Search Results (29)

Gravity segregation is a critical phenomenon in thick condensate gas reservoirs, significantly influencing fluid composition and phase behavior. Reservoir-scale numerical simulation, serving as an indispensable technical approach in modern petroleum engineering, provides both quantitative data support and theoretical frameworks for development strategy optimization. However, the impact of gravity segregation on the distribution of initial fluid compositions is often overlooked in conventional numerical simulations due to data limitations or underestimated importance. This oversight leads to systematic deviations between simulated reservoir performance and actual field observations, ultimately compromising the efficient development of reservoirs. This study analyzed PVT data from reservoir fluid samples at different depths to determine the initial fluid composition distribution. Two models were developed: one incorporating gravity segregation and another neglecting it, to evaluate their performance during gas injection. Key findings include: (i) Gravity segregation alters the initial fluid composition, creating lighter components near the reservoir top and heavier ones at the bottom, resulting in distinct phase behaviors and production dynamics. (ii) The model accounting for gravity segregation aligns better with historical production data, while the model neglecting it underestimates oil production rates by about 9% and overestimates oil recovery by 2–5% during gas injection, due to inaccurate fluid composition assumptions. (iii) The model without gravity segregation also underestimates differences in oil recovery between injection–production strategies, such as top versus bottom injection. This study highlights the critical role of gravity segregation in reservoir simulation and provides valuable insights for optimizing the development of condensate gas reservoirs with complex fluid distributions. The findings reveal that accounting for gravity segregation in reservoir simulation models through proper initialization of fluid distribution leads to improved simulation accuracy, thereby enabling more precise development strategy design. Full article

With the increase in exploration in recent years, buried hill condensate gas reservoirs have gradually become an important field for increasing reserves and production of offshore oil and gas in China, and efficient development of condensate gas reservoirs has also become a hot issue in hydrocarbon development. Due to the complex phase-change law and retrograde condensation phenomenon of deep condensate gas reservoirs, the reservoir properties and production dynamics data obtained by conventional pressure-recovery-test methods were greatly limited, and the dynamic data and evaluation parameters of the single well control area cannot be accurately determined. In this paper, using the production analysis method to analyze the production dynamics data of a single well, combined with static geological data and well-test analysis data, the reservoir parameters of a single well were evaluated. Specifically, the Blasingame method was applied to realize the production-decline law of production wells, and new dimensionless flow, pressure parameters, and pseudo-time functions were introduced. Using the unstable well test theory and the traditional production decline analysis technology, the IHS Harmony software is used to fit the production dynamic data with the theoretical chart. The evaluation parameters such as reservoir permeability, skin factor, well control radius, and well control reserves were calculated, providing strong support for the production decision-making of the petroleum industry and also providing a strong decision-making basis for the dynamic adjustment of oil–gas-well manufacture. Full article

The exploitation of Block L within the Tarim Basin oilfield commenced in 1989 and it has transitioned from the natural energy development stage to the current water injection development stage. Despite this, the efficacy of water flooding remains suboptimal, with the low degree of control, uneven utilization of reserves, and subpar mining outcomes. The block still contains substantial remaining oil resources, necessitating continued extraction. Notably, the primary oil produced in this block is condensate oil, which commands a high economic value. To enhance the oil recovery efficiency of the block reservoir, a development plan employing alternating and water-natural gas flooding has been proposed. The objective of this study is to evaluate the feasibility of the proposed alternating displacement scheme involving natural gas and water in this reservoir. The specific steps include PVT fitting, historical matching, residual oil evaluation, and the optimization of gas injection parameters. Results show that for this reservoir the water-natural gas flooding (WAG) is the optimal option. And this article has the application of WAG flooding simulation, simulating 15 years of operation. Compared with the original development scheme of the original well pattern, the recovery of this reservoir is increased by 12.05%, which provided a reference basis for the on-site application of WAG in this reservoir. Full article

The SAGP (steam and gas push) process is an effective enhanced oil recovery (EOR) method for heavy oil reservoirs. Understanding the microscopic interactions among steam, non-condensable gasses (NCGs), and heavy oil under reservoir conditions in SAGP processes is important for their EOR applications. In this study, molecular simulations were performed to investigate the microscopic interactions among steam, NCG, and heavy oil under reservoir conditions in SAGP processes. In addition, the microscopic EOR mechanisms during SAGP processes and the effects of operational parameters (NCG type, NCG–steam mole ratio, temperature, and pressure) were discussed. The results show that the diffusion and dissolution of CH₄ molecules and the extraction of steam molecules cause the molecules of saturates with light molecular weights in the oil globules to stretch and gradually detach from one another, resulting in the swelling of heavy oil. Compared with N₂, CH₄ has a stronger ability to diffuse and dissolve in heavy oil, swell the heavy oil, and reduce the density and viscosity of heavy oil. For this reason, compared with cases where N₂ is used, SAGP processes perform better when CH₄ is used, indicating that CH₄ can be used as the injected NCG in the SAGP process to improve heavy oil recovery. As the NCG–steam mole ratio and injection pressure increase, the diffusion and solubility abilities of CH₄ in heavy oil increase, enabling CH₄ to perform better in swelling the heavy oil and reducing the density and viscosity of heavy oil. Hence, increasing the NCG–steam mole ratio and injection pressure is helpful in improving the performance of SAGP processes in heavy oil reservoirs. However, the NCG–steam mole ratio and injection pressure should be reasonably determined based on actual field conditions because excessively high NCG–steam mole ratios and injection pressures lead to higher operation costs. Increasing the temperature is favorable for increasing the diffusion coefficient of CH₄ in heavy oil, swelling heavy oil, and reducing the oil density and viscosity. However, high temperatures can result in intensified thermal motion of CH₄ molecules, reduce the interaction energy between CH₄ molecules and heavy oil molecules, and increase the difference in the Hildebrand solubility parameter between heavy oil and CH₄–steam mixtures, which is unfavorable for the dissolution of CH₄ in heavy oil. This study can help readers deeply understand the microscopic interactions among steam, NCG, and heavy oil under reservoir conditions in SAGP processes and its results can provide valuable information for the actual application of SAGP processes in enhancing heavy oil recovery. Full article

The natural gas industry has developed rapidly in recent years, with gas storage playing an important role in regulating winter and summer gas consumption and ensuring energy security. The Ke7010 sand body is a typical edge water condensate gas reservoir with an oil ring, and the construction of gas storage has been started. In order to clarify the feasibility of synergistic storage building for gas injection and production, the fluid characteristics during the synergistic reservoir building process were investigated through several rounds of drive-by experiments. The results show that the oil-phase flow capacity is improved by increasing the number of oil–water interdrives, and the injection and recovery capacity is improved by increasing the number of oil–gas interdrives; the reservoir capacities of the high-permeability and low-permeability rock samples increase by about 4.84% and 7.26%, respectively, after multiple rounds of driving. Meanwhile, a numerical model of the study area was established to simulate the synergistic storage construction scheme of gas injection and extraction, and the reservoir capacity was increased by 7.02% at the end of the simulation period, which was in line with the experimental results. This study may provide a reference for gas storage construction in the study area. Full article

This study investigates the complex dynamics of retrograde condensation in condensate gas reservoirs, with a particular focus on the challenges posed by retrograde condensate pollution, which varies in condensate oil content and impacts on reservoir productivity. Numerical simulations quantify the distribution of condensate oil and the reduction in gas-phase relative permeability in reservoirs with 100.95 g/m³, 227.27 g/m³, and 893.33 g/m³ of condensate oil. Unlike previous studies, this research introduces an orthogonal experiment to establish a methodology for studying the dynamic sensitivity factors across different types of gas reservoirs and various development stages, systematically evaluating their contributions to condensate oil. The analysis reveals that reservoirs with low to moderate condensate oil content gradually experience expanding polluted regions, affecting long-term production. The maximum condensate saturation near the wellbore can reach 0.19, reducing gas-phase relative permeability by about 25.44%. In contrast, high-condensate oil reservoirs show severe early-stage retrograde condensation, with saturations up to 0.35 and a permeability damage rate reaching 73%. The orthogonal experiments identify reservoir permeability and condensate oil content as critical factors influencing production indicators. The findings provide key insights and practical recommendations for optimizing production strategies, emphasizing tailored approaches to mitigate retrograde condensation and enhance recovery, especially in high-condensate oil reservoirs, offering theoretical and practical guidance for improving reservoir management and economic returns. Full article

The Bozi 3 reservoir is an ultra-deep condensate reservoir (−7800 m) with a high temperature (138.24 °C) and high pressure (104.78 MPa), leading to complex phase behaviors. Few PVT studies could be referred in the literature to meet such high temperature and pressure conditions. Furthermore, it is questionable regarding the applicability of existing condensate production techniques to such a high temperature and pressure reservoir. This study first characterized the phase behavior via PVT experiments and EOS tuning. The operating conditions were then optimized through reservoir numerical simulation. Results showed that: (1) the critical condensate temperature and pressure of Bozi 3 condensate gas were 326.24 °C and 43.83 MPa, respectively; (2) four gases (methane, recycled dry gas, carbon dioxide, and nitrogen) were analyzed, and methane was identified as the optimal injection gas; (3) gas injection started when the production began to fall and achieved higher recovery than gas injection started when the pressure fell below the dew-point pressure; (4) simultaneous injection of methane at both the upper and lower parts of the reservoir can effectively produce condensate oil over the entire block. This scheme achieved 8690.43 m³ more oil production and 2.75% higher recovery factor in comparison with depletion production. Full article

Surfactants play a crucial role in tertiary oil recovery by reducing the interfacial tension between immiscible phases, altering surface wettability, and improving foam film stability. Oil reservoirs have high temperatures and high pressures, making it difficult and hazardous to conduct lab experiments. In this context, molecular dynamics (MD) simulation is a valuable tool for complementing experiments. It can effectively study the microscopic behaviors (such as diffusion, adsorption, and aggregation) of the surfactant molecules in the pore fluids and predict the thermodynamics and kinetics of these systems with a high degree of accuracy. MD simulation also overcomes the limitations of traditional experiments, which often lack the necessary temporal–spatial resolution. Comparing simulated results with experimental data can provide a comprehensive explanation from a microscopic standpoint. This article reviews the state-of-the-art MD simulations of surfactant adsorption and resulting interfacial properties at gas/oil–water interfaces. Initially, the article discusses interfacial properties and methods for evaluating surfactant-formed monolayers, considering variations in interfacial concentration, molecular structure of the surfactants, and synergistic effect of surfactant mixtures. Then, it covers methods for characterizing microstructure at various interfaces and the evolution process of the monolayers’ packing state as a function of interfacial concentration and the surfactants’ molecular structure. Next, it examines the interactions between surfactants and the aqueous phase, focusing on headgroup solvation and counterion condensation. Finally, it analyzes the influence of hydrophobic phase molecular composition on interactions between surfactants and the hydrophobic phase. This review deepened our understanding of the micro-level mechanisms of oil displacement by surfactants and is beneficial for screening and designing surfactants for oil field applications. Full article

Gas injection for enhanced oil and gas reservoir recovery is a crucial method in offshore Carbon Capture, Utilization, and Storage (CCUS). The B6 buried hill condensate gas reservoir, characterized by high CO₂ content, a deficit in natural energy, developed fractures and low-pressure differentials between formation and saturation pressures, requires supplementary formation energy to mitigate retrograde condensation near the wellbore area through gas injection. However, due to the connected fractures, the B6 gas reservoir exhibits strong horizontal and vertical heterogeneity, resulting in severe gas channeling and a futile cycle, which affects the gas injection efficiency at various levels of fracture development. Based on these findings, we conducted gas injection experiments and numerical simulations on fractured cores. A characterization method for oil and gas relative permeability considering dissolution was established. Additionally, the gas injection development boundary for this type of condensate gas reservoir was quantified according to the degree of fracture development, and the gas injection mode of the B6 reservoir was optimized. Research indicates that the presence of fractures leads to the formation of a dominant gas channel; the greater the permeability difference, the poorer the gas injection effect. The permeability gradation (fracture permeability divided by matrix permeability) in the gas injection area should be no higher than 15; gas injection in wells A1 and A2 is likely to achieve a better development effect under the existing well pattern. Moreover, early gas injection timing and pulse gas injection prove beneficial in enhancing the recovery rate of condensate oil. The study offers significant guidance for the development of similar gas reservoirs and for reservoirs with weakly connected fractures; advancing the timing of gas injection can mitigate the retrograde condensation phenomenon, whereas initiating gas injection after depletion may reduce the impact of gas channeling for reservoirs with strongly connected fractures. Full article

The steam assisted gravity drainage (SAGD) process requires high energy input to maintain the continuous expansion of the steam chamber for achieving high oil recovery. In the late stage of SAGD operation where the oil rate is low and the heat loss is high from a mature steam chamber, maintaining steam chamber pressure with a lower steam injection is the key to maintaining the economic oil-to-steam ratio (OSR). Both laboratory studies and field tests have demonstrated the effectiveness of adding a non-condensable gas (NCG) to the SAGD steam chamber for improving the overall thermal efficiency. In this study, a multi-well reservoir model was built based on the detailed geological description from an operating SAGD project area, which contains thick pay and top water. Grounded with the history matching of more than 20 years of production using CSS (cyclic steam stimulation) and SAGD as follow-up process, the model was applied to optimize the operating strategies for the late stage of SAGD production. The results from this study demonstrated that the co-injection of steam with CO₂ or the injection of CO₂ only has potential to improve the OSR and reduce emissions by more than 50% through the improvement in steam-saving and the storage of CO₂. The results from reservoir modeling indicate that, with the current volume of a steam chamber and an operating pressure of 4.0 MPa, about 55 sm³ of CO₂ could be sequestrated and utilized for producing 1.0 m³ of oil from this reservoir through the replacement of a steam injection with CO₂ in the late stage of SAGD operation. Full article

Effective fluid-loss control in oil wells is a critical concern for the oil industry, particularly given the substantial reserves situated in carbonate reservoirs globally. The prevalence of such reservoirs is expected to rise with the slow depletion of hydrocarbons, intensifying the need to address challenges related to deteriorating reservoir properties post well-killing operations. This deterioration results in significant annual losses in hydrocarbon production at major oil enterprises, impacting key performance indicators. To tackle this issue, this study focuses on enhancing well-killing technology efficiency in carbonate reservoirs with abnormally low formation pressures. To address this issue, the authors propose the development of new blocking compositions that prevent the fluid loss of treatment fluids by the productive reservoir. The research tasks include a comprehensive analysis of global experience in well-killing technology; the development of blocking compositions; an investigation of their physico-chemical, rheological, and filtration properties; and an evaluation of their effectiveness in complicated conditions. The technology’s application in the oil and gas condensate fields of the Volga-Ural province showcases its practical implementation. This study provides valuable insights and solutions for improved fluid-loss control in carbonate reservoirs, ultimately enhancing well performance and hydrocarbon recovery. Full article

During the depletion development of condensate gas reservoirs, when the formation pressure drops below the dew point pressure, the condensate oil and natural gas systems are in the non-equilibrium state of foggy retrograde condensation. The rational use of the non-equilibrium phase characteristics of the foggy retrograde condensation phenomenon during the development process will be beneficial to the recovery of condensate oil and natural gas. In order to clarify the retrograde condensation control mechanism during the non-equilibrium depletion development of condensate gas reservoirs, the phase characteristics of a condensate oil and gas system were studied by constant composition expansion and constant volume depletion experiments. Then, on the basis of a long core depletion experiment and chromatographic analysis experiment, the influence of different pressure drop speeds, fluid properties, and reservoir physical properties on the control effect of non-equilibrium retrograde condensation after the coupling of the fluid retrograde condensation and reservoir core is analyzed. The results show that during the pressure decline process, the condensate oil and gas system will produce a strong foggy retrograde condensation phenomenon, with the saturation of the retrograde condensate increasing and then decreasing. The cumulative recovery of the condensate oil and natural gas, as well as the mass fraction of the heavy components in the condensate oil, increase with the increase in the depletion rate. Different fluid properties and reservoir physical properties have a great influence on the cumulative recovery degree of the condensate oil, and have little influence on the recovery degree of the natural gas. This work has a certain guiding role for the stable production and enhanced recovery of fractured condensate gas reservoirs in subsurface structures of metamorphic rocks. Full article

Water alternating gas (WAG) flooding is a widely employed enhanced oil recovery method in various reservoirs worldwide. In this research, we will employ SiO₂ nanofluid alternating with the CO₂ injection method as a replacement for the conventional WAG process in oil flooding experiments. The conventional WAG method suffers from limitations in certain industrial applications, such as extended cycle times, susceptibility to water condensation and agglomeration, and ineffectiveness in low-permeability oil reservoirs, thus impeding the oil recovery factor. In order to solve these problems, this study introduces SiO₂ nanofluid as a substitute medium and proposes a SiO₂ nanofluid alternate CO₂ flooding method to enhance oil recovery. Through the microcharacterization of SiO₂ nanofluids, comprehensive evaluations of particle size, dispersibility, and emulsification performance were conducted. The experimental results revealed that both SiO₂-I and SiO₂-II nanoparticles exhibited uniform spherical morphology, with particle sizes measuring 10–20 nm and 50–60 nm, respectively. The SiO₂ nanofluid formulations demonstrated excellent stability and emulsification properties, highlighting their potential utility in petroleum-related applications. Compared with other conventional oil flooding methods, the nanofluid alternating CO₂ flooding effect is better, and the oil flooding effect of smaller nanoparticles is the best. Nanofluids exhibit wetting modification effects on sandstone surfaces, transforming their surface wettability from oil-wet to water-wet. This alteration reduces adhesion forces and enhances oil mobility, thereby facilitating improved fluid flow in the rock matrix. In the oil flooding experiments with different slug sizes, smaller gas and water slug sizes can delay the breakthrough time of nanofluids and CO₂, thereby enhancing the effectiveness of nanofluid alternate CO₂ flooding for EOR. Among them, a slug size of 0.1 PV approaches optimal performance, and further reducing the slug size has limited impact on improving the development efficiency. In oil flooding experiments with different slug ratios, the optimal slug ratio is found to be 1:1. Additionally, in oil flooding experiments using rock cores with varying permeability, lower permeability rock cores demonstrate higher oil recovery rates. Full article

The largest marine carbonate oilfield and gas condensate field in China have been found in the Ordovician limestones in the central Tarim Basin. They are defined as large “layered” reef-shoal and karstic reservoirs. However, low and/or unstable oil/gas production has been a big challenge for effective exploitation in ultra-deep (>6000 m) reservoirs for more than 20 years. Together with the static and dynamic reservoir data, we have a review of the unconventional characteristics of the oil/gas fields in that: (1) the large area tight matrix reservoir (porosity less than 5%, permeability less than 0.2 mD) superimposed with localized fracture-cave reservoir (porosity > 5%, permeability > 2 mD); (2) complicated fluid distribution and unstable production without uniform oil/gas/water interface in an oil/gas field; (3) about 30% wells in fractured reservoirs support more than 80% production; (4) high production decline rate is over 20% per year with low recovery ratio. These data suggest that the “sweet spot” of the fractured reservoir rather than the matrix reservoir is the major drilling target for ultra-deep reservoir development. In the ultra-deep pre-Mesozoic reservoirs, further advances in horizontal drilling and large multiple fracturing techniques are needed for the economic exploitation of the matrix reservoirs, and seismic quantitative descriptions and horizontal drilling techniques across the fault zones are needed for oil/gas efficient development from the deeply fractured reservoirs. Full article

Natural gas injection is considered for enhanced oil recovery (EOR) in a high saturation pressure reservoir in block B111 of the Dagang oilfield, China. To investigate the interaction characteristics of injected natural gas and crude oil, the ability for dissolution–diffusion and miscibility–extraction of natural gas in crude oil was tested using a piece of high-temperature and high-pressure PVT equipment. The physical properties and minimum miscible pressure (MMP) of the natural gas–crude oil system and their interaction during dynamic displacement were analyzed using the reservoir numerical simulation method. The results show the following: (1) Under static gas–oil contact conditions, natural gas has a significant dissolution–diffusion and miscibility–extraction effect on the crude oil in block B111, especially near the gas–oil interface. The content of condensate oil in gas phase is 10.14–18.53 wt%, while the content of dissolved gas in oil phase reaches 26.17–57.73 wt%; (2) Under the reservoir’s conditions, the saturated solubility of natural gas injected in crude oil is relatively small. The effect of swelling and viscosity reduction on crude oil is limited. As the pressure increases with more natural gas dissolved in crude oil, the phase state of crude oil can change from liquid to gas; accordingly, the density and viscosity of crude oil will be greatly reduced, presenting the characteristics of condensate gas; (3) The MMP of natural gas and crude oil is estimated to be larger than 40 MPa. It mainly forms a forward-contact evaporative gas drive in block B111. The miscible state depends on the maintenance level of formation pressure. The injected natural gas has a significant extraction effect on the medium and light components of crude oil. The content of C2–C15 in the gas phase at the gas drive front, as well as the content of CH₄ and C16+ in the residual oil at the gas drive trailing edge, will increase markedly. Accordingly, the residual oil density and viscosity will also increase. These results have certain guiding significance for understanding gas flooding mechanisms and designing gas injection in block B111. Full article