Residual Saturation Research Articles

Investigating the effects of make-up water dilution and oil presence on polymer retention in carbonate reservoirs.

The application of polymer flooding is challenging in harsh temperature and salinity conditions in Middle-Eastern carbonate reservoirs, as they can deteriorate the commonly used polymers such as Hydrolyzed Polyacrylamide (HPAM). One solution to this issue is the use of newly developed Acrylamido-Tertiary-Butyl Sulfonate (ATBS) based polymers, which can endure adverse temperature and salinity conditions. However, they also tend to adsorb onto carbonate rocks with positive surface charge. This study aims to tackle the problem of high polymer retention by employing low-salinity polymer flooding. For that coreflooding experiments were conducted on an ATBS-based polymer in salinities ranging from 400 to 167,000 ppm using fully water-saturated cores and cores at residual oil saturation (Sor). The single-phase retention experiments determined polymer retention values of around 25µg/g-rock when using diluted brines, which is about half of the retention values (47-56µg/g-rock) observed with high salinity seawater (43,000 ppm) and formation water (167,000 ppm). Furthermore, the retention of the ATBS-based polymer was further reduced by 50% in the presence of oil compared to the experiments conducted in the absence of oil. The results demonstrated that an optimal salinity threshold of 10,000 ppm and lower yields significant improvements in the efficiency of polymer flooding.

Research on CO2 sequestration in saline aquifers with different relative permeability considering CO2 phase conditions

Saline aquifers are the most feasible potential site for the storage of CO2. The behavior of CO2 in different phase states may significantly affect the flow properties and sequestration efficiency. It is important to understand and predict the effects of different CO2 phases. This study conducted relative permeability tests under two experimental conditions with CO2 in different phases. Incorporating experimental data into reservoir-scale simulations to analyze the effects of different phases of CO2 on structural, solubility, and residual sequestration mechanisms, and to predict CO2 behavior in saline aquifers. The results show that the CO2 relative permeability and residual CO2 saturation are high under supercritical conditions. It is more favorable to consider the relative permeability and hysteresis effects on the supercritical CO2 results, with a more dispersed distribution of CO2 at the bottom of the reservoir. There was a significant difference in residual sequestration, with the gaseous group showing a 14.16 % reduction in residual sequestration and a 4.27 % reduction in total sequestration compared to the supercritical group. The ratio of structural sequestration, solubility sequestration, and residual sequestration in the total sequestration in this study is about 50 %:30 %:20 %.

Multiscale simulation of water/oil displacement with dissolved CO[formula omitted]: Implications for geological carbon storage and CO[formula omitted]-enhanced oil recovery

This study combines molecular and pore-scale simulations to enhance our understanding of water, carbon dioxide (CO2), and oil flow in a porous system for high-efficiency geological carbon storage and enhanced oil recovery. We use molecular dynamics simulations to study the variation of interfacial tension (IFT), viscosity, and contact angle across varying system CO2 concentrations. The study reveals that the IFT simulation accuracy in the three-component mixture system relates positively to the volume-to-interfacial area ratio, and IFT decreases with CO2 concentration. Oil–CO2 mixture viscosity decreases and shows an intersection with water viscosity as CO2 concentration increases. The contact angle on the hydrophobic surface of kaolinite first increases and then decreases with CO2 concentration, while the hydrophilic surface contact angle is not sensitive to the CO2 concentration. Visualizing CO2 density distribution reveals its accumulation at fluid-fluid and fluid-solid interfaces and the combined effect results in the highest CO2 density at contact-line regions. Meanwhile, the elevated CO2 density at fluid-fluid interfaces reduces IFT, contributing to the initial contact angle increase, while the CO2 density increase at fluids-solid surface explains the subsequent contact angle decrease. These findings are then upscaled into a core-scale system using lattice Boltzmann simulations. The results are summarized into a phase diagram, which reveals the non-monotonic variations of the initial-residual (I-R) curves across different CO2 concentrations, and the residual saturation overall decreases with CO2 concentration for high initial saturations. These findings underscore the critical roles of system CO2 concentration and rock components, particularly kaolinite clay minerals, in subsurface multiphase seepage confronted in geological carbon storage and CO2-enhanced oil recovery, highlighting the importance of digital rock physical chemistry.

Zeta Potential of Supercritical CO2‐Water‐Sandstone Systems and Its Correlation With Wettability and Residual Subsurface Trapping of CO2

AbstractAlthough CO2 geological storage (CGS) is thought to be one of the most promising technologies to sequester the anthropogenic CO2 to mitigate the climate change, implementation of the method is still challenging due to lack of fundamental understanding of controls of wettability, which is responsible for residual trapping of the gas and its flow dynamics. One of the key parameters that controls the wetting state is the zeta potential, ζ, at rock‐water and CO2‐water interfaces. ζ in systems comprising rocks, carbonated aqueous solutions and immiscible supercritical CO2 have not been measured prior to this study, where we detail the experimental protocol that enables measuring ζ in such systems, and report novel experimental data on the multi‐phase ζ. We also demonstrate for the first time that ζ of supercritical CO2‐water interface is negative with a magnitude greater that 14 mV. Moreover, our experimental results suggest that presence of multi‐valent cations in tested solutions causes a shift of wettability toward intermediate‐wet state. We introduce a new parameter that combines multi‐phase ζ and relative permeability endpoints to characterize the wetting state and residual supercritical CO2 saturation. Based on these results, we demonstrate that ζ measurements could serve as a powerful experimental method for predicting CGS efficiency and/or for designing injection of aqueous solutions with bespoke composition prior to implementing CGS to improve the residual CO2 trapping in sandstone formations.

Study on interfacial tension, wettability and viscosity in different salinities of synthesized a new polymeric surfactant for improving oil recovery

Over 50% of the original oil in place (OOIP) is immobile or trapped in the reservoir. Therefore, today, more efficient methods have been introduced in the tertiary oil recovery sector as a scheme of enhanced oil recovery (EOR). Due to the decline of conventional hydrocarbon reserves, polymers are increasingly used in EOR methods, such as surfactant-polymer (SP) and alkaline-surfactant-polymer (ASP) flooding. SP flooding has a complex formulation and design, leading to undesirable phase separation if improperly mixed. Polymeric surfactants are a promising alternative to SP flooding. They consist of hydrophobic groups attached to hydrophilic polymers, which help to improve the mobility ratio and reduce interfacial tension (IFT). This paper examines the rheological and synthesis properties of a new polymeric surfactant produced through bond co-polymerization reaction using different hydrolyzed polyacrylamide (HPAM) ratios and a zwitterion hydrophobic group. The synthesized hydrophobically modified zwitterionic polyacrylamide (HMZPAM) was characterized by FTIR and HMNR analysis. HMZPAM performed better than other substances in IFT, viscosity, wettability, oil recovery, and resistance to different one and two-valence cations. The results indicate that HPAM reduced the IFT to 13.65, while HMZPAM reduced it to 0.441 mN/m. Wettability change evaluated on a rock carbonate/crude oil/HMZPAM system that changed the water-wet state of the primary oil-wet rock carbonate to strongly water-wet state as wettability change measurements showed a decrease in contact angle from 62.76 to 21.23 degree. Comparative studies on the effectiveness of HPAM and HMZPAM were also conducted according to the measurement of viscosity and shear rate in the presence of salt, which indicates the higher shear rate and viscosity of HMZPAM. Core flooding tests revealed that HMZPAM resulted in better additional recovery due to microscopic displacement, resulting in a total oil recovery of 84%, compared to 48% of residual oil saturation for HPAM. Also, salts decreased oil recovery in HPAM injection but increased oil recovery in HMZPAM injection.

Enhanced Carbon/Oxygen Ratio Logging Interpretation Methods and Applications in Offshore Oilfields

As the development of most domestic and international oilfields progresses, many fields have entered a mature phase characterized by high water cut and high recovery, with water cut levels often exceeding 90%. Carbon/oxygen ratio logging has proven to be an indispensable tool for distinguishing oil layers from water layers in complex environments, especially where salinity is low, unknown, or highly variable. This logging method has become one of the most effective techniques for determining residual oil saturation in cased wells, providing critical insights into the oil–water interface. In this study, we evaluate two key interpretation models for carbon/oxygen ratio logging: the fan chart method and the ratio chart method. We optimize the interpretation parameters in the ratio chart model using an improved genetic algorithm, which significantly enhances interpretation precision. The optimized parameters enable a more seamless integration of logging results with reservoir and conventional logging data, reducing the influence of lithological variations and physical property differences on the measurements. This research establishes a robust theoretical foundation for enhancing the interpretation accuracy of carbon/oxygen ratio logging, which is crucial for effectively identifying water-flooded layers. These advancements provide vital technical support for monitoring oil–water dynamics, optimizing reservoir management, and improving production efficiency in oilfield development.

Characterization and Inversion Method of Relative Permeability of Emulsion Flooding.

Relative permeability curves are one of the crucial factors that control the behavior of multiphase flow in petroleum reservoirs. Accurate prediction of the relative permeability curve involving emulsification and emulsion transport in emulsion flooding is vital to enhancing heavy oil recovery. In this study, a relative permeability characterization model including the emulsification mechanism and emulsion transport is developed, in which residual oil saturation and end-point permeability for water are parametrized as functions of emulsion concentration and capillary number. Based on the built characterization model, an inversion method (ensemble Kalman filter) is used to estimate the relative permeability curves of emulsion flooding. The inversion results of four sets of emulsion flooding experiments show that the errors of end points between the Johnson-Bossler-Neumann method and inversion method are less than 10%. For the continuous emulsification process in the in situ emulsion flooding tests, the inversed relative permeability curves shift between the upper and the inferior limits of the permeability. The error of residual oil saturation between the inversion and the experiment is less than 10%. In summary, this study demonstrates the feasibility of using the characterization model and inversion method to infer the relative permeability curves of emulsion flooding, which can aid in the predictions of multiphase flow in heavy oil reservoirs.

Low-field MRI study of the 1H distribution and migration in porous sediments during natural gas conversion from methane hydrate

Gas hydrates, crystalline compounds formed from water and guest molecules like methane, are gaining attention as a promising clean energy source. While research has extensively focused on the extraction and transport of natural gas hydrates from offshore marine sediments, the dynamic processes in the porous sediments remain under explored. This study employs low-field Magnetic Resonance Imaging (MRI) to investigate the in-situ formation and dissociation of methane hydrate within a partially saturated stack of glass beads. By integrating advanced MRI techniques, including 1D dhk SPRITE, bulk T1 distribution, and 2D spatial T2 imaging, this research provides a comprehensive analysis of fluid distribution and migration during phase transitions in the porous sediments. Three key findings emerged from the study. First, SE-SPI measurements successfully quantified hydrate and residual water saturation, aligning with previous X-ray CT and high-field MRI studies and validating low-field MRI for hydrate research. Secondly, this study introduced a volumetric approach to T1 and T2 measurements, distinguishing between free and bound water, with characteristic relaxation times for each, confirming the technique's capability to differentiate types of residual water. Finally, spatially resolved T2 relaxation time distributions revealed vertical fluid migration within the pore spaces, identifying an equilibrium zone where inflow and outflow rates were balanced. Overall, this study underscores the effectiveness of low-field MRI as a noninvasive tool for analyzing hydrate-bearing sediments. The findings lay the groundwork for further exploration of hydrate in porous sediments, enhancing our understanding of gas production dynamics in hydrate-rich environments.

Methodological approaches to assessing the invasion of process fluids into the core pore space

Background. The reliability of the lithological and petrophysical studies is largely determined by the quality of the core material. The invasion of drilling mud filtrate into the core will primarily affect the measurements of the fluid type, residual oil and water saturation, porosity, permeability, geochemical properties and wettability of the rock. Evaluating the suitability of the core material for laboratory studies is one of the main tasks in the study of low-invasion core. Objective. To determine the most informative methods of penetration of process fluids into the pore space of the rock to assess the suitability of the core for laboratory studies. Materials and methods. The paper uses the methods of lithological and petrophysical research of core and reservoir fluids. Results. The application of the used research methods is analyzed. The advantages and limitations of each of the presented methods are determined. Conclusions. The assessment of the degree of mud filtrate invasion into the core determines the suitability of the core material for further petrophysical research.

Compositional simulation of coupled transport mechanisms in fractured-vuggy underground gas storage: A case study of LWC in the Sichuan Basin

Compositional models were built to simulate the underground gas storage (UGS) operation, which is characterized by multiple cycles of rapid injection and production. Based on the validated model of the fractured-vuggy underground gas storage Lao Weng-Chang (LWC), this study evaluated the individual and coupling effects of stress sensitivity, relative permeability hysteresis, and high-speed non-Darcy flow on UGS operation. It was found that stress sensitivity is the main controlling factor behind the reduced working gas volume, and it led to a 6.07% decline in working gas volume. Relative permeability hysteresis is the determining factor for the storage capacity, and it led to a 9.05% decline in storage capacity. The high-speed non-Darcy flow only led to a 0.16% reduction in storage capacity but led to a 4.19% decline in working gas volume. A higher stress sensitivity coefficient and increased residual gas saturation both lead to greater losses in both storage capacity and working gas volume. Coupling stress sensitivity and relative permeability hysteresis would have a more pronounced effect on working gas volume than when considered individually. Considering the high-speed non-Darcy flow further decreases working gas volume. The gas production per unit pressure drop will also decrease with the increasing Reynolds number, and there exists a critical value of Re where the decrease significantly accelerates.

Enhanced oil recovery and carbon sequestration in low-permeability reservoirs: Comparative analysis of CO2 and oil-based CO2 foam

Excessive CO2 emissions contribute to global climate change thus mandating effective methods for CO2 utilization and sequestering. In this study, one-dimensional flow simulation experiments on CO2 flooding, CO2 Huff-n-Puff, oil-based CO2 foam flooding, and oil-based CO2 foam Huff-n-Puff are conducted using low-permeability sandstone cores modeled after the Q131 block in Liaohe Oilfield, characterized by porosity ranging from 15% to 20% and permeability between 25 mD to 35 mD. Low permeability reservoirs are rich in oil resources and may effectively sequester CO2. Parameters pertaining to oil and gas production and carbon storage are collected. Nuclear magnetic resonance (NMR) is employed to determine the spatial variation of oil saturation in the cores. The experimental results show 8.03% and 41.21% increase in oil recovery factor by foam flooding and foam Huff-n-Puff relative to CO2 as the recovery agent. Moreover, NMR analysis confirms lower residual oil saturation in core samples using foam, suggesting better displacement agent. Oil-based CO2 foam recovery contributed to effective carbon sequestration, with carbon storage increasing by 34.24% and 315% relative to CO2 flooding and CO2 Huff-n-Puff, respectively. CO2 storage mechanisms for oil-based CO2 foam recovery method are detailed.

Uncovering the impact of morphology of porous media and capillary number on immiscible oil recovery using computational fluid dynamics

Pore-scale simulation and analysis of oil displacement in digital rocks has shown great promise in tracking oil recovery in porous media. This paper examines three digital rocks with varying pore and throat radii but the same porosities, studying their behavior under immiscible oil recovery through waterflooding. Computational fluid dynamics was used to conduct numerical simulations to observe the impact of rock morphology on breakthrough times, residual oil saturations, and oil displacement patterns. The validity of the simulation mechanism is confirmed in both imbibition and drainage conditions through the pore doublet Chatzis' experiment. This study consisted of 33 separate simulations which varied in mobility ratios, interfacial tensions, and injection velocities. The findings suggest that smaller pore and throat radii result in higher oil recovery and water percolation and faster breakthrough times that facilitates the effects of viscous fingering. An increase in capillary number was found to have a significant impact on oil recovery in larger pores and throats.

Three dimensional time-variation simulator for water flooding reservoir based on “effective water flux”

Long-term water flooding leads to changes in pore throat structure, resulting in alterations in macroscopic reservoir petrophysical parameters. However, commercial numerical simulation software does not have this capability. Ignoring variations in physical parameters during the formulation of development plans and numerical simulations can lead to significant prediction errors, which severely impacts oil field recovery. This paper, based on an analysis of effective flow rate and waterflood intensity, proposes a new erosion degree characterization parameter: Effective water flux, to represent the time-varying patterns of physical parameters. It is embedded into a black oil model to develop a time-variation simulator, whose accuracy and stability in both black oil and time-variation models are validated through comparison with the commercial numerical simulation software CMG. The study further explores the effects of different parameter variations on the development process. It was found that increases in permeability and oil viscosity exacerbate heterogeneity and reduce displacement efficiency, while decreases in residual oil saturation and water phase permeability under residual oil saturation enhance water flooding efficiency. In complex models, the effects of variations in different parameters intertwine, collectively influencing development outcomes. This paper advances the development of time-variation numerical simulation technology.

Non-thermal recovery of a viscous oil with a surfactant-polymer process

The goal of this work is to improve recovery of a viscous oil reservoir at 70 °C using a non-thermal process. Polymer floods can improve sweep efficiency, but leave behind a residual oil saturation. A surfactant-polymer flood has the potential to improve both the sweep as well as the displacement efficiency. Phase behavior experiments with the viscous oil, water and surfactants were conducted to identify surfactants. 1D and 2D sandpack displacements were conducted to evaluate the efficacy of the process. Phase behavior experiments showed Winsor type I behavior with a low interfacial tension using a single surfactant, but not ultralow tension. Water flood recovered about 50% OOIP and reduced the oil saturation to about 45% in 1D floods. The subsequent SP flood increased the cumulative oil recovery to 99% in sandpacks when the viscosity of chemical slugs exceeded the oil viscosity. When the permeability decreased (as in a Bentheimer core), the oil recovery decreased to about 86%. Secondary SP floods also recovered most of the oil and faster than tertiary floods. Reduction of polymer concentration (and viscosity to about 1/4th of the oil viscosity) reduced the oil recovery, especially in 2D sandpack floods. Decrease in interfacial tension increased the requirement of polymer concentration to maintain flood front stability. This flood demonstrates the effectiveness of Winsor type I SP formulation for viscous oil, high permeability reservoirs. Such a SP process would reduce the carbon footprint of viscous oil recovery compared to that of thermal processes.

Reservoir numerical simulation method considering time-varying relative permeability during polymer flooding process

Abstract In response to the abnormal decline in liquid production capacity during the middle and later stages of chemical flooding in Chinese offshore oil fields, in-depth analysis was conducted using reservoir engineering, dynamic analysis, and reservoir simulation methods. Because of the viscoelasticity of polymer solution, the relative permeability curve of oil/water during polymer flooding is different from that during water flooding, including the minimum mobile water saturation and residual oil saturation. In this study, an interpolation coefficient ‘f’ related to polymer solution concentration was firstly proposed for simplicity. Then, reservoir numerical simulation with the self-developed simulator ‘SIMFAST’ were conducted to investigate the influence of the interpolation coefficient ‘f’ on the injector and producer performance and the applications in actual field production history matching. The results indicated that compared with the commercial simulators, the self-developed simulator with the interpolation factor could more reliably describe the characteristic of the injected polymer solution in controlling water cut rise, and more efficiently simplify the combination of parameters on relative permeability curves during polymer flooding in offshore oilfields. Finally, above reservoir simulation method considering the change of the relative permeability curves during chemical flooding, was successfully conducted in the production history matching in J oilfield in Bohai Bay China, in terms of oil rate & water cut parameters. The research results give an efficient method to investigate the fluid seepage behaviour variation and its influence on oil rate and water cut during polymer flooding in China offshore reservoirs, which offers very useful technical support for the accurate design of chemical flooding schemes.

Why gravity improves waterflood recovery in oil-wet and mixed-wet reservoirs

Most past experimental and numerical research on water flooding has demonstrated a reduction in oil recovery in gravity dominated flow: gravity leads to the water slumping to the bottom of the reservoir with earlier water breakthrough and poor sweep efficiency. However, these studies were all performed on strongly water-wet systems: wherever the water has gone, the oil is at residual saturation so a reduction in sweep efficiency gives a reduction in recovery. In reality few if any reservoirs are strongly water-wet. If the rock is mixed or oil-wet, gravity improves the local displacement efficiency. Gravity reduces the mobility of injected water forcing downward water movement and better oil displacement laterally. When gravity dominates, once water reaches the bottom of the reservoir, it moves upwards in a gravity-stable displacement, with improved local displacement efficiency that can be quantified by linear Buckley-Leverett analysis. We show, using fine-grid simulations of water flooding in a two-dimensional homogeneous vertical cross-section with typical fluid and rock properties, that the overall recovery after ∼0.3 pore volumes of water injected is higher than without gravity for heavy oil-wet (unfavourable mobility) applications. This improvement is greater in light oil-wet (favourable mobility) applications and occurs even before water breakthrough counteracting the negative effect of poor sweep efficiency. Simulations on a heterogeneous reservoir model representing an oil field from the Middle East confirmed the significance of gravity on improving the displacement and overall oil recovery. The same considerations should pertain in reverse for gas storage: storage efficiency improves in gravity dominated flow.

Impact of Material Balance Calculation on Trapped Gas in Water-drive Gas Reservoir

Abstract The development of water-drive gas reservoir takes a very important position in China. Not only its recovery is markedly lower than that of dry gas reservoir, but also its residual gas saturation is higher. The main reason has been proven in the lab is water invasion which can generate trapped gas by sealing gas in porous media. However, it is still difficult to calculate the volume of trapped gas theoretically and practically. In order to quantify trapped gas, we designed experiments to simulate the development of water-drive gas reservoir. The experimental system can provide accurate measurements on gas production, water influx, pressure and so on. The results showed that the original material balance equations are not consistent with experimental data when water invasion happens. With water influx increasing, the errors become more obvious. This phenomenon has been repeated for many times in our lab. On basis of this phenomenon and with the analysis of many experimental data, we observed that water influx causes some high pressure trapped gas which is not considered in original material balance equation. By regression analysis, we proposed a correction term which can be added to the original material balance equation to effectively eliminate the disagreements between the results of original equation and the experiments. The modified material balance equation was also verified by field cases. The correction term can be applied to quantify the degree of trapped gas, which is significant to calculate the water influx and to predict production and improves the original material balance equation so that the trapped gas in water-drive gas reservoir can be fully considered. The correction term is proposed through statistical regression analysis based on a large number of experimental data. The modified material balance equation with the correction term can quantify the trapped gas and have a great significant impact on the development of water-drive gas reservoir, especially on the water influx calculation and production prediction.

Investigation of smoothed particle hydrodynamics (SPH) method for modeling of two-phase flow through porous medium: application for drainage and imbibition processes

The drainage and imbibition processes are critical mechanisms in petroleum engineering. These processes in a porous medium are controlled by surface forces and pressure gradients. The study of these processes in the pore scale by common simulators always has limitations in multiphase flow modeling. Also, obtaining relative permeability curves through laboratory analysis requires expensive equipment. Additionally, these laboratory experiments are quite expensive and may introduce significant uncertainties. For this purpose, this study investigated the creation of relative permeability curves and their effect on oil production. Initially, single-phase fluid and two-phase droplet flow within a fracture with both soft and rough surfaces were utilized to validate the formulation of the Smoothed Particle Hydrodynamics (SPH) method. Then, by using three randomly constructed porous medium models, the imbibition and drainage processes have been studied. Finally, sensitivity study has been carried out on critical parameters related to fluid flow dynamics in the porous environment, including pressure changes, wettability, and heterogeneity in drainage and imbibition processes. The simulation results were consistent with current theories; therefore, it is reasonable to consider SPH to characterize the fluid flow dynamic during the drainage and imbibition processes. According to sensitivity studies, pressure gradient (residual saturation of displaced fluid is about 5.65% and 8.44%) and heterogeneity (the residual saturation of the displaced fluid was 4.04% and 2.98%) have the largest impact on flow modeling in both drainage and imbibition processes and wettability (the residual saturation became 36.62% and 5.12%) has significant effect on the drainage process through porous medium. In general, fluid flow dynamic studies can be performed using the SPH method to model fluid flow in simple and complex porous medium under various flow conditions. The SPH method can also be used as an applicable tool to investigate the hydrocarbon fluids flow within larger geometries in the future.

Core‐flooding experiments of various concentrations of CO2/N2 mixture in different rocks: II. Effect of rock properties on residual water

AbstractDuring CO2 storage in deep saline aquifers, the presence of residual water has an important influence on the storage efficiency and safety. In this study, natural rock cores taken from deep reservoirs in the Ordos Basin and Fukang, Xinjiang are used as research objects. Nine groups of core‐flooding experiments are performed under different CO2/N2 gas mixture ratios to study the influence of rock properties (mineral composition, permeability, porosity and pore structure) on the residual water. Furthermore, the geophysical and chemical properties of rock cores are analyzed by X‐ray diffraction, electron microscopy, field emission scanning electron microscopy and piezoelectric mercury method. The results show that residual water saturation is a quantitative power function of drainage time. The residual water saturation is positively correlated with the total amount of quartz and feldspar and increases with increasing permeability. Moreover, both the average and median pore throat radius show a strong inverse correlation with irreducible residual water saturation; as these radius increase, the residual water saturation decreases. In contrast, the porosity and maximum pore throat radius display a weaker correlation with irreducible residual water saturation. This study is of great value for engineering practices such as the site selection of CO2 storage projects in saline aquifer and improvement of CO2 storage efficiency. © 2024 Society of Chemical Industry and John Wiley & Sons, Ltd.

Experimental study on microscopic production characteristics and influencing factors during dynamic imbibition of shale reservoir with online NMR and fractal theory

Dynamic imbibition and displacement between the matrix and fractures in shale reservoirs can significantly enhance oil recovery (EOR) following initial depletion. However, the microscopic production characteristics and seepage mechanisms at different pore scales during the dynamic imbibition process remain incompletely understood. In this study, we established an online physical simulation experiment method that combines dynamic displacement and imbibition based on nuclear magnetic resonance (NMR) and fractal theory, and a series of online NMR water flooding dynamic imbibition experiments were conducted. Through real-time dynamic monitoring of multiphase flow and migration behavior of crude oil in each stage of dynamic imbibition, the microscopic production characteristics and influencing factors were quantitatively studied from the recovery and residual oil saturation field distribution of different scale pores. Additionally, we developed a novel two-dimensional (2-D) NMR interpretation model to investigate the dynamic development characteristics of shale oil injection-imbibition-soaking-production integration, and the multiphase and multi-scale dynamic imbibition crude oil migration models were discussed. The results show that shale oil occurrence pores can be categorized into two types based on the corresponding production mode (imbibition + displacement). The water flooding dynamic imbibition process in shale reservoirs unfolds in three stages: strong displacement and weak imbibition stage characterized by the rapid production of large pores and fractures under displacement action; weak displacement and strong imbibition stage involving the slow production of small pores under reverse imbibition; and dynamic equilibrium stage characterized by weak displacement and weak imbibition. When viewing the entire water flooding dynamic imbibition process as an organism, it becomes imperative to maximize the recovery of large pores while ensuring the recovery degree of small pores. High permeability contributes to better pore throat connectivity and a greater imbibition and displacement production degree. The contribution of the.two production modes to the recovery of small and large pores increased by 4.67 % and 3.17 %, respectively. A negative correlation was observed between high displacement pressure and imbibition recovery, yet it is conducive to the contribution of displacement to total recovery. Notably, fractures can effectively reduce oil-water seepage resistance, and increase the contribution of displacement to recovery by 21.65 %. Finally.a positive correlation was noted between increased imbibition amount and free oil recovery, while residual oil gradually shifted towards adsorbed and organic matter-dominated forms, leading to decreased recoverability. Effectively utilizing the bridge flow conductivity of fractures, fluid imbibition displacement, and carrying effect is crucial for achieving optimal EOR. The findings provide theoretical support for clarifying the interaction between matrix-fracture imbibition and displacement and for the efficient development of shale oil.