Academic literature on the topic 'Bassin de (Norvège)'

Angola Opens Congo, Kwanza Blocks in Ongoing Bid Round Angola’s National Oil, Gas, and Biofuel’s Agency has opened blocks for licensing in the Onshore Lower Congo Basin and the Onshore Kwanza Basin as part of its 2020 oil and gas licensing round. This latest call to tender is part of the agency’s ongoing 2019–2025 hydrocarbons licensing strategy. The Onshore Lower Congo Basin Blocks include CON1, CON5, and CON6; while the Onshore Kwanza Basin Blocks comprise KON5, KON6, KON8, KON9, KON17, and KON20. The round aims to expand research and evaluation activities across sedimentary basins, increase geological knowledge of Angola’s hydrocarbon potential, and invite a new wave of explorers to yield new discoveries. Raven Field Startup for BP in Egypt Natural gas has begun flowing from the BP-operated Raven field, the third stage of the company’s major West Nile Delta (WND) development off the Mediterranean coast in Egypt. The $9-billion WND development includes five gas fields across the North Alexandria and West Mediterranean Deepwater offshore concession blocks in the Mediterranean Sea. Raven is currently producing approximately 600 MMcf/D with a peak potential of 900 MMcf/D and 30,000 B/D of condensate. Raven follows the Taurus/Libra and Giza/Fayoum projects, which started production in 2017 and 2019, respectively. It produces gas to a new onshore processing facility, alongside the existing WND onshore processing plant. In total, the WND development includes 25 wells producing gas to the onshore processing plant via three long-distance subsea tiebacks. The onshore facilities—including the new Raven facility—now have a total gas processing capacity of around 1.4 Bcf/D of gas. All gas produced is fed into Egypt’s national grid. BP is the operator and has an 82.75% stake in the WND development, with Wintershall Dea holding the remaining 17.25% interest. CGX Secures Rig for Kawa-1 Well off Guyana CGX Energy and Frontera Energy, joint venture partners in the Petroleum Prospecting License for the Corentyne block offshore Guyana, have secured semisubmersible Maersk Discoverer to drill the Kawa-1 well. An early third quarter spud for the exploration well is targeting a Santonian age, stratigraphic trap, interpreted to be analogous to the discoveries immediately to the east on Block 58 in Suriname. The well is anticipated to be drilled to a total depth of approximately 6500 m in a water depth of approximately 370 m. The contract has an estimated duration of 75–85 days and has a one-well option attached. If exercised, that probe would spud in the nearby Demerara Block and take an estimated 40 days to reach its target. Talos’ Bulleit Reservoir in US Gulf Smaller Than Expected A technical assessment of the main producing sand performance at Talos Energy’s Green Canyon Block 21 Bulleit field in the US Gulf has indicated a smaller reservoir than originally anticipated. Project partner Otto Energy said the assessment included detailed bottomhole pressure and reservoir performance data collected after hookup and first production. The Block 21 field is flowing via a single subsea well tied back to a platform in nearby Green Canyon Block 18. While additional technical work is ongoing, the currently favored path forward is to move away from the current sand and execute a recompletion of the well in the shallower DTR-10 sand. A DTR-10 recompletion will require the procurement of long-lead items from manufacturers, which are expected to cost $3.5 million with payment expected in mid-2021. The recompletion is expected to begin in mid-2022, with production from the DTR-10 immediately following in mid-to late 2022. Captain Field EOR Stage 2 Project a Go Ithaca Energy, operator of the Captain field, has sanctioned the Captain Enhanced Oil Recovery (EOR) Stage 2 project in the UK Central North Sea after receiving Field Development Plan Addendum consent from the Oil and Gas Authority. EOR Stage 2 is designed to significantly increase hydrocarbon recovery by injecting polymerized water into the reservoir through additional subsea wells, subsea infrastructure, and new topsides facilities. Stage 1 of the project demonstrated that polymer EOR technology can work, with the production response in line with or better than expected across all injection patterns, helping maximize economic recovery. The Captain field was discovered in 1977, in Block 13/22a located on the edge of the outer Moray Firth. The billion-barrel field achieved first production in March 1997—over 24 years ago. Ithaca Energy holds 85% working interest, while partner Dana Petroleum holds the remaining 15%. Equinor Touts new Tyrihans Field Discovery Equinor and partners Total E&P Norge AS and Vår Energi AS have struck oil and gas in a new segment belonging to the Tyrihans field in the Norwegian Sea. Exploration well 6407/1-A-3 BH in production license 073 was drilled from sub-sea template A at Tyrihans North. The well was drilled to a measured depth of 5332 m by semisubmersible drilling rig Transocean Norge and struck a gas column of about 43 m and an oil column of about 15 m in the Ile formation, including about 76 m of moderate to good reservoir quality sandstone. In the Tilje formation, moderate to good quality water-bearing reservoir was struck. The Tyrihans field is in the middle of the Norwegian Sea, some 25 km southeast of the Åsgard field and 220 km northwest of Trondheim. The licensees consider the discovery commercial and intend to start production immediately. Recoverable resources are so far estimated at between 19 and 26 million BOE. Maersk Awarded Intervention Work off Brazil Maersk Drilling has been awarded a contract with Karoon Energy Ltd. for the semisubmersible rig Maersk Developer to perform well intervention on four wells at the Baúna field offshore Brazil. The contract is expected to begin in the first half of 2022, with a firm duration of 110 days. The value of the contract is $34 million, including rig modifications and a mobilization fee. The contract contains options to add up to 150 days of drilling work at the Patola and Neon fields. Carnarvon Completes Farmout of Buffalo Project Carnarvon Petroleum has completed the farmout of 50% of the Buffalo project to Advance Energy PLC. On 17 December 2020, Carnarvon announced that Advance Energy would acquire 50% of the Buffalo project off the west coast of Australia by funding the drilling of the Buffalo-10 well up to $20 million on a free carry basis. Advance met this funding requirement and now has a 50% interest in the project. The well is on track to be drilled in late 2021, subject to securing a drilling rig, where the tendering process is already underway. Following the well, the joint venture will acquire development funding from third-party lenders and any additional funding will be provided by Advance as an interest-free loan. The current plan is to suspend a successful well as a future producer and begin early development studies during 2021. Shell Hires Seadrill Rig for Brazilian Campaign Shell has contracted Seadrill’s drillship West Tellus for a new drilling campaign offshore Brazil this year. The program is expected to start in BC-10 of the Campos Basin, where Shell operates the Parque das Conchas made up of the Abalone, Argonauta, and Ostra fields. BC-10 has produced more than 100 million bbl since oil first started flowing from the block in 2009. The drillship will be used on the third phase of BC-10 activity, which includes five additional production wells and two water-injection wells at the Massa and Argonauta O-Sul fields, with the wells connected to the Espirito Santo FPSO. Shell owns a 50% operating stake in BC-10. India’s ONGC retains a 27% minority share and Qatar Petroleum the remaining 23%. Following the BC-10 work, the operator is expected to drill the first wells in the Campos Basin’s C-M-791 block, which was acquired during the 15th bid round held in 2017. Shell owns a 40% operating stake in the block, with Chevron retaining a 40% interest and Portugal’s Galp Energia the remaining 20%. Panoro Energy Kicks Off 2021 Drilling Campaign Offshore Gabon Panoro Energy has initiated its 2021 Gabon drilling campaign with the spudding of the Hibiscus Extension well on the Dussafu Marin Permit. That well will be followed by drilling at Tortue and Hibiscus North. Hibiscus and Tortue are two out of a total of six discovered fields within the Dussafu Permit offshore Gabon. Panoro currently holds a 7.5% interest in the license and has entered into an agreement to acquire an additional 10% working interest in the Dussafu Permit, bringing its total ownership to 17.5% following completion of the transaction. The Extension well is being drilled with the jackup Borr Norve and is the first well in a three-well campaign planned on Dussafu during 2021. The well is planned as a vertical well to test structure, oil, and reservoir presence in what is believed to be a possible northerly extension of the Gamba reservoir in the Hibiscus field. The well is positioned about 3 km northwest of the Hibiscus discovery well drilled by the joint venture in 2019. The initial well and its appraisal sidetrack established a 2P gross recoverable reserves of just over 46 million bbl at the Hibiscus field. The Extension well is expected to take around 30 days to drill and log to a total depth of 3500 m. Success at the probe could prompt one or two appraisal side-tracks to further delineate the field. Following the Hibiscus Extension, the rig will move to drill a horizontal production well, DTM-7H, at the Tortue field. This will complete the Phase 2 development of Tortue and, along with DTM-6H, will bring the total number of production wells at Tortue up to six. An exploration well at the Hibiscus North prospect, located approximately 6 km north-northeast of the initial Hibiscus well is also scheduled. Hibiscus North is a separate 10–40 million bbl prospect that could be tied into the Hibiscus/Ruche development project. Puma West Strike for BP in the US Gulf An exploration well at the Puma West prospect in the deepwater US Gulf has yielded a significant oil discovery for operator BP. The well, on Green Canyon Block 821, was drilled using Seadrill drillship West Auriga to a total depth of 23,530 ft and encountered oil pay in a high-quality Miocene reservoir with fluid properties like productive Miocene reservoirs in the area. Preliminary data supports the potential for a commercial volume of hydrocarbons. The Puma West partners will begin planning an appraisal program to better define the discovered resource. The discovery well has been suspended as a keeper well to preserve future utility. Puma West is located west of the BP-operated Mad Dog field and is approximately 131 miles off the coast of Louisiana in 4,108 ft of water. The Puma West is operated by BP with a 50% working interest. Partners include Chevron with 25% and Talos Energy with the remaining 25%. Petrobras Pushes First Oil at Mero Into 2022 Petrobras has postponed first oil from its Mero 1 field via the FPSO Guanabara in the Santos Basin offshore Brazil due to delays with the production system. Startup at Mero 1 was originally expected in the fourth quarter of this year and is now expected to begin flowing during the first quarter of 2022 due to COVID-19 pandemic-related delays with the buildout of the production system in China. The FPSO will be installed in the Mero field, which belongs to the Libra Block, in the Santos Basin pre-salt area, with a processing capacity of 180,000 OPD. The field is operated by Petrobras (40%) in partnership with Shell Brasil Petróleo (20%), Total E&P (20%), CNODC Brasil Petróleo e Gás (10%), CNOOC Petroleum Brasil (10%), and Pré-Sal Petróleo, which is the contract manager.

Ces études intègrent la stratigraphie séquentielle, la bio stratigraphie, l'analyse des structures, des attributs sismiques et des faciès sismiques. La base des donnes consiste de la sismique en 2D et 3D, des puits diagraphies, qui est fourni de Exxon-Mobil Norway et SAGA Petroleum. Le bassin étudié, le bassin du Marulk, est localisé à l'intersection de la partie septentrionale du Viking Graben nord et de la zone faillée du More-Trondelag à la marge Atlantique. Le bassin a évolué comme un bassin de rift pendant le Jurassique moyen à supérieur puis durant le Crétacé. Il a donc eu une histoire polyphasée. Cette particularité qu'il partage avec d'autres bassins du Viking Graben nord est due à sa position entre la limite septentrionale de la Mer du Nord et à la marge Atlantique. Cette situation à l'intersection de deux différents domaines extensifs, un point essentiel de l'étude du bassin du Marulk, est sous l'influence des développements structuraux de la Mer du Nord et de l'Atlantique Nord. En outre, l'évolution tectono-stratigraphique du bassin du Jurassique moyen au Tertiaire et les modalités concernant la sédimentation pré-, syn- et post rift sont les objectifs. Le deuxième point de l'étude était la construction des modèles de dépôts des séquences jurassiques, crétacées et tertiaires inférieurs liés à des surfaces d'érosion dans le bassin du Marulk. Ces surfaces d'érosion sont la discontinuité de Kimméridgien, de la base du Crétacé, de l'Albien supérieur, Cénomanien moyen, de Crétacé/Tertiaire et de l'Ypresien. Les résultats des analyses d'attributs et de la faciès sismique sont intégrés dans les contextes stratigraphie séquentielle et dans le cadre structurale. Ces analyses supportent la reconnaissance, l'identification et la délinéation des faciès sismiques pour en aboutir des caractéristiques stratigraphiques et géologiques de ces intervalles. Les models de dépôts contribue à la localisation des zones des réservoirs potentiels
This study integrates sequence stratigraphy, biostratigraphic, seismic, structural, seismic facies and attribute analysis. The data consist of 2D and 3D reflection seismic and wells furnished by Exxon-Mobil Norway and SAGA Petroleum. The investigated Marulk Basin is located at the intersection between northernmost part of the North Viking Graben and the More-Trondelag Fault Zone (MTFZ) on the northeast Atlantic margin. The Marulk Basin at the northern termination of the northern North Sea evolved as a rift basin during the middle/late Jurassic, but has also a poly-phase extensional history during the Cretaceous. This particularity with respect to other North Viking Graben sub-basins is due to its location at the boundary between the northern North Sea and the Atlantic margin. This interplay between two different styles of extensional tectonics gives the overall direction for the major aim for the study of the Marulk Basin: the overprint of the North Sea and North Atlantic structural developments, the tectono-stratigraphic basin evolution from middle Jurassic to lower Tertiary and the modalities concerning the pre-, syn- and post-rift sedimentation in the Marulk Basin. The second aim was to build depositional models of Jurassic, Cretaceous and lower Tertiary key sequences associated with erosional surfaces in the Marulk Basin through seismic facies and attribute analyses. The selected surfaces are the Kimmeridgian Unconformity, Base Cretaceous Unconformity, Latest Albian and Mid Cenomanian Unconformity, Cretaceous/Tertiary Unconformity and the Ypresian Unconformity. Seismic facies and attribute analyses of these sequences are integrated in the sequence stratigraphic and structural framework. These analyses support the recognition, identification and delineation of seismic facies in order to characterize stratigraphic and geological features for these intervals. Depositional models improve the delineation of areas that could be of interest for hydrocarbon exploration

S'appuyant sur de longues missions de terrain, ce travail offre le regard quantitatif et qualitatif d'un géographe sur la dynamique nivo-glaciaire en région polaire dans un contexte de changement climatique actuel. Il s'inscrit dans le cadre du programme ANR Hydro-Sensor-FLOWS mis en oeuvre dans la mouvance de l'Année Polaire Internationale. En amont de ce programme pluridisciplinaire visant à comprendre le fonctionnement hydrologique d'un petit hydrosystème polaire il fallait adjoindre une étude plus spécifique concernant le rôle de la neige et de la glace dans l'équation hydrologique : c'est l'objet de cette thèse. Le bassin glaciaire de l'Austre Lovénbreen (10 km2, Spitsberg - 79°N) a servi de terrain d'étude dans une approche géographique à échelle locale. De nombreuses méthodes ont été testées tant sur le terrain (stations photo automatiques, carottages de la neige, DGPS et GPR) que pour l'exploitation des données acquises. Au total, ce travail suit la dynamique nivo-glaciaire pendant trois années (2008, 2009 et 2010) à partir de 15 séries de carottages en 40 points du bassin, de mesures de densité, de profils nivologiques, de bilan de masse et de suivi continu, en 20 points, de la température de l'air. Outre l'image satellite, ce travail s'appuie également sur une collection de 3 clichés journaliers acquis en 10 points du bassin. Des méthodes ont été développées pour corriger géométriquement les photos afin d'en faire des documents en projection verticale dont il est possible de tirer de l'information quantitative. Les outils de la géomatique ont permis de spatialiser l'information ponctuelle et d'établir à des pas de temps variables, par croisement des données acquises in situ, les diverses lames entrant dans l'équation hydrologique (précipitations, fonte potentielle de la neige et de la glace en relation avec les lames écoulées). Les trois années consécutives de suivi offrent des conditions très différentes qui révèlent le rôle constant et modérateur des températures et celui beaucoup plus impulsif des précipitations. Ce travail pose également le problème des mesures et de leur fiabilité dans un milieu aussi sévère et aussi impétueux que l'Arctique

L'analyse tectonique et microtectonique des bassins devoniens de norvege a permis de mettre en evidence une epaisse (2km) zone de cisaillement ductile a vergence ouest. Le regime, la cinematique et les conditions thermiques de la deformation sont precisees. La lineation d'allongement, de nature retrometamorphique, et les nombreux criteres de cisaillement associes caracterisent la deformation a vergence ouest qui reutilise la foliation precoce. Suivant l'age adopte pour la formation des eclogites, differents modeles d'evolution tectonique de la chaine caledonienne sont discutes. Si l'on envisage un age caledonien pour ces roches, ces resultats sont en accord avec un modele thermomecanique d'uplift et d'erosion (retour a l'equilibre) de la croute caledonienne prealablement epaissie par chevauchements. L'extension devonienne, par le rejeu en faille normale des chevauchements caledoniens, favorise ce processus

On propose des procedures pour reconstituer et interpreter le regime thermique des bassins sedimentaires, a partir d'estimations de la conductivite thermique et de la temperature des formations. Ces parametres sont deduits de l'analyse de donnees de puits d'exploration petroliere: diagraphies, carottes, deblais de forages et temperatures. Les procedures sont appliquees a trois bassins. Dans la premiere partie, la conductivite des formations est estimee a trois echelles significatives: 1) a l'echelle de l'electrofacies diagraphique; 2) a l'echelle de la formation a chaque forage et; 3) pour chaque formation a l'echelle du bassin. Dans la seconde partie, apres extraction des erreurs systematiques associees a l'histoire du forage, le champ de temperature est estime par inversion stochastique des temperatures et des epaisseurs des formations, en prenant en compte les correlations laterales entre gradients thermiques. Dans la troisieme partie, une methode d'analyse des modes de transfert de chaleur, basee sur l'inversion simultanee des conductivites et des temperatures, est developpee. La prise en compte de la physique des transferts de chaleur permet: i) de considerer des correlations laterales et verticales entre les gradients thermiques et; ii) de distinguer entre transferts conductifs et convectifs