Pore Throat Size Distribution Research Articles

Critical pressure (Pc) and critical temperature (Tc) of Midra shale

AbstractThe critical pressure (Pc) and critical temperature (Tc) of shale gas depend on the characteristic pore size because of the importance of fluid–rock interactions in the matrix. This size dependency is neglected in highly permeable formations, where gas composition is only implemented because the fluid–fluid interactions are dominant. This study determines the critical properties by accounting for the characteristic pore size in the shale matrix and gas composition. The analyzed components are carbon dioxide, ethane, methane, n-butane, nitrogen, pentane, and propane. It shows that the bulk properties overestimate the actual critical properties. The overestimation varies between 15 and 26% in a uniform 5 nm conduit with a circular cross section, and it increases nonlinearly when decreasing the conduit size. Overestimation versus size is presented to provide a convenient tool for correcting the existing data. This study also determines the critical properties of Midra shale by accounting for the pore-throat size and pore-body size distributions. The former distribution is based on the mercury injection capillary pressure measurements of eight samples, whereas the latter is based on the nitrogen adsorption measurements of six samples. This study indicates that common bulk properties overestimate the critical properties of the studied shale between 5 and 22%. The results have applications in characterizing multiphase transport in shale gas reservoirs.

Augmenting X-ray micro-CT data with MICP data for high resolution pore-scale simulations a of flow properties of carbonate rocks

Pore-scale modeling is essential in understanding and predicting flow and transport properties of rocks. Generally, pore-scale modeling is dependent on imaging technologies such as Micro Computed Tomography (micro-CT), which provides visual confirmation into the pore microstructures of rocks at a representative scale. However, this technique is limited in the ability to provide high resolution images showing the pore-throats connecting pore bodies. Pore scale simulations of flow and transport properties of rocks are generally done on a single 3D pore microstructure image. As such, the simulated properties are only representative of the simulated pore-scale rock volume. These are the technological and computational limitations which we address here by using a stochastic pore-scale simulation approach. This approach consists of constructing hundreds of 3D pore microstructures of the same pore size distribution and overall porosity but different pore connectivity. The construction of the 3D pore microstructures incorporates the use of Mercury Injection Capillary Pressure (MICP) data to account for pore throat size distribution, and micro-CT images to account for pore body size distribution. The approach requires a small micro-CT image volume (7-19 mm3) to reveal key pore microstructural features that control flow and transport properties of highly heterogeneous rocks at the core-scale. Four carbonate rock samples were used to test the proposed approach. Permeability calculations from the introduced approach were validated by comparing laboratory measured permeability of rock cores and permeability estimated using five well-known core-scale empirical model equations. The results show that accounting for the stochastic connectivity of pores results in a probabilistic distribution of flow properties which can be used to upscale pore-scale simulated flow properties to the core-scale. The use of the introduced stochastic pore-scale simulation approach is more beneficial when there is a higher degree of heterogeneity in pore size distribution. This is shown to be the case with permeability and hydraulic tortuosity which are key controls of flow and transport processes in rocks.

A percolation model of unsaturated hydraulic conductivity using three-parameter Weibull distribution

Accurate estimation of unsaturated hydraulic conductivity, K(Sw), is crucial for modeling water and solute transport in variably-saturated soils. In this study, a new model for the estimation of K(Sw) based on percolation theory and critical path analysis is presented, in which the pore-throat size distribution is described by the three-parameter Weibull probability density function. To evaluate the performance of the proposed K(Sw) model, two datasets including more than three hundred samples are analyzed. The first dataset includes 240 pore-network simulations, while the second dataset consists of 101 soil samples from the UNSODA database. For the pore-network simulations, for which both pore-throat size distributions and capillary pressure curves are available, we estimate K(Sw) from the capillary pressure curve with RMSLE = 0.54 slightly better than the estimations obtained from the pore-throat size distribution with RMSLE = 0.6. For the soil samples, since only the capillary pressure curve is measured, we estimate K(Sw) from the capillary pressure curve and evaluate three previously proposed approaches for determining the exponent, α, in Poiseuille's law. We find that RMSLE = 0.98 for α = 3, RMSLE = 0.87 for α = 2(4 − D) − (3 − D)/(2D − 3), and RMSLE = 1.06 for α = 4 − 0.74D, in which D is the fractal dimension characterizing the pore space. Comparing the results with previous studies in which the power-law probability density function was used to characterize capillary pressure curve and pore sizes shows that the proposed three-parameter Weibull distribution, in conjunction with the CPA analysis, may more accurately estimate K(Sw) for a wide variety of soils ranging from very fine to very coarse textures.

Rock type based-estimation of pore throat size distribution in carbonate reservoirs using integrated analysis of well logs and seismic attributes

Rock type based-estimation of pore throat size distribution in carbonate reservoirs using integrated analysis of well logs and seismic attributes

Altering shale permeability by cold shock

The matrix permeability of shale is on the order of nanodarcy (nD), and hydrocarbon recovery from it is economical only after hydraulic fracturing. Another fracturing technique, which is often overlooked, is cryogenic fracturing. This study determines the effects of cold shock on shale permeability by focusing on the sub-100-nm pore throats that control access to a significant fraction of the pore space in the matrix. We extracted shale samples, heated them to mimic various formation burial depths, and shocked them in liquid nitrogen. Subsequently, we measured their capillary pressures. This study presents a conceptual model to shed light on the heterogeneous deformations at a sub-100-μm scale. Also, it uses a network modeling approach to determine the permeability enhancement based on the pore-throat size distributions obtained from the capillary pressure measurements. It demonstrates that cold shock enhances permeability by 20%, significantly lower than the typical values reported in the literature where the effects of subsurface temperature have been neglected. The enhancement depends non-monotonically on the temperature difference applied. Moreover, the results indicate that there may be an optimal scenario to maximize the enhancement that can only be determined experimentally. The reason for the incapability of the purely analytical approach is also discussed.

Experimental evaluation of cement integrity on exposure to supercritical CO2 using NMR: Application to geostorage

Carbon sequestration is one approach to achieve carbon dioxide reduction in the atmosphere. Underground storage of CO2 requires an understanding of geochemical and geomechanical alteration on the integrity of the injection wellbore. In this study, we investigate the reactivity of supercritical CO2 (scCO2) at 65 °C and 20.7 MPa on Portland class G cement plugs used for oil and gas well completion, for exposure of up to 5 weeks.For nanoporous media, such as cement, diffusion is believed to be the major mass transport mechanism (Perkins and Johnston, 1963) [1]. To quantify the extent of the alteration (mineralization/dissolution) on fluid diffusivity through the cement matrix, a novel approach based on Nuclear Magnetic Resonance (NMR) is employed to derive diffusional tortuosity. Comparing pre- and post-scCO2 exposure, deuterium oxide (D2O) intrusion profiles allow us to determine flow path alteration in the cement plugs. Additional characterizations include Fourier Transform Infrared Spectroscopy (FTIR) to observe the change in cement composition, micro X-ray Computed Tomography (μXCT), along with Scanning Electron Microscopy (SEM) and Energy Dispersive Spectroscopy (EDS) to determine invasion extent and microstructure modifications, Mercury Injection Capillary Pressure (MICP) for pore throat size distribution and BET N2 isothermal adsorption for surface area and pore size distribution.The results show that exposure to scCO2 promotes both calcium carbonate precipitation and dissolution simultaneously. However, the alteration is pore size dependent. After 5 weeks of exposure, there is evidence of carbonate dissolution in smaller pores (<30 nm) and both precipitation and dissolution in larger pores (30–200 nm). The alteration of the cement plugs leads to a decrease in the storage and connectivity of the cement. The porosity decreased from 37 to 33 % in 5 weeks, while the matrix tortuosity increased by 6 and 3 times after 2 and 5 weeks of exposure, respectively. The experimental results imply that the cement carbonate precipitation can limit the migration of scCO2 through the cement matrix.This work also highlights an alternative laboratory approach to quantify the risk associated with scCO2 exposure on Portland cement using NMR-derived tortuosity.

Application of Young-Laplace with size-dependent contact angle and interfacial tension in shale

Shale has been studied extensively since its hydrocarbon recovery became economical, but there are still uncertainties in the applicability of existing models for characterizing its transport properties. A relevant example is the Young-Laplace equation (YL) for interpreting capillary pressure measurements. This study implements its contact angle and interfacial tension as functions of pore throat size to extend its applicability to shale. This study shows a threshold throat size below which implementing size-dependent (actual) properties is crucial. The threshold size is close to 10 nm. The error of the common approach (fixed contact angle and interfacial tension) increases from 5% to 20% where the throat size decreases from 10 nm to 2 nm.This study applies the actual properties to determine the pore throat size distributions of two shale samples. Implementing actual properties influenced the common interpretations from 20% to 50% of the pore volumes of the samples. This study also quantifies the error of the common approach in calculating the pore-throat size. More importantly, it proposes a simple relation that provides a convenient tool for modifying the existing data to determine the actual pore throat size. The results and the simple relation have applications in characterizing the transport properties of shale formations.

Simulating reservoir capillary pressure curves using image processing and classification machine learning algorithms applied to petrographic thin sections

Reservoir rock porosity and capillary pressure data are fundamental parameters to understand the physical properties of rocks. Porosity, which shows the rock's void fraction to its bulk volume, can be measured by s techniques such as He-porosimetry, mercury injection capillary pressure (MICP) analysis, point counting analysis, and image analysis. Image analysis has for many years been used to obtain relevant data from digital microscopic images. Segmentation of images is an important technique used to partition an image into distinctive components to extract useful data. When an image is segmented, it is simplified, making it easier to understand its component parts. In this research, two-dimensional (2D) rock thin section image processing is initially applied to determine porosity. To achieve this, the K-means clustering algorithm was used to automatically segment and measure the digital rock porosity. In this regard, one hundred and nine samples were selected from approximately one thousand 2D petrographic thin-section images of the Dorood Oilfield reservoir rocks and were digitally processed and evaluated. The porosity values estimated from the image analysis agree with the porosity derived from whole-rock core analysis with a correlation coefficient of 67 %. Moreover, petrographic studies distinguished five microfacies, which relate to lagoon, shoal, mid and outer ramp depositional environments associated with a carbonate homoclinal ramp. In addition. three distinct Hydraulic Flow Units(HFUs) were determined based on K-means clustering by applying the Elbow method. Based on those clusters, permeability was estimated from HFU porosity distributions with high correlation coefficient (R = 90 %). Pore-throat size distributions and Pc curves were then estimated from thin-section image analysis based on the Pittman equations for different mercury saturation percentages. The estimated Pc curves derived from image analyses show an acceptable correlation with SCAL-derived Pc curves. Comparison between RT/HFU and depositional settings show that RT1/HFU1 belongs to the lagoon and outer ramp depositional settings, RT2/HFU2 belongs to shoal and mid carbonate ramp environments and RT3/HFU3 belongs to a shoal environment.

Pore network simulations of thin porous medium characterization by evapoporometry

Evapoporometry is a technique aiming at characterizing the pore size distribution of a porous medium from evaporated mass measurements. In this work, evapoporometry is studied from numerical simulations on model pore networks allowing a detailed analysis of the underlying physics at play in the technique. Simulations indicate that both the pore body size and throat size distributions can be characterized and pinpoint the need of a very accurate determination of the evaporation rate. This is notably illustrated by varying the evaporated mass acquisition time step. Evapoporometry and liquid-liquid displacement porometry techniques are discussed comparatively in relation with experimental works reporting differences between the pore size distributions identified through both techniques.

Study of pore-throat structure characteristics and fluid mobility of Chang 7 tight sandstone reservoir in Jiyuan area, Ordos Basin

Abstract Quantitative studies of the pore-throat structure (PTS) characteristics of tight sandstone reservoirs and their effects on fluid mobility were proposed to accurately evaluate reservoir quality and predict sweet spots for tight oil exploration. This study conducted high-pressure mercury injection (HPMI) and nuclear magnetic resonance (NMR) experiments on 14 tight sandstone samples from the Chang 7 member of the Yanchang Formation in the Jiyuan area of the Ordos Basin. The HPMI was combined with the piecewise fitting method to transform the NMR movable fluid transverse relaxation time (T 2) spectrum and quantitatively characterize the PTS characteristics and the full pore-throat size distribution (PSD). Then, movable fluid effective porosity (MFEP) was proposed to quantitatively evaluate the fluid mobility of tight sandstone reservoirs and systematically elucidate its main controlling factors. The results showed that the PTS could be divided into four types (I, II, III, and IV), which showed gradual decreases in average pore-throat radius (R a), continuous increases in the total fractal dimension (D t), and successive deterioration of reservoir fluid mobility and percolation capacity. Moreover, the full PSD (0.001–10 μm) showed unimodal and multi-fractal characteristics. According to the Swanson parameter (r apex), the reservoir space types can be divided into small and large pore-throat and the corresponding fractal dimension has a relationship where D 1 &lt; D 2. Large pore-throat had higher permeability contribution and pore-throat heterogeneity but a lower development degree and MFEP than small pore-throat, which had a relatively uniform and regular PSD and represented the primary location of movable fluids. Moreover, the development degree and heterogeneity of small pore throat controlled the flowability of reservoir fluids. MFEP can overcome the constraints of tiny throats and clay minerals on movable fluid, quantify the movable fluid content occupying the effective reservoir space, and accurately evaluate the reservoir fluid mobility. The combination and development of various pore-throat sizes and types in tight sandstone reservoirs results in different PTS characteristics, whereas differences in the mineral composition and content of reservoirs aggravate PTS heterogeneity, which is the main factor controlling the fluid mobility.

Integrated approach for closure correction of mercury injection capillary pressure measurements

Closure correction is a key requirement for a reliable petrophysical evaluation using mercury injection capillary pressure (MICP). The available correction methods rely on identifying deflection points on capillary pressure curves which is often difficult and subjective and requires additional information for macropores that control the closure effect. The proposed approach in this study is novel in terms of integrating the pore-throat size distribution and incremental mercury intrusion data from MICP with porosity from routine core analysis as well as 2D visualization and watershed segmentation from thin section images. The proposed approach allows for lowering the uncertainty in closure correction by incorporating the pore-throat sizes and segmented porosity of the macropores from thin-section images. We tested this approach on samples of the Austin Chalk and Indiana Limestone. The effects of sample size and equilibrium time were also investigated. Identifying the closure pressure is demonstrated to be more difficult on small crushed samples due to the impact of mercury conformance associated with the increased specific surface area. The impact of increasing the equilibrium time is insignificant on relatively permeable Austin Chalk. However, for the tighter Indiana Limestone, conducting fast MICP experiments results in inconsistent and misleading results. We used rate-equilibrium testing at 0.001 μL/g to generate initial-residual curves and evaluate pores accessibility. We show that Austin Chalk pores are fully intruded below 10,000 psia whereas Indiana Limestone requires higher pressure to invade all the pore systems. This study emphasizes the importance of integrating additional information with the MICP data for the closure correction of complex pore systems.

Experimental Study on EOR in Shale Oil Cores during Associated Gasflooding: A Case Study from Yanchang Formation, Ordos Basin

Summary A significant amount of associated gas has been produced from shale oil reservoirs in the Ordos Basin, northern China, in recent years, which has provided an opportunity for using low-cost, associated gas in enhanced oil recovery (EOR) projects. However, there are few other reports of EOR projects in shale oil reservoirs using associated gas, and a quantitative evaluation of the technique is needed. Therefore, we conducted associated gas and waterflooding experiments in shale oil samples at constant and gradually increasing injection pressure while monitoring the spatial distribution of movable and residual oil by means of nuclear magnetic resonance (NMR) technology. Before the injection experiments, we performed mercury intrusion tests and measured the NMR transverse relaxation time, T2, of fully saturated samples to characterize the pore-throat size distribution of rock samples. Furthermore, we established a novel and robust mathematical model based on a fractal description of the pore space and a capillary tube model to determine the lower limit of the pore radius of movable oil, rc, during gas- and waterflooding. We observed that the oil recovery factor at a low injection pressure (i.e., 0.6 MPa) during the associated gasflooding was lower than that during waterflooding under both constant pressure injection mode and gradually increasing pressure injection mode. However, the performance of associated gasflooding was greatly improved by increasing the injection pressure. High injection pressure indeed produced a higher oil recovery factor, thinner residual oil film thickness, and smaller rc during associated gasflooding than during waterflooding under both injection modes. These differences in behavior appear to be linked to dissimilarities in flooding mechanisms at high and low injection pressures. Our main conclusion is that associated gasflooding at high injection pressure (i.e., 6 MPa) has a better potential for enhancing the oil recovery factor than waterflooding in shale oil reservoirs.

Full Scale of Pore-Throat Size Distribution and Its Control on Petrophysical Properties of the Shanxi Formation Tight Sandstone Reservoir in the North Ordos Basin, China

Abstract Pore-throat size distribution is a key factor controlling the storage capacity and percolation potential of the tight sandstone reservoirs. However, the complexity and strong heterogeneity make it difficult to investigate the pore structure of tight sandstone reservoirs by using conventional methods. In this study, integrated methods of casting thin section, scanning electron microscopy, high-pressure mercury intrusion (HPMI), and constant-pressure mercury intrusion (CPMI) were conducted to study the pore-throat size distribution and its effect on petrophysical properties of the Shanxi Formation tight sandstones in the northern Ordos Basin (China). Results show that pore types of the Shanxi tight sandstone reservoirs include intergranular pores, dissolution pores, intercrystalline micropores, and microfracture, while the throats are dominated by sheet-like and tube-shaped throats. The HPMI-derived pore-throat size ranges from 0.006 to 10 μm, and the pore-throats with a radius larger than 10 μm were less frequent. The pore body size obtained from CPMI shows similar characteristics with radii ranging from 100 to 525 μm, while the throat size varies greatly with radii ranging from 0.5 to 11.5 µm, resulting in a wide range of pore-throat radius ratio. The full range of pore size distribution curves obtained from the combination of HPMI and CPMI displays multimodal with radii ranging from 0.006 to 525 µm. Permeability of the tight sandstone reservoirs is primarily controlled by relatively larger pore throats with small proportions, and the permeability decreases as the proportions of smaller pore-throats increase. The pervading nanopores in the tight gas sandstone reservoirs contribute little to the permeability but play an important role in the reservoir storage capacity. A new empirical equation obtained by multiple regression indicates that r15 (pore-throat size corresponding to 15% mercury saturation) is the best permeability estimator for tight gas sandstone reservoirs, which yields the highest correlation coefficient of 0.9629 with permeability and porosity.

Pore Distribution Characteristics of Different Lithofacies Shales: Evidence from Scanning Electron Microscopy

To disclose the pore distribution characteristics of different lithofacies lacustrine shales, ten samples collected from the Shahejie Formation, Dongying Sag, Bohai Bay Basin, China, were examined using argon ion beam milling–scanning electron microscopy (SEM). A quantitative method was adopted to characterize shale pore distributions based on the SEM images. Mercury intrusion capillary pressure was employed to determine the pore throat size distributions of the shales. The SEM images indicated that in shale reservoirs, interparticle pores at the edges of brittle particles and intraparticle pores in clay mineral aggregates primarily contribute to the reservoir spaces and that in calcite-rich shales, dissolution pores provide secondary reservoir space. Among the morphologies of dissolution, intraparticle, and interparticle pores, the morphology of the dissolution pores is the simplest, followed by those of intraparticle and interparticle pores in that order. Clay and felsic minerals primarily control the shale pore sizes and the larger the clay mineral content in the shales, the smaller their pore size; the felsic minerals demonstrate the opposite behavior. The image-based point counting data indicate that shale pore sizes are mostly between 20 nm and 2 μm. In contrast, most pore throats are less than 20 nm in diameter, implying that the pores in the nanometer to micrometer scales are connected by tiny throats. Among the four lithofacies shales, felsic-rich shales are favorable for shale oil accumulation and seepage because of their large pore sizes and throats their ability to form intercalated shale oil adjacent to organic-rich shales. Calcareous shales with a large number of dissolution pores and a large content of organic matter could produce self-generation and self-storage matrix shale oil and would typically develop fractures, thereby creating a seepage channel for shale oil. This study presents the micro-distributions of different lithofacies of shale pores, which would help in understanding the occurrence and seepage of oil in shale reservoirs.

Pore throat structure heterogeneity and its effect on gas-phase seepage capacity in tight sandstone reservoirs: A case study from the Triassic Yanchang Formation, Ordos Basin

The microscopic heterogeneity of pore-throat structures in tight sandstone is a crucial parameter for understanding the transport mechanism of fluid flow. In this work, we firstly developed the new procedure to characterize the pore size distribution (PSD) and throat size distribution (TSD) by combining the nuclear magnetic resonance (NMR), cast thin section (CTS), and constant-rate mercury injection (CRMI) tests, and used the permeability estimated model to verify the full-scale PSD and TSD. Then, we respectively analyzed the fractal feature of the pore and throat, and characterized the heterogeneity of pores and throats. Finally, we elaborated the effect of the pore and throat heterogeneity on the gas-phase seepage capacity base on the analysis of the simple capillary tube model and gas-flooding experiment. The results showed that (1) The PSD and TSD of the tight sandstone sample ranged from 0.01 to 10 μm and from 0.1 to 57 μm, respectively, mainly contributed by the micropores and mesopores. Meanwhile, the permeability estimated by the PSD and TSD was consistent with the experimental permeability, and relative error was lower than 8%. (2) The PSD and TSD exhibited multifractal characteristics, and singularity strength range, Δα, could be used as the indicator for characterizing the heterogeneity of pore and throat. Furthermore, the throat of the sample showed stronger heterogeneity than that the pore. (3) The throats played an important role for the fluid transport in the tight sandstone, and the effect of the throat heterogeneity on the gas-phase seepage capacity was different under the lower and higher injection pressure. The macropores and micropores maybe respectively become the preferential migration pathways at the lower and higher injection pressure. In the end, the identification plate was established in our paper, and could be described the relationship among the throat heterogeneity, injection pressure, permeability and flow path of the gas phase in the tight sandstone.

Controlling effect of pore-throat structures on tight oil accumulation effectiveness in the upper Cretaceous Qingshankou formation, Songliao Basin

The Gaotaizi reservoir in the Qingshankou Formation, northern Songliao Basin is one of the most potential tight oil targets in China and it is underlain directly by the OM-rich shales of the Qingshankou Formation. Previous studies indicated a strong oil-bearing heterogeneity in the Gaotaizi reservoir, while the relationship between pore-throat system and oil-bearing property is poorly understood. Thin section, Soxhlet extraction, MICP, fluid inclusion PVTX simulation and basin modelling were combined to investigate the pore-throat structure, and its effect on oil-bearing abundance and the tight oil accumulation effectiveness. Three pore-throat structures in the Gaotaizi reservoir were identified. The pore-throat size distribution (PSD), pore-throat configuration, and the corresponding physical properties became worser from Type I to Type III, as well as the pore types. A close relationship between pore-throat structures and sedimentary facies was established. Type I and II were dominated in mouth bar sand, while Type II, and Type III were mainly distributed in distal sandbars and sheet sand, respectively. The fluid properties and oil-bearing grades in the Gaotaizi tight sandstones were significantly controlled by the pore-throat structures. There were few fluids produced from the tight sandstones with Type III pore-throat structures, whose pore-throat size was almost half of that in tight sandstones with oil production. The dynamic model and ratio of pore containing oil (RPO) parameter were proposed. The residual pressure difference between the source rock and reservoir was 4.1 MPa, and the corresponding lower limit of pore-throat radius for tight oil accumulation was around 180 nm considering the limited buoyancy. Under the same driving force, the RPO of the Type I, II, III pore-throat structure reservoir was 74.4%, 58.0%, 23.3%, respectively, caused by pore-throat structure differences. It shows that an optimal tight oil “sweet spot” formed in the Type I reservoir, and favourable tight oil zones typically developed in the Type II reservoir, whereas only poor tight oil or dry zones developed in the Type III reservoir. This research improves the understanding of continental tight oil enrichment mechanism and provides a reference for optimizing favourable area of tight oil exploration.

3D confocal imaging methodology optimized for pore space characterization of carbonates

Pore space characterization of carbonate materials is of fundamental importance to a wide range of earth science and engineering applications. In this study, we show how confocal microscopy can be used as a reliable tool to visualize and quantify the heterogeneous pore space in carbonate materials. In confocal imagery, the quality of pore space images is controlled by various factors including the choice of fluorophore, objective lens, and medium of imaging. Our experiments demonstrated that there is no “fit-for-all” dye. The red dye provides more depth of investigation, while the blue dye can capture large pores more efficiently. Our investigation indicated that quantitative pore space description from confocal images can be significantly influenced by imaging artifacts associated with imaging the heterogeneous and complex pore space in carbonates. By applying image deconvolution, we mitigated the confocal imaging artifacts (e.g., spherical aberration, and resolution deviation), and extracted a more reliable 3D pore-network model of the carbonate sample. We employed our optimized confocal imaging protocol to visualize and quantify macro- and micropores, and more importantly their interconnectivity within an Indiana limestone (IL) sample. The computed pore-throat size distribution (PSD) from the 3D confocal images was able to capture the inherent bimodal distribution of IL.

Petrophysical properties of representative geological rocks encountered in carbon storage and utilization

This study evaluates petrophysical properties (especially porosity, permeability, tortuosity, and diffusivity) of representative geological rocks in the context of injectivity, storage space, and caprock integrity for effective utilization and long-term storage of carbon dioxide. A total of 10 geological rocks were selected as representative storage media for consideration as saline aquifers & depleted oil and gas reservoirs (sandstones and carbonates), basalts, and cap rocks, as well as utilization in organic-rich shale and coal seams. An integrated suite of laboratory tests, including liquid immersion porosimetry, gas expansion porosimetry, grain size distribution, mercury intrusion porosimetry, and gas diffusion, were performed on these various rock samples. The results exhibit a disparity of petrophysical properties among two broad groups of rocks: rocks selected for possible storage of CO2 have porosities of ∼10-25%, permeabilities of ∼10−16-10−13 m2, μm-sized pore-throat size distribution, and mostly good pore connectivity; in contrast, the potential caprocks have porosities of ∼0.5-5%, permeabilities of ∼10−20-10−18 m2, pore throat sizes of <50 nm, and probably poorly connected pore networks. An understanding of the measured facets of pore structure and contribution of fractures is also critical in the context of different testing principles and data interpretation of petrophysical analyses, as well as observational scales in the laboratory and field, and therefore reliable confidence of CO2 storage and utilization performance. Our work further illustrates the controlling influence of grain size distribution and geological processes on pore size distribution and pore connectivity for a wide range of rock types and lithologies, and particularly presents the extent and behavior of CO2 gas diffusion with a custom-designed apparatus for a holistic understanding of various petrophysical attributes of widely different geological rocks.

Insights into the Effects of Pore Structure, Time Scale, and Injection Scenarios on Pore-Filling Sequence and Oil Recovery by Low-Salinity Waterflooding Using a Mechanistic DLVO-Based Pore-Scale Model

Summary Despite the proven advantage of the low-salinity waterflooding (LSWF) technique, mechanistic understanding of the underlying phenomena at pore-scale remains uncertain. Hence, the corresponding models have limited predictability. In this study, wettability alteration via electrical double-layer (EDL) expansion is captured in a pore-scale model using a multispecies, multiphase computational fluid dynamics simulator. A combination of a pore-doublet and snap-off model is used to evaluate the low-salinity effect (LSE) in two geometries with different pore-throat size distributions. Contact angle is calculated intrinsically within the model using the concept of disjoining pressure through the implementation of the Derjaguin-Landau-Verwey-Overbeek (DLVO) theory and augmented Young-Laplace equation. The results illustrate that even in a simple pore structure, various pore-filling sequences and recoveries are obtained based on the pore geometrical factors, time effects, backward mixing, and injection scenarios. Secondary LSWF results in higher ultimate oil recovery since both small and large pores are accessible to flow and breakthrough is delayed, giving more time for more efficient displacement. Regarding the pore-throat geometry, the case with larger pores connected via larger throats generally exhibits higher ultimate recoveries. However, the geometry with larger pores connected by small throats results in higher incremental recovery via tertiary LSWF. Moreover, an optimal time scale exists in secondary LSWF due to the snap-off phenomenon, while faster LSE results in higher recovery in tertiary mode. The proposed model is capable of mechanistically capturing and predicting LSE and its subsequent flow dynamics, which exhibits a higher recovery factor by LSWF compared to the commonly used linear wettability model. Thus, this approach improves the predictive capability of the previous models as it does not require contact angle data and arbitrary interpolation schemes.

Effects of pore size and pore connectivity on trapped gas saturation

Abstract Trapped or residual air (or gas) is known to affect the multiphase hydraulic properties of both soils and rocks. Trapped air is known to impact many vadose zone hydrologic applications such as infiltration and flow in the capillary fringe, but is also a major issue affecting recoverable oil reserves. Although many studies have focused on the relationship between porosity and trapped gas saturation (S gt ) in sandstones, far fewer studies have been carried out for carbonate rocks. This work aims to analyze the influence of porous media properties on trapped gas saturation in carbonate rocks. For this we used thirteen Indiana Limestone and Silurian dolomite rock samples from the USA, and several coquinas from the Morro do Chaves formation in Brazil. Pore size distributions were obtained for all samples using Nuclear Magnetic Resonance (NMR), and Mercury Injection Capillary Pressure (MICP) data from three of the samples to determine their pore throat size distributions. Additionally, 3D microtomography (microCT) images were used to quantify macropore profiles and pore connectivities. Results indicate a lower capacity of gas trapping in carbonate rocks in which micro- and mesopores predominate. Results also indicate that in carbonate rocks, pore size exerts a greater influence on the ability of gas trapping compared to pore connectivity, so that rocks with a predominance of macropores have greater capacity for gas trapping, even when the macropores are well interconnected. These findings show that pore characteristics very much affect the processes governing gas trapping in carbonate rocks, and indirectly the multiphase hydraulic properties and recoverable oil reserves of carbonate rock reservoirs.