bluuebunny/crossref_metadata_2025_split huggingface dataset:
The North Brae and Beinn Fields, Block 16/7a, UK North Sea
Authors: Brehm J. A. 
Published: April 2008

Abstract
North Brae is located in Block 16/07a, and was discovered in 1975 by Pan Ocean Oil Company. The field was purchased by Marathon Oil Company in 1976 and was delineated in the early 1980s. Production by gas recycling was commenced in 1988. Liquid reserves are estimated at 207 MMBBLs with recoverable dry gas of 800 BCF.
The North Brae Field is one of three gas/condensate fields in the Brae fields area of the South Viking Graben in the UK Sector of the North Sea. The reservoir is part of a large turbidite and debris flow, submarine fan system that also encompasses the East Brae and Kingfisher fields to the northeast of North Brae. North Brae is located at the proximal end of this fan system, and channelized massive conglomerates and sandstones characterize its reservoirs. The stratigraphy of the fan system was influenced by highly variable changes in relative sea level that controlled sediment input. Structural activity was also important, such as syn-sedimentary normal faulting related to the subsidence of the South Viking Graben, and structural inversion, in a series of regional compressive episodes commencing in the Late Jurassic and Early Cretaceous.
The West Brae and Sedgwick Fields, Blocks 16/06a, 16/07a, UK North Sea
Authors: Wright Simon D. 
Published: April 2008

abstract
The Marathon-operated West Brae Field straddles Blocks 16/06a and 16/07a in the UK Central North Sea approximately 140 miles (225 km) NE of Aberdeen. The field was discovered in 1975 with drilling of exploration well 16/07-2. The West Brae reservoirs consist of Eocene Balder Formation and Upper Sele Formation Sandstones that were deposited in NW-SE trending submarine channels across the area. Development of the field commenced in April 1997 with first oil being achieved in October the same year. The filed has been developed using sub-sea tie-back to the Brae A platform, which lies 5.6 miles (9 km) SE of the sub-sea manifold. Recoverable reserves are estimated to be 60 MMBBLs, of which some 23 MMBBLs had been produced by 31 December 1999
The Staffa Field, Block 3/8b, UK North Sea
Authors: Gluyas J. G. , Underhill J. R. 
Published: April 2008

Abstract
The Staffa Field occurs at the crest of an intermediate tilted fault block that is located between the Ninian and Alwyn fields in the northern North Sea. The partnership BP, Lasmo and Ranger discovered the field with well 3/8b-10 in 1985. By 1990, BP had left the partnership while Lasmo and Ranger had received Annex B approval for development. First production from this small field reservoired in sandstones belonging to the Middle Jurassic, Brent Group was obtained in 1992. At sanction, reserves were estimated to be about 5.5 MMBBL together with 26.8 BCF corresponding to a recovery factor of 18%. Field life was expected to be about 7.5 years (to 2000) and the plateau length six months. Although initial production exceeded the planned plateau rate of 8000 BOPD, production ceased in June 1993 when the pipeline to Ninian became blocked with wax or wax hydrates. Remedial solvent treatment failed to remove the blockage and replacement of the blocked section was undertaken. This too became blocked soon after resumption of production and the field was shut-in in November 1994. It was then abandoned, since further replacement of the line was not justified economically. At abandonment the field had produced 3.9 MMBBL of oil, 0.296 MMBBL of NGL and 6.457 BCF of gas Gust 13% of its original STOIIP).
The T-Block Fields, Block 16/17, UK North Sea
Authors: Gambaro M. , Donagemma V. 
Published: April 2008

abstract
The Tiffany, Toni, Thelma and SE Thelma fields, collectively referred to as the T-Block fields lie wholly within UK Block 16/17 at the southern end of the South Viking Graben. The four fields were discovered between 1976 and 1980 and despite the fact that they share a common reservoir, the Upper Jurassic Brac Formation, they are quite distinct in terms of their petroleum content (type), reservoir quality and production performance. This paper summarizes the characteristics of the T-Block petroleum accumulations and highlights the differences between each of the field.
The MacCulloch Field, Block 15/24b, UK North Sea
Authors: Gunn C. , MacLeod J. A. , Salvador P. , Tomkinson J. 
Published: April 2008

Abstract
The MacCulloch Field lies within Block 15/24b in the UK Central North Sea and is located on the northern flank of the Witch Ground Graben. It was discovered by Conoco well 15/24b-3 in 1990.
MacCulloch Field is a four-way dip closure at Top Paleocene over a deeper Mesozoic structure. The reservoir consists of Upper Balmoral Sandstones containing 32-37° API oils derived from Kimmeridge Clay Formation shales and sealed by shales belonging to the Sele Formation. The field contains recoverable reserves of 60-90 MMBOE.
Reservoir quality is generally very good, with an average porosity of 28% and core permeabilities (Kh) between 200 mD and 2D. AVO anomalies and a seismic flat spot are associated with oil filled reservoir and the oil-water contact in certain areas of the field.
The Davy, Bessemer, Beaufort and Brown Fields, Blocks 49/23, 49/30a, 49/30c, 53/5a, UK North Sea
Authors: McCrone C. W. 
Published: April 2008

abstract
Davy, Bessemer, Beaufort and Brown are a series of small to moderate (30-200 BCF) dry gas fields, which span the southeastern corner of the UK Southern North Sea Rotliegend Play fairway. Davy was discovered in 1970; however, it was not until 1989 that Bessemer and subsequently Beaufort in 1991 were drilled. These fields were developed and brought on-stream by Amoco licence groups in 1995/96. More recently the Brown Field was discovered in October 1998 with first gas seven weeks later. The commercial viability of these relatively small accumulations is the result of technical advances across several fronts: 3D seismic imaging, horizontal well technology and minimum offshore facilities.
In the Bessemer and Beaufort area, the Rotliegend Leman Sandstone Formation reservoir (250 ft) primarily consists of stacked aeolian dune sandstones of good reservoir quality (porosity 17%, permeability 10-1000mD). However, in the Davy and Brown area there is greater variation in the Rotliegend isopach (300-700 ft) and the nature of facies present e.g., aeolian dune, sabkha and playa lake.
The fields are tied back from the Bessemer and Davy mono-tower platforms via 15 km and 43 km pipelines, respectively, to the compression facilities on the Indefatigable 23AT platform.
The Leman Field, Blocks 49/26, 49/27, 49/28, 53/1, 53/2, UK North Sea
Authors: Hillier A. P. 
Published: April 2008

Abstract
Discovered in 1966 and starting production in 1968, Leman was the second gas field to come into production in the UK sector of the North Sea and is still producing gas today. It is classified as a giant field with an estimated initial gas-in-place of 397 BCM of gas in the aeolian dune sands of the Rotliegend Group. The field extends over five blocks and is being developed by two licence groups with Shell and Amoco (now BP Amoco) being the operators
The Mercury and Neptune Fields, Blocks 47/9b, 47/4b, 47/5a, 42/29, UK North Sea
Authors: Smith B. , Starcher V. 
Published: April 2008

Abstract
The Mercury and Neptune Gas Fields, discovered in 1983 and 1985 respectively, are located on the NW margin of the southern North Sea. Both fields have reservoirs in the Permian Lower Leman Sandstone Formation of the Rotliegend Group. The Mercury Field, at Rotliegend level, is an elongate, southerly tilting horst block. It trends NW-SE and is bounded by reverse faults. The Neptune Field, at top reservoir level is a faulted, four-way dip closed structure that is elongated in a NW-SE direction. The combined gas-in-place for the two fields is estimated at 465 BCF with recoverable reserves of 368 BCF. Development drilling on Mercury commenced in early 1999 and on Neptune it is scheduled to start in Q3 1999. The maximum gas export rate will be 250 MMSCFD with first gas anticipated in November 1999.
The V-Fields, Blocks 49/16, 49/21/, 48/20a, 48/25b, UK North Sea
Authors: Courtier James , Riches Hugh 
Published: April 2008

Abstract
The Vulcan, Vanguard, North and South Valiant gas fields are collectively known as the V-Fields and lie on the eastern flank of the Sole Pit Basin in the southern sector of the UK North Sea. They are contained within blocks 49/16, 49/21, 48/20a and 48/25b and are operated by Conoco (UK) Ltd. The first field to be discovered was South Valiant, in 1970, and the initial phase of exploration drilling continued until 1983, with the discovery of the North Valiant, Vanguard and Vulcan fields. Prominent faults and dip closures define the limits of the fields and gas is contained within aeolian sands of Early Permian age. The gross average reservoir thickness is approximately 900 ft with porosities ranging from 3-23% and permeabilities varying from 0.1 mD to 2 Darcies in producing zones. The development of the V-Fields consisted of drilling centrally located production wells in each field, targeting higher quality reservoir zones in areas of maximum structural relief. Initial gas-in-place is estimated at 2.6 TCF with recoverable reserves of about 1.6 TCF. The fields were brought on-stream in October 1988 and currently produce, as of November 1999, up to 260MMSCFD of gas through the LOGGS complex to the Conoco terminal at Theedle-thorpe, Lincolnshire.
The Waveney Field, Block 48/17c, UK Southern North Sea
Authors: Bruce D. R. S. , Rebora P. 
Published: April 2008

Abstract
The Waveney Field lies entirely within UK block 48/17c in the Southern Gas Basin, approximately 46 km north-east of the Norfolk coast line and to the west of the Mobil's Lancelot and Guinevere Fields. The water depth is approximately 75 ft. The field was discovered in 1996 by the 48/17c-12 well and brought on production in 1998 following a 14 month fast track development program and the drilling of two 2500 ft horizontal wells. The gas field is a low relief northwest trending asymmetrical anticline, with a length of 6 kms, and a maximum width of 2 kms. The crest of the structure is at approximately 7748 ft. TVDSS. The original reserves were 84 bcf. The reservoir predominantly comprises aeolian dune sandstones of the Upper Permian Rotliegend with an average reservoir quality range of 7-10% porosity and 0.1-200mD permeability. The hydrocarbons are sourced from down dip Carboniferous Westphalian Coals.
The Sean North, Sean South and Sean East Fields, Block 49/25a, UK North Sea
Authors: Hillier A. P. 
Published: April 2008

Abstract
Sean North, Sean South and Sean East are small prolific gas fields located on the Indefatigable Shelf in the Southern North Sea. They, like most of the other fields in the area, have a Carboniferous source, a Rotliegend aeolian sandstone reservoir and a Zechstein evaporite cap rock. Sean North and South have been developed to fulfil a peak-shaving role, being produced for only a few days per year in times of high gas demand when they can produce at rates of up to 600 MMSCF/D. East Sean is sold to the direct market. Reserves for the fields are 234 BCF (North), 488 BCF (South) and 127 BCF (East).
Sea bed morphology of the Faroe-Shetland Channel derived from 3D seismic datasets
Authors: Long D. , Bulat J. , Stoker M. S. 
Published: April 2008

Abstract

First returns from 3D exploration surveys have been utilized to display seafloor morphology of the Faroe-Shetland Channel between the UK and the Faroes. The image combines 32 datasets creating a regional perspective of Quaternary sedimentary processes. Geomorphic information is of significance for sea bed geohazard evaluation, environmental studies and as an analogy for former sedimentary environments. The image covers more than 25000 km
2
extending from the shelf (water depth ∼ 120 m) to the basin floor (water depth up to ∼ 1600 m).

On any margin knowledge of the sea bed morphology is essential for understanding the environmental setting and for safe operations in deepwater. Under favourable circumstances, the sea bed can be picked from 3D exploration seismic surveys in a similar manner to any other horizon to provide detailed images of the seafloor, thereby negating the need for dedicated sea bed surveys. Combining first returns from several surveys creates a regional perspective, essential when considering importance of features e.g. the rarity of a certain seafloor environment or the presence of a potential landslide upslope from an operations area.
The Faroe-Shetland Channel displays a wide range of sea bed features including, sediment waves, contourite deposits, polygonal cracking, landslides, debris flows, turbidity current channels, glacial moraines and iceberg ploughmarks. Resolving the spatial aspects of these features greatly assists the interpretation of shallow profile data for geohazard and environmental studies and provides a backdrop onto which biologists, oceanographers, sedimentologists and engineers can overlay their data sets and thus their interpretations.
3D Analogue Models of Rift Systems: Templates for 3D Seismic Interpretation
Authors: McClay K.R. , Dooley T. , Whitehouse P. , Fullarton L. , Chantraprasert S. 
Published: April 2008

Abstract
3D visualizations of modern, high-resolution seismic data have provided valuable insights into the finite geometries and spatial extent of extensional fault systems, but their evolution in time is poorly understood. Scaled 3D analogue models of rift basin evolution provide kinematic templates for understanding the 4D evolution of extensional fault systems. This paper reviews the development of extensional fault systems in analogue models of orthogonal, oblique and offset rifts. In orthogonal and oblique models, stretching above a zone of ductile deformation at the base of the model initially produced segmented rift border faults whose orientations were strongly controlled by the underlying baseplate configuration. In contrast, the intra-rift faults generally initiated at high angles to the extension direction. With increased extension both the rift border faults and the intra-rift faults propagated along strike, first producing segmented fault systems separated by relay ramps, which, with increased extension, became breached as fault linkage occurred. Kinks in the fault traces indicate linkage points. Within the models, asymmetric intra-rift sub-basins were formed where the extensional fault arrays had a dominant dip polarity. Intra-basin accommodation zones, separating individual sub-basins along the rift axis, were formed by interlocking oppositely dipping fault systems. Offset oblique rift models, formed above a zone of ductile stretching with basement offsets, generated intra-basin accommodation zones whose orientation was controlled by the underlying basement fabric. The results of the analogue models can be directly compared with fault systems in the Northern Ethiopian rift system, with the accommodation zones in the Gulf of Suez, Egypt, with extensional fault arrays in Canyonlands, Utah, and with rift fault systems in the Gulf of Thailand and the southern North Sea.
Kinematic Indicators for Shallow Level Igneous Intrusions from 3D Seismic Data: Evidence of Flow Firection and Feeder Location
Authors: Trude K. J. 
Published: April 2008

Abstract
This paper describes some of the results from a 3D seismic-based analysis of the mechanics of igneous sill emplacement in sedimentary basins. Detailed 3D interpretation of igneous intrusions flanking the Corona Ridge in the Faroe-Shetland Basin has led to the discovery of a sill (the Corona Sill) with a previously unrecognized morphology. Two potential feeder sources have been interpreted for the broadly rectangular intrusion, of which the surveyed portion measures approximately 15 by 4 km. The Corona Sill has a linear NW margin and two lobate protuberances along the SE side. Arcuate ridges that radiate from a central point at the intersection of the lobes cover the imaged surface of the sill. The ridges have wavelengths of 220-350m and amplitudes in the range 25-50m.
The ridged morphology on the surface of the Corona Sill has not previously been described from any seismic or outcrop-based study of igneous sills. The ridges are interpreted to have formed as a direct result of the propagation mechanism, and are thought to have been influenced by the viscosity of the magma, host sediment and the depth of intrusion, which is likely to have been within 400 m of the sediment-water interface. It is suggested that during very shallow intrusion of viscous magma into soft, waterlogged sediments, magma is able to spread, creating a geometry similar to that expected for a high viscosity lava flow.
Ridges were formed by compression of a more rigid outer layer of magma in the sill, retarded by the solidifying sill front. Forward movement of the surface layer is likely to be caused by viscous drag from within the sill body. The ridges on the sill top surface are a kinematic indicator for the flow direction of the magma, enabling identification of the feeder zone, which displays a clear link to an underlying sill. It is demonstrated that 3D seismic data has significant untapped potential for the study of magma transport and intrusive processes in the upper crust
Locating Exploration and Appraisal Wells Using Predictive Rock Physics, Seismic Inversion and Advanced Body Tracking: an Example from North Africa
Authors: Pickering G. , Knight E. , Bletcher J. , Barker R. , Kemper M. 
Published: April 2008

Abstract
A case study is described that illustrates a complete reservoir property prediction workflow, from petrophysical analysis, through rock physics, impedance inversion, and on to interpretation and final drilling locations. This study is from onshore Algeria, where the hydrocarbons are found in several clastic reservoirs of varying ages and properties. The controls on the presence of both reservoir and hydrocarbon location are not straightforward, therefore reducing the risk of drilling locations has significant value. This study concentrated on the Triassic TAG-I formation, which forms the major reservoir in the study area. The prediction method used was an impedance based deterministic approach, using relationships based on rock physics, although the interpretation method includes fuzzy set classifications to take into account the knon-uniqueness' inherent in any seismic attribute. The petrophysical work ensured that the analysis of each well reconstructed *virgin-zone" conditions. Rock physics models were then used to predict shear wave velocities. Acoustic impedance (AI), shear impedance (SI), and elastic impedance (EI) profiles were derived. Shear impedance was the best pure lithology indicator, with acoustic impedance showing a good relationship to porosity and elastic impedance most sensitive to fluid content. As the near angle seismic data were too noisy, gradient/intercept analysis was impossible, so shear reflectivity and consequently SI could not be derived. Although AI showed some lithological discrimination between sands and shales, it was not sufficient to be used as a single discriminator, so interpreted horizons were used to separate reservoir and non-reservoir intervals. The far-angle data were inverted to EI and this was analysed using a fuzzy logic approach. This method produces a classification volume and 3D body tracking was then used to find the best drilling targets. Generally, the analysis correctly predicted the results of the wells, both discoveries and non-discoveries. However, some of the discoveries were not predicted, which appears to be where the classification was not correctly calibrated. Work is now underway to improve the accuracy of the prediction process.
Use of 3D Visualization Techniques to Unravel Complex Fault Patterns for Production Planning: Njord Field, Halten Terrace, Norway
Authors: Dart Chris , Cloke Ian , Herdlevær Åge , Gillard Dominique , Rivenæs Jan C. , Otterlei Cecilie , Johnsen Eivind , Ekern Anders 
Published: April 2008

Abstract
In this paper we demonstrate the benefits of 3D seismic visualization techniques for fault interpretation where the structural geology is complex and the seismic data quality is often poor. Production from the Njord field is strongly influenced by a complex pattern of segmented and linked extensional faults. The current interpretation of the well test data and production history is that the faults form barriers to fluid flow, reducing oil production, and limiting effective gas injection and pressure support. Drilling results demonstrate that geometrical uncertainties remain in the seismic interpretation. An additional problem is that currently available commercial reservoir modelling technology cannot easily handle a very complex fault pattern, making simulation grid construction difficult. Accurate well placement and production forecasting requires that fault geometries and properties are suitably represented in the reservoir simulation model. 3D visualization of depth-scaled volumes and depth-converted interpretations helped to decide how to best simplify the fault geometry for simulation, and compare automatically generated geological model components against seismic interpretations and data. The reservoir simulation model runs resulted in the identification of a number of well targets. 3D visualization techniques were then used to predict faults and structures that the proposed well trajectories may intersect.

Supplementary material:
The nineteen movies referred to in the article are available at
https://doi.org/10.6084/m9.figshare.c.4784667
Integrated Use of 3D seismic in field development, engineering and drilling: examples from the shallow section
Authors: Austin Bryn 
Published: April 2008

Abstract
Examples from exploration acreage and field developments across the glaciated Northwest European Continental Shelf and Slope demonstrate the usefulness of conventional three-dimensional (3D) seismic data to spatially image geological features. Compared to previous grid-based two-dimensional (2D) seismic this allows fundamentally more confident identification, mapping and prediction of geotechnical conditions which is important to ensure safe, efficient engineering and drilling operations. Whilst of immense benefit, the paper argues that the 3D seismic data often do not meet the full expectations, particularly in terms of critical vertical resolution and accurate depth prediction requirements. To illustrate the limitations, direct comparison is made between conventionally acquired 3D and HiRes 2D seismic data. Whilst industry funding to support innovative HiRes 3D seismic acquisition remains sparse, much can be achieved by the careful integration and interpretative calibration of the 3D and HiRes 2D seismic datasets. Three field development case studies illustrate this. Short offset trace correction and reprocessing of the 3D seismic data followed by limited, target specific HiRes 2D seismic, calibrated where possible with drilling or other geological data, is an optimal cost-effective approach.