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A benchtop humidity and temperature chamber was used to assess water vapor sorption in four US shale samples at 90 °C. Water sorption isotherms were measured at relative humidity ranging from 10 to 99% and temperature of 90 °C. Shale fractal properties were then evaluated, and capillary pressure (ranging from 1.70 to 386 MPa) was obtained using Kelvin relationship. The results show that Mancos shale, from the US, adsorbed more absorbed water due to its high clay concentration and low TOC. However, Wolfcamp shale, from the US, has the lowest TOC and clay concentration, adsorbing the lowest amount of water. There is little hysteresis between adsorption and desorption isotherms explaining water retention phenomenon in some shales. The obtained fractal dimension values ranged between 2.45 and 2.76 and average of 2.56 indicating irregular pore surface and complex pore structure. All shale sample's capillary curves were fitted to Brooks & Corey and van Genuchten models with nonlinear regression. The fitting coefficient, R2, which represents the proportion of variance for Brooks & Corey fits ranged from 0.90 to 0.97 for imbibition and 0.85 to 0.98 for drainage, while R2 for the van Genuchten model ranged from 0.94 to 0.99 for both imbibition and drainage. Thus, the proposed method can be used to measure capillary pressure–saturation relationships in gas shales.

A substantial amount of water used for fracking shale formations is trapped by capillary and interfacial forces. Such trapped water is detrimental to gas production because of its potential to obstruct gas’s desorption and, subsequently, its flow path. Surfactants are proposed to alleviate the problem; however, further insight is required to understand the underlying mechanism. In this study, a cationic surfactant, namely, cetyltrimethylammonium bromide (CTAB), and a clay-rich Marcellus shale are used to investigate and explain the mechanism. The study encompasses a series of systematic experiments and molecular simulations. First, laboratory measurements of CH₄–brine interfacial tension, CH₄ surface excess, and zeta potential at different CTAB concentrations were conducted. Then, we evaluated CH₄ adsorption in Marcellus shale before and after treatment with CTAB. Second, a molecular dynamics simulation by GROMACS software was used to explain the phenomenon at the molecular level. Experimental results indicated that CTAB reduced the CH₄–brine interfacial tension by up to 80%. The zeta potential data showed that shale’s dominant surface charge was altered from negative to positive after treatment with CTAB. Furthermore, the presence of CTAB has significantly influenced the distribution of CH₄ in the aqueous phase as indicated by the changes in the CH₄ surface excess concentration. Moreover, the adsorbed CH₄ amount decreased with increasing CTAB concentration when the CTAB concentration was kept below the critical micelle concentration (CMC). The reduction in adsorbed CH4 was explained by the molecular dynamics simulation results, which revealed a 62% shrinkage in vertical distances between CH₄ molecules and clays after introducing CTAB. Simulation findings also unfold that CTAB has reduced the density distribution of CH₄ molecules along with clay layers by 64%. One of the more significant result of this study is that surfactants injected at above CMC values can lessen fracking water trapping by reducing CH₄ brine interfacial tension, changing surface charges, and reducing molecular distances between CH₄ and hydrophilic clays.

The current study evaluated the source rock characteristics, thickness, and lithology of the Late Jurassic Arwa Member to provide information about both conventional and unconventional resource systems in the Al-Jawf sub-basin. Three exploratory wells in the south-eastern portion of the Al-Jawf sub-basin were used for the source rock geochemistry and basin modeling study. Results from the geochemical and basin modeling indicate that the Arwa Member is a self contained source-reservoir whose shales are considered as gas-prone source rocks, and have generated large amounts of thermogenic gas through secondary cracking of oils at high thermal maturity levels. The geochemical results reveal that the Arwa shales currently contain Type III and IV kerogen in a gas-window maturity stage and are shale-gas resources. The basin models illustrate that the late Jurassic to early Miocene age was the peak-oil generation window of the Arwa shale source rock, with a transformation ratio (TR) of 10–85%. Most of the oil was expelled along micro-fractures caused by the pressure of oil generated within the Arwa shales, which was then trapped in the carbonate reservoir rocks within the Arwa Member itself. The oil retained in the Arwa carbonate rocks was partially and/or completely cracked into gas between the early Miocene and the present-day. This thermogenic gas was generated due to high thermal maturity caused by Tertiary volcanic rocks. Assuming a thickness of 360–1590 m and partial and/or complete cracking of retained oil to gas, the Arwa Shale Member could have a huge gas-generation potential.

Hydrogen sulphide generation in subsurface formation–of ten dubbed as souring--is a phenomenon that happens as a result of in-situ biodegradation reactions during and after the water-flooded reservoir. This phenomenon is caused by sulfate-reducing microorganisms, which a group composed of sulfate-reducing bacteria and sulfate-reducing archaea. Sulfate-reducing bacteria, by oxidizing a carbon source, sulfate ions can be turned into hydrogen Sulfide. Furthermore, Water cut, temperature, pressure, and fluid chemistry can affect the concentration observed. This paper introduced a simulation model that describes We simulated H 2 S generation (souring) at subsurface formation utilizing a 2D model. The conditions that are favorable for souring are met in the constructed model. We chose STARS- CMG--an advanced Process Thermal Compositional Simulator –to simulate the aftermath of geochemical and chemical reactions. The bacterial-induced souring. The results suggest that bacterial activity has consumed the sulfate in the aqueous phase. Such consumption was seen as the SO4 concentration dropped from 1.8e-05-6.0e-06mo1/L. The consumed SO 4 was converted into H 2 S or caused water souring. The souring occurrence was inferred by the sharp increase in H 2 S concentration that reached a maximum of $\sim$0.0006mo1/L. The introduced simulation approach could serve as a way of predicting the aftermath of biodegradation reactions that causes H 2 S generation in the subsurface.

The influence of an anionic surfactant, a cationic surfactant, and salinity on adsorbed methane (CH4) in shale was assessed and modeled in a series of systematically designed experiments. Two cases were investigated. In case 1, the crushed Marcellus shale samples were allowed to react with anionic sodium dodecyl sulfate (SDS) and brine. In case 2, another set of crushed Marcellus shale samples were treated with cetyltrimethylammonium bromide (CTAB) and brine. The surfactant concentration and salinity of brine were varied following the Box-Behnken experimental design. CH4 adsorption was then assessed volumetrically in the treated shale at varying pressures (1-50 bar) and a constant temperature of 30 °C using a pressure equilibrium cell. Mathematical analysis of the experimental data yielded two separate models, which expressed the amount of adsorbed CH4 as a function of SDS/CTAB concentration, salinity, and pressure. In case 1, the highest amount of adsorbed CH4 was about 1 mmol/g. Such an amount was achieved at 50 bar, provided that the SDS concentration is kept close to its critical micelle concentration (CMC), which is 0.2 wt %, and salinity is in the range of 0.1-20 ppt. However, in case 2, the maximum amount of adsorbed CH4 was just 0.3 mmol/g. This value was obtained at 50 bar and high salinity (∼75 ppt) when the CTAB concentration was above the CMC (>0.029 wt %). The findings provide researchers with insights that can help in optimizing the ratio of salinity and surfactant concentration used in shale gas fracturing fluid.

Shale rocks are one of the world's most important unconventional gas resources today, thanks to technical advancements. Fluid adsorption in tight rocks like shale is critical for designing fracturing and treatment fluids. However, adsorption of fluids in shale is not fully understood, and quantifying it remains difficult. In addition, the complicated pore structure of shale rocks makes characterisation challenging. Wettability can be used to understand the affinity of a solid surface to adhere certain fluid. Shales present several basic problems when employing standard techniques because of their small grain size, low permeability, and reactive components. We assessed and compare the wettability of shale using contact angle and spontaneous imbibition methods in two shale samples. The findings showed no correlation between contact angle and imbibition curves. Such behaviour is due heterogeneity of shale surface. Contact angle produces local wetting characteristics, but shale sample is rather complex and contact angle is therefore not representative. Imbibition results might be more reliable since fluids contacts with the whole sample.

During the fracking process in shale, an interaction occurs between shale and fracking fluid that contains a cocktail of chemicals. One of the chemicals used in fracking fluid is often surfactant, which is generally used as a viscofier. However, surfactants also have the potential of significantly influencing the wettability and thus gas desorption–key factors affecting ultimate gas recovery from shale reservoirs. Even though a few studies discussed the ability of surfactants to alter wettability in shale, the implication of that change in adsorption/desorption behavior has never been experimentally investigated beyond hypothetical inferences. In this study, the influence of the wettability change by anionic surfactant on gas adsorption/desorption behavior in shale was investigated through a series of experiments. Baseline wettability readings of two shale samples were established by measuring the contact angles (BG-1 = 22.7°, KH-1 = 35°) between a drop of pure water placed on their polished surfaces, ind...

Caprocks/ CO 2 interfacial tension ( γ sc ) is an essential parameter that helps to provide insights into the interaction between CO 2 and caprocks. Lower values of γ sc suggest stronger CO 2 - caprocks interaction (lower CO 2 capacity is inferred) and vice versa. Rocks/CO2 interfacial tension also explains why different minerals have different wettability to CO2 at the same pressure and temperature. Two caprock samples acquired from a potential CO 2 storage site in New South Wales in Australia were used in this work. All the laboratory measurements were conducted at varying pressure from 5 MPa to 20 MPa and a temperature of 343 K. Our findings suggest that solid/ CO 2 interfacial tension ( γ sc ) in caprocks is highly dependent on total organic carbon (TOC) percentage, pressure, and quartz content. γ sc in sample-2 of higher TOC and quartz (TOC =0.11 wt%, quartz = 62%) is lower than γ sc in sample-1 of lower TOC and quartz (TOC =0.081 wt%, quartz = 31%. The higher percentage of TOC and quartz increases the hydrophobic sites available in the sample, allowing stronger affinity towards CO 2 . Lower interfacial tension implies a stronger affinity of CO 2 towards caprock surface (the high chance that CO 2 will enter through caprocks and causes leakage). Therefore, it can be inferred that high TOC caprocks offer a lower CO 2 trapping integrity, hence reducing their CO 2 storage capacity. A remarkable relationship between solid/ CO 2 interfacial tension and CO 2 density–which is easy to determine – at different pressures (up to 20 MPa) and 343 K temperature was also demonstrated in this work. This insight can significantly enhance Carbon Geosequestration processes' fundamental understanding.

There is an urgent need to store millions of tons of CO2 in deep underground formations to reduce anthropogenic emissions in the atmosphere. Basaltic rocks are recently depicted as feasible and safe candidates for storing CO2 in mineralized form. The leakage of stored C O 2 in basaltic rocks could be minimized due to the mineralization process reported to occur in timescales magnitude shorter than those predicted for sandstone reservoirs. Rock/ C O 2 interfacial tension and wettability are essential factors to understand the interaction between C O 2 and basalt rocks. Low values of rock/ C O 2 interfacial tension suggest stronger C O 2 -rock interaction, thus lower CO2 capacity is inferred, and vice versa. In other words, low values of rock/ C O 2 interfacial tension indicate stronger adhesion of CO2 molecules onto the rock surface. In this study, we have experimentally investigated basalt/ C O 2 interfacial tension under various pressures ranged from 4 MPa to 20 MPa and at temperatures of 308o K and 333o K. Our findings suggest that, as expected, Basalt/ C O 2 interfacial tension decreases as the pressure increases and increases as the temperature increases; solid/water interfacial energy decreases with increasing the temperature. The results also revealed that Basalt's CO2 sealing capacity is reduced as the contact angle (pressure) and temperature increases. The CO2 sealing capacity was reduced by up to 50% as the contact angle became ~80° or when the pressure reached 17 MPa. We also found that there is a remarkable relationship between Basalt/ CO 2 IFT and CO 2 density (ρ) at 308 K and 333 K. The introduced relationship could serve as a handy tool to give a quick prediction of IFT CO 2 /basalt in basaltic formation or other CO 2 /solid systems. Determining solid/gas surface energy helps explain why minerals/rocks offer different wettability at certain pressure and temperature, leading to a better understanding of geological CO2-storage processes.

Polymers are often added with water as a viscosifier to improve oil recovery from hydrocarbon reservoirs. Polymer might be lost wholly or partially from the injected polymer solution by adsorption on the grain surfaces, mechanical entrapment in pores, and hydrodynamic retention in stagnant zones. Therefore, having a clear picture of polymer losses (and retention) is very important for designing a technically and economically successful polymer flood project. The polymer adsorption and mechanical entrapment are discussed more in depth in the literature, though the effect of hydrodynamic retention can be just as significant. This research investigates the effect of the hydrodynamic retention for low and high molecular weight (AN 113 VLM and AN 113 VHM) sulfonated polyacrylamide polymer. Two high permeability Bentheimer core plugs from outcrops were used to perform polymer corefloods. Polymer retention was first determined by injecting 1 cm3/min, followed by polymer core floods at 3, 5, and 8 cm3/min to determine the hydrodynamic retention (incremental retention). A higher molecular weight polymer (AN 113 VHM) showed higher polymer retention. In contrast, hydrodynamic retention for lower molecular weight (AN 113 VLM) was significantly higher than that of the higher molecular weight polymer. Other important observations were the reversibility of the hydrodynamic retention, no permanent permeability reduction, the shear thinning behavior in a rheometer, and shear thickening behavior in core floods.

In this study, previous literature that discussed CO2/brine interfacial tension and wettability of rock/CO2/brine systems were critically reviewed. Using a shale core from Malaysian formation, laboratory experiments were conducted to extend the scope of available data for CO2/brine interfacial tension (IFT) and contact angles of shale/CO2/brine system, as well as shale/oil/brine system to elevated pressures (8 MPa–22 MPa), temperatures (80 °C–180 °C), and NaCl concentrations (0 wt% - 7 wt %), that are representative of downhole conditions. HPHT (high pressure, high temperature) drop shape analyzer (DSA100) instrument was employed for the contact angles and IFT measurements. The CO2/brine IFT was measured using the pendant drop method while the sessile drop/captive bubble techniques were used to measure the advancing and receding contact angles respectively. Correlations were developed for predicting changes in contact angles and CO2/brine IFT as a function of changing temperature, pressure and salinity. Results showed that the crude oil advancing and receding contact angles for shale/oil/brine system decreased with increasing temperature and salinity, but slightly increased with pressure. The brine advancing and receding contact angles of shale/CO2/brine system increased with increasing pressure and salinity, but decreased with increasing temperature. Conversely, the CO2/brine IFT increased with increasing temperature and salinity, but decreased with increasing pressure. The simulated and experimental values showed reasonable consistency with R2 values of 98% and 99% gotten from the statistical fits of the contact angles values. Precisely, at 80 °C and 7 wt% NaCl concentration, the shale surface became strongly CO2-wet, with brine advancing contact angles of 139.92°, 156.06°, and 162.63° when the pressure reached 18 MPa, 20 MPa, and 22 MPa respectively. At similar salinity conditions and 10 MPa, significant increment in CO2/brine IFT from 36.50 mN/m to 47.54 mN/m occurred with increasing temperature from 80 °C to 180 °C. Such wettability modification of the rock surface and change in IFT at elevated temperature, pressure and salinity will greatly influence hydrocarbon recovery, as well as CO2 containment security in Malaysian unconventional shale formation.

Water reservation, especially in remote and drought-prone areas and environmental concerns, are two major drawbacks of water-based fracturing. Waterless fracturing technologies, however, also referred to as green hydraulic fracturing, are friendly to the environment and have the potential to replace water-based fracturing. This article critically reviews such technologies. More attention is given to supercritical carbon dioxide (Sc-CO2), as it is the most viable option with the potential to mitigate global warming. Waterless fracturing technologies cause minimal formation damage, have high fluid compatibility, increase production, exhibit quick flowback rate, and utilize reusable materials. However, an in-depth understanding of the mechanisms and limitations of technologies is required to extract the maximum benefit and to de-risk projects. While some of the problems related to these technologies have been addressed, field-wide applications are yet challenging. Waterless fracturing technologies have high initial costs but, over a longer period of time, these technologies, in particular Sc-CO2 fracturing fluid, offer excellent economic efficiency. However, Poor proppant carrying capacity, high frictional resistance, high displacement, and easy sand plugging are problems associated with Sc-CO2 fracturing. Trending research in the field of Sc-CO2 fracturing involves an understanding of its adsorption in shale, developing the best fit adsorption isotherm, and increasing its viscosity in order to improve the carrying ability of the proppants.

Part of the injected polymer during polymer flooding is lost in porous media by adsorption, mechanical entrapment, and hydrodynamic retention. Therefore, having a clear understanding of polymer losses/retention is very important for designing a technically and economically successful polymer flooding project. Polymer losses are traditionally modeled using Langmuir Isotherms, requiring costly and time-consuming dynamic corefloods to obtain fitting parameters. This research suggests a faster and low-cost method for first-order approximation of polymer adsorption in porous media without conducting corefloods. The proposed technique uses the results of polymer adsorption on the crushed core in the static test that can be used in a lookup table in the simulator instead of Langmuir Isotherms Equation. Mercury injection (MICP) was used to find a cut-off molecular size based on the hydrodynamic size of the polymer calculated using the Flory-Fox equation. Brunauer-Emmett-Teller (BET) tests are used to measure the specific surface area of the crushed core. These three tests determine the equivalent weight of crushed core to be used for static adsorption tests that would represent the specific surface area of the core. Seven high permeability Bentheimer core plugs from outcrops were used to perform polymer corefloods to determine polymer adsorption, followed by seven static adsorption tests performed at similar conditions to compare the results. Polymer adsorption tests showed that 1-h residence time, 0.5 solid-to-liquid ratio, and pre-saturating crushed core with brine before starting static adsorption were important to map static to dynamic polymer adsorption. Other important observations were the increase in polymer adsorption with increasing polymer molecular weight, polymer concentration, and NaCl salinity in order of descending significance of the effect. The proposed method gave a reasonable statistical correlation between static and dynamic polymer adsorption with a coefficient of determination (R2) of 0.97, and Pearson's correlation coefficient (r) of 0.98. The maximum deviation between static and dynamic result was 34% for cores of similar flow zones, and 48% for cores of dissimilar flow zones.

Shale gas has been an important source of natural gas and is expected to contribute 30% towards the global output by 2040. Shale formations also have CO2 sequestration potential, which could be used to mitigate the greenhouse gas emissions. A quarter of Malaysian's sedimentary comprises of black shale formations. In this article, we evaluated the CO2 sequestration potential of some of Malaysian's formation under sub-critical conditions, and we correlate shale's characteristics to CO2 storage behaviour under sub-critical conditions. The evaluation is based on total organic carbon (TOC wt. %) contents, mineralogical compositions, particle size distribution PSD of mesopores and micropores. The results show that total organic carbon measured by TOC analyser ranges between 0.5wt. % to 12.1wt%. Bulk mineralogical composition was semi-quantified using X-ray Diffraction (XRD). Non-clay composition varies between ~35 wt.% to ~75 wt. %, which is dominated by quartz. All samples also contain clay minerals such as kaolinite and illite at different range. The CO2 adsorption isotherm results show that KH sample adsorb the most while in contrast the KL samples adsorb the least of CO2. Positive correlation between organic content and CO2 adsorption was observed in most samples, indicating that formations with high organic content has higher CO2 sequestration potential. Mineralogical composition also influence the CO2 adsorption, for instance, illite has lower surface area and pore volume compare with some other clays, subsequently, its presence reduced the CO2 storage potential on KL sample. However, the application of this observation may not fit to other formations due to the high degree of heterogeneity of shale formations.

The characterization of carbonate formations is challenging as compared to sandstones, yet carbonate reservoirs hold over 60% of the world's hydrocarbon reserves. Carbonate reservoirs exhibit a high level of heterogeneity at every scale; from core to field. To be able to manage heterogeneity for reservoir modelling, the formation has to be discretized into a few rock types, each of which having somewhat similar flow properties. Recently, the interest in extending the rock-typing approaches is increasing with the aim to identify the potential layers in complex lithology like carbonates. The approach becomes more rigorous if the geological description is coordinated with petrophysical data, an approach that has been followed in this study. The hydraulic flow units in Arab-D formation were identified and interpreted using both geological facies and petrophysical data. All three methods; histogram analysis, normal probability plot and least-squared regression were utilized to determine the optimum number of hydraulic flow units across Arab-D carbonate formation. Published routine core analysis data from ten wells of Arab-D formation was analyzed and six optimum hydraulic flow units were identified. The average porosity and average permeability of each hydraulic flow unit was then computed. The results were found to be in good agreement with the geological facies data of the Arab-D formation, thus validating the identified flow units.