Water Plugging Research Articles

Experimental Study of Synergy between Polymeric Microspheres and Nanoemulsions for Profile Control and Water Plugging.

The development of low-porosity and low-permeability oil reservoirs in the Changqing oilfield presents a significant challenge due to the high injection pressure and limited space for profile control and pressure raising. Therefore, the synergistic profile control and flooding technology of polymer microspheres (PMs) and nanoemulsions is proposed, which makes use of the plugging performance of PMs and the pressure-reducing and oil-driving properties of nanoemulsions, with the objective of controlling the water-absorbing profile and increasing the recovery rate. The paper assessed the properties of nanoemulsions and PMs and evaluated their suitability for reservoirs. The construction parameters of profile control and flooding were optimized on an experimental basis. The experimental results demonstrate that the initial particle size of microspheres can more closely match the pore diameter of the formation and that the core exhibits a higher plugging rate after hydration and expansion. Moreover, the nanoemulsion can effectively reduce the interfacial tension, thereby exerting a beneficial effect on pressure reduction. The construction parameters of microspheres and nanoemulsions were optimized by alternately injecting them with 2:1 multistage plugs, and the injected pressure was lowered by 43%, with a high plugging rate and value-added recovery rate of up to 26.5%. Based on the experimental study, 8 well sets of field tests were conducted, and the results demonstrated that the efficiency rate of profile control reached 50%. Furthermore, the average injection pressure of the injected wells decreased by 1.7 MPa, the rise in water content decreased by 2.27%, and the petroleum production increased by 1110.2 tons. The validity period reached 162 days, indicating a positive application effect.

Study on increasing polymer gel strength with Janus nanoparticles and its feasibility in profile control and water plugging

In formations subjected to prolonged flooding, dominant channels are formed in high permeability layers, thereby reducing the displacement efficiency in medium- and low-permeability layers. In this study, the Janus synthesis method was employed to produce Janus Nano-TiO2 with a particle size range of 60–120 nm and superior dispersion properties. These nanoparticles were subsequently combined with polyacrylamide to formulate a high-strength polymer nano-gel for water plugging applications. The successful synthesis of the material was confirmed through FTIR and TGA. Gelation experiments indicated that the gelation strength and time augmented significantly with the increased addition of Janus-T6. Conversely, an increase in temperature or salinity resulted in a reduction of both gelation strength and time. Rheological experiments demonstrated a decrease in polymer viscosity with rising shear rates or temperatures, revealing significant shear thinning behavior in the water-plugging agent solution. System viscosity increased with more Janus-T6. Flow experiments revealed decreasing resistance coefficients at higher permeabilities, while all cores exhibited plugging rates above 85%. Additionally, the breakthrough pressure continuously rose with the increased addition of Janus-T6. Ultimately, displacement experiments indicated a 22.83% increase in the recovery rate after employing PNG plugging followed by secondary water flooding, compared to primary water flooding alone.

Research and Application of Chemical Water Plugging Technology with High Salt Resistant Gel and Immobile String

Abstract The salinity of formation water in Gasi N1-N2 reservoir is 18 × 104 mg/L, in which calcium and magnesium ions are 6300 mg/L. The conventional gel used for profile control and water plugging has poor salt resistance and is easy to dehydrate under the erosion of formation water; At the same time, the chemical water plugging of oil wells in the past needs to trip down the downhole string for many times, and the construction period is long. In order to solve the former problem, an anti-high salt organic gel suitable for Gasi N1-N21 reservoir is synthesized. The formula is 0.4 wt% SD-3000 + 0.1-0.2 wt% urotropine + 0.05 wt% resorcinol + 0.4 wt% additive. The viscosity of the gel is more than 6000 mPa.s after gelation, and no obvious dehydration phenomenon is found after aging for five months in the formation water environment of Gasi N1-N21 reservoir at 65 °C. The technology of chemical water plugging without moving the string has been innovatively developed, which does not require the operation of tubing and pump during construction. In Gasi N1-N21 reservoir, anti-high salt gel was used to carry out three well-times of chemical water plugging tests without pulling the string, which were all successful, saving 44% of the cost of measures and shortening 78% of the construction period. After water plugging, water production was obviously inhibited, and the average moisture content was reduced from 95% to 45%. The average daily oil increment of a single well was 1.8 tons, and the cumulative oil increment was 1700 tons. The results show that the chemical water plugging technology without pulling string has broad application prospects in Gasi N1-N21 reservoir in Qinghai Oilfield and similar reservoirs in China.

Research Progress onLeak Prevention and Plugging Technology in Deepwater Drilling

Abstract With the continuous development of global oil and gas resources, onshore and shallow water crude oil production is no longer sufficient to meet the demand. Therefore, deepwater oil and gas exploration and development have attracted high attention from various countries. China’s oceans are vast and rich in offshore oil resources, especially in the South China Sea, where oil and natural gas reserves are enormous. In recent years, it has become a key focus of national offshore oil exploration and development. The increasing complexity of deep-sea well leakage in the ocean and the increasing difficulty of management have brought great challenges to drilling construction and also caused significant economic losses. Therefore, the research on leak prevention and plugging technology for deep water in the ocean has become particularly important. This article investigates the current research status of deep water leakage prevention and plugging technology both domestically and internationally, discusses the main problems that exist in the development and drilling process of deep water oil and gas fields, analyzes the reasons for well leakage, and proposes corresponding solutions.

Research and Application of Compound Movable Gel Plugging Agent Suitable for Gasi Oilfield

Abstract In order to meet the water plugging requirements of high salinity reservoirs at different temperatures, we developed three kinds of movable gel plugging and regulating agent by using salt resistant polymer as the main agent, organic chromium and organic aldehyde as the cross-linking agent, supplemented by organic stabilizers and reinforcing agents. Namely, low, medium and high-temperature and high-salinity composite movable gel plugging and regulating agent, and the formulas are 0.4% YG-100 + 0.1% YG-107,0.4% YG-100 + 0.15% YG-107+0.8% YG-103,0.4% YG-100+0.15% YG-107+0.8% YG-103 respectively. The gelling performance, thermal stability and salt resistance of the composite movable gel are evaluated. The results showed the suitable temperature is 40~126 °C, and the salinity of formation water is 260000mg/L. Seven well groups were implemented on site, and the oil pressure in the water wells generally increased. Water channeling was controlled to a certain extent, and the comprehensive water content decreased from 90.5% to 85.1%, a decrease of 5.4%. The cumulative increase in oil production was 3164 tons, and a good oil increase effect was observed.

Enhancement and mechanism of mechanical properties and functionalities of polyacrylamide/polyacrylic acid hydrogels by 1D and 2D nanocarbon

Highly flexible hydrogels are widely used in fields such as agriculture, drug delivery, and tissue engineering. However, the simultaneous integration of excellent mechanical properties, swelling properties, and high electrical conductivity into a hydrogel is still a great challenge. This work introduces 1D tubular multi-walled carbon nanotubes (MWCNTs) and 2D layered graphene oxide (GO) into polyacrylamide/poly-acrylic acid (PAM/PAA) hydrogels. The high specific surface area and oxygen-containing groups of GO contribute to excellent mechanical properties and water absorption of the PAM/PAA hydrogels, but the conductivity is poorly affected due to the presence of defects on GO surface. However, MWCNTs with large aspect ratios benefit to form continuous conductive paths in PAM/PAA hydrogels which further improves conductivity of the hydrogels. MWCNTs are entangled with PAM/PAA molecular chains to form a dense three-dimensional (3D) network structure, and this special structure improves the water absorption of PAM/PAA hydrogels by 3.7 g g−1. What’s more, the MWCNTs/PAM/PAA hydrogel not only provides excellent mechanical properties (compressive strength up to 2.7 MPa), but also has high conductivity (2.3 S m−1). In particular, a strain sensor based on MWCNTs/PAM/PAA hydrogel exhibits exceptional sensitivity (gauge factor = 3.9 at 230–300 % strain) with a rapid response (200 ms) over a wide strain range (50 ∼ 200 %) which enables the ability to precisely and reliably monitor human motion. Therefore, the work provides a new insight into the design of multifunctional hydrogels with application on anatomical water plugging, electronic skin, and biosensors.

Design, synthesis, and characterization of novel copolymer gel particles for water-plugging applications

Abstract Multi-stage plugging represents a promising strategy for enhancing production and injection rates in medium-and low-permeability oilfields. Despite its potential, the efficacy of current plugging agents, particularly hydrophobically bonded water-soluble polyacrylamide-based gel microspheres, is hindered by notable drawbacks such as low stability and inadequate compressive strength. Therefore, a comprehensive understanding of water plugging mechanisms coupled with the optimization of gel microsphere properties is essential for advancing the development of gel-based plugging agents with superior characteristics or intelligent regulatory capabilities. The P(AA-AM-[PrSO3]Vim) ionic liquid copolymerized gel particles were designed and synthesized by using microfluidic technique and titration gel method with AM, acrylic acid (AA), 1-vinylimidazole (Vim) and 1,3-propylsulfonyl lactone (PrSO3) as the raw materials. The morphology and structure of the copolymer gel particles were characterized, and the effects of [PrSO3]Vim and cross-linker content on the water-absorbing properties and strength of the gel particles were investigated. When the amount of [PrSO3]Vim was 12%, the concentration of crosslinker was 1.5%, and the temperature was 40°C, the water absorption capacity reached the maximum value of 163 g·g−1. The strength of the P(AA–AM–[PrSO3]Vim) spherical gel particles was maximized at a [PrSO3]Vim content of 4%. Furthermore, the chemical and physical roles of the P(AA–AM–[PrSO3]Vim) spherical gel particles were studied in a typical water-plugging environment. This study provides experimental data and a theoretical basis for the application of functional spherical gel-plugging particles in current oilfield environments.

Performance evaluation and physical simulation experiment of SiO2 nanoparticle synergistic crosslinked polymer system

Abstract As natural gas development gradually shifts from early to mid to late stages, water outflow from gas wells has become an inevitable problem. In this study, polyethyleneimine cross-linked polymers were synthesized and nano particles were introduced to obtain SiO2 nanoparticle synergistic cross-linked polymer systems. Rheological experiments show that the system has stronger shear resistance and higher yield stress, and the linear viscoelastic region has a stress amplitude less than 3.5Pa, exhibiting good elastic properties in the range of 0.01 to 10Hz. In terms of stability, after 45 days of aging, the viscosity retention rate of the system is 77.66%. When the mineralization degree is 224852mg/L, the viscosity retention rate is greater than 76.33%, indicating that the system has good aging stability and salt resistance.The physical simulation experiment of core displacement shows that SiO2 nanoparticle synergistic cross-linked polymer gel has gas-water selective plugging ability, and the reduction of water phase permeability is much greater than that of gas phase. The gas phase permeability can remains at about 75%, which is 2300 times that of water phase permeability, and has a good water plugging effect.

Towards in-depth profile control using s-MPG synergy with MSRG in fractured-vuggy carbonate reservoirs

In-depth profile control is a crucial technique employed to enhance oil recovery in fractured-vuggy carbonate reservoirs. However, it is a challenge to achieve in-depth profile control. In this paper, two types of organic gel systems, namely s-MPG and MSRG, tailored for fractured-vuggy reservoirs with 140 °C and 22 × 104 mg/L have been developed. FTIR was used to analyze the functional groups of s-MPG and MSRG. Additionally, the quality retention rates of s-MPG and MSRG were assessed using TG-DSC, yielding results of 92.85% and 92.65%, respectively. The dilution rates of s-MPG and MSRG are found to be 18.69% and 26.69%, respectively, demonstrating excellent compatibility and adaptability. The enhancement performance depends on the synergistic effect that the anti-dilution s-MPG effectively separates bottom water, while high-strength MSRG separates the oil layer. Moreover, the EOR performances of s-MPG synergy with MSRG in various types of fractured-vuggy carbonate models were also evaluated. The highest oil recovery of 12% is achieved in fracture network model. Laboratory results indicate that the synergistic combination of s-MPG and MSRG for water plugging in fractured-vuggy carbonate reservoirs results in a more effective enhancement of oil recovery compared to using a single gel system for plugging. Finally, the s-MPG synergy with MSRG has been applied in actual fractured-vuggy carbonate reservoirs. As expected, the water cut of typical well is reduced from 100% to 30% and the increased oil production is 1142 t totally. Therefore, this study presents a novel approach to achieving in-depth profile control by leveraging the synergistic effect of s-MPG with MSRG in fractured-vuggy carbonate reservoirs.

Study on Grouting Performance Optimization of Polymer Composite Materials Applied to Water Plugging and Reinforcement in Mines.

With the increasing drilling depth of mines, the cross-complexity of fissures in the rock body, and the frequent occurrence of sudden water surges, polymer slurry, with its advantages of good permeability and strong water plugging, is increasingly used in mine grouting projects. Additional research is needed in order to further improve the grouting performance of polymer slurry, ensure the safety of mining operations, and reduce the grouting cost. In this paper, a polymer composite grouting material was prepared with diphenyl methyl diisocyanate, polyether polyol, and fly ash, as the main raw materials, with coupling agent and catalyst as auxiliary reagents. The performance of the composite grouting material in terms of mechanical properties, thermal stability, hydrophobicity, and bonding was explored. This study's findings indicated that incorporating fly ash led to notable enhancements in the thermal stability and water resistance of the polymer slurry. Furthermore, the introduction of fly ash notably raised the starting degradation temperature of the polymer, boosted the water contact angle of the composite material, and reduced the density and reaction temperature of the composite material. In addition, the catalyst and coupling agent as auxiliary reagents affected the polymers in terms of mechanical properties; in this paper, dibutyltin dilaurate was used as the catalyst, and organosilanes were used as the coupling agent. The catalyst successfully sped up the polymer's gel time, however, an excessive quantity of catalyst compromised the polymer's mechanical characteristics. The addition of organosilanes has a positive effect on the dynamic mechanical properties of the composites, fracture toughness, compression, bending, and bond strength. The research can offer a theoretical direction for creating polymer mixtures in mine grouting projects.

Design of degradable hybrid dual-crosslinked polymer for high-efficiency profile control in high temperature reservoirs

Profile control and water plugging are key technologies to enhance oil and gas recovery. Traditional plugging materials, due to short gelation time, low mechanical strength, and difficulty in balancing plugging and protection, thus limiting application in high temperature reservoirs. Herein, a degradable hybrid dual-crosslinked polymer was prepared by employing a copolymerization - dual-grafting and physical adsorption design strategy. The dual-crosslinked process and reaction mechanism were analyzed using infrared spectroscopy and differential scanning calorimetry. The mechanical properties, water dilution resistance, aging stability and degradability of the dual cross-linked composite were also investigated. The solvation forces enable silica particles to exhibit excellent suspension stability in a PEG solvent. The temperature ranges from normal atmospheric temperature (20 °C) to reservoir temperature (140 °C), with the apparent viscosity falling within the range of 10–1200 mPa·s, meeting the requirements for mixing and injection. The combination of free radical copolymerization and click reaction is utilized to control the gelation time (2–10 h) in high temperature environment (140 °C), which is favorable for regulating the action position of the plugging agent in the reservoir. The cured material exhibits excellent mechanical strength owing to the presence of dual-crosslinking and inorganic hybridization, with a compressive strength of 0.221 MPa and a peak strain of 55.3 %. Furthermore, this composite material undergoes hydrolysis through an addition-elimination reaction, transitioning from a solid to a liquid state within 24 h, thereby aiding in the restoration of productivity in the temporarily shielded target layer. Compared to traditional materials, this dual-crosslinked composite system have the advantages of controllable gelation time, high mechanical strength, aging resistance, and degradability, making it suitable for profile control in high temperature reservoirs (140 ℃, 21.81×104 mg/L).

Research and Practice on Implementing Segmented Production Technology of Horizontal Well during Extra-High Water Cut Stage with Bottom Water Reservoir

Bohai X oilfield has reached the extra-high water cut stage of more than 95%, dominated by the bottom water reservoir. The oilfield mainly adopts horizontal-well exploitation, with the characteristics of high difficulty and low success rate for well water plugging. To solve the above problem, the segmented production technology of horizontal wells was developed to guide oilfield applications and tap their potential. In the segmented design stage, the horizontal section is objectively segmented by drilling condition analysis, optimally based on drilling through interlayers or permeability discrepancy formation, simultaneously combined with the numerical simulation method. When implementing measures, annulus chemical packer materials are squeezed between segments to effectively inhibit the fluid flow between the open hole and the sand-packing screen pipe. Moreover, the packers are used to seal between segments to effectively restrain the flow between the screen and the central tube, achieving the establishment of compartments. In the production process, the valve switch on the central tube can be independently controlled by a remotely adjustable method to achieve optimal production. This segmented production technology was successfully tested for the first time in Bohai oilfield. Up to now, a total of six compartment measures have been implemented, remarkably decreasing water cut and increasing oil production for horizontal wells in the bottom water reservoir. This method does not require water testing, and the optimal production section can be chosen through segmented independent production, greatly improving the success rate of water-plugging measures for horizontal wells. This technology opens up a new mode for the efficient development of horizontal wells in bottom water reservoirs and is planned to be widely promoted and applied in similar oilfields.

Nanocellulose/scleroglucan-enhanced robust, heat-resistant composite hydrogels for oilfield water plugging

In an oil exploitation process, hydrogel plugging agents can effectively reduce the water-oil intermixing, decrease water extraction volume, and enhance oil recovery rate. The practical applications of traditional polyacrylamide (PAM) hydrogel plugging agents in oilfield are limited by their non-biodegradability, poor mechanical performance, and inferior temperature-resistance. This work developed a mechanically stable and high-temperature-resistant composite hydrogel (STP) by incorporating biodegradable scleroglucan (Slg) and TEMPO-oxidized cellulose nanofibers (TOCN) in the PAM hydrogel. The addition of Slg conferred heat resistance to the PAM hydrogel, while TOCN reinforced the mechanical strength. Anti-aging analyses revealed that the STP endured for 108 h in a saline environment at 140 °C. In the water flooding characterization, the STP displayed a breakthrough pressure of 42.10 psi/ft. at a flow rate of 0.75 cm3/min. Under these extreme conditions, the plugging pressure reached 14.74 psi/ft., meeting the essential criteria for oilfield water plugging. This research demonstrates the potential of polysaccharides in the preparation of sustainable, tough, and heat-resistant water plugging materials.

Effect of Polymer and Crosslinker Concentration on Static and Dynamic Gelation Behavior of Phenolic Resin Hydrogel.

The application results of profile control and water plugging technology are highly related to the gelation time and strength of phenolic resin hydrogel. In this work, a hydrogel solution was prepared by fully mixing the prepared polymer solution with a crosslinker. The static gelation process of PFR hydrogel in ampoule bottles and porous media was analyzed by changes in the viscosity and residual resistance coefficient. Then, the dynamic gelation of the PFR hydrogel in porous media was tested using a circulating flow device, and the changes in viscosity and injection pressure were analyzed during the dynamic gelation process. Finally, the effects of the polymer concentration and crosslinker concentration on dynamic gelation were analyzed. The initial gelation time and final gelation time in porous media were 1-1.5 times and 1.5-2 times those in ampoule bottles under static conditions, respectively. The initial dynamic gelation time in porous media was 2-2.5 times and 1.5-2 times the initial static gelation times in ampoule bottles and porous media, respectively. The final dynamic gelation time was four times and two times the initial static gelation times in ampoule bottles and porous media, respectively. The production after dynamic gelation in porous media comprised hydrogel aggregates and water fluid, leading to a high injection pressure and low viscosity of the produced liquid. As the concentration of polymer and crosslinker increased, the dynamic gelation time was shortened and the gel strength was increased. In the dynamic gelation process in porous media, the phenol resin hydrogel could migrate deeply, but it was limited by the concentrations of the polymer and crosslinker. The results of subsequent water flooding showed that the polymer hydrogel had a good plugging ability after dynamic gelation. The deep reservoir could only be blocked off in the subsequent water flooding process when the migration of hydrogel happened in the dynamic gelation process.

Study on a Strong Polymer Gel by the Addition of Micron Graphite Oxide Powder and Its Plugging of Fracture.

It is difficult to plug the fracture water channeling of a fractured low-permeability reservoir during water flooding by using the conventional acrylamide polymer gel due to its weak mechanical properties. For this problem, micron graphite powder is added to enhance the comprehensive properties of the acrylamide polymer gel, which can improve the plugging effect of fracture water channeling. The chemical principle of this process is that the hydroxyl and carboxyl groups of the layered micron graphite powder can undergo physicochemical interactions with the amide groups of the polyacrylamide molecule chain. As a rigid structure, the graphite powder can support the flexible skeleton of the original polyacrylamide molecule chain. Through the synergy of the rigid and flexible structures, the viscoelasticity, thermal stability, tensile performance, and plugging ability of the new-type gel can be significantly enhanced. Compared with a single acrylamide gel, after adding 3000 mg/L of micrometer-sized graphite powder, the elastic modulus, the viscous modulus, the phase transition temperature, the breakthrough pressure gradient, the elongation at break, and the tensile stress of the acrylamide gel are all greatly improved. After adding the graphite powder to the polyacrylamide gel, the fracture water channeling can be effectively plugged. The characteristics of the networked water flow channel are obvious during the injected water break through the gel in the fracture. The breakthrough pressure of water flooding is high. The experimental results are an attempt to develop a new gel material for the water plugging of a fractured low-permeability reservoir.

Preparation of Low-Viscosity Epoxy Resin Sealing Agent and Evaluation of Injection, Plugging, and Degradation Properties.

The technology of water plugging and increasing production in high water cut reservoirs of low permeability is a common problem in the industry. Epoxy resin, displaying excellent mechanical properties and adherent performance, can easily inject a tiny crack, forming a long-term blocking barrier. This study aimed to investigate an easily injectable degradable epoxy resin sealing material. The injectable performance, long-term stability, and mechanical and plugging properties were comparatively analyzed in the fractured core, and the degradable performance was discussed in the degrading solution. The result showed that the range of R (R is the ratio of EOG and MHHPA) from 1 to 1.1 and the mass fraction range of EMI from 0.01 to 4 wt % are the optimal formulations (EOGM). The curing time from 1 to 12 h could be regulated by adjusting the dosage of EMI, as well as the strength being more than 60 MPa. The plugging agent's initial viscosity is lower than 100 MPa s at 20 °C and injecting pressure is lower than 0.1 MPa. After curing for 24 h, compressive strength was more than 72.76 MPa, 3.6 times higher than that of cement, and the adhesion strength was 4.41 MPa when the contact area was 75.93 cm3. Breakthrough pressures for sealing 1-5 mm fractures were all more than 10 MPa, and the breakthrough pressure for 1 mm crack even reached 29.4 MPa. Epoxy resin/acid anhydride system could be degraded in a mixed solution of phenol-potassium salt-heavy aromatics within 7 days at 60-100 °C, which reduced the plugging well risk of the epoxy resin plugging agent. These results suggest that an epoxy resin/acid anhydride plugging agent can be employed effectively and safely for the injection of tiny cracks, which is of great engineering significance.

Lignocellulosic hydrogel for profile control and water plugging in high salt reservoirs

Profile control is an effective method for enhancing oil recovery. In-situ crosslinked gels offer advantages such as easy pumping and controllable gel formation time when used as agents for profile control. However, conventional in-situ crosslinked gels suffer from the drawback of shrinkage under high salinity, and the crosslinking agent is typically organometrics, leading to permanent damage to the reservoir. Therefore, it is very important to develop a plugging agent that is resistant to high salinity and causes minimal damage. In this study, sodium lignosulfonate, known for its excellent thermal stability and biocompatibility, was crosslinked with carboxymethyl cellulose and β-cyclodextrin to create a hydrogel gf. The structures of the hydrogel were characterized using FTIR, XRD, viscosimeter and SEM. The temperature resistance, salt resistance, shear resistance, long-term stability and plugging ability of the gel gf-5 were evaluated. The results showed that, compared with the traditional underground crosslinked gel pg-1, gf-5 showed better application performance. Even at a high salinity level of 200,000 mg/L in the aqueous solution, the viscosity of gf-5 was 96830 mPa·s. Additionally, the Ca2+ present in the mineralized water formed calcium hydroxide particles with hydroxide, acting as rigid support points. This phenomenon enhanced the strength and toughness of the gel. Furthermore, the gel system maintained a stable structure at 60–90 ℃ for 120 days. In sand-packed tubes with varying permeability, the sealing rate exceeded 96 %, and the breakthrough pressure reached 8.593 MPa. SEM images demonstrated that the gel effectively enveloped the sand and adhere to the porous medium.

An extended discontinuous deformation analysis for simulation of grouting reinforcement in a water-rich fractured rock tunnel

Grouting has been the most effective approach to mitigate water inrush disasters in underground engineering due to its ability to plug groundwater and enhance rock strength. Nevertheless, there is a lack of potent numerical tools for assessing the grouting effectiveness in water-rich fractured strata. In this study, the hydro-mechanical coupled discontinuous deformation analysis (HM-DDA) is inaugurally extended to simulate the grouting process in a water-rich discrete fracture network (DFN), including the slurry migration, fracture dilation, water plugging in a seepage field, and joint reinforcement after coagulation. To validate the capabilities of the developed method, several numerical examples are conducted incorporating the Newtonian fluid and Bingham slurry. The simulation results closely align with the analytical solutions. Additionally, a set of compression tests is conducted on the fresh and grouted rock specimens to verify the reinforcement method and calibrate the rational properties of reinforced joints. An engineering-scale model based on a real water inrush case of the Yonglian tunnel in a water-rich fractured zone has been established. The model demonstrates the effectiveness of grouting reinforcement in mitigating water inrush disaster. The results indicate that increased grouting pressure greatly affects the regulation of water outflow from the tunnel face and the prevention of rock detachment face after excavation.

Co-Injection of Foam and Particles: An Approach for Bottom Water Control in Fractured-Vuggy Reservoirs

Fractured-vuggy carbonate reservoirs are tectonically complex; their reservoirs are dominated by holes and fractures, which are extremely nonhomogeneous and are difficultly exploited. Conventional water injection can lead to water flooding, and the recovery effect is poor. This paper takes the injection of foam and solid particles to control bottom water as the research direction. Firstly, the rheological properties of foam were studied under different foam qualities and the presence of particles. The ability of foam to carry particles was tested. By designing a microcosmic model of a fractured-vuggy reservoir, we investigated the remaining oil types and the distribution caused by bottom water. Additionally, we analyzed the mechanisms of remaining oil mobilization and bottom water plugging during foam flooding and foam–particle co-injection. The experimental results showed that foam was a typical power-law fluid. Foam with a quality of 80% had good stability and apparent viscosity. During foam flooding, foam floated at the top of the dissolution cavities, effectively driving attic oil. Additionally, the gas cap is released when the foam collapses, which can provide pressure energy to supplement the energy of the reservoir. Collaborative injection of foam and solid particles into the reservoir possessed several advantages. On one hand, it inherited the benefits of foam flooding. On the other hand, the foam transported particles deep into the reservoir. Under the influence of gravity, particles settled and accumulated in the fractures or cavities, forming bridge plugs at the connection points, effectively controlling bottom water channeling. The co-injection of foam and solid particles holds significant potential for applications.

Research on Water Invasion Law and Control Measures for Ultradeep, Fractured, and Low-Porosity Sandstone Gas Reservoirs: A Case Study of Kelasu Gas Reservoirs in Tarim Basin

The exploitation of ultradeep, fractured, and low-porosity gas reservoirs often encounters challenges from water invasion, exacerbated by the presence of faults and fractures. This is particularly evident in the Kelasu gas reservoir group, located in the Kuqa Depression of the Tarim Basin. The complexity of the water invasion patterns in these reservoirs demands a thorough investigation to devise effective water control measures. To elucidate the water invasion patterns, a combined approach of large-scale physical modeling and discrete fracture numerical simulations was adopted. These models allowed for the identification and categorization of water invasion behaviors in various gas reservoirs. Furthermore, production dynamic analysis was utilized to tailor water control strategies to specific invasion patterns. The large-scale physical simulation experiment revealed that water invasion in gas reservoirs is primarily influenced by high-permeability channels (faults + fractures), and that the gas production rate serves as the key factor governing gas reservoir development. The range of gas extraction rates spans from 3% to 5%. As the gas extraction rate increases, the extraction intensity diminishes and the stable production duration shortens. On the basis of the changes in the water breakthrough time and water production rate, a 2% gas extraction rate is determined as the optimal rate for the model. The embedded discrete fracture numerical simulation model further supports the findings of the physical simulation experiments and demonstrates that ① this type of gas reservoir exhibits typical nonuniform water invasion patterns, controlled by structural location, faults, and degree of crack development; ② the water invasion patterns of gas reservoirs can be categorized into three types, these being explosive water flooding and channeling along faults, uniform intrusion along fractures, and combined intrusion along faults and fractures; ③ drawing from the characteristics of water invasion in various gas reservoirs, combined with production well dynamics and structural location, a five-character water control strategy of “prevention, control, drainage, adjustment, and plugging” is formulated, with the implementation of differentiated, one-well, one-policy governance. The study concludes that a proactive approach, prioritizing prevention, is crucial for managing water-free gas reservoirs. For water-bearing reservoirs, a combination of three-dimensional water plugging and drainage strategies is recommended. These insights have significant implications for extending the productive lifespan of gas reservoirs, enhancing recovery rates, and contributing to the economic and efficient development of ultradeep, fractured, and low-porosity gas reservoirs.