A tremendous amount of fossil fuel is utilized to meet the rising trend in the world’s energy demand, leading to the rising level of CO₂ in the atmosphere and ultimately contributing to the greenhouse effect. Numerous CO₂ mitigation strategies have been used to reverse this upward trend since large-scale decarbonization is still impractical. For multiple reasons, one of the optimal and available solutions is the usage of old depleted oil and gas reservoirs as objects for prospective CO₂ utilization. The methods used in CO₂ underground storage are similar to those used in oil exploration and production. However, the process of CO₂ storage requires detailed studies conducted experimentally and numerically. The main goal of this paper is to present an overview of the existing laboratory studies, engineering and modeling practices, and sample case studies related to the CCS in oil and gas reservoirs. The paper covers geological CO₂ storage technologies and discusses knowledge gaps and potential problems. We attempt to define the key control parameters and propose best practices in published experimental and numerical studies. Analysis of laboratory experiments shows the applicability of the selected reservoirs focusing on trapping mechanisms specific to oil and gas reservoirs only. The current work reports risk control and existing approaches to numerical modeling of CO₂ storage. We also provide updates on completed and ongoing CCS in oil and gas reservoir field projects and pilots worldwide.

This paper presents an integrated petrophysical characterization of a representative set of complex carbonate reservoir rock samples with a porosity of less than 3% and permeability of less than 1 mD. Laboratory methods used in this study included both bulk measurements and multiscale void space characterization. Bulk techniques included gas volumetric nuclear magnetic resonance (NMR), liquid saturation (LS), porosity, pressure-pulse decay (PDP), and pseudo-steady-state permeability (PSS). Imaging consisted of thin-section petrography, computed X-ray macro- and microtomography, and scanning electron microscopy (SEM). Mercury injection capillary pressure (MICP) porosimetry was a proxy technique between bulk measurements and imaging. The target set of rock samples included whole cores, core plugs, mini cores, rock chips, and crushed rock. The research yielded several findings for the target rock samples. NMR was the most appropriate technique for total porosity determination. MICP porosity matched both NMR and imaging results and highlighted the different effects of solvent extraction on throat size distribution. PDP core-plug gas permeability measurements were consistent but overestimated in comparison to PSS results, with the difference reaching two orders of magnitude. SEM proved to be the only feasible method for void-scale imaging with a spatial resolution up to 5 nm. The results confirmed the presence of natural voids of two major types. The first type was organic matter (OM)-hosted pores, with dimensions of less than 500 nm. The second type was sporadic voids in the mineral matrix (biogenic clasts), rarely larger than 250 nm. Comparisons between whole-core and core-plug reservoir properties showed substantial differences in both porosity (by a factor of 2) and permeability (up to 4 orders of magnitude) caused by spatial heterogeneity and scaling.

The experimental and numerical modeling of thermal enhanced oil recovery (EOR) requires a detailed laboratory analysis of core properties influenced by thermal exposure. To acquire the robust knowledge on the change in rock saturation and reservoir properties, the fastest way is to examine the rock samples before and after combustion. In the current paper, we studied the shale rock properties, such as core saturation, porosity, and permeability, organic matter content of the rock caused by the combustion front propagation within the experimental modeling of the high-pressure air injection. The study was conducted on Bazhenov shale formation rock samples. We reported the results on porosity and permeability evolution, which was obtained by the gas pressure-decay technique. The measurements revealed a significant increase of porosity (on average, for 9 abs. % of porosity) and permeability (on average, for 1 mD) of core samples after the combustion tube experiment. The scanning electron microscopy showed the changes induced by thermal exposure: the transformation of organic matter with and the formation of new voids and micro and nanofractures in the mineral matrix. Low-field Nuclear Magnetic Resonance (NMR) was chosen as a primary non-disruptive tool for measuring the saturation of core samples in ambient conditions. NMR T₁–T₂ maps were interpreted to determine the rock fluid categories (bitumen and adsorbed oil, structural and adsorbed water, and mobile oil) before and after the combustion experiment. Changes in the distribution of organic matter within the core sample were examined using 2D Rock-Eval pyrolysis technique. Results demonstrated the relatively uniform distribution of OM inside the core plugs after the combustion.

In this work, we have investigated the wettability of Bazhenov Formation rock samples using a nuclear magnetic resonance (NMR), the methods of vapor adsorption, and wetting contact angle. We have conducted the petrographic description of rocks using ultra-thin sections and scanning electron microscopy (SEM). In addition, we used data on the organic content (TOC) obtained by the Rock-Eval method and the results of lithological typing on thin sections for detailed analysis of NMR and contact angle methods results. Thus, for target rock, the groups with a similar rock wettability were highlighted by the lithological description of thin sections. The calculation of the wetting angle provided an initial assessment of the surface wettability of the rock and made it possible to establish the relationship between the wetting angle and the TOC, which is relevant for rocks of the Abalak-Bazhenov group. The NMR method described the core plug wettability proved to be less sensitive to the rock lithotype and organic matter (OM) texture in the rock and, therefore, used for the integral characterization of core plugs. Correlations of calculated wetting angle and adsorption wettability index vs. TOC and OM texture illustrated the dependence of rock wettability behavior on both the lithological specifics and the OM properties.

The migration of dissolved salts from natural saline solutions (cryopeg brines or seawater) into permafrost and its effect on the dissociation of intrapermafrost gas hydrates is studied in laboratory experiments. The experiments are applied to laboratory-made frozen sand samples saturated with methane hydrate and exposed to interaction with chemically different frozen saline solutions simulating cryopeg brines. The runs were performed at atmospheric pressure and a constant subzero temperature of approximately −6 °C, i.e., under the P-T conditions that can maintain self-preservation of metastable methane pore hydrates. Variations in the NaCl/MgCl ₂ concentration ratio in the solutions affect significantly the salt transport patterns and the salinity level critical for complete hydrate dissociation. Specifically, both salt migration and hydrate dissociation in frozen soils are faster at lower NaCl and higher MgCl ₂ concentrations. Phase transitions in the pore moisture of frozen hydratebearing sand samples interacting with frozen saline solutions are analyzed using low-field NMR relaxometry. According to the NMR data, the front of elevated liquid water content propagates along the salt flow direction, at a rate increasing with the mobility of salt ions in the series Na ₂ SO ₄ – NaCl – MgCl ₂ . The experimental results confirm that migration of natural saline solutions (e.g., cryopeg brines or seawater) driven by natural or production-related factors can destabilize intrapermafrost gas hydrates.

Accurate determination of fluid saturation and organic matter content is essential for the characterization and assessment of organic-rich source rock reserves. However, few advanced techniques are available to precisely identify fluid-porous systems and define prospective deposits throughout various stages of field exploration. This paper explores the combined application of two widely utilized methods — low-field nuclear magnetic resonance relaxometry (NMR) and Rock-Eval pyrolysis — using an expanded suite of rock samples. The primary objective of this study is to establish optimized workflows that offer a more comprehensive quantification of liquid saturation with heavy to mobile hydrocarbons compared to standard industry practices and help to identify the fluid volumetric model of the target formation. Main findings demonstrate correlations between NMR-obtained data, mineral composition of the rock and organic matter components by Rock-Eval pyrolysis. The detailed analysis and comparison of experimental results is performed using the manual interpretation of NMR T₁-T₂ maps and Mutual Information regression approach that processed the NMR T₂ spectrum. The research lays the groundwork for NMR-based Machine Learning-assisted in situ characterization of mineral components (quartz and clays), crude oil maturity and volume for shale deposits, along with determining the ratio between bound and mobile oil components.