Search Results (64)

To address critical technical challenges in coalbed methane fracturing, including the uncontrollable release rate of conventional breaker agents and incomplete gel breaking, this study designs and fabricates an intelligent controlled-release breaker system based on paraffin-coated mesoporous silica nanoparticle carriers. Three types of mesoporous silica (MSN) carriers with distinct pore sizes are synthesized via the sol-gel method using CTAB, P123, and F127 as structure-directing agents, respectively. Following hydrophobic modification with octyltriethoxysilane, n-butanol breaker agents are loaded into the carriers, and a temperature-responsive controlled-release system is constructed via paraffin coating technology. The pore size distribution was analyzed by the BJH model, confirming that the average pore diameters of CTAB-MSNs, P123-MSNs, and F127-MSNs were 5.18 nm, 6.36 nm, and 6.40 nm, respectively. The BET specific surface areas were 686.08, 853.17, and 946.89 m²/g, exhibiting an increasing trend with the increase in pore size. Drug-loading performance studies reveal that at the optimal loading concentration of 30 mg/mL, the loading efficiencies of n-butanol on the three carriers reach 28.6%, 35.2%, and 38.9%, respectively. The release behavior study under simulated reservoir temperature conditions (85 °C) reveals that the paraffin-coated system exhibits a distinct three-stage release pattern: a lag phase (0–1 h) caused by paraffin encapsulation, a rapid release phase (1–8 h) induced by high-temperature concentration diffusion, and a sustained release phase (8–30 h) attributed to nano-mesoporous characteristics. This intelligent controlled-release breaker demonstrates excellent temporal compatibility with coalbed methane fracturing processes, providing a novel technical solution for the efficient and clean development of coalbed methane. Full article

Channeling in cementing causes interlayer interference, severely restricting oilfield recovery. Existing channeling plugging agents, such as cement and gels, often lead to reservoir damage or insufficient strength. Oil-soluble resin (OSR) particles show great potential in selective plugging of channeling fractures due to their excellent oil solubility, temperature/salt resistance, and high strength. However, their application is limited by the efficient filling and retention in deep fractures. This study innovatively combines the OSR particle plugging system with the mature rapid filtration loss plugging mechanism in drilling, systematically exploring the influence of particle size and sorting on their filtration, packing behavior, and plugging performance in channeling fractures. Through API filtration tests, visual fracture models, and high-temperature/high-pressure (100 °C, salinity 3.0 × 10⁵ mg/L) core flow experiments, it was found that well-sorted large particles preferentially bridge in fractures to form a high-porosity filter cake, enabling rapid water filtration from the resin plugging agent. This promotes efficient accumulation of OSR particles to form a long filter cake slug with a water content <20% while minimizing the invasion of fine particles into matrix pores. The slug thermally coalesces and solidifies into an integral body at reservoir temperature, achieving a plugging strength of 5–6 MPa for fractures. In contrast, poorly sorted particles or undersized particles form filter cakes with low porosity, resulting in slow water filtration, high water content (>50%) in the filter cake, insufficient fracture filling, and significantly reduced plugging strength (<1 MPa). Finally, a double-slug strategy is adopted: small-sized OSR for temporary plugging of the oil layer injection face combined with well-sorted large-sized OSR for main plugging of channeling fractures. This strategy achieves fluid diversion under low injection pressure (0.9 MPa), effectively protects reservoir permeability (recovery rate > 95% after backflow), and establishes high-strength selective plugging. This study clarifies the core role of particle size and sorting in regulating the OSR plugging effect based on rapid filtration loss, providing key insights for developing low-damage, high-performance channeling plugging agents and scientific gradation of particle-based plugging agents. Full article

Lost circulation is a major challenge in oil and gas drilling operations, severely restricting drilling efficiency and compromising operational safety. Conventional bridging and plugging materials rely on precise particle-to-fracture size matching, resulting in low success rates. Self-healing gels penetrate loss zones as discrete particles that progressively swell, accumulate, and self-repair in integrated gel masses to effectively seal fracture networks. Self-healing gels effectively overcome the shortcomings of traditional bridging agents including poor adaptability to fractures, uncontrollable gel formation of conventional downhole crosslinking gels, and the low strength of conventional pre-crosslinked gels. This work employs stearyl methacrylate (SMA) as a hydrophobic monomer, acrylamide (AM) and acrylic acid (AA) as hydrophilic monomers, and graphene oxide (GO) as an inorganic dopant to develop a GO-based self-healing organic–inorganic hybrid plugging material (SG gel). The results demonstrate that the incorporation of GO significantly enhances the material’s mechanical and rheological properties, with the SG-1.5 gel exhibiting a rheological strength of 3750 Pa and a tensile fracture stress of 27.1 kPa. GO enhances the crosslinking density of the gel network through physical crosslinking interactions, thereby improving thermal stability and reducing the swelling ratio of the gel. Under conditions of 120 °C and 6 MPa, SG-1.5 gel demonstrated a fluid loss volume of only 34.6 mL in 60–80-mesh sand bed tests. This gel achieves self-healing within fractures through dynamic hydrophobic associations and GO-enabled physical crosslinking interactions, forming a compact plugging layer. It provides an efficient solution for lost circulation control in drilling fluids. Full article

Coalbed methane (CBM), a significant unconventional natural gas resource, holds a crucial position in China’s ongoing energy structure transformation. However, the inherent low permeability, high brittleness, and strong sensitivity of CBM reservoirs to drilling fluids often lead to severe formation damage during drilling operations, consequently impairing well productivity. To address these challenges, this study developed a novel low-damage, plugging, and anti-collapse water-based drilling fluid gel system (ACWD) specifically designed for coalbed methane drilling. Laboratory investigations demonstrate that the ACWD system exhibits superior overall performance. It exhibits stable rheological properties, with an initial API filtrate loss of 1.0 mL and a high-temperature, high-pressure (HTHP) filtrate loss of 4.4 mL after 16 h of hot rolling at 120 °C. It also demonstrates excellent static settling stability. The system effectively inhibits the hydration and swelling of clay and coal, significantly reducing the linear expansion of bentonite from 5.42 mm (in deionized water) to 1.05 mm, and achieving high shale rolling recovery rates (both exceeding 80%). Crucially, the ACWD system exhibits exceptional plugging performance, completely sealing simulated 400 µm fractures with zero filtrate loss at 5 MPa pressure. It also significantly reduces core damage, with an LS-C1 core damage rate of 7.73%, substantially lower than the 19.85% recorded for the control polymer system (LS-C2 core). Field application in the JX-1 well of the Ordos Basin further validated the system’s effectiveness in mitigating fluid loss, preventing wellbore instability, and enhancing drilling efficiency in complex coal formations. This study offers a promising, relatively environmentally friendly, and cost-effective drilling fluid solution for the safe and efficient development of coalbed methane resources. Full article

Lost circulation during drilling has significantly hindered the safe and efficient development of oil and gas resources. Supramolecular polymer gel–based lost circulation materials have shown significant potential for application due to their unique molecular structures and superior performance. Herein, a high–performance supramolecular polymer gel was developed, and the influence of reservoir conditions on the performance of the supramolecular polymer gel was investigated in detail. The results identified an optimal formulation for the preparation of supramolecular polymer gel comprising 15 wt% acrylamide, 3 wt% 2-acrylamide-2-methylpropanesulfonic acid, 2.6 wt% divinylbenzene, 5 wt% polyvinyl alcohol, 0.30 wt% cellulose nanofibers, and 3 wt% laponite. The performance of the gel-forming suspension and the resulting supramolecular polymer gel was influenced by various factors, including temperature, density, pH, and the intrusion of drilling fluid, saltwater, and crude oil. Nevertheless, the supramolecular polymer gels consistently exhibited high strength under diverse environmental conditions, as confirmed by rheological measurements. Moreover, the gels exhibited strong plugging performance across various fracture widths and in permeable formations, with maximum breakthrough pressures exceeding 6 MPa. These findings establish a theoretical foundation and practical approach for the field application of supramolecular polymer gels in complex geological formations, demonstrating their effectiveness in controlling lost circulation under challenging downhole conditions. Full article

Gas channeling phenomena in carbonate fracture-vuggy reservoirs frequently occur, primarily in the form of negative pressure gas channeling and displacement gas channeling, with the possibility of mutual conversion between the two. This is accompanied by the risk of hydrogen sulfide (H₂S) release from the reservoir, which poses significant challenges to controlling safety. Currently, liquid bridging and gel plugging technologies are effective methods for mitigating complex issues such as downhole overflow, fluid loss, and heavy oil backflow. This paper focuses on the development and optimization of key treatment agents, including high-temperature-resistant polymers and crosslinking agents, to formulate a high-temperature chemical gel plugging agent. A gel-breaking, high-strength colloidal chemical gel plugging agent system capable of withstanding temperatures up to 150 °C was developed, and it has an apparent viscosity of about 7500 mPa·s, an energy storage modulus and a loss modulus of 51 Pa and 6 Pa, respectively, after gel formation at elevated temperatures, and an apparent viscosity retention rate of the gel of greater than 82% after aging for 9 d at a temperature of 150 °C. This system forms a stable gas isolation barrier in the wellbore, with performance remaining stable after 7 to 12 days of aging, and the degradation rate reaches 99.8% after 24 h at 150 °C. This technology is of significant importance in solving complex issues such as overflow, fluid loss, and heavy oil backflow in gas injection and recovery wells in high-temperature, high-pressure reservoir conditions. Full article

Lost circulation has become one of the important problems restricting the speed and efficiency of oil and gas drilling and production. To address severe drilling fluid losses in high-temperature fractured formations during deep/ultra-deep well drilling, this study developed a high-temperature and high-strength gelled resin gel plugging system through optimized resin matrix selection, latent curing agent, flow regulator, filling material, etc. Comparative analysis of five thermosetting resins revealed urea-formaldehyde resin as the optimal matrix, demonstrating complete curing at 100–140 °C with a compressive strength of 9.3 MPa. An organosilicon crosslsinker-enabled water-soluble urea-formaldehyde resin achieved controlled solubility and flow–cure balance under elevated temperatures. Orthogonal experiments identified that a 10% latent curing agent increased compressive strength to 6.26 MPa while precisely regulating curing time to 2–2.5 h. Incorporating 0.5% rheological modifier imparted shear-thinning and static-thickening behaviors, synergizing pumpability with formation retention. The optimal formula (25% urea-formaldehyde resin, 10% latent curing agent, 10% high-fluid-loss filler, 0.5% rheological modifier) exhibited superior thermal stability (initial decomposition temperature 241 °C) and mechanical integrity (bearing pressure 13.95 MPa in 7 mm wedge-shaped fractures at 140 °C). Microstructural characterization confirmed interlocking crystalline layers through ether-bond crosslinking, providing critical insights for high-temperature wellbore stabilization. Full article

In response to the special requirements for shale gas reservoir stimulation, a novel environmentally responsive fracturing fluid thickener was designed and developed in this paper. N,N-dimethylhexadecylallylammonium chloride (C16DMAAC), N-vinylpyrrolidone (NVP), 2-acrylamido-2-methylpropanesulfonic acid (AMPS), and Acrylamide (AM) were used as functional monomers, and the synthesis of the target product was achieved successfully through free radical polymerization in an aqueous solution. The findings indicated that in the optimized situation, where the total monomer mass fraction was 25%, the ratio of AM:AMPS:C16DMAAC:NVP was 15:10:3:2, the initiator mass fraction was 0.3%, the pH was 6.5, and the temperature was 60 °C, the thickener achieved a number-average molecular weight of 1.13 × 10⁶. Furthermore, its remarkable thermal stability was manifested, as it only experienced a 15% mass loss in the temperature interval spanning from 40 °C to 260 °C. Performance evaluation results indicated that, at 120 °C, the viscosity of the thickener under study increased by over 49% compared to the control group. Simultaneously, in a 0.4 wt% CaCl₂ environment, it retained a high viscosity of 54.75 mPa·s. This value was 46.61 mPa·s greater than that of the control group. Furthermore, under the conditions of a temperature of 170 °C, the fracturing fluid viscosity remained above 68 mPa·s. Regarding the flow performance, within the flow rate range from 110 to 150 L/min, it showed a remarkable drag reduction effect, achieving a maximum drag reduction rate of 70%. At 150 °C, the fracturing fluid exhibited superior proppant-carrying efficacy, with a settlement rate that was 26.1% lower than that of the control group. The viscosity and residue content of the gel-broken fracturing fluid exceeded the requirements of industry standards. In particular, the residue content of this fracturing fluid was 21% lower than that of the control group. The research results provide an environmentally responsive fracturing fluid thickener with excellent performance for shale gas reservoir stimulation. Full article

Hydraulic fracturing is widely used for developing shale reservoirs with low porosity and permeability. Large volumes of fracturing fluids are injected into reservoirs, yet the impact of these fluids on shale is not entirely understood. This study investigates the effects of commonly used fracturing fluids on the fundamental properties of shale during the shut-in period using experimental methods. Shale samples are collected from the Longmaxi Formation in the Sichuan Basin. Two types of fracturing fluids (guar gel and slickwater) are prepared for tests. The effects of these fluids on shale’s mineral composition, pore distribution, and fracture structure are analyzed using a range of techniques, including X-ray diffraction, nuclear magnetic resonance, nitrogen adsorption-desorption, and X-ray computed tomography scanning. The results show that the shale is composed of quartz, siderite, and clay minerals. The reservoir’s pore structure is relatively uniform, with a higher proportion of small pores and a predominance of wedge-shaped pore types. The porosity ranges from 1.8% to 4.33%, with an average pore diameter varying between 10.8 nm and 24.8 nm. More fracturing fluid enters the reservoir as shut-in time increases. Initially, fluid invasion occurs rapidly, but the volume of infiltrated fluid stabilizes after 15 days. The fracturing fluids cause chemical reactions and hydration of clay minerals. Both fracturing fluids lead to a decrease in the proportion of clay minerals and an increase in the proportion of quartz. After soaking in guar gel, the shale’s surface area and pore volume decrease while the average pore diameter increases. The breakdown of guar gel leads to a residue that blocks pore spaces, resulting in lower surface porosity. In contrast, slickwater increases surface area and pore volume while reducing the average pore diameter. Slickwater also promotes the development of fractures, with larger pores forming around them. The results suggest that slickwater is more effective than guar gel in improving shale’s pore structure. Full article

Ensuring the overall efficiency of hydraulic fracturing treatment depends on the ability to forecast bottomhole pressure. It has a direct impact on fracture geometry, production efficiency, and cost control. Since the complications present in contemporary operations have proven insufficient to overcome inherent uncertainty, the precision of bottomhole pressure predictions is of great importance. Achieving this objective is possible by employing machine learning algorithms that enable real-time forecasting of bottomhole pressure. The primary objective of this study is to produce sophisticated machine learning algorithms that can accurately predict bottomhole pressure while injecting guar cross-linked fluids into the fracture string. Using a large body of work, including 42 vertical wells, an extensive dataset was constructed and meticulously packed using processes such as feature selection and data manipulation. Eleven machine learning models were then developed using parameters typically available during hydraulic fracturing operations as input variables, including surface pressure, slurry flow rate, surface proppant concentration, tubing inside diameter, pressure gauge depth, gel load, proppant size, and specific gravity. These models were trained using actual bottomhole pressure data (measured) from deployed memory gauges. For this study, we carefully developed machine learning algorithms such as gradient boosting, AdaBoost, random forest, support vector machines, decision trees, k-nearest neighbor, linear regression, neural networks, and stochastic gradient descent. The MSE and R² values of the best-performing machine learning predictors, primarily gradient boosting, decision trees, and neural network (L-BFGS) models, demonstrate a very low MSE value and high R² correlation coefficients when mapping the predictions of bottomhole pressure to actual downhole gauge measurements. R² values are reported as 0.931, 0.903, and 0.901, and MSE values are reported at 0.003, 0.004, and 0.004, respectively. Such low MSE values together with high R² values demonstrate the exceptionally high accuracy of the developed models. By illustrating how machine learning models for predicting pressure can act as a viable alternative to expensive downhole pressure gauges and the inaccuracy of conventional models and correlations, this work provides novel insight. Additionally, machine learning models excel over traditional models because they can accommodate a diverse set of cross-linked fracture fluid systems, proppant specifications, and tubing configurations that have previously been intractable within a single conventional correlation or model. Full article

To enhance oil and gas recovery, a novel hydrophobic terpolymer was synthesized via free radical polymerization. The terpolymer consists of acrylamide, acrylic acid, and hydrophobic monomers, and is used as a hydraulic fracturing fluid thickener for freshwater environments. Hydrophobic groups were introduced into terpolymer to improve its tackiness and temperature resistance. The conformation and key parameters of hydrophobic monomers at different temperatures were investigated through a combination of experiments and molecular dynamics simulations. These methods were employed to elucidate the mechanism behind its high-temperature resistance. The experiment results show that, at concentrations between 0.2% and 0.4%, significant intermolecular aggregation occurs, leading to a substantial increase in solution viscosity. Configuring the base fluid of synthetic polymer fracturing fluid with 1% doping, the apparent viscosities of the base fluid were 129.23 mPa·s and 133.11 mPa·s, respectively. The viscosity increase rate was 97%. The base fluid was crosslinked with 1.5% organozirconium crosslinker to form a gel. The controlled loss coefficient and loss velocity of the filter cake were C₃ = 0.84 × 10⁻³ m/min^1/2 and v_c = 1.40 × 10⁻⁴ m/min at 90 °C, meeting the technical requirements for water-based fracturing fluid. Molecular dynamics simulations revealed that the radius of gyration of the hydrophobically linked polymer chain segments decreases as the temperature increases. This is due to the increased thermal motion of the polymer chain segments, resulting in less stretching and intertwining of the chains. As a result, the polymer chains move more freely, which decreases the viscosity of the solution. In conclusion, the proposed fracturing fluid thickener system demonstrates excellent overall performance and shows significant potential for application in oil and gas recovery. Full article

The issue of fluid loss in fractured formations presents a significant challenge in petroleum engineering, often leading to increased operational costs and construction risks. To address the limitations of traditional lost circulation materials (LCMs) in oil reservoirs with different fracture sizes, this study developed an acrylic resin gel particle with excellent thermal stability (thermal decomposition temperature up to 314 °C) and compatibility. By employing Box–Behnken design and response surface methodology, the synergistic interaction of calcium hydroxide (Ca(OH)₂), asbestos fibers, and cement was optimized to create a novel gel solidification plugging system that meets the requirements of fluid loss control and compressive strength improvement. Experimental results revealed that the gel-based system demonstrated exceptional performance, achieving rapid fluid loss (total fluid loss time of 18~47 s) and forming a high-strength gelled filter cake (24 h compressive strength up to 17.5 MPa). Under simulated conditions (150 °C), the gel-based system provided efficient fracture sealing, showcasing remarkable adaptability and potential for engineering applications. This study underscores the promise of acrylic resin gel particles in overcoming fluid loss challenges in complex fractured formations. Full article

The main tight sandstone gas reservoirs in the Linxing block of the Ordos Basin exhibit a temperature range of 35–60 °C. Under these low-temperature conditions, conventional oxidative gum breakers used in fracturing operations react sluggishly, fail to break the gum completely, and can cause significant reservoir damage. In order to achieve complete breakage of the fracturing fluid and reduce the damage to the fracture and reservoir, active bio-enzyme-enhanced breakers have been incorporated into fracturing fluid formulations, so as to achieve rapid breakage, re-discharge at low temperature, and reduce the contact time between the fracturing fluid and the formation, which is critical for enhancing production efficiency. Based on the preliminary success of bio-enzyme-enhanced fracturing technology, this paper carries out an optimization study of bio-enzyme-enhanced fracturing technology for the low-temperature reservoir in the Ordos Linxing block. The study simulates the temperature recovery of the injected fluids under different reservoir temperatures during the fracturing process, aiming to further optimize the concentration of the bio-enzyme-enhanced fracture breakers in the fracturing phases, and to achieve optimized fracturing technology which is more in line with the temperature environment of the fluids. This can further optimize the concentration of the bio-enzyme breaker added at each fracturing stage, and achieve enhanced breaking in a stepwise manner that is more in line with the fluid temperature environment, thus improving the efficiency and production capacity for subsequent production. The optimized fracturing fluid system, incorporating the tailored concentration of the bio-enzyme breaker, was applied to 54 wells in this block, resulting in about a two-times improvement in production compared to conventional non-optimized methods, with many wells achieving high output. These results demonstrate the strong applicability of the optimized breaker procedure in this geological context. Additionally, this study investigated an optimization model for the well shut-in time during winter operations involving low-temperature fracturing fluids in low-temperature reservoirs, providing a valuable design basis for future production planning. Full article

The utilization of CO₂ foam gel fracturing fluid offers several significant advantages, including minimal reservoir damage, reduced water consumption during application, enhanced cleaning efficiency, and additional beneficial properties. However, several current CO₂ foam gel fracturing fluid systems face challenges, such as complex preparation processes and insufficient viscosity, which limit their proppant transport capacity. To address these issues, this work develops a novel CO₂ foam gel fracturing fluid system characterized by simple preparation and robust foam stability. This system was optimized by incorporating a thickening agent CZJ-1 in conjunction with a foaming agent YFP-1. The results of static sand-carrying experiments indicate that under varying temperatures and sand–fluid ratio conditions, the proppant settling velocity is significantly low. Furthermore, the static sand-carrying capacity of the CO₂ foam gel fracturing fluid exceeds that of the base fluid. The stable and dense foam gel effectively encapsulates the proppant, thereby improving sand-carrying capacity. In high-temperature shear tests, conducted at a shear rate of 170 s⁻¹ and a temperature of 110 °C for 90 min, the apparent viscosity of the CO₂ foam gel fracturing fluid remained above 20 mPa·s after shear, demonstrating excellent high-temperature shear resistance. This work introduces a novel CO₂ foam gel fracturing fluid system that is specifically tailored for low-permeability reservoir fracturing and extraction. The system shows significant promise for the efficient development of low-pressure, low-permeability, and water-sensitive reservoirs, as well as for the effective utilization and sequestration of CO₂. Full article

This study investigates the development of a novel CO₂-foamed viscoelastic gel-based fracturing fluid to address the challenges of high-temperature formations. The influence of various parameters, including surfactant type and concentration, gas fraction, shear rate, water salinity, temperature, and pressure, on foam viscosity was systematically explored. Rheological experiments were conducted using a high-pressure/high-temperature (HPHT) rheometer at 150 °C and pressures ranging from 6.89 to 20.68 MPa. To simulate field conditions, synthetic high-salinity water was employed. The thermal stability of the CO₂ foam was evaluated at a constant shear rate of 100 1/s for 180 min. Additionally, foamability and foam stability were assessed using an HPHT foam analyzer at 100 °C. The results demonstrate that liquid phase chemistry, experimental conditions, and gas fraction significantly impact foam viscosity. Viscoelastic surfactants achieved a peak foam viscosity of 0.183 Pa·s at a shear rate of 100 1/s and a 70% foam quality, surpassing previous records. At lower foam qualities (≤50%), pressure had a negligible effect on foam viscosity, whereas at higher qualities, it increased viscosity by over 30%. While a slight increase in viscosity was observed with foam qualities between 40% and 60%, a significant enhancement was noted at 65% foam quality. The addition of polymers did not improve foam viscosity. The generation of viscous and stable foams is crucial for effective proppant transport and fracture induction. However, maintaining the thermal stability of CO₂ foams with minimal additives remains a significant challenge in the industry. This laboratory study provides valuable insights into the development of stable CO₂ foams for stimulating high-temperature wells. Full article