North Sea Exploration: ABSTRACT

A continuous oil accumulation is one that is pervasive throughout a large area and is not affected by natural hydrodynamic influences. Three source rocks in the San Joaquin Valley of California are actively producing hydrocarbons and represent potential continuous oil accumulations: the Monterey, Kreyenhagen, and Moreno Formations. The Energy Information Administration announced in 2014 that there are potentially 15 billion bbl of recoverable oil in the Monterey Formation in California, spiking huge interest. Such a resource would make the Monterey by far the largest continuous oil accumulation in North America. This number has since been reduced dramatically to 600 million bbl of oil for the state and 21 million bbl of oil within the San Joaquin Valley. In this study, the subsurface character of the Bakken Formation of North Dakota is compared with the three source rocks in the San Joaquin Valley at oil window depths. To characterize these reservoirs, hundreds of well logs, core descriptions, and mud logs were studied. A technique to rank character of oil show data was developed in which interesting, possibly interesting, or not interesting wells were located on thermal maturity maps. Interesting wells have significant oil shows, whereas not interesting wells have minor or no shows. In the Bakken Formation, the character of the oil show correlates with well productivity. Applying this same classification to the San Joaquin Valley source rocks leads to a more disappointing conclusion. Although there are oil shows in the source rocks of the San Joaquin Valley at oil window depths suggesting the presence of a continuous oil accumulation, the distribution of shows is both laterally and vertically heterogeneous and not predictable. Moreover, recent attempts to produce from source rocks at these depths have not been economically successful. We conclude that the three source rocks in the San Joaquin Valley represent heterogeneous and discontinuous oil accumulations at oil window depths in the subsurface. Likely there are billions of barrels of oil in these discontinuous oil accumulations. Source rocks in the Bakken are rated as world class; source rocks in the San Joaquin Valley are good to excellent quality. However, the quality of the oil shows in the San Joaquin Valley appears poorer than the Bakken Formation. It is possible that effective drainage between the source rocks and the up-dip reservoirs has left large volumes of the source rocks at oil window depths with only residual oil saturation. Complex structural and stratigraphic architecture, heterogeneity, and continuity create issues of predictability for optimal areas to target. Rapid rates of subsidence over the past few million years and accompanying thrusting and folding resulted in a complex subsurface pressure regime. The lack of clear hydraulic fracture targets, analogous to the middle Bakken, further complicates drilling decisions and likely deliverability. In addition, the oil windows in the San Joaquin Valley are significantly deeper than the Bakken Formation, which would result in substantially higher well cost. Recent drilling results support this study and suggest that heterogeneous and discontinuous oil accumulations in the San Joaquin are unlikely to become economic without dramatic changes in technology.

Hibernia is the pioneer development for the emerging Canadian east coast offshore oil industry. As the first operator in this area, the Hibernia Management and Development Company Ltd. (HMDC) is developing local skills and infrastructure which can support future developments. The Hibernia field is located 315 kilometres east southeast of St. John's, Newfoundland. It consists of two reservoirs - the Avalon and the Hibernia reservoirs, located at average depths of 2400 metres and 3700 metres respectively. Containing approximately three billion barrels of oil in place, Hibernia is the fifth largest discovered oil field in Canada. Recoverable reserves are estimated to be 615 million barrels. Limited data is available on the Avalon reservoir at this time, and initial drilling activity is expected to identify significant reserves upside. A fixed drilling and production platform is being assembled in Newfoundland to produce the field. Its design includes a first-of-its-kind concrete Gravity Base Structure, which has a 15 metre thick ice belt that can withstand the impact of multi-million tonne icebergs. The completed platform is scheduled to be towed to its offshore location in June 1997, with first oil expected in December. The platform has a design production capacity of 150,000 barrels of oil per day. Average production of 135,000 barrels of oil per day is expected during the 6 year plateau period. Other discoveries around Hibernia offer the opportunity for subsea tiebacks for processing and storage of crude in the future. Hibernia has a pre-production budget of US$4.4 billion, and total development costs are estimated to be US$8.0 billion, excluding transportation costs. Introduction The waters off the east coast of Newfoundland are host to 16 undeveloped oil fields containing estimated recoverable reserves of 25 1 million m3 (1.6 billion barrels). The area also contains an estimated 234 billion m3 of gas, and 58 million m3 of natural gas liquids1. With oil in place estimated at 477 million m3 (three billion barrels) and recoverable reserves of 98 million m3 (615 million barrels), Hibernia is by far the largest discovery offshore Canada to date. In fact, it is the largest undeveloped oilfield in Canada, and by the turn of the century is expected to produce approximately 10% of Canada's light crude oil production. Once Hibernia begins production in December 1997, it will be leading the development of a new offshore oil industry for Canada. However, one field does not constitute an industry. In order for an industry to evolve, Hibernia has to prove that it can compete with similar operations by achieving its goal of top quartile industry performance in relation to the North Sea. This goal is achievable but will present challenges, especially in the area of platform support costs. Using present day technology, it will take 18 years todeplete the estimated 98 million m3 (615 million barrels) of recoverable oil from the Hibernia field.

The lower Paleozoic area in Tarim Basin is the key field of deep oil and gas exploration, and the lower Cambrian source rock is the focus of current research. However, due to the deep burial depth, there are few samples of Lower Cambrian source rocks revealed by drilling. The lower Cambrian source rocks are widely exposed in the northwest of the basin, which provides a good opportunity for the study of source rocks. In this paper, the organic geochemistry of three sections and a shallow drill sample from Aksu Area in the northwest and Kuruktag area in the northeast of the basin has been systematically analyzed. The total organic carbon (TOC), bitumen content and maturity of source rocks are studied. The organic carbon content of the lower Cambrian source rocks in the Keping area of the northwest basin ranges 1.49%-14.07%, and the content of bitumen ranges 7.73-24.53 mg / g • TOC. However, the organic carbon content of the lower Cambrian outcrop samples in the Sugetebulake section ranges from 0.93% to 7.90%, and the soluble organic matter content ranges from 0.73 to 5.89 mg / g • TOC. The TOC of Lower Cambrian source rocks in Yardang mountain area of northeast basin is low, ranging from 0.75% to 1.42%, and the content of bitumen is between 2.97-3.94 mg / g • TOC. In terms of organic matter abundance, the Cambrian source rocks developed in gentle slope facies are better than those in deep-water shelf facies. The measured reflectance (Ro%) of Shairik shallow drilling samples is between 1.0% - 1.7%, with an average of 1.45%. The Ro% of Sugatebulak samples is between 1.4%-1.75%, with an average of 1.55%, indicating that the overall maturity of the source rocks in the northwest is in the condensate wet gas stage. The measured reflectance of the Cambrian source rocks in the Yardangshan and Kuruktag sections in the northeast of the basin is between 1.5-2.5% RO, with an average of 1.75% ro. The overall maturity of the source rocks in the northeast of the basin is relatively higher, suggesting a wet gas stage.

The principal source rocks in the Danish and southern Norwegian Central Graben in the North Sea are the Upper Jurassic to lowermost Cretaceous marine shales of the Farsund Formation that corresponds to the Kimmeridge Clay Formation and equivalents elsewhere in the North Sea. The evaluation of the Farsund Formation shales shows that the distribution of the generation potential and the maturity is more complex than generally accepted. Further studies are required to understand the variations in source rock quality, the controlling factor(s) on kerogen composition, and to determine if the rich intervals can be regionally correlated. The Upper Jurassic marine shales underlying (Lola and Haugesund Formations) the Farsund Formation are traditionally not included as potential source rocks, but the documented extra potential of the Upper Jurassic shales below the Farsund Formation should be investigated in more detail. Attention should also be given to deeply buried mature source rocks in areas with overpressure. These factors have considerable impact on location and extent of kitchen areas. The problems are explored with the goal to capture new knowledge of the Upper Jurassic petroleum source rocks.

The petroliferous sedimentary basins of the UK Continental Shelf are remarkable for the diversity of their reservoir strata. Reservoir rocks in fields currently in production range in age from Devonian to earliest Eocene, but significant hydrocarbon discoveries have also been made in rocks as as young as the mid-Eocene. The reservoirs are predominantly siliciclastic rocks, with facies ranging from continental fluvial and aeolian, to marine gravity flow deposits from sub-wave base environments. In this paper stratigraphic context of the producing horizons in the UK Continental Shelf (UKCS), principally the North Sea, is reviewed, and the sedimentation of the reservoir strata placed in an outline geological history. The main producing horizons are described in summary. Matters of stratigraphic terminology and correlation both between fields and between basins are discussed. A lithostratigraphy for the UK southern North Sea was established by Rhys (1974), and for the central and northern North Sea by Deegan & Scull (1977). Although these schemes have proved to be fairly robust, in the last 13 years the acquisition of new data plus a proliferation of new terms not fully documented in the public domain, argue strongly for a comprehensive revision and rationalization which is beyond the scope of this paper. Attempts in the public domain to standardize nomenclature across international boundaries in the North Sea, pursued by Deegan & Scull (1977) for the UK and Norwegian sectors, have lapsed for the most part in subsequent years. Economic basement in the UK North Sea can be regarded at present

Tunnel valleys of the central and northern North Sea (56°N to 62°N): Distribution and characteristics

Trends in chlorobiphenyl contents in livers of Atlantic cod (Gadus morhua) from the North Sea, 1979–1987

Production from the structurally complex Gullfaks Field in the northern North Sea is now on decline, reduced by a third from the peak year 1994, when oil production exceeded 30 MSm3. Recoverable reserves are currently estimated at 319 MSm3, of which approximately 240 MSm3 have been produced to date. Approximately 80% of the recoverable reserves lie in the middle Jurassic Brent Group. An important goal for the Gullfaks license is to increase the recoverable reserves by 47 MSm3, of which the Brent Group isexpected to yield 30 MSm3 through a recently launched technology programme. Locating the remaining oil is an important part of this programme. Time lapse seismic data are considered to be a key element in this process, and a multidisciplinary team is now in the process of integrating 4D seismic data with other available reservoir and production information, in order to improve the static, as well as the dynamic, reservoir description. The project is also a testing ground for several recent R&D results in the field of geological modelling, reservoir and production engineering, assisted by modern visualization techniques to enhance communication of technical information and ideas. An example of how the multidisciplinary approach has improved our reservoir and drainage understanding will be demonstrated. This improved understanding provides a better basis for quantifying the field's IOR potential. Introduction Reservoir Description. The Gullfaks Field is located in the Norwegian sector of the North Sea, in block 34/10, approximately 175 km northwest of Bergen, where the Gullfaks Business Unit is based, on the west coast of Norway, see Figure 1. The reservoir units are sandstones of early and middle Jurassic age, around 2000m sub sea and measure several hundred meters thick (Ref. 1). The uppermost Brent sequence contains roughly 80% of the reserves, with the deeper Cook and Statfjord formations contributing the remainder. Reservoir quality is generally very high, with permeability ranging from few tens of mD to several Darcys depending on layer and location. Figure 2 shows a cross section indicating the quality and variability of the reservoirs. The reservoirs are over pressured, with an initial pressure of 310 bar at datum depth of 1850 m below mean sea level, and a temperature of 70 degrees C. The oil is undersaturated, with a saturation pressure of approximately 245 bar, depending on formation depth and location. The GOR ranges between 90 and 180 Sm3/Sm3, with stock tank oil gravity around 860 kg/m3. Structurally, the field can be divided into three regions(Ref. 2). The so-called 'Domino Area' with rotated fault blocks in the west, and a Horst area in the east. In between is a complex 'Adaptation Zone', characterized by folding structures. The north-south faults that divide up the field have throw up to 300 meters. In the western part the faults slope typically around 28 degrees downward to the east, whereas in the eastern horst they slope 60–65 degrees downwards to the west. The field is further cut by smaller faults, with throws of zero to few tens of meters, both in the dominant north-south as well as east-west direction. Many of these lesser faults have slopes of 50–80 degrees.

The Quaternary succession in the northern North Sea

Elementary composition of suspended particulate matter in the North Sea

Egg weight and fecundity in the north sea herring (clupea harengus)

<p>Storm Xaver impacted the northern Europe on 5-6 December 2013.  It developed southeast of Greenland and passed north of Scotland and across southern Norway on a trajectory that led to a cold air outbreak across the North Sea and intense convection activity in northern Europe.  Strong sustained north winds led to a high storm surge that impacted all countries bordering the North Sea.  Storm Xaver was a century scale event with certain locations around the North Sea reporting their highest ever water levels since the start of modern records.  Media reports from the time of the storm chronicle the scale of the disruptions, including many cancelled flights, interrupted rail networks, closed bridges and roads, coastal building collapses, and power blackouts across northern Europe.  Much of this was due to the strong winds, but coastal storm surge flooding was important in the UK, and it led to interrupted port operations around the North Sea.</p><p>The storm was important for energy infrastructure and particularly for wind energy infrastructure.  In the northern North Sea, petroleum platforms were evacuated and operations closed ahead of the storm as a precautionary measure.  A number of onshore wind turbines were badly damaged by high winds and lightning strikes in the UK and Germany.  Over the North Sea, wind speeds exceeded the turbine shutdown threshold of 25 m/s for an extended period of time, with economic impacts from the loss of power generation.   In the German Bight, the FINO1 offshore wind energy research platform was damaged at the 15 m level by large waves.  This was the third report of storm damage to this platform after Storm Britta in 2006 and Storm Tilo in 2007.  Researchers have highlighted the need to reassess  the design criteria for offshore wind turbines based on these kinds of extreme meteorological events.  For the offshore wind industry, an important element of energy meteorology is to characterize both the evolving wind and wave fields during severe storms as both elements contribute to turbine loads and potential damage.</p><p>The present conference contribution presents a literature review of the major events during Storm Xaver and impacts on energy infrastructure.  Tide gauge records are reanalyzed to trace the progress of the storm surge wave around the North Sea.  A spectral analysis is used to separate the long period storm surge component, diurnal/semidiurnal tide, and short period components in the original water level record.  The short period component of the tide gauge record is important as it may be linked with infragravity waves that have been implicated in certain cases of offshore infrastructure damage in addition to coastal erosion.  Discussion is made of offshore wave records during the storm.  Storm Xaver is compared with two damaging offshore storms in 2006 and 2007.</p>

For 50 years a principal Gulf of Mexico frontier has been exploration in water deeper than the deepest existing platform. Progress was steady but not always smooth. Selected historical highlights provide some of the story behind the progress. A pattern of leasing in deeper water than drilling and drilling in deeper water than production is illustrated by plotting the extent of leasing, drilling, and production on maps for each decade from the first oil discovery in 1938. By 1988, leasing has reached 9,300 feet of water, drilling has reached 7,520 feet of water,, and production has reached 1,025 feet of water soon to be extended to 1,760 feet of water. Industry action appears to be fueled more by guest for reserves than by current or near term economics or politics. Successes have resulted from optimism, technical advances, and a favorable political climate. Failures have resulted mostly from industry's exploring of the high risk very high reserve prospects. Over 11 billion barrels of oil and 130 trillion cubic feet of gas have been discovered in the United States waters of the Gulf of Mexico, and half again more may remain to be discovered. Through 1985, value of oil and gas sold was $166.46 billion. The United States has received $67.85 billion in bonus, royalty, and delay rentals. The challenge is to fully explore the Gulf of Mexico. Many of the circumstances facing' the industry in the 1980's are not dissimilar to those that faced the industry in the 1940's. INTRODUCTION For 50 years, oil and gas exploration into deeper and deeper waters of the Gulf of Mexico has been fueled by optimism. Optimism that large accumulations of oil and gas are there to be found; optimism that earth science, drilling, and producing technology could find and produce the oil and gas, and finally, optimism that cash income at the time of production and 20 to 30 years thereafter would be ample to cover investments and have some left over to keep the program going. Exploration in federal and state waters has resulted in the discovery of over 11 billion barrels of oil and 130 trillion cubic feet (TCF) of gas (Forrest, 1986). About 7 billion barrels of oil and 80 TCF gas have been produced, leaving proved reserves of about 4 billion barrels of oil and 50 TCF gas. Risotto and Collins (1986) estimate economically recoverable undiscovered reserves (risked mean oil resource) to be 6.03 billion barrels of oil and 59.64- TCF gas. Their five per cent probability estimate for undiscovered reserves is 11.90 billion barrels of oil and 121.87 TCF gas, which provides a range within which most prognostications fall. Through 1985, the total value of oil, condensate and gas production when sold from the Gulf of Mexico Outer Continental Shelf (OCS) was $166.46 billion.

Buyzen, J.P.M., Shell Expro UK Ltd. Scotland Introduction Shell Expro operates in the British sector of the North Sea on behalf of Shell and Exxon. The company has three operating locations: London, (Head Office), Lowesoft (Southern Gas fields) and Aberdeen (Middle and Northern North Sea). This paper deals with the operation of the Auk-ELSBM (Middle North Sea) and Brent-SPAR (Northern North Sea), activities which are controlled from Aberdeen (Fig. 1). DESCRIPTION OF THE INSTALLATIONS General The hostile environment of the North Sea demands a major effort with respect to the design and effective operation of the offshore loading facilities. Although designs show significant differences, each of these installations is a variation of the Single Point Mooring theme, in that they all incorporate some form of mooring turntable and fluid swivel, which permits the tanker, while remaining moored, to weathervane around the SPM in response to the prevailing weather and sea conditions. THE AUK-ELSBM (Exposed Location Single Buoy Mooring) Location The ELSBM is located 2,000 m from the Auk platform and moored to the seabed by 8 anchors, each weighing 15 tons, which are set around the buoy in a circle with a 460 m radius. Each anchor is attached to the ELSBM by a 3 in. diameter stud link chain and is pretensioned (Fig. 2). The water depth in the Auk field is 84 m.

MEPS Marine Ecology Progress Series Contact the journal Facebook Twitter RSS Mailing List Subscribe to our mailing list via Mailchimp HomeLatest VolumeAbout the JournalEditorsTheme Sections MEPS 175:191-200 (1998) - doi:10.3354/meps175191 Metazoan plankton and the structure of the plankton community in the stratified North Sea H. G. Fransz1,*, S. R. Gonzalez1, S. F. Steeneken2 1Netherlands Institute for Sea Research, PO Box 59, 1790 AB Den Burg, The Netherlands 2Department of Marine Biology of the University of Groningen, PO Box 14, 9750 AA Haren, The Netherlands *E-mail: fransz@nioz.nl ABSTRACT: The hypothesis of size-differential control of phytoplankton was tested by sampling stations on a transect from the Dogger Bank to the Shetland Isles in the North Sea on cruises in March/April and July/August 1994. On this transect light limitation was expected in spring, and an increase in nutrient limitation was expected from north to south in summer. The Shetland area, where nutrient levels and primary production rates were highest in summer, did not show the correspondingly higher relative abundances of large algae which would have been predicted by the hypothesis. The question addressed in this study is how the highly abundant zooplankton in the stratified North Sea in summer affect the structure of the plankton community of interacting algae, heterotrophic protists and metazoans. Variations in zooplankton species distributions revealed 4 latitudinal subregions. The Calanus finmarchicus population in the central North Sea reproduced in March. In August, reproduction rates were highest in the 2 northernmost regions. Carbon specific ingestion based on in vitro egg production rates led to an estimate of 10.4% for these stations in summer. It was concluded that the stratified central and northern North Sea can vary with latitude in zooplankton species composition, population structure and vertical distribution. In summer, adjacent subregions can differ widely in vertical distribution of C. finmarchicus biomass. High copepod abundance and grazing rates can promote the dominance of small algae by causing mortality of large algae and heterotrophic protists (grazers of small algae). During summer in the North Sea, egg production rates indicated an increased grazing activity of C. finmarchicus towards the north. This could have obscured the negative effect of decreasing nutrient limitation on the dominance of small algae predicted by the hypothesis of size-differential control of phytoplankton. KEY WORDS: Mesozooplankton · Calanus finmarchicus · Biomass · Egg production · Plankton community structure · Size-differential control · North Sea Full text in pdf format PreviousNextExport citation RSS - Facebook - Tweet - linkedIn Cited by Published in MEPS Vol. 175. Publication date: December 17, 1998 Print ISSN:0171-8630; Online ISSN:1616-1599 Copyright © 1998 Inter-Research.