Middle Jurassic Brent Group Research Articles

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.

The Penguins Cluster, Blocks 211/13a and 211/14, UK North Sea

Abstract The Penguins Cluster of fields are owned jointly (50:50) by Shell UK Ltd (Shell) and Esso Exploration and Production UK Ltd (Esso), with Shell as the operator. The cluster was discovered in 1974 and is composed of a combination of oil and gas condensate accumulations located 50–65 km north of the Brent Field, at the northern end of the North Viking Graben. Two main producing reservoirs are present: the Penguins West Field (Penguin A) consists of an Upper Jurassic Magnus Sandstone Member reservoir, while the Penguins East Field (Penguin C, D and E) consists of a Middle Jurassic Brent Group reservoir, underlain by currently undeveloped Statfjord and Triassic (Cormorant) reservoirs. The Magnus reservoir is composed of turbidite sands with an average porosity of 15% and permeabilities of 0.10–300 mD. The Brent reservoirs are composed of deltaic shoreface deposits with an average porosity of 14% and permeabilities of 0.01–1000 mD. The fields were brought on stream in 2003 as a subsea development via what at the time was the world's longest comingled tieback to the Brent Charlie facility. A total of nine producing wells have been drilled from four subsea manifolds, producing c. 78 MMboe to date through depletion drive.

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.

Characterization of effective permeability in heterolithic, distal lower-shoreface sandstone reservoirs: Rannoch Formation, Brent Group, UK North Sea

The reservoir properties of distal lower-shoreface and distal wave-dominated delta-front deposits, which consist of sandstone beds with locally scoured bases and mudstone interbeds, are poorly understood. The lower Rannoch Formation (Middle Jurassic Brent Group) forms an interval of such heterolithic sandstones in many North Sea reservoirs, and is used to illustrate a workflow for rapid estimation of reservoir properties and their sensitivity to key parameters. Mudstone-interbed thickness distributions in cored reservoir successions are compared to the thickness distribution of sandstone scour-fills in an outcrop analogue(s) in order to identify mudstones with the potential to form laterally extensive barriers to vertical flow. Effective k v / k h at the scale of several typical reservoir-model grid cells (200 × 100 × 20 m) is estimated in intervals bounded by these mudstone barriers via a simple analytical technique that is calibrated to previously documented reservoir-modelling experiments, using values of sandstone proportion measured in cored reservoir successions. Using data from the G2 parasequence (Grassy Member, Blackhawk Formation, east-central Utah, USA) outcrop analogue, mudstones bounding 3–8 m-thick, upwards-coarsening successions in the lower Rannoch Formation may define separate stratigraphic compartments in which grid-cell-scale effective k v / k h is estimated to be 0.0001–0.001 using a streamline-based analytical method.

Quantification of uncertainty in 3-D seismic interpretation: implications for deterministic and stochastic geomodeling and machine learning

Abstract. In recent years, uncertainty has been widely recognized in geosciences, leading to an increased need for its quantification. Predicting the subsurface is an especially uncertain effort, as our information either comes from spatially highly limited direct (1-D boreholes) or indirect 2-D and 3-D sources (e.g., seismic). And while uncertainty in seismic interpretation has been explored in 2-D, we currently lack both qualitative and quantitative understanding of how interpretational uncertainties of 3-D datasets are distributed. In this work, we analyze 78 seismic interpretations done by final-year undergraduate (BSc) students of a 3-D seismic dataset from the Gullfaks field located in the northern North Sea. The students used Petrel to interpret multiple (interlinked) faults and to pick the Base Cretaceous Unconformity and Top Ness horizon (part of the Middle Jurassic Brent Group). We have developed open-source Python tools to explore and visualize the spatial uncertainty of the students' fault stick interpretations, the subsequent variation in fault plane orientation and the uncertainty in fault network topology. The Top Ness horizon picks were used to analyze fault offset variations across the dataset and interpretations, with implications for fault throw. We investigate how this interpretational uncertainty interlinks with seismic data quality and the possible use of seismic data quality attributes as a proxy for interpretational uncertainty. Our work provides a first quantification of fault and horizon uncertainties in 3-D seismic interpretation, providing valuable insights into the influence of seismic image quality on 3-D interpretation, with implications for deterministic and stochastic geomodeling and machine learning.

Role of forced regression in controlling Brent Group reservoir architecture and prospectivity in the northern North Sea

The Middle Jurassic Brent Group of the northern North Sea presents a mature and highly productive reservoir play fairway where a combination of effective facies analysis and depositional sequence stratigraphy offers real potential to optimize exploitation. The north of the Brent province differs from classically studied southern areas in being dominated by marginal-marine delta-front facies. A core- and log-based study of 37 wells around the Don fields was performed to establish a sequence stratigraphic framework, map facies and thereby describe facies architecture. The results demonstrate that reservoir quality and productivity are regionally and locally controlled by facies. Of particular interest are intervals of fluvio-estuarine channel to sharp-based shoreface sandstone that formed during sea-level lowstands, since it is these packages that boost well productivity but, conversely, also increase the risk of early water breakthrough on production. Analogy with the Saloum Delta of Senegal highlights the importance of rapid and continuous barrier migration and destruction in controlling the deflection and switching of fluvio-estuarine channels, explaining also the preferential preservation of channel-floor deposits over continuously eroded barrier and delta-top facies. Interpretations suggest that deposition in the study area was dominated by punctuated progradation of the Brent Delta, as periods of delta plain incision alternated with episodes of base-level rise and delta aggradation/progradation. A model of regression for the Brent Delta is presented, where the Rannoch, Etive and Ness formations are an amalgam of highstand, falling stage and lowstand systems tract deposits, and the Tarbert Formation is a transgressive systems tract deposit, with the delta responding to regional relative sea-level changes driven by uplift and deflation of the mid North Sea dome. The prograding Brent Delta is characterized as a succession of attached shorefaces formed by alternating periods of normal and forced regression. Significantly, this explains the long distance (>200 km) build out of the Brent Delta and the continued presence of coarse-sandstone packages, as well as the potential for high-quality reservoirs even in the distal reaches of the system. It also suggests that there is limited potential for lowstand fan plays beyond the northernmost tip of the delta.

Designer wells to maximize recovery for Otter Field development, Northern North Sea

The 2002 to 2003 Otter Field development drilling campaign utilized a combination of detailed trajectory planning and integrated geosteering techniques. The objective of this work was to maximize oil recovery, with a minimal number of wells, from the complexly faulted Otter structure. To achieve this, subhorizontal production wells were planned to track near top reservoir, through the structural culminations, to connect adjacent fault blocks. Otter is the most northwesterly of the Brent Province fields of the Northern North Sea, located in UK blocks 210/15a and 210/20d, 530 km north of Aberdeen, operated by TOTAL with partners Shell U.K. Exploration and Production, ExxonMobil and Dana. The field was discovered by the Phillips 210/15-2 well in 1977 (then called Wendy) and appraised by Fina well 210/15a-5 in 1997, following 3D seismic acquisition in 1994. The decision to proceed with development was confirmed after the success of appraisal well 210/15a-6 drilled by TotalFina in 2000. The Otter structure is an easterly dipping tilted panel that is divided into four major blocks and several minor blocks by a network of subsidiary faults. The reservoir is the Middle Jurassic Brent Group, with the uppermost Tarbert Formation shallow marine sandstones comprising the main producing target. The oil source rock is the Late Jurassic Kimmeridge Clay, present in the off-structure areas, though locally absent over the Otter Field area. Top seal is provided by the Mid- to Late Jurassic Heather Shales. The Otter oil is a medium gravity crude (36.5° API) with a GOR of 79m 3 /m 3 (443 scf/bbl), in a normally pressured reservoir at a crestal depth of 1970m subsea. Otter well planning was conducted using a 3D geocellular model based on interpretation of both conventional and acoustic impedance inversion seismic datasets. Apilot study, prior to development drilling, included geochemical and petrophysical reservoir unit definition and the forward modelling of LWD log response in sub-horizontal wells. The results of these studies were used to aid geosteering, incorporating real time chemostratigraphy and LWD data at the wellsite. In addition, borehole resistivity images while drilling were used to assist in structural interpretation in real time and thus to guide the well trajectory to maximize the pay section. A key component in using these new technologies was the office-based integration of all the data via web-based monitoring of the operations. Three production wells target the culminations at the extremities of the Otter Field, supported by a downdip water injector, all drilled from a centrally located subsea template. Following the successful drilling of the first production well, 210/215a-T1, production start-up was in October 2002, via subsea tieback to the Eider facility.

4D elastic inversion helps locate in-fill wells at Oseberg field

H. Rutledal, Norsk Hydro E&P, and J. Helgesen and H. Buran, both with CGG Norge, describe how, 4D elastic inversion for the Oseberg field was combined with modern 3D visualisation techniques to support the reservoir history matching process and detect areas of undrained reserves. Several successful in-fill wells have been planned and drilled based on the integrated analysis of inversion results, well data and reservoir models. Oseberg is a major oil and gas field operated by Norsk Hydro in the North Sea some 140 km off the coast of Norway. The reservoir comprises sandstones from the Middle Jurassic Brent Group in three eastward-dipping, tilted fault-blocks. Production at the Oseberg field started in 1988. The production plateau was reached in 1992, and production started to decline in 1996. Currently, close to 85% of the initial oil reserves have been produced. The challenge facing the operator Norsk Hydro is to maximise the economic value of the field by increasing oil recovery. Additional in-fill drilling, guided by 4D seismic interpretation, was identified as a way of achieving this. A monitor survey was acquired in 1999 and combined with a base survey from 1992. The two vintages were processed using a 4D sequence to maximise repeatability. In order to exploit the full potential of the 4D data, an elastic inversion of the 1999 vintage was carried out for reservoir characterisation purposes, using a 3D layer-based inversion (StrataVista). After successful testing, this elastic inversion was extended to the 1992 data for mapping of production effects.

The Heather Field, Block 2/5, UK North Sea

abstract The Heather oil field is located in Block 2/5 in the Northern North Sea. Oil is produced from sandstones of the Middle Jurassic Brent Group. at depths between 9500ft and 11600 ft below sea level. The field has been in production for over 20 years, and to date 120 MMSTB of oil have been produced out of an oil-in-place volume of 464 MMSTB. Although approaching non-commercial flow rates, an ambitious programme of field re-evaluation has been conducted since 1997 to identify remaining infill potential, and to investigate the development potential of satellite accumulations. New 3D seismic surveys shot in 1995 and 1997 have been combined to produce a continuous top reservoir map of the main field and adjacent satellite structures. The new mapping and an updated reservoir description were integrated with reservoir simulation models to identify zones of unswept oil. Main field infill projects have been identified which target the unswept oil, allowing extension of field life to be planned in conjunction with satellite field development. An additional 57 MMSTB of recoverable oil are expected to be produced from Middle Jurassic reservoirs in the main field and in satellite areas.

The Dunbar, Ellon and Grant Fields (Alwyn South Area), Blocks 3/8a, 3/9b, 3/13a, 3/14, 3/15, UK North Sea

Abstract The Dunbar, Ellon and Grant oil and gas fields (also known as the Alwyn South area) are located in the southeastern part of the East Shetland Basin, approximately 140 km E of the Shetland Islands. Most of the accumulations lie in Blocks 3/9, 3/14 and 3/15, which are parts of Licence P090 operated by Total Oil Marine pic (33.33%) with Elf Exploration UK PLC as sole partner (66.67%). Ellon was discovered in 1972, Dunbar in 1973 and Grant in 1977. Dunbar consists of a number of generally N-S trending, westerly dipping Mesozoic fault blocks with variable amounts of crestal erosion. Reservoir is provided by fluvial, deltaic and shallow marine sandstones of the Middle Jurassic Brent Group, Lower Jurassic Statfjord Formation and Upper Triassic Upper Lunde Formation. The Brent oil composition of Dunbar varies with depth and evolves from volatile oil at the base of the column to gas condensate at the top without a discontinuity of composition. In addition there is a small gas accumulation within a Paleocene submarine fan reservoir in a compactional structure. Ellon consists of two westerly dipping fault blocks with gas condensate contained within the Brent Group. Grant is one westerly dipping fault block with gas condensate in the Brent Group. In both the Ellon panels and also in Grant, thin waxy oil 'rims' are found below the gas. The depth of the shallowest structural crest within the Alwyn South complex is 3100 m TVDSS, with the deepest proven hydrocarbon at around 3800 m TVDSS. Sealing for the Alwyn South accumulations is provided by various combinations of Cretaceous, Upper Jurassic (Heather and Kimmeridge Clay Formations) and Lower Jurassic (Dunlin Group) mudstones. The source rock for the hydrocarbons is the Upper Jurassic Kimmeridge Clay Formation, which is mature and adjacent to the fields. These accumulations are being developed from a tender-assisted minimally manned fixed platform with a total of 28 well slots located over the Dunbar Field, in a water depth of 145 m. The Ellon and Grant Fields are produced as sub-sea satellites to Dunbar from a well-head cluster located between Ellon and Grant, in a water depth of 135 m. First oil and gas production from Dunbar and Ellon was in December 1994 and gas production commenced from Grant in July 1998. The time lag between discovery and development reflects the complex geology (structure, compartmentalization, reservoir thickness variations, dia-genesis and differing hydrocarbon compositions) with a total of 28 exploration and appraisal wells being drilled in the Alwyn South area between 1971 and 1998. Total oil and gas initially in place is in the order of 850 MMBBL and 2.62 TCF respectively, with the current estimate for ultimate recoverable reserves being 200 MMBBL liquids and 1.28 TCF gas.

Innovative use of petrophysics in field rehabilitation, with examples from the Heather Field

The Heather oil field is located in the Northern North Sea and is operated by DNO Heather Limited. Oil is produced from sandstones of the Middle Jurassic Brent Group. Although approaching non-commercial flow rates, infill projects are under way which target unswept oil. At this late stage in field life, projects are typified by extracting as much new oil from the field as possible with minimal expenditure. These result in incomplete or degraded log data. This paper describes how the application of innovative techniques can replace data shortfalls, providing quality data without compromising budgetary constraints. Four infill wells were drilled during 2000 and 2001. Innovative petrophysical techniques have been used to enhance the electric log data gathered. Fuzzy logic techniques have been applied to predict reservoir permeability and choose perforating intervals. Some sections of the highly deviated wells were necessarily logged in sliding mode and fuzzy logic was also used to repair the resulting degraded log curve data. Following the infill well programme, field production has increased from 5000 BBL oil per day (BOPD) to 7000 BOPD. This success was partly due to the better location of wells, particularly 2/5-H62Y, because of the improved reservoir model resulting from these petrophysical techniques. The height above free-water level (HAFWL) was estimated across the Heather Field using the so-called FOIL function (bulk volume of water plotted as a function of HAFWL) ( Cuddy 1993 ). The FOIL function has given valuable insights into free-water level variation across the Heather Field and has improved water saturation modelling. A method is presented in this paper for geosteering using the FOIL function.

3D oil migration modelling of the Jurassic petroleum system of the Statfjord area, Norwegian North Sea

3D oil migration modelling of the Statfjord area of the Northern North Sea has led to increased understanding of the migration routes and definition of oil migration fairways. The majority of discovered fields in the Statfjord area lie on fault block ridges. Migration modelling demonstrates that they were filled by oil generated from the Viking Graben, East Shetland and Marulk basins, migrating stratigraphically downwards from the Upper Jurassic Draupne Formation source rock into the Middle Jurassic Brent Group sandstones. Thereafter, lateral migration in a fill–spill manner occurred along the axes of the ridges. Locally, petroleum also migrated laterally through both Upper and Lower Jurassic sandstones. The migration modelling has been combined with geochemical source rock and oil correlation resulting in increased confidence. For the first time we have been able to quantitatively model and visualize the complex petroleum system of the area and gain an insight into its development through geological time.

ABSTRACT: Integrated use of 3D Visualisation, Sedimentology and Seismic Modelling of Subtle Syn-rift plays on the West Flank of the Oseberg Field, Norwegian North Sea

Present production of hydrocarbons on the west flank of the Oseberg Field, Norwegian North Sea is from the Middle Jurassic Brent Group. However, there is evidence that considerable additional reserves exist in Upper Jurassic syn-rift marine sandstones in an area characterised by complex structural and stratigraphic traps. Recent work has revealed that the distribution of syn-rift sands is intimately related to the contemporaneous growth and linkage of extensional faults bounding tilted fault blocks on the terraced west flank of the field. Lateral and vertical growth of faults has also resulted in the development of fault propagation folds and emergent fault block crests. Sands are considered unlikely to be laterally extensive in such a complex setting and the seismic data indicate a variety of depositional environments ranging from attached shoreline systems to turbidites infilling large channels. Extensive use of 3D visualisation techniques (formation sculpting, voxel rendering, virtual reality) coupled with seismic modelling has been used to map the geometry and distribution of the syn-rift sandbodies. The combination of these technologies coupled with the integration of structural and stratigraphic models has lead to an increased understanding of the interaction between fault growth and linkage with the eventual aim of delineating subtle syn-rift plays.

Abstract: Application of 3D stratigraphic forward modelling to improve reservoir prediction - Middle Jurassic Brent Group, North Sea

Abstract: Application of 3D stratigraphic forward modelling to improve reservoir prediction - Middle Jurassic Brent Group, North Sea

Syn-rift evolution and resulting play models in the Snorre-H area, northern North Sea

Abstract An upper Jurassic, wedge-shaped syn-rift succession, comprising the Heather and Draupne Formations, is present in the hangingwall trough of the Snorre Fault Block. The succession is bounded to the west by the Statfjord East Fault, whereas it onlaps the snorre Fault Block to the east. It consists of a two-fold coarsening-upward sequence from shale to sandstone of shallow marine/shoreline origin. Active fault block rotation and subsidence in the Snorre-H area commenced in the Mid-Bathonian and lasted through the Ryazanian. The Heather Formation was deposited during the early rift stage (Mid-Bathonian-Early Oxfordian; 3° cumulative tilt), whereas the Draupne Formation (Late Oxfordian-Ryazanian; 9° cumulative tilt) accumulated during the main and late rift stages. The lower part of the Heather Formation was likely deposited across a submerged tilted fault block terrain, with a predominant extra-basinal sediment supply. Deposition of the upper Heather Formation, however, was governed by gradually emerging footwall islands, albeit yet without significant local erosion. As a result of increased fault/block rotation during deposition of the Draupne Formation Shale, Sequences I–II (late Early Oxfordian-early Mid-Volgian) footwall islands became firmly established, providing a predominant local sediment source to the Snorre-H sub-basin. Clay and silt were supplied from erosion of the Heather Formation on the Snorre-H hangingwall, with subordinate input of sand from the Statfjord East footwall. Subsequent deposition of the Draupne Formation, Sequences III–V (Late Mid-Volgian-Ryazanian), was governed by significant relief on the footwall islands, causing deep erosion into the Brent Group on the Snorre-H hangingwall dip-slope and leading to progradation of the Upper Draupne Sandstone shoreline complex across the Snorre-H area. Deposition of the Draupne Formation and temporal shoreline position were likely partly controlled by northwards fault-tip propagation of the Statfjord East Fault. Various syn-rift play models and depositional reservoir facies are present within the Snorre-H hangingwall basin. They include dip-slope shallow marine/shoreline sands, basin floor gravity transported sands and likely footwall talus sands enveloped in organic rich shales of the Draupne Formation. The distribution of reservoir facies is intimately linked to exposure and erosion of the middle Jurassic Brent Group below the syn-rift unconformity.

Modeling Quartz Cementation and Porosity in Middle Jurassic Brent Group Sandstones of the Kvitebjørn Field, Northern North Sea

Petrographic study of deeply buried Middle Jurassic Brent Group sandstones from the Kvitebjorn gas field in the Norwegian sector of the North Sea shows that quartz cement volumes range from less than 1% to almost 30% over short distances, and porosity ranges from 5 to 30%. A clear correlation between quartz surface area and quartz cement volume indicates that this variation is due to differences in quartz surface area available for quartz overgrowth formation, which, in turn, is a function of grain size, abundance of grain coatings, and quartz clast abundance. The correlation between quartz surface area and quartz cement volume also suggests that the quartz cementation process is a strongly precipitation rate-controlled process, and that quartz cementation can indeed be modeled quantitatively by modeling the precipitation step in the quartz cementation process. Using temperature history, detrital mineralogy, grain size, and grain coating abundance as input, quartz cement volumes were for 90% of the samples modeled to within 4% or less of observed values with the EXEMPLAR® diagenetic modeling program. Modeled porosities deviate from measured values by less than 3% for 75% of the samples, and the difference between measured and modeled porosities exceeds 5% for only two of the 40 samples. Deviations between modeled and measured quartz cement volumes do not correlate with distance to nearest stylolite, but a tendency for underestimating quartz cement in samples with low quartz surface areas may possibly be present. Comparison with results from modeling of quartz cementation in other sandstones shows that optimal fit between measured and modeled quartz cement volumes is not always obtained with the same values for the kinetic parameters controlling quartz precipitation rate per unit surface area as a function of temperature. The variation in optimal kinetics between data sets is probably partly due to inaccurate temperature histories, but improving the quartz surface area function may also reduce the range of optimal values for the kinetic parameters. Olav Walderhaug is employed in Statoil's exploration technology division in Stavanger, Norway, where diagenesis and reservoir quality prediction are his main areas of responsibility. Olav holds an M.Sc. degree in petroleum geology from the University of Bergen and a D.Sc. degree in sandstone diagenesis from the University of Oslo. His research interests are mainly within sandstone diagenesis and related topics, including the development of quantitative models of cementation, porosity evolution, and basin subsidence.

Abstract: 3D Regional Stratigraphic Modelling of the Middle Jurassic Brent Group, North Sea

Abstract: 3D Regional Stratigraphic Modelling of the Middle Jurassic Brent Group, North Sea

Sequence stratigraphy of source and reservoir rocks in the Upper Permian and Jurassic of Jameson Land, East Greenland

Approximately half of the hydrocarbons discovered in the North Atlantic petroleum provinces are found in sandstones of latest Triassic – Jurassic age with the Middle Jurassic Brent Group, and its correlatives, being the economically most important reservoir unit accounting for approximately 25% of the reserves. Hydrocarbons in these reservoirs are generated mainly from the Upper Jurassic Kimmeridge Clay and its correlatives with additional contributions from Middle Jurassic coal, Lower Jurassic marine shales and Devonian lacustrine shales. Equivalents to these deeply buried rocks crop out in the well-exposed sedimentary basins of East Greenland where more detailed studies are possible and these basins are frequently used for analogue studies (Fig. 1). Investigations in East Greenland have documented four major organic-rich shale units which are potential source rocks for hydrocarbons. They include marine shales of the Upper Permian Ravnefjeld Formation (Fig. 2), the Middle Jurassic Sortehat Formation and the Upper Jurassic Hareelv Formation (Fig. 4) and lacustrine shales of the uppermost Triassic – lowermost Jurassic Kap Stewart Group (Fig. 3; Surlyk et al. 1986b; Dam & Christiansen 1990; Christiansen et al. 1992, 1993; Dam et al. 1995; Krabbe 1996). Potential reservoir units include Upper Permian shallow marine platform and build-up carbonates of the Wegener Halvø Formation, lacustrine sandstones of the Rhaetian–Sinemurian Kap Stewart Group and marine sandstones of the Pliensbachian–Aalenian Neill Klinter Group, the Upper Bajocian – Callovian Pelion Formation and Upper Oxfordian – Kimmeridgian Hareelv Formation (Figs 2–4; Christiansen et al. 1992). The Jurassic sandstones of Jameson Land are well known as excellent analogues for hydrocarbon reservoirs in the northern North Sea and offshore mid-Norway. The best documented examples are the turbidite sands of the Hareelv Formation as an analogue for the Magnus oil field and the many Paleogene oil and gas fields, the shallow marine Pelion Formation as an analogue for the Brent Group in the Viking Graben and correlative Garn Group of the Norwegian Shelf, the Neill Klinter Group as an analogue for the Tilje, Ror, Ile and Not Formations and the Kap Stewart Group for the Åre Formation (Surlyk 1987, 1991; Dam & Surlyk 1995; Dam et al. 1995; Surlyk & Noe-Nygaard 1995; Engkilde & Surlyk in press). The presence of pre-Late Jurassic source rocks in Jameson Land suggests the presence of correlative source rocks offshore mid-Norway where the Upper Jurassic source rocks are not sufficiently deeply buried to generate hydrocarbons. The Upper Permian Ravnefjeld Formation in particular provides a useful source rock analogue both there and in more distant areas such as the Barents Sea. The present paper is a summary of a research project supported by the Danish Ministry of Environment and Energy (Piasecki et al. 1994). The aim of the project is to improve our understanding of the distribution of source and reservoir rocks by the application of sequence stratigraphy to the basin analysis. We have focused on the Upper Permian and uppermost Triassic– Jurassic successions where the presence of source and reservoir rocks are well documented from previous studies. Field work during the summer of 1993 included biostratigraphic, sedimentological and sequence stratigraphic studies of selected time slices and was supplemented by drilling of 11 shallow cores (Piasecki et al. 1994). The results so far arising from this work are collected in Piasecki et al. (1997), and the present summary highlights the petroleum-related implications.

Application of High-Resolution Sequence Stratigraphy to Northwest Hutton Field, Northern North Sea: Implications for Management of a Mature Brent Group Field

The Middle Jurassic Brent Group reservoirs in Northwest Hutton comprise shallow-marine, marginal-marine, and coastal-plain reservoir sandstones of both channelized and sheet geometries. The connectivity and production characteristics of these sandstones can be predicted through the application of high-resolution sequence stratigraphic correlation techniques. The Broom Formation overlies a basal Brent sequence boundary and is a lowstand to transgressive systems tract tidal-estuarine complex. The overlying Rannoch Formation comprises shoreface sands that represent a highstand systems tract. The overlying Etive Formation is a multilayer fluvial to estuarine channelized system of near fieldwide development interpreted as incised valley fills. The superjacent Ness Formation is genetically related to the Etive and is the main oil-bearing interval over much of the field. The Lower Ness comprises mouth-bar parasequences and is interpreted to be a transgressive systems tract to the Etive lowstand. The Upper Ness is a nonmarine delta plain succession, interpreted as a highstand systems tract. Upper Ness channel sands typically correlate between several wells and are oriented west-east. An interval of widespread, stacked channels indicates a change in drainage orientation and is related to a high-frequency relative sea level fall. The uppermost reservoir unit is the Tarbert Formation, related to a further major sequence boundary. Original repeat formation tester data support a stratigraphically well- connected reservoir model. Compartmentalization exists and is due to stratigraphic layering (laterally persistent mudstones creating low vertical permeability) and variable dimensions of channels and valley fills.

The Middle Jurassic Oseberg Delta, Northern North Sea:  A Sedimentological and Sequence Stratigraphic Interpretation

The Aalenian Oseberg Formation (0-80 m thick) is an important reservoir unit in the Middle Jurassic Brent Group in the northern North Sea, consisting of multiple sets of sandy Gilbert-type deltas. Small-scale (1.5-10 m) fining-upward units seen in the gamma-ray log correspond with individual delta sets, as independently confirmed by steepening-upward trends seen in the dip log. Within each set, the steep foreset slopes typically show thinly bedded sandstone facies (avalanche grain flows), whereas the lower foreset slopes, toesets, and bottomsets are formed largely by massive sandstone facies (sandy debris flows). On an intermediate scale (up to 40 m), the gamma-ray logs show both fining-upward and coarsening-upward trends through stacked delta sets, and these trends, traceable between wells, are interpreted in terms of decelerating and accelerating rates of relative sea level rise, respectively. The relative abundance of the sandy debris-flow deposits reflects a periodic and significant instability of the delta's upper foreset slope, probably during times of increased water depth in front of the delta. The normal progradation of individual Gilbert-type sets, however, is likely to have been along a subhorizontal topography during periods of little or no change in water depth. The long-term change to produce the observed vertical stacking of deltaic sets was one of a generally rising relative sea level. Modeling of the sea level rise in a steplike manner can account for the rarity of topsets. The progressive eastward truncation of the underlying Drake Formation on the Horda Platform by the Oseberg Formation suggests tectonic uplift and a lowstand of sea level immediately prior to the development of the Oseberg deltas. The Oseberg Formation is thus seen as a lowstand prograding wedge that developed during an interval of relatively high sediment supply and a variably rising sea level, culminating in the latest Aalenian flooding seen in the base of the overlying Rannoch Formation. The dip-log data, integrated with cores and other logs, are critical to correctly interpreting the reservoir's internal architecture. The slope-readjustment model predicts that the development of stacked massive reservoir sandstones of Oseberg type will occur preferentially in local areas of high subsidence or syndepositional faulting, or where there is deeper water in the lee of already existing fault scarps.