Shale Swelling Research Articles

Amine-functionalized graphene oxide in polyamine based drilling fluids for nanosized pore plug filter cake

Water-based muds (WBM) is widely used in oil and gas wells drilling industry due to its environmental friendliness and lower operational cost implication. However, WBM drilling process has severe shale swelling problems caused by the hydration due to the shale minerals affinity to water from the WBM which reduces WBM technical performance. Thus, additives that fitted to its function should be added in WBM formulations to enhance overall drilling performance to achieve the target depth. In this study, graphene oxide (GO) is selected as the additive due to its excellent physico-chemical properties could benefit as an option to mitigate the above challenges. GO was synthesized via Modified Hummers' method where the average thickness obtained was ±46 nm. The GO additive was then modified with Octadecylamine (ODA) to alter the surface hydrophobicity. The contact angle of GO changed from 25° ± 0.5 to 98.9° ± 1.8 after the ODA modification. The hydrophobic GO (HGO) was then added in the drilling fluid formulation and the drilling fluid performance was evaluated based on filtration characteristics. The filter cake showed a thickness of 0.832 mm and a filtrate volume of 5.09 ml at 150 psi/30 min after the filtration with drilling fluid treated with HGO. The filter cake formed was the thinnest and the least filtrate volume was produced which are 30% and 20% reductions compared to drilling fluid without GO, which signify the remarkable reduction of fluid loss. On top of that, the drilling fluid with HGO demonstrated a good rheology property over wide shear rate scheme and enhanced thermal stability. Hence, GO was highly recommended as a potential fluid loss control nano-additive in drilling fluid formulation.

An equivalent time-dependent analysis for predicting horizontal wellbore instability in a reactive shale formation using the imbibition/diffusion principle

Osmotic pressure generation, ion migration, shale swelling, and strength reduction are some problems engineers face when drilling through reactive shale. Mody and Hale's model for evaluating the osmotic pressure is not explicitly time-dependent, whereas diffusion is. Moreover, it does not consider membrane destruction with time. Thus, it becomes difficult to apply the model during the analysis of time-dependent instability without needing the conventional thermo-chemo-mechanical coupling process. This process is costly, rigorous, and time-consuming and does not consider the membrane's destruction with time. To this end, the authors analyzed wellbore instability in reactive shale by exploiting Kirsch's stresses. The authors derived some equations for strength reduction, membrane destruction with time, and the time-dependent osmotic pressure based on empirical analysis. Then, they added these equations to the constitutive stresses and applied the Mogi-Coulomb criterion. The study area is located in the passive continental margin of the Tertiary Niger Delta, which has shale diapirs and many growth faults near the deep Atlantic. The results show that the wellbore instability increases with time in an open face mainly because of diffusion and strength reduction. Wellbore instability affected the fracture pressure more than the collapse pressure. In addition, the increase in the Cation Exchange Capacity (CEC) or clay content causes the mud window to reduce with time.

Effects of shale swelling on shale mechanics during shale–liquid interaction

An essential feature of shale is swelling induced by shale–liquid interactions. Shale swelling is an important inducing factor for shale damage that affects shale mechanics. A better understanding of the effects of shale swelling on shale mechanics is crucial for drilling and fracturing design. Therefore, the effects of shale swelling on shale damage and shale mechanics were investigated. The results demonstrated that an increase in shale swelling increases shale damage, thus negatively affecting shale mechanics. The compressive strength decreases rapidly with increasing shale swelling. Moreover, the decrease in the elastic modulus is controlled by shale swelling. The elastic modulus of shale reduces by 17.9% when shale swelling is 0.4%, compared to only 3.1% when shale swelling is 0.2%. The effects of shale swelling on the elastic modulus are affected by quartz content and confining pressure. Shale can maintain a high elastic modulus at high quartz content during shale swelling. The correlations of shale swelling and elastic modulus under different quartz contents were established. Based on these research results, a possible reason for casing deformation in the Weirong shale gas field was discussed.

Application of Novel Magnetic Surfactant-Based Drilling Fluids for Clay Swelling Inhibition

Water-based drilling fluids are widely employed in the oilfield industry for the efficient and smooth drilling of wellbore reservoirs. In this study, a novel drilling formulation was prepared by mixing a magnetic surfactant in the base mud formulation. Several drilling fluid tests were conducted, which include steady shear and dynamic rheology, filtration, clay sedimentation, clay swelling, and particle size distribution analysis. Different analytical techniques─XRD, FTIR, and TGA analyses─were performed to study the interactions of magnetic surfactant with the clay platelets. The experimental results of the surfactant-modified formulations were compared to the base mud formulation. Thermal gravimetric analysis of the surfactant-modified mud showed improved thermal stability compared to the base mud. FTIR analysis results of the base mud and surfactant-modified mud were compared. In the steady shear rheology experiments, the flow curves of the base mud and surfactant-modified mud showed that the addition of surfactant in the base mud affects the shear stress of formulation. The shear stress data of rheology was fitted to the Herschel–Bulkley model, and model parameters trends were assessed with and without the addition of surfactant in the base mud. Shale inhibition tests showed that the incorporation of magnetic surfactant minimized the clay hydration of swelling, thus proving a superior shale inhibitor. The particle size analysis showed that the average particle size of clay particles increased with the increasing concentration of the magnetic surfactant. The linear swelling analysis of clay showed that the rate of swelling was 90% in the surfactant-modified mud as compared to the swelling rate in deionized water. According to the zeta potential, the combination of surfactants significantly affects the electrokinetic behavior of dispersion. Further, the XRD proved that the interlayer spacing of clay increasing while interacting with magnetic surfactant molecules indicates the ability of magnetic surfactant as a shale swelling and hydration inhibitor for water-based drilling formulations.

Statistical approach used to evaluate the performances of different diffusion correlations in modeling Pakistan shale swelling characteristics

Statistical approach used to evaluate the performances of different diffusion correlations in modeling Pakistan shale swelling characteristics

Nano-scale synchrotron imaging of shale swelling in the presence of water

Swelling of shale in response to interaction with water is an important consideration within subsurface energy systems. In the case of waste disposal, swelling can provide important barriers around the waste and enhance the sealing ability of rocks. For shale gas exploration purpose, however, swelling may cause wellbore instability. Therefore, a careful study of shale swelling is critical for subsurface energy related applications. Here, the swelling effects of shale were imaged at nanoscale using an advanced synchrotron Transmission X-ray Microscopy (TXM) imaging technique for the first time, with a spatial resolution down to 40.9 nm. Organic matter and clays within the analysed sample were observed to display large swelling effects which resulted in a 50% reduction in porosity. Strain maps generated using Digital Volume Correlation (DVC) show deformation and significant strain were mostly localized to between the contact boundaries of sharp brittle minerals and softer organic matter and clays. This is the first study, to our knowledge, to directly image the swelling deformation of shale at the tens of nanometer scale and provide local information on the strain evolution.

A Magnetic Surfactant Having One Degree of Unsaturation in the Hydrophobic Tail as a Shale Swelling Inhibitor

One of the foremost causes of wellbore instability during drilling operations is shale swelling and hydration induced by the interaction of clay with water-based mud (WBM). Recently, the use of surfactants has received great interest for preventing shale swelling, bit-balling problems, and providing lubricity. Herein, a novel synthesized magnetic surfactant was investigated for its performance as a shale swelling inhibitor in drilling mud. The conventional WBM and magnetic surfactant mixed WBM (MS-WBM) were formulated and characterized using Fourier Transform Infrared (FTIR) and Thermogravimetric analyzer (TGA). Subsequently, the performance of 0.4 wt% magnetic surfactant as shale swelling and clay hydration inhibitor in drilling mud was investigated by conducting linear swelling and capillary suction timer (CST) tests. Afterward, the rheological and filtration properties of the MS-WBM were measured and compared to conventional WBM. Lastly, the swelling mechanism was investigated by conducting a scanning electron microscope (SEM), zeta potential measurement, and particle size distribution analysis of bentonite-based drilling mud. Experimental results revealed that the addition of 0.4 wt% magnetic surfactant to WBM caused a significant reduction (~30%) in linear swelling. SEM analysis, contact angle measurements, and XRD analysis confirmed that the presence of magnetic surfactant provides long-term swelling inhibition via hydrophobic interaction with the bentonite particles and intercalation into bentonite clay layers. Furthermore, the inhibition effect showed an increase in fluid loss and a decrease in rheological parameters of bentonite mixed mud. Overall, the use of magnetic surfactant exhibits sterling clay swelling inhibition potential and is hereby proffered for use as a drilling fluid additive.

An investigation into shale swelling inhibition properties of dodecyltrimethylammonium chloride (DTAC) for water-based drilling fluids

Shale formations adsorb water and swell when they are in contact with water-based drilling fluids due to the content of active clay minerals. Shale swelling in the well wall is one of the main challenges of drilling operations and causes many problems and damages. Modifying drilling mud with shale swelling inhibitors is one of the solutions to this challenge. Recently, amines and their derivatives have been considered by researchers due to their ability to control the swelling of shale layers and the range of properties that can be adapted to any drilling conditions. In this study, Dodecyltrimethylammonium Chloride (DTAC) was investigated as a new shale stabilizer and swelling inhibitor. Various tests such as bentonite sedimentation, bentonite inhibition, shale sample recovery and dynamic linear swelling were used for this study. Wettability, zeta potential, isothermal water adsorption and thermogravimetric analysis (TGA) tests were performed to evaluate the mechanism of action of this amine-based shale swelling inhibitor. Based on the results, DTAC shows good inhibition power in controlling and reducing the swelling of shale and bentonite samples at both low and high temperatures, even at low concentrations. DTAC is well-compatible with other common additives in drilling fluids. On the other hand, this amine shows a relatively stronger function than Cetyltrimethyl Ammonium Bromide (CTAB) and Ammonium Chloride (NH4Cl). Adsorption of DTAC molecules on the surface of charged plates of bentonite particles reduces the negative charges of these plates, makes inaccessible places available on the plates of water molecules, increases their hydrophobicity and finally reduces the sensitivity of surfaces to adsorption of water molecules, which leads to stabilization of shale samples and bentonite particles against contact with aqueous media.

Shale damage simulation considering shale swelling during shale-liquid interaction

Shale-liquid interactions can lead to shale swelling, shale damage and affect the mechanical and other properties of shale. The relationship between shale swelling and shale damage was not well understood. A better understanding of the relationship is essential for drilling and fracturing designs. In this work, we employ shale swelling tests, computed tomography scanning technology and numerical simulation to understand the relationship between shale swelling and shale damage. The experimental results show that the shale swelling is 0.23% after the experiment. When the shale swelling is small, the damage is weak. However, the shale damage growth rate is 495.05% when the shale swelling rate increases by 0.19%, and macrofractures are formed. Using COMSOL with MATLAB, we further explore the relationship between shale damage and shale swelling. The simulation results show that shale swelling has an important effect on shale damage, and this effect is verified by comparing the simulation and experimental results. Shale damage is weak or even absent when shale swelling is not considered, while the distinct shale damage can be observed when shale swelling is considered. The increase of shale swelling leads to the increase in shale damage, which leads to more obvious fractures expansion, resulting in an increase in permeability. When shale swelling is 0.4%, the permeability at the end of the simulation is 322% higher than the initial permeability. The variation in stress at 0.4% shale swelling is 21 times that without considering shale swelling, and the large variations in stress are an important factor in shale damage. The higher the in-situ stress, the lesser is the tendency for shale damage to occur. Shale damage occurs at high injection pressures, even when shale swelling is low. In addition, the more complex the fracture network, the higher is the tendency for shale damage to occur, and the permeability after the simulation was 6% higher than that of bedding model. Therefore, fracturing methods with high injection pressures should be used, and the hydraulic fracturing should be conducted at locations where natural fractures develop to achieve significant shale-liquid interactions and better hydraulic fracturing results.

EFFECT OF CLAY MINERALOGY AND BRINE CONCENTRATION ON THE SWELLING PROPERTIES OF SHALE.

Chemical wellbore instability is mostly attributed to the “unfavorable interaction” between the formation pore fluid, its shale constituents and the drilling fluid, this is mostly experienced in terms of shale swelling that tends to under gauge the drilled well. This study was conducted to examine the impact of brine concentration and mineralogy on the swellability of shale. Sixteen shale samples were obtained from selected wells across two selected fields (OR and OG) in the Niger Delta. X-ray diffraction analysis was carried on the shale samples to determine its mineralogy distribution. A Nacl brine solution was prepared alongside a water based mud formulated using sodium chloride brine of varied concentration. The shale samples were tested for its swellability in both brine solution formulated water based mud for 24 hours and 48 hours. Results obtained showed that there were more clay minerals (56%) across both fields and that Palygorskite was the most abundant clay minerals for both fields. Also, for the swelling test (shale-in-brine and shale-in-mud) that the shale samples swelled in both medium as expected, but to different degrees, mainly as a function of the mineralogy content of the shale and the brine concentration of the fluid in which they are immersed. The import of this goes to buttress the necessity for understanding the place of mineralogy and concentration in the study of wellbore instability caused by chemical interaction.

Synthesis of amyl ester grafted on carbon-nanopolymer composite as an inhibitor for cleaner shale drilling

Wellbore instability in oil and gas industry well drillings is a significant challenge that is linked to shale swelling when shale interacts with free water molecules in the water-based drilling fluid. Strategic design of environmentally benign, biodegradable, and effective shale hydration inhibitors is a prominent objective of contemporary exploration in well-drilling fluids as a replacement for the common KCl which is detrimental to aquatic lives. This work reports the synthesis and potential of novel green acrylic polymer-amyl ester activated carbon (-C) nanocomposite to hinder shale hydration in formations during drilling. Both less hydrophobic acrylic acid-acrylamide-activated carbon-amyl ester (AA-AAm-C-Amyl) and more hydrophobic acrylic acid-acrylamide-octadecene-activated carbon-amyl ester (AA-AAm-OD-C-Amyl) composites were synthesized, characterized, and tested with standard methods as a cleaner fluid additive for shale swelling inhibition, and their results compared with that of KCl. The polymer matrixes displayed remarkable thermal stability. Results also indicate that AA-AAm-C-Amyl and AA-AAm-OD-C-Amyl composites could stabilize wellbore effectively with 95.2% and 93.7% anti-swelling ratio, and shale recovery capacity of 97 and 95.2% respectively. The surface evaluation of the composite fluid-treated bentonite revealed that the mechanism of inhibition could be based on the collaborative action of nanopore plugging of carbon core and strong adsorption of the polymer component of the materials on clay surfaces via encapsulation and hydrogen bonding to form an impressive filter cake which could actively prevent water invasion into formation. Hence, AA-AAm-C-Amyl and AA-AAm-OD-C-Amyl composites could be a sustainable substitute for the conventional KCl as a shale inhibitor for well-drilling.

Robust superhydrophobic TiO2@carbon nanotubes inhibitor with bombax structure for strengthening wellbore in water-based drilling fluid

Shale gas has become one of the most promising energies to cope with the ever-increasing energy demand, while wellbore instability incidents frequently occur due to the hydration and subsequent swelling of shale during the long horizontal drilling process. In this paper, a novel superhydrophobic carbon nanotube composite for high-efficiency water-based drilling fluid was prepared by the combination of the chemical vapor deposition method and the in-situ precipitation method. The prepared composite can form a superhydrophobic adsorption layer with high roughness and low surface free energy on the rock surface, achieving hydration inhibition by wettability alteration. The functional groups, surface morphology, electrical properties, and element valence of the synthesized composite were characterized by FTIR, SEM, zeta potentiometer, and XPS technique, result evidenced that the product was prepared as expected design. The effect of superhydrophobic carbon nanotube composites on the rheology and filtration properties of drilling fluid was studied, the drilling fluid can maintain favorable viscosity and shear force after adding the composite; the linear expansion rate test, the contact angle measurement, and lubrication experiments were performed to evaluate the inhibition and lubrication performance, the linear expansion rate of core decreased from 59.1 % to 21.9 % after treated with 1 % composite solution for 16 h, the wettability of rock surface can be altered from liquid-wetting to strong hydrophobicity, the reduction rate of extreme pressure lubrication coefficient was 46.9 %, and the zeta potential of shale decreased with the increasing concentration of composite. The possible explanation for its excellent performance could be that the superhydrophobic carbon nanotube composite can form a dense hydrophobic adsorption layer on the shale surface through electrostatic attraction, and an anchoring structure between the neighboring crystal lattices can be preferentially formed by the amino groups in the non-polar end of the molecule, which can alleviate the intrusion of drilling fluid, achieving the inhibition of the hydration and expansion of shale.

Bridging performances of lost circulation materials (LC-LUBE and mica) and their blending in 80/20 and 60/40 oil-based drilling fluids

In drilling wells, lost circulation, barite sagging, shale swelling, and formation damage are critical problems for the industry. These problems can be controlled by designing appropriate drilling fluids and lost circulation materials. In this study, the performance of 80/20 and 60/40 oil-based drilling fluids (OBMs) was compared based on the lost circulation materials’ (LCMs) bridging performance, filtrate loss, barite sagging, and shale stability. The results show that in terms of LCM stability, the performance of LC-LUBE improved when blended with mica. Both drilling fluids inhibit shale swelling. The overall analysis showed that the 60/40 OBM is better and recommended.

Improving the anti-collapse performance of water-based drilling fluids of Xinjiang Oilfield using hydrophobically modified silica nanoparticles with cationic surfactants

Wellbore instability, especially drilling with water-based drilling fluids (WBDFs) in complex shale formations, is a critical challenge for oil and gas development. The purpose of this paper is to study the feasibility of using hydrophobically modified silica nanoparticle (HMN) to enhance the comprehensive performance of WBDFs in the Xinjiang Oilfield, especially the anti-collapse performance. The effect of HMN on the overall performance of WBDFs in the Xinjiang Oilfield, including inhibition, plugging, lubricity, rheology, and filtration loss, was studied with a series of experiments. The mechanism of HMN action was studied by analyzing the changes of shale surface structure and chemical groups, wettability, and capillary force. The experimental results showed that HMN could improve the performance of WBDFs in the Xinjiang Oilfield to inhibit the hydration swelling and dispersion of shale. The plugging and lubrication performance of the WBDFs in the Xinjiang Oilfield were also enhanced with HMN based on the experimental results. HMN had less impact on the rheological and filtration performance of the WBDFs in the Xinjiang Oilfield. In addition, HMN significantly prevented the decrease of shale strength. The potential mechanism of HMN was as follows. The chemical composition and structure of the shale surface were altered due to the adsorption of HMN driven by electrostatic attraction. Changes of the shale surface resulted in significant wettability transition. The capillary force of the shale was converted from a driving force of water into the interior to a resistance. In summary, hydrophobic nanoparticles presented a favorable application potential for WBDFs.

Formulating Inhibited Fluids for Stable Drilling Operations into Tanuma and Zubair Shales, Zubair Oilfield, Southern Iraq

Tanuma and Zubair formations are known as the most problematic intervals in Zubair Oilfield, and they cause wellbore instability due to possible shale-fluid interaction. It causes a vast loss of time dealing with various downhole problems (e.g., stuck pipe) which leads to an increase in overall well cost for the consequences (e.g., fishing and sidetrack). This paper aims to test shale samples with various laboratory tests for shale evaluation and drilling muds development. Shale's physical properties are described by using a stereomicroscope and the structures are observed with Scanning Electron Microscope. The shale reactivity and behavior are analyzed by using the cation exchange capacity testing and the capillary suction test is utilized for selecting shale inhibitor base. As a result, four drillings muds are formulated with different additives and approved by using the Linear Swelling Meter and the Hot Rolling experiments. Tanuma’s shale is at higher reactivity level, where it is moderate to high active shale than Zubair’s shale, which is at a low to moderately reactive formation. Microfractures and micropores are excited in both formations and potentially in Tanuma’s shale. The shale stability can be achieved by adding 8 % of KCl for Tanuma’s mud and 4% of KCl for Zubair’s mud. The filtration controls are contributed to seal the shale open structures and adding the Poly amino acid hydration suppressant reduced the risk of shale swelling significantly. The results can be used for designing drilling mud to reduce shale instability issues and the cost.

A Double Action P-D (Polymer-Deep Eutectic Solvent) Based Shale Inhibitor in Drilling Mud

Shale stabilization is very significant during drilling to avoid wellbore stability issues. Water based drilling fluid results into shale swelling on contact with shale formation. Different additives are added in the drilling mud which inhibits the shale swelling by stabilizing the charge on the clay surface. Various polymers and different Deep Eutectic Solvents (DES) have been proven to be successful shale inhibitors, but their performance can be further improved by using a combination of polymer and DES. This research features a double action P-D (Polymer – Deep Eutectic Solvent|) inhibitor formulated by the combination of Potassium Carbonate based DES and modified oxazoline based polymer and compares its inhibition performance with KCl (Potassium Chloride). Linear Swell meter has been used after compressing the Na-Bt (Sodium bentonite) wafers at 1600 psia and swelling results have been analysed after 24 hours. Moreover, surface tension, d-spacing, and Zeta potential of inhibitors-based samples have been measured to justify and understand the swelling results. The results showed P-D inhibitor showed the best inhibition of 76% with maximum decline of 36% and 73% in Surface tension and Zeta Potential respectively. The double action of P-D inhibitor is associated with its capability to form hydrogen bond and exhibit Vander wall forces with the clay surface altogether.

A critical investigation of diffuse double layer changes in clay-electrolyte systems at high temperatures

Abstract The objective of this work was to explore the impact of temperature on shale swelling and explain it in terms of diffuse double layer mechanics: Debye–Hückel length alterations. This was made possible through the use of a newly developed thermal linear swelling test. Moreover, the combined impact of temperature, dielectric constant of water and ionic strength (ionic concentration) of salt solutions on Debye–Hückel length and resultant shale swelling and shrinkage were investigated. For dilute solutions, results showed that the product of temperature and dielectric constant of water (T*εr) remained near constant for a wide range of temperature (25–90°C). Results suggest that the dielectric constant of water may have been reduced by both temperature and ionic strength of solution, all of which caused a greater reduction in Debye–Hückel length and subsequent shale shrinkage. As for saturated NaCl and CaCl2 solutions, shale exhibited swelling behaviour at moderate temperatures followed by shale shrinkage thereafter. This could be attributed to the development of repulsive forces between alike ions within diffuse double layer. At higher temperatures, the contribution of dielectric constant of water on lowering Debye–Hückel length may have softened the repulsion action produced by ions.

Recent Advances in Deep Eutectic Solvents as Shale Swelling Inhibitors: A Comprehensive Review.

Inhibitors have evolved from their primary function of controlling swelling during hydraulic fracturing processes in shale reservoirs. This study provides a comprehensive review of recent deep eutectic solvent (DES) advancements as inhibitors in swelling inhibition techniques. The swelling inhibitory potentials and mechanisms of DESs have been studied analytically and compared to existing conventional inhibitors. The functional effects of concentration, temperature, and types of DES are explored. Data on the effect of DES on rheology, swelling, zeta potential, shale cutting recovery, surface tension, particle size distribution, XRD, and FTIR analyses are presented. Along with preparation procedures, environmental concerns and applications of DESs in several fields are discussed. This study suggests that DESs are preferable swelling inhibitors due to their inhibitory performance, cost-effectiveness, and environmental friendliness. Moreover, this review includes guidelines and recommendations for selecting and designing DES to inhibit swelling more effectively.

Comprehensive Review of Property Alterations Induced by CO2–Shale Interaction: Implications for CO2 Sequestration in Shale

CO2–shale interaction performs a crucial role in determining the capacity and leakage risk of CO2 storage in shale reservoirs. In this paper, the alterations of physical and chemical properties of shale triggered by CO2–shale interaction are reviewed, and then the implications for CO2 sequestration in shale formations are discussed. CO2–shale interaction induced the mineral alterations in shale and then further induced the pore structure alterations. The pore structure alterations are mainly controlled by mineral dissolution/precipitation and extraction and CO2 adsorption induced swelling in shale, which is closely related to the reservoir pressures and temperatures. Furthermore, the mineral and pore structure alterations may also influence the wetting behavior of shale. After CO2 exposure, the contact angle of shale increased, indicated the weakening in the hydrophilicity of the shale surface. The microscopic property alterations induced the macroscopic mechanical properties of shale to be weakened after CO2–shale interaction. The permeability variation of shale is significantly influenced by chemical–mechanical coupling effects including mineral dissolution/precipitation, adsorption induced swelling, wettability, and mechanical weakening induced by CO2–shale interaction. The shale property alterations will ultimately affect the CO2 storage capacity and security in shale. Future research needs to focus on the CO2–shale interaction covering multiple spatial and temporal scales at in situ conditions and considering the chemical–mechanical coupling effect on CO2 sequestration in shale.

Effects of chemical osmosis on swelling clays and the elastic properties of the Pierre shale with its implications for oil recovery

The main objective in this study is to experimentally investigate how two types of shales different in swelling characteristic and organic carbon content behave in terms of the mechanical and infiltration properties when being subjected to changing osmosis with varying brine salinity under in-situ stress conditions. This research also aims to determine the swelling tendency of thePierre shale and replicate the effect of selection of brine salinity on oil recovery in liquid-rich shales. A series of coupled measurements from the triaxial experiments at reservoir conditions was conducted on Pierre shale core samples to determine rock properties and behavior under fluid pore pressure intrusion. The main use of the measured properties is to demonstrate the impact of fluid transport induced by low salinity water injection accompanied by osmosis, clay swelling, and rock elasticity change on oil recovery from rock matrix. The Young's modulus, bulk modulus, and Poisson's ratio of the Pierre shale were determined from measurements on the two types of Pierre shale samples obtained from an outcrop having high 65 wt% of smectite content and well core having lean clay content and 3.5 wt% TOC (total organic carbon). The first two experiments were performed on the outcrop samples comprising of similar characteristics of 65 wt% smectite with negligible TOC while the last experiment was performed on the well core sample containing negligible smectite content with 3.5 wt% TOC. The membrane efficiencies of the shale samples were experimentally determined to range from 5% to 28% depending on clay content and stress. The outcrop shale showed 1% of swelling that is significantly higher than 0.07% of swelling developed in the well core shale lean in clay content. One of the most important findings of this research is that the membrane coefficient representing the stress sensitivity of membrane efficiency of organic-rich well core shale was found to be 11.5%/kpsi which is significantly higher than that of the swelling shale ranging from 2.2 to 3.5%/kpsi. This is interesting because the approximately 5.5 times stiffer matrix of organic-rich shale shows the significantly higher stress sensitivity in terms of the membrane efficiency. The Young's modulus of swelling shale declined with water saturation as well as the water transfer driven by osmotic pressure with low salinity brine. In contrast, the well core shale showed significant increase in the dynamic Young's modulus. The experimental data were used to evaluate the mass exchange between the fractures and rock matrix using a coupled fluid flow and geomechanics model accounting for shale swelling and osmosis transport to evaluate how fluid and rock interaction affect the oil recovery from the rock matrix of the Pierre shale during low salinity water injection (LSWI). A 25% increase in oil recovery factor was determined after considering the effects of changing membrane efficiency due to clay swelling resulting from LSWI. The modeling results therefore suggest that the variation of membrane efficiency due to swelling can be an important factor affecting the oil recovery from matrix block during LSWI enhanced oil recovery.