Search Results (30)

This study utilizes high-resolution X-ray computed tomography (CT) to evaluate the reservoir characterization in heterogenous carbonate rocks. These rocks show a diagenetic alteration that influences the reservoir quality in the Cretaceous Qamchuqa–Bekhme formations in outcrop and subsurface sections (Gali-Bekhal, Bekhme, and Taq Taq oilfields, NE Iraq). The scanning of fifty-one directional line analyses was conducted on three facies: marine, early diagenetic (non-hydrothermal), and late diagenetic (hydrothermal dolomitization, or HTD). The facies were analyzed from thousands of micro-spot analyses (up to 5250) and computed tomographic numbers (CTNs) across vertical, horizontal, and inclined directions. The surface (outcrop) marine facies exhibited CTNs ranging from 2578 to 2982 Hounsfield Units (HUs) (Av. 2740 HU), with very low average porosity (1.20%) and permeability (0.14 mD) values, while subsurface marine facies showed lower CTNs (1446–2556 HU, Av. 2360 HU) and higher porosity (Av. 8.40%) and permeability (Av. 1.02 mD) compared to the surface samples. Subsurface marine facies revealed higher porosity, lower density, and considerably enhanced conditions for hydrocarbon storage. The CT measurements and petrophysical properties in early diagenesis highlight a considerable porous system in the surface compared to the one in subsurface settings, significantly controlling the quality of the reservoir storage. The late diagenetic scanning values coincide with a saddle dolomite formation formed under high temperature conditions and intensive rock–fluid interactions. These dolomites are related to a hot fluid and are associated with intensive fracturing, vuggy porosities, and zebra-like textures. These textures are more pronounced in the surface than the subsurface settings. A surface evaluation showed a wide CTN range, accompanied by an average porosity of up to 15.47% and permeability of 301.27 mD, while subsurface facies exhibited a significant depletion in the CTN (<500 HU), with an average porosity of about 14.05% and permeability of 91.56 mD. The petrophysical characteristics of the reservoir associated with late-HT dolomitization (subsurface setting) show two populations. The first one exhibited CTN values between 1931 and 2586 HU (Av. 2341 HU), with porosity ranging from 3.10 to 18.43% (Av. 8.84%) and permeability from 0.08 to 2.39 mD (Av. 0.31 mD). The second one recorded a considerable range of CTNs from 457 to 2446 HU (Av. 1823 HU), with porosity from 6.38 to 52.92% (Av. 20.97%) and permeability from 0.16 to 5462.62 mD (Av. 223.11 mD). High temperatures significantly altered the carbonate rock’s properties, with partial/complete occlusion of the porous vuggy and fractured networks, enhancing or reducing the reservoir quality and its storage. In summary, the variations in the CTN across both surface and subsurface facies provide new insight into reservoir heterogeneity and characterization, which is a fundamental factor for understanding the potential of hydrocarbon storage within various geological settings. Full article

Due to their low permeability, the location of natural fractures is key to the successful development of buried hill reservoirs. Due to the high degree of rock fragmentation and strong absorption of seismic waves at the top of buried hill formations, it is hard to identify the distribution of natural fractures inside a buried hill using conventional seismic methods. To overcome this difficulty, this study proposes a natural fracture identification technology for buried hill reservoirs that combines a continuum damage mechanics model with finite element numerical simulation. A 3D numerical solution workflow is established to determine the natural fracture distribution in target buried hill reservoirs. By constructing a geological model of a block, reconstructing the orogenic history, developing a 3D finite element model, and performing numerical simulations, the multi-stage orogenic processes experienced by buried hill reservoirs and the resultant natural fracture formation are replicated. This approach yields 3D numerical results of natural fracture distribution. Using the G-Block in the Zhongyuan Oilfield as a case study, the natural fracture distribution in a buried hill reservoir composed of mixed lithologies, including marble and Carboniferous formations, within the faulted G6-well group is analyzed. The results include plane views of the contour of damage variable SDEG, which represents the fracture distribution within the subsurface layer at 600 m intervals below the buried hill surface, as well as a vertical sectional view of the contour of SDEG’s distribution along specified well trajectories. By comparison with the results of the fracture distribution obtained with logging data, a consistency of 87.5% is achieved. This indicates the reliability of the numerical results for natural fractures obtained using the technology presented here. Full article

CO₂ geological storage (CGS) is critical for mitigating emissions in hard-to-abate industries under carbon neutrality. However, its implementation faces significant challenges. This paper examines CO₂-trapping mechanisms and proposes key safety measures: the continuous monitoring of in situ CO₂ migration and formation pressure dynamics to prevent remobilization, and pre-injection lithological analysis to assess mineral trapping potential. CO₂ injection alters reservoir stresses, inducing surface deformation; understanding long-term rock mechanics (creep, damage) is paramount. Thermomechanical effects from supercritical CO₂ injection pose risks to caprock integrity and fault reactivation, necessitating comprehensive, multi-scale, real-time monitoring for leakage detection. Geostatistical analysis of well log and seismic data enables realistic subsurface characterization, improving numerical model accuracy for risk assessment. This review synthesizes current CGS knowledge, analyzes technical challenges, and aims to inform future site selection, operations, and monitoring strategies. Full article

In the context of the current global transition toward low-carbon energy, the issue of $C{O}_2$ utilization has become increasingly important. One of the most promising natural targets for $C{O}_2$ sequestration is the terrigenous sedimentary formations found in oil, gas, and coal basins. It is generally assumed that $C{O}_2$ injected into such formations can be stored indefinitely in a stable form. However, the dissolution of $C{O}_2$ into subsurface water leads to a reduction in pH, which may cause partial dissolution of the host formation, altering the structure of the subsurface in the injection zone. This process is relatively slow, potentially unfolding over decades or even centuries, and its long-term consequences require careful investigation through mathematical modeling. The geological formation is treated as a partially soluble porous medium, where the dissolution rate is governed by surface chemical reactions occurring at the pore boundaries. In this study, we present an applied mathematical model that captures the coupled processes of mass transport, surface chemical reactions, and the resulting microscopic changes in the pore structure of the formation. To ensure the model remains grounded in realistic geological conditions, we based it on exploration data characterizing the composition and microstructure of the pore space typical of the Cenomanian suite in northern Western Siberia. The model incorporates the dominant geochemical reactions involving calcium carbonate (calcite, $CaC{O}_3$), characteristic of Cenomanian reservoir rocks. It describes the dissolution of $C{O}_2$ in the pore fluid and the associated evolution of ion concentrations, specifically $H^{+}$, $C{a}^{2+}$, and $HC{O}_3^{-}$. The input parameters are derived from experimental data. While the model focuses on calcite-based formations, the algorithm can be adapted to other mineralogies with appropriate modifications to the reaction terms. The simulation domain is defined as a cubic region with a side length of 1 $\mathsf{\mu }$m, representing a fragment of the geological formation with a porosity of 0.33. The pore space is initially filled with a mixture of liquid $C{O}_2$ and water at known saturation levels. The mathematical framework consists of a system of diffusion–reaction equations describing the dissolution of $C{O}_2$ in water and the subsequent mineral dissolution, coupled with a model for surface evolution of the solid phase. This model enables calculation of surface reaction rates within the porous medium and estimates the timescales over which significant changes in pore structure may occur, depending on the relative saturations of water and liquid $C{O}_2$. Full article

Geological storage is an integral element of the green energy transition. Geological formations, such as aquifers, depleted reservoirs, and hard rock caverns, are used mainly for the storage of hydrocarbons, carbon dioxide and increasingly hydrogen. However, potential adverse effects such as ground movements, leakage, seismic activity, and environmental pollution are observed. Existing research focuses on monitoring subsurface elements of the storage, while on the surface it is limited to ground movement observations. The review was carried out based on 191 research contributions related to geological storage. It emphasizes the importance of monitoring underground gas storage (UGS) sites and their surroundings to ensure sustainable and safe operation. It details surface monitoring methods, distinguishing geodetic surveys and remote sensing techniques. Remote sensing, including active methods such as InSAR and LiDAR, and passive methods of multispectral and hyperspectral imaging, provide valuable spatiotemporal information on UGS sites on a large scale. The review covers modelling and prediction methods used to analyze the environmental impacts of UGS, with data-driven models employing geostatistical tools and machine learning algorithms. The limited number of contributions treating geological storage sites holistically opens perspectives for the development of complex approaches capable of monitoring and modelling its environmental impacts. Full article

Underground hydrogen storage (UHS) in carbonate and siliceous formations presents a promising solution for managing intermittent renewable energy. However, experimental data on hydrogen–rock interactions under representative subsurface conditions remain limited. This study systematically investigates mineralogical and petrophysical alterations in dolomite, calcite-rich limestone, and quartz-dominant siliceous cores subjected to high-pressure hydrogen (100 bar, 70 °C, 100 days). Distinct from prior research focused on diffraction peak shifts, our analysis prioritizes quantitative changes in mineral concentration (%) as a direct metric of reactivity and structural integrity, offering more robust insights into long-term storage viability. Hydrogen exposure induced significant dolomite dissolution, evidenced by reduced crystalline content (from 12.20% to 10.53%) and accessory phase loss, indicative of partial decarbonation and ankerite-like formation via cation exchange. Conversely, limestone exhibited more pronounced carbonate reduction (vaterite from 6.05% to 4.82% and calcite from 2.35% to 0%), signaling high reactivity, mineral instability, and potential pore clogging from secondary precipitation. In contrast, quartz-rich cores demonstrated exceptional chemical inertness, maintaining consistent mineral concentrations. Furthermore, Brunauer–Emmett–Teller (BET) surface area and Barrett–Joyner–Halenda (BJH) pore distribution analyses revealed enhanced porosity and permeability in dolomite (pore volume increased >10×), while calcite showed declining properties and quartz showed negligible changes. SEM-EDS supported these trends, detailing Fe migration and textural evolution in dolomite, microfissuring in calcite, and structural preservation in quartz. This research establishes a unique experimental framework for understanding hydrogen–rock interactions under reservoir-relevant conditions. It provides crucial insights into mineralogical compatibility and structural resilience for UHS, identifying dolomite as a highly promising host and highlighting calcitic rocks’ limitations for long-term hydrogen containment. Full article

Understanding tortuosity is essential for accurately modeling fluid flow in complex porous media, particularly in the sub-surface reservoir rock; therefore, tortuosity estimation was evaluated using three approaches: Streamline streamline simulations via the Lattice Boltzmann Method (LBM), geometric pathfinding using Dijkstra’s algorithm, and empirical modeling based on pore-structure parameters. The analysis encompassed 1963 micro-Computed Tomography (micro-CT) images of Brazilian pre-salt carbonate and sandstone samples, with the effective porosity extracted from LBM velocity fields, isolating flow-contributing pores, establishing streamline tortuosity as the reference standard. Sandstones exhibited relatively narrow tortuosity ranges (Dijkstra: 1.29–1.75; Streamline: 1.18–2.61; Empirical: 1.18–4.42), whereas carbonates display greater heterogeneity (Dijkstra: 1.00–3.18; Streamline: 1.00–3.68; Empirical: 1.59–4.93). Model performance assessed using the corrected Akaike Information Criterion (AICc) revealed that the best agreement with the data was achieved by the semi-empirical model incorporating coordination number and minimum throat length (AICc = −113.11), followed by the Dijkstra-based geometrical approach (−99.74) and the empirical porosity-based model (202.23). There was a nonlinear inverse correlation between tortuosity and effective porosity across lithologies. This comprehensive comparison underscores the importance of incorporating multiple pore-scale parameters for robust tortuosity prediction, improving the understanding of flow behavior in heterogeneous reservoir rocks. Full article

The work aims to give a preliminary investigation of the geothermal potentiality of the hot dry granitic rocks in the Hail area, Northern KSA. The Hail area is characterized by a massive exposed belt of radioactive granitic rocks in the southern part, while the northern part is covered by a sedimentary section. A comprehensive methodology utilizing different categories of mineralogical petrographic, geochemical, geophysical well logging and, radiometry datasets, was used to assess the radiogenic heat production capacity of this granite. The measured data are integrated and interpreted to quantify the potential geothermal capacity of the granite and estimate its possible power production. The radioactivity and radiogenic heat production (RHP) of the Hail granites are among the highest recorded values in Saudi Arabia. Land measurements indicate uranium, thorium, potassium, and RHP values of 17.80 ppm, 90.0 ppm, 5.20%, and 11.93 µW/m³, respectively. The results indicated the presence of a reasonable subsurface geothermal reservoir condition with heat flow up to 99.87 mW/M² and a reservoir temperature of 200 °C (5 km depth). Scenarios for energy production through injecting water and high-pressure CO₂ in the naturally/induced fractured rock are demonstrated. Reserve estimate revealed that at a 2% heat recovery level, the Hail granites could generate about 3.15 × 10¹⁶ MWe, contributing to an average figure of 3.43 × 10¹² kWh/y, for annual energy per capita Saudi share. The results of this study emphasized the potential contribution of the Hail granite in the future of the energy mix of KSA, as a new renewable and sustainable resource. It is recommended to enhance the surface geophysical survey in conjunction with a detailed thermo-mechanical laboratory investigation to delineate the subsurface orientation and geometry of the granite and understand its behavior under different temperature and pressure conditions. Full article

The article presents a comprehensive analysis of long-term studies on hydrogen-hydrocarbon free gases (FGs) in the rocks of the Khibiny massif, systematically organized and generalized for the first time. Gasometric observations were predominantly conducted within underground mine workings, with occasional measurements taken during the drilling of exploration boreholes at the surface or in subsurface air within loose sediments. Methane is the primary component of these gases, followed in descending order by hydrogen, ethane, helium, other methane homologs, and alkenes. Nitrogen is also presumed to be present, although its proportions remain undefined. The carbon and hydrogen in FGs exhibit relatively heavy isotopic compositions, which progressively lighten from methane to ethane. The intensity of gas emissions is characterized by a gas flow rate from shot holes and boreholes, reaching up to 0.5 L/min but generally decreasing significantly within an hour of reservoir exposure. Gas-bearing areas, ranging in size from a few meters to tens of meters, are distributed irregularly and without discernible patterns. The FG content in rocks and ores varies from trace amounts to approximately 1 m³ of gas per cubic meter of undisturbed rock. These gases are primarily residual, preserved within microfractures and cavities following the isolation of fluid inclusions. Their distribution and composition may fluctuate due to the dynamic geomechanical conditions of the rock mass. The release of flammable and explosive FGs presents a significant hazard during ore deposit exploration and development, necessitating the implementation of rigorous safety measures for mining and drilling operations. Additionally, the environmental implications and potential applications of gas emissions warrant attention. Future comprehensive studies of the Khibiny gases using advanced methodologies and equipment are expected to address various scientific and practical challenges. Full article

Geothermal energy has emerged as a cornerstone in renewable energy, delivering reliable, low-emission baseload electricity and heating solutions. This review bridges the current knowledge gap by addressing challenges and opportunities for engineers and scientists, especially those transitioning from other professions. It examines deep and shallow geothermal systems and explores the advanced technologies and skills required across various climates and environments. Transferable expertise in drilling, completion, subsurface evaluation, and hydrological assessment is required for geothermal development but must be adapted to meet the demands of high-temperature, high-pressure environments; abrasive rocks; and complex downhole conditions. Emerging technologies like Enhanced Geothermal Systems (EGSs) and closed-loop systems enable sustainable energy extraction from impermeable and dry formations. Shallow systems utilize near-surface thermal gradients, hydrology, and soil conditions for efficient heat pump operations. Sustainable practices, including reinjection, machine learning-driven fracture modeling, and the use of corrosion-resistant alloys, enhance well integrity and long-term performance. Case studies like Utah FORGE and the Geysers in California, US, demonstrate hydraulic stimulation, machine learning, and reservoir management, while Cornell University has advanced integrated hybrid geothermal systems. Government incentives, such as tax credits under the Inflation Reduction Act, and academic initiatives, such as adopting geothermal energy at Cornell and Colorado Mesa Universities, are accelerating geothermal integration. These advancements, combined with transferable expertise, position geothermal energy as a major contributor to the global transition to renewable energy. Full article

The complex and variable structure of subsurface oil reservoirs as well as the small pore throat size of reservoirs make it extremely important to investigate the effect of oil–water–rock interactions for enhancing oil recovery. In this paper, the powder wettability of oil sand with different polar solvents was investigated using the improved Washburn capillary rise method, and the surface free energy of oil sand was calculated in combination with the OWRK method. In addition, the wettability of anionic surfactants HABS and PS solutions on the surface of oil sand was determined, and it showed that their wetting rates showed different trends after CMC (critical micelle concentration). The C×cosθ value of HABS decreased significantly with increasing concentration, whereas PS showed little changes. This may be related to the aggregate structure formed by HABS on the oil sand surface. Meanwhile, the interfacial free energy between crude oil and oil sand was obtained by crude oil-to-oil sand wetting experiments, and found that the wetting rate of crude oil to oil sand was much lower than that of solvents and surfactants. In combination with the above results and the oil–water interfacial tension (IFT), the oil–water–rock three-phase contact angle and the work of adhesion between the crude oil and the solid were obtained by Young’s equation. From the three-phase contact angle results, it can be found that the contact angle values of both HABS and PS are obviously higher than that of the simulated water, and both HABS and PS have the ability to significantly reduce the work of adhesion, which shows a strong ability to strip the oil film on the surface of the solid. The research results of this paper are helpful to understand the oil displacement mechanism of chemical flooding in reservoir pores, which is of great significance for improving oil recovery. Full article

Seismic reflection data and implicitly sonic velocity are undoubtedly the most important source of information for large-scale subsurface characterization. Yet, deriving reservoir and fluid flow properties from acoustic data is still challenging in carbonates, which display large acoustic velocity variations that contest many of the conventional assumptions regarding wave propagation in porous media. In this comprehensive study on 370 carbonate samples (247 limestones and 123 dolomites), we re-evaluate the impact of mineral velocity on bulk rock acoustic properties of dolomite and limestone by assessing the link between sonic velocity and the rock’s pore geometry. We quantify pore size and pore network complexity using parameters from both digital image analysis (DIA) and the extended Biot theory (EBT). We then compare DIA and EBT parameters to assess the impact of pore network geometry versus mineral velocity on the acoustic velocity of carbonate rocks. We explore the usefulness of EBT parameter γ_k in improving permeability estimates. Published values of velocity indicate that dolomites exhibit higher velocities than limestones at any given porosity. Our laboratory measurements of acoustic velocity, however, reveal that both dolomites and limestones show extreme variations in sonic velocities where samples with compressional velocity of ~5000 m/s may range in porosity from 5% to 25% and samples with porosity of ~20% may range in velocity from ~4000 m/s to 5700 m/s. Through the quantitative assessment of the pore network in our samples we document that pore network geometry has much more impact on the acoustic velocity of carbonates than variations in mineralogy, in this case dolomite and calcite. Most of the dolostone samples studied are dominated by small pores, resulting in relatively low velocities for their given porosity, while limestones with similar velocity–porosity values often possess simpler pore networks with larger pores. This pore size difference offsets the faster velocity of dolomite. The extended Biot theory parameter γ_k, captures this variation in pore size and internal geometry and exhibits a strong correlation to specific surface. Moreover, γ_k captures the impact of internal pore geometry on acoustic velocity, providing the basis for challenging existing assumptions regarding the importance of mineral velocity. By quantifying internal geometry, γ_k can improve permeability estimates in reservoir characterization and enhance evaluations of producibility and injectability. With that, it has direct implications on general geophysics, hydrocarbon exploration, and CCS initiatives. Full article

Geothermal power production may result in significant CO₂ emissions as part of the produced steam. CO₂ capture, utilisation, subsurface storage (CCUS) and developments to exploit geothermal resources are focal points for future clean and renewable energy strategies. The Synergetic Utilisation of CO₂ Storage Coupled with Geothermal Energy Deployment (SUCCEED) project aims to demonstrate the feasibility of using produced CO₂ for re-injection in the geothermal field to improve geothermal performance, while also storing the CO₂ as an action for climate change mitigation. Our study has the aim to develop innovative reservoir-monitoring technologies via active-source seismic data acquisition using a novel electric seismic vibrator source and permanently installed helically wound cable (HWC) fibre-optic distributed acoustic sensing (DAS) system. Implemented together with auxiliary multi-component (3C and 2C) geophone receiver arrays, this approach gave us the opportunity to compare and cross-validate the results using wavefields from different acquisition systems. We present the results of the baseline survey of a time-lapse monitoring project at the Hellisheiði geothermal field in Iceland. We perform tomographic inversion and multichannel seismic processing to investigate both the shallower and the deeper basaltic rocks targets. The wavefield analysis is supported by seismic modelling. The HWC DAS and the geophone-stacked sections show good consistency, highlighting the same reflection zones. The comparison of the new DAS technology with the well-known standard geophone acquisition proves the effectiveness and reliability of using broadside sensitivity HWC DAS in surface monitoring applications. Full article

Recently, a series of prolific fracture-vug reservoirs have been discovered in the lower Ordovician dolostone successions of the northern Tarim Basin. However, the genesis of these reservoirs remains unclear. In this study, observations on drilling cores and thin sections identify the pore space characterized by dissolved fractures, fissures, and vugs. Petrology, cathodoluminescence, and homogenization temperatures of fluid inclusions aid in establishing the diagenetic paragenetic sequence. Dissolving enlargement occurred after chemical compaction of overlying limestone and before the Permian volcanic activity. Breccia pores containing unique fillings of terrestrial materials (quartz sand and allogenic kaolinite) and calcite cements with negative δ¹⁸O_PDB values (−18.4‰) along with ⁸⁷Sr/⁸⁶Sr ratios (up to 0.71026) indicate that the dissolving fluid originated from meteoric freshwater at the surface. The δ¹⁸O_SMOW values of the calcite precipitating fluid (−2.1‰ to −8.7‰) further suggest freshwater as the source of the dissolving fluid, buffered by the Ordovician wall rocks or formation water. As the distance from the unconformity surface increases, both the homogenization temperature and δ¹⁸O_PDB values of the breccia pore-filling calcite in the southern study area gradually elevate and deplete, respectively, indicating a rise in temperature during the infiltration of meteoric freshwater with increasing subsurface temperatures. The abnormal reflection bodies identified as reservoirs in seismic profiles along deep-seated strike-slip faults delineate these faults as the channel for the infiltration of meteoric freshwater. The penetrating strata of these faults and the high ⁸⁷Sr/⁸⁶Sr values of breccia pore-filling calcite suggest that karstification occurred during the Devonian period. Accordingly, we establish a deep karst model in which the Devonian meteoric freshwater penetrated along the strike-slip faults and dissolved the Ordovician dolostones, resulting in the development of deep buried karstic fault reservoirs in the southern region of the northern Tarim Basin. Full article

Capturing and storing CO₂ (CCS) was once regarded as a significant, urgent, and necessary option for reducing the emissions of CO₂ from coal and oil and gas industries and mitigating the serious impacts of CO₂ on the atmosphere and the environment. This recognition came about as a result of extensive research conducted in the past. The CCS cycle comes to a close with the last phase of CO₂ storage, which is accomplished primarily by the adsorption of CO₂ in the ocean and injection of CO₂ subsurface reservoir formation, in addition to the formation of limestone via the process of CO₂ reactivity with reservoir formation minerals through injectivities. CCS is the last stage in the carbon capture and storage (CCS) cycle and is accomplished chiefly via oceanic and subterranean geological sequestration, as well as mineral carbonation. The injection of supercritical CO₂ into geological formations disrupts the sub-surface’s existing physical and chemical conditions; changes can occur in the pore fluid pressure, temperature state, chemical reactivity, and stress distribution of the reservoir rock. This paper aims at advancing our current knowledge in CO₂ injection and storage systems, particularly CO₂ storage methods and the challenges encountered during the implementation of each method and analyses on how key uncertainties in CCS can be reduced. CCS sites are essentially unified systems; yet, given the scientific context, these storage systems are typically split during scientific investigations based on the physics and spatial scales involved. Separating the physics by using the chosen system as a boundary condition is a strategy that works effectively for a wide variety of physical applications. Unfortunately, the separation technique does not accurately capture the behaviour of the larger important system in the case of water and gas flow in porous media. This is due to the complexity of geological subsurface systems, which prevents the approach from being able to effectively capture the behaviour of the larger relevant system. This consequently gives rise to different CCS technology with different applications, costs and social and environmental impacts. The findings of this study can help improve the ability to select a suitable CCS application method and can further improve the efficiency of greenhouse gas emissions and their environmental impact, promoting the process sustainability and helping to tackle some of the most important issues that human being is currently accounting global climate change. Though this technology has already had large-scale development for the last decade, some issues and uncertainties are identified. Special attention was focused on the basic findings achieved in CO₂ storage operational projects to date. The study has demonstrated that though a number of CCS technologies have been researched and implemented to date, choosing a suitable and acceptable CCS technology is still daunting in terms of its technological application, cost effectiveness and socio-environmental acceptance. Full article