Shale Surface Research Articles

Experimental and molecular investigation of water adsorption controls in marine and lacustrine shale reservoirs

The restriction of hydrocarbon migration within shale reservoirs by pre-adsorbed water necessitates an investigation into water adsorption control mechanisms within shales. In this study, water vapor adsorption isotherms obtained from marine and lacustrine shale samples along with isotherms from their organic matter and experimentally verified kerogen molecular models were used to evaluate water adsorption mechanisms, with simulated wet kerogen-quartz nanocomposites. Furthermore, these were also used to investigate organic matter-inorganic interaction controls on water adsorption. Pore size distribution (PSD) controls on water distribution in organic matter were obtained via water vapor adsorption and low-pressure nitrogen adsorption analysis, along with small angle neutron scattering (SANS) analysis. The results reveal water adsorption is linked to changes in mesopore volume within organic matter and porosity in kerogen models. PSD obtained from the shales only reveal mesopore controls at high RH, with water adsorption mainly controlled by oxygen functional groups in organic matter pores and swelling clays. Inorganic controls on water adsorption are also observed in adsorbed water not tightly bound to the shale surface due to a high montmorillonite content in clay interlayers, and organic matter interaction with quartz with a negative relationship between the adsorbed water and the quartz content. Collectively, these findings indicate that CO2 migration in shale reservoirs could be inhibited by water that is distributed in potential CO2 adsorption sites within organic matter pores and montmorillonite.

Adsorption characteristics of shale gas in organic–inorganic slit pores

With the gradual advancement of shale gas exploration and development technology, shale gas has replaced conventional oil and gas as the primary energy source. As the main occurrence form of natural gas in shale reservoirs, the adsorption state is always an important research topic for evaluating the gas-bearing property of shale reservoirs and improving shale gas recovery. However, at present, there are few studies on control factors and control mechanisms of adsorbed gas in organic–inorganic slit pores, with several unexplained control factors and mechanisms. Taking Songliao Basin shale as an example, molecular simulations are employed to investigate shale gas adsorption in organic–inorganic slit pores, the graphene and kaolinite rock matrix model is employed, and molecular dynamics simulations, particularly the grand canonical Monte Carlo simulation is studied for pore sizes of 2, 4, and 6 nm, The adsorption behavior of methane on heterogeneous shale surfaces at temperatures of 298, 323, 348, 373, and 398 K and pressures of 0.1, 5, 10, 15, and 20 MPa reveals the microscopic mechanism of shale gas adsorption in organic–inorganic slit pores at a molecular scale. The results show that as temperature and pressure increase simultaneously, methane is more strongly adsorbed on the surface of graphene than kaolinite, the number of methane molecules also gradually decreases, the root mean square of the displacement of methane and different surface forces between atoms exhibit certain regularity, and the adsorption capacity of the system is proportional to the changes in diameter within the system. Van der Waals energy and electrostatic energy in the system also increase gradually with changes in temperature and pressure, and electrostatic energy has a greater influence on the adsorption of the system than van der Waal energy. These findings provide ideas for the adsorption capacity of shale gas in organic–inorganic slit pores and are critical for the accurate evaluation of shale reservoir gas content and improvement of shale gas recovery.

Hydrophobically modified low molecular weight polymers as high temperature resistant shale inhibitor

With the exploration and development of deep oil and gas, an efficient shale inhibitor resistant to high temperatures is critical for wellbore stability during drilling. In this paper, a hydrophobically modified low molecular weight polymer (SDY) is studied to maintain wellbore stability at high temperatures during drilling. The inhibition performance of SDY was investigated using linear swelling experiments and rolling recovery experiments at different temperatures. The experimental results showed that SDY had good inhibition performance. At 150 °C, the expansion rate was 61.69 % for 1 % SDY and 175.51 % in water. And the rolling recovery of shale rock chips was 87.53 % for 1 % SDY and 18.92 % in water. Compared with water, it can reduce the hydration swelling rate of bentonite rock mold by 57 % and improve the recovery rate of shale rock chips by 3.37 times at 150 °C. The inhibition mechanism of SDY was analyzed by zeta potential, particle size distribution, contact angle, self-absorbing water, X-ray diffraction and scanning electron microscopy experiments. The good inhibition performance of SDY at high temperatures may be attributed to three aspects. First of all, SDY molecules can neutralize the negative charge on the shale surface by electrostatic effect, and reduce the repulsive force between shales to inhibit the hydration dispersion of shales. Second, SDY can still adsorb on the shale surface at high temperatures to form a hydrophobic film and change the wettability of the shale surface. This increases the adsorption resistance of water molecules on the shale surface thereby inhibiting shale surface hydration. Third, SDY molecules can insert between the layers of bentonite sheets to bind the adjacent clay layers together, effectively inhibiting the permeable hydration of shale. This study provides an approach for addressing wellbore stability in deep wells with higher temperature.

Use of modified polystyrene micro-nano spheres to improve the inhibition and plugging performance of water-based drilling fluids

Wellbore instability is a challenging issue in drilling engineering, especially in shale formations. The objective of this paper is to achieve wellbore stability by changing the hydrophobicity of the shale surface and plugging the micro-nano pores through the synthesis of modified polystyrene micro-nano spheres (MPS). The MPS was characterized through Fourier transform infrared spectroscopy (FTIR), thermogravimetric analysis (TGA), particle size distribution, and transmission electron microscopy (TEM). The inhibition and plugging performance of MPS were evaluated through linear expansion, shale recovery, and plugging of polytetrafluoroethylene (PTFE) microporous membrane. To study the inhibition and plugging mechanisms of MPS, contact angle, pore size distribution, and SEM analysis were performed. The results showed that MPS was spherical with a particle size distribution of 91–712 nm and had good thermal stability. The MPS had excellent compatibility with drilling fluids and better inhibition than KCl, polyamines, and SiO2. When using PTFE microporous filter membrane as a filtration medium, the API filtration loss volume of 3 wt% MPS aqueous solution was only 42 mL, while that of the solution without MPS was 260 mL. The pore size of the PTFE microporous membrane was decreased after plugging. The MPS adsorbed on the shale surface to form a hydrophobic layer, which could weaken the hydrophilicity of shale. The contact angle of shale slices treated with 2 wt% MPS was 108.2°. Furthermore, SEM observations indicated that MPS can improve the quality of mud cakes and plug the small pores. MPS has potential applications in improving wellbore stability.

Study of the Wellbore Instability Mechanism of Shale in the Jidong Oilfield under the Action of Fluid

Wellbore instability is the primary technical problem that restricts the low-cost drilling of long-interval horizontal wells in the shale formation of the Jidong Oilfield. Based on the evaluation of the mineral composition, structure and physicochemical properties of shale, this paper investigates the mechanical behavior and instability characteristics of shale under fluid action by combining theoretical analysis, experimental evaluation and numerical simulation. Due to the existence of shale bedding and microcracks, the strength of shale deteriorates after soaking in drilling fluid. The conductivity of the weak surface of shale is much higher than that of the rock matrix. The penetration of drilling fluid into the formation along the weak surface directly reduces the strength of the structural surface of shale, which is prone to wellbore collapse. The collapse pressure of the shale formation in the Nanpu block of the Jidong oilfield was calculated. The well inclination angle, azimuth angle and drilling fluid soaking time were substituted in the deterioration model of rock mechanics parameters, and the safe drilling fluid density of the target layer was given. This work has important guiding significance for realizing wellbore stability and safe drilling of hard brittle shale in the Jidong Oilfield.

Organic-rich source rock/H2/brine interactions: Implications for underground hydrogen storage and methane production

There is increasing global interest in the attainment of a carbon dioxide-free global economy by replacement of carbon-based fossil fuels with clean hydrogen. But huge volume of hydrogen needs to be stored to address the imbalance between energy demand and supply due to low volumetric energy content of H2. Underground Hydrogen Storage (UHS) is an integral part of the hydrogen economy value chain and an appealing technology for the attainment of global decarbonization. The Jordan oil shale (Upper Cretaceous, organic-rich source rock sequence) has been proposed as a promising geological storage medium for hydrogen due to its exceptionally high organic content because methane can be produced from the reaction of trapped hydrogen with the kerogen. However, the extraction of methane from kerogen during hydrogen storage in organic-rich shale has not yet been reported. In this study, pressurized hydrogen was injected into high TOC shale samples for 80 days at 1500 psi and 75 °C to assess the extent of hydrogen-rock reaction and possible methane production. We also measured H2/brine and CH4/brine interfacial tensions (IFT), as well as the contact angles of H2/brine/shale and CH4/brine/shale systems at 75 °C and varying pressure (500–1500 psi) to understand the shale-fluid interaction at subsurface conditions. Results indicate some reaction of H2 with the shale after 80 days. No hydrogen sulfide was detected from gas chromatography analysis at the end of the experiment, but traces of methane (0.018 %) were detected. The reaction between hydrogen and organic matter of the shale yielded only a little methane under the conditions investigated in this research, possibly because the experimental temperature and reaction time was insufficient for copious methane generation. Furthermore, contact angle values of CH4/brine were found to be higher than of H2/brine. This means that under geo-storage conditions, the surface becomes fully CH4-wet condition (131o-149o) but remains only intermediate-wet in the presence of the H2/brine system (94o -106o) with increasing pressure, confirming that the interaction of methane with the shale surface is higher than hydrogen-shale surface interaction at similar conditions. The opposite trend was observed for IFT values. The hydrogen/brine IFT was 69.4 mN/m at 500 psi but decreased to 67.9 mN/m at 1500 psi. Likewise, the methane/brine IFT decreased from 69.7 mN/m to 58.3 mN/m with increasing pressure from 500 to 1500 psi. The findings of this study contribute to a better understanding of the adsorption trapping potential of organic-rich source rocks.

Investigation of the Mechanism and Effect of Citric Acid-Based Deep Eutectic Solvents Inhibiting Hydration and Expansion of Gas Shale Clay Minerals

This study developed a shale hydration inhibitor using a citric acid-based deep eutectic solvent (Cit-DES) and hexadecylammonium bromide (cetyltrimethylammonium bromide) to aid wellbore instability and collapse caused by drilling of shale gas wells with water-based drilling fluids. Soaking and linear expansion experiments were conducted with Na-bent and Longmaxi formation shale, respectively. The changes in illite interlayer spacing, wettability, and water absorption capacity of shale samples before and after soaking in an inhibitor solution were evaluated, which indicated that the inhibitor reduced shale hydration. The results showed that the inhibitor effectively inhibits the osmotic and surface hydration of the shale. Due to the Cit-DES hydrogen bond, the inhibitor is firmly adsorbed on the shale pore wall and inserted between clay minerals, reducing the shale surface energy, hydrophilicity, and surface potential. The swelling expansion rate of shale inhibitors is only 38.9% compared to a 3% KCl solution. The amount of shale imbibition per unit mass in distilled water is 0.011 g/g. In the inhibitor, the imbibition mass per unit of shale is 0.002 g/g, which is only 23.68% of that in distilled water. The inhibitor is environment-friendly and has a broad application prospect for maintaining shale wellbore stability and preventing wellbore collapse during horizontal shale drilling operations.

Molecular Simulation Study on Methane Adsorption in Amorphous Shale Structure

Gas adsorption in the porous shale matrix is critical for gas-in-place (GIP) evaluation and exploration. Adsorption investigations benefit significantly from the use of molecular simulation. However, modelling adsorption in a realistic shale topology remains a constraint, and there is a need to study the adsorption behaviour using molecular models containing both organic and inorganic nanopores. Most simulations use a single component, either kerogen (organic composition) and quartz or clay (inorganic composition), to represent the shale surface. In this work, the molecular dynamic (MD) and grand conical Monte Carlo (GCMC) simulations were utilised to provide insight into methane adsorption behaviour. Amorphous shale structures composed of kerogen and quartz were constructed. The kerogen content was varied to replicate the shale with 2 wt.% and 5 wt.% Total Organic Carbon (TOC) content with 5 nm pore size. The simulated densities of the shale structures showed consistent values with actual shale from the Montney, Antrim, and Eagle Ford formations, with 2.52 g/cm3 and 2.44 g/cm3, respectively. The Average Error Analysis (ARE) was used to assess the applicability of the proposed amorphous shale model to replicate the laboratory adsorption isotherm measurements of actual shale. The ARE function showed that the amorphous shale shows good agreement with experimental measurements of all Barnett shale samples with an average of 5.0% error and slightly higher for the Haynesville samples with 8.0% error. The differences between the experimental adsorption measurement and simulation resulted from the amorphous packing, and actual shales have more minerals than the simulated model.

Water wettability alternation of CO2-water-shale system due to nanoparticles: Implications for CO2 geo-storage

The wettability of rocks is closely related to the CO2 geo-storage (CGS) security after CO2 injection into the reservoir. Nanofluids can be used to efficaciously alter the wettability of the CO2-water-rock system toward an advantageous state (water-wet) for CGS. In this study, we investigated the potential of SiO2 and Al2O3 nanofluids at different aging time and concentrations to retain the wettability reversal of CO2-exposed shale from the Sichuan Basin after supercritical carbon dioxide (ScCO2) exposure. Fourier Transform Infrared Spectrometer and field emission scanning electron microscopy tests were performed to evaluate the variations of functional groups and surface topography of shale. Results indicated that both nanoparticles efficiently retain the wettability reversal of shale after a period of ScCO2 treatment, which is conducive to structural trapping in the CGS project. The efficiency was improved by increasing the nanofluid aging time and concentrations, while beyond a certain value, the contact angle value changed trivially. Quasi-homogeneously distributed on the shale surface in ScCO2 may contribute to the wettability alteration of shale in ScCO2, whereas there are still removals of nanoparticles in some sites. The variations of functional groups suggest that the existence of nanoparticles may mildly expedite the CO2 mineralization, signifying the change of wetting behavior of shale in ScCO2 depends on the wettability of nanoparticles, and the nanofluids treatment may exert a positive influence on mineral trapping in the CGS project. The findings in this research provide an important basis for raising the CO2 geological storage security and potential via nanofluids.

Coal mine waste characterization and defluoridation property

Fluoride contamination has been addressed as a major problem worldwide, along with the scarcity of water. This attracts researchers to do more research in the field of fluoride contamination and mitigation of high fluoride content in water. There are various studies, that used a variety of adsorbents for the removal of fluoride from contaminated water. But none of them utilized the vast number of waste, that is generated from the coal mining industries. In this paper, Shale, which is a common coal mine waste, has been used as an adsorbent for fluoride removal from aqueous solution. Along with the defluoridation property of shale, the effect of weathering on the adsorption property of shale was also analyzed using different characterization tests, such as XRD (X-ray powder diffraction), SEM (Scanning Electron Microscope), and FTIR (Fourier Transform Infrared spectroscopy). Two types of shale samples were collected, crushed, and used in the adsorption process in the lab using synthetic fluoride solution. The maximum efficiency of type I (weathered) shale was obtained as 47.05% compared to type II (fresh) shale as 40.02% for 3 ppm initial fluoride solution for 60 min of contact time in pH range 5–7 using batch adsorption process. Other parameters such as shale particle size, pH, and total suspended solid present before and after the adsorption process were also taken into consideration. The adsorption followed pseudo-second kinetics and Freundlich isotherm with an adsorption capacity of 23.66 mg/g, and 21.33 mg/g for weathered and fresh shale respectively. The characterization test showed more clayey content in the weathered shale compared to fresh shale, making it more porous and suitable as a fluoride adsorbent. XRD showed the F− containing minerals such as Villiaumite (5.1%) and Fluorite (4.3%) in F− loaded weathered shale, confirming the F− adsorption onto the shale surface. The major advantage of shale over other existing adsorbents is, it removes the fluoride without significant change in pH, and there are no or very less suspended ions that can be found in treated water. This means the water may not need any secondary treatment after the adsorption process. Shale is a very common and readily available mine waste, that is used for the ceramic industry, building materials, and road construction, making it a no-cost material to be used as an adsorbent for fluoride removal.

Investigation into shale softening induced by water/CO2-rock interaction

To investigate the shale softening behavior induced by water/Carbon dioxide (CO2)-rock interaction, a series of scanning electron microscope (SEM) observation and nanoindentation tests were performed on carbonate-rich shale specimens after high-temperature and high-pressure static soaking treatments. The characteristics of shale surface softening and the evolution of micromechanical properties were analyzed. It was indicated that water/CO2-rock interaction resulted in different extents of micromechanical degradation, which was closely related to both the type of soaking fluid and the soaking time. According to the shale surface observation by SEM images, the aperture of hydration-induced fractures after soaking with water was larger than that of adsorption-induced fractures after soaking with CO2. The statistical results of nanoindentation tests show that when soaking with water, the Young's modulus and the hardness ultimately decreased by 34.6% and 57.6% with the soaking time increased from 2 to 6 d, respectively. When soaking with CO2, the extent of shale softening was alleviated. After soaking for 6 d, the ultimate degradation extents were 14.8% and 30.0% for the Young's modulus and the hardness, respectively. Furthermore, due to the higher penetrability of CO2, the micromechanical degradation of the shale surface mainly occurred in the first 2 d. Indents located in the vicinity of shale laminas or induced fractures tended to possess the lower Young's modulus and the hardness than those located in shale matrix, meanwhile resulting in crushed zones or fracture compaction.

Gas content prediction model of water-sensitive shale based on gas–water miscible competitive adsorption

The evaluation of gas content plays a key role in determining the efficient development of shale reservoirs. To better understand the gas–water miscible competitive adsorption mechanism in the pore-fracture system of water-bearing shale, the water vapor adsorption experiment of dry shale and the methane gas adsorption experiment of water-bearing shale were carried out to compare and analyze the competitive adsorption laws of formation water and methane gas on the shale surface under different temperatures, pressures, and water saturation conditions. Moreover, based on the molecular layer adsorption theory, the gas–liquid–solid interface competitive adsorption model considering the coupling of temperature, pressure, and water saturation was established to predict the actual gas content of water-bearing shale reservoirs. The results show that the main controlling factors affecting the adsorbed gas content of water-bearing shale are specific surface area, temperature, and water content in turn according to weight coefficients; Compared with the gas–solid adsorption model, the gas–liquid–solid competitive adsorption model has higher accuracy in calculation results, which are much closer to the desorption data of shale cores in Jiaoshiba area, Fuling, China. Hence, the competitive adsorption model provides a theoretical foundation for reasonably evaluating the exploitation potential of shale gas reservoirs.

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.

Mechanism of Hexane Displaced by Supercritical Carbon Dioxide: Insights from Molecular Simulations

Supercritical carbon dioxide (sCO2) has great potential for displacing shale oil as a result of its high solubility and low surface tension and viscosity, but the underlying mechanisms have remained unclear up to now. By conducting equilibrium molecular dynamics (EMD) simulations, we found that the displacing process could be divided into three steps: the CO2 molecules were firstly injected in the central region of shale slit, then tended to adsorb on the SiO2-OH wall surface and mix with hexane, resulting in loose hexane layer on the shale surface, and finally displaced hexane from the wall due to strong interactions between CO2 and wall. In that process, the displacing velocity and efficiency of hexane exhibit parabolic and increased trends with pressure, respectively. To gain deep insights into this phenomenon, we further performed non-equilibrium molecular dynamics (NEMD) simulations and found that both the Onsager coefficients of CO2 and hexane were correlated to increase with pressure, until the diffusion rate of hexane being suppressed by the highly dense distribution of CO2 molecules at 12 MPa. The rapid transportation of CO2 molecules in the binary components (CO2 and hexane) actually promoted the hexane diffusion, which facilitated hexane flowing out of the nanochannel and subsequently enhanced oil recovery efficiency. The displacing process could occur effectively at pressures higher than 7.5 MPa, after which the interaction energies of the CO2-wall were stronger than that of the hexane-wall. Taking displacing velocity and efficiency and hexane diffusion rate into consideration, the optimal injection pressure was found at 10.5 MPa in this work. This study provides detailed insights into CO2 displacing shale oil and is in favor of deepening the understanding of shale oil exploitation and utilization.

Effects of surfactant on Bacillus mucilaginosus adsorption characteristics during vanadium bioleaching process

Bioleaching is a sustainable and economical technology for extracting valuable elements from low-grade ores or refractory resources. Adsorption of bacteria on mineral surface is the usual basic condition for the deep interaction between bacteria and minerals, thereby improving the bioleaching efficiency of target elements. The addition of surfactants in bioleaching process is an efficient and promising method for improving the bacteria adsorption on mineral surface. Therefore, effects of surfactant SDS (Sodium Dodecyl Sulfate) on bacterial adsorption characteristics were investigated during the bioleaching process from vanadium-bearing shale by Bacillus mucilaginosus (B.M). The optimal vanadium bioleaching conditions were 0.5 g/L of SDS, 2 g/L of yeast dip powder, and 7.0 of the initial pH. The B.M adsorption equilibrium on the surface of the vanadium-bearing shale with and without addition of surfactant SDS fitted a Freundlich equation, and the addition of surfactant SDS could significantly enhance the B.M absorption on the vanadium-bearing shale. The Pseudo-first-order adsorption kinetics was more suitable to be selected for the demonstration of the B.M adsorption on the surface of the vanadium-bearing shale with and without addition of surfactant SDS, and the addition of surfactant SDS could accelerate the B.M adsorption rate on the surface of the vanadium-bearing shale.

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.

The Characteristic and Distribution of Shale Micro-Brittleness Based on Nanoindentation.

Shale is a special kind of rock mass and it is particularly important to evaluate its brittleness for the extraction of gas and oil from nanoporous shale. The current brittleness studies are mostly macro-evaluation methods, and there is a lack of a micro-brittleness index that is based on nanoindentation tests. In this paper, nanoindentation tests are carried out on the surface of shale to obtain mechanical property, and then a novel micro-brittleness index is proposed. Drawing a heat map by meshing indentation, the distribution characteristics of the brittleness index for the surface of shale and the variation laws between the mineral and brittleness index are explored. The results showed that the dimensionless brittleness index involved parameters including indentation irreversible deformation, elastic modulus, hardness and fracture toughness. The micro-brittleness index of the shale ranged from 7.46 to 65.69, and the average brittleness index was 25.837. The brittleness index exhibited an obvious bimodal distribution and there was great heterogeneity on the surface of shale. The crack propagation channels were formed by connecting many indentation points on the shale surface with high brittleness. The total brittleness index of quartz minerals was high, but the cementation effect with different minerals was various. Although the general brittleness of clay was low, the high brittleness index phenomenon was also exhibited. Studying the micro-brittleness of shale provides a more detailed evaluation for the shale friability, which is used to determine the optimal shale oil and gas recovery regime.

In Situ Shale Wettability Regulation Using Sophisticated Nanoemulsion to Maintain Wellbore Stability in Deep Well Drilling.

Wettability alteration of the shale surface is a potential strategy to address wellbore instability issues arising from shale hydration. In this study, we have explored an oil-in-water (o/w) nanoemulsion, in which soluble silicate (lithium silicate and potassium methyl silicate) as the aqueous phase and organosilanes (3-methacryloxypropyltrimethoxysilane (KH570) and n-octyltriethoxysilane (n-OTES)) as the oil phase, as a shale inhibitor via forming a hydrophobic "artificial borehole shield" in situ on shale surfaces to maintain wellbore stability in high-temperature drilling operations. The shale dispersion test showed the highest shale recovery of nanoemulsion was up to 106.4% compared to that of water (20%), and recovered shale cuttings remained at the original integrity after hot rolling at 180 °C, indicating superior inhibition performance and resistance to elevated temperatures. Moreover, recovered shale cuttings manifested water repellency upon reimmersion in water, ascribed to the hydrophobic film, preventing water from permeating into the shale. The results of the contact angle measurement elucidated that the film wettability, from hydrophilic to superhydrophobic (ranging from 9.6-154°), can be achieved by altering the n-OTES-to-KH570 weight ratio from 0.2 to 2.25, and the film with the highest hydrophobicity (154°) and the lowest surface energy (3.17 mJ·m-2) can be obtained at a ratio of 1.3. Scanning electron microscopy images demonstrated that the superhydrophobic film was composed of tightly stacked reticulate nanofilaments with a diameter of 7-17 nm and several micrometers in length and overlapped well-distributed nanospheres with a diameter of 30 nm. X-ray diffraction and Fourier transform infrared spectroscopy confirmed the film was crystalline silica grafted with long-chain alkylsiloxane. It is assumed that the unique micronanostructure combined with the siloxane modification contributed to the hydrophobicity. Consequently, this study provides a potential alternative solution for wellbore stabilization in deep well drilling engineering by employing nanoemulsion as a shale hydration inhibitor via forming a protective film with controllable wettability. Furthermore, it can be conferred a practical application due to easily available, less hazardous, and cost-effective materials.

An amphiphilic polymer as shale inhibitor in water-based drilling fluid

Shale hydration inhibitor in water-based drilling fluids (WBDFs) is the key to solve the problem of shale wellbore instability during drilling. In this study, a new amphoteric polymer was studied as a shale inhibitor. The amphiphilic copolymer ADL was synthesized by using acrylamide (AM), diallyl dimethyl ammonium chloride (DMDAAC) and dodecyl acrylate (LA) as monomers, benzoyl peroxide as initiator and hexadecyl trimethyl ammonium bromide (CTAB) as an emulsifier in aqueous solution. Infrared spectra indicated that the target product was synthesized successfully. TGA showed that the copolymers had good temperature resistance and the decomposition temperature was 240°C. The performance of ADL was evaluated by linear expansion experiment, rolling recovery rate experiment. The inhibition mechanism of the ADL was analyzed by particle size distribution experiment, zeta potential experiment and contact angle experiment. The experimental results show that ADL can adsorb on the surface of shale to change its wettability and increase the repulsive force between shale particles, thus inhibiting the hydration of shale. Because of its excellent shale inhibition performance, ADL has a potential application prospect as a shale inhibitor in WBDF.

Palynomorphs Content and Paleodepositional Environments of Mamu Formation in Okpekpe-1, Imiegba-1 and Imiegba-2, Benin Flank of Anambra Basin, Nigeria

Twenty surface samples were taken from road cuttings along Okpekpe and Imiegba areas located in Benin Flank of Anambra Basin, Nigeria with an aim to establish the biozones, age and paleodepositional environments of the Mamu Formation. Using palynological laboratory standard procedures, the shale surface samples collected from the Mamu Formation in the study area were prepared and analyzed. The recovered marker pollens, spores and dinoflagellate cysts from the study area are Milforadia jardinei, Milforadia sp., Longapertites marginatus, Longapertites sp., Retidiporites sp., Monocolpites marginatus,Cyathidites minor, Cyathidites spp., Cingulatisporites ornatus, Distaverrusporites simplex, Laevigatosporites spp., Foveotriletes margaritae, Subtilisphaera sp., Andalusiella sp., Paleocystodinium australinium and microforaminiferal wall linings. Four biozones were erected for the shale intervals in the study area, namely: Longapertites sp., Monocolpites marginatus, Cyathidites minor, and Paleocystodinium australinium biozone, respectively, dated to Upper Maastrichtian to Early Paleocene age, which are lateral equivalents to Spinizonocolpites baculatus biozone of the Upper Benue Trough. The presence of the dinoflagellates cysts such as Paleocystodinium australinium, Subtilisphaera sp. and Andalusiella sp., microforaminiferal wall linings, pollens and spores established that the shales were deposited in nearshore to shallow marine environments. The presence of Cingulatisporites ornatus and Distaverrusporites simplex are indicative of marine regression that was followed by fluvial continental influence in anoxic bottom conditions that in turn favored the formation of coal seams in shales in the study area. The paucity of palynomorphs in the study area is inferred to have occurred because of the dry climatic condition that prevailed during the Upper Maastrichtian to Early Paleocene.