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- Volume 12, Issue 1, 2006
Petroleum Geoscience - Volume 12, Issue 1, 2006
Volume 12, Issue 1, 2006
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A regional chemostratigraphically-defined correlation framework for the late Triassic TAG-I Formation in Blocks 402 and 405a, Algeria
Authors K. T. Ratcliffe, J. Martin, T. J. Pearce, A. D. Hughes, D. E. Lawton, D. S. Wray and F. BessaThe Triassic Argilo-Gréseux Inférieur Formation (TAG-I) is one of the principal hydrocarbon reservoirs in the Berkine Basin of Algeria. Sedimentological studies have shown that it exhibits marked spatial and temporal facies variations on both a local field scale and a regional basinal scale. This variability, combined with a lack of diagnostic flora and fauna, makes regional correlation within the unit difficult. In turn, the lack of a consistent regional stratigraphic framework hampers the comparison of the various correlation schemes devised by operators in the basin.
Contrasting the TAG-I in Blocks 402 and 405a exemplifies the problems encountered when attempting regionally to define a correlation framework for the interval. Between these two blocks, a distance of approximately 200 km, there are marked changes in the style of deposition from sand-dominated, proximal fluvial systems in the SW (Block 405a, MLN, MLC, KMD and MLNW fields) to a more distal, more clay-prone system in the NE (Block 402, ROD/BRSE/BSFN, SFNE and BSF fields). A chemostratigraphic study of the TAG-I in these two blocks has allowed a four-fold correlation framework to be defined, where each chemostratigraphic package has distinctive geochemical features. Chemostratigraphic Package 10, the oldest unit, lies above the Hercynian Unconformity, but beneath a geochemically identifiable hiatal surface. Chemostratigraphic Package 20 lies above the hiatal surface but is separated from the overlying packages by a mineralogical change identifiable in both claystone and sandstone geochemistry. Chemostratigraphic Packages 30 and 40 are chemically somewhat similar, but are separated by a regional event interpreted as a period of dolocrete and lacustrine development. By combining the geochemical differentiation of the units and recognition of their stratal boundaries, it is possible to define a correlation for the TAG-I between Blocks 402 and 405a.
The proposed correlation between the two blocks suggests that the northern parts of Block 405a may have been occupied by a spur or subsidiary channel from the main SW–NE-trending fluvial system, resulting in one of the chemically defined packages being demonstrably absent in the MLNW, MLN, KMD and MLC fields when compared with the other areas of the study.
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Maturity and source-rock potential of Palaeozoic sediments in the NW European Northern Permian Basin
Authors Jon H. Pedersen, Dag A. Karlsen, Jan E. Lie, Harald Brunstad and Rolando di PrimioThe Northern Permian Basin is located in the offshore area SSW of Norway, NNW of Denmark and east of Scotland. This basin is filled mainly by Lower Permian aeolian desert sediments and volcanics, plus Upper Permian evaporitic sediments. The aeolian sandstone is an excellent reservoir rock and is generally capped by thick layers of salt that potentially form a tight cap rock. The highest risk in the petroleum exploration of the Palaeozoic Northern Permian Basin is linked to the presence of source rocks. Palaeozoic source-rock candidates in the Northern Permian Basin area may be present among Lower Palaeozoic marine sediments, within Devonian–Carboniferous lacustrine/deltaic pre- and syn-rift sediments and as Permian marine shales. This study investigates Lower Palaeozoic marine shales, lacustrine Devonian mudstones, Carboniferous mudstones and coals and marine Permian shales in order to assess the thermal maturity, source-rock potential and distribution of Palaeozoic sediments in the Northern Permian Basin region. The majority of the investigated samples were within the oil window in terms of thermal maturity. Lower Palaeozoic marine sediments may have generated both oil and gas, while Upper Palaeozoic coals and mudstones are dominantly gas-prone source rocks. Middle Permian marine shales (Kupferschiefer) are a good oil-prone source rock. Generation and expulsion of hydrocarbons from Lower Palaeozoic source rocks in the eastern parts of the Northern Permian Basin probably began in the Upper Silurian, with peak oil generation in Carboniferous times. Upper Palaeozoic rocks in the same area matured rapidly in Early Triassic times. The likely presence of multiple Palaeozoic source rocks suggests that hydrocarbons were generated in the Northern Permian Basin.
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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 Matthew J. Pranter, Zulfiquar A. Reza and David A. BuddCarbonate 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.
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Hydrocarbon potential of the Karapinaryaylasi Formation (Paleocene–Eocene) source rock in the Tuz Gölü Basin, central Anatolia, Turkey
More LessIn the Tuz Gölü Basin (central Anatolia), the Karapinaryaylasi Formation (Paleocene–Eocene) is represented by shale and sandstone alternation, conglomerates and lensoid limestones. The total organic carbon (TOC) results from most outcrops and the Karapinar-2A well samples show less than 0.50 wt%, and the hydrogen index (HI) and genetic potential values are very low. In the Aktas-1A, Aksaray-1 and Sultanhani-1 wells, the TOC content is generally lower than 0.5 wt% but can reach up to 1.50 wt%. Rock-Eval pyrolysis indicates that some intervals within the Karapinaryaylasi Formation possess good gas potential, with a total yield of up to 4268 ppm. The Paleocene–Eocene rocks are thermally immature to marginally mature with respect to T max, ranging from 420°C to 458°C, while vitrinite reflectance and spore colour index values range from 0.50% Ro to 0.88% Ro and 4 to 8(?), respectively. Microscopic investigations and the HI vs. oxygen index (OI) and HI vs. T max diagrams show that the samples contain Type III and Type II kerogen, which is often oxidized, together with reworked material. Gas chromatography and gas chromatography–mass spectrometry analysis results support these conclusions. Consideration of all the data indicates that the Karapinaryaylasi Formation (Paleocene–Eocene) could be the source rock for gas production in the Tuz Gölü Basin.
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Rock physics modelling of shale diagenesis
Authors Anders Dræge, Morten Jakobsen and Tor Arne JohansenA model for estimating the effective anisotropic properties of cemented shales is presented. The model is based on two mathematical methods for estimation of effective properties of a composite medium; a self-consistent approximation and a differential effective medium model. In combination these theories allow approximation of a shale with connected clay minerals and cement, and disconnected pores and quartz grains, which can be compared with the conditions in a real cemented shale. A strategy is also presented for estimation of stiffnesses in the transition zone from mechanical compaction to chemical compaction dominated diagenesis. Combining these theories with a shale compaction theory, enables modelling of the effective elastic stiffnesses for shales from deposition and mechanical compaction to deep burial and chemical compaction/cementing. Results from the model were compared with velocity data from three wells, showing good fit for velocity predictions, following the main velocity trends with increased temperature and depth.
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The development of Middle Cretaceous carbonate platforms, Persian Gulf, Iran: constraints from seismic stratigraphy, well and biostratigraphy
More LessIn 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.
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Geochemical characterization of a Cretaceous black shale from the Mamfe Basin, Cameroon
Authors E. Eseme, R. Littke and C. M. AgyingiShale 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 mgCO2 g−1TOC), pr/ph (1.79) and high gammacerane index (22) suggest deposition in a highly saline reducing environment. The n-alkane distribution dominated by n-C15 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), C31(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−1TOC). Expulsion may have occurred before uplift and erosion but a more elaborate study is required to evaluate the petroleum systems of the basin.
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The geological and geochemical characteristics of source rocks in the Tertiary Nadu Formation of the Eastern Depression, Baise Basin, China
Authors Liu Luofu, Harald Hoiland, Zhao Suping, Guo Yongqiang, Li Shuangwen and Chen YuanzhuangDark mudstones are widely distributed in the Upper and Lower Sub-members of the Na1 Member and the Na2 Member of the Tertiary Nadu Formation in the Eastern Depression of the Baise Basin, with a cumulative thickness of 200–1000 m. There is more than 1% organic carbon in these three sets of dark mudstones in most areas of the Eastern Depression, indicating that they are good source rocks. The kerogen of these three sets of effective source rocks is mainly of Type IIA, but also with Types IIB and III. Distribution of the kerogen type was controlled by sedimentary environment. Ro values of the Na1 Member mudstones are 0.4–0.65%, showing that the organic matter is at the immature to low-mature stage, while those of the Na2 Member, which are deeper, are 0.7–0.8% or even higher, showing that the organic matter is at the early mature stage. The facies of thicker dark mudstones in the Depression suggest a semi-deep lake environment, and the areas with higher organic carbon and Ro values – the depositional centre and the subsiding centre of the basin – coincide with the hydrocarbon generation centre. The Na2 Member should be the most effective source rock in this area because of its maturity, thickness, the sedimentary environment, and the organic abundance and type. The Tiandong Sedimentary District, with its larger area, greater thickness of mudstone, wider range of semi-deep lacustrine environment, higher organic carbon amount, better organic matter type and higher maturity, has a greater potential for hydrocarbon generation and expulsion than the Tianyang Sedimentary District.
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The geochemistry of two unusual oils from the Norwegian North Sea: implications for new source rock and play scenario
Authors Jon H. Pedersen, Dag A. Karlsen, Kristian Backer-Owe, Jan E. Lie and Harald BrunstadTwo 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.
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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)