Journal articles: 'Oil and gas engineering'

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Hensler, Fran. "Oil and gas extraction: Using engineering simulation." Filtration & Separation 46, no. 3 (May 2009): 18–20. http://dx.doi.org/10.1016/s0015-1882(09)70123-5.

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Huang, Z., and A. Seireg. "Optimization in Oil and Gas Pipeline Engineering." Journal of Energy Resources Technology 107, no. 2 (June 1, 1985): 264–67. http://dx.doi.org/10.1115/1.3231187.

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A survey of applications of optimization techniques in oil and gas pipeline engineering is presented. These applications include the optimal design, optimal expansion, optimal control and optimal operation of pipeline systems. Applications in off shore pipeline engineering is also involved.

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Hause, Matthew, and Steve Ashfield. "The Oil and Gas Digital Engineering Journey." INCOSE International Symposium 28, no. 1 (July 2018): 337–51. http://dx.doi.org/10.1002/j.2334-5837.2018.00485.x.

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Xu, B. X., Y. H. Bai, G. H. Chen, and R. Y. Feng. "The impact of engineering parameters on shale oil and gas production: theory and practice." "Proceedings" of "OilGasScientificResearchProjects" Institute, SOCAR, no. 2 (June 30, 2015): 24–31. http://dx.doi.org/10.5510/ogp20150200239.

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Panevnyk, O. V., and D. O. Panevnyk. "Analysis of tendencies of oil and gas engineering development." Oil and Gas Power Engineering, no. 1(33) (September 3, 2020): 90–100. http://dx.doi.org/10.31471/1993-9868-2020-1(33)-90-100.

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Based on the study of the dynamics of global costs for oilfield equipment, it was found that its production shows slow growth, the largest share of oil and gas machinery is in North America, and the largest segment of production belongs to the manufacture of equipment for collecting and transporting hydrocarbons and pipe products. In the process of analysis of the nomenclature and geography of production of machines, mechanisms, individual components and parts of drilling and oil and gas equipment, the inconsistency of the level of development of oil and gas engineering in Ukraine with the needs of the fuel and energy complex is shown. The required level of production of equipment and spare parts directly depends on the quality of maintenance of oil and gas machines, which with the development of new technologies for the development of hydrocarbon fields should increase. The main reasons for failures of oil and gas equipment are the lack of proper maintenance. Domestic oil companies are focused on the import of oil equipment, and a negative problem for the development of the domestic market of oil services is the reduction of their own production of oil and gas equipment. One of the most important competitive advantages of domestic service companies is a lower level of prices for services, as well as a deeper knowledge of the specifics and features of local conditions for the development of hydrocarbon deposits. An important aspect of the development of the service market is the transition to innovative technologies in the field of geological engineering and drilling. In accordance with the development trends of the world oil and gas engineering industry, the staffing requirements of service companies are increasing. Given the complexity of mining and geological conditions for the development of hydrocarbon deposits, the development of new technologies for oil and gas production requires increasing attention to training specialists who are aware of modern methods of design, operation and maintenance of oil and gas equipment.

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Mohd Said, Naqiyatul Amirah, Nur Emma Mustaffa, and Hamizah Liyana Tajul Ariffin. "Integrating Cloud in Engineering, Procurement and Construction Contract." Journal of Computational and Theoretical Nanoscience 17, no. 2 (February 1, 2020): 893–901. http://dx.doi.org/10.1166/jctn.2020.8738.

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Engineering, Procurement, and Construction Contract is a project delivery method in the oil and gas industry. However, the complexity of Engineering, Procurement and Construction projects inevitably leads to issues of project management, risk and technical to occur. Therefore, oil and gas players demand a course of action in minimizing the issues arise in this project. Digitalization in the oil and gas trade indeed offers benefits in the upstream value chain of exploration, development, and production, which Engineering, Procurement and Construction projects take place. Oil and gas companies had been focusing too much on digitizing technical work until the non-technical aspect has been abandoned. Therefore, this study presents and discusses the issues in Engineering, Procurement and Construction contract specifically in the Malaysian oil and gas industry. This is a descriptive study and the methodology used is essentially based on the review of the literature in relation to Engineering, Procurement and Construction contract and the findings of a pilot study in relation to Engineering, Procurement and Construction contract and cloud computing. The analysis revealed that the characteristics of cloud computing in relation to the adoption of Engineering, Procurement and Construction contract helps in empowering collaboration among stakeholders, allow oil and gas companies work highly automated, improve the performance of upstream oil and gas industry, improve speed and minimize financial risks, delayed in schedule as well as improving the quality of the project.

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Yang, Zhennan, Liqun Pei, and Jinsheng Zhu. "Application of New Energy Natural Gas in Ship Engineering." Insight - Energy Science 1, no. 1 (August 9, 2018): 1. http://dx.doi.org/10.18282/i-es.v1i1.113.

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Traditional ships are mainly fueled by diesel or gasoline, which are produced from the oil and are non-renewable. People are now rapidly consuming oil and burning oil generates poisonous gases day and night. Because of the soaring oil prices and the deteriorating ecology, many ship-owners are seeking an alternative energy to replace oil. Among all possible candidates, the calling of natural gas is getting higher and higher. This paper discusses the application of natural gas in ship engineering, and explains in detail the advantages and disadvantages. Natural gas may not be a new energy but has rarely been used in ship engineering so far. We conclude that its application in ship engineering helps to alleviate the fuel shortage in the future.

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Su, Yu Bin, and Heng Zheng. "Applied Technology for Tight Oil in Engineering of Oil Manufacturing in the Western Canada Sedimentary Basin." Applied Mechanics and Materials 540 (April 2014): 287–91. http://dx.doi.org/10.4028/www.scientific.net/amm.540.287.

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Canada is the second country after the US to start the shale gas exploration and production in the world. And the Western Canada Sedimentary Basin (WCSB) is known for its rich shale gas reserves. However, with the development of shale gas, it is found that the success of the United States is difficult to replicate. In addition, many oil companies were forced to transfer their focus of exploration and development from shale gas to tight oil for the extended downturn of gas-price in recent years. Afterwards, abundant resources of tight oil were discovered in northeast Alberta located in the Western Canada Sedimentary Basin. This paper studies the developing history and current situation of tight oil, and review the horizontal well drilling technology, stimulated reservoir volume (SRV) fracturing completion technology and multi-well pad factory operation. Meanwhile, some opinions and Suggestions on the tight oil exploration and production in China are proposed.

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Denney, Dennis. "Twelve Steps To Engineering Safe Oil and Gas Facilities." Journal of Petroleum Technology 63, no. 12 (December 1, 2011): 67–69. http://dx.doi.org/10.2118/1211-0067-jpt.

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Crook, J. "Extreme engineering [Russian Pacific oil and gas field exploitation]." Power Engineer 18, no. 5 (2004): 29. http://dx.doi.org/10.1049/pe:20040505.

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Nikolaou, Michael. "Computer-aided process engineering in oil and gas production." Computers & Chemical Engineering 51 (April 2013): 96–101. http://dx.doi.org/10.1016/j.compchemeng.2012.08.014.

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Wang, Jia Shan, Ting Wang, and Rui Hua Wang. "The Effect of Oil and Gas Production and Construction on Soil Erosion and its Prevention Measures." Advanced Materials Research 869-870 (December 2013): 644–47. http://dx.doi.org/10.4028/www.scientific.net/amr.869-870.644.

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Through researching the oil and gas in many companies, such as the Daqing Oilfield, Changqing Oilfield and the West-East Gas Pipeline Company and so on, we found that the production and construction of oil and gas at different stages influence the soil erosion vary greatly, including the exploration in oil and gas has a little effect on soil erosion, but oil and gas field surface engineering and pipeline construction impact on soil erosion greatly, and limited impact on soil erosion in oil and gas development, and long-distance pipeline operators had no effect on soil erosion.Oil and gas companies have taken appropriate preventive measures in the soil erosion and have achieved good control effect.

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Dos Santos, Ismael H. F., Luciano P. Soares, Felipe Carvalho, and Alberto Raposo. "A Collaborative Virtual Reality Oil and Gas Workflow." International Journal of Virtual Reality 11, no. 1 (January 1, 2012): 1–13. http://dx.doi.org/10.20870/ijvr.2012.11.1.2832.

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The current way of designing industrial plants relies on the communication among experts in the field, and on tools that allow the simulation of the site. Virtual reality (VR) tools are used to visualize and interact with complex 3D environments in real time, and several engineering simulations employ VR to foresee the results of complex industrial operations. The research project described here presents a Service Oriented Architecture aimed to create a collaborative environment, called CEE (Collaborative Engineering Environment) that integrates VR techniques into a system where the execution of different sequences of engineering simulations is modeled as scientific workflows. The focus of this research is on the oil and gas industry, particularly offshore engineering, where the project of a new production unit is a lengthy, expensive and usually is conducted by different specialists who are geographically distributed. Among the integrated engineering simulations are those involving structural calculus, hydrodynamics, naval engineering with mooring systems, meteo-oceanography, and others. The main objective is to improve the users' interpretation capacity and skills while providing visualization tools for a better understanding of the results.

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Kong, Xiangwen, Hongjun Wang, Wei Yu, Ping Wang, Jijun Miao, and Mauricio Fiallos-Torres. "Compositional Simulation of Geological and Engineering Controls on Gas Huff-n-Puff in Duvernay Shale Volatile Oil Reservoirs, Canada." Energies 14, no. 8 (April 8, 2021): 2070. http://dx.doi.org/10.3390/en14082070.

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Duvernay shale is a world class shale deposit with a total resource of 440 billion barrels oil equivalent in the Western Canada Sedimentary Basin (WCSB). The volatile oil recovery factors achieved from primary production are much lower than those from the gas-condensate window, typically 5–10% of original oil in place (OOIP). The previous study has indicated that huff-n-puff gas injection is one of the most promising enhanced oil recovery (EOR) methods in shale oil reservoirs. In this paper, we built a comprehensive numerical compositional model in combination with the embedded discrete fracture model (EDFM) method to evaluate geological and engineering controls on gas huff-n-puff in Duvernay shale volatile oil reservoirs. Multiple scenarios of compositional simulations of huff-n-puff gas injection for the proposed twelve parameters have been conducted and effects of reservoir, completion and depletion development parameters on huff-n-puff are evaluated. We concluded that fracture conductivity, natural fracture density, period of primary depletion, and natural fracture permeability are the most sensitive parameters for incremental oil recovery from gas huff-n-puff. Low fracture conductivity and a short period of primary depletion could significantly increase the gas usage ratio and result in poor economical efficiency of the gas huff-n-puff process. Sensitivity analysis indicates that due to the increase of the matrix-surface area during gas huff-n-puff process, natural fractures associated with hydraulic fractures are the key controlling factors for gas huff-n-puff in Duvernay shale oil reservoirs. The range for the oil recovery increase over the primary recovery for one gas huff-n-puff cycle (nearly 2300 days of production) in Duvernay shale volatile oil reservoir is between 0.23 and 0.87%. Finally, we proposed screening criteria for gas huff-n-puff potential areas in volatile oil reservoirs from Duvernay shale. This study is highly meaningful and can give valuable reference to practical works conducting the huff-n-puff gas injection in both Duvernay and other shale oil reservoirs.

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Bajpai, S., and J. P. Gupta. "Securing oil and gas infrastructure." Journal of Petroleum Science and Engineering 55, no. 1-2 (January 2007): 174–86. http://dx.doi.org/10.1016/j.petrol.2006.04.007.

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16

Valkó, P. P., and W. D. McCain. "Reservoir oil bubblepoint pressures revisited; solution gas–oil ratios and surface gas specific gravities." Journal of Petroleum Science and Engineering 37, no. 3-4 (March 2003): 153–69. http://dx.doi.org/10.1016/s0920-4105(02)00319-4.

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Zadakbar, O., A. Vatani, and K. Karimpour. "Flare Gas Recovery in Oil and Gas Refineries." Oil & Gas Science and Technology - Revue de l'IFP 63, no. 6 (September 9, 2008): 705–11. http://dx.doi.org/10.2516/ogst:2008023.

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18

Chen, Hang. "Study on Ground Engineering and Management of Carbonate Oil Field A under Rolling Development Mode." Frontiers Research of Architecture and Engineering 4, no. 1 (May 19, 2021): 32. http://dx.doi.org/10.30564/frae.v4i1.3157.

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Carbonate rock has the characteristics of complicated accumulation rules, large-scale development, high yield but unstable production. Therefore, the management and control of surface engineering projects of carbonate rock oil and gas reservoirs faces huge difficulties and challenges. The construction of surface engineering should conform to the principle of integrated underground and ground construction and adapt to the oilfield development model. This paper takes the newly added area A of the carbonated oil field as an example to study the ground engineering under the rolling development mode and aims to provide the constructive ideas for the surface engineering under rolling development mode. The overall regional process design adheres to the design concept of "environmental protection, efficiency, and innovation", strictly follows the design specifications, and combines reservoir engineering and oil production engineering programs, oil and gas physical properties and chemical composition, product programs, ground natural conditions, etc. According to the technical and economic analysis and comparison of area A, this paper has worked out a suitable surface engineering construction, pipeline network layout and oil and gas gathering and transportation plan for area A. Some auxiliary management recommendations are also proposed in this paper, like sand prevention management and HSE management for carbonate reservoirs.

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Taylor, B. "Offshore oil and gas." Ocean and Shoreline Management 16, no. 3-4 (1991): 259–73. http://dx.doi.org/10.1016/0951-8312(91)90007-o.

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Li, Songyan, and Zhaomin Li. "Effect of Temperature on the Gas/Oil Relative Permeability of Orinoco Belt Foamy Oil." SPE Journal 21, no. 01 (February 18, 2016): 170–79. http://dx.doi.org/10.2118/174089-pa.

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Summary Foamy-oil flow has been successfully demonstrated in laboratory experiments and site applications. On the basis of solution-gas-drive experiments with Orinoco belt heavy oil, the effects of temperature on foamy-oil recovery and gas/oil relative permeability were investigated. Oil-recovery efficiency increases and then decreases with temperature and attains a maximum value of 20.23% at 100°C. The Johnson-Bossler-Naumann (JBN) method has been proposed to interpret relative permeability characteristics from solution-gas-drive experiments with Orinoco belt heavy oil, neglecting the effect of capillary pressure. The gas relative permeability is lower than the oil relative permeability by two to four orders of magnitude. No intersection was identified on the oil and gas relative permeability curves. Because of an increase in temperature, the oil relative permeability changes slightly, and the gas relative permeability increases. Thermal recovery at an intermediate temperature is suitable for foamy oil, whereas a significantly higher temperature can reduce foamy behavior, which appears to counteract the positive effect of viscosity reduction. The main reason for the flow characteristics of foamy oil in porous media is the low gas mobility caused by the oil components and the high viscosity. High resin and asphaltene concentrations and the high viscosity of Orinoco belt heavy oil increase the stability of bubble films and prevent gas breakthrough in the oil phase, which forms a continuous gas, compared with the solution-gas drive of light oil. The increase in the gas relative permeability with temperature is caused by higher interfacial tensions and the bubble-coalescence rate at high temperatures. The experimental results can provide theoretical support for foamy-oil production.

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SYZRANTSEV, V. N., S. I. CHELOMBITKO, and M. D. GAMMER. "THE USE OF VIRTUAL LABORATORY WORKS IN THE STUDY OF ENGINEERING DISCIPLINES OF OIL AND GAS TRAINING." Periódico Tchê Química 15, no. 30 (August 20, 2018): 563–69. http://dx.doi.org/10.52571/ptq.v15.n30.2018.567_periodico30_pgs_563_569.pdf.

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The effect from the introduction of an interactive form of learning in the study of engineering disciplines is examined, as well as factors that decrease the effectiveness of the results of using modern computer training aids (simulators). Virtual laboratory works are described that are used at the department "Machines and equipment of the oil and gas industry" of the Industrial University of Tyumen in studying general engineering and special disciplines of the area "Oil and gas engineering", profile "Operation and maintenance of technological facilities of oil and gas production". Based on the experience of using simulators at the department, it was concluded that the greatest effect of achieving the required knowledge, abilities, and skills was obtained by using simulators in the form of virtual laboratory works.

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Johnstone, James, and James Curfew. "Twelve Steps to Engineering Safe Onshore Oil and Gas Facilities." Oil and Gas Facilities 1, no. 04 (August 1, 2012): 38–46. http://dx.doi.org/10.2118/141974-pa.

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Zhu, Hongjun, Zhi Yang, Youming Xiong, Yongyou Wang, and Lu Kang. "Virtual emulation laboratories for teaching offshore oil and gas engineering." Computer Applications in Engineering Education 26, no. 5 (June 28, 2018): 1603–13. http://dx.doi.org/10.1002/cae.21977.

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Braga, Pedro Tovar, Wagner Fernandes Esteves, and Rodrigo Luz Marques. "Specific purpose virtual assistant for oil and gas engineering projects." Rio Oil and Gas Expo and Conference 20, no. 2020 (December 1, 2020): 431–32. http://dx.doi.org/10.48072/2525-7579.rog.2020.431.

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Di, Shiying, Shiqing Cheng, Nai Cao, Chaoli Gao, and Linan Miao. "AI-based geo-engineering integration in unconventional oil and gas." Journal of King Saud University - Science 33, no. 6 (September 2021): 101542. http://dx.doi.org/10.1016/j.jksus.2021.101542.

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Tang, Guo-Qing, Yi Tak Leung, Louis M. Castanier, Akshay Sahni, Frederic Gadelle, Mridul Kumar, and Anthony R. Kovscek. "An Investigation of the Effect of Oil Composition on Heavy Oil Solution-Gas Drive." SPE Journal 11, no. 01 (March 1, 2006): 58–70. http://dx.doi.org/10.2118/84197-pa.

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Summary This study probes experimentally the mechanisms of heavy-oil solution gas drive through a series of depletion experiments employing two heavy crude oils and two viscous mineral oils. Mineral oils were chosen with viscosity similar to crude oil at reservoir temperature. A specially designed aluminum coreholder allows visualization of gas phase evolution during depletion using X-ray computed tomography (CT). In addition, a visualization cell was installed at the outlet of the sandpack to monitor the flowing-gas-bubble behavior vs. pressure. Bubble behavior observed at the outlet corroborates CT measurements of in-situ gas saturation vs. pressure. Both depletion rate and oil composition affect the size of mobile bubbles. At a high depletion rate (0.035 PV/hr), a foam-like flow of relatively small pore-sized bubbles dominates the gas and oil production of both crude oils. Conversely, at a low depletion rate (0.0030 PV/hr), foam-like flow is not observed in the less viscous crude oil; however, foam-like flow behavior is still found for the more viscous crude oil. No foam-like flow is observed for the mineral oils. In-situ imaging shows that the gas saturation distribution along the sandpack is not uniform. As the pattern of produced gas switches from dispersed bubbles to free gas flow, the distribution of gas saturation becomes even more heterogeneous. This indicates that a combination of pore restrictions and gravity forces significantly affects free gas flow. Additionally, results show that solution-gas drive is effective even at reservoir temperatures as great as 80°C. Oil recovery ranges from 12 to 30% OOIP; the higher the depletion rate, the greater the recovery rate. Introduction Solution gas drive has shown unexpectedly high recovery efficiency in some heavy-oil reservoirs. The mechanisms, however, that have been proposed are speculative, sometimes contradictory, and do not explain fully the origin of high primary oil recovery and slow decline in reservoir pressure. Smith (1988) first identified this effect. He hypothesized that gas bubbles smaller than pore constrictions are liberated from the oil, but are not able to form a continuous gas phase and flow freely. Instead, the gas bubbles exist in a dispersed state in the oil and only flow with the oil phase. Smith stated that oil viscosity is reduced significantly, resulting in high recovery performance. Later, many researchers focused on so-called foamy-oil behavior. Claridge and Prats (1995) hypothesized that heavy-oil components (such as asphaltenes) concentrate at the interfaces between oil and gas bubbles, thereby preventing bubbles from coalescing into a continuous gas phase. Bubbles are assumed to be smaller than pore dimensions. Claridge and Prats stated that the concentration of heavy-oil components at the interfaces results in a reduction of the viscosity of the remaining oil. Bora et al. (2000) discussed the flow behavior of solution gas drive in heavy oils. Based on their studies, they found that dispersed gas bubbles do not coalesce rapidly in heavy oil, especially at high depletion rate. They stated that the main feature of the gas/oil dispersion is a reduced viscosity compared to the original oil. Models to explain the experimental results were also established (Sheng et al. 1994, 1996, 1999, 1995).

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Berkhout, Guus, Christian Bos, Peter Currie, and Ruud Weijermars. "Executive Education for Oil and Gas Professionals." Talent & Technology 02, no. 01 (December 1, 2008): 06–09. http://dx.doi.org/10.2118/0201-06-tt.

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Feature The current prospect for the petroleum industry is a future in which the big crew change retires experienced professionals without qualified workers to replace them. A lack of experienced personnel could cost the industry as much as USD 35 billion per year. To some extent, the problem has been alleviated by the rise in the number of petroleum engineering students in recent years.

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Berkhout, Guus, Christian Bos, Peter Currie, and Ruud Weijermars. "Executive Education for Oil and Gas Professionals." Talent & Technology 02, no. 01 (December 1, 2008): 06–09. http://dx.doi.org/10.2118/0201-06-tt.

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Feature The current prospect for the petroleum industry is a future in which the big crew change retires experienced professionals without qualified workers to replace them. A lack of experienced personnel could cost the industry as much as USD 35 billion per year. To some extent, the problem has been alleviated by the rise in the number of petroleum engineering students in recent years.

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Xu, Jianping, Yuanda Yuan, Qing Xie, and Xuegang Wei. "Research on the application of molecular simulation technology in enhanced oil-gas recovery engineering." E3S Web of Conferences 233 (2021): 01124. http://dx.doi.org/10.1051/e3sconf/202123301124.

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In recent years, molecular simulations have received extensive attention in the study of reservoir fluid and rock properties, interactions, and related phenomena at the atomistic scale. For example, in molecular dynamics simulation, interesting properties are taken out of the time evolution analysis of atomic positions and velocities by numerical solution of Newtonian equations for all atomic motion in the system. These technologies assists conducting “computer experiments” that might instead of be impossible, very costly, or even extremely perilous to carry out. Whether it is from the primary oil recovery to the tertiary oil recovery or from laboratory experiment to field test, it is difficult to clarify the oil displacement flow mechanism of underground reservoirs. Computer molecular simulation reveals the seepage mechanism of a certain oil displacement at the microscopic scale, and enriches the specific oil displacement flow theory system. And the molecular design and effect prediction of a certain oil-displacing agent were studied, and its role in the reservoir was simulated, and the most suitable oil-displacing agent and the best molecular structure of the most suitable oil-displacing agent were obtained. To give a theoretical basic for the development of oilfield flooding technology and enhanced oil/gas recovery. This paper presents an overview of molecular simulation techniques and its applications to explore enhanced oil/gas recovery engineering research, which will provide useful instructions for characterizing the reservoir fluid and rock and their behaviors in various oil-gas reserves, and it greatly contribute to perform optimal operation and better design of production plants.

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Turta, A. T., and A. K. Singhal. "Reservoir Engineering Aspects of Light-Oil Recovery by Air Injection." SPE Reservoir Evaluation & Engineering 4, no. 04 (August 1, 2001): 336–44. http://dx.doi.org/10.2118/72503-pa.

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Summary This paper addresses the reservoir engineering aspects of air injection as an enhanced oil recovery technique for light-oil reservoirs. In its most successful form, the process has been applied in deep, carbonate reservoirs. The development of this process in conjunction with an application of the in-situ combustion (ISC) process to light-oil reservoirs, as well as the main mechanisms pertaining to ISC and to gas miscible flooding, are analyzed. It is seen that various air-injection processes (AIP's) can be classified, depending on their spontaneous ignition potential and gas miscibility at reservoir conditions, into four different processes. Based on an in-depth literature review, the best reservoir conditions for application of each of these four processes are derived. The main differences in operational aspects (pollution, corrosion, safety) for these processes are also discussed. Design considerations for pilot testing of the technique are presented. The crucial point is location of the pilot on the structure, which is also a key element in its proper evaluation, and its subsequent development to a commercial-size operation. Finally, recommendations on laboratory work in support of design and evaluation of a field pilot are also presented. Introduction AIP's comprise those oil recovery processes that occur naturally when air is injected in an oil reservoir. The ISC process is one variation of air injection. Although the focus of this paper is not on ISC, the experience gained from ISC is used whenever relevant. ISC is an AIP, but the reverse is not true; some AIP's cannot be considered as ISC processes at all. Usually, the application of the ISC process is associated with the existence of a high peak temperature (350 to 600°C) or an ISC front that travels from injection to production wells. On the other hand, the application of an AIP does not necessarily assume the existence of a high peak temperature. In other words, application of ISC sometimes requires an ignition operation to initiate it (create the heat wave), while the application of an AIP does not. The ISC does not appear feasible in low-porosity matrix reservoirs; the porosity requirement is directly related to heat losses within the matrix. However, if the intent of air injection is merely pressure maintenance, the air injection should still be feasible, either as a miscible or an immiscible gas displacement process. Because the composition of air/flue gases, or a mixture of nitrogen with hydrocarbons in the vapor phase, is closer (from the miscibility point of view) to that of nitrogen, the miscibility of nitrogen can be a starting point in analyzing the feasibility of AIP's; this is illustrated in this paper. Generally, if the miscibility with nitrogen cannot be achieved, only an immiscible gas displacement needs to be evaluated. This paper analyzes the main reservoir engineering aspects of air-injection application through a new classification based on the main mechanisms of ISC and miscible flooding, as well as in light of limited experience gained from airflooding light and very light-oil reservoirs. Air-Injection-Based Oil-Recovery Processes Air-injection-based oil-recovery processes were evaluated based on the screening criteria for improved-oil-recovery (IOR) processes used in the software program PRIze™, a package that evaluates the IOR potential of oil reservoirs.1 Basically, the screening criteria for application of ISC, gas miscible flooding, and immiscible gasflooding were used. When air is injected into an oil reservoir, two simultaneous phenomena occur: displacement of oil and oxidation of oil. According to the efficiency of displacement and the intensity of oxidation, four main types of processes can occur.Immiscible Airflooding (IAF) with High Temperature Oxidation (HTO)IAF with Low Temperature Oxidation (LTO)Miscible Airflooding (MAF) with HTOMAF with LTO The last two processes are commonly known as high pressure air injection (HPAI) processes. Depending on the intensity of oxidation, either the LTO or the HTO reactions can dominate development of the process. Actually, when HTO takes place in immiscible airflooding, the classic ISC process is obtained, while if only LTO takes place, the process is called LTO-IAF (LTO combined with IAF). The LTO-IAF was unintentionally obtained while attempting ISC, either when the ignition operation was not successful or when it was successful, but the ISC front did not sustain itself. Therefore, this kind of process has been applied only for relatively viscous oils. So far, the LTO-IAF process has not proved to be an effective IOR process (as compared to the ISC process). As a matter of fact, it seems to be the least efficient one among the four possible combinations. Stoichiometrically, the volume of gases produced during an HTO process is roughly the same as that of air injected; hence, the oxidation reactions do not significantly impact pressure maintenance. For an LTO process, a part of oxygen is consumed without releasing carbon oxides, leading to a shrinkage of the injected gas volume. Consequently, benefits of pressurization are somewhat less for this process, and some over injection may be considered. Air injection can be used in both horizontal and vertical flooding. In a vertical flood, air is injected at the top of the structure (which may be a reef), and oil is produced from lower intervals, taking full advantage of gravity. This way, the volumetric sweep efficiency and displacement efficiency are aided by natural forces and are usually extremely efficient. In the hydrocarbon miscible flood, field experience has indicated incremental oil recovery using a vertical flood to be of the order of 30% original oil in place (OOIP), whereas for horizontal floods, the incremental oil recovery is typically 10% OOIP. A similar difference in the magnitude of oil recovery is expected for the application of air injection in these two modes. A typical horizontal immiscible gas injection can increase the ultimate oil recovery by up to 5 to 6% OOIP. For a vertical immiscible flood, this increment is expected to be much higher. In general, the IAF is expected to increase the ultimate oil recovery by at least as much as that obtained during immiscible flooding with such gases as nitrogen, flue gas, or hydrocarbon gas. For cases where a combination of extensive fracturing and unfavorable mobility ratio between air and oil causes severe channeling, horizontal gasflooding may not be a viable option. However, gas injection at the top of the reservoir with velocities of displacement lower than the critical velocity may still be feasible. It is expected that the oxygen contained in the injected air will not appear at the production well; rather, it will be consumed by reacting with the oil (oxygen uptake). Following gas breakthrough, the produced gas will consist mainly of nitrogen and hydrocarbon gases. This is true for most oil reservoirs, even in cases where air injection is accompanied by LTO, so long as heterogeneity is not too high.

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Ahn, Suhyun, Jeong Mog Seo, and Heejin Lee. "Thermogravimetric Analysis of Marine Gas Oil in Lubricating Oil." Journal of Marine Science and Engineering 9, no. 3 (March 19, 2021): 339. http://dx.doi.org/10.3390/jmse9030339.

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Marine lubricating oil (LO) is deteriorated by contaminants—especially marine gas oil (MGO), which is invariably mixed during its usage—that can damage engine performance. This study investigates a method for determining the content of MGO in lubricating oil. Weight loss from MGO-containing lubricant was evaluated through thermogravimetric analysis (TGA), and a standard calibration curve was plotted to establish a correlation with MGO content. A comparison of the commonly used ASTM–based gas chromatography (GC) analysis, and this TGA approach revealed that the former was more accurate when the lubricant contained ≤1% MGO; however, TGA afforded higher accuracy when the MGO content was between 0.5% and 15%. Hence, TGA can be used as a simple, reliable, and rapid method to analyze the contents of a lubricant contaminant such as MGO.

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Khidr, T. T., and E. A. El Shamy. "Effect of Flow Improvers on the Rheological Properties of Gas Oil and Gas Oil Raffinate." Petroleum Science and Technology 26, no. 1 (January 22, 2008): 114–24. http://dx.doi.org/10.1080/10916460500442361.

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Wang, He Hua, Ling Wu, Ting Ting Feng, Yuan Sheng Li, and Jian Yang. "The Development and Technology Policy for a Gas Cap and Edge Water Reservoir with Narrow Oil Ring." Advanced Materials Research 962-965 (June 2014): 500–505. http://dx.doi.org/10.4028/www.scientific.net/amr.962-965.500.

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Reservoir with gas cap, edge water is complex. And the oil-water and oil-gas interface will seriously influence the performance. Once out of control, gas and water invasion may occur, then oil productivity will fall sharply and oil recovery will become low. In addition, the oil penetrating into gas cap would lead to oil loss. So, the controlling methods are crucial. In this paper, we study the productive characteristics of a certain reservoir with gas cap, edge water and narrow oil ring. For the phenomenon several productive wells appeared gas breakthrough and water invasion after putting into production, this paper puts up a strategy shutting in high gas-oil ratio wells and blocking off gas breakthrough layers that proved effective. At the same time, adjusting oil and gas distribution underground by gas-water alternate also be proved practicable.

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Billiter, T. C., and A. K. Dandona. "Simultaneous Production of Gas Cap and Oil Column With Water Injection at the Gas/Oil Contact." SPE Reservoir Evaluation & Engineering 2, no. 05 (October 1, 1999): 412–19. http://dx.doi.org/10.2118/57640-pa.

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Summary The conventional way to produce an oil reservoir that has a gas cap is to produce only from the oil column while keeping the gas cap in place so that it can expand to provide pressure support. Depending upon the geometry, reservoir dip angle, and oil production rates, gas can either cone down to the oil producers or breakthrough as a front, leading to substantial increases in the gas-oil ratios of the oil producers. This paper presents a unique production methodology of simultaneously producing the gas cap and oil column while injecting water at the gas-oil contact to create a water barrier to separate the gas cap and oil column. This methodology has application in reservoirs with a low-dip angle, large gas cap, and a low residual gas saturation to water. It is demonstrated that the net present value of the project is improved if there is an immediate market for gas. Geostatistical reservoir models are used to demonstrate that the gas cap recovery is minimally impacted by heterogeneities. Introduction of the Concept The conventional way to produce an oil reservoir that has a gas cap is to produce the oil column while minimizing production from the gas cap. During the pressure depletion of the reservoir, the gas cap will expand to provide pressure or energy support. After the oil column is depleted, the gas cap is "blown down." In developing a production strategy for an oil reservoir with a large gas cap, a low-dip angle, and an available gas market, simultaneous waterflooding of the gas cap and oil column was evaluated. The water is injected at the gas-oil contact at rates high enough to overcome gravity effects and thus, the water displaces the gas up dip. In addition to providing pressure support, the created water wall separates the gas cap and the oil column regions. Since the development plan calls for the use of electrical submersible pumps (ESPs) in the oil producing wells, it is imperative to keep the gas production volumes from these oil wells at low levels so the ESPs will operate smoothly. As such, it is critical to control the downward migration of the gas cap. To maintain the reservoir pressure, water is injected not only at the gas-oil contact but also around the downdip periphery of the oil column to support the oil withdrawal rates. A simplistic representation of the simulated structure is shown in Fig. 1. This figure shows the location of the gas-oil contact, along with the location of the water injector at the gas-oil contact and of the gas cap producer. The reservoir considered in this study has a dip angle of 2°. For the purposes of illustration the dip angle has been exaggerated in Fig. 1. The horizontal distance between the injector and producer is 12,155 feet. The structural elevation difference between these two wells is 425 feet. Taking into account the density difference between the water and gas, the injected water must overcome a gravity component of 149 psi in addition to the energy required for the water to displace the gas. The possibility of injecting water at high enough rates to overcome both the gravity and displacement components is shown in this paper. The main objective of this paper is to present the concept of simultaneously producing the gas cap and oil column while injecting water at the gas-oil contact. The application of this concept for a newly discovered, offshore oil field has been studied. In this study, the majority of the effort was dedicated to theoretically proving this concept, as opposed to optimizing the number of wells and placement of wells to increase the recovery factors for oil and gas. This production methodology should be applicable to other reservoirs with similar characteristics. Partial Proof of Concept A literature survey indicated that the simultaneous production of the gas cap and oil column while injecting water at the gas-oil contact, has never been documented. However, four case histories were found in which water was injected at the gas-oil contact for the sole purpose of preventing the migration of the gas cap down structure. By preventing this migration, increased oil recoveries were realized. In these four cases, the gas cap was not produced during the depletion of the oil column. One successful application of this production methodology was to the Adena field in the Denver basin in 1965.1 By injecting water at the gas-oil contact, the operator was able to keep the producing gas-oil ratio value close to the solution gas-oil ratio value for an extended time. The ultimate oil recovery was estimated to be 47% of the original oil in place. The methodology of injecting water at the gas-oil contact was also applied in seven of the oil reservoirs of the Algyo Field in Hungary.2 These seven reservoirs are thin oil edge zones with large gas caps. The operators of this field were able to increase oil recovery by over 10% of original oil in place by using this methodology. In the Canadian oil field Kaybob South, the injection of water at the gas-oil contact was studied by Deboni and Field.3 They used numerical simulation to determine that a waterflood can be successfully implemented adjacent to a gas cap if a proper water "fence" is established between the gas cap and oil column. The authors concluded that an additional 10% of the oil in place can be recovered.

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Glukhikh, Igor Nikolaevich, Artyom Fedorovich Mozhchil, Mikhail Olegovich Pisarev, Otabek Anzor ugli Arzykulov, and Kristina Zakharovna Nonieva. "Evaluating the Cost Efficiency of Systems Engineering in Oil and Gas Projects." Applied System Innovation 3, no. 3 (September 14, 2020): 39. http://dx.doi.org/10.3390/asi3030039.

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Studies of systems engineering applications have revealed that systems engineering (SE) has a high potential for transferring economically inefficient oil and gas projects into a profitable zone due to preserving the value created at the concept stage right up to the implementation stage. To implement any project, including an organizational one, the company must have an economic justification for innovation. Studies into the global experience of assessing SE efficiency based on projects of various types have revealed the lack of a universal assessment method; however, individual studies have potential to be used in developing a method for quantifying the value of SE in oil and gas projects. Considering this fact, we developed our own method and prototype to assess the economic effect from the introduction of SE into oil and gas projects. The method is based on a decision tree used to calculate the Net Present Value considering the probability of projects’ success and failure in terms of budget and deadlines. This allowed us to predict the effect from introducing SE to an oil company’s capital project. The results obtained demonstrated the model’s performance capability and its possible applications in project resource planning stages.

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Orchard, Bryan. "Meeting oil & gas project demands." World Pumps 2010, no. 6 (June 2010): 28–29. http://dx.doi.org/10.1016/s0262-1762(10)70162-0.

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37

Raloff, J. "Glasnost Offers Oil-and-Gas Dividend." Science News 141, no. 8 (February 22, 1992): 117. http://dx.doi.org/10.2307/3976351.

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38

Rowcraft, Graham. "Oil and gas production—progress needed." Production Engineer 64, no. 10 (1985): 44. http://dx.doi.org/10.1049/tpe.1985.0251.

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Mitusova, T. N., I. Ya Perezhigina, B. A. �nglin, L. N. Shabalina, A. M. Senekina, V. A. Stankevich, and A. A. Makarov. "Catalytic light gas oil as a diesel oil component." Chemistry and Technology of Fuels and Oils 27, no. 9 (September 1991): 465–68. http://dx.doi.org/10.1007/bf00718790.

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40

Bahramova, Gunel F., Bahar N. Aliyeva, Namig Rahimov, and Rustam B. Rustamov. "Global Positioning System/Geographic Information System Environment for Engineering Infrastructure Facility Monitoring." Applied Science and Innovative Research 2, no. 3 (August 28, 2018): 118. http://dx.doi.org/10.22158/asir.v2n3p118.

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Oil and gas companies need to ensure continuous operation of critical equipment, no matter how remote. This means knowing exactly where your fleets and equipment are, how they are performing and identifying problems as they occur. There are number of existing security systems developed to protect linear systems like oil pipelines for transportation of oil and gas products from the first point of development up to collection stations. In the current stage is the gap of the oil and gas pipeline systems security purposes of use of space technology advances. This paper dedicated to the subject of linear pipeline monitoring with use of global positioning system for observation of changes of land in the areas actively functioning of natural disaster factor (Babatunde, Chris, Rupert, & Phil, 2015).

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41

Jenkins, Gilbert. "Ussr Oil and Gas Developments." Energy & Environment 9, no. 1-2 (March 1998): 1–3. http://dx.doi.org/10.1177/0958305x98009001-201.

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Robinson, David. "Oil and gas: Water treatment in oil and gas production – does it matter?" Filtration & Separation 47, no. 1 (January 2010): 14–18. http://dx.doi.org/10.1016/s0015-1882(10)70032-x.

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43

Dickinson, Richard R. "Fuel Oil." Energy Exploration & Exploitation 4, no. 2-3 (May 1986): 125–34. http://dx.doi.org/10.1177/014459878600400204.

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As the price of petroleum has increased, the power industry has displaced a great deal of more expensive petroleum and natural gas with coal and nuclear power. The petroleum industry has installed processing facilities to upgrade its heavy fuel oil to make lighter products. These two actions, when combined, have effectively resulted in producing clean products indirectly from coal. A profitable synfuels industry has been created by the refining and power industries without conscious direction on their part—and without government support. The net effect has been to substantially reduce demand for both crude oil and natural gas, stretching future supplies of petroleum energy. This displacement has contributed to the temporary bubble in natural gas and the present oversupply of crude oil, creating downward price pressures on both crude oil and products. Even so, fuel oil prices have remained relatively stable because the industry has installed sufficient capability through its refinery improvements to upgrade fuel oil into more clean products, thereby reducing production of heavy fuel oil. In the future, we can expect the interaction among these fuels to continue to exert their effects. Since there are many consumers who can use either natural gas or fuel oil, their prices will remain tied to each other. Fuel oil prices will set the upper limits to which the burner tip price of natural gas can rise. Conversely, natural gas prices will tend to set the floor under fuel oil prices.

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44

Zhang, Lei, and Guo Ming Liu. "Analysis Development Status of A12 Reservoir." Advanced Materials Research 650 (January 2013): 664–66. http://dx.doi.org/10.4028/www.scientific.net/amr.650.664.

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A12 oil and gas reservoirs in L Oilfield Carboniferous carbonate rocks of oil and gas bearing system, saturated with the gas cap and edge water and bottom water reservoir. The A12 oil and gas reservoir structure the relief of the dome-shaped anticline, oil, gas and water distribution controlled by structure, the gas interface -2785 meters above sea level, the oil-water interface altitude range -2940 ~-2980m, average-2960m. Average reservoir thickness of 23m, with a certain amount of dissolved gas drive and gas cap gas drive energy, but not very active edge and bottom water, gas cap drive index.

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45

Krishna, R., G. C. Joshi, R. C. Purohit, K. M. Agrawal, P. S. Verma, and S. Bhattacharjee. "Correlation of pour point of gas oil and vacuum gas oil fractions with compositional parameters." Energy & Fuels 3, no. 1 (January 1989): 15–20. http://dx.doi.org/10.1021/ef00013a003.

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Wang, Xia, and Qingquan Duan. "Improved AHP–TOPSIS model for the comprehensive risk evaluation of oil and gas pipelines." Petroleum Science 16, no. 6 (September 21, 2019): 1479–92. http://dx.doi.org/10.1007/s12182-019-00365-5.

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Abstract A comprehensive and objective risk evaluation model of oil and gas pipelines based on an improved analytic hierarchy process (AHP) and technique for order preference by similarity to an ideal solution (TOPSIS) is established to identify potential hazards in time. First, a barrier model and fault tree analysis are used to establish an index system for oil and gas pipeline risk evaluation on the basis of five important factors: corrosion, external interference, material/construction, natural disasters, and function and operation. Next, the index weight for oil and gas pipeline risk evaluation is computed by applying the improved AHP based on the five-scale method. Then, the TOPSIS of a multi-attribute decision-making theory is studied. The method for determining positive/negative ideal solutions and the normalized equation for benefit/cost indexes is improved to render TOPSIS applicable for the comprehensive risk evaluation of pipelines. The closeness coefficient of oil and gas pipelines is calculated by applying the improved TOPSIS. Finally, the weight and the closeness coefficient are combined to determine the risk level of pipelines. Empirical research using a long-distance pipeline as an example is conducted, and adjustment factors are used to verify the model. Results show that the risk evaluation model of oil and gas pipelines based on the improved AHP–TOPSIS is valuable and feasible. The model comprehensively considers the risk factors of oil and gas pipelines and provides comprehensive, rational, and scientific evaluation results. It represents a new decision-making method for systems engineering in pipeline enterprises and provides a comprehensive understanding of the safety status of oil and gas pipelines. The new system engineering decision-making method is important for preventing oil and gas pipeline accidents.

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Nickels, Liz. "Hardmetal benefits for oil and gas." Metal Powder Report 74, no. 4 (July 2019): 187–89. http://dx.doi.org/10.1016/j.mprp.2019.04.058.

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Abbott, D. "International Oil and Gas Markets." Energy Exploration & Exploitation 6, no. 4-5 (September 1988): i—iii. http://dx.doi.org/10.1177/014459878800600401.

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Fatemi, S. Mobeen, and Mehran Sohrabi. "Relative permeabilities hysteresis for oil/water, gas/water and gas/oil systems in mixed-wet rocks." Journal of Petroleum Science and Engineering 161 (February 2018): 559–81. http://dx.doi.org/10.1016/j.petrol.2017.11.014.

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Gurevich, A. E., B. L. Endres, J. O. Robertson, and G. V. Chilingar. "Gas migration from oil and gas fields and associated hazards." Journal of Petroleum Science and Engineering 9, no. 3 (June 1993): 223–38. http://dx.doi.org/10.1016/0920-4105(93)90016-8.

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Journal articles on the topic 'Oil and gas engineering'

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