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}
Most of the potential sandstone reservoirs within the Namurian and lower Westphalian succession of the Southern North Sea Basin are originally feldspathic sands in which the feldspar has mainly been altered to microporous kaolinite clays. The sandstones provide a moderate porosity (typically 8-15%, depending mainly on grain size), but permeability is severely limited owing to the microporous nature of much of the porosity. Permeability is typically 1 mD or less, rising to a few tens of millidarcies in occasional coarse- and very coarse-grained sands. Predicting the presence of higher-permeability reservoir zones is therefore a critical exploration problem in these successions.
Quartzitic sands have been discovered in places, especially for example in the Trent field (block 43/24), where physical reworking of sands during the transgressions that preceded the deposition of marine bands removed much of the feldspar, so that less clay was formed during burial diagenesis. Although these sandstones display moderately elevated permeabilities, commonly several to several tens of millidarcies, they are usually fine-grained, which limits their reservoir potential.
A particular type of quartzitic sandstone reservoir has been identified quite widely within the Namurian and lower Westphalian succession of the Southern North Sea. This type is indistinguishable in terms of sedimentology and inferred detrital composition from the originally feldspathic facies which now form the widespread kaolinite-rich, low-permeability sandstones. However, it has a very low kaolinite content (commonly 1-2%, compared with a more usual 5-20%) so that these sandstones display permeabilities of the order of several hundred millidarcies.
Wireline log data from nineteen wells within UK Quadrants 43 and 44 have been examined, and all relevant core logged in order to compare the depositional settings of the quartzitic and non-quartzitic sandstones. Existing data from over 500 petrographic thin sections from the area have been reviewed and 78 new thin sections analysed to determine the petrographic controls on reservoir quality in both sandstone types. The diagenetic histories of each type have been interpreted. The dissolution of feldspars during diagenesis of the quartzitic sandstones, without a substantial residue of kaolinite or other aluminium-rich mineral, is attributed to the mobilisation of aluminium within organic complexes. This is thought to require the presence of certain organic acids.
{"title":"QUARTZITIC SANDSTONES IN THE NAMURIAN AND LOWER WESTPHALIAN SUCCESSION OF THE SOUTHERN NORTH SEA: A NEW HIGH-PERMEABILITY CARBONIFEROUS RESERVOIR TYPE","authors":"G. A. Blackbourn, J. D. Collinson","doi":"10.1111/jpg.12824","DOIUrl":"10.1111/jpg.12824","url":null,"abstract":"<p>Most of the potential sandstone reservoirs within the Namurian and lower Westphalian succession of the Southern North Sea Basin are originally feldspathic sands in which the feldspar has mainly been altered to microporous kaolinite clays. The sandstones provide a moderate porosity (typically 8-15%, depending mainly on grain size), but permeability is severely limited owing to the microporous nature of much of the porosity. Permeability is typically 1 mD or less, rising to a few tens of millidarcies in occasional coarse- and very coarse-grained sands. Predicting the presence of higher-permeability reservoir zones is therefore a critical exploration problem in these successions.</p><p>Quartzitic sands have been discovered in places, especially for example in the Trent field (block 43/24), where physical reworking of sands during the transgressions that preceded the deposition of marine bands removed much of the feldspar, so that less clay was formed during burial diagenesis. Although these sandstones display moderately elevated permeabilities, commonly several to several tens of millidarcies, they are usually fine-grained, which limits their reservoir potential.</p><p>A particular type of quartzitic sandstone reservoir has been identified quite widely within the Namurian and lower Westphalian succession of the Southern North Sea. This type is indistinguishable in terms of sedimentology and inferred detrital composition from the originally feldspathic facies which now form the widespread kaolinite-rich, low-permeability sandstones. However, it has a very low kaolinite content (commonly 1-2%, compared with a more usual 5-20%) so that these sandstones display permeabilities of the order of several hundred millidarcies.</p><p>Wireline log data from nineteen wells within UK Quadrants 43 and 44 have been examined, and all relevant core logged in order to compare the depositional settings of the quartzitic and non-quartzitic sandstones. Existing data from over 500 petrographic thin sections from the area have been reviewed and 78 new thin sections analysed to determine the petrographic controls on reservoir quality in both sandstone types. The diagenetic histories of each type have been interpreted. The dissolution of feldspars during diagenesis of the quartzitic sandstones, without a substantial residue of kaolinite or other aluminium-rich mineral, is attributed to the mobilisation of aluminium within organic complexes. This is thought to require the presence of certain organic acids.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"45 4","pages":"363-393"},"PeriodicalIF":1.8,"publicationDate":"2022-09-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"48430927","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}
A.S.M. Al Ghafri, A.P. Heward, G.A. Booth, I.A. Abbasi
The age and origin of reservoir sandstones which underlie the lowermost Silurian “hot” shales of the Sahmah Formation in the west of Oman is controversial. Here we describe one such sandstone which was cored and interpreted based on geological well evidence, and which then had to be re-interpreted when definitive palynological results became available. The findings are enhanced when interpreted along with other deep wells in the area which have consistent palynological data.
The western part of the Sultanate of Oman is a tectonically stable intra-basinal high with low regional dips. In this area, the relief on the base-Silurian unconformity of >250 m appears to be greater than that beneath the Permo-Carboniferous unconformity which is well known for being highly erosive. The sandstones preserved beneath the base-Silurian unconformity vary in depositional environment and reservoir quality from well to well, depending on their age, degree of erosion and differences in regional subsidence.
There has been little evidence for the presence of Hirnantian-aged deposits in Oman to date. However, some of the erosion and deep incisions which affect deposits of the Upper Ordovician Hasirah Formation are almost certainly related to falling sea levels accompanying the Hirnantian glaciation, just as the presence of the “hot shale” source rocks in the overlying Sahmah Formation are likely to be related to rising sea-levels and anoxic conditions during the later deglaciation. Deformed strata in the Upper Ordovician deposits may reflect the instability of valley-sides cut into weakly-consolidated strata exposed during changes in sea-level.
The Sahmah oil play underlying the basal Silurian “hot” shales in Oman carries significant risks relating to the presence or absence of closures and reservoir, and the character, continuity and cementation of reservoir sandstones.
{"title":"THE AGE, ORIGIN AND CONTEXT OF RESERVOIR SANDSTONES UNDERLYING THE LOWERMOST SILURIAN “HOT” SHALES IN THE WEST OF THE SULTANATE OF OMAN","authors":"A.S.M. Al Ghafri, A.P. Heward, G.A. Booth, I.A. Abbasi","doi":"10.1111/jpg.12823","DOIUrl":"10.1111/jpg.12823","url":null,"abstract":"<p>The age and origin of reservoir sandstones which underlie the lowermost Silurian “hot” shales of the Sahmah Formation in the west of Oman is controversial. Here we describe one such sandstone which was cored and interpreted based on geological well evidence, and which then had to be re-interpreted when definitive palynological results became available. The findings are enhanced when interpreted along with other deep wells in the area which have consistent palynological data.</p><p>The western part of the Sultanate of Oman is a tectonically stable intra-basinal high with low regional dips. In this area, the relief on the base-Silurian unconformity of >250 m appears to be greater than that beneath the Permo-Carboniferous unconformity which is well known for being highly erosive. The sandstones preserved beneath the base-Silurian unconformity vary in depositional environment and reservoir quality from well to well, depending on their age, degree of erosion and differences in regional subsidence.</p><p>There has been little evidence for the presence of Hirnantian-aged deposits in Oman to date. However, some of the erosion and deep incisions which affect deposits of the Upper Ordovician Hasirah Formation are almost certainly related to falling sea levels accompanying the Hirnantian glaciation, just as the presence of the “hot shale” source rocks in the overlying Sahmah Formation are likely to be related to rising sea-levels and anoxic conditions during the later deglaciation. Deformed strata in the Upper Ordovician deposits may reflect the instability of valley-sides cut into weakly-consolidated strata exposed during changes in sea-level.</p><p>The Sahmah oil play underlying the basal Silurian “hot” shales in Oman carries significant risks relating to the presence or absence of closures and reservoir, and the character, continuity and cementation of reservoir sandstones.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"45 4","pages":"345-362"},"PeriodicalIF":1.8,"publicationDate":"2022-09-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45648914","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}
M. Molina Camargo, G. F. Chinelatto, M. Basso, A. C. Vidal
Lower Cretaceous carbonates in the pre-salt succession in the Santos Basin, eastern Brazil, are highly heterogeneous in terms of their reservoir characteristics as a result of depositional and diagenetic factors. Electrofacies have widely been used for reservoir zonation and, when allied with computer-based methods such as neural networks, may help with the study of such complex reservoir rocks and with the identification of high-quality reservoir zones. In this work, an unsupervised artificial neural network known as a self-organizing map (SOM) was used to carry out a zonation of the pre-salt carbonates in the Aptian Barra Velha Formation, the main reservoir unit in the Santos Basin. Available data included gramma-ray, neutron porosity, resistivity deep, sonic, density, photoelectric factor, total porosity and effective porosity profiles from 21 wells together with mineralogical models. Core descriptions and thin section images were used as additional data for the lithological characterization of the electrofacies and consequently for reservoir zonation. A total of four electrofacies were defined from the SOM application, and five reservoir zones were identified.
The characterization of the reservoir zones also considered the structural locations of the wells based on the relative depth to top- Barra Velha Formation; well locations were classified as structurally high, intermediate or low. Based on the reservoir zone characteristics, the results could be correlated with zonations in previous studies. A general tendency was noted for there to be an increase of finer-grained sediments in the formation in wells located in structural lows; packstone and mudstone facies were prevalent in these wells and were in general characterized as poor-quality reservoir rocks. By contrast, the shrubstones and grainstones which were more frequent in structurally high wells comprised higher quality reservoir rocks.
The basal reservoir zone showed wide lithological variation compared to the overlying reservoir zones. Grainstone-dominated facies were identified in the middle of the formation, and the uppermost reservoir zones were characterized by an upward increase in shrubstones and reworked grainstones which in general pointed to better quality reservoirs.
巴西东部桑托斯盆地下白垩统盐下碳酸盐岩受沉积和成岩因素影响，储层特征极不均匀。电相已被广泛用于储层划分，当与神经网络等基于计算机的方法相结合时，可以帮助研究这种复杂的储层岩石并识别优质储层。在这项工作中，一种被称为自组织图(SOM)的无监督人工神经网络被用于对Aptian Barra Velha组(Santos盆地的主要储层单元)的盐下碳酸盐岩进行分带。现有数据包括21口井的伽马、中子孔隙度、深部电阻率、声波、密度、光电系数、总孔隙度和有效孔隙度剖面以及矿物学模型。岩心描述和薄片图像被用作电相岩性表征的附加数据，从而用于储层分带。通过SOM应用，共确定了4个电相，并确定了5个储层。储层的表征还考虑了基于Barra Velha组顶部相对深度的井的构造位置;井位被划分为构造高、中、低。根据储层的区带特征，研究结果可以与前人的研究分区相关联。构造低洼井中，地层中细粒沉积物呈增加趋势;这些井以包岩和泥岩相为主，总体上属于劣质储层。而在构造高的井中较为常见的灌木岩和颗粒岩则构成了较优质的储集岩。与上覆储层相比，基底储层岩性差异较大。储层中部以颗粒岩为主，上部储层发育灌木岩和改造颗粒岩，储层质量总体较好。
{"title":"ELECTROFACIES DEFINITION AND ZONATION OF THE LOWER CRETACEOUS BARRA VELHA FORMATION CARBONATE RESERVOIR IN THE PRE-SALT SEQUENCE OF THE SANTOS BASIN, SE BRAZIL","authors":"M. Molina Camargo, G. F. Chinelatto, M. Basso, A. C. Vidal","doi":"10.1111/jpg.12827","DOIUrl":"10.1111/jpg.12827","url":null,"abstract":"<p>Lower Cretaceous carbonates in the pre-salt succession in the Santos Basin, eastern Brazil, are highly heterogeneous in terms of their reservoir characteristics as a result of depositional and diagenetic factors. Electrofacies have widely been used for reservoir zonation and, when allied with computer-based methods such as neural networks, may help with the study of such complex reservoir rocks and with the identification of high-quality reservoir zones. In this work, an unsupervised artificial neural network known as a self-organizing map (SOM) was used to carry out a zonation of the pre-salt carbonates in the Aptian Barra Velha Formation, the main reservoir unit in the Santos Basin. Available data included gramma-ray, neutron porosity, resistivity deep, sonic, density, photoelectric factor, total porosity and effective porosity profiles from 21 wells together with mineralogical models. Core descriptions and thin section images were used as additional data for the lithological characterization of the electrofacies and consequently for reservoir zonation. A total of four electrofacies were defined from the SOM application, and five reservoir zones were identified.</p><p>The characterization of the reservoir zones also considered the structural locations of the wells based on the relative depth to top- Barra Velha Formation; well locations were classified as structurally high, intermediate or low. Based on the reservoir zone characteristics, the results could be correlated with zonations in previous studies. A general tendency was noted for there to be an increase of finer-grained sediments in the formation in wells located in structural lows; packstone and mudstone facies were prevalent in these wells and were in general characterized as poor-quality reservoir rocks. By contrast, the shrubstones and grainstones which were more frequent in structurally high wells comprised higher quality reservoir rocks.</p><p>The basal reservoir zone showed wide lithological variation compared to the overlying reservoir zones. Grainstone-dominated facies were identified in the middle of the formation, and the uppermost reservoir zones were characterized by an upward increase in shrubstones and reworked grainstones which in general pointed to better quality reservoirs.</p>","PeriodicalId":16748,"journal":{"name":"Journal of Petroleum Geology","volume":"45 4","pages":"439-459"},"PeriodicalIF":1.8,"publicationDate":"2022-09-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49660597","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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