Dzeti Farhah Mohshim

Context Low interfacial tension (IFT) between fracturing fluids and reservoir fluids is essential for enhancing gas recovery and mitigating formation damage in shale gas systems. However, conventional surfactants used in hydraulic fracturing pose environmental and sustainability concerns, necessitating the development of greener alternatives. This study evaluates the potential of the bio-derived surfactant D-limonene in reducing methane–water interfacial tension under both ambient and high-pressure high-temperature (HPHT) conditions representative of shale reservoirs. A systematic relationship between IFT and solvation free energy (ΔGₛₒₗᵥ) was observed across all investigated conditions. Increasing temperature significantly reduced IFT, with reductions of up to ~ 80% under ambient conditions (18–90 °C), whereas the reduction was less pronounced under HPHT conditions (~ 7 mN/m). Pressure exhibited a comparatively minor influence, with IFT increasing by approximately 8% between 70 and 120 MPa. Increasing D-limonene concentration consistently lowered IFT, although higher concentrations were required under HPHT conditions to achieve comparable reductions. Methods All calculations were performed using classical molecular dynamics simulations. Molecular interactions among methane, water, and D-limonene were described using the Optimized Potentials for Liquid Simulations (OPLS) force field. Molecular topologies were generated using the Automated Topology Builder, and simulations were conducted using GROMACS®. Systems were equilibrated under constant number of particles, volume, and temperature (NVT) and constant number of particles, pressure, and temperature (NPT) ensembles. The solvation free energy (ΔGₛₒₗᵥ) was computed using thermodynamic integration (TI), where the ensemble-averaged energy derivatives ⟨∂V/∂λ⟩ were evaluated across 21 λ-coupling states and numerically integrated using the trapezoidal rule. Interfacial tension was subsequently determined via its thermodynamic correlation with ΔGₛₒₗᵥ.

Carbon dioxide CO₂ adsorption in organic-rich shale is a key mechanism governing the effectiveness of shale formations as geological carbon storage media. Although Type II kerogen dominates most gas shale systems, its pronounced molecular and compositional heterogeneity introduces significant uncertainty in predicting CO₂ adsorption capacity and storage efficiency. In particular, the influence of Type II kerogen subtypes on CO₂ adsorption behaviour under reservoir-relevant conditions remains poorly constrained. In this study, molecular simulations are employed to systematically investigate CO₂ adsorption in four Type II kerogen subtypes (II-A, II-B, II-C, and II-D) over a wide pressure range (up to 30 MPa) and shale reservoirs temperature (25, 60, and 100 °C). The adsorption isotherms reveal a strong dependence of CO₂ uptake on both pressure and kerogen subtype, with adsorption capacity consistently decreasing with increasing temperature, reflecting the exothermic nature of physisorption. Among the kerogen subtypes examined, Type II-C exhibits the highest CO₂ adsorption capacity across all conditions, followed by Type II-B, II-D, and II-A. This hierarchy is governed by differences in kerogen chemical composition and molecular structure, particularly aromaticity, aliphatic content, heteroatom abundance, and pore accessibility. Isosteric heat analysis further confirms stronger CO₂ and kerogen interactions in Type II-C, indicating enhanced adsorption energetics relative to the other subtypes. These results demonstrate that kerogen heterogeneity within Type II organic matter exerts a first-order control on CO₂ adsorption behaviour. The findings show that CO₂ adsorption in shale is controlled not only by organic content but also by kerogen molecular structure and adsorption energetics, indicating that conventional assessments based solely on TOC or surface area may be insufficient to predict CO₂ storage performance.

The recent COVID-19 pandemic has brought about a need for rapid changes to the existing education system to ensure continuous fulfilment of human capital development needs amidst the challenges of social distancing. Thus, game-based cooperative learning carried out via an online environment is proposed for implementation to ensure students stay engaged in the newly created study atmosphere. For this study, online game-based learning is implemented on a group of final year Petroleum Engineering students taking Production Chemistry and Flow Assurance in a private government-linked Malaysian university. Students’ feedback was obtained to analyse the effectiveness of the implemented study upon completion of the semester. The survey questions were grouped into 6 themes, namely Relevance, Reflective Thinking, Interactivity, Tutor Support, Peer Support, and Interpretation. Overall, the implementation was a success indicated by student satisfaction at 88.3% by the first class with room for improvement in the area of peer support. The maximum score of 5 was rated as the mode for 92% of the 24 survey questions while the mean ranged from 4.0 to 4.7. The standard deviation was also found to range from 0.45 to 1.11, showing a relatively collective agreement on the successful implementation of game-based learning.

This study investigates the CO2 adsorption capacity of the Eagle Ford (EF) shale under varying temperatures, utilizing six isothermal adsorption models: Langmuir, Freundlich, Dubinin-Radushkevich (D-R), Sips, Toth, and Brunauer-Emmett-Teller (BET). The shale sample was characterized through Total Organic Carbon (TOC) analysis, X-ray diffraction (XRD), BET surface area analysis, and Field Emission Scanning Electron Microscopy (FESEM) to assess its organic content, mineral composition, pore structure and elemental composition. CO2 adsorption experiments were conducted using a volumetric method at pressures up to 12 MPa and temperatures of 35°C, 55°C, and 70°C. The results revealed that the adsorption capacity increased with pressure but decreased with rising temperature, which is consistent with the exothermic nature of CO2 adsorption. Among the models, Freundlich and Sips provided the best fit for most temperature conditions, highlighting the heterogeneous nature of the shale surface, while the Langmuir, Toth, and D-R models performed well but with slight deviations. The BET model exhibited the poorest fit. Overall, the findings suggest that the EF shale has significant potential for CO2 storage, especially at lower temperatures, with Freundlich and Sips models being the most reliable for predicting adsorption behavior in EF shale formations.

The recent COVID-19 pandemic has brought about a need for rapid changes to the existing education system to ensure continuous fulfilment of human capital development needs amidst the challenges of social distancing. Thus, game-based cooperative learning carried out via an online environment is proposed for implementation to ensure students stay engaged in the newly created study atmosphere. For this study, online game-based learning is implemented on a group of final year Petroleum Engineering students taking Production Chemistry and Flow Assurance in a private government-linked Malaysian university. Students’ feedback was obtained to analyse the effectiveness of the implemented study upon completion of the semester. The survey questions were grouped into 6 themes, namely Relevance, Reflective Thinking, Interactivity, Tutor Support, Peer Support, and Interpretation. Overall, the implementation was a success indicated by student satisfaction at 88.3% by the first class with room for improvement in the area of peer support. The maximum score of 5 was rated as the mode for 92% of the 24 survey questions while the mean ranged from 4.0 to 4.7. The standard deviation was also found to range from 0.45 to 1.11, showing a relatively collective agreement on the successful implementation of game-based learning.

Modeling and theoretical description of gas transport through mixed matrix membranes synthesized by including a covalent organic framework are essential for the efficient design of these membranes. This paper reports a theoretical analysis of various permeation models for gas transport through covalent organic framework‐based mixed matrix membranes. The existing models, such as Bruggeman, Maxwell, and Lewis Nielson, were analyzed. The Maxwell model calculated the permeation through voids and filler by considering interfacial defects in the covalent organic framework mixed matrix membrane's structure. Hence, dual Maxwell model was used to estimate gas transport through mixed matrix membranes. The percentage absolute average relative error of the dual Maxwell model was found to be less than 4 %. The results suggest that the dual Maxwell model effectively describes gas transport through a covalent organic framework mixed matrix membrane.

The performance optimization studies of zeolite 4A embedded polyetherimide mixed matrix membranes to separate carbon dioxide/methane by simultaneously considering the effect of process parameters on process responses were the focus of this study. Mixed matrix membranes were characterized and analyzed. The thermophysical characteristics of the synthesized membranes were assessed by different analytical equipment. The permeability of pure gases was determined at varying feed pressures (4 bar to 10 bar) to evaluate gas separation performance. Process optimization studies were accomplished by response surface methodology to find the relation of pressure and zeolite loading on carbon dioxide and methane permeability, and carbon dioxide/methane selectivity. The characterization results revealed that all membranes were dense in structure and has improved thermal stability. The spectrometry results confirmed the molecular interaction between polyetherimide and zeolite 4A filler. Gas permeability results showed a more than 90 % increase in carbon dioxide permeability compared to the nascent polyetherimide membrane. Similarly, selectivity of mixed matrix membranes was 45 % higher than polyetherimide membrane. The optimal operating conditions were found to be 20 wt. % zeolite loading and 6 bar pressure with overall desirability of 0.700. These membranes can find potential in various gas separation applications.

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/cm^3, 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.