bluuebunny/crossref_metadata_2025_split huggingface dataset:
Structural elements and petroleum geology of the Norwegian sector of the northern Barents Sea
Authors: GROGAN P. , ØSTVEDT-GHAZI A.-M. , LARSSEN G. B. , FOTLAND B. , NYBERG K. , DAHLGREN S. , EIDVIN T. 
Published: April 2010

The northern Barents Sea is divided into two principal prospective provinces: (1) the platform areas south and east of Svalbard contain possible hydrocarbon plays in Upper Palaeozoic clastics and carbonates, and in Mesozoic sandstones; (2) The Barents Sea margin, which includes the Yermak Plateau, with possible plays in late Mesozoic and Tertiary sandstones. The platform areas are underlain by a Palaeozoic rift system of highs and intervening basins, containing Devonian and Early Carboniferous rocks overlain by relatively flat-lying sequences of Late Palaeozoic and Mesozoic age. The Barents Sea margin is a complex basin province formed in response to phases of the Late Mesozoic and Cenozoic break-up of the Pangea supercontinent, and subsequent seafloor spreading west of Spitsbergen.
The northern Barents Sea is as yet not open for commercial exploration, and no deep wells have been drilled in the offshore areas. It is one of the largest remaining frontier areas in western Europe and as such affords a wide range of exploration opportunities. However, the area is considered to be of high risk for petroleum exploration, with generally low statistical probabilities of discovery, largely because of the limited amount of data available to evaluate potential hydrocarbon plays, and in particular the presence, distribution, quality and maturity of source rocks. Hydrocarbon resource estimates are therefore characterized by large uncertainties.
Potential reservoir rocks are identified, and seismic mapping has revealed many structural and stratigraphic leads on the Sentralbanken High, the Kong Karls Land Platform, the Gardarbanken High and in the Mesozoic and Tertiary sub-basins northwest of Bjørnøya. Future challenges will be focused on reducing uncertainties in mapping the distribution of source rocks of suitable quality. Limited basin modelling studies indicate that oil may have been generated and accumulated in many provinces, but better constrained models are required to evaluate Early Cretaceous thermal events and Late Cenozoic uplift processes that may have had negative effects on both oil generation and the retention of hydrocarbons in traps.
Cenozoic development of the Norwegian margin 60–64°N: sequences and sedimentary response to variable basin physiography and tectonic setting
Authors: MARTINSEN O. J. , BØEN F. , CHARNOCK M. A. , MANGERUD G. , NØTTVEDT A. 
Published: April 2010

The Cenozoic development of the Norwegian margin between 60 and 64°N can be described in terms of five, unconformity-bounded, megasequences: Paleocene–lowermost Eocene (65–51 Ma), Lower Eocene–lowermost Oligocene (51–31 Ma), Lower–upper Oligocene (31–24 Ma), Miocene–Pliocene (24–1.9 Ma), and Pleistocene (1.9 Ma–present). Each sequence is constructed of systems tracts, varying in type and number between sequences. In the Møre Basin (62–64°N), lowstand wedges dominate and form an offlapping, regressive pattern. In the Northern North Sea Basin (60–62°N), lowstand, transgressive and highstand systems tracts are present, showing a more variable framework.
The variability observed is interpreted to reflect the response of sediment supplied, both in time and space, into different basin physiographies related to the overall tectonic context of the two areas. The Northern North Sea Basin in the Cenozoic received sediments generated from the basin margins in periods of uplift and lowstand. Clastic systems probably prograded into a gradually-shallowing central basin area, formed as a response to decaying, post-rift subsidence, margin uplift and sediment fill. The Møre Basin, in contrast, acted as a margin to incipient and on-going North Atlantic rifting, and the basin physiography was that of a more steeply inclined slope facing the northwest. Larger water depths caused sediment wedges to be restricted to the basin margin rather than acting as fill of the central basin area such as occurs in the North Sea. The offlapping pattern probably records repeated uplift of the Norwegian mainland, shedding sediments into the basin.
Early Tertiary heat flow along the UK Atlantic margin and adjacent areas
Authors: GREEN P. F. , DUDDY I. R. , HEGARTY K. A. , BRAY R. J. 
Published: April 2010

The sedimentary basins of the UK North Atlantic margin are characterized by extensive igneous activity, mostly of Early Tertiary age, related to continental rifting which led to the separation of Europe from Greenland. Given this setting, it might be expected that elevated basal heat flow during the Early Tertiary would have exerted a critical control on the thermal histories of potential hydrocarbon source rocks. Apatite fission track analysis and vitrinite reflectance data have been used to identify, characterize and quantify significant palaeothermal events which have affected the region. This approach allows reconstruction of thermal histories based on directly measured data, rather than relying on theoretical models.
Results from the West of Shetland region show significant Tertiary heating, but this is often characterized by low palaeogradients or non-linear palaeotemperature profiles, suggesting heating caused by fluid movements. No evidence has been observed of enhanced Early Tertiary heat flow, and little evidence has been found to support significantly deeper burial during the Early Tertiary. Results from Hebridean basins also argue against a significantly increased Early Tertiary heat flow, while showing strong evidence for Late Tertiary uplift and erosion.
Consistent evidence for increased Early Tertiary heat flow is seen to the south, in the Lake District and Solway basins. This may reflect the ability of extensive igneous activity to release heat from the base of the crust to shallower levels throughout the Atlantic margin and the Tertiary igneous province, whereas in the absence of igneous activity, the lack of a pathway for heat to escape results in elevated basal heat flow.
Models based on high Early Tertiary heat flow are likely to over-predict maturity levels in Jurassic source rocks, and predict an earlier timing for hydrocarbon generation. Both factors could lead to false assessment of regional hydrocarbon prospectivity.
Petroleum geology of the Irish Rockall Trough – a frontier challenge
Authors: WALSH A. , KNAG G. , MORRIS M. , QUINQUIS H. , TRICKER P. , BIRD C. , BOWER S. 
Published: April 2010

The Irish Rockall Trough is a frontier area recently opened for hydrocarbon exploration. The Trough, a NE–SW trending Mesozoic–Cenozoic basin, lies in water depths ranging between 500 m and 3000 m. Basin development began as early as the Late Carboniferous and a series of rift episodes continued sporadically throughout the Mesozoic and Tertiary. The most important of these occurred between the Late Jurassic and Early Cretaceous. The post-rift thermal sag phase followed in the Late Cretaceous and Tertiary. The resultant basin is characterized by thinned continental crust, a series of tilted fault blocks and a number of smaller ‘perched’ basins adjacent to the main basin-bounding faults.
This paper presents an assessment of the petroleum prospectivity of the Rockall Trough by focusing on its stratigraphic and structural development, integrating the results from modelling work and providing concise play models. A suite of regional palaeogeographic maps are used to develop a full understanding of the stratigraphic history of the Trough. A structural modelling study is then discussed in which two regional seismic lines are interpreted and flexurally back-stripped. Finally, a source-rock modelling study is presented whereby the timing and extent of oil and gas explusion within the potential kitchen areas are examined. The conclusions of this work are illustrated on a series of play concept diagrams.
The structural evolution of the Erris Trough, offshore northwest Ireland, and implications for hydrocarbon generation
Authors: CHAPMAN T. J. , BROKS T. M. , CORCORAN D. V. , DUNCAN L. A. , DANCER P. N. 
Published: April 2010

The Erris Trough is a narrow, elongate, Mesozoic basin lying adjacent to the eastern margin of the Rockall Trough to the northwest of Ireland. Limited drilling in the area has proven Carboniferous, Permo-Triassic, Lower–Middle Jurassic and Cretaceous sediments beneath a thin Tertiary cover. Considerable variation in structural style and preserved stratigraphy is observed along the basin. Based on interpreted fault polarity and observed pre-Cretaceous stratal dip, the Erris Trough can be subdivided into three structural sub-basins separated by diffuse, poorly defined, overlapping or divergent transfer zones.
Carboniferous basin development in the area of the Erris Trough was significant but is poorly constrained. Permo-Triassic rifting produced a series of half-graben, some of which were controlled by down-to-the-southeast faults. This extensional phase was followed by post-rift subsidence during the Early and Middle Jurassic. In addition, N–S and NW–SE faults locally influenced depositional patterns. In the southern part of the Erris Trough a Middle to Late Jurassic rifting event produced a reversal of the earlier basin geometry with the generation of northwest- and west-downthrowing normal faults. Along the western margin of the Erris Trough, footwall uplift associated with this event induced massive, kilometre scale, uplift and erosion implying Late Jurassic rifting within the Rockall Trough. Restricted basins may have been developed in the area during the Cretaceous as a result of ‘ponding’ of deposition to the east of this zone of footwall uplift. A minor extensional phase occurred during the Aptian–Albian resulting in local reactivation of the Late Jurassic faults concurrent with rifting in the Rockall Trough. A westerly tilt of the basin was established during the Late Cretaceous–Early Tertiary caused by downflexing associated with thermal subsidence of the Rockall Trough. Regional uplift and erosion occurred during the Oligocene–Miocene.
Basin modelling indicates that Lower Jurassic source rocks may have generated oil during the Early Eocene to Early Miocene, dependent on an elevated geothermal gradient during the Early Tertiary. Late Carboniferous sediments may have generated hydrocarbons at a number of times during the basin’s history.
Comparative Jurassic and Cretaceous tectono-stratigraphy and reservoir development in the Jeanne d’Arc and Porcupine basins
Authors: WILLIAMS B. P. J. , SHANNON P. M. , SINCLAIR I. K. 
Published: April 2010

The Jeanne d’Arc Basin offshore Newfoundland and the Porcupine Basin to the west of Ireland, developed under similar tectono-sedimentary conditions in pre-Late Cretaceous times. Rifting events in Permo-Triassic, Late Jurassic–Early Cretaceous and mid Cretaceous times were each followed by a phase of thermal subsidence. While a broadly common lithofacies pattern occurs within and between the basins, the detailed response of the basins differs in terms of style of structuring, reservoir architecture and quality of source rock development. The Late Jurassic–Early Cretaceous (Tithonian to Berriasian) rift episode is the most significant, with good reservoir sandstones and rich source rocks forming part of this rift sequence.
A Late Oxfordian to Kimmeridgian onset warp phase resulted in the development of shallow marine limestones and deeper water organic-rich shales and marls in the Jeanne d’Arc Basin, with non-marine, shoreface and restricted marine sandstones and shales in the Porcupine Basin. The Late Jurassic–Early Cretaceous syn-rift episode resulted in the development of sandstone-prone successions which interfinger with good oil-prone source rocks in both basins. Reservoir architecture in both basins was influenced by this episode. Within the Porcupine Basin a range of lithofacies developed, ranging from fluvial channels and bars, to submarine fan turbidites. Within the Jeanne d’Arc Basin, periodic rejuvenation of fault footwalls produced conglomeratic pulses resulting in transverse alluvial fans which interfinger with axially-flowing braid channels and bars within the incised valley fills. Periods of increased subsidence resulted in the development of lacustrine facies and flood plain mudstones.
Sedimentary basins and petroleum systems offshore Newfoundland and Labrador
Authors: DeSILVA N. R. 
Published: April 2010

The sedimentary basins offshore Newfoundland and Labrador include those related to the opening and closing of the Palaeo-Atlantic (Iapetus) Ocean and those formed during the opening of the present Atlantic Ocean. The oldest among these are the Lower Palaeozoic Anticosti Basin and the Carboniferous Maritimes successor basin offshore western Newfoundland. The Mesozoic sedimentary basins on the Grand Banks and on the Labrador Shelf record the progressively northward opening of the present Atlantic Ocean. These include the South Whale Sub-basin of the Scotian Basin, Whale Basin, Horseshoe Basin, Carson Basin, Jeanne d’Arc Basin, Flemish Pass Basin, East Newfoundland Basin, Hopedale Basin and Saglek Basin.
Petroleum systems occur in the Anticosti Basin, Maritimes Basin, South Whale Sub-basin, Jeanne d’Arc Basin, Flemish Pass Basin and the Hopedale Basin. In the Anticosti Basin, Lower Palaeozoic marine shales constitute source rocks and carbonates form the reservoir rocks. In the Maritimes Basin, Lower Carboniferous lacustrine rocks form the source rocks and Carboniferous sandstones form the major reservoir rocks. On the Grand Banks, Kimmeridgian shale represents the source and Upper Jurassic and Lower Cretaceous sandstones constitute the main reservoir units. Offshore Labrador, Tertiary shales are considered to be the source and Cretaceous sandstones form the principal reservoir rocks. All the basins with petroleum systems have a favourable combination of elements and processes needed for hydrocarbon accumulations.
Stratigraphic relationships of the Lower Tertiary of the Faeroe Basalt Plateau and the Faeroe–Shetland Basin
Authors: KIØRBOE L. 
Published: April 2010

The Faeroe Basalt Plateau is located in the western part of the Faeroe–Shetland Channel. The Plateau consists of Lower Tertiary basalt subaerially extruded and accumulated both on land and under water. The basaltic succession is described and interpreted using seismic facies analysis and genetically related seismic units. The formation of each unit is related to eruptive pulses. The variation in the stacking pattern of the seismic units is related to: (1) the amount of available lava; and (2) the change of relative sea-level.
The Faeroe–Shetland Basin is a major NE–SW trending sedimentary basin located in the Faeroe–Shetland Channel. The Lower Tertiary sediments of the Faeroe–Shetland Basin are subdivided into sequences that are tentatively correlated to the lavas of the Faeroe Basalt Plateau and East Greenland.
The importance of fluid pressures and migration to the hydrocarbon prospectivity of the Faeroe–Shetland White Zone
Authors: ILIFFE J. E. , ROBERTSON A. G. , WARD G. H. F. , WYNN C. , PEAD S. D. M. , CAMERON N. 
Published: April 2010

The hydrocarbon prospectivity of the Faeroe–Shetland White Zone, located in the area between the Shetland and Faeroe Islands, was assessed in a regional study that integrated seismic and well interpretations with detailed source-rock geochemistry and predictive basin modelling.
The Faeroe Basin formed during a Barremian rifting event followed by subsidence during the Late Cretaceous. The Paleocene began with a period of thermal uplift of basement highs and rapid sedimentation which infilled the submarine topography formed during the Cretaceous, and produced marked overpressuring in the basin. Gradual subsidence continued through the Tertiary except for a significant mid Tertiary inversion event that formed several interesting structures in the basin.
New thermal models of basins and a new pressure mechanism for inducing hydrofractures that allow vertical hydrocarbon migration from Jurassic source rocks through Cretaceous mudrocks to Tertiary reservoirs, which we call the ‘whoopee cushion effect’, provide the key controls on the hydrocarbon charge mechanism, timing and petroleum composition.
The other crucial elements, source, reservoir, and traps which are present at several stratigraphic levels in the White Zone, are summarized in this paper.
The interplay of overpressure, hydrocarbon generation and migration during a complex basin evolution makes the White Zone a highly prospective frontier petroleum province.
Reservoir quality and petrophysical evaluation of Paleocene sandstones in the West of Shetland area
Authors: SULLIVAN M. , COOMBES T. , IMBERT P. , AHAMDACH-DEMARS C. 
Published: April 2010

A series of regionally correlatable unconformity bounded sequences has been identified within the Paleocene interval of the West of Shetland area. These sequences contain a succession of sandstones deposited in deep-water environments within the Early to ‘mid’ Paleocene (Danian to early Thanetian) with a gradual shallowing upwards to shelf and deltaic deposits in the Late Paleocene.
Reservoir properties of these sandstones vary widely, with porosities ranging from >30% to below 10%, and permeabilities from >2D to <0.1 mD. Although there is a severe reduction of reservoir quality with depth of burial, certain sandstone units have retained high porosities (>20%) and permeabilities (10–100 mD) at below 3 km burial depth. This preservation of reservoir quality is due in part to depositional facies, but mineralogical/diagenetic variability has also allowed the preservation of porosity and permeability. In particular, the presence of grain rimming chlorite in these sandstones is fundamental in preserving porosity.
Log and core analyses of these sandstones has shown that interpretation of reservoir potential and fluid saturations is not straightforward. The effect of diagenetic minerals on log responses and in particular the salinity of formation waters (both in water- and hydrocarbon-bearing zones) were poorly known at the start of the study, and had to be accurately quantified.
The integration of all available data, including intensive study of core material, allowed the definition of these effects and thus allowed the adequate modelling of hydrocarbon saturations.
The Foinaven Field: managing reservoir development uncertainty prior to start-up
Authors: COOPER M. M. , EVANS A. C. , LYNCH D. J. , NEVILLE G. , NEWLEY T. 
Published: April 2010

Foinaven was the first oil field discovery in the deep waters west of the Shetland Islands. The field was (re)discovered in deep water sands of Late Paleocene age in 1992 by Well 204/24a-2, and from late 1993 was the subject of an accelerated appraisal programme leading to field development approval in November 1994. Production started in November 1997 through a subsea system connected to a floating production, storage and offloading (FPSO) vessel with shuttle tanker export.
Continual improvement in the quality of the seismic data across the field coupled with the large amount of well data acquired during the appraisal and development programmes has reduced much of the static uncertainty associated with estimates of the STOIIP (oil initially in place) and reservoir geometry. However, significant issues relating to channel inter-connectivity, the field’s connected reserves, well production decline and pressure maintenance have only been able to be addressed through the acquisition of dynamic data. The key to these data has been an extended well test (EWT) performed on a horizontal appraisal well in Panel 3.

With 42 × 10
6
BBL of reserves, the Panel 3 segment of Foinaven is the second largest of the five segments identified in the field to date. The principal reservoir zone is made up of two separate seismically-identifiable channels, which may or may not be in good communication. For either outcome we planned to achieve good recovery efficiency by appropriate placement of the two pre-drilled horizontal producers. The seismic geometry of the channels, combined with the analysis of a pressure build up (PBU) following a short clean-up flow on one of the wells, indicate the presence of a potential barrier between the two targeted channels. Recent longer-term data from down-hole gauges shows similar 15 psi depletion in the both wells as a result of the extraction of 437016 BBL during the EWT. These data have indicated there is some communication between the channels and have been invaluable in maximizing understanding prior to field start-up.
The Schiehallion development
Authors: LEACH H. M. , HERBERT N. , LOS A. , SMITH R. L. 
Published: April 2010

The Schiehallion development is one of the largest on the United Kingdom Continental Shelf in the last ten years, with mean recoverable reserves of 425 × 10
6
BBL. It is the second development West of Shetland, following the Foinaven Field. The Schiehallion development comprises two fields; Schiehallion and Loyal, which are located approximately 200 km west of the Shetland Islands and a similar distance northwest of the Orkneys in water depths of 300–500 m.

The Schiehallion Field was discovered in late 1993 by Well 204/20-1 and side-track -1Z. Oil is trapped in submarine slope reservoir sandstone of Paleocene age. The discovery well penetrated an oil–water contact at 2064 m TVDSS. The field extent was mapped on 3D seismic data through the first half of 1994. This was followed by the drilling of five further vertical appraisal wells in 1994–95, three operated by BP/Britoil and two by Amerada Hess. In 1995, a horizontal well, 204/20-5, was drilled and subsequently tested over an extended period.
The Loyal Field, to the north of Schiehallion, was discovered in late 1994 by Well 204/20-3 which encountered an oil column in sandstone of Paleocene age. The well was successfully side-tracked into a second, adjacent oil-hearing sandstone. An oil–water contact was penetrated at 2397 m TVDSS. A second well, 204/20-6A, drilled in 1995, confirmed the presence of oil at the crest of Loyal in a second separate segment with an oil–water contact inferred at 2160-m TVDSS.
The mapping of net pay thickness directly from 3D seismic underpins the reservoir description of the Schiehallion and Loyal fields. Vertical appraisal wells were targeted to calibrate the net pay model and reduce reservoir uncertainties. This enabled a rapid appraisal of the key elements of the static reservoir description.

Seismic attribute mapping and detailed seismic facies mapping, combined with sedimentological analysis of the cores and borehole imaging electric logs, defined the channelized architecture of the reservoirs. Horizontal Well 204/20–5 and subsequent extended well test (EWT) were designed to answer questions on the dynamic performance of the reservoir, particularly the connectivity and productivity of the sandstone reservoirs. This well was completed in the summer of 1995 after penetrating a gross reservoir length of
c
. 1700 m. The subsequent EWT achieved a stabilized, constrained flow rate of
c
. 18000 BQPD and demonstrated the productivity and good reservoir connectivity of the field. The well was suspended as a future producer.

The development of the two fields was sanctioned in 1996. Development drilling began later in 1996 and oil production commenced on schedule in July 1998. The fields will be exploited using a floating production, storage and off-loading (FPSO) vessel which is jointly owned by the field partners (BP Exploration (Operator), Shell UK Exploration and Production, Amerada Hess Ltd, Murphy Petroleum Ltd, OMV (UK) Ltd and Statoil (UK) Ltd).