Brent Group Reservoir Research Articles

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.

A renewed look at calcite cement in marine-deltaic sandstones: the Brent Reservoir, Heather Field, northern North Sea, UK

Abstract Wireline and seismic acoustic impedance imaging show that the marine part of the clastic Brent Group reservoir in the Heather Field, northern North Sea, contains much calcite cement in the flank parts of the structure. The non-marine Ness Formation and crest parts of the structure contain negligible calcite cement. This localized calcite cement has led to relatively poor reservoir performance since first oil in 1978, although a new suite of wells has boosted production with plans to keep the field active until 2030. Understanding the origin and distribution of calcite cement would help the development of more realistic reservoir models and boost production rates through optimum well location. We have thus used a suite of techniques, including standard point counting, SEM-EDS mineralogy, BSE microscopy, fluid inclusion thermometry and stable isotope analysis, to develop new and improved models of calcite distribution. Calcite seems to have attributes of both early and late diagenetic cement. A 30–40% intergranular volume in calcite cemented beds seems to support pre-compactional growth but high-temperature fluid inclusions and the presence of primary oil inclusions suggest late growth. Much calcite may have developed early but it seems to have recrystallized, and possibly undergone redistribution, at close to maximum burial or had a late growth event. Calcite cement probably originated as marine-derived micrite, bioclasts or early marine cement but adopted the isotopic characteristics of high-temperature growth as it recrystallized. Quartz grains have corroded outlines in calcite-cemented areas with one sample, with 79% calcite cement, displaying signs of nearly total replacement of quartz grains by calcite. The flank localization of calcite cement remains to be explained, although it could be due to primary depositional factors, early diagenetic loss of calcite from crestal regions or late diagenetic loss of calcite from crestal regions. Controversially, the growth of calcite seems to be associated with quartz dissolution, although the geochemical and petrophysical cause of this remains obscure. Diagenetic loss of quartz from sandstones cannot easily be explained by conventional modelling approaches and yet seems to be an important phenomenon in Heather sandstones.

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.

3D inversion of lithological properties in the Gullfaks Brent Group

Gullfaks is a structurally com-plex field with sandstone reservoir units of Cretaceous to Triassic age. The reservoir quality is generally very good, with porosities in the range of 30–35% and per-meability up to several darcies in the most important Brent Group reservoir. The baseline streamer survey was acquired in 1985, one year before the start of production. A simultaneous seismic AVO in-version of the baseline streamer survey was performed in 2006 to obtain acoustic impedance (AI) and Poisson's ratio (PR). AI and PR contain valuable information about rock and fluid properties, and one goal of this project was to create empirical relationships based on well-log data between AI/PR and porosity (φ), differential pressure (Pd), lithology (Vsh), and fluid bulk modulus (Kf). Kf is directly linked to brine saturation. The next step was to estimate rock and fluid properties as functions of AI and PR from the seismic inversion. This approach depends on good agreement between modeled and well-log data and als...

Controls on facies architecture in the Brent Group, Strathspey Field, UK North Sea: implications for reservoir characterization

The Brent Group reservoir in the Strathspey Field, UK North Sea comprises shallow marine, marginal marine and non-marine strata of variable reservoir character. Controls on the distribution, geometry, connectivity and orientation of sandbodies within the reservoir have been assessed via the application of high-resolution sequence stratigraphic methods to an integrated dataset comprising core, wireline log, 3D seismic and reservoir production data. The base of the Brent Group is a major sequence boundary overlain by weakly wave-influenced, shallow marine sandstones of the lowstand-to-transgressive Broom Formation. The overlying Rannoch Formation represents highstand progradation of a wave-dominated shoreface, which is truncated across a sequence boundary by a near-field-wide fluvio-estuarine complex (Etive Formation). Marginal-marine strata of the overlying Ness Formation are divided into field-wide units bounded by mudstones that form vertical pressure barriers. Major, oil-bearing fluvial sandbodies overlie sequence boundaries and the widths and orientations of two such sandbodiesare controlled by syn-depositional, intra-reservoir faults. The distribution of these sandbodies is therefore predictable. The Ness Formation is truncated by a major sequence boundary overlain by stacked, tidally influenced, shallow marine sandstones of the Tarbert Formation. The resulting facies architecture has been successfully used to refine reservoir models, identify bypassed oil and target infill wells.

The Strathspey Field, Block 3/4a, UK North Sea

Abstract The Strathspey Field was the first sub-sea development in the North Sea to be tied back to a third party operator, the Ninian Field now operated by Canadian Natural Resources (CNR). The field was discovered in 1975 by well 3/4-4 and lies wholly within Block 3/4a. The field is a tilted fault block, unconformity trap and consists of two separate reservoirs, a volatile oil and a gas condensate reservoir: the Middle Jurassic, Brent Group and the Lower Jurassic/Upper Triassic, Banks Group respectively. Two 3D seismic surveys cover the field, the most recent being a Vertical Cable Seismic survey recorded in 1996. The Banks Group reservoir is produced under depletion drive by five wells and the Brent Group reservoir by water flooding with 3 water injectors and 6 producing wells. In place volumes are 290 BCF and 90MMSTB for the Banks Group and 120MMSTR in the Brent Group Reservoir. Ultimate recoveries are estimated to be 230BSCF, 22MMBBL and 70MMSTB, 88 BSCF respectively. Oil export is via the Ninian pipeline system to Sullom Voe, while gas export is through the Far North Liquids and Gas System (FLAGS) pipeline system to St Fergus.]

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

Abstract The Brent Field was the first discovery in the northern part of the North Sea, and is one of the largest hydrocarbon accumulations in the United Kingdom licence area. There are two separate major accumulations: one in the Middle Jurassic (Brent Group reservoir) and one in the Lower Jurassic/Triassic (Statfjord Formation reservoir). The Brent Field lies entirely within UK licence Block 211/29 at latitude 61°N and longitude 2°E; the adjacent Brent South accumulation extends into Block 3/4A. The water depth is 460 ft. The Brent Field discovery well was drilled in 1971, and was followed by six further exploration and appraisal wells. Seismic data over the Brent Field has been acquired in four separate vintages. The latest acquisition in 1995 allowed detailed mapping of the complex eastern margin of the field for the first time The Brent Field is developed from four fixed platforms (Alpha, Bravo, Charlie, Delta) installed between 1975 and 1978. Production commenced in 1976 and, for the first 22 years of field life, the platforms provided production, water injection and gas injection facilities for both the Brent and Statfjord Formation reservoirs. The Brent South accumulation is produced via the Brent Alpha platform, through sub-sea tie-backs and extended reach wells. In 1992, the decision was taken to depressurize the Brent Field to recover an additional 1.5 TSCF of gas and 34 MMSTB of oil, extending the field's life by 5-10 years. In January 1998, water injection into the main field was stopped and depressurization of the field initiated. As of January 2000, a total of 220 platform wells and three sub-sea wells (173 producers, 50 water injectors) have been drilled in the Brent Field. The original oil/condensate-in-place is currently estimated at 3.8 MMMSTB, and the estimated original wet gas-in-place is 7.5 TSCF. Total ultimate recovery for all reservoirs is expected to be 1988 MMSTB oil and condensate and 6000 BSCF gas. Cumulative oil and net gas production, as of 1st January 2000, was 1875 MMSTB oil and 4196 BSCF gas This paper summarizes the current understanding of the field based on acquisition of new 3D seismic data, 130 new wells, detailed structural and sedimentological modelling, development of the complex crestal part of the field and finally, the initiation of an extensive brown field re-development project to depressurize the reservoir

Pore water evolution in oilfield sandstones: constraints from oxygen isotope microanalyses of quartz cement

Oxygen isotope microanalyses of authigenic quartz, in combination with temperatures of quartz precipitation constrained by fluid inclusion microthermometry and burial history modelling, are employed to trace the origin and evolution of pore waters in three distinct reservoirs of the Brae Formation in the Miller and Kingfisher Fields (North Sea). Oxygen isotope ratios of quartz cements were measured in situ in nine sandstone thin sections with a Cameca ims-4f ion microprobe. In conjunction with quartz cement paragenesis in the reservoirs, constrained from textural and cathodoluminescence (CL) microscopy studies, pore water evolution was reconstructed from the time of deposition of the sandstones in the Upper Jurassic until the present. CL photomicrographs of quartz overgrowths in the Brae Formation sandstones show three cement zones (A, B and C) which can be related to different oxygen isotope compositions: (1) the earliest, and thinnest, zone A (homogeneous CL pattern with probable δ 18O values between +23‰ and +26‰—direct measurements were not possible) precipitated in the sandstones at temperatures <60 °C; (2) the second zone B (complex CL pattern and directly measured δ 18O values between +15‰ and +18‰) precipitated in the sandstones most likely between 70 and 90 °C; (3) the third zone C (homogeneous CL pattern and directly measured δ 18O values between +16‰ and +22‰) precipitated in the sandstones most likely at temperatures >90 °C. Calculated oxygen isotope compositions of pore waters show that zone A quartz cements, and enclosing concretionary calcite, precipitated from a meteoric-type fluid (∼−7‰) during shallow burial (<1.5 km). Zone B quartz cements precipitated from fluids which evolved in composition from a meteoric-type fluid ( δ 18O −7‰) to a more 18O-enriched fluid ( δ 18O −4‰) as burial continued to ∼3.0 km. Data from zone C quartz cements are consistent with further fluid evolution from δ 18O −4‰ to basinal-type fluids with δ 18O similar to the present-day formation water oxygen isotope composition (+0.6‰ at 4.0 km burial). A similar pore water evolution can be derived for all three reservoirs studied, indicating that hydrogeologic evolution was similar across sandstones of the whole Brae Formation. The quartz cement zones observed in the Brae Formation sandstones, and the pore water history derived for the area studied, is analogous to published petrographic and pore water evolution data from the nearby Brent Group reservoirs and from reservoirs located in the Haltenbanken area on the Atlantic margin offshore Norway. Considering quartz cement is a major porosity-occluding phase in many reservoir sandstones, and because pore waters both dissolve quartz and carry the dissolved silica to cementation sites, the data presented are valuable for improving the understanding and prediction of reservoir quality development in sandstones globally.

The petroleum characteristics and filling history of the Frøy field and the Rind discovery, Norwegian North Sea

The Brent Group reservoirs of the Frøy field and the Rind discovery, Norwegian North Sea, show complex distributions of petroleum and aqueous fluids. Multiple fluid contacts are present in the Rind discovery, and the fields show various extent of compartmentalisation due to faulting. Geochemistry data of core extracts indicate that the two fields have different petroleum sources (Bhullar, Karlsen, Holm, Backer-Owe & Tran, 1998). Late diagenetic modifications of the reservoir quality consist of quartz cementation followed by carbonate and kaolinite cementation and dissolution of K-feldspar. Fluid inclusion results indicate that filling of the reservoirs occurred after the main phase of quartz cementation at pressure–temperature conditions close to the present. Differences in fluid properties between fault compartments in both fields have been identified. Fluid inclusion data have proved especially valuable for evaluation of the sealing capacity of faults through time, and given evidence for the fault lineament north of both fields to be a time-integrated pressure seal. Except for a lower gas condensate zone in the 25/2–13 compartment of Rind, the present reservoir fluids are volatile oils close to gas saturation. The previous presence of an oil in the lower reservoir zone of 25/2–13 has also been demonstrated. The fluid inclusion data indicate that the condensate in 25/2–13 represents a second episode of migration/filling rather than phase separation.

Clay Diagenesis in the Sandstone Reservoir of the Ellon Field (Alwyn, North Sea)

AbstractThe nature, composition, and relative abundance of clay minerals in the sandstones of the Brent Group reservoir were studied between 3200–3300 m in a well of the Ellon Field (Alwyn area, North Sea). The sandstones have a heterogeneous calcite cement which occurred during early-diagenesis. Clay diagenesis of the cemented and uncemented sandstones was investigated using optical microscopy, scanning electron microscopy (SEM), X-ray diffraction analyses (XRD), and infrared spectroscopy (IR). The influence of cementation on clay neoformation is demonstrated in this study. Detrital illite and authigenic kaolinite are present in both the calcite-cemented and uncemented sandstones suggesting that kaolinite precipitated before calcite cementation. In the uncemented sandstones, blocky dickite replaces vermiform kaolinite with increasing depth. At 3205 m, authigenic illite begins to replace kaolinite and shows progressive morphological changes (fibrous to lath-shape transition). At 3260 m, all sandstones are not cemented by calcite. Illite is the only clay mineral and shows a platelet morphology.In the cemented samples, vermiform kaolinite is preserved at all depths, suggesting that dickite transformation was inhibited by the presence of the calcite cement. This observation suggests that calcite cement would prevent fluid circulation and dissolution-precipitation reactions.

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.

Fluid inclusion constraints on conditions and timing of hydrocarbon migration and quartz cementation in Brent Group reservoir sandstones, Columba Terrace, northern North Sea

Abstract Fluid inclusion data have been obtained from Brent Group sandstones from the Columba Field on the margin of the East Shetland Basin, northern North Sea. Cogenetic primary aqueous and hydrocarbon inclusios trapped during the initial stages of late diagenetic quartz overgrowth are common, indicating that the pore fluid present during the onset of a major phase of quartz-kaolinite(-illite) diagenesis consisted of immiscible saline aqueous and petroleum phases. Similar inclusions are also observed in abundant planar arrays cross-cutting detrital and authigenic quartz. Homogenization temperature and salinity data from the two types of aqueous inclusions are statistically indistinguishable, as are the properties of the two types of hydrocarbon inclusions, suggesting that the same two-phase fluid was present probably throughout the main phase of quartz cementation. Fluid inclusion thermobarometry shows that the majority of the fluids were trapped in the range 104 ± 6°C and 300 ± 33 bars. These data are consistent with either (1) trapping of a warm, over-pressured hydrocarbon + aqueous fluid, probably in thermal and chemical disequilibrium with the host reservoir rocks, derived from a Kimmeridgian source in the deep Viking Graben basin to the east of the reservoir within the period 85–55 Ma, or (2) trapping of a hydrostatically pressured fluid, in thermal equilibrium with the host reservoir rocks, with hydrocarbon ± aqueous fluids derived by lateral up-dip migration from a local Kimmeridgian hydrocarbon source in the East Shetland Basin within the period 65–40 Ma. A maximum duration of 10 Ma for the fluid flow event can be estimated based on a typical burial history model for the area.

Influence of Depositional Sand Quality and Diagenesis on Porosity and Permeability: Examples from Brent Group Reservoirs, Northern North Sea

ABSTRACT Multivariate statistical analysis was applied to examine correlations between reservoir quality and petrology in two data sets from the Middle Jurassic Brent Group. One of the data sets is from relatively shallow depth and has been little affected by chemical diagenesis (Statfjord Nord and Ost Fields; 2.3-2.6 km below the sea floor), while the second data set is from a more deeply buried reservoir having an advanced degree of diagenesis (Huldra Field; 3.6-3.9 km). Much of the total variation in porosity and permeability within each data set (0.02 mD to > 7 D in both sets) can be accounted for by laboratory measurements of parameters mainly related to depositional sand quality, including shaliness (represented by bulk-rock alumina/silica ratio), early carbonate cement, feldspar co tent, and grain size. Despite major differences in the proportions of different sedimentary facies in the two data sets, they have similar ranges of depositional sand quality and therefore probably had similar reservoir quality early in their burial history. Deeper burial diagenesis at Huldra Field has shifted the average of both porosity and permeability to lower values and produced a bimodal permeability distribution, apparently reflecting preferential preservation of permeability in the cleaner sandstones. On the basis of these examples, we outline an approach for unmixing the diagenetic and lithologic components of variation in regional compilations of sandstone porosity-permeability data. The procedure and its consequences are illustrated using a regional compilation of core data fr m the Brent Group of the northern North Sea.

Uncertainties in Reservoir Production Forecasts

Being aware of uncertainties in forecasts of production characteristics is important for reservoir management. Decisions concerning further appraisal drilling, flexibility in development plans, and selection among reservoir prospects all require that uncertainties are taken into account. This study addresses the problem of quantifying uncertainties due to incomplete knowledge of the initial reservoir characteristics, with emphasis on the difference between heterogeneity modeling and assessment of uncertainty. In this study we outline a formalism for uncertainty modeling in a Bayesian framework and present an extensive case study of a North Sea Brent Group reservoir. The results are obtained by computer software implemented such that no human interference is required once the stochastic reservoir model is established. Once the stochastic reservoir model is established, multiple realizations can be generated, rescaled, and fed into a fluid flow simulator to forecast production characteristics and quantify uncertainty associated with response parameters such as cumulative oil production, recovery factors, and water cuts. The results demonstrate that uncertainty in model parameters contributes significantly to the overall uncertainty. The most influential parameters in our case study include the sealing capacity of major faults, seismic velocities used in depth conversion, and average porosities and shale continuity within the main reservoir sandstone.

Application of magnetostratigraphy to Brent Group reservoir zonation in the Visund Field

Application of magnetostratigraphy to Brent Group reservoir zonation in the Visund Field

Influence of Depositional Sand Quality on Porosity and Permeability: Examples from Brent Group Reservoirs in the Northern North Sea

Multivariate statistical analysis was applied to examine correlation between reservoir quality and petrology in two data sets from the Middle Jurassic Brent Group. One of the data sets is from relatively shallow depth an has been little affected by chemical diagenesis (Staffjord Nord & Ost Fields 2.3-2.6 km below the sea floor), while the second data set is from a more deeply buried reservoir having an advanced degree of diagenesis (Huldra Field 3.6-3.9 km). Much of the total variation in porosity and permeability (0.02 mD to >7 D in both sets) can be accounted for by laboratory measurements of parameters mainly related to depositional sand quality, including {open_quotes}shaliness{close_quotes} (represented by bulk-rock alumina content), earl carbonate cement, feldspar content, and grain size. Despite major differences in the proportions of different sedimentary facies in the two data sets, they have similar ranges of depositional sand quality and therefore probably had similar reservoir quality early in their burial history. Deeper burial diagenesis at Huldra Field has shifted the average porosity and permeability lower and produced a bimodal permeability distribution, apparently reflecting preferential preservation of permeability in the cleaner sandstones. Based on these examples, a method is outlined for {open_quotes}unmixing{close_quotes} the diagenetic and lithologicmore » components of variation in regional compilations of sandstone porosity-permeability data. The procedure and its consequences are illustrated using a regional compilation of core data from the Brent Group of northern North Sea.« less

An integrated thermal and isotopic study of the diagenesis of the Brent group, Alwyn South, U.K. North Sea

The petrography, fluid inclusion thermometry and isotope geochemistry of diagenetic cements are used to reconstruct the pore-fluid history of the Middle Jurassic Brent Group reservoir sandstones in the Alwyn South area of the U.K. North Sea. The study focuses on a relatively limited area of three adjacent reservoir compartments at successively higher structural levels. The cement assemblage of kaolinite, quartz and illite has resulted in severe deterioration of otherwise good reservoir quality. Early precipitation of vermiform and late blocky kaolinite was succeeded by a period of relatively intense illite precipitation. Temperature estimates for kaolinite precipitation of 80°C and δ 18O of ≈ + 15‰ (±3‰) suggest co-existing fluids of δ 18O ≈ −3‰. Quartz cementation overlapped both kaolinite and illite formation. Fluid inclusion data indicate that quartz cementation took place at temperatures of 109±7°C. Pore fluid salinities were ≈4 wt% NaCl with a H 2O O isotopic composition of ≈ -1 %o ± 0.5‰ SMOW. The fluids which precipitated coexisting illite were compositionally homogeneous with equilibrium δ 18O water compositions of +0.5‰ SMOW. Illite SD values range from −33 to −50‰ SMOW. These fluid inclusion and isotopic data suggest that both quartz and illite were precipitated from pore waters with a uniform, marine signature. This is consistent with the predominantly marine to paralic depositional context of the Brent Group in Alywn South. Illite precipitation was followed by hydrocarbon emplacement between the Middle Eocene and Lower Oligocene.

A Sr Residual Salt Analysis (SrRSA) Study to Investigate the Connectivity of the Brent Group Reservoir of the Dunbar Field, UK North Sea: ABSTRACT

The Middle Jurassic Brent Group reservoir sequence of the Dunbar oilfield in the UK Northern North Sea consists of interbedded fluvio-deltaic sandstones, mudstones and coals. This sequence occurs within rotated fault block structures on the western margin of the North Viking Graben. Strontium Residual Salt Analysis (SrRSA) has been performed on 254 core samples from 9 wells in the Dunbar Field. SrRSA data are {sup 87}Sr/{sup 86}Sr ratios from residual salts (and/or water) extracted from reservoir cores. These data reflect the {sup 87}Sr/{sup 86}Sr ratios of irreducible waters at the time they were trapped by hydrocarbons. Profiles of variation of SrRSA {sup 87}Sr/{sup 86}Sr ratios with depth were integrated with sedimentological, structural and petrophysical data to assess compartmentalization within and between the study wells. The results of this study suggest that certain coal and mudstone beds are laterally extensive scaling barriers which isolate flow units within the Brent reservoir. In addition, these data have also indicated that other barriers - which may be seated faults are present between certain wells in the field area. The results of this study have confirmed some aspects of the pre-existing reservoir model and thus enhanced confidence in the interpretations. The SrRSA data have alsomore » highlighted previously unexpected aspects of reservoir connectivity and thus enabled informed decisions to be made on the optimum production strategy. The integration of SrRSA with the geological and reservoir engineering database during the development phase may thus have helped optimize production from the Brent reservoir of the Dunbar Field.« less

Migration of hydrocarbons in the Tampen Spur area, Norwegian North Sea: a reservoir geochemical evaluation

Abstract This paper describes the application of reservoir geochemical protocols to a study of oil-field and regional petroleum compositional variations in the major fields in the Tampen Spur area. The Tampen Spur high is located in the middle of several oil-mature to gas-mature source-rock kitchens and most of the structures might receive petroleum from several different directions. Based on the definition of several different petroleum populations within the Tampen Spur area, we define five major petroleum charging systems. Correlating the petroleum population variations with geological information allows us to derive likely migration/fill scenarios for many of the oil-fields and requires us to invoke a new Upper Jurassic carrier system in parts of the area connecting Brent Group reservoirs across major faults. Based on this hypothesis, two exploration wells were drilled on structures to test this carrier and petroleum was found in one of the structures. An understanding of the migration pathways and petroleum drainage efficiency of the basins is of great economic interest, because most of the smaller substructures are marginally economic. Thus, it is important to provide an effective risk analysis and ranking of the satellite prospects prior to drilling. This study has demonstrated that filling and migration in a geological province are controlled by a series of complex processes and that the filling history of the structures within the Tampen Spur is more complicated than suggested earlier.

Application of magnetostratigraphy to Brent Group reservoir zonation in the Visund Field

Abstract Magnetostratigraphy has been applied to an increasing number of oil fields in the North Sea region with promising results for detailed chronostratigraphic reservoir correlation. However, the magnetization processes in hydrocarbon reservoir successions, and the potential use of magnetostratigraphy for reservoir zonation purposes, are not very well known. Therefore, aspects of these subjects are discussed on the basis of a magnetostratigraphic study of three different wells covering the Middle Jurassic Brent Group at the Visund Field, northern North Sea. Results from scanning electron microscopy and remanent coercivity analysis suggest that the primary magnetization defining the magnetozones in the Brent Group is a combination of detrital remanent magnetization and a chemical remanent magnetization, probably acquired contemporaneously shortly after deposition. Detailed thermal demagnetization has uncovered an important secondary magnetization component in most of the core samples. This magnetization is probably due to cooling of the cores from a reservoir temperature of about 110°C to surface temperature, and it causes the main disturbances in the palaeomagnetic results. Based on analyses of individual core samples, characteristic remanent magnetization components have been defined. The magnetopolarity stratigraphy for the individual wells is based on these components and the results are comparable from well to well. The well correlation covers a rock sequence with a thickness of about 200m, and both magnetostratigraphic and biostratigraphic results have been used in combination with the lithostratigraphy. The acme of Corollina represents the most important palyno-event, and the top and bottom of this palynozone is used as the main tie-level for two of the wells. Sixteen additional correlation lines have been derived from the magnetostratigraphic results, six of these considered as tentative. The correlation reveals that the magnetostratigraphic results are facies independent and some of the lithostratigraphic formation lines appear to be diachronous within this deltaic mega-sequence. Although the magnetostratigraphy only provides a relative time framework for the Brent Group, the results are encouraging and suggest the possibility of achieving high resolution chronostratigraphic well correlations for Middle Jurassic reservoir sequences in the northern North Sea area.