bluuebunny/crossref_metadata_2025_split huggingface dataset:
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.
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.
Angola Block 18: a deep-water exploration success story
Authors: FRASER A. J. , HILKEWICH D. , SYMS R. , PENGE J. , RAPOSO A. , SIMON G. 
Published: April 2010

Offshore Angola Block 18 was awarded to Amoco in October 1996 for an initial four-year exploration period with an associated four well commitment. This was subsequently extended in October 2000 for an additional three years and further two well commitment. Ownership is BP (operator) 50% and Shell 50%. The block covers an area of 4880 km
2
, the equivalent of some 35 UKCS blocks. Water depths range from 200m in the east to over 1600m in the west. Block 18 is almost entirely covered by over 5000 km
2
of high quality 3D seismic data.

Exploration activity has, to date, focused on the western part of the block lying in 1200–1600m of water on the southward extension of the successful Tertiary play from Blocks 15 and 17. Reservoir targets occur in Miocene and Oligocene submarine slope channel sands associated with the evolving Congo River cone. Charge is derived from Upper Cretaceous–Tertiary marine shales of the Iabe Formation. Dominant trap styles are combined structural and stratigraphic domes and turtles associated with movement of Aptian salt.
Since the BP–Amoco merger in January 1999, six exploration wells have been drilled to fulfil the first and second phase exploration commitments (Platina, Plutonio, Galio, Paladio, Cobalto & Cromio) all of which have been significant oil discoveries in turbidite channel and sheet sands of Miocene and Oligocene age. Given an unprecedented six discoveries out of six wells, it is clear that the working Tertiary fairway in Block 17 extends south into Block 18. Keys to success have been rapid integration of BP’s Block 15 and 17 experience with existing Amoco interpretation and technologies in Block 18.
The learnings from the successful exploration campaign in Block 18 Angola, specifically in the use of high quality 3D seismic attributes as a risk reduction tool, have application in deep-water plays elsewhere, such as the Tertiary and Upper Cretaceous of the North Sea and offshore mid Norway.