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The homogeneous acid etching of conventional acid in porous heterogeneous carbonate reservoirs leads to a large amount of consumption in the near-wellbore area, which makes the acidification effect often not ideal. In order to improve the acidizing effect of porous heterogeneous carbonate reservoirs, viscous acid is used to increase the stimulation of the target block in this paper. Through systematic experiments, the adaptability of the viscous acid in the four layers of the M reservoir in the target block was evaluated, and the MD and ME layers suitable for acidizing stimulation were determined in combination with physical property analysis. Finally, based on the geological characteristics and experimental data of the preferred layers, a two-scale acid wormhole growth radial model was established, and the construction parameters of acidizing stimulation were optimized. The results show that (1) The preferred viscous acid system has a dissolution rate of more than 95% for the rock powder in the four layers. When the matrix permeability is high, the effect of the acid wormhole is obvious and the permeability increase is higher. (2) The steel sheet corrosion and residual acid damage experiments showed that the acid system was not corrosive to the wellbore, and the reservoir damage rate of the residual acid after the reaction was low. (3) Based on the relationship between reservoir porosity and permeability and the position of edge and bottom water, the MD and ME layers with more potential for acidizing stimulation are selected. (4) The results of the numerical simulation show that the optimal acid pump rate of the MD and ME layers is 1.4 bpm and 1.0 bpm, and the acidizing fluid volume is 255 bbl, which can form effective acid wormholes, and the range of reservoir permeability transformation is the largest. The field application results show that the optimization scheme effectively improves the production of oil wells, verifies the practicability of the scheme, and provides a reference for the process optimization of viscous acid in the same type of porous heterogeneous carbonate reservoir stimulation. [ABSTRACT FROM AUTHOR]

Mishrif (M) reservoir of Faihaa (F) oilfield in Iraq is a heterogeneous porous carbonate reservoir. The reservoir properties of each reservoir unit differ greatly, and the distribution of porosity and permeability is non-uniform. Some reservoir units have the problem that the expected production cannot be achieved or the production decline rate is too fast after matrix acidification. This work optimized and compared the process of acid fracturing and hydraulic fracturing techniques. The Mishrif B (MB) and Mishrif C (MC) layers are selected as the target units for fracturing and the perforation intervals are optimized. The acid fracturing process adopted the acid fracturing technology of guar gum pad fluid and gelled acid multi-stage injection. According to the wellhead pressure limit and fracture propagation geometry, the pumping rate is optimized. The recommended maximum pumping rate of acid fracturing is 5.0 m3/min, and the optimized acid volume is 256.4 m3. The pressure changes during hydraulic fracturing and acid fracturing are different. It is recommended that the maximum hydraulic fracturing pump rate is 4.5 m3/min for MB and MC layers, and the amount of proppant in MB and MC layers is 37.5 m3 and 43.7 m3, respectively. The production prediction of two optimized processes is carried out. The results showed that the effect of acid fracturing in MB and MC layers is better than hydraulic fracturing, and it is recommended to adopt acid fracturing technology to stimulate MB and MC layers. Acid fracturing operation is carried out in the X-13 well, and better application results are achieved. The results of this study provide optimized reference ideas for reservoir stimulation in heterogeneous porous reservoirs. [ABSTRACT FROM AUTHOR]

Temporary plugging diversion fracturing (TPDF) technology has been widely used in various oil fields for repeated reconstruction of high-water-cut old oil wells and horizontal well reservoir reconstruction. Previous studies have carried out in-depth study on the pressure-bearing law and placement morphology of different types of temporary plugging agents (TPAs) in fractures, but there are relatively few studies on TPA accumulation body permeability. To solve this problem, an experimental device for evaluating the TPA performance with adjustable fracture pores is proposed in this paper. Based on the test of fracturing fluid breaking time and residue content, the low damage of fracturing fluid to the reservoir is determined. The TPA degradation performance test determines whether the TPA causes damage to the hydraulic fracture after the temporary plugging fracturing. Finally, by testing the TPA pressure-bearing capacity and the temporary plugging aggregation body permeability, the plugging performance and the aggregation body permeability are determined. The results show the following: (1) Guar gum fracturing fluid shows good gel-breaking performance under the action of breaking agent, and the recommended concentration of breaking agent is 300 ppm. At 90~120 °C, the degradation rate of the three types of TPAs can reach more than 65%, and it can be effectively carried into the wellbore during the fracturing fluid flowback stage to achieve the effect of removing the TPA in the fracture. (2) The results of the pressure-bearing performance of the TPA show that the two kinds of TPAs can quickly achieve the plugging effect after plugging start: the effect of ZD-2 (poly lactic-co-glycolic acid (PLGA)) particle-and-powder combined TPA on forming an effective temporary plugging accumulation body in fractures is better than that of ZD-1 (PLGA) pure powder. There are large pores between the particles, and the fracturing fluid can still flow through the pores, so the ZD-3 (a mixture of lactide and PLGA) granular temporary plugging agent cannot form an effective plugging. (3) The law of length of the temporary plugging accumulation body shows that the ZD-2 combined TPA has stronger plugging ability for medium-aperture simulated fracture pores, while the ZD-1 powder TPA has stronger plugging ability for small aperture simulated fracture pores, and the ZD-3 granular TPA should be avoided alone as far as possible. This study further enriches and improves the understanding of the mechanism of temporary plugging diverting fracturing fluid. [ABSTRACT FROM AUTHOR]

The migration and sedimentation behavior of proppant in complex fractures plays a vital role in the formation of fractures with high conductivity. Most of the existing studies on proppant sedimentation and migration are based on a single vertical fracture model that propagates in the same direction. However, due to in situ stress and reservoir heterogeneity, the propagation of fractures in reservoirs will produce multiple branch fractures that intersect with the main fractures and have a certain inclination angle. Therefore, it is necessary to study the sedimentation and migration behavior of proppants in inclined complex fractures. In this paper, the proppant particles sedimentation law in fractures is studied based on computational fluid dynamics. By changing the particle size, volume fraction, and inlet flow velocity of proppant, the migration and sedimentation law of proppant in a single fracture is simulated and verified. Then, through the establishment of a complex fracture model with multiple branches, and from the four dimensions of the vacant length of the front edge of the sand embankment, the length of the sand embankment, the highest point of the sand embankment, and the effective laying area of the proppant, the angle between the main and branch fractures in the complex fractures, the fracture angle and the inlet flow velocity, as well as the location relationship of the branch fracture setting and the migration and sedimentation of the proppant in the complex fractures are explored. [ABSTRACT FROM AUTHOR]

The development of natural fractures (NFs) in shale gas reservoirs is conducive to improving the productivity of shale gas wells. However, NF development leads to high-frequency frac hits between the infill and parent wells, which critically restricts its efficiency. To elucidate the large contribution of hydraulic fractures (HFs) and NFs in frac hits during the production and the development of NF-developed shale gas reservoirs, such reservoirs in the WY area of western China are taken as an example. A total of 197 frac hits well events in this area are systematically classified via the frac-hit discrimination method, and the effects of different factors on HF- and NF- dominated frac hits are classified and studied. Combined with the correlation analysis method and the chart method, the main controlling factors affecting the two types of frac hits are determined, and the corresponding frac-hit prevention countermeasures are proposed. The research demonstrates that (1) the distribution and development of NFs are crucial to production after frac hits. NFs and HFs in the WY area cause 51% and 49%, respectively, of the frac hits. (2) The main controlling factors in NF-dominated frac hits are the approximation angle, fracture linear density, and horizontal stress difference, whereas they are net pressure in fractures, horizontal stress difference, and liquid strength in HF-dominated frac hits. Sensitivity analysis shows that the NF activation difficulty coefficient fluctuates between −35.1% and 47.6%, and the maximum hydraulic fracture length fluctuates between −43.5% and 25.29%. (3) The corresponding frac-hit prevention countermeasures are proposed for the two types of formation mechanisms from different approaches, including frac-hit risk assessment and path planning, production well pressurization and stress diversion, and infill-well fracturing parameter optimization. This paper not only provides a reference for exploring the formation mechanism of frac hits in fractured shale gas reservoirs but also a theoretical basis for the corresponding frac-hit prevention countermeasures. [ABSTRACT FROM AUTHOR]

The staged and multi-cluster fracturing of horizontal wells is the main fracturing technology used for shale gas reservoir development. Temporary plugging diversion (TPD) is an important technical means to realize a uniform propagation of hydraulic fractures and avoid problems such as frac hits (i.e., well-to-well interference). Although this technology has been extensively used worldwide, field monitoring results have shown that temporary plugging cannot effectively improve the nonuniform propagation of multiple fractures. The fundamental reason is the lack of an organic combination of laboratory research and field application. To solve this problem, this study investigated the reservoir adaptability and plugging performance of three types of temporary plugging agent (TPAs), namely, powder, particle, and fiber, used in the fracturing of wells in the Weiyuan (WY) shale gas field, Sichuan, China, using a pressure-bearing capacity test device for three dimensional (3D)-printing-simulated TPA. A calculation method for the plugging efficiency of the TPA was established, and the ratio and concentration of the TPA were optimized under different fracture widths. The similarity criterion was used to calculate the amount of TPA required for different fracture widths. A field application chart of the TPA was formulated, and a method that connects laboratory research and field application was established. The results showed that the three TPAs have good reservoir adaptability and degradation performance. It is recommended to use 200–400 mesh powder + 6 mm fiber with different concentrations and dosages when performing temporary plugging and fracturing at the front end of 1–3 mm fractures. In the case of inter-cluster TPD for a fracture width of 4–6 mm, a combination of 20 mesh powder + 6 mm fiber + 1–3 mm particles is recommended. The field application results showed that the pressure increased significantly at the front end of the fractures and during inter-cluster temporary plugging when the plugging agent was in place, and there were no frac hits in the adjacent wells. This paper provides a practical research method for hydraulic fracturing involving temporary plugging, from laboratory research to engineering application. [ABSTRACT FROM AUTHOR]

Natural fractures (NFs) are developed in shale gas reservoirs, which can easily cause frac hits during hydraulic fracturing and reduce the productivity of infill wells and parent wells. Temporary plugging diverting fracturing (TPDF) can hinder the single forward extension of fracture transition and avoid the communication of hydraulic fractures (HFs) or NFs adjacent to wells. In order to explore the fracture propagation law of TPDF in fractured shale gas reservoirs, this study systematically evaluates the main factors such as stress difference, displacement, and fracturing fluid viscosity on the fracture temporary plugging diversion (TPD) law by means of true triaxial hydraulic fracturing simulation device and cohesive element model in ABAQUS. The findings reveal that (1) the law of fracture initiation and propagation at the engineering scale is similar to that in indoor experiments. Upon the primary fracturing (PF), the smaller the horizontal stress difference, the larger the pumping displacement, and the smaller the viscosity of the fracturing fluid is, the greater the corresponding fracture breakdown pressure and the stronger the rock compression resistance. (2) After TPD secondary fracturing, a small horizontal stress difference and a large pumping displacement facilitate the formation of a vertical complex fracture network structure on the primary fracture. Because of the small size of the indoor rock, viscosity has little effect on the fracture propagation of the TPDF, but the numerical simulation results reveal that the higher the viscosity, the greater the width of the new fracture. In addition, (3) the smaller the angle between the new fracture opened after PF and TPDF, the better the propagation effect of the new fracture. Meanwhile, the farther the temporary plugging zone is from the fracture front end, the wider the new fracture opened after TPDF. The field construction results reveal that the TPDF technology can avoid the effect of HFs, thus preventing frac hits during shale gas reservoir reconstruction. This study not only posits a physical and numerical simulation method for simulating the fracture propagation law of TPDF in fractured shale gas reservoirs but also provides theoretical guidance for applying TPDF to field construction. [ABSTRACT FROM AUTHOR]

For tight oil and gas reservoirs to form complex fracture networks with high conductivity and repeated treatment of old wells, temporary plugging and diverting fracturing technology has become one of the important stimulation methods. Previous articles have been carried out on different types of temporary plugging agents in fracture pressure rise law and placement shape, but studies on the permeability of temporary plugging cakes are relatively lacking. In this paper, the pressure rise law of five kinds of temporary plugging agent is studied by conventional fracture simulation device, and the permeability properties of temporary plugging cakes are studied by original design manufactured porous medium device. The results show that there are some differences between the permeability of temporary plugging cakes and the formation of pressure-bearing plugging cakes, the permeability is related to the types of plugging cakes, and the pressure rising law is related to the type and particle size distribution of temporary plugging material. The maximum length of DA-1, DA-2, DA-3 and KMS-D aggregates is 2.93 cm, 5.83 cm, 6.73 cm and 6.00 cm, and the minimum aggregate permeability is 23.88 mD, 19.19 mD, 15.13 mD and 36.97 mD. [ABSTRACT FROM AUTHOR]

In the development of natural gas reservoirs, the water produced in wells will cause a decline in gas well productivity. In this study, a selective frozen gel plugging agent system suitable for water plugging in gas reservoirs under conditions of high temperature and high salinity. The plugging capacity of the gel system was evaluated. The experimental results showed that: (1) the optimal experimental scheme of the frozen gelling system was as follows: 107 °C with 1.0% AM-AMPS +0.6% p-benzenediol +0.6% hexamethylenetetramine +0.2% thiourea. (2) The optimal injection volume of the system for water phase plugging was 0.5 PV, and the system has an excellent plugging effect at a permeability of 356–3118 mD. (3) The system could also effectively improve the degree of heterogeneity, and the smaller the degree of heterogeneity, the better the improvement effect. (4) The gel system had a good effect on different plugging methods, and the gas medium did not affect the plugging performance. This study provides a sufficient theoretical basis for the exploitation of high-temperature and high-salinity water-bearing gas reservoirs through experimental research, which is of great significance for improving production capacity. [ABSTRACT FROM AUTHOR]

A temporary plugging agent is an effective tool for increasing production in old wells. By considering the temporary plugging materials used in the remote WY area, three concentrations and five ratios under different fracture widths were designed and optimized. Thus, the fracture diversion under true triaxial stress was studied. The results showed that when the fracture widths were 2.0, 4.0, and 6.0 mm, the corresponding optimal plugging scheme was that the concentrations of the temporary plugging agent were 12.0, 18.0, and 18.0 kg/m3 and the ratios of 20–70 mesh to 200–300 mesh temporary plugging agent were 4:1, 2:1 and 4:1, respectively. When maintaining the same horizontal stress, an increase in the axial stress was accompanied by an increase in the fracture pressure; the initial fractures almost propagated along the direction of the horizontal maximum principal stress, but the shapes of the turning fractures were different. When the axial stress was the same, an increase in the horizontal stress difference was accompanied by a decrease in the corresponding fracture pressure and a gradual decrease in the degree of fracture turning. This study provides a basis for numerical simulation and field application of temporary plugging fracturing at fracture ends. [ABSTRACT FROM AUTHOR]

AbstractNatural gas hydrate is one of the main clean energy sources. It has abundant reserves and high exploitation value in the world. At present, the injection inhibitor decomposition method is the most effective extraction method. In order to further clarify the mechanism of thermodynamic inhibitors for methanol, this paper combines experimental and molecular simulation methods to study the dynamic influence mechanism of methanol on hydrate formation and decomposition in simulated seawater. The specific mechanism of how salt ions and alcohol molecules affect hydrate growth is analyzed, and an explanation is given accordingly. The results show that: ① Methanol at a concentration of 1 wt% has a promoting effect of 9.91% on the formation of methane hydrates. At lower concentrations of 3 wt% and 5 wt%, methanol shows a weak inhibitory effect on hydrates. At a concentration of 10 wt%, the formation of hydrates is completely inhibited. ② From the perspective of kinetics analysis, methanol has no effect on the decomposition of hydrate, but can effectively inhibit the secondary formation of hydrate. ③ The salt ions in simulated seawater have hydration and salt-expulsion effects, which continuously reduce the solubility of methane, leading to an extended growth period of hydrate and inhibiting the formation of hydrate. ④ The molecular simulation results show that when the simulation step size lasts for 30 ns, methane gas exhibits different existential states in simulated seawater and fresh water. The former shows obvious gas-liquid stratification, and the latter appears in the form of nanobubbles, and an increase in methanol concentration will prolong the formation time of methane nanobubbles. ⑤ According to the simulation results from the perspective of molecular dynamics, when methanol molecules enter the crystal cavity of the hydrate, the hydroxyl groups will disturb the formation of the hydrogen bond network of the hydrate, resulting in the inability of the hydrate cage structure to close, which inhibits the formation of the hydrate. The above research results are helpful for field personnel to deepen the understanding of the mechanism of methanol inhibitors. [ABSTRACT FROM AUTHOR]

The surface of a tight reservoir appears to be oil-wet or mixed-type wet upon soaking in crude oil for a long time, and the yield decreases rapidly after fracturing under the influence of capillary force. The oil sweep efficiency affected by many factors such as formation water dilution, salinity, crude oil type, temperature, and pressure can be enhanced by adding nanosurfactants into the fracturing fluid, so it is necessary to study the influence of different factors on the spontaneous imbibition replacement efficiency of nanosurfactants. In this study, the basic properties of nanosurfactants such as particle size, oil-water interfacial tension (IFT), and the wetting modification effect were tested, and the influence of surfactant type, concentration, temperature, and pressure on imbibition replacement efficiency was studied. The main conclusions are as follows: (1) The particle size of the nanosurfactant that was synthesized by a microemulsion method is 12-21 nm, which indicated good injectability in tight cores. Moreover, the IFT values between the crude oil and five kinds of 0.30 wt % nanosurfactants were all lower than 0.15 mN/m, and nanosurfactant C had the best wetting modification effect with increasing the contact angle by 100.30°. (2) The type and concentration of surfactant have a certain influence on imbibition replacement efficiency, and appropriate concentration of anionic nanosurfactant is beneficial to enhancing the imbibition replacement efficiency. The imbibition replacement efficiency of 0.30 wt % anionic surfactant C solution is higher than that of nonionic and cationic surfactant solutions, and the imbibition replacement efficiency is as high as 33.386% under NTP . (3) The nanosurfactant in brine is prone to forming fine emulsified oil droplets with crude oil and activates the oil droplets in the small pores to enhance the imbibition replacement efficiency. The crude oil type, temperature, and pressure can influence imbibition replacement efficiency, and the influence of crude oil type and temperature is greater than that of pressure. This work further studies the influencing factors of imbibition replacement efficiency., Competing Interests: The authors declare no competing financial interest., (© 2021 The Authors. Published by American Chemical Society.)