Search Results (37)

With increasing global energy demand and depletion of onshore oil–gas resources, deep-sea hydrocarbon exploration and development have become strategically vital. As core subsea transportation equipment, the performance of helico-axial multiphase pumps directly determines the efficiency and economic feasibility of deep-sea extraction. However, non-uniform inflow patterns caused by uneven gas–liquid distribution in pipelines degrade pressure-boosting capability and reduce pump efficiency under actual operating conditions. To address this, an optimization method employing helical static mixers was developed. A mixer with a 180° helical angle was designed and installed upstream of the pump inlet. Numerical simulations demonstrate that the mixer enhances gas-phase distribution uniformity in stratified flow, improving efficiency and head across varying gas void fractions (GVFs). At a stratification height ratio (Ψ) of 0.32, efficiency increased by 15.41% and head rose by 15.64 m, while turbulent kinetic energy (TKE) at the impeller outlet decreased by up to 50%. For slug flow conditions, the mixer effectively suppressed gas volume fraction fluctuations, consistently improving efficiency under different slug flow coefficients (φ) with a maximum head increase of 9.82%. The optimized flow field exhibits uniform gas–liquid velocity distribution, stable pressure boosting, and significantly reduced TKE intensity within impeller passages. Full article

Integrating renewable energy requires robust, large-scale storage solutions to balance intermittent supply. Underground hydrogen storage (UHS) in geological formations, such as salt caverns, depleted hydrocarbon reservoirs, or aquifers, offers a promising way to store large volumes of energy for seasonal periods. This review focuses on the biological aspects of UHS, examining the biogeochemical interactions between H₂, reservoir minerals, and key hydrogenotrophic microorganisms such as sulfate-reducing bacteria, methanogens, acetogens, and iron-reducing bacteria within the gas–liquid–rock–microorganism system. These microbial groups use H₂ as an electron donor, triggering biogeochemical reactions that can affect storage efficiency through gas loss and mineral dissolution–precipitation cycles. This review discusses their metabolic pathways and the geochemical interactions driven by microbial byproducts such as H₂S, CH₄, acetate, and Fe²⁺ and considers biofilm formation by microbial consortia, which can further change the petrophysical reservoir properties. In addition, the review maps 76 ongoing European projects focused on UHS, showing 71% target salt caverns, 22% depleted hydrocarbon reservoirs, and 7% aquifers, with emphasis on potential biogeochemical interactions. It also identifies key knowledge gaps, including the lack of in situ kinetic data, limited field-scale monitoring of microbial activity, and insufficient understanding of mineral–microbe interactions that may affect gas purity. Finally, the review highlights the need to study microbial adaptation over time and the influence of mineralogy on tolerance thresholds. By analyzing these processes across different geological settings and integrating findings from European research initiatives, this work evaluates the impact of microbial and geochemical factors on the safety, efficiency, and long-term performance of UHS. Full article

Groundwater at petroleum-contaminated sites typically exhibits elevated dissolved inorganic carbon (DIC) levels due to hydrocarbon biodegradation; however, our prior field investigations revealed an enigmatic DIC depletion anomaly that starkly contradicts this global pattern and points to an unrecognized carbon sink. In a breakthrough demonstration, this study provides the first experimental confirmation that sulfur-oxidizing bacteria (SOB) drive substantial carbon sequestration via a coupled sulfur oxidation autotrophic assimilation process. Through integrated hydrochemical monitoring and 16S rRNA sequencing in an enrichment culture system, we captured the complete DIC transformation trajectory: heterotrophic acetate degradation initially increased DIC to 370 mg/L, but subsequent autotrophic assimilation by SOB dramatically reduced DIC to 270 mg/L, yielding a net consumption of 85 mg/L. The distinctive pH dynamics (initial alkalization followed by acidification) further corroborated microbial regulation of carbon cycling. Critically, Pseudomonas stutzeri and P. alcaliphila were identified as the dominant carbon-fixing agents. These findings definitively establish that chemolithoautotrophic SOB convert DIC into organic carbon through a “sulfur oxidation-carbon fixation” coupling mechanism, overturning the conventional paradigm of petroleum-contaminated sites as perpetual carbon sources. The study fundamentally redefines natural attenuation frameworks by introducing microbial carbon sink potential as an essential assessment metric for environmental sustainability. Full article

This paper presents three design case studies for implementing large-scale geologic carbon storage in the Appalachian Basin region of the midwestern United States. While the Appalachian Basin has a challenging setting for carbon storage, the three case studies detailed in this article demonstrate that there are realistic options for implementing carbon storage in the basin. Carbonate rock formations, depleted hydrocarbon reservoirs, and moderate-porosity sandstones can be utilized as carbon-storage reservoirs in the Appalachian Basin. While these are not typical concepts for CO₂ storage, the storage zones have advantages such as defined trapping mechanisms, multiple caprocks, and defined boundaries that are not always present in thick, permeable sandstones being targeted for many carbon-storage projects. The geologic setting, geotechnical parameters, and hydrologic setting for the three case studies are provided, along with the results of reservoir simulations of the CO₂ injection-deployment strategies. The geological rock formations available for CO₂ storage in the Appalachian Basin are more localized reservoirs with defined boundaries and finite storage capacities. Simulation results showed that accessing carbon-storage resources in these fields may require wellfields with 2–10 injection wells. However, these fields would have the capacity to inject 1–3 million metric tons of CO₂ per year and up to 90 million metric tons of CO₂ in total. The CO₂ storage resources would fulfill decarbonization goals for many of the natural-gas power plants, cement plants, hydrogen plants, and refineries in the Appalachian Basin region. Full article

This study examines the distribution of pore pressure (PP) and fracture gradient (FG) within intervals of lost circulation encountered during drilling operations in the Ordovician reservoir (IV-3 unit) of the Tin Fouye Tabankort (TFT) field, located in the Illizi Basin, Algeria. The research further aims to determine an optimized drilling mud weight to mitigate mud losses and enhance overall operational efficiency. PP and FG models for the Ordovician reservoir were developed based on data collected from five vertical development wells. The analysis incorporated multiple datasets, including well logs, mud logging reports, downhole measurements, and Leak-Off Tests (LOTs). The findings revealed an average overburden gradient of 1.03 psi/ft for the TFT field. The generated pore pressure and fracture gradient (PPFG) models indicated a sub-normal pressure regime in the Ordovician sandstone IV-3 reservoir, with PP values ranging from 5.61 to 6.24 ppg and FG values between 7.40 and 9.14 ppg. The analysis identified reservoir depletion due to prolonged hydrocarbon production as the primary factor contributing to the reduction in fracture gradient, which significantly narrowed the mud weight window and increased the likelihood of lost circulation. Further examination of pump on/off cycles over time, coupled with shallow and deep resistivity variations with depth, confirmed that the observed mud losses were predominantly associated with induced fractures resulting from the application of excessive mud weight during drilling operations. Based on the established PP and FG profiles, a narrow mud weight window of 6.24–7.40 ppg was recommended to ensure the safe and efficient drilling of future wells in the TFT field and support the sustainability of drilling operations in the context of a depleted reservoir. Full article

CO₂-enhanced gas recovery (EGR) has emerged as a promising method for improving hydrocarbon production and achieving carbon sequestration in offshore gas reservoirs. This study investigates the performance and influencing factors of CO₂-based gas displacement using long core displacement experiments. Consolidated synthetic cores were prepared to replicate reservoir conditions, and experiments were conducted at formation pressure and temperature to evaluate the effects of permeability, injection pressure, CO₂ concentration, and core length on gas recovery efficiency. The results reveal that (1) for a homogeneous porous medium, permeability and injection pressure have minimal correlation with recovery efficiency when sufficient gas is injected; (2) direct gas displacement after reservoir depletion outperforms pressure-boosting displacement methods; (3) higher CO₂ concentrations delay gas breakthrough, enhance piston-like displacement behavior, and improve recovery efficiency; and (4) core length significantly affects recovery, with longer cores resulting in slower breakthroughs and more stable displacement. Cores of at least 1 m in length are essential for accurately simulating field conditions. For a CO₂ injection with a pressure of 7 MPa and a temperature of 81 °C, when 0.87 PV of CO₂ is injected, the current recovery can reach 87%, after which the displacement efficiency decreases sharply. The ultimate EGR can be as high as 50%. These findings provide valuable insights into optimizing CO₂ injection strategies for enhanced gas recovery in offshore reservoirs, offering guidance for both experimental designs and practical applications in the field. Full article

This study highlights the importance of quantifying groundwater resources for the Monahans and Kermit dune fields in the northern Chihuahua Desert, West Texas, USA, as potential contributors to the regional Pecos Valley Aquifer (PVA). Dunal aquifers in arid environments are often unquantified, may augment regional groundwater resources, and can be compromised by anthropogenic activity. Sedimentary architecture models of these dune fields show perched aquifers with water tables 1–10 m below the surface and southwestern groundwater flow sub-parallel to a Pleistocene/Pliocene aquitard. The deuterium and oxygen isotopic ratios for groundwater from the Kermit and Monahans dune fields show pronounced evaporative isotopic depletion and less isotopic variability than corresponding rainfall, particularly for deuterium values. The radiocarbon and δ¹³C analyses of dissolved inorganic carbon (DIC) indicate that recharge occurs through enhanced capture of recent precipitation on mostly bare active dunes where infiltration rates are >250 mm/h. In contrast, more evolved ¹⁴C values at the western margin (FM = 0.84) and at 30 m below the surface (FM = 0.76) of the dunes, similar to proximal Fm values from the PVA (0.89–0.82), may indicate dissolution of older (>100 ka) DIC from buried playa-lake sediments and less direct atmospheric influence. Mixing models for DIC source partitioning highlighted possible groundwater contamination with hydrocarbon up to 24% in the PVA and in the dunal aquifers. The perched aquifers of the Monahans and Kermit dune fields each contain water volumes >0.1 km³ and may contribute up to 18% of the total annual recharge to the PVA. Full article

This study introduces a robust methodology utilizing Multi-Criteria Decision Analysis (MCDA) combined with an Analytic Hierarchy Process (AHP) to repurpose abandoned hydrocarbon fields for energy storage, supporting the transition to renewable energy sources. We use a geostatistical approach integrated with Python scripting to analyze reservoir parameters—including porosity, permeability, thickness, lithology, temperature, heat capacity, and thermal conductivity—from a decommissioned hydrocarbon field in Southeast Hungary. Our workflow leverages stochastic simulation data to identify potential zones for energy storage, categorizing them into high-, moderate-, and low-suitability scenarios. This innovative approach provides rapid and precise analysis, enabling effective decision-making for energy storage implementation in depleted fields. The key finding is the development of a methodology that can quickly and accurately assess the feasibility of repurposing abandoned hydrocarbon reservoirs for underground thermal energy storage, offering a practical solution for sustainable energy transition. Full article

The field of refrigeration technology has played a pivotal role in modern society, providing essential cooling solutions for various industries, including food preservation, healthcare, and manufacturing. However, the conventional refrigerants used in these systems, such as hydrofluorocarbons (HFCs) and chlorofluorocarbons (CFCs), have been identified as major contributors to climate change and ozone depletion. Recently, the heightened environmental consciousness of the refrigeration industry paved the way for searching for natural refrigerants (NRs) as an alternative to the usual commercial and synthetic refrigerant (SR). Natural refrigerants are known to be substances that occur naturally in the Earth’s surroundings and were commonly used, while synthetic refrigerants took their place because of their known better thermal performance durability and safety. Despite challenges such as flammability and toxicity, these NR substitutes demonstrate competitive performance, urging a transition from traditional SR. In this review paper, commonly known NRs such as ammonia, carbon dioxide, air, and hydrocarbons, are presented in terms of their sustainable characteristics, historical origins, selection criteria, preparation techniques, evaluations, and impacts. To provide a sustainable and eco-friendly guideline for the advancement of refrigeration technology, this analysis examines the trends, selection criteria, preparation processes, and evaluation procedures of different NRs. Finally, the results presented in this paper will be useful baseline information for both researchers and scientists in developing a refrigeration system. Full article

Nowadays, there is a need to search for new renewable energy sources from which it is possible to obtain hydrocarbons that are similar in composition and properties to hydrocarbons of petroleum origin. This is due to a significant increase in demand for natural minerals and, as a consequence, the depletion of their reserves. Today, the most promising alternative renewable energy sources are various vegetable oils, which are used both in their pure form, adding them to commercial mineral fuels, and as products of catalytic processing using various catalysts. However, most studies in the field of alternative energy show that the use of fuels obtained from vegetable oils is limited by their properties as well as the climatic conditions of the areas where biofuels can be used. In this work, we propose an integrated approach to the processing of vegetable oils, which allows us to obtain products of a wide fractional composition with improved operational properties. This approach consists of sequential processing of vegetable oils, first using a CoMo/Al₂O₃ hydrotreating catalyst in order to obtain classical long-chain hydrocarbons with unsatisfactory properties, and then using a zeolite catalyst, ZSM-5 type, which is characterized by the active occurrence of cracking, isomerization, and aromatization reactions, which are accompanied by a decrease in the length of the hydrocarbon chain of the hydrocarbons obtained during the hydrotreating process and, as a result, improving the physicochemical and low-temperature properties of the resulting processed products. Full article

Saline aquifers have been used for CO₂ storage as a dedicated greenhouse gas mitigation strategy since 1996. Depleted gas fields are now being planned for large-scale CCS projects. Although basalt host reservoirs are also going to be used, saline aquifers and depleted gas fields will make up most of the global geological repositories for CO₂. At present, depleted gas fields and saline aquifers seem to be treated as if they are a single entity, but they have distinct differences that are examined here. Depleted gas fields have far more pre-existing information about the reservoir, top-seal caprock, internal architecture of the site, and about fluid flow properties than saline aquifers due to the long history of hydrocarbon project development and fluid production. The fluid pressure evolution paths for saline aquifers and depleted gas fields are distinctly different because, unlike saline aquifers, depleted gas fields are likely to be below hydrostatic pressure before CO₂ injection commences. Depressurised depleted gas fields may require an initial injection of gas-phase CO₂ instead of dense-phase CO₂ typical of saline aquifers, but the greater pressure difference may allow higher initial injection rates in depleted gas fields than saline aquifers. Depressurised depleted gas fields may lead to CO₂-injection-related stress paths that are distinct from saline aquifers depending on the geomechanical properties of the reservoir. CO₂ trapping in saline aquifers will be dominated by buoyancy processes with residual CO₂ and dissolved CO₂ developing over time whereas depleted gas fields will be dominated by a sinking body of CO₂ that forms a cushion below the remaining methane. Saline aquifers tend to have a relatively limited ability to fill pores with CO₂ (i.e., low storage efficiency factors between 2 and 20%) as the injected CO₂ is controlled by buoyancy and viscosity differences with the saline brine. In contrast, depleted gas fields may have storage efficiency factors up to 80% as the reservoir will contain sub-hydrostatic pressure methane that is easy to displace. Saline aquifers have a greater risk of halite-scale and minor dissolution of reservoir minerals than depleted gas fields as the former contain vastly more of the aqueous medium needed for such processes compared to the latter. Depleted gas fields have some different leakage risks than saline aquifers mostly related to the different fluid pressure histories, depressurisation-related alteration of geomechanical properties, and the greater number of wells typical of depleted gas fields than saline aquifers. Depleted gas fields and saline aquifers also have some different monitoring opportunities. The high-density, electrically conductive brine replaced by CO₂ in saline aquifers permits seismic and resistivity imaging, but these forms of imaging are less feasible in depleted gas fields. Monitoring boreholes are less likely to be used in saline aquifers than depleted gas fields as the latter typically have numerous pre-existing exploration and production well penetrations. The significance of this analysis is that saline aquifers and depleted gas fields must be treated differently although the ultimate objective is the same: to permanently store CO₂ to mitigate greenhouse gas emissions and minimise global heating. Full article

The planned pilot CO₂ storage Zar-3 is an oil field with a gas cap in the final production stage in the SE Czech Republic. It is composed of a dolomite Jurassic reservoir sealed by three different formations that differ significantly in lithology. Previous studies left open questions on the nature of pore space and connectivity and the quality of the seal in the future CO₂ storage complex. Microscopic petrography of the reservoir suggests dolomitisation in shallow water followed by karstification and brecciation with fracture-correct-dominated porosity. The seal horizons have porosity limited to the micro- and nanoscales. The oil consists of significantly biodegraded black oil of Jurassic origin mixed with less biodegraded gasoline-range hydrocarbons. Biomarkers in the caprock bitumens trapped in nanopores show a genetic relationship to the reservoir oil. Gas in the not yet fully depleted gas cap of the field is of thermogenic origin with no contribution of microbial methane. The formation water has total dissolved solids typical of isolated brines not diluted by infiltrated fresh water. The geochemical characteristics of the storage system together with the fact that the initial oil column is about 105 m tall with another 150 m of gas cap suggest that the seals are efficient and the Zar-3 future storage complex is tight and safe. Full article

The exploration and development of new hydrocarbon deposits is facing increasing challenges as the global shift to renewable energy sources, such as shallow geothermal deposits, wind farms, and photovoltaics, reduces the dependence on hydrocarbons. To navigate this evolving landscape, it becomes crucial to find solutions that optimize the energy extraction efficiency while maximizing the use of hydrocarbon deposits. This requires exploring opportunities in existing fields and wells, including those slated for decommissioning. This article discusses the potential for extracting resources from seemingly depleted fields, where some 60–70% of the resources remain unrecoverable due to low reservoir energy. Meeting this challenge requires the implementation of secondary and tertiary EOR methods that involve the introduction of external energy to increase reservoir pressure and enhance resource recovery. One of the proposed innovative tertiary methods involves reaming the reservoir using multiple small-diameter radial boreholes generated by a hydraulic drilling nozzle. This strategy is designed to intensify the contact between the production hole and the reservoir layer, resulting in increased or commenced production in certain cases. The described method proves to be a practical application in hydrocarbon deposits, offering the dual benefits of mitigating environmental pollution by eliminating the need for drilling new boreholes and providing a cost-effective means of accessing resources in decommissioned deposits with insufficient reservoir energy for self-exploitation. Another article points out the design variation of a hydraulic drilling nozzle tailored specifically for reaming a reservoir layer. Taking the above into account, this article provides very practical information for future projects in which paths should be sought for the design and development of hydraulic wellheads, among other things, in order to intensify the production from hydrocarbon deposits. Full article

Conventional recovery enhancement techniques are aimed at reducing the abandonment pressure, but there is an upper limit for recovery enhancement due to the energy limitation of reservoirs. Gas injection for energy supplementation has become an effective way to enhance gas recovery by reducing hydrocarbon saturation in gas reservoirs. This review systematically investigates progress in gas injection for enhanced gas recovery in three aspects: experiments, numerical simulations and field examples. It summarizes and analyzes the current research results on gas injection for EGR and explores further prospects for future research. The research results show the following: (1) Based on the differences in the physical properties of CO₂, N₂ and natural gas, effective cushion gas can be formed in bottom reservoirs after gas injection to achieve the effects of pressurization, energy replenishment and gravity differentiation water resistance. However, further experimental evaluation is needed for the degree of increase in penetration ability. (2) It is more beneficial to inject N₂ before CO₂ or the mixture of N₂ and CO₂ in terms of EGR effect and cost. (3) According to numerical simulation studies, water drive and condensate gas reservoirs exhibit significant recovery effects, while CO₂-EGR in depleted gas reservoirs is more advantageous for burial and storage; current numerical simulations only focus on mobility mass and saturation changes and lack a mixed-phase percolation model, which leads to insufficient analysis of injection strategies and a lack of distinction among different gas extraction effects. Therefore, a mixed-phase-driven percolation model that can characterize the fluid flow path is worth studying in depth. (4) The De Wijk and Budafa Szinfelleti projects have shown that gas injection into water drive and depleted reservoirs has a large advantage for EGR, as it can enhance recovery by more than 10%. More experiments, simulation studies and demonstration projects are needed to promote the development of gas injection technology for enhanced recovery in the future. Full article

The storage potential of hydrocarbon reservoirs in the central Gulf of Mexico (GOM) makes future development of CO₂ storage projects in those areas promising for secure, large-scale, and long-term storage purposes. Focusing on the producing and depleted hydrocarbon fields in the continental slope of the central GOM, this paper analyzed, assessed, and screened the producing sands and evaluated their CO₂ storage potential. A live interactive CO₂ storage site screening system was built in the SAS^® Viya system with a broad range of screening criteria combined from published studies. This offers the users a real-time assessment of the storage sites and enables them to adjust the filters and visualize the results to determine the most suitable filter range. The CO₂ storage resources of the sands were estimated using a volumetric equation and the correlation developed by the National Energy Technology Laboratory (NETL). The results of this study indicate that 1.05 gigatons of CO₂ storage resources are available in the developed reservoirs at the upper slope area of the central GOM. The Mississippi Canyon and Green Canyon protraction areas contain the fields with the largest storage resources. Full article