Shale Surface Research Articles

Analytical simulation of the simultaneous adsorption process of methane and water vapor in shales

ABSTRACT Investigations on the diffusion – adsorption of methane and water vapour in shale nanopores are essential for developing shale gas extraction. A kinetic model considering diffusion and different adsorption mechanisms was proposed. An analytical solution to the model was obtained through the integral transformation method and used to predict the distributions of methane and water within a shale particle. The results suggest that the reversible adsorption caused by the dispersion force is not the only adsorption mechanism; irreversible adsorption caused by hydrogen bonding or other types of intermolecular forces is more prominent, lengthening the delay to reach equilibrium. The presence of water strongly affects shale, considerably decreasing the diffusivity and adsorption capacity as well as the swelling of the shale matrix caused by the increase in the methane pressure. The diffusion and adsorption process expands to the shale particle surface after the pores near the particle centre are filled. The transport and storage of water vapour are more sensitive to the pore structure than those of methane. In the initial stage of the methane diffusion‒adsorption process, a large number of water molecules enter the particles, and the adsorbed water hinders methane molecules from contacting the shale surface.

Improving shale hydration inhibition with hydrophobically modified graphene oxide in water-based drilling fluids

Frequent wellbore instability issues caused by shale hydration and dispersion are encountered in water-based drilling fluids. In order to mitigate shale hydration, a hydrophobic graphene oxide (HGO) was prepared as a new shale inhibitor and characterized. The effectiveness of HGO in inhibiting shale hydration was evaluated through hydration expansion, hydration dispersion, and bentonite sheets immersion tests. The expansion height of bentonite in HGO (3.87 mm) was lower than that of commercial shale inhibitors potassium chloride (KCl, 4.64 mm) and polyether amine (PA, 4.33 mm). The shale recovery rate in HGO at 80 °C was 86.25 %, which was superior to KCl (46.60 %) and PA (78.25 %). Furthermore, the morphology of bentonite sheet remained more intact after immersion in HGO. Additionally, the inhibitory mechanism of HGO was studied in-depth, employing zeta potential, particle size, surface tension, wettability, capillary rise height, and scanning electron microscopy (SEM) tests. By virtue of electrostatic attraction, HGO could tightly adsorb to the shale surface, resulting in a hydrophobic blocking membrane, thereby greatly reducing water infiltration. Following interaction with shale at a concentration as low as 0.5 %, the water contact angle exhibited a notable enhancement, rising from 22.49° to 86.69°. And it could also decrease the capillary self-suction capacity of shale, further reducing water adsorption. Consequently, HGO exhibited significant potential for inhibiting hydration in shale drilling.

Molecular dynamics study of shale oil adsorption and diffusion behavior in reservoir nanopores: Impact of hydrocarbon composition and surface type

Understanding shale oil adsorption in reservoir nanopores is essential for efficient extraction. This study used MD simulations to analyze the adsorption and diffusion of two- and multi-component hydrocarbons (Aromatics, Alkanes, Resin) on various shale surfaces (Calcite, Montmorillonite, Quartzite, Organic) at 353 K and 25 MPa. Hydrocarbons formed a bilayer adsorption structure comprising a high-concentration adsorption layer (L1, 0.35–0.90 g/cm3) and a low concentration weak adsorption layer (L2), with adsorption density ranked as Resin > Aromatics > Alkanes. Reservoir surfaces were classified as ionic (e.g., calcite, montmorillonite) and non-ionic (e.g., quartz, graphite), and polar hydrocarbons exhibited higher adsorption densities and energies on ionic surfaces due to combined electrostatic and van der Waals interactions, while non-ionic surfaces showed smaller adsorption differences. For multicomponent hydrocarbons, adsorption layer densities followed the order: graphite > MMT-SiO > quartz > calcite > MMT-Na, with competitive adsorption observed. The polar component exhibited a greater adsorption advantage on the calcite, MMT-SiO side and graphite surfaces due to electrostatic interactions and π-π interactions, and a lesser advantage on the MMT-Na side and quartz surfaces. Hydrocarbon diffusivity was influenced by molecular mass and polarity and ordered as Alkanes > Aromatics ≫ Resin. Polar molecules had a weaker diffusion than nonpolar molecules at similar molecular masses. Among the multicomponent hydrocarbons, the self-diffusion coefficient (Self-D) of Resin increased, while that of lighter components decreased compared to two-component systems. These findings offer strategies for improving shale oil recovery by tailoring injection fluids to reservoir types, anionic surfactants or chelating agents may be used to reduce electrostatic interactions in carbonate and clay reservoirs, while nonionic surfactants may be more effective in quartz reservoirs.

Depressurization-induced production of shale gas in organic-inorganic shale nanopores: A kinetic Monte Carlo simulation

Methane gas production from unconventional reservoirs, such as shale formations, is in high demand due to the global energy needs. However, maximizing production remains challenging due to the ultra-tight porosity, heterogeneity, and complex nature of shale rocks under high pressure. To address this issue, we employ a novel kinetic Monte Carlo (kMC) simulation to investigate the molecular-level behavior of shale gas in both homogeneous and heterogeneous organic-inorganic shale nanopores. This approach not only provides accurate computations of shale gas under high pressure but also aims to uncover the mechanisms of shale gas storage at reservoir pressure and production during pressure drawdown. Our findings indicate that organic shale ultramicropores (pore width < 0.7 nm) contribute significantly to the highest storage capacity of shale gas but pose challenges for production capacity solely through depressurization. In contrast, the free gas zone is the primary source of shale gas production from mesoporous shales, which has a high recovery efficiency but a low production capacity due to less pronounced interaction effects from the shale surface. The heterogeneous nature of shale surfaces leads to asymmetric distributions of density and potential energy across pore widths, with methane molecules favoring locations near organic pore walls due to stronger attractive interactions, while inorganic pore walls facilitate shale gas migration. Interestingly, the optimal ultramicropore size yields the highest recovery efficiency of shale gas via depressurization, characterized by a transition from near-commensurate to incommensurate molecular packing between reservoir and post-drawdown pressures. Based on these detailed molecular simulations, further research is necessary to develop innovative techniques for enhancing shale gas recovery, especially in micropores.

Achieving the hydrophobic alteration by functionalized nano-silica for improving shale hydration inhibition

Shale hydration is the primary cause of wellbore instability during drilling processes. In this study, two non-fluorinated silane-coupling agents, octyltriethoxysilane (OTES) and (3-Aminopropyl) triethoxysilane (APTES), were grafted onto the nano-silica surface to develop a hydrophobic material (SHM). Various performance characterizations, including infrared spectroscopy, thermogravimetric analysis, surface tension, wetting alteration, capillary self-suction height, bentonite expansion, and shale dispersion, were employed to investigate the shale inhibition properties of SHM comprehensively. Experimental results revealed that SHM could significantly improve shale hydration inhibition. For instance, in a 2 % SHM liquids, the shale hot rolling recovery rate increased from 25.39 % to 83.78 %, and the bentonite expansion height decreased from 7.65 mm to 2.80 mm. The inhibition performance was notably superior to potassium chloride (KCl) and polyether amine (PEA). Inhibition mechanisms analysis unveiled that the outstanding inhibitory effect of SHM was achieved through electrostatic adsorption, wettability alteration, and surface tension reduction. Firstly, SHM contained numerous amine groups that could demonstrate strong adsorption on the clay surface through electrostatic and hydrogen bonding interactions. Secondly, with long hydrophobic alkyl chains, it formed a highly hydrophobic film enveloping the shale surface, effectively preventing water from invading. Thirdly, it reduced liquid surface tension, further minimizing the water infiltration. As a result, the use of SHM significantly enhanced shale hydration inhibition during the shale drilling process.

Compositional controls on the Lower Cretaceous Rodby Shale pore structure and surface area: a planned CCS top seal caprock for the Acorn storage site

Fine-grained lithologies above CCS reservoirs cannot automatically be assumed to be mineralogically stable, or high quality top-seals to highly pressured CO2 as saline aquifer have previously contained hydrostatically pressured water. We have investigated the mineralogy, pore systems and surface area characteristics of the Lower Cretaceous Rodby Shale, the caprock to the Captain Sandstone at the UK's planned Acorn/Goldeneye CCS site. Rodby Shale core was logged and analysed by XRD, light microscopy, and SEM. Grain size was measured using laser particle size analysis. Mercury intrusion porosimetry and nitrogen adsorption analysis were used to characterise the pore network. The Rodby is smectite-rich and contains abundant calcite as well as quartz silt with small quantities of chlorite and plagioclase. Calcite was sourced from benthic microfossils, locally recrystallised to create a pore-filling cement. The mean pore throat and pore body diameter are about 17 nm putting the Rodby in the mesopore range and suggesting a predominance of slit-like pores. There are three lithofacies in the Rodby Shale: (i) high surface area clay-rich shale, (ii) low surface area calcite-rich shale, (iii) intermediate surface area quartz-rich. if the second lithotype encountered CO2, then the resulting calcite dissolution would lead to increasing surface area of the remaining shale. The Rodby Shale has good potential to be an effective barrier for CO2 escape, based on assessments of diffusion rate and post-breakthrough advection rate as well as stability and sealing assessments.

Improving Shale Stability through the Utilization of Graphene Nanopowder and Modified Polymer-Based Silica Nanocomposite in Water-Based Drilling Fluids

Shale formations present significant challenges to traditional drilling fluids due to fluid infiltration, cuttings dispersion, and shale swelling, which can destabilize the wellbore. While oil-based drilling fluids (OBM) effectively address these concerns about their environmental impact, their cost limits their widespread use. Recently, nanomaterials (NPs) have emerged as a promising approach in drilling fluid technology, offering an innovative solution to improve the efficiency of water-based drilling fluids (WBDFs) in shale operations. This study evaluates the potential of utilizing modified silica nanocomposite and graphene nanopowder to formulate a nanoparticle-enhanced water-based drilling fluid (NP-WBDF). The main objective is to investigate the impact of these nanoparticle additives on the flow characteristics, filtration efficiency, and inhibition properties of the NP-WBDF. In this research, a silica nanocomposite was successfully synthesized using emulsion polymerization and analyzed using FTIR, PSD, and TEM techniques. Results showed that the silica nanocomposite exhibited a unimodal particle size distribution ranging from 38 nm to 164 nm, with an average particle size of approximately 72 nm. Shale samples before and after interaction with the graphene nanopowder WBDF and the silica nanocomposite WBDF were analyzed using scanning electron microscopy (SEM). The NP-WBM underwent evaluation through API filtration tests (LTLP), high-temperature/high-pressure (HTHP) filtration tests, and rheological measurements conducted with a conventional viscometer. Experimental results showed that the silica nanocomposite and the graphene nanopowder effectively bridged and sealed shale pore throats, demonstrating superior inhibition performance compared to conventional WBDF. Post adsorption, the shale surface exhibited increased hydrophobicity, contributing to enhanced stability. Overall, the silica nanocomposite and the graphene nanopowder positively impacted rheological performance and provided favorable filtration control in water-based drilling fluids.

Effects of nanoactive fluids on water wettability reversal of shale: Implications for CO2 geo-sequestration

CO2 geo-sequestration (CGS) is crucial in tackling global climate change, and the safety of CO2 storage within the reservoir is intricately linked to wettability. The utilization of nanofluids-surfactants for adjusting reservoirs’ wettability has emerged as a promising approach to enhance the security of CGS. However, the mechanism underlying their impact on reservoir wettability and carbon sequestration remains elusive. Regarding nanoactive fluid (ASNF) compounded with nano-SiO2 and AOS, to explore its potential for wettability reversal of CO2-exposed shale under in situ conditions, comparative experiments were conducted with Longmaxi Formation shale as the subject. The chemical structures and microstructures of shale before and after the experiments were comprehensively characterized. The results showed that a maximum of 67.93 % enhanced the water wettability of samples co-treated with ASNF and ScCO2. The primary reason for shale wettability reversal was increased hydrophilic chemical groups and enhanced interaction energy between organic matter and water molecules, stemming from nanoactive particle retention on the shale surface. The alteration in wettability decreased the mobility of CO2 and increased the distribution of surface water films, enhancing the carbon sequestration capabilities of the trapping mechanism. These findings provided an important foundation for improving the effectiveness and safety of CGS in shale reservoirs.

Research on Mechanism and Effect of Enhancing Gas Recovery by CO2 Huff-n-Puff in Shale Gas Reservoir.

The technology of CO2-enhanced gas recovery (CO2-EGR) plays a pivotal role in the CCUS (Carbon Capture, Utilization, and Storage) industry, which helps to achieve a win-win situation of economic benefit and environmental benefit for gas fields. Shale gas reservoirs, with their unique geological and surface engineering advantages, are one of the most promising options for CCUS implementation. Focusing on shale formations within the mid-deep blocks of the Sichuan Basin, this study conducted competitive adsorption experiments using multicomponent gases. Through physical simulations and single-well numerical modeling, factors such as injection volume, timing, shut-in time, and huff-n-puff rounds were examined for their impact on recovery. The results show that the higher the CO2 content in the injected medium, the more pronounced advantage in gas adsorption on shale surfaces. Optimal performance was achieved with a CO2 content in the injection medium of 80% to 100%, an injection volume of 0.2-0.3 PV, a shut-in time exceeding 6 h, and a relatively delayed injection timing. The recovery in the first round of huff-n-puff was increased by 24.2% to 47.8%, which gave a full play to the role of huff-n-puff and achieved favorable benefits. Based on the middle-deep geological parameters, a single-well numerical simulation was established, which demonstrates that single-well EUR (estimated ultimate recovery) can be increased by 14.2% to 19.8% compared to gas wells without CO2 injection. This study provides essential guidance for the enhanced recovery in shale gas reservoirs through CO2 huff-n-puff.

Quantitative Characterization of Adhesion Work on Shale Surfaces and Discussion on the Influence of Roughness Based on Atomic Force Microscopy (AFM).

Adhesion is an intrinsic property of rocks and liquids. Investigating the factors contributing to its formation and the mechanisms governing its action is crucial for elucidating the adhesion work between solids and liquids. The adhesion work, serving as a parameter that characterizes the energy changes during the solid-liquid contact process, is a vital tool for probing this phenomenon. However, conventional measurements of the adhesion work are significantly influenced by surface roughness and fail to differentiate local variations in the adhesion performance. This limitation obscures our understanding of the primary adsorption sites and mechanisms between solids and liquids, posing significant challenges to the study of rock surface properties. In this study, in conjunction with scanning electron microscopy and contact angle analyses, we elucidated for the first time the locations where voids form during the solid-liquid contact process, the lithological composition of rough areas, and their impact on the adhesion work between water/oil and the surfaces. Additionally, employing atomic force microscopy (AFM), we examined the variations in water/oil-solid adhesion work across different characteristic regions, thereby characterizing the overall hydrophilic/hydrophobic properties of the rock core. Specific conclusions are as follows: (1) A negative correlation exists between roughness and the contact angle adhesion work, with heterogeneity impeding liquid-rock contact; (2) By comparing the strength of water-solid/oil-solid adhesion work within localized areas, we delineated the adhesion work characteristics of samples and their primary generation sites, with oil-solid adhesion work in target blocks predominantly originating from quartz, clay minerals, and organic matter; (3) The influence of pore throat development on the overall adhesion work of samples was clarified, demonstrating that an increase in the proportion of internal rock pores enhances the surface oil-solid adhesion work; (4) A dimensionless wetting index I was established to mitigate the impact of roughness on the expression of adhesion work, exhibiting a strong correlation with traditional evaluation methods.

Temperature-sensitive polymer grafted with nano-SiO2 improves sealing and inhibition performance of shale water-based drilling fluid

Drilling fluid loss is an important factor restricting oil and gas production. The development of pores and micro-fractures in shale formations is the main cause of drilling fluid loss. In this study, silane coupling agent modified nano-SiO2 was used as the rigid core, and N-isopropylacrylamide and 2-hydroxyethyl methacrylate were used as the flexible outer shell. The temperature-sensitive blocking agent PKSHN was synthesized by inverse microemulsion polymerization method. PKSHN was analyzed and tested through Fourier transform infrared spectroscopy, simultaneous thermal analysis, transmission electron microscopy, dynamic laser scattering and other methods. The results show that PKSHN can achieve a hydrophilic/hydrophobic transition under the response temperature, with a median particle size of 189.35 nm, which can form a hydrophobic layer on the shale surface and reduce fluid intrusion into the shale formation. This study tested the performance of three drilling fluids with different densities by adjusting the amount of weighting agent. The results showed that the high-temperature and high-pressure filter losses of the three different densities of drilling fluids were all less than 10 mL. The addition of PKSHN can effectively reduce fluid loss. The rolling recovery experiment and linear expansion experiment show that after aging for 16 h at 150 °C, the rolling recovery rate is above 90 % and the linear expansion rate is below 7 %, indicating that the addition of PKSHN can effectively control the hydration expansion of shale.

Carbonate dissolution enhances particulate iron sulfide mobilization during water-shale interaction

The interaction between shale and water in the environment can lead to the mobilization of micrometer-sized iron sulfide (pyrite) grains. Because these grains often contain high concentrations of toxic elements, including arsenic, this process can pose a significant hazard. While previous studies have suggested that calcite dissolution plays a major role in iron sulfide mobilization, the relationship between rock composition and the release of particulate matter is unclear. Here, we performed laboratory experiments that simulated water–rock interaction in the subsurface on 5 different shale formations: Eagle Ford, Marcellus, Mancos, and Barnett from the USA, and Ein Zeitim from Israel. We used high resolution imaging to evaluate the impact of a reactive fluid on the shale surface, and used image analysis software to determine the rate of iron sulfide grain mobilization. Comparison of the shale surfaces before and after the experiments showed that the dissolution of calcite cement had a major impact on sulfide mobilization: grains that were primarily surrounded by calcite cement were up to 85 times more likely to be mobilized than grains embedded in the shale matrix, which compromises a complex mixture of submicrometer-scale phases, including phyllosilicates, organics, and carbonates. By contrast, iron sulfide embedded in organic matter typically remained cemented in place. This suggests that while calcite dissolution is a crucial phase in facilitating iron sulfide detachment in shales, organic matter might act as an adhesive that suppresses particulate mobilization. However, the adhesive effect of organic matter is only likely to be of secondary importance. Overall, our results indicate that during hydraulic fracturing operations, which involve the injection of fluid into shales in the subsurface, formations with high levels of carbonate cement are more likely to release particulate iron sulfide, thereby reducing the quality of flowback water and potentially increasing treatment costs.

Mechanisms of carbon dioxide extracting oil at the boundary layer on shale nanopore surface: insights from molecular dynamics

Boundary layer formed by crude oil on the shale nanopores surface hinders fluidity of crude oil and leads to a decline in oil recovery. CO2 injection has been considered as an effective method to enhance shale oil recovery. However, the impact of CO2 on the disruption of boundary layers within shale nanopores and the extraction mechanisms of crude oil during the recovery process remains unclear. In this work, molecular dynamics simulation was employed to investigate the process of using scCO2 to extract crude oil from shale nanopore surface. During the process of scCO2 extraction, polar molecules have the capability to reduce the diffusion coefficient, prolong the residence time, and decrease flowability of decane, ultimately resulting in a deterioration of its kinetic properties. Phenol, with its hydrophilic hydroxyl group, closely adheres to the shale surface, while the oleophylic benzene ring covers the shale surface, causing a transition in the wettability of this segment from hydrophilic to oleophylic. As a result, a substantial adsorption of decane occurs on phenol. The research findings contribute to the comprehension of the scCO2 extraction mechanism and the advancement of unconventional oil and gas resources.

Experimental study of adsorption/desorption and enhanced recovery of shale oil and gas by zwitterionic surfactants

Shale reservoirs have the characteristics of low permeability and low porosity. In order to enhance the recovery of shale oil and gas, surfactant flooding is a mature reservoir oil recovery method. However, the adsorption of different surfactants on the reservoir rock surface is restricted, depending on the type of surfactant. Therefore, a zwitterionic surfactant (OPHS) was synthesized from oleic acid, 3-dimethylaminopropylamine and sodium 3-chloro-2hydroxypropanesulfonate, and characterized by FTIR, 1H NMR, and TGA, and the mechanism of the OPHS for enhancing oil and gas recovery on shale surfaces was investigated. The results showed that the critical micelle concentration (CMC) of OPHS surfactant solution is 7.9 × 10-4 mol/L and the γCMC is 27.5 mN/m; the concentration of 0.1 % OPHS surfactant solution could reduce the contact angle of the cores from 127.2° to 38.8°, which resulted in spontaneous imbibition; The absolute Zeta potential of shale particles in the OPHS surfactant solution was measured at 39 mV, whereas in deionized water at 15.3 mV. This difference can be attributed to the formation of a stable hydration film on the surface of shale particles induced by the wetting reversal effect. Spontaneous imbibition experiments showed that a 0.1 % solution of OPHS surfactant was able to increase the recovery rate by more than four times compared to the imbibition solution without added surfactant; In high-pressure gas adsorption/desorption experiments, the OPHS surfactant solution demonstrated a higher affinity for adsorption onto the shale surface. It effectively occupied adsorption sites, ultimately facilitating methane gas desorption from the shale. In summary, OPHS zwitterionic surfactants exhibit the capability to desorb hydrocarbons from shale pores through mechanisms such as wetting reversal and competitive adsorption. This research holds significant potential for advancing the field of shale oil and gas recovery, providing valuable insights for enhancing recovery processes.

Acylated Inulin as a Potential Shale Hydration Inhibitor in Water Based Drilling Fluids for Wellbore Stabilization.

Shale hydration dispersion and swelling are primary causes of wellbore instability in oil and gas reservoir exploration. In this study, inulin, a fructo-oligosaccharide extracted from Jerusalem artichoke roots, was modified by acylation with three acyl chlorides, and the products (C10-, C12-, and C14-inulin) were investigated for their use as novel shale hydration inhibitors. The inhibition properties were evaluated through the shale cuttings hot-rolling dispersion test, the sodium-based bentonite hydration test, and capillary suction. The three acylated inulins exhibited superb hydration-inhibiting performance at low concentrations, compared to the commonly used inhibitors of KCl and poly (ester amine). An inhibition mechanism was proposed based on surface tension measurements, contact angle measurements, Fourier-transform infrared analysis, and scanning electron microscopy. The acylated inulin reduced the water surface tension significantly, thus, retarding the invasion of water into the shale formation. Then, the acylated inulin was adsorbed onto the shale surface by hydrogen bonding to form a compact, sealed, hydrophobic membrane. Furthermore, the acylated inulins are non-toxic and biodegradable, which meet the increasingly stringent environmental regulations in this field. This method might provide a new avenue for developing high-performance and ecofriendly shale hydration inhibitors.

Statistical physics modelling of adsorption isotherms of water vapour on shale: Stereographic, energetic and thermodynamic investigations

AbstractUnderstanding the mechanisms of shale–water interaction by water vapour adsorption is crucial for predicting shale gas productivity. In this study, equilibrium adsorption data of water vapour on four different shales of the Sichuan Basin at three temperatures (298, 308, and 318 K) were measured using static gravity techniques. The water vapour adsorption isotherms were simulated by three statistical physics models. Steric parameters, including the number of water vapour molecules adsorbed per site (n), monolayer adsorption amount (q0), and adsorption energy (ΔEa), and thermodynamic parameters such as configuration entropy (Sa), internal energy (Eint), and free energy (Ga) derived from the selected model were used to explain the adsorption mechanism. The model analyses suggest that the adsorbed water vapour molecules are attached to the shale surface in a multi‐anchorage manner. The adsorption of the first layer shows a Type I characteristics, while the adsorption of the subsequent layer is of Type III. The calculated adsorption energies indicate that the physical adsorption takes place on the water vapour molecules on the shale, and the main interaction forces are hydrophilic bonding forces and van der Waals forces. Negative Eint and Ga values indicate that the spontaneous properties are for water vapour adsorption and that the system requires the release of energy to capture the water vapour molecules.

Adsorption and Desorption Behavior of Partially Hydrolyzed Polyacrylamide on Longmaxi Shale

Large-scale volumetric fracturing is generally used during shale gas development. The return rate of fracturing fluid is low, and a large amount of slickwater is retained in the reservoir. The adsorption and desorption of partially hydrolyzed polyacrylamide (HPAM), an additive commonly used in slickwater, on the surface of shale was studied using Longmaxi shale from the Sichuan Basin. The experimental results showed that the mass ratio of the HPAM solution to shale reached saturation adsorption at 20:1 when the concentration of HPAM solution was 1000 mg/L and 25:1 when the concentration of HPAM solution was 500 mg/L. The mass ratio of the HPAM solution to shale was fixed at 25:1, and the adsorption equilibrium was reached at a HPAM concentration of 1000 mg/L when the aqueous solution temperature was 30 °C and 800 mg/L when the aqueous solution temperature was 60 °C. The Langmuir adsorption model yielded a better fit than the Freundlich adsorption model. The adsorption equilibrium time at 30 °C was at 60 min for a HPAM concentration of 500 mg/L, while for a concentration of 1000 mg/L, it was at 90 min. The adsorption equilibrium time at 60 °C was 40 min for a HPAM concentration of 500 mg/L, whereas it was 60 min for a HPAM concentration at 1000 mg/L. The pseudo-second order (PSO) kinetics model yielded better fits than the pseudo-first order (PFO) kinetics model. The adsorption of HPAM on shale was strong, and the adsorbed HPAM resembled cobwebs adhering to the shale surface. HPAM on the surface of shale after adsorption was able to resist the desorption capacity of water. However, when the amount of adsorbed HPAM on shale increased significantly, the amount of residual HPAM on the surface of the shale decreased rapidly during desorption in deionized water. The desorption of HPAM on the shale surface followed a modified desorption model. The higher the concentration of HPAM adsorbed on the shale surface was, the easier it was to desorb and the easier it was to be removed from the shale.

Study of CO2 Injection into Sumatran Shale Layers to increase Hydrocarbon Gas Productivity of The Shale Gas Reservoir

Injecting CO2 into a reservoir has some important reasons. CO2 injection can enhance oil and gas recovery by reducing the capillary pressure, increasing the pressure gradient, and changing the phase behavior of the fluids. It can reduce greenhouse gas emissions by capturing and storing CO2 underground. It can also create economic benefits by utilizing CO2 as a valuable resource and generating revenue from carbon credits. Therefore, injecting CO2 into a reservoir benefits the environment and the industry. We can inject CO2 in shale gas reservoirs to increase productivity because CO2 has a stronger adsorption capacity on shale surfaces than hydrocarbon gas. When CO2 is injected into shale reservoirs, it can displace the adsorbed CH4 flow out of the micropores and free up more space for gas flow. Injecting CO2 can also reduce the viscosity and density of shale gas, improving its mobility and transport. Moreover, injecting CO2 can provide environmental benefits by reducing carbon emissions and storing CO2 underground. Therefore, CO2 injection is a promising technique for enhancing shale gas recovery and mitigating climate change. We characterized several types of shale from Sumatra using XRD to determine the mineral content. We injected the shale sample with the inert gas and CO2 gas. The characteristics of pressure build up after CO2 injection seem lower than one after inert gas injection. The volumetric of released gas after injection shows the same phenomena as pressure build up’s phenomena which shows clearly that shale rock released less of CO2 gas than the one of inert gas (CH4). These phenomena show that the CH4 can be released easier than the CO2 in the shale rock. Therefore, CO2 can be utilized as material for enhancing the gas recovery in shale reservoir.

Influence of tectonic preservation conditions on the nanopore structure of shale reservoir: A case study of Wufeng-Longmaxi Formation shale in western Hubei area, south China

Tectonism is one of the dominant factors affecting the shale pore structure. However, the control of shale pore structure by tectonic movements is still controversial, which limits the research progress of shale gas accumulation mechanism in the complex tectonic region of southern China. In this study, 34 samples were collected from two exploratory wells located in different tectonic locations. Diverse experiments, e.g., organic geochemistry, XRD analysis, FE-SEM, low-pressure gas adsorption, and high-pressure mercury intrusion, were conducted to fully characterize the shale reservoir. The TOC, Ro, and mineral composition of the shale samples between the two wells are similar, which reflects that the shale samples of the two wells have proximate pores-generating capacity and pores-supporting capacity. However, the pore characteristics of shale samples from two wells are significantly different. Compared with the stabilized zone shale, the porosity, pore volume, and specific surface area of the deformed zone shale were reduced by 60.61%, 64.85%, and 27.81%, respectively. Moreover, the macroscopic and fine pores were reduced by 54.01% and 84.95%, respectively. Fault activity and uplift denudation are not conducive to pore preservation, and the rigid basement of Huangling uplift can promote pore preservation. These three factors are important reasons for controlling the difference in pore structure between two wells shales. We established a conceptual model of shale pores evolution under different tectonic preservation conditions. This study is significant to clarify the scale of shale gas formation and enrichment in complex tectonic regions, and helps in the selection of shale sweet spots.

Study on the Inhibition Mechanism of Hydration Expansion of Yunnan Gas Shale using Modified Asphalt.

Drilling fluids play an essential role in shale gas development. It is not possible to scale up the use of water-based drilling fluid in shale gas drilling in Yunnan, China, because conventional inhibitors cannot effectively inhibit the hydration of the illite-rich shale formed. In this study, the inhibition performance of modified asphalt was evaluated using the plugging test, expansion test, shale recovery experiment, and rock compressive strength test. The experimental results show that in a 3% modified asphalt solution, the expansion of shale is reduced by 56.3%, the recovery is as high as 97.8%, water absorption is reduced by 24.3%, and the compression resistance is doubled compared with those in water. Moreover, the modified asphalt can effectively reduce the fluid loss of the drilling fluid. Modified asphalt can form a hydrophobic membrane through a large amount of adsorption on the shale surface, consequently inhibiting shale hydration. Simultaneously, modified asphalt can reduce the entrance of water into the shale through blocking pores, micro-cracks, and cracks and further inhibit the hydration expansion of shale. This demonstrates that modified asphalt will be an ideal choice for drilling shale gas formations in Yunnan through water-based drilling fluids.