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Acidizing is one of the most used stimulation techniques in the petroleum industry. Several reports have been issued on the difficulties encountered during the stimulation operation of the Ahdeb oil field, particularly in the development of the Mishrif reservoir, including the following: (1) high injection pressures make it difficult to inject acid into the reservoir formation, and (2) only a few acid jobs have been effective in Ahdeb oil wells, while the bulk of the others has been unsuccessful. The significant failure rate of oil well stimulation in this deposit necessitates more investigations. Thus, we carried out this experimental study to systematically investigate the influence of acid treatment on the geomechanical properties of Mi4 formation of the Mishrif reservoir. The acid core-flood experiments were performed on seven core samples from the oil reservoir in central Iraq. The porosity, permeability, acoustic velocities, rock strength, and dynamic elastic parameters were computed before and after the acidizing treatment. To determine the optimal acid injection rate, different injection flow rates were used in the core-flooding experiments. The propagation of an acid-induced wormhole and its effect on the rock properties were analyzed and compared to that of intact rocks. Computed tomography (CT) scan and a 3D reconstruction technique were also conducted to establish the size and geometry of the generated wormhole. To analyze the influence of mineralogical variation and heterogeneity and confirm the consistency of the outcomes, acidizing experiments on different rock samples were conducted. The results demonstrate that for all the rock samples studied, the mechanical properties exhibit rock weakening post-acid treatment. The Young’s modulus reduced by 26% to 37%, while the Poisson’s ratio, the coefficient of lateral earth pressure at rest, and the material index increased by 13% to 20%, 23% to 32%, and 28% to 125%, respectively. The CT scan visually confirmed that the acid treatment effectively creates a pathway for fluid flow through the core.

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.

Hypothesis CO2 geo-storage is a technique, where millions of tonnes of CO2 are stored in underground formations every year for permanent immobilization to reduce greenhouse gas emissions. Among promising geo-storage formations, basalt is attracting keen interest from researchers and industry. However, the literature severely lacks information on the wetting behaviour of basaltic rocks at geo-storage conditions. Experiments To enable a more general statement of basalt-scCO2-brine contact angles, the wettability of a basalt from Western Australia was compared with a similar rock type from Iceland. This study reports the advancing and receding contact angles for a basalt-scCO2-brine system at pressures ranging from 0.1 to 20 MPa and temperatures of 298 and 323 K, respectively. Based on the experimental data, the amount of CO2, expressed by the column height, which could be safely trapped beneath the basalt was then calculated. Findings The basalt was initially water-wet but with increasing pressure, it was converted sequentially from a water-wet to an intermediate-wet and then finally into a completely CO2-wet template at pressures exceeding 15 MPa and 323 K. Under those experimental conditions, found in the field at depths below 1500 m, injected supercritical CO2 into a porous basalt reservoir is assumed to flow freely in lateral and vertical directions and is less impeded by capillary/residual trapping, potentially leading to CO2 leakage. It is suggested that the injection depth should not be chosen too deep to avoid increased free CO2 plume mobility. It is found from CO2 column height calculations that at 800 m depth (a minimum requirement to keep CO2 supercritical), the height of the CO2 column that can be safely trapped below the cap rock, was still 100 m but shrank to nil at ≥1500 m.

Gas hydrates are large energy resources with estimated global reserves of approximately 500–10 000 Gt of carbon, which can be extracted from underground reservoirs. In addition, such reservoirs can...

The challenge associated with large-scale hydrogen storage is a pertinent one to achieve a hydrogen economy. The increasing global demand for clean and green energy is the driving force to propel such an economy. Furthermore, hydrogen is also considered an alternative energy source compared to fossil fuel as a clean energy alternative. Hydrogen geo-storage in a deep saline aquifer, depleted oil and gas reservoirs can resolve this challenge. We assess the potential of a saline aquifer in a sandstone formation to store hydrogen through first-of-its-kind x-ray micro-computed tomography miniature coreflood experiments. The investigation shows that ~65% of the sandstone's pore volume can be occupied by hydrogen when injected at a slow rate. Residual saturation of hydrogen upon brine injection can be ~41%.

CO2 geo-storage in basaltic formations has recently been identified as a viable option to rapidly dispose large quantities of CO2 , hence mitigating anthropogenic CO2 emissions. However, it has been shown that basalt is weakly water-wet or intermediate-wet at typical storage conditions, which reduces capillary trapping capacities and increases lateral and vertical spreading of the CO2 plume; and these effects increase project risk. We thus propose here to prime basalt surfaces with anionic surfactant (here we used sodium dodecyl benzene sulfonate), and demonstrate that such priming is highly efficient, and renders the basalt completely water-wet even at high pressures and minute sodium dodecyl benzene sulfonate concentrations. Such a wettability alteration can therefore significantly de-risk storage projects. This work aids in the improvement of CO2 storage in basaltic formations and supports implementation of industrial-scale CO2 geo-sequestration and climate change mitigation. Cited as: Iglauer, S., Al-Yaseri, A. Improving basalt wettability to de-risk CO2 geo-storage in basaltic formations. Advances in Geo-Energy Research, 2021, 5(3): 347-350, doi: 10.46690/ager.2021.03.09

Today, bi - reforming of methane is considered as an emerging replacement for the generation of high-grade synthesis gas (H2:CO = 2.0), and also as an encouraging renewable energy substitute for fossil fuel resources. For achieving high conversion levels of CH4, H2O, and CO2 in this process, appropriate operation variables such as pressure, temperature and molar feed constitution are prerequisites for the high yield of synthesis gas. One of the biggest stumbling blocks for the methane reforming reaction is the sudden deactivation of catalysts, which is attributed to the sintering and coke formation on active sites. Consequently, it is worthwhile to choose promising catalysts that demonstrate excellent stability, high activity and selectivity during the production of syngas. This review describes the characterisation and synthesis of various catalysts used in the bi-reforming process, such as Ni-based catalysts with MgO, MgO–Al2O3, ZrO2, CeO2, SiO2 as catalytic supports. In summary, the addition of a Ni/SBA-15 catalyst showed greater catalytic reactivity than nickel celites; however, both samples deactivated strongly on stream. Ce-promoted catalysts were more found to more favourable than Ni/MgAl2O4 catalyst alone in the bi-reforming reaction due to their inherent capability of removing amorphous coke from the catalyst surface. Also, Lanthanum promoted catalysts exhibited greater nickel dispersion than Ni/MgAl2O4 catalyst due to enhanced interaction between the metal and support. Furthermore, La2O3 addition was found to improve the selectivity, activity, sintering and coking resistance of Ni implanted within SiO2. Non-noble metal-based carbide catalysts were considered to be active and stable catalysts for bi-reforming reactions. Interestingly, a five-fold increase in the coking resistance of the nickel catalyst with Al2O3 support was observed with incorporation of Cr, La2O3 and Ba for a continuous reaction time of 140 h. Bi-reforming for 200 h with Ni-γAl2O3 catalyst promoted 98.3% conversion of CH4 and CO2 conversion of around 82.4%. Addition of MgO to the Ni catalyst formed stable MgAl2O4 spinel phase at high temperatures and was quite effective in preventing coke formation due to enhancement in the basicity on the surface of catalyst. Additionally, the distribution of perovskite oxides over 20 wt % silicon carbide-modified with aluminium oxide supports promoted catalytic activity. NdCOO3 catalysts were found to be promising candidates for longer bi-reforming operations.

Abstract Underground hydrogen (H2) storage is a prominent technique for enabling H2-based economy via offering a large-scale storage medium. Recently, volcanic basaltic formations have been investigated as a potential medium for gas storage due to their thickness, vast extension, and potential volumetric capacity. Wettability is one of the essential parameters studied to understand the capillary-entrapment of the stored gas in porous media. Therefore, in this study, we evaluate the wettability of rock/H2/brine system of two different saudi basaltic rock samples by measuring the contact angles using relevant reservoir brine (10% NaCl) under storage conditions at temperature of 323K and varying pressures (3 to 28 MPa). The measurements were conducted using the modified sessile drop method and surface roughness was determined to ensure accurate results. The results showed relatively low variation with pressure. Saud basalt-1 with higher Si-O-Si and hydroxyl group bondings from FTIR demonstrated better sealing conditions for H2 storage than Saudi basalt-2. Additionally, the pore throat radius has a proportional relationship with 𝑝𝑐𝑒 and ℎ𝑔𝑚𝑎𝑥. Smaller pore-size basaltic rocks are better for safe and secure storage, and a potential effective capillary entrapment of H2. Introduction Governments and countries worldwide are adapting strict environmental regulations to reduce harmful anthropogenic emissions of greenhouse gases such as carbon dioxide (CO2), attributed mainly to the burning of fossil fuels (Hashemi et al., 2021; IEA, 2018). Alternatively, hydrogen (H2) emerges as a promising clean fuel to support decarbonization by converting energy production from fossil fuels into a more environmental-friendly form and supporting clean energy from renewable resources such as wind turbines and solar power (Pan et al., 2021). However, wide-scale implementation of an H2-based economy requires a medium of Giga to Tera scale storage capacity, which can be theoretically offered by geological formations such as saline aquifers, depleted oil and gas reservoirs, and salt caverns (Heinemann et al., 2021).

Objectives/Scope Underground hydrogen storage (UHS) has been raising more interest to safely and cost-effectively store hydrogen at large-scale to help the transition from fossil fuel to sustainable energy and to achieve net-zero emission target. During hydrogen subsurface storage particularly in depleted gas reservoirs, the wellbore plays an important role in injection and reproduction to meet seasonal energy demand. However, it is still unclear how wellbore cement would react with stored hydrogen in the presence of formation brine, which may effect long-term cement integrity. We thus performed thermodynamic modelling on cement reactions with hydrogen and water at reservoirs conditions. Methods, Procedures, Process The dissolution of individual components of cement including C3S, C2S, C3A, C4AF and gypsum of Class G/H, and potential precipitation of twenty secondary minerals were simulated at an infinite time scale at reservoir temperature and pressure (representing the worst case scenario of cement degradation from geochemical perspective; in real case, the degree of cement degradation would be much less than the results from thermodynamic modelling as it is a time-dependent process). The extent of cement mineral reactions with hydrogen was compared with that of methane and carbon dioxide to assess the wellbore cement integrity during UHS compared to UGS and CCS. Results, Observations, Conclusions The cement hydration process would lead to the transformation of the major cement compositions C3S and C2S to C1.5SH (CSH) and portlandite. Adding hydrogen would only slightly change the percentage of C1.5SH and portlandite and generate a small fraction of new mineral mackinawite. As a comparison, adding methane would generate a considerable amount of calcite. When CO2 is involved, all CSH compounds would transform to calcite through the cement carbonation process. Overall, the compositional mineral phases of cement after cement hydration is more closed to the case involving H2 compared to CH4 and CO2, implying a relatively low risk of wellbore cement degradation during UHS. Novel/Additive Information Our work underlines the importance of incorporating geochemical modelling in hydrogen geo-storage evaluation when using existing old wells and new drilled wells.

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.

Fracture is one of the most important geological phenomena that affect the production of hydrocarbon compounds in broken carbonate reservoirs. However, fracture controlling factors must be combined with well data to achieve accurate fracture modeling. Therefore, structural data, drilling data, well flow diagrams, cores data, wells production data, and dynamic reservoir data have been considered here. Finally, by combining the above-mentioned information and through statistical and mathematical methods, the mechanism of fracture creation, general trends, and dominant fracture patterns are determined. These patterns are directly related to the tectonic regime and the stresses governing the region. For the first time, in this paper, we divided Zubair carbonate gas reservoir into 10 zones based on porosity and water saturation, and shale volume variation. We conclude that just four-zone of these are economic producible. Besides, the dominant lithology of this formation is more than limestone and a small number of thin shale layers. We defined types of cross-sectional petro-physical graphs and confirmed them by the geological graphic diagram prepared at the head.

In-situ nuclear magnetic resonance (NMR) core flooding system has enabled researchers to monitor several rock properties such as porosity, pore size distribution, and fluid saturation along the tested samples with high resolutions and under reservoir conditions. However, spatially resolved rock strength/mechanical property alteration coupled to fluid migration/substitution remains poorly characterized. To this end, Fiber Bragg Grating (FBG) multiplex sensors were integrated with NMR core flooding system to monitor rock strength changes, or generally speaking, to observe hydro-mechanical-chemical coupling mechanisms during core flooding tests. In this study, we present a novel approach on how to conduct core flooding experiments, while simultaneously monitoring NMR and FBG strain response of the tested limestone plug. The NMR cell was modified to integrate FBG technology without impeding the NMR signal and core flooding high pressure/temperature capacity. A high spatial resolution optical fiber was attached onto the sample radial surface. The results show the successful association of NMR and FBG sensors to track any change at each stage of brine injection. The FBG is capable of measuring the rock strain variations induced by rock-fluid interactions during brine injection, allowing it to capture the fluid front location along with the sample and at a faster rate than the NMR.

Wettability is one of the main parameters controlling CO2 injectivity and the movement of CO2 plume during geological CO2 sequestration. Despite significant research efforts, there is still a high uncertainty associated with the wettability of CO2/brine/rock systems and how they evolve with CO2 exposure. This study, therefore, aims to measure the contact angle of sandstone samples with varying clay content before and after laboratory core flooding at different reservoir pressures, of 10 MPa and 15 MPa, and a temperature of 323 K. The samples’ microstructural changes are also assessed to investigate any potential alteration in the samples’ structure due to carbonated water exposure. The results show that the advancing and receding contact angles increased with the increasing pressure for both the Berea and Bandera Gray samples. Moreover, the results indicate that Bandera Gray sandstone has a higher contact angle. The sandstones also turn slightly more hydrophobic after core flooding, indicating that the sandstones become more CO2-wet after CO2 injection. These results suggest that CO2 flooding leads to an increase in the CO2-wettability of sandstone, and thus an increase in vertical CO2 plume migration and solubility trapping, and a reduction in the residual trapping capacity, especially when extrapolated to more prolonged field-scale injection and exposure times.