Middle Jurassic Brent Group Research Articles

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

Abstract The Heather Oil Field is located at the western margin of the East Shetland Basin, in the northern North Sea, and is operated by Unocal UK Ltd. Oil is trapped in Middle Jurassic Brent Group sandstones below 9500 ft TVSS in a highly-faulted reservoir that has undergone considerable diagenetic modification. The field was declared commerical in 1974, began producing in 1978 from a single platform and has recovered 84 MMBBL of oil to date through primary and secondary recovery methods. Ultimate reserves are estimated to be 100 MMBBL of oil.

Geologic Aspects of Reservoir Souring--Brent Group Sandstones, North Sea: The Use of Conventional and Laser Extraction Techniques in Sulfur Isotope Studies of Authigenic Pyrite

The Middle Jurassic Brent Group sandstones are prolific oil reservoirs in the North Sea. Recently, a number of Brent wells have experienced increased levels of hydrogen sulfide contamination during production. A study involving the characterization of all iron-bearing minerals to understand the controls of mineralogy on the nature and timing of souring has been undertaken. The potential of iron minerals to scavenge hydrogen sulfide and hence delay/inhibit souring by precipitation of pyrite has been investigated by determining its distribution, quantity, and origin. Authigenic pyrite occurs as disseminated (framboidal, cubic, and octahedral) crystals and as a pore-filling cement. The pyrite has formed throughout the diagenetic history of the sandstones. however, most of the pyrite is considered to be a late cement formed during burial diagenesis. Conventional separation and sulfur isotope analysis of the authigenic pyrite was conducted on samples from oil- and water-bearing sequences to give a bulk signature for all pyrite present. Subsequently, laser sulfur isotope analysis was used to characterize the signature and origin of the different pyrite morphologies present. The enhanced level of sulfur isotope signature characterization can be used to improve the knowledge of the origin and timing of the different pyrite morphologies. This allows closer reconciliationmore » of the isotopic data to the diagenetic history of the Brent sandstones. Calculations have been made using the known quantities of iron in these minerals and the hydrogen sulfide concentrations present. This indicates the effect of sulfide precipitation on the hydrogen sulfide levels remaining in the reservoir.« less

The Dunlin Field, Blocks 211/23a and 211/24a, UK North Sea

Abstract The Dunlin Oilfield is located in the East Shetland Basin, 160 km northeast of the Shetland Islands. It lies in UK Blocks 211/23a and 211/24a in about 500 ft of water. The field was discovered in June 1973 by well 211/23-1. The oil accumulation is trapped, in a north-south oriented, tilted fault block at the western margin of the Viking Graben, at a depth of about 8500 ft TVSS. The reservoir is contained in the formations of the Middle Jurassic Brent Group. In the Dunlin area they form a 450 ft thick sequence of sands and intercalated minor shales, which has been deposited by a shore face and delta system prograding northwards across the Viking Graben. The seal is formed by the shales of the Middle/Upper Jurassic Heather Formation. Reservoir properties of the Brent sands are fair to good with porosities of up to 30% and average permeabilities in the range from 10 to 4000 md. Development of the field is carried out from a single platform, from which production started in 1978. To date 40 development wells have been drilled and the total cumulative production amounts to 282 MMBBL of an ultimate recovery of 363 MMBBL.

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.

Oxygen Isotopic Analysis of Diagenetic Quartz Overgrowths from the Brent Sands: A Comparison of Two Preparation Methods

ABSTRACT Two preparation methods used for determining the 18O of quartz overgrowths are compared from the sandstones of the Middle Jurassic Brent Group, Northern North Sea. Method one uses dilute HF to preferentially attack interfacial materials present between the overgrowth and the detrital core, with subsequent ultrasonic agitation used to break the overgrowths off at the weakened contacts. Size fractionation by sieving should concentrate overgrowths into the smaller grain size separates. In the Brent sands studied, however, little interfacial material is present between overgrowth and core, and the overgrowths are thinly developed (average width 20-50 microns). Concentration of the diagenetic overgrowths is therefore difficult. This difficulty is compounded by large amounts of detrital quartz in the size fractions, as a result of internal fracturing of the grains. The 18O (SMOW) values for the finest size fraction (supposedly overgrowth rich), ranging from 9 to 13.3, are unusually low for diagenetic quartz overgrowths, and result from the high detrital component. The second method derives the 18O values for the overgrowths by the difference in 18O for the quartz grains plus overgrowths and quartz grains from which the overgrowths have been removed by HF dissolution. The mass balance used requires the overgrowth abundance to be known from point counting. The calculated 18O values obtained are typical for authigenic quartz overgrowths and range from 17.1 to 20.9. Direct isolation of quartz overgrowths for 18O measurement is suitable where interfacial material exists between the detrital grain and the overgrowth and where overgrowths are well developed. Otherwise, preferential HF dissolution of the overgrowths and a 18O mass balance calculation is the preferred method.

The Tern Field, Block 210/25a, UK North Sea

Abstract The Tern Oilfield is situated 150 km northeast of the Shetland Islands in Block 210/25a in the UK sector of the northern North Sea. The discovery well 210/25-1 was drilled in 1975 in a water depth of about 541 ft. The trap is defined at around 8000 ft TVSS by a tilted horst-structure. The hydrocarbons are contained in reservoirs belonging to the Middle Jurassic Brent Group sands deposited by a wave-dominated delta system in the East Shetland Basin. Complex faulting of the structure is responsible for the division of the field into two areas with different original oil-water contacts: the Main Area of the field with an oil-water contact at 8260 ft TVSS, and the Northern Area with a possible oil-water contact at 8064 ft TVSS. Reservoir quality is good with average porosities ranging from 20-24% and an average permeability of 350 md. The expected STOIIP and ultimate recovery of oil are 452 and 175 MMBBL, respectively which represents a recovery factor of 39%. The initial stage of the development plan calls for ten wells, five oil producers and five water injectors, to be drilled from a single platform, Tern Alpha. Development drilling started in February 1989 and first oil was produced on 2 June 1989. The oil is evacuated via the North Cormorant and Cormorant Alpha platforms into the Brent System pipeline for export to the Sullom Voe terminal. To date, two producers have b een drilled and total cumulative production is 6.4 MMBBL (1 January 1990). Ultimate recovery is estimated to be some 175 MMBBL.

The Ninian Field, Blocks 3/3 & 3/8, UK North Sea

Abstract The Ninian Field, located in the northern North Sea, lies in the East Shetland Basin on the west side of the Viking Graben. The field straddles Blocks 3/3 and 3/8 and is developed under a unitization agreement with Chevron UK Limited as operator. The structure is a westward tilted fault block. The estimated original oil-in-place contained in the marine-deltaic sandstones of the Middle Jurassic Brent Group, is 2920 MMBBL, of which an estimated 35 to 40% is recoverable. The oil is a paraffinic-naphthenic type with an API gravity of 36°. The field development consists of three fixed platforms with a total of 109 drilling slots. The natural drive in the field is negligible so that water flooding is required. The production of the Ninian Field started in December 1978 and reached a peak of 315 000 BOPD in the summer of 1982. At the end of 1988 over 811 MMBBL had been produced.

Calcite Cemented Layers, Their Characterization and Use in Improving Reservoir Recovery from Murchison Field, Northern North Sea

Murchison field is a mature development forming part of the Brent oil province in the East Shetland basin, northern North Sea. The productive reservoir consists of coastal deltaic sands of the Middle Jurassic Brent Group and is produced by a line-drive waterflood mechanism. The Rannoch Formation in Murchison, one of the field's most prolific producing zones, is characterized by the presence of calcite-cemented zones, known locally as doggers, which occlude all porosity and behave as vertical barriers to fluid flow. Geochemical-mineralogical analysis of the carbonate cements allied to sedimentological studies of host sandstone indicate that they occur as continuously cemented layers with relatively homogeneous compositions. Dogger occurrence is generally confined to the upper parts of individual coarsening-upward confined to the upper parts of individual coarsening-upward profile and sand bodies, characterized by low detrital clay and mica contents, low bioturbation, and high pre-cementation porosites and permeabilities. The carbonate bands are thus thought to represent zones of maximum pore water flow through high permeability conduits during burial diagenesis. Wireline correlation supported by core description indicates that at least three significant, laterally continuous calcite-cemented zones occur, the most extensive of which has a lateral extent of at least 5 km. All significant doggersmore » have been mapped geologically and incorporated into the full-field reservoir simulation model. Based on this new understanding, a revised infill drilling and perforation strategy has been devised for the Rannoch Formation, aimed at improving recovery from this complex reservoir zone.« less

Gas-Lift Design and Performance Analysis in the North West Hutton Field

Experience at the North West Hutton field has emphasized the importance of properly understanding gas-lift valve behavior. In conjunction with regular downhole pressure and temperature surveys, this has helped maximize production from gas-lifted wells. This paper emphasizes the importance of the downhole temperature survey and of simultaneous well testing with downhole survey work. The paper shows how this kind of performance analysis can reveal such classic problems as leaking valves and such fundamental problems as mandrel spacing that does not match well performance. These analysis techniques also can predict the consequences of increasing available surface injection pressure and have led naturally to the development of more flexible design procedures that optimize production from wells whose performance may be either unpredictable or unlikely to permit a deep point of injection. Field application of these design procedures also is discussed.

The Osprey Field, Blocks 211/18a & 211/23a, UK North Sea*

Abstract The Osprey Oilfield is located 180 km northeast of the Shetland Islands in Blocks 211/23a and 211/18a in the UK sector of the northern North Sea. The discovery well 211/23-3 was drilled in January 1974 in a water depth of 530 ft. The trap is defined at around 8500 ft TVSS by two dip and fault closed structures, the main 'Horst Block' and the satellite 'Western Pool'. The hydrocarbons are contained in reservoir sandstones belonging to the Middle Jurassic Brent Group which was deposited by a wave-dominated delta system in the East Shetlands Basin. The expected STOIIP and ultimate recovery are estimated at 158 MMBBL and 60 MMBBL of oil respectively, which represents a recovery factor of 38%. The 'Horst Block' contains 85% of the reserves with an OOWC about 150 ft shallower than in the 'Western Pool'. Reservoir quality is excellent, with average porosities varying from 23-26% and average permeabilities varying from 35-5300 md. The development plan envisages eleven satellite wells, six producers and five water injectors, closely clustered around two subsea manifolds. First production is expected in late 1990/early 1991. The wet crude oil will be piped to the Dunlin 'A' platform for processing and from there to the Cormorant Alpha platform into the Brent System pipeline for export to the Sullom Voe terminal.

The Thistle Field, Blocks 211/18a and 211/19, UK North Sea

Abstract The Thistle Oilfield is located on the western margin of the North Viking Graben in UK Blocks 21l/18a and 211/19. The field was discovered in 1973 by the Halibut Group, operated by the Signal Oil Company. The discovery well was drilled in 1973 and the field was declared commerical before completion of the first two appraisal wells. The extension of the field into Block 211/19 was confirmed by well 211/19-1 drilled in 1974 and the field was subsequently unitized. The Middle Jurassic Brent Group forms the oil-bearing reservoir sequence. The structure is an easterly dipping, rotated fault block divided into five main compartments by N-S normal faults and E-W cross faults. A 60 slot drilling and production platform was installed in 1976 and production began in February 1978. It is now connected by pipeline to Sullom Voe and production through this link commenced in late 1978. Due to only limited aquifer support, injection wells have been drilled on the east flank of the field, in order to maintain reservoir pressure. In addition, several wells in partly isolated fault blocks are produced by gas lift completions. The current STOIIP is estimated at 794 MMBBL of which 396 MMBBL will ultimately be recovered. Cumulative production to the end of 1988 was 334 MMBBL from 34 production wells, with support from 13 injection wells.

THE SEDIMENTOLOGY OF THE BRENT GROUP IN THE CORMORANT BLOCK IV OILFIELD

Cormorant Block IV is one of four, large‐scale fault‐bounded accumulations which together comprise the Cormorant oilfield. The field lies some 150 kms NE of the Shetland Islands, in the East Shetland Basin. Oil is trapped in the Middle Jurassic (Aalenian‐Bathonian) Brent Group. Block IV is a separate accumulation in a downthrown area formed by a large synsedimentary listric fault, which produced a dome‐shaped structure with further internal fault‐block compartmentalisation. A concerted data‐gathering effort on the accumulation included the coring of 43% of the reservoir section penetrated by wells.The Brent Group in Block IV fits into the “classical” overall regressive/transgressive, wavedominated delta model widely accepted for these sediments. However, the synsedimentary boundary fault has had some influence on the shallow‐marine Broom and Tarbert Formations and the coastal‐plain Upper Ness sediments, in each case preserving a unique and thicker sequence on the downthrown eastern side. The lowermost Broom Formation includes a shallow‐marine, Gilbert‐delta type deposit that infilled a topographic feature formed by the fault, and is genetically distinct from the rest of the Group. The Rannoch and Etive delta‐shoreface sediments, the main resrvoir interval, appear to have prograded through the area towards the NNE so rapidly that no fault influence was felt. Lateral variability at this level can be explained by the location of distributaries in the upper shoreface, controlling the grade of sediment supply and progradation rates of the entire system. The barrier‐attached coastal‐plain sequence of the lower Ness is chronostratigraphically equivalent to the Etive. and thins rapidly towards the north. The upper Ness is strongly layered by repeated periods of emergent coastal‐plain development separated by at least block‐wide lagoonal drowning events. Erosion at the base of the shallow‐marine Tarbert Formation, and the marked variability of sediment type and thickness in this horizon, suggests that it formed over a considerable time‐period at the end of Brent Group deposition, as the structure of the block was still developing.

An Overview of "Chronostratigraphy of Cenozoic Terrestrial Sediments and Faunas"

Previous articleNext article No AccessAn Overview of "Chronostratigraphy of Cenozoic Terrestrial Sediments and Faunas"Bruce J. Mac FaddenBruce J. Mac Fadden Search for more articles by this author PDFPDF PLUS Add to favoritesDownload CitationTrack CitationsPermissionsReprints Share onFacebookTwitterLinkedInRedditEmail SectionsMoreDetailsFiguresReferencesCited by The Journal of Geology Volume 98, Number 4Jul., 1990Chronostratigraphy of Cenozoic Terrestrial Sediments and Faunas Article DOIhttps://doi.org/10.1086/629417 Views: 1Total views on this site Citations: 2Citations are reported from Crossref Copyright 1990 The University of ChicagoPDF download Crossref reports the following articles citing this article:Andrew D. Miall Whither stratigraphy?, Sedimentary Geology 100, no.1-41-4 (Dec 1995): 5–20.https://doi.org/10.1016/0037-0738(95)00100-XEirik Hauger, Reidar Løvlie, Paul van Veen Magnetostratigraphy of the Middle Jurassic Brent Group in the Oseberg oil field, northern North Sea, Marine and Petroleum Geology 11, no.33 (Jun 1994): 375–388.https://doi.org/10.1016/0264-8172(94)90056-6

The influence of variations in illite morphology on the permeability of Middle Jurassic Brent Group sandstones, Cormorant Field, UK North Sea

SEM examination of core samples from Brent Group sandstones in the Cormorant Field reveals that critical point drying preserves delicate illite morphologies that are damaged during air drying. This damage may lead to an increase in permeability, as defined by the ‘drying effect’ (air permeability air dried/air permeability critical point dried). The Cormorant reservoir sandstones contain four illite morphologies. Early diagenetic pore-lining illite formed before hydrocarbon emplacement and occurs ubiquitously. Pore-bridging illite, ‘blooming illite’ and illite that replaces kaolinite all formed later and occur preferentially at or below the oil-water contact. Damage to these late illites causes an average drying effect of 3.5 and explains why measured permeabilities predict higher water injection rates than occur in the field. Comparison with data from other reservoirs reveals that the drying effect is influenced by variations in illite particle dimensions as well as illite morphology. TEM shadowing techniques reveal that illite particle sizes describe a trend from small particles in reservoirs with large drying effects to large particles in reservoirs with small drying effects. These size variations probably reflect differing illite growth rates. Permeability in illite-bearing sandstones thus reflects not only the amount of illite present but also the size of the individual particles and their morphology.

The early to mid-Jurassic evolution of the northern North Sea

Abstract The early to mid-Jurassic history of the northern North Sea is summarized as a complex transgressive-regressive-transgressive cycle controlled by variations in ‘long-term’ eustatic sea level rise, basin subsidence/margin uplift and sediment supply. The first of the transgressions occurred in the Hettangian when the Boreal Ocean spread southwards during a phase of fluctuating but generally increasing sea level rise. Offshore marine conditions developed in the north of the area during the Hettangian to Pliensbachian, while coastal to non-marine conditions developed around the ocean margins in the Unst Basin, the Beryl Embayment, the central Viking Graben and over parts of the Horda Platform. The coastal systems in the Beryl Embayment and central Viking Graben were drowned in the late Pliensbachian as a result of continued sea level rise. A widespread marine link was established with the Tethys Ocean to the south at this time. Sea level fall and/or basin margin uplift and erosion in the Aalenian led to the shedding of coarse clastic sediment transversely into the East Shetland Basin and the northern end of the Viking Graben. The main reservoir unit of the area, the Middle Jurassic Brent Group, formed in this way. A marine connection was maintained into the central Viking Graben area throughout the transverse progradation further north. Drowning of the progradational clastics and the start of the third major transgression began in the late Bajocian, but offshore conditions did not become fully established throughout the area until the Callovian or early Oxfordian.

Facies and development of the Middle Jurassic Brent Delta near the northern limit of its progradation, UK North Sea

Summary The lithofacies patterns in the Middle Jurassic Brent Group, the principal hydrocarbon reservoir in the UK northern North Sea, are examined in seven wells. The sections, from the area of the Don and Murchison oil fields, record the nature of the Brent Delta near the northern limit of its progradation. Here the deltaic deposits of the Brent Group, which regionally constitute a major regressive-transgressive clastic wedge, progressively lose the interbedded sands and muds of the delta plain which characterize the middle part of the succession further S. This leads locally to a maximum sand-to-mud ratio for the Brent Group reservoir interval. A regressive storm-wave-influenced marine succession, from offshore transition-zone silts and muds up to hummocky cross-stratified nearshore sand, is overlain in turn by stacked distributary channel sands. Distributary mouth deposits are absent. The interbedded delta-plain succession, where it occurs, exhibits some marine influence and records wave reworking of interdistributary bay or lagoonal sediments. The Brent Group succession is capped by transgressive sands which were deposited in a storm-wave-influenced nearshore environment. Delta-plain drowning is also evident in the gradual marine incursions into distributary channels at the northern limit of the study area. The character of the delta locally is compared with the nature of the wave-dominated Brent Delta elsewhere on its progradational path. High energy nearshore deposits in both regressive and transgressive phases are widely distributed, but there is a contrast between the dominance of fluvial processes in the study area and the development elsewhere of a barrier island complex in front of a coastal plain.

Diagenetic quartzarenite and destruction of secondary porosity: An example from the Middle Jurassic Brent sandstone of northwest Europe

Significant amounts of feldspar have been dissolved from Middle Jurassic sandstone oil reservoirs in the North Sea (northwest Europe) during burial diagenesis Sandstones of the Middle Jurassic Brent Group become increasingly quartzose with increasing burial depth. At Statfjord field (2500 m depth), sandstones are arkose to subarkose; at Hutton field (3050 m depth), they are subarkose to quartzarenite, and at Lyell field (3500 m depth), sandstones are typically quartzarenite. In spite of extensive feldspar dissolution, the abundance of secondary porosity due to feldspar dissolution is similar for all fields, averaging 2.9% of the total rock volume. Thus, far more feldspar has been dissolved than is recorded as secondary porosity. The limit on preservation of secondary porosity may be largely the effect of the mechanical strength of the rock. An excessive number of large secondary pores lowers the rock strength below the point at which the rock can withstand overburden stress, thus causing collapse of some of the secondary pores.

Statfjord Field: Development Strategy and Reservoir Management

Summary This paper reviews reservoir performance and management of the Statfjord field after 8 years of production. The reasons behind the reservoir development strategies and field experiences are presented. The field comprises three reservoirs produced simultaneously with designated wells for each reservoir: the Upper and Lower Brent and the Statfjord. The two Brent reservoirs are produced with a waterflood, while the Statfjord reservoir is produced with a high-pressure miscible gasflood. The original development plans have been refined on the basis of field performance through an extensive monitoring program and use of reservoir simulation. The induced gamma ray spectra (IGRS) log is used to monitor water movement in the Brent reservoirs, while the compensated neutron tool (CNT) is the main tool used to monitor the gasflood in the Statfjord reservoir. The acquired data have improved the geologic model and the knowledge of fluid movements in all three reservoirs. This resulted in a large and complex reservoir simulation model with more than 20,000 gridblocks. Introduction The Statfjord field, the largest producing oil field in Europe, is located in the prolific northern part of the Viking graben, 125 miles [200 km] northwest of Bergen, Norway, on the U.K./Norwegian boundary (Fig. 1). The field was discovered in March 1974 with the drilling of Well 33/12-1 and was delineated with drilling of 11 additional wells. The field lies mainly in Norwegian Blocks 33/12 and 33/9, but also extends into U.K. Blocks 211/24 and 211/25. The field was unitized in 1976 with Mobil as operator. The equity redetermination of 1979 resulted in 84.1 % of the field being in the Norwegian sector and 15.9 % in the U. K. sector. The operatorship was transferred from Mobil to Statoil in Jan. 1987. The Statfjord field, which is 15 miles [24 km] long and averages 2.5 miles [4 km] in width, is located in a westerly tilted and eroded Jurassic fault block. The main recoverable reserves, about 75 %, are located in the Middle Jurassic Brent group, while the remaining 25 % is in the Lower Jurassic/Upper Triassic Statfjord formation. Both Brent and Statfjord have exceptionally good reservoir characteristics. The estimated ultimate recovery is around 3 × 109 bbl [475 × 106 M3] of oil and 3 × 10 12 Scf [85 × 109 std M3] of gas. Both Brent and Statfjord reservoirs contain highly undersaturated low-sulfur crude oil. Reservoir data and fluid properties are given in Tables 1 and 2. The Statfjord field is being developed with three gravity-based Condeep-type platforms and single-point mooring for offshore oil tanker loading. Production from Platform A commenced in Nov. 1979, while Platform B came on production in Nov. 1982 and Platform C in June 1985. Regular gas sales by pipeline to the U.K. and the European continent began in Oct. 1985. Eighty-nine development wells have been drilled to date to achieve the current average daily oil-production and water-injection rates of 750,000 STB/D [119 000 stock-tank M3 /d] and 1,050,000 B/D [ 167 000 M 3 /d], respectively. As of Dec. 1987, nearly 1.2 × 109 bbl [190 × 10(6) M3] Of oil. or about 40% of the recoverable reserves, has been produced.

Geological Controls on Heterogeneous Reservoir Behavior in Complex Deltaic Sediments, Brent Field, Northern North Sea: ABSTRACT

The Brent field is the largest oil field in the United Kingdom sector of the northern North Sea, and its discovery in 1971 pioneered development in the area. The field contains some 3.4 billion bbl of oil in place, trapped in two reservoirs in a simple rotated fault block on the western margin of the Viking graben failed rift system. Three-fifths of the oil is found in an 800-ft section of deltaic deposits of the Middle Jurassic Brent Group, with a single oil water contact and an 850-ft hydrocarbon column. The lower part of this reservoir is a sand-rich, wave-dominated delta-front sequence overlain by delta-plain sediments. The first oil was produced in 1976 under a downflank artificial water drive. Three dominant controls on the reservoir geologic framework have been identified: (1) individual delta lobe progradation and abandonment, (2) irregular periods of rapid subsidence followed by relative sea level stillstand, and (3) crestal collapse. The first two primary depositional controls combined to produce a layered reservoir in the delta-plain sequences characterized by fieldwide coals marking delta-lobe abandonment. Extensive shales resulted from the periods of rapid subsidence. These shales now form vertical permeability barriers defining subreservoirs highlighted by repeat formation tester profiles.more » Late Jurassic graben-associated tectonics initiated the fault block rotation and allowed crestal unroofing and erosion. Instability in the underlying plastic marine shales created complex rotational faulting in the Brent sediments. These crestal features complicate reservoir behavior, especially in the gas cap. Continued fault movement created a number of unconformities and condensed sequences in the overlying Upper Jurassic and Lower Cretaceous reservoir sealing shales.« less

Cormorant Field, United Kingdom North Sea--Synergistic Approach to Optimum Development of a Complex Reservoir: ABSTRACT

The Cormorant oil field containing 1.5 billion bbl of oil in place, is situated in the United Kingdom sector of the northern North Sea. The reservoir comprises Middle Jurassic Brent Group sandstone in a westward tilted fault block. The top seal is provided by Upper Jurassic shales. The Brent Group consists of several units, which represent a single large-scale regressive and transgressive sequence of a northerly prograding delta complex. The structure style is a product of two tectonic phases, one dominated by wrench tectonics and a subsequent one which created the westward-dipping faults blocks. This has resulted in a complex field consisting of four separate fault-bounded blocks. Each has distinctive characteristics and problems associated with varying internal geometry and sedimentology. Block IV, resulting from crestal collapse, is internally faulted and displays a number of elongate subblocks, which are bounded by a complex interactive suite of faults. Three-dimensional seismic coverage has not allowed adequate resolution of this complex faulting. Delineation of sub-blocks is critical as development has shown that many faults are sealing. Block II, southwest of the main culmination, presents problems of a sedimentological and structural nature. Production history shows the existence of barriers within the reservoir, probably associated with small-scale faulting, the sealing caused by juxtaposition, and/or clay smearing. There is also evidence of permeability reduction with increasing depth. Kaolinite is the predominant clay mineral within the reservoir, whereas illite may be present in small quantities in the water-bearing zone; this differential impairment has an effect on development strategy. End_of_Article - Last_Page 315------------