ABSTRACT The Draugen oil field lies in block 6407/9 in the Haltenbanken oil and gas province. The field is located 150 km off the coast of Norway and 200 km south of the Arctic Circle, in water depths of 240 to 280 m. The Draugen field was discovered in 1984 by well 6407/9-1. Five additional exploration/appraisal wells and 2D seismic assisted in delineating the reservoir The field is hosted by a low-relief north-south-trending anticline measuring some 20 by 6 km. The reservoir lies at a depth of 1600 m subsea and has an oil column of 40 m. The main reservoir is the Late Jurassic Rogn Formation sands, interpreted as a shallow marine sand bar. A separate, smaller accumulation has also been proved in Middle Jurassic Garn Formation sands in the western part of the field. The estimated STOOIP is 180 million standard m 3 . Recoverable reserves are estimated at 67 million standard m 3 of oil and some 3 billion standard m 3 of associated gas. The field will be developed with a concrete gravity base structure and offshore loading. The initial development plan calls for six oil producers and six subsea water injectors. The platform will be installed in the summer of 1993, with first oil shortly thereafter. The planned plateau production rate is 14,300 standard m 3 of dry oil per day.

Abstract The world’s 877 giant oil and gas fields are those with 500 million bbl of ultimately recoverable oil or gas equivalent. Remarkably, almost all of these 877 giant fields, which by some estimates account for 67% of the world’s petroleum reserves, cluster in 27 regions, or about 30%, of the earth’s land surface. In this paper, we present maps showing the location of all 877 giants located on tectonic and sedimentary basin maps of these 27 key regions. We classify the tectonic setting of the giants in these regions using six simplified classes of the tectonic setting for basins in these regions: (1) continental passive margins fronting major ocean basins (304 giants); (2) continental rifts and overlying sag or “steer’s head” basins (271 giants); (3) collisional margins produced by terminal collision between two continents (173 giants); (4) collisional margins produced by continental collision related to terrane accretion, arc collision, and/or shallow subduction (71 giants); (5) strike-slip margins (50 giants); (6) subduction margins not affected by major arc or continental collisions (8 giants). For giant fields with multiphase histories, we attempt the difficult task of discriminating the single tectonic event/setting we consider to have the most profound effect on hydrocarbon formation, migration, and trapping. Our main classification criterion is the basin style dominating at the most typical stratigraphic and structural level of giant accumulations. Continental passive margins fronting major ocean basins form the dominant tectonic setting, which includes 3 5% of the world’s giant fields. Continental rifts and overlying sag basins, especially failed rifts at the edges or interiors of continents, form the second most common tectonic setting, which includes 3 1 % of the world’s giant fields. T erminal collision belts between two continents and associated foreland basins form the third setting, with 20% of the world’s giant fields. Other setting classes — including foreland basins at collision margins related to terrane accretion, arc collision, and/or shallow subduction; basins in strike-slip margins; and basins in subduction margins — are relatively insignificant; with 14% or less of the total basin population. Our tabulation indicates the importance of extensional settings formed during the early and late stages of oceanic opening for giant accumulations: The rift and passive categories combined account for two-thirds, or 66%, of all 877 giants. Our result differs significantly from previously published giant classifications in which collisional settings form the dominant tectonic setting for oil giants. We propose the following possibilities to explain the dominance of extensional rift and passive margin settings over all other tectonic settings: (1) localization of high-quality source rocks in lacustrine and restricted marine settings during the early rift stage; (2) effectiveness of the sag or passive margin section above rifts to either act as reservoirs for hydrocarbons generated in the rift section and/or to seal hydrocarbons generated in the underlying rift section; (3) tectonic stability following early rifting that allows hydrocarbon sources and reservoirs to remain undisturbed by subsequent tectonic events acting on distant plate boundaries. Trends in the discovery of giants in the period from 1990 to 2000 that we consider likely to continue into the 21st century include (1) the discovery of fields in deep-water basinal settings along passive margins such as Brazil, west Africa, and the Gulf of Mexico associated with nodes of high-quality source-rock areas and stratigraphic traps located using three-dimensional seismic reflection data, (2) continued discoveries of giants in known areas, including expansion of the Persian Gulf hydrocarbon province to the south into Yemen and the Arabian Peninsula and north into Iraq; expansion of the West Siberian Basin in the Arctic offshore area; radial expansion of the Illizi Basin of Algeria, (3) continued discoveries in Southeast Asia, where Cenozoic rift, passive margin, and strike-slip environments all coexist around the South China Sea or in the largely submerged Sunda continent, (4) along-strike expansion of elongate foreland trends in the Rocky Mountains, northern South America, the southern Andes, the Ural-Timan-Pechora and Barents Sea, and the North Slope, and (5) expansion of discoveries in the Black Sea-Caspian region associated with closure and burial of northern Tethyal passive margin or arc-related basins. Despite the association of giant fields with Cenozoic or Mesozoic plate edges (especially failed rifts trending at high angles to continental margins), the possibility always exists for further discovery of “lockbox-type” giants associated with now cratonic interior, but previous Paleozoic or Precambrian plate edges, as exemplified by known Paleozoic and Precambrian hydrocarbon giant clusters in the Permian Basin in the United States, the Illizi Basin of Algeria, and the Siberian Platform.

Abstract Petroleum inclusion and geochemical data from core extracts were applied to deduce a model for oil migration, overpressure development and palaeo-leakage of oil from currently dry structures in the Haltenbanken Vest area. The existence of fluorescent oil type inclusions in quartz in the Smørbukk (Åsgard-2) field suggest that oil migrated into this structure 70–50 million years before present (Ma bp). This is also the case for the dry structures 6506/12-4, 6506/11-3 and 6506/11-1, west of the main Smørbukk Fault Zone. Black oil inclusions with medium gas/oil ratio (GOR) occur in these fields together with condensate-type petroleum inclusions. This suggests that the dry structures transformed from containing oil to condensate before leakage. Petroleum extracted from inclusions in these structures and in nearby fields have identical marine type II kerogen signatures. Source rocks at the Spekk Formation level in the current drainage area of Smørbukk and these dry structures, were immature 70–50 Ma bp and the Smørbukk Sør (Åsgard-3) field did not fill at this early time. Thus, oil must initially have entered into Smørbukk from areas to the W-SW, through the currently pressure sealing Smørbukk Fault Zone which today marks the westward limit of the Smørbukk field. Diagenesis in this fault zone caused the much later overpressure development and petroleum was lost from the 6506/12-4, 6506/11-3 and 6506/11-1 structures as overpressure built up regionally. Petroleum loss from these structures with their often thick seals must have occurred via self-propagating open-fracture-induced mechanisms. Lack of petroleum in the Cretaceous strata above these structures suggests that leakage occurred to even shallower strata. This could imply that the Cretaceous strata in Halten Vest were overpressured at the time of leakage. In contrast, the oil in the Cretaceous Lysing and Lange Formation (above the Jurassic reservoirs in Smørbukk and Smørbukk Sør) most likely originated (based on geochemistry and GORs) from the Jurassic reservoirs below and not from Cretaceous strata. This migration event would have been facilitated if it occurred before these sands became overpressured as they are today. Modelling suggests that the Spekk Formation became mature in the Smørbukk Sør region <10 Ma bp and microthermometry of oil inclusions from Smørbukk Sør supports filling during the past 10 Ma. This implies that caprock failure in the Halten Vest structures 6506/12-4, 6506/11-1 and 6506/11-3 most likely occurred after filling of the Smørbukk Sør and 6406/3-1 structures. Rapid regional burial during the past 10 Ma caused local migration of oil into Smørbukk Sør, Smørbukk and 6406/3-1 structures, and generation of high GOR oils in the deeper Halten Vest region. High GOR petroleum inclusions in the Halten Vest structures signify this event and suggests that caprock fracturing occurred after a gas-condensate had replaced oil in these traps. Rapid burial during the past 3 Ma is likely to have caused the current overpressure and associated leakage in Halten Vest. The fact that these traps did not later refill in this progressively subsiding and maturing basin must be related to trap pressures remaining too close to the actual fracture pressures.

Abstract The development stage of a reservoir covers the period after data collection and subsequent appraisal when the project is considered viable and investment has been committed. Field development often is viewed in phases: planning, in which a depletion strategy is determined, initial production wells are located, and facilities are designed; and initial buildup, when facilities are constructed and initial wells are brought on stream. Development-related activities also extend into field production.

Abstract Concerns about climate change and the need to stabilize atmospheric CO 2 concentrations are driving the development of a lower carbon future. Within this context, carbon dioxide capture and storage (CCS) is gaining momentum as a large-scale option to reduce greenhouse gas emissions. This paper reviews the rationale and potential scale of CCS, the status of geological storage options and lessons from the operating In Salah project. CCS is expected to have applications in the oil and gas industry, and other industries, particularly the coal and power sectors. CO 2 -enhanced oil recovery, depleted oil and gas fields and saline formations are considered the most important geological storage options. Experience with geological storage is being gained at the In Salah project in Algeria. Operating since 2004, it is the world's first industrial-scale project storing CO 2 in the water leg of a gas reservoir. A key challenge for wider deployment is for geological storage to be accepted as a safe and effective option, providing long-term CO 2 containment, with high integrity. This has several associated technical and regulatory challenges, including site characterization and selection, geological and well integrity risk assessment, performance prediction, the design of appropriate monitoring schemes and handling the closure and post-closure phases. The petroleum industry has the capabilities and know-how to deploy CCS and to manage the associated risks. This lends confidence that CCS will be a viable option and that deployment will help enable a low-carbon future.