Search Results (59)

The stability of nitrogen gas foam hinders its applicability in petroleum applications. Fly ash nanoparticles and clay improve the N₂ foam stability, and flue gas foams provide a cost-effective solution for carbon capture, utilization, and storage (CCUS). This study examines the stability, volume, and bubble structure of foams formed using two anionic surfactants, sodium dodecyl sulfate (SDS) and sodium dodecylbenzene sulfonate (SDBS), along with the cationic surfactant cetyltrimethylammonium bromide (CTAB), selected for their comparable interfacial tension properties. Analysis of foam stability and volume and bubble structure was conducted under different CO₂/N₂ mixtures, with half-life and initial foam volume serving as the evaluation criteria. The impact of fly ash and clay on SDS-N₂ foam was also evaluated. The results showed that foams created with CTAB, SDBS, and SDS exhibit the greatest stability in pure nitrogen, attributed to low solubility in water and limited gas diffusion. SDS showed the highest foam strength attributable to its comparatively low surface tension. The addition of fly ash and clay significantly improved foam stability by migrating to the gas–liquid interface, creating a protective barrier that reduced drainage. Both nano fly ash and clay improved the half-life of nitrogen foam by 11.25 times and increased the foam volume, with optimal concentrations identified as 5.0 wt% for fly ash and 3.0 wt% for clay. This research emphasizes the importance of fly ash nanoparticles in stabilizing foams, therefore optimizing a foam system for enhanced oil recovery (EOR). Full article

The salt flotation of graphite in the presence of lithium nickel manganese cobalt oxide (NMC) was assessed by performing colloidal probe atomic force microscopy (CP-AFM) on sessile gas bubbles and conducting batch flotation tests with model lithium-ion-battery black mass. The modeling of film drainage and detachment during particle–bubble interactions provides insight into the fundamental microprocesses during salt flotation, a special variant of froth flotation. The interfacial properties of particles and gas bubbles were tailored with salt solutions containing sodium chloride and sodium acetate buffer. Graphite particles can attach to gas bubbles under all tested conditions in the range pH 3 to pH 10. The attractive forces for spherical graphite are strongest at high salt concentrations and pH 3. The conditions for the attachment of NMC to gas bubbles were evaluated with simulations using the Stokes–Reynolds–Young–Laplace model for film drainage, under consideration of DLVO forces and a hydrodynamic slip to account for irregularities of the particle surface. CP-AFM measurements in the capillary force regime provide additional parameters for the modeling of salt flotation, such as the force and work of detachment. The contact angles of graphite and NMC particles during retraction and detachment from gas bubbles were obtained from a quasi-equilibrium model using CP-AFM data as input. All CP-AFM experiments and theoretical results suggest that pristine NMC particles do not attach to gas bubbles during flotation, which is confirmed by the low rate of NMC recovery in batch flotation tests. Full article

The synergistic development of low-permeability reservoirs such as deep coalbed methane (CBM) and tight gas has emerged as a key technology to reduce development costs, enhance single-well productivity, and improve gas recovery. However, due to fundamental differences between coal seams and tight sandstones in their pore structure, permeability, water saturation, and pressure sensitivity, significant variations exist in their flow capacities and fluid production behaviors. To address the challenges of production allocation and main reservoir identification in the co-development of CBM and tight gas within deep gas-bearing basins, this study employs the transient multiphase flow simulation software OLGA to construct a representative dual-gas co-production well model. The regulatory mechanisms of the gas–liquid distribution, deliquification efficiency, and interlayer interference under two typical vertical stacking relationships—“coal over sand” and “sand over coal”—are systematically analyzed with respect to different tubing setting depths. A high-precision dynamic production allocation method is proposed, which couples the wellbore structure with real-time monitoring parameters. The results demonstrate that positioning the tubing near the bottom of both reservoirs significantly enhances the deliquification efficiency and bottomhole pressure differential, reduces the liquid holdup in the wellbore, and improves the synergistic productivity of the dual-reservoirs, achieving optimal drainage and production performance. Building upon this, a physically constrained model integrating real-time monitoring data—such as the gas and liquid production from tubing and casing, wellhead pressures, and other parameters—is established. Specifically, the model is built upon fundamental physical constraints, including mass conservation and the pressure equilibrium, to logically model the flow paths and phase distribution behaviors of the gas–liquid two-phase flow. This enables the accurate derivation of the respective contributions of each reservoir interval and dynamic production allocation without the need for downhole logging. Validation results show that the proposed method reliably reconstructs reservoir contribution rates under various operational conditions and wellbore configurations. Through a comparison of calculated and simulated results, the maximum relative error occurs during abrupt changes in the production capacity, approximately 6.37%, while for most time periods, the error remains within 1%, with an average error of 0.49% throughout the process. These results substantially improve the timeliness and accuracy of the reservoir identification. This study offers a novel approach for the co-optimization of complex multi-reservoir gas fields, enriching the theoretical framework of dual-gas co-production and providing technically adaptive solutions and engineering guidance for multilayer unconventional gas exploitation. Full article

The massive heavy oil reserves in the Athabasca region of northern Alberta depend on steam-assisted gravity drainage (SAGD) for their economic exploitation. Even though SAGD has been successful in highly viscous oil recovery, it is still a costly technology because of the large energy input requirement. Large water and natural gas quantities needed for steam generation imply sizable greenhouse gas (GHG) emissions and extensive post-production water treatment. Several methods to make SAGD more energy-efficient and environmentally sustainable have been attempted. Their main goal is to reduce steam consumption whilst maintaining favourable oil production rates and ultimate oil recovery. Oil saturation within the steam chamber plays a critical role in determining both the economic viability and resource efficiency of SAGD operations. However, accurately quantifying the residual oil saturation left behind by SAGD remains a challenge. In this experimental research, sand pack Expanding Solvent SAGD (ES-SAGD) coinjection experiments are reported in which Pentane -C₅H₁₂, and Hexane -C₆H₁₄ were utilised as an additive to steam to produce Long Lake bitumen. Each solvent is assessed at three different constant concentrations through time using experiments simulating SAGD to quantify their impact. The benefits of single-component solvent coinjection gradually diminish as the SAGD process approaches its later stages. ES-SAGD pentane coinjection offers a smaller improvement in recovery factor (RF) (4% approx.) compared to hexane (8% approx.). Between these two single-component solvents, 15 vol% hexane offered the fastest recovery. The obtained data in this research provided compelling evidence that the coinjection of solvent under carefully controlled operating conditions, reduced overall steam requirement, energy consumption, and residual oil saturation allowing proper adjustment of oil and water relative permeability curve endpoints for field pilot reservoir simulations. Full article

The distribution of leachate in landfill systems significantly influences landfill stability, pollutant migration, and gas transport. However, existing methods for measuring leachate levels in landfills with multiple intermediate cover layers remain insufficient. This study introduces a novel in situ testing method to determine multi-layer leachate levels. Field experiments at a landfill site in northwestern China successfully quantified leachate levels on each intermediate cover layer. Seepage analysis simulated the leachate level recovery test method used in field investigations, enabling examination of the formation mechanisms and drainage characteristics of multi-layer leachate systems. Measurement results demonstrated that each intermediate cover layer retained a corresponding perched leachate level. Variations in perched water head across waste layers arise from differences in drainage capacity between waste strata. Differential settlement of the intermediate cover layers in localized areas generated adverse hydraulic gradients, contributing to spatial heterogeneity in perched leachate distribution. Back analysis yields an in situ saturated hydraulic conductivity ranging from 1 × 10⁻⁴ to 3.3 × 10⁻³ cm/s. Low-permeability intermediate cover layers were identified as the primary factors contributing to multi-layer leachate formation. The implementation of effective horizontal drainage can reduce perched leachate accumulation above intermediate layers. Full article

Currently, the development of oil reservoirs with high water cut faces numerous challenges, including poor economic efficiency, difficulties in residual oil recovery, and a lack of effective development technologies. In light of these issues, this paper conducts research on gas drive development during the high water cut stage in middle–high permeability reservoirs and introduces an innovative technical approach for air thermal miscible flooding. In this study, the Enhanced Oil Recovery (EOR) mechanism and the dynamic characteristics of thermal miscible flooding were investigated through laboratory experiments and numerical simulations. The N₂ and CO₂ flooding experiments indicate that gas channeling is likely to occur when miscible flooding cannot be achieved, due to the smaller gas–water mobility ratio compared to the gas–oil mobility ratio during the high water cut stage. Consequently, the enhanced recovery efficiency of N₂ and CO₂ flooding is limited. The experiment on air thermal miscible flooding demonstrates that under conditions of high water content, this method can form a stable high-temperature thermal oxidation front. The high temperature, generated by the thermal oxidation front, promotes the miscibility of flue gas and crude oil, effectively inhibiting gas flow, preventing gas channeling, and significantly enhancing oil recovery. Numerical simulations indicate that the production stage of air hot miscible flooding in reservoirs with middle–high permeability and high water cut can be divided into three phases: pressurization and drainage response, high efficiency and stable production with a low air–oil ratio, and low efficiency production with a high air–oil ratio. These phases can enable efficient development during the high water cut stage in medium to high permeability reservoirs, with the theoretical EOR range expected to exceed 30%. Full article

The development of deep coalbed methane (CBM) wells faces challenges such as significant reservoir depth, low permeability, and severe liquid loading in the wellbore. Traditional drainage and gas recovery techniques struggle to meet the dynamic production demands. This study, using the deep CBM wells at the Jishen 15A platform as an example, proposes a “cyclic gas lift–wellhead compression-vent gas recovery” composite synergy technology. By selecting a critical liquid-carrying model, innovating equipment design, and dynamically regulating pressure, this approach enables efficient production from low-pressure, low-permeability gas wells. This research conducts a comparative analysis of different critical liquid-carrying velocity models and selects the Belfroid model, modified for well inclination angle effects, as the primary model to guide the matching of tubing production and annular gas injection parameters. A mobile vent gas rapid recovery unit was developed, utilizing a three-stage/two stage pressurization dual-process switching technology to achieve sealed vent gas recovery while optimizing pipeline frictional losses. By combining cyclic gas lift with wellhead compression, a dynamic wellbore pressure equilibrium system was established. Field tests show that after 140 days of implementation, the platform’s daily gas production increased to 11.32 × 10⁴ m³, representing a 35.8% rise. The average bottom-hole flow pressure decreased by 38%, liquid accumulation was reduced by 72%, and cumulative gas production increased by 370 × 10⁴ m³. This technology effectively addresses gas–liquid imbalance and liquid loading issues in the middle and late stages of deep CBM well production, providing a technical solution for the efficient development of low-permeability CBM reservoirs. Full article

Steam-assisted gravity drainage (SAGD) is a widely used thermal enhanced oil recovery (EOR) technique in North America, particularly in high-permeability oil sand reservoirs. While effective, its economic viability has declined due to low oil prices and high greenhouse gas (GHG) emissions from the steam generation. To improve cost-effectiveness and reduce emissions, solvent-assisted SAGD techniques have been explored. Expanding Solvent-SAGD (ES-SAGD) involves co-injecting light hydrocarbons like propane or butane with steam to enhance oil viscosity reduction. This approach lowers the steam–oil ratio by combining solvent dissolution effects with thermal effects. However, the high cost of solvents, particularly butane, challenges its commercial feasibility. Propane is cheaper but less effective, while butane improves performance but remains expensive. This research aims to optimize ES-SAGD by using a propane–butane mixture to achieve efficient performance at a lower cost than pure butane. A linear sand pack is used to evaluate different propane/butane compositions, maintaining constant operational conditions and a solvent concentration of 15 vol.%. Temperature monitoring provides insights into steam chamber growth. Results show that solvent injection significantly enhances ES-SAGD performance compared to conventional SAGD. Performance improves with increasing butane concentration, up to 80% butane in the C₃–C₄ mixture at the test pressure and ambient temperature. Propane alone results in the lowest system temperature, while conventional SAGD reaches the highest temperature. These findings highlight the potential of optimized solvent mixtures to improve ES-SAGD efficiency while reducing costs and GHG emissions. Full article

Background: Emphysema is a chronic lung disease characterized by alveolar wall destruction, leading to impaired gas exchange. Giant bullous emphysema (GBE) is a severe form of emphysema, often requiring surgical intervention. Video-assisted thoracoscopic surgery (VATS) is a minimally invasive approach for various thoracic pathologies, including lung volume reduction surgery (LVRS) and bullectomy for emphysematous bullae. Uniportal VATS (U–VATS), a further refinement, offers benefits such as reduced postoperative pain and faster recovery. Methods: This retrospective study analyzed data from two high-volume European Thoracic Surgery centers between August 2016 to January 2024. A total of 29 patients underwent U–VATS bullectomy for GBE. Results: Nineteen patients were males (65.5%) with a mean age of 44.7 ± 8.8 years. Ten (34.5%) were active smokers. Eighteen patients (62.1%) presented with a single giant bulla, while the remaining cases were in the context of pulmonary emphysema. Four patients (13.8%) presented with pneumothorax, with one requiring preoperative chest drainage. Twenty-eight patients (96.6%) underwent only U–VATS bullectomy, with additional chemical pleurodesis in eleven cases (37.9%). One patient (3.4%) underwent a left upper lobectomy for a giant bulla and NSCLC. In cases of severe lung emphysema and fragile pulmonary tissue, the stapler line was buttressed with Gore^® Seamguard^®. No conversions to thoracotomy, postoperative air-leaks, or major complications were recorded. At a mean follow-up time of 22.0 ± 14.0 months, no pneumothorax recurrence was documented. At about six months after surgery, pulmonary function significantly improved. Conclusions: U–VATS bullectomy appears to be a safe and feasible technique for the treatment of bullae in GBE, offering promising postoperative outcomes. Full article

Multi-stage hydraulic fracturing is a widely used technology in the development of shale oil and gas reservoirs that creates artificial fractures and forms fracture networks that enhance fluid flow within reservoirs. A well-designed fracture network can significantly enhance the production performance of oil and gas wells, thereby improving the recovery of shale oil and gas reservoirs. To achieve this, understanding the gas production performance of individual artificial fractures is crucial, as it provides valuable insights for refining subsequent fracturing designs, ultimately leading to an optimized fracture network design. At present, numerical simulations are commonly used to study the production performance of individual artificial fractures by modeling the production process of the entire shale oil and gas reservoir. However, due to the heterogeneity of reservoirs and the presence of numerous natural fractures, traditional numerical simulations require high-resolution grids to model the production process, making them computationally expensive and time-consuming. To address this issue, in this work, based on the concept of diffusive time of flight (DTOF), the authors propose a fast simulation method to efficiently simulate the production behavior of individual artificial fractures throughout the shale oil and gas reservoir production process. The DTOF can be obtained by solving the Eikonal equation using the fast marching method (FMM), which is then used to calculate the drainage volume of individual artificial fractures. Subsequently, a geometric approximation of the drainage volume is used to efficiently compute the production rates of individual artificial fractures. Unlike traditional numerical simulations, this method uses a single non-iterative calculation to determine the drainage volume of individual artificial fractures, followed by a geometric approximation to compute the production rates. This eliminates the need for high-resolution grids, significantly reducing computational cost and time, which allows the proposed method to provide faster simulations compared to traditional numerical methods while maintaining sufficient accuracy. Full article

This paper summarizes the research progress and applications of oxygen-reduced-air-assisted gravity drainage (OAGD) in enhanced oil recovery (EOR). The fundamental principles and key technologies of OAGD are introduced, along with a review of domestic and international field trials. Factors influencing displacement performance, including low-temperature oxidation reactions, injection rates, and reservoir dip angles, are discussed in detail. The findings reveal that low-temperature oxidation significantly improves the recovery efficiency through the dynamic balance of light hydrocarbon volatilization and fuel deposition, coupled with the synergistic optimization of the reservoir temperature, pressure, and oxygen concentration. Proper control of the injection rate stabilizes the oil–gas interface, expands the swept volume, and delays gas channeling. High-dip reservoirs, benefiting from enhanced gravity segregation, demonstrate superior displacement efficiency. Finally, the paper highlights future directions, including the optimization of injection parameters, deepening studies on reservoir chemical reaction mechanisms, and integrating intelligent gas injection technologies to enhance the effectiveness and economic viability of OAGD in complex reservoirs. Full article

During the development of multi-layer tight sandstone gas reservoirs in Ordos Basin, China, it has not been easy to calculate accurately the production of each individual layer in gas wells. However, production allocation provides a vital basis for evaluating dynamic reserves and drainage areas of gas wells and remaining gas distributions of gas layers. To improve the accuracy and reliability of production allocation of gas wells, a new model was constructed based on the seepage equation, material balance equation, and pipe string pressure equation. In particular, this new model introduced the seepage equation with an elliptical boundary to accurately capture the fluid flow characteristics within a lenticular tight gas reservoir. The new model can accurately calculate the production and reservoir pressure of each individual layer in gas wells. In addition, the new model was validated and applied in the Sulige gas field, Ordos Basin. The following conclusions were drawn: First, The gas production contribution rates of pay zones based on the new model are fairly close to the measurements of the production profile logging, with errors less than 10%. Second, The overall drainage area of a gas well lies among those of each pay zone, and the total dynamic reserves of the well are close to the sum of the dynamic reserves of pay zones. Third, Higher permeability may lead to higher initial gas production of the pay zone, but the ultimate gas production contributions of pay zones are affected jointly by permeability and dynamic reserves. Finally, The new model has been successfully applied to the SZ block of the Sulige gas field, in which the fine evaluation of dynamic reserves, drainage areas, gas production, recovery factors, and remaining gas distributions of different layers was delivered, and the application results provide technical support for the future well placement and enhanced gas recovery of the block. Full article

Nitrogen foam is a promising enhanced oil recovery (EOR) technique with significant potential for tertiary oil recovery. This improves the efficiency of the oil displacement during the gas drive processes while expanding the swept volume. However, in the high-temperature, high-salinity reservoirs of the Tahe Oilfield, conventional N₂ foam systems show suboptimal performance, as their effectiveness is heavily limited by temperature and salinity. Consequently, enhancing the foam stability under these harsh conditions is crucial for unlocking new opportunities for the development of Tahe fracture-vuggy reservoirs. In this study, the Waring–Blender method was used to prepare weathered coal particles as a foam stabilizer. Compared to conventional foam stabilizers, weathered coal particles were found to enhance the stability of the liquid film under high-temperature and high-salinity conditions. Firstly, the foaming properties of the six foaming agents were comprehensively evaluated and their foaming properties were observed at different concentrations. YL-3J with a mass concentration of 0.7% was selected. The foaming stabilization performance of four types of solid particles was evaluated and weathered coal solid particles with a mass concentration of 15% and particle size of 300 mesh were selected. Therefore, the particle-reinforced foam system was determined to consist of “foaming agent YL-3J (0.7%) + weathered coal (15.0%) + nitrogen”. This system exhibited a foaming volume of 310 mL at 150 °C and salinity of 210,000 mg/L, with a half-life of 1920 s. Finally, through interfacial tension and viscoelastic modulus tests, the synergistic mechanism between weathered coal particles and surfactants was demonstrated. The incorporation of weathered coal particles reduced the interfacial tension of the system. The formation of a skeleton at the foam interface increased the apparent viscosity and viscoelastic modulus, reduced the liquid drainage rate from the foam, and mitigated the disproportionation effect. These effects enhanced the temperature, salinity resistance, and stability of the foam. Consequently, they contributed to the stable flow of foam under high-temperature and high-salinity conditions in the reservoir, thereby improving the oil displacement efficiency of the system. Full article

The productivity prediction of weakly volatile fractured reservoirs is influenced by reservoir parameters and fluid characteristics. To address the computational challenges posed by complex fractures, an equivalent fracture element method is proposed to calculate equivalent permeability in fractured zones. A three-phase seepage model based on material balance is developed, using the Baker linear model to determine the relative permeabilities of oil, gas, and water while accounting for bound water saturation. Dynamic drainage distance and conductivity coefficients are introduced to calculate production at each stage, with the semi-analytical model solved iteratively for pressure and saturation. Validation against commercial simulation software confirms the model’s accuracy, enabling the construction of productivity curves and analysis of reservoir characteristics and injection scenarios. Results showed that the equivalent fracture element method effectively handled multiphase nonlinear seepage and predicted productivity during water flooding. Productivity was more sensitive to through-fracture models, with production increasing as the fracture extent expanded. Optimal water injection occurred when the formation pressure dropped to 80% of the bubble point pressure, and the recovery efficiency improved with periodic-injection strategies compared to conventional methods. These findings have significant implications for improving oil recovery, optimizing injection strategies, and advancing the design of efficient reservoir management techniques across scientific, practical, and technological domains. Full article

Carbonate gas reservoirs are crucial in gas field development, with carbonate bottom-water gas reservoirs being a significant subset. However, the development of these reservoirs often faces challenges such as water invasion, leading to a low gas recovery rate. Enhancing gas recovery is a primary goal for researchers in this field. This study provides a systematic review of the mechanisms, identification, and dynamic prediction of water invasion in these gas reservoirs. The technical adaptability and application range of different enhanced recovery methods are summarized, and their application effects are evaluated. The results indicate that carbonate gas reservoirs have diverse types of storage and permeability spaces, with a wide distribution of pore size scales, leading to various types of enclosed gas caused by water invasion. The prediction accuracy of water invasion models for bottom-water gas reservoirs with fractures and vugs is relatively low. Therefore, numerical simulation research on the basis of fine reservoir characterization is the key technology. The control of bottom-water invasion and the rescue measures after the bottom-water invasion are the keys to improving gas recovery, which can be divided into four types: drainage gas recovery, water control production, active drainage, and injection medium. Gas production by drainage is the main technology for improving gas recovery, among which foam drainage is the most widespread. The optimization of development parameters in production by water control has a good effect in the early stages of development. The active drainage technology on the water invasion channel is the bottom-up technology for the effective development of strong water-flooded gas reservoirs. CO₂ injection may have great potential to improve the recovery of bottom-water gas reservoirs, which is one of the important research directions under the background of “carbon peaking and carbon neutrality”. The research provides theoretical and technical reference significance for enhanced recovery of carbonate bottom-water gas reservoirs. Full article