Rock Permeability Research Articles

Study on the influence of statistical geometrical characteristics on the permeability tensor of fractured rock masses by the equivalent pipe network method

The permeability of the host rock of the nuclear waste underground repository is one of the most keys for estimating the potential risk for nuclide waste to escape. Therefore, a three-dimensional discrete fracture network (DFN) model using the Monte Carlo method is generated based on the statistical geometrical characteristics of fracture network in Beishan I area which is selected as the site for constructing the nuclear waste repository in China. And the permeability of Beishan I fractured rock masses is calculated through the equivalent pipe network (EPN) method and representative elementary volume (REV) of it is determined. A rotating algorithm is developed to calculate different direction permeability. Furthermore, the influence of fracture statistical geometrical characteristics on REV size is explored by creating a series of DFN models with varying log-normal distribution of side lengths. The results show that the REV size of the Beishan Ⅰ area is 1.66 × 105 m3 and the corresponding principal permeability direction is 111.29°/75.36°. The REV size and permeability both increase with the increment of the mean and variance of the log-normal distribution increases. And with the increase of mean and variance, the growth rate gradually accelerated.

Forecast of 241Am Migration from a System of Deep Horizontal Boreholes

Highly radioactive materials classified as high-level nuclear waste (HLW) of atomic power engineering should be disposed of deeply underground in special geological disposal facilities (GDFs), which can be of either shaft or borehole type. The advantages of borehole-type GDFs result from smaller volumes of mining operations, a simpler construction technology, shorter construction time and cost. This allows us to consider them as an alternative to shaft-type GDFs. The parts of the boreholes in which waste containers should be placed can be both vertical and horizontal. Computer simulation of the migration of radionuclides from a group of parallel horizontal boreholes into the biosphere made it possible to conclude that horizontal GDF boreholes have significant advantages over vertical ones. We determined a forecast of 241Am migration by a method of mathematical modelling of 241Am release from vitrified HLW disposed of in several horizontal drillholes. The maximum concentrations of americium in the near-surface groundwater above the repository are calculated depending on the number of boreholes, the depth of their location and the distance between them, the permeability of rocks and the time of waste storage prior to disposal. Influence of different conditions on the safety of a GDF of borehole type is estimated. Calculations show that the heat generated by HLW causes a weaker groundwater convection near horizontal boreholes compared to vertical boreholes of the same capacity. In addition to that, at an equal thickness of the rock layer separating the HLW from the surface, the geothermal temperature of the host rocks in the near field of a horizontal borehole will be lower than the average geothermal temperature near a vertical borehole. As a result, the rate of radionuclides leaching from the waste forms by groundwaters will also be lower in the case of horizontal boreholes.

Responses of plant sap flow rate to epikarst water availability under different karst water-bearing media

The water supply capacities of epikarst zones play an essential role in the restoration of vegetation and sustainable utilization of groundwater resources in karst areas. The permeability and water storage capacity of karst water-bearing media directly determines prospective water acquisition for plants. However, the degree to which karst water-bearing systems influence plant transpiration remains unclear. Consequently, this study selected three common karst water-bearing structures (pore and fissure (L1), fissure and conduit (L2), dissolution seam and pore (L3), to examine the sap flow rate (SF), infiltration rate, meteorological factors, soil water, and groundwater depth (GD) associated with the growth of Toona sinensis. The results revealed that: (1) Marked differences in the SF based on long term monitoring (2016/1–2022/6) were observed in three sample plots with the order of L2 > L1 > L3. Similar trends in the rock permeability coefficient were also found. (2) Groundwater depth and soil water are the major factors that determine the SF. (3) The threshold of GD (2.54 m for L1, 0.96 m for L2, and 3.56 m for L3) was identified, wherein the sensitivity of SF to GD (λn) was weakened with greater GD. (4) The fissure and conduit sample plot with a shallower GD and higher rock permeability provided more plant-available water, resulting in a larger SF. In contrast, the dissolution seam and pore sample plot with a more stable GD and media rock permeability hindered the absorption of water by plants, which translated to a lower SF. These results highlighted that the structures of karst water-bearing media determined the overall SF. This study provides useful information toward guiding the restoration of vegetation in subtropical karst areas with abundant rainfall and shallow groundwater reservoirs.

Experimental study on the influence of ultrasonic excitation duration on the pore and fracture structure and permeability of coal body

The study aims to explore the effect of ultrasonic duration on the pore structure and seepage characteristics of coal. Herein, we adopted a self-developed ultrasonic excitation experiment system using low-field nuclear magnetic resonance (NMR) technology and NM-4B non-metallic ultrasonic wave velocity detector. The study investigated NMR relaxation time T2 patterns and the number of pores of each size, internal structural damage, and seepage characteristics of the coal body before and after ultrasonic fracturing. Based on the Warren-Root model, the permeability model of coal under ultrasonic fracturing was established, revealing the changing law of ultrasonic fracturing at different times on the change of pore scale, connectivity, and nuclear magnetic permeability of the coal body. The mechanism of ultrasonic fractured coal body evolution at different times was clarified. The results showed that the ultrasonic fracturing at different times improved the number and volume of all size pores in the coal body, expanded primary fractures, and developed newborn fractures. The rate of change in pore size, porosity, wave velocity, and coal permeability had a linear relationship with the fracturing time. The growth rate of seepage pore volume proportion was positively correlated to the decreased rate of adsorption pore volume proportion. The fracturing duration leads to the interconnection of micropores within the coal body, forming medium and large pore fractures. This transformation between pores and fractures enhances the pore structure and seepage characteristics of the coal body. The coal rock permeability model can be used to calculate the permeability of a coal body, which follows the same change law as nuclear magnetic permeability. When evaluating the index using absolute and relative errors, the range of relative error is 0.97%–7.91%. The error variation range is small, indicating that the established model can effectively reflect the change law of porosity and permeability of the coal body responding to ultrasonic fracturing. The ultrasonic fracturing rendered the ultrasonic cavitation takes micropores as fracturing units, developed pores of all sizes, connected closed pores, increased free fluid space proportion, and improved the coal permeability.

Fenitization at the Lovozero Alkaline Massif, NW Russia: Composition and Evolution of Fluids

The 360–370 Ma old Lovozero massif (NW Russia) is a layered nepheline syenitic-foidolitic pluton. Despite its huge size (650 km2), the massif is surrounded by a narrow fenite aureole, and the most intensive fenitization is associated with pegmatites and hydrothermal veins that have intruded into the wall rocks. We studied petrography, petrochemistry, mineralogy and fluid inclusions along a profile crossing the direct contact of the Lovozero massif with country Archean gneiss. We found that the fluid responsible for fenitization was a heterogeneous mixture of two coexisting phases, an aqueous fluid with salinity 8.6–15.1 eq. wt.% NaCl and a methane fluid. The coexistence of these two fluids indicates immiscibility conditions at (or below) CH4–H2O solvus. The aqueous fluid affected both the endocontact alkaline rocks and country gneiss. In the endocontact, intense autometasomatic alterations of the early crystallized minerals occurred, for example, the natrolitization of nepheline and sodalite. Besides, the aqueous fluid transported Na2O, K2O, as well as P2O5, TiO2, H2O, F, Cl and S into the exocontact. These components were precipitated in the immediate vicinity of the massif contact, and the salinity of the aqueous fluid decreased to 0.53–3.06 eq. wt.% NaCl. We assume that there are two reasons for a narrow fenite aureole in the Lovozero massif: intense autometasomatic alterations and a decrease in the permeability of country rocks due to fluid immiscibility.

Minerals Dissolution Effect on the Mechanical Properties of Synthetic Carbonate Rocks

Injection of CO2 and water in saline aquifers or oil reservoirs causes changes of pressure, saturation and concentrations that affect the state of stress and promote chemical reactions in the host rock, resulting in porosity and permeability variations. It is therefore a coupled hydro-mechanical and chemical (HMC) problem. Numerical simulation of multiphase and multicomponent flow of CO2, oil and water with mechanical coupling allows realistic modeling of the reservoir and cap rocks. Carbonate reservoirs are geological formations composed mainly of minerals such as calcite and dolomite which can dissolve or precipitate in the medium when injecting a fluid of chemical composition and temperature different from those of the fluids initially contained in the rock. Water-weakening due to matrix acidification of carbonates is a well-known phenomenon that can be modeled by including mineral concentrations as state variables in the stress-strain behavior of the material.
 The objective of this work is to characterize synthetic carbonate rocks through microtomography and petrography techniques, focusing on a comparative analysis before and after load application and degradation with a reactive fluid [1]. The synthetic rocks were subjected to physical characterization (mineralogy, computed tomography and porosity) and mechanical characterization (uniaxial compressive strength and Brazilian tests) before and after the dissolution process. The petrographic analysis verified an increase in both intergranular and intragranular porosities after dissolution. The microtomography analysis quantified the maximum increase in porosity, from 11.8% to 41.3% in the two-dimensional analysis and 31.6% to 52% in the three-dimensional analysis of the porous structures. Furthermore, the pores were quantified according to their area, and data was obtained on the orientation of the pores, providing insight into the preferred paths of fluid flow. It was also observed that the microtomography technique was an effective tool for characterizing fractures in the samples before and after dissolution [1].
 Dissolution tests were also performed in a modified oedometer cell adapted to measure horizontal stress. The dissolution phase was conducted using water and an acid solution to evaluate the influence of the pH on the mechanical behaviour of the samples. When the sample in the oedometric cell is exposed to an acid solution under constant vertical load of 400kPa, vertical displacement takes place (volume decrease of the sample) and horizontal stress increases (Figure 1). The synthetic rock used in this experiment is mainly composed by calcite, with small additions of calcium hydroxide, and the reactive fluid is water acidified with acetic acid (with 10% concentration). This material is manufactured in laboratory in order to have greater control of its constituents and reproducibility of experimental results. During the acidification phase of the experiment, the sample was subjected to an acid flow with a pressure differential of 12kPa for 7h. The behavior in Figure 1 was also observed by [2] and [3]. The model for degradation of carbonatic soft rocks proposed by [2] was implemented in a finite element code capable of performing coupled THMC analyzes in porous media [4]. This model is based on the Critical State Theory with the introduction of a bonding variable that controls the size of the yield surface by modifying the tensile strength and the pre-consolidation stress of the material. In Figure 1 it is also possible to see that the HMC coupled simulation of the oedometric test was able to reproduce the experimental results in terms of volumetric strain and horizontal stress. In Figure 2 tomographic images of the synthetic carbonate rock before and after exposure to the acid solution in an oedometric cell under constant vertical load are presented. Such analyses are crucial for the injection of reactive fluids, such as CO2, at high depths. Dissolution of minerals will affect not only the porosity and permeability of the reservoir rock but also, possibly, the stress state in the vicinity of the injection well.

A New Method for Evaluating Fracability Based on Cluster Analysis and Well Logging Petrophysical Facies Division

The fracability of rock is a crucial parameter in determining the efficiency of fracturing in tight reservoirs. However, current methods for evaluating fracability have significant limitations. This paper proposes a new method for evaluating reservoir fracability based on cluster analysis of logging petrophysical facies. This method considers rock mechanics characteristics, petrophysical response characteristics, and reservoir physical parameters, among other factors. The Well X of the block was used as the research subject. Using the brittleness index and permeability evaluation index, the reservoir fracability of the target block is classified into five categories: high brittleness and low permeability rock, high brittleness and super low permeability rock, low brittleness and low permeability rock, low brittleness and super low permeability rock, and clay/shale. Geolog software is used to generate fracability prediction profiles for representative wells based on petrophysical facies. To further validate this evaluation method, the fracture construction data and microseismic monitoring interpretation results of Well Y in a tight block of an oil field were synthesized and analyzed to predict its fracability. The overall prediction accuracy reached 81.8%, indicating that the new fracability evaluation method has good application effect.

Guadalupian–Lopingian (Middle–Late Permian) radiolarians from clastic rocks and zircon U–Pb ages of intercalated tuff and tuffaceous sandstone on Sado Island, central Japan

We investigated Permian strata in the Ota area of the Kosado Hills, Sado Island, central Japan, and their depositional ages were determined based on radiolarian biostratigraphy and zircon U–Pb dating. We also focused on the geology of the region and its lithologic correlation with other geological units in the Inner Zone of Southwest Japan. The radiolarian analysis identified the presence of Follicucullus porrectus and F. dilatatus in mudstone exposed on the coastline of Ota, indicating a middle–late Capitanian to early Changhsingian age. Mudstone exposed along the forest road in the Ota area contained Cariver charveti, suggesting a late Capitanian–early Changhsingian age. Zircon U–Pb dating of the tuff layer intercalated within the Follicucullus-bearing mudstone yielded a weighted-mean age of 259.9 ± 2.0 Ma, corresponding to a Capitanian–Wuchiapingian age. The tuffaceous sandstone interbedded with mudstone containing C. charveti yielded a weighted-mean age of 264.1 ± 6.3 Ma, which covers the Roadian to Wuchiapingian ages. The youngest model peak age (256.6 ± 2.6 Ma; Wuchiapingian) provides the most reliable estimate of the maximum depositional age. The Paleozoic strata in the Kosado Hills have previously been correlated with the Ultra-Tamba and Maizuru belts in Southwest Japan based on fossil occurrences. Our findings indicate that the Permian rocks in the Kosado Hills exhibit differences in lithology from those in the Ultra-Tamba belt but share similarities with the upper Guadalupian–Lopingian strata in the Maizuru belt.

Thermal‒hydraulic‒mechanical‒chemical coupling analysis of enhanced geothermal systems based on an embedded discrete fracture model

Enhanced geothermal system (EGS) is subject to the comprehensive effects of multiple physical fields during the long-term heat extraction process, including hydraulic (H), thermal (T), mechanical (M) and chemical (C) fields. The embedded discrete fracture model (EDFM) can effectively simulate the variations of flow, temperature, mechanical and concentration fields in fractured reservoirs. At present, however, the thermo-hydro-mechanical-chemical (THMC) coupling model based on EDFM is less researched. In this paper, the THMC coupling model of fractured reservoir is established based on EDFM by considering the changes in reservoir heterogeneity and physical properties as well as water–rock reactions. Then, the spatiotemporal evolution of flow, temperature, displacement and concentration fields in the operation process of EGS is simulated and analyzed. And the following research results are obtained. First, when the permeability of the basement rock is low, the production temperature decrease during exploitation is gradual, allowing EGS to maintain a high exploitation temperature for an extended period. However, lower permeability may result in a decrease in the quality flow rate from production wells, thereby affecting net heat extraction power. Second, when fracture permeability or fracture opening changes, EGS can output higher temperature stably for a certain period and then the temperature decreases at different amplitudes. When the fracture permeability increases to a certain value or the fracture opening decreases to a certain value, the influence of the change in fracture parameters on production temperature gets weak. Third, After 40 years of EGS operation, considering variable property fluids results in a 22 °C lower exploitation temperature compared to using constant property fluids, and considering water–rock reactions results in a 15 °C lower exploitation temperature, with a 12.5 % increase in reservoir average porosity. In conclusion, when researching a long-term operating EGS, it is necessary to comprehensively consider the influences of reservoir rock parameters, physical properties of injected fluid, water–rock reaction and other factors. And in the future, attention shall be paid to the two-way coupling of chemical reaction and mechanical deformation of other mineral compositions in the reservoir to the hydro-thermo-chemical field influence, so as to provide more accurate and reliable prediction for the engineering development and utilization of EGS reservoirs.

Exploration Guides for High-Grade Hypogene Porphyry Copper Deposits

Abstract Hypogene porphyry Cu deposits, unaffected by supergene enrichment, are generally perceived as relatively low-grade orebodies, in keeping with a current average production grade of 0.53% Cu. Nonetheless, all or large parts of some deposits exceed 1% Cu, and smaller deposit components can be much higher in grade, locally >6% Cu. In view of the major economic and environmental benefits afforded by high grades, we briefly review geologic features and factors conducive to development of >1% hypogene Cu ore in porphyry Cu systems. Intense quartz veinlet stockworks, magmatic-hydrothermal breccias, vuggy residual quartz or vein systems in telescoped lithocaps, proximal skarns, carbonate-replacement mantos and pipes, low-permeability barriers, and reactive mafic host rocks—either alone or in various combinations—are identified as particularly favorable features because they enhance rock permeability and/or reactivity; most of them may be taken into account when planning and conducting exploration programs, thereby maximizing the chances of high-grade porphyry Cu discoveries.

Impact of permeability anisotropy misalignment on flow rates predicted by hydrogeological models

The notion of permeability is critical to compute underground fluid flow. In most cases rock permeability is anisotropic, due to physical processes including gravitational compaction, which often results in the principal permeability directions being approximately horizontal and vertical in undeformed rocks. However, rocks often are tilted and/or deformed over time, therefore permeability orientation varies. Anisotropic permeability with varying orientation is hard to quantify in three-dimensional (3D) models and is therefore sometimes approximated, for convenience, by setting the principal permeability directions to horizontal and vertical, and assuming that corresponding errors in fluid flow might be negligible when the change in orientation is minimal. This study shows how minor misalignment of the permeability tensor can lead to large errors in fluid flow magnitude and corresponding transport times for strongly anisotropic rocks. It also provides a method to set anisotropic permeability orientation appropriately in geometrically complex 3D models using implicit 3D geological modelling. The misalignment is particularly costly when fluid flow is localised in thin channels, where a misalignment of just 5° leads to errors of two orders of magnitude for anisotropy ratios (between the largest and smallest principal values of the permeability tensor) of 104. It is therefore recommended to set anisotropic permeability accurately, using longitudinal and transverse components along with their respective orientations, rather than horizontal and vertical components. This approach will become increasingly important as 3D models gain realism in their representation of complex geometries.

Mechanical and hydraulic properties of fault rocks under multi-stage cyclic loading and unloading

The rock mass in fault zones is frequently subjected to cyclic loading and unloading during deep resource exploitation and tunnel excavation. Research on the mechanical and hydraulic characteristics of fault rock during the cyclic loading and unloading is of great significance for revealing the formation mechanism of water-conducting pathways in fault and preventing water inrush disasters. In this study, the mechanical and seepage tests of fault rock under the multi-stage cyclic loading and unloading of axial compression were carried out by using the fluid–solid coupling triaxial experimental device. The hysteresis loop of the stress–strain curve, peak strain rate, secant Young's modulus, and permeability of fault rock were obtained, and the evolution law of the dissipated energy of fault rock with the cyclic number of load and unloading was discussed. The experimental results show that with an increase in the cyclic number of loading and unloading, several changes occur. The hysteresis loop of the stress–strain curve of the fault rock shifts towards higher levels of strain. Additionally, both the peak strain rate and the secant Young's modulus of the fault rock increase, resulting in an increase in the secant Young's modulus of the fault rock mass. However, the growth rate of the secant Young's modulus gradually slows down with the increase of cyclic number of loading and unloading. The permeability evolution of fault rock under the multi-stage cyclic loading and unloading of axial compression can be divided into three stages: steady increase stage, cyclic decrease stage, and rapid increase stage. Besides, the calculation model of dissipated energy of fault rock considering the effective stress was established. The calculation results show that the relationship between the dissipated energy of fault rock and the cyclic number of loading and unloading conforms to an exponential function.

Provenance of a Late Permian retroarc foreland basin along the eastern Gondwanan margin: northern Sydney Basin, eastern Australia

Abstract The Upper Permian sedimentary successions in the northern Sydney Basin have been the subject of several stratigraphic, sedimentological and coal petrographic studies, and recently, extensive U-Pb zircon dating has been carried out on tuffs in the Newcastle Coal Measures. However, detailed petrographic and geochemical studies of these successions are lacking. These are important because a major change in tectonic setting occurred prior to the Late Permian because of the Hunter-Bowen Orogeny that caused the uplift of the Carboniferous and Devonian successions in the Tamworth Group and Tablelands Complex adjacent to the Sydney Basin. This should be reflected in the detrital makeup of the Upper Permian rocks. This study provides data that confirms major changes did take place at this time. Petrographic analysis indicates that the source area is composed of sedimentary, felsic volcanic and plutonic and low-grade metamorphic rocks. Conglomerate clast composition analysis confirms these results, revealing a source region that is composed of felsic volcanics, cherts, mudstones and sandstones. Geochemical analysis suggests that the sediments are geochemically mature and have undergone a moderate degree of weathering. The provenance data presented in this paper indicate that the southern New England Orogen is the principal source of detritus in the basin. Discrimination diagrams confirm that the source rocks derive from an arc-related, contractional setting and agree with the provenance analyses that indicate sediment deposition in a retroarc foreland basin. This study offers new insights on the provenance and tectonic setting of the Northern Sydney Basin, eastern Australia.

Analysis of structural-tectonic and petrophysical features of productive horizons of Mishovdag fold


 
 
 The article analyzes the geological structure, lithofascial, tectonic, and morpho- logical features of the Mishovdag oil field, which is a productive area in terms of oil content. Morphologically, it represents a brachianticlinal fold located in the north-west and south-east directions. The Mishovdag fold is located on the Kalamaddin-Bandovan anticline zone between the Kichik Harami (in the northeast) and Galmaz (in the northwest) structures. The Mishovdag-Galmaz part of the anticlinal zone extends in the sub-southern direction. The structures included in the zone are represented on the surface mainly by Aghjagil, Absheron, and ancient Khazar sediments. Productive layer sediments come to the surface in few areas. The tectonic movements and activity of mud volcanoes (active or buried) have left characteristic traces in the geological structure of the research area. Brachianticlinal and other types of structures were formed here. Under the strong influence of tectonic movements, the layers forming them were deformed and broken into blocks by regional tectonic faults. The anticlinal structures of the zone are complicated by longitudinal and latitudinal faults. The Mishovdag fold is represented by a brachianticline, 20-25 km long and 4-6 km wide. Brachianticline has a sharply asymmet- rical structure. The southwestern limb is steep, and inclined at an angle of 25-450, while the northeastern limb is flat and characterized by an inclination angle of 7-250. As a result of the analysis of the cross-sections of deep wells drilled in the field, it was determined that Mesozoic, Paleogene-Miocene, and Pliocene-Anthropogenic sediments are developed in the section of the fold. Sediments repre- senting the cross-section are characterized by high reservoir properties. Geological-geophysical works are carried out in the field. Core materials were taken from wells. The lithological-petrophysical characteristics – carbonate, porosity, and permeability of reservoir rocks have been determined according to core samples taken from exploration wells drilled in the field. The lithological-petrophysical characteristic regularities of change were investigated depending on depth.
 
 

A study of non-equilibrium wave groups in two-phase flow in high-contrast porous media with relative permeability hysteresis

Non-equilibrium models are applicable in various physical situations, including phase transitions, hysteresis, and chemical reactions, among others. To model the dynamics of such phenomena, partial differential equations are employed with source terms, as seen in Eq. (1.1). This work focuses on situations where we connect states in equilibrium while allowing for non-equilibrium times. In our model, we model non-equilibrium through relaxation. The source term, in this case, acts as an attractor, and the model’s dynamics allow only a small-time far from equilibrium. We use this theory to model a two-equation system in a two-phase fluid in porous media, where different permeabilities of the flow lead to hysteresis phenomena. We show several examples and study the Riemann solution to gain a better understanding of the solution. We investigate the interplay between nonlinear wave groups of water–oil saturation with different permeabilities in the non-wetting phase and the high-contrast heterogeneity of the porous medium in two-space dimensions. This phenomenon is described by a coupled set of time-dependent partial differential equations of hyperbolic–parabolic–elliptic mixed type. We present and discuss a new projection method with relaxation to obtain 1D-analytical Riemann solutions in an idealized homogenized medium, and we use this solution to validate our numerical method. The primary components of obtaining these solutions are shocks, rarefactions, and bifurcations. We obtain 2D-numerical solutions using an operator splitting approach based on physics, highlighting the discretization methods used. We provide robust analytical–numerical examples to verify the theory and illustrate the approach’s capabilities. In particular, we discuss the 1D-2D behavior of wave groups in situations driven by water–oil infiltration problems of permeable reservoir rocks.

Experimental Measurements to Study Correlations between Porosity, Absolute Permeability, and Capillary Pressure

Rock permeability is a measurement of how easily a fluid can flow through a rock while porosity is a measure of the rock’s storage capacity or its pore volume that is capable of holding fluids. In many cases correlations may exist between porosity and permeability, however, these correlations are usually derived for a certain formation, and therefore they do not exhibit general application or validity. Cross-plot of permeability versus porosity data, to create a porosity-permeability transform, is sometimes used to assign permeability values to areas of a reservoir where permeability data are unavailable. The capillary pressure curve is also used to predict rock absolute permeability. In the present work, porosity, absolute permeability, and capillary pressure were measured experimentally to investigate and establish new correlations between porosity, Klinkenberg-corrected permeability, and capillary pressure. Fifty-nine core plugs, obtained from two different fields located in Sirte basin, Libya, were utilized. Results indicate that porosity might be a reasonable estimator of permeability, as correlations between porosity and permeability were observed and empirical permeability equations based on porosity were established. Capillary pressure was observed to be overall inversely proportional to permeability, however, determined capillary pressure curves varied within the same formation.

Studying the effect of surfactant assisted low-salinity water flooding on clay-rich sandstones

Sandstone reservoirs often contain clay particles that can cause damage and reduce permeability during low-salinity water flooding. In this study, the effect of surfactants on fine migration in clay-rich sandstones and its impact on oil recovery was investigated.First, the impact of surfactants on interparticle forces in fine-matrix, fine-fine, and oil-matrix systems was modeled. The results showed that both CTAB (cetyltrimethyl ammonium bromide) and QS (quillaja saponin) cause EDL compaction, weakening the repulsive forces. However, SDS (sodium dodecyl sulfate) and TX (triton X-100) do not affect the EDL. Next, the effect of surfactants on IFT reduction and wettability alteration was experimentally investigated. All surfactants reduced IFT due to the surface excessive concentration mechanism. The wettability alteration experiment illustrated that although QS and CTAB compact EDL around oil and matrix particles leading to attraction force augmentation, they both alter wettability through adsorption on matrix and carboxylic groups present in crude oil, respectively.Surfactant aqueous solutions were then injected into various clay-rich sandstone sanpacks, which resulted in increased oil recovery. However, the mechanisms leading to enhanced oil recovery variedby surfactant type. CTAB increased recovery by 10% through IFT reduction and wettability alteration, while SDS and TX increased recovery by 12% and 9%, respectively, through wettability alteration and extreme fine migration. In contrast, partial fine migration in the QS flooding experiment reached a recovery increase of 18%. Permeability trends through experiments were also recorded. During CTAB injection, permeability did not reduce, while QS aqueous solution reduced rock permeability to 5 mD. SDS and TX reduced the magnitude of permeability to 2 mD.In conclusion, this study demonstrates that surfactants can effectively improve oil recovery in clay-rich sandstones by altering the interparticle forces, reducing IFT, and changing wettability. The results suggest that the type of surfactant used should be carefully selected to achieve the desired recovery increase without affecting the permeability of the reservoir.

Interaction and linkage of basin-boundary fault segments control deformation bands distribution and damage zone permeability

Analyzing the factors that affect the fault damage zone parameters and the impact of deformation on host rock permeability is fundamental for predicting the fluid flow behavior in subsurface reservoirs. This study combines 3D seismic data with field-based structural and petrophysical analyses to determine the influence of a basin-boundary fault geometry on (1) the damage zone thickness, (2) the spatial distribution of deformation bands, and (3) the damage zone permeability. Seismic interpretation and outcrop investigation on the Portalegre Fault, NE Brazil, revealed complexity in the boundary fault geometry and subsidiary structures. The boundary fault exhibits significant local variation in its strike (from N45°E up to N85°), while minor faults and deformation bands establish cross-cutting relationships with NW–SE-oriented structures, displacing NE–SW- and E–W-oriented structures. By analyzing deformation bands frequency, we identified the presence of three subsequent fault damage zones, totaling approximately 275 m in width. The first damage zone was developed near the basin-bounding Portalegre Fault, and secondary rift faults developed the other two damage zones during breaching and segment overlap. We observed that the permeability distribution recorded successive increases and decreases as we moved away from one fault and approached another. This structural and petrophysical complexity led us to interpret this fault damage zone as a linking damage zone. These observed patterns contrast with the structural and petrophysical behavior of a wall damage zone, wherein the frequency of subseismic structures decreases and permeability increases with distance from the fault. Thus, our study highlights the effect of fault tip interaction and linkage on the distribution of deformation bands and permeability, clarifying aspects related to structural heterogeneities of siliciclastic reservoirs affected by faults.

Study on SiO2 Nanofluid Alternating CO2 Enhanced Oil Recovery in Low-Permeability Sandstone Reservoirs

Water alternating gas (WAG) flooding is a widely employed enhanced oil recovery method in various reservoirs worldwide. In this research, we will employ SiO2 nanofluid alternating with the CO2 injection method as a replacement for the conventional WAG process in oil flooding experiments. The conventional WAG method suffers from limitations in certain industrial applications, such as extended cycle times, susceptibility to water condensation and agglomeration, and ineffectiveness in low-permeability oil reservoirs, thus impeding the oil recovery factor. In order to solve these problems, this study introduces SiO2 nanofluid as a substitute medium and proposes a SiO2 nanofluid alternate CO2 flooding method to enhance oil recovery. Through the microcharacterization of SiO2 nanofluids, comprehensive evaluations of particle size, dispersibility, and emulsification performance were conducted. The experimental results revealed that both SiO2-I and SiO2-II nanoparticles exhibited uniform spherical morphology, with particle sizes measuring 10–20 nm and 50–60 nm, respectively. The SiO2 nanofluid formulations demonstrated excellent stability and emulsification properties, highlighting their potential utility in petroleum-related applications. Compared with other conventional oil flooding methods, the nanofluid alternating CO2 flooding effect is better, and the oil flooding effect of smaller nanoparticles is the best. Nanofluids exhibit wetting modification effects on sandstone surfaces, transforming their surface wettability from oil-wet to water-wet. This alteration reduces adhesion forces and enhances oil mobility, thereby facilitating improved fluid flow in the rock matrix. In the oil flooding experiments with different slug sizes, smaller gas and water slug sizes can delay the breakthrough time of nanofluids and CO2, thereby enhancing the effectiveness of nanofluid alternate CO2 flooding for EOR. Among them, a slug size of 0.1 PV approaches optimal performance, and further reducing the slug size has limited impact on improving the development efficiency. In oil flooding experiments with different slug ratios, the optimal slug ratio is found to be 1:1. Additionally, in oil flooding experiments using rock cores with varying permeability, lower permeability rock cores demonstrate higher oil recovery rates.

A new approach to investigate the effect of burial depth and clay content on fault permeabilities applied at the Njord Field

Fault permeability prediction typically relies on empirical relationships between permeability and clay content or burial depth. Calibration of such methods relies on either core data or subsurface observations of fluid pressure and hydrocarbon contact offsets across faults. Published core data suggest that no relationships exist between host rock clay content and fault permeability for phyllosilicate-framework fault rocks, whereas published subsurface calibration data suggest otherwise. We here present a new method for calibration of fault rock permeabilities to subsurface pressure data. This approach is an analogue from electrical engineering to compute fault permeabilities across all major faults in a study area and optimise depth and clay content dependence of fault permeabilities. We tested this method at the Jurassic section of the Norwegian Njord Field area, where faults span the depth range of 2.7- 4.5 km and the lowest clay content in individual faults varies between 8.9 to 25.7%. The flow-restricting faults at Njord are phyllosilicate-framework fault rocks. Our modelling shows that fault rock permeability decreases with burial depth, whereas the clay content has nearly no impact. Sensitivity analyses show that these results are robust. Therefore, SGR-based algorithms for fault seal prediction cannot be expected to give good fault permeability predictions for seismic-scale faults at Njord. Thematic collection: This article is part of the Fault and top seals 2022 collection available at: https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022 Supplementary material: https://doi.org/10.6084/m9.figshare.c.6824325