Matrix Permeability Research Articles

Hydraulic Behavior of Fractured Calcite-Rich Sandstone After Exposure to Reactive CO2–H2O Flow

Geological carbon sequestration in jointed reservoirs will require the use of fracture network for the flow of CO2 plumes. However, acidic solution formed at the interface between brine and CO2 can cause chemical erosion of the local rock mass, especially in rocks with high carbonate content. The use of the water alternating gas technique for injection stimulation can exacerbate this issue, as the water–CO2 interface occurs in areas near the injection point. As a result, acidic flow can impact the surrounding rock mass, particularly around the main flow paths where fracture network conductivity is much higher than matrix permeability. To investigate the impact of acidic flow on fracture conductivity, we conducted an experiment on a fractured sandstone sample that was exposed to CO2-saturated water. Our findings revealed a nearly ten-fold increase in post-experimental water-relative permeability, and restriction of flow within established flow channels, which consist one third of the fracture surface. In conclusion, our study sheds light on the dynamic behavior of fractured sandstone under the influence of CO2–H2O flow, revealing significant changes in transmissivity and fracture geometry. These findings contribute to a better understanding of the hydraulic performance of fractures in the context of geological carbon sequestration.

Investigating the Influencing Factors of Imbibition of Fracturing Fluids in Tight Reservoirs

Tight reservoirs are the focus of unconventional oil and gas resource development, but most tight reservoirs exhibit complex pore structures, strong non-homogeneity, and limited water drive development. Fracturing fluid imbibition is a critically important way to improve the recovery of tight reservoirs. In this paper, an NMR experimental device was used to conduct imbibition experiments in tight reservoirs, and the relationship between temperature, pressure, matrix permeability, and imbibition recovery was investigated. Based on the fracturing fluid imbibition recovery curve, the imbibition process is divided into the fast imbibition stage, slow imbibition stage, and imbibition equilibrium. In addition, based on the pore structure division, the recovery changes of each pore under different experimental conditions were quantitatively analyzed. The results indicate that the highest imbibition recovery is achieved at an experimental pressure of 5 MPa within the range of 0 MPa to 15 MPa. Increasing the experimental pressure can increase the imbibition rate but will not increase imbibition recovery. Within the investigated range in this paper, fracturing fluid imbibition increases with rising temperature and matrix permeability. Moreover, the recovery of each pore gradually increases with the experimental pressure ranging from 0 MPa to 5 MPa. The recovery of each pore is positively correlated with matrix permeability and temperature. During the experiment, micropores contributed the most to the recovery, while macropores contributed the least. The study in this paper guides the efficient development of tight reservoirs.

Numerical Reservoir Simulation of Supercritical Multi-Source and Multi-Component Steam Injection for Offshore Heavy Oil Development

We present the workflow for numerical reservoir simulation of supercritical multi-source and multi-component steam injection for offshore heavy oil development. We have developed unique techniques in a commercial reservoir simulator to implement the thermal properties of supercritical multi-source and multi-component steam, the pyrolysis chemical reactions, the temperature-dependent relative permeability, and the process of partially dissolving the sandstone rock to enhance the matrix permeability in a commercial reservoir simulator. Simulations are conducted on the type pattern reservoir model, which represents one of the heavy oil fields in CNOOC’s Bohai Bay oil field. Simulation input parameters are calibrated based on laboratory experiments conducted for supercritical multi-source and multi-component steam injection. Simulation results have shown clear improvements in injecting supercritical multi-source and multi-component steam in offshore heavy oil reservoirs compared to the normal steam injection process using subcritical steam. This serves as a workflow for implementing a numerical simulation of the novel supercritical multi-source and multi-component steam injection recovery process.

Computation of the effective permeability of 2D doubly porous materials with elliptical shaped pores by using boundary element method

In recent years, the prediction of the effective transport properties have received a great number of investigations. The present work is dedicated to determining the effective permeability of two-dimensional (2D) doubly porous materials made of an isotropic permeable solid matrix in which elliptical shaped pores of any size are embedded. At the interface between the fluid and the solid, the Beaver–Joseph–Saffman conditions are applied. To achieve this objective, the Boundary Element Method (BEM) is first elaborated in the simulation of velocity and pressure solution fields of two coupled Stokes and Darcy problems. Afterwards, with the help of this solution results, the effective permeablity of the doubly porous material under investigation can be determined. For the purpose of assessing the accuracy and convergence of the BEM solution, the results obtained for the velocity and pressure fields are compared with the ones provided by the finite element method (FEM). Finally, several numerical examples are carried out to analyze the fluid/solid interface influence, the effect of area fraction and geometrical properties of pores, such as the size and distribution of the pores within the matrix phase.

The influence of alteration and fractures on gas permeability and mechanical properties of the sedimentary and volcanic rocks of the Acoculco Caldera Complex (México)

Petrophysical and mechanical properties of limestones and volcanic altered and unaltered rocks were estimated by a series of laboratory measurements. The aim of this work was to study the changes in matrix permeability and the influence of an induced vertical fracture. The phenomenon was studied by direct comparison of different properties (porosity, UCS, permeability) and by a multiple linear regression analysis. Porosity, UCS, and matrix permeability of limestones and non-altered volcanic rocks showed homogeneous values. However, the permeability increased from poor to moderate after fracture induction (10–17 to 10–14 m2). Altered volcanic specimens showed a more complex pore system. Thus, considerable variations in all measured properties were identified. For example, porosity ranged from 6 to 50% and Permeability ranged from 10–14 to 10–12 m2. Comparison plots including UCS, porosity, and matrix permeability showed a good fitting (R2=0.75). Multiple linear regression analysis in fractured specimens has a moderate R2 (0.55) The model that better explains the permeability evolution of fractured specimens has the fracture permeability as the response variable and the porosity values as independent variables. The usage and repeatability of these equations in other zones should include more singularities of every single specimen as pore size, pore distribution, and fractures.

Integrated wellbore-reservoir-geomechanics modeling for enhanced interpretation of distributed fiber-optic strain sensing data in hydraulic-fracture analysis

Fiber-optic distributed strain sensing (FO-DSS) has been successful in monitoring strain changes along horizontal wellbores in hydraulically fractured reservoirs. However, the mechanism driving the various FO-DSS responses associated with near-wellbore hydraulic fracture properties is still unclear. To address this knowledge gap, we use coupled wellbore-reservoir-geomechanics simulations to study measured strain-change behavior and infer hydraulic fracture characteristics. The crossflow among fractures is captured through explicit modeling of the transient wellbore flow. In addition, local grid refinement is applied to accurately capture strain changes along the fiber. A Base Case model was designed with four fractures of varying properties, simulating strain change signals when the production well is shut-in for 10 d after 240 d of production and reopened for 2 d. Strain-pressure plots for different fracture clusters were used to gain insights into inferring fracture properties using DSS data. When comparing the model with and without the wellbore, distinct strain change signals were observed, emphasizing the importance of incorporating the wellbore in FO-DSS modeling. The effects of fracture spacing and matrix permeability on strain change signals were thoroughly investigated. The results of our numerical study can improve the understanding of the relation between DSS signals and fracture hydraulic properties, thus maximizing the value of the dataset for fracture diagnostics and characterization.

Horizontal borehole azimuth optimization for enhanced stability and coal seam gas production

Horizontal boreholes have been widely used to extract natural gas from coal seams. However, these boreholes can encounter severe instability issues leading to production interruption. Optimizing drilling azimuth is a potential solution for enhancing borehole stability while considering gas production. In this work, we improved and implemented a dual-porosity, fully coupled geomechanical-hydraulic numerical model into COMSOL Multiphysics to investigate into this factor. The sophisticated numerical model incorporates various critical factors, including desorption-induced matrix shrinkage, stress-dependent anisotropic fracture permeability, and the interactions of gas flow and reservoir deformation in matrices and fractures.A suite of simulation scenarios (e.g., varying coal strength) was carried out to quantify the impact of drilling azimuth on coal permeability evolution, cumulative gas production, and the borehole break-out width for Goonyella Middle Seam of Bowen Basin, Australia. The model was calibrated against both theoretical permeability values and field gas production data. Due to the lack of directly measured matrix permeability data, the actual gas production was used to back calculate the best-matched matrix permeability, which is 0.65 μD for this particular work. Moreover, based on the breakout shape and induced volumetric strains around the borehole, drilling along the maximum horizontal stress does not necessarily lead to the best stability of the borehole, as generally believed. A drilling azimuth between 0° and 60° results in similar breakout width, whereas a drilling azimuth between 60° and 90° achieves the most efficient gas production. By considering both gas production efficiency and borehole stability, for this particular reservoir condition, the optimum drilling azimuth is determined to be between 45° and 60°.This study presents a practical approach for determining the optimum drilling azimuth in coal seam gas extraction through in seam boreholes.

The Dependence of Water and Gas Breakthrough on the Choice of Model Parameters in Naturally Fractured Reservoirs Using Sector and Full Reservoir Models

Assessing fractures in carbonate reservoirs is crucial due to their substantial impact on reservoir permeability. Understanding the characteristics of these fractures is vital for optimizing oil production. Additionally, extremely heterogeneous and anisotropic permeability distribution within the natural fractured reservoir is often caused by the complexity of a fracture network. Therefore, accurate reservoir modelling and simulation must be conducted in order to achieve ultimate recovery. In this paper, a sector model has been developed based on the studied example field, and its results are compared with the full reservoir model to find out the degree of resemblance between their outputs. The study area has four natural fracture compartments, with an average reservoir height of 95m and WOC and GOC depths of 685 m and 590 m, respectively. A dual-porosity and single-permeability modelling system was used to simulate the properties of the reservoir rock. This model was derived from the Petrel layercake model. A sensitivity analysis was also carried out to look into the relationships between field performance and the well. The outcomes of both models demonstrated that matrix permeability and fracture dimension had a significant impact on the early breakthrough of water and gas to comparable, huge extents. Other factors, such as aquifer size and WOC, show a moderate impact on water and gas breakthrough as well as final recovery.

A 3D FRACTAL MODEL COUPLED WITH TRANSPORT AND ACTION MECHANISMS TO PREDICT THE APPARENT PERMEABILITY OF SHALE MATRIX

The permeability of shale controls gas transport in shale gas reservoirs. The shale has a complex pore structure at the nanoscale and its permeability is affected by multiple transport and action mechanisms. In this study, a 3D fractal model for predicting the apparent gas permeability of shale matrix is presented, accounting for the effects of the transport mechanisms (bulk gas transport and adsorption gas diffusion) and action mechanisms (gas adsorption, real gas properties, water film, stress dependence, and total organic carbon (TOC) content). The proposed model is validated with the published experimental data. A series of sensitivity analyses are performed to investigate the influence of fractal characteristics and action mechanisms on the apparent permeability caused by each transport mechanism. The results show that the real gas properties, water film, and stress dependence cause different effects on the total apparent permeability of shale under different fractal characteristics. The maximum pore diameter is inversely proportional to the effects of these action mechanisms, and the porosity is positively proportional to the effects of real gas properties and water film but inversely proportional to the effects of stress dependence. An increase in TOC content can cause an improvement in the total apparent permeability. Furthermore, the effects of action mechanisms on the apparent permeability caused by different transport mechanisms are differently affected by the fractal characteristics. Changes in fractal characteristics mainly affect the apparent permeability caused by slip flow in the real gas effect, slip flow and Knudsen diffusion in the water film effect, and all transport mechanisms in the stress dependence effect.

Natural Fractures Help Unlock Tight Carbonates in Oman

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 211336, “Natural Fractures Help Unlock Tight Carbonates: Redeveloping the Natih B Reservoir in a Giant Field in the Sultanate of Oman,” by Loic Bazalgette, Nawal Aamri, SPE, and Chris Field, Petroleum Development Oman, et al. The paper has not been peer reviewed. _ Within the stratigraphy of one of the largest fields in north Oman is the Natih B reservoir. The development of the reservoir has undergone several challenges over the past decades because of the complexity of the reservoir setting and difficulties in locating the natural fractures. Success in developing such tight carbonates depends on the integration of high-quality seismic, borehole imagery, petrophysics, and dynamic data. The objective of the complete paper is to develop an integrated technical approach that can be used to unlock one of the largest undeveloped resources in the operator’s current portfolio. Introduction With approximately 1 billion bbl of oil originally in place in the development area of interest, Natih B is a significant undeveloped resource in the operator’s portfolio. Attempts were made during the 1980s and 1990s to produce from Natih B, but production was uneconomical because of low productivity or early gas breakthrough. The low matrix permeability of Natih B organic-rich carbonates negatively affected the flow of the early Natih B producers, but the presence of large-scale, vertically persistent fracture corridors and fault-damage zones allowed gas from the Natih A reservoir above to shortcut into these wells. The opportunity to redevelop Natih B was initiated in late 2018. The initiative involved a tight collaboration between the operator’s fractured-reservoir specialist and subject-matter experts of the structural geology of fractured reservoirs and of carbonate reservoir geology. Overview of Natih B Properties The Natih carbonate reservoir is composed of multiple units named Natih A, B, C, D, E, F, and G from top to bottom. In the field of interest, these are structured as a fault-bounded, northeast-dipping monocline (Fig. 1). In this structure, the reservoir is shallow. The initial reservoir pressure is 61 bar at 400 m true vertical depth subsea (TVDSS). All reservoir units are in pressure communication through cross-cutting fracture corridors and have a common free water level at approximately 550 m TVDSS. Current production is from all reservoir units with the exception of Natih B. In the outcrops of the Salakh Arch area (north Oman), the Natih B unit is divided into five subunits. Under Natih B reservoir conditions, this subdivision scheme can be simplified to four well-correlatable subunits with relatively small thickness variations (Natih B1 to B4). In the area of interest, the subunit thickness is approximately 15 m for B1, 30 m for B2, 10–15 m for B3, and 15–20 m for B4. Facies show a cyclicity of clean limestone and organic-rich layers, which is more pronounced in the B1 and B2 subunits. Natih B4 isolates the Natih B reservoir unit from the underlying Natih C reservoir. Above the free water level, the porosity of Natih B subunits B1, B2, and B3 ranges generally between 0.15 and 0.30. The permeability of Natih B is low and ranges from 0.2 to 5 md, with an average of approximately 1 md.

Low permeability sealing materials based on sewage, digestate and incineration industrial by-products in the final landfill cover system

This study explores repurposing municipal solid waste from the sewage, digestate, and incineration industries as landfill-sealing materials, aligning with circular economy principles. The main materials include digested sewage sludge (DSS), pretreated digested sewage sludge (PDSS), and digestate sludge (DS), with biomass bottom ash (BBA) and Al-anodizing waste (AAW) introduced as additives, complemented by 1.5 wt% water glass to enhance the sealing performance. The research evaluates the characteristics of the various treated and sourced sludges and additives, assessing their influence on water permeability, reaction products and the environmental consequences. Results demonstrate the achievement of low permeability in the sludge-based sealing materials, with optimal performance observed in the specimens prepared with DSS and AAW (k value = 3.78 ×10−12 m/s). Thermal Pressure Hydrolysis pre-treatment in sewage plants reduces the organic content in PDSS, resulting in a slight increase in permeability. DS-based specimens exhibit higher permeability due to their relatively lower organic content in DS. Gypsum is the primary reaction product attributed to leachable sulphate in BBA and AAW. Water glass addition in BBA-modified specimens promotes silica gel formation, while AAW effectively reduces matrix permeability as an externally added gel-like substance. Additionally, heavy metals (As, Pb and Cr) derived from the by-products are effectively immobilized in the sealing materials owning to the coagulation effect of organic matter in the sludge and sulphates in the products. Overall, this novel approach to landfill sealing materials exhibits promising applications in the Netherlands, offering cost savings and reduced environmental impact by recycling industrial by-products.

Hybrid Discrete Fracture Network Inversion of Hydraulic Tomography Data From a Fractured‐Porous Field Site

AbstractThe accurate characterization of hydraulic conductivity heterogeneities in an aquifer is crucial for predicting flow and transport processes correctly. Hydraulic tomography (HT) experiments are often used to infer the hydraulically relevant features, but the correct inversion of the data remains a challenging task. We implemented a discrete fracture network (DFN) inversion approach that is expanded by considering a nonzero matrix permeability. The hybrid model allows the accurate characterization of fractured‐porous sites by taking into account both matrix and fracture flow. This novel inversion algorithm is successfully applied to HT data acquired at a field site in Goettingen (Germany), and the results are compared with those of a standard travel time inversion. Furthermore, we validate the inversion results by using them as the underlying material parameters for simulating heat tracer experiments and comparing the modeled temperature responses with those of heat tracer tests actually conducted at the site. It is shown that the DFN ensemble predicts the thermal response of the experiments correctly for the two major fractures in terms of location, amplitude, and time‐dependent behavior of the temperature anomaly, as long as the stochastic nature of the results is taken into account. We conclude that considering both matrix and fracture flow in a hybrid DFN inversion approach can lead to significant improvements in flow and transport modeling at fractured‐porous sites.

Numerical simulation of the thermo-hydro-chemical coupling in enhanced geothermal systems: Impact of SiO2 dissolution/precipitation in matrix and fractures

The hydraulic properties of reservoir matrix and fractures, as well as the production performance of enhanced geothermal systems, can be significantly affected by chemical dissolution and precipitation. Therefore, chemical reaction effects must be considered when exploiting dry hot rock resources. To investigate the impact of chemical effects, this study incorporates the dissolution/precipitation process of silica in the reservoir matrix and fractures and establishes a thermo-hydro-chemical coupling dual-well model that includes a main fracture and multiple secondary fractures. Results indicate that under-saturation injections increase the mechanical aperture of the main fracture by up to 0.066 mm and permeability by up to 217.3 % over a 30-year production period. Oversaturation injections decrease the mechanical aperture by up to 0.035 mm and permeability by up to 66.1 %. Reservoir matrix permeability exhibits a noticeable zonal distribution, with a maximum increase of 22.6 % in the under-saturation injection and a maximum decrease of 4.1 % in the saturation injection over a 30-year production period. Chemical reactions have a significant impact on the average production pressure. Neglecting chemical reactions in the matrix may result in overestimation or underestimation of changes in production pressure. These results provide a reference for the sustainable production of EGS in the long term.

Functional connectivity across dominant forest ecosystems in Ecuador: A major challenge for a country with a high deforestation rate

Ecuador is one of the countries with the highest deforestation rate in South America, despite being one of the most biodiverse countries in the world. However, there is a lack of information concerning the harmful spatial and temporal effects of deforestation on fragmentation and the connectivity lost. The objective of this research was to study the changes in deforestation (land-use changes), fragmentation patterns, and the functional connectivity of the forests of continental Ecuador between 1990 and 2018. Different land cover layers provided by the Ecuadorian Ministry of the Environment were employed, and deforestation and fragmentation were analyzed by overlaying these layers in GIS systems. Functional connectivity for generic species with a dispersion of 5 km was calculated using Graphab at global and on patch scales. The results showed that Ecuador lost 21,263 km2 of forest (transformed mainly into agricultural land) during the study period, thus losing connectivity and increasing fragmentation, with the coastal region being that most affected. Global connectivity decreased by between 25% and 13.69% during the 28-year period, depending on the metric analyzed. Corridors varied over time, thus showing that a more permeable matrix and scattered but connectable patches are essential to increase ecosystems connectivity. Although global connectivity is a fundamental factor as regards ensuring the persistence of ecosystems, it is not always being considered for either conservation or reforestation plans in Ecuador. As this work shows, the identification of corridors and their further conservation could be essential as regards maintaining global connectivity.

The characteristics and effects of Huff-n-Puff in shale with brine, aqueous surfactant solutions and CO2

In this study, we evaluated the permeability damage and throughput potential of shale cores, focusing particularly on the damage water inflicts on shale permeability and the potential for hydrocarbon extraction using various injection media. Nuclear magnetic resonance (NMR) was utilized to analyze the distribution of crude oil across different pore sizes and to determine the limits of their utilization under varied media injection cycles. The results indicate that the Shengli Oilfield FY shale possesses abundant inorganic pores, primarily composed of intergranular and intragranular pores. Organic matter is dispersed and contains numerous micro-fractures. While formation water has only a minor impact on the permeability of fractured cores, it significantly impairs matrix permeability. Moreover, when the formation water content exceeds 10%, the degree of damage will decrease. In contrast to formation water, distilled water causes serious damage to both matrix and fractured cores. Therefore, anti-swelling measures are essential to ensure effective development in subsequent stages. After five injection cycles, the final recovery rates for brine, surfactant, and CO2 injection are 11.5%, 29.3%, and 45.9%, respectively. CO2 injection demonstrates the best production enhancement, followed by surfactant injection. CO2 is particularly effective in each cycle, primarily due to its expansion and extraction mechanism. Surfactants enhance production mainly by reducing interfacial tension and altering wettability, resulting in significant improvement in the first cycle. Meanwhile, brine injection primarily augments production through improved wettability and capillary pressure, resulting in a moderate production improvement. Based on NMR experiments, the minimum pore size for CO2 injection is estimated to be around 10–15 nm, Surfactant injection necessitates pore sizes with a minimum of 30–40 nm and brine injection requires pore sizes of approximately 60–70 nm. This research provides valuable experimental data for on-site shale oil development and deepens our understanding of the mechanisms involved in hydrocarbon recovery from shale using different injection media.

The enriched-embedded discrete fracture model (nEDFM) for fluid flow in fractured porous media

The embedded discrete fracture model (EDFM) is widely adopted for simulating fluid flow in fractured porous media, but it faces limitations when dealing with blocking fractures due to its assumption of symmetric and linear pressure distribution around fractures. To improve this, our work presents a novel numerical framework named the enriched-embedded discrete fracture model (nEDFM). This framework, based on a non-conforming grid and discretized using the mass-conservative finite volume method, offers significant advancements. An attractive feature of the nEDFM is its applicability to both conductive and blocking fractures, as well as isotropic and anisotropic matrix permeability, all while maintaining a low computational cost. The local shape function, which introduces two enriched degrees of freedom for every fracture cell, is developed to model the discontinuities of pressure and its gradient on two sides of the fracture. Additionally, two equations for coupling the matrix and reduced fracture are supplemented to close the system and improve the accuracy of mass exchange between the matrix and fracture. Comparative assessments between the nEDFM, classical EDFM, and projection-based EDFM (pEDFM) demonstrate the superior performance of nEDFM. Specifically, the nEDFM outperforms the EDFM for conductive fractures and can obtain better pressure distribution inside blocking fractures than the pEDFM. In scenarios involving anisotropic matrix permeability with either conductive or blocking fractures, the nEDFM can get solutions comparable to those obtained by the reference solution. Hence, the nEDFM emerges as an accurate and flexible method for simulating fluid flow in fractured porous media.

Performance evaluation of enhanced geothermal systems with intermittent thermal extraction for sustainable energy production

Efficient extraction of thermal energy from deep geothermal reservoirs using Enhanced Geothermal Systems (EGS) is fundamental for sustainable clean energy generation. This study presents the Intermittent Thermal Extraction (ITE) method, addressing thermal breakthrough challenges encountered during continuous thermal extraction (CTE) within EGS reservoirs. Employing a thermal-hydraulic coupled approach and discrete fracture network modeling, the ITE process for EGS reservoirs is assessed, omitting considerations of stress-induced deformation. The research evaluates the ITE and CTE methods within a typical high-temperature geothermal reservoir in the Himalayan geothermal belt. Analysis includes variations in reservoir temperatures and pressures, alongside an examination of rock matrix permeability and injection fluid temperature impacts on EGS thermal extraction performance. Results demonstrate the ITE method's efficacy in prolonging the EGS reservoir lifespan by preventing thermal breakthroughs and maintaining pressure equilibrium. Under studied conditions, ITE extends the EGS reservoir lifespan by a minimum of 17.7 years, amplifying clean power generation by 13.1% compared to CTE. Additionally, ITE implementation substantially reduces greenhouse gas emissions by an estimated 1.46–5.03 million tons. The rock matrix permeability and injection fluid temperature significantly affect the EGS thermal extraction performance when the fracture aperture is constant. These findings highlight the ITE method's potential to optimize thermal extraction from EGS reservoirs, particularly in remote regions. This study contributes essential insights into advancing geothermal energy extraction techniques, emphasizing ITE as a promising approach for sustainable energy production.

The friction factor of the fracture-matrix system considering the effects of free flow, seepage flow, and roughness

The friction factor plays a crucial role in evaluating pressure gradient loss for water flow through fracture-matrix systems (FMS). This study presents a theoretical model for the FMS friction factor, incorporating viscous and inertial terms based on Forchheimer's law. The model considers the coupled effects of free flow, seepage flow, and roughness. The non-Darcy coefficient in the inertial term is determined by fitting 284 sets of FMS seepage test data. To validate the derived friction factor, COMSOL simulations are conducted using the coupled free and porous media flow module, considering two relative roughness values. The proposed model demonstrates higher accuracy compared to existing models and experimental data, with 101 fewer missed prediction points and a 21.4% improvement in accuracy. Additionally, this study examines fluid flow regimes and critical Reynolds numbers for various matrix porosities, permeabilities, fracture apertures, and relative roughness values. The findings reveal that FMS with low matrix permeability, high roughness, and small apertures exhibit larger friction factors and are more prone to nonlinear deviations from Darcy flow.

Permeability reduction techniques: Plain and fiber HPAM gels in fractured cores

The aim of this study is to investigate how fibers influence the ability of polymer gels to resist washing out from fractures. For this purpose, synthetic and mineral wool fibers were integrated into polymer gels. These fiber-gels were compared to plain gels using bottle tests, viscosity measurements, and fractured core flooding experiments.The bottle tests show no effect of 13-mm-long synthetic fibers on gel strength. However, inside a constricted fracture, the polymer-synthetic fiber gel exhibited 8.4 times higher resistance to the flow of brine compared to the plain gel. This is explained by the retention of the fibers at the constriction point. In low salinity brine, mineral wool fibers allowed a substantial improvement in gel strength, while, at the same time, a reduction in the concentration of chemicals by 40% was made possible.Furthermore, with the addition of 0.6 wt.% mineral wool fibers, the viscosity of the 0.3 wt.% polymer gel increased from 560.5 to 106,920 cp. In fact, in a 1-mm-wide fracture, a gel containing 0.3 wt.% polymer and 0.6 wt.% mineral wool fiber achieved a post-flush pressure gradient that was 58 times higher than a 0.75 wt.% plain polymer gel. Unfortunately, the choice of a makeup brine with an increased salinity resulted in the deterioration of fiber-gel strength. Nonetheless, a substantial improvement of gel strength can be achieved by adding 0.6 wt.% mineral wool fibers, even if the salinity is as high as 143 g/L. Moreover, in experiments in which the permeability of the adjacent matrix was very low, 0.018 mD, a gel of 0.3 wt.% polymer and 0.6 wt.% mineral wool fiber prepared in 242.6 g/L brine, was still superior to a 0.75 wt.% plain gel prepared in low salinity brine.Experimentation with large fracture widths of 2.55 mm and 4 mm was also done to confirm gel effectiveness. For example, a gel of 0.3 wt.% polymer and 0.6 wt.% mineral wool fiber, prepared in 14 g/L brine, provided a 1.46 times higher post-flush pressure gradient in a 2.55-mm-wide fracture, as compared to that of a 0.75 wt.% plain polymer low salinity gel in a 1-mm-wide fracture. With an increase in the salinity, to 234.6 g/L, of the makeup brine used with a fiber-gel, the resistance to the flow of brine in a 2.55-mm-wide fracture became comparable to that of a plain gel in a 1-mm-wide fracture. In a 4-mm-wide fracture, a gel with 0.3 wt.% polymer prepared in 234.6 g/L brine and one of 0.5 wt.% polymer prepared in 14 g/L brine, each with 0.6 wt.% mineral wool fiber, provided maximal post-flush pressure gradients equal to 12–14 psi/ft. This is the same range usually expected from a 0.5 wt.% relatively low molecular weight plain polymer gel in a 1-mm-wide fracture.Although, fibers improved the ability of gels to resist washing out from fractures, in a 4-mm-wide fracture such a fiber-gel could not provide notable resistance to the flow of brine with an increase in the superficial flow velocity higher than 1,000 ft/d. Discovering formulas that would increase the resistance of gels to being washed out of wide fractures must continue.

Investigations of Water Transport in Shale Reservoir with Dual-Wettability by Using Monte Carlo Method.

How liquids transport in the shale system has been the focus because of fracturing fluid loss. In this study, a single-nanopore model is established for liquid transport in shale while considering the slip effect and effective viscosity of confined fluids. Then, the fractal Monte Carlo (FMC) model is proposed to upscale the single-pore model into shale porous media. The effects of different transport mechanisms, shale wettability, and pore characteristic parameters on confined liquid flow in shale rock are investigated. Results show that FMC permeabilities are 2-3 orders of magnitude larger than intrinsic and slip-corrected permeabilities in organic matter. However, the slip effect and effective viscosity have little influence on water flow in inorganic matter. With the contact angle of organic pore (θom) increasing and contact angle of inorganic pore (θin) decreasing, the effective permeability of the whole shale matrix grows in number. The enhancement factor in the situation of θom = 170° and θin = 20° is 4 orders of magnitude larger than the case of θom = 130° and θin = 40°, although the close effective macroscopic contact angle (θeff = 80°) occurs in these two cases, which indicates that shale microscopic wettability has a significant impact on the confined liquid transport. Moreover, with the increase of porosity and maximum pore diameters, shale permeability increases rapidly, but the enhancement factor has the opposite trend. Compared with the tiny impact of the variance of minimum inorganic pore diameters, minimum organic pore diameters have more significant impacts on liquid flow in shale systems, and the enhancement factor also rapidly increases up to 30 times for the case of 0.5 nm because of the strong slip effect.