Dunlin Group Research Articles

Chapter 3. Sequence stratigraphy scheme for the Lower Jurassic of the North Sea area

Abstract This chapter describes Lower Jurassic second-order sequences J00 and J10, and their component third-order sequences J1–J6 and J12–J18. Two sequences (J1 and J3) are new, four sequences (J2, J4, J12 and J16) are amended and one sequence (J17) is renamed. A significant unconformity at the base of the J12 sequence (Upper Sinemurian) is present near the base of the Dunlin Group in the North Viking Graben–East Shetland Platform and in the Danish Central Graben, and correlates with an equivalent unconformity around the margins of the London Platform, onshore UK. A marked unconformity at the base of the J16 sequence is recognized in the North Viking Graben and onshore UK, where it is related to structural movements on the Market Weighton High, eastern England. Several levels of carbon enrichment (carbon isotope excursions (CIEs)) and associated geochemical changes tie to J sequences defining maximum flooding surfaces: the Upper Sinemurian CIE equates to the base J6 maximum flooding surface (MFS), the basal Pliensbachian CIE ties to the base J13 MFS, the basal Toarcian CIE relates to the base J17 MFS and the Toarcian Ocean Anoxic Event corresponds with the base J18 MFS.

Impact of the lower Jurassic Dunlin Group depositional elements on the Aurora CO2 storage site, EL001, northern North Sea, Norway

Northern Lights is the CO2 transport and storage component of Longship, the Norwegian full-scale CCS project. Injection is planned into an under-explored sloping saline aquifer in the northern North Sea, the Johansen and Cook formations of the Lower Jurassic Dunlin Group. To bridge the information gap, well 31/5-7 (Eos) was drilled. The comprehensive dataset acquired was fundamental to interpret the depositional environment and determine the scale and spatial distribution of heterogeneities, as input to 3-D models aimed at improving storage resource assessment and understanding the injected CO2 plume behaviour over time. The interpreted gross depositional environments of the storage units are marginal- to shallow-marine, arranged in three successive fining-upwards intervals. The lower interval includes coastal deposits with mixed wave- and river influence, correlatable over a large distance, dominated by meso-scale heterogeneities. The middle interval records paralic deposits with a wave- and tidal- interplay generating higher vertical and lateral variability. The upper interval is interpreted as tidal-dominated, predominantly with cm-scale heterogeneities. The repeated fining-upwards trends are ideal for plume redistribution and efficient CO2 storage, and the reconstructed lateral depositional trends associated with generally good properties indicate a high storage potential. The Eos well data enabled building the properties distribution model, highlighting the importance of well control for storage evaluation.

Containment Risk Assessment of the Northern Lights Aurora CO2 Storage Site

Assessment of containment (storage site integrity) is a key activity in the evaluation, and a requirement for approval, of potential CO2 storage sites. Here we present the workflow used for, and key results of, the containment risk assessment (CRA) in the Northern Lights project, which is the transport and storage part of the Norwegian “Longship” full-scale CCS project. In the Northern Lights project, CO2 storage is planned to take place at the Aurora site (Exploitation license EL001), southwest of the Troll Field. Injection is planned into the sandstone-rich Johansen Formation (Lower Jurassic Dunlin Group). The argillaceous upper member of the Dunlin Group, the Drake Formation, provides the main seal for the storage reservoir. Several further barrier and baffle units and intervening sandstones are present between the Drake Fm. and the sand-rich units of the Viking Group, which contain the giant Troll field with a high level of depletion to date. The injection site is located downdip of – and stratigraphically deeper than – the Troll West gas province (TWGP). Injected CO2 is expected to move slowly over time buoyancy-driven up-dip (northwards), with a small proportion reaching eventually the structural trap underneath the TWGP. A key method utilized in the Aurora CRA is the bowtie method. Bowties were prepared for each identified “leakage” pathway (according to the definition in the EU CO2 Storage Directive, thus not implying any emission to the water column) instead of per “leakage” mechanism, as has been the case in previous CO2 storage CRAs. The bowties were designed to allow for updates, which took place as new data or interpretations became available. A major update occurred after drilling of a confirmation well at the planned injection site. Key results of the CRA are that the probability of any emissions into the water column due to “leakage” of CO2 out of the storage complex is very low to negligible. Important arguments for this conclusion are (i) the hydraulic separation of the Johansen Formation from the shallower, depleted Viking Group, as attested by pressure data in the confirmation well, and (ii) the proven effectiveness of the seal to the Viking Group sandstones, which have accumulated and stored hydrocarbons over geological time. Further, any CO2 reaching and blending into the hydrocarbon accumulations nearby (such as the Troll Field) is regarded to also have very low probability. Storage Complex Monitoring (SCM) is an integral element of the CRA to enable mitigating actions in case of indications for unpredicted behaviour or “leakage” of the injected CO2.

The Statfjord Field, Blocks 33/9, 33/12 Norwegian sector, Blocks 211/24, 211/25 UK sector, Northern North Sea

Abstract The Statfjord Field, the largest oil field in the Northern North Sea, straddles the Norway/UK boundary and is located on the southwestern part of the Tampen Spur within the East Shetland Basin. The accumulation is trapped in a 6-8° W-NW dipping rotated fault block comprised of Jurassic-Triassic strata sealed by Middle to Upper Jurassic and Cretaceous shales Reserves are located in three separate reservoirs: Middle Jurassic deltaic sediments of the Brent Group, Lower Jurassic marine-shelf sandstones and siltstones of the Dunlin Group; and Upper Triassic-lowermost Jurassic fluviatile sediments of the Statfjord Formation. The majority of reserves are contained within the Brent Group; and Statfjord Formation sediments which exhibit good to excellent reservoir properties with porosities ranging from 20-30% permeabilities ranging up to several darcies, and an average net-to-gross of 60-75%. The sandstones and siltstones of the Dunlin Group have poorer reservoir properties where the best reservoir unit exhibits an average porosity of 22%, an average permeability 300 raD and net-to-gross of 45% Structurally, the field is subdivided into a main field area characterized by relatively undeformed W-NW dipping strata, and a heavily deformed east flank area characterized by several phases of 'eastward' gravitational collapse Production from the field commenced in 1979 and as of January 2000, 176 wells have been drilled. The oil is undersaturated and no natural gas-cap is present. The drainage strategy has been to develop the Brent and Dunlin Group reservoir with pressure maintenance using water injection and the Statfjord Formation reservoir by miscible gas flood. However, a strategy to improve recovery by implementing water alternating gas (WAG) methods is gradually being implemented for both the Brent and Statfjord reservoirs. Current estimates indicate that by 2015 a total of 666 x 10 6 Sm 3 (4192 MMBBL) of oil will be recovered and 75 GSm 3 (2.66 TCF) gas will be exported from the field

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.

The Statfjord 3-D, 4-C OBC survey

This paper presents initial processing and interpretation of 3-D multicomponent seismic data acquired over parts of Statfjord Field in the last quarter of 1997. Statfjord Field, in the Tampen Spur area straddling the British/Norwegian border in the northern portion of the Viking Graben, covers about 500 km2 and has estimated oil reserves of 674×106 m3. Production started in 1979. The reservoir units are Jurassic sandstones of the Brent Group, Dunlin Group, and Statfjord Formation.

Evolution and geometries of gravitational collapse structures with examples from the StatfJord Field, northern North Sea

Gravitational collapse structures may range in scale from centimetres to hundreds of kilometres and affect both loose sediments and consolidated rocks. The area affected by gravitational failure will commonly be amphitheatre-like in map view, whereas a cross-sectional view will typically display a listric and concave upwards detachment surface. The degree of deformation increases in the direction of sliding. If movement of the sliding rocks is sufficiently slow, several intact slump blocks may be identified within the slide area. The movement of blocks may be translational or rotational. Two types of gravitational collapse structures are identified. In Type A, the newly-formed detachment reaches a free surface at the toe of the slide. In Type B, however, the listric detachment fault follows a weak layer and its displacement is accommodated by simultaneous slip along a major, steeper fault. This results in a ramp-flat-ramp fault geometry. Gravitational failure is observed along the east flank of the Statfjord Field, northern North Sea. The triggering mechanisms were probably earthquakes and high fluid pressures. Listric faults detached within soft shales and are associated with several rotated slump blocks that decrease in size away from the break-away zone. The slumping occurred in several phases. First, parts of the Brent Group failed. The detachment surface was within shales of the Ness Formation. Next, the slumping cut into the Dunlin Group and detached within the lower parts of the group (shales of the Amundsen Formation). Renewed slumping of the Brent Group occurred at the new break-away zone created by the Dunlin slumping. In the final stages of gravitational failure, slumping reached into the Stattjord Formation and detached within shales at the base of the unit or within shales of the uppermost Hegre Group. The relief created at the head (break-away zone) of Statfjord slumping caused renewed slumping of the Brent and Dunlin Groups. A study of gravitational failure analogues demonstrates several similarities in geometry in spite of differences in scale, lithology, degree of consolidation, and triggering mechanism.

Dunlin Group Sequence Stratigraphy in the Northern North Sea: A Model for Cook Sandstone Deposition

The Dunlin Group in the northern North Sea, consisting of the Johansen, Amundsen, Burton, Cook, and Drake formations of late Sinemurian- Toarcian age, hosts important hydrocarbon reservoirs in the Cook Formation sandstones. The Johansen Formation is associated with a relative fall of sea level and is interpreted to be a large sandstone delta confined within a broad incised valley at the base of the group. During a later stage of relative sea level rise, the finer grained Amundsen and Burton formations were deposited. The overlying Cook Formation consists of four sandstone tongues, each of which is characterized by a lower zone of sharp-based, upward-coarsening, thinly bedded shoreface sandstones and siltstones (reflecting forced regression during falling relative sea level) and an erosively based upper zone of thin tidal flat and thick deltaic/estuarine sandstones (reflecting lowstand incision, as well as initial progradation and subsequent transgressive backfill of estuaries during relative sea level rise). The Drake Formation shales were deposited during continued relative sea level rise. Several types of erosional surfaces are recognized within the studied succession: (1) sequence boundaries occur at the base of the Johansen Formation and within the Cook Formation, and represent the bottoms of incised valleys that truncate the underlying ©Copyright 1997. The American Association of Petroleum Geologists. All rights reserved.1Manuscript received May 4, 1995; revised manuscript received March 27, 1996; final acceptance September 12, 1996. 2Department of Geology/Paleontology, University of Zagreb, 10000 Zagreb, Croatia. 3Department of Geology/Geophysics, University of Wyoming, Laramie, Wyoming 82071. This paper was part of the sequence stratigraphy research project at the University of Bergen, Norway, and is a product of studies on the architecture of Lower Jurassic shelf sandstones of the northern North Sea. The work was sponsored by STATOIL through a VISTA fellowship awarded to T. Marjanac, and this support is gratefully acknowledged. We are grateful to D. Mellere and L. M. Falt for discussion and encouragement during the work. We also thank Else Lien for drafting the sections and Jane Ellingsen for reprographs. Constructive criticism from D. Nummedal, J. Webb, and K. T. Biddle on the final version of the manuscript is much appreciated.

Magnetostratigraphy of the Middle Jurassic Brent Group in the Oseberg oil field, northern North Sea

Magnetopolarity stratigraphy of the Brent Group and the uppermost part of the Dunlin Group has been established in two well cores from the Oseberg Field (well 30/6 - 7 and well 30/9-2), northern North Sea. Palaeomagnetic analysis of thermal demagnetization results defines a series of normal and reverse magnetozones in both wells. Remanent coercivity analysis of these Middle Jurassic clastic sediments indicates a magnetomineralogy independent of grain size interpreted to be of diagenetic origin, thus suggesting that the magnetization is of early post-depositional origin. Integration with the existing palynostratigraphic framework results in the establishment of several isochronous horizons, especially in the Ness Formation, which suggests lateral continuity of magnetostratigraphic datum planes between the two wells at the Oseberg Field. Although the exact dating of the magnetozones is not established, the combined application of magnetopolarity and biostratigraphy provides a stratigraphic framework of improved resolution for these rock formations.

The Murchison Field, Block 211/19a, UK North Sea

Abstract The Murchison oil field forms part of the Brent oil province in the East Shetland Basin, northern North Sea. The field, which straddles the UK-Norway international boundary, was discovered in 1975 and began production with Conoco (UK) Ltd as Operator, in 1980. Like many oil accumulations in the East Shetland Basin the trap consists of a northwesterly dipping rotated fault block of Jurassic-Triassic age sourced and sealed by unconformable Upper Jurassic shales. The productive reservoir consists of Middle Jurassic Brent Group sandstones which represent the south to north progradation of a wave/tide influenced delta system. The Brent Group on Murchison has an average thickness of 425 ft with average porosities of 22% and permeabilities in the 500-1000 md range in producing zones. The maximum hydrocarbon column thickness is approximately 600 ft. The oil is undersaturated and no gas cap is present. Recoverable reserves are 340 MMBBL from a total oil in place figure of 790 MMBBL. Oil production which is via a single steel jacket platform peaked at 127 000 BOPD in 1983 and currently averages 45 000 BOPD. Economic field life is expected to be at least 20 years. The Murchison Field is located in the East Shetland Basin, northern North Sea at approximate latitude 61° 23' N, longitude 1° 43.5' E, 120 miles northeast of the Shetland Islands (Fig. 1). The field straddles the UK-Norway international boundary with the greater portion in the UK Block 21 l/19a and the lesser portion in Norway Block 33/9. Water depth is -512 ft BMSL. In the context of the North Sea the field is of medium size with an areal closure of approximately 7 square miles and contains 790 million barrels of oil in place. The productive reservoir consists of coastal deltaic sandstones of the Middle Jurassic Brent Group which lie between the marine shales of the Lower Jurassic Dunlin Group and the marine, organic-rich shales of the Upper Jurassic Humber Group. The trap is structural comprising a single, northwesterly dipping rotated fault block which has been sourced and sealed by the overlying Upper Jurassic shales. The field is named after the Scottish geologist Sir Roderick Impey Murchison (1792-1871), who is best known for his contribution to Palaeozoic stratigraphy.

Application of a new preparative pyrolysis technique for the determination of source-rock types and oil/source-rock correlations

A new preparative pyrolysis technique enabling the recovery and fractionation (into saturated hydrocarbons, unsaturated hydrocarbons, and aromatic hydrocarbons) of the total C 6+ hydrocarbon fraction (instead of the C 13+ fraction usually recovered) has been applied to different types of source-rocks. The composition of the C 7–C 13 hydrocarbon fraction in the pyrolysate, particularly the amount of aromatic hydrocarbons as compared to alkanes, was found to be characteristic of each type of kerogen, with the alkane aromatic ratio consistently decreasing in the progression from Type I to Type III kerogens. While the C 13+ fraction is useful in kerogen typing, it was found that the C 7–C 13 hydrocarbon fraction, which represents 40 to 50% of the total recovered pyrolysate, was the most signficant in emphasizing differences between kerogen types, allowing a rapid and precise estimation of the source-rock type. This new technique was applied to potential source-rocks of the Viking Graben, North Sea (Draupne formation, Heather formation, Brent coals, and Dunlin group). In each case, the pyrolysates allowed us to determine whether the organic matter was Type II, Type III, or a mixture of both. Pyrolysis of asphaltenes from crude oils from the various regions was conducted and potential applications of our technique to studies of oil/source-rock correlations were examined.

Dunlin Field - A Review of Development and Reservoir Performance to Date

Summary This paper discusses the reservoir geology, fluid properties, and reservoir performance of the Dunlin properties, and reservoir performance of the Dunlin field in the U.K. sector of the northern North Sea. Because of the heavily faulted nature of the field, the development plan has needed continuous updating in the light of new geological and reservoir information. This has necessitated the use of a flexible plan beginning early in the history of the field. Introduction The Dunlin field is situated in the northern North Sea, close to the Norwegian boundary between latitudes 61 deg. 13'N and 61 deg. 19'N. It straddles the border between the Shell/Esso Block 211/23 and the Gulf/Conoco/British Natl. Oil Corp. Block 211/24. Both groups agreed early in the appraisal of the field to a unitized development with Shell as the operator. This approach has proved extremely beneficial to the efficient operation of the field. Of the fifteen development wells that have been drilled from a single concrete platform, 11 were producers, three were water injectors, and one was a dry hole. Oil is produced from the Middle-Jurassic Brent sands, encountered at depths from 8,700 to 9,700 ft true vertical depth subsea (TVSS). The field oil/water contact is found at approximately 9,165 ft TVSS, although "oil down to's" (ODT's) have been found significantly deeper in several appraisal wells. For the purpose of assessing reserves, the field has been subdivided into several "fault-bounded" blocks (see Fig. 1). The currently estimated remaining reserves of the field are 244 MMbbl, of which 212 MMbbl are within the unit area. Areas 3, 5, and 6 lie outside the Dunlin Unit area. The reservoir fluid is a highly undersaturated oil containing small quantities of solution gas. The bubble-point pressure, tank oil gravity, and solution GOR of most of the oil are 960 psi, 36 deg. API, and 240 scf/bbl, respectively (Table 1). psi, 36 deg. API, and 240 scf/bbl, respectively (Table 1). Geological Setting The Dunlin structure has an elongated north- northwest/south-southeast trend with extensions to the northwest and southwest. Dunlin is highly faulted and the majority of the reserves are contained in a central horst block (Area 1 of Fig. 1) bounded on the cast, south, and west by faults and on the north by dip closure. The sands of this block dip to the north and west and are truncated on the southeast by erosion at the top Brent level. The following reservoir subdivisions mapped in Dunlin are based on the stratigraphic nomenclature of Deegan and Scull:Tarbert plus Upper Ness,Mid-Ness shale,Lower Ness,Etive,Rannoch, andBroom. The Tarbert has been included (at least initially) with the Upper Ness because its presence or absence is very difficult to predict due to the uneven crestal erosion of the Brent sands. From Shell's sedimentological studies in this and neighboring fields, the geological history of the Jurassic has been reconstructed as follows. Toward the end of the Lower Jurassic Age, the area was dominated by marine conditions with the deposition of the shales and siltstones of the Dunlin group. The seas then shallowed and the Middle Jurassic sedimentation was represented by the deposition of the Brent group. This was deposited as a delta that prograded across the Dunlin shales from south to north. JPT P. 1713

Studies on the Charadriiformes.–I. on the Systematic Position of the Ruff. (Machetes pugnax) and the Semipalmated (Ereunetes pusillus), together with a Review of some Osteological character which differentiate the Eroliinœ (Dunlin group) from the Tringinœ (Redshank group).

Studies on the Charadriiformes.–I. on the Systematic Position of the Ruff. (Machetes pugnax) and the Semipalmated (Ereunetes pusillus), together with a Review of some Osteological character which differentiate the Eroliinœ (Dunlin group) from the Tringinœ (Redshank group).