Residual Water Saturation Research Articles

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.

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.

Assessment of petrophysical properties of reservoirs by well data

The use of traditional research complexes is of great importance in solving such important problems as correlating well sections for the purpose of lithological assessment, determining the reservoir properties of reservoir layers that make up the section, namely, saturation, porosity, permeability and clay content, as well as identifying oil and gas-bearing and aquifer layers. The complexity of solving such important problems depends entirely on the petrophysical properties of reservoir layers. For example, the electrical resistivities of oil-bearing and aquifer reservoirs are similar in magnitude, which leads to high clay content and significant variation in porosity throughout the field, which, as a result, makes it difficult to separate oil-bearing and aquifer reservoirs from each other. On the other hand, it is also known that an increase in the amount of cementing clays in reservoirs leads to a decrease in porosity and an increase in residual water saturation. In this regard, in the article, based on a set of well data, the values of the petrophysical parameters of reservoir layers were determined, models were built that determine the correlation between them, and regression equations based on the statistical distribution of these parameters were established. The article also built models for the distribution of porosity, permeability, clay content and oil and gas saturation along well sections. The constructed models provide the basis for forming a definite opinion about the field and obtaining results of both a scientific and practical nature when studying the filtration and reservoir characteristics of reservoir layers, as well as when determining the relationship between petrophysical parameters. The object of the study was the on the Kirmakinskaya (KS) and Underkirmaky (UK) formations of the productive series (PS) selected from the wells of the Gyurgyan-Deniz field.

Diffusion hysteresis in unsaturated porous media: A microfluidic study

In unsaturated flow studies, water saturation is commonly used as the sole descriptor for macroscale flow models. However, this approach often results in hydraulic hysteresis in capillary pressure and relative permeability during drainage and imbibition processes. Furthermore, the effects of these behaviors on solute diffusion remain unclear. To address this knowledge gap, we conducted microfluidic experiments to investigate these hysteresis relationships. We firstly implemented drainage and imbibition processes in the micromodel to establish pore-scale water configurations. Subsequently, we upscaled the capillary pressure and diffusion coefficients to the Representative-Elementary-Volume scale. Our results revealed that, at the same saturation levels, the unsaturated diffusion coefficients during drainage were at least 6.1 % higher than during imbibition, indicating the presence of diffusion hysteresis. We observed that this hysteresis was influenced by capillary number and residual water saturation. An increase in the capillary number reduced diffusion hysteresis, similar to the capillary pressure hysteresis. While a decrease in residual saturation rose diffusion hysteresis. We also proposed a quadratic polynomial model that effectively predicts the diffusion coefficient by incorporating both saturation and capillary pressure. This research emphasizes the importance of historical changes in unsaturated water flow, which hold significant implications for modeling solute transport processes.

Estimation of residual water saturation in 3D geological modeling

Estimation of residual water saturation in 3D geological modeling

Analysis of experimental and simulation data of evaporation‐driven isotopic fractionation in unsaturated porous media

AbstractStable water isotopologs can add valuable information to the understanding of evaporation processes. The identification of the evaporation front from isotopolog concentration depth profiles under very dry soil conditions is of particular interest. We compared two different models that describe isotopolog transport in a drying unsaturated porous medium: SiSPAT‐Isotope and DuMux. In DuMux, the medium can dry out completely whereas in SiSPAT‐Isotope, drying is limited to the residual water saturation. We evaluated the impact of residual water saturation on simulated isotopic concentration. For a low residual water saturation, both models simulated similar isotopolog concentrations. For high residual water saturation, SiSPAT‐Isotope simulated considerably lower concentrations than DuMux. This is attributed to the buffering of changes in isotopolog concentrations by the residual water in SiSPAT‐Isotope and an additional enrichment due to evaporation of residual water in DuMux. Additionally, we present a comparison between high‐frequency experimental data and model simulations. We found that diffusive transport processes in the laminar boundary layer and in the dried‐out surface soil layer need to be represented correctly to reproduce the observed downward movement of the evaporation front and the associated peak of isotopolog enrichment. Artificially increasing the boundary layer thickness to reproduce a decrease in evaporation rate leads to incorrect simulation of the location of the evaporation front and isotopolog concentration profile.

Evaluation of the effectiveness of the method of studying water saturation for solving urgent decarbonization problems

At present, the impact of the decarbonization trend on the oil and gas industry is becoming more and more tangible. One of the promising approaches to carbon dioxide utilization is the technology of its injection into the productive formation for enhanced oil recovery. The projects realized in the world have shown the efficiency of liquefied carbon dioxide application as a solvent for wells, which leads to increase of hydrocarbon flow rate due to various mechanisms. CO2 injection has been proven to reduce the interfacial tension at the hydrocarbon-water interface and improve water wettability of the rock, converting it from a film state to a droplet state. However, when implementing this approach, it is worth paying attention to the study of formation parameters such as saturation and capillary forces. In this paper, the capillarometry principle is considered to calculate the water saturation parameter of a complex reservoir type with low filtration properties. The study is to evaluate an effective approach to study the estimated residual water saturation under complex pore space geometry and possible pore hydrophilicity disturbance. The practical interest of this work is to increase the study of reservoir properties at the pore level for prediction of its physical and chemical properties in the modeling of composite dynamic model for solving topical issues in reservoir development.

Formation mechanisms of residual water in CO2-water-rock systems: Effects of the CO2 phase

This study focused on the effects of the CO2 phase on the formation mechanisms of residual water. Based on nine groups of core-flooding experiments, the order of residual water saturation was gaseous CO2 > supercritical CO2 > liquid CO2, and a quantitative power function relationship between residual water saturation and displacement time for different CO2 phases was proposed. The experimental results show that when CO2 transitions from the gaseous phase to the supercritical phase and then to the liquid phase, the decrease in the interfacial tension and cosine value of the contact angle in two-phase flow can lead to a decrease in residual water saturation. Meanwhile, an increase in the viscosity ratio of two-phase flow weakens the viscous fingering phenomenon and can also lead to a decrease in residual water saturation. However, the logCa-logM stability phase diagram reveals that the viscous force is the primary factor influencing all core-flooding experiments.

Adsorbed residual oil saturation and phase permeability relationship for oil in Western Siberia productive formations

Relevance. Relative phase permeabilities determine oil by water displacement mechanism, efficiency of productive formations flooding, dynamics of producing wells flooding. Relative phase permeabilities curves allow us to estimate the inflow nature according to geophysical well studies. Currently, relative phase permeabilities curves are constructed according to core samples laboratory studies. They are used to select a mathematical model describing the nature of the curves for a given productive reservoir. The most optimal option is to justify the individual relative phase permeabilities curve parameters. This option allows transition from the core sample level to the entire productive reservoir characteristics using geophysical well studies data. Aim. To substantiate a choice of a model describing the change in the relative phase permeability curves using field geophysics data based on the adsorbed residual oil saturation and phase permeability to oil relationship. Objects. Productive layers of individual deposits of the West Siberian oil and gas province, confined to the Lower Cretaceous deposits. Methods. Statistical processing of capillarimetric research data, analysis and substantiation of mathematical models describing relative phase permeability. Results. The paper shows that the permeability to oil at residual water saturation (the starting point of the relative phase permeabilities curve to oil) is determined by the adsorbed residual reservoir oil saturation. The authors have obtained the formula, linking the adsorbed residual oil saturation coefficient with the phase permeability to oil with residual water saturation. The adsorbed residual oil saturation is also closely related to the residual reservoir water saturation. Such relation is carried out through the reservoir clay content. The authors proposed the technique that allows residual oil saturation by type structuring and mobility degree. This technique allows as well as finding out the residual reserves of mobile oil distribution to justify the recovery techniques.

Effect of Rock Dissolution on Two-Phase Relative Permeabilities: Pore-Scale Simulations Based on Experimental Data

Relative phase permeability is an important characteristic of multiphase flow in porous media. Its assessment is an urgent issue when the pore structure changes due to rock dissolution. This article examines the effect of carbonate rock dissolution on two-phase flow based on images obtained by X-ray microcomputed tomography with a spatial resolution of ~18 µm. The characteristics of the two-phase flow were calculated through pore network modeling. The studies were conducted on 20 sub-volumes, which were extracted from cylindrical samples A and B with permeabilities of 0.72 and 0.29 D. HCl solutions (12% and 18%) were injected into samples A and B at a rate of 8 and 2 mL/min, respectively. Due to rock dissolution, the porosity and absolute permeability of the sub-volumes increased by 1.1–33% and 44–368%, respectively. Due to dissolution, the residual oil and water saturations decreased by 20–46% and 25–60%, respectively. These results showed that an increase in absolute permeability led to a significant reduction in residual oil and water saturations. These results also demonstrated that rock dissolution resulted in a change in the spatial heterogeneity of the relative phase permeabilities. The spatial heterogeneity increased in sample A after rock dissolution, while in sample B, it decreased.

Residual Saturation Effects on CO2 Migration and Caprock Sealing: A Study of Permeability and Capillary Pressure Models

In CO2 geological storage, multiphase flow plays a vital role in the movement and distribution of CO2. However, due to the limitations of fluid buoyancy and capillary forces, CO2 encounters challenges in penetrating the caprock, and the potential for leakage remains a concern due to variations in injection conditions. The migration and distribution of CO2 in the process of CO2 geological storage in saline formations are determined by relative permeability and capillary pressure, which are key factors. Consequently, this study focuses on two essential models: relative permeability and capillary pressure models. A two-dimensional isothermal reservoir–caprock model was constructed, utilizing data from the Shenhua CCS demonstration project. The analysis indicates that the core parameters in the model are residual gas saturation and residual water saturation. Specifically, residual gas saturation governs the diffusion distance of CO2 within the reservoir–caprock system, while its combined effect with residual water saturation affects the permeation rate of CO2. Through the application of the Analytic Hierarchy Process (AHP) to analyze the impact of different models on caprock integrity, it was determined that when selecting caprock models and optimizing parameters, precedence should be given to models with lower residual saturation and caprocks that offer sufficient capillary pressure for optimal sealing effects. These research findings can serve as references for practical CO2 storage projects, providing guidance on activities such as adjusting water injection strategies and controlling gas injection pressures to optimize geological storage efficiency.

Viscosification of CO2 to improve subsurface storage — A modeling study

In this work, we numerically investigate the potential benefits of a recently proposed functional molecule that can both significantly increase the viscosity of CO2 and reduce the residual water saturation in the context of CO2 storage in subsurface aquifers. We model different degrees of CO2 viscosification in field-scale formations at both shallow and greater depths, consider a range of permeabilities from 100 md to 2,000 md, and both homogeneous and highly heterogeneous formations. To quantify the impacts of CO2 viscosification, we track multiple domain-integrated quantitative measures such as CO2 tip velocity and dispersion widths. In all scenarios, we find that CO2 viscosification increases the total amount of CO2 retained but the degree of improvement varies. Moreover, the fraction of solubility trapping versus structural trapping is highest for neat CO2. These modeling results can inform stakeholders in CO2 viscosification technology for future large-scale CO2 storage projects.

Theoretical justification and creation of petrophysical models of residual water saturation and effective porosity of a thin-layer reservoir

The paper deals with theoretical justification and mathematical construction of analytical petrophysical models of residual water saturation and effective porosity of granular reservoirs taking into account the presence of fine-dispersed cement fraction (dispersed clay content), clay interlayers (laminated clay content) and bound water of the rock matrix. Models are given for two mechanisms of residual water saturation formation: in the case of unchanged water-holding capacity of the rock matrix (volume of bound water of the matrix does not change when the matrix vessel is filled with cement) and for the case in which an increase in the aggregate cement content leads to a decrease in the volume of bound water of the matrix. Such models are necessary for solving the system of petrophysical equations describing the methods of well logging in order to determine the porosity and permeability continuously along the section taking into account the micro-layering of sediments, which, in turn, increases the informativeness of the interpretation results.

METHODOLOGY FOR SUBSTANTIATING THE CALCULATION PARAMETERS OF COMPLEXLY CONSTRUCTED TERRIGENOUS RESERVOIRS IN WESTERN SIBERIA, INCLUDING THOSE WITH TRIZ, ACCORDING TO THE CORE AND GIS STUDY

The article presents an analytical solution to the direct problem of the method of spontaneous polarization of rocks in a well crossing an electrically inhomogeneous reservoir of limited thickness with a drilling mud penetration zone. The analytical solution of the problem by the employees of Schlumberger-Doll Research (M.R. Taherian, at all) for an impermeable reservoir in the absence of a penetration zone is a special case of the analytical solution of the direct problem of the spontaneous polarization (PS). The accuracy of the interpretation of the analytical and numerical solution of the inverse PS problem does not exceed the permissible accuracy of measuring the PS potential. The static potential of the ESP calculated on the basis of the analytical solution of the direct and inverse PS problem is used to construct the correlation dependence of the «core-GIS» static potential of the ESP on the volumetric humidity W, equal to the product of the porosity coefficient KP by the coefficient of residual water saturation KOV. An example of the interpretation of low-permeable, low-resistance oilsaturated reservoirs of Jurassic sediments for the operational assessment of reserves of the Yegansky, Martovsky and Zaozerny deposits of Western Siberia is given. The algorithm proposed in the article can be used for automated interpretation of the PS method and multi-probe induction logging in the corporate software of PJSC OC Rosneft.

An investigation of factors affecting Low Tension Gas process for enhanced oil recovery in carbonate reservoirs

Laboratory scale experiments have established LTG (Low Tension Gas) flooding to be a promising EOR method in low permeability and high salinity carbonate reservoirs for both tertiary and secondary recovery. In this work, three important factors that strongly influence the performance of LTG process are investigated: (i) wettability, (ii) injection gas type, and salinity variation. LTG flooding was investigated for the first time for low permeability carbonate cores, which had been aged for over five weeks after being oil flooded at residual water saturation (aged cores), and high formation brine salinity hardness. Hydrocarbon gas from the field was tested as a candidate for co-injection with surfactant solution to generate foam during LTG flooding. This eliminates the need for importing gas from an external source. Another innovation in the LTG process design is that the need for freshwater or treating the produced water from the field was removed by using the re-purposed high salinity produced water for all stages of the LTG flood. LTG floods in aged cores was observed to give oil recovery similar to non-aged cores under same conditions. LTG flood in aged cores resulted in a residual oil saturation of 11% compared to 19.4% using secondary WAG injection.

Experimental Study on the Influence of Wettability Alteration on Gas–Water Two-Phase Flow and Coalbed Methane Production

The surface wettability is important in the change in the relative permeability of gas and water. Due to the heterogeneous property of coal, it has a mixed wetting state, which makes it difficult to predict the change in permeability. To investigate the influence of different wettabilities on two-phase flow, a total of three different rank coal samples were collected and were treated with different chemicals. The alteration of the coal’s wettability, characteristics of gas–water flow, and relative permeability of the coal after the chemical treatments were analyzed. The research conclusions suggest that (1) the coal samples treated with SiO2 and H2O2 increased the hydrophilicity of the coal surface, while the coal samples treated with DTAB increased the hydrophobicity of the coal surface. Compared to SiO2, both H2O2 and DTAB can form a uniform wetting surface. (2) The wettability alteration mechanism among the three different chemical reagents is different. (3) All the chemicals can change the gas–water interface. The water migrates more easily through the cleats after H2O2 treatment, while it is more difficult for the water to migrate through cleats after the DTAB treatment. (4) There are two types of flow states of gas and water on different wetting surfaces. A slug flow is formed on a hydrophilic surface, while an annular flow is formed on a hydrophobic surface. (5) The crossover point and the residual water saturation of the relative permeability curves were influenced by the surface wettability.

Study of petrophysical parameters of productive series by use of well data

The progress of existing geophysical techniques for the last years led to a wider scope of the problems resolved using this set of tools. The tools allow tackling pivotal tasks such as the study of lithology in a geological section, correlation, evaluation of saturation, porosity, permeability, and clay fraction, and outlining of oil-gas and water-saturated layers. Complications emerging while resolving these problems directly depend on the petrophysical parameters of reservoir layers. For instance, similar values of resistivity in oil and water layers result in high value of clay fraction and variation of porosity in a wide range and this complicates distinguishing the oil and water layers. On the other hand, it is known that an increase of cementing clay amount in reservoirs causes drop of porosity (Kpor.) and increase of residual water saturation.
 This paper is devoted to design of models defining correlation between petrophysical parameters of reservoir layers by use of integrated well data and establishing regression equations from these parameters’ distributions. Models of variation of porosity, permeability, clay fraction and oil and gas saturation through the sections of wells were also designed. They made it possible to evaluate filtration-capacity characteristics and establish correlation between petrophysical parameters of reservoir layers and gain information about this field.
 The bar graph was drawn for permeability coefficient variation through studied reservoirs in Qirmaky suite (QD-1, QD-2, QD-3, QD-4) by use of sections of wells conditionally marked as 1, 2, 3, and 4 in the Balakhany field.
 Analysis of the constructed histograms allows us to classify the studied collector layers according to their permeability. Of the 17 layers studied in section of well 1, only Layer 17 has very good permeability, the other 16 are of good permeability; all 17 layers of well 2 have good permeability characteristics; of the 17 layers of well 3, Layer 3 is of poor permeability, layers 6, 7, and 14 have average permeability, and the rest are of good permeability; all 12 layers of well 4 have good permeability.
 The study target is Qirmaky suite (QD-1, QD-2, QD-3, QD-4) of the Productive Series in Balakhany field.

Influence of two-phase displacement characteristics on the storage efficiency and security of geological carbon storage

In the mitigation of greenhouse gas emissions, the storage efficiency and security of geological carbon storage (GCS) are the focus of attention, and both of them are closely related to the displacement behavior between immiscible two phases. In this study, CO2-water two-phase displacement experiments were conducted on six samples with various pore structures using nuclear magnetic resonance and magnetic resonance imaging technology to characterize the fluid distribution and determine displacement patterns. The displacement property was found to be closely related to the heterogeneity and anisotropy of pore structure. The two-phase displacement instability gradually evolved from tonguing (logCa > −2.94) to capillary fingering (logCa < −2.03), and then further evolved into viscous fingering (logCa > −2.03). Nevertheless, rocks with good connectivity and high permeability will restrain the occurrence of unstable displacement even if logCa is in the favorable range. Combined analyses of displacement patterns and pore structure can provide effective means for the evaluation of reservoir and caprock. For rocks dominated by micropores, their displacement pattern is more likely to correspond to time-consuming piston-like displacement. Their high sealing efficiency is characterized by high capillary displacement pressure and low effective gas permeability, which allow them to be considered as caprocks. For rocks with lower capillary displacement pressure and higher effective gas permeability, their lower residual water saturation makes them more suitable as favorable reservoirs for GCS. Reservoir rocks with stable piston-like displacement exhibit the highest displacement efficiency, while the difference of displacement rates in pores with diverse sizes caused by the fingering or tonguing phenomena weakens the displacement efficiency.

Numerical investigations on performance of sc-CO2 sequestration associated with the evolution of porosity and permeability in low permeable saline aquifers

Storing of supercritical carbon dioxide (sc-CO2) in the saline aquifer is studied extensively in the present work using numerical investigations. A mathematical model is developed and applied successfully to determine the movement of sc-CO2 from the injection well along the low permeable saline aquifer. The injected fluid and petrophysical properties are considered as a function of pore pressure in the formation. The impact of permeability modulus in both low and high permeable saline aquifers are studied. The impact of porosity, permeability, injection velocity, permeability anisotropy, residual water saturation, and residual gas saturation is studied. All these parameters influence the migration of sc-CO2 in the reservoir and storage capacity. It is observed that the pore pressure is highly impacted by the change in permeability and injection velocity. Porosity is inversely proportional to pore pressure buildup and directly proportional to the storing of sc-CO2 in the porous media. Due to the increase in pore pressure, the change in porosity is 14.5%, while the change in permeability is 7mD (millidarcy) for 1000 days. At a lower permeability ratio (kV/kH), due to an increase in pore pressure also, the migration of injected sc-CO2 in a vertical direction is decreased when compared with a higher permeability ratio. Thus, this work provides a better understanding of the influencing parameters for storing and migration of sc-CO2 in the low permeable saline aquifer.

Method for oil and water relative permeability calculating in Western Siberia formations according to capillarimetric and geophysical data

The most important filtration characteristics of productive formations are the oil and water phase and relative permeability. Methods for obtaining relative phase permeabilities can be divided into laboratory and analytical. Currently, the main source of information about RFP are techniques based on laboratory core studies. However, for each productive reservoir, it is desirable to have analytical models describing experimental data on RFP with an accuracy sufficient for practical purposes. The existence of such models will make it possible to increase the accuracy of development computer modeling. The analytical expressions obtained in this study allow us to take into account the influence of the pore channels heterogeneity in size on the relative phase permeabilities magnitude. It is shown that the pore channels heterogeneity in size can be estimated by the residual water saturation amount, which in turn can be determined from the geophysical well studies. Keywords: relative permeability; residual water saturation; pore channels; capillarimetric and geophysical studies.