bluuebunny/crossref_metadata_2025 huggingface dataset:
Regional correlation of Westphalian sandbodies onshore UK: implications for reservoirs in the Southern North Sea
Authors: AITKEN J. F. , QUIRK D. G. , GUION P. D.
Published: April 2010

An extensive and closely-spaced seismic and well dataset from coal and hydrocarbon exploration in the East Pennine Coalfield and the East Midlands Oilfield has enabled the detailed subsurface correlation and mapping of major Westphalian A to C sandbodies. Maximum flooding surfaces are represented by marine bands which are faunal concentrate condensed horizons. The large fluvial sandbodies do not show characteristics of incized valley fills. The remoteness of the study area from the sea during deposition meant that eustatic changes are less significant than other factors. The interplay of tectonics, climate and autocyclic processes was responsible for exceedingly complex sequences in terms of both lateral and vertical organization, and it is difficult to isolate the relative importance of the various mechanisms controlling sedimentation.

Closely spaced onshore borehole data and outcrop studies have been used to model reservoir characteristics and continuity offshore in the Southern North Sea, where well spacing is far greater. Architectural variability and 3D geometry of onshore sandbodies can be used as an analogue for Southern North Sea reservoirs. Geometric data from 20 mapped onshore sandbodies illustrates a relationship between sandbody width and thickness, with 90% of channel sandbodies being less than 25 km in width and less than 40 m in thickness. A remarkable similarity exists between the sand distribution onshore UK and Westphalian reservoir intervals in the Southern North Sea. Sandbodies onshore and offshore show comparable thicknesses (up to 100 m) and widths (up to 30 km). Additionally, the sandbodies do not display incised bases, as is also typical of all the main Westphalian reservoir targets in the Southern North Sea.
Incised valley fill sandstone bodies in Upper Carboniferous fluvio–deltaic strata: recognition and reservoir characterization of Southern North Sea analogues
Authors: HAMPSON G. J. , DAVIES S. J. , ELLIOTT T. , FLINT S. S. , STOLLHOFEN H.
Published: April 2010

Multistorey fluvial sandstone bodies in Upper Carboniferous fluvio–deltaic strata are proven reservoirs in the Southern North Sea. Several of these bodies have been interpreted as incised valley fills. Analogous valley fill sandstone bodies have been studied in outcrop and subsurface datasets from Upper Carboniferous successions in the onshore UK and Germany. Using techniques and tools applicable to Southern North Sea datasets, we review the diagnostic criteria of these valley fills: (1) stratigraphic context, characterized by deep erosion into underlying strata, lateral correlation to an interfluve surface and intimate association with an initial flooding surface in overlying strata; (2) basinward facies shift at the base of the sandstone body; (3) erosion of underlying time markers; and (4) distinctive internal architecture, which reflects increasing accommodation space during valley filling.

Several features of onshore valley fill sandstones have been characterized in order to constrain the properties of analogous valley fill reservoirs in the Southern North Sea. (1) Valley geometry and extent. Studied onshore valley fills generally have a uniform thickness of 20–25 m, thickening locally to 30–45 m, and widths of 5–25 km. A small number of valley fills, associated with turbidite-fronted deltas, thicken to 50–80m in the 2–5 km adjacent to their mouths. Sheet-like fluvial sandstones overlying sequence boundaries have thicknesses comparable to conventional valley fills, but exceed 35–70 km in width. (2) Valley connectivity; typically, valley fills occur as discrete sandstone bodies, but they may amalgamate laterally, to form sheet-like sandstones, and vertically, producing thick (up to 200 m) sand-prone stratigraphic packages. The internal geometry of these sand-prone packages is complex. (3) Valley fill character. Valley fills generally lack an overall fining-upwards trend and are dominated by coarse- to medium-grained sandstone of low-sinuosity (braided?) fluvial facies throughout. Where present, fine-grained facies are preferentially preserved in the upper part of a valley fill. (4) Detrital mineralogy and provenance. At least some valley fill sandstones exhibit a different composition and provenance to surrounding strata. Such valley fill sandstones are likely to be anomalously feldspathic in the Southern North Sea.
Structural analysis of 3D seismic data, using the correlation attribute: a case study – Carboniferous of the Southern North Sea (UK)
Authors: BIRRELL S. , COURTIER J.
Published: April 2010

With the advent of a new seismic attribute, generically termed correlation, interpreters have a non-specialist tool which enables decisions to be made on structural and stratigraphic patterns within a 3D dataset. The process behind the attribute may appear to be black box technology, however, the resultant data are straightforward and enable the interpreters to make their own conclusions about the seismic information presented. Correlation data are simply a quantified comparison of adjacent seismic traces. The value to be unlocked from this attribute lies in rapid delineation of fault and stratigraphic patterns. This requires a revised approach to the interpretation workflow, involving analysis of the correlation attribute volume during primary stages of any 3D-interpretation project. Using a technique termed ‘ribbon interpretation’, correlation data are analysed for information relating to lineaments and data inconsistencies. The identification of features using ribbons, which are short 2 point segments, can then be stacked and filtered by the interpreter to give direct information on faulting and stratigraphic features. The filtered ribbon data are then progressed through to horizon interpretation, where they can be integrated to provide a more robust structural or stratigraphic solution. Application of the ribbon interpretation technique within the mature environment of the structurally complex, Carboniferous play (UK SNS) (Fig. 1) has allowed faster and better results across exploration, appraisal and production scenarios.
Upper Jurassic basin axial turbidites within the Gertrud Graben, Danish Central Graben
Authors: RASMUSSEN E. S. , JEPSEN A.-M. , MAVER K. G.
Published: April 2010

For more than twenty years, the Jurassic succession in the Danish Central Graben has been subject to intense exploration for hydrocarbons. Approximately 43 wild-cats have been drilled and most of these tested structural traps located on footwall crests. The reservoirs encountered were Middle and Upper Jurassic sandstones deposited mainly in nearshore depositional environments. Some of these wells penetrated thin turbidites of Late Jurassic to Early Cretaceous age. Within the Gertrud Graben distinct seismic anomalies indicate the presence of basin floor turbidites, which can be correlated to fan fringe turbidites encountered in the Jeppe-1, Gwen-2 and Mona-1 wells. Seismic inversion provides additional evidence of sandstone deposits in the zone characterized by high acoustic impedance. The turbidites are located within the axial zone of the NW–SE trending Gertrud Graben. Southward the turbidites pinch out gradually; the northern limit of the deposits (in Norwegian territory) is unknown. The deposition of the turbidites is interpreted to be associated with a lowstand of sea-level when conditions were favourable for deposition of coarse-grained deposits in basinal areas. The sediments were probably sourced from an area to the north. Basin axial turbidites are well-known phenomena in various basins. They are not always associated with structural closures and consequently constitute a high risk exploration target. However, in mature basins such as the Danish Central Graben this type of play should be considered in future exploration.
Influence of syn-depositional faulting on thickness variations in chalk reservoirs – Valhall and Hod fields
Authors: FARMER C. L. , BARKVED O. I.
Published: April 2010

The depositional model for the Tor Formation at the Valhall and Hod fields has been revised to reflect the influence of syn-depositional faulting and reworking on reservoir thickness variations. New ideas for the structural and depositional model were based on detailed reservoir interval correlations in the Valhall–Hod area using biostratigraphy and graphic correlation techniques. Three-dimensional seismic data was also integrated and applied to develop the model. The Tor Formation was deposited during a tectonically active time in the Late Cretaceous and the Early Tertiary. During this time Valhall and Hod anticlines were forming as a result of inversion along the Lindesnes Ridge. Regionally the Tor and Hod formations thicken away from the Ridge. This indicates that the area was a structural high which is interpreted to be a large shoal. A major unconformity is present at the Hod/Tor Formation boundary. During continued uplift, crestal areas collapsed forming a series of horsts and grabens. The Tor Formation (Campanian and Maastrichtian, with documented Danian reworking) filled in the lows formed by these graben. Seismic data and well control demonstrate that the Tor Formation is thicker in graben and thinner over horsts. Removal of the Hod and Tor formations from local structural highs can be best explained by wave action and winnowing across a large shoal. The graben areas, sheltered from waves and protected from scouring and erosion, became local depositional centres for thicker slumped and reworked Tor Formation chalk. In the Tor Formation there is strong evidence for local erosion, formation of hard-grounds, grain size sorting, and down-slope movement through slumping and debris flows. Thickness and facies variations in the Tor Formation of Valhall and Hod fields can be linked to syn-depositional faults. Recognition of a fault controlled depositional model along with detailed mapping of thick reworked chalk in local graben led to the definition of additional reserves in the Valhall–Hod area.
Shearwater prospect development: a high pressure/high temperature challenge
Authors: BLEHAUT J. F. , VAN BEEK F. , BILLEAU C. , GAUSE J. K. , KIMMINAU S. , PAARDEKAM A. , RADCLIFFE N. , RADEMAKER R. , STORMS L. , WELSH B. J. , WITTEMANN A.
Published: April 2010

The Shearwater development involves exploitation of a high pressure/high temperature (HP/HT) (15 000psi, 185°C) prospect in the Central Graben of the North Sea which contains sour gas/condensate reserves equivalent to 406 × 10
6
BBL oil. The prospect is divisible into four blocks with reservoir intervals in the Upper Jurassic Fulmar Sands and the Middle Jurassic Pentland Formation at depths
c.
4700–5000 m. Progress of the Shearwater project, from feasibility to detailed engineering design, was achieved by breaking down traditional project boundaries on both management and technical sides and by integrating exploration and engineering tools in order to investigate and quantify wide numbers of options and scenarios to assist in reducing subsurface uncertainties.
Structural development and trap formation in the Central North Sea HP/HT play
Authors: HELGESON D. E.
Published: April 2010

This paper describes a new family of structures and class of tectonism; it is not wholly detached nor basement linked but falls between the two. The 3D interplay between basement extension and salt movement is used to describe the formation of a continuum of genetically linked trap styles in the Central North Sea HP/HT province. This style of deformation is progressive and manifests itself from simple low relief tilted fault blocks to large diapiric structures common to the UK eastern Central Graben. The proposed kinematic model attempts to unite basement structure, behaviour of salt, and observed map patterns into a simple continuous process. The model is composed of a succession of 6 time-ordered elements:

an initial basement (Permian/Triassic) framework of north–south and east–west normal faults;

Zechstein salt infill;

deposition of Triassic and Jurassic strata;

Late Jurassic basement extension, initiation of salt movement;

grounding and rotation of Triassic/Jurassic strata about the edges of basement fault blocks; and

upward movement of salt localized at the apex of the Triassic/Jurassic fault pattern.

The relative amount of salt involved varies, and produces structures of similar architecture, but of varying scale. The Triassic/Jurassic fault pattern and block orientation reflect this structural process in an apparently random nature (i.e. with no dominant trend in either fault or bedding strike). The orientation of each block and the resultant faulted boundaries are mainly an indirect reflection of the underlying 3D-basement configuration. Rotation occurs about a fulcrum between the Triassic/Jurassic section and the point of first contact with a basement fault block, with subsequent rotation into an adjacent graben. This allows for a range of possible fault and bedding orientations inherited from the initial and evolving basement structure, combined with interaction between the rotating Triassic/Jurassic blocks. Although the overall process is simple, the observed map patterns may be complex.

This model inherently decouples faults in the basement from the faults in the Triassic/Jurassic section. The Upper Jurassic and basement faults are different ages, and formed in response to different regional tectonics. Thus, common appeals to wrench tectonics, based on opposing offset along a single fault, seem to be unwarranted. This model is additionally supported by experimental analogues, where the seismic based observations can be reproduced in a qualitative manner.
Tern Field development: a marriage of new technologies for business benefit
Authors: BLACK R. C. , POELEN H. J. , ROBERTS M. J. , RODDY S. E.
Published: April 2010

The Tern Field, in the Northern North Sea, started production in 1989 and until 1995 was subject to conventional development, surface facilities improvements matching subsurface development priorities, and production. The principal Lower Ness/Etive reservoir was the focus of early development; production from the poorer quality Rannoch and Upper Ness reservoirs increasingly lagged behind. Development of sub-economic Triassic oil sands below, and small Brent satellite accumulations around the field, were not addressed. Since 1995 an ‘asset management’ approach to the Tern area, focused on maximizing full-field life value of the combined surface and subsurface assets has been adopted. Appropriate development of all potential hydrocarbon streams available to the Tern platform has been prioritized, and technology drivers to improve profitability of all streams have been aggressively pursued. In anticipation of rapid watering-out of Lower Ness/Etive reservoir, this wider development strategy incorporates the integration new technology in reservoir definition and exploitation to ensure continuing profitability in the Tern Field while maximizing reserves appreciation and development.

The strategy encompasses the poorer Brent and Triassic reservoir formations, several ‘near facilities potential’ accumulations, third-party development volumes. Reservoir definition methodologies comprise seismic inversion, bodymapping and time-lapse work, while modelling integrates seismic, geological and dynamic reservoir simulation technologies.

Exploitation methods comprise horizontal development within 15 ft thick sands, and more recently multilateral wells across Brent and Triassic objectives. These methods will lead to fundamentally improved opportunities to enhance profitability. Further plans to integrate extended-reach drilling and concurrent platform activities will enhance efficiency/effectiveness of the Tern area development. This paper illustrates the successful marriage of several technologies to the continuing benefit of a most successful field development.
Britannia Field, UK Central North Sea: modelling heterogeneity in unusual deep-water deposits
Authors: JONES L. S. , GARRETT S. W. , MACLEOD M. , GUY M. , CONDON P. J. , NOTMAN L.
Published: April 2010

Britannia Field is currently the UK’s largest undeveloped gas field, containing 4.3 × 10
12
SCF gas in place and condensate reserves of 150 × 10
6
BBL. Lower Cretaceous reservoir sands of low-moderate permeability (average 50 mD) form a combination structural–stratigraphical trap. Understanding the stratigraphy is a critical factor in reservoir description, geostatistical modelling and deliverability prediction.

The Britannia Formation is unique amongst known deep-water deposits in being dominated by slurry flow deposits which present challenges in reservoir interpretation and modelling. Slurry flow deposits contain most of the gas in the upper reservoir zones of UK Blocks 16/26, 16/27a and 16/27b. Many of these slurry flow sand events may be correlated over several kilometres using petrological, sedimentological and lithostratigraphical data. In contrast, clean high density turbidite (HDT) sandstones are well developed in the lower reservoir in UK Blocks 15/29a and 15/30. These sands are less extensive, and their interpretation is constrained by high resolution biostratigraphic and lithostratigraphic data.

An integrated 3D modelling environment links surface modelling, reservoir characterization, and fluid flow simulation at three different scales. Firstly, the sensitivity of production to geological heterogeneity from pre-drilled wells is tested on single-zone models. Secondly, optimization of well types and completions to maximize deliverability uses sector models containing all zones. Thirdly, the sensitivity of long-term field performance predictions to large-scale structural and stratigraphical reservoir compartmentalization is tested using full-field models. The use of different scales of reservoir model for different business purposes will contribute significantly to the optimization of drilling and production strategies as the Britannia Field moves into operation during 1998.
Innovation and risk management in a small subsea-tieback: Arkwright Field, Central North Sea, UK
Authors: KANTOROWICZ J. D. , ANDREWS I. J. , DHANANI S. , GILLIS M. , JENNINGS C. , LUMSDEN P. J. , ORR G. , SIMM R. W. , WILLIAMS J.
Published: April 2010

Arkwright is a 50 × 10
6
BBL oil field located within a single Forties Sandstone Member turbidite ‘channel’ system. Arkwright was discovered in 1990 and developed in 1996. Earlier start-up was precluded by reservoir risk and lack of export pipeline capacity. Reservoir definition improved after acquiring a 3D survey and applying imaging and attribute studies. This, combined with subsurface analogue, core, and carbon, oxygen and strontium isotopic studies, improved understanding of reservoir architecture and connectivity. Geostatistical techniques were used to quantify the STOIIP. The main risks identified were the absence of aquifer support, and possible vertical and lateral baffling. As these could not be tested by appraisal drilling it was decided to commence development.

Low-cost, two-well development options were considered and rejected because of the subsurface risk. Without guaranteed aquifer support, the productivity from early sub-bubble point flow would be lost waiting for injection support to be added. Risk-weighting highlighted the advantage of initial expenditure to safeguard the project, and so a third initial production well was planned, in a location suitable for conversion to injection.

Predicted rates were increased and the impact of lateral baffling minimized by drilling deviated producers on opposite sides of the structure, and not reusing the discovery well. Costs were reduced by using a drilling centre outside the field. The perforation strategy ensures drainage above and below potentially sealing abandonment shales, and facilitates future zonal isolation. Communication within the reservoir was tested at start-up with an interference test.
High resolution zonation within a tide-dominated deltaic reservoir: the Middle Jurassic Beryl Formation, Beryl Field, UKCS
Authors: MAXWELL G. , HARTLEY A. , CRANE J.
Published: April 2010

The Middle Jurassic (Bajocian–Bathonian) Beryl Formation of the Beryl (Bravo) Field (Viking Graben), has been produced since 1979 and contains estimated remaining reserves of 180 × 10
6
BBL oil. Previous studies of this deltaic/shallow marine succession have defined five reservoir units. Production characteristics indicate that this lithostratigraphically-based zonation scheme does not adequately define reservoir flow units and constrain sweep efficiency. Here, a more refined reservoir zonation is used to form the basis for an upgraded reservoir simulation model.

High density well coverage (50 wells) in the Beryl Bravo area allows the construction of a high resolution reservoir zonation scheme within the main producing interval of the Beryl Formation: Unit 3. The scheme is based on integration of sedimentology, ichnology, biostratigraphy, dynamic data and well log character. Nine reservoir zones (consisting of nine genetic sequences) have been defined and confirmed and are supported by drilling and production data.

The complex reservoir zonation scheme is based upon the recognition of regionally extensive marine/brackish mudstones which, in many cases, form traceable pressure barriers across tilted fault blocks. This framework has allowed subdivision into 3 to 25 m thick correlatable units. Individual units record the progradation and transgression of tide-dominated deltaic deposits. Variations in the thickness and development of these units result from sedimentation in actively subsiding half-graben that were subject to regionally extensive base-level changes. The integrated approach taken here has substantially improved the understanding of the architecture and production characteristics of the Beryl Formation.
Faeroes Large Aperture Research Experiment (FLARE): imaging through basalt
Authors: WHITE R. S. , FRUEHN J. , RICHARDSON K. R. , CULLEN E. , KIRK W. , SMALLWOOD J. R. , LATKIEWICZ C.
Published: April 2010

The acquisition of high density, large aperture seismic data may allow the deep crustal structure to be studied in areas that have traditionally proven difficult to image using conventional seismic profiling techniques, such as those where high-velocity basalt flows or sills overlie sedimentary sections. This is because the amplitudes of reflections at wide angles are generally much larger than at near normal-incidence, and because large aperture seismic data carries much more velocity information than the limited aperture data recorded along conventional seismic profiles. We discuss the acquisition and processing of synthetic aperture seismic profiles, using two 2D seismic vessels to achieve continuous offsets to more than 38 000 m along profiles near the Faeroe Islands, shot as part of the Faeroes Large Aperture Research Experiment (FLARE).

The new technique shows the presence of lava flows extending away from the Faeroe Islands across a thick (up to 4 km), probably Mesozoic and early Tertiary underlying sedimentary section. Seismometers on the Faeroese island of Suduroy show that the sedimentary section pinches out beneath the island, and also provides control on the crustal thinning beneath the region southeast of the Faeroe Islands. Since Tertiary basalt flows and sills are such a pervasive feature of the geology of the highly prospective northwest European continental margins, synthetic aperture profiles are likely to be of considerable importance in the future in imaging sub-basalt structure in these areas.
Diagenetic porosity creation in an overpressured graben
Authors: HASZELDINE R. S. , WILKINSON M. , DARBY D. , MACAULAY C. I. , COUPLES G. D. , FALLICK A. E. , FLEMING C. G. , STEWART R. N. T. , McAULAY G.
Published: April 2010

The Central Graben of the North Sea is an actively subsiding, highly overpressured, basin. At the present day, hydrocarbons are migrating both vertically and laterally through the stratigraphy to fill reservoirs from Permian through to Eocene. The late Jurassic Fulmar Sandstone approaches rock fracture pressure in many Central Graben areas. Petrographic studies show that sandstones originally contained as much as 35–40% potassium feldspar. This has dissolved rapidly below 3 km, so that by 4.5 km sandstones may contain only 5% feldspar. This loss is not matched by growth of authigenic clays or feldspars; aluminium is interpreted to have been exported from the sandstones by an unknown mechanism. In some cases, excess kaolin may form in overlying Palaeogene sandstones. Improved stratabound secondary porosity (an additional 5–15%) is created along the top of reservoir sandstones and at structurally high leak-off points. Leak-off points maintain high porosities, partly because overpressure reduces the effective compactional stress. This secondary porosity forms zones of good reservoir quality in predictable positions.

Oils migrating vertically and laterally into Palaeogene sandstones have been bacterially oxidized, to form calcites with distinctive carbon isotope signatures. The distribution of such cements can be a guide to deeper leak-off positions. Modelling of modern temperatures across the graben shows that spikes of elevated temperature occur above leak-off positions, demonstrating that vertical fluid-flow is still active.

The Central Graben, and any actively subsiding deep basin, can be viewed as one interconnected system, where localized deep porosity is created, and shallow porosity is destroyed. The organic, inorganic, temperature and overpressure fluid systems are all interactive.
Assessment of undiscovered resources on the Norwegian Continental Shelf
Authors: ØSTVEDT O. J. , BLYSTAD P. , MAGNUS C.
Published: April 2010

The Norwegian Petroleum Directorate (NPD) makes annual assessments of the total petroleum resources on the Norwegian Continental Shelf (NCS). Major updates of the undiscovered resources have been done every second year, most recently in 2003. The resource assessment provides an overview of the resource potential that can be materialized in the future. This is used by the government to plan future licensing rounds and to make forecasts on petroleum activity and it provides oil companies with valuable information about exploration potential.

The NPD defines resources as the total recoverable petroleum. The estimation is done using a probabilistic method, using the mean value as the official number. The undiscovered resources are estimated as a total figure for both the mapped (prospects) and the unmapped (potential prospects) for each play. The input parameters are standard volumetric parameters, with the addition of distribution of prospect size, number of prospects likely to occur in a play and the average chance of success. Discoveries and prospects provide crucial information to the play analysis.

The North Sea, although fairly mature, still holds a considerable potential of undiscovered resources and is assumed to be the most oil-rich province. Pre-Jurassic plays are poorly explored in the Norwegian sector, as are stratigraphic plays. A large part of the remaining resources is assumed to be in medium to small discoveries. The Norwegian Sea holds the largest potential of undiscovered resources, with potential large structural traps in Cretaceous and Tertiary deep-water plays in the Vøring and Møre basins. The Barents Sea has potential for large discoveries of both oil and gas. Recent identification of pre-Jurassic source rocks increases the chance of discoveries in pre-Jurassic plays. The uncertainty in the estimates is large due to few wells drilled outside the Hammerfest Basin.
Predicting gas production from future gas discoveries in the Netherlands: quantity, location, timing, quality
Authors: LUTGERT J. , MIJNLIEFF H. , BREUNESE J.
Published: April 2010

Recent policy and market developments have raised the question not only as to how much gas remains to be discovered in the Netherlands but also where and when it will be produced and of what quality. These questions are addressed by compiling a ‘firm futures’ database, estimating the ‘potential futures in proven plays’ and simulating the exploration process using the prospect portfolio.

The firm futures are assessed using an integrated play evaluation method in a combined database/GIS environment. The database includes a prospect portfolio of firm futures, well data and maps. Volumetric estimates (low, mean and high success volumes) are assigned to the prospects. The risk of each prospect is estimated using play maps and the historical success ratio for that play. Using standard GIS functionality, the distance to production nodes, the gas quality, licence status and operator are determined for each prospect. The prospect portfolio is not static but dynamic. Using the creaming curve, fractal distribution analysis and the average POS (Possibility of Success) of the play, the gas volume and the amount of structures in the potential futures category are estimated. Again, GIS functionality is used to determine possible new locations and the gas quality of the prospects. The prospect portfolio is the input for a computer program that stochastically simulates the exploration process. Assumptions about future drilling efforts, economic screening scenarios and time delays from discovery to production are made explicit. The program simulates annual drilling campaigns. A number of prospects are drilled according to an assumed exploration efficiency and the POS is used to determine the result: a discovery or a dry well. The discovered volume is economically assessed and, if economic, transformed into a production and gas-quality profile.
Fault trap analysis of the Permian Rotliegend gas play, Lauwerszee Trough, NE Netherlands
Authors: CORONA F. V.
Published: April 2010

The Lauwerszee Trough is a northwest-trending sub-basin within the Southern Permian Basin and lies in the onshore area of northeastern Netherlands. Referred to as the ‘Golden Lane’ Trend, it is the classical Lower Permian Rotliegend gas play of the Netherlands, consisting of the prolific, high net-to-gross sandstone reservoirs of the Slochteren Formation. Traps are tilted extensional fault blocks that entrap gas sourced from the Carboniferous Coal Measures. The overlying Rotliegend Ten Boer Claystone and Upper Permian Zechstein evaporitic rocks provide the top and lateral seals for the fault traps.

In this study 30 fault traps were analysed in which 22 were found to have gas accumulations. Trap fill is controlled primarily by Slochteren sand-on-sand juxtaposition leakage across a fault; however, some gas accumulations as mapped appear to be filled deeper than this leakpoint and require sand-on-sand fault seal. Retained fault-seal gas columns are relatively small and mostly less than 60 m with one exception of 95 m.

Seven potential Slochteren sand-on-sand fault-zone seals were identified in this study. The analysis of these fault traps revealed three possible criteria that may promote the development of such fault seals: (1) juxtaposition against a tight, shale-rich interval; (2) small isolated sand-on-sand juxtaposition area (<25 000 m
2
) typically associated with fault lengths less than 1 km; or (3) occurrence of a complex narrow fault zone. However, some sealing fault segments are associated with structural interpretation/mapping uncertainty. Minor map changes may eliminate perceived sand-on-sand fault-zone seals and explain trap fill by conventional fault juxtaposition.
Role of Cenozoic fault reactivation in controlling pre-rift plays, and the recognition of Zechstein Group evaporite-carbonate lateral facies transitions in the East Orkney and Dutch Bank basins, East Shetland Platform, UK North Sea
Authors: RICHARDSON N. J. , ALLEN M. R. , UNDERHILL J. R.
Published: April 2010

The East Orkney and Dutch Bank basins are located to the north of the Moray Firth rift arm in the UK North Sea. The East Orkney Basin measures approximately 60 by 30 km and is bounded to the west, north and east by large normal faults. The West Fladen High consists of a series of horsts and grabens, and separates the East Orkney Basin from the Dutch Bank Basin, which is situated immediately to the north of the Witch Ground Graben and to the west of the Fladen Ground Spur. Although exploration well results for the limited penetrations of structural highs on the margins of the East Orkney Basin have been disappointing, geophysical and geochemical analyses all appear to indicate the presence of a mature source in the region. Integration of wireline data, core samples, and the interpretation of 2D seismic data within the area allow mapping of the main structures in the basins and correlation to the adjacent well penetrations, thus not only enabling a tectonic and stratigraphic history, but also a framework for prospectivity to be established.

A pillow-shaped sedimentary package at approximately 3 seconds two-way traveltime within the centre of the East Orkney Basin represents the downdip equivalent of stratigraphy on the West Fladen High, and is interpreted to be a Zechstein Group salt body, underlain by a thick sequence of Lower Permian (Rotliegend Group) and Devonian strata. Cored intervals from well 14/2-1 on the West Fladen High contain carbonates, evaporite dissolution breccias and anhydrites, implying a lateral change in sedimentary facies between structural highs and lows. Rifting took place through the Triassic and Jurassic, followed by relative tectonic quiescence in the Cretaceous, but as in adjacent areas, the Cenozoic witnessed structural inversion related to plume-generated uplift in the North Atlantic and the activation/reactivation of underlying faults coupled with deformation of the basin fill adjacent to these structures. Regional tilting from the Paleocene to early Eocene led to an influx of siliciclastics into the Dutch Bank Basin. The main play type is thought to consist of Rotliegend Group and Devonian sandstone reservoirs on the West Fladen High, sealed by Zechstein Group anhydrites or Cretaceous/Tertiary mudstones and charged by a deeply buried Devonian (Orcadian) lacustrine source. Although hydrocarbons are interpreted to have utilized normal faults as migration pathways, comparison with adjacent areas and observations of numerous oil seeps on the sea surface suggest that reservoir breach through reactivation of these faults to the seabed poses the main exploration risk. This fault reactivation has resulted from differential uplift combined with synchronous extensional faulting that affected adjacent areas, including the Inner Moray Firth.
Better recovery through better reservoir characterization: overview
Authors: GLUYAS J. G. , GARRETT S. W.
Published: April 2010

In a mature petroleum province, such as offshore NW Europe, the critical role of the petroleum geoscientist is to find the remaining oil and gas in producing fields, undeveloped segments and satellites. A survey of literature from previous conferences in the NW Europe series demonstrates the progression in technology and recovery, with the most significant and consistent improvement in recovery being from large Paleocene oil fields. Examples from the 2003 conference demonstrate advances in the resolution in data, 4D seismic, modelling, and well placement. Remaining potential uncertainty and upside in recovery in later field life present opportunities both for established major companies who wish to maximize value of core properties, and for new entrants who adopt innovative mindsets to creating new economic wealth through field rejuvenation.
A significant satellite: the Nevis South Field in Block 9/13
Authors: FARQUHARSON G. W. , GIBSON J. P. C.
Published: April 2010

The Nevis South Field is an outstanding field in a number of respects. It contains four stacked reservoirs, two contrasting oil types, a high quality Triassic reservoir and a Beryl reservoir of such quality that one of the producing wells held the North Sea’s record for productivity index. The field is operated by Mobil North Sea Limited (ExxonMobil) with co-venturers Amerada Hess Limited, Enterprise Oil Limited and OMV (UK) Limited. It is a sub-sea development tied back to the Beryl Alpha platform that lies 7 km to the east-northeast. First oil was produced in 1996 but the field is still actively being drilled to new reservoirs and to maximize recovery from already producing reservoirs. Structurally the field is a relatively simple rotated fault block with beds dipping to the southwest and a crestal depth of 8700 ft. The Base Cretaceous Unconformity cuts down into the crest of the fault block such that strata are progressively eroded towards the northeast. Consequently, the core of the field contains Triassic strata with younger, Jurassic, strata on the flank. The oldest reservoir in the field is the Triassic Lewis I sequence of fluvio-lacustrine origin. It contains an unusual heavy oil which is currently being produced via a single, high-angle well. Above this unit lies the Lewis III/IV reservoir which contains the bulk of the hydrocarbons in the field. These sediments are ephemeral stream deposits which are exploited via four producers and a pair of water injectors. The Middle Jurassic Beryl reservoir is a high net:gross tidal delta succession of multi-Darcy permeability. Drainage of the Beryl oil rim is by three horizontal wells with pressure support supplied by the large aquifer. A Beryl gas blowdown phase of development is scheduled for 2005. Drilling and workover activity is guided by fine-scale geological modelling and accompanying simulation. The youngest reservoir comprises mass-flow sandstones of the Middle–Late Jurassic Heather Formation. These relatively thin sandstones contain a comparatively small volume of oil and gas which it is currently uneconomic to develop.
The Mittelplate oil field
Authors: DOEHLER M.
Published: April 2010

The Mittelplate oil field with its 600 × 10
6
BOIP is Germany’s largest oil field and lies offshore Germany in coastal tidal flats about 100 km northwest of Hamburg at the mouth of the River Elbe estuary, some 25km northeast of Cuxhaven. It is located in the Westholstein Jura Trough with its flanking salt walls, Oldensworth and Heide.

The discovery well Mittelplate 1 was drilled in 1980 by the consortium RWE Dea AG and Wintershall AG. The prospects targeted by the Mittelplate 1 well were Middle Jurassic Dogger sandstone reservoirs. At the time only 2D data was available to the group and only a few seismic lines defined the play. The discovery well encountered two separate oil columns within the Middle Jurassic ‘Mittelplate’ sands which, when tested, flowed low gravity oil from four sandstone reservoir horizons at a depth of 2136–2743m below sea level.

In 1981 three appraisal wells were drilled, confirming the structure with initial recoverable reserves estimated to be at around 200 × 10
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BO. The distance of the field to the coast is between 7 and 13 kmwith a N–S extension of more than 10km straddling the western flank of the Büsum salt dome. After building an artificial drilling and production island in 1985, 15 wells have been drilled since 1986 from the Mittelplate-A platform draining the central part of the field.

Along with the acquiring of new 3D seismic in 1997 in the area between the appraisal wells Mittelplate 2 and Mittelplate 3, a pilot project was initiated to develop the field through extended reach wells from onshore. Three wells were drilled from the Mittelplate island to the salt dome to verify geology and drilling requirements. At the same time one well, the Dieksand 1, was drilled from the shore to investigate the situation from the onshore side. After only half a year of engineering time, the first extended reach drilling (ERD) well, Dieksand 2, was spudded, drilled more than 3600m horizontally through the Büsum salt dome and was successfully completed at a TD of 7727min 1998. Since then a further six ERD wells have been drilled from onshore reaching a maximum length of 9275mMD. After 17 years of undisturbed and accident-free operation, the Mittelplate group is now planning to investigate the development of the southern and northern part of the field with horizontal wells of more than 8km from the Mittelplate-A platform location.
Estimation of shape factors in fractured reservoirs
Authors: IF F. , FRYKMAN P.
Published: April 2010

This paper describes a procedure for calculating the matrix–fracture transfer shape factor for dual porosity models for fractured reservoirs. The procedure is implemented in 3D and uses the Continuous Time Random Walk (CTRW) method.

In previous works the method has been implemented only in 2D and has required a mesh produced by triangulation of the 2D fracture network. The CTRW method used here is extended to 3D in a simpler implementation with rectangular grid cells, which significantly reduces computation effort, but otherwise relies on the same principles. The method is based on modelling of random walk of particles through the matrix media. For each particle the random walk is terminated when the particle encounters a fracture and the random walk time is recorded. The average random walk time for many particles is used for calculating the shape factor for the investigated volume.

The calculated shape factor with this new method is compared with analytical estimates for idealized regular networks of fractures, and with flow simulation-derived shape factors for more realistic fracture networks. The results demonstrate that the new method reproduces analytical and numerical results in simple fracture models from other studies and, furthermore, is capable of analysing very complex 3D fracture models and their properties. The method has potential in traditional dual porosity simulation in oil and gas studies, and also in transport modelling where diffusion processes are the driving force in exchange between matrix and fractures. The method also has potential as a general characterization tool in fractured rock systems, where the shape factor and its distribution can be used as a qualitative descriptor of the rock matrix block-geometry and as an indicator of the behaviour of matrix–fracture exchange processes.
On the dynamics of capillary gas trapping: implications for the charging and leakage of gas reservoirs
Authors: SYLTA Ø.
Published: April 2010

Capillary leakage of gas from buried structures can be quantified using Darcy migration concepts together with formulations for cap-rock permeability, relative permeability and entry pressures at low gas saturations. Capillary trapping has a static component defined by the entry pressure of the cap rock and a dynamic component defined by Darcy migration velocities and rates of migration into the trap. The importance of the dynamic trapping component increases with burial due to a corresponding reduction in cap-rock permeability. The low gas migration velocities through buried cap rocks make it unlikely that gas escape from these traps will be focused above their tops. Barriers within the cap-rock sequence may increase the gas saturation and increase the lateral width of the leakage zone. This may result in complex leakage routes into shallower structures.

Source rocks that supply gas to deeply buried traps will start to become exhausted as the temperatures increase. This reduces the rate of gas supply into the traps. Dynamic traps which have trapped gas columns that exceed the capacity of the cap-rock entry pressures can then no longer support the same column heights, and they are reduced in size. The reduction in column heights may continue below the capacity defined by cap-rock entry pressures because of hysteresis effects.

The reduction in seal capacity for deeply buried traps can be estimated if the gas fill history of the trap is known. Traps with a low vertical relief can be shielded from the dynamic seal destruction mechanism by the spill process. During periods of reduced or halted gas generation from the source rocks, dynamic traps will continue to leak for million of years. This delayed leakage may be an important source for the filling of shallower traps with gas long after the source rocks have been buried too deeply for generation to take place.
Modelling fine-scale heterogeneity for optimal history matching from aeolian gas reservoirs, Neptune Field, UKCS
Authors: GARDEN R. , MENTIPLY M. , COOK R. , SYLVESTER I.
Published: April 2010

Improved matching of reservoir simulation model results to production data in gas fields allows improved reservoir management and optimization of hydrocarbon production. In high net:gross aeolian sandstones this requires the full range of scales of permeability heterogeneity to be represented in a model. This necessitates the modelling and appropriate upscaling of rock properties, including the millimetre-scale lamina effects within the aeolian dune slipface facies, the contrast between dune apron and slipface facies and the impact of first- and second-order bounding surfaces within the dune complexes and the super-bounding surfaces that separate them.

The Neptune Gas Field lies on the northwest margin of the Southern North Sea gas basin and in Block 47/4b and extends into Blocks 47/5a and 42/29. Gas is reservoired in the Lower Leman Formation which in the Neptune Field, comprises a succession of stacked dry aeolian sandstones and thin, wet interdune deposits. Permeability varies significantly at the lamina and bedform scale and these variations impact the performance of production wells in the field.

A deterministic reservoir simulation model was constructed prior to development drilling, with permeability determined from porosity–permeability transforms based on core analysis data. The collection of continuous bottom-hole pressure (BHP) data from three of the development wells showed that this model failed to match accurately the rate of pressure decline whilst flowing, and over-predicted the build-up pressure when the wells were shut in. Review of the sedimentological information revealed that heterogeneity in the aeolian sands was being lost in the modelling of permeability and the coarse upscaling. To test whether the poor dynamic history match was due to the deterministic model not incorporating the permeability heterogeneity, a fine-scale geocellular model was built to characterize the expected geological heterogeneity and then upscaled for flow simulation. To accommodate the range in scales of heterogeneity present, the modelling was undertaken in two principal steps. First, the lamina-scale effects were modelled to determine average flow properties perpendicular and parallel to dune migration directions. The results of the lamina-scale heterogeneity modelling were then incorporated into petrophysical models of dune bodies that were characterized by low permeability dune apron facies and high permeability base of dune slipface facies that grade upwards into moderate permeability slipface facies.

Upscaling of the stochastic permeability grid captured the impact of the fine-scale heterogenetity and gave BHP responses at the development wells in better agreement with the production data than any deterministic permeability distribution modelled. The stochastic rock property distributions have, thus, been adopted as the base case in all future history match and reservoir performance prediction studies.