bluuebunny/crossref_metadata_2025 huggingface dataset:
Productivity evaluation of hydraulically fractured gas-condensate reservoirs
Authors: Zheng Shi-Yi , Zhiyenkulov Murat , Yi TongChun
Published: October 2008

This study describes an application of a compositional single well simulator to analyse well tests in gas-condensate reservoirs. An important aspect of this application for gas-condensate well tests is accurate fluid property prediction during the multi-phase flow regime, which occurs in the near-well region. The simulator can also be used to understand the impact of liquid drop-out and fracture flow on well productivity.

Hydraulic fracturing improves the economics of wells drilled in tight reservoirs. However, the operation involves a significant amount of expenditure. In recent years this technique has also been used to stimulate gas-condensate reservoirs by creating a flow conduit through the condensate banking near the well. Thus, it is crucial to keep a fracture as small as possible. In practice it has been proved that a short, wide fracture can provide much higher production than the traditionally pursued narrow, long fracture.

The workflow in this study contains compositional simulation of a single well in a tight gas-condensate reservoir, which is used to generate transient pressure data for well test analysis and interpretation to predict multi-phase flow behaviour, and to analyse productivity impairment due to condensation. Simulation models were then further modified to study the impact of various hydraulic fractures on the well productivity index (PI), which is defined as the ratio of production rate (constant) divided by the pressure drop across the reservoir. PIs for fractured cases are compared with respect to the non-fractured base case. Streamline simulation of the fractured gas-condensate reservoir was also included in the study to allow visualization of the flow profile in and around the hydraulic fracture.
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.
The effect of hydrocarbons on quartz cementation: diagenesis in the Upper Jurassic sandstones of the Miller Field, North Sea, revisited
Authors: Aase Nils Einar , Walderhaug Olav
Published: October 2008

Variable quartz cementation and porosity distribution in the Upper Jurassic Brae Formation deep-water sandstone reservoir of the Miller Field (UK, North Sea) is mainly controlled by the amount of coatings on the quartz grains. Oil was possibly present in the pore space for the last 40 Ma, but had no significant effect on preserving porosity in the oil leg relative to the water leg. Samples with anomalously high porosities, which commonly occur in the shallowest sandstone intervals, are microquartz coated, and it is a misinterpretation to explain these high porosities as due to hydrocarbons inhibiting quartz cementation. Porosity preservation due to microquartz coating is quite common in Upper Jurassic sandstones in the North Sea. Kinetic modelling of quartz cementation with the Exemplar program correctly predicts observed quartz cement volumes in the Brae Formation outside the microquartz-coated zones, when high quality petrographic data, including abundance of clay coatings, are provided as input. Significant overprediction of quartz cement volumes occurs only for samples where scanning electron microscope analysis shows microquartz coatings to be present. Failure to recognize grain coating as one of the major parameters controlling quartz cementation may lead to incorrect geological models of reservoir quality and selection of inappropriate exploration or production strategies.
Tectono-thermal evolution of the Junggar Basin, NW China: constraints from R
o
and apatite fission track modelling
Authors: Nansheng Qiu , Ming Zha , Xulong Wang , Haibo Yang
Published: October 2008

The thermal evolution of the Junggar Basin, northwest China, was evaluated based on the thermal modelling results of 59 wells by using vitrinite reflectance (R
o
) and apatite fission track (AFT) data. The thermal history indicates a cooling process of the basin since the Permian, but some differences in thermal evolution existed among the six structural units of the basin due to tectonic movements. The Junggar Basin was a ‘hot basin’ during the Permian, after which a cooling process with normal heat flow values occurred during the Mesozoic. Then the basin became a ‘cool basin’ from the beginning of the Tertiary. The average heat flow of the whole basin was 80 mW m
−2
at the beginning of the Permian, then it decreased to 68 mW m
−2
at the end of the Permian, to 63 mW m
−2
at the end of the Triassic, 55 mW m
−2
at the end of the Jurassic, 50 mW m
−2
at the end of the Cretaceous and 42 mW m
−2
at the present day.

The heat flow distribution of the basin at different geological times also shows the thermal evolution characteristics of the Junggar Basin. At the beginning of the Permian, the highest heat flow, 85 mW m
−2
, occurred in the central basin and the eastern part of the basin, but the lowest heat flow was distributed along the southern and western basin margins, down to 70 mW m
−2
. The heat flow values were between 45 mW m
−2
and 65 mW m
−2
at the end of the Jurassic, with the lower value of 45 mW m
−2
at the southern basin margin. The highest heat flow value again occurred at the southern end of the Luliang Uplift, at the northern part of the Central Depression and at the Eastern Uplift area during that period. At the end of the Cretaceous, it was down to 40–55 mW m
−2
. The lowest heat flow occurred at the Southern Margin and in the Wulungu Depression, and the highest value in the Eastern Uplift area.

The tectonic subsidence also supports this thermal evolution of the basin. The rapid decrease of heat flow during the Tertiary in the Southern Margin of the basin may be caused by the uplift of the Tianshan Mountain. These heat flow data can provide useful parameters for the study of the Junggar Basin. Palaeoheat flow data are the critical parameter for hydrocarbon generation calculations. The results of this study provide a foundation for hydrocarbon generation history modelling and petroleum resource assessment in the Junggar Basin, which are important factors in the exploration of the Wulungu Depression and the study of stratigraphic and subtle traps in the Central Depression.
Unstructured 3D gridding and upscaling for coarse modelling of geometrically complex reservoirs
Authors: Prévost Mathieu , Lepage François , Durlofsky Louis J. , Mallet Jean-Laurent
Published: October 2008

The generation of accurate and reliable unstructured 3D models for reservoir simulation remains a challenge. In this paper, new developments for grid generation, upscaling and streamline simulation for such models are described. In combination, these techniques provide a prototype workflow for the construction of unstructured simulation models. The grid generation framework described here allows the incorporation of both geometrical constraints and grid-resolution targets. Flow adaptation of the unstructured grid (i.e. higher grid density in key regions) is accomplished through the use of single-phase flow calculations on the underlying geocellular grid, which are used to generate target grid resolution maps for the unstructured coarse model. A novel transmissibility upscaling procedure is introduced to capture the effects of fine-scale heterogeneity. A new method for streamline simulation on unstructured grids is also introduced. This technique provides an efficient flow-based diagnostic for the assessment of the coarse simulation model in terms of flow response. The performance of the various components of the methodology is demonstrated using several examples.
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.
Elasticity/saturation relationships using flow simulation from an outcrop analogue for 4D seismic modelling
Authors: Kirstetter Olivier , Corbett Patrick , Somerville Jim , MacBeth Colin
Published: October 2008

Three production scenarios have been simulated for three displacement mechanisms using three lithofacies models built at two scales (fine and coarse) from a 2D outcrop analogue. Analysis of the flow simulation results and the associated seismic modelling investigate the dependence of the time-lapse response on the lithofacies model and the vertical grid block size. Elastic attribute quantification from coarse-grid models requires a decision on the type of fluid saturation distribution (uniform or patchy) within the coarse-grid blocks. Here, empirical relations for scaling up the fluid bulk modulus are developed which, when inserted into standard Gassmann calculations, permit calibration of the response for the coarse-grid block model from the finer-scale model. At the coarse scale, fluid saturation changes during water injection and pressure depletion can be represented adequately by these relations but, for gas injection, it appears necessary to refer back to the fine-scale models. For the case of gas injection they cannot be generalized readily for each different lithofacies model and are thus observed to be outcrop dependent.
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.
The geochemistry of two unusual oils from the Norwegian North Sea: implications for new source rock and play scenario
Authors: Pedersen Jon H. , Karlsen Dag A. , Backer-Owe Kristian , Lie Jan E. , Brunstad Harald
Published: October 2008

Two oils from the Norwegian North Sea and a source-rock extract from the Danish North Sea are seen to have chemical properties deviating from any previously known North Sea oils. An organic geochemical investigation concludes that the two oils are of low to medium maturity, and that these oils represent alternative organic facies of Upper Jurassic age. The organic facies that sourced the investigated oils are believed to be hypersaline and carbonate-type source rocks, which were most likely deposited in locally developed, secluded lagoonal settings with elevated salinity and low clastic influx. The alternative source rocks inferred by the two atypical oils may add new concepts to petroleum exploration on the margins of the Mesozoic Central Graben and Viking Graben in the North Sea.
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.
Structural and sedimentological analysis of an early Late Rotliegendes graben based on 3D seismic and well log data, German North Sea
Authors: Börmann Christoph , Gast Reinhard , Görisch Frank
Published: October 2008

The geophysical and geological interpretation of a 3D survey, which was acquired in 2001, and four wells in the study area have revealed the structural framework on the West Schleswig Block, consisting of horsts and graben. The structural development of the area from Early to Late Rotliegendes times has been reconstructed and a multiphase history of depositional infill and associated fault patterns can be demonstrated. Well-log correlation provided a wider view of the regional structural styles and the stratigraphic setting of the study area. The Altmark, Havel & Elbe Sub-group lithologies of Rotliegendes times were analysed by sequence stratigraphic methods, concluding that depositional facies is linked to the tectonic movements of the Altmark pulses. Finally, the development of the palaeomorphology and its associated sedimentary facies types throughout time and space showed a sequence starting with dry desert environments and ending with perennial saline lake conditions. The interdisciplinary analysis led to the conclusion that 3D seismic and well information in the German sector of the Southern North Sea identified an early Late Rotliegendes graben filled with reservoir-prone sandstones equivalent to the German onshore.
Fracture intensity vs. mechanical stratigraphy in platform top carbonates: the Aquitanian of the Asmari Formation, Khaviz Anticline, Zagros, SW Iran
Authors: Wennberg O. P. , Svånå T. , Azizzadeh M. , Aqrawi A. M. M. , Brockbank P. , Lyslo K. B. , Ogilvie S.
Published: October 2008

Outcrop analogue studies can significantly improve the understanding of fracture distribution and their impact on fluid flow in hydrocarbon reservoirs. In particular, the outcrops may reveal details on the relationships between mechanical stratigraphy and fracture characteristics. This has been investigated in an integrated sedimentological-structural geological study in the Aquitanian sequence of the Asmari Formation on the NE limb of the Khaviz Anticline in the Zagros foothills in SW Iran. The Aquitanian sequence was deposited in a platform top setting and is characterized by well-defined bedding planes and relatively thin layers (<4 m) with rapid changes in textures from laminated peritidal mudstones to bioclast and ooid grainstones. Fractures in the studied area dominantly strike parallel to the fold axis, have a high angle to bedding and are stratabound. In the literature it is often reported that fracture spacing or the inverse fracture intensity (FI) is controlled by the mechanical layer thickness (MLT). However, in the present study area a rather poor correlation between FI and MLT was observed. Instead, the Dunham texture appears to be more important for the FI. Mud-supported textures (mudstone and wackestone) have higher FI than grain-supported (packstone and grainstone) ones. The degree of dolomitization does not appear to have any significant effect on FI within each texture class. A strong relationship between FI and MLT is observed generally in cases where there has been one single phase of extension and when interbed contacts are weak, e.g. interbedded competent limestones and incompetent shales. However, in the present study area a rather complex deformation history exists and well-developed shales between fractured carbonate layeres are lacking. It is suggested that in such cases the MLT is of minor importance for the FI, which is controlled by the texture.
Hierarchical approach for simulating fluid flow in normal fault zones
Authors: Berg Silje Støren , Øian Erlend
Published: October 2008

Two-phase flow in faults is complex and difficult to predict. To analyse the effect of fault zones on fluid flow, this article presents a hierarchical geological/numerical framework aimed at simulating two-phase flow. The starting point is that fault zones consist of structures at several length scales, with each scale represented by suitable techniques within the same numerical model. A series of two-phase flow simulation experiments was conducted on four geological cases: one reference case with undeformed host rock and three cases with increasingly more complexity added to them. All the structures consist of lower permeability fault rocks in a high permeability host rock. The simulations were performed using an in-house flow simulator. The fault core (large scale) was modelled explicitly through local grid refinement, the subsidiary faults (intermediate scale) were represented in a discrete manner, while an upscaling procedure captured the effect of the deformation bands (fine scale). The simulation results show that each scale has a significant effect on the saturation, pressure drop and oil production, and that capillary pressure and anisotropic permeability are important parameters. The results emphasize the importance of the scale-dependent approach for analysing the effect of faults on two-phase flow.
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.
A strategy for modelling the diagenetic evolution of seismic properties in sandstones
Authors: Dræge Anders , Johansen Tor Arne , Brevik Ivar , Thorsen Dræge Camilla
Published: October 2008

The 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.
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.
Static characterizations of reservoirs: refining the concepts of connectivity and continuity
Authors: Hovadik Joseph M. , Larue David K.
Published: October 2008

Static descriptive measures can be used to quantify characteristics of a 3D reservoir model. These static measures may have implications for the prediction or interpretation of dynamic performance and can draw attention to geological uncertainties that may impact flow behaviours. This study reviews, modifies and introduces techniques to characterize the spatial distribution of permeability in reservoir models, with emphasis placed on connectivity and continuity analysis. Topics include: the relationship between connectivity and percolation theory; definition of types of reservoir connectivity; methods of measuring connectivity; connectivity as a function of distance; connectivity maps; categorical classifications of connectivity; types of reservoir path lengths; and continuity lines. The key factors controlling reservoir connectivity are identified. Static measures can be used to locate regions of higher sweep efficiency and lower tortuosity that are connected to the wells.
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.
Exploring below the basalt, offshore Faroes: a case history of sub-basalt imaging
Authors: Gallagher Joseph W. , Dromgoole Peter W.
Published: October 2008

Discoveries in the Faroe–Shetland Basin to date have been made in areas not covered by extensive basalt flows as these flows seismically obscure the geology and structure of the underlying section. The industry has been tackling this problem for many years and it is known that high frequencies penetrate only a short way into the basalt before being scattered, generating high frequency noise. Recent seismic data in Faroes Licence 006 show a dramatic improvement in sub-basalt imaging in this problem area. The improvement comes primarily from processing the data, removing high frequencies (dominantly noise) early in the processing to concentrate on the low frequency data and using careful multiple removal at all stages of the processing. Velocity analysis must be performed as an iterative process and take into account the geological model. Deep towing the source and cable also improves the data by avoiding the higher frequencies that generally cause noise and thereby enhancing the lower frequency signal. Applying these processing techniques to earlier 2D surveys also shows significant improvement in imaging the sub-basalt structure. Data examples show that the sub-basalt structure can now be mapped on the improved data and sub-basalt prospects defined.
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.
A road map for improving the technical basis for the estimation of petroleum reserves
Authors: Worthington Paul F.
Published: October 2008

Reserves estimation can be based on one or more methodologies, each with its associated uncertainty. These include ‘static’ volumetrics, reservoir simulation, material-balance analysis, and/or projections of ultimate recovery according to production decline. The static volumetric method is in focus here, as the most commonly used approach during the development and early production stages when there has been limited petroleum recovery and the uncertainty associated with a reserves estimate can be considerable. There are several key technical aspects of the static volumetric process, including: the issue of minimum data requirements in relation to reservoir complexity; the upscaling of reservoir parameters and the interpretative algorithms through which they are interrelated; the identification of net reservoir and net pay; and the integration of data sources in a manner that is dynamically conditioned, i.e. tied back to permeation properties. This last point is especially important because reserves, by definition, are commercially recoverable. Suggested improvements reveal additional opportunities for cross-validation and groundtruthing. The approach is synthesized into a high-level, yet pragmatic workplan. It is proposed that the adoption of such a workplan will remove some of the uncertainty that is currently inherent in the technical process for estimating reserves.
Overpressure development in rift basins: an example from the Malay Basin, offshore Peninsular Malaysia
Authors: Madon Mazlan
Published: October 2008

The Malay Basin is a Tertiary transtensional rift basin located in offshore Peninsular Malaysia. A study of the subsurface pressure data has revealed at least two major overpressure compartments that are sealed by regional shale units. The main, basin-centre overpressure compartment has a domal shape and, in profile, shows a convex-up top-of-overpressure surface. In the basin centre, the top of overpressure is generally between 1900 m and 2000 m depth, and is confined mainly to a particular stratigraphic unit, the Middle Miocene unit E. It appears that the top of overpressure is influenced by the underlying regional shale seal in unit F, and that the mild overpressure encountered in unit E represents the overpressure transition zone. Due to the convex-upward top-of-overpressure surface, overpressure is generally encountered at shallower depths in the basin centre compared to the basin flanks. A smaller overpressure compartment is also identified on the northeastern flank of the basin. This compartment is sealed by the onlapping, transgressive shale of unit L (Lower Miocene) and occurs at a depth of 2600–3000 m. Hence, regional shale seals have a strong influence on overpressure distribution.

Disequilibrium compaction is believed to be the primary causal mechanism for the overpressure in the basin centre. Overpressure development is the consequence of high subsidence and sedimentation rates during basin extension. Low subsidence and sedimentation rates on the basin flanks do not generate overpressure. The domal shape of the top-of-overpressure surface is thus a result of different rates of subsidence and sedimentation across the basin.

The basin's overpressure history is simulated by means of a simple model. Modelling results indicate that the basin overpressure developed very early, during the syn-rift phase (
c.
30–21 Ma), when sediment burial rates were very high (>1000 m Ma
−1
). Overpressure build-up occurred rapidly during the syn-rift phase but has started to dissipate gradually since the post-rift phase began 21 Ma ago, when sedimentation rates were well below 1000 m Ma
−1
. This suggests that disequilibrium compaction as an overpressure-generating mechanism was effective during only the syn-rift phase of basin development. Sedimentation rates during the post-rift phase (generally less than 500 m Ma
−1
) were not high enough to generate overpressure. The pre-existing overpressure is thus able to dissipate through the sedimentary column, causing the build-up of pore pressure in the post-rift section. Thus, the overpressure in the post-rift strata is probably of secondary origin, derived from excess pressure dissipated from the underlying syn-rift strata. Overpressure generated by disequilibrium compaction during the syn-rift phase has been modified and re-distributed as the basin evolved through the post-rift phase.