Mobile Fluid Research Articles

Analysis of the factors influencing movable fluid in shale oil reservoirs: a case study of Chang 7 in the Ordos Basin, China

Shale oil in the Ordos Basin is one of the most important areas for further exploration. In this paper, the relationships between the organic geochemistry, physical properties, micropore structure and mobile fluid composition of the Chang7 shale were studied via field emission scanning electron microscopy field emission scanning electron microscopy, nuclear magnetic resonance and computed tomography. The results indicate that the shales are mainly composed of quartz, clay and feldspar. The micro/nanopores are composed of mineral intergranular pores, dissolution pores and intercrystalline pores. The pore size of the mobile fluid ranges from 10 to 30 nm and from 0.1 to 10 μm, and a higher temperature is associated with a better fluidity of 10–30 nm. Based on the fractal turning point method, the shale reservoirs are classified as moderate or high heterogeneity. The mobile liquid was mainly controlled by the brittleness index, permeability, permeability, radius of the throat, radius of the pore throat, and volume ratio of the pore throat. The second factor was the heterogeneity strength and burial depth, but the relationship with TOC content and maturity was not obvious.

Determination method and application of variable T2 cutoff value in nuclear magnetic logging

Abstract Nuclear magnetic resonance logging (NMR) is a new logging technology. By inversion of relaxation time T2 spectrum, pore characteristics can be directly measured, independent of the influence of rock skeleton minerals, and parameters such as effective porosity, movable fluid porosity, bound water porosity, pore size distribution and permeability can be calculated. The key parameter for calculating fine pore structure is the critical relaxation time of bound water and mobile fluid, namely the T2 cutoff value. The current T2 cutoff value is a fixed value based on the T2 mean value corresponding to the flowable porosity (permeability contribution porosity) in the mercury injection experimental data. However, according to the analysis of mercury injection data, there are differences in the flowable porosity of cores with the same porosity and permeability under the same pressure difference. Based on the synchronous data of nuclear magnetic logging and core mercury injection experiment, this paper establishes a variable T2 cutoff value determination method, which significantly improves the interpretation accuracy of nuclear magnetic logging and lays a foundation for the important application of nuclear magnetic logging in reservoir fine description.

Effect of charge inversion on the electrokinetic transport of nanoconfined multivalent ionic solutions

Understanding the effects of phenomena occurring at electrically charged interfaces, such as charge inversion (CI), is crucial for enabling electroosmosis as an efficient transport mechanism in nanodevices. Here, we employ molecular dynamics (MD) simulations to systematically analyze the effect of CI on the electrokinetic transport of multivalent ionic solutions confined in amorphous silica nanochannels. We employ mixtures of monovalent and multivalent counterions while fixing the total ionic concentration to establish correlations between observed phenomena and the amount of multivalent ionic species in the electrolyte solution. The results show that the development of CI is related to a decrease in the mobility of the fluid layers adjacent to the charged surface. In addition, we observe that interfacial overcharging disrupts the water molecular orientation in the fluid layers adjacent to the channel walls. From the non-equilibrium MD simulations of electro-osmotic flow, we disclose the influence of phenomena related to the presence of CI. In particular, flow reversal occurs in scenarios involving CI due to increased local viscosity and a higher concentration of coions within the hydrodynamically mobile and electrokinetically active region of the charged interface. We also find that the magnitude of the wall zeta (ζ) potential displays a monotonic increase with the development of CI in the system. Moreover, we explain why positioning the wall ζ potential at an imaginary (slip) plane, which separates the hydrodynamically mobile and immobile fluid, is misleading.

Coupled adsorption/precipitation (Γ/Π) modelling of scale inhibitor transport in porous media using the coupled isotherm, AΓΠ(c)

Scale inhibitor (SI) “squeeze” treatments are widely used operations in production assurance to prevent inorganic scales as one of the main flow assurance problems. In these treatments, a high concentration SI slug is injected (“squeezed”) into the porous medium, retained in the formation rock, and is gradually produced back at relatively small concentrations that can prevent (or significantly reduce) scale formation. The retention of SI in the formation is governed by coupled mechanisms of adsorption (Γ) and precipitation (Π) of SI species in the system. To design such SI treatments in an optimized manner, it is important to have good mathematical models of both the transport and the coupled interactions of adsorption/precipitation (Γ/Π) processes. In this study, a 1D advection-dispersion-reaction transport model has been developed, considering the coupled Γ/Π retention processes, and it is used to model linear core flood systems. The parameters for the equilibrium Γ/Π model can be derived from the routine bulk SI “apparent adsorption” tests that are usually conducted before any treatments. From previous works, equilibrium adsorption isotherm, Γ(c), is used to describe the adsorption behavior in such systems. However, although the precipitation kinetics are “fast” (almost at equilibrium), the kinetics of SI dissolution are “slow” and is therefore modelled by a kinetic rate law. From the derived dimensionless form of the transport-Γ/Π model equations, it is shown that the system is governed by 4 dimensionless numbers, NA, NP, NPe and NDa, which are the adsorption number, the precipitation number, the Peclet number, and the Damköhler number, respectively. The shape of the adsorption isotherm also plays a very important part in the extent and form of the effluent SI returns from the linear system. The developed model was then employed to carry out a series of sensitivity calculations relating to coupled adsorption/precipitation (Γ/Π) processes. Both equilibrium and kinetic SI precipitation were modelled coupled with the equilibrium SI adsorption, and the effect of these processes on the form and extent of the SI effluents was assessed. A range of sensitivities was then carried out to determine the effect of a wide range of parameters, including the effects of flow rate and shut-in periods on the kinetic dissolution effluent behavior. The findings from this work present the most clear explanation to date of why and how “precipitation squeezes” can greatly extend squeeze lifetime. A novel feature of this analysis is to show how the role of precipitation and adsorption changes over the various stages of the return effluent by developing plots of the %SI adsorbed on the rock, in the precipitate, and the mobile fluid phase.

Pore structure characterization and reservoir quality prediction in deep and ultra-deep tight sandstones by integrating image and NMR logs

Pore structure and fracture determine reservoir quality in deep and ultra-deep tight sandstones, however, the limited availability of core data makes it challenging to describe the complexity of pore-throat structure and characterize the wide range of fractures. To fill this gap, a comprehensive analysis was conducted to evaluate pore structure and fractures from multiple perspectives. Integration of core, thin sections, scanning electron microscopy (SEM), high pressure mercury injection (HPMI) and nuclear magnetic resonance (NMR) tests are used to evaluate pore structure and characterize fracture of deep and ultra-deep tight sandstones in the Cretaceous Bashijiqike Formation in the Kuqa Depression. Pore structure and reservoir quality types can be divided into dominantly three types according to characteristics of NMR transverse relaxation time (T2) distribution and HPMI curves. Correlation analysis among HPMI and NMR parameters with petrophysical parameters indicate that maximum pore throat size (rmax), logarithmic mean of T2 (T2gm), irreducible water saturation (Swi), and reservoir quality index (RQI) are the most sensitive parameters for pore structure characterization. The Type Ⅰ pore structure is composed of intergranular and intragranular pores, and NMR T2 spectrum shows the highest magnitude, with the calculated mobile fluid saturation content also being the highest. The Type II and III pore structures are composed of intergranular pores, intragranular dissolved pores and intercrystalline micropores in clay minerals. T2gm of Type II and III are smaller, with the calculated mobile fluid saturation content being the lower.The fracture features and parameters including fracture density, porosity, aperture, and length are analyzed using image logs and core. The pore structure characteristics are quantificationally and qualitatively analyzed by NMR logs. Integration of pore structure and fractures by image logs and NMR logs are used for prediction of high quality reservoir and hydrocarbon productivity. High hydrocarbon productivity is obtained in well intervals with abundant natural fractures, and favorable pore structure will also contribute to high matrix porosity. Therefore, NMR logs and image logs are crucial for evaluating reservoir quality and predicting productivity when calibrated with core and analysis data. The comprehensive analysis integrating core data with geophysical well logs provide important insights for reservoir quality prediction of deep and ultra-deep tight sandstones.

Investigation of pore structure evolution and damage characteristics of high temperature rocks subjected to liquid nitrogen cooling shock

Liquid nitrogen (LN2) can be utilized in the development of enhanced geothermal systems, as well as for deep/ultra-deep hydrocarbon reservoir stimulation, fire suppression, and other high-temperature geological projects. It is a crucial issue in the utilization of LN2 to investigate the pore structure evolution, permeability, and damage characteristics of high-temperature rocks under the influence of LN2 cooling shock. These rocks were first slowly heated to 150∼600°C and held for 2 h, followed by LN2 or natural cooling. The evolution of pore volume in high-temperature rocks affected by liquid nitrogen cooling was quantified. T2 cutoff values were determined through centrifugal tests, while the contents of irreducible and mobile fluids were estimated. Based on the aforementioned analysis as well as changes in irreducible fluid saturation, pore throat, tortuosity, and permeability, this study examines the closure and development of pores along with permeability behavior. The findings suggest that, despite a more pronounced decrease in porosity at lower heating temperatures, LN2 cooling specimens exhibit superior pore connectivity and permeability compared to those cooled naturally. LN2 stimulation not only induces crack initiation and propagation but also results in further cooling induced densification based on heating densification. 225°C is considered to be the optimal temperature for cooling contraction induced densification in this study. At higher heating temperatures, the damage to rock cooled with LN2 is more severe than that of naturally cooled. This results in a greater increase in porosity, movable fluid content and proportion, and permeability of LN2 cooled specimens compared to naturally cooled specimens. The damage mechanism can be better understood by the constructed damage model that coordinates the pore increase/decrease and mutual pore transformation from the perspective of pore evolution.

Идентификация компонентного состава твердой углеводородной фазы в пласте и оценка ее влияния на поведение подвижного флюида баженовской свиты в процессе разработки залежи

The purpose of the work is to identify the composition of the initial reservoir hydrocarbon (HC) system of the Bazhenov formation, as well as to assess the influence of the presence of a heavy solid hydrocarbon phase (bitumen) in the formation on the production of mobile fluids using PVT modeling methods. The article describes the necessary experiments to determine the component composition of the C81+ fraction and the PVT properties of the formation mobile fluid taken from the well and the bitumen extract from the rock, and also presents their results. In addition, the properties of fractions up to C81+ were calculated depending on the molecular weight for PVT modeling (extension of the Katz-Firuzabadi table). One of the important parts of the article is the assessment of the ratio of bound and free oil in the original reservoir system. Based on geochemical research data, an analysis was performed to assess the component composition of the original system (using the example of the Bazhenov Formation) using rock pyrolysis and studying formation fluid and bitumen. Using the results of studies of reservoir fluid samples, a PVT model was built and tuned. This PVT model was used to assess the properties of the initial reservoir hydrocarbon system and was adjusted to the fraction of the solid phase in the reservoir at the initial reservoir conditions. After this, based on the PVT model, an assessment was made of the influence of the presence of a solid phase in the composition of the reservoir system on the behavior of a mobile hydrocarbon fluid during reservoir development for depletion, as well as on the use of enhanced oil recovery methods (injection of associated petroleum gas and thermal methods of influencing the reservoir).

Evaluation method of oil saturation index OSI for shale oil reservoir based on well logging data

Oil saturation index (OSI) serves as an important indicator for potential movable hydrocarbons evaluation of shale oil reservoirs, which is mainly obtained through rock pyrolysis experiments. A new method is proposed to evaluate the OSI of shale quantitatively by NMR logging. The OSI value can be accurately obtained through the experimental measurement of organic carbon content (TOC) and rock pyrolysis of shale samples, which can identify the development of mobile hydrocarbons. Subsequently, the mobile fluid porosity can be obtained based on NMR logging. In order to establish the relationship between OSI value and mobile fluid porosity, it is important to determine the T2 cutoff value corresponding to the mobile fluid porosity. Take shale samples from the first member of the Qingshankou Formation (“Qing 1 Member”) as an example, based on 2D NMR experimental analysis in three different states (original, dried state at 105°C, saturated kerosene), the NMR T2 cutoff value of movable fluid porosity in the shale of Qing 1 Member is clarified as 8 ms. Integrating rock pyrolysis and 2D NMR experiments, it suggests that the NMR bin porosity with T2>8 ms has a good linear relationship with the OSI value obtained by pyrolysis analysis. The NMR bin porosity with T2> 8 ms reflects the OSI value of shale effectively. The larger the NMR bin porosity with T2>8 ms, the higher the mobile oil content of shale reservoir, which is consistent with the understanding of oil-bearing large pores in the Gulong Shale. The NMR bin porosity can continuously evaluate the vertical variation of the mobile hydrocarbon content. Compared with the traditional experimental measurement of finite depth points, this method has significant advantages, and can avoid the possibility of missing potentially movable oil layers.

Microscopic pore-throat structure variability in low-permeability sandstone reservoirs and its impact on water-flooding efficacy: Insights from the Chang 8 reservoir in the Maling Oilfield, Ordos Basin, China

The Chang 8 reservoir of the Maling Oilfield in the Ordos Basin, China is facing a series of challenges in hydrocarbon resource development, including rapidly decreasing production rates, declining dynamic fluid levels, and elevated water cuts in oil wells, along with heterogeneity in microscopic pore-throat structures and notable interstratal inconsistencies. To systematically address these issues, this study selected representative samples from the reservoir and conducted rigorous microscopic percolation experiments on them. A comprehensive evaluation of the heterogeneity in microscopic pore structures was conducted using an integrative methodological approach, involving physical property quantification, petrographic thin-section analysis, scanning electron microscopy, constant-rate mercury intrusion, and nuclear magnetic resonance techniques. The primary objective of this investigation is to elucidate the underlying formation mechanisms, states of occurrence, and spatial distributions of residual oil. Understanding of these issues will facilitate the establishment of empirical correlations between diverse microscopic pore structures and water-flooding efficiencies, and aid in the identification of key variables governing the distribution of residual oil. Analytical outcomes reveal substantial variations in seepage characteristics contingent upon the nature of microscopic seepage conduits. Specifically, the Chang 8 reservoir manifests four discernible categories of microscopic seepage pathways: solely intergranular pores, a confluence of dissolution and intergranular pores, exclusively dissolution pores, and micropores. A correlative decline in oil displacement efficiency is observed across these conduit types. Critical variables such as throat radius and its distribution patterns emerge as pivotal determinants influencing oil displacement efficiency, eclipsing the impact of conventional physical properties and mobile fluid saturation levels. Remarkably, samples characterized by a composite of dissolution and intergranular pores demonstrate superior displacement efficiency. Distinct types of pore structures correspond to noticeably different water-flooding oil pathways and oil displacement efficiencies. During the water-flooding process, fingering network displacement is dominant, and it exerts a significant control on oil displacement efficiency. Key factors affecting this efficiency include the injected water volume multiples and displacement pressure, values of which should be optimized during the actual water-flooding process.

Pore Structure Characteristics of Shale Oil Reservoirs with Different Lithofacies and Their Effects on Mobility of Movable Fluids: A Case Study of the Chang 7 Member in the Ordos Basin, China

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.

Sublithospheric Diamonds: Plate Tectonics from Earth's Deepest Mantle Samples

Sublithospheric diamonds and the inclusions they may carry crystallize in the asthenosphere, transition zone, or uppermost lower mantle (from 300 to ∼800 km), and are the deepest minerals so far recognized to form by plate tectonics. These diamonds are distinctive in their deformation features, low nitrogen content, and inclusions of these major mantle minerals: majoritic garnet, clinopyroxene, ringwoodite, CaSi perovskite, ferropericlase, and bridgmanite or their retrograde equivalents. The stable isotopic compositions of elements within these diamonds (δ11B, δ13C, δ15N) and their inclusions (δ18O, δ56Fe) are typically well outside normal mantle ranges, showing that these elements were either organic (C) or modified by seawater alteration (B, O, Fe) at relatively low temperatures. Metamorphic minerals in cold slabs are effective hosts that transport C as CO3 and H as H2O, OH, or CH4 below the island arc and mantle wedge. Warming of the slab generates carbonatitic melts, supercritical aqueous fluids, or metallic liquids, forming three types of sublithospheric diamonds. Diamond crystallization occurs by movement and reduction of mobile fluids as they pass through host mantle via fractures—a process that creates chemical heterogeneity and may promote deep focus earthquakes. Geobarometry of majoritic garnet inclusions and diamond ages suggest upward transport, perhaps to the base of mantle lithosphere. From there, diamonds are carried to Earth's surface by eruptions of kimberlite magma. Mineral assemblages in sublithospheric diamonds directly trace Earth's deep volatile cycle, demonstrating how the hydrosphere of a rocky planet can connect to its solid interior. ▪Sublithospheric diamonds from the deep upper mantle, transition zone, and lower mantle host Earth's deepest obtainable mineral samples.▪Low-temperature seawater alteration of the ocean floor captures organic and inorganic carbon at the surface eventually to become some of the most precious gem diamonds.▪Subduction transports fluids in metamorphic minerals to great depth. Fluids released by slab heating migrate, react with host mantle to induce diamond crystallization, and may trigger earthquakes.▪Sublithospheric diamonds are powerful tracers of subduction—a plate tectonic process that deeply recycles part of Earth's planetary volatile budget.

A Study on the Pore Structure and NMR Fractal Characteristics of Continental Shale in the Funing Formation of the Gaoyou Sag, Subei Basin

The continental shale oil resource in China exhibits significant potential and serves as a crucial strategic alternative to the country’s conventional oil and gas reserves. The efficacy of shale oil exploration and production is heavily contingent upon the heterogeneity of the pore structure within the reservoir. However, there remains a scarcity of research pertaining to the pore structure of continental shale and the factors that influence it. The objective of this study is to provide a quantitative characterization of the heterogeneity exhibited by the continental shale of the Funing Formation in the Gaoyou Sag. In this study, the research focus is directed toward the continental shale of the Funing Formation located in the Gaoyou Sag of the Subei Basin. This paper examines the correlation between the fractal dimension of nuclear magnetic resonance (NMR) and various factors including the total organic carbon (TOC), mineral composition, geochemical parameters, and physical properties, utilizing the principles of fractal dimension theory. The findings indicate that the primary pore types observed in the Funing Formation continental shale are inorganic matrix pores, which encompass dissolution pores, clay mineral intergranular pores, and a limited number of pyrite intergranular pores. By employing a relaxation time cutoff, the NMR fractal dimension can be categorized into two distinct dimensions: the bound-fluid-pore fractal dimension (0.5795~1.3813) and the movable-fluid-pore fractal dimension (2.9592~2.9793). The correlation between mineral composition and the fractal dimension indicates a negative relationship between the fractal dimensions of bound-fluid pores and movable-fluid pores and the content of quartz. The correlation between clay minerals and the fractal dimension indicates a significant negative relationship between the fractal dimensions of bound-fluid pores and movable-fluid pores with illite. There exists a negative correlation between the pore fractal dimension of bound fluid and the content of organic matter, whereas a positive correlation is observed between the pore fractal dimension of mobile fluid and the content of organic matter. The range of maturity of organic matter within the Funing Formation exhibits a relatively limited span, as indicated by the vitrinite reflectance (Ro) values falling between 0.8% and 0.9%. This narrow range of maturity does not exert a substantial influence on the two fractal dimensions. The NMR fractal dimension exhibits a negative correlation with permeability in relation to reservoir physical properties, while the bound-fluid-pore fractal dimension demonstrates a negative correlation with the total porosity. The findings suggest that the NMR fractal dimension can serve as a valuable indicator for evaluating the physical characteristics of reservoirs. The present study successfully examined the pore structure of continental shale through the utilization of nuclear magnetic resonance technology. This innovative technique provides a novel avenue for the assessment of continental shale reservoirs and the investigation of pore heterogeneity on a global scale.

Using digital cores and nuclear magnetic resonance to study pore-fracture structure and fluid mobility in tight volcanic rock reservoirs

Pore-fracture structure characterization and fluid mobility analysis are key to the effective development of tight reservoirs. However, it is difficult to accurately characterize the pore-fracture structure of tight volcanic rocks using a single method, and the mechanisms of fluid mobility are not fully understood. A combination of X-ray diffraction, casting thin section observations, scanning electron microscopy, high-pressure mercury injection, constant-speed mercury injection, nuclear magnetic resonance (NMR), X-ray computed tomography, and the advanced mathematical algorithms in the AVIZO visualization software was used to analyze the Permian tight volcanic rock in the ZhongGuai area of the Junggar Basin to investigate its overall pore-fracture structure characteristics. On this basis, NMR centrifugation experiments were conducted to monitor the fluid migration dynamics in the tight volcanic rocks, and the mobile fluid migration characteristics were studied based on the NMR T2 spectra. The results show that the porosity and permeability of the samples are 0.2–18.7 % (avg. of 8.3 %) and 0.001–6.680 × 10−3μm2 (avg. of 1.602 × 10−3μm2), respectively, and the various pore types are due to the differences in cementation and compaction. The distribution of the pore throats are mainly contiguous and isolated, and the connected pores are mainly distributed in enriched bands, which is due to the interconnection of gas pores, intergranular pores, and dissolution fractures; while the disconnected pores are mainly isolated, which is related to the development of inter-gravel dissolved pores and matrix dissolution pores. In addition, the contribution of the pore connectivity to seepage is greater than that at the pore scale. The pores in the tight volcanic rock have a wide range of sizes, from 3 nm to 120 μm, and are dominated by Gaussian and bimodal distribution patterns. The micron-scale pore radius in this area is mainly 4.47–31.56 μm. Also, the fractures can be divided into three types according to their occurrence and openings. They are mainly high-angle structural fractures and vertical fractures; the pore-fracture structures have strong heterogeneity, and the fractures play a larger role on the seepage of oil and gas. The connectivity of the pore throats in the tight matrix is poor, and the pore throat structure has a great influence on fluid mobility. Subsequently, the movable fluid saturation increases with increasing permeability, and the fractures and micropores have less flow resistance and are more conducive to water flow than small pores. This study provides new insights for the exploitation of similar tight reservoirs.

Permeability evaluation based on Nuclear Magnetic Resonance analysis for gas hydrate reservoir

Permeability (or hydraulic conductivity) is one of the most important parameters for analyzing hydraulic behavior of underground. For example, in the geotechnical engineering, permeability is necessary to calculate water inflow and draw down of water level during excavation, to predict the deformation time due to the consolidation, and to evaluate the barrier of the ground for radioactive waste disposal. In the petroleum industry, permeability is considered an essential parameter which is directly linked to the productivity of oil and natural gas. Therefore, predicting permeability using wireline logging or logging while drilling (LWD) is required during the assessment of the reservoir. Nuclear Magnetic Resonance (NMR) logging is performed at this point. Low-field NMR measurements are sensitive to the hydrogen proton, 1H, in liquid water but not to the 1 H bond in solid form, making it possible to obtain the bulk water volume. In addition, the hydrogen proton NMR- T2 (transverse or spin-spin) relaxation time distribution is used to infer pore-size information and to estimate permeability [1, 2]. The major methods used for estimating permeability, k, are the Schlumberger Doll Research (SDR) model and Timur-Coates (TC) model [3, 4]:
 Where fNMR is the NMR-estimated (effective) porosity. SDR model uses the averaged value of the T2 distribution plotted on log-scale of time and matches it to the experimental reference permeability with the fitting parameter a [mD/(ms)2]. The TC model seeks to differentiate between the fraction of free (mobile) fluid volume (FFV) and bound fluid volume (BFV) and estimates permeability with FFV/BFV ratio and the material constant c [m2/s2]. The permeability in the research and development of methane hydrate, which is expected to be a next-generation resource, has been estimated using above methods. Methane hydrate is an ice-like solid crystalline structure of water and methane molecules. Because hydrate is solid, NMR is not sensitive, the initial (effective) permeability can be estimated by NMR analyzer. On the other hand, A strong disconnect (up to 2 orders of magnitude) between NMR-based estimates of permeability with those determined from a laboratory study of pressure cores from the same reservoir has further cast uncertainty in the application of borehole NMR data in hydrate evaluation [5, 6]. Recently, authors provided comparisons between NMR-derived values and direct fluid flow estimates of permeability in naturally occurring hydrate-bearing sediment [7, 8]. On the basis of the NMR measurement for hydrate-bearing pressure core sediments, which were recovered from the Gulf of Mexico and Alaska North Slope, the following new hydraulic radius model was proposed [7].
 This equation estimates the specific surface based on the NMR signal and has been shown to successfully estimate the initial permeability of a hydrate reservoir by expressing a hydraulic radius model based on Kozeny's equation [9]. However, the proposed equation is not universal and has been found to overestimate for clayey and silty hydrate free sediment. This study summarizes the methods and parameters used to estimate permeability using NMR signals from hydrate-bearing sediment obtained from logging and laboratory tests for the Gulf of Mexico and Alaska North Slope. In addition, we reports parameters for predicting model for muddy sediments which was recovered from overburden of hydrate-reservoir in the Hyuganada sea in 2022 Japan [10, 11]. When using the hydraulic radius model to predict permeability of hydrate-bearing sediment, reasonable estimates can be obtained by setting the shape factor for grains Cs = 1/2 (for a circular grain) and the shape factor for the flow path cn = 4 (for the cylinder network), respectively. Although, for hydrate free muddy sediment, Cs = 1/3 for parallel plate grain shape and cn = 2 for the fracture network model matched its permeability. Furthermore, the conversion parameter from T2 relaxation time to the pore size for hydrate free muddy sediments r2 = 0.009 (mm/s) was confirmed based on the result of mercury injection capillary pressure analysis, which is lower than r2 = 0.0325 (mm/s) of hydrate-bearing sediments.

Extensional rheometry of mobile fluids. Part I: OUBER, an optimized uniaxial and biaxial extensional rheometer

Numerical optimization of a “six-arm cross-slot” device yields several three-dimensional shapes of fluidic channels that impose close approximations to an ideal uniaxial (biaxial) stagnation point extensional flow under the constraints of having four inlets and two outlets (two inlets and four outlets) and for Newtonian creeping flow. One of the numerically designed geometries is considered suitable for fabrication at the microscale, and numerical simulations with the Oldroyd-B and Phan-Thien and Tanner models confirm that the optimal flow fields are observed in the geometry for both constant viscosity and shear thinning viscoelastic fluids. The geometry, named the optimized uniaxial and biaxial extensional rheometer (OUBER), is microfabricated with high precision by selective laser-induced etching of a fused-silica substrate. Employing a refractive index-matched viscous Newtonian fluid, microtomographic-particle image velocimetry enables the measurement of the flow field in a substantial volume around the stagnation point. The flow velocimetry, performed at low Reynolds number (<0.1), confirms the accurate imposition of the desired and predicted flows, with a pure extensional flow at an essentially uniform deformation rate being applied over a wide region around the stagnation point. In Part II of this paper [Haward et al., J. Rheol. 67, 1011–1030 (2023)], pressure drop measurements in the OUBER geometry are used to assess the uniaxial and biaxial extensional rheometry of dilute polymeric solutions, in comparison to measurements made in planar extension using an optimized-shape cross-slot extensional rheometer [OSCER, Haward et al., Phys. Rev. Lett. 109, 128301 (2012)].

Extensional rheometry of mobile fluids. Part II: Comparison between the uniaxial, planar, and biaxial extensional rheology of dilute polymer solutions using numerically optimized stagnation point microfluidic devices

Part I of this paper [Haward et al., J. Rheol. 67, 995–1009 (2023)] presents a three-dimensional microfluidic device (the optimized uniaxial and biaxial extensional rheometer, OUBER) for generating near-homogeneous uniaxial and biaxial elongational flows. Here, in Part II, the OUBER device is employed to examine the uniaxial and biaxial extensional rheology of model dilute polymer solutions, compared with measurements made under planar extension in the optimized-shape cross-slot extensional rheometer [OSCER, Haward et al. Phys. Rev. Lett. 109, 128301 (2012)]. In each case, micro-particle image velocimetry is used to measure the extension rate as a function of the imposed flow conditions, and excess pressure drop measurements enable estimation of the tensile stress difference generated in the fluid via a new analysis based on the macroscopic power balance for flow through each device. Based on this analysis, for the most dilute polymer sample tested, which is “ultradilute”, the extensional viscosity is well described by Peterlin’s finitely extensible nonlinear elastic dumbbell model. In this limit, the biaxial extensional viscosity at high Weissenberg numbers (Wi) is half that of the uniaxial and planar extensional viscosities. At higher polymer concentrations, although the fluids remain dilute, the experimental measurements deviate from the model predictions, which is attributed to the onset of intermolecular interactions as the polymer chains unravel in the extensional flows. Of practical significance (and fundamental interest), elastic instability occurs at a significantly lower Wi in uniaxial extensional flow than in either biaxial or planar extensional flow, thereby limiting the utility of this flow type for extensional viscosity measurement.

Numerical study of the effect of Péclet number on miscible viscous fingering with effective interfacial tension

Viscous fingering or Saffman–Taylor instability shows fingering interfacial patterns when a more mobile fluid displaces a less mobile one in porous media. The effective interfacial tension (EIT) is like capillary force, acting at the miscible interface on time scales shorter than interface relaxation. It has been numerically reported so far that the fingers are wider with EIT compared with those without EIT. A recent experiment observed finger widening with increasing flow rate in a miscible system with EIT, which is not observed in classical immiscible and miscible systems. In this study, we have numerically investigated the effect of $Pe$ (which corresponds to the injection flow rates in the experiment) on miscible viscous fingering with/without EIT. We have shown that the fingers are monotonically thinner with an increase in $Pe$ in the system without EIT, while finger widening with increasing $Pe$ is observed in the system with EIT. Furthermore, we have also examined a one-dimensional underlying concentration profile and EIT profile by using a one-dimensional diffusion–convection model because EIT is proportional to the squared concentration gradient. We have then shown that the concentration gradient is steeper and, thus, the EIT is larger as $Pe$ is larger. Therefore, this is the first numerical study that can theoretically verify finger widening with increasing flow rate, which occurs only in a miscible system with EIT to the extent of our targeting EIT values, and explain the mechanism by one-dimensional analysis.

Enrichment of free oil in alkaline lacustrine Fengcheng Formation in Mahu Sag

Estimation of free hydrocarbon quantities in tight formations where pore sizes are at the nano and micron size is very important to understand formation producibility. In the Mahu sag, the Fengcheng Formation is being considered as an important source rock. Although the importance, characteristics of the Fengcheng Formation in terms of controlling factors on the enrichment of free vs. adsorbed hydrocarbons in pore spaces is still not clear. In this study, 13 samples were collected from the Fengcheng Formation and a combination of analytical techniques: X-ray diffraction analysis (XRD), nitrogen gas adsorption, total organic content (TOC), and Rock Eval pyrolysis were employed to analyze the microstructures and geochemical properties of the samples. These analyses were performed on two groups: 1) intact samples and 2) when the soluble hydrocarbon were extracted from the samples. The pore surface area and pore volume were measured slightly higher in the latter group, which were around 2.12 and 1.23 times of the intact samples, respectively. Moreover, deconvolution of pore size distribution (PSD) curves demonstrated that soluble oil mainly exists in the pore phases: 1, 2, 3, and 4 with the mean pore diameter of 15, 35, 51, and 67 nm, respectively. Overall, the oil in the samples of the Fengcheng Formation can become enriched with mobile (vs. adsorbed) fluids if the quantities of the free generated oil and pore size, each exceeds 0.7 wt% and 10.94 nm, respectively. This study can help researchers deepen their understandings of oil mobility and the evaluation of formation producibility in reservoirs deposited in an alkaline lake sedimentary environment.

Micropore Throat Structure and Movable Fluid Characteristics of Chang 63 Tight Sandstone in Baibao Area of Ordos Basin

Tight sand is an important unconventional reservoir. Aiming at the problem of large unused reserves and the poor development effect of Chang 63 reservoir, this paper researches reunderstanding reservoir and evaluating unused reserves. Employing rock slice and scanning electron microscope (SEM), the experiment of low-field nuclear magnetic resonance (NMR), water-oil relative permeability experiment, reservoir space, movable fluid, and oil-water seepage characteristics was studied. The factors affecting NMR T 2 cutoff, controlling factors of movable fluids, and controlling factors of displacing efficiency in tight sandstone reservoirs are discussed. The study demonstrates that (1) the mean pore volume and permeability are 4.4% and 0.068 mD, respectively. The reservoir pertains to tight sandstone, mainly intergranular pore and dissolution pore, and the intercalated materials are mainly chlorite and illite. (2) The characteristic of the NMR T 2 spectrum has bimodal characteristics and can be subdivided into two classes: left peak dominant and right peak dominant. The mean value of mobile fluid saturation was 17.9%. (3) According to the relative permeability curve pattern, it is divided into four categories, and the mean bound water saturation is 29.9%. The average irreducible oil saturation was 40.6%. The mean oil flooding efficiency was 40.2%. (4) The better the pore-throat relationship, the lower the T 2 cutoff, the stronger ability of the fluid migration ability, and the higher of a percentage of active fluid. The percentage of active fluid in a low-permeability reservoir is affected by the reservoir’s physical property and pore structure.

Experimental analysis of the pore structure, relative permeability, and water flooding characteristics of the Yan'an Formation sandstone, southwestern Ordos Basin

The oil and gas potential of the Yan'an Formation in the Ordos Basin has yet to be fully tapped. In this study, the pore structure, mobile fluid saturation, and water flooding micro-mechanism of the Yan'an Formation sandstone are systematically studied through the application of a series of rock physics and fluid experiments. The results show that there is a good positive correlation between porosity and permeability, and the reservoirs are divided into types Ⅰ, Ⅱ, and Ⅲ. Mercury injection tests show that the average pore throat radius of the oil-bearing reservoir ranges from 1 to 7 μm. The displacement pressure of the Yan'an Formation is also relatively low, and it decreases from 0.1 MPa to 0.01 MPa as the rock porosity increases from 11% to 18%. NMR tests show that small (diameter <0.5 μm) and medium pores (diameter ranging from 0.5 to 2.5 μm) are predominant in the reservoir. Different types of reservoirs have different characteristics of relative permeability curve. In addition, when the average oil recovery rate is less than 1 ml/min, the oil displacement efficiency increases faster. However, when the average oil recovery rate is between 1–3.5 ml/min, the oil displacement efficiency is maintained at around 27%–30%. Physical properties of the reservoir, pore-throat structure, experimental pressure difference, and pore volume injected — all have significant effects on oil displacement efficiency. For Type Ⅰ and Type Ⅱ reservoirs, the increase of the pore volume injected has a significant effect on oil displacement efficiency. However, for Type Ⅲ reservoirs, the change of pore volume injected has insignificant effect on oil displacement efficiency. This study provides a reference for the formulation of estimated ultimate recovery (EUR) measures for similar sandstone reservoirs.