Search Results (10)

The oil content in a produced fluid plays a crucial role in oil production engineering. In this paper, a predictive model for the oil and water proportions in produced fluid was established through nuclear magnetic resonance coupling displacement. This model successfully predicts the oil proportion in the produced fluid from each block within the Gaotaizi oil reservoir of the Songliao Basin and elucidates the reasons for its variation across different blocks. The production of pure oil in a vertical well area was attributed to the reservoir fluid exhibiting high bound water saturation, resulting in oil being the primary movable phase. In the testing and extended areas, variations in oil saturation combined with the pore size distribution governing oil and water occupancy are likely responsible for the differing oil-water ratios observed in the produced fluid. Specifically, a higher oil-to-water ratio (7:3) was produced in the testing area, while the extended area yielded a lower oil-to-water ratio (3:7). Furthermore, the model predicts an oil-to-water ratio of 4:6 for the produced fluid in the Fangxing area. To enhance oil production in the extended area, narrowing the fracture interval is proposed. However, this measure may not prove effective in other blocks. Full article

This study explored the effectiveness of gas injection for enhanced oil recovery (EOR) in fractured basement complex reservoirs, combining laboratory experiments with numerical simulation analyses. The experiments simulated typical field conditions, focusing on understanding the interaction between the injected gas and the reservoir’s fracture–matrix system. The laboratory results showed that under the current reservoir pressure and temperature conditions, nitrogen gas flooding in the fractured matrix achieved a superior oil recovery efficiency compared to that of the other gases tested (CO₂, APG, and oxygen-reduced air), exhibiting the most favorable movable oil saturation range and the lowest residual oil saturation. To evaluate the performance of nitrogen gas injection in a fractured basement complex reservoir, a 3D reservoir model with complex natural fractures was built in a numerical reservoir simulator. Special methods were required for the geological modeling and reservoir simulation, with the specific principles outlined. Numerical simulations of gas injection into fractured basement complex reservoirs revealed that cyclic gas injection was identified as the most effective strategy, balancing incremental oil recovery with minimized gas channeling risks. This study demonstrated that the optimal injection location and rate are crucial factors affecting the recovery performance. These findings provided actionable insights for implementing gas injection EOR strategies in fractured basement complex reservoirs, highlighting the importance of optimizing the injection parameters to maximize the recovery. Full article

The Qing-1 layer of the Gulong Depression in the northern Songliao Basin is a liquid-rich shale oil reservoir that has the characteristics of nanopores, high maturity, high gas/oil ratio (GOR), etc. The production performance of wells in the Gulong shale oil reservoir shows the characteristics of “single gas production followed by oil-gas production”. It is difficult to analyze the initial occurrence state and movability of fluid in the shale nanopores using conventional methods. In this study, a comprehensive method, including phase behavior analysis, physical experiments, and molecular simulation, was established to analyze the initial occurrence state and movability of fluid in the Gulong shale oil reservoir. The phase state of the fluid was calculated by the equation of state (EOS), considering nano-confinement effects, and the initial occurrence state was quantitatively evaluated by combining two-dimensional nuclear magnetic resonance (NMR) and molecular dynamics simulation. The movable fluid saturation was quantitatively determined by centrifugal experiments. The results show that the condensate gas state was in small pores, while the volatile oil state was in large pores. The occurrence states of oil were mainly adsorbed oil and free oil. The proportion of adsorbed oil in inorganic pores was about 24.4%, while the proportion of absorbed oil in organic pores was about 57.8%. Based on the cutoff value of T₂ before and after the centrifuged laboratory experiments, the movable limit of oil was determined to be 4.5 nm, and the movable fluid saturation was about 11%. The research method proposed in this study has important guiding significance for the initial occurrence state and movability evaluation of similar liquid-rich shale reservoirs. Full article

The Chang 7 member of the Triassic Yanchang Formation in the Ordos Basin is a significant continent shale oil reservoir in China. Therefore, conducting an in-depth investigation into the pore structure and fluid mobility characteristics of the Chang 7 shale oil reservoir holds immense importance for advancing shale oil exploration. This study conducts a detailed analysis of the pore structures and their impact on fluid mobility of the Chang 7 shale oil reservoir using multiple methodologies, i.e., a cast thin section, scanning electron microscopy (SEM), X-ray diffraction (XRD), high-pressure mercury injection (HPMI), low-temperature nitrogen adsorption (LTNA), and nuclear magnetic resonance (NMR). The results show that the sandstone in the Yanwumao area of the Chang 7 shale oil reservoir consists mainly of lithic arkose and feldspathic litharenite, which can be classified into three lithofacies (massive fine-grained sandstone (Sfm), silt-fine sandstone with graded bedding (Sfgb), and silt-fine sandstone with parallel bedding (Sfp)). Moreover, three pore structures (Type I, II, and III), and four pore spaces (nanopores, micropores, mesopores, and macropores) can be characterized. Pore structure Type I, characterized by large pores, exhibits bimodal pore diameter curves, resulting in the highest levels of movable fluid saturation (MFS) and movable fluid porosity (MFP). Pore structure Type II demonstrates unimodal pore structures, indicating robust connectivity, and higher MFS and MFP. Pore structure Type III primarily consists of dissolved and intercrystalline pores with smaller pore radii, a weaker pore configuration relationship, and the least fluid mobility. Furthermore, a correlation analysis suggests that the pore structure significantly impacts the fluid flowability in the reservoir. Favorable petrophysical properties and large pores enhance fluid flowability. Micropores and mesopores with high fractal dimensions have a greater impact on reservoir fluid mobility compared to macropores and nanopores. Mesopores mainly control MFS and MFP, while micropores govern the shift from bound fluid to movable fluid states. Among the lithofacies types, the Sfm lithofacies exhibit the highest fluid mobility due to their significant proportion of macropores and mesopores, whereas the Sfgb lithofacies have lower values because they contain an abundance of micropores. The Sfp lithofacies also dominate macropores and mesopores, resulting in medium fluid mobility levels. This study combines lithofacies types, micro-reservoir pore structure characteristics, and mobile fluid occurrence characteristics to better understand the dominant reservoir distribution characteristics of the Chang 7 shale oil reservoirs in the Ordos Basin and provide theoretical information for further optimization of production strategies. Full article

Shale oil yield, movability, and reservoir brittleness are three factors that must be focused on for shale oil exploration and development. The yield and composition of hydrocarbons and mineral composition have changed significantly during diagenesis, affecting the yield and movability of shale oil and the brittleness of the rock. In this study, the source rocks at different depths in the Dongying Sag were subjected to hydrous pyrolysis, and the yield and composition of pyrolyzed hydrocarbons and mineral composition were systematically analyzed. The brittleness index (BEI), weighted average specific surface area (SSA_WA), and polarity index (PI) have been established to quantitatively characterize the brittleness and adsorption capacity of rock as well as the mobility of shale oil. The results suggest that diagenetic evolution controls rocks’ brittleness and adsorption capacity by changing their mineral composition. In the low-temperature stage, the mineral transformation is not obvious, and the BEI and SSA_WA fluctuate in a small range. In the high-temperature stage, the rapid smectite illitization leads to an increase in the brittleness and a decrease in the adsorption capacity. In addition, the nonpolar components such as saturates and aromatics in the pyrolyzed hydrocarbons gradually increased with the increasing temperature, enhancing the mobility of the shale oil. Based on the three evaluation indexes of BEI, PI, and SSA_WA, and combined with the changes in hydrocarbon yields during hydrous pyrolysis, we comparatively analyzed the differences in the mobility and yields of original soluble organic matter as well as pyrolyzed hydrocarbons of the source rocks at different depths. Based on the above results, it can be concluded that the shale in the depth range of 3300–3795 m is a favorable area for shale oil exploration and development in the study area. This work suggests that predicting the sweet spot for shale oil exploration and development requires more attention to the impact of diagenetic evolution on the composition of minerals and hydrocarbons. Full article

The lacustrine shale in the second member of the Kongdian Formation (Ek2) is the most significant target of shale oil exploration in the Cangdong Sag, Bohai Bay Basin, China. To investigate the occurrence mechanisms and to reveal the influencing factors of shale oil mobility in Ek2, a series of analyses (X-ray diffraction (XRD), field emission scanning electron microscopy (FE-SEM), total organic carbon (TOC) analysis, Rock-Eval pyrolysis, low-temperature nitrogen physisorption (LNP), mercury intrusion porosimetry (MIP), and multiple isothermal stage (MIS) pyrolysis) were conducted on samples collected from well cores in the Cangdong Sag. The results show that the lithofacies can be categorized as laminated felsic shales, laminated and massive mixed shales, and laminated and massive carbonate shales. The shales were characterized by a high organic matter abundance and moderate thermal evolution with good to excellent hydrocarbon generation potential and contained a high abundance of Type I and II1 kerogens. Laminated felsic shales and laminated mixed shales, compared with other lithofacies, had clear advantages in the amount of free hydrocarbon that can be volatilized from the rock (S1), the oil saturation index (OSI) value, and the free oil and movable oil content. LNP, MIP, and MIS pyrolysis analyses show that the residual shale oil mainly occurred in pores with diameters smaller than 200 nm, and the pore diameter when residual oil occurred in some laminated shale samples could reach 50 μm. The lower limits of the pore diameter where free oil and movable oil occurred were 7 and 30 nm, respectively. The mobility of shale oil is controlled by the shale oil component, thermal maturity, TOC content, and pore volume. The results herein provide a basis for the evaluation of optimal shale oil intervals. Full article

Many factors need to be considered in the evaluation of tight conglomerate reservoirs, including the microscopic pore-throat structure, pore connectivity, lithology, porosity, permeability, and clay mineral content. The contents and types of clay minerals reflect the mineral evolution process during the deposition of the reservoir and can reflect the reservoir’s physical properties to a certain extent. In this study, cores from the Baikouquan Formation in Mahu were used to comprehensively analyze the effects of the clay mineral content on the physical properties of a tight conglomerate reservoir, including field emission scanning electron microscopy (FE-SEM), casting thin section observations, X-ray diffraction (XRD), interface property testing, high-pressure mercury injection, low temperature N₂ adsorption, and nuclear magnetic resonance (NMR)-movable fluid saturation testing. The results revealed that differences in different lithologies lead to differences in clay mineral content and pore structure, which in turn lead to differences in porosity and permeability. The interface electrification, adsorption, and specific surface area of the reservoir are positively correlated with the clay mineral content, which is mainly affected by the smectite content. As the clay mineral content increases, the proportion of nanoscale pore throats increases, and the core becomes denser. The saturation of the movable fluid controlled by the >50 nm pore throats in the tight conglomerate ranges from 8.7% to 33.72%, with an average of 20.24%. The clay mineral content, especially the I/S (mixed layer of Illite and montmorillonite) content, is negatively correlated with the movable fluid. In general, the research results clarified the relationship between the lithology and physical properties of clay minerals and the microscopic pore structure of the tight conglomerate reservoirs in the Baikouquan Formation in the Mahu area. Full article

Nanoscale pore-throat systems are widely developed in the pore-throat of tight reservoirs. The pore-throat structures of different microscales are complex and diverse with obvious microscale effects. Taking the Chang 6₃ tight sandstone reservoir of the Huaqing area in Ordos basin as an example, under the guidance of information entropy theory, the quantitative characterization model of pore-throat micro-scale heterogeneity in a tight oil reservoir is established based on casting thin sections, physical properties analysis, constant velocity mercury injection, and NMR technology. Moreover, the correlation between pore-throat heterogeneity and porosity, permeability and movable fluid saturation is analyzed. The results show that there are obvious differences in pore-throat heterogeneity between different reservoirs, and the throat uniformity of macro pore-fine-throat reservoir, macro pore–micro throat reservoir, and macro pore–micro throat reservoir becomes worse, successively. There is a negative correlation between porosity uniformity and porosity, permeability and movable fluid saturation. However, there is a positive correlation between throat uniformity and combined pore throat uniformity and porosity, permeability and movable fluid saturation. Therefore, the uniformity of the throat controls the seepage capacity and fluid mobility in the pore system of the Chang 6₃ tight sandstone reservoir in the study area. This has important theoretical and practical significance to enhance oil recovery and promote the efficient development of a tight oil and gas reservoir. Full article

Some inter-salt shale reservoirs have high oil saturations but the soluble salts in their complex lithology pose considerable challenges to their production. Low-field nuclear magnetic resonance (NMR) has been widely used in evaluating physical properties, fluid characteristics, and fluid saturation of conventional oil and gas reservoirs as well as common shale reservoirs. However, the fluid distribution analysis and fluid saturation calculations in inter-salt shale based on NMR results have not been investigated because of existing technical difficulties. Herein, to explore the fluid distribution patterns and movable oil saturation of the inter-salt shale, a specific experimental scheme was designed which is based on the joint adaptation of multi-state saturation, multi-temperature heating, and NMR measurements. This novel approach was applied to the inter-salt shale core samples from the Qianjiang Sag of the Jianghan Basin in China. The experiments were conducted using two sets of inter-salt shale samples, namely cylindrical and powder samples. Additionally, by comparing the one-dimensional (1D) and two-dimensional (2D) NMR results of these samples in oil-saturated and octamethylcyclotetrasiloxane-saturated states, the distributions of free movable oil and water were obtained. Meanwhile, the distributions of the free residual oil, adsorbed oil, and kerogen in the samples were obtained by comparing the 2D NMR T₁-T₂ maps of the original samples with the sample heated to five different temperatures of 80, 200, 350, 450, and 600 °C. This research puts forward a 2D NMR identification graph for fluid components in the inter-salt shale reservoirs. Our experimental scheme effectively solves the problems of fluid composition distribution and movable oil saturation calculation in the study area, which is of notable importance for subsequent exploration and production practices. Full article

Given the difficulty in developing waterflooding in tight oil reservoirs, using waterflooding huff-n-puff is an effective method to improve oil recovery. Online nuclear magnetic resonance (NMR) can detect the change in internal oil and water during the core displacement process, and magnetic resonance imaging (MRI) in real time. To improve the tight oil reservoir development effectiveness, cores with different permeability were selected for a waterflooding huff-n-puff experiment. Combined with online NMR equipment, the fluid saturation, recovery rate, and residual oil distribution were studied. The experiments showed that, for tight oil cores, more than 80% of the pores were sub-micro- and micro-nanopores. More than 77.8% of crude oil existed in the sub-micro- and micropores, and movable fluids mainly existed in the micropores with a radius larger than 1 μm. The NMR data and the MRI images both demonstrated that the recovery ratio of waterflooding after waterflooding huff-n-puff was higher than that of conventional waterflooding, and, therefore, residual oil was lower. Choosing two cycles’ of waterflooding, huff-n-puff was more suitable for tight oil reservoir development. The production of crude oil increased by 22.2% in the field pilot test, which preliminarily proved that waterflooding huff-n-puff was suitable for tight oil reservoirs. Full article