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Outcrop photograph of hydrothermal dolomite (darker brown). Note dolomitised fault zone in photograph centre, and stratabound dolomites pinching out to right and left.
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The possibility of using complex information on morphological parameters of structures, block porosity and the reservoir pressure gradient over previously explored deposits for the development of a multidimensional equation for estimating secondary porosity is considered. This is examined by the example of reservoirs with secondary (fractured) poro...
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The Permian-Cretaceous Polish Basin belonged to the system of epicontinental depositional basins of Western and central Europe and was filled with several kilometers of siliciclastics, carbonates, and also thick Zechstein (Upper Permian) evaporites. The Polish Basin was inverted in Late Cretaceous-Paleocene times. Presence of the Zechstein evaporit...
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Citations
... Conventional reservoirs typically occur within grainy rudist-rich carbonates developed at the margins of intrashelf basins (Jordan et al., 1985;Burchette and Britton, 1985;Burchette, 1993;Perrotta et al., 2017). The reservoir properties of the Mishrif carbonates may be enhanced as a result of karstification and meteoric diagenesis (Wagner, 1990;Sharp et al., 2010;Hajikazemi et al., 2017;Malekzadeh et al., 2020), fracturing and/or dolomitisation (Sharp et al., 2006;Lapponi et al., 2011). ...
... In these instances, diagenesis and/or fracturing may improve reservoir quality and compensate for relatively low primary matrix permeability (Taghavi et al., 2006;Hollis et al., 2011), and reservoirs with high primary reservoir quality may also be enhanced by these secondary processes (Cantrell et al., 2020;Majeed et al., 2021). Tectonic fracturing may result in a dual permeability system which in turn may promote subsequent dolomitization by providing pathways for hydrothermal fluids (Sharp et al., 2006(Sharp et al., , 2010Lapponi et al., 2011). Hydrothermal dolomites commonly enhance reservoir quality but are not stratigraphically predictable (Sharp et al., 2010). ...
In order to facilitate the search for new play concepts and exploration opportunities, a sequence stratigraphic synthesis of the Cenomanian-Turonian interval of the Arabia Plate has been compiled. The synthesis is based on published datasets which have been analysed within a temporal framework constrained by biostratigraphy and isotope stratigraphy. The high stratigraphic resolution allows the palaeogeography of the study area to be mapped within 3rd order depositional sequences, and the relative influence of eustasy and tectonics on basin development to be evaluated. This significantly improves the prediction of stratigraphic architecture and depositional morphology at the scale of the entire tectonic plate.
Conceptual models informed by outcrop and subsurface observations have been applied to characterize the development of intrashelf basins in depositional settings that are either isolated from siliciclastics (symmetrical intrashelf basin model) or influenced by siliciclastics (asymmetrical intrashelf basin model). The application of a sequence stratigraphic model across regional well log transects facilitates an understanding of stratigraphic architecture and acts as an important control for the generation of a new suite of gross depositional environment (GDE) maps. These characterise palaeogeography at previously unprecedented resolution and scale during periods of high relative sea-level (maximum flooding surface and highstand systems tract) and low relative sea-level (lowstand systems tract). These maps are complemented by sequence isopachs which reveal changes in accommodation through time and space.
This approach helps characterize the preserved distribution and stratigraphic configuration of petroleum systems elements. In the Shilaif (UAE) and Natih (Oman) intrashelf basins, condensed, organic-rich carbonate source rocks were deposited in restricted, anoxic conditions. These basins resulted from differential aggradation of the carbonate platform during the transgressive systems tract. Grainy, rudist debris-rich carbonate reservoir rocks developed along the margins of the intrashelf basins during highstand progradation. Claystones in the overlying sequence may form intraformational seals and were deposited during retrogradation of the shoreline associated with sea-level rise.
By contrast in the Najaf intrashelf basin (Iraq), there is a significant siliciclastic component sourced from the Arabian Shield. This influx resulted in a mixed carbonate-siliciclastic ramp depositional system on the proximal, western margin of the basin, and an apparent absence of organic-rich intervals within the central basin succession. Grainy carbonate reservoir rocks are restricted to the eastern margin and are charged by older source rocks within the underlying stratigraphy.
The GDE maps record the configuration of these petroleum systems elements within the Cenomanian-Turonian interval and forms the basis for play screening. The Cenomanian-Turonian interval is punctuated by the major mid-Turonian unconformity which is a major tectonostratigraphic boundary of considerable geological and economic significance. In the southern and eastern part of the Arabian Plate, this unconformity has a differential erosion profile that facilitates a subcrop play with exploration potential. Identifying subtle stratigraphic traps is challenging, but by combining GDE facies with the mapped preservation limit for each sequence, it is possible to identify areas where rudist-rich reservoir facies with potential karst enhancement are overlain by a regional claystone seal, high-grading areas with subcrop trap potential.
... Two methods were employed to reflect the natural variability in the location and volume of dolomitized debris flows observed in the field. The first method, following Sharp et al. (2006) used a percentage to populate a certain volume of the R-1 facies. The percent dolomitized bodies were calculated from logs (23%); however, the results were found to underestimate the number of dolomitized R-1 facies, based on comparison with field photographs. ...
Constructing geocellular models of carbonate rocks using standard software is challenging since most of modelling packages are designed, first and foremost, to represent siliciclastic depositional systems, where rock properties are strongly facies-controlled. The distribution and components of carbonate depositional facies vary drastically across the geological timescale as a result of paleoclimate and its effects on carbonate-producing biota. Furthermore, reservoir architecture is less strongly controlled by depositional environment than in clastic settings, and rock physical properties, including fracture networks, are controlled by both primary components and their subsequent diagenetic alteration. This means that rock property distribution is less predictable than in siliciclastic systems, and less well represented by geocellular models that are designed to represent sedimentary architecture. In other words, in carbonate systems, the depositional and diagenetic history needs to be reconstructed in order to successfully model reservoir properties.
In this study a geocellular model was created by using a well-characterised outcrop analogue obtained from the Hammam Faraun Fault (HFF) Block, located on the eastern coast of the Gulf of Suez in Sinai, Egypt. This model integrates sedimentological, petrophysical, diagenetic, and structural information into a single database. The workflow utilizes the regional tectonic history, upscaled lithological logs, and two-stage facies modelling (reflecting in and ex situ depositional facies) and resulted in the creation a realistic model of remobilized carbonates that were deposited on the slope of a carbonate platform during a period of tectonic instability. Diagenetic overprinting was achieved using probability functions to reflect the history of burial, rifting, and the spatial relationship of stratabound and non-stratabound dolostone bodies. The study demonstrates a workflow for modelling mass-transport carbonate facies and multistage fault-related diagenesis so that flow controlling facies and diagenetically altered poroperm and fracture networks are accurately represented using commercially available modelling software, and in particular demonstrates how diagenetically controlled geobodies can be captured using simple algorithms.
... fracture length and cross-cutting relationships. Therefore outcrop studies have been used to improve our understanding of fracture formation and the spatial distribution of fractures (e.g.Aydin 2000;Sharp et al. 2006;Awdal et al. 2013).Gutmanis et al. (2017)present an outcrop study of Cretaceous carbonates in anticlines in the foreland of the Catalan Pyrenees. The paper illustrates the importance of heterogeneity and the variable connectivity of open fractures. ...
This volume examines the current best practice and new challenges in reservoir characterization and modelling of small- to subseismic-scale deformation features through case studies, experimental results and modelling. The papers in this volume include contributions on four themes related to the small-scale deformation of hydrocarbon reservoirs: the characterization of deformation in porous sandstones; novel characterization techniques; quantifying and characterizing deformation in carbonates; and modelling small-scale features. It includes eight papers from the conference Small to Subseismic-Scale Reservoir Deformation, organized by the Petroleum Group of the Geological Society and held in London from 29 to 30 October 2014, plus two additional papers. The observations in this introduction reflect the authors’ experiences and opinions, presentations at the conference and the papers within this volume.
... Fracture patterns are difficult to characterize from well data, such as core and image logs, and therefore outcrop analogues are commonly used in fractured reservoir studies (e.g. Sharp et al. 2006;Wennberg et al. 2006Wennberg et al. , 2007. Outcrop analogues are particularly useful for the understanding of fracture formation, definition of fracture sets and their relative spatial distribution. ...
... Both of these units represent producing reservoirs in the subsurface a few kilometres away from the outcrops. These outcrops illustrate several important aspects of fracture pattern in carbonates in anticlines (Sharp et al. 2006;Wennberg et al. 2006;Casini et al. 2011). Folds and hydrocarbon traps in SW Iran were mainly formed during the formation of the Cenozoic Zagros fold and thrust belt. ...
Permeability in fractured carbonate reservoirs is very heterogeneous due to fracturing at different scales superimposed on inherent textures from deposition and diagenesis. Observations of fractures in core and outcrop indicate that flow in open fractures in carbonate rock tends to be channelled rather than through fissures. Most of the flow takes place along a few dominating channels in the fracture plane, whereas most of the fracture plane is not effective for fluid flow. The formation of flow channels is caused by a combination of mechanical and, in particular, diagenetic processes. Single extension fractures occur as partly open or vuggy fractures, and their hydraulic properties are controlled by dissolution and cementation. Single shear fractures are typically open at local steps in the fault plane controlled by shearing along irregular fracture surfaces. Fault damage zones tend to be concentrated at fault tips, intersections, pull-aparts and overlap zones that represent areas of dilation. These damage zones represent elongated features in three dimensions with a high fracture density that will result in channelled flow at reservoir scales. The effect of channelled flow should be taken into account during evaluation of fractured carbonate reservoirs and when building dynamic flow models.
... The occurrence of highly permeable fracture corridors in wells are of concern because they may cause early water breakthrough, as demonstrated by numerical analysis by Jonoud et al. (2011). In this context, careful use of scaled outcrop data can, to some extent, improve reservoir modelling and constrain uncertainties (Sharp et al. 2006. ...
... Fracture patterns are difficult to characterize from well data, such as core and image logs, and therefore outcrop analogues are commonly used in fractured reservoir studies (e.g. Sharp et al. 2006;Wennberg et al. 2006Wennberg et al. , 2007. Outcrop analogues are particularly useful for the understanding of fracture formation, definition of fracture sets and their relative spatial distribution. ...
... Both of these units represent producing reservoirs in the subsurface a few kilometres away from the outcrops. These outcrops illustrate several important aspects of fracture pattern in carbonates in anticlines (Sharp et al. 2006;Wennberg et al. 2006;Casini et al. 2011). Folds and hydrocarbon traps in SW Iran were mainly formed during the formation of the Cenozoic Zagros fold and thrust belt. ...
Fractured carbonate reservoirs are commonly extremely heterogeneous. This heterogeneity is caused by fracturing at multi scales superimposed on inherent textures from deposition and diagenesis. In addition, there is an interrelationship between diagenesis and fracture formation, e.g. the matrix properties may change due to reactions with fluids provided by the fracture network or fractures are filled with calcite cement. The aim of this study is first to describe individual fractures and the fracture network of some typical fractured carbonate reservoirs, and secondly to discuss their importance for fluid flow in the reservoir. Finally, it will be outlined how these findings should be incorporated into static and dynamic reservoir models. Traditionally fluid flow in fractured reservoirs is simulated using dual porosity or dual porosity/dual permeability formulation based on the work of Warren and Root (1963). Each cell in the simulation models is typically 100*100*10m and characterized by one value of fracture permeability (tensor) and one fracture porosity. The matrix-fracture fluid exchange is described using a transfer function which is commonly regarded to be proportional via shape factor to the block-size, which is kept constant within one simulation cell. However, this simplistic image of a fractured reservoir only partly captures the internal fracture features and fracture network geometry as observed in core or outcrop analogues of reservoir rocks. Firstly, the majority of fractures in core are only partly open. This implies that flow within fractures will tend to be channelized instead of fissure type flow. Furthermore, the parts of the fracture which are open do show a variable amount of calcite cement between the matrix and the open void. The calcite cement on the fracture planes inhibits transfer of fluid between matrix and fracture. This implies that the fracture matrix transfer function is not only controlled by the geometry of the matrix blocks, but also by the area of the fracture plane, adjacent to the matrix block, which is not coated with cement. Finally, the fracture fill form bridges between the two sides of the fracture will keep the fractures open during pressure depletion in the reservoir. Layering and bed parallel stylolites do also have a significant effect on fracture network geometry as fractures commonly terminates against these features. The combination of stylolites and open fractures do result in complicated flow patterns as demonstrated by use of CT-scan monitoring of gas flooding experiments of core samples (Wennberg et al 2009) Outcrop studies in the Zagros of SW Iran show that several fracture sets coexist in anticlines which are outcrop analogues to hydrocarbon fields in the area. The fractures generate very complex fracture network geometries and four distinct fracture sets have been recognized. Set A and B are parallel and perpendicular to the fold axis respectively. Set C and D are oblique and symmetric to the fold axis. The presence of more than 2 fracture sets implies that the matrix block in general has a non-rectangular shape. It is well known that fracture spacing is dependent on the mechanical stratigraphy, i.e. the spatial variation in mechanical properties due to changes in lithology or other matrix properties. The mechanical stratigraphy is controlled by the depositional environment and subsequent diagenesis. In this study the distribution of fracture spacing have been investigated using the coefficient of variance (Cv) which is the standard deviation divided by the average fracture spacing (Gillespie et al. 2001). Cv equals 0 for a regular spacing, Cv equals 1 for random spacing distribution and Cv > 1 implies clustering of fractures. Fracture spacing investigated in Cretaceous and Tertiary outcrops of reservoir analogues is not regular as shown by a coefficient of variance ranging between 0.4 and 2. The majority of Cv values are close to 1 i.e. the fracture spacing do dominantly have a random distribution. Hence, both the shape and the size of matrix blocks do indeed have large variation within a rock volume equivalent of a simulation model cell. Both the distribution of cement within a fracture and the fracture spacing characteristics described above will have an important impact on the fluid flow and recoverable reserves in fractured reservoirs. Hence, these characteristics should be taken into account when building reservoir models and when analysing the results of the simulation model. Furthermore, the observations above demonstrate the importance of an integrated multi-disciplinary study of fractures characterization and modelling. Improving static modelling, followed by dynamic simulation, of naturally fractured reservoirs, requires involvement of all disciplines including sedimentology, diagenesis, structural geology, petrophysics, geophysics, well test analysis, core analysis and reservoir engineering as well as drilling and production engineering.
References:
Gillespie, P.A., Walsh, J.J., Watterson, J., Bonson, C.G. and Manzocchi, T. 2001. Scaling relationships of joints and vein arrays from The Burren Co, Clare, Ireland. Journal of Structural Geology 23, 183-201.
Warren, J.E and Root, P.J. 1963. The behaviour of naturally fractured reservoirs. SPE-426-PA.
Wennberg, O.P., Rennan, L., Basquet, R. 2009. CT-Scan imaging of natural open fractures in a porous rock geometry and fluid flow. Gephysical Prospecting 49, 239-249.
