bluuebunny/crossref_metadata_2025_split huggingface dataset:
Cretaceous and Palaeogene turbidite systems in the North Sea and Norwegian Sea Basins: source, staging area and basin physiography controls on reservoir development
Authors: MARTINSEN O. J. , LIEN T. , JACKSON C. 
Published: April 2010

The Cretaceous and Palaeogene succession in the North Sea and Norwegian Sea basins show widely variable deep-water sedimentary systems in terms of processes, facies, geometries, scale and distribution. The primary controls on the large-scale variability are considered to be source area size, basin and basin margin physiography and bathymetry, tectonic history and resulting morphology of drainage and delivery systems of sediments to deep-water areas, and the rate of sediment delivery. The North Sea and Norwegian Sea basins were comparable during the earliest Cretaceous, but thereafter developed in widely different ways as a response to proximity to oncoming North Atlantic seafloor spreading.
In the North Sea Basin, the Cretaceous and Palaeogene turbidite systems were controlled by an inherited structural template from Late Jurassic rifting, and by source area size. Poorly developed or small drainage systems on the Norwegian margin and the broad Horda Platform gave little sand supply from the east to the Viking Graben area. Sand-rich systems were sourced from a relatively large hinterland and shallow marine staging area on the East Shetland Platform. North of the Horda Platform, sand supply was abundant in very discrete periods, particularly in the Early Eocene.
In the Norwegian Sea basins, the Late Jurassic structural template controlled Early Cretaceous deep-water sedimentary systems in a manner similar to the North Sea Basin. Generally small and poorly developed drainage systems caused development of mud-rich systems. In contrast, in the Late Cretaceous, onset of precursor tectonic activity to sea-floor spreading led to increased sand supply from the west into the Vøring Basin. A relatively narrow palaeoshelf and a large source area contributed to forming sand-rich systems. Smaller turbidite systems developed along the Norwegian margin, which were sourced from the east from smaller drainage areas, and partially across broad shelves, such as the Trøndelag Platform. Both in the Cretaceous and Palaeogene, the sandiest systems are found only to the south and the north of the inherited structural features.
Dynamic fault seal analysis and flow pathway modelling in three-dimensional basin models
Authors: CLARKE S. M. , BURLEY S. D. , WILLIAMS G. D. 
Published: April 2010

Faults are important elements of petroleum systems that influence the migration and trapping of hydrocarbons in sedimentary basins. When faults undergo displacement, their fluid transmissibility properties change as a result of juxtaposing lithologies across the fault, by smearing semi-permeable or impermeable argillaceous rocks within fault zones and by pumping or valving aqueous fluids. We describe here a 4D hydrocarbon migration model that incorporates juxtaposition and argillaceous smear processes.
The technique uses the geometries of strata that are cut by faults and their physical properties to construct 3D models in which the evolution of cross-fault relationships can be calculated and the development of fault-zone argillaceous smear predicted. Hydrocarbon migration pathways through faulted structures are then investigated with a 4D migration model based on invasion percolation (IP) techniques.
The controls on hydrocarbon migration have been investigated for fieldwork-derived models of rock volumes from the Moab Fault, Utah, USA to test the modelling techniques against reality. As a result predominantly of argillaceous smear, hydrocarbons are shown to accumulate in the hanging wall of parts of the modelled section of the Moab Fault, but leak across juxtaposed sandstones elsewhere on the fault to produce footwall accumulations.
The techniques are then applied to a seismically derived model of the Artemis Field, UK Southern North Sea, to demonstrate how hydrocarbon charging history and pathways are influenced by fault geometries. Multiple model realizations enable the risk associated with charging of individual fault compartments to be assessed.
The history of hydrocarbon filling of Danish chalk fields
Authors: VEJBÆK O. V. , FRYKMAN P. , BECH N. , NIELSEN C. M. 
Published: April 2010

It is well established that dynamic conditions expressed as tilted fluid contacts characterize most hydrocarbon accumulations in North Sea Chalk reservoirs. Chalk is a low-permeability, high-porosity rock and properties grade smoothly from reservoir over baffle to seal. The natural dynamic conditions prevail because pressure dissipation takes place through the rockmatrix, as fracture-supported flow often is minimal. The dynamic conditions are imposed by processes occurring on a geological time-scale and result mainly in lateral pressure differences in the water zone and even in lateral pressure differences in the oil zone. Re-equilibration of fluid contacts also occurs on a geological time-scale. These processes are of paramount importance for trap definition and impose severe restrictions on migration distances.
Reservoir simulation techniques are applied, in combination with back-stripping, to the simulation of geological time-scale secondary migration and trapping. Flow simulation of the filling dynamics of a chalk reservoir shows a complex filling geometry due to the high capillary entry pressures in the low-permeability chalks. Such internal barriers will re-direct hydrocarbons and residual oil can be left on the migration route. The process of hydrocarbon charging is slow and equilibration of hydrocarbons with respect to pressure gradients, therefore, also occurs very slowly. The Kraka Field and the Dan and Halfdan fields are subjected to studies of primary oil charging and re-migration in this paper and the dynamic oil on Dan Field west flank is successfully mimicked. Results show that a time span in the order of 2 Ma is required for the hydrocarbons to reach the summit in an approximately equilibrium state from a flanking position. However, even dynamic equilibrium may not be fully obtained due to re-perturbation by tectonic movements and changing water zone pressure gradients. Results show that saturation profiles in drilled wells may appear in drainage equilibrium while under partial re-imbibition, which impairs saturation modelling.
Reducing structural uncertainties through anisotropic pre-stack depth imaging: examples from the Elgin/Franklin/Glenelg HP/HT fields area, Central North Sea
Authors: SUITER J. , ROMANI R. , ARNAUD J. , HOLLINGWORTH S. , HAWKINS K. 
Published: April 2010

This paper highlights how a global approach to quantifying structural uncertainties has ultimately reduced overall structural uncertainty through improved seismic imaging, notably anisotropic pre-stack depth migration, in a structurally complex area. The Elgin/Franklin high pressure/high temperature (HP/HT) fields lie in the Central Graben area of the North Sea UK sector,
c
. 240 km east of Aberdeen. The fields are the deepest production in the North Sea and represent the largest gas condensate development in the world, with recoverable reserves estimated at over 700 × 10
6
BBL equivalent. The reservoirs produce from the Jurassic Fulmar shallow-marine and Pentland fluvial reservoirs at depths of 5100–5600 m subsea. Production from these HP/HT reservoirs (1100 bar/200°C) started in March 2001 and flows over 200 000 BOE per day from 12 wells.

For this type of producing environment, the stakes are high for understanding uncertainties related to imaging. Improved fault imaging translates not only to reduced uncertainties in bulk rock volumes, and ultimately in-place hydrocarbon volumes but also to an increased understanding of the static/dynamic behaviour of the fields through better imaging of internal faulting. The application of various proprietary and contractor-based seismic depth processing since 1997 has allowed for a better understanding of structural configuration of the deep reservoirs. This rich processing history has provided the interpretation team with various processing volumes (isotropic Post-SDM, anisotropic Post-SDM and, most recently, anisotropic Pre-SDM) to allow a more complete understanding of the uncertainties related to different imaging approaches.
Historically, the effects of anisotropy on vertical and lateral positioning were realized and a number of internal proprietary software tools were developed to quality control depth imaging processing. The 1998 Glenelg discovery southwest of Elgin Field was the focus for the initial anisotropic Pre-SDM study, which was later expanded to include the Elgin/Franklin fields area. This processing benefited from Total’s internal QC tools and a combination of additional data (e.g. walk-away VSP profiles with different orientations, long-offset 2D seismic data) which provided an optimum mix to derive and verify the anisotropic parameters for the velocity model. Overall, the new seismic data shown significant improvement over the previous time- and depth-migrated datasets, reduced uncertainty on internal and bounding-fault positions and allowed the observation of the vertical and spatial uncertainties attached to different migration approaches. This understanding of the variability in seismic imaging and its effects on the reservoir parameters and structural configurations in depth is used as an input to understand ranges of in-place hydrocarbon volumes, the potential of near-field exploration and future infill-drilling strategies.
Preliminary results from investigations of seismic and petrophysical properties of Faroes basalts in the SeiFaBa project
Authors: JAPSEN P. , ANDERSEN C. , ANDERSEN H. L. , ANDERSEN M. S. , BOLDREEL L. O. , MAVKO G. , MOHAMMED N. G. , PEDERSEN J. M. , PETERSEN U. K. , RASMUSSEN R. , SHAW F. , SPRINGER N. , WAAGSTEIN R. , WHITE R. S. , WORTHINGTON M. 
Published: April 2010

The development of methods of seismic imaging beneath basalts is still hindered by a lack of knowledge about the elastic properties of basaltic sequences and the degree of three-dimensional heterogeneity. The SeiFaBa project (2002–2005) is funded by the Sindri Group as part of the programmes for licensees within the Faroese area and will attempt to address these issues.
The Glyvursnes-1 well was drilled by SeiFaBa through the Upper Basalt Formation outside Tórshavn in 2002. A full core and numerous wireline logs were acquired from the 700m deep well. During the same operations, the existing 660m deep Vestmanna-1 well drilled mainly into the Middle Basalt Formation was reamed and logged. The two wells are central to a number of closely co-ordinated experiments, which are all targeted at creating models for seismic wave propagation through a succession of basalt by combining detailed analysis at core, log and seismic scales. Data from these two wells, in combination with the data for the Lopra-1 well drilled into the Lower Basalt Formation, will give new stratigraphic and petrophysical control of the Lower, Middle and Upper Basalt formations on the Faroes.
The seismic programme was initiated in 2002 and the main acquisition was carried out during 2003. The well site at Glyvursnes gives optimal conditions for combining VSP, offset-VSP and surface seismic experiments both onshore and offshore and the seismic effects of a nearby near-vertical shear zone can be studied in detail. Preliminary analysis of log data from the Lopra-1 well suggests that the acoustic properties of these basalt flows are mainly controlled by porosity of a stiff matrix filled with clay minerals and water. Further studies will allow for explanations of the sonic response of basalt in terms of physical and compositional properties and a better understanding of the seismic signatures of flood basalt successions.
Three-dimensional visualization for well placement and geosteering: Njord Field, offshore mid-Norway
Authors: DART C. , DENICHOU J. M. , BRIDGER T. , HAUGEN R. , SJØHOLM J. , HALVORSEN Å. , ØYE V. , SEIM M. 
Published: April 2010

Njord is a structurally complex Lower Jurassic oil field located on the Halten Terrace, offshore mid-Norway. The field was discovered in 1986 and has been under production since 1997. The field is produced by a combination of depletion and crestal gas injection. Difficulties in finding new economically viable drilling targets led to a drilling stop in 2001–2002 and production is now in decline. A second drilling phase comprising three infill wells began in late 2002. Production results from these three wells will be critical for determining Njord’s future beyond 2005. During the drilling stop, advanced 3D visualization techniques were used to unravel the field’s complex extensional fault pattern. New well targets were identified using multiple seismic datasets and multiple interpretations. 3D visualization was also used during drilling to keep the wells within the reservoir and to avoid an unstable formation.
Reservoir simulation models were used to identify areas with undrained potential, and 4D seismic data indicated fault blocks where changes in gas saturation had occurred. The reservoir oil is initially under-saturated, but gas has also come out of solution in areas with significant pressure depletion. Gas has also been re-injected. New wells were planned to avoid these fault blocks. Target points were placed using 3D visualization software and well path dog-leg angles were calculated. The process continued iteratively until a well path had been achieved with maximum reservoir penetration and realistic dog-leg angles (< 3.5°). Real time data were transmitted to shore during drilling using a web service. These data included survey, petrophysical log, biostratigraphical and borehole image data that were used alongside the 3D visualizations. In this way, drilling progress through the G&G interpretation was continuously monitored. Similarly, geosteering, or plug back and sidetrack, decisions were quickly evaluated.

Supplementary material:
Movies referred to in the article are available at
https://doi.org/10.6084/m9.figshare.c.4812936
The MacCulloch Field: improving reservoir characterization through time-lapse analysis
Authors: SCORER J. , FULLER N. , MALCOLM J. , BRUNER J. 
Published: April 2010

The MacCulloch oil field lies in Block 15/24b in the UK Central North Sea. The field is produced using a floating production storage and offtake facility from two sub-sea centres and has been on production since 1997.
The original geophysical mapping of the field was based on 3D seismic data acquired in 1993. In April 2002, a repeat 3D survey was acquired over the field with the aim of better understanding the depletion of the field using time-lapse seismic analysis.
The MacCulloch Field reservoirs are turbidites of the Upper Balmoral Sandstone Unit in the Lista Formation of the Upper Paleocene, which are connected to a large aquifer in the underlying Lower Balmoral Sandstone Unit. Connection to such a large aquifer means that pressure support over field life has been very good (<100 psi drop over field life). This fact, coupled with the lack of a gas cap, means that for the time-lapse analysis any change should primarily be due to a substitution of water for oil.
The MacCulloch Field reservoir is made up of five discrete turbidite sandstone-dominated sand bodies, which can be distinguished on the seismic data. Examination of the time-lapse response in these bodies shows that they have acted as a primary control on the depletion of the field. The individual bodies have been analysed using 3D visualization and interpretation techniques, and incorporated into the geological model with differing rock properties assigned to each. Within the reservoir simulation model, the assignment of directional permeabilities to these units and the placing of transmissibility barriers at their boundaries substantially improved the history match of the field, thereby enhancing our ability to predict future performance and identify possible infill drilling locations.
Application of 3D seismic visualization techniques for seismic stratigraphy, seismic geomorphology and depositional systems analysis: examples from fluvial to deep-marine depositional environments
Authors: POSAMENTIER H. W. 
Published: April 2010

In recent years, 3D seismic has become an essential tool for the interpretation of subsurface stratigraphy and depositional systems. Seismic stratigraphy in conjunction with seismic geomorphology, calibrated by borehole data, has elevated the degree to which seismic data can facilitate geological interpretation. 3D seismic data has enabled interpreters to visualize details of complex depositional systems, which can be incorporated into borehole planning for exploration as well as development needs to improve risk management significantly. Common techniques for geological visualization include (1) imaging stratigraphic horizons, (2) time slicing and flattened time slicing, (3) interval attribute analysis, (4) voxbody interpretation and mapping, (5) 3D perspective rendering and (6) opacity rendering.
One of the key benefits of modern 3D seismic interpretation is that stratigraphic horizons can be interpreted and horizon attributes (such as reflection amplitude, dip magnitude, dip azimuth, and curvature) can then be imaged directly in 2D or 3D space. Techniques such as variable illumination can enhance geomorphological interpretations, and, when integrated with stratigraphic analyses, can yield insights regarding distribution of source, seal, and reservoir facies. Stratigraphic intervals bracketing sections of geological interest can be evaluated for amplitude and frequency content and can contribute to geological interpretations. Time slices and flattened time slices (also referred to as horizon slices) can bring to light map patterns and geological features that other techniques might overlook. Voxel picking can further bring out features of geological interest. This method involves auto-picking of connected voxels of similar seismic character, a technique that can illuminate discrete depositional elements in three dimensions. Similarly, opacity rendering, which makes opaque only those voxels that lie within a certain range of seismic values, can further bring out features of stratigraphic interest. Examples of fluvial, shallow marine, and deep marine depositional environments are shown. A variety of visualization techniques are applied to these examples in an effort to illustrate the variety of interpretation techniques available to the geoscientist. These examples will highlight the integration of seismic stratigraphic and seismic geomorphological analyses essential for maximum benefit to be derived from geological analyses of 3D seismic data.
Automated mapping of carbonate build-ups and palaeokarst from the Norwegian Barents Sea using 3D seismic texture attributes
Authors: CARRILLAT A. , HUNT D. , RANDEN T. , SONNELAND L. , ELVEBAKK G. 
Published: April 2010

Geological heterogeneity in hydrocarbon reservoirs is normally related to variability in depositional facies, diagenesis and structure. On the Loppa High, Norwegian Barents Sea, reservoir quality in prospective Upper Palaeozoic carbonates is considered to be controlled mainly by primary depositional facies variability linked to active faulting, with a secondary overprint of palaeokarst. The best quality reservoirs are anticipated in build-up facies. Although high-quality 3Dseismic data exist over the prospect, it is a challenge to map the buildups and palaeokarst in three-dimensional space using conventional 3Dseismic interpretation tools. This is mainly due to the internal heterogeneity of the build-ups and palaeokarst, which are characterized by a range of seismic reflection/attribute patterns.
A procedure for multi-attribute mapping of seismic facies is described and utilized to provide a truly threedimensional interpretation of build-up and palaeokarst geobodies. A neural network classifier is used to analyse a set of 3D attributes that capture the seismic stratigraphical and structural patterns inherent in the data. These attributes are referred to as 3D texture attributes since they describe the reflector-geometry in a small 3D neighbourhood. Pattern recognition is interpreter-guided, with the desired seismic facies to be mapped input as ‘training data’ and analysed prior to their presentation to the 3D-classification system. Once the classification is made, the interpreter is presented with a 3D classified volume and an uncertainty analysis of each of the mapped facies/classes. This is used to evaluate the results prior to their visualization in 3D space. The method allows the interpreter to identify quickly a volume where the features of interest occur and to focus the interpretation work directly on them. In addition, the 3D visualization of the mapped geobodies brings important new information that might be overlooked when inspecting data in vertical or horizontal data windows.
In the Norwegian Barents Sea case study, 3Dseismic facies mapping provides the first truly three-dimensional interpretation of the build-ups and palaeokarst, where their external form, juxtaposition, cross-cutting relationships and structural information are preserved. These data give new insights as to the stratigraphic distribution and internal variability of the build-ups and palaeokarst system; this information is important to estimation of reservoir volume, connectivity and variability.
Salt tectonics above complex basement extensional fault systems: results from analogue modelling
Authors: DOOLEY T. , McCLAY K. R. , HEMPTON M. , SMIT D. 
Published: April 2010

Physical model studies of salt tectonics related to thick-skinned extension have been largely confined to 2Dstructures. An experimental programme, utilizing silicone polymer and silica sand/ceramic beads as ductile and brittle analogues respectively, was designed to investigate the 3D relationships between salt diapirs and intersecting basement fault systems seen in the Central Graben, UK North Sea.
During extension, intersection points in the basement fault system generate complex single, two-way or three-way, flap structures in the overburden, localizing deformation and footwall diapiric activity on the rift margins. Flap structures and associated diapirs are located adjacent to, but diagonally inboard of, the basement intersection points and consist of single, or multiple, convex-to-the-hanging-wall fault segments that are gradually breached with increasing extension. Major diapirs that attain passive status accommodate much of the continued basement extension through down building processes. Intra-basin horst systems develop inwardly dipping graben, cored by a major salt wall, during initial extension. Axial flow along this structure feeds growing diapirs. Grounding of the brittle overburden results in source cut-off and deflation of the salt wall due to continued expansion by extensional faulting.
During subsequent inversion major diapirs are reactivated, exhibiting rapid active rise through the overburden, suggesting that buoyancy forces associated with diapirs play a major role in their reaction to subsequent tectonic stresses. Basin margins with major corner point systems develop highly segmented inversion fronts related to the localized nature of brittle structuring during extension. Diapir crests and entrained salt bodies are nucleation sites for the development of brittle reverse faults. Basin margins with minor corner systems commonly demonstrate reactivation of the basin margin fault system, producing a linked inversion front. The models display close similarities to structures seen in the UK Central North Sea and other salt basins, and have important implications for basement control on diapir locations during post-salt basin extension.