bluuebunny/crossref_metadata_2025_split huggingface dataset:
Sedimentology and sequence stratigraphy of the Hugin Formation, Quadrant 15, Norwegian sector, South Viking Graben
Authors: Kieft R. L. , Jackson C. A.-L. , Hampson G. J. , Larsen E. 
Published: May 2011

Abstract
The Middle Jurassic Hugin Formation has been the target of exploration within Quadrant 15 of the Norwegian South Viking Graben since the 1960s. The Hugin formation comprises shallow-marine and marginal-marine sediments deposited during the overall transgression and southward retreat of the ‘Brent Delta’ systems. Sedimentological analysis of cores across the quadrant has identified six facies associations: bay-fill, shoreface, mouth bar, fluvio-tidal channel-fill, coastal plain and offshore open marine. These facies associations are arranged in a series of parasequences bounded by flooding surfaces, several of which are correlated regionally using biostratigraphic data. Within this stratigraphic framework, facies association distributions and stratigraphic architectures are complicated, reflecting the spatial and temporal interaction of various physical processes (e.g. waves and tides) with an evolving structural template produced by rift initiation and salt movement. The overall transgression was highly diachronous, becoming younger from north to south. The northern part of the study area (Sigrun–Gudrun area) is characterized by a series of backstepping, linear, north–south-trending barrier shorelines and sheltered bays. The central part of the study area (Dagny area) contains stacked, backstepping strandplain shorelines that fringed syn-depositional topographic highs. Local angular unconformities are developed around these highs, implying that they formed above fault-block crests and salt-cored structures. The southern part of the study area (Sleipner area) contains stacked deltaic shorelines that were modified by both waves and tides. Sandbody geometry is closely related to depositional regime and syn-depositional tectonic setting within the basin; a robust understanding of both is critical to successful exploration of Hugin Formation reservoirs.
Overcoming multiple uncertainties in a challenging gas development: Chiswick Field UK SNS
Authors: Nesbit R. , Overshott K. 
Published: May 2011

Abstract
Twenty-three years after BP discovered the Chiswick Field in 1984, first gas production was achieved by Venture Production. During its long period of appraisal and development, this asset has passed between five different operators and a large number of co-venturers. Prior to development, the field represented one of the largest undeveloped gas volumes present in the UK Southern North Sea. Key uncertainties include reservoir compartmentalization, low net/gross ratios and poor reservoir permeability, uncertainties in structural mapping and gas–water contact depths, as well as a widely varying Carboniferous subcrop and significant lateral changes in fluviatile sandstone architecture. Drilling and completion during the first phase of development were a significant challenge, with ambitious long and deep fracture-stimulated horizontal wells. The installation comprised a five-slot minimum facilities well-head platform with production tied back via the Venture-operated Markham J6A Platform with gas landed in Den Helder, Holland. As part of Phase II development a further three wells are being planned to accelerate recovery and access the remaining undeveloped reserves in both the primary Carboniferous and secondary Rotliegend reservoirs in the Chiswick Field.
Locating the remaining oil in the Nelson Field
Authors: Gill C. E. , Shepherd M. 
Published: May 2011

Abstract
The Nelson Field has been in production since 1994 and is at the mid-mature stage of field life. The current management strategy has focussed on identifying infill well locations with the aim of recovering bypassed oil. An increasingly detailed reservoir description is required in order to locate these opportunities and to help screen them for their economic viability. A systematic workflow has been followed through to localize those areas of the Nelson Field where the target oil volumes are most likely to be found. This workflow is given the name ‘locate the remaining oil’ within Shell. The aim of this workflow is to understand the relationship between sweep and the geological framework of the reservoir. On this basis, drainage cells are defined within the reservoir. Rather than behaving as a single ‘tank’ of oil with a common rising oil–water contact, the Nelson Field produces from nine discrete drainage volumes, each with separate producing oil–water contacts. The drainage cells have been defined on the basis of sedimentology, oil and water geochemistry in combination with quantitative volumetric analysis. Screening of the nine drainage cells in the reservoir has identified four cells that contain significant remaining volumes of mobile oil. These have then been investigated in further detail with a view to locating any stranded oil volumes that are unlikely to be produced by the existing well stock, and to determine if these are large enough to justify infill well drilling.
The Scott Field: revitalization of a mature field
Authors: Brook G. R. , Wardell J. R. , Flanagan S. F. , Regan T. P. 
Published: May 2011

Abstract

The Scott Field, located in the UK Central North Sea, is in a mature stage of development. The Scott platform has been on production since 1993, when the Scott Field came on stream, followed in	by the subsea tie-back of the Telford Field development, located to the south of Scott. By 2005 the Scott Field had produced 400×10
6
boe cumulative production. However, the field was producing at water cuts approaching 90% and the previously completed 2002–2004 infill drilling campaign had not met expectations. A change in strategy was undertaken in the subsequent 2005–2007 Scott drilling campaign, which yielded positive results, adding reserves and significantly increasing platform export rates. The focus moved from peripheral targets towards the edge of the field to lower risk targets closer to existing well control. Success was also attributed to focusing on the seismic interpretation of block bounding faults in poorly imaged areas of the field, allowing identification of small fault-bound targets. The recent drilling has demonstrated that significant value can be found in small and often complex accumulations within an extensively drilled mature field.
Tilting oil-water contact in the chalk of Tyra Field as interpreted from capillary pressure data
Authors: Fabricius I. L. , Rana M. A. 
Published: May 2011

Abstract
The Tyra Field in the central North Sea is located in Palaeogene and Upper Cretaceous chalk. It contains a natural gas zone underlain by an oil leg. Based on analysis of logs and core data from ten wells drilled prior to the field being put into production, normalized water saturation depth-trends from logs were compared with normalized water saturation depth-trends predicted from capillary pressure core data. The ten wells lie close to a SW–NE cross section of the field. For the gas–oil contact, a free contact measured in one well corresponds to a practically horizontal contact interpreted from logging data in the remaining wells. A westerly dipping oil–water contact was found from logging data. Comparison of the depth-wise trends in normalized water saturation among the different wells indicates a regional pattern: in the western side of the field, the trends correspond to a situation of imbibition, where the free water level overlies an interval of residual oil, whereas in the eastern part of the field, the depth-wise trends in normalized water saturation correspond to a situation of drainage. The free water level apparently dips to the east due either to hydrodynamic action or to pressure inequilibrium in the aquifer following tectonic tilting.
Investigating fault-sealing potential through fault relative seismic volume analysis
Authors: Dutzer J.-F. , Basford H. , Purves S. 
Published: May 2011

Abstract
Accurate fault interpretation is key to building a robust and reliable reservoir model, and is essential for further study of fault-seal behaviour and reservoir compartmentalization. Conventional fault interpretation defines faults as planar features. Although the concept of fault damage zones (FDZ) is well established, manual delineation of FDZ from subsurface imaging data is difficult and rarely attempted. In this work we are using the concept of a seismic fault distortion zone (SFDZ). The SFDZ differs from the geological FDZ and is the 3D extent of the regions where the presence of a fault has perturbed the seismic image. The SFDZ represents an area of significant uncertainty within the seismic volume where the signal is distorted either by changes in geology associated with faulting or by imaging problems due to the presence of the fault. Delineation of the SFDZ is a key step in further analysing 3D seismic data to provide information regarding variations in seismic attributes across a fault that can be used to indicate how juxtaposition of strata influences a potential sealing fault. The SFDZ is delineated using an adaptive region growing algorithm and produces a set of detailed 3D SFDZ geobodies. The delineated SFDZ is then used as the input to a set of analysis techniques that examine 3D volumetric juxtaposition of seismic attributes, and properties relative to the fault. The techniques involve automated statistical measurement along seismic structure relative to the fault itself. The workflow has been applied and its utility assessed on an underground gas storage dataset. Initial results suggest that by taking account of the 3D geometry of the SFDZ and subsequently analysing 3D frequency and acoustic impedance volumes relative to these structures, an improved understanding of the juxtaposition of layers across the fault and the lateral variability, juxtaposition can be determined at seismic resolution, and subsequently used to assess the potential for fault seal and fluid migration.
4D acquisition and processing: a North Sea case study on the relative contributions to improved 4D repeatability
Authors: Rushmere E. C. , Dyce M. , Campbell S. , Hill A. J. 
Published: May 2011

Abstract
Using a case study from the Mungo Field in the Central North Sea, we investigate the relative impact of acquisition and processing improvements on 4D seismic repeatability. The results show that, while advancements in both have helped to reduce 4D noise, significant noise reduction can be attributed to processing alone. 4D noise can be thought of as any non-production-related amplitudes that are observable on a 4D difference section, and has both random and coherent components. Both are undesirable as they can mask any real 4D signal. A great deal of effort is employed to reduce noise levels by optimizing acquisition and processing between the 3D surveys, which are differenced to highlight the 4D signal. This paper studies the changes introduced by acquisition and processing improvements using the calibrated difference in reflectivity measure.
3D seismic mapping and porosity variation of intra-chalk units in the southern Danish North Sea
Authors: Abramovitz T. , Andersen C. , Jakobsen F. C. , Kristensen L. , Sheldon E. 
Published: May 2011

Abstract
Deposition of the Upper Cretaceous–Danian Chalk Group in the Salt Dome Province of the southern Danish Central Graben took place during a tectonic period dominated by post-rift subsidence, halokinesis and structural inversion. This resulted in highly variable chalk distribution with >1300 m of chalk located in synclines and <200 m preserved on inversion highs and salt structures. The area is mature with respect to exploration with most of the chalk fields located in structural traps discovered in the 1970s. However, the Halfdan discovery in 1999 illustrates the existence of off-structural traps, leading to renewed exploration interest. To locate additional off-structural traps, a detailed geological model is necessary for prediction of chalk intervals with reservoir potential. To unravel basin development, we combine 3D seismic interpretation, well log correlation and 2D seismic inversion to estimate acoustic impedance along selected profiles. The 2D acoustic impedance profiles are converted to total porosity and used to identify areas with potential untargeted reservoirs. A prominent high-amplitude reflection is interpreted as a regional unconformity separating two distinctly different chalk deposition patterns. Nannofossil biostratigraphy suggests a latest Campanian to early Maastrichtian age for the unconformity. It corresponds to an increase in acoustic impedance and decrease in porosity in wells. The Tor Formation contains porous intervals while the underlying Hod Formation contains less porous chalk. The Hod Formation has a maximum porosity of <20% based on well log and inversion data. In contrast, inversion data indicate that the Tor Formation comprises reservoir-grade porosity at several locations on downflank structures. In several areas, the inversion-based maximum porosity is predicted to be higher than expected, compared with porosity/depth trends derived from well data. Therefore, the spatial porosity variation in chalk is complex and controlled by factors other than burial depth.
Seismic imaging of variable water layer sound speed in Rockall Trough, NE Atlantic and implications for seismic surveying in deep water
Authors: Jones S. M. , Sutton C. , Hardy R. J. J. , Hardy D. 
Published: May 2011

Abstract

Natural variation in sound speed within ocean water can degrade sub-seabed images from 2D, 3D and 4D seismic reflection datasets. Degrading effects include vertical offset of reflections between adjacent or intersecting sail lines and difficulties in suppressing multiples from water layer reverberations. Here we investigate water layer variability in Rockall Trough, offshore Ireland, in water depths ranging from 200 m to 3.5 km. A compilation of vertical sound speed profiles, calculated from temperature and salinity profiles obtained by probes lowered from ships, shows that the mean sound speed in the water layer mostly varies between 1490 and 1500 m s
−1
. Vertical offsets of up to about 15 ms two-way travel time are predicted at seismic line intersections. A significant amount of the total observed sound speed variability can occur along a single seismic sail line. These effects result mainly from spatial and temporal fluctuations in the thicknesses of, and vertical sound speed gradients within, an upper layer of North Atlantic Central Water and a mid-depth layer of Mediterranean Outflow Water. Seismic sections across Rockall Trough commonly show lateral variability in reflectivity within these same two water layers. Some reflective packages contain lens-shaped structures consisting of reflective rims and transparent cores and with diameters between 10 and 50 km. Other reflective packages have abrupt, almost vertical boundaries and no distinct transparent core. We infer that the lateral boundaries of the reflective packages are likely to be associated with significant variations in average water layer sound speed. When processing 2D, 3D and 4D seismic surveys of regions of high oceanic variability, such as Rockall Trough, it is necessary to employ techniques that can solve for and then remove the effect of significant fluctuations in water layer sound speed over time periods as short as a few hours and distances as short as a kilometre.
New aeromagnetic and gravity compilations from Norway and adjacent areas: methods and applications
Authors: Olesen O. , Brönner M. , Ebbing J. , Gellein J. , Gernigon L. , Koziel J. , Lauritsen T. , Myklebust R. , Pascal C. , Sand M. , Solheim D. , Usov S. 
Published: May 2011

Abstract

The Geological Survey of Norway (NGU) has produced new aeromagnetic and gravity maps from Norway and adjacent areas, compiled from ground, airborne and satellite data. Petrophysical measurements on core samples, hand specimens and on
in situ
bedrock exposures are essential for the interpretation of these maps. Onshore, the most prominent gravity and magnetic anomalies are attributed to lower crustal rocks that have been brought closer to the surface. The asymmetry of the gravity anomalies along the Lapland Granulite Belt and Kongsberg–Bamble Complex, combined with the steep gradient, points to the overthrusted high-density granulites as being the main source of the observed anomalies. The Kongsberg–Bamble anomaly can be traced southwards through the Kattegat to southern Sweden. This concept of gravity field modelling can also be applied to the Mid-Norwegian continental shelf and could partially explain the observed high-density rocks occurring below the Møre and Vøring basins and in the Lofoten area. Extrapolations of Late-Caledonian detachment structures occurring on the mainland can be traced on aeromagnetic and gravimetric images towards the NW across the continental margin. Subcropping Late Palaeozoic to Cenozoic sedimentary units along the mid-Norwegian coast produce a conspicuous magnetic anomaly pattern. The asymmetry of the low-amplitude anomalies, with a steep gradient and a negative anomaly to the east and a gentler gradient to the west, relates the anomalies to gently westward dipping strata. Recent aeromagnetic surveys in the Barents Sea have revealed negative magnetic anomalies associated with shallow salt diapirs. Buried Quaternary channels partly filled with gravel and boulders of crystalline rocks generate magnetic anomalies in the North Sea. The new maps also show that the opening of the Norwegian–Greenland Sea occurred along stable continental margins without offsets across minor fracture zones, or involving jumps in the spreading axis. A triple junction formed at 48 Ma between the Lofoten and Norway Basins.
Charging the giant gas fields of the NW Siberia basin
Authors: Fjellanger E. , Kontorovich A. E. , Barboza S. A. , Burshtein L. M. , Hardy M. J. , Livshits V. R. 
Published: May 2011

Abstract
The West Siberia basin is the largest petroleum province in Russia, with 80% of the country's gas resources in the Cenomanian Pokur Formation. Significant undiscovered gas resources have been assessed as on trend with the giant gas fields. However, the origin of the large amounts of dry, isotopically light gas is still an enigma, albeit extensively addressed in the literature. This study aims at quantifying the gas contribution from all relevant thermal sources. The West Siberia Basin is the world's largest intracratonic basin, comprising up to 12 km of Mesozoic and Cenozoic clastic rocks. The Basement is composed of Palaeozoic accretionary crust. Northward-trending Permian–Triassic rifts were filled by fluvial–deltaic sediments from the south and east, punctuated by marine transgressions from the north. Cenozoic basin inversion formed traps for petroleum. A regional high-resolution 3D basin simulation was used to model the thermal evolution of the northern West Siberia basin. Geostatistical modelling was applied to assess source rock richness and quality. Basal heat flow was modelled by calibration to bottom-hole temperature and vitrinite measurements. Hydrocarbon generation kinetic parameters were derived from measurements performed on West Siberia rock samples. Thermal gas charge expelled from the hydrocarbon kitchen drainage areas of key fields were compared with the gas volumes accumulated in these fields. The study found that Cretaceous terrestrial sources can generate sufficient early thermal gas to charge accumulations in the South Kara Sea area, and additional Jurassic sources can charge the remaining accumulations of the study area if favourable conditions apply. Biogenic gas is likely to have contributed to the gas accumulations. Mixing of thermal and biogenic gas could explain the observed isotopic composition. Sensitivity analyses show that the timing of structuring and uplift is the most critical factor of the assessment. Variations in glaciation, heat flow and source kinetics show less effect on the hydrocarbon accumulation.
Integrated petroleum systems and play fairway analysis in a complex Palaeozoic basin: Ghadames-Illizi Basin, North Africa
Authors: Dixon R. J. , Moore J. K. S. , Bourne M. , Dunn E. , Haig D. B. , Hossack J. , Roberts N. , Parsons T. , Simmons C. J. 
Published: May 2011

Abstract
The Ghadames–Illizi Basin system is a highly productive petroleum province with a long exploration history in Algeria, Libya and Tunisia (from the late 1950s to present day). Ongoing exploration success in all three countries suggests that it will continue to provide attractive exploration targets in the future. The basin has a long (Cambrian to Plio-Pleistocene) and complex geological evolution characterized by multiple phases of subsidence punctuated by significant regional uplift events. Two ‘world-class’ petroleum source rocks of different geological age are present (Lower Silurian and Upper Devonian) with similar depositional environments and geochemical characters. Both source horizons have generated significant volumes of oil and gas. Migration is strongly influenced by the stratigraphic architecture of the basin fill, notably distribution of regional seals and the complex patterns of subcrop and onlap across regional unconformities. Multiple reservoir–seal combinations are presented by Late Ordovician glaciogenic sediments and younger Silurian through to Carboniferous paralic sequences. Integrating the stratigraphic relationships with the complex burial history of the basin (timing of uplift, degree of tilting, amount of section removed by erosion) is not a trivial task, but is key to exploration success in such a complex basin. With the aid of 3D basin reconstruction and fluid flow modelling software, we can attempt to capture the stratigraphic and structural complexity and make exploration predictions. If basin modelling techniques are to be optimally applied in such settings, a fully integrated and geologically realistic approach involving sedimentologists, structural geologists, geophysicists and geochemists is required. A modelling approach, workflow and some results are presented.
Constraints on volcanism, igneous intrusion and stretching on the Rockall–Faroe continental margin
Authors: White R. S. , Eccles J. D. , Roberts A. W. 
Published: May 2011

Abstract

The northern North Atlantic margins are classic examples of ‘volcanic’ rifted continental margins, where breakup was accompanied by massive volcanism. We discuss strategies used to obtain good intra- and sub-basalt seismic penetration so as to map the structure and the extruded and intruded igneous volume. We recorded deep penetration reflection data using a 12 000 m long single sensor (Q-)streamer and wide-angle seismic profiles with 85 4-component ocean bottom seismometers, along two transects across the Faroe and Hatton Bank continental margins in the NE Atlantic. Tomographic inversion of both compressional (P) and shear (S) wave crustal velocities are crucial in improving the reflection image and in constraining the nature of the sub-basalt lithology and the volume of extruded and intruded melt. Beneath the basalts, which reach 5 km thickness, is a low-velocity zone with P- and S-wave velocities characteristic of sedimentary rocks intruded by basalt sills. The underlying stretched continental basement contains abundant intrusive igneous sills on the rifted margin. Near the Faroe Islands, for every 1 km along-strike, 340–420 km
3
of basalt was extruded, while 560–780 km
3
was intruded into the continent–ocean transition (COT). Lower-crustal intrusions are focussed mainly into a narrow zone less than 50 km wide on the COT, whereas extruded basalts flow >100 km from the rift. Melt on the COT is intruded into the lower crust as sills which cross-cut the stretched and tilted continental fabric, rather than as ‘underplate’ of 100% melt, as has often been assumed previously. Our igneous thickness and velocity observations are consistent with the dominant control on the melt production being rifting above mantle with a temperature elevated above normal. The mantle temperature anomaly was up to 150°C above normal at the time of continental breakup, decreasing by
c
. 70–80°C over the first 10 Ma of seafloor spreading.