Search

The gas production of deep coalbed methane wells in Linxing-Shenfu block decreases rapidly, the water output is high, the supporting effect is poor, the effective supporting fracture size is limited, and the migration mechanism of proppant in deep coal reservoir is not clear at present. To investigate the migration behavior of proppants in complex fractures during the volume reconstruction of deep coal and rock reservoirs, an optimization test on the conductivity of low-density proppants and simulations of proppant migration in complex fractures of deep coal reservoirs were conducted. The study systematically analyzed the impact of various fracture geometries, proppant types and fracturing fluid viscosities on proppant distribution. Furthermore, the study compared the outcomes of dynamic proppant transport experiments with simulation results. The results show that the numerical simulation is consistent with the results of the proppant dynamic sand-carrying experiment. Under the conditions of low viscosity and large pumping-rate, a high ratio of 40/70 mesh proppant can facilitate the movement of the proppant to the depths of fractures at all levels. The technical goal is to create comprehensive fracture support within intricate trapezoidal fractures in deep coal and rock reservoirs without inducing sand plugging. The sand ratio is controlled at 15%–20%, with a proppant combination ratio of 40/70:30/50:20/40 = 6:3:1. Proppant pumping operations can effectively address the issue of poor support in complex fractures in deep coal formations. The research results have been successfully applied to the development of deep coalbed methane in the Linxing-Shenfu block, Ordos Basin. [ABSTRACT FROM AUTHOR]

Carbonate formation is the key reservoir in Sichuan Basin for natural gas development. Compared with the early stage of development, the burial depth of targeted formation becomes deeper, and the formation temperature gets higher. So, the characteristics of acidizing effectiveness in high-temperature carbonate formations make this evaluation slightly difficult. Currently, it is common that a single parameter is considered to study acidizing effectiveness by simulation and experiment methods. In this paper, for a more accurate investigation of acidizing effectiveness, multiple parameters, including permeability change rate, fracture conductivity, and surface roughness, were introduced by a series of experiments. It is revealed that the permeability change rate is more than 57% when using gelled acid. As the amount of diverting agent increases in diverting acid, the viscosity of the acid grows to its peak with the reaction, making it easier to block the high permeability core temporarily and divert to acidify the low permeability core, where the permeability change rate of the low permeability core goes from 51.6% to 64.2%, which shows well acidizing effectiveness. In addition, the short-term and long-term conductivity of the samples from the three different formations are more than 200 mD∙m under high closure stress. The conductivity of Maokou Formation is the largest due to its high content of carbonate minerals and high dissolution rate. And the results of long-term conductivity are consistent with those of surface roughness, making the evaluation results more reliable for acidizing effectiveness. It is worth noting that temperature is a factor that cannot be ignored in the evaluation of acidizing effectiveness because it has a great influence on the performance of the acid system, such as viscosity and the reaction-reduced rate, leading to an acidizing effectiveness affect. So, the temperature resistance of an acid system is important as well. [ABSTRACT FROM AUTHOR]

This work establishes an analytical model for determining the critical velocity for proppant flowback, and evaluates how proppant flowback affects fracture conductivity for tight reservoirs. The multiphase effects are considered for determining the critical velocity for proppant flowback before and after fracture closure, respectively. The model's performance is demonstrated by comparing the results against previous models. A finite-element model is built to simulate the proppant flowback process for a hydraulic-fractured well completed in the Ordos Basin. The change in fracture conductivity caused by proppant flowback for several scenarios with varying saturation and net pressure in fractures is further quantitatively assessed. Our results highlight the importance of multiphase effects in determining the critical velocity for proppant flowback at relatively low water saturation in fractures. The critical velocity generally increases with increasing water saturation in fractures and net pressure in fractures. At a flowback velocity higher than the critical value, the loss in fracture conductivity becomes relatively more pronounced at a lower water saturation in fractures and a lower net pressure in fractures. The findings of this work are expected to provide insights into the mechanisms of proppant flowback and flowback drawdown management for field operations in tight reservoirs. [ABSTRACT FROM AUTHOR]

In situ-generated acid is commonly employed in ultra-deep, high-temperature carbonate reservoirs during acid fracturing to increase the effective acid penetration distance. However, the variation pattern of acid-etched fracture conductivity with in situ-generated acid has not been systematically studied. This paper investigates the evolution of the conductivity of primary and secondary fractures through a series of experiments involving in situ acid displacement and acid-etched fracture conductivity measurement. Based on the experimental results, a calculation model for the conductivity of acid-etched fractures with in situ-generated acid was established. The study indicates that after acid etching, rough particulate points and grooved dissolution patterns form on the surfaces of primary and secondary fractures, respectively. The dissolution volume in primary fractures is greater than that in secondary fractures, with both showing a linear increase over time. Due to the presence of dissolution grooves on the surfaces of secondary fractures, their conductivity is higher than that of primary fractures under the same acid–rock contact time. The conductivity of both primary and secondary fractures increases with the acid–rock contact time. However, beyond approximately 70 min of contact time, the conductivity of primary fractures shows no significant increase. The conductivity of primary and secondary fractures with in situ-generated acid is slightly lower than that with gelled acid under the same contact time, but significantly higher than that with crosslinked acid. This study provides guidance for the design and parameter optimization of acid fracturing in ultra-deep, high-temperature carbonate reservoirs. [ABSTRACT FROM AUTHOR]

Abstract The hydraulic fracturing of shale reservoirs is an important topic, and adjusting the fracturing process can enhance fracturing efficiency. To analyze the effect of injection conditions on the fracture network structure and conductivity, numerical simulations and theoretical calculations are carried out based on the construction data, and the variation patterns of the fracture network parameters are determined. During the theory study, a fracture network conductivity model was obtained by combining the fracture network expansion model and the fracture diversion model. Then a numerical model was set up according to the analysis results of monitoring data. The numerical simulation results showed the fracture network structure and proppant distribution under different conditions. Throughout the simulation process, the structural parameters and conductivity of the fracture network can be determined by controlling the injection amount and adjusting the injection method, speed, and sand ratio. Results indicated that the proppant pulse frequency during the injection process was a major factor affecting the structure and conductivity of the fracture network. At the same time, a comparison of the distribution structure of the proppant revealed that although the intermittent injection of the proppant improved the flow channel, the efficiency of fracture utilization can still be improved.

Abstract\nHIGHLIGHTSThe formation of a complex fracture network with sufficient proppant conductivity is crucial for the efficient development of deep shale gas. Due to cost considerations, quartz sand has commonly replaced ceramic proppant in the field. However, the significant crushing of quartz sand and its distribution as multiple particle sizes both before and after crushing, termed as particle size redistribution, raises concerns about its ability to meet the demands of the fracture network. Based on contact mechanics, we developed an evolutionary equation for fracture width that considers particle size redistribution. The particle crushing is described using a fragmentation replacement method, and changes in specific surface area before and after crushing are used to correct the permeability model of the fracture. By integrating models of fracture width and permeability evolution, we have established an analytical model for proppant conductivity that accounts for quartz sand crushing and its particle size redistribution. Numerical simulations further validate the predictive accuracy of our model. Sensitivity analyses investigate the impact of quartz sand degree of crushing, compressive strength, particle size, particle combination ratio, and closure pressure on fracture conductivity, demonstrating the reliability of quartz sand as a substitute for ceramic proppant in deep shale applications.Developed a new model for fracture conductivity considering the embedding and crushing of multiple particle sizes of quartz sand in a proppant monolayer.Demonstrated the reliability of replacing ceramic proppants with quartz sand in deep oilfield applications through model studies.Provided an alternative evaluation method for selecting and optimising sand addition during construction based on reservoir conditions. [ABSTRACT FROM AUTHOR]

Proppant is one of the key materials for hydraulic fracturing. For special situations, such as middle-deep reservoirs and closure pressures ranging from 40 MPa to 60 MPa, using a single proppant cannot solve the contradiction between performance, which means crushing rate and fracture conductivity, and cost. However, using combined proppants is an economically effective method for hydraulic fracturing of such special reservoirs. Firstly, for different types, particle sizes, and proportions of combined proppants, various contact relationships between proppant particles are considered. The random phenomenon of proppant particle arrangement is described using the Monte Carlo method, and the deterministic phenomenon of proppant particles is processed using an optimization model, achieving computer simulation of the microscopic arrangement of proppant particles. Secondly, a mathematical model for the force analysis of combined proppant particles is established, and an improved singular value decomposition method is used for numerical solution. A computational model for the crushing rate and fracture conductivity of combined proppants is proposed. Thirdly, the numerical calculation results are compared and discussed with the test values, verifying the accuracy of the computational model. Finally, the application of combined proppants is discussed, and a model for optimizing the proportion of combined proppants is proposed. The onsite construction technology is introduced, and the cost and economic benefits of combined proppants are compared with those of all ceramic particles and excessive all-quartz sand. It is proved that combined proppants can balance performance and price, and are an economically effective method for hydraulic fracturing of special reservoirs. The research results can select the optimal proppant material and optimize the combination of different proppant types, which can help achieve cost reduction and efficiency increase in oil and gas development. [ABSTRACT FROM AUTHOR]

As a crucial exploration technique for unconventional reservoirs, hydraulic fracturing enables the formation of complex fracture networks, thereby facilitating the flow of oil and gas. The closure of natural fractures decreases stimulation performance. Microparticle proppants are used to fill natural fractures and effectively increase the stimulation area. The 100-mesh proppant conventionally used in field operations may be insufficiently small to effectively access natural fractures. In order to effectively overcome natural fractures closure, microparticle proppants (i.e., proppants with a diameter of 75 µm (200-mesh) or less) are required. The particle size threshold test of microparticle proppants placement is conducted to determine the size threshold of proppants flowing into natural fractures. The microparticle proppants placement experiment in multi-branch fractures is conducted to investigate the volume difference of proppants in different fractures. Numerical simulations are performed to model proppant transport within fractures of actual dimensions to facilitating the optimization of stimulation parameters. The main conclusions are as follows: (1) Effective inflow of microparticle proppants requires a size threshold of proppants. For the 200-mesh proppants, the size should be less than half of natural fractures width when microparticle proppants effectively flow into natural fractures. (2) Sand concentration affects the size threshold of microparticle proppants. The size threshold should appropriately increase to ensure the inflow of proppant. (3) Difference of multi-branch fracture width has a significant effect on volume of microparticle proppants inside fractures. When the width ratio of multi-branch fractures exceeds 2, this effect becomes obvious. (4) Particle size has an effect on proppant placement. 200-mesh proppants can obtain uniform distribution of proppants among natural fractures. 140-mesh proppants can obtain maximum proppant volume among natural fractures. Sand concentration significantly affects proppant placement performance. The optimal sand concentration is 60kg/m³. The pumping rate for a single cluster fracture should not be excessively low. The pumping rate should be larger than 0.5m³/min and the optimal pumping rate 2m³/min. In this paper, the particle size and concentration of particulate proppant are optimized and the geometric characteristics of fractures are considered. These conclusions provide important practical guidance and scientific basis for the optimization and application of hydraulic fracturing technology. [ABSTRACT FROM AUTHOR]

The hydraulic fracturing of shale reservoirs is an important topic, and adjusting the fracturing process can enhance fracturing efficiency. To analyze the effect of injection conditions on the fracture network structure and conductivity, numerical simulations and theoretical calculations are carried out based on the construction data, and the variation patterns of the fracture network parameters are determined. During the theory study, a fracture network conductivity model was obtained by combining the fracture network expansion model and the fracture diversion model. Then a numerical model was set up according to the analysis results of monitoring data. The numerical simulation results showed the fracture network structure and proppant distribution under different conditions. Throughout the simulation process, the structural parameters and conductivity of the fracture network can be determined by controlling the injection amount and adjusting the injection method, speed, and sand ratio. Results indicated that the proppant pulse frequency during the injection process was a major factor affecting the structure and conductivity of the fracture network. At the same time, a comparison of the distribution structure of the proppant revealed that although the intermittent injection of the proppant improved the flow channel, the efficiency of fracture utilization can still be improved. [ABSTRACT FROM AUTHOR]

The key performance parameters of proppant are mainly the crushing rate and fracture conductivity, which are usually evaluated using physical experimental methods. However, the testing method for fracture conductivity has limitations, such as its long time-consumption, high testing costs, instability, and even the presence of large errors in testing results under the same conditions. The purpose of this paper is to propose a calculation method that can replace physical experiments. Firstly, we analyze the random and deterministic phenomena in the contact relationship between proppant particles from a microscopic perspective. Subsequently, we develop a physical model of the microscopic arrangement of these particles, enabling us to conduct further computer simulations of their microscopic configuration. Secondly, we conduct a microscopic mechanical analysis of the contact between proppant particles and between particles and boundaries and establish a corresponding mathematical model. Then, utilizing the simulation and mechanical analysis results of the proppant, we calculate the crushing rate. Considering the crushing rate of proppant, we improve the Kozeny–Carmen equation to determine the fracture permeability, and subsequently calculate the fracture conductivity. Finally, the calculated results are compared with the experimental results. The results show that the calculated values for the proppant crushing rate and fracture conductivity matched well with experimental data, and that the model's calculation values were more accurate. As the number of simulations increased, the accuracy of the calculation results became higher. Research shows that the fracture conductivity is influenced by factors such as the particle size, microstructure, and crushing rate. Numerical calculation methods can replace physical experiments and provide theoretical support for engineering applications of hydraulic fracturing proppant materials. [ABSTRACT FROM AUTHOR]

The field stress of the shale affects the proppant embedment, fracture conductivity, well production rate, and ultimately the recovery of hydrocarbons from reservoir formations. This paper presents, for the first time, an experimental study investigating the mechanical characteristics of a shale under confining pressures that simulate the in situ stress state in deep reservoirs. Bidirectional but equal confining pressures were applied to the shale sample to replicate its field stress state. Microindentation tests were conducted to assess the alterations of mechanical properties resulting from the application of confining pressures. The results demonstrate a significant increase in Young's modulus, hardness, and fracture toughness for the samples subjected to confining pressure. Considering the effect of confining pressure, the decrease in proppant embedment is proportional to Young's modulus of the shale. For larger-sized proppants (e.g., D = 2.50 mm), the influence of confining pressure on fracture conductivity is relatively minor. However, when smaller-sized proppants (e.g., D = 1.00 mm) are used, particularly in scenarios involving shale debris swelling due to prolonged interaction with fracturing fluid, there is a noticeable improvement in fracture conductivity. Importantly, previous computational models have tended to overestimate proppant embedment depth while underestimating fracture conductivity. The findings from this study contribute to advancing the understanding of shale's mechanical characteristics under in situ reservoir conditions and support the optimization of proppant embedment and fracture conductivity calculation models for the efficient extraction of shale gas. [ABSTRACT FROM AUTHOR]

Geological carbon sequestration in jointed reservoirs will require the use of fracture network for the flow of CO2 plumes. However, acidic solution formed at the interface between brine and CO2 can cause chemical erosion of the local rock mass, especially in rocks with high carbonate content. The use of the water alternating gas technique for injection stimulation can exacerbate this issue, as the water–CO2 interface occurs in areas near the injection point. As a result, acidic flow can impact the surrounding rock mass, particularly around the main flow paths where fracture network conductivity is much higher than matrix permeability. To investigate the impact of acidic flow on fracture conductivity, we conducted an experiment on a fractured sandstone sample that was exposed to CO2-saturated water. Our findings revealed a nearly ten-fold increase in post-experimental water-relative permeability, and restriction of flow within established flow channels, which consist one third of the fracture surface. In conclusion, our study sheds light on the dynamic behavior of fractured sandstone under the influence of CO2–H2O flow, revealing significant changes in transmissivity and fracture geometry. These findings contribute to a better understanding of the hydraulic performance of fractures in the context of geological carbon sequestration. [ABSTRACT FROM AUTHOR]

As a crucial exploration technique for unconventional reservoirs, hydraulic fracturing enables the formation of complex fracture networks, thereby facilitating the flow of oil and gas. The closure of natural fractures decreases stimulation performance. Microparticle proppants are used to fill natural fractures and effectively increase the stimulation area. The 100-mesh proppant conventionally used in field operations may be insufficiently small to effectively access natural fractures. In order to effectively overcome natural fractures closure, microparticle proppants (i.e., proppants with a diameter of 75 ^m (200mesh) or less) are required. The particle size threshold test of microparticle proppants placement is conducted to determine the size threshold of proppants flowing into natural fractures. The microparticle proppants placement experiment in multi-branch fractures is conducted to investigate the volume difference of proppants in different fractures. Numerical simulations are performed to model proppant transport within fractures of actual dimensions to facilitating the optimization of stimulation parameters. The main conclusions are as follows: (1) Effective inflow of microparticle proppants requires a size threshold of proppants. For the 200-mesh proppants, the size should be less than half of natural fractures width when microparticle proppants effectively flow into natural fractures. (2) Sand concentration affects the size threshold of microparticle proppants. The size threshold should appropriately increase to ensure the inflow of proppant. (3) Difference of multi-branch fracture width has a significant effect on volume of microparticle proppants inside fractures. When the width ratio of multi-branch fractures exceeds 2, this effect becomes obvious. (4) Particle size has an effect on proppant placement. 200-mesh proppants can obtain uniform distribution of proppants among natural fractures. 140-mesh proppants can obtain maximum proppant volume among natural fractures. Sand concentration significantly affects proppant placement performance. The optimal sand concentration is 60kg/m3. The pumping rate for a single cluster fracture should not be excessively low. The pumping rate should be larger than 0.5m3/min and the optimal pumping rate 2m3/min. In this paper, the particle size and concentration of particulate proppant are optimized and the geometric characteristics of fractures are considered. These conclusions provide important practical guidance and scientific basis for the optimization and application of hydraulic fracturing technology. [ABSTRACT FROM AUTHOR]

The current worldwide energy supply is insufficient to meet the rising demand. As a result, the energy prices are expected to keep soaring despite the recent increases in a variety of renewable energy resources. Although not renewable, shale oil and gas — “unconventional” hydrocarbon resources are relatively clean forms of energy resources, which still hold a vast share of the energy market. For many oil and gas companies, meeting profitable production goals from shale reservoirs is sometimes challenging, due to the loss of fracture conductivity and premature declines in the production. In this paper we investigate the stress-dependent changes in the hydraulic conductivity of proppant-filled fractures and mechanical fracture–proppant interactions in Caney Shale, a calcareous, organic-rich mudrock, through laboratory experiments and numerical modeling. American Petroleum Institute (API) fracture conductivity tests were conducted using 2% KCl on five locations within the Caney Shale that consisted of selecting three brittle (reservoir) zones and two ductile zones. Confining pressures ranged from 1,000 psi to 12,000 psi at 210 °F. Conductivity, permeability as well as embedment were measured during the test. Also, an additional, laboratory in-situ visualization test was conducted to examine the detailed proppant-shale matrix interaction under elevated stress (3,920 psi effective stress) and temperature (252 °F), with a synthetic reservoir fluid. Our experimental results have confirmed that improved fracture conductivity is attributed to proppant size, and that the increase in porosity of the proppant pack, closure pressure changes and the reduction in fracture conductivity are a function of many factors such as fracture closure stress.

Deep and ultra-deep reservoirs have gradually become the primary focus of hydrocarbon exploration as a result of a series of significant discoveries in deep hydrocarbon exploration worldwide. These reservoirs present unique challenges due to their deep burial depth (4500e8882 m), low matrix permeability, complex crustal stress conditions, high temperature and pressure (HTHP, 150e200 °C, 105e155 MPa), coupled with high salinity of formation water. Consequently, the costs associated with their exploitation and development are exceptionally high. In deep and ultra-deep reservoirs, hydraulic fracturing is commonly used to achieve high and stable production. During hydraulic fracturing, a substantial volume of fluid is injected into the reservoir. However, statistical analysis reveals that the flowback rate is typically less than 30%, leaving the majority of the fluid trapped within the reservoir. Therefore, hydraulic fracturing in deep reservoirs not only enhances the reservoir permeability by creating artificial fractures but also damages reservoirs due to the fracturing fluids involved. The challenging "three-high" environment of a deep reservoir, characterized by high temperature, high pressure, and high salinity, exacerbates conventional forms of damage, including water sensitivity, retention of fracturing fluids, rock creep, and proppant breakage. In addition, specific damage mechanisms come into play, such as fracturing fluid decomposition at elevated temperatures and proppant diagenetic reactions at HTHP conditions. Presently, the foremost concern in deep oil and gas development lies in effectively assessing the damage inflicted on these reservoirs by hydraulic fracturing, comprehending the underlying mechanisms, and selecting appropriate solutions. It's noteworthy that the majority of existing studies on reservoir damage primarily focus on conventional reservoirs, with limited attention given to deep reservoirs and a lack of systematic summaries. In light of this, our approach entails initially summarizing the current knowledge pertaining to the types of fracturing fluids employed in deep and ultra-deep reservoirs. Subsequently, we delve into a systematic examination of the damage processes and mechanisms caused by fracturing fluids within the context of hydraulic fracturing in deep reservoirs, taking into account the unique reservoir characteristics of high temperature, high pressure, and high in-situ stress. In addition, we provide an overview of research progress related to high-temperature deep reservoir fracturing fluid and the damage of aqueous fracturing fluids to rock matrix, both artificial and natural fractures, and sand-packed fractures. We conclude by offering a summary of current research advancements and future directions, which hold significant potential for facilitating the efficient development of deep oil and gas reservoirs while effectively mitigating reservoir damage. [ABSTRACT FROM AUTHOR]

Copyright of Petroleum Geology & Oilfield Development in Daqing is the property of Editorial Department of Petroleum Geology & Oilfield Development in Daqing and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

This work establishes an analytical model for determining the critical velocity for proppant flowback, and evaluates how proppant flowback affects fracture conductivity for tight reservoirs. The multiphase effects are considered for determining the critical velocity for proppant flowback before and after fracture closure, respectively. The model’s performance is demonstrated by comparing the results against previous models. A finite-element model is built to simulate the proppant flowback process for a hydraulic-fractured well completed in the Ordos Basin. The change in fracture conductivity caused by proppant flowback for several scenarios with varying saturation and net pressure in fractures is further quantitatively assessed. Our results highlight the importance of multiphase effects in determining the critical velocity for proppant flowback at relatively low water saturation in fractures. The critical velocity generally increases with increasing water saturation in fractures and net pressure in fractures. At a flowback velocity higher than the critical value, the loss in fracture conductivity becomes relatively more pronounced at a lower water saturation in fractures and a lower net pressure in fractures. The findings of this work are expected to provide insights into the mechanisms of proppant flowback and flowback drawdown management for field operations in tight reservoirs.

Proppant is one of the key materials for hydraulic fracturing. For special situations, such as middle-deep reservoirs and closure pressures ranging from 40 MPa to 60 MPa, using a single proppant cannot solve the contradiction between performance, which means crushing rate and fracture conductivity, and cost. However, using combined proppants is an economically effective method for hydraulic fracturing of such special reservoirs. Firstly, for different types, particle sizes, and proportions of combined proppants, various contact relationships between proppant particles are considered. The random phenomenon of proppant particle arrangement is described using the Monte Carlo method, and the deterministic phenomenon of proppant particles is processed using an optimization model, achieving computer simulation of the microscopic arrangement of proppant particles. Secondly, a mathematical model for the force analysis of combined proppant particles is established, and an improved singular value decomposition method is used for numerical solution. A computational model for the crushing rate and fracture conductivity of combined proppants is proposed. Thirdly, the numerical calculation results are compared and discussed with the test values, verifying the accuracy of the computational model. Finally, the application of combined proppants is discussed, and a model for optimizing the proportion of combined proppants is proposed. The onsite construction technology is introduced, and the cost and economic benefits of combined proppants are compared with those of all ceramic particles and excessive all-quartz sand. It is proved that combined proppants can balance performance and price, and are an economically effective method for hydraulic fracturing of special reservoirs. The research results can select the optimal proppant material and optimize the combination of different proppant types, which can help achieve cost reduction and efficiency increase in oil and gas development.

The key performance parameters of proppant are mainly the crushing rate and fracture conductivity, which are usually evaluated using physical experimental methods. However, the testing method for fracture conductivity has limitations, such as its long time-consumption, high testing costs, instability, and even the presence of large errors in testing results under the same conditions. The purpose of this paper is to propose a calculation method that can replace physical experiments. Firstly, we analyze the random and deterministic phenomena in the contact relationship between proppant particles from a microscopic perspective. Subsequently, we develop a physical model of the microscopic arrangement of these particles, enabling us to conduct further computer simulations of their microscopic configuration. Secondly, we conduct a microscopic mechanical analysis of the contact between proppant particles and between particles and boundaries and establish a corresponding mathematical model. Then, utilizing the simulation and mechanical analysis results of the proppant, we calculate the crushing rate. Considering the crushing rate of proppant, we improve the Kozeny–Carmen equation to determine the fracture permeability, and subsequently calculate the fracture conductivity. Finally, the calculated results are compared with the experimental results. The results show that the calculated values for the proppant crushing rate and fracture conductivity matched well with experimental data, and that the model’s calculation values were more accurate. As the number of simulations increased, the accuracy of the calculation results became higher. Research shows that the fracture conductivity is influenced by factors such as the particle size, microstructure, and crushing rate. Numerical calculation methods can replace physical experiments and provide theoretical support for engineering applications of hydraulic fracturing proppant materials.

The field stress of the shale affects the proppant embedment, fracture conductivity, well production rate, and ultimately the recovery of hydrocarbons from reservoir formations. This paper presents, for the first time, an experimental study investigating the mechanical characteristics of a shale under confining pressures that simulate the in situ stress state in deep reservoirs. Bidirectional but equal confining pressures were applied to the shale sample to replicate its field stress state. Microindentation tests were conducted to assess the alterations of mechanical properties resulting from the application of confining pressures. The results demonstrate a significant increase in Young’s modulus, hardness, and fracture toughness for the samples subjected to confining pressure. Considering the effect of confining pressure, the decrease in proppant embedment is proportional to Young’s modulus of the shale. For larger-sized proppants (e.g., D = 2.50 mm), the influence of confining pressure on fracture conductivity is relatively minor. However, when smaller-sized proppants (e.g., D = 1.00 mm) are used, particularly in scenarios involving shale debris swelling due to prolonged interaction with fracturing fluid, there is a noticeable improvement in fracture conductivity. Importantly, previous computational models have tended to overestimate proppant embedment depth while underestimating fracture conductivity. The findings from this study contribute to advancing the understanding of shale’s mechanical characteristics under in situ reservoir conditions and support the optimization of proppant embedment and fracture conductivity calculation models for the efficient extraction of shale gas.

This paper provides a comprehensive review on the application of proppants to maintain fracture permeability over the lifetime of a well based on published observations from experiments and modeling. The review identifies and describes important processes occurring during proppant embedment, during hydraulic fracturing, laboratory testing of fracture conductivity, proppant embedment and modeling of proppant embedment. Finally, this paper identifies the challenges and knowledge gaps that also provide future avenues of research and opportunities for collaborative technological development which requires an interdisciplinary approach of science, engineering in academia, government, and private sector.

Oil and gas resources are closely related to daily life and are an important support for the economy of a city or even a country. Hydraulic fracturing is an indispensable technique to economically develop oil and gas resources through creating complex fractures. Temporary plugging and diverting fracturing (TPDF) can generate diversion fractures perpendicular to the initial fractures and enhance the stimulated area. The aperture of the diversion fractures determines its conductivity and the oil/gas production. However, it is difficult to evaluate the aperture of the diversion fracture due to the complex physical process of hydraulic fracturing. This work established a fluid–solid fully coupled simulation model to investigate the fracture aperture influenced by various factors during TPDF. The model can simulate the propagation of the initial fracture and the diversion fracture. Various factors include the tight plug's permeability, the tight plug's length, Young's modulus, rock tensile strength, in situ stress contrast, the leak-off coefficient of the fracture surface, and fluid injection rate. The results show that the aperture of the previous fracture can be enlarged, and the aperture of the diversion fracture can be decreased by the tight plug. The aperture at the diversion fracture mouth is much smaller than that along the diversion fracture. Reservoirs with low Young's modulus values and high rock tensile strength can generate the diversion fracture with a wider aperture. Moreover, increasing the fluid injection rate can effectively increase the fracture mouth aperture. In this way, the risk of screenout can be lowered. This work is beneficial for the design of the TPDF and ensures safe construction. [ABSTRACT FROM AUTHOR]

Hydraulically fractured well productivity greatly depends on fracture conductivity, which itself is dictated by proppant transport and placement. To guide engineering design and evaluate performance of proppant placement, a full understanding of the underlying physics and robust numerical models are needed. This paper introduces a continuum approach for simulating the transport of multiple fluids and proppant particles within hydraulic fractures. To achieve computational efficiency, this proppant model is developed based on the assumption of multi-component single phase flow and captures proppant settling, hindering effects, proppant-bed erosion and transport. Inter-particle stresses and collisions are not numerically calculated but represented through empirical correlations to include the effects of particle clustering and hindered settling. This model couples the fluid phase and particle phase through the slip velocity, which is governed by particle settling, particle–particle interaction and fluid-particle drag forces. The presented proppant model is validated by comparing numerical results with experimental data. With the calibrated simulation, the modeling capabilities on fracturing treatment design are demonstrated through sensitivity analysis and field-scale applications. Moreover, based on proppant placement and deformation, a generic model is applied to forecast fracture conductivity in different scenarios. As illustrated in this study, this coupled three-dimensional model is capable of simulating proppant placement and fracture conductivity under various operational conditions. This model can be broadly applied to improve fracturing design in various formations, including tight sandstone, shale, coal bed methane and carbonate reservoirs. Highlights: To achieve computational efficiency, we introduce a continuum approach for simulating the transport of multiple fluids and proppant particles. In this new model, several underlying mechanisms are considered to highlight the coupling between proppant transport and fluid flow. The modelling predictions on proppant transport and distribution show a good agreement with the reported experimental data. Using the model calibrated to lab tests, the modeling capability is demonstrated and controlling parameters on proppant transport are identified. This model works for field-scale hydraulic fracturing simulations to model proppant transport and fracture conductivity evolution. [ABSTRACT FROM AUTHOR]

The presence of a reasonable flowback system after fracturing is a necessary condition for the high production of shale gas wells. At present, the optimization of the flowback system lacks a relevant theoretical basis. Due to this lack, this study established a new method for evaluating the conductivity of artificial fractures in shale, which can quantitatively characterize the backflow, embedment, and fragmentation of proppant during the flowback process. Then, the mechanism of the stress sensitivity of artificial fractures on fracture conductivity during the flowback stage of the shale gas well was revealed by performing the artificial fracture conductivity evaluation experiment. The results show that a large amount of proppant migrates, and the fracture conductivity decreases rapidly in the early stage of flowback, and then the decline gradually slows down. When the effective stress is low, the proppant is mainly plastically deformed, and the degree of fragmentation and embedment is low. When the effective stress exceeds 15.0 MPa, the fragmentation and embedment of the proppant will increase, and the fracture conductivity will be greatly reduced. The broken proppant ratio and embedded proppant ratio are the same under the two choke-management strategies. In the mode of increasing choke size step by step, the backflow proppant ratio is lower, and the broken proppant is mainly retained in fractures, so the damage ratio of fracture conductivity is lower. In the mode of decreasing choke size step by step, most of the proppant flows back from fractures, so the damage to fracture conductivity is greater. The research results have important theoretical guiding significance for optimizing the flowback system of shale gas wells. [ABSTRACT FROM AUTHOR]

Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Carbon dioxide (CO2) fracturing as an alternative to hydrofracturing is one of the most effective fracking techniques for shale gas extraction. As the water-based fracturing fluid can cause formation damage, clay swelling, and water blocking in shale, it is essential to replace it with CO2 fracturing fluids. The CO2 fracturing technique utilizes comparatively fewer chemicals and water, and has a high capacity for adsorbing CO2 with CH4. The CO2 fracturing technique is an appropriate fracturing technique as compared to other fracturing fluids. As the shale reservoirs are heterogenous, fracturing techniques are controlled by several parameters. Therefore, the shale reservoirs need to analyze adequately at a different scale. 3D modeling is essential to understand the efficacy of fracturing in unconventional reservoirs. The present study demonstrates the 3D geo-mechanical model through reservoir simulation techniques, and we estimate the gas recovery for a shale reservoir. The multi-stage fracturing tests were conducted on the unconventional reservoir using the fracture model to assess the heterogeneity, and change in the distance between the fractures. This study also analyzes the effects due to the space distance and fracture conductivities. The simulation study is conducted under different conditions by using CO2 as a fracturing fluid. The results suggest that the shale gas recovery rate increased by approximately 3 to 7% with the changes in fracture half-length, spacing, and fracture numbers. [ABSTRACT FROM AUTHOR]

Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Abstract Hydrate reservoirs in the South China Sea belong to muddy silt‐type hydrate reservoirs with low permeability. Horizontal well fracturing is one of the main stimulation methods for low‐permeability oil and gas reservoirs. For muddy silt‐type hydrate reservoirs, the stability and effectiveness of hydraulic fractures may be a severe problem due to poor reservoir cementation, reservoir deformation, and sand production. In this paper, the time variability of fracture conductivity is considered for the first time. According to the geological data at offshore gas hydrate production test site in the South China Sea, a multilayer hydrate reservoir model was established, and the influence of the time variable fracture conductivity on the production behavior in the process of horizontal well fracturing was analyzed. The simulation results show that, compared with the case of constant fracture conductivity, the gas production rate with the case of time variable fracture conductivity is greatly reduced, and the 5‐year cumulative gas production is reduced by 49.9%. Sensitivity analysis shows that the larger the initial fracture conductivity, the higher the peak gas production rate; the larger the attenuation magnitude of the fracture conductivity, the lower the gas production rate in the late production period; the larger the decline rate coefficient of the fracture conductivity, the higher the gas production rate in the early production period. The analysis of the orthogonal experimental design shows that the influence of the attenuation magnitude of fracture conductivity, the initial conductivity of fracture, and the decline rate coefficient of fracture conductivity on the cumulative gas production decreases in order. The actual production process should try to avoid excessive attenuation magnitude of fracture conductivity, while improving the initial fracture conductivity as much as possible to ensure high cumulative gas production.

Acid fracturing is an important technique for carbonate rock reservoir development. Acid injection method, fracture opening and wormhole shape directly affect the fracture conductivity of acid fracture. Taking the ordovician subrock carbonate reservoir as the research target, based on the establishment of fracture opening characterization method, the influence of different acid systems, different acid injection methods, different fracture opening and different fracture surface morphology on acid fracture conductivity was studied, and the main controlling factors affecting acid fracture conductivity were identified. The experimental results show that the main acid adding thickening and cleaning agent has little effect on the dissolution rate and the conductivity of the fracture after acid etching. Single acid injection and alternating acid injection have little effect on acid fracture conductivity, but a large effect on acid flowback. Alternating acid injection can reduce the reflux pressure by 70% . The larger the fracture opening is, the larger the fracture conductivity is after acid etching, but the smaller the multiple of improving the conductivity is. Fracture aperture > 12 μm is easy to form “ crossflow ” acid wormhole, which is conducive to the establishment of acid etching channel. The connection between microfracture opening and fracture development is the main factor affecting acid wormhole and conductivity, followed by micropore development and fracture development and mineral distribution. The comprehensive acid fracturing process is recommended by fracturing first, acidizing later and acid injection alternately. [ABSTRACT FROM AUTHOR]

The stability of a rock slope is strongly influenced by the pattern of groundwater flow through the fracture system, which may lead to an increase in the water pressure in partly open joints and the consequent decrease in the rock wall strength. The comprehension of the fracture pattern is a challenging but vital aspect in engineering geology since the fractures' spatial distribution, connectivity, and aperture guide both the water movement and flow quantity within the rock volume. In the literature, the most accepted methods to hydraulically characterise fractured rocks in situ are the single borehole packer test, the high-resolution flow meters for fractures, and the artificial tracer tests performed in boreholes. However, due to the high cost a borehole requires and the general absence of wells along coastal cliffs, these methods may not be appropriate in rockfall-prone areas. In this study, an unsaturated rocky cliff, strongly affected by rockfalls, was investigated by combining kinematic analysis, Discrete Fracture Network (DFN) modelling, and artificial tracer tests. The DFN model and potential rock block failure mechanisms were derived from high-resolution 3D virtual outcrop models via the Structure from Motion (SfM) photogrammetry technique. An artificial tracer was injected using a double ring infiltrometer atop the recharge zone of the slope to determine the infiltration rate and validate the DFN results. The DFN and tracer test methods are frequently used at different spatial scales and for different disciplines. However, the integration of digital photogrammetry, DFN, and tracer tests may represent a new step in rockfall and landslide studies. This approach made possible the identification of groundwater flow patterns within the fracture system and revealed about a 10-day tracer transit time from the injection area and the monitored slope, with similar conductivity values gathered from both the DFN and tracer test. Planar and wedge failures with volumes ranging from 0.1 and 1 m3 are the most probable failure mechanisms in the areas. The results were consistent with the delay between the intense rainfall and the slope failures previously documented in the study area and with their mechanisms. [ABSTRACT FROM AUTHOR]

For the high-salt reservoir of the Fengcheng Formation in the Mahu area, the production decreases rapidly due to the conductivity decrease after fracturing. The analysis shows that this has a great relationship with the special salt dissolution characteristics of the High salinity reservoir. In order to study the problem of salt dissolution pattern, the effect of different temperatures, the salt concentration of fracturing fluid, the viscosity of fracturing fluid, and injection rate on the rate of salt dissolution was evaluated by using the dynamic experimental evaluation method of salt dissolution. Through the grey correlation analysis of salt rock dissolution rate, it can be found that the degree of influence is from large to small which the influence of temperature is greater than fracturing fluid velocity, followed by fracturing fluid viscosity and, finally, fracturing fluid salt concentration. The results of compressive strength tests on salt-bearing rocks after dissolution show that the compressive strength is greatly reduced after salt dissolution by more than 60%. At the same time, the test results of proppant-free conductivity showed that the conductivity increased first and then decreased sharply after salt dissolution. This shows that in the early stage of salt dissolution, the flow channel will increase through dissolution. The rock strength decreases greatly with the increase of salt dissolution. As a result, collapse leads to a sharp reduction in the facture conductivity. Therefore, it is necessary to choose saturated brine fracturing fluid. In the proppant conductivity experiments, by optimizing the use of saturated brine fracturing fluid with 30/50 mesh or 20/40 mesh ceramic proppant with a sand concentration of 5 Kg/m2, a high facture conductivity can be achieved under high closure pressure conditions. Based on the above study, directions and countermeasures for improving high saline reservoirs are proposed, which point the way to improve the fracturing conductivity. [ABSTRACT FROM AUTHOR]

Hydrate reservoirs in the South China Sea belong to muddy silt‐type hydrate reservoirs with low permeability. Horizontal well fracturing is one of the main stimulation methods for low‐permeability oil and gas reservoirs. For muddy silt‐type hydrate reservoirs, the stability and effectiveness of hydraulic fractures may be a severe problem due to poor reservoir cementation, reservoir deformation, and sand production. In this paper, the time variability of fracture conductivity is considered for the first time. According to the geological data at offshore gas hydrate production test site in the South China Sea, a multilayer hydrate reservoir model was established, and the influence of the time variable fracture conductivity on the production behavior in the process of horizontal well fracturing was analyzed. The simulation results show that, compared with the case of constant fracture conductivity, the gas production rate with the case of time variable fracture conductivity is greatly reduced, and the 5‐year cumulative gas production is reduced by 49.9%. Sensitivity analysis shows that the larger the initial fracture conductivity, the higher the peak gas production rate; the larger the attenuation magnitude of the fracture conductivity, the lower the gas production rate in the late production period; the larger the decline rate coefficient of the fracture conductivity, the higher the gas production rate in the early production period. The analysis of the orthogonal experimental design shows that the influence of the attenuation magnitude of fracture conductivity, the initial conductivity of fracture, and the decline rate coefficient of fracture conductivity on the cumulative gas production decreases in order. The actual production process should try to avoid excessive attenuation magnitude of fracture conductivity, while improving the initial fracture conductivity as much as possible to ensure high cumulative gas production. [ABSTRACT FROM AUTHOR]

Complex fracture network is easy to form after hydraulic fracturing in coalbed methane reservoir. In order to study the influencing factors of complex fracture conductivity, an improved proppant filling fracture conductivity tester was used to evaluate the effects of proppant particle size, sand concentration, coal elastic modulus, coal powder content and fracturing fluid type on complex fracture conductivity in coalbed methane reservoir. The results show that: under the same sand concentration, the conductivity of E-type fracture is significantly greater than that of T-type fracture and single fracture, that is, the more complex the fracture morphology is, the greater the conductivity is; the conductivity of ceramsite as proppant is significantly greater than that of coated sand and quartz sand; the higher the sand concentration is, the greater the elastic modulus of coal and rock is, the greater the conductivity of fracture is; coal powder and fracturing fluid have great influence on fracture conductivity. The higher the content of coal powder is, the higher the damage rate to fracture conductivity is. Guar gum fracturing fluid has the greatest damage to fracture conductivity, followed by clean fracturing fluid and active hydraulic fracturing fluid. In addition, the more complex the fracture morphology is, the more serious the damage degree of coal powder and fracturing fluid to fracture conductivity is.

Enhanced Geothermal System (EGS) reservoirs represent a vital frontier in clean energy production. However, short-circulation flow within these reservoirs can significantly affect their immediate efficiency and long-term viability. Injected cold fluids moving through wide fractures or direct channels between injection and production wells reduce thermal production temperatures, disrupting energy output. Preformed Particle Gels (PPGs) have proven effective in controlling preferential fluid flow in oil and gas reservoirs, effectively regulating fluid movement. This work explores the potential of a novel High-Temperature Preformed Particle Gel (HT-PPG), designed for geothermal applications, to plug fractures in a simulated geothermal reservoir. Core flooding experiments in coated and uncoated sandstone models were conducted under varying HT-PPG sizes, swelling ratios, and fracture widths to determine gel plugging efficiency. Variations in the HT-PPG injection pressure, breakthrough pressure, and residual resistance factor (F rr) were evaluated. Water breakthrough pressures can reach 464.10 psi/ft. While the stable injection pressure of HT-PPG decreased with increasing swelling ratio and fracture width, it was higher in uncoated cores. The HT-PPG significantly sealed the fractures, drastically reducing conductivities to millidarcy levels. This work validates HT-PPG a robust solution to mitigate fluid diversion challenges in sandstone EGS reservoirs, enhancing performance and advancing sustainable geothermal energy production. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing is a potentially promising technology for stimulating gas production and improving energy efficiency in low-permeability hydrate reservoirs. However, marine hydrate reservoirs, with weak cementation, unconsolidated nature, low mechanical strength, and the potential for decreased strength and fines migration resulting from hydrate decomposition, pose significant challenges for effective fracture propping and maintaining high conductivity. To assess hydraulic fracturing feasibility in marine hydrate reservoirs, we conducted experiments to investigate the impact of closure pressure, hydrate saturation, and hydrate decomposition mode on fracture conductivity, with a particular focus on understanding the propping mechanism and identifying potential sources of conductivity damage in artificial fractures. The results demonstrated that the conductivity of propped fractures within hydrate-bearing clayey silt sediments linearly decreased with increasing closure pressure, primarily due to proppant compaction and embedding. The conductivity disparity under different hydrate saturation levels decreasesd and became similar at 16 MPa closure pressure. The decomposition mode of hydrates had a significant impact on fracture conductivity damage, with higher degree of damage observed with increasing depressurization range (up to 90.3% at a 3.0 MPa range), whereas slow decomposition induced by heating only resulted in minor decreases in fracture conductivity (damage degree: 6.6%), primarily attributed to the migration of fine particles during gas-water production. Proppant embedding and fines migration were the main causes of fracture conductivity damage in hydrate reservoirs. Proppant embedding damage occurred at higher closure pressures or slow hydrate decomposition, while fines migration damage occurred with rapid hydrate decomposition. In proppant-filled propped fractures, fines migration posed a greater risk to fracture conductivity than proppant embedding, as the migration of fine particles can block the pore spaces within the proppant-filled fractures, leading to a significant reduction in conductivity. Therefore, it was recommended to induce hydrate decomposition by slowly reducing pressure during production to minimize fines migration damage to fracture conductivity. These research findings hold significant importance in the application of hydraulic fracturing during field tests conducted on hydrate reservoirs, as they assist in optimizing the propping mode of fractures and ensuring the effectiveness and prolonged success of fracturing stimulation. • The fracture conductivity was measured under varying closure pressure, hydrate saturation, and decomposition mode. • Feasibility of hydraulic fracturing in marine hydrate reservoirs was evaluated. • Hydrate decomposition mode had a significant impact on fracture conductivity damage. • Mechanism of fracture conductivity damage within hydrate-bearing sediments was revealed. • Proppant embedding and fines migration caused fracture conductivity damage in hydrate reservoirs. [ABSTRACT FROM AUTHOR]

True tri-axial sanding fracturing experiments are carried out on conglomerate samples from the Permian Wuerhe Formation of Mahu sag, Junggar Basin, to study hydraulic fracture propagation geometry and quartz sand transport in matrix-supported fine conglomerate and grain-supported medium conglomerate. The effect of rough fracture surface on conductivity is analyzed using the 3D-printing technology to reconstruct the rough surface formed in the fractured conglomerate. The hydraulic fractures formed in the matrix-supported fine conglomerate are fairly straight, and only more tortuous when encountering large gravels at local parts; thus, proppants can get into the fractures easily with transport distance about 70%–90% of the fracture length. By contrast, in the grain-supported medium conglomerate, hydraulic fractures tend to bypass the gravels to propagate in tortuous paths and frequently change in width; therefore, proppants are difficult to transport in these fractures and only move less than 30% of the fracture length. As the matrix-supported fine conglomerate has high matrix content and low hardness, proppants embed in the fracture surface severely. In contrast, the grain-supported medium conglomerate has higher gravel content and hardness, so the quartz sand is crushed more severely. Under the high proppant concentration of 5 kg/m2, when the closure stress is increased (above 60 MPa), fractures formed in both matrix-supported fine conglomerate and grain-supported medium conglomerate decrease in width significantly, and drop 88% and 92% in conductivity respectively compared with the case under the low closure stress of 20 MPa. The field tests prove that under high closure stress above 60 MPa, using a high proportion of fine proppants with high concentration allow the proppant to move further in the fracture; meanwhile proppant places more uniformly in the rough fracture, resulting in a higher fracture conductivity and an improved well performance.

Acid fracturing is an important means of reservoir stimulation, whose purpose is to form an incompletely closed acid-etched fracture as the flow channel for oil and gas during production. The length and conductivity of acid-etched fractures can be used to evaluate acid fracturing and directly impact production. To study their influence on the stimulation effect and final production, an acid fracturing coupling model including a fracture propagation model coupled with reservoir flow and temperature field models is established for the first time in this study based on an embedded discrete fracture model (EDFM), which can realize the coupling of fracture propagation and reservoir flow and simplify the solution of fracture and reservoir temperatures. The simulation results of the acid fracturing coupling model are introduced into the productivity model, which is also based on the EDFM to analyze and evaluate well productivity. The results show that: (1) the EDFM can easily couple fracture propagation and reservoir flow and can be used to rapidly solve the temperature fields in the fracture and reservoir successfully for the first time. (2) Reservoir flow impacts the propagation of fractures by increasing or decreasing the leak-off velocity of the working fluid. (3) Temperature diffusion is much weaker than pressure diffusion during acid fracturing and is limited near the acid fracture. The reaction between the acid and rock increases the local temperature around the acid fracture, and may even exceed the initial formation temperature. (4) Raising the injection rate reasonably enhances H+ diffusion, increases the effective length of acid-etched fractures, enlarges the drainage area of oil and gas, and benefits long-term well production.

Existing fractured gas reservoir development techniques are mainly based on dual medium numerical-simulation models, which can, to a certain extent, effectively simulate natural fractures with high fracture density; however, these models have some limitations, particularly in terms of simulating the fracture morphology and distribution. Considering carbonate gas reservoirs with complex fractures, in this paper, we establish a numerical-simulation model of embedded discrete-fracture seepage in horizontal wells of carbonate gas reservoirs, in order to compare and study the development effect of carbonate gas reservoirs under different horizontal well fracture parameters. The fracture distribution and structure in carbonate gas reservoirs is obtained using an ant-tracking approach based on 3D seismic bodies, and a numerical-simulation model based on the embedded discrete-fractures model is solved using the open-source program MRST. We considered the following parameters: half fracture length, fracture permeability, and horizontal segment length. By changing the fracture parameters of horizontal wells and comparing the gas-production trends, technical optimization in gas reservoir development can be realized. The results show that the embedded discrete-fracture model can effectively solve the difficult problem of characterizing fluid seepage in fractures of different scale in carbonate gas reservoirs. Although gas production increases with increasing fracture length, fracture conductivity, horizontal section length, and natural fracture conductivity, the contributions of these parameters to gas well production capacity are greatly influenced by the natural fractures. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing or hydro-frac fluids can impede well production due to the damage caused to the reservoir formation and fracture face, generated from adverse interactions with reservoir rock. Understanding the mechanisms of hydraulic fracturing, optimum treatment designs, and pumping/pressure profiles is critical for hydro-frac success. However, to realize the full potential of fracturing and the mitigation strategies for reservoir and fracture conductivity damage during and after its occurrence, fracturing must be considered during the design phase itself. This article provides a brief overview of hydro-frac techniques, including design, optimization, modeling, commonly used proppants, and fracturing fluid benefits and consequences based on critically reviewed case studies. However, the primary focus of this article is on the potential of fracture conductivity damage and the intrinsic mechanisms in hydraulic fracturing. The article presents updated information on various damage mitigation processes established through laboratory investigation and field implementation. The authors expect that the provided workflow in this article will be helpful to researchers and stimulate engineers to a great extent. [ABSTRACT FROM AUTHOR]

The damage of fracturing fluid to proppant conductivity greatly affects the effectiveness of fracturing operation. In order to study the damage effect of foam and non-foam fracturing fluid on proppant fractures. The test results show that the damage rates of non-foam fracturing fluid and foam fracturing fluid to the fracture conductivity of quartz sand and light ceramic proppant are 72.3%, 31.5%, 64.8% and 26.3% respectively. In the process of hydraulic fracturing, the foam fracturing fluid has little damage to the fractures filled with proppant, which can better maintain appropriate rheological parameters and ensure the continuous suspension capacity of proppant. This method can be used to evaluate the hydraulic fracturing fluid and proppant for tight gas reservoirs. [ABSTRACT FROM AUTHOR]

As an important stimulation technology, refracturing is commonly used to enhance oil or gas recovery in tight reservoirs, particularly for poorly/damaged fractured wells in these reservoirs. However, the stimulation effect of refracturing is not clear at present. Accurate evaluation of the effect of refracturing treatment on the productivity of a poorly/damaged fractured well is of great significance to the rapid and efficient development of tight reservoirs. In this study, two semi-analytical models, including an initially fractured well model and a refractured well model, were established to calculate their productivity indices, respectively, for quantitative productivity evaluation. Productivity index ratio, a newly defined parameter reflecting the characteristics of both productivity indices, was calculated to evaluate the refracturing stimulation effect. The comparisons with two classic cases indicated our solutions were exactly consistent with the results in the previous literature and verified the reliability and accuracy of our solutions. Results show that compared with initially fractured well, the productivity of refractured well first rises rapidly and then slows down as principal/reoriented fracture angle or rotation angle increases, but an inverse relationship may occur at low initial fracture conductivity. Meanwhile, the productivity index ratio curves under the same initial fracture conductivity converge into a bunch of curves, first increasing and then slowing down as reorientation fracture conductivity enhances. Overall, refracturing treatment is more effective for fractured wells when initial fracture conductivity becomes lower. Reoriented/principal fracture length ratio has a weak negative correlation with the productivity index ratio, but reorientation fracture number shows a stronger influence on the stimulation than the other factors. Principal/reoriented fracture angle, fracture length ratio, reorientation fracture number and fracture conductivity should be optimized before refracturing to achieve the optimal productivity. Additionally, in a rectangular reservoir, the central refractured well obtains larger productivity than the eccentric refractured well, and hydraulic fractures deploying along the reservoir extension can slightly increase well productivity. [ABSTRACT FROM AUTHOR]

RTA (Rate Transient Analysis) is a valuable method for obtaining reservoir parameters and well performance, but current RTA models hardly consider the MLVF (Multi-Layer Vertical Fractured) well in a layered tight gas reservoir. To capture the production response caused by the fracture with non-uniform length and conductivity, a novel RTA model for an MLVF well in a layered tight reservoir was presented. In this paper, we present a novel tight gas reservoir RTA model, an extended MLVF well with non-uniform fracture length and conductivity to investigate the production decline feature by the combined RTA type curves. After that, the proposed RTA model is verified to ensure calculation accuracy. Sensitivity analysis is conducted on the crucial parameters, including the formation transmissibility, formation storability, fracture length, fracture conductivity, and fracture extension. Research results show that there are three rate decline stages caused by a multi fracture with non-uniform conductivity. The wellbore storage and formation skin can be ignored in the rate transient analysis work. The formation transmissibility affects the rate transient response more than the formation storability. The increase in fracture length, fracture conductivity, and the extension of a high conductivity fracture will improve the well's production rate in a tight gas reservoir's early production stage. Therefore, it is significant to incorporate how the effects of the MLVF well intercepting with non-uniform length fractures change conductivity. The RTA model proposed in this paper enables us to better evaluate well performance and capture the formation of complex fracture characteristics in a layered tight gas reservoir based on rate transient data. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing has become a standard stimulation technology to enhance hydrocarbon production in unconventional reservoirs in recent decades. During organic‐rich tight carbonate reservoir stimulation, extensive microfractures will be created and pre‐existing microfractures will be opened in the far‐field during hydraulic fracturing, but they tend to close after the release of hydraulic pressure due to the larger sizes of the conventional proppants not fitting into the microfractures. The well productivity will be further enhanced if these microfractures can be held open during production, like the primary hydraulic fractures supported by proppants. Based on this idea, industry has introduced microproppants into the pad or pre‐pad fluid so that they can be placed into opened microfractures during hydraulic fracturing. In this work, we propose further enhancing the stimulation efficiency by introducing solid delayed acid generating materials (SDAGM)‐coated microproppants into the stimulation for the dual function of keeping microfractures open, and, through subsequent reactions of the coating materials with the carbonate formation, creating extra void space inside the microfractures. To prove this concept and help select the appropriate microproppant coating plan, lattice Boltzmann simulation is performed to measure the hydraulic conductivity of the stimulated microfractures under different scenarios that represent corresponding stimulation treatment schemes. The simulations showed that fracture conductivity of the microfractures can be significantly improved by placing SDAGM‐coated microproppant into them. Using the mixed uncoated and SDAGM‐coated microproppants (Scheme II) may have better fracture conductivity improvement than using the coated microproppant alone (Scheme I). [ABSTRACT FROM AUTHOR]