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1
O'Brien, Geoff, Monica Campi und Graeme Bethune. „2013 PESA production and development review“. APPEA Journal 54, Nr. 1 (2014): 451. http://dx.doi.org/10.1071/aj13044.
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The boom in Australian oil and gas development continued in 2013, with record overall investment of $60 billion. This investment resulted from spending on the seven LNG projects under development, together with that on numerous other oil and gas developments. These projects are expected to collectively contribute up to 665 million barrels of oil equivalent (MMboe) to Australia’s oil and gas production, which totaled 513.8 MMboe in 2013. LNG, presently Australia’s seventh largest export, is likely to soon rival the nation’s largest export, iron ore. By the end of 2013, three of the LNG projects under construction—Gorgon, Queensland Curtis LNG (QCLNG) and Gladstone LNG (GLNG)—were more than 70% complete; first LNG will be before the end of 2014 for QCLNG and in 2015 for Gorgon, GLNG and Australia Pacific LNG (APLNG). The other three LNG projects—Wheatstone, Prelude and Ichthys—are close behind. These new LNG projects follow Pluto, Australia’s third LNG project, which commenced production in 2012. A full year of production from Pluto drove increased gas production in 2013. Woodside also completed the North Rankin redevelopment and continued development of the Greater Western Flank, both of which will extend the life of the North West Shelf (NWS) project. A number of other projects also commenced production. In the Carnarvon Basin, oil production began at Santos’s Fletcher-Finucane Field, and at BHP Billiton’s Macedon project, domestic gas production started. In the Timor Sea, PTTEP’s Montara Field began production of oil. In Victoria, the ExxonMobil Kipper-Turrum-Tuna project came online, with the production of gas from Tuna and oil from Turrum. Production of gas from Origin Energy’s Geographe Field (as part of the Otway Gas Project) commenced in mid-2013. Onshore oil production grew in 2013, with the Cooper-Eromanga Basin now producing more oil than any other onshore Australian basin. A major effort is underway to increase production from the western flank oil trend and to develop both the conventional and unconventional gas fields in the Cooper Basin. Spending on the development of new projects probably peaked in 2013 and there is growing concern about a dearth of future projects, with expansion of existing LNG projects and development of new projects being pushed back due to a combination of increased costs and growing international competition. There are also ongoing industry concerns about impediments to onshore gas exploration and development generally.
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Willetts, Jim. „Production and development review 2007“. APPEA Journal 48, Nr. 1 (2008): 423. http://dx.doi.org/10.1071/aj07030.
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Australian petroleum production was close to record levels in 2007 with higher oil production and expansion of domestic gas, LNG and coal seam gas production. Growth in coal seam gas production has reached the point where it is not only providing a significant supply source for domestic gas and power station projects, but is proposed as the source of supply to no less than four potential LNG export plants in Queensland. Five new oil and gas developments came on stream during the year. Four final investment decisions were taken on major projects, the largest being the Pluto project in the Carnarvon Basin. The pipeline of committed and potential projects now includes about 25 significant petroleum projects with a combined value of over $100 billion. Together these have the potential to significantly increase Australian production in the next five to ten years, primarily through growing gas production. In the near term significant new oil projects carry the prospect of higher oil production in 2008. Cost estimates for new projects continued to escalate sharply and skills shortages in all parts of the project delivery chain threaten the ability to deliver all of the projects as contemplated.
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Humphreys, Geoff. „PESA production and development review 2009“. APPEA Journal 50, Nr. 1 (2010): 121. http://dx.doi.org/10.1071/aj09009.
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Australian hydrocarbon production reached record levels in 2009 due to strong growth in production of LNG from the North West Shelf Venture. Domestic gas production also reached record levels. Coal seam gas production continued to grow, with the continuing development of existing fields and the development of the Kenya and Talinga projects in Queensland. Two new conventional gas projects also came into production: Blacktip in the Timor Sea and Longtom in the Gippsland Basin. However oil production was below that in the previous year, reflecting natural field decline and the absence of large scale projects reaching production. The project sanction highlight of the year was the final investment decision on the $43 billion Gorgon LNG project. This project will comprise three LNG trains with total capacity of 15 million tonnes per annum plus a domestic gas plant. The first gas from this project is planned for 2014. Eight other potential LNG projects are in various stages of front end engineering and design, most targeting final investment decisions in 2010 or 2011. The pipeline of committed and potential LNG projects has a combined value estimated to be well over $100 billion. These projects have the potential to significantly increase Australian LNG production over the next five to ten years. In the near term the start-up of the Van Gogh, Pyrenees and Turrum oil projects are expected to provide some respite from the decline in Australian oil production. Cost estimates for new projects are again escalating and skills shortages in all parts of the project delivery chain threaten the ability to deliver all of the projects under consideration.
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Zhang, Muzhen, Ailin Jia, Zhanxiang Lei und Gang Lei. „A Comprehensive Asset Evaluation Method for Oil and Gas Projects“. Processes 11, Nr. 8 (09.08.2023): 2398. http://dx.doi.org/10.3390/pr11082398.
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The rapid and accurate evaluation of oil and gas assets, specifically for new development projects, poses a significant challenge due to the various project types, limited data availability, brief periods for assessment and decision making, and constraints arising from varying contractual and taxation conditions, political stability, and societal factors. This study leverages the grading standards of the evaluation index system for new oil and gas field development projects, along with relevant mathematical theories and methods for project evaluation and optimization. We developed an asset evaluation approach for new oil and gas projects by analyzing the assets of six new oil and gas field development projects in Brazil. This analysis resulted in the grading and ranking of new projects, and we tested and demonstrated four asset optimization techniques. After a comparative analysis with conventional evaluation results, we established an oil and gas project asset optimization approach centered on the cloud model comprehensive evaluation and linear weighted ranking, exhibiting Kendall’s tau coefficient of 0.8667 with conventional methods. The findings suggest that the combination of the cloud model comprehensive evaluation method with the linear weighted ranking method can facilitate asset optimization for oil and gas field development projects, meeting the practical needs for fast selection among various new projects. Furthermore, this research offers a technical and theoretical foundation for rapid evaluation and decision making regarding new assets.
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Marin, Evgenii A., Tatiana V. Ponomarenko, Natalia V. Vasilenko und Sergey G. Galevskiy. „Economic evaluation of projects for development of raw hydrocarbons fields in the conditions of the northern production areas using binary and reverting discounting.“ Север и рынок: формирование экономического порядка 25, Nr. 3/2022 (29.09.2022): 144–57. http://dx.doi.org/10.37614/2220-802x.3.2022.77.010.
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The conversion from the development of large deposits to unconventional, small and Arctic deposits of hydrocarbon raw materials in the Russian requires oil and gas companies improving the quality of the economic justification of projects, including cost-effectively recoverable reserves. For this reason, the development of the discounted cash flow (DCF) method for economic evaluation of oil and gas projects is required. The purpose of the study was to develop a methodological approach to the economic evaluation of oil and gas projects. The disadvantages of the DCF model in the economic evaluation of oil and gas field development projects are analyzed, a comparative analysis of project evaluation methods through the use of binary and reverting discounting models is performed. The authors justified the choice of a risk-free discount rate for project outflows and dynamically changing values of discount rates for project cash inflows for the evaluation of oil and gas projects, taking into account their identified features. The application of the developed methodological approach, both at the pre-project phase and during the operation of the field, will allow oil and gas companies to justify the magnitude of commercially exploitable reserves and indicators of the economic efficiency of the project due to more correct risk accounting. The developed methodological approach has been approved on the example of the Novoportovskoye field development project.
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Cherepovitsyn, Alexey, Anna Tsvetkova und Nadejda Komendantova. „Approaches to Assessing the Strategic Sustainability of High-Risk Offshore Oil and Gas Projects“. Journal of Marine Science and Engineering 8, Nr. 12 (06.12.2020): 995. http://dx.doi.org/10.3390/jmse8120995.
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In the face of today’s global challenges, oil and gas companies must define long-term priorities and opportunities in implementing complex Arctic offshore projects, taking into account environmental, economic, technological and social aspects. In this regard, ensuring strategic sustainability is the basis for long-term development. The aim of the study is to analyze existing approaches to the concept of “strategic sustainability” of an offshore Arctic oil and gas project and to develop a methodological approach to assessing the strategic sustainability of offshore oil and gas projects. In the theoretical part of the study, the approaches to defining strategic sustainability were reviewed, and their classification was completed, and the most appropriate definition of strategic sustainability for an offshore oil and gas project was chosen. The method of hierarchy analysis was used for strategic sustainability assessment. Specific criteria have been proposed to reflect the technical, geological, investment, social and environmental characteristics important to the offshore oil and gas project. The strategic sustainability of 5 offshore oil and gas projects was analyzed using an expert survey as part of the hierarchy analysis method. Recommendations were made on the development of an offshore project management system to facilitate the emergence of new criteria and improve the quality of the strategic sustainability assessment of offshore projects in the Arctic.
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Bethune, Graeme. „Australian petroleum production and development 2018“. APPEA Journal 59, Nr. 2 (2019): 482. http://dx.doi.org/10.1071/aj18285.
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This Petroleum Exploration Society of Australia review looks in detail at the trends and highlights for oil and gas production and development both onshore and offshore Australia during 2018. Total petroleum production climbed strongly for the third consecutive year, driven by LNG. A highlight is the start-up of the INPEX Ichthys project. Production is set for further growth in 2019 with the ramp-up of this project and the start-up of Shell’s Prelude floating LNG project. Prelude and Ichthys are the last projects to be commissioned in a wave of seven new LNG projects that are making Australia the world’s largest LNG exporter and a crucial supplier of gas to Asia, including the largest source of LNG for Japan and China and the second-largest source for South Korea. By contrast, Australian oil production continued to fall rapidly and is now easily surpassed by rising condensate production from new LNG projects. There were stark contrasts between domestic gas on the west and east coasts. On the west coast, prices remain low and supply relatively plentiful. The east coast domestic market was tighter and LNG producers responded by diverting gas supplies to the domestic market. This paper canvasses these trends and makes conclusions about the condition of the oil and gas industry in Australia. This paper relies primarily on production and reserves data compiled by EnergyQuest and published in its EnergyQuarterly reports.
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Nadrus, Inas, Valery Anshin und Igor Demkin. „One Method to Identify the Real Options in the Investment Project“. Scientific Research and Development. Russian Journal of Project Management 8, Nr. 3 (18.12.2019): 35–44. http://dx.doi.org/10.12737/2587-6279-2019-35-44.
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The present article describes a research that examines the sources of flexibility in the investment projects in the oil and gas industry using multiple case studies of several oil and gas projects. More precisely, the study is concerned with revealing uncertainties that give rise to real options. Ultimately, the methodology for real options identification in the exploration & development type of investment projects of the oil and gas industry is proposed. It is anticipated that the results might help to bring certain improvements into the existing managerial conception of using real options for investment project evaluation considering the specific nature of investment projects in the oil and gas industry.
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McMahon, Xavier T., und Jake D. Williams. „'Lawfare' in the oil and gas industry“. APPEA Journal 59, Nr. 2 (2019): 651. http://dx.doi.org/10.1071/aj18251.
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There is a growing concern within the resources industry about activists’ use of the legal system to disrupt and delay major projects. Currently, referred to by many as ‘lawfare’, the tactic is not new. However, recent challenges to high profile cases, such as the Adani Carmichael Coal Project, has brought renewed focus to the tactics being used by activists to further their agendas, and a perception at least that the risk to the industry is ever increasing. This paper looks at trends and novel developments in national and international environmental law, and considers what implications this may have for the development of oil and gas projects in Australia.
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������ und Igor Demkin. „Estimation of Company Participation Cost in International Oil & Gas Projects“. Russian Journal of Project Management 2, Nr. 1 (29.03.2013): 0. http://dx.doi.org/10.12737/280.
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The competition aggravation in the world oil and gas markets forces the companies to realize projects not only within the country, but also abroad for ensuring competitive advantage. When elaborating of strategies of development and investment programs the oil and gas companies face the need of cost estimation related to participation in international projects. In this article the methodology developed by authors of cost estimation related to participation in international oil and gas projects is presented. Approbation was carried out on the project of Wheatstone LNG production and supply. Application of research results will allow the oil and gas companies to carry out the efficiency assessment of participation in the international projects, and also to reduce time and to increase scientific validity of development of strategy and investment programs.
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Mohammed, Sani Damamisau. „Clean development mechanism and carbon emissions in Nigeria“. Sustainability Accounting, Management and Policy Journal 11, Nr. 3 (03.11.2019): 523–51. http://dx.doi.org/10.1108/sampj-05-2017-0041.
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Purpose Carbon emissions from gas flaring in the Nigerian oil and gas industry are both a national and international problem. Nigerian government policies to eliminate the problem 1960-2016 yielded little or no results. The Kyoto Protocol (KP) provides Clean Development Mechanism (CDM) as an international market-based mechanism to reducing global carbon emissions. Therefore, the purpose of this paper is to analytically highlight the potentials of CDM in eliminating carbon emissions in the Nigerian oil and gas industry. Design/methodology/approach This paper reviewed the historical background of Kyoto protocol, Nigerian Government policies to eliminating gas flaring in its oil and gas industry 1960-2016 and CDM projects in the industry. The effectiveness of the policies and CDM projects towards ending this problem were descriptively analysed. Findings Government policies towards eliminating gas flaring with its attendant carbon emissions appeared not to be yielding the desired results. However, projects registered under CDM in the industry looks effective in ending the problem. Research limitations/implications Therefore, the success recorded by CDM projects has the policy implication of encouraging Nigeria to engage on establishing more CDM projects that ostensibly proved effective in reducing CO2 emissions through gas flaring reductions in its oil and gas industry. Apparent effectiveness of studied CDM should provide a way forward for the country in eliminating gas flaring in its oil and gas industry which is also a global menace. Nigeria could achieve this by providing all needed facilitation to realising more CDM investments. Practical implications CDM as a policy has proved effective in eliminating gas flaring in the Nigerian oil and gas industry. The government should adopt this international policy to achieve more gas flaring reductions. Social implications Social problems of respiratory diseases, water pollution and food shortage among others due to gas flaring are persisting in oil and gas producing areas as government policies failed to end the problem. CDM projects in the industry have proved effective in eliminating the problem, thus improving the social welfare of the people and ensuring sustainable development. Originality/value The paper analysed the effectiveness of Nigerian Government policies and an international market-based mechanism towards ending gas flaring in its oil and gas industry.
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Henzell, Steve, und Steve Cooper. „2014 PESA production and development review“. APPEA Journal 55, Nr. 1 (2015): 177. http://dx.doi.org/10.1071/aj14013.
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2014 was the penultimate year for many of the massive multi-year LNG development projects. These projects will lift Australia’s LNG capacity by more than 250% from present levels. The first train of the Queensland Curtis LNG project came on-line in late 2014. Exports are expected to commence from a further three LNG projects (APLNG, Gladstone LNG and Gorgon) in 2015. The ramp-up in gas demand on the east coast of Australia is spurring secondary development. A pipeline link has been proposed from the NT’s gas transmission system to connect to the east coast gas transmission system to allow gas from the Timor Sea to be fed into the east coast market and to the Queensland LNG projects. 2014 was a quiet year for new oil developments. Offshore, the Balnaves FPSO development was brought on-line. Onshore, the operators of the Cooper western flank continued to discover and develop a series of small fields. These small developments and better performance from some existing fields were able to offset natural reservoir decline elsewhere, leading to an overall increase in crude oil production of approximately 4% from the previous year. The second half of 2014 was characterised by a decline in crude oil price from more than $100/BBL to under $60/BBL by year-end. For many LNG contracts, LNG price is linked to oil price; existing LNG developments are well progressed and are unlikely to be curtailed by the low commodity price, but future developments are already being slowed or stopped.
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Sakata, Nobuyuki. „Gas field development projects of Nippon Oil Exploration.“ Journal of the Japanese Association for Petroleum Technology 66, Nr. 2 (2001): 141–50. http://dx.doi.org/10.3720/japt.66.141.
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������, Aleksandr Senko, ������ und Valeriy Funtov. „Oil and Gas Asset and Project Management in Russia“. Russian Journal of Project Management 3, Nr. 1 (10.03.2014): 17–25. http://dx.doi.org/10.12737/2664.
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Resources of the majority of oil and gas companies in Russia are managed within functional organizational structure. Thereof productivity and management efficiency depends a little on needs of a company for use and development of an oil and gas field and its infrastructure. In some industry enterprises a project management is used. The analysis of project management in such companies, as TNK-BP, LUKOIL Overseas, Rosneft, Gazprom dobycha Yamburg, Gazprom dobycha Noyabrsk was made. It is offered to use a complex of 2 models for oil and gas enterprise management. The first model has to be based on concept of oil and gas asset, the second one has to use a project management methodology. A new definition for the term "Oil and Gas Asset" is entered. The oil and gas asset is one or several fields with integrated economy, production, auxiliary and transport infrastructure, grouped according to their development logic. The oil and gas asset has its own life cycle consisting of stages and including life cycles of fields entering in the asset. Life cycle�s stages are filled both traditional (operational) activity, and design (projects� programs and projects themselves). Management of an oil and gas asset is impossible without application of one-man management principle. A project, as well as an asset has to be managed by one owner � manager or administrator (depending on powers and responsibility delegated to him). For development, elaboration and support of fields and their infrastructure (i. e. that activity which is difficult to operate in functional organizational structures) it is offered to apply the project management methodology. A multilevel project management model, as well as examples of projects� type design practice, and structures of decomposition of their works have been presented in this paper. The specified models were applied to development and deployment of mana gement�s corporate systems in OAO Tomskgazprom and OOO Gazprom transgaz Tomsk. Systems apply complex integration approach to a problem of coordinated management of fields and other assets and resources related to the oil and gas company.
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Tsiglianu, Pavel, Natalia Romasheva und Artem Nenko. „Conceptual Management Framework for Oil and Gas Engineering Project Implementation“. Resources 12, Nr. 6 (25.05.2023): 64. http://dx.doi.org/10.3390/resources12060064.
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More than half of the global demand for energy resources is covered today by oil and natural gas, and according to various forecasts, it is expected to grow 1.5–2 times greater over the next 30–50 years. This creates serious prospects for the development of the national oil and gas sectors of various countries, including Russia. Modern industry challenges create significant restrictions for the development of Russian oil and gas resources, and considering their predominant technological nature, the key solution is the increase in internal technological potential, in particular through the implementation of engineering projects aimed at creating the necessary technological solutions. This article presents an approach to the development of a conceptual management framework that will allow for the effective implementation of oil and gas engineering projects. The methodology of the research includes desk studies, systematization, the expert method (including interviews and questionnaires), grouping, generalization, and algorithm design techniques. The results of the study showed that effective implementation of engineering projects should be based on a systematic management approach, one of which is the TRA process. This article analyzes the TRA methods, on the basis of which key project readiness indicators are identified. Based on a literature review and the expert method, the relevant readiness indicators necessary for the assessment of oil and gas engineering projects are substantiated. Given these indicators, the authors proposed a framework for a comprehensive readiness assessment of oil and gas engineering projects and developed an algorithm for management decision-making on project implementation.
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MacGinley, James, und Brad Calleja. „Financing alternatives in a changing gas landscape“. APPEA Journal 54, Nr. 2 (2014): 516. http://dx.doi.org/10.1071/aj13089.
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In recent years, Australia has gone through an unprecedented expansion in its oil and gas industry. The demand for capital has been enormous and has resulted in some of the largest project debt financings globally. In the coming years, the funding requirement will change dramatically as projects reach completion; become cash-flow positive; and, owners changing their funding structure from project finance debt to lower cost, lower covenant corporate debt. The development of a number of Australia’s largest oil and gas projects during the past five years coincided with a tightening of capital from the traditional project finance market. This lead to the emergence of export credit agency financing as an integral component of project development. During the past year, however, re-capitalisation of global banks are now re-entering the Australian market and are driving competition and increasing liquidity. This extended abstract covers a review of the funding approaches taken on major Australian LNG projects, including lessons from the funding of CSG projects that may be relevant to other new development markets such as shale gas. It also draws on historical lessons of funding new technologies and provide insight about funding of the next wave of LNG development: floating LNG. The National Australia Bank is one of the largest resources project finance banks globally and is well positioned to provide APPEA’s delegates with relevant insight about the future of debt funding in the oil and gas industry.
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Ogwang, Tom, und Frank Vanclay. „Social Impacts of Land Acquisition for Oil and Gas Development in Uganda“. Land 8, Nr. 7 (08.07.2019): 109. http://dx.doi.org/10.3390/land8070109.
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Uganda’s oil and gas sector has transitioned from the exploration phase to the development phase in preparation for oil production (the operations phase). The extraction, processing, and distribution of oil require a great deal of infrastructure, which demands considerable acquisition of land from communities surrounding project sites. Here, we examine the social impacts of project land acquisition associated with oil production in the Albertine Graben region of Uganda. We specifically consider five major oil related projects that have or will displace people, and we discuss the consequences of this actual or future displacement on the lives and livelihoods of local people. The projects are: Tilenga; Kingfisher; the East African Crude Oil Pipeline; the Kabaale Industrial Park; and the Hoima–Kampala Petroleum Products Pipeline. Our findings reveal both positive and negative outcomes for local communities. People with qualifications have benefited or will benefit from the job opportunities arising from the projects and from the much-needed infrastructure (i.e., roads, health centres, airport) that has been or will be built. However, many people have been displaced, causing food insecurity, the disintegration of social and cultural cohesion, and reduced access to social services. The influx of immigrants has increased tensions because of increasing competition for jobs. Crime and social issues such as prostitution have also increased and are expected to increase.
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Kazanin, Aleksey G. „Strategic management challenges in the development of Arctic oil and gas fields“. Север и рынок: формирование экономического порядка 26, Nr. 4/2023 (19.12.2023): 7–18. http://dx.doi.org/10.37614/2220-802x.4.2023.82.001.
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The current development of hydrocarbon fields in the Arctic necessitates innovation-driven solutions regarding technology and management. While extensive production experience exists in onshore projects, the complexities of offshore hydrocarbon fields, such as limited access and underdeveloped infrastructure, demand strategic decisions in an unstable market environment. Long-term in nature, these decisions require a comprehensive application of strategic management methods and tools. The irreversibility of economic processes associated with substantial investments and the potential for major financial losses in project failure underscore the importance of employing strategic management methodologies. Global factors such as fluctuating oil prices, geopolitical challenges, the rise of green energy, and heightened corporate social responsibility expectations in the oil and gas sector necessitate a reevaluation of fundamental principles in strategic management systems. This study employs logical and general research methods to classify and synthesize relevant literature, identifying strategic management issues and evolving principles and approaches in strategy formulation. Technical and economic aspects of project implementation onshore and offshore are highlighted. The article argues for the revision of strategic management principles in Arctic oil and gas projects, particularly in offshore field development. Conceptual models of functional strategies for business units implementing onshore and offshore projects are proposed.
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Cullen, Frankie. „Production and development across Australia 2016“. APPEA Journal 57, Nr. 2 (2017): 363. http://dx.doi.org/10.1071/aj16258.
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In 2016, sustained depressed and volatile oil prices led companies to continue cost reduction strategies. Proposed developments have seen delays and reductions in scope as a result. Australian oil production declined by around 10%. However, new and continued liquefied natural gas (LNG) production bolstered both Australian and global gas supply. Australia was the strongest contributor to global LNG growth in 2016, showing the biggest year-on-year increase. In the first half of 2016, 20% of global LNG came from Australia, second only to Qatar with 29% of the market share. Australia remains on track to become the world’s largest LNG producer in the next 3–5 years. 2016 saw the start-up of Gorgon LNG in March, the first of Chevron’s two North West Shelf LNG projects and the third of several producing, developing and proposed LNG projects within the North Carnarvon Basin – already Australia’s most prolific producing basin. On the east coast, development of the coalbed methane (CBM) to LNG projects continued with an additional train brought onstream at each of the Origin/ConocoPhillips-operated APLNG Project and Santos’ GLNG Project. This further increased production in the Bowen–Surat Basins and drove discussions around the ability of east coast gas to meet both the demands of the LNG projects and ensure continued domestic gas reliability. Additional gas may be required for both, opening opportunities for production from other basins. Gas production continues to drive the Australian industry, with substantial inputs from LNG and unconventional operations. The next phase, in all sectors, will be key to Australia’s future in the global energy market. Will it be able to overcome the expected challenges of global oversupply, continued price volatility and domestic reliability concerns to fulfil its potential?
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Romasheva, Natalia, und Diana Dmitrieva. „Energy Resources Exploitation in the Russian Arctic: Challenges and Prospects for the Sustainable Development of the Ecosystem“. Energies 14, Nr. 24 (09.12.2021): 8300. http://dx.doi.org/10.3390/en14248300.
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According to the forecasts made by IEA, BP, and Total in early 2021, the demand for hydrocarbons will continue for decades, and their share in the global energy balance will remain significant. Russia, as a key player in the energy market, is interested in maintaining and increasing hydrocarbon production, so further exploitation of the Arctic energy resources is an urgent issue. A large number of onshore oil and gas projects have been successfully implemented in the Arctic since the 1930s, while recently, special attention has been paid to the offshore energy resources and implementation of natural gas liquefaction projects. However, the implementation of oil and gas projects in the Arctic is characterized by a negative impact on the environment, which leads to a violation of the ecological balance in the Arctic, and affects the stability of its ecosystem, which is one of the most vulnerable ecosystems on the planet. The main goal of the present study is to understand how the implementation of oil and gas projects in the Arctic affects the ecosystem, to assess the significance of this process, and to find out what the state and business could do to minimize it. In the article, the authors analyze energy trends, provide brief information about important oil and gas projects being implemented in the Arctic region of Russia, and investigate the challenges of the oil and gas projects’ development and its negative impacts on the Arctic environment. The main contributions of this paper are the identification of all possible environmental risks and processes accompanying oil and gas production, and its qualitative analysis and recommendations for the state and business to reduce the negative impact of oil and gas projects on the Arctic ecosystem. The research methodology includes desk studies, risk management tools (such as risk analysis, registers, and maps), brainstorming, the expert method, systematization, comparative analysis, generalization, and grouping.
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Dziublo, Aleksandr. „Hazardous natural processes and risks at offshore fields development with the use of subsea production of hydrocarbons (In English).“ Izvestiya vysshikh uchebnykh zavedenii Gornyi zhurnal 1, Nr. 8 (21.12.2020): 5–13. http://dx.doi.org/10.21440/0536-1028-2020-8-5-13.
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Introduction. The article considers the main risks (technological, geological, societal and environmental) of offshore fields development, facilities construction and exploitation with the use of subsea production of hydrocarbons. Research aim is to analyze the main risks of offshore oil and gas projects implementation, which are associated with harsh natural and climatic conditions of the Sakhalin Island shelf, their impact on subsea facilities and to develop the remedial measures for the risks. Methodology. Risk analysis made it possible to identify the main risk factors in offshore projects development and determine remedial measures that are high-priority in offshore field exploitation at the stage of design and, most importantly, at the stage of project implementation. Analysis and discussion. Based on actual data of large oil and gas fields development, an in-depth analysis of the main risks associated with the climatic conditions on the Sakhalin shelf has shown that the region’s main geological risks are: seismicity, surface gas, seabed gouging by ice and soil liquefaction. Therefore, it is necessary to use modern environmentally sound technologies of subsea oil and gas production, which are based on successfully implemented projects abroad and the experience of shelf fields development in Russian. Conclusion. Effective development of oil and gas fields on the Sakhalin shelf is possible only if in the course of project implementation the geological, technological, societal and environmental risks are taken into account and controlled based on the developed remedial measures.
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Keith, Joe. „Australia petroleum production and development – 2020“. APPEA Journal 61, Nr. 2 (2021): 341. http://dx.doi.org/10.1071/aj21007.
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This Petroleum Exploration Society of Australia review considers the production and development of oil and gas in Australia over the year 2020. In a challenging year, which included commodity price wars and severe global impacts felt from the coronavirus disease 2019 (COVID-19), the Australian industry continued to produce high gas volumes due to sustained liquefied natural gas (LNG) output, and minimal decreases were seen in liquids production. Development approvals for large offshore projects did not materialise as expected in 2020 as operators reduced capital spend and focused on portfolio management in a year when oil prices fell by around USD 45bbl. Critically, all major projects with an financial investment decision (FID) target of 2020/21 were not cancelled, but development decisions were instead deferred. By the end of 2020, domestic-focused gas projects continued to be pursued for development with a target to support the declining resources for the Australian east coast domestic gas market.
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O’Brien, James Patrick, und Patrick S. McCaffrey. „Development of API Selection and Training Guidelines for in situ Burning Personnel“. International Oil Spill Conference Proceedings 2017, Nr. 1 (01.05.2017): 403–18. http://dx.doi.org/10.7901/2169-3358-2017.1.403.
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ABSTRACT Guidance for in situ burning of oil spills has been developed under the auspices of the Joint Industry Oil Spill Preparedness and Response (OSPR) Task Force (JITF) and the American Petroleum Institute (API), Oil Spill, Emergency Preparedness & Response Subcommittee (OSEPR). These groups convened to evaluate the procedures and lessons learned during the Deepwater Horizon oil spill response. The initial focus was to identify potential opportunities for improvement to the oil spill response system. One of the categories addressed by the JITF and OSEPR was in situ burning of spilled oil. Within this category a number of projects were identified to be worked on by individual project teams. One of those projects was to develop selection and training guidance for oil spill responders to in situ burns. Consequently, a project team was formed of volunteers representing the oil and gas industry, federal and state government, subject matter experts, oil spill response organizations and manufacturers of relevant equipment.
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Magaev, Nikolay A., Gagik M. Mkrtchyan und Larisa V. Skopina. „Real Options Valuation of Deposits“. World of Economics and Management 19, Nr. 2 (2019): 31–48. http://dx.doi.org/10.25205/2542-0429-2019-19-2-31-48.
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Income approach based on the method of discounted cash flows (DCF) seems to be the main instrument to evaluate economic efficiency of investment projects when developing oil and gas fields. However, at early stages of exploration and exploitation of hydrocarbon resources, uncertainty and risks of investors are very high, which limits the use of traditional methods. It is necessary to develop valuation tools accounting high uncertainty of input data on the exploitation of oil and natural gas resources, flexibility of their development by formation of rational production strategy with volatility of the operating parameters such as the world oil prices and the size and value of oil and gas reserves. In this article presents the real options approach which accounts the potential of flexible and adaptive project management providing advantages in assessing development projects as compared to the traditional income methods. Implementation of this method is exemplified by the case of oil and gas fields in the east of the Siberian platform.
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Bogatyrev, M. I., O. S. Kirichenko, Yu A. Nazarova, I. M. Nikonov und N. S. Shcherbakova. „Determining the discount rate for complex investment projects in oil and gas industry“. Lomonosov Economics Journal 59, Nr. 1 (2024): 171–86. http://dx.doi.org/10.55959/msu0130-0105-6-59-1-8.
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In the investment programs of modern oil and gas companies (i.e., PJSC Lukoil Oil Company, PJSC Gazprom, PJSC Novatek), complex projects are gaining more and more attention, and in this case the efficiency for an investor should be assessed in terms of the overall effectiveness of projects. As an object of research, the authors consider a set of projects for the types of gas production and transportation activities. This paper studies the question of finding a discount rate with a focus on specific features of oil and gas industry. The relevance of the chosen topic is determined by the need to find a balanced rate of return of a complex investment project for inclusion in the investment portfolio of an oil and gas company. When evaluating the economic efficiency of complex projects that include subprojects of various types, such as mining or transportation, the discount rate of the entire project should be in balance with the regulatory rates for the types of activities presented in the project. In their work, the authors, drawing on the analysis of the formulas of the mathematical apparatus for calculating complex discount rate, propose a variant of calculating the internal rate of return (IRR) for a group of projects for which there is a formed level of normative values of IRR. The article is designed within the framework of economic research methods. The analysis of scientific literature and the comparative approach are combined with the use of methods of economic and mathematical modeling. The theoretical significance of the study consists in the description of the main postulates related to the analysis of profitability of investment projects in oil and gas industry. The practical significance lies in the development of approaches to determining the discount rate when assessing the economic efficiency of complex high-risk projects on the example of gas industry and the possibility of using these approaches in investment and strategic analysis of oil and gas companies.
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Sebire, Tamara. „PESA 2010 production and development review“. APPEA Journal 51, Nr. 1 (2011): 167. http://dx.doi.org/10.1071/aj10011.
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2010 was another busy year for Australian hydrocarbon production and development. Natural gas production was the standout performer with both domestic gas and LNG production increasing by about 5% compared to 2009. Domestic gas output was strong with significant growth in production from the Gippsland Basin, coal seam methane in the Surat-Bowen Basin, and the start-up of the Blacktip gas project in WA. Domestic gas output is set to reach record levels again next year and has strong growth prospects in the future with final investment decisions being taken on coal seam gas projects in Queensland and the Macedon project in WA. Australian LNG production increased 4.5% in 2010 accounting for 34% of Australian hydrocarbon production. LNG production will grow further in 2011 with first gas expected from Pluto LNG project during the year. Oil production was steady in 2010; however, it is set to increase in 2011 with a full year of production from the Van Gogh and Pyrenees projects. Production levels only tell part of the Australian hydrocarbon story. In addition to the proposed domestic gas and oil projects, the combined value of committed and potential LNG projects in Australia has surpassed $100 billion. A highlight of 2010 was the final investment decision on the A$15 bn Queensland Curtis LNG Project (QCLNG). The first phase of QCLNG will consist of two LNG trains with a combined capacity of 8.5 million tonnes per annum, with first LNG exports expected in 2014. QCLNG is the first of many proposed coal seam gas to LNG (CSG-LNG) developments in Queensland. Other CSG-LNG projects reached significant milestones this year. Of particular note is the federal environmental approval of Gladstone LNG and state environmental approval of Australia Pacific LNG. In WA, the Browse LNG project complied with all Browse Basin retention lease conditions and remains on track for a targeted final investment decision in 2012. Other major LNG projects including Ichthys and Wheatstone also continue to make positive progress towards a final investment decision in the next 24 months. Sunrise, Prelude and Bonaparte LNG set a technology milestone in the industry with all three selecting floating LNG (FLNG) as their preferred development concept. 2010 has also seen the emergence of further new technologies in the form of small scale LNG projects for resources previously considered un-commercial. This has opened the door for South Australia and New South Wales to enter the LNG export market in the future. The Australian hydrocarbon industry continues to grow and its global importance, particularly in LNG, reflected by the increasing number of foreign companies entering Australia. In 2010, Shell and PetroChina increased their involvement in the Australian industry purchasing Arrow Energy for A$3.5 bn. CNOOC has increased its involvement in a number of areas, including purchasing a 5–10% stake in QCLNG and investment in CSM exploration through Exoma Energy. GDF Suez and Total have reinvigorated their interests in offshore WA and Petrobras made their first entry into Australia acquiring an interest in exploration acreage offshore WA. 2010 was an active year for Australian hydrocarbon production and development–continued success depends on the successful execution of committed and proposed projects. Escalation of development costs and a looming skills shortage remain the largest risks to the Australian hydrocarbon industry as multiple projects attempt to move forward simultaneously.
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Mohd Said, Naqiyatul Amirah, Nur Emma Mustaffa und Hamizah Liyana Tajul Ariffin. „Integrating Cloud in Engineering, Procurement and Construction Contract“. Journal of Computational and Theoretical Nanoscience 17, Nr. 2 (01.02.2020): 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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Williams, Adrian, und Dave Macey. „HARRIET GAS GATHERING PROJECT, BARROW SUB-BASIN“. APPEA Journal 32, Nr. 1 (1992): 56. http://dx.doi.org/10.1071/aj91006.
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Since start-up of Harriet oil production in early 1986, the TL/1 joint venturers have attempted to find a use for the oil-associated gas as well as other gas from neighbouring small gas fields. Initially, supplies from the North West Shelf Project were well in excess of local demand and acted as a damper on new development projects. With time, however, gas reserves in the Harriet area were augmented through new discoveries and the State's demand grew steadily until, in mid 1990, a new project could be justified. In December 1990, an agreement was reached with the State Energy Commission of Western Australia (SECWA) for the supply of 140 PJ (123 BCF) of gas over a ten year period, with an option for a further 65 PJ (57 BCF). First gas supplies are planned for June 1992.The project is based on the supply of Harriet solution gas as well as free gas from the Campbell, Sinbad and Rosette fields. Bambra is a potential future addition but is not required initially for the contract.The project involves small offshore platforms at Campbell and Sinbad, a wet gas pipeline from these platforms to Varanus Island, a facility on the Island to dry the gas and boost the pressure, and a transmission line to SECWA's system, approximately 100 km distant.The transmission pipeline has considerable reserve capacity over the initial contract flowrate of 30 to 60 TJ/day (26 to 52 MMCFGD) and provides a basis for further small gas projects utilising either flare gas from new oil developments or new gas field developments.
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Komarova, Anna V., und Irina V. Filimonova. „INFLUENCE OF INSTITUTIONAL TRANSFORMATIONS ON THE EFFICIENCY OF OIL AND GAS PROJECTS IN THE ARCTIC“. Interexpo GEO-Siberia 3, Nr. 1 (08.07.2020): 96–103. http://dx.doi.org/10.33764/2618-981x-2020-3-1-96-103.
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In the near future, a number of bills regarding the promotion of investment activity in the Arctic will be enacted. At the same time, some of them are aimed at increasing the attractiveness of oil and gas projects in this territory. Thus, the already established taxation system for the oil and gas sector in this region will be changed. However, questions remain about assessing the effectiveness of the current and future tax system. The purpose of the article is to assess the effectiveness of the implementation of oil and gas projects in the Arctic regions, taking into account the current institutional environment. The article uses methods of geological and economic assessment of a typical oil-bearing object in the Khatanga-Lena zone, which covers the northern regions of the Republic of Sakha (Yakutia). As a result of the calculations, the effectiveness of the project was evaluated, the high sensitivity of the performance indicators from oil prices was revealed, and the minimum level of market indicators for the development of oil and gas potential was assessed. Further formation of comprehensive measures is necessary for the successful development of the region. A distinctive feature of the study is the evaluation of projects in accordance with the new tax regime of the industry, as well as a comprehensive analysis of the region’s resource base and institutional reforms.
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Raydugin, Yuri. „Quantifying Unknown Unknowns in an Oil and Gas Capital Project“. International Journal of Risk and Contingency Management 1, Nr. 2 (April 2012): 29–42. http://dx.doi.org/10.4018/ijrcm.2012040103.
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Projects continue to fail at a high rate despite the well-known risk benchmarks published decades ago. Risk assessment and contingency planning are needed in oil and gas (O&G) capital projects because of many ‘unknown unknowns.’ Uncertainty must be estimated for the project schedule as well as for investment costs. Quantitative estimates and diagramming tools can assist in understanding and communicating project risk levels. This paper outlines and applies a method for quantifying unknown unknowns in the O&G industry based on a case study. Four dimensions of unknown unknowns are discussed: novelty of a project, phase of project development, type of industry, and bias. Uncertainty is classified as unknown unknowns, bias, known unknowns, and corporate risks. Practical recommendations are made to quantify uncertainty using probabilistic risk models, and then to integrate these estimates into the budget and schedule.
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Quesnel, Raymond E. „A Review of the Canada Petroleum Resources Act and the Canada Oil and Gas Operations Act as the Legal Framework for Future Development in the Northwest Territories“. Alberta Law Review 40, Nr. 1 (01.05.2002): 83. http://dx.doi.org/10.29173/alr502.
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This article examines the current core legislation that governs oil and gas activity in Canada's North. While there has been increased industry interest in the Northwest Territories, there has thus far been a lack of actual oil and gas projects against which to measure the efficacy of the current regime in the context of northern development. An historical analysis of the legislative developments indicates that the northern regime formed the basis for the legislative framework now governing east coast megaprojects. The author evaluates the current basis on which rights are granted and recorded, the tenure system, the royalty regime, and the project approval process. He concludes that, while the northern regime is suitable for large scale developments, it may require certain changes to accommodate smaller, more conventional projects likely to be undertaken.
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Bethune, Graeme. „PESA PRODUCTION AND DEVELOPMENT REVIEW 2006“. APPEA Journal 47, Nr. 2 (2007): 657. http://dx.doi.org/10.1071/aj06058.
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The Australian petroleum industry is having considerable success in offsetting natural field decline through new developments in existing basins and projects in new basins. The industry is also having great success with less conventional coal seam methane production. In energy terms Australian petroleum production peaked in 2000, and then fell until 2003 due to falling oil production. Since then, and despite continuing falls in oil and liquids production, total production has been increasing towards the 2000 peak. In 2006 eight new developments came into production: Darwin LNG, three oil and four gas developments. Seven of these developments were in new basins. Looking to the future there are now more than 20 significant petroleum projects with a combined value of more than A$50 billion either committed or being considered. Between them these could significantly increase Australian production in the next five years, primarily through growing gas production. Replacing falling oil production remains a challenge, as does managing cost increases and skills shortages generally.
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Titova, Natalya Yur'evna. „Models of sustainable development of oil and gas companies in conditions of decarbonization: comparison of Russian and foreign experience“. Vestnik of Astrakhan State Technical University. Series: Economics 2023, Nr. 2 (28.06.2023): 54–62. http://dx.doi.org/10.24143/2073-5537-2023-2-54-62.
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The conducted bibliographic search revealed that the scientific articles have already raised the issues of sustainable development of oil and gas companies, including the implementation of sustainable development projects in the context of aggravated environmental agenda, as well as the contribution of oil and gas companies in achieving sustainable development goals. Foreign experience demonstrates that the models of sustainable development of oil and gas companies are formed pursuant to the territorial and country specifics. It has been stated that the study of companies in the Russian oil and gas sector in this aspect has not yet been reflected in scientific papers. The distribution of Russian oil and gas companies (PJSC NK Rosneft, PJSC Gazprom, PJSC Lukoil, PJSC Novatek, PJSC Tatneft) was carried out according to the selected UN priority sustainable development goals. There is set up the question of comparing the current model of sustainable development of Russian oil and gas sector companies with Asian, European and American models of development. There are presented the results of SWOT-analysis of measures of sustainable development reports of the largest oil and gas companies of the Russian Federation. As a result of the analysis the characteristics that allow comparing the Russian experience of sustainable development with foreign experience are identified. It has been inferred that in the context of the aggravated geopolitical situation Russian oil and gas companies should also focus on achieving the goals stated in the national projects of the Russian Federation.
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Cherepovitsyn, Alexey, Evgeniya Rutenko und Sergey Yudin. „Global challenges and opportunities for Arctic oil and gas projects“. E3S Web of Conferences 378 (2023): 06007. http://dx.doi.org/10.1051/e3sconf/202337806007.
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Integrated development of hydrocarbon potential is one of the high-priority tasks of the government of Russia policy in the Arctic region. When determining the prospects of oil and gas projects, it may be necessary to envisage ways of responding to large-scale changes in the global energy system, which significantly affect the timing, commercial and budgetary efficiency of project activities in the Arctic. The high level of turbulence creates new challenges for the Russian and global oil and gas complex associated with the strengthening of competition in traditional markets of hydrocarbon resources, the progressive development of technological innovation, and changes in the price environment. The main direction of development of the Arctic oil and gas sector should be quick adaptation to new conditions, reassessment of strategic planning systems of key market players, as well as a targeted state policy in relation to the formation of a favorable investment climate and flexible taxation system in the region. For the purpose of the study, an analysis of the factors of instability of the global energy system and their influence on the efficiency of operation of arctic hydrocarbon fields is conducted. The characteristics of the main directions of government policy in the Arctic zone, stimulating the production of hydrocarbons, are given. The potential limitations and opportunities for the implementation of oil and gas projects resulting from the transformation of the global raw materials market are identified and systematized.
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Muir, Wal. „2008 Production and development highlights“. APPEA Journal 49, Nr. 1 (2009): 541. http://dx.doi.org/10.1071/aj08036.
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Australian petroleum production reached record levels during 2008 due mainly to continued growth in gas production, particularly from coal seam gas in Queensland. Coal seam gas (CSG) has provided a major fillip to gas production in the east of the country, with four LNG projects slated for Curtin Island off Gladstone, and the Surat/Bowen Basin supplanting the Cooper Basin in gas production for the first time. Three new projects were brought on stream in the Carnarvon Basin, offsetting the projected natural decline of oil production in that basin. The pipeline of committed and planned projects continues to rise, with a number of major projects in the Carnarvon Basin moving closer to fruition and the Browse Basin likely to join the Carnarvon as a major LNG producer in the medium term. The impact of the global financial crisis, with a large number of countries which take Australia’s energy production in recession, is still being assessed. It appears that there may be a softening in costs, although the trends were not yet clear at year’s end.
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Здольник, Daria Zdolnik, Тищенко, Olga Tishchenko, Тищенко und Nazar Tishchenko. „Resistance to Sustainability Innovations in the Oil and Gas Sphere“. Russian Journal of Project Management 6, Nr. 2 (18.07.2017): 31–36. http://dx.doi.org/10.12737/article_595f76094653f3.91663060.
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The article analyzes the main causes of resistance to the principles of the sustainable development concept as the results of the research in the oil company "Bashneft". In addition, the article describes the main risks of the industry, which led to changes in strategy and, as a consequence, changes in project portfolio, including sustainable development projects. There is also a system of the implementation management of the changes related to the sustainable development concept developed and the main methods of combating and preventing resistance identified in the article.
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Imamov, R. R. „DEVELOPMENT OF RISK ASSESSMENT METHODS IN THE IMPLEMENTATION OF EXPLORATION PROJECTS“. Strategic decisions and risk management 14, Nr. 3 (26.03.2024): 256–61. http://dx.doi.org/10.17747/2618-947x-2023-3-256-261.
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The peculiarity of oil and gas projects is their long implementation period, during which they are subject to the influence of a large number of different risk factors that complicate project implementation and result in failure to achieve the planned economic indicators set by investors. The effective operation of companies therefore depends on how reliably investors can predict the prospects for project development. The success of the subsequent functioning of the investment project depends to a large extent on the reliability of the assessment of the effectiveness of the investment project, based on the optimally chosen strategy of its development, and, above all, on the anticipation of possible risk factors and tools for their prevention. Therefore, at present, the competitive struggle in the oil and gas production industry is currently shifting to the area of pre-project preparation of investment projects and increasing the reliability (quality) of their economic efficiency assessment at the stage of making a decision to start their implementation.Geological risks become important in the implementation of exploration projects, the first stage in the overall process of developing the Company's assets. It is necessary to find a balance between the cost of project implementation and the amount of accumulated hydrocarbons for the forecast period, which will ensure maximum profitability of the project. The challenge to optimize the financial outlay on the implementation of geological exploration works by focusing on the most promising and important projects for companies becomes relevant. In this regard, the article considers the methodological approaches proposed by the author to assess the risks of exploration with the aim of improving the efficiency of the planning process and reducing inefficient financial costs.
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Balashov, A. M. „Impact of sanctions on business development of oil and gas corporations in Russia“. Mining Industry Journal (Gornay Promishlennost), Nr. 3/2022 (01.07.2022): 74–78. http://dx.doi.org/10.30686/1609-9192-2022-3-74-78.
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The Russian economy is currently subjected to unprecedented sanctions pressure from the United States and the Western countries. Supply of innovative equipment that is necessary for oil and gas production in the Arctic shelf and other hardtorecover fields to Russia is banned. International consortiums that were involved in large investment projects related to the extraction and transportation of oil from hard-to-recover fields terminated their cooperation with Russian oil and gas companies. However, the European and American companies are being replaced by Chinese corporations, which also have the necessary technologies and equipment for oil and gas production in hard-to-recover fields. It should also be noted that the European Union plans to reduce the volume of natural gas supplied from the Russian Federation and to build new terminals for the imported LNG, and has already abandoned the project to pump gas through the Nord Stream-2 pipeline. In response to these Western initiatives, the Russian authorities are likely to undertake a number of steps to re-route the natural gas supplies to China and build a gas pipeline to India. In this article, the author made an attempt to analyze from the scientific point of view and critically re-evaluate the issues of the sanctions impact on the development of business activities of oil and gas corporations in Russia.
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Bitner-Gregersen, E. M., J. Lereim, I. Monnier und R. Skjong. „Economic Risk Analysis of Offshore Projects“. Journal of Offshore Mechanics and Arctic Engineering 114, Nr. 3 (01.08.1992): 165–74. http://dx.doi.org/10.1115/1.2919968.
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A quantitative analysis of economic risk associated with large investments in offshore oil and gas field development and production is presented. The analysis is intended as a supporting tool in decision-making faced with uncertainty and risk, to study the effect of alternative decisions in an easy manner. The descriptors for the project assessment, such as the Internal Rate of Return (IRR) and Net Present Value (NPV) are applied. The study demonstrates first the impacts of early pilot production (EPP) prior to a main oil field development on the field economy of an oil field development and production installation. Furthermore, the result of cases which reflect relevant situations connected with cost overruns are presented, as well as derivation of rational decision criteria for termination/continuation of a project subjected to cost overruns. Finally, an oil field development project scheduling is demonstrated.
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Brown, D. J., und M. R. Barley. „TIRRAWARRA AND MOORARI ENHANCED OIL RECOVERY PROJECTS—‘GETTING MORE OIL OUT FROM DOWN UNDER’“. APPEA Journal 26, Nr. 1 (1986): 389. http://dx.doi.org/10.1071/aj85033.
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The Tirrawarra and Moorari oilfields are located in the South Australian portion of the Cooper Basin. Production to date in the fields has been maintained primarily by infill drilling, with individual wells showing substantial declines in productivity. In the absence of an active aquifer, some form of pressure maintenance was required to arrest this productivity decline and increase recovery. The miscibility characteristics of the reservoir oil, the low rock permeability, and the availability of miscible injection gases made miscible gas flooding the preferred improved recovery process.In 1984 pilot gas injection floods were initiated in both the Tirrawarra and Moorari fields to test the effectiveness of pressure maintenance and the miscible process in the Tirrawarra Sandstone. Injection was initiated using the Tirrawarra Field non-associated Patchawarra Formation separator gas to defer the high facility costs associated with alternative injection gases.The results of the pilot injection programs have been most promising. Production has improved in most offset producing wells with no sign of early injection gas breakthrough. In 1986, expansion of the Tirrawarra pilot will complete development of a major portion of the Tirrawarra Field on inverted seven spot injection patterns. Ultimate development of the field for full scale injection may involve infill drilling and well conversions resulting in skewed five spot patterns. Three alternative injection gases are being considered: Patchawarra separator gas, carbon dioxide, and ethane, each of which show favourable miscibility characteristics with the Tirrawarra oil. The incremental oil recovery expected from the full development is 23 million stock tank barrels oil.
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Voronina, Elena P. „CONTOURS OF INTENSIFICATION OF SOCIO-ECONOMIC DEVELOPMENT OF THE ARCTIC REGIONS IN THE CONTEXT OF THE IMPLEMENTATION OF OIL AND GAS PROJECTS“. Economy of the North-West: problems and prospects of development 3, Nr. 74 (24.11.2023): 70–80. http://dx.doi.org/10.52897/2411-4588-2023-3-70-80.
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Oil and gas projects implemented in the Arctic zone of the Russian Federation are a strategic priority and their implementation should have important socio-economic significance in the development of regions. The article studies problems related to the impact of the implementation of oil and gas projects of the Arctic zone of the Russian Federation on the socio-economic development of regions, taking into account the transition to the domination of resource-innovative model of management, with priority given to social values. SWOT-analysis of implementation of arctic oil and gas projects is presented, strengths and weaknesses, opportunities and threats are identified and systematized, key criteria are analyzed, conditions of functioning and factors of influence on social and economic development of the arctic regions. Conclusions have been summarized and presented, measures have been proposed in the implementation of oil and gas projects in the interests of realization of priorities of socio-economic development. In order to solve these problems, the author substantiates the necessity of active state policy. The national interests of the Russian Federation in the arctic region require a systematic approach to the implementation of projects based on the principles: coherence of industrial and regional economy and environmental management, adaptive management, based on the integration of economic, innovative, social and environmental factors, taking into account well-defined and structured benchmarks.
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Ribeiro, Vinicius Farias, Ilana Zeitoune, Eduardo Flach und Fabiano Barboza. „Asset Sharing in Oil and Gas Production Development Projects in Brazil“. Rio Oil and Gas Expo and Conference 20, Nr. 2020 (01.12.2020): 93–94. http://dx.doi.org/10.48072/2525-7579.rog.2020.093.
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André, Djoï N., Nwosu I. Joseph und Ikiensikimama S. Sunday. „Central Limit Theorem-based Stochastic Economic Evaluation (CLT-SEE) Model for Evaluating Oil Wells: Case Study from Niger Delta, Nigeria“. European Journal of Engineering and Technology Research 8, Nr. 3 (04.05.2023): 8–16. http://dx.doi.org/10.24018/ejeng.2023.8.3.3033.
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Oil and natural gas production has been highly contributing to world economy and is some countries’ economy root. After the discovery of a new oil/gas field, the operator has to decide whether or not to develop that field. Such decisions rely on the economic evaluation of potential oil/gas fields development when they will be discovered and of the proven oil/gas reserves. The economic indicators used for that purpose are actually computed with deterministic and/or stochastic methods. Deterministic models show limitations while stochastic ones reduce the risks and doubts in the decision making. Stochastic models require the knowledge of the probability distribution of the model inputs, what is costeous in terms of software, data and conditions to be satisfied. Our study proposes a technique, called “Central Limit Theorem-based Stochastic Economic Evaluation (CLT-SEE) Model’’ that eases projects NPV probability distribution determination and the computation of P10, P50 and P90 of projects NPV, IRR and PI. A case study is carried out on a Nigerian’s Niger Delta onshore oil well. The results show the well NPV, IRR and PI are respectively MM$ 84.112, 24.5%, 1.169. The well project P10(NPV), P50(NPV) and P90(NPV) are respectively MM$ 96.4, MM$ 84.16 and MM$ 71.89; P10(IRR), P50(IRR) and P90(IRR) are respectively 27%, 24.75% and 22%; P10(PI), P50(PI) and P90(PI) are respectively 1.34, 1.17 and 1. These stochastic outputs show that the company has 90% of chance to earn at least MM$ 71.89 which is its investment and the likelihood that the project IRR be more than 22% is 0.9. As a result, the use of CLT-SEE model for oil wells economic evaluation offers much more chance and confidence to oil companies to decide righteously in field and well development projects.
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Evans, Ross, David Close, Brenton Richards und Rachael Ilett. „2015 PESA production and development review“. APPEA Journal 56, Nr. 1 (2016): 515. http://dx.doi.org/10.1071/aj15037.
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Low oil prices through 2015 challenged oil and gas operators to cut costs and minimise expenditure to survive the long cold winter of low pricing. Oil production decreased more than 10%—relative to 2014—to 128 mmboe for 2015. In 2015, natural gas production of 2,611 PJ was relatively consistent with 2014 production, with the exception of the Bowen and Surat basins, where production more than doubled to over 630 PJ. The primary driver for the increased Bowen and Surat basin output was the first full year of operation of QCLNG and, to a lesser extent, the startup of GLNG in the fourth quarter of 2015. The start-up of two major LNG operations in Queensland, followed by a third (APLNG) within the first weeks of 2016, is a transformational event for the eastern Australian gas market. As each of the projects has commenced exports during an extremely long—and therefore low-price—LNG market, there is intense market pressure on these projects to improve profitability through efficiency improvements and cost reductions. In contrast to Australia’s other LNG exporters, which are all fed by offshore conventional fields with relatively few wells, the Queensland projects have the opportunity to benefit from constant improvements to upstream operations as they continue to drill hundreds of wells to sustain the LNG operations. North American operators have continuously improved during the past decade of unconventional gas development and this provides a proof of concept that is encouraging for Australia’s aspirants. Effective cost reductions have already been announced by operators in Queensland; maintaining these reductions as the market improves will be critical to the success of the Queensland CSG to LNG projects, and expanding efficient and cost-effective operations to other onshore basins provides an opportunity for the Australian industry-at-large.
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BRODT, Luiza E. „Best Practices of Oil and Gas Companies to Develop Gas Fields on the Arctic Shelf“. Arctic and North, Nr. 44 (24.09.2021): 30–44. http://dx.doi.org/10.37482/issn2221-2698.2021.44.30.
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The development of the hydrocarbon potential of the Arctic shelf is one of the priority tasks for Russia, forming the conditions for its strategic presence in the region. Russia's official energy documents stipulate the need to increase oil and gas production in the Arctic, including offshore production, to ensure the stable operation of the country's oil and gas complex in the long term. However, the development of hydrocarbon fields on the Arctic shelf is a serious technological challenge for the domestic oil and gas in-dustry. While offshore oil production in the Russian Arctic is already underway, natural gas production remains a promising future target. The article analyses the current gas projects on the Arctic shelf in terms of their technological complexity and unique solutions, and the strategies of operators to attract foreign participants to the project. We consider these in the contexts of technological issues, organizational features, securing foreign investment. The author believes that the provisions and conclusions of this study will help add to the comprehensive picture of the foreign oil and gas companies experience engaged in natural gas production on the Arctic shelf, which will minimise the errors and risks in the development of hydrocarbon resources on the Russian Arctic seas shelf.
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Khlebnikov, V. N., N. V. Likhacheva, V. N. Dubinich, I. V. Khamidullina, V. A. Lyubimenko, I. N. Grishina, V. D. Stytsenko und V. I. Frolov. „Solving the Problem of Climate Change on the Planet. Possible Scenario for the Development of Gas and Oil Production in Russia“. Oil and Gas Technologies 138, Nr. 1 (2022): 3–9. http://dx.doi.org/10.32935/1815-2600-2022-138-1-3-9.
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A new scenario for the development of gas and oil production is proposed, based on the use of greenhouse gas sequestration projects that allow increasing the oil recovery coefficient of reservoirs depleted by flooding, ensuring the production of viscous, shale, and hard-to-recover oil, as well as starting the production of methane from its hydrates or from coal. The main idea of the article is that oil and gas production and sequestration of greenhouse gases are not antagonists. Reducing greenhouse gas emissions is possible through the use of natural gas, which is an environmentally friendly fuel. It is necessary to involve huge reserves of methane hydrate or coal methane in the development while using collectors for sequestration of CO2. To improve the economy of sequestration projects, it is proposed to abandon the simultaneous commissioning of the entire technological chain of greenhouse gas sequestration and the use (where possible) of a high degree of concentration; it is recommended to pump greenhouse gas in the form of a water-gas mixture with pumping and booster units; for sequestration, first of all, use reservoirs with hard-to-recover oil reserves.
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Shchegolkova, Asya A. „Spatial Organization of Gas Resources Development on the Arctic Shelf of the Russian Federation“. Arctic and North, Nr. 49 (22.12.2022): 86–104. http://dx.doi.org/10.37482/issn2221-2698.2022.49.86.
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Being strategic, the Arctic shelf is a region with an extremely low level of exploration. The undiscovered hydrocarbon resources on the Russian Arctic shelf exceed 90%. The long-term development of strategic programs and projects for the development of gas production on the shelf are constrained by insufficient technical accessibility of industrial development, as well as the difficulty of assessing the actual volume of initial potential oil and gas resources. The reproduction of free gas reserves has been assessed, the level of parity between production and growth of explored reserves has been determined. The state of the gas resources of the Arctic shelf was studied taking into account localization in oil and gas regions, which allowed to make a conclusion about the degree of exploration of the resource base and to identify the basis for the gas potential. The factors restraining the development of offshore projects were identified and analyzed. It was determined that offshore projects should be presented to investors with more attractive operational, technological and economic indicators than alternative onshore projects. The lack of tested methods for the development of hydrocarbons at superdeep depths under severe ice conditions does not allow to fully assessing the economic efficiency of offshore gas projects in the Arctic. It is concluded that within the resource base of Arctic offshore fields, it is necessary to allocate the static (probabilistic) potential of hydrocarbon resources of the Arctic region. The need to transform the Arctic foreign policy is identified.
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Downey, Peter, Jon Thomas und Mark Stone. „From initial advice statement to export – a 10 year retrospective of Queensland's liquefied natural gas industry“. APPEA Journal 59, Nr. 1 (2019): 58. http://dx.doi.org/10.1071/aj18070.
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A decade on from the submission of project initial advice statements to Queensland Government agencies in 2008, this paper provides a retrospective on the development journey of three integrated coal seam gas (CSG) to liquefied natural gas (LNG) mega-projects currently delivering domestic and international markets. The process from development concept to operating asset is considered from several perspectives including: project rationale, description and delivery, as well as regulatory approvals. Project delivery is further considered in terms of the upstream, midstream and downstream components. The delivery of world first CSG to LNG is discussed in the context of project execution during significant volatility in the global oil, gas and LNG markets. All three projects have successfully completed commissioning and start-up. Although all six trains have been performance tested at name-plate production capacity, current LNG production is below this level. This paper examines their evolution from the initial concepts through to delivery, including current gas reserves and those required to sustain gas supply over expected project life. The paper also considers how these projects and any future expansion of the Queensland LNG industry will be impacted upon by an evolving global LNG market.
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Ivanova, Mеdeya V. „Institutional aspects of tax regulation of Arctic oil and gas projects.“ Север и рынок: формирование экономического порядка 25, Nr. 2/2022 (27.06.2022): 97–106. http://dx.doi.org/10.37614/2220-802x.2.2022.76.008.
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The article presents the issues of tax regulation connected to the implementation of oil and gas projects in the Arctic region of Russia. Over the past decades, revenue from oil and gas have dominated the state budget and, as a following, the country's economy. Fiscal policy has evidently become one of the main regulators of support and development of this industry. Currently, the mineral extraction tax, export duty and additional income tax have become the main types of payments for the use of subsoil. Current trends of exploration and development of deposits have shifted towards the seas and oceans of the Arctic basin and facing new technical and legislative challenges. Significant differences in the conditions for the development of “Arctic” and “traditional” fields require a differentiated approach to tax regulation, in order to stimulate investment activity in the Arctic and improve the efficiency of oil and gas projects in the region. The study is built on elements of a functionalist institutional approach to the formation of tax relations and regulations between the state and businesses, representing the main Arctic players. The functionalist approach assumes that institutions reflect the interests of their creators. Any change in interests or conditions leads to the transformation of the institution, as evidenced by the permanent change in the rules of tax regulation in the fields of production and realization of oil and gas products. The purpose of the study was to monitor the tax regulation related to the development of the oil and gas business in the Arctic, which ensures the formation of a cargo base and an increase in the load on the Northern Sea Route. The first part of the study is devoted to the definition of special conditions for the implementation of projects in the Arctic region which determine the need for special tax regulation. The second part of the discussion considers the transformation of tax regulation of Arctic oil and gas projects in terms of mineral extraction tax and export duty. The study allows us to conclude that the state, being one of the key stakeholders, introduces tax incentives and creates favorable conditions for companies, taking on the risks of losing tax revenue. However, this approach opens up access to the oil and gas reserves of the Arctic region, the extraction of which was previously economically inefficient.
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Dello, Lou. „2011 PESA industry review: production and development“. APPEA Journal 52, Nr. 1 (2012): 89. http://dx.doi.org/10.1071/aj11007.
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2011 was a lacklustre year for Australian hydrocarbon production, however a stellar year for LNG development. Domestic gas production was flat despite two new gas developments, Reindeer/Devil Creek and Halyard/Spar, which came into production during the year. Oil production fell, primarily due to the redevelopment of North West Shelf oil facilities, with Kitan in the Timor Sea being the only new offshore oil field that commenced production. LNG production was also flat however, Final Investment Decisions (FID) were announced for five new LNG projects, including Ichthys early in 2012, bringing the combined value of all eight sanctioned LNG projects to more than $180 billion. This is a huge volume of development, not only for the industry but for the whole Australian economy. Importantly, it has also moved Australia closer to becoming the world’s largest LNG producer. Increasing development costs and competition for skilled labour still remain the biggest challenges for the industry. Introduction of the carbon tax was also an important development in 2011, marking a significant step towards a low-carbon economy and increasing the opportunity for natural gas, but also burdening trade-exposed industries like LNG. The success of unconventional gas in the United States and CSG in Australia has sparked a step-change in exploration and development of unconventional gas in onshore Australia. Consolidation in coal seam gas sector continued on the east coast with the two acquisitions of Eastern Star Gas by Santos and Bow Energy by Arrow Energy. Continuing to effectively engage with the community will be central to the industry’s success.