To investigate the fracture initiation and propagation behavior of fractures in tight sandstone under the supercritical CO2 (SCCO2) shock fracturing, laboratory fracturing experiments were conducted using a true-triaxial-like SCCO2 shock fracturing system. Computed tomography (CT) scanning and three-dimensional fracture reconstruction were employed to elucidate the effects of shock pressure, pore pressure, and in-situ stress on fracture characteristics. In addition, nuclear magnetic resonance (NMR) transverse relaxation time spectra were used to assess the internal damage induced by SCCO2 shock fracturing. The results indicate that, compared with conventional hydraulic fracturing and SCCO2 quasi-static fracturing, SCCO2 shock fracturing facilitates multidirectional fracture initiation and the formation of complex fracture networks. Increasing shock pressure more readily activates bedding-plane weaknesses, with main and subsidiary fractures interweaving into a dense fracture network. Under the same impulse intensity, elevated pore pressure reduces the effective normal stress and alters stress-wave scattering paths, thereby inducing more branch fractures and enhancing fracture complexity. An increase in differential in-situ stress promotes fracture propagation along the direction of the maximum principal stress, reduces branching, and simplifies fracture morphology. With increasing SCCO2 shock pressure, pore volume and connectivity generally increase: small-to-medium pores primarily respond through increased number and enhanced connectivity; when the shock pressure rises to 40-45 MPa, crack coalescence generates larger pores and fissures, which play a dominant role in improving flow pathways and effective storage space, ultimately forming a multiscale pore-fracture network.

Fractures in rock masses are a central focus in research areas such as unconventional energy extraction, nuclear waste disposal, and carbon sequestration. Laboratory investigations of fracture parameters are essential for optimizing field operations. In recent years, CT scanning has emerged as a widely adopted non-destructive inspection technique. However, existing methods for post-processing CT scan data face persistent challenges in achieving high accuracy and efficiency. To address these challenges, we propose a novel Python-based post-processing framework that integrates a slice-by-slice thinning algorithm, local thickness computation, and point cloud data processing techniques. This framework enables precise characterization of fractured digital rocks by quantifying fracture width distribution and fracture surface orientation, alongside standard structural evaluation metrics such as the fractal dimension, volume ratio, and the H-index. Its feasibility, accuracy, and flexibility are validated through analyses of diverse fracturing samples, including fluid-fractured samples, shear-induced fracture samples, and samples containing multiple secondary fractures. PROGRAM SUMMARY Program title:Digifrac CPC Library link to program files: https://10.17632/hcynpd9hf4.1 Developer’s repository link: https://github.com/BinWang0213/DigiFrac Licensing provisions: GPLv3 Programming language: Python Nature of problem: This program quantitatively calculates the three-dimensional structural parameters of fracture networks in rocks based on CT scan data. In addition to basic parameters such as fractal dimension, fracture volume, and surface area, it also provides accurate determinations of fracture width distribution and fracture surface orientation. Solution method: The random forest algorithm is employed to improve the accuracy of CT data segmentation, while a slice-by-slice thinning algorithm is used to extract the fracture medial surface, thereby enhancing the precision of fracture aperture distribution calculations. Furthermore, the three-dimensional orientation distribution of fractures is determined from the 3D point cloud data of the extracted medial surface.

This study presents an integrated, multi-scale laboratory workflow designed specifically for organic-rich shales using multistage solvent extraction. Applied to oil shales of the Bazhenov Formation of varying maturity and lithology, the key unconventional play in Western Siberia, it enables the construction of a robust, volumetric fluid saturation model. The workflow combines mineralogical characterization, conventional core testing, low-field nuclear magnetic resonance relaxometry, high-resolution X-ray computed microtomography, Rock-Eval pyrolysis, and sequential saturates, aromatics, resins, and asphaltenes fractionation following a three-stage solvent extraction protocol. The core analysis following three-step extraction provides new insights into the interplay between lithology, pore system architecture, and fluid distribution mechanisms within tight, organically heterogeneous media. Key findings highlight that conventional methods often underestimate producible hydrocarbons trapped in kerogen nanopores and asphaltene aggregates, necessitating revised nuclear magnetic resonance interpretation approaches. Mechanically induced porosity, varying with organic matter maturity, is identified and linked to hydrocarbon release and matrix deformation. Combining nuclear magnetic resonance and gas porosity measurements provides a rapid, accurate porosity estimation method with minimal sample alteration. Finally, a conceptual fluid physical model is proposed to better interpret nuclear magnetic resonance data and pore-scale fluid dynamics in similar oil shales. The refined methodology of express core assessment significantly improves industry conventional practices by enabling a more precise and physically meaningful quantification of in-situ fluid saturation, including differentiation between bound heavy hydrocarbons and mobile fractions. Beyond advancing the fundamental understanding of fluid saturation and storage capacity in unconventional systems, this framework supports improved reservoir characterization and modeling efforts.

Deep coal seams are ideal reservoirs for CO2 geological storage. However, their pore-fracture structures are usually saturated with a large amount of formation water after fracturing stimulation, making it crucial to effectively increase the solubility of CO2 in formation water for successful geological sequestration. Therefore, this study employs molecular simulation to investigate the dissolution stability of CO2 in water with the addition of sodium lauroyl sarcosinate (SLS) under the conditions of 60℃ and 20MPa. The results indicate that although CO2 can be captured by micelles in the short term, the system is difficult to mix stably at the macro level. Regardless of the concentration of SLS, micelle aggregation and solubilization resistance both increase the mixing free energy, leading to gas-liquid separation. Thus, the addition of SLS in deep coal seams cannot effectively promote CO2 geological storage. To enable environmentally friendly surfactants with biodegradability to function effectively in CO2 geological sequestration, a synergistic approach involving the addition of co-surfactants, natural polymers, and nanoparticles can be considered.

Binary surfactant mixtures exhibit superior performance in enhanced oil recovery and CO₂ sequestration applications, yet the molecular origins of their synergistic behavior remain incompletely understood. Here, we integrate experimental characterization (tensiometry, conductimetry, foam rheology) with molecular dynamics simulations to establish quantitative structure-property relationships governing surfactant synergy at oil-water interfaces. By systematically investigating eight individual surfactants and six binary combinations across multiple mixing ratios, we demonstrate that synergistic interactions reduce critical micelle concentrations by up to 50% compared to individual components, with the most pronounced effects observed in anionic-nonionic mixtures (AOS:FARUS, 1:2 ratio). Rubingh's Regular Solution Theory analysis reveals that negative interaction parameters (β = −5.7) correlate with enhanced molecular packing and reduced interfacial tension (as low as 0.30 mN/m). Molecular dynamics simulations uncover the atomistic origins of this synergy: radial distribution function analysis demonstrates that optimal mixing stoichiometry promotes contact ion pair formation (Os–Na+ at 0.22 nm), effectively screening headgroup repulsion and enabling denser monolayer packing. This charge-mediated organization, quantified through Os–Na+/Os–Ow peak intensity ratios, provides a predictive metric for interfacial performance. Furthermore, binary systems generate CO₂ foams with approximately twice the apparent viscosity of single-surfactant foams despite 50–70% lower surfactant concentrations, attributable to the formation of more rigid, structurally coherent foam films with enhanced resistance to coalescence. Our multiscale approach suggests the entropy-driven molecular organization, rather than specific enthalpic interactions, governs enhanced interfacial properties. These findings provide a molecularly-grounded framework for the rational design of advanced surfactant formulations, enabling more efficient and sustainable hydrocarbon production with reduced chemical and environmental footprints.

The thermally enhanced oil recovery method based on supercritical water (SCW) injection into fractured horizontal wells in shale formations represents a promising strategy for converting organic solid matter (kerogen) into mobile hydrocarbons (HC). This study introduces a laboratory-scale methodology to simulate the thermal treatment of fractured shale at temperatures ranging from 300°C to 400°C and a reservoir pressure of 25 MPa while systematically evaluating the response of the shale matrix, proppants, and fracture systems. A dedicated high-pressure, high-temperature (HPHT) cell was designed and fabricated to replicate these conditions. The experiments were performed on shale samples from the Sredny Nazym oil field (total organic carbon, TOC = 7.3%) containing an artificially induced fracture packed with high-strength ceramic proppant. For 50 h, water was injected through the fracture network at temperatures ranging from 120°C to 400°C under isothermal conditions. Thermal simulation at 400°C resulted in a nearly threefold reduction in fracture conductivity, primarily driven by fracture surface degradation associated with HC generation and proppant embedment. The HC recovery coefficient reached 89%, where the pyrolysis analysis indicated a kerogen conversion of 93%. The proppant coating exhibited significant integrity loss under high-temperature and chemically aggressive conditions. Within the 120°C–300°C range, the fracture conductivity is predominantly governed by the proppant embedment and thermally induced modifications in the shale mechanical properties, coupled with matrix expansion. In contrast, at 300-400°C, fracture conductivity degradation is mainly controlled by shale matrix and fracture surface damage, along with proppant coating degradation during kerogen conversion and HC release.

In-situ hydrogen generation in hydrocarbon reservoirs provides a pathway to produce low-carbon hydrogen while retaining CO2 underground. A critical challenge for this concept is selective hydrogen recovery under extreme downhole conditions, including temperatures of 300-600 degrees C, elevated reservoir pressures, presence of mixed gas feeds including steam, methane and low concentrations of H2S. This review systematically evaluates hydrogenselective membrane classes - polymeric, inorganic, metallic, ceramic, mixed-matrix and two-dimensional - with emphasis on degradation mechanisms and operational feasibility under reservoir-relevant harsh environments. Reported performance shows H2/CO2 selectivities from below 20 for many polymeric membranes to 1000 and higher close to infinite selectivity for Pd-based systems, though often limited by mixed feeds, sulfur poisoning and embrittlement. No single membrane material satisfies all thermal, chemical and mechanical requirements. Based on comparative analysis, the review identifies dense cermet membranes as the most robust selective core and proposes a multilayer downhole architecture integrating sulfur scavengers, zeolite armor layers, 2D protective films and a cermet core. This multifunctional design improves tolerance to wet CO2 and sulfur species while remaining compatible with standard well completion practices, offering a practical pathway toward fieldscale downhole hydrogen separation.

Predicting the performance of in-situ combustion (ISC) in carbonate reservoirs is notoriously challenging. This study reveals a paradoxical permeability inversion phenomenon: initially high-permeability grainstones (up to 2600 mD) suffer catastrophic permeability damage, while initially low-permeability packstones (below 250 mD) show marked improvement. We demonstrate that this counter-intuitive behavior is driven by the thermal decomposition of dolomite. This process fundamentally transforms the rock fabric, shifting it from a robust, grain-supported architecture (grainstone/packstone) to a fragile, matrix-supported texture (wackstone-like), which critically reduces pore throat radii in high-quality rocks. At the micro-scale, the key agent of this transformation is identified as the neoformation of needle-shaped magnesium-calcium hydrosilicate crystals, which occlude pores and can occupy up to 50% of the pore volume. Stable isotope analysis confirms that this mineralogical alteration is the dominant process, revealing up to 70% of CO2 produced originates from dolomite decomposition rather than hydrocarbon combustion. These findings prove that initial reservoir quality is a poor predictor of ISC performance; instead, the geochemical reactivity and thermal stability of the rock fabric are paramount. We therefore propose the rock-fabric number as a more robust metric for predicting reservoir response to thermal EOR processes.

Thermal enhanced oil recovery techniques are widely recognized for their applicability not only in oil upgrading but also as promising methods for renewable and sustainable energy production. This study experimentally investigates carbonate decomposition under high-temperature (350, 500, and 650 degrees C) and high-pressure (8 MPa) conditions in the presence of water/steam, aiming to develop a universally applicable kinetic model for core alterations during in situ combustion, independent of oil oxidation effects. Mineral composition and rock structure are analyzed using XRF/XRD and SEM to assess changes in properties caused by high-temperature treatment and carbonate decomposition. The experimental results are numerically validated through replication in a numerical model. The validated kinetics are then integrated into a separate model of a complex triple-porosity system (matrix-fracture-vug) in carbonate rock, applied to ISC for heavy oil. The findings confirm the accelerating effect of water/steam and highlight the versatility of the developed kinetic model.

Compared with conventional chemical enhanced oil recovery methods, micro/nanofluidbased emulsion systems offer several advantages, including improved mobility control, enhanced stability, and effective modification of interfacial properties, while requiring lower chemical dosage and exhibiting better tolerance to harsh reservoir conditions. This study systematically evaluated the potential of a novel nanofluid-based emulsion as an enhanced oil recovery agent, with emphasis on its rheological behavior, emulsion stability, and interfacial performance. Rheological measurements demonstrate that emulsion viscosity is strongly influenced by the water-to-oil ratio and mixing duration. Systems with low oil content exhibit only modest viscosity changes, whereas increasing oil fraction and mixing time result in pronounced viscosity enhancement, indicating the formation of structured emulsion networks. This viscosity growth contributes to improved emulsion stability, which is further supported by microscopic observations revealing complex multiphase structures. Interfacial characterization shows that the nanofluid-based emulsion effectively lowers the oil-water interfacial tension and induces a strong wettability shift toward water-wet conditions, both of which are favorable for enhanced oil displacement. Microfluidic displacement experiments provide pore-scale evidence that the combined effects of viscosity enhancement, improved emulsion stability, interfacial tension reduction, and wettability alteration lead to efficient mobilization of residual oil. Visual observations confirm in situ emulsion formation within the porous network and improved sweep behavior compared with conventional water injection. Overall, the results highlight the multifunctional role of nanofluid-based emulsions in stabilizing flow, enhancing sweep efficiency, and modifying interfacial dynamics, demonstrating their strong potential as an advanced chemical strategy for enhanced oil recovery applications.

In the global effort to reduce greenhouse gas emissions, Carbon Capture, Utilization, and Storage (CCUS) has become a key strategy. Gas injection well, as a critical component of the CCUS technology, require effective monitoring and precise control during their operation. However, traditional wired communication methods face numerous challenges in the application of gas injection well. Pressure wave wireless communication technology offers a new solution to address these issues. To tackle this problem, this study investigates pressure wave wireless communication in CO2 injection well by establishing an OLGA-based wellbore model. Compared with H2O injection well, the propagation speed of pressure waves in CO2 injection well is about 53

Surfactant encapsulation presents a novel strategy for the targeted delivery of active molecules to oil reservoirs. This study investigates the interfacial tension, wettability alteration, static adsorption and oil displacement performance of two novel encapsulated surfactants, anionic alkyl ether carboxylate and non-ionic alkyl polyglucoside, in water-oil and water-oil-carbonate rock systems. A refined synthesis yielded silica carriers with dimensions appropriate for transport through carbonate reservoir pore networks, preventing pore blockage while enabling effective delivery. A synergism between the surfactants and silica nanoparticles, released upon carrier rupture, was confirmed. The cooperative action of silica nanoparticles and surfactant molecules, facilitated by multiple intermolecular forces, including hydrogen bonding, electrostatic, and hydrophobic, enhanced the efficiency of interfacial adsorption, leading to a significant reduction in interfacial tension compared to pure surfactant systems. Furthermore, silica nanoparticles accelerated the alteration in wettability towards a hydrophilic state via disjoining pressure and competitive adsorption on the carbonate surface. Consequently, the simultaneous enhancement of interfacial behavior and mitigation of static adsorption due to encapsulation translated into more efficient oil displacement compared to use of the pure surfactants. This work demonstrates that encapsulation not only reduces adsorption but also enhances interfacial performance and displacement efficiency, supporting its potential application in chemical enhanced oil recovery.

Mobility control of CO2 is important for effective subsurface utilization and sequestration of anthropogenic CO2 in depleted formations. This not only enhances oil recovery but also increases CO2 storage efficiency, addressing a key challenge for a future zero-carbon economy. In this study, novel techniques were developed by injecting CO2 foam generated with a nonionic-based binary surfactant system to improve geological CO2 storage and to co-optimize carbon utilization and storage efficiency in high salinity carbonate porous media, based on hypotheses from our previous works. Carbonate core samples from a producing oil field were used as the porous media to evaluate oil production and CO2 storage with varying injectants. The introduction of foam as a mobility control fluid significantly increased the CO2 retention factor by 4.6 times. With the addition of a nonionic-based binary surfactant system as a foaming agent, the retention factor further increased to 5.6 times. This is in addition to an 85% increase in oil recovery. This study demonstrates the potential of surfactant foams to control the mobility of injected gas, thereby enhancing CO2 retention in carbonate porous media. The findings highlight the effectiveness of nonionic-based binary surfactant systems as foaming agents for the co-optimization of carbon utilization and storage in depleted oil formations.

Well cements play a key role in zonal isolation of wellbores and preventing fluid or gas migration on oil, gas and geothermal wells. Creating an environmentally safe cement with excellent placement and sealing properties presents a major goal of the petroleum and geothermal industry. Unfortunately, common API (American Petroleum Institute) Class oil well cement exhibits a relatively high CO2 footprint of similar to 800 kg CO2/ton cement. To reduce this significant CO2 emission in the production of oil well cement, calcined clay (CC) presents an option as a clinker substitute. To this end, in this study, a 50:50 wt/wt. blend of API Class G cement and a calcined clay was investigated with respect to its rheological and thickening behavior and its response to common oil well cement additives (dispersant, retarder, fluid loss additives (FLA)). Experiments were carried out at water-to-cement blend ratios of 0.44 and 0.50, respectively and at low to medium temperatures (27 degrees C, 50 degrees C and 80 degrees C). It was found that calcined clay increases water demand and plastic viscosity while yield point is decreased. Moreover, owed to the lower reactivity of calcined clay, it prolongs thickening time (pumping time) and requires less retarder. The results signify that within the temperature range tested here, this cement blend could achieve excellent pumpability, adjustable thickening times using a lignosulfonate retarder, and low fluid loss rates when a common FLA was applied. Furthermore, a climate-neutral cement exhibiting a CO2 footprint of similar to 450 kg CO2/ton binder can be achieved, yet it requires a clinker substitution rate of 70 % and increased dispersant dosage. It is demonstrated that calcined clay presents a technically feasible and environmentally preferable alternative to OPC (Ordinary Portland Cement) clinker in oil well cements, and that it can significantly reduce the CO2 footprint of well cements.

Sustainable oil production and water management in the Eastern Venezuela Basin, where the largest world oil reserves are located, represents a great challenge. In the Orinoco Oil Belt or "La Faja Petrolífera Del Orinoco", the injection of polymer and surfactant (SP) has been envisioned as a strategy to control water mobility/viscous instabilities and mobilize residual oil. The objective of this article is to evaluate the feasibility of SP injection in a reservoir of the Zuata Principal Field-Junín Block to increase oil production with current recovery factors of < 5%. For the evaluation of surfactant and polymer injections in the area Zuata Principal, a cluster with a simple horizontal well configuration was chosen for the injection and future monitoring of the CEOR process. Four coreflood tests have been performed in the selected area (crude oil 9°API and 4,500 cP at 50°C), both on Bentheimer outcrops and on a real reservoir rock (unconsolidated sandstone), at the reservoir temperature of 50°C, using polymer injection (HPAM3630S) and a tailored SP alkaline-free formulation to avoid operational problems such as the formation of complex emulsions and/or scales. The history matching of laboratory tests was carried out, and a development/optimization plan was proposed for the evaluated cluster considering different injection and production scenarios. History matching of experimental tests using polymer and surfactant as a mixture is discussed in detail in this article. High recoveries were observed after SP injection in secondary conditions, with final oil saturations of less than 10% at the core scale. The importance of recovery mechanisms such as mobility control, reduction of interfacial tension, wettability alteration, microemulsion effect, and possible ions exchange due to the low salinity of the injected brine is highlighted. Additionally, a development/optimization plan is presented for the evaluated cluster system considering different chemical concentrations, injection and production scenarios. This article shows the potential of the injection of surfactants and polymers to increase production of highly viscous crude oils from the Eastern Venezuela Basin, being the first case of SP pilot application in Venezuela. The need to carry out additional studies for the optimization of chemicals and type of polymer is indicated, as well as considering economic aspects (OPEX and CAPEX) and possible operational issues associated with mobility control, high chemical losses, fluid separation, emulsion formation, water treatment, among others.

This is a conference abstract presented at the Smart microfluidics 2025.The abstract was published in the Book of Abstracts of Smart microfluidics 2025 (pp. 18–19).

This is a conference abstract presented at the Smart microfluidics 2025.The abstract was published in the Book of Abstracts of Smart microfluidics 2025 (pp. 16–17).

Supercritical CO2 (ScCO2) shock fracturing generates unique, complex radial fracture networks, but their quantitative productivity impact is poorly understood. This study introduces a novel simplified four-parameter geometric model consisting of the shock radius, fracture number, fracture network aspect ratio, and hybrid hydraulic-shock fracture length, to quantitatively characterize these specific ScCO2 fracture geometries. This geometric model was integrated with the pEDFM (projection-based Embedded Discrete Fracture Model) method. The simulation was implemented using the Matlab Reservoir Simulation Toolbox (MRST) on a structured Cartesian grid. A sensitivity analysis on cumulative oil production revealed that the shock radius has the most significant positive impact on productivity, while the fracture network aspect ratio has the least. However, increasing the shock radius carries practical safety risks and costs. Therefore, a hybrid hydraulic-shock fracturing approach, which combines an initial ScCO2 shock with subsequent quasi-static hydraulic fracturing, is proposed as a promising and practical solution, balancing productivity gains with operational constraints. This work provides quantitative guidance for optimizing ScCO2 shock treatment design.

Efficiency of surfactants in chemical EOR depends on their interfacial properties and how these properties appear in the porous medium. In each specific case, different types of surfactants perform differently and require thorough investigation of their properties and performance. This paper aims to study the mechanism of alkyl ether carboxylate (AEC) (sodium trideceth-7 carboxylate) in oil recovery within a vuggy carbonate reservoir with moderate permeability. The oil displacement process was studied through two coreflooding experiments. First experiment with X-Ray in situ saturation monitoring (ISSM) involved surfactant injection in tertiary mode and demonstrated that surfactant preferentially flows through already swept pores and does not mobilize trapped oil instantly, resulting in a slow and small increment of displaced oil. However, a 48-hour shut-in period led to enhancement of oil recovery after flow resumed. The second experiment employed low-field NMR ISSM and included measurement of relative permeability curves and showed that both brine and surfactant displace oil from the same pore range. Nonetheless, a decrease in apparent relative permeability was observed when the aqueous phase was a surfactant solution - an effect that was negated when a 48-hour shut-in was applied. The most reasonable interfacial mechanism explaining these results is oil solubilization into surfactant micelles followed by displacement of this micellar solution.

The management and storage of gases are essential to produce energy with low environmental impact from the different hydrocarbon basins in Venezuela. In particular, Eastern Venezuela Basin, where a wide variety of reservoirs with different types of complex mixtures are found (including the highly viscous oil reservoirs of the Orinoco Oil Belt), encompasses potential structures for management and storage of produced gases due to proven reservoir/seal integrity and existing infrastructure in many cases. This article presents a methodology for the storage of gases (i.e., carbon dioxide, methane, nitrogen, hydrogen) in an extra-heavy crude oil field in the Eastern Venezuela Basin, with special emphasis on the analyses of phase behavior, role of cushion and type of gas, flow and recovery mechanisms, as well as prospective additional recovery of hydrocarbons. To reproduce the phase behavior and flow/recovery mechanisms, it was necessary to build a fluid model by tuning an equation of state using a PVT analysis representative of the area under study (Junín Block of the Orinoco Belt), specifically, lab tests such as Constant Composition Expansion, Differential Liberation, separator tests, together with viscosity measurements. This fluid model was based on a tailored lumping scheme that allowed the evaluation of the injection of CO2, methane, nitrogen, and hydrogen. Additionally, miscibility slim tube experiments by injecting each of these gases (as solvents) are utilized and matched accordingly. Finally, multiple scenarios of gas injections were simulated in a cluster of wells in the field by evaluating gas injection time, injection and production rates, effect of pressure on the integrity of the reservoir, along with the possible impact on the production of hydrogen and additional recovery of hydrocarbons. Results of this study show the effect of the type of gas injected on the hydrocarbon storage and recovery capabilities in a real reservoir model, where the injected gases are immiscible with the selected extra-heavy crude oil. Different predictions of gas injection in both the crude oil and water zones, as well as the main mechanisms involved in the process are discussed in this article. Based on the complexity of current reservoir fluids (free gas, oil, water, emulsions, etc.), a program of fluid sampling and laboratory analyses are recommended, including pore scale analysis for the quantification of dissolution, trapping and wettability of the injected gases, among others. This article may serve as a basis for feasibility studies of gas storage in extra-heavy crude oil reservoirs in Venezuela and worldwide for the acquisition of experimental data and reservoir monitoring, which in turn would allow a successful implementation of this technology in a full-field scale.