Bibliographies thématiques / Giant oil and gas discoveries

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Littérature scientifique sur le sujet « Giant oil and gas discoveries »

Auteur : Grafiati
Publié le 17 décembre 2022

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Articles de revues sur le sujet "Giant oil and gas discoveries"

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Arezki, Rabah, Valerie A. Ramey et Liugang Sheng. « News Shocks in Open Economies : Evidence from Giant Oil Discoveries* ». Quarterly Journal of Economics 132, no 1 (13 novembre 2016) : 103–55. http://dx.doi.org/10.1093/qje/qjw030.

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Abstract This article explores the effect of news shocks in open economies using worldwide giant oil and gas discoveries as a directly observable measure of news shocks about future output—the delay between a discovery and production is on average four to six years. We first analyze the effects of a discovery in a two-sector small open economy model with a resource sector. We then estimate the effects of giant oil and gas discoveries on a large panel of countries. Our empirical estimates are consistent with the predictions of the model. After an oil or gas discovery, the current account and saving rate decline for the first five years and then rise sharply during the ensuing years. Investment rises robustly soon after the news arrives, whereas GDP does not increase until after five years. Employment rates fall slightly and remain low for a sustained period.
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Harding, Torfinn, Radoslaw Stefanski et Gerhard Toews. « Boom Goes the Price : Giant Resource Discoveries and Real Exchange Rate Appreciation ». Economic Journal 130, no 630 (20 février 2020) : 1715–28. http://dx.doi.org/10.1093/ej/ueaa016.

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Abstract We estimate the effect of giant oil and gas discoveries on bilateral real exchange rates. A giant discovery with the value of 10% of a country’s GDP appreciates the real exchange rate by 1.5% within ten years following the discovery. The appreciation starts before production begins and the non-traded component of the real exchange rate drives the appreciation. Labour reallocates from the traded goods sector to the non-traded goods sector, leading to changes in labour productivity. These findings provide direct evidence on the channels central to the theories of the Dutch disease and the Balassa–Samuelson effect.
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Koning, Tako. « Giant and major-size oil and gas fields worldwide in basement reservoirs : state-of-the-art and future prospects ». Georesursy, Special issue (31 août 2020) : 40–48. http://dx.doi.org/10.18599/grs.2020.si.40-48.

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Oil and gas occurs in basement reservoirs in many parts of the world. The reserves of basement fields are as small as one or two million barrels of oil or gas-equivalent such as the Beruk Northeast pool in Sumatra, Indonesia to over 1.0 billion barrels of oil as in Viet Nam’s Bach Ho field and Libya’s Augila-Naafora field. This paper focuses on three giant-size oil and gas fields and six major-size fields. Exploration for oil and gas in basement has been remarkably successful in the past decade with important discoveries in basement in Indonesia, United Kingdom, Norway, Chad, and Argentina. In order to successfully develop basement oil and gas fields and also to avoid costly mistakes, all available geological, geophysical, reservoir engineering and economic data must be closely studied. Also, it is very important to study analogues worldwide of basement oil and gas fields in order to understand why some fields are very successful and others turn out to be technical and economic failures.
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Foster, M. T. Bradshaw C. B., M. E. Fellows et D. C. Rowland. « THE AUSTRALIAN SEARCH FOR PETROLEUM : PATTERNS OF DISCOVERY ». APPEA Journal 39, no 1 (1999) : 12. http://dx.doi.org/10.1071/aj98001.

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Three cycles of successful commercial hydrocarbon exploration and discovery have occurred in Australia since 1960, although sporadic efforts to locate oil accumulations have occurred since 1860. The first cycle of successful exploration, from 1960 to 1972, revealed most of the productive basins and all of the giant oil fields found to date. After an interval of very low drilling rates between 1973 and 1978, exploration activity returned to strong levels for a second cycle of discovery between 1978 and 1988. A third cycle commenced in 1989 when there was an increase in exploration activity and the number of hydrocarbon discoveries again, after a low point in the mid 1980s.The discovery of oil and gas fields is dependent on the rate of exploration activity, geological endowment, exploration efficiency and chance. Technology and geological knowledge influence exploration efficiency. The main driver of exploration activity is the profit motive, which is modified by government policies, oil price, markets, and perceived prospectivity. Discovery itself is a powerful stimulus to further exploration. Through the last 40 years these factors have varied in their impact on exploration and the resulting petroleum discoveries.
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Madon, Mazlan. « Five Decades Of Petroleum Exploration And Discovery In The Malay Basin (1968-2018) And Remaining Potential ». Bulletin Of The Geological Society Of Malaysia 72 (15 novembre 2021) : 63–88. http://dx.doi.org/10.7186/bgsm72202106.

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Since the first oil discovery in the Malay Basin in 1969, more than 700 exploratory wells have been drilled. To date, there are more than 181 oil and gas discoveries, about half of which are currently in production and about a dozen are already in their secondary or tertiary recovery stages. In 2014 it was estimated that a total of over 14.8 billion barrels of oil equivalent (bboe) of recoverable hydrocarbon resource have been discovered in the basin, contributing to approximately 40% of the total hydrocarbon resources of Malaysia. By the end of the first decade of exploration in 1979, all the major basin-centre anticlinal structures had been tested. This play type contributed 60% of the total discovered resource in the basin. By 1981 this most prolific play type had been practically exhausted, as all the giant fields (those with recoverable resource > 0.5 bboe) had been found. As “creaming” of the basin-centre anticlinal play continued into the early 1980s, exploration efforts gradually shifted to the newly discovered western margin play types, particularly in the Western Hinge Fault Zone, Tenggol Arch and the adjacent Penyu Basin. There was a “lull” period from 1985 to about 1990, due to the global oil crisis, after which exploration was rejuvenated through significant discoveries in several play types on the northeastern ramp margin. This followed a successful drilling campaign that lasted until around 1997 and contributed an additional ~1 bboe of recoverable resources over a seven-year period. Since then, most of the incremental resource addition came from the highly gas-charged play in northern region that comes under the Malaysia-Thai Joint Development Area (JDA) and on the northeastern ramp margin, which includes the Commercial Arrangement Area (CAA) between Malaysia and Vietnam. Individually, however, the hydrocarbon volumes in these later discoveries were relatively small compared to the earlier discovered play types. Subsequently, new play types were pursued, including stratigraphic channels, deeper reservoirs beneath existing fields, high pressure/high temperature (HPHT) reservoirs, overpressured and tight reservoirs, and fractured basement reservoirs. All had some measure of success but none were able to volumetrically match the discoveries made decades earlier. As of end of 2018, over 2100 exploration and development wells had been drilled in the entire basin. Based on the creaming curve, since around 1990 and into the fifth decade of exploration, the incremental resource addition has been increasing steadily at an average rate of ca. 120 MMboe per year. The data indicate that the expected average discovery size would be less than 25 MMboe, and that at least 5 wells need to be drilled per year to sustain the same rate of resource addition. If no new plays are explored and no significant discoveries made, resource addition is expected to plateau beyond 2020. The basin needs a new stimulus, and more importantly, new exploration play concepts to sustain exploration business.
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Dolson, John C., Mark V. Shann, Sayed I. Matbouly, Hussein Hammouda et Rashed M. Rashed. « Egypt in the Twenty-First Century : Petroleum Potential in Offshore Trends ». GeoArabia 6, no 2 (1 avril 2001) : 211–30. http://dx.doi.org/10.2113/geoarabia0602211.

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ABSTRACT Since the onshore discovery of oil in the Eastern Desert in 1886, the petroleum industry in Egypt has accumulated reserves of more than 15.5 billion barrels of oil equivalent. An understanding of the tectono-stratigraphic history of each major basin, combined with drilling history and field-size distributions, justifies the realization of the complete replacement of these reserves in the coming decades. Most of the increase in reserves will be the result of offshore exploration. In addition to the 25 trillion cubic feet already discovered, the offshore Mediterranean may hold 64 to 84 trillion cubic feet and the onshore Western Desert may contribute 15 to 30 trillion cubic feet in new gas resources. Many of the new fields are expected to be in the giant-field class that contains greater than 100 million barrels of oil equivalent. Challenges include sub-salt imaging, market constraints for predominantly gas resources and economic constraints imposed by the high cost of development of the current deep-water gas discoveries that are probably unique worldwide. The offshore Gulf of Suez may yield an additional 1.5 to 3.3 billion barrels of oil equivalent, but it continues to be technologically constrained by poor-quality seismic data. Advances in multiple suppression and development of new ‘off-structure’ play concepts with higher quality seismic data should result in continual new pool discoveries. Offshore frontier exploration includes the Red Sea rift (currently under reassessment with area-wide 3-D surveys) and the Gulf of Aqaba. Deep-water and sub-salt imaging remain significant challenges to be overcome. Despite a relatively complex history, the Phanerozoic geological framework of Egypt is extremely prospective for oil and gas. Eight major tectono-stratigraphic events are: (1) Paleozoic craton; (2) Jurassic rifting; (3) Cretaceous passive margin; (4) Cretaceous Syrian Arc deformation and foreland transgressions; (5) Oligocene-Miocene Gulf of Suez rifting; (6) Miocene Red Sea opening; (7) the Messinian salinity crisis; and (8) Pliocene-Pleistocene delta progradation. Each of these events has created multiple reservoir and seal combinations. Source rocks occur from the Paleozoic through to the Pliocene and petroleum is produced from reservoirs that range in age from Precambrian to Pleistocene. The offshore Mediterranean, Gulf of Suez and Red Sea/Gulf of Aqaba contain significant exploration potential and will provide substantial reserve replacements in the coming decades.
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Chatterjee, Priyabrata, Utpalendu Kuila, B. N. S. Naidu, Hriday Jyoti Bora, Anil Malkani, Sandipan Dutta, Arpita Mandal, Premanand Mishra et Pinakadhar Mohapatra. « Fatehgarh lacustrine turbidite potential, Barmer Basin, India ». Leading Edge 38, no 4 (avril 2019) : 280–85. http://dx.doi.org/10.1190/tle38040280.1.

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Global discovered resources of oil and gas in giant stratigraphic and structural-stratigraphic combination traps have increased by nearly 50% in the last 17 years. Among the biggest contributors are the large discoveries in deepwater turbidite systems in passive margins and rift basins. The current study area is located in the Barmer Basin in northwestern India. Barmer Basin is a prolific petroliferous basin with major oil discoveries in structural plays including Mangala, Bhagyam, and Aishwariya fields. The principal reservoirs in the structural highs are high-quality fluvial sandstones of the Paleocene Fatehgarh Formation. Lacustrine turbidite plays have been discovered in the overlying Paleocene Barmer Hill Formation, albeit with moderate to poor reservoir quality. The potential exists, however, for finding off-structure lacustrine deepwater turbidite plays in the Paleocene Fatehgarh with reservoir quality comparable to the high-quality fluvial facies encountered updip in the structural plays. An integrated approach was adopted to identify stratigraphic entrapments across the basin to chase high-quality Fatehgarh reservoirs. Gross depositional environment maps integrating new geoscientific data were created, followed by well-calibrated seismic geomorphology and seismic facies interpretations to identify the distal lacustrine deepwater turbidite system fed by the updip fluvial Fatehgarh systems. Worldwide, the critical risk elements associated with such plays are reservoir presence, quality, and lateral seal. Geophysical tools like unsupervised seismic waveform classification, spectral decomposition, and seismic inversion were applied to the available seismic data, and the results were integrated with the regional geology and well facies information to derisk the critical risk segments.
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Zhang, Gongcheng, Hongjun Qu, Guojun Chen, Chong Zhao, Fenglian Zhang, Haizhang Yang, Zhao Zhao et Ming Ma. « Giant discoveries of oil and gas fields in global deepwaters in the past 40 years and the prospect of exploration ». Journal of Natural Gas Geoscience 4, no 1 (février 2019) : 1–28. http://dx.doi.org/10.1016/j.jnggs.2019.03.002.

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Robertson, C. S. « AUSTRALIA'S PETROLEUM PROSPECTS : CHANGING PERCEPTIONS SINCE THE BEGINNING OF THE CENTURY ». APPEA Journal 28, no 1 (1988) : 190. http://dx.doi.org/10.1071/aj87016.

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Perceptions of Australia's petroleum prospectivity, both by the general public and by professional explorationists, have changed considerably over the years. By the 1920s there had already been a considerable change from the optimism of the early part of the century, engendered largely by gas and condensate indications in water bores drilled in the Roma area, to a comparatively pessimistic view due to the failure of numerous small drilling ventures, and to the published opinions of some overseas experts.The public then remained generally apathetic or pessimistic about Australia's petroleum future until the Rough Range discovery in 1953 finally dispelled the myth that Australia was barren of producible oil. Rough Range proved to be the first of a series of discoveries which significantly upgraded industry and public perceptions of Australia's petroleum potential.Other particularly significant discoveries were the Moonie oilfield in 1961, the Gidgealpa and Barracouta gas fields in 1963 and 1964, the giant King-fish and Halibut oilfields in 1967, gas/condensate and oilfields on the North West Shelf in 1971, the Strzelecki and Fortescue oilfields in 1978, and the Jabiru oilfield in 1983. Exploration of the Exmouth Plateau from the early 1970s onwards initially caused a significant increase in estimates of Australia's petroleum potential, followed by downward revisions in the early 1980s because of the failure of the Plateau to live up to expectations.Perceptions of the prospects of some individual basins have also changed dramatically with time. Notable examples are the onshore Carnarvon Basin, the Georgina Basin and the Eromanga Basin.The most significant change in methods of assessing Australia's prospectivity was the introduction of quantitative, probabilistic methods in the 1970s. BMR's current assessment is that we can expect to find an additional 2 400 million barrels of oil, 23 trillion cubic feet of gas, and 550 million barrels of condensate on the Australian continental plate (average estimates).
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Marlow, Lisa, Kristijan Kornpihl et Christopher G. St C. Kendall. « 2-D Basin modeling study of petroleum systems in the Levantine Basin, Eastern Mediterranean ». GeoArabia 16, no 2 (1 avril 2011) : 17–42. http://dx.doi.org/10.2113/geoarabia160217.

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ABSTRACT The Levantine Basin has proven hydrocarbons, yet it is still a frontier basin. There have been significant oil and gas discoveries offshore the Nile Delta, e.g. several Pliocene gas plays and the Mango Well with ca. 10,000 bbls/day in Lower Cretaceous rocks and recently, Noble Energy discovered two gas “giants” (> 5 TCF and one estimated at 16 TFC) one of which is in a pre-Messinian strata in ca. 1,700 m (5,577 ft) water depth. Regional two-dimensional (2-D) petroleum system modeling suggests that source rocks generated hydrocarbons throughout the basin. This paper provides insight into the petroleum systems of the Levantine Basin using well and 2-D seismic data interpretations and PetroMod2D. Tectonics followed the general progression of the opening and closing of the Neo-Tethys Ocean: rift-extension, passive margin, and compression. The stratal package is up to 15 km thick and consists of mixed siliciclastic-carbonate-evaporite facies. Five potential source rock intervals (Triassic – Paleocene) are suggested. Kerogen in the older source rocks is fully transformed, whereas the younger source rocks are less mature. There are several potential reservoir and seal rocks. The model suggests that oil and gas accumulations exist in both structural and stratigraphic traps throughout the basin.
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Thèses sur le sujet "Giant oil and gas discoveries"

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Kere, Axelle. « Essays on fiscal policy and domestic resource mobilization in resource-rich developing countries ». Thesis, Université Clermont Auvergne (2021-...), 2022. http://www.theses.fr/2022UCFAD002.

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Cette thèse examine l'effet des ressources naturelles extractives sur l'environnement macroéconomique des pays en développement et aborde la question de la mobilisation des ressources domestiques dans ces pays. Après avoir passé en revue la littérature théorique et empirique existante sur la malédiction des ressources naturelles, elle explore empiriquement l'impact des grandes découvertes de pétrole et de gaz sur la politique budgétaire des pays en développement et teste l'effet d'une solution proposée par les institutions multilatérales et les gouvernements pour atténuer les défis de la gestion de ces ressources.Le premier chapitre met en évidence l'impact négatif des découvertes de pétrole et de gaz sur la probabilité d'occurrence d’une crise de la dette souveraine dans les pays subsahariens. Cet effet se produit principalement dans les pays dont les exportations sont fortement concentrées; à l'inverse, il disparaît pour les pays qui sont diversifiés. Ce résultat est important car les pays de notre étude ont déjà bénéficié d'un allègement de leur dette par le biais de l'initiative en faveur des Pays Pauvres Très Endettés (PPTE) et de l'Initiative d'Allègement de la Dette Multilatérale (IADM).Le deuxième chapitre montre l'impact des découvertes de pétrole et de gaz sur la composition des dépenses publiques dans les pays en développement. Il met en évidence les effets néfastes de ces découvertes sur les dépenses de santé et d'éducation. En outre, les résultats montrent que les gouvernements privilégient des catégories de dépenses moins productives et plus discrétionnaires, comme les dépenses militaires et de protection sociale. Les résultats de ce chapitre participent à la discussion quant à la réalisation de l’Objectif de développement durable (ODD) sur la croissance économique.Le troisième chapitre analyse l'impact des fonds souverains comme solution à la malédiction des ressources naturelles. Cet article montre que les fonds souverains, en particulier les fonds de stabilisation, ont un impact significatif et positif sur la mobilisation des impôts dans les secteurs hors ressources. En effet, le fait d'imposer une contrainte budgétaire supplémentaire aux pays riches en ressources naturelles encourage une meilleure mobilisation des recettes. Ce dernier résultat participe à l’identification des propositions permettant d'atteindre les objectifs du Consensus de Marrakech, qui a souligné l'importance d'une meilleure mobilisation des recettes intérieures.Enfin, nous concluons en formulant des recommandations de politiques économiques pratiques pour résoudre le problème de la malédiction des ressources naturelles
This thesis examines the effect of extractive natural resources on the macroeconomic environment of developing countries and addresses the issue of domestic resource mobilization in these countries. After reviewing the existing theoretical and empirical literature on the natural resource curse, it explores empirically the impact of giant oil and gas discoveries on the fiscal policy of developing countries and tests the effect of a solution promoted by multilateral institutions and governments to alleviate the challenges of the management of such resources. The first chapter highlights the negative impact of oil and gas discoveries on the likelihood of sovereign debt crises in sub-Saharan countries. This effect occurs mainly in countries with a high concentration of exports; conversely, it disappears for so-called diversified countries. This result is noteworthy because the countries in our study have already received debt relief through the Heavily Indebted Poor Countries (HIPC) initiative and the Multilateral Debt Relief Initiative (MDRI). The second chapter shows the impact of oil and gas discoveries on the composition of public expenditures in developing countries. It emphasizes the harmful effects of these discoveries on health and education spending. In addition, governments privilege less productive and more discretionary categories of spending, like military and social protection spending. The results of this chapter raise concerns about whether the first of the Sustainable Development Goals (SDGs) about economic growth will be achieved.The third chapter analyzes the impact of Sovereign Wealth Funds (SWFs) as a solution promoted by several governments. This article shows that SWFs, particularly stabilization funds, have a significant impact on addressing the deterrent effect of non-resource tax mobilization. Furthermore, imposing an additional fiscal constraint on resource-rich states encourages better revenue mobilization across non-resource sectors. This last result contributes to the discussion of options for achieving the objectives of the Marrakech Consensus, which emphasized the importance of better domestic revenue mobilization.Finally, we conclude by providing practical economic policy recommendations to address the multidisciplinary problem of natural resource curse
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Livres sur le sujet "Giant oil and gas discoveries"

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SEPM Core Workshop (12th 1988 Houston, Tex.). Giant oil and gas fields : A core workshop. Tulsa, OK, U.S.A : Society of Economic Paleontologists and Mineralogists, 1988.

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Schamel, Steven. Shale gas resources of Utah : Assessment of previously undeveloped gas discoveries. Salt Lake City, Utah : Utah Geological Survey, 2006.

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Giant Oil and Gas Fields of the Decade 1978-1988 (Conference) (1990 Stavanger, Norway). Giant oil and gas fields of the decade 1978-1988. Tulsa, Okla : American Association of Petroleum Geologists, 1992.

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1909-, Halbouty Michel Thomas, et American Association of Petroleum Geologists., dir. Giant oil and gas fields of the decade, 1990-1999. Tulsa, Okla : American Association of Petroleum Geologists, 2003.

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Finch, Warren I., A. C. Huffman, James E. Fassett, J. L. Ridgley, R. S. Zech, S. M. Condon, M. H. Alief et V. T. McLemore, dir. Coal, Uranium, and Oil and Gas in Mesozoic Rocks of the San Juan Basin : Anatomy of a Giant Energy‐Rich Basin : Sandia Mountains to Mesita, New Mexico June 30–July 7, 1989. Washington, D. C. : American Geophysical Union, 1989. http://dx.doi.org/10.1029/ft120.

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Cherry-Garrard, Apsley. The Worst Journey in the World : Antarctica 1910-13. 8e éd. London : Pimlico, 2003.

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Cherry-Garrard, Apsley. The Worst Journey in the World. New York : Carroll & Graf Publishers, Inc., 1992.

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Cherry-Garrard, Apsley. The worst journey in the world : Antarctica, 1910-1913. New York : Skyhorse Pub., 2013.

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Cherry-Garrard, Apsley. The worst journey in the world : With Scott in Antarctica 1910-1913. Mineola, N.Y : Dover Publications, Inc., 2010.

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Cherry-Garrard, Apsley. Shi jie zui xian e zhi lü. Chongqing : Chongqing chu ban she, 2007.

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Chapitres de livres sur le sujet "Giant oil and gas discoveries"

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Agarwal, Bijan, et Scott C. Key. « Reservoir Characterization of the Ekofisk Field : A Giant, Fractured Chalk Reservoir in the Norwegian North Sea-Phase 1, Reservoir Description ». Dans Geology of Fossil Fuels - Oil and Gas, 191–204. London : CRC Press, 2021. http://dx.doi.org/10.1201/9780429087837-19.

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MacLachlan, M. E. « Lexicon of Triassic to Pliocene stratigraphic units in field trip area ». Dans Coal, Uranium, and Oil and Gas in Mesozoic Rocks of the San Juan Basin : Anatomy of a Giant Energy‐Rich Basin : Sandia Mountains to Mesita, New Mexico June 30–July 7, 1989, 1–8. Washington, D. C. : American Geophysical Union, 1989. http://dx.doi.org/10.1029/ft120p0001.

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Ridgley, Jennie. « Introduction to the geology and geography of the San Juan Basin ». Dans Coal, Uranium, and Oil and Gas in Mesozoic Rocks of the San Juan Basin : Anatomy of a Giant Energy‐Rich Basin : Sandia Mountains to Mesita, New Mexico June 30–July 7, 1989, 9–12. Washington, D. C. : American Geophysical Union, 1989. http://dx.doi.org/10.1029/ft120p0009.

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Condon, Steven M., et A. Curtis Huffman. « Mesozoic and Cenozoic structure and stratigraphy of the San Juan Basin : An overview ». Dans Coal, Uranium, and Oil and Gas in Mesozoic Rocks of the San Juan Basin : Anatomy of a Giant Energy‐Rich Basin : Sandia Mountains to Mesita, New Mexico June 30–July 7, 1989, 13–18. Washington, D. C. : American Geophysical Union, 1989. http://dx.doi.org/10.1029/ft120p0013.

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Fassett, James E. « Coal resources of the San Juan Basin ». Dans Coal, Uranium, and Oil and Gas in Mesozoic Rocks of the San Juan Basin : Anatomy of a Giant Energy‐Rich Basin : Sandia Mountains to Mesita, New Mexico June 30–July 7, 1989, 19–26. Washington, D. C. : American Geophysical Union, 1989. http://dx.doi.org/10.1029/ft120p0019.

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Finch, W. I., et V. T. McLemore. « Uranium geology and resources of the San Juan Basin ». Dans Coal, Uranium, and Oil and Gas in Mesozoic Rocks of the San Juan Basin : Anatomy of a Giant Energy‐Rich Basin : Sandia Mountains to Mesita, New Mexico June 30–July 7, 1989, 27–32. Washington, D. C. : American Geophysical Union, 1989. http://dx.doi.org/10.1029/ft120p0027.

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Huffman, A. Curtis. « Petroleum geology of the San Juan Basin ». Dans Coal, Uranium, and Oil and Gas in Mesozoic Rocks of the San Juan Basin : Anatomy of a Giant Energy‐Rich Basin : Sandia Mountains to Mesita, New Mexico June 30–July 7, 1989, 33–38. Washington, D. C. : American Geophysical Union, 1989. http://dx.doi.org/10.1029/ft120p0033.

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Stone, William J. « Hydrology of the San Juan Basin ». Dans Coal, Uranium, and Oil and Gas in Mesozoic Rocks of the San Juan Basin : Anatomy of a Giant Energy‐Rich Basin : Sandia Mountains to Mesita, New Mexico June 30–July 7, 1989, 39–41. Washington, D. C. : American Geophysical Union, 1989. http://dx.doi.org/10.1029/ft120p0039.

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Cust, /James, Alexis Rivera-Ballesteros et David Mihalyi. « Chapter 2 : The Economic Effects of Giant Oil and Gas Discoveries ». Dans Memoir 125 : Giant Fields of the Decade : 2010–2020, 21–35. AAPG, 2021. http://dx.doi.org/10.1306/13742355mgf.2.3874.

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Cust, /James, Alexis Rivera-Ballesteros et David Mihalyi. « Chapter 2 : The Economic Effects of Giant Oil and Gas Discoveries ». Dans Memoir 125 : Giant Fields of the Decade : 2010–2020, 21–35. AAPG, 2021. http://dx.doi.org/10.1306/13742355mgf.2.3874.

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Actes de conférences sur le sujet "Giant oil and gas discoveries"

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Widyoko, Bhayu, Patria Indrayana, Toto Hutabarat, Andriadi Budiarko, Mitterank Siboro et Henricus Herwin. « Enhancing Economics of Resources Development of Mature Mahakam Fields Through Innovation, Design Optimization, and Value Engineering ». Dans SPE/IATMI Asia Pacific Oil & Gas Conference and Exhibition. SPE, 2021. http://dx.doi.org/10.2118/205713-ms.

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Mahakam Contract Area is located in East Kalimantan Province, Indonesia. It covers an operating area of 3,266 km2, and consists of 7 producing fields. Most of Mahakam hydrocarbon accumulations are located below body of water, with wellhead production facilities installed in the estuary of Mahakam river (referred as swamp area, 0 to 5m water depth) and the western part of Makassar Strait (referred as offshore area, 30 to 70 m water depth). Mahakam production history goes as far back as mid 1970s with production of Handil and Bekapai oil fields. Gas production started by the decade of 1990s along with emergence of LNG trading, supplying Bontang LNG plant, through production of 2 giant gas fields: Tunu and Peciko, and smaller Tambora field. In the mid 2000s, Mahakam attained its peak gas production in the level of 2,600 MMscfd and was Indonesia's biggest gas producer. Two remaining gas discoveries, Sisi Nubi and South Mahakam, were put in production respectively in 2007 and 2012. Due to absence of new discoveries and new fields brought into production, Mahakam production has entered decline phase since 2010, and by end of 2020, after 46 years of production, the production is in the level of 600 MMscfd. In 2018, along with the expiration of Mahakam production sharing contract, Pertamina Hulu Mahakam (PHM), a subsidiary of Indonesian national energy company, Pertamina, was awarded operatorship of Mahakam Block. This paper describes the efforts undertaken by PHM to fight production decline and rejuvenate development portfolio, with focus on expanding subsurface development portfolio and reserves renewal by optimizing development concept and cost through fit-for-purpose design, innovation, and full cycle value engineering.
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Wiratno, J. « What Will Be Next ? After a Decade of Exploration Activities Towards Giant Discovery in Indonesia ». Dans Digital Technical Conference. Indonesian Petroleum Association, 2020. http://dx.doi.org/10.29118/ipa20-bc-124.

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Exploration activities in a decade we're going toward making a significant contribution to the discovery of oil and gas reserves or resources in Indonesia. The success of exploration activities is a joint result of several parties including the government and Cooperation Contract Contractors under SKK Migas control. The Special Task Force for Upstream Oil and Gas Business Activities (SKK Migas) continues to take various initiatives to find giant discoveries or significant oil and gas reserves. In the road map of exploration activities, a total of around 805 wells and 127,411 km of 2D seismic surveys and 64,513 km2 of 3D seismic surveys have been carried out to search for giant discoveries over the past decade. Exploration drilling activities were mostly carried out in the Western area of Indonesia with a total of 358 wells, followed by the Kalimantan area with planned drilling of 258 wells. Then as many as 195 wells were drilled in Java and Eastern Indonesia with 115 wells. Most seismic survey activities were carried out in eastern Indonesia with a total area surveyed along 60,928 km and an area of 25,470 km2, Kalimantan 24,475 km and an area of 15,287 km2, Java along 22,4455 km and 7,969 km2, the southern Sumatra area 6,708 km and an area of 6,708 km and 4,696 km2 and the survey in the North Sumatra and Natuna area is 12,854 km and 11,091 km2. Besides, various policies have been issued to intensify exploration activities in particular to maintain the Republic of Indonesia's National Energy Security in the eyes of the World.
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Shemin, Georgy G. « Integrated substantiation of the Erema–Chona giant gas–condensate–oil field (Lena–Tunguska petroleum province) ». Dans Недропользование. Горное дело. Направления и технологии поиска, разведки и разработки месторождений полезных ископаемых. Экономика. Геоэкология. Федеральное государственное бюджетное учреждение науки Институт нефтегазовой геологии и геофизики им. А.А. Трофимука Сибирского отделения Российской академии наук, 2020. http://dx.doi.org/10.18303/b978-5-4262-0102-6-2020-028.

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This paper provides compelling evidence for the previously discovered oil and gas fields in the central, most uplifted part of the Nepa–Botuoba anteclise, to be the constituent structural elements of the Erema–Chona giant gas–condensate–oil field. The revealed tectonic, lithological–facies, and geochemical affinities within its limits attest to equally favorable conditions for the formation of oil and gas accumulations.
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M. Zaffa, Farisa, Amir Ayub, Shahram Sherkati, Nur Bakti M. Makhatar, Ahmad Fahrul Januri, Fariza M. Zanal, Ka Cheng Khor et al. « The Ionian-Crete Basin : Is this the Next Frontier ? » Dans International Petroleum Technology Conference. IPTC, 2022. http://dx.doi.org/10.2523/iptc-21893-ea.

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Abstract Over the past decade, the Eastern Mediterranean has been the prime focus of E & P Companies, mainly attributed to the giant discoveries of Zohr-Egypt, Glaucus-Cyprus and Levantine-Israel involving isolated Miocene-Cretaceous carbonate build-ups and Miocene-Pliocene deepwater clastics turbidite plays. A total of 13 Bboe of proven 2P reserves have been added since 2010. These plays are the focus of exploration. Being located in the center of these giant discoveries and the only remaining unexplored region in the Eastern Mediterranean, the frontier Ionian-Crete has recently attracted the attention of the Oil and Gas industry and concessions have been allocated to number of operators (Fig.1). This study is aimed to investigate the hydrocarbon potential of this basin utilizing an integrated play-based exploration approach. Triassic to Pliocene stratigraphic successions and associated thermogenic petroleum systems and plays have been evaluated and areas of high prospectivity have been identified. A crustal model was built to establish the basin geohistory and to understand the impact of crustal reconfiguration during the Hellenides Orogeny and its implications to the petroleum systems maturity.
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Ahmad, Noor Afiqah, Zhin Houng Chieng, Anie Jelie, Hazrina Abdul Rahman, M. Farid M Amin, Nicholas Kwang Hui Foo, Ahmad Fakrudin Zakeria et al. « Array Production Survey Accurately Pinpoints Water Shut-Off Location and Strengthen the Understanding on Remaining Potential of a Giant Carbonate Gas Field, Offshore East Malaysia ». Dans SPE/IATMI Asia Pacific Oil & Gas Conference and Exhibition. SPE, 2021. http://dx.doi.org/10.2118/205785-ms.

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Abstract Over the years, Multiple Array Production Suite (MAPS) has been run several times in Offshore Peninsular Malaysia but never in Offshore East of Malaysia. Field A is located 260km North-North West of Bintulu, Offshore Sarawak and was discovered in 1992 with first gas produced in 2004. One of the many challenges currently faced in managing the field is the prediction and handling of water breakthrough at the existing producers. Based on historical data, water breakthrough from carbonate Zone T begin around 2010 which then followed by series of Water Shut-Off (WSO) campaign. To strengthen the understanding, evaluate the remaining potential and to optimize near term well and reservoir management of the field, an integrated remedial approach is essential. Well-AA was identified for mechanical WSO in an effort to remediate high water production and improve well productivity. The target well was chosen as the well unable to sustain production after a rapid tubing pressure drop due to the highest water production in the field. Moreover, its production had to be capped due to the water production constraints at the receiving hub. Production Logging (PL) was planned across the carbonate sections to accurately identify the appropriate zones for WSO operations. The long horizontal section and high water production typically create a stratified flow regime that forces a smaller volume of hydrocarbon to flow on the high side of the well, hence the conventional PL technology would have been unable to deliver accurate and insightful results. As such, the MAPS technology was run for an initial assessment to identify the water producing zones. MAPS was deployed using wireline tractor and was combined with the Noise Tool (NTO) to provide a comprehensive 3D image of the multi-phase flow profile across the entire wellbore and to investigate the integrity of annular swell packers located in between the carbonate sections. This paper illustrates the best practices involved in the successful downhole Production Logging with a Multiple Array Production Suite and Digital Noise Tool (PL-MAPS-NTO) toolstring, which served as the key input in determining the WSO treatment depth and strategy in Well-AA, that may lead to a potential gain of 10.8MMscf/d.
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Ahmed, Sheraz, Ghulam Muhammad Waqas et Hafiz Mustafa Ud Din Sheikh. « Uplifting the Productivity of a Mature Gas Giant in Pakistan Using Integrated Asset Modelling ». Dans International Petroleum Technology Conference. IPTC, 2022. http://dx.doi.org/10.2523/iptc-22050-ms.

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Abstract It's almost certain that the oil & gas industry has passed its plateau for large field discoveries. This places an extra burden on the efficient handling of our mature assets, as reasonable amount of hydrocarbons still exist in such reservoirs. However, the ever-increasing cost of new projects and low production gains hardly justify the economics. This study presents a novel approach applied on a mature gas giant, in order to revitalize old wells, optimize surface network and exploit the scattered sweet spots still prevailing in the field, with integrated surface and subsurface engineering strategies. The field under study has been producing since 1955, with around 112 wells, completed in four independent formations. The primary reservoir (Reservoir-A) is categorized as a depletion-drive gas reservoir and has been on production since the field's inception; the reservoir pressure has depleted from 1,900psi to 300psi. The other formations: Reservoir B, C & D started producing from 1968, 2000 and 2015 respectively. At its peak, the field produced ∼1,000 MMScfd gas; but lately, the production decline rose to around 7-8% annually, mainly due to natural depletion. However, deterioration in well performances and limitations of surface facilities (feederlines, Gas-Gathering-Mains (GGMs) and compressors) have also exacerbated this decline, due to the additional pressure drops amassed in their dynamics with reservoir pressure depletion & water production. To counter the field's rapid decline, a comprehensive workflow and an Integrated Asset model was developed, with an absolute focus on the NPV for each development. At the subsurface level, Reservoir-B (still under-developed) was the first targeted, as most of its wells were producing at uneconomical rates. An ant-tracking algorithm was run on the newly acquired 3D-seismic; and natural fractures - near the 02 high producers in Reservoir-B, were analyzed. A workflow was then developed to target similar fractures and the integrated impact, on surface facilities, was evaluated. Finally, three successful pilots were drilled in Reservoir-B and Reservoir-C, to evaluate the post-drill dynamics. Based on the real-time performances of these pilots with existing producers and surface facilities, the integrated field model was updated, coupling the wells, surface facilities and all four reservoirs (with independent reservoir models). As a result of this integrated model, 12 more wells, 09 workovers, 02 GGM optimizations and 03 compressor modification jobs were finalized; giving an overall increase in EUR by 800 BCF, while the NPV of the field increased by 131 $MM. This study offers an innovative approach that has been followed to utilize each data-set systematically, in order to re-vitalize a field even after 84% depletion. The paper also describes the evaluation process for all the optimization opportunities and their impact on the NPVs, to reap the maximum reward from such an old field.
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Shi, Hongfu, Hui Cai et Zhongbo Xu. « How to Improve the Benefit of Greenfield Development – Case Study of an Offshore Marginal Oilfield ». Dans Offshore Technology Conference. OTC, 2022. http://dx.doi.org/10.4043/32054-ms.

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Abstract Well-known offshore oil-gas-bearing basin such as the Gulf of Mexico, the North Sea, and the Bohai Bay has entered the middle and late stages of development, which can also be called the mature stage. As a mature petroliferous basin, there are always two sides to everything. Taking the Bohai Bay Basin as an example, six major regional oil production areas have been built in the basin. There are stable logistics links between the regions, including natural gas pipelines, power transmission, Floating Production Storage and Offloading (FPSO) sharing, and mature onshore oil and gas processing terminals. However, the oil and gas exploration in the Bohai Bay Basin has entered the late stage of its peak, and the discovery of giant and large oil fields is becoming more and more difficult. Many low-quality medium and small oil fields have been discovered. Under the current economic conditions, development technology and tax policies, the development of such oil fields is not profitable, so it is called marginal oil fields? How to develop such small and medium oil fields cost-effectively is one of the biggest challenges. This paper expounds that the development of green maiginal oil fields is promoted through multi-disciplinary cooperation and innovation, case stuy of maiginal oil field in Bohai Bay.
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Shi, Hongfu, Hui Cai et Zhongbo Xu. « How to Improve the Benefit of Greenfield Development – Case Study of an Offshore Marginal Oilfield ». Dans Offshore Technology Conference. OTC, 2022. http://dx.doi.org/10.4043/32054-ms.

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Abstract Well-known offshore oil-gas-bearing basin such as the Gulf of Mexico, the North Sea, and the Bohai Bay has entered the middle and late stages of development, which can also be called the mature stage. As a mature petroliferous basin, there are always two sides to everything. Taking the Bohai Bay Basin as an example, six major regional oil production areas have been built in the basin. There are stable logistics links between the regions, including natural gas pipelines, power transmission, Floating Production Storage and Offloading (FPSO) sharing, and mature onshore oil and gas processing terminals. However, the oil and gas exploration in the Bohai Bay Basin has entered the late stage of its peak, and the discovery of giant and large oil fields is becoming more and more difficult. Many low-quality medium and small oil fields have been discovered. Under the current economic conditions, development technology and tax policies, the development of such oil fields is not profitable, so it is called marginal oil fields? How to develop such small and medium oil fields cost-effectively is one of the biggest challenges. This paper expounds that the development of green maiginal oil fields is promoted through multi-disciplinary cooperation and innovation, case stuy of maiginal oil field in Bohai Bay.
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da Costa, Pedro Vassalo Maia, Alvaro Maia da Costa, Julio Romano Meneghini, Kazuo Nishimoto, Gustavo Assi, Nelson Francisco Favilla Ebecken, Luiz Pinguelli Rosa et al. « World’s First Carbon Sequestration Project in Salt Caverns Built Offshore in Ultra Deep Water in Brazil ». Dans ASME 2020 39th International Conference on Ocean, Offshore and Arctic Engineering. American Society of Mechanical Engineers, 2020. http://dx.doi.org/10.1115/omae2020-19129.

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Abstract In 2006, giant oilfields were discovered in Brazil in a water depth of ∼ 2200 m and under a caprock of 2000 m of continues salt rock overlaying the reservoirs, called pre-salt. Currently more than a half of the Brazilian oil and gas production comes from these reservoirs. However, some of these assets have big Oil & Gas ratio with a high level of CO2 contamination, which are currently being reinjected in the reservoirs. This procedure gradually increases the CO2 content associated with the oil extracted, reducing well productivity and leading to high costs of CO2 and CH4 separation by the membrane technology. The Research Center for Gas Innovation (RCGI) located at the State University of São Paulo in Brasil, sponsored by Shell Brazil, is developing a technology that uses the thick layer of salt rock overlying the pre-salt reservoirs to build caverns where the contaminated gas will be injected and decontaminated. After 2 years of extensive research, several studies have been carried out to analyze the main critical aspects of the technology in order to evaluate its feasibility, and now it has been decided to advance to the field proof stage. The salt dome studied can accommodate the construction of 15 caverns, thus providing the confinement of approximately 108 million tons of CO2. Before the system be construct in full scale, it was decided to initially build an experimental cavern with smaller size to obtain field parameters of the final design of the caverns. This paper describes this development denominated Offshore Salt Cavern Ultra-deep Water CCS System, that aims to perform the natural gas storage, a natural gravitational separation between CO2 / CH4 inside the caverns, and the confinement of CO2 (CCS). It presents important results related to structural integrity analysis of the giant and experimental caverns, well design using the same methodology applied in more than 200 projects of the pre-salt oil wells, instrumentation plan of the experimental cavern, storage capacities and other relevant data. If the economics proves feasible, this offshore gas storage station will be the first of its kind and possibly the biggest CCS Project in the world.
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Tchagop, Alfred, et Opeyemi Oyelami. « Managing the High-Temperature Drilling Challenges of Deepwater HP/HT Wells : A Gulf of Mexico Case Study ». Dans SPE Annual Technical Conference and Exhibition. SPE, 2022. http://dx.doi.org/10.2118/210122-ms.

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Abstract High-pressure/high-temperature (HP/HT) drilling operations have unique challenges, which need to be carefully addressed. The need to address these challenges is because the search for additional hydrocarbon reserves is increasingly in the direction of frontier drilling. Frontier drilling has more and more become an attractive option in the search for new hydrocarbon exploration and production. This drilling activity has been driven by the maturing of existing fields, the growing world demand for hydrocarbons, and technological advances. As proven fields are being depleted and because discoveries of giant fields have peaked, the greatest potential for new oil and gas discovery is in the frontier areas. Frontier areas, defined as remote, hostile, and undrilled regions, are characterized by harsh climates or difficult environments. These environments include water depths greater than 2,000 ft, and downhole pressures and temperatures exceeding the equipment and tool ratings required to explore or develop those reservoirs. The HP/HT environment limits the availability of equipment employed to operate safely and efficiently. The energy industry is constantly designing and developing equipment and operational workflows capable of operating in these HP/HT conditions. This paper presents a systematic approach, which includes workflows and processes, to overcome the HT challenges in Gulf of Mexico (GOM) deepwater wells. The goal of these efforts is to enable safe and efficient drilling operations at temperatures greater than 302°F circulating bottomhole temperature.
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Rapports d'organisations sur le sujet "Giant oil and gas discoveries"

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Morrell, G. R. Oil and gas discoveries. Natural Resources Canada/ESS/Scientific and Technical Publishing Services, 1996. http://dx.doi.org/10.4095/207707.

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Arezki, Rabah, Valerie Ramey et Liugang Sheng. News Shocks in Open Economies : Evidence from Giant Oil Discoveries. Cambridge, MA : National Bureau of Economic Research, janvier 2015. http://dx.doi.org/10.3386/w20857.

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