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- Volume 25, Issue 2, 2019
Petroleum Geoscience - Volume 25, Issue 2, 2019
Volume 25, Issue 2, 2019
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Crustal structure and heat-flow history in the UK Rockall Basin, derived from backstripping and gravity-inversion analysis
Authors Alan M. Roberts, Andrew D. Alvey and Nick J. KusznirSeismic data made available by the UK OGA (Oil & Gas Authority) has been used to constrain a model of crustal structure and heat-flow history for the UK Rockall Basin. Top basement/base sediment has been interpreted around the full extent of the seismic dataset. This has produced a model for the thickness of the sediment fill within the basin which is thicker than previous published estimates.
The new sediment-thickness model has been incorporated into a 3D backstripping study, producing maps of subsidence and thinning factor. Analysis of backstripped subsidence shows the thinning factor reaching peak values of c. 0.8–0.85 (β factor >5) in the south-central axial area, reducing in magnitude northwards to c. 0.7. The new sediment-thickness model has also been incorporated into a 3D gravity-inversion study, mapping Moho depth, crustal thickness and thinning/stretching factor. The results show crustal-basement thickness reduced to c. 6 km, thinning factor c. 0.8, in the south-central area, while it spans the range c. 6–10 km further north. The results are compatible with previous seismic refraction work in both the UK and Irish sectors of the Rockall Basin. We believe that the extension which created the basin was non-magmatic and that the axial region is underlain by highly-thinned continental crust.
The results from the gravity inversion have been used to make predictions about the top-basement heat-flow history. Heat flow in the basin centre is predicted to have been initially high, reducing with time, associated with cooling of the transient synrift heat-flow anomaly. On the basin flanks heat flow was less variable over time, its magnitude controlled primarily by constant radiogenic heat input from the basement, rather than by the transient geotherm anomaly.
There remain considerable uncertainties associated with our interpretation and analysis. These uncertainties have been addressed with sensitivity analyses.
A regional gravity-inversion model, using the new sediment-thickness data spliced into regional public-domain information, shows that structural and stretching continuity can be mapped at the crustal scale along the full length of the UK/Irish Rockall Basin, contrary to conclusions from some previous studies.
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Hydrocarbon charge assessment of frontier basins – a case study of the oceanic crust of the Moroccan Atlantic margin
Authors Martin Neumaier, Ralf Littke, Stefan Back, Peter Kukla, Michael Schnabel and Christian ReichertA string of prominent structural anticlines is located in the deep offshore Atlantic Ocean c. 150 km west of Essaouira (Morocco), possibly forming large traps. However, the basement is inferred to comprise oceanic crust, which raises concerns for source-rock presence and sufficient subsurface temperatures for oil generation. The presented work showcases a hydrocarbon charge assessment approach adapted to the very sparse data context and the specific geodynamic settings of the Moroccan Atlantic margin. Regional 2D basin and petroleum systems modelling was performed to assess possible scenarios of hydrocarbon charge of the deep-water folds, its migration style and timing. Several possible oil and gas generation drivers have been identified for postulated Toarcian marine shale source rocks. These range from simple burial-driven heating to more unique scenarios involving early stage oceanic ridge heating and the effect of the Canary Island hotspot. In particular, the latter might have had a major impact on the oil and gas generation, the migration style and overall accumulated amounts.
Supplementary material: A table with lithology parameters used for modelling, an overview table of modelling cases and annex figures with additional results from modelling cases are available at https://doi.org/10.6084/m9.figshare.c.4183106
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Estimation of net apparent erosion in the SW Barents Sea by applying velocity inversion analysis
Authors Dimitrios Ktenas, Ivar Meisingset, Erik Henriksen and Jesper Kresten NielsenThe SW Barents Sea was subjected to significant uplift and erosion during the Cenozoic, processes that are believed to have had a significant impact on hydrocarbon maturation and migration in the area. The current study uses compaction of shale- and sand-dominated layers to make a map of net apparent erosion throughout the SW Barents Sea. The map shows regional trends consistent with deep-seated isostatic uplift of the crust in combination with glacial erosion as a driving mechanism for the erosion. We find increased erosion towards the north and decreased erosion towards the west, in the western Barents Sea. The trend of highest erosion has an axis stretching in a SE–NW orientation towards Svalbard. This indicates a major change in the crustal uplift pattern in the transition from the Norwegian mainland to the Barents Sea. The velocity inversion method used in this study combined with a two-baseline normal compaction trend model demonstrates a reliable procedure for accurate erosion estimations. It allows erosion estimates from layers with different lithologies to be integrated into a common interpretation and differences to be interpreted geologically: for example, an apparent facies change to a mixed sand–shale lithology, possibly with reservoir quality sands developed, in the Cretaceous on the Bjarmeland Platform.
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Using pilot wells to integrate geological modelling and history matching: applied to the Norne Benchmark case
Authors Gil G. Correia and Denis J. SchiozerThe inherent uncertainties in numerical reservoir simulation can lead to models with significant differences to observed dynamic data. History matching reduces these differences but often neglects the geological consistency of the models, compromising production forecasting reliability. To address this issue, this work proposes a geological modelling workflow integrated within a probabilistic, multi-objective history-matching workflow, using the concept of pilot points. The pilot-point method is a geostatistical parameterization technique that calibrates a pre-correlated field, generated from measured values, and a set of additional synthetic data at unmeasured locations in the reservoir, referred to as pilot points. In this study, the synthetic data correspond to synthetic wells; henceforth referred to as pilot wells. The methodology is applied to a real dataset, the Norne Field benchmark case. The flexibility of the pilot-well method is the principal advantage, while a key challenge is to optimize the pilot-well configuration. The configuration includes production data, the preferred fluid-flow paths and the geological framework. The flexibility of the method is demonstrated in the two case studies presented here: generating specific sedimentary features (G-segment) and finding the best location for the cemented stringers responsible for the fluid behaviour (C-segment).
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Efficient brownfield optimization of a reservoir in west Siberia
In this work we present a methodology for optimal management of brownfields that is illustrated on a real field. The approach does not depend on the particular reservoir flow simulator used, although streamline-derived information is leveraged to accelerate the optimization. The method allows one to include (non-linear) constraints (e.g. a recovery factor larger than a given baseline value), which are very often challenging to address with optimization tools. We rely on derivative-free optimization coupled with the filter method for non-linear constraints, although the methodology can also be combined with approaches that utilize exact/approximate gradients. Performance in terms of wall-clock time can be improved further if distributed-computing resources are available (the method is amenable to parallel implementation). The methodology is showcased using a real field in west Siberia where net present value (NPV) is maximized subject to a constraint for the recovery factor. The optimization variables represent a discrete time series for well bottom-hole pressure over a fraction of the production time frame. An increase in NPV of 7.9% is obtained with respect to an existing baseline. The optimization methods studied include local optimization algorithms (e.g. generalized pattern search) and global search procedures (e.g. particle swarm optimization). The controls for one injection well in the real field were actually modified according to the solution determined in this work. The results obtained suggest improvement for most economic scenarios.
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Exploring the link between the flow zone indicator and key open-hole log measurements: an application of dimensional analysis
Authors Ali A. Garrouch and Athbi A. Al-SultanDimensional analysis has been used as a tool for developing a non-linear empirical model giving the flow zone indicator (FZI) as a function of open-hole log measurements. Dimensional analysis confirms that interval transit time (Δt), true resistivity (R t), bulk density (ρ b), the apparent water resistivity (R wa) and the photo-electric absorption (P e) are essential well-log measurements for estimating the FZI in sandstone formations.
A unique power-law relationship has emerged between a dimensionless FZI group (λ) and a dimensionless resistivity group for distinct hydraulic flow units. Petrotyping, using either the discrete rock type (DRT) approach or the global hydraulic elements (GHE) approach, appears to provide a credible framework for comparative hydraulic flow unit description. Dimensionless groups permitted the analysis of the effect of several operational variables. The FZI increases with increasing bulk density, and with increasing interval transit time. On the other hand, the FZI decreases with increasing true resistivity (R t). The relationship between the FZI and the photo-electric absorption is more intricate, though, since it depends on the value of the power-law exponent .
Conventional log data from an oil well (well B), penetrating two distinct sandstone oil reservoirs in an onshore sandstone oilfield in the Middle East, were used to validate the dimensionless groups. For the field case presented, the FZI empirical model prediction capability does not appear to be diminished by the existence of a capillary transition zone. The FZI-based model, used for estimating permeability, represents an improvement in the prediction of permeability provided that reliable estimates of the FZI are available. Dimensional analysis proved to be a powerful modelling tool capable of revealing fine relationships that are invisible to exhaustive data mining techniques.
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Effects of erosional scours on reservoir properties of heterolithic, distal lower-shoreface sandstones
More LessDistal intervals of interbedded sandstones and mudstones in shallow-marine, wave-dominated shoreface and deltaic reservoirs may contain significant hydrocarbon resources, but their reservoir properties are difficult to predict. Relatively small-scale (200 × 100 × 20 m) three-dimensional object-based reservoir models, conditioned to outcrop analogue data, have been used to investigate the controls on the proportion of sandstone, the proportion of sandstone beds that are connected by sandstone-filled erosional scours and the effective vertical-to-horizontal permeability ratio (k v/k h) of such intervals. The proportion of sandstone is controlled by sandstone-bed and mudstone-interbed thickness, and by parameters that describe the geometry, dimensions and lateral-stacking density of sandstone-filled scours. Sandstone-bed connectivity is controlled by the interplay between the thickness of mudstone interbeds and sandstone-filled erosional scours. Effective k v/k h is controlled by the proportion of sandstone, which represents the effects of variable distributions and dimensions of mudstones produced by scour erosion, provided that scour thickness is greater than mudstone-interbed thickness. These modelling results provide a means of estimating the effective k v/k h at the scale of typical reservoir-model grid cells using values of mudstone-interbed thickness and the proportion of sandstone that can potentially be provided by core data.
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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)