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- Volume 26, Issue 1, 2020
Petroleum Geoscience - Volume 26, Issue 1, 2020
Volume 26, Issue 1, 2020
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Mechanics of salt systems: state of the field in numerical methods, Part II
Authors Rajesh Goteti, Maria A. Nikolinakou and Mahdi HeidariThematic collection: This article is part of the Mechanics of salt systems: state of the field in numerical methods collection available at: https://www.lyellcollection.org/cc/mechanics-of-salt-systems
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The competition for salt and kinematic interactions between minibasins during density-driven subsidence: observations from numerical models
Stratal geometries of salt-floored minibasins provide a record of the interplay between minibasin subsidence and sedimentation. Minibasin subsidence and resulting stratal geometries are frequently interpreted by considering the minibasins in isolation and implicitly assuming that internal geometries are the result of purely vertical halokinetic processes. However, minibasins rarely form in isolation and may record complex subsidence histories even in the absence of tectonic forces. In this study we use numerical models to investigate how minibasins subside in response to density-driven downbuilding. We show that minibasins subsiding in isolation result in simple symmetrical minibasins with relatively simple internal stratigraphic patterns. In contrast, where minibasins form in closely spaced arrays and subside at different rates, minibasins can kinematically interact due to complex patterns of flow in the encasing salt, even during simple density-driven subsidence. More specifically, we show that minibasins can: (1) prevent nearby minibasins from subsiding; (2) induce lateral translation of nearby minibasins; and (3) induce tilting and asymmetrical subsidence of nearby minibasins. We conclude that even in areas where no regional or dominant salt flow regime exists, minibasins can still be genetically related and the minibasin subsidence histories cannot be fully understood if considered in isolation.
Thematic collection: This article is part of the Mechanics of salt systems: state of the field in numerical methods collection available at: https://www.lyellcollection.org/cc/mechanics-of-salt-systems
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Feedback between synrift lithospheric extension, sedimentation and salt tectonics on wide, weak continental margins
Authors J. Allen, C. Beaumont and M. E. DeptuckNumerical modelling in 2D is used to explore interactions between synrift lithospheric extension, salt deposition and deformation, and pre- and post-salt sedimentation, for wide rifted margins with weak continental crust. Distributed aggrading synrift sedimentation enhances listric normal faulting of the sediments and crust in the mid and distal margin. In contrast, localized prograding sedimentation initiates a positive feedback between sedimentation, faulting and mid- to lower-crustal flow. This feedback causes localized crustal extension at the proximal margin, and leads to thick sediments in deep proximal basins. The feedback is more pronounced when more sediment is deposited, and does not develop in models with stronger, narrower rifted margins. Later initiation of the post-salt prograding sediments leads to a less pronounced feedback with lower-crustal flow and a more significant advancement of the prograding wedge over the salt body. We compare our model results with the rifted Nova Scotia Atlantic margin, contrasting margin evolution and salt tectonics between the northeastern region, which experienced significant post-salt synrift sedimentation, and the central region, where less post-salt sediment was deposited. We show that the northeastern margin may have experienced enhanced proximal graben development owing to prograding synrift sedimentation.
Thematic collection: This article is part of the Mechanics of salt systems: state of the field in numerical methods collection available at: https://www.lyellcollection.org/cc/mechanics-of-salt-systems
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Comparison of stresses in 3D v. 2D geomechanical modelling of salt structures in the Tarfaya Basin, West African coast
We predict stresses and strains in the Tarfaya salt basin on the West African coast using a 3D static geomechanical model and compare the results against a simplified 2D plane-strain model. Both models are based on present-day basin geometries, are drained, and use a poroelastic description for the sediments and visco-plastic description for salt. We focus on a salt diapir, where an exploratory well has been drilled crossing a major fault. The 3D model shows a significant horizontal stress reduction in sediments at the top of the diapir, validated with measured data later obtained from the well. The 2D model predicts comparable stress reduction in sediments at the crest of the diapir. However, it shows a broader area affected by the stress reduction, overestimating its magnitude by as much as 1.5 MPa. Both models predict a similar pattern of differential displacement in sediments along both sides of the major fault, above the diapir. These displacements are the main cause of horizontal stress reduction detected at the crest of the diapir. Sensitivity analysis in both models shows that the elastic parameters of the sediments have a minimal effect on the stress–strain behaviour. In addition, the 2D sensitivity analysis concludes that the main factors controlling stress and strain changes are the geometry of the salt and the difference in rock properties between encasing sediments and salt. Overall, our study demonstrates that carefully built 2D models at the exploration stage can provide stress information and useful insights comparable to those from more complex 3D geometries.
Thematic collection: This article is part of the Mechanics of salt systems: state of the field in numerical methods collection available at: https://www.lyellcollection.org/cc/mechanics-of-salt-systems
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Structural and lithological controls on the architecture of igneous intrusions: examples from the NW Australian Shelf
Authors N. J. Mark, S. P. Holford, N. Schofield, C. H. Eide, S. Pugliese, D. A. Watson and D. MuirheadRift-related magmatism resulting in widespread igneous intrusions has been documented in various basins, including the Faroe Shetland Basin (UK), the Voring and Møre basins (Norway), and along the NW Shelf of Australia. Seismic mapping, combined with fieldwork, has resulted in greater understanding of subsurface intrusive plumbing systems but knowledge of emplacement style and the mechanisms by which intrusions propagate is limited. The interpretation of a 3D seismic dataset from the Exmouth Sub-basin, NW Shelf of Australia, has identified numerous igneous intrusions where a close relationship between intrusions and normal faults is observed. These faults influence intrusion morphology but also form pathways by which intrusions have propagated up through the basin stratigraphy. The steep nature of the faults has resulted in the intrusions exploiting them and thus manifesting as fault-concordant, inclined dykes; whereas in the deeper parts of the basin, intrusions that have not propagated up faults typically have saucer-shaped sill morphologies. This transition in the morphology of intrusions related to fault interaction also highlights how dykes observed in outcrop may link with sills in the subsurface. Our interpretation of the seismic data also reveals subsurface examples of bifurcating intrusions with numerous splays, which have previously only been studied in outcrop.
Supplementary material: Figures showing uninterpreted seismic lines are available at https://doi.org/10.6084/m9.figshare.c.4395974
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Evaporate facies recognition using an unsupervised artificial neural network in the northern Arabia Plate
Authors Si-Hai Zhang, Yin Xu and Mee Kee TengThe carbonate–evaporite depositional combination of Late Jurassic age, incorporates the most prolific oil-producing intervals in the world and forms many giant fields. The succession is the top member of four upwards-shoaling carbonate–anhydrite cycles of Upper Kimmeridgian age, and is overlain by the impermeable anhydrite in northern Arabia. The weak depositional contrasts in carbonate ramp settings make the lateral seal configurations subtle and tough to recognize. Multiple attribute analyses based on an artificial neural network (ANN) can delineate the internal character of the reservoir and seal in a consistent way.
In order to recognize the sedimentary facies and characterize stratigraphic traps within this reservoir interval, multiple seismic attributes were input to an unsupervised ANN. Unsupervised ANN offers a powerful means of classification, implemented here using a single-layer perceptron network. The network is trained by comparing the neurons to the input vectors using competitive-learning techniques. Once a neuron migrates to the centre of a class, the network stabilizes, training is finished and the neuron is assigned to a representative class. Without prior information, the unlabelled class is calibrated and analysed by lithofacies generated from log and core data. Further sedimentary facies are recognized by integrating local geological knowledge.
The depositional environments in the study area are well characterized by the unsupervised ANN, and the recognized sedimentary facies are consistent with the drilled wells and the resulting geological model. Lagoonal deposits of the inner-ramp, ramp-crest shoal and proximal deposits of the middle ramp are recognized within the study area. The widespread ramp crest with peloid and oolitic grainstones provides good reservoirs, whereas the lagoonal deposits distributed between the shoals have a greater abundance of tight limestone with low porosity and permeability, thereby forming a good lateral seal. The selected study area, covering the Rimthan Arch is considered a favorable area for the presence of stratigraphic traps. The sedimentary facies recognition helps to define potential areas for favourable prospect definition and hence prospect ranking.
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Rivers, reefs and deltas: geomorphological evolution of the Jurassic of the Farsund Basin, offshore southern Norway
More LessIn many petroleum-bearing, data-poor ‘frontier’ basins, source, reservoir and seal distribution is poorly constrained, making it difficult to identify petroleum systems and play models. However, 3D seismic reflection data provide an opportunity to directly map the 3D distribution of key petroleum system elements, thereby supplementing typically sparse, 1D sedimentary facies information available from wells. Here, we examine the Farsund Basin, an underexplored basin offshore southern Norway. Despite lying in the mature North Sea Basin, the Farsund Basin contains only one well; meaning there remains a poor understanding of its hydrocarbon potential. This east-trending basin is anomalous to the north-trending basins present regionally, having experienced a different tectonic, and most likely geomorphological, evolution. We identify a series of east-flowing rivers in the Middle Jurassic, the distribution of which are controlled by salt-detached faults. In the Middle Jurassic, a series of carbonate reefs, expressed as subcircular amplitude anomalies, developed. Within the Upper Jurassic we identify numerous curvilinear features, which correspond to the downlap termination of southwards-prograding deltaic clinoforms. We show how seismic-attribute-driven analysis can determine the geomorphological development of basins, offering insights into both the local and regional tectonostratigraphic evolution of an area, and helping to determine its hydrocarbon potential.
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Bedding-scale geomodelling for effective permeability estimation in the Upper McMurray Formation, NE Alberta, Canada
Authors Chen Hao, Mu Longxin, Huang Jixin and Chang GuangfaThe McMurray Formation is one of the most significant bitumen deposits in Canadian oil sands. Bitumen-bearing sand intervals deposited and reworked in fluvial, tidal or estuarine environments result in heterogeneous sediment distributions comprising clean sands and low-permeability muddy laminae or mud drapes. These interlayers increase the difficulty in estimating reservoir permeability, which is a critical geological parameter to predict the performance of in situ thermal processes of the oil sands projects. In this paper, we describe a bedding-scale geomodelling and simulation workflow using core images, core-plug and Vshale logs to estimate the effective permeability (K h, K v) in the Upper McMurray Formation. Details of five steps in this workflow are presented. To show the general applicability of this workflow, three pay-zone facies from tidal-channel infilled deposits of the Mackay River Project, CNPC, were selected to demonstrate this sedimentary process mimicking bedding-scale geomodelling strategy. The results of effective permeability estimation have the potential to improve history matching in flow simulations and performance forecasting.
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Raiders of the Lost Mud: the geology behind drilling incidents within the Balder Formation around the Corona Ridge, West of Shetland
The Faroe–Shetland Basin, NE Atlantic continental margin, hosts a number of important hydrocarbon fields; although deep water and narrow weather windows mean that drilling costs are considerably higher than for other parts of the UK Continental Shelf. Any additional drilling complications are therefore important to predict and negate as such issues can result in avoidable multi-million pound cost implications. This study focuses on the Corona Ridge, an intrabasinal high which contains the Rosebank Field, where a plethora of drilling issues, of enigmatic origin, are common within a key stratigraphic marker known as the Balder Formation. Drilling fluid loss, bit balling, wellbore breakouts and wellbore ‘ballooning’, where lost drilling fluid returns to the wellbore, are all recognized within the Balder Formation along the Corona Ridge. We find that many of the drilling incidents can be traced back to both the lithological character of the Balder Formation and the mid-Miocene tectonic inversion of the Corona Ridge. Moreover, we find that this geological explanation has wider implications for exploration in the region, including the mitigation of drilling incidents in future wells through drill-bit selection.
Supplementary material: A table detailing the drilling acronyms and terminology used in this study (adapted from Mark et al. 2018 ) is available at https://doi.org/10.6084/m9.figshare.c.4290602
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Reservoir modelling notional CO2 injection into the Precipice Sandstone and Evergreen Formation in the Surat Basin, Australia
The Lower Jurassic Precipice Sandstone and Evergreen Formation are an important prospective reservoir–seal pair for CO2 storage in the Surat Basin, Australia. However, there is little seismic and well data to constrain reservoir modelling in the best notional injection area. To test the likely storage performance, three contrasting sector-scale static reservoir models were built to capture the range of geological uncertainty in facies distribution and reservoir properties. These considered sectors of the Surat Basin with different palaeogeographical arrangements. The models were focused on capturing detail at the interface between the top of the Precipice Sandstone (Blocky Sandstone Reservoir: BSR) and the overlying basal portions of the Evergreen Formation (Transition Zone: TZ), a critical area for understanding CO2 injection. Object modelling was used for the BSR and lower TZ. Stochastic modelling was implemented for the upper TZ and the Ultimate Seal because these zones were less sensitive to facies distributions. Porosity was modelled stochastically, and permeability calculated using porosity–permeability transformation functions. Dynamic simulation showed the TZ has the capacity to arrest CO2 flow out of the BSR given appropriate CO2 injection conditions. This study shows a method of capturing uncertainty in geological heterogeneity when data are sparse or absent. The promising initial modelling results of CO2 injection into the Surat Basin suggests that it presents a real option for carbon storage at a climate mitigation scale. Further investigation should focus on assessing other major risks associated with carbon storage such as fault seals, reactive fluid transport and the impact of legacy wells.
This article is part of the Energy Geoscience Series available at https://www.lyellcollection.org/cc/energy-geoscience-series
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Model calibration for forecasting CO2-foam enhanced oil recovery field pilot performance in a carbonate reservoir
Authors M. Sharma, Z. P. Alcorn, S. B. Fredriksen, A. U. Rognmo, M. A. Fernø, S. M. Skjæveland and A. GraueApplication of foam has been found to mitigate challenges associated with field-scale CO2 floods for enhanced oil recovery (EOR) by providing in-depth mobility control. The field pilots that have been run so far have shown varying results, inferred mainly from inter-well tracer studies and production data analysis. A research collaboration has been set up to advance the technology of using foam as a mobility control agent for CO2 EOR, with focus on integrated reservoir modelling to assist technology transfer to a high-cost environment. A heterogeneous carbonate reservoir onshore in west Texas, USA has been selected for the field trial. The reservoir has been waterflooded for more than 50 years, and a significant part of it has been on continuous CO2 injection for the last 5 years. An inverted five-spot pattern, which had rapid CO2 breakthrough in adjacent producers and is currently recycling significant amounts of CO2, has been selected for the study. The pilot is planned for 2 years with surfactant alternating gas (SAG) injection in the first year, followed by CO2 injection in the next year.
A reservoir model was created by integrating available static and dynamic information. Since the measurement of static information and production performance is usually imprecise, even the most carefully constructed models do not exactly represent reality. In this paper, we present a workflow that was used to calibrate the reservoir model to historical data for practical forecasting, which takes into account a wide range of uncertainties caused by the inaccessibility of information. Laboratory studies were performed with reservoir cores, fluids and selected surfactant to obtain the base values of foam model parameters. As an output, distributions for key performance indicators such as cumulative oil production and CO2 retention were generated for the proposed pilot to guide further decision-making.
Supplementary material: The details of simulation set-up and results for history matching and prediction are available at https://doi.org/10.6084/m9.figshare.c.4704374
This article is part of the Energy Geoscience Series available at https://www.lyellcollection.org/cc/energy-geoscience-series
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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)