Petroleum Research最新文献

In this work, the design and construction of a continuous and pilot-scale flotation facility are demonstrated. The performance of the new facility was evaluated from series of pilot flotation tests, carried out using oil sands slurry to extract bitumen—an extra-heavy form of petroleum. Results indicated that bitumen recoveries of the new pilot plant for an identical ore and water chemistry were largely dependent on air injection method, slurry conditioning time, flotation residence time, and slurry temperature. Importantly, when compared with those of bitumen extraction tests using a bench-scale Batch Extraction Unit (BEU) operated at the most optimal conditions, it was suggested that the new pilot plant produced flotation recoveries of bitumen and froth qualities at a level as good as, or even higher than, the level accomplished using the BEU at an identical ore, water chemistry and operating temperature. This continuous, pilot flotation plant could potentially serve as a pre-commercial production system that verifies a new processing aid, or as an alternative extraction technology for oil sand, coal, and mineral processing.

Laboratory measurements using nuclear magnetic resonance, scanning electron microscopy, and gas porosity and permeability analysis were conducted to acquire a petrophysical interpretation of the Carbon Tan Sandstone and Savonnieres Carbonate for potential carbon dioxide storage in subsurface formations. The relationships between pore structures, such as pore-size distribution, pore geometry, and porosity/permeability, were investigated near and far from the wellbore. At operating pressures of 2500psi (17.24 MPa) and temperatures of 176 °F (50 °C), carbonated water was injected into a composite core constructed of two similar core samples bounded by a compact disc located between them. The current results showed that a strong calcite dissolution took place near the injection position of both rock samples and led to improvements in the primary intergranular permeability and porosity, while the carbonate sample showed significant improvement compared to sandstone. The durable heterogeneous dissolution of calcite grains also led to the creation of new pores as intra-granular micro-pores. While at deeper depths from the injection position, it noticed an insignificant development in pore structure and its populations as well as rock hydraulic properties of both rock samples. In conclusion, the study revealed that the injected carbonated brine had a valuable impact on fluid-formation interactive, which improved rock's inlet properties compared with outlet.

Geomechanics as the knowledge of rock deformation and stability is an indispensable part of all field development plans. Conducting geomechanical analyses leads to a safer and more efficient operation otherwise different kinds of instability and distortion might occur. In this study, the geomechanical behavior of Ilam and Sarvak formations of an oil field in southwest of Iran was investigated. The research objectives can be summarized as wellbore stability evaluation and predicting the value of reservoir subsidence due to pressure drop as a result of reservoir fluid production. To fulfill these, a set of petrophysical logs run in the exploration well of this green field were collected. Next, using empirical correlations and statistical methods, required data for evaluating wellbore stability during drilling, specifying safe mud window to discover reservoir breakdown pressure, predicting the possibility of wellbore collapse in field lifetime, and assessing reservoir subsidence were determined. The results revealed that the average subsidence value as the consequence of production within 21 years is 0.275 ft Which is not significant. In terms of wellbore stability, it was concluded that all horizontal and vertical wells remain stable during this time period. Briefly to conclude, field development is not associated with alarming incidents from geomechanical aspect.

Three different technologies for the low-temperature separation (LTS) of gas condensate from the Achimov deposits in the Russian Urengoyskoe gas and condensate field were assessed using exergy analyses. The options examined included turbo-expansion and ejection. Thermomechanical exergy values were calculated for material streams and exergy losses and efficiencies were estimated for dedicated equipment used in the LTS. The lowest exergy loss of 4221.2 kW was obtained using turbo-expansion and electricity cogeneration. The carbon release associated with each scenario was calculated while considering different production rates, technological parameters and natural decreases in wellhead pressure. The integral carbon footprint after 40 years of LTS operation was estimated for all cases. A classical ejector-based LTS scheme was shown to produce 1200 t of CO₂ emissions over 40 years of operation. This same scheme combined with a turboexpander and electricity generator produced 59% less CO₂ in the same period. An expansion-cogeneration LTS scheme was found to be the most effective and ecologically friendly among the various options based on this analysis.

Excess water production is one of the crucial complications in the oil industry, leading to a rapid decline in oil production. To overcome this problem, different polymer gels are used to block the water's path to reduce water production. In the present work, polymer gel systems were prepared with polymers namely partially hydrolyzed polyacrylamide (PHPA), organic crosslinkers like hexamine, and hydroquinone with the incorporation of silica and alumina nanoparticles. Nanoparticles are used to enhance the stability of the gel framework in high salinity and high temperature reservoir environment. When designing the polymer gel system, factors such as pH, thermal stability, brine composition, injection rate, and chemical concentration were considered. Concentrations of PHPA and nanoparticles were varied from 1 to 2 wt% and 0.25–1.0 wt% respectively for the preparation of different gel systems. The concentration of the organic crosslinker was extended from 5000 to 11000 ppm for investigating the effect on gelation time. Brine concentration was chosen from 2 to 8 wt% to find the impact of high salinity. Succinic acid as an accelerator was also used to study the effect on gelation time, and it was found that the gelation time is reduced as the concentration of succinic acid increases. The prepared polymer solution was taken in a test tube and was kept inside a hot air oven at 95 °C to perceive the gelation time and nature of the produced gel. Results showed that nanoparticles do not influence the gelation time, but they considerably affect gel stability. However, concentrations of polymer, accelerator, and salt (salinity) have significant effects on the gelation behavior of the gel systems.

Continental shale oil is widely distributed in the Cretaceous Qingshankou Formation of the Songliao Basin in Northeast China. In the Qijia-Gulong sag and the Changling sag in the Songliao Basin, breakthroughs of shale oil exploration and development have been made in the first and second members of the Qingshankou Formation, and several wells represented by Well GYYP1 have achieved high and stable shale oil production. However, some horizontal wells in shale oil development pilot test (Well groups A and D) were characterized by low shale oil production, high flowback rate and rapid production decline. Therefore, controlling factors of the shale oil production were investigated. The results show that shale oil enrichment area and optimal sweet spots are fundamental for high shale oil production, improving horizontal length and drilling ratio of sweet spots is a technical guarantee for enhancing shale oil production of single well, and artificial fracture network (incl. scale, complexity, and coupling with pre-existing geological bodies) created by fracturing is a direct factor for controlling the shale oil production. For subsequent exploration and development of the shale oil, the heterogeneity of sweet spot distribution should be carefully considered, the shale oil enrichment areas and optimal sweet spots also need be optimized, and the wellbore trajectory control and fine geological modeling techniques should be figured out. Moreover, the fracturing techniques suitable for the shale with high clay mineral content and weak brittleness should be developed, and the personalized and differentiated staged fracturing also needs to be performed, to effectively enhance single-well shale oil production and estimated ultimate recovery.