Wax formation and deposition in crude oil pipelines pose a very significant challenge, such as flow restriction, increased cost of maintenance and potential shutdowns. The goals of this study are to reduce wax accumulation in the China National Petroleum Corporation-Niger Petroleum (CNPC-NP) pipeline network, which connects the Agadem oil fields to the SORAZ refinery, by optimizing critical operating conditions. The Reliability of Aspen HYSYS for analyzing wax behavior was validated by the simulation model that closely matched the real-world data, with a simulated flow rate of 182.49 m³/h with, only 0.27% higher than the actual 182 m³/h. The study suggested changing the operating condition using a genetic algorithm method of optimization, which indicates a slight increase in the pressure from 0.6 MPa to 0.65 MPa, while decreasing in temperature from 51°C to 48.5°C and a potential increase in the flow rate to 187.49 187.49 m³/h. Furthermore, the results of the optimization led to a decrease in wax thickness from 0.058 mm to 0.0409 mm, which indicated an improvement in pipeline operating conditions. Also, the economic analysis revealed, the total capital investment was roughly $3.3 million, and the annual operating expenses were estimated to be $2.4 million. The financial indicators include an Internal Rate of Return (IRR) of 9%, a Net Present Value (NPV) of $2.14 million and a Profitability Index (PI) of 1.99, all of which were higher than the IRR of the current CNPC-Niger Petroleum, which was 8%. The results show that the economic performance of the crude oil pipeline system can be improved, and wax formation risk can be effectively decreased by combining simulation-driven decision-making with strategic operational parameter adjustment.

Emissions of carbon dioxide (CO2) resulting from steam-driven enhanced oil recovery (EOR) operations present an environmental challenge as well as an opportunity to further enhance oil recovery. Using numerical simulations with realistic input data from field and laboratory measurements, we demonstrate a prudent approach to reduce CO2 emissions by capturing CO2 from steam generators of a steam-driven enhanced oil recovery (EOR) project and injecting it in a nearby oil field to improve oil recovery in this neighboring field. The proposed use of CO2 as a water-alternating-CO2 (WAG-CO2) EOR project in a small, 144-acre, sector of a target limestone reservoir would yield 42% incremental EOR oil while sequestering CO2 with a net utilization ratio (NUR) of 3100 standard cubic feet CO2 per stock tank barrel (SCF/STB) of EOR oil in a single five-spot pattern consisting of a central producer and four surrounding injectors. This EOR application sequesters 135,000, 165,000, and 213,000 metric tons of CO2 in five, ten, and twenty years in the single five spot pattern (i.e., our sector target), respectively. As a related matter, the CO2 emissions from nearby steam oil recovery project consisting of ten 58-ton steam/hr boilers amounts to 119,000 metric tons of CO2 per year with an estimated social cost of USD 440 million over 20 years. Upscaling the results from the single five-spot pattern to a four-pattern field scale increases the sequestered amount of CO2 by a factor of 4 without recycling and to 11 with recycling produced CO2 from the EOR project. Furthermore, the numerical model indicates that initiating CO2 injection earlier at higher residual oil saturations improves EOR efficiency while somewhat decreases sequestration per incremental EOR barrel. The most significant conclusion is that the proposed venture is an economically viable EOR idea in addition to being an effective sequestration project. Other sources of CO2 emissions in oil fields and nearby refineries or power generators may also be considered for similar projects.

Summary In the process of waterflood development in oil and gas reservoirs, the injection/production ratio is one of the key indicators affecting both the development effectiveness and economic benefits. A reasonable injection/production ratio directly impacts the development parameters, such as reservoir pressure maintenance levels and water-cut rise rates, and it helps maintain high production capacity in the oil field, ultimately achieving a higher recovery factor. However, existing constrained-waterflood reservoir production optimization methods often face challenges such as time-consuming calculations and the risk of getting trapped in local optima when dealing with such nonlinear constraint problems, making it difficult to effectively achieve a balance between constraints and economic benefits. To address this issue, we propose an injection/production ratio–constrained production optimization method based on the worst-case soft actor-critic (WCSAC) algorithm. This method effectively handles the constraint issue by introducing a safety critic, ensuring the injection/production ratio constraint is met, and maximizing economic benefits throughout the entire life cycle. Specifically, this method models the injection/production ratio–constrained production optimization problem as a constrained Markov decision process (CMDP). On the one hand, it uses conditional value at risk (CVaR) as a safety metric to assess the safety risks of the policy and achieves a balance between reward and safety by adjusting adaptive safety weights. On the other hand, it uses the maximum entropy mechanism to enhance policy exploration and improve the efficiency of global optimization. This results in the training of a stable and reliable safe reinforcement learning (RL) agent to achieve injection/production ratio–constrained production optimization. The agent can adjust and determine the production optimization plan that satisfies the injection/production ratio constraint in real time based on the current reservoir development status, without the need for retraining, thus reducing computational time. To validate the performance of the proposed method, tests were conducted in two reservoir models. The analysis results indicate that, compared with other optimization methods, the proposed method can achieve a higher net present value (NPV) while satisfying the injection/production ratio constraints, demonstrating good model applicability.

Total organic carbon-based proxy for QuEChERS estimation of microplastic mass in soils.

The rhizosphere as a hotspot for nitrite- and nitrate-dependent anaerobic oxidation of methane in paddy fields.

As a typical material for structural light weighting, aluminum alloys have broad application prospects in the petroleum and petrochemical industry. Among them, heat-resistant aluminum alloys feature high specific strength, high temperature resistance, corrosion resistance, fatigue resistance, and good processing performance, and have been promoted and applied in the field of aluminum alloy drill pipes. However, traditional aluminum alloys are limited to service temperatures below 200°C, which restricts their application in utra-deep oil and gas fields. The performance of heat-resistant aluminum alloys mainly depends on the stability of their microstructure. The present review summarizes the influence rules and strengthening mechanisms of typical alloying elements on the microstructure, mechanical properties, high-temperature resistance and corrosion resistance of Al-Cu-Mg heat-resistant aluminum alloys. The development directions of heat-resistant aluminum alloy drill pipe materials and their application prospects in oil and gas development are also prospected.

This article examines current geomechanics issues related to numerical modeling of stress-strain states in the near-wellbore zone during oil and gas field development. Methods for analyzing stress fields are proposed to identify potential failure zones in the main casing and perforation borehole components. An example of calculating reservoir permeability using effective conditional modeling of near-wellbore stresses is provided.

The Karachaganak field (Karachaganak oil and gas condensate field) is characterized by "acidic" production conditions: the presence of both CO₂ and H₂S with relatively low water availability, complex stratigraphy of the deposit and an extremely continental climate. The complex corrosion hazard is determined by a combination of mechanisms: carbon dioxide corrosion of steel, sulfide stress cracking and hydrogen embrittlement in environments with HS, hydrogen-induced corrosion/delamination, acidification of condensation water, as well as microbiological corrosion. The article provides an analytical review of corrosion factors for a typical well stock and pipeline strapping in Karachaganak; a research methodology with simulated reservoir/surface conditions is proposed; the results of a computational and experimental assessment of metal loss rates and the risk of brittle fracture forms for API steels and corrosion-resistant alloys according to ISO 15156 are discussed; a set of engineering solutions is formed: selection of materials, inhibitory protection, pH stabilization, moisture/salt management, pipe cleaning, monitoring (ER/LPR samples, coupons, inspection). It has been shown that at partial pressures of co₂≈H₂S and temperatures of 70-95 °C, FECO₃ protective films are destabilized by hydrogen sulfide phases (mackinawite, greigite), which increases the localization of corrosion and sensitivity to SSC; at the same time, low waterlogging and effective degassing/drying of gas reduce the risks in the main lines of dry gas. The findings confirm the need for differentiated corrosion management by systems (borehole—fountain fittings—plume—separation—water separation—reinjection), as well as the integration of the RBI approach into the maintenance program.

This article analyzes the issue of a significant proportion of hard-to-recover reserves remaining in place during the development of oil fields due to low reservoir permeability, insufficient water flooding, and heterogeneity of the collector. In such conditions, one of the most effective methods of enhancing oil recovery is considered to be the hydraulic fracturing (HF) technology. Hydraulic fracturing is a method of mechanical impact on the productive formation, which involves injecting fluid under high pressure to create fractures. After the formation of fractures, under the influence of fluid pressure, the fractures expand and connect with the system of natural fractures previously not penetrated by the well, thereby covering zones with very low permeability that were not previously drained. HF ensures the formation of artificial fractures in the productive formation by injecting fluid under high pressure and allows the inclusion of previously undrained zones. The paper scientifically describes the history of the development of HF technology, the characteristics of injected fluids and proppant types, and the relevance and effectiveness of multi-stage HF operations. It also analyzes the design of parameters for near-wellbore impact, the requirements for equipment operating pressure, and the calculation of hydraulic parameters. The obtained results confirm the high potential of the HF method in increasing oil production in low-permeability reservoirs and the need for its broader industrial application.

ABSTRACTSeismic inversion plays a critical role in populating subsurface properties into geomodel; however, its effectiveness is often constrained by the resolution limits of seismic data. This study evaluates the effectiveness of stochastic versus deterministic acoustic‐impedance inversion for estimating total porosity (Φtotal), effective porosity (Φe) and permeability (K) in the complex reefal carbonates of the Soğucak formation, Deveçatağı oil field—northwestern Thrace Basin, Türkiye—whose thickness ranges from 2 to 57 m. The wedge model indicates a tuning thickness of 60 m in Soğucak formation which limits the vertical resolution of the deterministic inversion that directly affects the geomodel resolution. To address this challenge, a stochastic inversion was performed to resolve beds below the tuning thickness, using a high‐resolution 1 millisecond (ms) vertical sampling grid and producing non‐unique, fine‐layered impedance realizations. Petrophysical relationships were established using 75 core plugs showing strong porosity–permeability trends that were cross‐validated with wireline logs. These relationships were applied to acoustic‐impedance volumes derived from both deterministic and stochastic inversion. Correlations at well locations used in the model are naturally higher due to constraints from acoustic‐impedance logs; therefore, we emphasized blind‐well correlations to assess predictive performance at locations without well control. Blind‐well tests at W‐2, W‐4, W‐6 and W‐11 demonstrate valid predictive capability, with stochastic inversion achieving correlations of 0.65–0.73 compared to 0.45–0.52 for deterministic inversion, effectively resolving sub‐tuning thickness beds and reliably predicting porosity and permeability. By overcoming the resolution limitations of deterministic inversion, stochastic inversion supported by robust petrophysical relationships—when applicable—provides a reliable and field‐proven tool that can be adapted to carbonate reservoirs in diverse geological settings worldwide.

Seismic cycle-controlled hydrocarbon vertical migration through carbonates in the Ragusa Oil Field (SE Sicily, Italy).

Oil field impacts on Venezuela’s rivers and water stress with environmental challenges

LN2 cryo-fracturing stimulation for future geothermal energy production from a depleted oil field: A case study of LN2 immersion in heated granite subsurface core specimens from Southwestern Kazakhstan

Reservoir modeling of heterogeneities, structures, and petrophysical properties of the Berenice Oil Field: Implications for sustainable management and CO2 storage in the North Western Desert, Egypt

Extended agitation facilitates pelleting coagulation for enhanced solid-liquid separation of highly concentrated waste drilling fluid from shale oil fields

Study on optimization of well washing parameters and efficiency improvement of oil field water injection wells based on intelligent optimization algorithm

Squalene (C30H50), a triterpene hydrocarbon, a critical precursor in the biosynthesis of cell membrane steroids, is enzymatically derived via squalene synthase in both prokaryotic and eukaryotic organisms. Its remarkable physicochemical properties and potent antioxidant characteristics underlie its extensive application across various sectors including nutraceuticals, pharmaceuticals, cosmetics, and fragrance industries. Historically, squalene has been predominantly sourced from shark liver oil and select plant oils. However, contemporary sustainable considerations have spurred pioneering investigations into unconventional reservoirs. This study reports, for the first time, the extraction of squalene from wastewater of Kazakhstan’s Uzen oil field, identifying an abiotic reservoir with significant scientific and industrial potential. In this study, wastewater samples from the Uzen oil field were collected, extracted, and the composition of dissolved volatile compounds in the extract was investigated using gas chromatography-mass spectrometry (GC-MS). Notably, the predominant constituents were hydrocarbons, which was expected. Intriguingly, the analysis also revealed substantial quantities of squalene–a natural biomarker of oil. This unexpected discovery underscores the significant promise of this unconventional source.

Petrophysical Analysis of Abu Roash Formation using well log data, Khalda oil field, North Western Desert, Egypt

Petroleum system analysis of the Ras Ghara oil Field: Geochemical evaluation and 2D basin modelling of pre-rift and syn-rift formations in the southern Gulf of Suez, Egypt

Cambodian rice field soils infested by Meloidogyne spp. unveil a potential source of natural pest biocontrol agents