Effect Of Natural Fractures Research Articles

Study on the effect of natural fractures and temperature on the wormhole morphology formed by two-phase acidizing in carbonate rocks

The simulation of a two-phase acidizing process coupled with thermal–chemical–fracturing is a complex task, given the presence of natural fractures in carbonate rocks and the influence of temperature on the acid–rock reaction. In this work, we introduce a mixed computational strategy combining the operator splitting and the Newton iteration built upon the embedded discrete fracture model. This innovative strategy is designed to tackle nonlinear problems arising from the coupling of multiphysics fields. The porosity improved region within rock is divided into three parts: the high (H), medium (M), and low (L) efficiency regions, aimed at clearly assessing the impact of various physical fields on acidizing efficiency. The results show that the wormhole morphology is determined by the H and M regions, and the L region determines the acidizing efficiency. The oil in the rock can have a “sealing effect” on the acid, improving the acidizing efficiency. For the large fracture aperture, the wormhole morphology is predominantly influenced by fractures, with the influence diminishing as the aperture decreases. At small apertures, fractures exhibit minimal impact on the morphology. While increasing injection temperature may not significantly alter the wormhole morphology, it can enhance acidizing efficiency. The morphology of wormholes is highly sensitive to multiphase interactions, fractures, and temperature variations. The proposed hybrid computational strategy effectively addresses multiphysics field challenges in two-phase acidizing.

A Study on Three-Dimensional Multi-Cluster Fracturing Simulation under the Influence of Natural Fractures

Multi-cluster fracturing has emerged as an effective technique for enhancing the productivity of deep shale reservoirs. The presence of natural bedding planes in these reservoirs plays a significant role in shaping the evolution and development of multi-cluster hydraulic fractures. Therefore, conducting detailed research on the propagation mechanisms of multi-cluster hydraulic fractures in deep shale formations is crucial for optimizing reservoir transformation efficiency and achieving effective development outcomes. This study employs the finite discrete element method (FDEM) to construct a comprehensive three-dimensional simulation model of multi-cluster fracturing, considering the number of natural fractures present and the geo-mechanical characteristics of a target block. The propagation of hydraulic fractures is investigated in response to the number of natural fractures and the design of the multi-cluster fracturing operations. The simulation results show that, consistent with previous research on fracturing in shale oil and gas reservoirs, an increase in the number of fracturing clusters and natural fractures leads to a larger total area covered by artificial fractures and the development of more intricate fracture patterns. Furthermore, the present study highlights that an escalation in the number of fracturing clusters results in a notable reduction in the balanced expansion of the double wings of the main fracture within the reservoir. Instead, the effects of natural fractures, geo-stress, and other factors contribute to enhanced phenomena such as single-wing expansion, bifurcation, and the bending of different main fractures, facilitating the creation of complex artificial fracture networks. It is important to note that the presence of natural fractures can also significantly alter the failure mode of artificial fractures, potentially resulting in the formation of small opening shear fractures that necessitate careful evaluation of the overall renovation impact. Moreover, this study demonstrates that even in comparison to single-cluster fracturing, the presence of 40 natural main fractures in the region can lead to the development of multiple branching main fractures. This finding underscores the importance of considering natural fractures in deep reservoir fracturing operations. In conclusion, the findings of this study offer valuable insights for optimizing deep reservoir fracturing processes in scenarios where natural fractures play a vital role in shaping fracture development.

The effect of natural fractures on the failure mechanism of granite: Implication for enhanced geothermal systems

Hot dry rock is considered to be an important renewable energy source typically existing with extensive natural fractures. Studying the deformation and failure pattern of the granite containing natural fractures is of great engineering significance for the in-depth understanding of the hydraulic fracture intersecting with natural fractures. In this paper, three different types of natural fractures were obtained according to the cementing degree of the filling mineral. Afterward, the fracture toughness of the natural fractures was evaluated according to the nanoindentation-based energy approach. Then, the mechanical experimental tests including uniaxial compression tests, triaxial compression tests, and Brazilian disc tests were conducted on granite samples containing pre-existing natural fractures monitored by real-time acoustic emission (AE) monitoring technology. The results indicated that granite with weakly sealed natural fractures presented the lowest mechanical strength, followed by granite with partially sealed natural fractures and strongly sealed natural fractures. For the granite with the partially sealed or weakly sealed natural fracture, the characteristic of the stress curve showed a multimodal pattern with constant stress drop and rise due to slippage of the natural fracture, in which a substantial amount of the AE counts were recorded accordingly. The rise angle and average frequency analysis demonstrated that a larger proportion of shear cracks would be generated with the existence of natural fractures. Further, the partially sealed natural fractures were activated and connected with other newly formed cracks, resulting in more complex fracture networks than the other samples, which leads to a higher fracture volume ratio of granite samples. The strongly sealed natural fractures are difficult to get stimulated under the deformation of the samples, resulting in rather simple fracture networks similar to that of intact granite. The results suggested fracturing granite with partially sealed natural fractures could possibly form complex interconnected fracture networks, potentially favoring the development of the enhanced geothermal system. The findings are expected to provide theoretical guidance for the stimulation of the hot dry rock reservoir.

Effect of natural fractures on mechanical properties and fracture patterns of shale at microscopic scale: an example from the Lower Cambrian Niutitang formation in Qianbei region

In order to explore the influence of natural fractures on the mechanical properties and failure modes of shale at the micro scale, uniaxial compression numerical experiments were conducted on the shale of the Niutang Formation in northern Guizhou with different natural fracture angles using a rock failure process system and digital image processing technology. It is shown that the compressive strength of shale increases with the increase of natural crack inclination, and the growth rate of shale compressive strength also increases. Shale's microscopic fractures can generally be classified into four categories. The first category is to sprout along the natural cracks to the outside of the shale, and eventually form a crack similar to the "X" type (0°); the second category is to sprout along the natural cracks to the middle and outside of the shale, and eventually form an inverted "Y" type crack (15°, 30°); the third category is to sprout along the natural cracks to the middle and outside of the shale, and eventually form an inverted "Y" type crack (15°, 30°); the second type sprouts along the natural fractures toward the middle and outside of the shale, forming inverted "Y"-type fractures (15°, 30°); the third type cracks along the sides of the natural fractures, forming "Y"-type fractures (45°); and the fourth type does not crack along the natural fractures, forming "S"-type fractures (60°, 75°, and 90°). In the low natural fracture dip shale model, tensile damage mainly occurs, accompanied by a small amount of compressive shear damage; in the high natural fracture dip shale model, tensile damage and compressive shear damage account for a larger proportion in the fracture process.This suggests that the presence of natural cracks in shale has a significant impact on stress distribution. There are two main types of acoustic emission signal distribution and evolutionary features, the evolutionary features of acoustic emission signal distribution are of two types, 0°-45° test and 60°-90° test, and the difference is mainly reflected in the damage stage, the damage of shale with high natural fracture inclination is more intense, which is manifested by the decrease in the number of acoustic emission events, but the level of acoustic emission events in the damage stage is higher, which can reach 61788, 46605 and 94315, the shale with high natural fracture inclination is more brittle.

Coupled Thermal-Hydraulic-Mechanical Modeling of Near-Well Stress Evolution in Naturally Fractured Formations during Drilling

Naturally fractured formations usually have strong heterogeneities. Drilling and production operations in such formations can involve unwanted formation failure risks such as wellbore collapse and wellbore fracturing. This study presents a coupled thermal-hydraulic-mechanical numerical model for near-well stress evolutions during drilling in naturally fractured formations. The evolution of pressure, temperature, and geo-mechanical responses on the wellbore wall and in the near-well region is simulated. The effects of wellbore pressure, internal friction angle, and natural fracture length on formation rock risks are discussed. A failure index is used to quantify the formation rock failure risks. The existence of natural fractures magnifies the heterogeneous system response induced by drilling. Increasing the wellbore pressure from a relatively low value can improve the support for the wellbore wall, which reduces the failure risks caused by shearing. In mechanically weak formations, the effect of natural fractures on formation rock failure becomes more significant. When the natural fracture length is large, the near-well region tends to have greater failure risks as the formations become more mechanically weak. This study provides a quantitative understanding of the effects of drilling and formation parameters on failure risks.

Global sensitivity analysis of CO2 storage in fractured aquifers via computer experiments

• Accelerated CO 2 storage sensitivity analysis via Computer Experiments as surrogate modes. • Rigorous dynamic models use to model non-reactive CO 2 storage mechanisms, inspired by the Teapot Dome in Wyoming dataset. • Demonstration that a network of connected fractures in an eolian sandstone shifts the importance of CO 2 storage controlling parameters. In this work, we use the “Design and Analysis of Computer Experiments” (DACE) technique to analyze the sensitivity of CO 2 storage in fractured aquifers. The aquifer static or geogical model was inspired by the Tensleep formation at Teapot Dome, a potential CO 2 storage target in Wyoming. The CO 2 storage performance in aquifers is comprehensively simulated in our dynamic model by considering all the trapping mechanisms, except for mineralization, i.e. structural, dissolution and residual, as well as local capillary trapping. Operational strategies are investigated to achieve an effective trade-off between higher CO 2 trapping efficiency and delayed CO 2 breakthrough at producers. The effect of natural fractures is explored by running single-porosity, dual-permeability and dual-porosity models. Results show that different models produce significantly different trapping efficiencies, which indicates that natural fractures and their type impact the CO 2 storage practice appreciably. To carry out the global sensitivity analysis, two 100-point computer experiments were designed using the modified space-filling method considering a bottom aquifer, matrix permeability and porosity, fracture permeability and spacing, and water Total Dissolved Solids (TDS). Results show that an active bottom aquifer reduces trapping efficiency noticeably. In addition, dissolution trapping becomes the dominant trapping mechanism. The variability of CO 2 trapping efficiency is explained primarily by fracture permeability, then depth, and finally matrix permeability. In contrast, in the absence of aquifer drive, the variability is almost completely explained by matrix permeability. Furthermore, our results provide guidance to the collection of information as to reduce the most dominant uncertainties.

Sensitivity analysis on the effect of natural fractures and injected fluid on hydraulic fracture propagation in a fractured reservoir

In this work, a series of numerical simulations based on an outcrop-data-based discrete fracture network (DFN) model of the shale reservoir in the Ordos Basin, China are conducted, trying to determine the dependence of hydraulic fracturing on the properties of natural fractures and injected fluid. The accuracy of the method is verified through the PKN solution for a homogeneous rock model and a laboratory test for a shale sample obtained from the study area. Parametric studies are performed for different field parameters, including natural fracture aperture, natural fracture frictional coefficient, fluid injection rate and fluid viscosity. The results suggest that the level of fracture complexity decreases as the aperture of natural fractures increase, and increasing the frictional coefficient of natural fractures can improve the hydraulic fracturing efficiency. Higher injection rates could translate into higher injection pressure and more energy available for rock failure near the wellbore, and therefore improve the fracture complexity. However, higher fluid viscosity leads to higher resistance to fracture propagation, and thus reduces the hydraulic fracturing efficiency.

Study of mechano-chemical effects on the morphology of hydraulic fractures

Acid fracturing is one of the main stimulation technologies in carbonate reservoir. Understanding the mechano-chemical effects on the morphology of hydraulic fractures is of great significance for acid concentration optimization. Based on the true tri-axial experiments on carbonate and CT scan and 3D reconstruction technology, the experimental results indicate that the hydraulic fracture changes from horizontal fracture to vertical fracture. In the process of acid fracturing, the stress field plays a dominant role in the formation of hydraulic fractures when the acid concentration is less than 10%, while the chemical reaction plays the dominant role when the acid concentration is more than 20%. The natural fracture system developed in carbonate reservoir provides seepage channel for acidizing reaction. With the increasing development of natural fractures, the hydraulic fractures formed in the process of acid fracturing are more complex, and the influence of acidizing reaction on acid fracturing is more serious. • The true tri-axial acid fracturing experiments are conducted. • The effect of mechanochemical synergism on acid fracturing are analyzed. • The effect of natural fractures on acid fracturing are analyzed.

Quantitative Prediction of Natural Fractures in Shale Oil Reservoirs

Natural fractures are the key factors controlling the enrichment of shale oil. It is of great significance to clarify the distribution of natural fractures to guide the selection of sweet spots for shale oil. Taking the Qing-1 Member shale oil reservoir in the northern Songliao Basin, China as an example, a new method considering the factors affecting fracture distribution was proposed to quantitatively predict the structural fractures. And the effect of natural fractures on shale oil enrichment was discussed. Firstly, the types and characteristics of fractures in shale oil reservoirs are characterized by using core and outcrop data. Combined with the experimental analysis, the influences of fault, mechanical stratigraphy, mineral composition and content, TOC, and overpressure on fracture intensity were clarified. Then, the number and density of fractures are quantitatively predicted according to the power-law distribution of fault length. Next, geomechanical simulation and fracture prediction were carried out on the model which was established with comprehensive consideration of the influencing factors of fracture distribution. Finally, the fracture distribution is evaluated comprehensively based on above prediction. The prediction results in this work are consistent with the core measurements.

Network fracturing technology of hydraulic fracturing in coalbed methane reservoir based on induced stress

The stimulated reservoir volume (SRV) fracturing is used to consider the effects of natural fractures in the fracture network formation. Meanwhile, the importance of the operation itself is often disregarded. To improve the oil and gas recovery factor, a reservoir reconstruction technique based on induced stress is examined. In this paper, we applied the theory of elastic–plastic mechanics to evaluate the induced stress of net pressure on the fracture plane during the fracturing process. A mathematical model of a fracture-induced stress field was established and combined with the distribution of the in situ stress field. The stress field around the fracture during fracturing is thereby elucidated. Based on this research, it is evident that fracture-induced stress has disparate variation regularity in different directions. Overall, the induced stress is the largest in the direction perpendicular to the fracture plane. It gradually decreases along the farther distance from the fracture plane until it disappears. This induced stress can change the stress field distribution around the fracture by enhancing the net pressure on the fracture plane. A method applied in stages to change the treatment pressure fully leverages the characteristics of induced stress, thereby causing the stress relations to change around the fracture plane. This provides good conditions for a new crack formation and a wider range of fracture network transformations.

Investigation on petrophysical properties of fractured tight gas sandstones: a case study of Jurassic Xujiahe Formation in Sichuan Basin, Southwest China

Integrated characterization methods from micro-scale to macro-scale were applied to thoroughly study petrophysical properties of the Upper Triassic Xujiahe fractured tight gas reservoirs. The lithology, pore types, pore structure, and porosity-permeability relationship were described based on experimental results of thin section analysis, computer tomography, and porosity and permeability measurements. And special attention was paid to characterize natural fractures and try to reveal the effects of fractures on gas storage and transportation. A dual porosity-dual permeability (DPDP) dynamic model of well L150 was established, and effects of natural fractures on natural gas productivity were studied. The lithology is mainly lithic arkose, feldspathic litharenite, and litharenite. The formation is highly tight due to compaction and cementation during the early and middle burial stages, and only some interparticle pores and grain dissolution pores remained. Fractures are classified into two types, which are structural fractures and interlayer fractures. The first type is caused by tectonic movement and is mainly developed in siltstone and fine sandstone, while the second type is developed between coarse sandstone beddings. Mercury injection capillary pressure experiment reveals that the pore size of the tight sandstone is 2–200 nm. Porosity of the samples is in the range of 2–6%, and permeability is 5 × 10−3–1 × 10−1 mD. Yet permeability of some samples may be as large as 1000 mD because of the micro-fractures. Results of history matching and production predictions of the dynamic model indicate that natural fracture is important to natural gas production.

Physical Simulation of Hydraulic Fracturing of Large-Sized Tight Sandstone Outcrops

Summary Hydraulic fracturing is an indispensable technology in developing tight oil and gas resources. However, the development of tight oil and gas is not consistently satisfactory. Further understanding of hydraulic fracturing of tight sandstone is required, which increases the production of tight oil and gas reservoirs, particularly in China. Currently, there are a few true triaxial hydraulic fracturing physical simulations of large tight sandstone outcrops. To weaken the boundary effect, this study performed simulations using large tight sandstone outcrops (500 × 500 × 500 mm and 500 × 500 × 800 mm) in the Shahezi Formation (Fm.), Jilin Province, China. The effect of natural fracture (NF) development degree, in-situ stress conditions, fracturing treatment parameters, and temporary plugging on fracture propagation were investigated. Furthermore, fracture propagation was investigated based on post-fracturing fine reconstruction, high-energy computed tomography (CT) scan, acoustic emission monitoring (AEM), and analysis of a fracturing pressure curve. Finally, suggestions on fracturing treatment were proposed. The results show that the NF is a key factor in determining the hydraulic fracture (HF) morphology in the tight sandstone reservoir. Further, the number, approaching angle, and cementation strength of the preexisting NF affect the HF propagation path; these are the key factors for forming complex fractures. In the tight sandstone reservoir with well-developed NFs, the fracture morphology is dominated by the NF under horizontal differential stress ≤ 9 MPa. A single fracture is more likely to occur under horizontal differential stress ≥ 12 MPa, which is less affected by the NF. In the fracturing at variable injection rates, a low rate facilitates fluid penetration into the NF, while a high rate facilitates deep HF propagation. A low-viscosity fracturing fluid at a high rate facilitates further propagation of the temporary plugging agent (TPA), thus achieving deep temporary plugging and fracture diversion. A high-viscosity fluid does not facilitate accumulation and plugging of particulate TPA. Higher horizontal differential stress leads to a smaller diversion radius of new HF, which is closer to the original HF, leading to poorer stimulation effect. The results provide a reference for the fracturing design of the tight sandstone.

Simulation of the meso-macro-scale fracture network development law of coal water injection based on a SEM reconstruction fracture COHESIVE model

Coal seam fracturing and water injection are important techniques for increasing permeability in joint coal and gas mining operations. The mechanism of fracture development during water injection fracturing has always been an important yet fully understood scientific issue. Scholars have conducted many studies on macro-scale fracturing laws and micro-meso-scale structure characterization, but few on the development laws of fracture networks under the macro-meso scale. In this study, scanning electron microscope (SEM) technology, image digital processing, simplified model processing, and fractal algorithm verification methods were applied to obtain an expanded macro-scale model. A global embedding cohesive model was adopted to study the fracture development law of water-injected coal samples under different stress differences. The fracture development laws at the meso and macro scales were determined, two modes of fracture development at the meso scale were found, and fracture development was divided into three stages. All the natural fractures in the development coverage of fractures were included in the development process. The effect of natural fractures on the development direction of the macro-scale fracture and the rule that the macro-scale development direction of fractures is parallel to the meso-scale natural fracture direction were observed. Pore pressure was closely related to the development process of the fracture. The increase in pore pressure at the tip of the fracture signified the start of fracture division and density increase. Finally, the relationship equations between parameters, such as water injection pressure, macro-scale development range, and initial fracture width, were also determined.

Effect of natural filling fracture on the cracking process of shale Brazilian disc containing a central straight notched flaw

The interaction between hydraulic fractures and natural fractures is a key factor in the forming of complex networks during shale fracturing. In spite of abundant natural filling fractures having been found in practical shale layers, previous studies have either ignored the effects of natural fractures or highly simplified them. In order to investigate how the natural filling fracture effect on crack propagation, in this paper, the central straight notched Brazilian discs (CSNBD) of shale under different loading angles were used to study the crack initiation and propagation via digital image correlation (DIC) method. The testing results reveal that the natural filling fracture leads to larger loading displacement, more active acoustic emission signals and lower strength, which indicates that the infillings may contain numerous micro-cracks, therefore, making the filling fracture a weak structure; The crack propagating path was unaffected when the filling natural fracture is parallel to loading line, while the natural filling fractures still on the risk of cracking due to the incompatible deformation between the natural infillings and the host rock; Besides, the initial cracking angle of the crack tip near the natural filling fracture increases while it decreases for the crack tip away from the natural filling fracture when the loading angle is 30°, 60° and 90°, nevertheless, for these discs without an infilling fracture, the two wing cracks are nearly symmetrical and initial cracking angles are almost equal. This research manifests that, on the laboratory scale, the failure modes and the cracking patterns of shale become more complicated when natural filling fractures exist. Therefore the influences of natural filling fractures could be even more significant when it is referred to the practical scale of on-site hydraulic fracturing, the related topics should be further studied in detail.

The effect of natural fractures on CO2storage performance and oil recovery from CO2and WAG injection in an Appalachian basin reservoir

AbstractNatural fractures affect both the oil recovery from the enhanced oil recovery (EOR) process and the associated CO2storage during and after EOR. The main objective of this study is to evaluate two performance parameters: (1) oil recovery during CO2and water alternating gas (WAG) injection, and (2) CO2storage, during and after EOR, in a fractured oil reservoir of the Appalachian basin. While previous studies have shown the potential of CO2‐EOR to enhance oil recovery in the Appalachian basin, this work investigates WAG performance in comparison to continuous CO2‐EOR. A compositional numerical modeling approach was used to quantify the incremental oil recovery stemming from incorporating natural fractures. History matching of primary production and CO2huff‐and‐puff pilot test for a well producing from a depleted oil field in Ohio was used to assign the fracture network parameters in the dual continuum model. The scenarios modeled include continuous CO2and WAG injection under two injection pore volumes. Each scenario is followed by a CO2storage phase. These simulations help evaluate the performance of different scenarios in terms of oil recovery and CO2storage. Simulation results show how oil recovery and CO2storage vary significantly as a function of operational parameters. The results also show the amount of CO2stored during WAG injection is significantly lower than that stored during the storage phase at the end of oil recovery. In addition, the operational parameters during WAG affect the amount of CO2stored at the end of following storage phase. © 2020 Society of Chemical Industry and John Wiley & Sons, Ltd.

Prediction and control of hydraulic fracture trajectory in enhanced geothermal system

ABSTRACT A new fully coupled numerical model is presented to analyze artificial fracture morphology and artificial fracture propagation during synchronous fracturing. The interaction mechanism between natural and artificial fractures is also considered in this new model. The new numerical solution, based on the boundary element method (BEM) and the finite difference method, is used to solve the problem of coupled rock deformation, fluid interference, stress interference, interface slipping, and opening and to investigate the effect of natural fractures and interference between fractures on fracture morphology during synchronous fracturing. An analysis of factors of influence showed that synchronous fracturing can be used to control the fracture trajectory and construct an effective enhanced geothermal system (EGS). Artificial fractures of two adjacent wells attract each other during synchronous fracturing, and eventually, the two fractures become connected, and the two wells become connected. The choice of well location also has an important influence on the successful establishment of an EGS. To establish an effective EGS successfully, the fracture spacing should preferably be no more than 20 m, and the well spacing should preferably be greater than 400 m. An EGS is easier to construct in a hot dry rock reservoir with a high natural fracture density and small natural fracture angles (preferably less than 30º).

Effect of Natural Fractures on Shale Gas Reservoir Reconstruction

Natural fractures have great influence on shale gas reservoir reconstruction. In order to find out the law of influence, comprehensive analysis of the characteristics of geological natural fracture and fracturing fracture before fracturing is carried out. Firstly, natural cracks are identified by using coherence and maximum relief attributes of ground seismic data. Secondly, the characteristics of hydraulic fracturing cracks and the response characteristics of natural cracks are analyzed by using the results of microseismic monitoring and positioning and the data of hydraulic fracturing construction. Finally, the influence of natural fracture on the effect of fracturing reconstruction is summarized. The results show that the response characteristics of natural cracks predicted by surface earthquakes are different in the results of microseismic monitoring. According to the response characteristics of natural cracks, they can be divided into active and inactive natural cracks. Combining with the fracturing data, it is found that both active and inactive natural cracks will affect the fracturing construction to varying degrees. Active natural fractures are prone to abnormal construction conditions such as sand plugging, casing deformation and fracturing fluid leakage. Non-active natural fractures play a role of stress shielding under certain conditions, which can affect the fracturing fracture morphology and the effect of fracturing reservoir reconstruction. The research results provide a basis for shale gas horizontal well trajectory optimization and adjustment of hydraulic pressure construction parameters.

Study on Prevention of Gas Channelling of Acid-resistant Gel Foam in CO2 Flooding of Low Permeability Reservoir

With the shortage of recoverable reserves in conventional oil reservoirs, the development of low-permeability oil reservoirs has received more and more attention. The oil recovery of low-permeability reservoirs can be significantly improved by CO2 flooding, as it can effectively supply formation energy. CO2 flooding is an effective technology for increasing oil production in low-permeability reservoirs. However, because of the heterogeneity of the reservoir and the effect of natural fractures, CO2 gas channelling easily occurs during CO2 flooding, seriously reducing CO2 flooding effect. In this study, the gas channelling technology of acid-resistant gel foam was investigated. Preferred acid-resistant gel foam system formula was found as 0.1% by mass of AOS foaming agent with 0.3% to 0.4% by mass of instant HPAM polymer and 1% to 2% by mass of water-soluble phenolic resin crosslinking agent. This system still has a good foaming ability and blocking performance under at pH=2 and a salinity of 10×104 mg/L. After 60 days of aging under oil reservoir conditions, there is no obvious water separation, and the plugging strength retention rate reached more than 60%. The gel foam channelling system can be applied to highly heterogeneous and low permeability reservoirs with a permeability gradient higher than 14 and can increase the recovery rate by more than 20% based on the CO2 flooding. Acid-resistant gel foam channelling technology can effectively inhibit CO2 gas channelling and improve CO2 flooding effect in low permeability reservoirs.

Effect of Natural Fractures on Stress Evolution of Unconventional Reservoirs Using a Finite Element Method and a Fracture Continuum Method

Refracturing, temporary plugging, and infilling well design play an important role in the development of reservoirs. The prediction of stress distribution can provide the basic guiding theory for the design and implementation of these techniques. In this paper, a fully-coupled three-dimensional production model based on the finite element method (FEM) and fracture continuum method (FCM) for naturally fractured reservoirs is presented to study the effects of fluid consumption on the reservoir stress. Furthermore, the effects of natural fractures on the stress re-distribution and stress re-orientation are also studied. The model also considers the influence of natural fractures on the permeability, and the effect of the effective stress on natural fracture openings, pore-elastic deformation, and fluid consumption. An analytical solution model and Eclipse were used for the comparison, which verifies the accuracy of the model results. Based on two cases of one cluster of fractures and three clusters of non-planar fractures, the research results revealed that natural fractures have a significant influence on the surrounding drainage, stress distribution, and stress re-orientation during the development. Under the influence of natural fractures, the production of the fluid along the direction of natural fractures is significantly easier, and it is highly probably that the insufficient consumption area is perpendicular to the direction of natural fractures. Compared with the conventional model, the stress distribution in the proposed model is deflected to a certain extent under the flow mode dominated by natural fractures, which is significantly prominent in the non-planar fracture model. Due to the effect of natural cracks, the absolute values of the stress, displacement, and stress difference in this model are relatively larger than those in the conventional model. Moreover, the re-orientation angles of the maximum principal stress are significantly different. After considering the natural cracks, there was an increase in the change in re-orientation and the re-orientation range. The research findings reported in this paper can be used to predict the initiation, extension, and steering process of temporary plugging fracturing fractures and refracturing fractures in fractured reservoirs.

Effect of natural fractures on determining closure pressure

In Utah FORGE reservoir, eight pressure transient tests (microhydraulic fracturing and DFIT™) show natural fracture/pressure-dependent leakoff. This behavior may lead to misinterpretation of the closure pressure (proxy for minimum principal stress). The closure pressures obtained from DFIT™ (or microhydraulic fracturing) testing may reflect shear failure along natural fractures or discontinuities rather than tensile failure and lead to inaccurate estimates of the minimum principal stress. In pressure tests conducted at the Utah FORGE site showed that reactivation or opening of natural fractures intersecting the wellbore and were suggested by multiple closure events in DFIT™ tests. In addition, comparisons between the pre- and post-well-tests FMI logs show that there are populations of induced fracture and reactivated natural fractures which are mostly vertical and sub-vertical. In this study, DFIT™ (or microhydraulic fracturing) test analysis and numerical simulations were used to suggest that hydraulic shearing of critically stressed natural fractures can contribute to multiple closure signatures and possibly lead to incorrect determination of the minimum principal stress. As other authors have previously advocated, the DFIT™ test analyses and numerical simulations suggest that better estimations of minimum principal stress may be derived by injecting at relatively high rate and pressure and insuring that tensile breakdown is reached. In addition, extended shut-in period is required to determine accurate reservoir characteristics and fluid flow regime.