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NARROW
GeoRef Subject
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all geography including DSDP/ODP Sites and Legs
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Arctic Ocean
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Norwegian Sea (1)
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Atlantic Ocean
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North Atlantic
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North Sea
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Brent Field (2)
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East Shetland Basin (5)
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Oseberg Field (1)
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Primary terms
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faults (9)
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granites (1)
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Indian Ocean
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marine installations (1)
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Mesozoic
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Cretaceous
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Lower Cretaceous (3)
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Upper Cretaceous (1)
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Jurassic
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Heather Formation (30)
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Lower Jurassic
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Dunlin Group (3)
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Toarcian (1)
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Middle Jurassic
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Aalenian (1)
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Bajocian
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Brent Group (10)
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Broom Formation (1)
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Etive Formation (2)
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Ness Formation (3)
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Rannoch Formation (2)
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Tarbert Formation (5)
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Bathonian
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Great Oolite Group (1)
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Callovian (2)
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Upper Jurassic
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Fulmar Formation (3)
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Kimmeridge Clay (11)
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Kimmeridgian (1)
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Oxfordian (4)
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Volgian (1)
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Statfjord Formation (2)
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Triassic (3)
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ocean floors (1)
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oil and gas fields (17)
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oxygen
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O-18/O-16 (2)
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paleogeography (3)
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Paleozoic
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Devonian (1)
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Upper Permian
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Zechstein (1)
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petroleum
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sedimentary rocks
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Tor Formation (2)
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sedimentary rocks
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chalk (1)
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clastic rocks
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claystone (1)
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conglomerate (2)
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mudstone (4)
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sandstone (12)
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shale (2)
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siliciclastics (1)
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turbidite (1)
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sediments
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siliciclastics (1)
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turbidite (1)
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Heather Formation
Abstract This chapter describes Middle Jurassic second-order sequences J20 and J30, and their component third-order sequences, J22–J26 and J32–J36. The J22 sequence contains the major Intra-Aalenian Unconformity (‘Mid-Cimmerian’) across a wide area of the North Sea Basin and an equivalent event onshore UK. The base J24 (Lower Bajocian) is marked by the Rannoch Shale (Brent Group) and by the flooding of the Ollach Sandstone, Hebrides Basin. The base J26 (Upper Bajocian) ties to the Mid Ness Shale (Brent Group) and the base of the Upper Trigonia Grit Member, central England. The base J32 (Upper Bajocian) ties to the base of the Tarbert Formation, the base of the Great Oolite Group in central England and the base of the Great Estuarine Group, Hebrides Basin. The base J33 (Middle Bathonian) falls within the Tarbert Formation and the base of the Taynton Limestone, central England. The base J34 (uppermost Middle Bathonian) commonly falls at the top of the Brent Group. The base J36 (uppermost Bathonian) represents a major increase in marine influence, at the base of the Beatrice Formation, in the Inner Moray Firth and at the base of the Staffin Bay Formation, Hebrides Basin.
Chapter 10. Sequence stratigraphy in the exploration for North Sea Jurassic stratigraphic traps
Abstract The application of sequence stratigraphic concepts and methods significantly enhances the evaluation of stratigraphic traps. In this chapter, five examples of, as yet undrilled, potential UK North Sea Jurassic combination stratigraphic traps, from the East Shetland Platform, South Viking Graben, Inner Moray Firth and Central Graben, are discussed and the potential application of sequence stratigraphic methods in their evaluation considered.
Abstract The most important North Sea Jurassic–lowermost Cretaceous lithostratigraphic units, as developed in the UK, Norway and Danish sectors, are summarized in this chapter (55 units from the UK, 25 from Norway and 10 from Denmark). Some significant issues remain with the use and application of lithostratigraphic terminology in the Jurassic of the North Sea Basin. In particular, there are inconsistencies in unit definition and nomenclature changes across country sector boundaries that obscure the recognition of regional stratigraphic patterns that exist across the region. To aid clarity and to overcome some issues of definition, some revisions are made to the existing lithostratigraphic schemes. Several informal lithostratigraphic units are described, a number of unit definitions are revised and various formerly informal units are formalized (Buzzard Sandstone Member, Ettrick Sandstone Member and Galley Sandstone Member). It is recommended that use of the Heno Formation in offshore Denmark is discontinued. In addition, four new lithostratigraphic member terms are introduced (Home Sandstone Member, North Ettrick Sandstone Member, Gyda Sandstone Member and Tambar Sandstone Member). All described units are placed into a sequence stratigraphic context. All significant lithostratigraphic boundaries conform with key sequence stratigraphic surfaces.
Abstract The Erskine high-pressure–high-temperature gas condensate field was the first such field developed in the UK Continental Shelf. Since production started in 1997, the field has produced over 350 bcf of gas and 70 MMbbl of condensate. The reservoir pressure has depleted from an initial pressure of 960 bar (13 920 psi) down to 140–400 bar (2030–5800 psi), resulting in some compaction and sand production in some of the wells. Free water production has led to the formation of wellbore scale, which has required interventions to remove. The reservoirs are sandstones of the Jurassic Puffin, Pentland and Heather formations. Estimates of hydrocarbons in place made using production and pressure data compare favourably with the initial estimates made during field development planning, although the Pentland Formation volume is some 20% below the sanction estimate. Several major field outages have occurred, such as a condensate fire in 2010 and a blockage of the multiphase export pipeline in 2007. In addition, the field has experienced flow assurance problems related to scale and wax deposition. A new pipeline section was installed in 2018 to bypass a full pipeline blockage which occurred due to wax deposition.
Abstract The Shearwater Field is a high-pressure–high-temperature (HPHT) gas condensate field located 180 km east of Aberdeen in UKCS Blocks 22/30b and 22/30e within the East Central Graben. Shell UK Limited operates the field on behalf of co-venturers Esso Exploration and Production UK Limited and Arco British Limited, via a fixed steel jacket production platform and bridge-linked wellhead jacket in a water depth of 295 ft. Sandstones of the Upper Jurassic Fulmar Formation constitute the primary reservoir upon which the initial field development was sanctioned; however, additional production has been achieved from intra-Heather Formation sandstones, as well as from the Middle Jurassic Pentland Formation. Following first gas in 2000, a series of well failures occurred such that by 2008 production from the main field Fulmar reservoir had ceased. This resulted in a shut-in period for the main field from 2010 before a platform well slot recovery and redevelopment drilling campaign reinstated production from the Fulmar reservoir in 2015. In addition to replacement wells, the redevelopment drilling also included the design and execution of additional wells targeting undeveloped reservoirs and near-field exploration targets, based on the lessons learned during the initial development campaign, resulting in concurrent production from all discovered reservoirs via six active production wells by 2018.
The Captain Field, Block 13/22a, UK North Sea
Abstract The Captain Field in Block 13/22a is in the Moray Firth region of the UK North Sea. The primary reservoirs are Lower Cretaceous turbidite sandstones of the Captain Sandstone Member. Upper Jurassic shallower-marine Heather Formation sandstones of Oxfordian age provide a secondary reservoir. Total oil in place exceeds 1 Bbbl; however, the oil is heavy and viscous, requiring the continuous application of innovative technologies to maximize economic recovery from the field. Captain has been producing since 1997, with reservoir waterflood planned from the outset. Captain has been developed using long horizontal producers to maximize reservoir contact. Water injectors provide pressure support, with the aim of full voidage replacement. The Captain development has been phased with facilities consisting of two bridge-linked platforms, a floating production, storage and offloading vessel, and two subsea manifolds. Peak oil rate (100 000 boepd) was achieved in 2002. Average production in 2019 was 28 000 boepd. Captain is executing a chemical enhanced oil recovery (EOR) project, a first for the UK North Sea. Conventional waterflood yields an estimated ultimate recovery of 30–40%. Chemical EOR is expected to improve this by 5–20% in areas of the reservoir under polymer flood.
The Golden Eagle, Peregrine and Solitaire fields, Blocks 14/26a and 20/01, UK North Sea
Abstract The Golden Eagle Field is located 18 km north of the Buzzard Field in the Moray Firth, and consists of oil accumulations in the Lower Cretaceous Punt and Upper Jurassic Burns Sandstone members. The development area comprises three fields, Golden Eagle, Peregrine and Solitaire, but up to 90% of the oil-in-place and ultimate recovery are in Golden Eagle. The two satellite fields are primarily structural closures, while the Golden Eagle Field reservoirs have a major element of stratigraphic pinchout. Production commenced in October 2014 and approximately 140 MMbbl of recoverable oil is anticipated over its field life from the 19 development wells (14 producers and 5 injectors) that form the initial development phase. Production performance to date has exceeded expectations, aided through the use of completions that provide zonal control of the reservoir units which has successfully supported reservoir management and improved sweep efficiency. A number of significant lessons have been learned during the early stages of the field life from the integration of dynamic data (real-time downhole fibre-optic reservoir monitoring instruments, inter- and intra-well tracers, and well interference tests) and seismic data improvements (post-start-up acquisition of high-density ocean-bottom node seismic and depth-conversion improvements).
The Hutton, NW Hutton, Q-West and Darwin fields, Blocks 211/27 and 211/28, UK North Sea
Abstract Hutton (discovered in 1973) and NW Hutton (discovered in 1975), together with Q-West (discovered in 1994) and Darwin (discovered in 1983, undeveloped), are part of a single petroleum system. The main fields were defined as two separate legal entities. Although Q–West covered multiple blocks, it was wholly developed via the Hutton platform. Together, Hutton and NW Hutton produced 328 MMbbl of oil and a small quantity of associated gas from Middle Jurassic Brent Group sandstones. The trap is a complex series of tilted fault blocks sealed by Mid–Upper Jurassic Heather and Kimmeridge Clay Formation mudstones. Oil was sourced from the Kimmeridge Clay Formation, which is mature for oil generation in the hanging walls to the field-bounding faults and deep on the footwall flanks. NW Hutton underperformed relative to Hutton. In part this was due to the poorer reservoir quality encountered at depth compared with the shallower Hutton Field but a significant component of the underperformance was due to the way in which the field was developed and then operated. Both fields contain areas of unproduced and unswept oil, with the NW Hutton portion having the largest remaining oil in place.
The Maria Field, Block 16/29a, UK North Sea
Abstract The Maria oilfield is located on a fault-bounded terrace in Block 16/29a of the UK sector of the North Sea, at the intersection of the South Viking Graben and the eastern Witch Ground Graben. The field was discovered in December 1993 by the 16/29a-11Y well and was confirmed by two further appraisal wells. The reservoir consists of shoreface sandstones of the Jurassic Fulmar Formation. The Jurassic sandstones, ranging from 100 to 180 ft in thickness, have variable reservoir properties, with porosities ranging from 10 to 18% and permeabilities from 1 to 300 mD. Hydrocarbons are trapped in a truncated rotated fault block, striking NW–SE. The reservoir sequence is sealed by Kimmeridge Clay Formation and Heather Formation claystones. Geochemical analysis suggests that Middle Jurassic Pentland Formation and Upper Jurassic Kimmeridge Clay Formation mudstones have been the source of the Maria hydrocarbons. Estimated recoverable reserves are 10.6 MMbbl and 67 bcf (21.8 MMboe). Two further production wells were drilled in 2018 to access unexploited areas.
The Pelican Field, Block 211/26a, UK North Sea
Abstract The Pelican Field lies in the East Shetland Basin, in Block 211/26, roughly 150 km NE of the Shetland Islands. It was discovered in 1975 by exploration well 211/26-4. Development was delayed until 1995 when economic development became feasible as a subsea tie back to the Cormorant Alpha Platform. The reservoir is the Middle Jurassic Brent Group, comprising sands deposited in a fluvio-deltaic, shallow-marine, wave-dominated system. The reservoir interval has an average thickness of around 300 ft, ranging from 220 ft on the crest to 400 ft in down-flank areas. The crest of the field lies at around 10 500 ft true vertical depth subsea. Current estimate of oil in place for the field is c. 500 MMbbl. The Pelican Field suffers from significant deterioration of reservoir properties with depth, leading to low recovery factors of 15–20%. To date, 21 production and injection wells have been drilled recovering a total of 76 MMbbl. Oil production started in 1996 and peak oil production was achieved at 50 000 bopd in the same year. Rates declined due to water-cut development in most of the wells and current production rates are around 2000 bopd.
Observations and suggested mechanisms for generation of low-frequency seismic anomalies: Examples from the Johan Sverdrup field, central North Sea Norwegian sector
Abstract The Skarfjell oil and gas discovery, situated 50 km north of the Troll Field in the NE North Sea, was discovered by well 35/9-7 and was appraised by three additional wells operated by Wintershall, in the period 2012–14. The Skarfjell discovery is an example of a combined structural/stratigraphic trap. The trap formed along the northern edge of a deep WNW–ESE-trending submarine canyon, which was created by Volgian erosion of intra-Heather, Oxfordian-aged sandstones and then infilled with Draupne Formation shales. This mud-filled canyon forms the top and side seal, with the bottom seal provided by Heather shales. The reservoir comprises mid-Oxfordian deep-water turbidites and sediment gravity flows, which formed in response to tectonic hinterland uplift and erosion of the basin margin, 10–20 km to the east. The Skarfjell discovery contains light oil and gas, and may be subdivided into Skarfjell West, in which the main oil reservoir and gas cap have known contacts, and Skarfjell Southeast, which comprises thinner oil and gas reservoirs with slightly lower pressure and unknown hydrocarbon contacts. The Upper Jurassic Draupne and Heather formations are excellent source rocks in the study area. They have generated large volumes of oil and gas reservoired in fields, and discoveries for which the dominant source rock and its maturity have been established by oil to source rock correlation and geochemical biomarker analysis. The Skarfjell fluids were expelled from mid-mature oil source rocks of mixed Heather and Draupne Formation origin. The recoverable resources are estimated at between 9 and 16 million standard cubic metres (Sm 3 ) of recoverable oil and condensate, and 4–6 billion Sm 3 of recoverable gas. The Skarfjell discovery is currently in the pre-development phase and is expected to come on stream in 2021.
ABSTRACT Numerous field and subsurface studies have shown the sensitivity of gravity-flow deposits to seafloor topography. Understanding the driving mechanisms of paleo-seafloor evolution will provide insights to the depositional architecture of such successions. The Gudrun field of Block 15/3 in the Norwegian Vilje subbasin in the South Viking Graben (SVG) exploits such sandstone reservoirs in the Upper Jurassic Draupne Formation. Spatial definition of the reservoir is hampered by low or even absent impedance contrast. However, detailed reservoir characterization based on sedimentological, petrophysical, petrological, and outcrop analog data in conjunction with dipmeter data, helped to optimize the development and production of this field. In the study area, the middle Oxfordian to Tithonian Draupne Formation ranges in thickness from 350 m to more than 800 m (1100–2600 ft) and is divided into Draupne Formation 1 (oldest) to 4 (youngest). Targeted reservoirs are the gas-condensate-filled Draupne Formation 1 and the oil-filled Draupne Formation 3. Dipmeter data in conjunction with a 2-D structural reconstruction indicate that the depositional slope in the Vilje subbasin was primarily controlled by the flexural downbending of the Brae hanging wall, resulting in a drowning of the eastern SVG shelf and the retrogradation of the Oxfordian Draupne Formation 1. Coeval normal faulting along the Gudrun fault created hydraulic jumps in seafloor topography, leading to preferential deposition of Draupne Formation 1 in the Gudrun hanging wall. Draupne Formation 1 and 2 were deposited in a sand-rich, channelized lobe system with a high net-to-gross (>70% sand), and good lateral and vertical connectivity. Seismic mapping revealed that sediments were transported from the Utsira High into the SVG via long-lived antecedent southeast-northwest-trending canyons during the Oxfordian to Early Cretaceous. Draupne Formation 3 was deposited in a channelized slope system (20–40%sand), resulting in higher heterogeneity and thus lower connectivity compared to Draupne Formation 1. Also, Draupne Formation 3 records the onset of inversion of the Gudrun hanging wall and the subsequent growth of the Gudrun fold, marking thus a fundamental change in seafloor topography. Progradation of Draupne Formation 2 and 3 suggests increased sediment flux from the Utsira High, which may be triggered by the observed shift toward more arid conditions or uplift of the Utsira High by lithospheric folding related to basin inversion. Finally, the turbidites of the Draupne Formation were deposited during a prolonged relative sea-level rise in the Late Jurassic. Therefore, eustatic sea-level fluctuations are considered to be of minor importance in controlling the depositional architecture of the Upper Jurassic turbidite system in the Gudrun area.
ABSTRACT Synrift to early postrift Upper Jurassic submarine fan sequences form the reservoirs of numerous large oil and gas condensate fields in the South Viking Graben. The largest of these fields are in the Brae area, on the western side of the graben. Here, proximal conglomerate and sandstone facies of the Brae Formation host the South Brae, Central Brae, and North Brae fields, each within its own discrete submarine fan unit. More distal, basin-floor sandstone facies derived from the later episodes of South Brae and North Brae fan activity host the Miller, Kingfisher, and East Brae fields. Interfan areas comprise thick sequences of fine-grained sediments, which provide very significant lateral stratigraphic trapping elements for all the fields. An extensive well and seismic data set now allows a more detailed tectonostratigraphic evaluation of the Jurassic reservoir sequences in the context of the development of the graben and footwall than was previously possible. The submarine fans resulted from the uplift of the Fladen Ground Spur footwall to the west, with the consequent erosion and redeposition into the graben of very large volumes of gravel, sand, and mud. A prerift sequence of the Bathonian alluvial to paralic Sleipner Formation, which culminated with deposition of an extensive coal unit, extends across the graben and was probably also deposited on the footwall. Late Jurassic rifting began in the early Callovian, with deposition of the Hugin Formation in a shallow marine setting, with sand and mud supplied from the low-relief platform area to the west. Episodes of abrupt but slight deepening of the basin, caused by initial fault movements at the graben boundary, are suggested by numerous sharp-based coarsening-upward sequences within this formation. Following a period of apparent quiescence, when the Fladen Ground Spur may have been flooded, the main rift phase began in the late Oxfordian when subsidence of the graben margin and uplift of the footwall resulted in a deep marine trough and subaerial relief on the footwall probably totaling several thousand feet (hundreds of meters). Early submarine fan systems are likely to have been relatively unorganized cones of conglomerate and sandstone deposited from noncohesive debris flows and high-density turbidity currents. Fan systems became more organized upward as accommodation space close to the graben margin was filled following the climax of rifting in the late Kimmeridgian, and two large proximal to basin-floor fan systems developed at South Brae and North Brae, with conglomeratic channels in the proximal areas and sheetlike sandstone units on the basin floor. In the later stages of Brae Formation deposition, the top of the footwall is likely to have been close to sea level, which allowed periodic flooding of the source area and deposition of regionally extensive, relatively thin mudstone units across the fans, which act as internal reservoir baffles within fields. At the peak of fan deposition, during the early Volgian, the three main fan systems in the area (the South, Central, and North Brae fans) plus several smaller fans were all active. However, fans became inactive sequentially, with deposition first on the Central Brae, then on the South Brae, and finally on the North Brae fans ceasing relatively abruptly as the Fladen Ground Spur was progressively transgressed. Deposition of mudstones of the Kimmeridge Clay Formation, which are the hydrocarbon source rocks and the top seals for the fields and with which the Brae Formation interdigitates, continued after fan deposition ceased, into the earliest Cretaceous. The current sub-Upper Jurassic basement rock types of the footwall in the immediate area of the Brae fields comprise well-lithified Devonian sandstones and a significant but minor area of Silurian granite. However, the origin of the coarse clastic detritus, particularly the sands, within the Upper Jurassic fan systems was not simply a result of erosion of these rock types. Regional mapping and provenance studies suggest that a considerable thickness of Middle Jurassic, Triassic, and Permian sedimentary rocks previously overlay the present-day basement rocks of the footwall. These strata were probably almost completely eroded from the area immediately west of the fields where footwall uplift is likely to have been the greatest and redeposited into the graben during the Late Jurassic.
The value of fault analysis for field development planning
Assessing source rock distribution in Heather and Draupne Formations of the Norwegian North Sea: A workflow using organic geochemical, petrophysical, and seismic character
Sedimentology and sequence stratigraphy of the Middle–Upper Jurassic Krossfjord and Fensfjord formations, Troll Field, northern North Sea
Sedimentology and sequence stratigraphy of the Hugin Formation, Quadrant 15, Norwegian sector, South Viking Graben
Abstract The Middle Jurassic Hugin Formation has been the target of exploration within Quadrant 15 of the Norwegian South Viking Graben since the 1960s. The Hugin formation comprises shallow-marine and marginal-marine sediments deposited during the overall transgression and southward retreat of the ‘Brent Delta’ systems. Sedimentological analysis of cores across the quadrant has identified six facies associations: bay-fill, shoreface, mouth bar, fluvio-tidal channel-fill, coastal plain and offshore open marine. These facies associations are arranged in a series of parasequences bounded by flooding surfaces, several of which are correlated regionally using biostratigraphic data. Within this stratigraphic framework, facies association distributions and stratigraphic architectures are complicated, reflecting the spatial and temporal interaction of various physical processes (e.g. waves and tides) with an evolving structural template produced by rift initiation and salt movement. The overall transgression was highly diachronous, becoming younger from north to south. The northern part of the study area (Sigrun–Gudrun area) is characterized by a series of backstepping, linear, north–south-trending barrier shorelines and sheltered bays. The central part of the study area (Dagny area) contains stacked, backstepping strandplain shorelines that fringed syn-depositional topographic highs. Local angular unconformities are developed around these highs, implying that they formed above fault-block crests and salt-cored structures. The southern part of the study area (Sleipner area) contains stacked deltaic shorelines that were modified by both waves and tides. Sandbody geometry is closely related to depositional regime and syn-depositional tectonic setting within the basin; a robust understanding of both is critical to successful exploration of Hugin Formation reservoirs.
Abstract A high magnitude of overpressure is a characteristic of the deep, sub-Chalk reservoirs of the Central North Sea. The Upper Cretaceous chalk there comprises both reservoir and non-reservoir intervals, the former volumetrically minor but most commonly identified near the top of the Tor Formation. The majority of non-reservoir chalk has been extensively cemented with average fractional gross porosity of 0.08, and permeability in the nano- to microDarcy range (10 −18 –10 −21 m 2 ), and sealing properties comparable to shale. Hence deeply buried chalk is comparable to shale in preventing dewatering and allowing overpressure to develop. Direct pressure measurements in the Chalk are restricted to the reservoir intervals, plus in rare fractured chalk, but reveal that Chalk pressures lie on a pressure gradient which links to the Lower Cenozoic reservoir above the Chalk and the Jurassic/Triassic reservoir pressures below. Hence a pore pressure profile of constantly increasing overpressure with increasing depth is indicated. Mud weight profiles through the Chalk, by contrast, show many borehole pressures lower than those indicated by these direct measurements, implying wells are routinely drilled underbalanced. The Chalk is therefore considered the main pressure transition zone to high pressures in sub-Chalk reservoirs. In addition to its role as a regional seal for overpressure, the Base Chalk can be shown to be highly significant to trap integrity. Analysis of dry holes and hydrocarbon discoveries relative to their aquifer seal capacity (the difference between water pressure and minimum stress) shows that the best empirical relationship exists at Base Chalk, rather than Base Seal/Top Reservoir, where the relationship is traditionally examined. Using a database of 65 wells from the HP/HT area of the Central North Sea, and extending the known aquifer gradients from the Fulmar reservoirs via Base Cretaceous to Base Chalk, leads to a risking threshold at 5.2 MPa (750 psi) aquifer seal capacity. Discoveries constitute 88% of the wells above the threshold and 36% below, with 100% dry holes where the aquifer seal capacity is zero (i.e. predicted breached trap). This relationship at Base Chalk can be used to identify leak points which control vertical hydrocarbon migration as well as assessing the risk associated with drilling high-pressure prospects in the Central North Sea.