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- Volume 18, Issue 1, 2012
Petroleum Geoscience - Volume 18, Issue 1, 2012
Volume 18, Issue 1, 2012
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Experimental investigation of CO2 breakthrough and flow mechanisms in shale
Authors Elin Skurtveit, Eyvind Aker, Magnus Soldal, Matthieu Angeli and Zhong WangSupercritical CO2 breakthrough and flow mechanisms in shale have been investigated in laboratory experiments using a high pressure flow cell and cylindrical samples of shale from the Draupne formation in the North Sea. The main objective is to study the basic mechanisms involved in the breakthrough process and define the controlling parameters for supercritical CO2 flow in a low permeable shale.
Experimental testing provides new insight into the CO2 breakthrough process through simultaneous measurements of deformation and ultrasonic velocities in the sample. A marked sample dilation associated with the CO2 breakthrough is identified accompanied with a pronounced drop in ultrasonic velocities. X-ray images of the sample using a high resolution 3D computer tomography (CT) scanner provide information on macroscopic fracture distribution inside the sample before and after testing.
The CO2 breakthrough pressure for the Draupne material seems to depend on confining pressure and effective pressure rather than pore pressure difference across the sample. After breakthrough the effective CO2 permeability was found to follow a simple model for permeability in fractured rock. The drop in ultrasonic velocity was associated with mechanical changes and possible micro fracturing inside the sample. Based on our observations we conclude that pressure-induced opening of micro-fractures during the breakthrough process is an important mechanism for flow in addition to capillary displacement. Our findings may have important consequences for later testing and estimation of CO2 breakthrough pressure and flow in shale.
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Geofluid behaviour in successive extensional and compressional events
Authors V. Baqués, A. Travé, E. Roca, M. Marín and I. CantareroThe structural position of the Upper Jurassic–Lower Cretaceous carbonates located in the central part of the Catalan Coastal Ranges corresponds to the southwestern end of the Vallès-Penedès Fault. This fault was reactivated at different times during successive extensional and compressional events and several generations of fractures and cementations were formed.
Based on petrological and geochemical analyses of this cementation an evolution of the fluids related to the different tectonic stages can be deduced. (1) During the Mesozoic extension, the parent fluids resulted either from a mixing of trapped Upper Jurassic–Lower Cretaceous seawater and meteoric water, or from buffered meteoric waters. (2) Related to the Paleogene compression, the fluids came from the percolation of meteoric waters indicating shallow-depth deformation. (3) During the transitional phase between Paleogene compression and Neogene extension, a karstic dissolution took place and the porosities were infilled by different generations of sediments and cements deposited from meteoric fluids. (4) During the Neogene extension several episodes of meteoric percolations and fracturing processes occurred. The Neogene extensional faults used the earlier karstic system to develop and, later, during the late post-rift stage, a new karstic system occurred, covering the walls of open fractures with speleothems.
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Using probabilistic shale smear modelling to relate SGR predictions of column height to fault-zone heterogeneity
More LessFault-seal analysis in hydrocarbon exploration often involves prediction of the sealing capacity of fault rock at reservoir–reservoir juxtapositions on subsurface faults. A proxy property, such as Shale Gouge Ratio (SGR), is mapped on to the fault surface, and then SGR is either (a) calibrated by observations of known sealing faults, to define its sealing capacity (empirical approach), or (b) assumed to be equal to the composition of the fault rock, for which a database of capillary threshold pressures is available from cores (deterministic approach). The deterministic approach implicitly assumes that capillary pressures measured on centimetre-scale samples are representative of seismically mappable faults, for example that faults of intermediate SGR are equivalent to phyllosilicate framework fault rocks.
This contribution builds on earlier outcrop and modelling work to suggest an alternative explanation for the observed progressive increase in sealing capacity on faults of increasing SGR. Stochastic models of disrupted shale smears display the same pattern of increasing sealing capacity as SGR increases. These models have a bimodal ‘fault rock’ composed only of sealing shale smears and non-sealing matrix and, yet, at intermediate SGR the predicted column heights are similar to those normally ascribed to intermediate composition fault rocks. The resulting ‘fault-seal envelope’ in the models is a statistical estimate of the maximum trappable column height, dependent on the random occurrence of a gap in the smeared fault surface.
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A new method for top seals predictions in high-pressure hydrocarbon plays
Authors Davide Casabianca and John CosgroveThe current model describing the sealing mechanism of high-pressure hydrocarbon traps and the ensuing methodology for predicting top seal integrity and capacity in high-pressure plays assumes that the caprock, defined as the low matrix permeability formation immediately overlying the reservoir, is the seal.
This study challenges this assumption and proposes the existence within the caprock of a fluid waste zone consisting of a system of fractures cutting from the reservoir upwards into the caprock and, therefore, charged with reservoir fluids. Because of the waste zone fractures the reservoir fluids are not sealed at the base of the caprock. Instead the seal coincides with the fracture waste zone tip point, which occurs at an important stress and stratigraphic boundary termed the ultimate seal. Six case studies demonstrate that in the UK Central Graben the top seal for Mesozoic high pressure hydrocarbon accumulations lies between the Base Cretaceous Unconformity and the base of the Chalk Group and that the Jurassic Kimmeridge Clay Formation is not necessarily the seal for these traps. The data used for the construction of structural and stress models for the case studies include pore pressure measurements, formation integrity measurements, well logs and reflection seismic profiles.
An important conclusion of this study is that the shorter the waste zone the higher the chance of finding a hydrocarbon column in the reservoir.
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Modelling induced polarization effects due to pyrite in geochemical alteration zones above hydrocarbon accumulations
Authors P. C. H. Veeken, E. O. Kudryavceva, O. F. Putikov, P. Y. Legeydo and S. A. IvanovGeoelectrical methods measure resistivity and induced polarization (IP) effects in the subsurface. The differentially normalized electromagnetic method (DNME) detects geochemical alteration zones due to anomalous electrical responses which are often located above a hydrocarbon accumulation. Leakage above a non-perfect top seal is postulated to change the pH in the overlying sediments where a shallower mobility barrier is encountered. Epigenetic pyrite mineral growth is stimulated when iron and sulfur ions are available. Leakage and mineral growth are modelled by mathematical formulae assuming diffusion migration through the overburden. Effects of time and tectonic faulting are examined. Pyrite is highly polarizable and easily detected by an electrical IP survey in the field, whereby a current is introduced into the ground and subsequently turned off. Decay of the potential difference over the receiver electrodes is monitored in time. Special parameters facilitate detection of IP anomalies related to the presence of hydrocarbons. An inverted electrical depth model is computed using the Cole–Cole formula. The impact of geochemical modelling and predicted epigenetic mineral growth is demonstrated for the Severo-Gulyaevskaya dataset (Siberia). The overall DNME track record shows a reduced risk attached to hydrocarbon prospects, with a more reliable ranking at reasonable costs.
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The third porosity system
Authors P. W. M. Corbett, S. Geiger, L. Borges, M. Garayev and C. ValdezWell testing is a critical part of any evaluation of a carbonate reservoir discovery. Well-test interpretation in carbonate reservoirs poses additional challenges to those normally faced in the interpretation process in clastic reservoirs. The range of different boundary and crossflow relationships that are generated during well testing by the complex porosity systems are often poorly quantified and understood. The volume over which the pressure response is effective is also a source of great uncertainty and could be critical at the exploration/appraisal stage in any project.
In this paper, which describes a generic modelling approach, we consider carbonate reservoirs which contain three pore sytems (or porosity types): (1) microporosity (end-member) with low permeability and high porosity; (2) macroporosity (end-member) with high permeability and high porosity; and (3) fracture porosity with high permeability and low porosity. These occur in various nested geometrical distributions and varying contrasts. The observed well-test responses (i.e. fracture flow, fracture–matrix interactions) tend to ‘obscure’ one of these systems when compared with theoretical models. Micro- (meso-) and macroporosity can merge into a single matrix porosity system where the permeability contrasts are not great and the correlation lengths short (which can often be the case in carbonates). Macroporosity can also appear in well testing to ‘merge’ with the fracture response, i.e. the contributions of flow in the fractures and (high-permeability) porous matrix are indistinguishable. As a result of the homogenizing attributes of pressure dissipation away from the well, it is not generally possible to see the effects of a ‘triple-porosity’ response (i.e. where three different pore systems have a separate and identifiable signature on the well-test response) and a classical double-porosity response in the well test, despite three different pore systems being present, is possible. The apparent double-porosity response, which might obscure a triple-porosity system, therefore needs careful interpretation in order to attribute the appropriate properties during reservoir characterization in carbonates.
In this work we use ‘geological’ well testing (i.e. well testing through numerical simulation of hypothetical geological models) to systematically analyse the effects of microporosity, macroporosity and fracture porosity on pressure dissipation and their apparent homogenization. While recent studies have proposed that a triple-porosity system should result in a ‘W-shaped’ response, we do not observe this behaviour in our simulations, although we specifically designed our geological models with a triple-porosity system. Instead we observe how macroporosity merges with the fractures or micro- and macroporosity merge, creating a ‘sub-dominant’ matrix or a ‘dominant’ fracture system, respectively and follow a traditional ‘V-shaped’ double-porosity response.
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Burial diagenetic evolution of the Lower Carboniferous (Dinantian) of the southern margin of the Askrigg Platform and a comparison with the Derbyshire Platform
Authors Cathy Hollis and Gordon WalkdenIn order to predict the style and impact of post-depositional modification of carbonate successions, well-studied and accessible outcrop analogues are invaluable. The Lower Carboniferous (Dinantian) carbonate platforms of the Pennine Basin of northern England have a long history of investigation. As such, they offer the potential to evaluate the mechanisms and timing of fluid flux during extensional tectonism, post-rift basinal subsidence and inversion. This study concentrates upon the diagenetic evolution of the late Dinantian of the southern margin of the Askrigg Platform of North Yorkshire and a comparison with published data from the age-equivalent Derbyshire Platform. A pattern of consistent, diagenetic modification during early diagenesis is evident, but key differences occur in the burial realm. On both the southern margin of the Askrigg Platform and the Derbyshire Platform, patterns of dolomitization, hydrocarbon emplacement and mineralization can be determined on the platform that reflect the diagenetic evolution of the adjacent basins. However, within the study area of the Askrigg Platform, there is only local evidence for a fault/fracture control on the migration of Mg-enriched, hydrocarbon-bearing fluids. In contrast, on the Derbyshire Platform, burial diagenesis is intimately associated with NW–SE- and NE–SW-trending faults and fractures. Data suggest that pervasive cementation in the marine and meteoric realm occluded matrix porosity in both areas, such that fluid migration was almost entirely fracture controlled. With the localization of structural deformation along the Craven Fault Zone, and a low abundance and density of open fault/fracture networks, circulation of fluids on to the southern margin of the Askrigg Platform was inhibited, however. Furthermore, the presence of local aquifers in the Craven Basin may have led to fluid expulsion from the basin during early burial.
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Paleocene deep-water depositional systems in the North Sea Basin
Authors Evelina Dmitrieva, Christopher A-L. Jackson, Mads Huuse and Adam McCarthyInterpretation of 3D seismic reflection data supported by well data provides insights into the geometry of early Paleogene depositional systems along the eastern margin of the North Viking Graben. These deposits, which consist mainly of sandstones interbedded with claystones and siltstones, are interpreted to document deposition at the edge of a large base-of-slope to proximal basin floor fan system which was sourced from the eastern basin margin. Individual sandstone bodies are up to 80 m thick and occur within four sandstone-prone packages (DU1–4), and well-to-seismic ties indicate that the thicker sandstones (>10 m) are represented by channelized or sheet-like, high-amplitude anomalies. Both well and seismic data suggest that the sandstones are of limited lateral extent (<1–5 km), implying they were deposited in a series of channels. Channelization and compensational stacking of sandstones may have been at least partly controlled by differential compaction across previously deposited sandbodies. The study reveals that deep-water depositional patterns are more complex than is apparent from previous, lithostratigraphically-driven correlations and from regional isochron mapping. In particular, this study has implications for the controls on the distribution and reservoir architecture of deep-water sandstones.
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Heavy mineral stratigraphic analysis on the Clair Field, UK, west of Shetlands
Authors Andrew Morton and Alex MilneHydrocarbons in the Clair Field, west of the Shetland Islands, are hosted by Devonian–Carboniferous clastic red beds deposited in a non-marine fluviolacustrine setting. The succession is almost entirely biostratigraphically barren and, hence, alternative approaches to reservoir correlation are required. Heavy mineral analysis (HMA), which subdivides clastic successions on the basis of changes in provenance and sediment transport history, has proven successful in establishing a high-resolution correlation framework for the Clair Field. Since the technique offers a reliable and rapid method for monitoring the stratigraphy of the Clair reservoir succession, HMA has been undertaken on a real-time basis at well site for virtually all development wells during Phase 1 of the Clair Field development, and for all Phase 2 appraisal wells. Heavy mineral data can be acquired in less than 2 hours from receipt of sample. Consequently, owing to the relatively slow penetration rates frequently associated with Clair drilling, stratigraphic information is usually acquired ahead of logging while drilling. Heavy mineral data are used in the decision-making process in a variety of situations, including picking of casing and coring points, whether to maintain or alter well trajectory, and when to terminate drilling. In the Clair Field, formation tops can be subtle and, since HMA can establish trends and predict formation changes before they are encountered, they are critical in aiding geosteering decisions. HMA has also been used to monitor stratigraphy and to pick formation tops when logging tools have failed, allowing drilling to continue and avoiding tripping to change the bottom-hole assembly. The application of HMA to the Clair Field development is illustrated by reference to a number of wells drilled on the field since 2005.
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A relational database for the digitization of fluvial architecture
Authors Luca Colombera, Nigel P. Mountney and William D. McCaffreyDepositional (facies) models of fluvial architecture permit straightforward categorization of deposits, but are necessarily simplistic. Here we describe a complementary database methodology which is designed to encapsulate the inherent complexity of fluvial systems and their preserved deposits. The database is implemented as a series of tables (characterizing qualitative and quantitative architectural and geomorphological properties and system attributes) populated with data derived from peer-reviewed studies of both modern rivers and ancient fluvial successions, and from other reliable sources. Architectural properties (geometries, internal organization, spatial distribution and reciprocal relationships of lithosomes) are assigned to three different orders of genetic bodies organized in a hierarchical framework, ultimately belonging to stratigraphic volumes that are homogeneous in terms of their controlling factors and internal parameters. Interrogation of the database generates a varied suite of quantitative information, whose principal applications include: (i) the quantitative comparison of fluvial architecture to evaluate the relative importance of intrinsic and extrinsic controls; (ii) development of quantitatively justified fluvial depositional models through the integration of data from multiple sources; (iii) development of better constraints on the workflows used to infer borehole correlations and to condition stochastic models of subsurface architecture; (iv) identification of appropriate modern and ancient analogues for hydrocarbon reservoirs.
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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)
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