bluuebunny/crossref_metadata_2025_split huggingface dataset:
Beryl Field: geological evolution and reservoir behaviour
Authors: ROBERTSON G. 
Published: April 2010

The Mobil-operated Beryl Field is located in UK Block 9/13. Hydrocarbons are present in Triassic and Jurassic sandstone reservoirs, within a large fault-bounded structural trap. Interaction of sub-perpendicular fault trends determined the geological evolution of this structure and controlled the distribution of the sandstone reservoirs.
Hydrocarbon generation and subsequent migration commenced in Paleocene time. Entrapment of these hydrocarbons was influenced by pre-existing geological complexity and reservoir continuity. The distribution of different oil-types and multiple fluid contacts is defined by both structural and stratigraphic compartmentalization. Pre-production, the field reached a state of dynamic equilibrium between influx and leakage of hydrocarbons.
Production of oil commenced in 1976. Gas injection and water injection were initiated to arrest pressure decline. Pressure distribution and fluid movement throughout the field’s productive life are strongly influenced by geological controls. Understanding these geological controls has resulted in more effective reservoir management and optimization of the hydrocarbon resource.
4D evolution of segmented strike-slip fault systems: applications to NW Europe
Authors: DOOLEY T. , McCLAY K. , BONORA M. 
Published: April 2010

Scaled, physical sandbox modelling has been used to simulate the progressive deformation of segmented strike-slip fault systems at both releasing (pull-apart basins) and restraining oversteps (‘pop-up’ structures) developed in a weak sedimentary cover above rigid basement. Pull-apart basin evolution is characterized by the initial development of a spindle graben bounded by oblique-extensional faults that cross the ‘basement’ overstep, and subsequent lengthening of the basin as displacement on the master faults increases. The pull-apart basins are bounded by terraced oblique slip extensional sidewall fault systems that link the laterally offset principal displacement zones (PDZ). The sidewall faults show changes in kinematics from dominantly dip-slip extension in their central sections to oblique slip and strike-slip at either end where they merge with the PDZ. The pull-apart basin models are flat-bottomed in the centre of the basin and become asymmetric at either end where the sidewall fault systems join the PDZ. Cross-basin fault systems, which are characteristic of all models, cut the floor of the pull-apart basins and link the offset PDZs. Deformation above restraining offsets is characterized by the formation of rhombic to lozenge-shaped uplifts or ‘pop-ups’ – structures bounded by oblique-slip reverse faults that fan outwards from the PDZ. With increased displacement on the master faults the rhombic-uplifts grow in amplitude. The upper surfaces of the ‘pop-up’ structures are dissected by both synthetic and antithetic strike- and oblique-slip faults. Distinctive asymmetric positive flower structures characterize the lateral margins of the ‘pop-up’ structures.
The analogue models are compared with natural examples of strike-slip pull-apart and ‘pop-up’ fault systems from NW Europe. The models show many strong similarities in structural geometry and stratal architectures with many natural examples, although it must be emphasized that similarities between structures of purely extensional origin (multiphase) and those associated with inversion do exist. Therefore, these analogue models of complex strike-slip structures may provide useful templates for seismic interpretation in petroleum basins provided there is a demonstrable link between strike-slip motion on basement structures and deformation in the cover.
The Hibernia Oilfield – effects of episodic tectonism on structural character and reservoir compartmentalization
Authors: SINCLAIR I. K. , EVANS J. E. , ALBRECHTSONS E. A. , SYDORA L. J. 
Published: April 2010

The giant Hibernia Oilfield in the Jeanne d’Arc Basin, the first hydrocarbon development on the Grand Banks of Newfoundland, began production from an ice-resistant, concrete gravity base platform in November 1997. An estimated 615 × 10
6
BBL recoverable oil reserves are trapped in a highly faulted and south-plunging anticline.

The tectonic stresses experienced on the western North Atlantic margin have largely controlled the density and size distribution of faults which limit and partition the Hibernia structure. More than 30 fault blocks have been identified at one major oil and gas reservoir alone, the fluvial–deltaic Hibernia Formation. Interpretations of relationships between the times of tectonism and changing stress directions with fault ages, orientations, and styles are based on comparison of a 1991 vintage 3D seismic survey along with data from one discovery, nine delineation and two development wells. There appear to have been three main episodes of extension that affected the oilfield.
The first extensional episode spanned the Late Triassic into the Early Jurassic. Adjacent to the Hibernia Oilfield, initial rifting resulted in growth of NE-trending, en echelon faults that were subsequently amalgamated into the major basin-bounding Murre Fault. Deposition of the Hibernia Formation sandstones occurred during the second tectonic episode that spanned Late Jurassic into Early Cretaceous time. Faults of this vintage in the Hibernia Oilfield are normal and mostly formed synthetic to the re-activated Murre Fault in response to E–W oriented extension. The most marked fault growth occurred during the third tectonic episode. This late Early Cretaceous rift episode was co-eval with deposition of another major oil reservoir (the marginal to shallow marine ‘Avalon’ formation) which is targeted for development. Numerous normal faults formed orthogonal to the basin margin, thereby transecting and rotating the Hibernia structure. Fault development during the latest rift episode also responded to basin margin effects as a result of reactivation of the Murre Fault as a zone of oblique-slip. For example, the character of the large Rankin and Nautilus faults changes from relatively planar to distinctly listric moving from east to west. Additionally, sinistral deflections in the trace of the Murre Fault corresponding to linkages of the en echelon offsets formed during the first rift episode are interpreted to have controlled the location of the largest northeast dipping faults formed during the third rift episode.
The largest faults formed during the third rift episode clearly compartmentalize the Hibernia reservoir while the sealing capacity of faults formed during deposition of the Hibernia sandstones remains unquantified.
Early Tertiary magmatism in the offshore NW UK margin and surrounds
Authors: RITCHIE J. D. , GATLIFF R. W. , RICHARDS P. C. 
Published: April 2010

The Iceland Plume, activated perhaps as early as Late Cretaceous time and extending through the Tertiary, was responsible for the generation of large volumes of igneous rocks, covering an area of roughly 2000 km in diameter, encompassing Greenland. the Vøring Basin, the Faeroes, the Faeroe–Shetland Basin, the Rockall Trough and NW Scotland. Within this large area, magmatism is mainly manifested as lava fields, sediment–sill complexes, and central or strato/shield type volcano complexes.
Towards the continental margin of NW Europe, extrusive rocks occur m two distinct geographical areas. SW of the Munkagrunnur Ridge of the Faeroe Platform, lavas are mainly extruded radially from strato/shield volcano complexes. To the NE, in contrast, seismic evidence suggests that the tipper part of the Faeroe Plateau Lava Group extrusive originate from the same source that formed the Seaward Dipping Reflector Sequences NW of the Faeroes. Towards the SE of the Faeroes, the distribution of the Faeroe Plateau Lava Group (Upper. Middle and Lower Series) lavas is controlled by pre-existing structure and sea-level fluctuations, Seismic and well evidence confirms that, generally, the Upper Series extends furthest into the Faeroe–Shetland Basin while basaltic progradational units form the SE limit of the Lower Series. Similar structures of possibly the same age have been identified within the NE Rockall Trough.
There appear to have been two major phases or pulses of Early Tertiary magmatism within the North Atlantic Igneous Province; an initial outburst at around 62 Ma and a later phase at around 55 Ma.
Anisotropy and amplitude versus offset: a case history from the West of Shetlands
Authors: MARGESSON R. W. , SONDERGELD C. H. 
Published: April 2010

An amplitude versus offset (AVO) case study is presented from the West of Shetlands, UKCS in which pre-drill AVO signatures over a prospect were interpreted to be expressions of hydrocarbons but upon study of the data provided by the well were interpreted as a manifestation of anisotropy. The core from the well proved to be crucial in understanding the non-hydrocarbon AVO signature.
The well encountered good quality, high porosity, water wet sand and an underlying tuff sequence. Neither the dipole sonic log nor the check-shot survey revealed any anomalous elastic properties, nor did they detect the presence of anisotropy. Conventional, isotropic modelling using the measured log properties could not match the observed AVO response. Only comparison of the dipole sonic log and the check-shots with the core measurements gave evidence for the presence of substantial elastic anisotropy. Incorporation of anisotropy inferred from core and log measurements in the shales and tuffs gave a reasonable match to the observed AVO. The inferred anisotropies are substantial, averaging 15% for both the compressional and shear velocities and increasing over some depth intervals to 25%. A subsequent walkaway vertical seismic profile (VSP), acquired for the specific purpose of calibrating the AVO response, shows a marked AVO effect at the base of the target sandstone and tuffs, consistent with the surface seismic data. It is clear from this case study and other work that simple transverse anisotropy, for example, produced by the natural layering in shales, can cause first order effects on the AVO response.
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 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.