ORCID Profile
0000-0001-7035-6000
Current Organisation
Khalifa University
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Publisher: Elsevier BV
Date: 08-2023
Publisher: Springer Science and Business Media LLC
Date: 15-05-2019
Publisher: American Chemical Society (ACS)
Date: 17-04-2023
Publisher: Elsevier BV
Date: 12-2022
Publisher: Elsevier BV
Date: 11-2022
Publisher: American Chemical Society (ACS)
Date: 04-05-2020
Publisher: Elsevier BV
Date: 09-2023
Publisher: Elsevier BV
Date: 08-2018
Publisher: American Chemical Society (ACS)
Date: 30-07-2021
Publisher: Elsevier BV
Date: 12-2020
Publisher: American Geophysical Union (AGU)
Date: 09-09-2017
DOI: 10.1002/2017GL073532
Publisher: American Chemical Society (ACS)
Date: 02-2023
Publisher: American Chemical Society (ACS)
Date: 08-2022
Publisher: Elsevier BV
Date: 07-2017
Publisher: Elsevier BV
Date: 07-2022
Publisher: Elsevier BV
Date: 12-2022
Publisher: American Chemical Society (ACS)
Date: 06-04-2023
Publisher: Elsevier BV
Date: 2023
Publisher: Elsevier BV
Date: 08-2023
Publisher: American Chemical Society (ACS)
Date: 29-09-2020
Publisher: Elsevier BV
Date: 06-2017
Publisher: Elsevier BV
Date: 11-2017
Publisher: Elsevier BV
Date: 07-2017
Publisher: Elsevier BV
Date: 05-2020
Publisher: MDPI AG
Date: 23-10-2022
Abstract: We performed molecular dynamics simulation to elucidate the adsorption behavior of hydrogen (H2), carbon dioxide (CO2), and methane (CH4) on four sub-models of type II kerogens (organic matter) of varying thermal maturities over a wide range of pressures (2.75 to 20 MPa) and temperatures (323 to 423 K). The adsorption capacity was directly correlated with pressure but indirectly correlated with temperature, regardless of the kerogen or gas type. The maximum adsorption capacity was 10.6 mmol/g for the CO2, 7.5 mmol/g for CH4, and 3.7 mmol/g for the H2 in overmature kerogen at 20 MPa and 323 K. In all kerogens, adsorption followed the trend CO2 CH4 H2 attributed to the larger molecular size of CO2, which increased its affinity toward the kerogen. In addition, the adsorption capacity was directly associated with maturity and carbon content. This behavior can be attributed to a specific functional group, i.e., H, O, N, or S, and an increase in the effective pore volume, as both are correlated with organic matter maturity, which is directly proportional to the adsorption capacity. With the increase in carbon content from 40% to 80%, the adsorption capacity increased from 2.4 to 3.0 mmol/g for H2, 7.7 to 9.5 mmol/g for CO2, and 4.7 to 6.3 mmol/g for CH4 at 15 MPa and 323 K. With the increase in micropores, the porosity increased, and thus II-D offered the maximum adsorption capacity and the minimum II-A kerogen. For ex le, at a fixed pressure (20 MPa) and temperature (373 K), the CO2 adsorption capacity for type II-A kerogen was 7.3 mmol/g, while type II-D adsorbed 8.9 mmol/g at the same conditions. Kerogen porosity and the respective adsorption capacities of all gases followed the order II-D II-C II-B II-A, suggesting a direct correlation between the adsorption capacity and kerogen porosity. These findings thus serve as a preliminary dataset on the gas adsorption affinity of the organic-rich shale reservoirs and have potential implications for CO2 and H2 storage in organic-rich formations.
Publisher: Elsevier BV
Date: 08-2022
DOI: 10.1016/J.JCIS.2022.03.138
Abstract: We conducted measurements of hydrogen adsorption on three coal s les of varying ranks at high pressure (0 to 102 bar) and elevated temperatures (303 K to 333 K) to assess their hydrogen storage potential. The excess adsorption capacity increased with increasing pressure but decreased with increasing temperature irrespective of coal rank. The highest hydrogen adsorption recorded was 0.721 mol/kg for the anthracite coal at 303 K and 102 bar. Furthermore, the hydrogen adsorption capacity correlated positively with coal vitrinite and fixed carbon contents (i.e. the high-rank coal exhibited greater adsorption), while all s les depicted predominantly type-I adsorption behavior for the entire pressure range. Micropore analysis and Fourier-transform infrared spectroscopy measurements were conducted to explore the microstructural and surface chemistry associated with these adsorption trends. The micropore content of the three s les followed the order: anthracite > sub-bituminous > bituminous, while H
Publisher: American Chemical Society (ACS)
Date: 15-08-2023
Publisher: American Chemical Society (ACS)
Date: 07-05-2021
Publisher: Elsevier BV
Date: 2024
Publisher: Elsevier BV
Date: 08-2017
Publisher: Elsevier BV
Date: 04-2019
Publisher: American Chemical Society (ACS)
Date: 06-10-2022
Publisher: Elsevier BV
Date: 10-2016
Publisher: Elsevier BV
Date: 04-2021
Publisher: American Chemical Society (ACS)
Date: 02-02-2021
Publisher: Elsevier BV
Date: 03-2020
Publisher: Elsevier BV
Date: 10-2016
Publisher: American Chemical Society (ACS)
Date: 05-12-2022
Publisher: American Chemical Society (ACS)
Date: 25-02-2022
Publisher: Elsevier BV
Date: 07-2016
Publisher: MDPI AG
Date: 07-03-2022
DOI: 10.3390/MOLECULES27051739
Abstract: An understanding of clay mineral surface chemistry is becoming critical as deeper levels of control of reservoir rock wettability via fluid–solid interactions are sought. Reservoir rock is composed of many minerals that contact the crude oil and control the wetting state of the rock. Clay minerals are one of the minerals present in reservoir rock, with a high surface area and cation exchange capacity. This is a first-of-its-kind study that presents zeta potential measurements and insights into the surface charge development process of clay minerals (chlorite, illite, kaolinite, and montmorillonite) in a native reservoir environment. Presented in this study as well is the effect of fluid salinity, composition, and oilfield operations on clay mineral surface charge development. Experimental results show that the surface charge of clay minerals is controlled by electrostatic and electrophilic interactions as well as the electrical double layer. Results from this study showed that clay minerals are negatively charged in formation brines as well as in deionized water, except in the case of chlorite, which is positively charged in formation water. In addition, a negative surface charge results from oilfield operations, except for operations at a high alkaline pH range of 10–13. Furthermore, a reduction in the concentrations of Na, Mg, Ca, and bicarbonate ions does not reverse the surface charge of the clay minerals however, an increase in sulfate ion concentration does. Established in this study as well, is a good correlation between the zeta potential value of the clay minerals and contact angle, as an increase in fluid salinity results in a reduction of the negative charge magnitude and an increase in contact angle from 63 to 102 degree in the case of chlorite. Lastly, findings from this study provide vital information that would enhance the understanding of the role of clay minerals in the improvement of oil recovery.
Publisher: Elsevier BV
Date: 2018
Publisher: Elsevier BV
Date: 04-2017
Publisher: Society of Petroleum Engineers (SPE)
Date: 09-02-2023
DOI: 10.2118/214324-PA
Abstract: Anhydrite (CaSO4) is a chemically reactive rock/mineral found predominantly as a constituent of carbonates. The main constituents of anhydrite are calcium and sulfate ions. The presence of anhydrite, its distribution, and the associated anhydrite-fluid interactions are important to precisely evaluate the effectiveness of oil recovery techniques. While anhydrite dissolution is the key interaction mechanism in anhydrite-rich rocks, its presence may also lead to complex rock wetting behavior. The underpinning logic is that pure anhydrite is strongly water-wet, while pure calcite and dolomite are somewhat intermediate to weakly oil-wet, thus the question remains unclear as to what the wettability would be of anhydrite and calcite, and anhydrite and dolomite combinations. Moreover, because anhydrite is negatively charged while dolomite and calcite in formation water (FW) are positively charged, depending on the mixture composition, pH, and brine type, it is not clear what the charge would be of a combination of anhydrite-calcite or anhydrite-dolomite, and, consequently, what the wetting behavior of calcite and dolomite would be due to anhydrite presence. Therefore, this research explores the effect of anhydrite mineral on carbonate wetting characteristics. The effect of mineralogical heterogeneity, specifically the presence of anhydrite minerals in calcite and dolomite wettability, is investigated across a range of scales. The results show that anhydrite dissolution occurs in deionized (DI) water, seawater (SW), and FW as evident from the general increase in sulfate ions concentration with increased anhydrite content in the anhydrite-carbonate system. We also found that zeta potential demonstrates an unstable colloidal system, which is indicated by near-zero and low zeta potential values (less than ±10) of the anhydrite-carbonate-brine systems. It also shows a nonmonotonic wetting behavior with brine salinity and pH variations. Accordingly, the zeta potential is not a general and valid candidate to justify the wettability behavior of heterogeneous carbonates. However, based on flotation and contact angle techniques of wettability estimation, anhydrite presence has the tendency to alter the wetting state of anhydrite-carbonate-brine-oil systems to more water-wet. Thus, findings from this research will provide answers to the question of how the mineralogy affects the wetting characteristics of carbonates. What will be the changes in carbonate wetting behavior with mineralogical heterogeneity? Specifically, what would be the wettability of calcite-anhydrite and dolomite-anhydrite combinations? This research therefore provides a systematic investigation of rock/fluid interactions and their implications on wettability and ultimate recovery of oil at different range scales. The findings from this study will significantly enhance our knowledge of fluid-rock interactions, in particular, anhydrite-rich carbonate wetting behavior, thereby reducing the uncertainties associated with laboratory-scale predictions and oil recovery planning.
Publisher: Elsevier BV
Date: 2016
DOI: 10.1016/J.JCIS.2015.09.076
Abstract: Precise characterization of wettability of CO2-brine-rock system and CO2-brine interfacial tension at reservoir conditions is essential as they influence capillary sealing efficiency of caprocks, which in turn, impacts the structural and residual trapping during CO2 geo-sequestration. In this context, we have experimentally measured advancing and receding contact angles for brine-CO2-mica system (surface roughness ∼12nm) at different pressures (0.1MPa, 5MPa, 7MPa, 10MPa, 15MPa, 20MPa), temperatures (308K, 323K, and 343K), and salinities (0wt%, 5wt%, 10wt%, 20wt% and 30wt% NaCl). For the same experimental matrix, CO2-brine interfacial tensions have also been measured using the pendant drop technique. The results indicate that both advancing and receding contact angles increase with pressure and salinity, but decrease with temperature. On the contrary, CO2-brine interfacial tension decrease with pressure and increase with temperature. At 20MPa and 308K, the advancing angle is measured to be ∼110°, indicating CO2-wetting. The results have been compared with various published literature data and probable factors responsible for deviations have been highlighted. Finally we demonstrate the implications of measured data by evaluating CO2 storage heights under various operating conditions. We conclude that for a given storage depth, reservoirs with lower pressures and high temperatures can store larger volumes and thus exhibit better sealing efficiency.
Publisher: Elsevier BV
Date: 2023
Publisher: Elsevier BV
Date: 2019
DOI: 10.1016/J.JCIS.2018.08.106
Abstract: CO We thus systematically analysed these relationships as a function of pressure, temperature, storage depth and organic acid concentrations. A particular focus was on identifying organic acid concentration thresholds above which storage efficiency may get influenced significantly. These thresholds (defined for structural trapping as a water contact angle θ > 90° and for capillary trapping when primary drainage is unaffected, i.e. θ > 50°) were very low for structural trapping (∼10
Publisher: Elsevier BV
Date: 06-2019
DOI: 10.1016/J.CIS.2019.03.009
Abstract: CO
Publisher: Elsevier BV
Date: 07-2018
Publisher: Elsevier BV
Date: 12-2017
DOI: 10.1016/J.JCIS.2017.08.043
Abstract: Nanofluids (i.e. nanoparticles dispersed in a fluid) have tremendous potential in a broad range of applications, including pharmacy, medicine, water treatment, soil decontamination, or oil recovery and CO
Publisher: Elsevier BV
Date: 06-2023
Publisher: American Chemical Society (ACS)
Date: 29-10-2020
Publisher: Elsevier BV
Date: 11-2023
Publisher: Elsevier BV
Date: 04-2018
Publisher: Elsevier BV
Date: 2021
Location: Saudi Arabia
No related grants have been discovered for Muhammad Arif.