bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Murdoch Gas Field, Block 44/22a, UK Southern North Sea
Authors: Conway A. M. , Valvatne C. 
Published: April 2008

Abstract
The Murdoch Field was discovered in 1984 when gas was tested from the Murdoch Sandstone of the Westphalian B, Carboniferous in well 44/22-1. The field lies along an elongate NW-SE trending faulted ridge, clearly evident at Top Base Permian structural level. Six exploration and appraisal wells were drilled on the structure prior to commencing a joint development in 1992 with the adjacent Caister Field. The reservoir unit, the Murdoch Sandstone, is interpreted as a low sinuosity fluvial complex of lower Westphalian B age. It is around 120' thick and was deposited by a large NE-SW flowing braided river system in which channels stacked and amalgamated to form the sand package. Production commenced at the beginning of October 1993 making it the first Carboniferous development in the UK North Sea. The maximum deliverabihty of the field is currently about 180MMSCFD from six of the eight producers. Developed with a not-normally-manned platform facility, the gas is delivered to the Theddlethorpe Gas Terminal. Heterogeneity in reservoir quality combined with complex structural compartmentalization are the key control mechanisms on gas production in the Murdoch Field.
The Schooner Field, Blocks 44/26a, 43/30a, UK North Sea
Authors: Moscariello A. 
Published: April 2008

Abstract

The Schooner Field is Shell U.K.'s first Carboniferous gas development in the North Sea. The field was discovered in 1987 by well 44/26-2 and gas production began in October 1996 from four wells. In contrast to the majority of the fields in the Southern North Sea producing from the aeolian Leman Sandstones Formation (Rotliegend), Schooner targets the low net-to-gross, fluvial Upper Carboniferous Barren Red Measures and Coal Measures formations. The reservoir consists of discrete, low sinuosity fluvio-deltaic channels draining a swampy coastal floodplain evolving upwards into a highly aggrading, low gradient, distal fluvial fan, dominated by braided and anastomosing channels. In Schooner, like other Carboniferous fields, reservoir connectivity is one of the key subsurface uncertainties due both to channel lateral discontinuity and fault compartmentalization. Production data and reservoir properties distribution, together with a new stratigraphical subdivision driven mostly by chemostratigraphic techniques, have been used to reassess the volume of gas-in-place which currently is estimated at 29.98 Gm
3
(1059 BCF)
The West Firsby Oilfield, Development Licence 003, Lincolnshire
Authors: Bailey R. J. 
Published: April 2008

Abstract
The West Firsby Oilfield exemplifies the classic east Midlands oil play, sourced by early Namurian pro-deltaic shales. Stacked fluvio-deltaic sandstone reservoirs of latest Namurian to early Westphalian 'A' age are structured into a Variscan inversion anticline in the hanging wall of the northeastern boundary fault of the Dinantian-Namurian Gainsborough Trough. The Enterprise West Firsby-1 discovery well, drilled on a 'Top Westphalian 'A'' seismic depth closure, encountered oil-bearing sandstones at three levels. These are thought to represent the earliest Westphalian 'A' Sub-Alton/Crawshaw distributary channel and mouthbar sandstones (Reservoir Zone [RZ] 1), the stacked fluvial channel sands of the Namurian Rough Rock (RZ2) and an underlying high quality mouth-bar sandstone (RZ3). In the hanging wall setting, these units can be correlated over an area far larger than the West Firsby Field.
On acquiring operatorship of the Development Licence (DL 003) in 1991, Tullow Exploration put the WF-1 well into production from RZ2 and 3 disposing of produced water in the earlier-drilled and unsuccessful WF-2 step-out. Between 1992 and 1996, three new production wells (WF-4, -5 and -6) were drilled from the same surface site. The wells principally produce from RZ2 and involve high-angle/horizontal sections in these sandstones, approaching 170 m in length in WF-6. Strong aquifer support, coupled with the injection of produced water into RZ2 of WF-2, promotes early natural flow from such wells at rates up to 800BOPD, and when this declines jet-pumping can maintain production at rates of several hundred BOPD/well. As of 1st January 1999, the West Firsby Oilfield had produced 0.97 MMBBL of an estimated 13 MMBBL OIIP, maintaining an average annual rate during 1998 of 345 BOPD from four wells. Remaining recoverable reserves are estimated at around 1.03 MMBBL.
The Malory Field, Block 48/12d, UK North Sea
Authors: O'Brien R. E. , Lappin M. , Komlosi F. , Loftus A. 
Published: April 2008

Abstract
The Malory Field straddles blocks 48/12d and 48/12c of the UK Sector of the Southern North Sea on the western margin of the Sole Pit Trough. The field is located within an upthrown part of the Dowsing Fault Zone and was discovered by the Mobil operated well 48/12d-9 in early 1997.
The Malory Field is a small fault-bounded horst structure with expected recoverable reserves of 75 BSCF. The reservoir consists of a 249 ft-section of Lower Permian, Rotliegendes Leman Sandstone Formation sandstones, is sourced from the Carboniferous Westphalian Coal Measures below, and is sealed by overlying Upper Permian Zechstein evaporites.
Reservoir quality is generally good with an average porosity of 14.7% and core permeabilities (Kh) between 0.2 and 1651 mD. This preservation of reservoir quality is attributed to a combination of the structure being located on a broad palaeostructural high, with a lower maximum burial depth than adjacent structures and associated lower compactional porosity loss, the presence of an early hydrocarbon charge and the preferential precipitation of chlorite over illite cements.
The Viking Field, Blocks 49/12a, 49/16, 49/17, UK North Sea
Authors: Riches Hugh 
Published: April 2008

Abstract
First production from the Viking Fields began in 1972 and at its peak a total of 13 platforms produced at rates up to 950 MMSCF/D from 20 wells. This supplied around 10% of the United Kingdom's natural gas requirements, 27 years on, that rate had declined to approximately 40 MMSCF/D. However following an extremely successful infield drilling programme in the mid 1990s, significant volumes of new gas have been discovered and new technology has facilitated the development of accumulations previously considered non-commercial. This has led to three new developments within the Viking area: the Vampire Field on the eastern margin; Kx to the south of the Philips' Alison Field; and four previously non-producing fields, captured within the Phoenix Development.
The major change since Morgan (1991) has primarily been the re-negotiation of the gas sales contract and the removal of the Gas Levy in 1992. This provided favourable marketing conditions for the development of additional Viking gas production and initiated an appraisal programme for remaining reserves. This programme, which will be the focus of this paper, began with the acquisition of a 3D seismic survey in 1993 and has concluded in the development of the Viking Extensions in 1998, now known as the Phoenix Development.
The Leman Sandstone Formation forms the reservoir and consists of aeolian and fluvial sandstones, which are interbedded in the north of the area with silty shales deposited within a sabkha environment. Hydrocarbons were sourced from the underlying Carboniferous Westphahan coals and carbonaceous shales, and migration into the Rotliegendes Group probably occurred during the Late Cretaceous to Early Tertiary.
The average daily production from the original Viking A and B fields and associated satellites had declined to 196 MMSCF/D by March 1989, peaking to over 300 MMSCF/D with seasonal demand. By October 1999, this had further reduced to around 40 MMSCF/D. Production from the Phoenix wells is currently at around 290 MMSCF/D, with further development wells planned. Cumulative production to date is approximately 2880 BCF.
The Kimmeridge Bay Oilfield, Dorset, UK Onshore
Authors: Gluyas J. G. , Evans I. J. , Richards D. 
Published: April 2008

Abstract
The Kimmeridge Oilfield is the oldest commercial discovery of petroleum in the Wessex Basin. The field was discovered in 1959. The discovery well was completed for production and that same well continues to produce today, more than forty years after discovery.
More than three million barrels of oil have been produced. Oil is trapped in fractured, Middle Jurassic, Cornbrash limestones in an anticline. The anticline is a product of Alpine inversion tectonics. Moreover, the Kimmeridge accumulation is unusual insofar as it is the only inversion structure to contain a commercial quantity of petroleum and the only producing field in the hanging wall of the Purbeck Disturbance.
3D Seismic Technology: Are We Realising Its Full Potential?
Authors: Davies Richard J. , Stewart Simon A. , Cartwright Joseph A. , Lappin Mark , Johnston Rodney , Fraser Scot I. , Brown Alistair R. 
Published: April 2008

Abstract
Three-dimensional (3D) seismic data have had a substantial impact on the successful exploration and production of hydrocarbons. Although most commonly acquired by the oil and gas exploration industry, these data are starting to be used as a research tool in other Earth sciences disciplines. However despite some innovative new directions of academic investigation, most of the examples of how 3D seismic data have increased our understanding of the structure and stratigraphy of sedimentary basins come from the industry that acquired these data. The 3D seismic tool is also making significant inroads into other areas of Earth sciences, such as igneous and structural geology. However, there are pitfalls that parallel these advances: geoscientists need to be multidisciplined and true integrators, and at the same time have an ever-increasing knowledge of geophysical acquisition and processing. Notably the utility of the 3D seismic tool seems to have been overlooked by most of the academic community, and we would submit that academia has yet to take full advantage of this technology as a research tool. We propose that the remaining scientific potential far exceeds the advances made thus far and major opportunities, as well as challenges, lie ahead.
Seismic Geomorphology: Imaging Elements of Depositional Systems from Shelf to Deep Basin Using 3D Seismic Data: Implications for Exploration and Development
Authors: Posamentier Henry W. 
Published: April 2008

Abstract
3D seismic data can play a vital role in hydrocarbon exploration and development especially with regard to mitigating risk associated with presence of reservoir, source, and seal facies. Such data can afford direct imaging of depositional elements, which can then be analyzed using seismic stratigraphy and seismic geomorphology to yield predictions of lithologic distribution, insights to compartmentalization. and identification of stratigraphic trapping possibilities. Benefits can be direct, whereby depositional elements at exploration depths can be identified and interpreted, or they can be indirect, whereby shallow-buried depositional systems can be clearly imaged and provide analogues to deeper exploration or development targets. Examples of imaged depositional elements from both shallow and deep sections are presented.
Initial Deformation in a Subduction Thrust System: Polygonal Normal Faulting in the Incoming Sedimentary Sequence of the Nankai Subduction Zone, Southwestern Japan
Authors: Heffernan A. S. , Moore J. C. , Bangs N. L. , Moore G. F. , Shipley T. H. 
Published: April 2008

Abstract3D seismic data from the Nankai margin provide detailed imagery documenting the onset of deformation at an active sediment-dominated accretionary prism, including a previously unmapped network of normal faults. The Nankai margin off southwest Japan is characterized by active subduction, seismogenesis, and a large accretionary prism with fold-and-thrust belt structure. Imbricate thrusting is the dominant structural style of the outer 20 km of the prism. This structural domain develops at the prism toe, where an incipient imbricate thrust displays significant along-strike variability in dip, offset, and development of hangingwall anticlines.Compressional deformation is preceded by normal faulting that initiates seaward of the trench axis. Seismic data in this area reveal a complex, intersecting pattern of normal faults within the incoming hemipelagic sediments. Underlying the faulted section is a high-amplitude reflector interpreted as representing oceanic basement. This reflector contains elongate horsts and grabens oriented perpendicular to the margin interpreted as relict spreading centre fabric.Analysis of the orientation of normal faults within the Shikoku basin sequence shows a correlation between fault geometry and basement structure. This faulting is notably similar to layer-bound compaction faults, documented in the North Sea and elsewhere, attributed to both hydrofracturing and volumetric contraction of fine-grained sediments. Mapped normal faults may thus be the result of a combination of differential compaction of sediments above irregular, dipping oceanic basement and compactional dewatering seaward of the toe of the accretionary prism.
Tertiary Inversion in the Faroe-Shetland Channel and the Development of Major Erosional Scarps
Authors: Smallwood John R. 
Published: April 2008

Abstract

At the shallowest point of the Faroe-Shetland Channel, between the Faroe Islands and the Shetland Isles, the sea bed is deformed into a series of major scarps and hollows. The cuspate scarps, or 'Judd Falls', are up to 15 km in length and are over 200 m high. Interpretation of 3D seismic data and high resolution 2D seismic data shows that the scarps are part of a larger series of structures that are partly buried. A second series of buried asymmetric hollows has been mapped 50 km to the northwest. Both sets of hollows are interpreted to have a deep-water erosional origin, postulated to be associated with the initiation of the high-energy bottom currents of the south-flowing Northern Component Water from the Norwegian-Greenland Sea into the North Atlantic. Present-day measurements presented here show that deep-water current velocity can peak at over 0.8ms
-1
. Both erosional complexes are positioned directly above Tertiary inversion structures, and this study has identified two periods of compressional deformation, latest Ypresian and late Lutetian, in addition to previously documented phases. Compression in the area has been linked to changes in the interaction between the Mid-Atlantic Ridge and the Iceland mantle plume. Enhanced plume activity also concentrated deep-water flow in the Faroe-Shetland Channel by physically impeding deep-water currents elsewhere. Where enhanced deep-water flow encountered the partial barriers of the inversion structures, accelerated turbulent erosional currents carved the scarps into the sea bed.
3D Seismic Analysis of the Geometry of Igneous Sills and Sill Junction Relationships
Authors: Hansen Dothe MØller , Cartwright Joseph A. , Thomas David 
Published: April 2008

Abstract
We use 3D seismic data in a novel way to describe the three-dimensional geometry of a number of igneous bodies intruded into the upper crust as well as to define and classify sill junction relationships. Igneous intrusions were emplaced into Upper Cretaceous and Palaeocene sediments of the Faroe-Shetland Basin during the Early Palaeogene and in many cases they adopt remarkable saucer- or trough-shaped geometries that are 2-8 km in diameter and have a vertical relief of several hundred metres. Individual intrusions are interlinked and form highly interconnected sill complexes. Three geometrically distinctive classes of sill junctions are defined and illustrated with examples from seismic data. Each class implies a specific evolutionary sequence of events and these are discussed for each of the classes of junction. The class of junction often changes along the line of junction with one class evolving in space to another. This has significant implications for spatial reconstruction of sill complexes based on two-dimensional outcrop and this is illustrated with reference to an example from a 3D seismic dataset.
Seismic Characteristics of Large-Scale Sandstone Intrusions in the Paleogene of the South Viking Graben, UK and Norwegian North Sea
Authors: Huuse Mads , Duranti Davide , Steinsland Noralf , Guargena Claudia G. , Prat Philippe , Holm Kristine , Cartwright Joseph A. , Hurst Andrew 
Published: April 2008

Abstract

Post-depositional remobilization and injection of sand can significantly change the geometry of deepwater clastic reservoirs. Features associated with these processes are particularly well developed in the lower Paleogene of the South Viking Graben of the UK and Norwegian North Sea. Seismic scale sandstone intrusions can be grouped in two classes. Class 1 comprises low-angle (20-40 degrees) tabular sandstone intrusions emanating from steep-sided
in situ
sand bodies within the Balder Formation. The intrusions may be 5-30+m thick and crosscut 120-250+m of compacted stratigraphic section. They terminate at an unconformity at the top of the Frigg interval where they may have extruded onto the palaeo-seafloor. Class 2 comprises conical sandstone intrusions that emanate some 50-300+m upward from distinct apexes located 400-700+m above the nearest depositional sand body. The conical intrusions may have been sourced from underlying sand bodies by clastic blow out pipes. Both types of intrusions seem to adopt their particular geometry independently of (but occasionally exploiting) polygonal faults within the encasing mudstones. Sandstone intrusions may be highly porous and permeable and are thus important both as reservoirs and as plumbing within thick mudstone sequences.
4D Seismic Imaging of an Injected C02 Plume at the Sleipner Field, Central North Sea
Authors: Chadwick R.A. , Arts R. , Eiken O. , Kirby G.A. , Lindeberg E. , Zweigel P. 
Published: April 2008

Abstract

C0
2
produced at the Sleipner field is being injected into the Utsira Sand, a major saline aquifer. Time-lapse seismic data acquired in 1999, with 2.35 million tonnes of C0
2
in the reservoir, image the C0
2,
plume as a number of bright sub-horizontal reflections. These are interpreted as tuned responses from thin (< 8 m thick) layers of C02 trapped beneath intra-reservoir shales. A prominent vertical 'chimney' of C0
2
appears to be the principal feeder of these layers in the upper part of the reservoir. Amplitude-thickness scaling for each layer, followed by a layer summation, indicates that roughly 80% of the total injected C0
2
is concentrated in the layers. The remainder is interpreted to occupy the feeder 'chimneys' and dispersed clouds between the layers. A prominent velocity pushdown is evident beneath the C0
2
accumulations. Velocity estimation using the Gassmann relationships suggests that the observed pushdown cannot readily be explained by C0
2
present only at high saturations in the thin layers; a minor proportion of low saturation C0
2
is also required. This is consistent with the layer volume summation, but significant uncertainty remains.
Towards an Automated Strategy for Modelling Extensional Basins and Margins in Four Dimensions
Authors: White Nicky , Haines John , Jones Stephen , Hanne Detlef 
Published: April 2008

AbstractThere is a need for quantitative models which predict the structural and thermal evolution of sedimentary basins and margins in three dimensions. Although many different, two-dimensional algorithms exist, most of them are forward models which assume that rifting is instantaneous. We outline a three-dimensional optimization strategy which calculates spatial and temporal variations in strain rate. This approach is a generalization of an existing two-dimensional inversion algorithm which already tackles three issues of interest to the hydrocarbon industry. First, the residual misfit between observed and predicted basin geometries allows competing structural and stratigraphic interpretations to be objectively tested. Secondly, the animated evolution of basin and margins can be produced using the strain rate tensor. Thirdly, spatial and temporal variations of strain rate control basal heatflow, which in turn constrains the temperature and maturation histories of the sedimentary pile. Here, we present a small selection of two-dimensional results and show how our three-dimensional formulation is a logical extension of earlier work. A three-dimensional algorithm is under development.
Examples of Multi-attribute, Neural Network-Based Seismic Object Detection
Authors: De Groot P. , Ligtenberg H. , Oldenziel T. , Connolly D. , Meldahl P. 
Published: April 2008

Abstract
Certain seismic objects, like faults and gas chimneys, are often difficult to delineate using conventional attribute analysis. Many attributes contain useful information about the target object but each new attribute provides a new and different view of the data. The challenge is to find the optimal attribute for a specific interpretation. In this paper the optimal attribute is found with a pattern recognition approach based on multi-dimensional/multi-attributes and neural network modelling. Multi-dimensional attributes, as opposed to point attributes, can provide the spatial information on the seismic objects. The role of the neural network is to classify the input attributes into two or more output classes. Neural networks are trained on seismic attributes extracted at representative example locations that are manually picked by a seismic interpreter. This approach is a form of supervised learning in which the network learns to recognize certain seismic responses associated with the identified target objects. Application of the trained network yields an 'object probability' cube for the target object. Essentially, the neural network can target any seismic or geological feature requiring detailed analysis. In this paper the method is described and examples are shown of gas chimneys, faults, salt domes and 4D anomalies. Some interpretation aspects are discussed.
Structural and tectonic development of the Timanide orogen
Authors: Roberts David , Olovyanishnikov Vesvolod 
Published: April 2008

Abstract
The northeastern margin of the East European Craton developed passively in an extensional regime from late Mesoproterozoic through to the later stages of Neoproterozoic time. Along the exposed parts of the Timan-Varanger Belt, a major fault zone separates pericratonic (platformal) and basinal domains. Successions of the basinal domain can be traced beneath the Pechora Basin, via drillcore and geophysical data, to where intra-oceanic subduction systems with island arcs are inferred to have existed in the later stages of the Late Riphean. In terminal Riphean to Vendian time, inferred subduction polarity reversal resulted in a progressive telescoping, dissection and accretion of these diverse magmatosedimentary assemblages against the northeastern margin of the craton, culminating in Mid to Late Vendian, Timanian orogenesis. The Timan Range exposes SW-verging upright folds with anchizone to lower greenschist-facies cleavages. Higher-grade rocks in the Kanin-North Timan area occur in anticlinal cores and thrust slices. Isotopic dating constraints suggest that peak Timanian metamorphism occurred during the time interval 600–550 Ma.