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- Volume 12, Issue 4, 2006
Petroleum Geoscience - Volume 12, Issue 4, 2006
Volume 12, Issue 4, 2006
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Connectivity of channelized reservoirs: a modelling approach
Authors David K. Larue and Joseph HovadikConnectivity represents one of the fundamental properties of a reservoir that directly affects recovery. If a portion of the reservoir is not connected to a well, it cannot be drained. Geobody or sandbody connectivity is defined as the percentage of the reservoir that is connected, and reservoir connectivity is defined as the percentage of the reservoir that is connected to wells.
Previous studies have mostly considered mathematical, physical and engineering aspects of connectivity. In the current study, the stratigraphy of connectivity is characterized using simple, 3D geostatistical models. Based on these modelling studies, stratigraphic connectivity is good, usually greater than 90%, if the net: gross ratio, or sand fraction, is greater than about 30%. At net: gross values less than 30%, there is a rapid diminishment of connectivity as a function of net: gross. This behaviour between net: gross and connectivity defines a characteristic ‘S-curve’, in which the connectivity is high for net: gross values above 30%, then diminishes rapidly and approaches 0.
Well configuration factors that can influence reservoir connectivity are well density, well orientation (vertical or horizontal; horizontal parallel to channels or perpendicular) and length of completion zones. Reservoir connectivity as a function of net: gross can be improved by several factors: presence of overbank sandy facies, deposition of channels in a channel belt, deposition of channels with high width/thickness ratios, and deposition of channels during variable floodplain aggradation rates. Connectivity can be reduced substantially in two-dimensional reservoirs, in map view or in cross-section, by volume support effects and by stratigraphic heterogeneities. It is well known that in two dimensions, the cascade zone for the ‘S-curve’ of net: gross plotted against connectivity occurs at about 60% net: gross. Generalizing this knowledge, any time that a reservoir can be regarded as ‘two-dimensional’, connectivity should follow the 2D ‘S-curve’. For channelized reservoirs in map view, this occurs with straight, parallel channels. This 2D effect can also occur in layered reservoirs, where thin channelized sheets are separated vertically by sealing mudstone horizons. Evidence of transitional 2D to 3D behaviour is presented in this study. As the gross rock volume of a reservoir is reduced (for example, by fault compartmentalization) relative to the size of the depositional element (for example, the channel body), there are fewer potential connecting pathways. Lack of support volume creates additional uncertainty in connectivity and may substantially reduce connectivity. Connectivity can also be reduced by continuous mudstone drapes along the base of channel surfaces, by mudstone beds that are continuous within channel deposits, or muddy inclined heterolithic stratification. Finally, connectivity can be reduced by ‘compensational’ stacking of channel deposits, in which channels avoid amalgamating with other channel deposits. Other factors have been studied to address impact on connectivity, including modelling program type, presence of shale-filled channels and nested hierarchical modelling.
Most of the stratigraphic factors that affect reservoir connectivity can be addressed by careful geological studies of available core, well log and seismic data. Remaining uncertainty can be addressed by constructing 3D geological models.
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A strategy for modelling the diagenetic evolution of seismic properties in sandstones
Authors Anders Dræge, Tor Arne Johansen, Ivar Brevik and Camilla Thorsen DrægeThe geometrical distribution of various components in a composite sandstone is decisive for its overall stiffness and seismic velocities. Information about which constituents, for example, are load bearing, dispersed in pore fluid or present as contact cement is, therefore, necessary if the seismic properties are to be modelled reliably. A distribution scheme for quartz cement, K-feldspar and some of the most common clay minerals in sandstones (illite, kaolinite, smectite and chlorite) is suggested on the basis of thin-section observations made by a number of authors. This classification scheme facilitates rock physics modelling as a function of mineral concentrations. A composite rock physics model has also been developed to account for simultaneous combinations of mineral distributions. Well-known mineral reactions are used to make simple models of mineralogy versus temperature (depth) from different starting scenarios, as various minerals tend to follow different and predictable paths during burial and increasing temperature. The mineralogical trends are then entered into the composite rock physics model to produce the diagenetic evolution of seismic rock properties, and the procedure is used to estimate the effective rock properties of sandstones in a well log. The modelling allows deductions to be made about possible mineralogies and their distributions from seismic parameters. Finally, reflection coefficients resulting from sandstones subjected to various diagenetic processes are modelled and analysed. The results show that it is possible to discriminate between reflections emanating from the interfaces of a selection of common diagenetic scenarios.
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Implicit net-to-gross in the petrophysical characterization of thin-layered reservoirs
Authors Paolo Scaglioni, Livio Ruvo and Mauro CozziA new workflow has been devised to characterize the petrophysical properties of two, thin-layered, heterolithic log facies from a turbidite reservoir. The methodology is based on a published modelling technique that enables an extremely accurate reconstruction of the fine-scale lithological and sedimentological reservoir heterogeneities and a thorough integration of petrophysical data from core plugs.
A large number of fine-scale rock models (geometrical grids) are: (1) stochastically generated to investigate the variability of the sedimentological features observed in cores; and (2) stochastically populated with porosity and permeability values of the pure lithological components (sandstone, siltstone and mudstone) to generate petrophysical grids. The petrophysical grids are subsequently upscaled using analytical and flow-based techniques, thus providing distributions of porosity, horizontal permeability and vertical permeability that are further analysed to characterize the aforementioned log facies.
The results obtained using this workflow are exhaustive, in the sense that they implicitly take into account all of the possible ranges of variation of ‘net-reservoir’ (sandstone and siltstone) and ‘non-net-reservoir’ (mudstone) lithologies. The use of net-to-gross in petrophysical characterization is thus made redundant.
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Three-dimensional modelling of stacked turbidite channels inWest Africa: impact on dynamic reservoir simulations
Authors Richard Labourdette, Jérôme Poncet, Julien Seguin, François Temple, JoAnn Hegre and Alan IrvingThe examination of production history from hydrocarbon fields composed of turbidite deposits indicates that fluid flow behaviour is often more complex than expected. The cause is commonly linked to the presence of fine-scale sedimentary heterogeneities, which complicate the reservoir. This is especially true in the case of turbiditic submarine channel complexes with final channel-filling stages composed of lateral migration deposits. These fine-scale heterogeneities are usually below seismic resolution and are rarely represented in initial reservoir models designed for such fields. Thus, it is difficult to match the production history or identify methods to improve production and reduce associated risks.
The various depositional patterns recognized in channel migration and aggradation packages from the Oligocene Malembo Formation of the Congo Basin, offshore Angola, exhibit different dynamic responses when modelled in a reservoir simulator. These dynamic differences are related to the different preservation rates of bank collapse sediments within isolated channel bodies, hereafter referred to as ‘elementary channels’. According to these preservation differences, the vertical stacking pattern of channels results in better connectivity than the true lateral migration. This effect has been incorporated into a full-field simulation model by applying petrophysical upscaling methods. The recognition and modelling of detailed sedimentological heterogeneities, and their distribution along full-field models produces a better history match when the inherent uncertainties have been taken into account.
Incorporating all available data and concepts to define reservoir architecture is essential in understanding the impact that fine-scale heterogeneities have on reservoir management. As the lateral extent and areal distribution of heterogeneities is still unknown, our modelling workflow incorporates uncertainty in the form of multiple realizations to identify and measure all uncertainties that might impact dynamic response.
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Interaction of the Zagros Fold–Thrust Belt and the Arabian-type, deep-seated folds in the Abadan Plain and the Dezful Embayment,SW Iran
Authors Iraj Abdollahie Fard, Alvar Braathen, Mohamad Mokhtari and Seyed Ahmad AlaviThe Dezful Embayment and Abadan Plain (SW Iran) contain major parts of the remaining Iranian oil reserves. These oil provinces are characterized by two types of structural closure: very gentle N–S- to NE–SW-trending basement-cored anticlines (Arabian-type highs) in the SE; and open to tight, NW–SE-trending thrust-related folds in the NE (Zagros Fold–Thrust Belt; ZFTB). Most deep-seated anticlines are upright and symmetrical in Cretaceous and older units. In some cases they reveal steep faults in their core which, in the light of regional observations, suggest that the basement is involved in the faulting. Untested plays around these anticlines include reefal build-ups, debris flows, truncated sedimentary sections and onlapping clastic units.
The ZFTB shows a classic structural style, with overall shortening reflected in thrust displacement declining from the Dezful Embayment towards the frontal zone in the Abadan Plain. The Early Cambrian Hormuz Salt represents the fundamental sole for the fold–thrust belt and locates major fault-propagation folds in the southwestern Dezful Embayment. These folds represent the main petroleum target of the area. Another important unit is the Mid-Miocene Gachsaran Formation. This detachment reveals both in-sequence and out-of-sequence thrusting. Interaction of deep-seated anticlines and fold–thrust structures results in thrust imbrications and formation of duplexes within the Gachsaran Formation when thrusts abut deep-seated anticlines. Above the crest of the anticlines, thrusts are forced up-section into syn-tectonic deposits, whereas the forelimb reveals out-of-the-syncline thrusts. Several petroleum plays are identified in such zones of structural interaction, including anticlines above buttress-related duplexes, out-of-sequence imbricate thrust fans with associated folds above major anticlines, truncation of footwall layers below potentially sealing thrusts, and sub-thrust anticlines.
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Architecture of Lower Oligocene source rocks in the Alpine Foreland Basin: a model for syn- and post-depositional source-rock features in the Paratethyan realm
Authors R. F. Sachsenhofer and H.-M. SchulzOligocene rocks are one of the most important sources of hydrocarbons within the Paratethyan realm. In the Alpine Foreland Basin (Central Paratethys) the main Oligocene source rock is the Schöneck Formation, but organic-rich rocks occur in the entire Lower Oligocene succession. Based on well-log calibration by core data, the spatial distribution and thickness variations of different Lower Oligocene source-rock facies are investigated. The deeper-water sediments are characterized by lateral continuity, but exhibit vertical variability. The latter reflects major palaeoceanographic changes in the Central Paratethys, such as the closure of seaways, basin-wide changes in salinity and in redox conditions. The upper shaly part of the Schöneck Formation has the highest source potential (>5% TOC, initial HI: 500–600 mgHC g−1TOC) and reaches its maximum thickness (c. 5 m) in a narrow belt parallel to the palaeo-shoreline.
The present-day distribution of Lower Oligocene rocks is controlled by submarine erosion which affected the northern passive slope of the foreland basin. Erosion climaxed during the late Early Oligocene. The eroded material was re-deposited along the lower basin slope (Oberhofen facies). The source-rock potential of the re-deposited sediments is relatively low. The oil kitchen (4–7 km burial depth) is located beneath the Alpine nappes where the Lower Oligocene succession was removed locally by the advancing nappes. Both submarine erosion at the northern basin slope and tectonic erosion beneath the Alps have to be considered in the evaluation of the prospectivity of the basin.
Because deposition of the Lower Oligocene succession in the Alpine Foreland Basin is controlled by basin-wide processes, it may serve as a model for source- rock deposition in foreland basins of the Paratethyan realm (e.g. Carpathians, Terek–Caspian Foredeep).
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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)