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- Volume 14, Issue 2, 2008
Petroleum Geoscience - Volume 14, Issue 2, 2008
Volume 14, Issue 2, 2008
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Pressure regression, fluid drainage and a hydrodynamically controlled fluid contact in the North Sea, Lower Cretaceous, Britannia Sandstone Formation
Authors Stephen A. O'Connor and Richard E. SwarbrickThe Lower Cretaceous Britannia Sandstone Formation is located below overpressured Sola Formation shales (c. 2800 psi overpressure) and above Jurassic reservoirs (up to 5700 psi overpressure) and represents a pressure regression, recording overpressure values ranging from approximately 100 psi in Block 15/30 (in the extensional Outer Moray Firth/Central North Sea basin) up to a maximum of approximately 1600 psi in Block 22/4. The Britannia Sandstone has an anomalously low overpressure when compared with deeper Cretaceous (Valhall) and Jurassic reservoir overpressures locally, and further afield in the Central North Sea at similar depths.
The pore pressures in the Sola Formation shales have been estimated using conventional porosity/sonic-based prediction methods, indicating strong overpressure disequilibrium between the Sola Formation shales and the Britannia Sandstones, both in the Britannia Field area and in the laterally age-equivalent sands to the west referred to as the Kopervik Fairway (the Aptian sands of the South Halibut Basin, forming the reservoirs of the Blake, Captain and Goldeneye fields).
Burial curve modelling indicates that it is likely that the Sola Formation shales have overpressured for the last 4 Ma, and likely much longer, suggesting an early history of pressure build up (now preserved in the Sola Formation shales and deeper, Jurassic reservoirs and associated sediments). The adjacent Britannia Sandstone Formation therefore lost fluid and pressure due to local availability of a fluid conduit. Resulting active fluid flow, driven by overpressure differences in the Britannia Sandstone Formation, has created a hydrodynamically tilted hydrocarbon–water contact with lateral flow from east to west. Well evidence indicates vertical flow from shallower reservoirs into the stratigraphically deeper, main Britannia reservoir. The fluid escape could be either laterally via the Kopervik Fairway and/or vertically through the Upper Cretaceous Chalk facilitated by fractures/faulting.
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Mineralogical control on mudstone compaction: a study of Late Cretaceous to Early Tertiary mudstones of the Vøring and Møre basins, Norwegian Sea
Authors Christer Peltonen, Øyvind Marcussen, Knut Bjørlykke and Jens JahrenThe Late Cretaceous to Early Tertiary sediments of the Vøring and Møre basins are predominantly composed of fine-grained mudstones. Variations in the mineralogy and chemistry of these mudstones provide information regarding facies, provenance and burial history, and may also be used to predict rock properties. Over 300 cuttings’ samples from five wells were analysed by XRD. The results show significant changes in mineralogy as a function of burial depth, as well as important lateral variations throughout the basins. Eocene mudstones with up to 55% smectite probably represent a northern equivalent of the Balder Formation (North Sea). The underlying Late Cretaceous sequence probably had less primary smectite derived from volcanic ash, as indicated by the lower iron content. The distribution of smectite is also limited by its thermal stability, thus providing important constraints on the temperature history. These mudstone sequences may appear to be relatively homogeneous based on gamma-ray and shale volume calculations from wireline logs, but mineralogical and geochemical analyses from cuttings show that they vary significantly in composition. The smectite content is greatest in the south (c. 55%) and decreases significantly northward (c. 20%), indicating a marked regional control on velocity/porosity–depth curves. Mudstones containing high smectite content are characterized by lower velocities, lower densities and higher porosities when compared with published burial curves. Stratigraphic and regional variations in velocity and density are important for seismic interpretation and are significant for basin modelling.
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On the occurrence and formation of open fractures in the Jurassic reservoir sandstones of the Snøhvit Field, SW Barents Sea
Authors Ole Petter Wennberg, Ove Malm, Tim Needham, Ewart Edwards, Signe Ottesen, Frode Karlsen, Lars Rennan and Rob KnipeOpen fractures were described in core and Formation Micro Image (FMI) image logs in the Jurassic sandstones of the Tubåen, Nordmela and Stø formations in the Snøhvit Field, and 3D fracture network properties analysed using Computer Tomography (CT)scanning in selected core samples. The most frequent open fracture type is short stylolite-related fractures (F1), but longer open fractures are also present, with no obvious relationship to stylolites (F2). The F1 fracture densities are related generally to the clay content of the host rock, which controls the occurrence and spacing of the stylolites. The fractures are steep, with a N–S-dominant strike azimuth and significant spread. Although, generally, the F1 fractures are short, a percolating and 3D connected open fracture network across the core was found in most of the CT-scan samples. Open fractures were also found in the damage zone of a lately reactivated fault. The formation of the open fractures in the Snøhvit Field is related most likely to thermoelastic processes during removal of overburden in late Tertiary time. The presence of open fractures may influence reservoir flow, particularly in intervals containing a high frequency of stylolites and in the damage zones of reactivated faults.
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Structures and hydrocarbon prospectivity in the northern Davis Strait area, offshore West Greenland
Authors Ulrik Gregersen and Torben BidstrupIn the northern Davis Strait to southernmost Baffin Bay area, offshore West Greenland, deep basins with Mesozoic and Cenozoic sedimentary successions occur and a number of large structures and closures at likely reservoir levels have been found. Mid-Cretaceous, Upper Cretaceous and Paleocene sand-rich deposits are well known onshore east of the study area and in offshore wells, and equivalent deposits may also be present in the structures. Some of the potential structural leads have thick seals of late Cretaceous–Cenozoic deposits and short distances to deep possible kitchens with mid-Cretaceous and Paleocene source rocks, which mainly came into the oil window during the Neogene. Onshore oil seeps and gas shows, together with amplitude anomalies from seismic data, such as possible bright spots, support a live petroleum system in the region. During Early to mid-Cretaceous time a number of large structures and basins formed as a result of extensional faulting, including the Kangerluk Structure, the Aasiaat Structural Trend, structures in the Aasiaat and Sisimiut basins, and in the Nagssugtôq Sub-basin. A period with less tectonic activity followed in the Late Cretaceous, with deposition of thick, basinal mudstone-dominated successions. In the Late Cretaceous to Early Paleocene renewed tectonic activity caused uplift and faulting of large structures, such as the Davis Strait High and partly the Kangerluk Structure. Late Paleocene to Early Eocene strike-slip movements created thrust faults and compressional structures, mainly in the Ikermiut Fault Zone, associated with formation of the Ikermiut Basin. During the Paleocene and mainly the Early Eocene the >200 km long Ilulissat Graben developed. Paleocene and Eocene basalts occur west of Disko and Nuussuaq and narrow in distribution further south. The basalt cover offshore may be more limited than believed earlier. The area was offered for licensing in two periods from 2006 to early 2008.
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Characterization of turbidites from the Urucutuca Formation of the Almada Basin, Bahia, Brazil, using seismic and petrophysical well log data
Authors Klédson Tomaso P. Lima and Carlos Alberto DiasFifty seismic lines and petrophysical logs from 15 wells were used to characterize the reservoirs of the Urucutuca Formation palaeo-canyon in the Almada Basin. The resulting 3D geological model allowed the Urucutuca Formation and its turbidite canyons to be evaluated as potential petroleum reservoirs. The log analyses indicate great variations in effective porosity (reaching a maximum value of 25%) and the clay content of the sandstones (ranging from less than 5% to greater than 40%). Other relevant factors in this context are the sandstone and calcarenite thicknesses which reach 243 m and 93 m, respectively. Information obtained from the seismic lines indicates that there was a strong tectonic influence on the geometry of the Almada Canyon, resulting in the formation of two canyons that join in the offshore portion of the basin. The connection between the canyons has been observed to extend from the continent to 27 km offshore. The results indicate that the Urucutuca Formation is an important horizon for future oil exploration, having favourable genetic and petrophysical characteristics.
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Evaluation of added value in reservoir management by application of flow control with intelligent wells
Authors F. Ebadi, D. R. Davies, A. R. Gardiner and P. W. M. CorbettIntelligent Well-systems Technology (IWsT) provides the delivery and management of production flexibility thorough downhole measurement and control. This paper uses a new workflow to evaluate the suitability of a wide range of reservoir types for IWsT application. This is achieved by a systematic study of a series of generic reservoir scenarios, based on property distributions derived from real field data and operational oil-field models. These geological scenarios were tested to determine the ‘Added Value’ from IWsT compared with standard well completions. Added value is expected through incremental oil recovery.
Results show that IWsT can control uneven, invading fluid fronts, which develop along the wellbore length due to permeability differences, reservoir compartmentalization, or different strengths of aquifer or gas cap support. The degree of improvement depends on the reservoir type (whether layered, faulted, channelized, etc.) and the distribution of porosity and permeability within it. Guidelines for the optimum placement of Internal Control Valve (ICV) locations in the planned completion zone are discussed. A global methodology was developed for the initial screening of favourable geological scenarios for the implementation of IWsT, and an ‘Application Envelope’ was developed based on the formation's correlation length and variability. The validity of this envelope is illustrated by its application to a real reservoir modelling case.
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Maximum Likelihood Deconvolution for sequence analysis and improved structural resolution in the Vindhyan Basin, India
Authors S. M. Chatterjee and Somaditya DuttaExploration in the Proterozoic Vindhyan Basin in the north-central part of India has received much attention because a number of basins coeval to it (Amadeus and McArthur basins, Australia and Lena–Tunguska petroleum province, Siberia) are known hydrocarbon producers. The assemblage of interbedded clastics and carbonates in the thick Vindhyan sedimentary column is considered to be favourable for a petroleum system. This is supported by discovery of oil and gas in Vindhyan sediments.
Wavelet processing and application of Maximum Likelihood Deconvolution (MLD) to post-stack seismic data have enhanced resolution significantly to facilitate identification of various stratigraphic features, including reflection pattern termination in the Jabera–Damoh area in the southeastern part of the basin. Sixteen seismic sequences correlatable with well data have been identified from the wavelet-processed data. MLD has also improved structural resolution and made identification of faults easier. This paper shows that MLD is a powerful tool for seismic sequence stratigraphy.
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A methodology for efficiently populating faulted corner point grids with strain
Authors Nestor Cardozo, Per Røe, Harald H. Soleng, Niclas Fredman, Jan Tveranger and Sylvie SchuellerThis article describes an algorithm to compute finite strain in faulted corner point grids using the software Havana. The algorithm is based on a simple fault displacement formula, and a volumetric computation of strain in the grid's deformed configuration. The volumetric computation of strain is tested by comparing the finite strain of a 3D trishear model calculated by this method, with that calculated by the tetrahedrons method. The agreement between both methods confirms the validity of the volumetric strain computation. The algorithm is applied to synthetic models of one and three intersecting normal faults, and to a real model with seven faults, the Emerald Field. In all cases the computed finite strain is consistent with the fault network and with the variation of slip along the faults. There is one parameter that affects the computation significantly: the drag radius (r d) or extent of folding across a fault. Low r d models yield high finite strain and strain gradients but limited fault interaction, and vice versa. Using empirical relations between fault throw and damage zone width, r d can be narrowed down and further constrained by evaluating the quality of the grid's restoration. The strain algorithm can be integrated easily into a reservoir modelling workflow and in stochastic modelling. The algorithm provides criteria for conditioning the distribution of deformational features within the reservoir zones affected by faulting, based on the magnitude of finite strain.
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Volumes & issues
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Volume 30 (2024)
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Volume 29 (2023)
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Volume 28 (2022)
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Volume 27 (2021)
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Volume 26 (2020)
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Volume 25 (2019)
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Volume 24 (2018)
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Volume 23 (2017)
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Volume 22 (2016)
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Volume 21 (2015)
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Volume 20 (2014)
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Volume 19 (2013)
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Volume 18 (2012)
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Volume 17 (2011)
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Volume 16 (2010)
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Volume 15 (2009)
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Volume 14 (2008)
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Volume 13 (2007)
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Volume 12 (2006)
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Volume 11 (2005)
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Volume 10 (2004)
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Volume 9 (2003)
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Volume 8 (2002)
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Volume 7 (2001)
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Volume 6 (2000)
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Volume 5 (1999)
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Volume 4 (1998)
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Volume 3 (1997)
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Volume 2 (1996)
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Volume 1 (1995)