North Sea Oil Field Research Articles

Immunomagnetically Captured Thermophilic Sulfate-Reducing Bacteria from North Sea Oil Field Waters

Immunomagnetic beads (IMB) were used to recover thermophilic sulfate-reducing bacteria from oil field waters from oil production platforms in the Norwegian sector of the North Sea. IMB coated with polyclonal antibodies against whole-cell antigens of the thermophilic Thermodesulfobacterium mobile captured strains GFA1, GFA2, and GFA3. GFA1 was serologically and morphologically identical to T. mobile. GFA2 and GFA3 were spore forming and similar to the Desulfotomaculum strains T90A and T93B previously isolated from North Sea oil field waters by a classical enrichment procedure. Western blots (immunoblots) of whole cells showed that GFA2, GFA3, T90A, and T93B are different serotypes of the same Desulfotomaculum species. Monoclonal antibodies (MAb) against T. mobile type strain cells were produced and used as capture agents on IMB. These MAb, named A4F4, were immunoglobulin M; they were specific to T. mobile and directed against lipopolysaccharides. The prevailing cells immunocaptured with MAb A4F4 were morphologically and serologically similar to T. mobile type strain cells. T. mobile was not detected in these oil field waters by classical enrichment procedures. Furthermore, extraction with antibody-coated IMB allowed pure strains to be isolated directly from primary enrichment cultures without prior time-consuming subculturing and consecutive transfers to selective media.

Social control of large-scale technological projects: inflexibility, non-incrementality and british north sea oil

In the quest to socure the much vaunted benefits of North Sea oil, highly non-incremental technologies have been adopied. By focu m g on the inflexible nature of North Sea hardware, the paper examines the implications of non-incremental technical change for the successful conduct of policy. Here, attention is on the microeconomic performance of the first generation of North Sea oilfields. Conclusions drawn relate to the degree to which non-incremental shiftS in policy permit decision makers to achieve their objectives at relatiue low cost. To discouer cases where non-incremmtal policy making has led to success in this way would be to falsity the thesis that decision makers are best served by employing incremental policies in their approach to complex problem solving The paper upholds the thesis that more incremental technical changes are better able to permit such control by enhancing the flexibility of aecisions made.

Spore-Forming Thermophilic Sulfate-Reducing Bacteria Isolated from North Sea Oil Field Waters

Thermophilic sulfate-reducing bacteria were isolated from oil field waters from oil production platforms in the Norwegian sector of the North Sea. Spore-forming rods dominated in the enrichments when lactate, propionate, butyrate, or a mixture of aliphatic fatty acids (C(4) through C(6)) was added as a carbon source and electron donor. Representative strains were isolated and characterized. The isolates grew autotrophically on H(2)-CO(2) and heterotrophically on fatty acids such as formate, propionate, butyrate, caproate, valerate, pyruvate, and lactate and on alcohols such as methanol, ethanol, and propanol. Sulfate, sulfite, and thiosulfate but not nitrate could be used as an electron acceptor. The temperature range for growth was 43 to 78 degrees C; the spores were extremely heat resistant and survived 131 degrees C for 20 min. The optimum pH was 7.0. The isolates grew well in salt concentrations ranging from 0 to 800 mmol of NaCl per liter. Sulfite reductase P582 was present, but cytochrome c and desulfoviridin were not found. Electron micrographs revealed a gram-positive cell organization. The isolates were classified as a Desulfotomaculum sp. on the basis of spore formation, general physiological characteristics, and submicroscopic organization. To detect thermophilic spore-forming sulfate-reducing bacteria in oil field water, polyvalent antisera raised against antigens from two isolates were used. These bacteria were shown to be widespread in oil field water from different platforms. The origin of thermophilic sulfate-reducing bacteria in the pore water of oil reservoirs is discussed.

The Argyll, Duncan and Innes Fields, Block 30/24 and 30/25a, UK North Sea

abstract The Argyll, Duncan and Innes Fields are situated in the UK Central Graben in Blocks 30/24 and 30/25a. They produce oil from Devonian, Rotliegendes, Zechstein and Jurassic reservoirs through a common floating production facility, the Deepsea Pioneer. Argyll was the first UK North Sea oil field to come on stream, with first oil produced in June 1975. Duncan and Innes were added later and the estimated STOIIP for the three fields is approximately 270 MMBBL. To date over 90 MMBBL have been recovered, and the fields are now on decline.

Oxfordian-Kimmeridgian (Late Jurassic) Reservoir Sandstones in the Witch Ground Graben, U.K North Sea

Oil-bearing Late Jurassic Oxfordian-Kimmeridgian sandstones of the Sgiath and Piper formations are of major economic importance in the Witch Ground Graben. They form the reservoirs in Scott, which in 1993 will be the largest producing North Sea oil field to come on stream for more than a decade. Together with Scott, the Piper, Saltire, Tartan, Highlander, Petronella, Rob Roy, and Ivanhoe fields contained almost 2 Bbbl of recoverable reserves in these formations. The Sgiath and Piper represent two phases of Late Jurassic transgression and regression, initially represented by paralic deposited sand culminating in a wave-dominated delta sequence. The history of the Sgiath and Piper formations is reviewed and lithostratigraphic and biostratigraphic correlations presented to illustrate the distribution of the reservoir sandstones.

Relation between Liquid Hydrocarbon Reserves and Geothermal Gradients--Norwegian North Sea

Comparison of average geothermal gradients and initial liquid hydrocarbon reserves for 28 Norwegian North Sea fields indicates that gradients in the largest North Sea oil fields cluster around 2.1F/100 feet. No reserves are found where gradients are lower than 1.8F/100 feet or higher than 2.3F/100 feet. At 6.89 billion barrels, reserves for 14 fields falling between 2.05 and 2.15/100 feet total over four times the reserves for all other fields put together. Reserves for seven fields at gradients lower than 2.05F/100 feet and for seven higher than 2.15F/100 feet total 594 and 991 million barrels, respectively. The conclusion is that 2.1F/100 feet is the optimum gradient for generation of liquid hydrocarbons in the Norwegian North Sea, given the depth, kerogen type, and source rock potential of the Kimmeridge Clay, the primary source rock there. Gradients lower than this have not stimulated maximum generation from the source rock. At higher gradients, increasing gas production from source rocks and thermal cracking of previously generated liquid hydrocarbons to gas are effective in limiting liquid hydrocarbon reserves. The 2.1F/100 feet gradient should be a useful pathfinder in the search for new oil reserves in the Norwegian North Sea. Determination of the optimum gradient shouldmore » be a useful pathfinder in other regions as well.« less

The Brent Field, Block 211/29, UK North Sea

Abstract The Brent Field was the first discovery in the northern part of the North Sea, and is one of the largest hydrocarbon accumulations in the United Kingdom licence area. There are two separate major accumulations: one in the Middle Jurassic (Brent Group reservoir) and one in the Lower Jurassic/Triassic (Statfjord Formation reservoir). The field lies entirely within UK licence Block 211/29 at latitude 61°N and longitude 2°E. The water depth is 460 ft. The discovery well was drilled in 1971, and six further exploration and appraisal wells were drilled. Seismic data over the Brent Field has been acquired in three separate vintages. The latest acquisition is a 3-D grid recorded in 1986. Reprocessing of the entire 1986 3-D seismic data set was initiated in 1989. The original oil/condensate-in-place, estimated on 1/1/89, is 3500 MMBBL, and the estimated original wet gas-in-place is 6700 TCF. Oil production is now in the decline phase. Average production in 1988 was 334,000 BOPD, with gas sales remaining at the plateau rate of 500 MMSCFD. The field is being developed from four fixed platforms, each providing production, water injection and gas injection facilities for both Brent and Statfjord Formation reservoirs. Gas injection is distributed to achieve an intermediate oil rim development in some reservoir units. The platforms were installed between 1975 and 1978. Production commenced in 1976. The slump faulted crestal areas of both reservoirs have yet to be developed. These crestal areas contain about 5% of the recoverable reserves. Appraisal drilling was carried out in the crest during 1988 and 1989. The Brent Field is located approximately 100 miles north-east of the Shetland Islands and 300 miles NNE of Aberdeen (Fig. 1). The discovery well location is at latitude 61°05'53.87" North longitude 1°41'30.H" East. The water depth is 460 ft The field comprises two distinct reservoirs, the Brent Group and the Statfjord Formation, which are of Middle Jurassic and Lower Jurassic/Triassic age respectively. The reservoirs occur in a westerly dipping tilted fault block in a fault controlled unconformity trap (Fig. 2). The size of the hydrocarbon bearing area is approximately 10 miles from north to south and 3 miles from east to west (Fig. 3). The reservoirs are in turn divided into seven separate reservoir units; four cycles in the Brent Group reservoir and three units in the Statfjord Formation reservoir. Laterally two major east-west orientated faults divide the field into three separate production areas. A fourth area is the north-south orientated crestal part of both reservoirs, which is faulted and has a series of down faulted slump blocks overlain by 'Reworked Sediment'. This area still has to be developed. The Shell/Esso joint venture North Sea oilfields are named after water and waterside birds. The Brent Field is named after the Brent goose.

Hydrocarbon-water interactions during brine migration: Evidence from hydrocarbon inclusions in calcite cements from Danish North Sea oil fields

Crude oils in primary and secondary fluid inclusions in calcite from fractures in seven offshore oil fields associated with diapiric salt structures in the Danish sector of the North Sea were analyzed by capillary column gas chromatography and compared with crude oils produced from the same reservoirs. Oils from fluid inclusions in all fields show evidence of biodegradation (decreased n- C 17/pristane and n- C 18/phytane ratios and loss of n-C 7, 2-methyl hexane, and 3-methyl hexane relative to methyl cyclohexane) and water washing (absence of benzene and depletion of toluene). Some oils in inclusions are extremely enriched in C 6 and C 7 cyclic alkanes suggesting that these samples contain hydrocarbons exsolved from ascending, hotter formation waters. Compared to inclusion oils the produced oils are less biodegraded, but are water washed, indicating that both types of oil interacted with large volumes of formation water. The carbon isotopic composition of the calcite host of the fluid inclusions in the Dagmar and Skjold fields is as light as −16.5%. PDB and the sulfur isotopic composition of pyrite in and adjacent to the calcite veins in the Skjold field is as light as −39.6%. CDT, indicating that biodegradation of the oils was a source of some of the carbon in the calcite and sulfate reduction was the source of sulfur for the pyrite. The evidence for microbial degradation of petroleum is consistent with present-day reservoir temperatures (65°–96°C) but is not consistent with previous estimates of the temperatures of calcite vein filling (95°–130°C) which are much higher than the temperatures of known occurrences of biodegraded oil.

Economic Future of North Sea Gas Fields

This paper briefly describes the development and complexities of the offshore taxation system of the United Kingdom. Use of OR techniques in North Sea oil and gas field development is discussed. The economic effects of recent tragic events in the North Sea are highlighted. The economic future of offshore gas fields is analysed using an econometric model.

Economic Future of North Sea Gas Fields

This paper briefly describes the development and complexities of the offshore taxation system of the United Kingdom. Use of OR techniques in North Sea oil and gas field development is discussed. The economic effects of recent tragic events in the North Sea are highlighted. The economic future of offshore gas fields is analysed using an econometric model.

Methodology of Formation MicroScanner image interpretation in Claymore and Scapa Fields (North Sea)

Abstract The Formation MicroScanner (FMS) * tool is an advanced dipmeter tool capable of producing high-resolution resistivity images of a borehole wall. When integrated with core and open hole logs, FMS images are of great utility in evaluating the thin bedded reservoir sequences of the Claymore and Scapa North Sea oil fields. Sedimentary features as small as 0.5 inches (1.2 cm) can be resolved on FMS images. Such detail is employed in the distinction of massive, parallel laminated, ripple cross-laminated, bioturbated and conglomeratic bedding types. The application of the FMS tool to reservoir description is not limited to bedding type identification. Bed boundaries, as well as small and large scale structural features, can be distinguished, including erosional contacts, slumps, fractures and faults. In the hydrocarbon-bearing zone permeability distribution outwith cored intervals can inferred. This can be confirmed by relating resistivity changes to core measured permeability values. The proposed approach to FMS interpretation involves the integration of all available open hole logs with detailed local geological knowledge and core data. Aspect and image quality of the FMS log are important considerations. By imaging the borehole wall, the aspect of the FMS tool provides a direct method of relating features detected using open hole logs to those observed in cores. Image quality is largely dependent on resistivity contrast in the formation and correlation with cores is imperative to establish confidence limits for extrapolation into uncored intervals.

Experience With Permanent Bottomhole Pressure/Temperature Gauges in a North Sea Oil Field

Summary The Beatrice oil field has been on production since 1981. Each production well is equipped with an electrical submersible pump (ESP) and a permanent bottomhole pressure/temperature gauge (PTG) that provides a continuous readout at surface. The gauge was installed primarily to monitor pump intake pressure and to avoid operation when the pressure falls below bubblepoint. Gauge specification and installation are described. Analysis of reliability in 87 completions in 23 wells is provided. An improvement in reliability over the 3-year period (1982-84) is associated with improved isolation of the gauge signal cable. An example of well-performance monitoring is provided for a problem well kept on production. Analysis of pressure buildups and interwell interference tests is discussed, showing how gauge data have helped refine reservoir description and guide reservoir management.

Lessons Learned In North Sea Oil Field Developments

Abstract Continued progress in matters of frontier resource development is dependent on avoidance of past errors. The development of oil and gas fields in the hostile North Sea environment represents a major pioneering effort which has witnessed the successful introduction of many new technologies. Evaluation of the success of North Sea ventures has, however, been confused by the impact of inflation and currency realignments.A recent analysis by Castle) of North Sea field Economic performance suggests that these fields would have been ‘underwater’ (due to technical under performance) if they had not been "bailed out" by the crude oil price increases, particularly of 1979. Examined are the technical factors responsible for Castle's observation for certain fields and it is concluded that greater care is needed in relating reservoir performance uncertainty to pre-development appraisal well data. Attempts are made to highlight some of the potential problem areas encountered when defining a development plan with the help of reservoir simulationmodels. Analyzed are published data for two typical North Sea fields: Thistle and Beatrice, which are amplified with observations from personal experience. Introduction Table 1 is partly extracted from a recent article by Castle(l) where an attempt was made to estimate how profitable 19 North Sea fields would have been if prices had remained flat from the time development was initiated. These "proforma" rate-of-return estimates, which ignore petroleum revenue tax as well as corporate taxes, and only deduct the 12 ? % royalty, indicated that only 14 fields in fact yielded a positive cash flow and of these only 7 yielded a rate of return in excess of 15%. At first glance Castle's analysis leads one to conclude that the performance of the oil industry in the North Sea was, in real terms, an economic disappointment. Table 1 has been enlarged with technical performance data extracted from the United Kingdom Brown Book(2). It is well known that the oil industry and various northwestern European National Treasuries have derived much benefit from the North Sea Oil Province. In terms of money of the day, the rates-of-return have been more than adequate to permit rapid payback of loans, a very large government "take", as well as to fund further developments. This is due, as Castle points out, to inflation and currency fluctuations ‘bailing out’ the North Sea projects most of which suffered from construction delays, cost overruns and production shortfalls. In this paper an attempt is made to identify the main technical reasons for under-performance of two of Castle's fields: Thistle and Beatrice (Fig. 1), These fields are rather well documented (see reference list) and thus provide much study material. This sample moreover includes a typical "Brent Province" Jurassic field representing one of the pioneering developments, as well as a later, non-Brent "marginal discovery" benefitting from five years of offshore technological progress. It is, therefore, a representative sample, and gives a fair insight into the technical risks inherent in offshore developments. Within the context of U.K offshore developments, both fields are successful.

Scales of Geologic Reservoir Description for Engineering Applications: North Sea Oil Field Example: ABSTRACT

A consequence of the increased interaction between geologists and engineers in resolving reservoir problems has been an awareness on the part of geologists of the need to vary the scale of their geologic description according to particular engineering applications. Conventional geological descriptions are normally too detailed for reservoir engineering simulations and often are not in an appropriate form for relating to reservoir performance. An example is presented of two scales of description of a North Sea oil field for two different applications. The field is a Tertiary submarine slope-fan deposit consisting of thick unconsolidated channel sand facies, a lobe sand facies, and a slope claystone facies, all arranged into 12 stratigraphic units and several subunits. Permeability of the channel sands is about twice that of lobe sands, demonstrating a facies control on reservoir quality. For the purpose of calculating reservoir volumetrics, it was possible to scale up the stratigraphy, by combining similar stratigraphic units, into a simple four-layer reservoir model. Average porosity and permeability vary among the layers in this geologically based model. For the purpose of improving understanding of the reservoir, a more complex flow unit model was developed according to geological and petrophysical properties that would influence themore » flow of fluids in the reservoir. This model is partly based upon sedimentary facies distribution, but differs from a geologic facies model and is in a more suitable form for relating to reservoir performance.« less

Field effects of platform discharges on benthic macrofauna

Although there were originally no statutory obligations for North Sea oilfield developers to monitor the environmental impact of their activities, many companies undertook such studies voluntarily. The central and northern North Sea is principally a level-bottom habitat and can be broadly considered as being dominated by variations of the classicalAmphiurabenthic community. Early approaches to monitoring studies involved the use of grids of sampling stations extending several kilometres in every direction from the proposed site of the installation. More recently it has been found that the major impact on the environment is from the discharge of oil-based drilling cuttings at the platforms and drilling rigs. Efforts are now concentrated closer to the installations, using transects starting as near to the source of the discharge as possible. By using community parameters such as diversity and equitability, it has been shown that the fauna responds with a dramatic drop in values of these measures close to the platform. However, in most surveys, background values are regained between 500 and 1000 m from the installation. This seems to be the case regardless of whether diesel or low toxicity oil-based drilling fluids are used. Numbers of individuals and biomass responded in a similar way at some installations using ‘low toxicity’ oil-based drilling muds but increased at others using diesel oil-base. The latter response is similar to that of areas of great organic enrichment while the drop in numbers is more indicative of disturbed or toxic conditions. The markedly patchy distribution of drilling cuttings around the production platforms calls into question the sampling strategies that have been adopted for offshore surveys in the past. The extreme variation of figures, particularly oil levels in sediments, makes it almost impossible to establish firm connections between cause and effect. The effects of the discharge of cuttings on the benthic environment has been shown to be very severe, but only in a very localized area around the installations. It is suggested that attention is now focused on the persistence of the oil in the cuttings and that future monitoring strategies should include this in their scope.

Summary and conclusions: environmental effects of North Sea oil and gas developments

This Royal Society Discussion Meeting has examined the total environmental impact of a whole industry in a single geographical area. Land-based developments related to the exploitation of the North Sea oilfields and their social consequences have been substantial, although neither the worst fears nor the best hopes have been realized. An accommodation has been reached with the fishing industry in the affected area. Offshore platforms are a source of chronic pollution from production water, but in recent years there has been a marked increase in the use of oil-based drilling muds and it is estimated that 20 Mt per year of petroleum hydrocarbons are added to the sea in oil-contaminated drill cuttings. The effect of these additions has been studied in the laboratory, in mesocosms and in field surveys which, together, yield a consistent picture. Within a radius of a few hundred metres of a platform there is impoverishment of the benthic fauna. Close to the platform the production of anoxic conditions through smothering and the activity of sulphide-producing bacteria is probably more significant than the toxic effect of the oil-based muds. Outside this immediate zone of impact, the oil results in organic enrichment and enhanced populations of some of the fauna. The total area affected is, in the context of the North Sea, minuscule. There is no evidence that plankton is materially affected and the success of commercial fisheries dependent upon the plankton crop is more influenced by fishery practices than by any other factor. Seabird populations, about which there was formerly much concern, have not so far been affected by oil pollution in the North Sea. There is wide fluctuation in recruitment success, but populations of species thought most vulnerable to oil pollution are generally increasing. Although marine pollution research has yielded valuable insights into the responses of individuals, populations and communities to perturbation, natural as well as man-made, it is not likely that future problems associated with oil extraction from the sea will be as stimulating to fundamental research. Different problems relating to environmental pollution should now be addressed by marine scientists.

Seabirds and North Sea oil

The history of large and well-publicized incidents of seabird mortality resulting from oil pollution from tanker accidents (such as the Torrey Canyon in 1967) and from unattributed oil slicks at sea, gave rise to real fears that the development of North Sea oilfields would result in serious mortality and declines in the large populations of seabirds breeding and wintering in and around the North Sea. The oil industry recognized the problem and attempted to minimize pollution risks in all exploration, production and transport operations. Preliminary maps were prepared showing the distribution of vulnerable concentrations of breeding and wintering birds to facilitate contingency planning, and, particularly in Shetland, Orkney and the Moray Firth, extensive and long-term programmes are established to monitor: (1) the numbers of breeding birds; (2) wintering concentrations (particularly of sea ducks); (3) the distribution and abundance of seabirds at sea; (4) the numbers, and percentage oiled, of birds found dead on beaches. The feared increase in oil pollution incidents has not materialized. The few accidents associated with offshore production have had little effect on seabirds. Tanker accidents have been few, but have had large, temporary and local effects (e.g. the Esso Bernicia at Sullom Voe in 1978-79). Breeding seabird populations in the area have increased, although in recent years, in some places, some species may have declined, but these declines cannot be attributed to oil activities in the North Sea. The Beached Bird Survey suggests that chronic oil-induced mortality is at a relatively low level.

Radioactive-Scale Formation

Radioactive-Scale Formation

Tender-Supported Operations at the Odin Field

Summary. The first North Sea tender-supported drilling operations were successfully completed at the Odin field in Feb. 1985. Tender-supported operation was chosen to minimize investment in this marginal field. The operations were very successful and the actual lost time resulting from support vessel disconnection was significantly lower than predicted. The tender support vessel (TSV) provided mud storage, mud pumps, and mud treating facilities; a cement pump; cement bulk storage; materials lay-down area; additional quarters; and other services during the drilling operations. During platform hookup and commissioning, the TSV provided additional accommodation. This paper describes the tender-support concept, major tender-support components, and operational experience at Odin. Introduction Odin is a gas field in the North Sea located in Block 30/10, which is approximately 178 km [96 naut miles] from Bergen. Norway, and 240 km [130 naut miles] from Stavanger, Norway. Fig. 1 identifies the Odin field and some of the surrounding North Sea oil and gas fields. The Block 30/ 10 license was awarded to Esso in 1969 as part of the second Norwegian licensing round. The license is operated and held. 100% by Esso, with a 17.5 % net profit interest belonging to the Norwegian government. The profit interest belonging to the Norwegian government. The Odin field discovery well, 30/10-2, was spudded in late Dec. 1973 in 103 m [338 ft] of water. The well was tested and abandoned in early 1974. A confirmation well, 30/10-3, was drilled later in 1974. While Esso was evaluating the discovery, at Odin, the Petronord Group was developing the much larger Frigg Petronord Group was developing the much larger Frigg field 22 km [12 naut miles] south of Odin. Initial evaluation of Odin indicated that a fully integrated drilling, production, and processing platform could not be justified production, and processing platform could not be justified because of the limited hydrocarbon resources. Studies conducted in 1977 and 1978 indicated that the Odin field might be developed economically if surplus capacity in the Frigg field facilities could be used. (Fig. is a diagram of the Odin/Frigg system.) This utilization minimized the size of the platform and the capital investment required. Key factors that enabled this to be done were the existence of available platform space and spare processing and transportation capacity in existing or processing and transportation capacity in existing or expandable infrastructure, the low number of wells required (11), and the short drilling period (19 months). Excess capacity meant space for two 28 337-kW [38,000-hp] compressors on Platform MCP-1 (a booster platform on the pipeline to St. Fergus), as well as space for the installation of a new metering and separation module on Platform TCP-2 (a platform in the Frigg field complex) Platform TCP-2 (a platform in the Frigg field complex) and space on Platform TCP-2 for additional compression when required. Spare capacity in existing compression and separation facilities on Platform TCP-2 was available initially. With the use of the Frigg installations for the compression, dehydration, metering, processing, and transportation activities. the drilling facilities became the dominating factor in determining the Odin platform space requirements. A study of various marginal field alternatives, including a subsea development similar to the Northeast Frigg field, identified the tender-support concept as a viable option. When evaluating the economic alternative of tender-supported operations for a field like Odin, one must compare the incremental cost of a larger platform, including possible delays in sales revenues resulting from a longer possible delays in sales revenues resulting from a longer construction period, vs. total costs for the support vessel over the expected drilling period, including possible positive effects if the support vessel can also be used for positive effects if the support vessel can also be used for additional accommodation and shop facilities during the hookup phase. Other factors-such as the company's tax paving position, local regulations regarding capitalizing and expensing costs, the competitiveness of the rig market at the time of contracting, depth and areal extent of the reservoir, and potential drilling problems that must be overcome-contribute to making each decision very field-, company-, and country-dependent. An analysis indicated that up to 16 wells could be drilled under the Odin field conditions before a tender-supported system lost its financial attractiveness. Although tender-supported drilling operations had not been conducted previously in the North Sea, the concept had been used for many years in the Gulf of Mexico. Furthermore, tender-supported accommodation units were readily available in the North Sea and had demonstrated an ability to remain on station at a platform during the most severe winter weather. The use of a TSV moved load and space requirements for the installation of major equipment from the platform to the support vessel. The equipment included mud and cement bulk tanks, mud pits and mud pumps, and the cement pumping unit. JPT p. 324

Slope and Deep Shelf Gully Sandstones, Upper Jurassic, East Greenland

The Upper Jurassic Hareelv Formation of Jameson Land, East Greenland, occurs in an area of 60 × 75 km. It consists of 200-500 m of black shale with thick, closely spaced sandstone bodies. The sandstones fill deep, steep-walled gullies and elongate scours, or form more regular, laterally extensive, parallel-sided, but erosive gully mouth or lobe deposits. Both types of sandstone bodies occur completely juxtaposed, and systematic vertical or lateral trends in bed thickness or grain size have not been observed. The sands were deposited in a deep-water shelf basin by high-density turbidity currents traveling from basin-margin source areas. A northeastern source area was represented by a short-lived, rapidly prograding delta, whereas the main, northwestern source area was a shallow, sandy barrier occurring along the length of a major north-northeast-striking fault-controlled slope. Voluminous turbidity currents probably were triggered by earthquakes in the fault zone. The resulting slope and basinal sand bodies are up to 50 m thick and hundreds of meters wide, and may be more than 5 km long in a downcurrent direction. They occur in a thick, rich oil-prone source rock. Thus, they may form potential stratigraphic reservoirs and help drain the source rock. The Hareelv Formation shows important similarities to the ramp facies model for delta-fed sand-rich turbidite systems; however, the formation is mainly tectonically controlled and independent of eustatic sea level changes. The Hareelv Formation may serve as a model for an unusual type of stratigraphic hydr carbon reservoir, and at least one North Sea oil field seems to have formed in an analogous setting.