Irreducible Saturation Research Articles

A coupled fractal model for predicting the relative permeability of rocks considering both irreducible fluid saturation and stress effects

The relative permeability of rocks is an essential parameter for evaluating two-phase flow characteristics and plays an important role in engineering fields such as resource exploitation. To this end, a mathematical model for predicting relative permeability was first developed based on an equivalent capillary model and fractal theory. The proposed model considers the irreducible fluid saturation under stress and quantifies the influence of the pore structure characteristics on the relative permeability. This model was then compared with relevant experimental data and existing theoretical expressions to verify its validity. Finally, the factors affecting the two-phase seepage characteristics were discussed. The results show that the irreducible fluid saturation is intimately connected to the fractal dimensions, pore size, fluid viscosity, pressure drop gradient, and elastic modulus. Fluid properties and pore structure characteristics are the main factors affecting relative permeability. The wetting phase relative permeability is more sensitive to pore structure and irreducible fluids. Increased effective stress increases irreducible fluid saturation, reduces two-phase flow capacity, and significantly decreases the relative permeability of wetting phase fluids. Increased elastic modulus and Poisson's ratio decrease the irreducible fluid content under stress and increase the permeability.

Relative permeability evolution with thermo-poromechanical process during N2 and scCO2 injection in brine saturated Deadwood sandstone from Aquistore

This study delves into the intrinsic and multiphase flow properties, specifically steady-state drainage relative permeability, of a subsurface Deadwood sandstone from the Aquistore CO2 storage site in Canada. Consecutive core-flooding experiments were conducted utilizing N2- and scCO2-brine pairs across a broad range of temperatures (20–70 °C) and isotropic effective stress (0–30 MPa). Moreover, we monitored crack initiation and propagation of the sandstone during uniaxial loading at an elevated temperature using an integrated approach that combines microCT scanning with an in-situ heating/loading test. Our findings reveal a 54 % decrease and a 3 % increase in the absolute permeability of the sandstone through isothermal compaction followed by thermal expansion processes, respectively. Elevating the temperature from 20 °C to 70 °C results in a systematic 24 % increase in irreducible brine saturation and nearly doubles the end-point N2 mobility, indicating an increased tendency of the rock surface towards the brine phase with temperature. Substituting N2 with scCO2 demonstrates a leftward shift in relative permeability and a decrease in irreducible brine saturation (from 0.36 to 0.31), consistent with low interfacial tension and the de-wetting effect during cyclic scCO2-brine injections. Micro-CT image analysis reveals micro-crack initiation at 10 MPa stress and 70 °C temperature, suggesting that a mixed impact of induced cracks, dynamic wettability, and thermo-mechanical deformation is responsible for the substantial increase in well injectivity over time in Aquistore. This novel experimental program provides indispensable insight into thermo-poromechanical and wettability controls on multiphase flow at the Aquistore injection site in Canada, with potential applicability to similar scenarios globally.

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.

An Analytical Relative Permeability Model Considering Flow Path Structural Characteristics for Gas-Liquid Two-Phase Flow in Shale Fracture

Summary Relative permeability models are essential in describing the multiphase fluid flow in reservoir rocks. Literature work has shown that the existing theoretical models of relative permeability cannot perfectly describe the two-phase flow experimental data in fractures because those models are mostly developed for porous media (such as sandstone) or proposed without fully taking the specific characteristics of two-phase flow into consideration. In this paper, we propose a theoretical two-phase flow relative permeability model based on the tortuous flow channels, considering the structural characteristics of two-phase flow in the fractures. This model considers that the gas and liquid flow through different channels of different shapes and sizes at the same time. The formula for two-phase relative permeability was derived from cubic law in fracture and Darcy’s law, with the influence of the slip effect of the gas phase also considered. The results from different models were compared using several series of experimental data. The model proposed in this paper has a better fit than the others for the raw experimental data. This study demonstrates that it is crucial to take the flow paths and distribution of the two phases into consideration to model the two-phase flow in fracture accurately. This work also found that the tortuosity of the gas channel at the irreducible liquid saturation has a negative effect on gas relative permeability but positive to liquid relative permeability. Moreover, the model demonstrates that the decrease in aperture leads to an increase in the gas relative permeability due to gas slippage, while the impact of gas slippage reduces under high pressure.

Effect of Confining Pressure on CO2-Brine Relative Permeability Characteristics of Sandstone in Ordos Basin

CO2-brine relative permeability significantly impacts CO2 injection and is a key parameter for carbon dioxide storage simulation in saline aquifers. In the study of relative permeability, factors such as temperature, pressure, and reservoir rock physical properties play a crucial role. To better understand the impact of confining pressure on the CO2-brine relative permeability characteristics of sandstone in the Ordos Basin, five sets of CO2-brine relative permeability data were obtained through unsteady-state displacement tests conducted at various confining pressures ranging from 12 to 20 MPa. The research findings indicate that with an increase in confining pressure there is a slight decrease in irreducible brine saturation. Furthermore, the CO2 relative permeability in the irreducible brine state decreased by 57% as the pressure increased from 12 MPa to 20 MPa. The study demonstrates notable differences in the CO2-brine relative permeability curves under varying confining pressure conditions. As the confining pressure increases, the CO2 relative permeability curve decreases, while the brine relative permeability increases. The change in brine relative permeability is not as pronounced as that of CO2. These experimental results offer essential support for subsequent numerical calculations and practical applications in engineering. Experimental research holds significant importance in the assessment of storage potential and the prediction of the evolutionary patterns of CO2 migration.

Fundamentals-Based Alternative Addresses Issue With Three-Phase Permeability Model

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 205883, “Issue With Stone II Three-Phase Permeability Model and a Novel Robust Fundamentals-Based Alternative to It,” by Subodh Gupta, SPE, Heretech Energy. The paper has not been peer reviewed. _ The objective of this paper is to present a fundamentals-based, three-phase flow model consistent with observation that avoids the pitfalls of conventional models. Though the use of the Stone II model is very popular for three-phase flow across the industry, one issue in the context of gravity drainage is how it appears counterintuitively to limit the flow of oil when water is present near its irreducible saturation. The novelty of the work presented in the complete paper is in the development of a model based on fundamentals of flow in fine channels that better explains observed results in the context of flow in porous media. Problem Definition Residual oil saturation (So) from retrieved cores from oil-drained chambers of steam-assisted gravity drainage (SAGD) reservoirs invariably shows values as low as 1 or 2%, whereas reservoir simulations using Stone II-based relative permeabilities (an industrywide favorite) predict significantly higher numbers (14–18%). In previous work, the author and others, in an attempt to remedy the situation, extended the oil-phase relative permeability in the presence of the water phase (krow) and oil-phase relative permeability in the presence of the gas phase (krog) curves all the way to water and gas saturation values less than unity; however, they discovered that, in the presence of water saturation (Sw) near the irreducible water saturation (Swi), the use of the Stone II formula for oil relative permeability still resulted in high residual So. Correct estimation of residual oil-phase saturation is even more important for solvent/steam mixed thermal recovery processes such as solvent-aided processes, where a small amount of solvent is added with steam in SAGD, and significantly more important for solvent-dominated processes, where a small amount of steam or heat is added with a large amount of solvent. A large amount of residual oleic-phase saturation and associated pessimistic solvent-recovery prediction will lead to erroneous economic assessment of these processes. The discrepancy in residual So, as the author and coauthors discovered in previous work, stems from a peculiarity of the Stone II formulation given by Equation 1 of the complete paper. To model this 1D problem numerically, a program developed by the author for his PhD thesis for modeling of moving front reservoir processes with dynamic gridding was modified and run with constant fluid properties for hexane and water at constant pressure and temperature. It also incorporated the three-phase relative permeabilities given by Equation 1 and Table 1 of the complete paper. The results are shown in Fig. 1.

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.

A new integrated approach to resolve the saturation profile using high-resolution facies in heterogenous reservoirs

The saturation calculation in complex reservoirs remains a major challenge to the oil and gas industry. In simple formations, a tendency towards simple saturation models such as Archie or Simandoux for clean and shaly reservoirs respectively is always preferable. These models were found to be working effectively in homogeneous formations within which the porosity and permeability are linked in the light of a simple facies scheme. Where the rocks show some degrees of heterogeneity, the well-logs are usually affected by different factors. This adversely results in a compromised or averaged log profiles that may affect the saturation calculations. Four wells drilled across a shaly sand of high heterogeneity have been studied in the Perth Basin, Western Australia. The aim is to resolve the hydrocarbon saturation and explain the high productivity results, despite the high water saturation, obtained through a conducted formation well test across the interested reservoir zones. A new integration technique between a suite of conventional and advanced logging tools together with the capillary pressure measurements has been carried out to generate a high-resolution reservoir saturation profile, that is lithofacies dependent. Three different independent methods were used in the studied wells to calculate the saturation and to reduce the uncertainty of the final estimated profiles. The methods are the resistivity-based saturation, the NMR-based irreducible saturation, and a new application through saturation height modeling. Furthermore, through the workflow, an effective calibration for the magnetic resonance T2 cutoff has been applied that is supported by the excellent reservoir production behavior from such complex reservoir. The methodology will help resolve the saturation calculation as one of the most challenging reservoir parameters, particularly where the resistivity logs are affected in complicated shaly sand environments. The effectiveness of the workflow shines the possibility to predict high resolution facies and saturation profiles in the lack of resistivity logs. A further possibility can complete the analysis on real time basis, which can certainly provide facies and saturation profiles extended to the uncored wells. Application of this methodology in the uncored wells has shown very encouraging results in various well trajectories, either vertical, deviated or horizontal long boreholes.

Complex fluids with visco-elastic rheology for applications in oil & gas industry

<h2>Abstract</h2> During the oil and gas recovery from subsurface, the recovery efficiency is mainly limited by two factors: pore-scale trapping resulting in irreducible hydrocarbon saturations and bypassing because of limited sweep efficiency due to rock heterogeneity, viscosity contrast and viscous instabilities. In order to improve the sweep efficiency, hydro-soluble polymer solutions with Non-Newtonian rheology are applied. The difficulty is in predicting the in-situ effective viscosity in Darcy-scale flow in the porous medium, based on bulk rheology provided for instance by shear rheometers (Berg and van Wunnik, 2017). Most of the relevant polymer systems, however, also exhibit viscoelasticity which can lead to elastic turbulence during flow through porous medium (De et al., 2022a). Here we show progress on the fundamental side, how to visualize the respective pore scale flow fields and understand the fundamental origins using a system that contains one single pore throat (Eguagie et al., 2020) and multiple pore throats and its effect on residual oil saturation (De et al., 2022b). In addition, we demonstrate how we numerically simulate the flow of viscoelastic fluids in porous medium and characterize elastic turbulence (De et al., 2022c).

Effects of temperature and CO2/Brine cycles on CO2 drainage endpoint phase mobility – implications for CO2 injectivity in deep saline aquifers

The coupled process of (seasonal) CO2 downhole temperature cycles and natural CO2/brine drainage-imbibition cycles is an inherent feature of large-scale CO2 injection schemes during the injection phase of a geologic storage site. Analysis of long-term field injection data shows that the effect of temperature cycles on injectivity is significant and cannot be explained by changes in CO2 properties alone, raising the question of whether CO2-rock properties such as relative permeability are also changing. We present the results of lab-scale coreflood experiments designed to measure CO2 drainage endpoint phase mobilities and relative permeabilities for cyclic CO2 displacing brine at representative reservoir drainage pressure/temperature conditions, using Basal Cambrian Sandstone (BCS) core samples from the storage reservoir of a large-scale (>1Mtpa) CO2 injection scheme in operation. The isothermal experiments are conducted at three temperatures: average seasonal low, average seasonal high, and reservoir. The measurements also incorporate the effects of repeated saturation cycles (or saturation hysteresis), between ∼100% brine saturation and irreducible brine saturation for the same core sample for up to 12 repetitive drainage-imbibition cycles. The results show that the CO2/brine two-phase flow characteristics change after each flooding cycle. CO2 drainage endpoint phase mobility increases as temperature increases, but the mobility increases cannot be fully explained by the decrease in CO2 viscosity and rock permeability changes alone. CO2 endpoint relative permeability (measured at about 0.20 ± 0.1) contributes marginally to the CO2 phase mobility changes with temperature and exhibits a weak inconsistent dependency on temperature. Field scale injectivity of CO2 can be optimised in large-scale CCS injection schemes design by exploiting the CO2 temperature-CO2/brine cycling-phase mobility functional relationship where CO2 phase mobility is enhanced at higher CO2 downhole temperatures. Field data show that this effect, though significant, may be weakened or even overridden by other temperature-dependent phenomena.

Investigation on the influence of capillary number on drainage in porous media using a lattice Boltzmann method

This work investigates the effect of the capillary number on the saturation of wetting and nonwetting phases during processes of drainage. A multicomponent Lattice Boltzmann model with a two-relaxation time scheme is used to simulate the flow in 2D and 3D digital models of porous rocks. The capillary number is varied by setting different values of the fluid inlet velocity, while viscosity and interfacial tension are fixed. The results show the invasion of nonwetting phase in the narrow pores of the media, forcing the wetting fluid to leave through the outlet. Different patterns are observed depending on the capillary number and the degree of porosity and heterogeneity of the models. Several pore-scale events are observed and play an important role in the trapping of wetting fluid. The nonwetting phase saturation is measured at breakthrough and quasi-steady states. In 2D models, the effect of the low velocity of the fluid at low Ca provides a better condition for fluid redistribution, causing a higher nonwetting fluid saturation. In 3D models, a lower value of Ca leads to more trapped wetting fluid mainly because of the media geometries. In all cases, the highest Ca range resulted in the highest nonwetting fluid saturation at a quasi-steady state. The saturation and relative permeability curves at the point of irreducible wetting phase saturation show that the degree of heterogeneity in 3D models has an important effect on sweeping effectiveness, which seems to be more significant than porosity or intrinsic permeability of the models.

Fractal Properties of Various Clay Minerals Obtained from SEM Images

Clay minerals significantly alter the pore size distribution (PSD) of the gas hydrate-bearing sediments and sandstone reservoir rock by adding an intense amount of micropores to the existing intragranular pore space. Therefore, in the present study, the internal pore space of various clay groups is investigated by manually segmenting Scanning Electron Microscopy (SEM) images. We focused on kaolinite, smectite, chlorite, and dissolution holes and characterized their specific pore space using fractal geometry theory and parameters such as pore count, pore size distribution, area, perimeter, circularity, and density. Herein, the fractal properties of different clay groups and dissolution holes were extracted using the box counting technique and were introduced for each group. It was observed that the presence of clays complicates the original PSD of the reservoir by adding about 1.31-61.30 pores/100 μm2 with sizes in the range of 0.003-87.69 μm2. Meanwhile, dissolution holes complicate the pore space by adding 4.88-8.17 extra pores/100 μm2 with sizes in the range of 0.06-119.75 μm2. The fractal dimension ( D ) and lacunarity ( L ) values of the clays’ internal pore structure fell in the ranges of 1.51-1.85 and 0.18-0.99, respectively. Likewise, D and L of the dissolution holes were in the ranges of, respectively, 1.63-1.65 and 0.56-0.62. The obtained results of the present study lay the foundation for developing improved fractal models of the reservoir properties which would help to better understand the fluid flow, irreducible fluid saturation, and capillary pressure. These issues are of significant importance for reservoir quality and calculating the accurate amount of producible oil and gas.

A general capillary equilibrium model to describe drainage experiments in heterogeneous laboratory rock cores

Macroscopic observations of two-phase flow in porous rocks are largely affected by the heterogeneity in continuum properties at length scales smaller than a typical laboratory sample. The ability to discriminate among the rock properties at the origin of the heterogeneity is key to the development of numerical models to be used for prediction. Here, we present a capillary equilibrium model that represents spatial heterogeneity in dual-porosity porous media in terms of the capillary entry pressure, 1/α, and the irreducible wetting phase saturation, Sir. Both parameters are used to scale local capillary pressure curves by using three-dimensional imagery acquired during multi-rate gas/liquid drainage displacements. We verify the proposed approach by considering the case study of a dual-porosity limestone core and use the spatial variation in Sir as proxy for microporosity heterogeneity. The latter places potentially next-to-leading order controls on the observed fluid saturation distribution, which is strongly correlated to the distribution of 1/α. While microporosity is by and large uniform at the observation scale on the order of 0.1 cm3, the spatial correlation of 1/α is on the order of 1 cm and is therefore not statistically represented in the volume of typical laboratory core samples.

Integrated analysis of well logs for productivity prediction in sand-shale sequence reservoirs of the Niger Delta—a case study

Work on fluid productivity prediction in the Niger Delta is sparse or even rare because of the need for expensive but limited information from core data, well test data, and nuclear magnetic resonance (NMR) data. Paucity of this information in the study area due to prohibitive cost makes justification of results of fluid productivity predictions very difficult to justify. However, an integrated well log analysis method is applied to three sand-shale sequence reservoirs of the Niger Delta for fluid productivity predictions in this work using basic log suites. This work utilizes irreducible saturation analysis calculated from the Buckles’ method for three (3) reservoirs in Well “AW” and Well “T”. Rock Physics estimates of Poisson’s ratio values and Vp/Vs ratio values allow for fluid type designation from a cross plot of Poisson’s ratio and Vp/Vs ratio; hence, it is possible to interpret gas saturation, brine saturation, and oil saturation for these reservoirs. The Buckle method yields numbers that are used to estimate irreducible water saturation values independently of Archie’s and Archie’s modified equations. In addition, Buckle’s numbers allow for a pore size and grain size forecast for sandstone reservoirs being intercepted within the two wells. For each of these reservoirs, water saturation (Sw) is compared with the irreducible water saturation (Swirr) with the logic that for a reservoir having Swirr > Sw, no water production is expected. Conversely, for Swirr Sw, no water production should be expected. In well “T” reservoirs T1, T2, and T3, all had Swirr > Sw. Hence, this work demonstrated the usefulness and effectiveness of the Buckle’s method in estimating many useful petrophysical parameters to predict reservoir productivity in the studied area, Niger Delta for wells lacking core data, well test data, and NMR data. Field-wide deployment of this technique may help to improve the reduction in oil-related water production and the cost of managing the produced water at the initial stage of production in the Niger Delta in the reservoir.

Experimental study of combined low salinity and surfactant flooding effect on oil recovery

A new generation improved oil recovery methods comes from combining techniques to make the overall process of oil recovery more efficient. One of the most promising methods is combined Low Salinity Surfactant (LSS) flooding. Low salinity brine injection has proven by numerous laboratory core flood experiments to give a moderate increase in oil recovery. Current research shows that this method may be further enhanced by introduction of surfactants optimized for lowsal environment by reducing the interfacial tension. Researchers have suggested different mechanisms in the literature such as pH variation, fines migration, multi-component ionic exchange, interfacial tension reduction and wettability alteration for improved oil recovery during lowsal injection. In this study, surfactant solubility in lowsal brine was examined by bottle test experiments. A series of core displacement experiments was conducted on nine crude oil aged Berea core plugs that were designed to determine the impact of brine composition, wettability alteration, Low Salinity Water (LSW) and LSS flooding on Enhancing Oil Recovery (EOR). Laboratory core flooding experiments were conducted on the samples in a heating cabinet at 60 °C using five different brine compositions with different concentrations of NaCl, CaCl2 and MgCl2. The samples were first reached to initial water saturation, Swi, by injecting connate water (high salinity water). LSW injection followed by LSS flooding performed on the samples to obtain the irreducible oil saturation. The results showed a significant potential of oil recovery with maximum additional recovery of 7% Original Oil in Place (OOIP) by injection of LS water (10% LS brine and 90% distilled water) into water-wet cores compared to high salinity waterflooding. It is also concluded that oil recovery increases as wettability changes from water-wet to neutral-wet regardless of the salinity compositions. A reduction in residual oil saturation, Sor, by 1.1–4.8% occurred for various brine compositions after LSS flooding in tertiary recovery mode. The absence of clay swelling and fine migration has been confirmed by the stable differential pressure recorded for both LSW and LSS flooding. Aging the samples at high temperature prevented the problem of fines production. Combined LSS flooding resulted in an additional oil recovery of 9.2% OOIP when applied after LSW flooding. Surfactants improved the oil recovery by reducing the oil-water interfacial tension. In addition, lowsal environment decreased the surfactant retention, thus led to successful LSS flooding. The results showed that combined LSS flooding may be one of the most promising methods in EOR. This hybrid improved oil recovery method is economically more attractive and feasible compared to separate low salinity waterflooding or surfactant flooding.

Multifractal analysis of coal pore structure based on NMR experiment: A new method for predicting T2 cutoff value

Nuclear magnetic resonance (NMR) is a commonly used method to quantitatively characterize the pore structure of coal. T2 cutoff value is closely related to the microscopic pore structure of coal reservoirs, which directly affects the calculation of porosity, permeability, movable and irreducible fluid saturation. In this study, the pore structure of four types of coal samples were studied based on NMR experiments and the multifractal characteristics of saturated coal samples were analyzed with multifractal theory. Furthermore, the correlation between T2 cutoff values and multifractal characteristic parameters were discussed. The results show that the pore structure characteristics of CZ, GD and GHS coal samples are basically the same, all of which are mainly micropores, with relatively less content of mesopores, macropores and microcracks, while PDS coal samples have relatively more content of mesopores, macropores and microcracks. Different types of coal samples have similar multifractal characteristics and all coal samples are dominated by micropores. There is an obvious linear relationship between T2 cutoff values and the multifractal characteristic parameters. Five models of T2 cutoff values changing with the multifractal characteristic parameters are obtained by linear fitting. The error range between T2 cutoff values calculated by the five models and the experimental values are within 0.1 ms, among which T2 cutoff values calculated by model 5 are highly consistent with the experimental values, indicating that model 5 can better predict T2 cutoff values. The results can provide theoretical reference for the characterization of coal pore structure and the prediction of T2 cutoff values.

Pore-Type Partitioning in Unconventional Tight Reservoirs: Impact on Formation Damage and Long-Term Production

SummaryWettability is an important petrophysical property, which governs irreducible fluid saturations, relative permeability, and fluid invasion in rocks. Unlike conventional reservoirs, which have relatively uniform pore surface properties, the concept of wettability is not clear in organic-rich tight reservoirs. These rocks do not only have a nanoporous system but also possess multiple pore types with different interfacial affinities. Previous studies have shown that the unconventional reservoirs consist of three major pore types: inorganic pores (assumed to be water-wet), organic pores (assumed to be oil-wet, controlled by organic matter and thermal maturity), and mixed-wet pores (controlled by organic-inorganic distribution) (Curtis et al. 2012).This study revisits the concept of pore-type partitioning in tight rocks. We propose and demonstrate a new workflow to evaluate pore partitioning. First, all the specimens were vacuum dried at 100°C for 6 days to remove the free fluids until the weight stabilized. Total porosity was estimated as the sum of residual liquid volume [using nuclear magnetic resonance (NMR)] and gas-filled volume [using helium high-pressure pycnometer (HPP)]. The companion specimens from two formations (Eagle Ford and Wolfcamp B) were subjected to multiple injection cycles: starting with imbibition, then counter imbibition, and finally step pressurization with the replacing phase. During this process, we used brine-then-dodecane and dodecane-then-brine as the injection fluid sequences. The companion samples were continuously monitored by both gravimetric and NMR measurements until equilibration. Relative fractions of both replaced and replacing phases were calculated from sample weights and pore-fluidvolumes.The new approach not only classifies the connected pore network into three categories—oil-wet,water-wet, and mixed-wet—but also quantifies their respective proportions. The mixed-wet pore is defined as the pore fraction, in which both oil and water can replace air under capillary suction. We observe that the behavior of mixed-wet pores is different among formations: they prefer brine over oil in Wolfcamp B shale, while they prefer oil over brine in the Eagle Ford Formation. Unlike conventional wettability assessments, from which an overall wettability is provided, the novelty of this method is to clearly classify different pore types and their distributions. The concept of fractional wettability is highlighted for organic-rich tight rocks, and the contribution of mixed-wet pores in relative flow is emphasized.Hydraulic fracturing is a necessary stimulation process for tight reservoirs, in which the usage of fracturing fluid can affect formation performance. During well completion, water blockage is more likely to happen in the Wolfcamp B Formation than Eagle Ford Formation. Due to the capillary preference of mixed-wet pores, the water blockage might aid the Wolfcamp Formation to boost initial production, however, at a later stage, damage the formation. The workflow thus is promising to fully describe the pore network in tight formations, in which pore-type partitioning is a more reasonable concept than wettability.

New fractal-dimension-based relation model for estimating absolute permeability through capillary pressure curves

This paper developed a new general power-law relation model to predict absolute permeability, which innovatively integrating Poiseuille's law and fractal capillary pressure model. The proposed model took into account the assumption of Poiseuille's law and Purcell theory characterizing the porous media as capillary tubes of various radii. Kewen Li fractal capillary pressure model was preferred to characterize capillary pressure curves and derive the new permeability relation model due to its higher fitting accuracy compared with Brooks-Corey model. Further, a randomly collected dataset containing 151 rock samples was used to calibrate the coefficients and another 53 rock samples were used to validate the feasibility of this new model. The proposed permeability model can predict absolute permeability through 5 basic parameters as follows: porosity, displacement pressure, capillary pressure at irreducible wetting phase saturation, irreducible wetting phase saturation and the fractal dimension. The fractal dimension, an indicator of the porous media heterogeneity, has a great impact on flow capacity in natural rock system. For rock samples with fractal dimension Df > 3, the capillary pressure matching results of Kewen Li power-law model are much better than those of Brooks-Corey capillary pressure model. 151 mercury injection capillary pressure (MICP) curves were all well fitted by Kewen Li model to estimate the basic parameters, and the absolute permeability of these rock samples were predicted through the new relation model. Then this study performed a comparison between the measured permeability in laboratory and calculated permeability through the new relation model. The regression Coefficient of Determination (R2) for measured and calculated permeability of 151 rock samples was 0.967. Besides, the new model consistently obtained attractive prediction results for another 53 validation rock samples. The new relation model can be widely used to estimate the absolute permeability for various rock types, including limestone, sandstone, dolomite, and from tight rocks to high permeability rocks.

Effects of Irreducible Fluid Saturation and Gas Entry Pressure on Gas Production from Hydrate-Bearing Clayey Silt Sediments by Depressurization

Gas hydrates in the Shenhu area are mainly hosted in clayey silt sediments, which have the relatively high irreducible fluid saturation and gas entry pressure. And then, they will have an impact on gas production from hydrate-bearing clayey silt sediments, which was evaluated by the numerical simulations of SH2 site in Shenhu area in this paper. The results showed that, with the increase in irreducible water saturation and irreducible gas saturation, the amount of water production and gas production was obviously reduced. When the irreducible water saturation increased from 0.10 to 0.50, the cumulative CH4 production volume decreased from 1668799 m3 to 1536262 m3, and the cumulative water production volume dropped from 620304 m3 to 564797 m3, respectively. When the irreducible gas saturation increased from 0.01 to 0.05, the cumulative CH4 production volume dropped from 1812522 m3 to 1622121 m3, and the cumulative water production volume dropped from 672088 m3 to 600617 m3, respectively. In addition, the capillary pressure increased obviously with the increase in gas entry pressure, but the effect on gas production was small and the effect on water production could be negligible. In conclusion, irreducible water and gas saturation had an important effect on the gas production from gas hydrate, whereas the effects of gas entry pressure could be ignored.

Experimental investigation on the effect of ethanol on micropore structure and fluid distribution of coalbed methane reservoir

The development of coalbed methane not only ensures the supply of natural gas but also reduces the risks of coal mine accidents. The micropore structure of coalbed methane reservoir affects the seepage of coalbed methane; improvement of pore structure is one of the effective methods to enhance the efficiency of coalbed methane exploitation. In this study, low-pressure nitrogen gas adsorption, specific surface area analysis, nuclear magnetic resonance spectroscopy, and centrifugation experiment were used to evaluate the effect of ethanol on coal microscopic pore structure and fluid distribution during hydraulic fracturing. Seven coal samples were collected from the No. 3 coal seam in Zhaozhuang Mine, Qinshui Basin. The samples are mainly composed of micropores, transition pores, and mesopores. The experimental results show that ethanol can significantly change the pore structure by increasing the pore diameter. The average specific surface area, pore volume, and pore diameter of rock samples before ethanol immersion are 1.1270 m2/g, 0.0104 cm3/g, and 14.20 nm, respectively. The three parameters of rock samples after ethanol immersion are 0.5865 m2/g, 0.0025 cm3/g, and 29.37 nm. Ethanol improves the connectivity between micropores and mesopores. The average irreducible fluid saturation of samples saturated with formation water after centrifugation is 86%, and the average irreducible fluid saturation of samples soaked in three concentrations of ethanol solution decreases. It is considered that an ethanol solution of 0.4% concentration has the best effect on improving the pore structure and fluid distribution.