bluuebunny/crossref_metadata_2025_split huggingface dataset:
The structural geology of the High Central Zagros revisited (Iran)
Authors: Bosold A. , Schwarzhans W. , Julapour A. , Ashrafzadeh A. R. , Ehsani S. M. 
Published: October 2008

The main purpose of this study in the High Central Zagros area near the townships of Lordegan and Yasuj was to investigate the nature of the High Zagros Fault (HZF) and the structural styles in the adjacent foreland. A second task was to determine whether the prolific petroleum plays productive further out in the Zagros Foreland would extend into the study area and if new petroleum plays could be recognized.
Two selected cross-sections across and one just behind the HZF provide evidence for its overthrust nature. In some places the HZF exhibits a low-angle thrust plane, locally with a substantial amount of thrusting over the foreland. The interpretation is based on surface geological mapping, available well data, remote sensing from satellite data, aeromagnetic and high resolution gravimetry data, magnetotelluric, WARRP (wide angle reflection refraction profiling) and reflection seismic data. The integration of this unique set of newly acquired geophysical data complements recently published papers, which were based more on surface geology and rather limited subsurface data. The data were integrated to construct a regional balanced cross-section and to develop structural petroleum play concepts for the area investigated.
Play potential may exist both in the overthrust terrain of the High Zagros as well as in the subthrust. Analysis of the width of the surface anticlines (or more precisely: their frequency) gives a first indication of the depth of the décollement plane. Within the adjacent Zagros Foreland evidence was found for the presence of multiple detachment planes above the ubiquitous deep Hormuz level, i.e. at the level of the Kazhdumi and the Pabdeh–Gurpi Formations. These intermediate décollement planes are thought to be responsible for the generation of deeper structural plays unrelated to the structuring that can be observed at the surface.
Geochemical characterization of a Cretaceous black shale from the Mamfe Basin, Cameroon
Authors: Eseme E. , Littke R. , Agyingi C. M. 
Published: October 2008

Shale from Cretaceous strata of the Mamfe Basin has been characterized by petrological and geochemical techniques. The aims of this study were to assess the quality of its organic matter, evaluate its thermal evolution and highlight its potential as a source rock. The total organic carbon (TOC) (4.45 wt%) of the shale constitutes that of a good source rock with oil-prone kerogen indicated by Rock-Eval S2/S3 (26.1). The low oxygen index (OI) (8 mgCO
2
g
−1
TOC), pr/ph (1.79) and high gammacerane index (22) suggest deposition in a highly saline reducing environment. The
n
-alkane distribution dominated by
n
-C
15
and infrared spectrum dominated by aliphatic and aromatic functional groups are considered to be indicators of Type II kerogen. The CPI (1.1),
T
max
(441° C), C
31
(S/S+R) ratio (0.6), Rr (0.7%) and MPI-1 (0.6) all indicate the maturity of this rock. This thermal evolution is thought to account for its current hydrogen index (HI) (222 mgHC g
−1
TOC). Expulsion may have occurred before uplift and erosion but a more elaborate study is required to evaluate the petroleum systems of the basin.
The development of Middle Cretaceous carbonate platforms, Persian Gulf, Iran: constraints from seismic stratigraphy, well and biostratigraphy
Authors: Farzadi Pourdad 
Published: October 2008

In the Iranian Persian Gulf several fields have been producing oil from Middle Cretaceous carbonates. Geological studies of these fields (limited to industry reports) describe the subsurface using lithostratigraphic principles. Lithological boundaries are obvious and are the focus for the correlation of the interwell areas. Most of the structural highs, which were easily found, have been drilled. The lack of a sufficiently detailed seismic sequence stratigraphic analysis has precluded the definition of reliable models at both regional and field scales.
The development of many oil and gas fields requires seismic sequence stratigraphy as a predictive technique, particularly in areas between drilled structures. This study aims to re-evaluate the field-scale stratigraphy in an oil field in the southern Persian Gulf using these techniques. The high quality seismic and well data from this field form one of the first datasets of this kind presented in the literature. High-resolution seismic data reveal the internal complexity of carbonates. The Cenomanian carbonate systems of the southeastern Persian Gulf reveal internal architecture and subsurface variability that neither seismic nor well data alone can provide. This paper analyses the seismic character of the Cenomanian Khatiyah and Mishrif formations and discusses how, even after more than 25 years of production, application of sequence stratigraphic principles can improve the understanding of an oil field. For this oil field, the combination of seismic, wireline logs and biostratigraphy has allowed a better understanding of the internal heterogeneity of the Mishrif reservoir. Understanding the successive stages of drowning and back-stepping of a carbonate platform within this reservoir unit has important implications for well planning and further reservoir development.
Important new information on the depositional geometries has also been obtained from within the Khatiyah Formation (the regional source rock) which leads to exploration targets in the interwell area. This information gives new insights as to the stratigraphic distribution and internal variability of the carbonate platforms and isolated build-up geometries. The insights gained are important to the estimation of reservoir volume, connectivity and variability.
Reservoir-scale characterization and multiphase fluid-flow modelling of lateral petrophysical heterogeneity within dolomite facies of the Madison Formation, Sheep Canyon and Lysite Mountain, Wyoming, USA
Authors: Pranter Matthew J. , Reza Zulfiquar A. , Budd David A. 
Published: October 2008

Carbonate reservoirs often exhibit complex pore networks and various scales of petrophysical heterogeneity associated with stratigraphic cyclicity, facies distribution and diagenesis. In addition, petrophysical variability also exists within distinct rock fabrics at the interwell scale. Data from lateral transects through dolomitized carbonates of the Mississippian Madison Formation in north and central Wyoming exhibit three scales of lateral petrophysical variability. These include a near-random component (nugget effect), short-range variability and a long-range periodic trend (hole effect) that is observed in both dolowackestone (Sheep Canyon) and dolograinstone (Lysite Mountain) facies. The dolowackestone represents outer and middle ramp mud-supported fabrics, while the dolograinstone represents amalgamated skeletal and oolitic shoals.
Detailed 3D petrophysical models of the dolomite facies and 2D multiphase waterflood simulations explore the effects of this heterogeneity on reservoir performance through several model scenarios. Fingering of the injected fluid front, sweep-efficiency, breakthrough time and bottom-hole well pressures are sensitive to lateral reservoir heterogeneity and rock fabric. Models with greater short-scale continuity of petrophysical properties have higher degrees of large-scale fingering, higher sweep efficiency and shorter breakthrough times. The reservoir performance of the dolowackestone differs from the dolograinstone for those models that exhibit a specific range of short-scale heterogeneity. In general, the dolowackestone has a higher degree of both small- and large-scale fingering, lower sweep efficiency and longer breakthrough time compared with the dolograinstone.
Intra-facies scale variability is significant in regard to reservoir performance and is often difficult or impossible to determine from typical subsurface datasets. Information from outcrop analogues is necessary to create conceptual 3D geological models and to begin to quantify interwell heterogeneity within dolomite reservoirs.
Sequence stratigraphic-based analysis of reservoir connectivity: influence of sealing faults – a case study from a marginal marine depositional setting
Authors: Ainsworth R. Bruce 
Published: October 2008

This case study of the Sunrise and Troubadour fields (offshore northwest Australia) deals with the impact of sealing faults on reservoir connectivity via a sequence stratigraphic-based, 3D reservoir modelling approach. The marginal marine, wave- and fluvial-dominated reservoir succession was subdivided into sequence stratigraphic units. The connectivity of sandbodies in each parasequence was calculated, following a palinspastic restoration of the 3D models to a depositional datum (depositional connectivity). Once the top structure and fault architecture interpreted from seismic data were incorporated into the 3D models, sandbody connectivity was again calculated on the same stratigraphic basis, with the faults being considered sealing (structural connectivity). The impact on sandbody connectivity of additional, probabilistic, sub-seismic sealing faults was also analysed.
The results indicate that the depositional architecture is the controlling factor on reservoir connectivity for low sealing fault densities. However, at a critical sealing fault density, the major control becomes the structural architecture. Using the approach detailed in this paper, relationships between sealing fault density and reservoir connectivity for different development well layout scenarios can be predicted as a basis for optimizing development well patterns.
Depositional environment and source potential of Jurassic coal-bearing sediments (Gresten Formation, Höflein gas/condensate field, Austria)
Authors: Sachsenhofer R. F. , Bechtel A. , Kuffner T. , Rainer T. , Gratzer R. , Sauer R. , Sperl H. 
Published: October 2008

Coal-bearing Jurassic sediments (Gresten Formation; Lower Quartzarenite Member) are discussed as source rocks for gas and minor oil in the basement of the Alpine–Carpathian frontal zone (e.g. Höflein gas/condensate field). Core material has therefore been analysed to characterize depositional environment and source potential of the Lower Quartzarenite Member (LQM). Geochemical data from the Höflein condensate are used to establish a source–condensate correlation.
The LQM was deposited in a flood basin with transitions to a delta-plain environment. Coal originated in frequently flooded mires and evolved within an oxygenated and acidic environment. It is inferred from geochemical data that organic matter from aquatic macrophytes and gymnosperms contributed to coal formation. Wildfires were abundant and oxidation of plant remains occurred frequently. This resulted in the formation of dull coal with very high inertinite contents. Bituminous shales were formed in deeper waters under dysoxic conditions. Apart from abundant algae and micro-organisms, it is concluded that there was an increased contribution of higher land plants relative to macrophytes to the biomass of the shales.
Despite high inertinite contents, coal within the LQM has a significant oil potential. Bituminous shales contain a Type III–II kerogen. According to pyrolysis–gas chromatography data, coal and shale generate a high wax paraffinic oil. The organic matter is immature to marginal mature (0.55% Rr). Bituminous shales are considered a potential source for the Höflein condensate. Coal may be the source for gas and minor oil in the Klement Field, but is not the source for the condensate. The equivalent vitrinite reflectance of the condensate is 0.8%, suggesting condensate generation at 4–4.5 km depth. The Gresten Formation reaches this depth near its depocentres, implying southward-directed migration of the Höflein condensate.
Implicit net-to-gross in the petrophysical characterization of thin-layered reservoirs
Authors: Scaglioni Paolo , Ruvo Livio , Cozzi Mauro 
Published: October 2008

A 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.
Three-dimensional modelling of stacked turbidite channels inWest Africa: impact on dynamic reservoir simulations
Authors: Labourdette Richard , Poncet Jérôme , Seguin Julien , Temple François , Hegre JoAnn , Irving Alan 
Published: October 2008

The 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.
How depositional texture and diagenesis control petrophysical and elastic properties of samples from five North Sea chalk fields
Authors: Fabricius Ida L. , Røgen Birte , Gommesen Lars 
Published: October 2008

Chalk samples from Dan, Tyra, South Arne, Valhall and Ekofisk fields were collected from hydrocarbon-bearing intervals in the Cretaceous Tor and Palaeogene Ekofisk formations in the central North Sea. The samples were compared with respect to stable isotope ratios, lithotype, texture, porosity, permeability, capillary entry pressure, as well as the dynamic elastic Biot's coefficient and Poisson's ratio. The depositional texture and present grain-size distribution were quantified by petrographic image analysis. Oxygen isotope ratio and Biot's coefficient were used as indicators of cementation.
Porosity varies more than 20 porosity units within each hydrocarbon field and is controlled by three parameters: (1) sorting as expressed by Dunham texture, so that mudstones tend to have highest porosity and packstones the lowest; (2) sorting of the carbonate mud, where a mixture of clay-size chalk particles and silicates tend to reduce porosity; and (3) by pore-filling cementation. The relative significance of these parameters varies with field and formation. The presence of chalk clasts as an indicator of re-deposited chalk seems to have no relationship to porosity. Permeability and capillary entry pressure depend on porosity and mineral content as expressed in specific surface. Prediction of permeability and capillary entry pressure may be aided by information on carbonate content or on Poisson's ratio.
Diagnosis of the Upper Cretaceous palaeokarst and turbidite systems from the Iranian Persian Gulf using volume-based multiple seismic attribute analysis and pattern recognition
Authors: Farzadi Pourdad , Hesthammer Jonny 
Published: October 2008

Depositional facies variability with a secondary overprint of Turonian palaeokarst controls the quality of the Cenomanian Mishrif reservoir, the main oil producer in the southeastern Persian Gulf. Subsequent drowning of the prominent area and successive deepening of the basin during the Coniacian and Santonian enabled the deposition of pelagic marls of the Coniacian Laffan Formation and the development of a carbonate turbidite system within the overlying Santonian Ilam Formation. The Ilam Formation occurs within slope and pelagic carbonates and consists of oil-bearing channel-reworked limestone facies.
Although high-quality 3D seismic data exist over the Sirri C/D oil fields studied in this paper, it is a real challenge to map the palaeokarst and turbidite deposits in 3D space using conventional seismic interpretation procedures.
This work describes a procedure using Paradigm's Seisfacies software for seismic facies classification and uses this to develop a volume-based interpretation of palaeokarst geobodies and sedimentary patterns of the carbonate turbidite. A hierarchical facies classification technique combined with principal component analysis (PCA) is used to analyse a set of seismic attribute volumes that capture the seismic stratigraphic patterns inherent in the data. PCA as a data reduction algorithm greatly optimized the analysis of the attribute volumes while preserving the essential features of seismic character. A hierarchical facies classifier recognized enough variability within the seismic data to reveal details of the associated geological features. This classification method uses multiple 3D volume attributes as input and generates a single 3D seismic facies volume (a synthesis of different attributes). Using this method, interpretative work can focus directly on geological features in 3D space. This study gives new insights into the internal variability of palaeokarst and carbonate turbidite systems in the Sirri C/D oil fields (SE Persian Gulf) that are essential for the estimation of reservoir volume, connectivity and variability.
The importance of constraining regional exhumation in basin modelling: a hydrocarbon maturation history of the Ghadames Basin, North Africa
Authors: Underdown R. , Redfern J. 
Published: October 2008

Estimation of eroded overburden at unconformities is essential to accurately constrain burial histories and predict the timing of hydrocarbon maturation. In the Ghadames Basin, three independent techniques, palaeo-isopach construction, sonic velocity and vitrinite reflectance analysis, were employed. The resultant basin model suggests that only the two most significant unconformities, the Hercynian (Late Carboniferous) and Alpine (early Eocene), have a major control on timing of hydrocarbon charge.
Modelling indicates only one period of generation from the Lower Silurian shales on the western margin of the basin, with 95% hydrocarbon generation prior to Hercynian exhumation. The central basin and southern margin experienced maximum burial during Eocene time. The Middle–Upper Devonian mudstones are the main source rocks and they did not generate significant volumes of hydrocarbons over the basin centre until Cretaceous time; they are currently within the peak oil generation zone.
In Libya, on the eastern/northeastern flank of the basin, results indicate Cenozoic maximum burial, followed by up to 2000 m of Alpine exhumation. The magnitude of this exhumation has not been recognized previously, although it is a critical component of the basin model as it has a major impact on potential hydrocarbon charge in this area. Maturation models predict that the Lower Silurian source underwent two generative phases: (1) pre-Hercynian (Carboniferous) generation; and, significantly, (2) post-Hercynian (Late Jurassic–Cenozoic) generation. The identification of late hydrocarbon generation offers potential for oil and gas to migrate into post-Hercynian traps. Over the western, northern and eastern flanks, the Devonian source rocks remain immature/ marginally mature at present day.
Sensitivity of fluid flow to fault core architecture and petrophysical properties of fault rocks in siliciclastic reservoirs: a synthetic fault model study
Authors: Fredman Niclas , Tveranger Jan , Semshaug Siv , Braathen Alvar , Sverdrup Einar 
Published: October 2008

Fluid flow simulation models of faulted reservoirs normally include faults as grid offset in combination with 2D transmissibility multipliers. This approach tends to oversimplify the way effects caused by the actual 3D architecture of fault zones are handled. By representing faults as 3D rock volumes in reservoir models, presently overlooked structural features may be included and potentially yield a more realistic description of structural heterogeneities. This paper investigates how a volumetric fault zone description, will affect fluid flow in simulation models.
An experimental 3D model grid including a single normal fault, defined as a volumetric grid, was constructed. Subsequently, the fault grid was populated with two conceptual fault deformation products – sand lenses and fault rock – using an object-based stochastic facies modelling technique. In order to evaluate the effect of varying petrophysical properties, fault rock permeability and sand lens permeability were varied deterministically between 0.01 mD and 1 mD and 50 mD and 500 mD, respectively. The impact of fault core architecture was investigated by deterministically varying sand lens fraction and sand lens connectivity. This yielded 24 model configurations, executed in 20 stochastic realizations each. Fluid flow simulation was performed on 480 model realizations.
Simulation results show that the most important parameters influencing fluid flow across the fault were fault rock matrix permeability, and whether or not the sand lenses were connected to the undeformed host rock. Sand lens permeability and sand lens fraction turned out to be less important for fluid flow than fault rock matrix permeability and sand lens connectivity.