao South area of Ordos Basin as an example, three different fracture modeling schemes are used to establish the geological model of fractured reservoirs, and the fitting ratios of the respective reservoir models are calculated by using the method of reservoir numerical simulation of the initial fitting, and the optimal fractured reservoir modeling scheme is screened in the end. The research area adopts three types of fracture prediction results based on FMI fracture interpretation data, seismic fracture prediction data, and rock mechanics artificial fracturing simulation data. On this basis, geological models of fractured reservoirs are established, respectively. The initial fitting of reservoir values of each geological model are compared, and the highest initial fitting rate of reservoir values is 88.44%, which is based on rock mechanics artificial fracturing simulation data. However, the initial fitting rate of the reservoir model was the lowest at 75.76%, which was established based on the fracture random modeling results of FMl fracture interpretation data. Under the constraints of seismic geostress prediction results and microseismic monitoring data, the simulation results of rock mechanics artificial fracturing fracture are used as the basis, on which the geological model of artificially fractured reservoirs is thus established, and this scheme can more realistically characterize the characteristics of fractured reservoirs after artificial fracturing in the study area.

Correlation between comprehensive evaluation method for fracture complexity in tight reservoirs post-fracturing and production capacity

The complexity of post-fracturing fractures in tight reservoirs is critical for evaluating fracturing effectiveness and is also a significant factor influencing well productivity. Currently, some scholars have utilized an improved G function to study the complexity of hydraulic fractures after fracturing. However, in certain specific construction curves, the characteristics and values of the G function alone are insufficient for comprehensive interpretation. To conduct a more thorough analysis of fracture complexity, this study introduces net pressure and liquid efficiency—parameters related to fracture complexity—based on the G function, and performs statistical analysis. Since the G function curve morphology is image data, it is not suitable for quantitative analysis. Therefore, digital calibration was conducted based on its corresponding morphological features to render it amenable to data analysis. Using Principal Component Analysis (PCA), a comprehensive fracture complexity coefficient was proposed, which considers four parameters: the digital calibration of the G function curve, G function characteristic values, net pressure, and liquid efficiency. The relationship between this coefficient and productivity was examined through Pearson and Spearman correlation analyses, utilizing post-fracturing production data from 26 wells in the Dabei block for validation. The results indicate a significant positive correlation between the comprehensive fracture complexity coefficient and productivity, with a high degree of correlation. This method not only addresses the shortcomings in interpreting certain specific construction curves but also provides a more comprehensive quantitative characterization of fracture complexity. Preliminary validation confirms the applicability of the method, offering valuable insights for evaluating post-fracturing effectiveness.

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 Morphological Method for Predicting Permeability in Fractured Tight Sandstone Reservoirs Based on Electrical Imaging Logging Porosity Spectrum

Summary Permeability is a crucial parameter in formation evaluation, which reflects reservoir fluid mobility and directly influences subsequent development and production. In conventional to tight sandstone formations without fractures, numerous methods have been developed to predict permeability. However, permeability prediction accuracy based on the current method is low in fractured tight sandstone reservoirs due to the influence of heterogeneity, and little research is focused on permeability evaluation in such reservoirs. Conventional wireline and nuclear magnetic resonance (NMR) logging lose their role in fracture parameter evaluation, whereas electrical imaging logging is available for reflecting fracture information. Hence, we adopt electrical imaging logging, instead of conventional wireline and NMR logging, to predict permeability in fractured tight sandstone reservoirs. In this study, we propose a morphological method for permeability prediction using electrical imaging logging. Initially, we process the electrical imaging logging data to obtain the porosity spectra and determine the peak of the primary porosity spectrum. We then extract the mean and standard deviation of the primary porosity spectrum based on its distribution morphology. Meanwhile, we also use the normal distribution function to fit the primary porosity spectrum and accumulate the amplitudes of the original and fitted porosity spectra, respectively. When the cumulative amplitude of the fitted spectra stabilizes, the corresponding porosity indicates the boundary between primary and secondary pores. This boundary allows us to calculate the proportion of primary pores to total pores. Permeability in fractured tight sandstone formations is influenced by both primary and secondary pores, showing a strong correlation with the proportion of primary porosity. Finally, we establish a permeability prediction model based on total porosity and the proportion of matrix pores. The reliability of our established permeability evaluation model is confirmed by comparing the predicted permeabilities with core-derived results in the Triassic Chang 63 Member of the Jiyuan area in the Ordos Basin. In unfractured formations, the predicted permeability based on our raised model closely matches the results derived solely from total porosity. In fractured formations, however, the calculated permeability using our proposed model aligns more closely with the core-derived result, while predictions based on current and NMR models tend to underestimate permeability.

Study on enhanced oil recovery improvement of fractured tight reservoir at extra high water cut stage

Study on enhanced oil recovery improvement of fractured tight reservoir at extra high water cut stage

Method for predicting the injection pressure for horizontal wells in fractured tight sandstone reservoirs

Hydraulic fracturing and horizontal well drilling are the key technologies for increasing the production of continental tight sandstone reservoirs. Taking the typical fractured tight sandstone in the Yuan-287 block of the Ordos Basin as an example, a reservoir geologic model is established based on the stratigraphic correlation of 206 wells. The model and 3D paleostress field are combined to predict fracture parameters such as fracture density and strike. Using reservoir breakdown pressure (RBP) monitoring data and other data such as reservoir physical and mechanical parameters, tectonic fracture characteristics, and in situ stress parameters, a quantitative evaluation model of the RBP, which predicts the 3D distribution of RBP, is established via stepwise regression, and the factors controlling the RBP are analyzed. The rock P-wave velocity, horizontal minimum principal stress, and fracture density are found to be three key parameters that control the breakdown pressure of this tight sandstone reservoir. By comparing the fracture opening pressure of subsurface tectonic fractures with the RBP, a new method for predicting the optimal water injection pressure of this reservoir is developed. This work provides a valuable evaluation model for accelerating the efficient development of continental tight sandstone reservoirs.

New Model for Predicting Production Capacity of Horizontal Well Volume Fracturing in Tight Reservoirs.

Production prediction is the most important and comprehensive index to measure the effect of oilfield development, and it is also one of the most fundamental problems in oilfield dynamic analysis. However, the recovery prediction is often affected by many factors. Usually, the recovery is predicted by core experiments, numerical simulations, and mathematical models. The main problem is accurately predicting reservoir recovery based on existing data. This paper proposes a comprehensive prediction model for the problem of recovery. First, the correlation coefficients between 14 factors and recovery were calculated based on Pearson, Spearman, gray correlation, variance selection, univariate selection method, and tree model. Second, the weights of the factors were determined using entropy weighting, CRITIC, and hierarchical analysis to clarify the degree of contribution of different factors to the recovery. Finally, a comprehensive evaluation model was established based on the results of the weighting analysis. The results indicate that the correlation coefficient and weight of porosity, permeability, oil saturation, well spacing, cluster spacing, total fluid volume, and horizontal section length are the most relevant to the recovery. The error between the comprehensive evaluation model and the actual results is less than 3%. Therefore, the method can predict the production capacity of the tight reservoirs. The research results of this paper are of guiding significance for improving the recovery of tight reservoirs.

The role of physical lost circulation materials type on the evolution of strong force chains of plugging zone in deep fractured tight reservoir

The selection of physical lost circulation materials (LCMs) type plays a crucial role in formulating effective plugging slurry. The structural stability of the plugging zone, formed by LCMs, is a decisive factor in determining their effectiveness in deep fractured reservoirs. In this study, combined with the Hertz contact model and calibration of contact forces of photoelastic particles, the color gradient mean square method was employed to quantitatively characterize the strong force chains evolution of the three typical types of plugging zones. Results showed that the incorporation of flexible particles into the LCMs enhanced the average shear strength, increased the proportion, and promoted the development of circular structures within the strong force chains, thereby facilitating stronger shear stability. This research provides new insight to understand the role of physical LCMs type on the mesoscale failure mechanism of plugging zone in deep fractured tight reservoir.

An innovative fracture plugging evaluation method for drill-in fluid loss control and formation damage prevention in deep fractured tight reservoirs

Lost circulation, resulting from the undesired loss of drilling fluid into formation fractures, stands as a significant technical obstacle in the exploration and production of oil, gas, and geothermal reservoirs. Effective mitigation of this challenge requires the development and application of robust experimental evaluation methods to assess the effectiveness of fracture plugging. The traditional approach to fracture plugging evaluation relies on a uniform evaluation index and experimental parameters for various lost circulation types. Unfortunately, this practice frequently results in inconsistent performance of loss control formulas during laboratory experiments and field tests. To address this issue, this paper introduces an innovative evaluation method that accounts for the specific characteristics of the three major lost circulation types. By adopting this approach, a more scientifically rigorous design and optimization of loss control formulas can be achieved, ensuring their effectiveness in managing lost circulation challenges. The development of the new method involves a systematic five-step establishment process: lost circulation type determination, evaluation index weight calculation, fitness degree analysis between laboratory experiment and field test, experimental parameters optimization, and quantitative scoring of loss control formula. Analytic hierarchy process is adopted to calculate the evaluation index weight. Quantitative scoring model is proposed to finally determine the integrated formula score for the quantitative evaluation and scientific optimization of loss control formula. To bridge the gap between laboratory and field applications, laboratory evaluation tests are developed to address different types of lost circulation scenarios. The experimental results demonstrate significant improvements achieved through the optimized formula. Specifically, the maximum plugging pressure increased from 5 MPa to 20.8 MPa, while the initial and cumulative loss volumes witnessed reductions of 30.3 ml and 121.2 ml, respectively. Moreover, the evaluation method proposed in this paper exhibits a fitting degree of over 90 % when compared to the actual control effect on drilling fluid loss. These findings substantiate the successful establishment of a connection between laboratory evaluations and field performance, providing valuable insights for future applications. Finally, a novel evaluation method for assessing the fracture plugging effect is established, accounting for various lost circulation types in deep fractured tight reservoirs. The reliability of this proposed evaluation method is validated by field test. Building upon this method, a high-score formula is designed and effectively deployed in a deep fractured tight reservoir in Tarim Basin, China. The successful application highlights the practical value and robustness of the developed evaluation method, offering promising prospects for future operations in similar reservoir settings.

Mechanical Study and Key Parameter Optimization of Temporary Plugging Fracturing in Tight Reservoirs

Staging fracturing with balls for temporary plugging is a crucial technique used to stimulate deep reservoirs. However, the transport of matter confined in a trap is very complicated. To investigate the influence of various factors on the force exerted by the ball sealer during the construction of the temporary plug, we analyse the ball sealer migration in three stages: before, after, and after the pump is stopped. We examine the effect of density, viscosity, displacement, number of holes, and fracturing fluid viscosity on the confined force state of the spherical sealer. Based on a model of entrainment dynamics with three stress states, we analyse the motion and force properties of the sphere. With this analysis, we have identified the main factors that affect the force exerted by the ball sealer. Our findings suggest that reducing the number of holes, especially when using high displacement and high viscosity fracturing fluids, can optimize the force state of the plug sphere and increase the plug efficiency. This conclusion provides a theoretical foundation for the formulation and optimization of a staged FRAC construction scheme with plug balls.

A New Method for Evaluating Fracability Based on Cluster Analysis and Well Logging Petrophysical Facies Division

The fracability of rock is a crucial parameter in determining the efficiency of fracturing in tight reservoirs. However, current methods for evaluating fracability have significant limitations. This paper proposes a new method for evaluating reservoir fracability based on cluster analysis of logging petrophysical facies. This method considers rock mechanics characteristics, petrophysical response characteristics, and reservoir physical parameters, among other factors. The Well X of the block was used as the research subject. Using the brittleness index and permeability evaluation index, the reservoir fracability of the target block is classified into five categories: high brittleness and low permeability rock, high brittleness and super low permeability rock, low brittleness and low permeability rock, low brittleness and super low permeability rock, and clay/shale. Geolog software is used to generate fracability prediction profiles for representative wells based on petrophysical facies. To further validate this evaluation method, the fracture construction data and microseismic monitoring interpretation results of Well Y in a tight block of an oil field were synthesized and analyzed to predict its fracability. The overall prediction accuracy reached 81.8%, indicating that the new fracability evaluation method has good application effect.

The non-plane initiation and propagation mechanism of multiple hydraulic fractures in tight reservoirs considering stress shadow effects

Multi-cluster fracturing in horizontal wells is an important stimulation technology for unconventional tight reservoirs. The interference among multiple simultaneously growing hydraulic fractures results in a non-uniform fluid distribution into fractures and non-planar fracture geometries. In this paper, the competition mechanism between perforations under the stress shadow, the formation mechanism of complex non-plane fractures near the wellbore, and the initiation and propagation mechanism of multiple hydraulic fractures are investigated by using the 3D lattice method. Also, the effects of fracture geometry, fracture spacing and rock mechanics parameters on the stress interaction among fractures are analyzed by the dislocation theory. The results showed the complexity of fracture initiation near the wellbore and the low efficiency of the perforation initiation in the case of spiral perforation, due to a strong interaction between perforations. However, these initial micro-cracks will eventually coalesce to be a macroscopical fracture which perpendicular to the direction of minimum principal stress. The study indicated that stress interaction and fracture propagation is significantly affected by inclined well orientation. The hydraulic fracture is more likely to deflect and propagate non-uniformly with the increasing width of hydraulic fracture, the decreasing spacing between perforation clusters and the increasing rock modulus. When the horizontal principal stress difference is small, it is obvious to cause a large deflection angle and sometimes furcation of fractures. This study can provide a theoretical basis and technical guidance for hydraulic fracturing design in tight reservoirs.

New Insights into Fracture Porosity Estimations Using Machine Learning and Advanced Logging Tools

Fracture porosity is crucial for storage and production efficiency in fractured tight reservoirs. Geophysical image logs using resistivity measurements have traditionally been used for fracture characterization. This study aims to develop a novel, hybrid machine-learning method to predict fracture porosity using conventional well logs in the Ahnet field, Algeria. Initially, we explored an Artificial Neural Network (ANN) model for regression analysis. To overcome the limitations of ANN, we proposed a hybrid model combining Support Vector Machine (SVM) classification and ANN regression, resulting in improved fracture porosity predictions. The models were tested against logging data by combining the Machine Learning approach with advanced logging tools recorded in two wells. In this context, we used electrical image logs and the dipole acoustic tool, which allowed us to identify 404 open fractures and 231 closed fractures and, consequently, to assess the fracture porosity. The results were then fed into two machine-learning algorithms. Pure Artificial Neural Networks and hybrid models were used to obtain comprehensive results, which were subsequently tested to check the accuracy of the models. The outputs obtained from the two methods demonstrate that the hybridized model has a lower Root Mean Square Error (RMSE) than pure ANN. The results of our approach strongly suggest that incorporating hybridized machine learning algorithms into fracture porosity estimations can contribute to the development of more trustworthy static reservoir models in simulation programs. Finally, the combination of Machine Learning (ML) and well log analysis made it possible to reliably estimate fracture porosity in the Ahnet field in Algeria, where, in many places, advanced logging data are absent or expensive.

A Volume Fracturing Percolation Model for Tight Reservoir Vertical Wells

Based on the non-linear seepage characteristics of tight reservoirs and the reconstruction mode of vertical wells with actual volume fracturing, a seven-area percolation model for volume fracturing vertical wells in tight reservoirs is established. Laplace transform and Pedrosa transform are applied to obtain analytical solutions of bottom hole pressure and vertical well production under a constant production regime. After verifying the correctness of the model, the influence of the fracture network parameters on the pressure and production is studied. The research results indicate that as the permeability modulus increases, the production of volume fracturing vertical wells decreases. The penetration ratio of the main crack and the half-length of the main crack have a small impact on production, while the diversion capacity of the main crack has a significant impact on the initial production, but it is ultimately limited by the effective volume of the transformation. Under constant pressure conditions, the greater the width and permeability of the ESRV region, the higher the vertical well production rate is. The smaller the aspect ratio of the ESRV region, the higher the mid-term yield and the faster the yield decrease. The research results show guiding significance for the design of vertical well volume fracturing in tight reservoirs.

An experimental study of CO2 injection strategies for enhanced oil recovery and geological sequestration in a fractured tight sandstone reservoir

Carbon dioxide enhanced oil recovery has been considered and tested in unconventional oil reservoirs due to its additional environmental benefits from simultaneous CO2 geological sequestration. However, it will require a proper injection strategy to overcome unfavorable sweep efficiency in CO2 displacement, which is even magnified in unconventional oil reservoirs due to strong heterogeneity caused by natural and artificial fractures. In this study, we investigated three immiscible CO2 injection strategies at reservoir conditions using tight fractured sandstone cores from the Ordos Basin, China: water alternative gas injection, cyclic CO2 injection, and CO2 foam/surfactant alternative gas injection. A pressurization and miscible CO2 injection were then added after each injection strategy to examine the influence of residual liquid distributions on the miscible displacement efficiency after the tested injection schemes. The core plugs with comparable porosity and permeability were selected, and all cores reached a similar recovery factor (∼11%) after primary CO2 flooding. We found that the cyclic CO2 injection had best performance, with the highest incremental and accumulative oil recovery at 23.6% and 32.26%. Its relatively higher sweep efficiency indicated a uniform CO2 distribution at the end of the cyclic injection, which further led to the highest incremental recovery of 4.94% in the following miscible injection. Comparable CO2 storage capacities were observed in the three fractured core samples (12.21%, 12.98%, and 9.71%, respectively) after completing the miscible displacements. In general, cyclic CO2 injection is recommended as an effective CO2 EOR and geo-storage in tight fractured rocks.

Main controlling factors of natural fractures in tight reservoirs of the lucaogou formation in the jimsar sag, Xinjiang, China

Natural fractures act as critical flow channels and reservoir space in the Lucaogou Formation tight reservoir of the Jimsar Sag. It is essential to identify the main controlling factors of natural fractures in order to achieve efficient development of tight oil in this area. There are mainly three types of natural fractures, including tectonic fractures, diagenetic fractures, and abnormal overpressure-induced fractures. Diagenetic fractures are predominantly bedding seams. The fracture development is affected by multiple factors including brittle minerals, lithology, tectonic stress, bed thickness, and total organic carbon (TOC). Large tectonic stress, smaller bed thickness, and higher total organic carbon are all favorable for the development of tectonic fractures and bedding seams. The controls of brittle minerals and lithology on fracture development are different for tectonic fractures and bedding seams. Specifically, carbonate minerals stimulate the tectonic fracture development, while brittle minerals have no control over the bedding seam development; tectonic fractures are most developed in the dolomitic rocks, while bedding seams are most developed in the argillaceous rocks. The calculated fracture density variation coefficients reveal that tectonic stress and brittle minerals are the main controlling factors of tectonic fracture development; total organic carbon and lithology are the main control factors of bedding seam development.

Productivity Analysis and Evaluation of Fault-Fracture Zones Controlled by Complex Fracture Networks in Tight Reservoirs: A Case Study of Xujiahe Formation

The development of tight gas reservoirs presents a significant challenge for sustainable development, as it requires specialized techniques that can have adverse environmental and social impacts. To address these challenges, efficient development technologies, such as multistage hydraulic fracturing, have been adopted to enable access to previously inaccessible natural gas resources, increase energy efficiency and security, and minimizing environmental impacts. This paper proposes a novel evaluation method to analyze the post fracturing productivity controlled by complex fault fracture zones in tight reservoirs. In this article, a systematic method to evaluate stimulated reservoir volume (SRV) and fault-fracture zone complexity after stimulation was established, along with the analysis and prediction of productivity through coupled fall-off and well-test analyses. Focusing on the Xujiahe formation in the Tongnanba anticline of northeastern Sichuan Basin, a 3D geological model was developed to analyze planar heterogeneity. The fall-off analytical model, coupled with rock mechanical parameters and fracturing parameters such as injection rates, fracturing fluid viscosity, and the number of clusters within a single stage, was established to investigate the fracture geometric parameters and complexities of each stage. The trilinear flow model was used to solve the well-test analysis model of multi-stage fractured horizontal wells in tight sandstone gas reservoirs, and well-test curves of the heterogeneous tight sandstone gas fracture network model were obtained. The results show that hydraulic fractures connect the natural fractures in fault-fracture zones. An analysis of the relationship between the fracture geometric outcomes of each segment and the net pressure reveals that as the net pressure in the fracture increases, the area ratio of natural fractures to main fractures increases notably, whereas the half length of the main fracture exhibits a decreasing trend. The overall area of natural fractures following stimulation is 7.64 times greater than that of the main fractures and is mainly a result of the extensive development of natural fractures in the target interval. As the opening ratio of natural fractures increases, the length of the main fractures decreases accordingly. Therefore, increasing net pressure within fractures will significantly enhance the complexity of fracturing fractures in shale gas reservoirs. Furthermore, the initial production of Well X1–10, which is largely controlled by fault-fracture zones, and the cumulative gas production after one year, are estimated. The systematic evaluation method in this study proposed a new way to accurately measure fracturing in tight reservoirs, which is a critical and helpful component of sustainable development in the natural gas industry.

Study on imbibition during the CO2 enhanced oil recovery in fractured tight sandstone reservoirs

Study on imbibition during the CO2 enhanced oil recovery in fractured tight sandstone reservoirs

New insights of further enhanced tight oil recovery after hydraulic fracturing by VES fracturing fluid

In the process of fracturing in tight reservoirs, viscoelastic surfactant (VES) fracturing fluid has many advantages that can significantly increase the recovery of tight oil. However, there is a risk of formation blockage due to heavy emulsification in the formation. In this study, a VES microemulsion (VES-M) system with low reservoir damage and high oil displacement efficiency is constructed using VES fracturing fluid and polyhydroxy alcohol. The average particle size in the fluid is only 3%–10% of the average pore size of the tight reservoir, and the formation damage is 16.00%. The new fluid can achieve ultra-low interfacial tension (IFT) with Winsor type III microemulsion. Compared with slickwater fracturing fluid and formation water, the new fluid can filtrate deeper into the matrix and increase the oil recovery by 7.20%–11.32% during the flowback process. This study provides a possibility for the field application of VES fracturing fluid in tight reservoirs and new insights into the effects and rules of employing the VES-M system to enhance tight oil recovery.