Petroleum最新文献

Wellbore instability is an issue that, if left untreated, can cause wells to collapse, resulting in human, environmental, equipment, and revenue losses. Drilling fluids have been used to enhance the drilling process by lubricating and cooling the drill bit, eliminating cuttings, and most importantly, by improving the stability of the well by preventing fluid loss. However, there has been an increase in operational demands and challenges that call for drilling fluids to be more effective, economical, sustainable, and environmentally friendly. With shales that have infinitesimally small pores, nanoparticle additives in drilling fluids can be crucial in providing the properties that are necessary to prevent fluid loss and provide wellbore stability while meeting the operational demands of the present day. Therefore, this paper examines the use of nanoparticle additives including copper (II) oxide (CuO), magnesium oxide (MgO), and aluminum oxide (Al₂O₃) where they are tested under three conditions using the permeable plugging tester (PPT), high-temperature high-pressure (HTHP) fluid loss apparatus, and API low-temperature – low-pressure (LTLP) fluid loss apparatus under concentrations of 0.03% and 0.10%. Finally, based on the results, each nanoparticle sample (particle sizes between one and 100 nm) performed well in contributing to the aim of this project. CuO is the most effective inhibitor across all concentrations and under the three different conditions. It contributed to reducing the fluid loss from 37.6 mL to 18.2 and 13.2 mL, which is between 52% and 65% of fluid reduction. For MgO, it contributed to fluid loss reduction to 23.8 mL and 15 mL, which translated to 37%–60% of fluid loss reduction. The use of Al₂O₃ nanoparticles resulted in a fluid loss reduction to 33.6 mL and 17.8 mL, reducing the fluid loss up to 11%, at HTHP and up to 53% at LTLP. Unlike CuO and MgO, Al₂O₃ was less effective under HTHP conditions when compared to LTLP conditions. Al₂O₃ did not suffer as a significant diminishing benefit with increasing concentration in LTLP conditions however which means that at a higher concentration, it may begin to be more effective. Each material used in this study has its own specific and technical characteristics that will help create a progressive amount of property, such as providing stability and withstanding the high-temperature and high-pressure condition downhole.

The carbon dioxide (CO₂) conversion to useable compounds remains a great contest to scientists, engineers, and environmentalists with regard to the reverse of the oxidative degradation of organics. This conversion is essential for the development of complementary fuels and raw materials for various industries, which in turn will help in avoiding the drastic increase in tropospheric temperature due to greenhouse effect leading to global warming. The solar energy is the earth's essential power source along with the other various forms of energy for example fossil fuels, hydropower, wind, and biomaterials, etc. The final goal is to establish the artificial photosynthesis, which can be replicated thru various chemical reduction techniques of CO₂ by employing appropriate photo-, thermal- and electro-catalysts in order to produce different one carbon atom (C₁) and higher carbon atoms containing products. Besides, the utilization of clean and sustainable CO₂ towards high-value products is of great interest today due to the recognized environmental worries and subsequent lessening of the fossil fuels utilization load to meet the energy demand of mankind. This way, solar energy can directly and/or indirectly be altered and stored in chemical energy form for industrial as well as societal applications. In this article our endeavor is to summarize the advances in CO₂ chemical reduction research area till date especially in free radical-based methods such as electrochemical, photochemical and plasma chemical for the development of carbon species up to two carbon (C₂) atoms containing products perceived in the chemical reduction of CO₂. The author hopes that this piece of work will be helpful to researchers and readers who are focused on the field of CO₂.

Surfactant injection is a well-established method of chemical EOR processes. Surfactant adsorption into clay layers can prevent their proper performance and thus reduce the oil recovery factor. On the other hand, this adsorption property of clay materials can be used to prevent surface and underground water pollution and reduce soil pollution. In this experimental study, the effect of surfactant concentration, electrolyte type (NaCl and MgCl₂), and the solution salinity on fluid adsorption into the interlayer space of different clay types (bentonite and kaolinite) was investigated. XRF analysis was conducted on two relevant clay samples, and immersion and Washburn tests were performed on the desired samples with the Sigma 700 setup. Then, according to the clay type, the most optimal conditions were introduced for the surfactant solution used in the two areas of EOR and environmental processes related to reducing soil pollution. In the EOR processes, the optimal condition for the lowest adsorption amount is C (with 1 CMC concentration and salinity of 100,000 ppm for NaCl salt). This fluid works better in kaolinite formations. In the environmental field related to the reduction of soil pollution, if the pollutants we are looking for are R and S (with alkyl benzene sulfonic acid as the dominant agent), bentonite has a better performance than kaolinite in terms of adsorption and subsequently pollution control. If the polluting fluid contains MgCl₂ ions in the exact salinity values, the adsorption amount and soil pollution control will be higher for both adsorbent clays than if our fluid has NaCl salinity. The study's findings have a wide range of applications in surfactant flooding designs, surfactant adsorption optimization, and can be generalized to other detergent types.

The dolostones and dolomitic limestones of the lower Cretaceous Judea formation are a key target of hydrocarbons in most of the Euphrates Graben fields. Core materials investigation, thin sections petrographically examinations, and petrophysical evaluations were obtained to determine enhancement of the porosity through dolomitization. Results showed that the lagoon-shallow marine carbonates of the Judea formation are subdivided into two main zones; the upper “limestone zone” is micritic limestones dominated with no reservoir potential, and the lower “dolomite zone” is dolomitic limestones and dolostones dominated with good to very good reservoir potential. Dolomitization of the mudstones and wackestones of the micritic limestones resulted in formation of microcrystalline dolomicrite and early fabric destructive dolomites. Conversely, dolomitization of the packstones and grainstones resulted in formation of the fabric destructive and saddle dolomites. Based on petrography data, dolomitization of the “limestone zone” is interpreted by the seawater dolomitization mechanism at low-temperatures, while dolomitization of the “dolomite zone” is interpreted by the burial dolomitization mechanism under high temperature and pressure conditions. The “limestone zone” is characterized by the poorest reservoir quality, while the “dolomite zone” is characterized by the best reservoir quality. The seawater dolomitization did not significantly enhance the porosity, while the burial dolomitization contributes to enhancing the preserved secondary porosity. Stylolites microfractures and dissolution seams associated with dolomitization played as major factors in porosity enhancement of the dolostones and dolomitic limestones and serving as pathways for hydrocarbon migration. Dissolution processes increased the porosity and more permeability unless they are filled with the precipitated dolomite and/or calcite. Calcification had significant effects on the porosity by blocking the cavities and channels and decreased the effective pore volume.

Oil transfer pump is the key dynamic equipment in the process of oil and gas gathering and transportation, and its working reliability directly affects the safety of oil and gas storage and transportation. Intelligent diagnosis is a key technical method to reduce failure rate of oil transfer pump, ensure the safety of gathering and transportation process, and avoid major safety accidents caused by oil transfer pump failure. Various oil transfer pumps have been emerged in recent decades, and the common fault types and characteristics of oil transfer pump have been brought out in the review. This article highlights on the research of the fault signal and processing methods of oil transfer pump. Firstly, the fault signal of the oil transfer pump is discussed and the advantages and disadvantages of different signal extraction are analyzed. Secondly, the intelligent diagnosis method of oil transfer pump and the shortcomings of the existing methods are pointed out. Finally, the conclusions are given and the future development perspectives of oil transfer pumps are suggested. The main contribution of this review is to give a syn-thetic understanding on oil transfer pumps.

The polymer solution flow in porous media is a central research topic related to hydraulic fracturing measures, formation damage and fracture propagation. Influenced by molecular weights and concentrations, various flow patterns of polymer in pores are presented, resulting in different filtration loss. In this work, the effectiveness of various polymer solutions for filtration loss was assessed by utilizing the core flooding experiment firstly. The result shows that lesser filtration loss normally is inextricably linked to solutions with high molecular weight and concentration. Subsequently, the flow behaviors of polymer solutions investigated by designed micro pore-throat structure and micro-particle image velocimetry (μ-PIV) further confirmed the above result. It was found that the central convergent flow pattern benefiting from higher viscous force loss and less filtration loss was observed at high flow rates (0.5 mL/h), and higher molecular weight and concentration were more prone to convergent flow patterns. The viscosity force loss increases by about 4 times varying the molecular weight of polymer from 5 × 10⁶ to 18 × 10⁶ g/mol or the concentration from 0.05 to 0.3%. It interprets higher molecular weight and concentration in core studies and field observations with decreased filtration loss of HPAM. This work provides a theoretical foundation for the application of fracturing fluids as well as fresh perspectives on how to access the filtration loss of fracturing fluids.

Consider a typical situation where an investor is considering acquiring an unexplored oilfield. The oilfield has undergone a preliminary geological and geophysical study in which pre-discovery data such as lithology, depth, depositional system, diagenetic overprint, structural compartmentalization, and trap type are available. In this situation, investors usually estimate production rates using a volumetric approach. A more accurate estimation of production rates can be obtained using analytical methods, which require additional data such as net pay, porosity, oil formation volume factor, permeability, viscosity, and pressure. We call these data post-discovery parameters because they are only available after discovery through exploration drilling. A data-driven approach to estimating post-discovery parameters of an unexplored oilfield is developed based on its pre-discovery data by learning from proven reservoir data. Using the Gaussian mixture model, and a data-driven reservoir typology based on the joint probability distribution of post-discovery parameters is established. We came up with 12 reservoir types. Subsequently, an artificial neural network classification model with the resilient backpropagation algorithm is used to find relationships between pre-discovery data and reservoir types. Based on k-fold cross-validation with k = 10, the accuracy of the classification model is stable with an average of 87.9%. With our approach, an investor considering acquiring an unexplored oilfield can classify the oilfield's reservoir into a particular type and estimate its post-discovery parameters' joint probability distribution. The investor can incorporate this information into a valuation model to calculate the production rates more accurately, estimate the oilfield's value and risk, and make an informed acquisition decision accordingly.

The Oligo-Miocene Asmari Formation is one of the most important hydrocarbon reservoirs in the Middle East. The oilfield under study is one of the largest oilfields in the Zagros basin with the Asmari Formation being the major reservoir rock. In this study, petrographic analyses, petrophysical data and neural network clustering techniques were used for identifying rock types in the Asmari reservoir. Facies analysis of the Asmari Formation in the study area has resulted in the definition of 1 clastic lithofacies and 14 carbonate microfacies types. Using petrophysical logs from 43 wells and their correlation with capillary pressure (P_c) curves, led to the recognition of 7 electrofacies (EF1-EF7). Microscopic evidence of Electrofacies group C1 and S1 show that the sedimentary facies of these electrofacies are most commonly found in restricted and shoal facies belts zone. Also, petrographic studies show that the sedimentary facies of C2, C3, C4, S2 and S3 were formed in the open marine, Lagoon, and Tidal flat facies belt zone of homoclinal ramp sedimentary environment during the Oligo-Miocene based on relative sea level changes respectively. The link between electrofacies and geological data indicated that both sedimentary and diagenetic processes controlled the reservoir quality of the Asmari Formation. Porosity, permeability and water saturation were used to estimate the reservoir quality of each electrofacies. EFs 1 and 2 with high porosity and permeability, low water saturation is considered as the best reservoir with regard to sedimentary textures (dolowackestone and dolograinstone) and the effect of diagenetic processes such as dolomitization processes. Vuggy, growth framework and interparticle porosities are major in EF-2, while the intercrystalline porosity is the major type in EF-1. EFs 3 and 4 show low values of porosity, permeability and high percentage of water saturations, which characterizes them as poor reservoir rocks. Finally, EF-5 is the only electrofacies in the siliciclastic parts of the Asmari reservoir, which is composed of rounded and well-sorted quartz grains that are slightly cemented. In sandstone electrofacies, electrofacies EF- 5 (S1), is the best type of sandstone reservoir rock and to move towards electrofacies EF-7 (S3), will reduce reservoir quality. In carbonate electrofacies, also, electrofacies no 1, the best type of carbonate reservoir rock can be observed and move towards electrofacie number 4, lower quality of reservoir rocks is seen.