Search Results (45)

To address core challenges involving severe reservoir heterogeneity, complex fracture systems, and rapid energy depletion encountered in the development of tight oil reservoirs in the G5 block of the Nanpu Sag, this study performs a systematic analysis of geological characteristics and optimizes an integrated geology–engineering development strategy. Through the integration of 3D seismic and well-logging data, the “sandwich-style” superposition architecture of sand bodies in the Es₃⁴ sub-member is quantitatively characterized. It reveals that productivity is co-controlled by high-quality main channel sand bodies (permeability: 0.5–1 mD) and high-density fracture zones (linear density: 3.2 fractures·m⁻¹) along structural ridges. Consequently, a comprehensive technical system is established, incorporating trajectory optimization for high-angle wells, differential stimulated reservoir volume (SRV) fracturing based on the Reservoir Quality Index (RQI), and CO₂ huff-n-puff for energy supplementation. Field applications demonstrate that optimized well placement increased the drilling encounter rate of high-quality reservoirs from 42% to 78%, while CO₂ huff-n-puff technology successfully restored the formation pressure coefficient from 0.65 to 0.82. The implementation of this integrated approach extended the stable production period of typical wells to 18 months, significantly mitigating production decline and increasing the ultimate recovery factor of the block to 14.5%, which provides a favorable recovery level for a complex fault-block tight oil reservoir compared with the generally low primary-recovery performance reported for analogous tight oil systems in rift-basin settings. This study confirms that the coupling zone of fracture systems along structural ridges and high-quality sand bodies represents the optimal target for economic development. The proposed geology–engineering synergy model provides a transferable technical paradigm for the efficient development of similar complex fault-block tight oil reservoirs. Full article

Aiming to investigate the unclear lower limit of microscopic pore mobilization during CO₂ pre-fracturing in the shale oil reservoirs of the Ma51X well block, this study integrates high-temperature and high-pressure (110 °C 70 MPa) CO₂ huff-n-puff with nuclear magnetic resonance (NMR) experiments. The results demonstrate the following: (1) under high-temperature (110 °C) and ultra-high-pressure (70 MPa) conditions, the lower limit of mobilizable pores for CO₂ to displace reservoir crude oil reaches 1.7~2.2 nm; (2) the dominant mobilized pore range for CO₂ is 5.1~38.5 nm, and macropore abundance directly dictates the macroscopic sweep coverage of CO₂; (3) the modification effect of CO₂ on pore structure is primarily concentrated within the mesopore-to-macropore systems, and with an increase in huff-n-puff cycles, crude oil in mesopores progressively migrates toward macropores; and (4) multi-cycle CO₂ huff-n-puff exhibits a cyclic performance pattern characterized by dominance in the initial cycle and subsequent attenuation. This study precisely delineates the lower limit of mobilizable pores for crude oil in the shale oil reservoirs of the Ma51X well block, providing a robust theoretical foundation for the efficient development of this formation and analogous ultra-low permeability reservoirs. Full article

Tight oil reservoirs are characterized by poor petrophysical properties. After hydraulic fracturing, the low flowback rate of fracturing fluid readily leads to the formation of a water invasion zone in the near-wellbore region, which severely restricts the performance of Carbon dioxide (CO₂) huff-n-puff. To clarify the damage mechanism of the water invasion zone on CO₂ huff-n-puff in tight oil reservoirs and determine the key regulatory parameters, tight cores with a relative water invasion zone length Δδ = 0.3 were adopted as the research subject. Five groups of injection–soaking–production time combinations were designed, and single-factor analysis was implemented using the control variable method. Integrated with numerical simulation and nuclear magnetic resonance (NMR) testing, the influence of the water invasion zone, pore crude oil mobilization characteristics, and parameter regulation effects were systematically explored. The results demonstrate that the water invasion zone occupies effective pore throats to form a continuous water-phase barrier, hindering CO₂ seepage and mass transfer. After four huff-n-puff cycles, the cumulative recovery factor of the water-invaded model is 4.13 percentage points lower than that of the water-free model. After four huff-n-puff cycles, the cumulative recovery factor of the water-invaded model is 4.13 percentage points lower than that of the water-free model. The NMR T₂ spectra of cores with and without water invasion exhibit remarkable discrepancies: the water-free core presents a unimodal structure, while the water-invaded core features a distinctive bimodal structure, with obvious staged characteristics in crude oil mobilization. The recovery factor declines nonlinearly and sharply with the increase of Δδ, verifying that the water invasion zone length is the dominant controlling factor. The regulation effects of injection, soaking, and production time differ significantly: injection time serves as the pivotal parameter for enhancing oil recovery. Prolonging injection time can strengthen displacement intensity and dismantle the water-phase barrier, thereby elevating the recovery factor, whereas soaking time and production time have no significant improvement effect. The results can provide valuable references for the parameter optimization of CO₂ huff-n-puff in water-invaded tight oil reservoirs. Full article

While CO₂ huff-n-puff (CO₂ HnP) is a promising technique for shale oil recovery, the characteristics and controlling factors of microscopically movable oil in lacustrine argillaceous-rich shales remain poorly understood. Shale samples from the Qingshankou Formation in the Songliao Basin were collected, and a series of experiments, including low-pressure N₂ adsorption, mercury injection porosimetry, and nuclear magnetic resonance, were conducted. High-pressure and high-temperature CO₂ HnP experiments were then conducted to investigate the effects of cycle number, soaking time and changes in pore structure on movable oil distribution. The shales exhibit multi-scale pores and lamellar fractures containing substantial residual oil (41.33–52.16% saturation). CO₂ HnP effectively mobilizes oil from macropores (50–1000 nm) and fractures (>1000 nm), with a limited effect in micro–mesopores (<50 nm). Three CO₂ HnP cycles were optimal for movable oil extraction. Extending the soaking time increased movable oil by ~4%, primarily from macropores and fractures (5.59–6.05%), with minimal improvement in smaller pores. A combination of CO₂ flooding followed by CO₂ HnP increased total movable oil by 4.83–7.26%, significantly enhancing recovery from micropores (7.26%) and macropores (9.21%). This study clarifies the pore size distribution and mobilization constraints of movable oil in argillaceous-rich shales. The integrated CO₂ flooding and HnP strategy proves to be highly effective, especially for movable oil in micro–mesopores. This study is the first to investigate pore-scale movable oil in lacustrine argillaceous-rich shales during CO₂ huff-n-puff under in situ reservoir conditions, and could provide critical insights for optimizing shale oil recovery in the Songliao Basin and similar lacustrine reservoirs. Full article

Tight oil reservoirs developed by volume fracturing commonly suffer from insufficient energy replenishment and rapid production decline. Although CO₂ huff-n-puff can enhance oil recovery, it is prone to early gas channeling through fracture-dominated high-permeability channels, and its effectiveness decreases with successive cycles. To clarify the coupled effects of fracture morphology and foam on CO₂ huff-n-puff performance, comparative experiments of multi-cycle CO₂ huff-n-puff and foam-assisted CO₂ huff-n-puff were conducted on fractured tight cores from the Xinjiang Mahu reservoir, combined with offline low-field NMR T₂ analysis. The results show a clear first-cycle dominant effect, and better reservoir properties lead to higher initial recovery and slower decline in subsequent cycles. Cross fractures increase the final oil recovery by 81.1%, 83.4%, and 73.2% for the three reservoir types, respectively, whereas excessively large fracture apertures reduce recovery because of intensified gas channeling. Foam further improves oil recovery, with 0.6% giving the optimum performance and increasing final recovery by 20.11%, 14.79%, and 8.36% in Type-I, Type-II, and Type-III reservoirs, respectively. NMR results indicate that foam mainly enhances the mobilization of remaining oil in medium and large pore–throat systems by blocking preferential flow channels and enlarging the effective swept volume. This study provides an experimental basis for parameter optimization and mechanistic understanding of foam-assisted CO2 huff-n-puff in fractured tight reservoirs. Full article

Carbon dioxide (CO₂) emissions resulting from natural gas flaring are significant contributors to atmospheric greenhouse gases, posing a substantial risk to the Earth’s climate by exacerbating global warming. As a response, both the oil industry and government authorities are actively exploring cost-effective strategies to address this issue through carbon capture, utilization, and storage (CCUS), as well as reducing natural gas flaring and CO₂ leaks in the oil fields to mitigate the adverse consequences of greenhouse gas emissions. This study presents a numerical investigation of CO₂ utilization for enhanced oil recovery (EOR) and associated CO₂ retention in unconventional reservoirs, using the Bakken Formation as a representative case. A compositional reservoir model is developed to simulate CO₂ Huff-n-Puff (HnP) processes in a fractured horizontal well. The model incorporates dual-porosity and dual-permeability formulations, fluid–rock interactions, and an equation-of-state-based compositional framework to capture multiphase flow behavior. Key operational parameters, including reservoir pressure, injection rate, injection duration, and CO₂ molecular diffusion, are systematically evaluated to assess their impact on oil recovery and CO₂ retention. The results show that lower bottom-hole pressures enhance oil recovery through increased drawdown, while operating pressures near the minimum miscibility pressure (MMP) improve CO₂ solubility and overall retention. Extended injection durations and higher diffusion coefficients increase CO₂ dissolution in the oil phase but exhibit diminishing marginal benefits beyond an optimal injection time. The study quantifies residual and solubility trapping mechanisms during the operational timeframe of CO₂-EOR and provides mechanistic insights into optimizing CO₂-HnP performance in tight formations. The proposed framework establishes a technical basis for integrating CO₂-EOR with emission mitigation strategies in unconventional reservoirs. Full article

To optimize enhanced oil recovery (EOR) techniques for pre-fractured heavy oil reservoirs, this research conducted long-core flooding experiments using three distinct injection media: CO₂, water, and CO₂/water alternate huff-n-puff. A 35 cm composite core was employed to simulate the reservoir conditions after pre-fracturing. Experimental results indicated that the CO₂ huff-n-puff process yielded the highest oil production, enhancing the overall recovery factor by 33.0% compared to depletion production, with a total recovery factor of 43.8% after four optimized cycles. The CO₂/water alternate huff-n-puff process increased the recovery factor by 28.3%, achieving a total of 41.9% after four cycles. In contrast, water injection improved the recovery factor by only 15.2%, reaching a total of 26.2% after three cycles. By evaluating both oil recovery efficiency and oil exchange ratio, the optimal cycle numbers were determined as four cycles for CO₂ huff-n-puff, four cycles for CO₂/water alternate huff-n-puff, and three cycles for water huff-n-puff. Based on these optimized parameters, the CO₂/water alternate huff-n-puff process was identified as the most effective EOR method for the target reservoir. Furthermore, this study assessed the potential for CO₂ storage in the reservoir post-production. Calculations of CO₂ storage ratios during the huff-n-puff process demonstrated the feasibility of integrating enhanced oil recovery with carbon sequestration. The findings provide a practical strategy for improving heavy oil recovery in low-permeability reservoirs while concurrently exploring the benefits of CO₂ storage. Full article

China possesses abundant tight conglomerate oil resources. However, these reservoirs are typically characterized by low porosity and permeability, high clay mineral content, and complex pore structures, resulting in poor performance of conventional waterflooding development. Challenges including insufficient energy replenishment and high flow resistance ultimately lead to low oil recovery factors. This study systematically investigates surfactant-assisted CO₂ huff-n-puff (SA-CO₂-HnP) for enhanced oil recovery in tight conglomerate reservoirs. For a tight conglomerate reservoir in a Xinjiang block, a fully implicit, multiphase, multicomponent dual-porosity numerical model was established. By integrating pore–throat distributions acquired through high-pressure mercury intrusion with a self-developed MATLAB PVT package, nanoconfinement-induced shifts in the phase envelope were rigorously embedded into the simulation framework. The calibrated model was subsequently employed to conduct a comprehensive sensitivity analysis, quantitatively delineating the influence of petrophysical, completion, and operational variables on production performance. Simulation results demonstrate that compared to conventional CO₂ huff-n-puff, the addition of surfactants increases the cumulative recovery factor by 3.5 percentage points over a 20-year production period. The enhancement mechanisms primarily include reducing CO₂–oil interfacial tension (IFT) and minimum miscibility pressure (MMP), improving reservoir wettability, and promoting CO₂ dissolution and diffusion in crude oil. Sensitivity analysis reveals that injection duration, injection pressure, and injection rate significantly influence recovery efficiency, while soaking time exhibits relatively limited impact. Moreover, an optimal surfactant concentration (0.0003 mole fraction) exists; excessive concentrations lead to diminished enhancement effects due to competitive adsorption and pore blockage. This study demonstrates that SA-CO₂-HnP technology offers favorable economic viability and operational feasibility, providing theoretical foundation and parameter optimization guidance for efficient tight conglomerate oil reservoir development. Full article

In response to the development challenges caused by the high initial water saturation, low porosity, low permeability, and strong heterogeneity in C tight sandstone reservoirs, a comprehensive study was conducted on the optimization of development methods using a fuzzy model, core flooding experiments, and reservoir numerical simulations. The initial evaluation indicates the good adaptability of CO₂ flooding for improving oil recovery in a C reservoir; the experimental result of the CO₂ displacement method also performs the best, with a recovery rate of 68.38% at a connate water saturation of about 30%, compared with surfactant flooding and water flooding. However, higher water saturation inhibits the CO₂ development effect. The oil recovery factor of pure CO₂ huff-n-puff is 32.24% lower than the CO₂ displacement method, while surfactant-assisted CO₂ huff-n-puff can increase the recovery rate by 0.85% compared to pure CO₂. Based on actual geological models, numerical simulations were conducted on Well Block A and B. The results showed that the optimized production pressure is above the Minimum Miscibility Pressure (16.44 MPa); with consideration of the fracture pressure limitation, the CO₂ injection rate in Block A should be less than 3000 m³/d, and the recovery rate after 10 years is only 0.48% (oil change ratio is 0.07 t/t), while the CO₂ displacement rate of Block B should not exceed 7500 m³/d, and the recovery rate after 10 years can reach 27.39% (oil change ratio is 0.2 t/t). CO₂ displacement is an effective development method for a C reservoir, but due to a high water content the oil change ratio is very low, indicating a low potential for further development. The research provides important references for the development of similar oil reservoirs. Full article

During the process of oil extraction, the urgent need for unconventional oil resources is driven by escalating global demand and the progressive depletion of conventional reserves. Shale oil represents a critical unconventional resource, with recovery efficiency being fundamentally constrained by the multiscale heterogeneity of shale reservoirs characterized by intricate networks of microscale fractures and nanoscale pores. To unravel pore structure impacts on microscopic transport phenomena, this study employed microfluidic chips replicating authentic shale pore architectures with pore depths as small as 200 nm to conduct immiscible flooding, constant volume depletion, and huff-n-puff experiments under representative reservoir conditions, with experiments reaching a maximum pressure of 40 MPa. The results show that large-pore and fine-throat structures create dual flow restrictions: the abrupt change in pore throat size amplifies the local flow resistance relative to the homogeneous structure, leading to a 78.09% decline in displacement velocity, while Jamin effect-induced capillary resistance reduces recovery efficiency, and even prevents some crude oil in the pore from being driven out. Slug flow occurred in the experiment, with calculated capillary numbers (Ca) of 0.0015 and 0.0026. This slug flow impedes microscopic transport efficiency, and lower Ca values yield more distinct liquid slugs. CO₂ exhibited effective extraction capabilities for light crude oil components, enriching residual heavy components that impeded subsequent extraction. When contact time was tripled under experimental conditions, this ultimately led to a 25.6% reduction in recovery rate. This investigation offers valuable insights into microscopic transport mechanisms within shale oil systems and provides practical guidance for optimizing shale reservoir development strategies. Full article

With increasing energy demands and depleting oil accessibility in reservoirs, the investigation of more effective enhanced oil recovery (EOR) methods for deep and tight reservoirs is imminent. This study investigates a novel hybrid EOR method, a synergistic approach of nonionic surfactant flooding with intermediate CO₂-based oil swelling. This study is focused on the efficiency of surfactant flooding and low-pressure oil swelling in oil recovery. We conducted a fluorescence-based microscopic analysis in a microchannel to explore the effect of sodium dodecyl sulfate (SDS) surfactant on CO₂ diffusion in Texas crude oil. Based on the change in emission intensity of oil, the results revealed that SDS enhanced CO₂ diffusion at low pressure in oil, primarily due to SDS aggregation and reduced interfacial tension at the CO₂ gas–oil interface. To validate the feasibility of our proposed EOR method, we adopted a ‘reservoir-on-a-chip’ approach, incorporating flooding tests in a polymethylmethacrylate (PMMA)-based micromodel. We estimated the cumulative oil recovery by comparing the results of two-stage surfactant flooding with intermediate CO₂ swelling at different pressures. This novel hybrid approach test consisted of a three-stage sequence: an initial flooding stage, followed by intermediate CO₂ swelling, and a second flooding stage. The results revealed an increase in cumulative oil recovery by nearly 10% upon a 2% (w/v) solution of SDS and water flooding compared to just water flooding. The results showed the visual phenomenon of oil imbibition during the surfactant flooding process. This innovative approach holds immense potential for future EOR processes, characterized by its unique combination of surfactant flooding and CO₂ swelling, yielding higher oil recovery. Full article

CO₂ huff-n-puff is regarded as an effective method to improve the recovery of low permeability and tight oil reservoirs. To understand the impact of CO₂ huff-n-puff on crude oil mobilization in tight reservoirs with different fracture scales, this study conducted CO₂ huff-n-puff nuclear magnetic resonance (NMR) and microscopic visualization experiments, focusing on how varying fracture apertures and densities affect the efficiency of the CO₂ huff-n-puff. The results show that in scenarios with a single fracture, larger fracture apertures significantly boost oil mobilization within the fracture and the surrounding matrix. For instance, increasing the aperture from 20 μm to 70 μm improved the recovery factor by 9.20%. In environments with multiple fractures, greater fracture density enhances reservoir connectivity, and increases the CO₂ sweep area, and the complex fracture model shows a 4.26% increase in matrix utilization compared to the simple fracture model. Notably, the improvement in recovery due to multi-scale fractures is most significant during the first two huff-and-puff cycles, with diminishing returns in subsequent cycles. Overall, increasing both fracture size and density effectively enhances crude oil mobilization in tight reservoirs. These findings provide valuable insights into improving the recovery efficiency of CO₂ huff-and-puff techniques in tight oil reservoirs. Full article

CO₂-Huff-n-Puff (CO₂-HnP) is an effective method for improving oil recovery in conventional reservoirs and has been widely applied to tight oil reservoirs. Recently, there has been a series of studies published on the oil increase mechanism and huff-n-puff parameter optimization of CO₂-HnP. However, the understanding of the influence of fracture characterization, threshold pressure gradient (TPG), and geomechanical effects on CO₂-HnP in fractured tight oil reservoirs is still limited. In this paper, a numerical model based on the embedded discrete fracture model (EDFM) was constructed to investigate the impact of TPG and geomechanical effects on cumulative oil production (COP). The effects of various huff-n-puff parameters, including bottomhole pressure, oil recovery rate, total CO₂ injection amount, number of huff-n-puff cycles, timing of production transfer injection, production time, injection time, CO₂ injection rate, and soaking time on the COP and oil replacement ratio were also explored in the paper. The results include the following: (1) The TPG and geomechanical effects led to significantly reduced COP. (2) A positive correlation with COP was found for parameters such as timing of production transfer injection and production time, while negative correlations were found for cycles, soaking time, and injection rate. For oil replacement ratio, soaking time and injection rate were positively correlated, while CO₂ injection amount and number of cycles showed negative correlation. (3) With a constant injection volume, it is crucial to avoid an excessive number of cycles that reduce COP. On the basis of this parameter optimization, the oil replacement ratio can be enhanced by advancing the production transfer injection, shortening the injection time, and extending the soaking time. The findings can help optimize CO₂-HnP strategies to improve oil recovery and economic benefits from the reservoir. This paper provides an effective numerical simulation method for CO₂-HnP in fractured tight oil reservoirs, which has certain reference value. Full article

The occurrence and mobility of shale oil are critical issues in exploration and development. Shale reservoirs exhibit a complex fluid state, with oil and water present in various forms. The presence of organic matter and clay minerals within the reservoir framework further complicates the fluid’s occurrence and mobility. Utilizing two-dimensional nuclear magnetic resonance (NMR) experiments, in this study, core samples from the Shengli Oilfield’s shale oil reservoirs were analyzed. We conducted pyrolysis-NMR and CO₂ huff-n-puff-NMR joint measurement experiments to assess the shale oil mobility. The results indicated that CO₂ huff-n-puff was the most effective in the initial cycle, with diminishing returns in subsequent cycles, and NMR signal changes were predominantly observed in the movable oil fraction. The selected samples showed an average recovery rate of 26.9%, suggesting good mobility of shale oil in the study area. Based on the experimental results, a fluid component identification template for the study region was established, which mainly consists of the following five parts: movable oil, adsorbed oil, asphaltene, clay-bound water, structural water, and kerogen. This research provides valuable insights for the efficient development of shale oil reservoirs. Full article

CO₂ injection in shale reservoirs is more suitable than the conventional recovering methods due to its easier injectivity and higher sweep efficiency. In this work, Grand Canonical Monte Carlo (GCMC) simulation is employed to investigate the adsorption/desorption behavior of CH₄-C₄H₁₀ and CH₄-C₄H₁₀-CO₂ mixtures in organic and inorganic nanopores during pressure drawdown and CO₂ huff and puff processes. The huff and puff process involves injecting CO₂ into the micro- and mesopores, where the system pressure is increased during the huffing process and decreased during the puffing process. The fundamental mechanism of shale gas recovery using the CO₂ injection method is thereby revealed from the nanopore-scale perspective. During primary gas production, CH₄ is more likely to be produced as the reservoir pressure drops. On the contrary, C₄H₁₀ tends to be trapped in these organic nanopores and is hard to extract, especially from micropores and inorganic pores. During the CO₂ huffing period, the adsorbed CH₄ and C₄H₁₀ are recovered efficiently from the inorganic mesopores. On the contrary, the adsorbed C₄H₁₀ is slightly extracted from the inorganic micropores during the CO₂ puffing period. During the CO₂ puff process, the adsorbed CH₄ desorbs from the pore surface and is thus heavily recovered, while the adsorbed C₄H₁₀ cannot be readily produced. During CO₂ huff and puff, the recovery efficiency of CH₄ is higher in the organic pores than that in the inorganic pores. More importantly, the recovery efficiency of C₄H₁₀ reaches the highest levels in both the inorganic and organic pores during the CO₂ huff and puff process, suggesting that the CO₂ huff and puff method is more advanced for heavier hydrocarbon recovery compared to the pressure drawdown method. In addition to CO₂ storage, CO₂ sequestration in the adsorbed state is safer than that in the free state. In our work, it was found that the high content of organic matter, high pressure, and small pores are beneficial factors for CO₂ sequestration transforming into adsorbed state storage. Full article