This paper provides an updated understanding of the reservoir stratigraphy, sedimentology, palaeogeography and diagenesis of the Upper Permian Hauptdolomit Formation of the Zechstein Supergroup (“Hauptdolomit”) in a study area on the southern margin of the Mid North Sea High. The paper is based on the examination and description of core and cuttings data from 25 wells which were integrated with observations based on existing and new 3D seismic.
Based on thin-section petrography of cuttings and core from the wells studied, it is evident that Hauptdolomit microfacies are distributed in a relatively predictable way, and well-defined platform interior, platform margin, slope and basin settings can be distinguished. Platform margins are typically characterised by the development of ooid shoals and, to a lesser-extent, by microbial build-ups. High-energy back-shoal settings are characterised by a more complex combination of peloid grainstones, thrombolitic and microbial build-ups, and fine crystalline dolomites. Lower energy lagoons which developed further behind the platform margin are characterised by a variety of microfacies types; fine crystalline dolomites are common in this setting as well as peloidal facies and local microbial build-ups. Intertidal and supratidal settings are typified by increased proportions of anhydrite and the development of laminated microbial bindstones (stromatolites). Platform margins are in general relatively steep and pass into slope and basinal settings. Only a few wells have penetrated Hauptdolomit successions deposited in a slope setting, and these successions are characterised by a range of resedimented shallow-water facies together with low-energy laminated dolomicrites and fine crystalline dolomites. Slope zones in the study area are interpreted from seismic data to be typically 1-1.5 km in width. Basinal Hauptdolomit deposits have been strongly affected by post-depositional diagenesis and are dedolomitised to variable degrees. The original depositional facies are rarely preserved.
Diagenetic studies show that dolomitisation has affected almost the entire Hauptdolomit Formation throughout the study area in both basinal and platform settings. The dolomite is considered to result from seepage-reflux processes and is an early diagenetic phase. Mouldic porosity is present in many facies types as a result of dissolution, especially in ooid grainstones, thrombolitic build-ups and peloidal facies. The dissolution cannot be associated with any one diagenetic phase but was most likely a result of the dolomitisation process itself. Stable isotope analyses indicate that all dolomites were precipitated from Permian marine-derived pore fluids. Fluid inclusion analyses of dolomite cements indicate that cementation continued into the burial realm. Anhydrite cementation occurs in two phases: early anhydrite precipitation was associated with dolomitisation, and can be distinguished from a later, pore-filling cement
{"title":"SEDIMENTOLOGY, PALAEOGEOGRAPHY AND DIAGENESIS OF THE UPPER PERMIAN (Z2) HAUPTDOLOMIT FORMATION ON THE SOUTHERN MARGIN OF THE MID NORTH SEA HIGH AND IMPLICATIONS FOR RESERVOIR PROSPECTIVITY","authors":"Jo Garland, Colin Tiltman, Callum Inglis","doi":"10.1111/jpg.12841","DOIUrl":"10.1111/jpg.12841","url":null,"abstract":"<p>This paper provides an updated understanding of the reservoir stratigraphy, sedimentology, palaeogeography and diagenesis of the Upper Permian Hauptdolomit Formation of the Zechstein Supergroup (“Hauptdolomit”) in a study area on the southern margin of the Mid North Sea High. The paper is based on the examination and description of core and cuttings data from 25 wells which were integrated with observations based on existing and new 3D seismic.</p><p>Based on thin-section petrography of cuttings and core from the wells studied, it is evident that Hauptdolomit microfacies are distributed in a relatively predictable way, and well-defined platform interior, platform margin, slope and basin settings can be distinguished. Platform margins are typically characterised by the development of ooid shoals and, to a lesser-extent, by microbial build-ups. High-energy back-shoal settings are characterised by a more complex combination of peloid grainstones, thrombolitic and microbial build-ups, and fine crystalline dolomites. Lower energy lagoons which developed further behind the platform margin are characterised by a variety of microfacies types; fine crystalline dolomites are common in this setting as well as peloidal facies and local microbial build-ups. Intertidal and supratidal settings are typified by increased proportions of anhydrite and the development of laminated microbial bindstones (stromatolites). Platform margins are in general relatively steep and pass into slope and basinal settings. Only a few wells have penetrated Hauptdolomit successions deposited in a slope setting, and these successions are characterised by a range of resedimented shallow-water facies together with low-energy laminated dolomicrites and fine crystalline dolomites. Slope zones in the study area are interpreted from seismic data to be typically 1-1.5 km in width. Basinal Hauptdolomit deposits have been strongly affected by post-depositional diagenesis and are dedolomitised to variable degrees. The original depositional facies are rarely preserved.</p><p>Diagenetic studies show that dolomitisation has affected almost the entire Hauptdolomit Formation throughout the study area in both basinal and platform settings. The dolomite is considered to result from seepage-reflux processes and is an early diagenetic phase. Mouldic porosity is present in many facies types as a result of dissolution, especially in ooid grainstones, thrombolitic build-ups and peloidal facies. The dissolution cannot be associated with any one diagenetic phase but was most likely a result of the dolomitisation process itself. Stable isotope analyses indicate that all dolomites were precipitated from Permian marine-derived pore fluids. Fluid inclusion analyses of dolomite cements indicate that cementation continued into the burial realm. Anhydrite cementation occurs in two phases: early anhydrite precipitation was associated with dolomitisation, and can be distinguished from a later, pore-filling cement ","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"46 3","pages":"329-360"},"PeriodicalIF":1.8,"publicationDate":"2023-07-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49501797","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
In the Witch Ground Graben area in the centralnorthern UK North Sea, four deviated wells (referred to here as wells A-D) have intersected the Halibut Carbonate Formation. This formation, which ranges in thickness from ca. 350 ft to ca. 100 ft from west to east, was deposited locally as part of the Upper Permian succession in the Northern Permian Basin. It consists of the lower Argyll Carbonate Member and the upper Innes Carbonate Member separated by the Iris Anhydrite Member. The formation is broadly equivalent to the Z1 and Z2 cycles of the Zechstein Supergroup in the better-known Southern Permian Basin. A distinctive conglomerate caps the Argyll Carbonate Member and is also recognised within the Iris Anhydrite Member, and is a possible equivalent to the Bosies Bank Formation. Downhole data from the studied wells (which includes cores and open-hole logs) has identified six different lithologies in the Halibut Carbonate Formation: dolostones, limestones, anhydrite and conglomerates, together with subordinate sandstones and claystones. Twenty-seven core facies have been determined from these lithologies and have been grouped into five facies associations. Facies association 1 (FA1) consists predominantly of dolomudstones and algal laminated dolostones (Fig. 1A) deposited within tidal flats and adjacent muddy lagoons. Facies association 2 (FA2) comprises dolofloatstones, dolorudstones and grainy dolostone facies interpreted as higher-energy sandto gravel-grade sand shoals. Facies association 3 (FA3)
{"title":"Extended abstract: UPPER PERMIAN HALIBUT CARBONATE FORMATION, WITCH GROUND GRABEN AREA, NORTH PERMIAN BASIN, UKCS: SEDIMENTOLOGY, CORRELATION AND RESERVOIR QUALITY","authors":"Giancarlo Rizzi, Graham Frederick Aplin","doi":"10.1111/jpg.12844","DOIUrl":"10.1111/jpg.12844","url":null,"abstract":"In the Witch Ground Graben area in the centralnorthern UK North Sea, four deviated wells (referred to here as wells A-D) have intersected the Halibut Carbonate Formation. This formation, which ranges in thickness from ca. 350 ft to ca. 100 ft from west to east, was deposited locally as part of the Upper Permian succession in the Northern Permian Basin. It consists of the lower Argyll Carbonate Member and the upper Innes Carbonate Member separated by the Iris Anhydrite Member. The formation is broadly equivalent to the Z1 and Z2 cycles of the Zechstein Supergroup in the better-known Southern Permian Basin. A distinctive conglomerate caps the Argyll Carbonate Member and is also recognised within the Iris Anhydrite Member, and is a possible equivalent to the Bosies Bank Formation. Downhole data from the studied wells (which includes cores and open-hole logs) has identified six different lithologies in the Halibut Carbonate Formation: dolostones, limestones, anhydrite and conglomerates, together with subordinate sandstones and claystones. Twenty-seven core facies have been determined from these lithologies and have been grouped into five facies associations. Facies association 1 (FA1) consists predominantly of dolomudstones and algal laminated dolostones (Fig. 1A) deposited within tidal flats and adjacent muddy lagoons. Facies association 2 (FA2) comprises dolofloatstones, dolorudstones and grainy dolostone facies interpreted as higher-energy sandto gravel-grade sand shoals. Facies association 3 (FA3)","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"46 3","pages":"407-412"},"PeriodicalIF":1.8,"publicationDate":"2023-07-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45762628","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
P. Browning-Stamp, C. Caldarelli, Graham Heard, James T. Ryan, J. Hendry
The Mid North Sea High (MNSH) region represents one of the least explored areas for the Late Permian Zechstein Hauptdolomit play in the Southern Permian Basin although some of the first offshore wells drilled in the UK were located here. In other parts of the basin such as onshore Poland, the Hauptdolomit Formation (“Hauptdolomit”) is an active and attractive exploration target, with oil and gas production from commercial‐sized fields. In the UK, the play has been overshadowed by drilling campaigns in areas to the south of the MNSH which tested plays in the underlying Rotliegend and Carboniferous successions. However, with these areas now in decline, there is increased exploration interest in the Hauptdolomit in the MNSH region, particularly since 2019 when 3D seismic data were acquired and the first hydrocarbon discovery was made at Ossian (well 42/04‐01/1Z). Geochemical data from the latter discovery have pointed to the presence of a prolific petroleum system with the potential for Hauptdolomit reservoirs to be charged both by Zechstein‐generated oils and Carboniferous condensate/gas. With regard to hydrocarbon migration and preservation in the southern MNSH, a detailed evaluation of the effects of the Mid Miocene Unconformity has allowed for a greater understanding of the main factors controlling hydrocarbon preservation and remigration. Reservoir characterization of the Hauptdolomit play has been achieved by integrating petrographic microfacies analyses, core data and petrophysical interpretations. The most important factors controlling reservoir quality are the presence and extent of anhydrite cementation and the presence of high energy shoal facies. Thicker and coarser grained shoal facies are expected to occur along the yet‐to‐be explored Orchard platform margin where numerous prospects have been mapped and refined using recently acquired 3D seismic data.
{"title":"THE ZECHSTEIN Z2 HAUPTDOLOMIT PLATFORM IN THE SOUTHERN UK MID NORTH SEA HIGH AND ITS ASSOCIATED PETROLEUM PLAYS, POTENTIAL AND PROSPECTIVITY","authors":"P. Browning-Stamp, C. Caldarelli, Graham Heard, James T. Ryan, J. Hendry","doi":"10.1111/jpg.12840","DOIUrl":"https://doi.org/10.1111/jpg.12840","url":null,"abstract":"The Mid North Sea High (MNSH) region represents one of the least explored areas for the Late Permian Zechstein Hauptdolomit play in the Southern Permian Basin although some of the first offshore wells drilled in the UK were located here. In other parts of the basin such as onshore Poland, the Hauptdolomit Formation (“Hauptdolomit”) is an active and attractive exploration target, with oil and gas production from commercial‐sized fields. In the UK, the play has been overshadowed by drilling campaigns in areas to the south of the MNSH which tested plays in the underlying Rotliegend and Carboniferous successions. However, with these areas now in decline, there is increased exploration interest in the Hauptdolomit in the MNSH region, particularly since 2019 when 3D seismic data were acquired and the first hydrocarbon discovery was made at Ossian (well 42/04‐01/1Z). Geochemical data from the latter discovery have pointed to the presence of a prolific petroleum system with the potential for Hauptdolomit reservoirs to be charged both by Zechstein‐generated oils and Carboniferous condensate/gas. With regard to hydrocarbon migration and preservation in the southern MNSH, a detailed evaluation of the effects of the Mid Miocene Unconformity has allowed for a greater understanding of the main factors controlling hydrocarbon preservation and remigration. Reservoir characterization of the Hauptdolomit play has been achieved by integrating petrographic microfacies analyses, core data and petrophysical interpretations. The most important factors controlling reservoir quality are the presence and extent of anhydrite cementation and the presence of high energy shoal facies. Thicker and coarser grained shoal facies are expected to occur along the yet‐to‐be explored Orchard platform margin where numerous prospects have been mapped and refined using recently acquired 3D seismic data.","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"46 1","pages":""},"PeriodicalIF":1.8,"publicationDate":"2023-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"64114619","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Liu Zuodong, Graham Blackbourn, Wen Zhixing, Wang Hongjun, He Zhengjun, Ma Feng, Liu Xiaobing, Chen Ruiying, Bian Haiguang
The so-called East Siberian “Basin” extends over an ancient continental block, the Siberian Platform, and is made up of a number of smaller-scale basement arches and basins with a variable sedimentary cover of mostly Proterozoic and Palaeozoic ages. The basin hosts the oldest large-scale petroleum systems known. Proterozoic (“Riphean”: 1650-650 Ma) marine source rocks, which were deposited on the passive margins which surrounded much of the Platform, generated hydrocarbons as they were buried, folded and thermally matured during a series of mostly Late Proterozoic to Cambrian continental collisions, with the final collision taking place in the Early Cretaceous along the northeastern (Verkhoyan) margin. The hydrocarbons were transported by long-distance migration to reservoirs in the sedimentary successions which drape basement uplifts, there forming giant oil and gas accumulations which were sealed by extensive Cambrian evaporites. Subsequent uplift and unroofing, especially in the north and east of the Platform where the seal is not present, led to degradation of the oil to leave giant accumulations of bitumen, defined here as petroleum with an API gravity of less than 10° which is immobile under reservoir conditions. A significantly younger petroleum system, which may still be active, is present in the Vilyui Basin in the NE of the Siberian Platform. This basin was initiated as a mid-Devonian rift and has a later Palaeozoic and Mesozoic fill.
Bitumen accumulations in the East Siberian Basin occur mainly in Precambrian, Cambrian and Permian reservoir rocks, and began to form from precursor oils during the Permian. Around twenty-five named fields have been described, many of which comprise portions of more extensive belts of bitumen occurrence. Although geological mapping of natural resources in the East Siberian Basin has been carried out since the 19th century, the region remains under-explored and none of the bitumen accumulations has yet been developed.
An attempt is made in this paper to catalogue and map all recorded occurrences of bitumen throughout the East Siberian Basin. Regional geological studies have been conducted in order to understand the origin and habitat of each occurrence. So far as possible, data on the areal extent and stratigraphic thickness of each bitumen occurrence has been collated, together with data on bitumen saturations and quality. These data were used to calculate resource volumes for each accumulation from first principles. Thus the total bitumen resources within the East Siberian Basin have been calculated as 24,640 MM (million) tonnes. Disregarding accumulations regarded as either of insufficient resource-density or too small to merit consideration, this figure has been reduced to 14,760 MM tonnes. Recoverable reserves, by analogy with comparable resources worldwide, are calculated as 6100 MM tonnes (approximately 33,900 MM brl)
{"title":"BITUMEN RESOURCES OF THE EAST SIBERIAN BASIN","authors":"Liu Zuodong, Graham Blackbourn, Wen Zhixing, Wang Hongjun, He Zhengjun, Ma Feng, Liu Xiaobing, Chen Ruiying, Bian Haiguang","doi":"10.1111/jpg.12833","DOIUrl":"10.1111/jpg.12833","url":null,"abstract":"<p>The so-called East Siberian “Basin” extends over an ancient continental block, the Siberian Platform, and is made up of a number of smaller-scale basement arches and basins with a variable sedimentary cover of mostly Proterozoic and Palaeozoic ages. The basin hosts the oldest large-scale petroleum systems known. Proterozoic (“Riphean”: 1650-650 Ma) marine source rocks, which were deposited on the passive margins which surrounded much of the Platform, generated hydrocarbons as they were buried, folded and thermally matured during a series of mostly Late Proterozoic to Cambrian continental collisions, with the final collision taking place in the Early Cretaceous along the northeastern (Verkhoyan) margin. The hydrocarbons were transported by long-distance migration to reservoirs in the sedimentary successions which drape basement uplifts, there forming giant oil and gas accumulations which were sealed by extensive Cambrian evaporites. Subsequent uplift and unroofing, especially in the north and east of the Platform where the seal is not present, led to degradation of the oil to leave giant accumulations of bitumen, defined here as petroleum with an API gravity of less than 10° which is immobile under reservoir conditions. A significantly younger petroleum system, which may still be active, is present in the Vilyui Basin in the NE of the Siberian Platform. This basin was initiated as a mid-Devonian rift and has a later Palaeozoic and Mesozoic fill.</p><p>Bitumen accumulations in the East Siberian Basin occur mainly in Precambrian, Cambrian and Permian reservoir rocks, and began to form from precursor oils during the Permian. Around twenty-five named fields have been described, many of which comprise portions of more extensive belts of bitumen occurrence. Although geological mapping of natural resources in the East Siberian Basin has been carried out since the 19th century, the region remains under-explored and none of the bitumen accumulations has yet been developed.</p><p>An attempt is made in this paper to catalogue and map all recorded occurrences of bitumen throughout the East Siberian Basin. Regional geological studies have been conducted in order to understand the origin and habitat of each occurrence. So far as possible, data on the areal extent and stratigraphic thickness of each bitumen occurrence has been collated, together with data on bitumen saturations and quality. These data were used to calculate resource volumes for each accumulation from first principles. Thus the total bitumen resources within the East Siberian Basin have been calculated as 24,640 MM (million) tonnes. Disregarding accumulations regarded as either of insufficient resource-density or too small to merit consideration, this figure has been reduced to 14,760 MM tonnes. Recoverable reserves, by analogy with comparable resources worldwide, are calculated as 6100 MM tonnes (approximately 33,900 MM brl)</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"46 2","pages":"127-156"},"PeriodicalIF":1.8,"publicationDate":"2023-04-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47950500","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Ivanka Orozova-Bekkevold, Erik Skovbjerg Rasmussen, Niels Hemmingsen Schovsbo
Overpressure build up in the clay-rich succession between sea floor and the top of the Chalk Group in the area around wells North Jens-1 and Fasan-1 in the Danish sector of the Central Graben, North Sea was examined by forward modelling. “Overpressure”, i.e. fluid pressure higher than hydrostatic pressure, is expressed here in terms of both the difference between pore pressure and hydrostatic pressure at a given depth and the ratio between these pressures. Pore pressure changes over time were estimated by numerical simulation of post-Danian depositional processes, incorporating sea level changes and variations in sedimentation rate. Results show that the deposition of the post-Danian (“overburden”) succession led to overpressure build up both in the overburden itself and in the underlying sediments (the so-called “underburden”). The largest estimated present-day overpressures (4.9-5.6 MPa, 23-26% above hydrostatic) occur at the base of the overburden, while an overpressure of up to 5.5 MPa was calculated to occur in the underburden. Variations in sedimentation rate appeared to have influenced the build-up of overpressure in the overburden, although no significant effect was found in the underburden.
The results indicate that more than 50% of the present-day overpressure in the overburden was generated in the last 5.3 million years, i.e. during the Pliocene and the Quaternary. When variations in sedimentation rate during the Miocene were included in the modelling calculation, this proportion increased to nearly 70%. A decrease in sedimentation rate in the mid-Miocene (Serravallian, 15-11.2 Ma) and the late Miocene (Messinian, 7.5-5.3 Ma) resulted in the dissipation of overpressures generated previously when the sedimentation rate was higher. About 60% of the overpressure generated in the Miocene developed during the Tortonian but only 14% during the Messinian.
Water depth appears to influence the overpressure magnitude. Sea level changes played a minor and short-lived role in overpressure build up. The influence of water depth was most pronounced when it was significantly greater than the thickness of the deposited sediments.
The method of overpressure estimation used in this paper may be a valuable alternative to methods based on porosity trend analysis which are widely used in the oil and gas industry. Both the methods used here and the results may be useful in subsurface evaluations related to carbon storage in the Danish Central Graben (e.g. project Green Sand).
{"title":"INFLUENCE OF POST-DANIAN SEA-LEVEL CHANGES AND VARIATIONS IN SEDIMENTATION RATE ON OVERPRESSURE BUILD UP IN THE CLAY-RICH OVERBURDEN IN THE DANISH SECTOR OF THE NORTH SEA CENTRAL GRABEN","authors":"Ivanka Orozova-Bekkevold, Erik Skovbjerg Rasmussen, Niels Hemmingsen Schovsbo","doi":"10.1111/jpg.12835","DOIUrl":"10.1111/jpg.12835","url":null,"abstract":"<p>Overpressure build up in the clay-rich succession between sea floor and the top of the Chalk Group in the area around wells North Jens-1 and Fasan-1 in the Danish sector of the Central Graben, North Sea was examined by forward modelling. “Overpressure”, i.e. fluid pressure higher than hydrostatic pressure, is expressed here in terms of both the difference between pore pressure and hydrostatic pressure at a given depth and the ratio between these pressures. Pore pressure changes over time were estimated by numerical simulation of post-Danian depositional processes, incorporating sea level changes and variations in sedimentation rate. Results show that the deposition of the post-Danian (“overburden”) succession led to overpressure build up both in the overburden itself and in the underlying sediments (the so-called “underburden”). The largest estimated present-day overpressures (4.9-5.6 MPa, 23-26% above hydrostatic) occur at the base of the overburden, while an overpressure of up to 5.5 MPa was calculated to occur in the underburden. Variations in sedimentation rate appeared to have influenced the build-up of overpressure in the overburden, although no significant effect was found in the underburden.</p><p>The results indicate that more than 50% of the present-day overpressure in the overburden was generated in the last 5.3 million years, i.e. during the Pliocene and the Quaternary. When variations in sedimentation rate during the Miocene were included in the modelling calculation, this proportion increased to nearly 70%. A decrease in sedimentation rate in the mid-Miocene (Serravallian, 15-11.2 Ma) and the late Miocene (Messinian, 7.5-5.3 Ma) resulted in the dissipation of overpressures generated previously when the sedimentation rate was higher. About 60% of the overpressure generated in the Miocene developed during the Tortonian but only 14% during the Messinian.</p><p>Water depth appears to influence the overpressure magnitude. Sea level changes played a minor and short-lived role in overpressure build up. The influence of water depth was most pronounced when it was significantly greater than the thickness of the deposited sediments.</p><p>The method of overpressure estimation used in this paper may be a valuable alternative to methods based on porosity trend analysis which are widely used in the oil and gas industry. Both the methods used here and the results may be useful in subsurface evaluations related to carbon storage in the Danish Central Graben (e.g. project Green Sand).</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"46 2","pages":"191-217"},"PeriodicalIF":1.8,"publicationDate":"2023-04-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47605990","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Anis Khalifeh-Soltani, Mohammad R. Ghassemi, Seyed Ahmad Alavi, Mehdi Ganjiani
Fault-related folds are present in most tectonic settings and can serve as structural traps for hydrocarbons. These structures have therefore been widely studied by both structural and petroleum geologists using a range of techniques. Approaches include field- and seismic-based methods, and numerical and analogue modelling. Geomechanical models attempt to examine the mechanical and geometric features of folds.
This study investigates the effects of variations in a range of parameters, including detachment and ramp geometry, friction coefficient and internal friction angle, on the geometry and development of detachment folds and fault-bend folds. For this purpose, we ran seven series of numerical, 3D elastic-plastic finite element models using ABAQUS software (26 model runs in all). Each model set-up consisted of five layers whose mechanical properties were based on those of stratigraphic units in the Zagros fold-and-thrust belt, SW Iran. The models were labelled series A to F and series H. Models in series A investigated the impact of concave, convex, wavy and oblique detachment surfaces on the development of detachment folds; those in series D examined the role of ramp dip and of listric, oblique and wavy ramps on the development of fault-bend folds. Models in series B and E, and series C and F, examined the effects of variations in the friction coefficient and of the internal friction angle, respectively, on the development of these two classes of folds. Finally, hybrid models in series H were provided to evaluate the results.
Major results were as follows. Firstly, the geometry of modelled detachment and fault-bend folds was found to be influenced by the geometry of the associated ramps and detachment faults. Thus the crests of anticlines and the trough lines of synclines were located at points of maximum curvature and at inflexion points on a wavy detachment fault or wavy ramp, respectively. Second, two important additional factors controlling fold style were identified: the friction coefficient, and the presence of along-strike geometric variations in the ramp or the detachment fault. Layers with low friction coefficients and high internal friction angles formed detachment folds with thick hinges and thin limbs; conversely, layers with high friction coefficients and low internal friction angles created detachment folds with thick limbs and thin hinges. Application of the results to modelling of the Ahwaz anticline in the Dezful Embayment, SW Iran, was successful, and in general the modelled structure was consistent with that observed in the field.
{"title":"PARAMETERS CONTROLLING THE GEOMETRY OF DETACHMENT AND FAULT-BEND FOLDS: INSIGHTS FROM 3D FINITE-ELEMENT MODELS APPLIED TO THE AHWAZ ANTICLINE IN THE DEZFUL EMBAYMENT, SW IRAN","authors":"Anis Khalifeh-Soltani, Mohammad R. Ghassemi, Seyed Ahmad Alavi, Mehdi Ganjiani","doi":"10.1111/jpg.12834","DOIUrl":"10.1111/jpg.12834","url":null,"abstract":"<p>Fault-related folds are present in most tectonic settings and can serve as structural traps for hydrocarbons. These structures have therefore been widely studied by both structural and petroleum geologists using a range of techniques. Approaches include field- and seismic-based methods, and numerical and analogue modelling. Geomechanical models attempt to examine the mechanical and geometric features of folds.</p><p>This study investigates the effects of variations in a range of parameters, including detachment and ramp geometry, friction coefficient and internal friction angle, on the geometry and development of detachment folds and fault-bend folds. For this purpose, we ran seven series of numerical, 3D elastic-plastic finite element models using ABAQUS software (26 model runs in all). Each model set-up consisted of five layers whose mechanical properties were based on those of stratigraphic units in the Zagros fold-and-thrust belt, SW Iran. The models were labelled series A to F and series H. Models in series A investigated the impact of concave, convex, wavy and oblique detachment surfaces on the development of detachment folds; those in series D examined the role of ramp dip and of listric, oblique and wavy ramps on the development of fault-bend folds. Models in series B and E, and series C and F, examined the effects of variations in the friction coefficient and of the internal friction angle, respectively, on the development of these two classes of folds. Finally, hybrid models in series H were provided to evaluate the results.</p><p>Major results were as follows. Firstly, the geometry of modelled detachment and fault-bend folds was found to be influenced by the geometry of the associated ramps and detachment faults. Thus the crests of anticlines and the trough lines of synclines were located at points of maximum curvature and at inflexion points on a wavy detachment fault or wavy ramp, respectively. Second, two important additional factors controlling fold style were identified: the friction coefficient, and the presence of along-strike geometric variations in the ramp or the detachment fault. Layers with low friction coefficients and high internal friction angles formed detachment folds with thick hinges and thin limbs; conversely, layers with high friction coefficients and low internal friction angles created detachment folds with thick limbs and thin hinges. Application of the results to modelling of the Ahwaz anticline in the Dezful Embayment, SW Iran, was successful, and in general the modelled structure was consistent with that observed in the field.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"46 2","pages":"157-190"},"PeriodicalIF":1.8,"publicationDate":"2023-04-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46234031","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Aneesa Ijaz Rabbani, Sameer Al-Hajri, Khaula Shahid Hussain, Graham Blackbourn, Chuangchuang Qi, Abhijith Suboyin, Jassim Abubacker Ponnambathayil, Md Motiur Rahman, Mohamed Haroun, Muhammad A. Gibrata, Lamia Rouis, Yanfidra Djanuar
The sedimentology, petrography and reservoir potential of Pliocene sandstones within the Upper Red Series in the offshore LAM field, Western Turkmenistan, have been examined. Depositional settings are interpreted within the framework of the Red Series palaeoenvironments across the entire Turkmen sector of the Apsheron-Prebalkhan uplift zone, including its onshore extension to the east.
Examination of 81 m of core from three separate intervals suggests that the Red Series in the LAM field is the product of a fluvial-dominated delta system with associated floodplain deposits, periodically flooded by the saline waters of the South Caspian Lake. Relatively thick sandstones, up to around 5 m thick, are interpreted as channel and point-bar deposits of a meandering river system, with thinner and finer-grained sandstones and siltstones inferred to be crevasse-splay and interdistributary floodplain deposits. Floodplain mudstones display signs of desiccation, soil formation, plant rootlets and occasional thin layers of anhydrite. Intervals with marine trace-fossil assemblages record incursions of saline-lake waters. Conglomeratic layers at the base of thicker mudstone intervals may be associated with abrupt transgressions of the lake. The best reservoir qualities are associated with the fluvial channel and point-bar sandstones. Crevasse-splay and other overbank sandstones are of poorer quality, while intercalated floodplain to lacustrine claystone/siltstone units may constitute local seals.
Eighteen sandstone plug samples from the cored intervals were examined in thin-section and by XRD and SEM to assess how mineralogy, grain size and diagenesis affect reservoir quality. The samples consist predominantly of lithic arkoses and feldspathic litharenites; higher porosities, and therefore better reservoir potential, are associated with the feldspathic litharenites. Primary controls on porosity include compaction, clay-matrix content and calcite cementation. XRD data reveal the presence of illite, illite-smectite and chlorite. The presence of swelling clays has been the main cause of formation damage in the field.
The interpretation of meandering fluvial channels here is thought to represent the first published account of such channels within Pliocene reservoir rocks in the north of the South Caspian Basin. Previous accounts of the Red Series sandstones deposited onshore to the east have indicated deposition within braided channels of the palaeo-Amu Darya river delta plain, and alluvial-fan deposits sourced from uplands to the north. Deposition of the equivalent Productive Series by the palaeo-Volga in the Azerbaijan sector to the west has also been interpreted as having taken place within braided systems, although mixed or suspended-load fluvial channels ascribed to the contemporary Kura delta farther south may have been associated with a meandering system. Two palaeogeographic maps a
{"title":"RESERVOIR CHARACTERIZATION OF THE PLIOCENE RED SERIES, LAM FIELD AND SURROUNDING AREAS, OFFSHORE WESTERN TURKMENISTAN","authors":"Aneesa Ijaz Rabbani, Sameer Al-Hajri, Khaula Shahid Hussain, Graham Blackbourn, Chuangchuang Qi, Abhijith Suboyin, Jassim Abubacker Ponnambathayil, Md Motiur Rahman, Mohamed Haroun, Muhammad A. Gibrata, Lamia Rouis, Yanfidra Djanuar","doi":"10.1111/jpg.12831","DOIUrl":"10.1111/jpg.12831","url":null,"abstract":"<div>\u0000 <p>The sedimentology, petrography and reservoir potential of Pliocene sandstones within the Upper Red Series in the offshore LAM field, Western Turkmenistan, have been examined. Depositional settings are interpreted within the framework of the Red Series palaeoenvironments across the entire Turkmen sector of the Apsheron-Prebalkhan uplift zone, including its onshore extension to the east.</p>\u0000 <p>Examination of 81 m of core from three separate intervals suggests that the Red Series in the LAM field is the product of a fluvial-dominated delta system with associated floodplain deposits, periodically flooded by the saline waters of the South Caspian Lake. Relatively thick sandstones, up to around 5 m thick, are interpreted as channel and point-bar deposits of a meandering river system, with thinner and finer-grained sandstones and siltstones inferred to be crevasse-splay and interdistributary floodplain deposits. Floodplain mudstones display signs of desiccation, soil formation, plant rootlets and occasional thin layers of anhydrite. Intervals with marine trace-fossil assemblages record incursions of saline-lake waters. Conglomeratic layers at the base of thicker mudstone intervals may be associated with abrupt transgressions of the lake. The best reservoir qualities are associated with the fluvial channel and point-bar sandstones. Crevasse-splay and other overbank sandstones are of poorer quality, while intercalated floodplain to lacustrine claystone/siltstone units may constitute local seals.</p>\u0000 <p>Eighteen sandstone plug samples from the cored intervals were examined in thin-section and by XRD and SEM to assess how mineralogy, grain size and diagenesis affect reservoir quality. The samples consist predominantly of lithic arkoses and feldspathic litharenites; higher porosities, and therefore better reservoir potential, are associated with the feldspathic litharenites. Primary controls on porosity include compaction, clay-matrix content and calcite cementation. XRD data reveal the presence of illite, illite-smectite and chlorite. The presence of swelling clays has been the main cause of formation damage in the field.</p>\u0000 <p>The interpretation of meandering fluvial channels here is thought to represent the first published account of such channels within Pliocene reservoir rocks in the north of the South Caspian Basin. Previous accounts of the Red Series sandstones deposited onshore to the east have indicated deposition within braided channels of the palaeo-Amu Darya river delta plain, and alluvial-fan deposits sourced from uplands to the north. Deposition of the equivalent Productive Series by the palaeo-Volga in the Azerbaijan sector to the west has also been interpreted as having taken place within braided systems, although mixed or suspended-load fluvial channels ascribed to the contemporary Kura delta farther south may have been associated with a meandering system. Two palaeogeographic maps a","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"46 1","pages":"77-102"},"PeriodicalIF":1.8,"publicationDate":"2022-12-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://onlinelibrary.wiley.com/doi/epdf/10.1111/jpg.12831","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49237911","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Depleted chalk oilfields and chalk structures in the Danish Central Graben, North Sea, are potential CO2 storage sites. In most of these fields, the main reservoir is the Upper Cretaceous – Danian Chalk Group and the Eocene – Miocene mudstones of the Horda and Lark Formations constitute the primary seal. In a few fields, the reservoir is composed of the Lower Cretaceous Tuxen and Sola Formations. Here the main seal is assumed to be the Chalk Group which however has poor gas sealing characteristics; the Horda and Lark Formations constitute an efficient secondary seal although they are quite high in the section. This study documents a workflow that may help to evaluate the seal integrity of the structures from an integration of mud gas data from wells with seismic data. Mud gas data provide detailed information about the distribution and types of gas (biogenic or thermogenic) throughout the seal section and overburden. The presence of higher carbon number gases (C3–C5, propane to pentane) in the seal indicates migration of thermogenic gas into the thermally immature sealing mudstones; whereas the dominance of C1 (methane) and partly C2 (ethane) likely reflects the presence of in situ generated biogenic gas in the mudstones, thus indicating that there are no seal integrity issues. The vertical thermogenic gas migration front has been determined, and a “traffic light” indicator system has been used for seal integrity evaluation. Where no or minor migration of thermogenic gas into the primary seal has occurred and a primary seal >30 m thick is present, the seal is considered to have good matrix seal integrity (green). If some significant thermogenic gas migration has occurred into the primary seal but more than 30 m of primary seal is present above the thermogenic gas migration front, the seal integrity is reduced (yellow). In structures where thermogenic gas migration is recorded through the primary seal and into the overburden, seal integrity is considered to be poor (red). In areas where significant leakage of thermogenic gas has occurred into the seal, high density, low porosity carbonate beds frequently occur encapsulated within the sealing mudstones and are interpreted to be composed of methane-derived authigenic carbonates (MDACs). Seismic data show that there is a convincing correlation between leakage as indicated from mud gas data and the presence of vertical wipe-out zones (gas chimneys), bright zones (gas-charged sediments or MDACs), and depressions (pockmarks). In general, potential CO2 storage sites in the study area in tectonically inverted structures show good seal integrity, but this may locally be reduced and require additional analyses. Storage sites associated with salt diapirs generally show poor seal integrity and are likely to be poor candidates for CO2 storage. In combination, mud gas and seismic data are therefore powerful tools to investigate (
{"title":"APPLICATION OF MUD GAS DATA AND LEAKAGE PHENOMENA TO EVALUATE SEAL INTEGRITY OF POTENTIAL CO2 STORAGE SITES: A STUDY OF CHALK STRUCTURES IN THE DANISH CENTRAL GRABEN, NORTH SEA","authors":"H.I. Petersen, F.W.H. Smit","doi":"10.1111/jpg.12830","DOIUrl":"10.1111/jpg.12830","url":null,"abstract":"<p>Depleted chalk oilfields and chalk structures in the Danish Central Graben, North Sea, are potential CO<sub>2</sub> storage sites. In most of these fields, the main reservoir is the Upper Cretaceous – Danian Chalk Group and the Eocene – Miocene mudstones of the Horda and Lark Formations constitute the primary seal. In a few fields, the reservoir is composed of the Lower Cretaceous Tuxen and Sola Formations. Here the main seal is assumed to be the Chalk Group which however has poor gas sealing characteristics; the Horda and Lark Formations constitute an efficient secondary seal although they are quite high in the section. This study documents a workflow that may help to evaluate the seal integrity of the structures from an integration of mud gas data from wells with seismic data. Mud gas data provide detailed information about the distribution and types of gas (biogenic or thermogenic) throughout the seal section and overburden. The presence of higher carbon number gases (C<sub>3</sub>–C<sub>5</sub>, propane to pentane) in the seal indicates migration of thermogenic gas into the thermally immature sealing mudstones; whereas the dominance of C<sub>1</sub> (methane) and partly C<sub>2</sub> (ethane) likely reflects the presence of in situ generated biogenic gas in the mudstones, thus indicating that there are no seal integrity issues. The vertical thermogenic gas migration front has been determined, and a “traffic light” indicator system has been used for seal integrity evaluation. Where no or minor migration of thermogenic gas into the primary seal has occurred and a primary seal >30 m thick is present, the seal is considered to have good matrix seal integrity (green). If some significant thermogenic gas migration has occurred into the primary seal but more than 30 m of primary seal is present above the thermogenic gas migration front, the seal integrity is reduced (yellow). In structures where thermogenic gas migration is recorded through the primary seal and into the overburden, seal integrity is considered to be poor (red). In areas where significant leakage of thermogenic gas has occurred into the seal, high density, low porosity carbonate beds frequently occur encapsulated within the sealing mudstones and are interpreted to be composed of methane-derived authigenic carbonates (MDACs). Seismic data show that there is a convincing correlation between leakage as indicated from mud gas data and the presence of vertical wipe-out zones (gas chimneys), bright zones (gas-charged sediments or MDACs), and depressions (pockmarks). In general, potential CO<sub>2</sub> storage sites in the study area in tectonically inverted structures show good seal integrity, but this may locally be reduced and require additional analyses. Storage sites associated with salt diapirs generally show poor seal integrity and are likely to be poor candidates for CO<sub>2</sub> storage. In combination, mud gas and seismic data are therefore powerful tools to investigate (","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"46 1","pages":"47-75"},"PeriodicalIF":1.8,"publicationDate":"2022-12-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41421922","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper presents the results of an integrated geochemical study of oils in Jurassic – Cenozoic reservoirs in the eastern region of the Arabian Plate. The main objective was to analyze the active petroleum systems at a regional scale across the study area which extends from NE Iraq to SE Oman and includes the entire Persian Gulf. The dataset for the study consisted of more than 500 crude oil samples from 112 oil fields and 11 different reservoir units. This dataset was compiled from both the literature and re-evaluated geochemical and stable isotope analyses, augmented by new analytical studies.
The study documents regional variations and trends in the bulk and molecular properties and stable isotope ratios of the oil samples. Two overall clans and twelve genetic oil families and sub-families were distinguished using multivariate statistical analysis (chemometrics) based on biomarker parameters. The age, lithology, depositional setting and organic matter type of the respective source rocks for each family/sub-family was inferred from oil geochemical fingerprints.
The results provide insights into the key geological factors that control the number, size and geochemical character of oil fields in the eastern Arabian Plate. The geographical extent of the various oil families was assessed and used to evaluate charge access and to predict migration directions and migration pathways in the study area.
The results indicate the value of implementing multivariate statistical analysis on “big data” along with state-of-the-art geological petroleum systems analysis and interpretation of biomarker and oil composition data to investigate complex and extended petroleum systems.
{"title":"PETROLEUM SYSTEMS ANALYSIS OF THE EASTERN ARABIAN PLATE: CHEMOMETRICS BASED ON A REVIEW OF THE GEOCHEMICAL CHARACTERISTICS OF OILS IN JURASSIC – CENOZOIC RESERVOIRS","authors":"Alireza Baniasad, Ralf Littke, Qusay Abeed","doi":"10.1111/jpg.12829","DOIUrl":"10.1111/jpg.12829","url":null,"abstract":"<p>This paper presents the results of an integrated geochemical study of oils in Jurassic – Cenozoic reservoirs in the eastern region of the Arabian Plate. The main objective was to analyze the active petroleum systems at a regional scale across the study area which extends from NE Iraq to SE Oman and includes the entire Persian Gulf. The dataset for the study consisted of more than 500 crude oil samples from 112 oil fields and 11 different reservoir units. This dataset was compiled from both the literature and re-evaluated geochemical and stable isotope analyses, augmented by new analytical studies.</p><p>The study documents regional variations and trends in the bulk and molecular properties and stable isotope ratios of the oil samples. Two overall clans and twelve genetic oil families and sub-families were distinguished using multivariate statistical analysis (chemometrics) based on biomarker parameters. The age, lithology, depositional setting and organic matter type of the respective source rocks for each family/sub-family was inferred from oil geochemical fingerprints.</p><p>The results provide insights into the key geological factors that control the number, size and geochemical character of oil fields in the eastern Arabian Plate. The geographical extent of the various oil families was assessed and used to evaluate charge access and to predict migration directions and migration pathways in the study area.</p><p>The results indicate the value of implementing multivariate statistical analysis on “big data” along with state-of-the-art geological petroleum systems analysis and interpretation of biomarker and oil composition data to investigate complex and extended petroleum systems.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"46 1","pages":"3-45"},"PeriodicalIF":1.8,"publicationDate":"2022-12-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49525906","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Ramadan Musbah M. Saheed, Tatjana Šolević Knudsen, Musbah Abduljalil M. Faraj, Hans Peter Nytoft, Branimir Jovančićević
Crude oil samples from the Sharara-C oil field (Concession NC-115, Murzuq Basin, SW Libya) were analysed by organic geochemical methods in order to infer the geochemical characteristics of their respective source rocks. Aromatic hydrocarbons were analysed by gas chromatography – mass spectrometry (GC-MS), and gas chromatography – tandem mass spectrometry (GC-MS-MS) was used to analyse saturated biomarkers. The Sharara-C oils are interpreted to have been generated by marine shales containing mixed terrigenous and marine organic materials deposited in an intermediate (suboxic) environment. Age-specific biomarker ratios indicated that the oils are older than Cretaceous, and maturation-related parameters pointed to their high thermal maturity. Consistent with previous studies, source rocks are inferred to be “hot” shales in the Lower Silurian Tanezzuft Formation.
Almost all the parameter ratios calculated varied over a very narrow range, indicating that the investigated oils were compositionally similar. The only significant difference that was noted concerned the sterane/hopane ratios whose variation suggested that there was some variability in the composition of the source organic material.
The organic geochemical parameters determined for the Sharara-C crude oils were compared with published data on other crude oils from Concession NC-115. Almost all the parameters agreed well with previously published data on oils from this part of the Murzuq Basin. The greatest deviation concerned the values of some of the maturity parameters. This tended to confirm the conclusions of previous studies concerning the presence of a number of distinct oil families and sub-families in the Sharara oil field area which are genetically related but which have different maturities.
{"title":"GEOCHEMICAL CHARACTERISTICS OF CRUDE OILS FROM THE SHARARA-C OIL FIELD, MURZUQ BASIN, SOUTHWESTERN LIBYA","authors":"Ramadan Musbah M. Saheed, Tatjana Šolević Knudsen, Musbah Abduljalil M. Faraj, Hans Peter Nytoft, Branimir Jovančićević","doi":"10.1111/jpg.12832","DOIUrl":"10.1111/jpg.12832","url":null,"abstract":"<p>Crude oil samples from the Sharara-C oil field (Concession NC-115, Murzuq Basin, SW Libya) were analysed by organic geochemical methods in order to infer the geochemical characteristics of their respective source rocks. Aromatic hydrocarbons were analysed by gas chromatography – mass spectrometry (GC-MS), and gas chromatography – tandem mass spectrometry (GC-MS-MS) was used to analyse saturated biomarkers. The Sharara-C oils are interpreted to have been generated by marine shales containing mixed terrigenous and marine organic materials deposited in an intermediate (suboxic) environment. Age-specific biomarker ratios indicated that the oils are older than Cretaceous, and maturation-related parameters pointed to their high thermal maturity. Consistent with previous studies, source rocks are inferred to be “hot” shales in the Lower Silurian Tanezzuft Formation.</p><p>Almost all the parameter ratios calculated varied over a very narrow range, indicating that the investigated oils were compositionally similar. The only significant difference that was noted concerned the sterane/hopane ratios whose variation suggested that there was some variability in the composition of the source organic material.</p><p>The organic geochemical parameters determined for the Sharara-C crude oils were compared with published data on other crude oils from Concession NC-115. Almost all the parameters agreed well with previously published data on oils from this part of the Murzuq Basin. The greatest deviation concerned the values of some of the maturity parameters. This tended to confirm the conclusions of previous studies concerning the presence of a number of distinct oil families and sub-families in the Sharara oil field area which are genetically related but which have different maturities.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"46 1","pages":"103-123"},"PeriodicalIF":1.8,"publicationDate":"2022-12-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43958983","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"地球科学","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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