bluuebunny/crossref_metadata_2025_split huggingface dataset:
Virtual fieldtrips for petroleum geoscientists
Authors: McCaffrey K. J. W. , Hodgetts D. , Howell J. , Hunt D. , Imber J. , Jones R. R. , Tomasso M. , Thurmond J. , Viseur S. 
Published: May 2011

Abstract

Significant advances in geosciences data acquisition, visualization and analysis now allow highly detailed outcrop models to be constructed for a range of petroleum industry purposes. From a given field locality, a virtual outcrop is created from a centimetre-scale digital elevation model and colour photographs with geological information overlaid as appropriate. In a visualization environment, these datasets can be viewed sequentially to simulate undertaking a fieldtrip. These
virtual fieldtrips
allow geoscientists to improve and expand the traditional fieldwork experience in a number of ways, ranging from planning and health and safety considerations for management, to providing live supplemental technical content on a mobile device to the fieldtrip participant. The fieldtrips are easily archived and content can be reviewed in the office to provide analogue information during technical work. Examples of virtual fieldtrips are provided on the DVD that accompanies this volume.

Supplementary material:
The virtual fieldtrip videoclips referred to in the article are available at
https://doi.org/10.6084/m9.figshare.c.4816377
The search for a Carboniferous petroleum system beneath the Central North Sea
Authors: Milton-Worssell R. , Smith K. , McGrandle A. , Watson J. , Cameron D. 
Published: May 2011

Abstract

This paper integrates interpretations of modern long-offset seismic datasets with potential field anomalies derived from dense grids of 2D gravity and magnetic data to present a regional-scale synthesis of Devonian, Carboniferous and Early Permian basin development beneath the UK Central North Sea. The 95 000 km
2
study area has had little modern exploration for petroleum systems beneath the Upper Permian. Seismic interpretation and potential field modelling confirm that along the southern fringe of the Central North Sea, as in northern England, Lower Carboniferous basin development was strongly influenced by the disposition of granite-cored Lower Palaeozoic basement blocks – Farne Block, Dogger Block and Devil's Hole High. This study adds a previously unidentified WNW–ESE trending pre-Devonian basement block, the Auk–Flora Ridge, that exerted a profound control on Late Devonian to Mesozoic structural evolution of the south-Central North Sea. From the Flora Field, where it is overlain by relatively thick mid-Devonian to earliest Permian strata, the sub-Permian relief of this block becomes progressively shallower towards the NW. On its southern flank lies a parallel half-graben, akin to the Stainmore Trough in northern England, and interpreted as also containing several thousand feet of Lower Carboniferous strata. As indicated by the coal measures section in well 39/7-1, these strata are likely to include prolific source rocks, which have been modelled as being fully mature for oil generation in Quadrant 29. Potential field modelling extends this interpretation beyond the current seismic coverage, and suggests that Carboniferous to earliest Permian basin development in the Central North Sea was strongly influenced by an underlying Scottish–Norwegian SW–NE trending Caledonoid structural fabric. An earliest Permian, Lower Rotliegend unit thickens southwards towards the Auk–Flora Ridge, and rests unconformably on one or more undrilled NE–SW trending Carboniferous basins. Red-bed fluvial facies akin to those at Flora are likely to dominate the substantial post-Dinantian fill of these basins, but significant thicknesses of Westphalian coal-measure source rocks may also be present locally. As in central Scotland, the Dinantian strata underlying a widespread mid-Carboniferous unconformity in these basins are likely to contain further coal-measure intervals and local developments of oil-shale source rocks. These Westphalian and Dinantian source rocks are key elements of a Carboniferous petroleum system that remains largely untested across large areas of the Central North Sea.
Reappraisal of the sequence stratigraphy of the Humber Group of the UK Central Graben
Authors: Sansom P. J. 
Published: May 2011

Abstract
Deposition of the Callovian–Ryazanian Humber Group of the UK Central Graben occurred during rifting and long-term relative sea-level rise, which acted to suppress the formation of eustatically forced Exxon-type sequence boundaries. The superposition of highly variable halokinetically controlled subsidence means that classic, passive-margin derived sequence stratigraphic models are not appropriate to describe stratigraphic evolution in this rift setting. The sequence stratigraphy of the Humber Group has been re-evaluated using a transgressive–regressive sequence model, where maximum regressive surfaces are employed as sequence bounding surfaces. The Humber Group comprises two megasequences which reveal distinct phases of evolution of the basin. The latest Callovian–Kimmeridgian megasequence comprises a conformable sequence stack which lacks significant internal unconformities and records progressive marine flooding and overall backstepping onto the basin flanks during a phase of active rifting. The Volgian–Ryazanian megasequence is condensed and highly fragmentary due to punctuation by a number of unconformities which are consistently recognizable throughout the basin. The onset of this change in architectural style corresponds to the oldest unconformity at the base of the Volgian–Ryazanian succession, termed the Base Volgian–Ryazanian Unconformity, of latest Kimmeridgian to earliest Volgian age. The patterns of erosion of the Callovian–Kimmeridgian megasequence and the intra Volgian–Ryazanian unconformities record the effects of dramatic redistribution of underlying salt accompanied by probable uplift of the Forties–Montrose High and J Ridge, resulting in major modification of the basin morphology and the severing of possible earlier links with the Fisher Bank Basin. The kinematics of this event are equivocal, but it is possible that restricted Volgian–Ryazanian depocentres resulted from localized salt collapse rather than basement extension. Widespread erosion of Callovian–Kimmeridgian Humber Group sediments may have occurred in some areas where Volgian–Ryazanian Kimmeridge Clay deposits now overlie pre-Jurassic strata, and exploration models must incorporate the effects of Volgian reconfiguration in order to accurately predict reservoir distribution.
The Jasmine discovery, Central North Sea, UKCS
Authors: Archer S. , Ward S. , Menad S. , Shahim I. , Grant N. , Sloan H. , Cole A. 
Published: May 2011

Abstract

The Jasmine Field is located in blocks 30/06 and 30/07a on the J Ridge, the southeastern extension of the Forties–Montrose High, which separates the eastern and western basins of the UK Central North Sea. The field was discovered in 2006 and is close to two ConocoPhillips producing fields, Jade and Judy, which serve as useful local analogues. The main
West Limb
structure is a turtle-back faulted anticline NW of the Joanne salt pillow. The primary reservoir is Triassic in age and consists of stacked fluvial sandstones of the Joanne Member of the Skagerrak Formation. The HPHT exploration wells 30/06-6 and geological sidetrack 30/06-6Z discovered a rich gas condensate column of 2300 ft, some 1100 ft deeper than the mapped independent structural closure of the prospect, and achieved good flow rates on test. To appraise the discovery and assess the potential for significant additional volumes in an adjacent downfaulted terrace, a programme comprising a main well and two sidetrack wells was initiated in 2007. Appraisal well 30/06-7 discovered a 550 ft hydrocarbon column in the
Northern Terrace
with a hydrocarbon–water contact shallower than that observed in the West Limb, thereby proving structural compartmentalization between the two fault blocks. Good flow rates were achieved from a drill stem test in mechanical sidetrack well 30/06-7Z. Sidetracks 30/06-7Y and 30/06-7X were drilled to confirm the northwestern extension of the West Limb discovery and to test the northern extent of the Northern Terrace accumulation, respectively. This programme has reduced volumetric uncertainty but the trapping mechanism and the ultimate extent of the Jasmine accumulation remain unknown. Comprehensive data acquisition throughout the exploration and appraisal phases, including drill stem testing, core recovery and seismic data reprocessing, has facilitated a detailed reservoir characterization programme. Jasmine represents a significant new high pressure/high temperature resource in the mature Central North Sea and is currently undergoing development planning.
Managing the start-up of a fractured oil reservoir: development of the Clair field, West of Shetland
Authors: Witt A. J. , Fowler S. R. , Kjelstadli R. M. , Draper L. F. , Barr D. , McGarrity J. P. 
Published: May 2011

Abstract

The Clair oilfield was discovered in 1977 and began production in 2005. It is a heterogeneous fractured sandstone reservoir with an estimated STOIIP of
c
. 1.5 billion barrels in the Phase 1 development area. An extended appraisal programme was required to assess reservoir deliverability, which is controlled by the distribution of natural fractures. Development drilling increased the understanding of the fracture system, through acquisition of conventional core, open-hole logging, drilling mud-loss recording, production logging and well test transient analysis. These data revealed a complex fracture system of conductive faults and background joints. Post-production formation pressure measurements showed greater lateral and vertical connectivity than would be expected from matrix and fluid properties alone. However, large pressure differences were encountered close to or across features mappable at a seismic scale. Closed fractures or sealing faults can form baffles between compartments, and conductive faults or fractures allow rapid pressure communication. In some cases the connection path or barrier can be identified with seismically mapped features. When the field was put onto water injection, one year after start-up, a key concern was the degree of imbibition of water from the fractures to the matrix. Despite the observed pressure connectivity, water breakthrough did not take place until 2007. Most producers have completions designed to permit zonal water shut-off. A successful intervention was carried out in early 2008, after a production logging run had demonstrated water entry at the toe of a high-angle well. The crestal Core segment of the development benefits from a permanent 4D seismic array of ocean-bottom cables. In 2007 the first permanent monitor survey was acquired and processing gave indications of a 4D response. These 4D data are improving the dynamic reservoir understanding and providing valuable spatial context to the well results.
Predicting production behaviour from deep HPHT Triassic reservoirs and the impact of sedimentary architecture on recovery
Authors: Kape S. , Diaz De Souza O. , Bushnaq I. , Hayes M. , Turner I. 
Published: May 2011

Abstract

The Triassic Skaggerak Formation is one of the main reservoirs in the high pressure–high temperature province of the North Sea. Production to date has come from fields located on the intra-basinal highs within the Central Graben, between 10 000 and 15 000 ft TVDss. Undrilled prospectivity has been recognized in structural traps in the deeper parts of the Central Graben up to 20 000 ft TVDss, yet reservoir effectiveness remains a key risk. Therefore, in order to optimize future exploration, appraisal and development programmes, it is necessary to consider the likely reservoir performance and production behaviour of these deeper Skaggerak prospects. The Skagerrak Formation comprises two main reservoir sandstones, the Judy Member and the overlying Joanne Member, separated by a thick shale interval, the Julius Member mudstone (

Goldsmith
et al.
2003

). The two reservoirs show markedly different production behaviour despite their apparently similar character on wireline logs. Integration of the production behaviour from the Jade and Judy fields with the sedimentology has enabled the causes of this different production behaviour to be better understood, allowing the controls on reservoir flow to be modelled in both a static and dynamic environment. The understanding of the reservoir behaviour in the currently producing fields has been carried through to a predictive phase of simulation and modelling to determine the range of production behaviours expected for a deeper exploration portfolio. A clear porosity–depth trend exists within the Skagerrak Formation and this has been used to translate the robust history-matched reservoir models from the producing fields to the depth of the prospects. Sensitivity to fluid, porosity–depth trend and permeability of the deep reservoirs have been tested, and a range of likely production rates and behaviours established.
Tectonic history and petroleum geology of the Russian Arctic Shelves: an overview
Authors: Drachev S. S. , Malyshev N. A. , Nikishin A. M. 
Published: May 2011

Abstract
The Eastern Barents, Kara, Laptev, East Siberian seas and the western Chukchi Sea occupy a large part of the Eurasian Arctic epicontinental shelf in the Russian Arctic. Recent studies have shown that this huge region consists of over 40 sedimentary basins of variable age and genesis which are thought to bear significant undiscovered hydrocarbon resources. Important tectonic events controlling the structure and petroleum geology of the basins are the Caledonian collision and orogeny followed by Late Devonian to Early Carboniferous rifting, Late Palaeozoic Baltica–Siberia collision and Uralian orogeny, Triassic and Early Jurassic rifting, Late Jurassic to Early Cretaceous Canada Basin opening accompanied by closure of the South Anyui Ocean, the Late Mesozoic Verkhoyansk–Brookian orogeny and Cenozoic opening of the Eurasia Oceanic Basin. The majority of the sedimentary basins were formed and developed in a rift and post-rift setting and later modified through a series of structural inversions. Using available regional seismic lines correlated with borehole data, onshore geology in areas with no exploration drilling, and recent Arctic-wide magnetic, bathymetry and gravity grids, we provide more confident characterization of the regional structural elements of the Russian Arctic shelf, and constrain the timing of basin formation, structural styles, lithostratigraphy and possible hydrocarbon systems and petroleum play elements in frontier areas.
Offset and curvature of the Novaya Zemlya fold-and-thrust belt, Arctic Russia
Authors: Scott R. A. , Howard J. P. , Guo L. , Schekoldin R. , Pease V. 
Published: May 2011

Abstract

The Novaya Zemlya archipelago contains a predominantly west-vergent fold-and-thrust belt that separates two contrasting hydrocarbon basins with enigmatic subsidence histories. On the foreland side is the deep depression of the eastern Barents Shelf that hosts the Shtokman gas condensate discovery; on the hinterland side is the South Kara Basin, an offshore continuation of the gas-dominated northern West Siberian Basin. Much of the compressional deformation recorded in Novaya Zemlya appears to have been later than the onset of subsidence in adjacent basins, and may therefore be expected to have had a potentially significant influence on hydrocarbon systems within them. Two characteristics of Novaya Zemlya immediately stand out on any topographic map: the
c
. 600 km westward offset compared with the remainder of the Uralian Orogen and the plan-view curvature (convex towards the Barents Shelf). Any regional tectonic model developed for the Novaya Zemlya fold-and-thrust belt must be able to explain these first-order features, and a wide range of mechanisms, geometries and timings has been proposed in the literature. However, as far as we are aware, there has been no previous attempt to link the geometry of structures on the archipelago with a potential mechanism that explains their curvature in plan view. Using field observations, information on geological maps and interpretation of satellite imagery, we demonstrate the link between structural geometries in Novaya Zemlya and the basins of the adjacent eastern Barents Shelf. We find no evidence to support previous interpretations of the fold-and-thrust belt as an orocline (bending of an originally straight deformation belt) or a far-travelled thin-skinned allochthon, and conclude that the offset from the remainder of the Uralian Orogen is a primary feature that results from an original embayment on the margin of Baltica.
A regional overview of the exploration potential of the Middle East: a case study in the application of play fairway risk mapping techniques
Authors: Fraser A. J. 
Published: May 2011

Abstract
The Middle East is the world's most prolific petroleum province, containing the world's top five countries in terms of oil reserves and four of the top 10 oil producers. This success is largely due to the stacked nature of what are essentially very simple play systems with multiple carbonate platform and deltaic clastic reservoirs, widespread evaporitic seals, world class source rocks and the overprint of very large compressional anticlines in both fold belt and foreland settings. As with most working petroleum systems, all areas of the Middle East are not equally endowed with petroleum resources and future potential. Using an analysis of the prolific Upper Jurassic ‘Arab’ play fairway of the Middle East, the application of play fairway risk mapping techniques is demonstrated.
New compilation of top basement and basement thickness for the Norwegian continental shelf reveals the segmentation of the passive margin system
Authors: Ebbing J. , Olesen O. 
Published: May 2011

Abstract
We present the first complete top basement map for the passive margin system of the Norwegian continental shelf, which covers the Northern North Sea, the mid-Norwegian margin system, and the western Barents Sea. This compilation is based largely on a review and synthesis of previously published portions on detailed depth to basement and 3D modelling studies, which in turn are based on a wealth of seismic profiles, commercial and scientific drilling on the shelf and mainland Norway, petrophysical sampling and a dense coverage of gravity and aeromagnetic data. The top basement defines the base of the sedimentary strata. Sedimentary thickness is larger than 14 km on the mid-Norwegian margin and the Barents Sea, but varies strongly along the different segments of the margin. In the northeastern North Sea, the Danish–Norwegian Basin, and over the Trøndelag Platform the top basement does not exceed 8 km in depth. The top basement map highlights the transition between the different segments of the Norwegian margin, between different basement domains (e.g. Caledonian and Precambrian basement), and shows a clear correlation with the normal faults mapped on the margin and prolongated from onshore Norway into the offshore realm. The distribution of basement domains provides a new regional understanding of the evolution of the entire passive margin system. We also present an updated Moho depth compilation, which allows calculation of a thickness of crystalline basement map for the entire margin. The basement thickness map enhances differences in crustal architecture for the different margin segments and shows extremely thin crust (less than 12.5 km) for large areas on the mid-Norwegian margin and westernmost Barents Sea, intermediate thin crust (15–20 km) below the Viking Graben, but moderately thin crust (20–30 km) below the Norwegian–Danish Basin and the remaining part of the Barents Sea.
Sedimentology, sandstone provenance and palaeodrainage on the eastern Rockall Basin margin: evidence from the Pb isotopic composition of detrital K-feldspar
Authors: Tyrrell S. , Souders A. K. , Haughton P. D. W. , Daly J. S. , Shannon P. M. 
Published: May 2011

Abstract

The Rockall Basin, west of Ireland, is a frontier area for hydrocarbon exploration, but currently the age and location of sand fairways through the basin are poorly known. A recently developed provenance approach based on
in-situ
Pb isotopic analysis of single K-feldspar grains by laser ablation multi-collector inductively coupled mass spectrometry (LA-MC-ICPMS) offers advantages over other provenance techniques, particularly when applied to regional palaeodrainage issues. K-feldspar is a relatively common, usually first-cycle framework mineral in sandstones and its origin is typically linked to that of the quartz grains in arkosic and sub-arkosic rocks. Consequently, in contrast to other techniques, the Pb-in-K-feldspar tool characterizes a significant proportion of the framework grains. New Pb isotopic data from K-feldspars in putative Permo-Triassic and Middle Jurassic sandstones in Well 12/2-1z (the Dooish gas condensate discovery) on the eastern margin of the Irish Rockall Basin are reported. These data suggest that three isotopically distinct basement sources supplied the bulk of the K-feldspar in the reservoir sandstones and that the relative contribution of these sources varied through time. Archaean and early Proterozoic rocks (including elements of the Lewisian Complex and its offshore equivalents), to the immediate east, NE and north of the eastern Rockall Margin, are the likely sources. More distal sourcelands to the NW cannot be ruled out but there was no significant input from southern sources, such as the Irish Massif. These data, together with previously published regional Pb isotopic data, highlight the important role played by old, near and far-field Archaean–Proterozoic basement highs in contributing sediment to NE Atlantic margin basins. The Irish Massif appears to have acted as a significant, but inert, drainage divide from the Permo-Triassic to the Late Jurassic and hence younger, Avalonian and Variscan sand sources appear to have been less important on the Irish Atlantic Margin.