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- Volume 10, Issue 4, 2004
Petroleum Geoscience - Volume 10, Issue 4, 2004
Volume 10, Issue 4, 2004
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Peat biomass and early diagenetic controls on the paraffinic oil potential of humic coals, Canterbury Basin, New Zealand
By R. SykesEarly mature, Pukeiwitahi Formation (Late Cretaceous) coals from Galleon-1 and Endeavour-1 wells in the Canterbury Basin, New Zealand have been analysed by petrographic, bulk chemical and thermal extraction- and pyrolysis-GC techniques and compared with similar coals in the Taranaki Basin to determine the primary controls on their paraffinic oil potential. The Pukeiwitahi coals, which are moderately perhydrous (HI 180–305 mgHC g−1TOC), vitrinite-rich (73–95%) and relatively liptinite-poor (<10%), accumulated in gymnosperm-dominated, planar mires in a temperate, coastal plain environment. Pyrolysate compositions are representative of high-wax, paraffinic–naphthenic–aromatic crude oil-generating coals. Petrographic data and the n-alkyl chain length distributions of extracts and pyrolysates suggest that the long-chain aliphatic hydrocarbons are derived primarily from leaf-derived liptinites (cutinite and liptodetrinite). The paraffinic oil potential of the coals is accordingly dependent on the net amount of leaf biomass in the precursor peats, following partial degradation of the available leaf litter under generally high surface water levels and dilution with other, less paraffinic biomass, particularly wood. The coals in Endeavour-1 generally contain more leaf-derived liptinites than those in Galleon-1 and, thus, have greater paraffinic oil potentials despite commonly lower HI values. Brackish conditions within the depositional environment caused the Galleon-1 and Endeavour-1 coals to be variably enriched in hydrogen but not in aliphatics. HI is, therefore, not a reliable indicator of the paraffinic oil potential of marine-influenced coals.
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The complexity of a ramp–flat–ramp fault and its effect on hanging-wall structuring: an example from the Njord oil field, offshore mid-Norway
Authors Ralf Ehrlich and Roy H. GabrielsenThe Njord oil field of the mid-Norwegian continental margin comprises a hydrocarbon trap structure, which is delineated by segments of master faults with complex geometry. The Vingleia Fault Complex includes the major fault segments that delineate the Njord structure to the southeast and east. Three master fault segments with a change in strike orientation are recognized. Reflection seismic sections reveal that these segments show strong variations in fault plane geometry. The central part is characterized by a pronounced ramp–flat–ramp geometry, which diminishes both southwestward and northeastward, so that the northeastern and southwestern segments have a more listric geometry. Hence, an along-strike profile shows an antiform-like culmination in the master fault surface.
To the characteristic deformation of ramp–flat–ramp faults, additional deformation in the Njord Field is obvious and marked by extensional horses, extensive roll-over folding, varying strata rotation, characteristic fault bending and variable influence of synthetic and antithetic faults. The occurrence of the style of deformation and geometrical variations in fault pattern are closely related to the structural position above the detachment fault. The following steps in the development of the Vingleia Fault Complex and the associated deformation of the hanging-wall fault block are proposed. (1) Initiation of the master faults in early Triassic. This stage was characterized by slow, extensional displacement. The positions of the master fault segments were possibly influenced by basement in homogeneities marked by a magnetic/gravity anomaly. (2) It is likely that the ramp–flat–ramp had already become established at this stage and that the master fault geometry and a proposed weak salt layer promoted this. (3) During accelerating extension in mid to late Jurassic, the master fault segments became connected by one-sided, lateral linking of fault tip and fault plane or by mutual curved linking of the fault tips. (4) Simultaneously, a roll-over anticline developed within the hanging wall of the master fault. Its relatively large amplitude is produced by a differential movement on the fault surface in combination with a dip-parallel shift of the vertical displacement maximum, which is positioned above a change in the footwall dip.
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Influence of porosity and pore fluid on acoustic properties of chalk: AVO response from oil, South Arne Field, North Sea
Amplitude versus offset (AVO) inversion provides direct evidence for the presence of light oil in high-porous chalk in the South Arne Field, North Sea. The elastic properties of the chalk were estimated at three scales by analysing core data, log-readings and AVO-inversion results. The velocity–porosity relation of the core data matches a modified upper Hashin–Shtrikman model for Ekofisk Field chalk and the model is extended to 45% porosity. A small clay content reduces porosity without affecting chalk stiffness and this content can be estimated from the water saturation, which is controlled by silicate content and particle sorting in the zone of irreducible water saturation. The model is, thus, scaled according to clay content estimated by the water saturation. Based on comparison with the model and measurements on core samples, it is found that the sonic log data represent chalk characterized by forced displacement of the oil by mud filtrate and, thus, a much higher water saturation than estimated from, for example, a shallow resistivity log. Forward modelling of the acoustic properties of the virgin zone results in a characteristic pattern of Poisson ratio versus depth. This pattern agrees with inverted seismic data, whereas it is not captured by conventional fluid substitution.
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Well test simulation through Discrete Fracture Network modelling in a fractured carbonate reservoir
Authors Claudio Casciano, Livio Ruvo, Bruno Volpi and Franco MasseranoA Discrete Fracture Network (DFN) model was used to simulate the results of a production test carried out in a well drilled in a tight, fractured carbonate reservoir. Several static DFN models, depicting different geological scenarios, were built based on data from well logs, core analyses, PLT surveys and structural geology studies. Each of these models underwent a validation procedure, consisting of the simulation of the production test. The comparison between the simulated results and the actual data identified the scenario whose results most closely matched the actual well behaviour.
In order to compensate for the lack of geological data, an iterative loop was performed between the static model and the dynamic simulation. Constraints-added flow simulations provided new information for use in modifying the DFN model, resulting in a step-by-step updating of the static model itself. Finally, a geologically sound model accurately matching the results of the production test was obtained. The final DFN model was used to calculate the equivalent petrophysical parameters that were transferred to the corresponding region of the full field dual-porosity fluid flow model.
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3D high-resolution digital models of outcrop analogue study sites to constrain reservoir model uncertainty: an example from Alport Castles, Derbyshire, UK
Authors J. K. Pringle, A. R. Westerman, J. D. Clark, N. J. Drinkwater and A. R. GardinerAdvances in data capture and computer technology have made possible the collection of 3D high-resolution surface and subsurface digital geological data from outcrop analogues. This paper describes research to obtain the 3D distribution and internal sedimentary architecture of turbidite channels and associated sediments at a study site in the Peak District National Park, Derbyshire, UK. The 1D, 2D and 3D digital datasets included Total Station survey, terrestrial photogrammetry and remote sensing, sedimentary logs and a Ground Penetrating Radar (GPR) dataset. A grid of 2D GPR profiles was acquired behind a cliff outcrop; electromagnetic reflection events correlated with cliff face sedimentary horizons logged by Vertical Radar Profiling. All data were combined into a Digital Solid Model (DSM) dataset of the site within reservoir modelling software.
The DSM was analysed to extract 3D architectural geometries for petroleum reservoir models. A deterministic base model was created using all information, along with a suite of heterogeneous turbidite reservoir models, using 1D, 2D or 3D information. The model suite shows significant variation from the deterministic model. Models built from 2D information underestimated connectivity and the continuity of geobodies, but overestimated channel sinuosity. Advantages of using 3D digital outcrop analogue data for 3D reservoir models are detailed.
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Heat flow in the Vøring Basin, Mid-Norwegian Shelf
More LessIn situ temperature and heat flow were determined in 1994 at 159 sites, grouped into 66 clusters between latitude 65° N and 67°30’ N at water depths from 669 m to 1464 m. The mean of all cluster heat-flow measurements conducted in this survey was 58.5 mW m−2, with a standard error of ±4.40 mW m−2. The mean heat flow from IKU well data for the Trøndelag Platform is 56.2±6.65 mW m−2. Shorter wavelength heat-flow variations appear to be controlled structurally and can be explained by sedimentation and thermal refraction effects. High heat flow associated with faulted structural highs such as the Nyk High and Vema Dome–Rym Fault Zone may also result from hydrothermal convection. Relatively isolated high (106.6 mW m−2) heat flow observed at 846 m water depth may be an artefact of bottom water disturbances; however, virtually identical deep-water heat-flow anomalies, believed to be of hydrothermal origin, also exist. While heat-flow measurements made at water depths less than 1000 m should be regarded with caution, there is presently no justification for eliminating those exhibiting linear heat flow with depth. Submarine avalanches seem unimportant in the survey area. Neither crustal thinning, underplating nor sill intrusion, within the last 50 Ma, would have a measurable effect on present-day heat flow. The net effect of crustal thinning may be a reduction of the crustal heat generation potential, depending on the degree of thinning of the upper crust, since the accumulating sediments cannot compensate fully for the lost heat generation from a crystalline basement.
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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)