To see the other types of publications on this topic, follow the link: Traps (Petroleum geology).
Journal articles on the topic 'Traps (Petroleum geology)'
Create a spot-on reference in APA, MLA, Chicago, Harvard, and other styles
Consult the top 50 journal articles for your research on the topic 'Traps (Petroleum geology).'
Next to every source in the list of references, there is an 'Add to bibliography' button. Press on it, and we will generate automatically the bibliographic reference to the chosen work in the citation style you need: APA, MLA, Harvard, Chicago, Vancouver, etc.
You can also download the full text of the academic publication as pdf and read online its abstract whenever available in the metadata.
Browse journal articles on a wide variety of disciplines and organise your bibliography correctly.
1
Mandelbaum, M. M., and A. I. Shamal. "Geophysical methods of oil and gas exploration in cambrian and precambrian sedimentary rocks of the Siberian Platform." Exploration Geophysics 20, no. 2 (1989): 37. http://dx.doi.org/10.1071/eg989037a.
Full textAbstract:
The Siberian Platform is the largest hydrocarbon-bearing sedimentary basin in the USSR. The conditions encountered in geophysical exploration in this basin are uniquely difficult. This very old sedimentary complex is characterised by abrupt changes in physical properties reflecting the presence of dolerites and tuffs, changes in salt thickness, and complex structure. Petroleum traps are controlled by low amplitude structures in the salt complex, although reservoir properties are variable, so that most traps are stratigraphic. This leads to the use of frequency content of seismic data to identify traps and electrical and time domain EM techniques to confirm the presence of the traps.
2
Zhou, Zhicheng, Wenlong Ding, Ruifeng Zhang, Mingwang Xue, Baocheng Jiao, Chenlin Wu, Yuting Chen, Liang Qiu, Xiaoyu Du, and Tianshun Liu. "Structural styles and tectonic evolution of Mesozoic–Cenozoic faults in the Eastern Depression of Bayanhaote Basin, China: implications for petroleum traps." Geological Magazine 159, no. 5 (January 20, 2022): 689–706. http://dx.doi.org/10.1017/s0016756821001242.
Full textAbstract:
AbstractThe Eastern Depression in the Bayanhaote Basin in western Inner Mongolia has experienced multi-stage Meso-Cenozoic tectonic events and possesses considerable exploration potential. However, structural deformation patterns, sequences and the genesis of oil-bearing structures in the basin are still poorly understood. In this study, based on high-quality 2D seismic data and drilling and well-logging data, we elucidate the activities and structural styles of faults, the tectonic evolution and the distribution characteristics of styles, as well as assessing potential petroleum traps in the Eastern Depression. Five types of faults that were active at different stages of the Meso-Cenozoic faults have been recognized: long-lived normal faults active since the late Middle Jurassic; reverse faults and strike-slip faults active in the late Late Jurassic; normal faults active in the Early Cretaceous; normal faults active in the Oligocene; and negative inverted faults active in the Early Cretaceous and Oligocene. These faults constituted 12 geometric styles in NE-trending belts at various stratigraphic levels, and were formed by compression, strike-slip, extension and inversion. The temporal development of structural styles promoted the formation and reconstruction and finalization of structural traps, while regional unconformities and open reverse and strike-slip faults provided migration pathways for petroleum to fill the traps. In general, potential traps that formed by compressional movement and strike-slip movement in the late Late Jurassic are primarily faulted anticlines. Those traps developed in Carboniferous rocks and are located in the southwestern region of the Eastern Depression, being controlled by NNE-NE-striking reverse and transpressive faults.
3
Lambiase, J. J. "Structural Traps VII. Treatise of petroleum geology, Atlas of Oil and Gas Fields." Marine and Petroleum Geology 11, no. 2 (April 1994): 247. http://dx.doi.org/10.1016/0264-8172(94)90100-7.
Full text
4
Sangree, John B. "Stratigraphic traps I: Treatise of petroleum geology, Atlas of oil and gas fields." Marine and Petroleum Geology 9, no. 5 (October 1992): 573. http://dx.doi.org/10.1016/0264-8172(92)90068-p.
Full text
5
Terken, Jos M. J. "The Natih Petroleum System of North Oman." GeoArabia 4, no. 2 (April 1, 1999): 157–80. http://dx.doi.org/10.2113/geoarabia0402157.
Full textAbstract:
ABSTRACT The Cretaceous Natih petroleum system is one of the smaller petroleum systems in Oman, measuring only some 20,000 square kilometers in areal extent. Resource volumes of oil initially in-place, however, are significant and amount to 1.3x109 cubic meters (equivalent to 8.2 billion barrels). Most of the recoverable oil is concentrated in two giant fields that were discovered in the early 1960s. Since that prolific time no new major discoveries have been made, except some marginally economic accumulations in the early 1980s. To evaluate the remaining hydrocarbon potential of the system, the oil kitchen was mapped and its generation and migration histories modeled and integrated with the regional setting to outline the geographical and stratigraphical extent of the petroleum system. The volume of liquid hydrocarbons generated by Natih source rocks was calculated and compared to the estimated oil-in-place to determine the generation-trapping efficiency of the petroleum system. Some 100x109 cubic meters of source rock is currently mature and produced a cumulative volume of 14x109 cubic meters (88 billion barrels) oil. Of this volume 9% has actually been discovered and 0.25x109 cubic meters (1.57 billion barrels) are currently booked as recoverable reserves, equivalent to 1.8% of the total generated volume. Both percentages classify the Natih petroleum system as the most efficient system in Oman. This extreme efficiency results from several factors, such as: (1) modest structural deformation in the foreland basin, which permits lateral migration to remain the dominant style; (2) abundant and uninterrupted access to oil charge from an active kitchen in the foreland basin; and (3) excellent intra-formational source rocks, which is retained by thick Fiqa shales. Most structural prospects have been tested in four decades of exploration. The remaining hydrocarbon potential is anticipated to exist mainly in stratigraphic traps in Fiqa turbidites in the foreland basin, and truncation traps across the northern flank of the peripheral bulge.
6
McLennan, Jeanette M., John S. Rasidi, Richard L. Holmes, and Greg C. Smith. "THE GEOLOGY AND PETROLEUM POTENTIAL OF THE WESTERN ARAFURA SEA." APPEA Journal 30, no. 1 (1990): 91. http://dx.doi.org/10.1071/aj89005.
Full textAbstract:
The northern Bonaparte Basin and the Arafura-Money Shoal Basins lie along Australia's offshore northern margin and offer significantly different exploration prospects resulting from their differing tectonic and burial histories. The Arafura Basin is dominated by a deep, faulted and folded, NW-SE orientated Palaeozoic graben overlain by the relatively flat-lying Jurassic-Tertiary Money Shoal Basin. The north-eastern Bonaparte Basin is dominated by the deep NE-SW orientated Malita Graben with mainly Jurassic to Recent basin-fill.A variety of potential structural and stratigraphic traps occur in the region especially associated with the grabens. They include tilted or horst fault blocks and large compressional, drape and rollover anticlines. Some inversion and possibly interference anticlines result from late Cenozoic collision between the Australian plate and Timor and the Banda Arc.In the Arafura-Money Shoal Basins, good petroleum source rocks occur in the Cambrian, Carboniferous and Jurassic-Cretaceous sequences although maturation is biassed towards early graben development. Jurassic-Neocomian sandstones have the best reservoir potential, Carboniferous clastics offer moderate prospects, and Palaeozoic carbonates require porosity enhancement.The Malita Graben probably contains good potential Jurassic source rocks which commenced generation in the Late Cretaceous. Deep burial in the graben has decreased porosity of the Jurassic-Neocomian sandstones significantly but potential reservoirs may occur on the shallower flanks.The region is sparsely explored and no commercial discoveries exist. However, oil and gas indications are common in a variety of Palaeozoic and Mesozoic sequences and structural settings. These provide sufficient encouragement for a new round of exploration.
7
Sobolev, P. N., and S. V. Dykhan. "OIL-AND-GAS SOURCE ROCKS AND THE PROBLEM OF PETROLEUM POTENTIAL OF THE ALDAN-MAYA DEPRESSION (SOUTH-EAST OF THE SIBERIAN PLATFORM)." Geology and mineral resources of Siberia, no. 3 (October 2022): 30–38. http://dx.doi.org/10.20403/2078-0575-2022-3-30-38.
Full textAbstract:
The analysis of existing understandings about distribution of oil-and-gas source rocks was performed for sedimentary section of the Aldan-Maya depression, the large margin structure in the south-east of the Siberian Platform. Taking into account new materials, the oil-and-gas generating potential of these strata was critically examined, and the ideas of previous research period were defined more precisely. On this basis, the sketch map of oil-and-gas bearing stratigraphic breakdown of the Aldan-Maya depression sedimentary cover was compiled. The main elements of hydrocarbon systems, including predicted petroleum plays and petroleum bearing strata were identified, forecast of possible types of traps for various parts of the depression was given. Based on this experience, the contour map of the petroleum potential forecast for the Aldan-Maya depression and adjacent territories was compiled.
8
Vuong, Hoang Van, Tran Van Kha, Pham Nam Hung, and Nguyen Kim Dung. "Research on deep geological structure and forecasting of some areas with petroleum prospects in the Red river delta coastal strip according to geophysical data." Tạp chí Khoa học và Công nghệ biển 19, no. 3B (October 21, 2019): 71–89. http://dx.doi.org/10.15625/1859-3097/19/3b/14516.
Full textAbstract:
The coastal areas of the Red River Delta are the transition areas from the continent to the sea and have great mineral prospects, especially petroleum prospects. In this area, a lot of topics and projects in geology and geophysics have been conducted for many different purposes such as studying the deep structure, tectonic - geological features, seismic reflection - refraction to identify petroleum traps in the Cenozoic sediments... However there are very few studies on deep structure features, using the results of processing and meta-analysis of gravity, magnetotelluric, tectonic - geological data to detect the direct and indirect relations to the formation of structures with petroleum potential. The authors have researched, tested and applied an appropriate methodology of processing and analysis, to overcome the shortfall of gravity data as well as the nonhomogeneity in details of seismic and geophysical surveys. The obtained results are semi-quantitative and qualitative characteristics of structure of deep boundary surfaces, structural characteristics of fault systems and their distribution in the study area, calculation of the average rock density of pre-Cenozoic basement... From these results, the authors established the zoning map of the areas with petroleum potential in the Red river delta coastal strip according to geophysical data.
9
Vujovic, Aleksandar, Ritu Gupta, and Gregory C. Smith. "Portfolio analysis of petroleum fields and prospects: a robust statistical method." APPEA Journal 57, no. 2 (2017): 572. http://dx.doi.org/10.1071/aj16095.
Full textAbstract:
Portfolio analysis of several prospects, fields or assets is an important part of economic analysis routinely done by most exploration, development and production companies, often for large dollar amounts. Yet the methods used have not changed for decades, most are done in complicated and difficult to audit spreadsheets, and commonly they are not statistically robust, meaning they sometimes give incorrect results. The Curtin University Petroleum Geology Group has an active research program working with the Curtin Statistical Group to improve assessment of petroleum volumetrics, risking, scenario and portfolio analysis. This note provides a simple case study of portfolio analysis using an area in the North West Shelf in which we have quickly mapped several leads, prospects and drilled traps. They span a range of risk outcomes from undrilled to drilled, of which some were dry and some were successful to varying degrees. The results allow us to demonstrate how to calculate and aggregate the volumes and dependencies for each structure, correctly add the results using a new statistical methodology and formulate the aggregated volumetric distribution for the portfolio. This workflow can be used for any portfolio in the petroleum and other industries.
10
Stoupakova, Antonina V., Nataliya I. Korobova, Alina V. Mordasova, Roman S. Sautkin, Ekaterina D. Sivkova, Maria A. Bolshakova, Mikhail E. Voronin, et al. "Depositional environments as a framework for genetic classification of the basic criteria of petroleum potential." Georesursy 25, no. 2 (June 30, 2023): 75–88. http://dx.doi.org/10.18599/grs.2023.2.6.
Full textAbstract:
Most classifications of reservoirs, seals and source rocks based on the ability of the rock to generate, accumulate and preserve hydrocarbons, and the genesis of rocks is not always taken into account. The article presents a ranking scheme for continental, coastal-marine and marine sedimentation environments that determine the genesis and properties of the basic criteria of petroleum potential – source rocks, reservoirs, seals and pinch-out traps. Rocks, which can consider as source rock, reservoirs and seals are formed in each depositional environment. However, their structure, mineral composition and distribution area will differ from each other depending on the sedimentary environment and conditions. A combination of elements of the hydrocarbon system formed, corresponding to the sedimentation environment and are characteristic for basins of various types. Continental environments are favorable for the formation of reservoirs and local seals, while the accumulation of source rocks limited by lacustrine, floodplain, and swamp facies. The coastal-marine environment is favorable for the formation of all the basic criteria of petroleum potential, and the transgressive-regressive cyclicity determines the interbedding of source rocks, reservoirs and seals in the section. The marine depositional environments are most favorable for the formation of regional seals and source rocks, including high-carbon formations. The proposed ranking scheme of sedimentary environments and the basic criteria of petroleum potential genetically related to them is applicable in system analysis and selection for analogues of petroleum system elements in sedimentary complexes formed in similar depositional environments.
11
Pitman, Janet K., Douglas Steinshouer, and Michael D. Lewan. "Petroleum generation and migration in the Mesopotamian Basin and Zagros Fold Belt of Iraq: results from a basin-modeling study." GeoArabia 9, no. 4 (October 1, 2004): 41–72. http://dx.doi.org/10.2113/geoarabia090441.
Full textAbstract:
ABSTRACT A regional 3-D total petroleum-system model was developed to evaluate petroleum generation and migration histories in the Mesopotamian Basin and Zagros fold belt in Iraq. The modeling was undertaken in conjunction with Middle East petroleum assessment studies conducted by the USGS. Regional structure maps, isopach and facies maps, and thermal maturity data were used as input to the model. The oil-generation potential of Jurassic source-rocks, the principal known source of the petroleum in Jurassic, Cretaceous, and Tertiary reservoirs in these regions, was modeled using hydrous pyrolysis (Type II-S) kerogen kinetics. Results showed that oil generation in source rocks commenced in the Late Cretaceous in intrashelf basins, peak expulsion took place in the late Miocene and Pliocene when these depocenters had expanded along the Zagros foredeep trend, and generation ended in the Holocene when deposition in the foredeep ceased. The model indicates that, at present, the majority of Jurassic source rocks in Iraq have reached or exceeded peak oil generation and most rocks have completed oil generation and expulsion. Flow-path simulations demonstrate that virtually all oil and gas fields in the Mesopotamian Basin and Zagros fold belt overlie mature Jurassic source rocks (vertical migration dominated) and are situated on, or close to, modeled migration pathways. Fields closest to modeled pathways associated with source rocks in local intrashelf basins were charged earliest from Late Cretaceous through the middle Miocene, and other fields filled later when compression-related traps were being formed. Model results confirm petroleum migration along major, northwest-trending folds and faults, and oil migration loss at the surface.
12
Stoupakova, Antonina V., Andrey A. Polyakov, Nikolay A. Malyshev, Roman S. Sautkin, Vladimir E. Verzhbitsky, Dmitry K. Komissarov, Vitkoriya V. Volyanskaya, et al. "Criteria of petroleum potential of a sedimentary basin." Georesursy 25, no. 2 (June 30, 2023): 5–21. http://dx.doi.org/10.18599/grs.2023.2.1.
Full textAbstract:
The criteria of petroleum potential of a sedimentary basin are the features that characterize the evolution of a hydrocarbon system as a geological unit. There are basic and additional criteria of oil and gas potential. Without basic criteria, the functioning of the hydrocarbon system and consequent petroleum field formation is impossible. Additional criteria characterize qualitatively and quantitatively properties of the basic criteria. The properties of all basic criteria are ordered by genesis and summarized in a system that allows to quickly and accurately establish a relationship between them and classify them. The system can be used to select quantitative parameters for geological simulation of different scales, but also for automated applying for petroleum exploration and production. At the same time, the classification of basic criteria can be used at all stages of exploration. At the prospecting stage, when the type of sedimentary basin and the sedimentary conditions are recognized with some uncertainty, it is possible to predict the properties of source rocks, reservoirs, types of traps and seals. If all static basic criteria, such as source rock, reservoir, seal and trap, are available, it is possible to simulate the formation of petroleum fields, including generation, migration, accumulation and subsequent post-accumulation processes. At the stage of exploration and development, the classifications will help to verify the geological and hydrodynamic models of the field, taking into account the link to the regional and local structural plans and correctly identify the geological features of the study object and select the geological analogues.
13
Wender, Lawrence E., Jeffrey W. Bryant, Martin F. Dickens, Allen S. Neville, and Abdulrahman M. Al-Moqbel. "Paleozoic (Pre-Khuff Hydrocarbon Geology of the Ghawar Area, Eastern Saudi Arabia." GeoArabia 3, no. 2 (April 1, 1998): 273–302. http://dx.doi.org/10.2113/geoarabia0302273.
Full textAbstract:
ABSTRACT Saudi Aramco is conducting an exploration program to discover additional non-associated gas reserves in the Ghawar Area. The program has successfully discovered significant sweet gas and condensate reserves in the pre-Khuff siliciclastics and has further increased our understanding of the Paleozoic petroleum system. The Lower Permian Unayzah Formation is the principal pre-Khuff hydrocarbon reservoir in the Southern Ghawar Area, where it contains both oil and gas. The Unayzah consists of fluvial to marginal marine sandstones. The Devonian Jauf Formation is the principal pre-Khuff reservoir in the Northern Ghawar Area, where it hosts the recently discovered giant Hawiyah gas-condensate field. The Jauf consists of shallow marine sandstones that exhibit unusually high porosities considering the burial depths. The primary source rock for pre-Khuff hydrocarbons is the basal “hot shale” of the Lower Silurian Qalibah Formation. Maturation modeling of these shales indicates hydrocarbon generation began in the Middle Triassic (oil) and continues to the present (dry gas). Pre-Khuff hydrocarbon traps are found in simple four-way closures as well as more complex structural-stratigraphic traps on the flanks of Hercynian structures. Trap formation and modification occurred in four main phases: (1) Carboniferous (Hercynian Orogeny); (2) Early Triassic (Zagros Rifting); (3) Late Cretaceous (First or Early Alpine Orogeny); and (4) Tertiary (Second or Late Alpine Orogeny). Structures in the Ghawar Area show differences in growth histories, which have impacted the amount and type of hydrocarbons contained.
14
Botor, Dariusz. "Burial and Thermal History Modeling of the Paleozoic–Mesozoic Basement in the Northern Margin of the Western Outer Carpathians (Case Study from Pilzno-40 Well, Southern Poland)." Minerals 11, no. 7 (July 6, 2021): 733. http://dx.doi.org/10.3390/min11070733.
Full textAbstract:
Hydrocarbon exploration under thrust belts is a challenging frontier globally. In this work, 1-D thermal maturity modeling of the Paleozoic–Mesozoic basement in the northern margin of the Western Outer Carpathians was carried out to better explain the thermal history of source rocks that influenced hydrocarbon generation. The combination of Variscan burial and post-Variscan heating due to elevated heat flow may have caused significant heating in the Paleozoic basement in the pre-Middle Jurassic period. However, the most likely combined effect of Permian-Triassic burial and Late Triassic–Early Jurassic increase of heat flow caused the reaching of maximum paleotemperature. The main phase of hydrocarbon generation in Paleozoic source rocks developed in pre-Middle Jurassic times. Therefore, generated hydrocarbons from Ordovician and Silurian source rocks were lost before reservoirs and traps were formed in the Late Mesozoic. The Miocene thermal overprint due to the Carpathian overthrust probably did not significantly change the thermal maturity of organic matter in the Paleozoic–Mesozoic strata. Thus, it can be concluded that petroleum accumulations in the Late Jurassic and Cenomanian reservoirs of the foreland were charged later, mainly by source rocks occurring within the thrustbelt, i.e., Oligocene Menilite Shales. Finally, this work shows that comprehensive mineralogical and geochemical studies are an indispensable prerequisite of any petroleum system modelling because their results could influence petroleum exploration of new oil and gas fields.
15
Suslova, Anna A., Antonina V. Stoupakova, Alina V. Mordasova, and Roman S. Sautkin. "Structural reconstructions of the Eastern Barents Sea at Meso-Tertiary evolution and influence on petroleum potential." Georesursy 23, no. 1 (March 30, 2021): 78–84. http://dx.doi.org/10.18599/grs.2021.1.8.
Full textAbstract:
Barents Sea basin is the most explored and studied by the regional and petroleum geologists on the Russian Arctic shelf and has approved gas reserves. However, there are many questions in the petroleum exploration, one of them is the structural reconstruction. During its geological evolution, Barents Sea shelf was influenced by the Pre-Novaya Zemlya structural zone that uplifted several times in Mesozoic and Cenozoic. The main goal of the research is to clarify the periods of structural reconstructions of the Eastern Barents shelf and its influence on the petroleum systems of the Barents Sea shelf. A database of regional seismic profiles and offshore borehole data collected over the past decade on the Petroleum Geology Department of the Lomonosov Moscow State University allows to define main unconformities and seismic sequences, to reconstruct the periods of subsidence and uplifts in Mesozoic and Cenozoic. The structural reconstructions on the Eastern Barents Sea in the Triassic-Jurassic boundary led to intensive uplifts and formation of the huge inversion swells, which is expressed in erosional truncation and stratigraphic unconformity in the Upper Triassic and Lower Jurassic strata. In the Jurassic period, tectonic subsidence reigned on the shelf, when the uplifts including the highs of Novaya Zemlya were partially flooded and regional clay seal and source rocks – Upper Jurassic «black clays» – deposited on the shelf. The next contraction phase manifested itself as a second impulse of the growth of inversion swells in the Late Jurassic-Early Cretaceous. Cenozoic uplift of the Pre-Novaya Zemlya structural zone and the entire Barents Sea shelf led to significant erosion of the Mesozoic sediments, on the one hand, forming modern structural traps, and on the other, significantly destroying the Albian, once regional seal.
16
Sitnikov, V. S., R. F. Sevostyanova, and K. A. Pavlova. "EVOLUTION OF CONCEPTS ABOUT THE STRUCTURE OF OIL AND GAS TRAPS IN THE STUDY OF PETROLEUM BEARING SUBSURFACE RESOURCES IN WESTERN YAKUTIA." Geology and mineral resources of Siberia, no. 1 (2021): 49–55. http://dx.doi.org/10.20403/2078-0575-2021-1-49-55.
Full textAbstract:
The article presents the development history of the oil and gas industry in the Republic of Sakha (Yakutia). It is shown that during the first seismic exploration, prospecting for fields was carried out exclusively in the lower reaches of the Vilyui River. These works made it possible to identify the large Khapchagai gas region in Mesozoic deposits in the eastern Vilyui syneclise and discover a number of gas fields. Traps on them are typical platform structures - brachyanticlines with first degrees of dips, without any traces of disjunctive tectonic dislocations. The latter are predicted here lower in the section, starting from the Permian top. Scientific concepts of oil and gas traps revealed in various years in Western Yakutia in the course of geological exploration, from the period of inition of the oil and gas geophysical service in the republic (1950) to the present, are considered. The evolution of concepts of the oil and gas trap structure is shown, using the example of Srednebotuobinskoye and Verkhnevilyuchanskoye fields. This evolution was carried out in the process of geological exploration due to a more complete record-keeping of disjunctive disllocations and their role in the structure of traps.
17
Selley, R. C. "E. A. Beaumont & N. H. Foster (compilers) 1990. Structural Traps I: Tectonic Fold Traps, x + 232 pp.; Structural Traps II: Traps Associated with Tectonic Faulting, xii + 267 pp.; Structural Traps III: Tectonic Fold and Fault Traps, x + 235 pp.; Structural Traps IV: Tectonic and Nontectonic Fold Traps, xii + 382 pp. American Association of Petroleum Geologists, Treatise of Petroleum Geology. Atlas of Oil and Gas Fields. Tulsa. Prices US $38, 38, 30, 39 respectively (hard covers). ISBNs 0 89181 850 5; 0 089181 581 3; 0 089181 583 X; 0 089181 584 8." Geological Magazine 128, no. 6 (November 1991): 678. http://dx.doi.org/10.1017/s001675680001983x.
Full text
18
Marlow, Lisa, Kristijan Kornpihl, and Christopher G. St C. Kendall. "2-D Basin modeling study of petroleum systems in the Levantine Basin, Eastern Mediterranean." GeoArabia 16, no. 2 (April 1, 2011): 17–42. http://dx.doi.org/10.2113/geoarabia160217.
Full textAbstract:
ABSTRACT The Levantine Basin has proven hydrocarbons, yet it is still a frontier basin. There have been significant oil and gas discoveries offshore the Nile Delta, e.g. several Pliocene gas plays and the Mango Well with ca. 10,000 bbls/day in Lower Cretaceous rocks and recently, Noble Energy discovered two gas “giants” (> 5 TCF and one estimated at 16 TFC) one of which is in a pre-Messinian strata in ca. 1,700 m (5,577 ft) water depth. Regional two-dimensional (2-D) petroleum system modeling suggests that source rocks generated hydrocarbons throughout the basin. This paper provides insight into the petroleum systems of the Levantine Basin using well and 2-D seismic data interpretations and PetroMod2D. Tectonics followed the general progression of the opening and closing of the Neo-Tethys Ocean: rift-extension, passive margin, and compression. The stratal package is up to 15 km thick and consists of mixed siliciclastic-carbonate-evaporite facies. Five potential source rock intervals (Triassic – Paleocene) are suggested. Kerogen in the older source rocks is fully transformed, whereas the younger source rocks are less mature. There are several potential reservoir and seal rocks. The model suggests that oil and gas accumulations exist in both structural and stratigraphic traps throughout the basin.
19
Ward, Kelsey L., and Frank O. Folorunso. "The Corringham, Gainsborough–Beckingham, Glentworth, Nettleham, Stainton and Welton fields, UK Onshore." Geological Society, London, Memoirs 52, no. 1 (2020): 45–54. http://dx.doi.org/10.1144/m52-2018-21.
Full textAbstract:
AbstractThis paper focuses on the southern part of the East Midlands oil province, in which most hydrocarbon reservoirs are in Carboniferous strata and are primarily oil producing. The oils are predominantly sourced from the Namurian interbedded shales in the Gainsborough Trough and are trapped within anticlinal structures.Oil and gas exploration and production in the UK was marked by the Hardstoft-1 discovery in 1919. Since this discovery, more than 33 fields have been discovered in the East Midlands oil province, including the fields studied in this paper: Egmanton (in 1955), Bothamsall and Corringham (in 1958), Gainsborough and Beckingham (in 1959), South Leverton (in 1960), Glentworth (in 1961), and, the UK's second largest onshore field, Welton (in 1981). All of these fields produce from a Carboniferous petroleum system, sourced from Pendleian-age shales, reservoired in Namurian- and Westphalian-age sands, and trapped predominantly via structural, anticlinal traps.
20
Jolley, J. E. "The Andrew and Cyrus Fields, Blocks 16/27a, 16/28, UK North Sea." Geological Society, London, Memoirs 20, no. 1 (2003): 133–37. http://dx.doi.org/10.1144/gsl.mem.2003.020.01.11.
Full textAbstract:
AbstractThe Andrew and Cyrus fields lie in UK Blocks 16/27a and 16/28 at the junction of the Witch Ground Graben and the South Viking Graben. The Andrew Fields was discovered in 1974 with well 16/28-1, and Cyrus in 1979 with well 16/28-4. Both fields share a common reservoir the Paleocene Andrew Formation and both are sealed by the overlying Andrew Shale and Sele Formation. Similarly the traps for both fields formed above swells within Zechstein salt. The Andrew and Cyrus Fields differ in their petroleum content. Andrew contains both gas and oil (40API) while Cyrus contains only oil (30API).Reserves for the Andrew Field are 140 MMBBL based upon a 46% recovery factor using natural aquifer drive. The same mechanism will deliver 16.5 MMBBL from Cyrus at a 21% recovery factor. Production began from Andrew in July 1996. Cyrus production began in April 1990 using the SWOPS system until April 1992. The small field was subsequently tied back to Andrew.
21
Li, Sumei, Xiongqi Pang, Zhijun Jin, Maowen Li, Keyu Liu, Zhenxue Jiang, Guiqiang Qiu, and Yongjin Gao. "Molecular and isotopic evidence for mixed-source oils in subtle petroleum traps of the Dongying South Slope, Bohai Bay Basin." Marine and Petroleum Geology 27, no. 7 (August 2010): 1411–23. http://dx.doi.org/10.1016/j.marpetgeo.2010.04.004.
Full text
22
Camac, Bronwyn A., Suzanne P. Hunt, and Peter J. Boult. "Predicting brittle cap-seal failure of petroleum traps: an application of 2D and 3D distinct element method." Petroleum Geoscience 15, no. 1 (February 1, 2009): 75–89. http://dx.doi.org/10.1144/1354-079309-796.
Full text
23
Blaizot, Marc. "Worldwide shale-oil reserves: towards a global approach based on the principles of Petroleum System and the Petroleum System Yield." Bulletin de la Société géologique de France 188, no. 5 (2017): 33. http://dx.doi.org/10.1051/bsgf/2017199.
Full textAbstract:
Global inventory of shale-oil resources and reserves are far from being complete even in mature basins which have been intensively drilled and produced and in which the main parameters of the regional or local oil-prone source rocks are known. But even in these cases, difficulties still occur for deriving reserves from resources: reaching a plausible recovery factor is actually a complex task because of the lack of production history in many shale-oil ventures. This exercise is in progress in several institutions (EIA, USGS, AAPG) or private oil and gas companies on a basin-by-basin basis in order to estimate the global potential. This analytical method is very useful and accurate but also very time consuming. In the last EIA report in 2013 “only” 95 basins had been surveyed whereas for example, no Middle-East or Caspian basins have been taken into account. In order to accelerate the process and to reach an order of magnitude of worldwide shale-oil reserves, we propose hereafter a method based on the Petroleum System principle as defined by Demaison and Huizinga (Demaison G and Huizinga B. 1991. Genetic classification of Petroleum Systems. AAPG Bulletin 75 (10): 1626–1643) and more precisely on the Petroleum System Yield (PSY) defined as the ratio (at a source-rock drainage area scale) between the accumulated hydrocarbons in conventional traps (HCA) and hydrocarbons generated by the mature parts of the source-rock (HCG). By knowing the initial oil reserves worldwide we can first derive the global HCA and then the HCG. Using a proxy for amount of the migrated oil from the source-rocks to the trap, one can obtain the retained accumulations within the shales and then their reserves by using assumptions about a possible average recovery factor for shale-oil. As a definition of shale-oil or more precisely LTO (light tight oil), we will follow Jarvie (Jarvie D. 2012. Shale resource systems for oil & gas: part 2 – Shale Oil Resources Systems. In: Breyer J, ed. Shale Reservoirs. AAPG, Memoir 97, pp. 89–119) stating that “shale-oil is oil stored in organic rich intervals (the source rock itself) or migrated into juxtaposed organic lean intervals”. According to several institutes or companies, the worldwide initial recoverable oil reserves should reach around 3000 Gbo, taking into account the already produced oil (1000 Gbo) and the “Yet to Find” oil (500 Gbo). Following a review of more than 50 basins within different geodynamical contexts, the world average PSY value is around 5% except for very special Extra Heavy Oils (EHO) belts like the Orinoco or Alberta foreland basins where PSY can reach 50% (!) because large part of the migrated oils have been trapped and preserved and not destroyed by oxidation as it is so often the case. This 50% PSY figure is here considered as a good proxy for the global amount of expelled and migrated oil as compared to the HCG. Confirmation of such figures can also be achieved when studying the ratio of S1 (in-place hydrocarbon) versus S2 (potential hydrocarbons to be produced) of some source rocks in Rock-Eval laboratory measurements. Using 3000 Gbo as worldwide oil reserves and assuming a quite optimistic average recovery factor of 40%, the corresponding HCA is close to 7500 Gbo and HCG (= HCA/PSY) close to 150 000 Gbo. Assuming a 50% expulsion (migration) factor, we obtain that 75 000 Gbo is trapped in source-rocks worldwide which corresponds to the shale-oil resources. To derive the (recoverable) reserves from these resources, one needs to estimate an average recovery factor (RF). Main parameters for determining recovery factors are reasonable values of porosity and saturation which is difficult to obtain in these extremely fine-grained, tight unconventional reservoirs associated with sampling and laboratories technical workflows which vary significantly. However, new logging technologies (NMR) as well as SEM images reveal that the main effective porosity in oil-shales is created, thanks to maturity increase, within the organic matter itself. Accordingly, porosity is increasing with Total Organic Carbon (TOC) and paradoxically with… burial! Moreover, porosity has never been water bearing, is mainly oil-wet and therefore oil saturation is very high, measured and calculated between 75 and 90%. Indirect validation of such high figures can be obtained when looking at the first vertical producing wells in the Bakken LTO before hydraulic fracturing started which show a very low water-cut (between 1 and 4%) up to a cumulative oil production of 300 Kbo. One can therefore assume that the highest RF values of around 10% should be used, as proposed by several researchers. Accordingly, the worldwide un-risked shale-oil reserves should be around 7500 Gbo. However, a high risk factor should be applied to some subsurface pitfalls (basins with mainly dispersed type III kerogen source-rocks or source rocks located in the gas window) and to many surface hurdles caused by human activities (farming, housing, transportation lines, etc…) which can hamper developments of shale-oil production. Assuming that only shale-oil basins in (semi) desert conditions (i.e., mainly parts of Middle East, Kazakstan, West Siberia, North Africa, West China, West Argentina, West USA and Canada, Mexico and Australia) will be developed, a probability factor of 20% can be used. Accordingly, the global shale-oil reserves could reach 1500 Gbo which is half the initial conventional reserves and could therefore double the present conventional oil remaining reserves.
24
Elisheva, O. V., and K. A. Sosnovskikh. "Experience in applying the method of fractal analysis to clarify the boundaries of facies zones when introducing digital technologies in the exploration process." Oil and Gas Studies, no. 5 (October 31, 2021): 36–50. http://dx.doi.org/10.31660/0445-0108-2021-5-36-50.
Full textAbstract:
In order to improve the efficiency of exploration drilling at various greenfield license areas owned by Rosneft Oil Company, Tyumen Petroleum Scientific Center LLC has been actively developing and implementing various innovative technologies in recent years that allow increasing the probability of discovering new hydrocarbon deposits. One of such approaches is the use of different methods based on the principles of fractality of geological objects. The article presents the results of using the fractal analysis method to solve one of the applied problems of oil and gas geology, namely, the correction of the boundaries of facies zones on facies maps, which are the basis for constructing risk maps for the "reservoir". It is shown that the boundaries of the facies zones on facies maps, built mainly on seismic data and a limited amount of materials from exploration drilling, have a large variability. The found statistical relationship between the distribution of the total reservoir thicknesses in different facies zones and the fractal dimension of the traps made it possible to correct facies and risk maps.
25
Farooqui, Mohammed Y., Khamis Farhoud, Dia Mahmoud, and Ahmed N. El-Barkooky. "Petroleum potential of the interpreted Paleozoic geoseismic sequences in the South Diyur Block, Western Desert of Egypt." GeoArabia 17, no. 3 (July 1, 2012): 133–76. http://dx.doi.org/10.2113/geoarabia1703133.
Full textAbstract:
ABSTRACT The South Diyur exploration block of nearly 38,000 sq km is located in the Farafra Oasis region in the Western Desert of Egypt. It is a frontier exploration area, the nearest well being Ammonite-1, a dry hole drilled by Conoco in 1979 immediately outside the southwestern corner of the block. The South Diyur Block is located on the probable northeast extension of the Kufra Basin in southeast Libya. Although prolific reserves of oil and gas occur in Paleozoic basins in North Africa and throughout the Middle East, to date, the targets for petroleum exploration in the northern Western Desert have been in Jurassic and Cretaceous rocks. The regional structural surface features in the South Diyur Block are the NE-trending Bahariya and Farafra anticlines interpreted as a deeply eroded and inverted Late Cretaceous structure on the southern extension of the Syrian Arc system. The oldest exposed rocks are a Cretaceous sequence of sublittoral sediments (the Campanian Wadi Hennis Formation) in the core of the anticline. The interpretation of the subsurface is based on 1,175 line-km of reprocessed 1970s-vintage 2-D seismic. Four sequence boundaries have been identified from the seismic data. SB-1 correlates with the Jurassic/Cretaceous boundary in Ammonite-1. SB-2 is regionally correlated with the Late Devonian to Early Carboniferous Hercynian unconformity that overlies deeply eroded and truncated Paleozoic sequences and possibly marks the regionally extensive Late Paleozoic basin inversion. SB-3 near the base of the interpreted Silurian sequence coincides with the ‘hot shale’ petroleum source rock that is present throughout North Africa and the Middle East. SB-4 is interpreted as a major unconformity at the top of an Upper Proterozoic sedimentary section that was misinterpreted as the Precambrian acoustic basement in Ammonite-1. Five seismic sequences relate to the seismic boundaries. SS-1, from the surface to SB-1 is characterized by subparallel seismic stratification and is composed mainly of sandstone with shale interbeds in Ammonite-1. SS-2, bounded by SB-1 and SB-2, is distinguished by parallel to subparallel seismic stratification. In Ammonite-1, the sequence of interbedded sandstone and shale is fresh-water bearing and lacking in top seals, thus reducing its prospectivity. The underlying SS-3 (SB-2 to SB-3) directly underlies the Hercynian unconformity and is characterized by semi-transparent seismic facies that may correspond to a thick Silurian shale sequence. SS-4 (SB-3 to SB-4) of probable Cambrian–Ordovician age has parallel seismic stratification. Deep channels are interpreted as evidence of a Late Ordovician–Early Silurian glacial phase that is present throughout North Africa and the Middle East. SS-5 (below SB-4) is marked by partial subparallel seismic stratification and block faulting. It probably belongs to the Late Proterozoic (Pan-African) phase of block faulting and pull-apart basins. Similar seismic geometries and facies occur in the Kufra Basin in southeast Libya and in many parts of the Arabian Plate, including the prolific petroleum systems of Oman. Exploration plays in the South Diyur Block are a combination of Paleozoic structural and stratigraphic traps associated with prospective fairways, and possible stratigraphic traps in the Late Ordovician–Early Silurian glacial channels. In addition, the interpreted Late Proterozoic sequences (SS-5) warrant further evaluation. In order to identify future exploration plays and drill targets, additional 2-D seismic (4,490 line-km), aeromagnetic and airborne gravity surveys will be integrated with the present seismic data and drilling results from Ammonite-1. This will allow a proper assessment of the magnetic basement, basin configuration and prospective fairways.
26
Abdullah, Rashed, Md Shahadat Hossain, Md Soyeb Aktar, Mohammad Moinul Hossain, and Farida Khanam. "Structural initiation along the frontal fold-thrust system in the western Indo-Burman Range: Implications for the tectonostratigraphic evolution of the Hatia Trough (Bengal Basin)." Interpretation 9, no. 3 (July 27, 2021): SF1—SF10. http://dx.doi.org/10.1190/int-2020-0227.1.
Full textAbstract:
The Bengal Basin accommodates an extremely thick Cenozoic sedimentary succession that derived from the uplifted Himalayan and Indo-Burman Orogenic Belts in response to the subduction of the Indian Plate beneath the Eurasian and Burmese Plates. The Hatia Trough is a proven petroleum province that occupies much of the southern Bengal Basin. However, the style of deformation, kinematics, and possible timing of structural initiation in the Hatia Trough and the relationship of this deformation to the frontal fold-thrust system in the outer wedge (namely, the Chittagong Tripura Fold Belt) of the Indo-Burman subduction system to the east are largely unknown. Therefore, we have carried out a structural interpretation across the eastern Hatia Trough and the western Chittagong Tripura Fold Belt based on 2D seismic reflection data. Our result suggests that the synkinematic packages correspond to the Pliocene Tipam Group and the Pleistocene Dupitila Formation. This implies that the structural development in the western Chittagong Tripura Fold Belt took place from the Pliocene. In the Hatia Trough, the timing of structural activation is slightly later (since the Plio-Pleistocene). In general, fold intensity and structural complexity gradually increase toward the east. The presence of reverse faults with minor strike-slip motion along the frontal thrust system in the outer wedge is also consistent with the regional transpressional structures of the Indo-Burman subduction system. However, to the west, there is no evidence for strike-slip deformation in the Hatia Trough. The restored sections indicate that the amount of east–west shortening in the Hatia Trough is very low (maximum 1.2%). In contrast, to the east, the amount of shortening is high (maximum 13.5%) in the western margin of the Chittagong Tripura Fold Belt. In both areas, the key trapping mechanism includes anticlinal traps, although stratigraphic and combinational traps are possible, but this requires further evaluation.
27
Sales, Mark, Malcolm Altmann, Glen Buick, Claire Dowling, John Bourne, and Alexandra Bennett. "Subtle oil fields along the Western Flank of the Cooper/Eromanga petroleum system." APPEA Journal 55, no. 2 (2015): 440. http://dx.doi.org/10.1071/aj14075.
Full textAbstract:
Oil production from Cooper/Eromanga started in 1978, peaked in the 1980s and began a steady decline. Oil production from the Western Flank commenced in 2002 and has steadily increased. In the year until July 2014, a total of 8.6 million BBL of oil was produced from 16 active fields along the Western Flank, bringing the cumulative total to 24 million BBL. Western Flank oil has underpinned a ten-fold growth in market capitalisation in four listed Australian companies: Beach Energy, Drillsearch Ltd, Senex Energy and Cooper Energy. Two sandstone plays dominate the Western Flank petroleum geology: the Namur Sandstone low-relief structural play and the mid-Birkhead stratigraphic play. The use of 3D seismic has improved the definition of both plays, increased exploration success and optimised field appraisal and development drilling. Success rates have improved despite most Namur structural closures being close to the resolution margin for depth conversions (less than 8 m). Seismic attribute mapping is being refined in the more difficult search for mid-Birkhead stratigraphic traps with recent exploration discoveries indicating improved success. Reservoir properties in the Namur are excellent with multi-Darcy permeability, unlimited aquifer strength, low gas/oil ratio (GOR) and low residual oil saturation. This combination leads to an oil recovery factor greater than 75%. Initial free-flow production rates commonly exceed 6,000 BBL per a day. The mid-Birkhead reservoir is also of high quality but the lack of a strong aquifer drive reduces primary recovery. New and re-processed 3D seismic and water-flood projects are expected to drive further discoveries, reserve and production growth.
28
Tari, Gábor, Didier Arbouille, Zsolt Schléder, and Tamás Tóth. "Inversion tectonics: a brief petroleum industry perspective." Solid Earth 11, no. 5 (October 21, 2020): 1865–89. http://dx.doi.org/10.5194/se-11-1865-2020.
Full textAbstract:
Abstract. Inverted structures provide traps for petroleum exploration, typically four-way structural closures. As to the degree of inversion, based on a large number of worldwide examples seen in various basins, the most preferred petroleum exploration targets are mild to moderate inversion structures, defined by the location of the null points. In these instances, the closures have a relatively small vertical amplitude but are simple in a map-view sense and well imaged on seismic reflection data. Also, the closures typically cluster above the extensional depocenters which tend to contain source rocks providing petroleum charge during and after the inversion. Cases for strong or total inversion are generally not that common and typically are not considered as ideal exploration prospects, mostly due to breaching and seismic imaging challenges associated with the trap(s) formed early on in the process of inversion. Also, migration may become tortuous due to the structural complexity or the source rock units may be uplifted above the hydrocarbon generation window, effectively terminating the charge once the inversion has occurred. Cases of inversion tectonics can be grouped into two main modes. A structure develops in Mode I inversion if the syn-rift succession in the preexisting extensional basin unit is thicker than its post-rift cover including the pre- and syn-inversion part of it. In contrast, a structure evolves in Mode II inversion if the opposite syn- versus post-rift sequence thickness ratio can be observed. These two modes have different impacts on the petroleum system elements in any given inversion structure. Mode I inversion tends to develop in failed intracontinental rifts and proximal passive margins, and Mode II structures are associated with back-arc basins and distal parts of passive margins. For any particular structure the evidence for inversion is typically provided by subsurface data sets such as reflection seismic and well data. However, in many cases the deeper segments of the structure are either poorly imaged by the seismic data and/or have not been penetrated by exploration wells. In these cases the interpretation in terms of inversion has to rely on the regional understanding of the basin evolution with evidence for an early phase of crustal extension by normal faulting.
29
Lisk, M., J. Ostby, N. J. Russell, and G. W. O’Brien. "OIL MIGRATION HISTORY OF THE OFFSHORE CANNING BASIN." APPEA Journal 40, no. 2 (2000): 133. http://dx.doi.org/10.1071/aj99069.
Full textAbstract:
The dual issues of the presence or absence of a viable, oil-prone petroleum system and reservoir quality represent key exploration uncertainties in the lightly explored Offshore Canning Basin, North West Shelf. To better quantify these factors, a detailed fluid inclusion investigation of potential reservoir horizons within the basin has been undertaken. The results have been integrated with regional petroleum geology and Synthetic Aperture Radar (SAR) oil seep data to better understand the oil migration risk in the region.The fluid inclusion data provide confirmation of widespread oil migration at multiple Mesozoic and Palaeozoic levels, including those wells that are remote from the likely source kitchens. The lack of evidence for present or palaeo-oil accumulations is consistent with the proposition that none of the currently water-wet wells appear to have tested a valid structure. These observations, when combined with the presence of numerous direct hydrocarbon indicators on seismic data and a number of oil slicks (from SAR data) at the basin’s edge, suggest that the potential for oil charge to valid structures is much higher than previously recognised.Petrographic analysis of the tight, gas-bearing, Triassic sandstones in Phoenix–1 suggests that the low porosity and permeability is the result of late poikilotopic carbonate cement. Significantly, the presence of oil inclusions within quartz overgrowths that pre-date the carbonate indicates that oil migration began prior to crystallisation of carbonate. Fluid inclusion palaeotemperatures combined with a 1D basin model suggest that trapping of oil as inclusions occurred in the Early to Middle Cretaceous and that predictions of reservoir quality using available water-wet wells could seriously under-estimate porositypermeability levels in potential traps that were charged with oil at about 100 Ma. Indeed, acid leaching of core plugs from Phoenix–1 indicates that removal of diagenetic carbonate results in significant permeability increase with obvious implications for the producibility of any future oil discovery. Further, evidence of Early Cretaceous oil charge has implications for the size and locality of source kitchens compared to that observed at the current day.Collectively, the data indicate the area has received widespread oil migration and suggest future exploration, even to relatively deep levels, may be successful if valid traps can be delineated.
30
Sapyanik, V. V., E. Yu Lapteva, E. V. Lyubutina, A. I. Nedospasov, P. I. Novikov, N. V. Petrova, A. V. Fateev, and A. P. Khilko. "GEODYNAMICS OF THE SEDIMENTARY COVER AND OIL-AND-GAS PROSPECTS OF THE TOMSK REGION EASTERN TERRITORY." Geology and mineral resources of Siberia, no. 3 (2021): 21–30. http://dx.doi.org/10.20403/2078-0575-2021-3-21-30.
Full textAbstract:
The article deals with geodynamic processes of the plicative tectonics of the Mesozoic-Cenozoic development stage in the southeastern territory of the West Siberian hemisyneclise, which allowed scientists to significantly clarify the configuration of multi-ordinal structures, to identify the second-order negative structure in the territory of the Baraba-Pikhtovka monocline, and to offer a new view of the structural-tectonic zoning of the Tomsk region eastern territory sedimentary cover. To substantiate the prospects of Jurassic petroleum plays, their resource potential is estimated using the basin modeling method. Based on an integrated analysis of structural imagings, history of the territory tectonic development, calculated maps of effective capacities, test results and WL conclusions, 42 traps of structural, structural-lithological, structural-stratigraphic types were mapped and their assessment by the volume-statistic method by Dl category [inferred resources] was given. The results obtained significantly expand the prospects for peripheral territories of the West Siberian Plate, where it is necessary to complete regional geological exploration.
31
Fedorovich, Marina O., and Alina Yu Kosmacheva. "Prediction of oil and gas occurrence in the Vilyui hemisineclise according to interpretation of geological and geophysical data and basin modeling (Republic of Sakha (Yakutia))." Georesursy 25, no. 1 (March 30, 2023): 81–94. http://dx.doi.org/10.18599/grs.2023.1.9.
Full textAbstract:
The paper is aimed at the prediction of oil and gas occurrence of the Upper Permian, Lower Triassic and Lower Jurassic deposits in the Vilyui hemisineclise. The basin modeling research implies the Upper Paleozoic and Mesozoic petroleum system model of the Vilyui hemisineclise. The initial generation time at the bottom of the Permian source rock is 270 Ma. The most intense generation of hydrocarbons is found to be in the late Permian and early Triassic. The generation power of the Permian source rock is 800 trillion m3. The hydrocarbon losses is up to 90% in consequence of unfavorable seal properties of the Lower Triassic and Lower Jurassic clay formations. All the potential hydrocarbon traps of the Vilyui hemisyneclise are considered to be formed during the Cretaceous stage of development. There is therefore an appropriate environment for the hydrocarbon accumulation to be in progress. The interpretation of geological and geophysical data identifies the areal extent prediction of sand reservoirs and overlying clay interlayers of high quality in the Upper Permian and Lower Triassic seals. The goal of a comprehensive approach to the sedimentary basin research is to divide the territory into oil and gas zones of various prospects in relation to the factors controlling hydrocarbon deposits.
32
Al-Ameri, Thamer K., Amer Jassim Al-Khafaji, and John Zumberge. "Petroleum system analysis of the Mishrif reservoir in the Ratawi, Zubair, North and South Rumaila oil fields, southern Iraq." GeoArabia 14, no. 4 (October 1, 2009): 91–108. http://dx.doi.org/10.2113/geoarabia140491.
Full textAbstract:
ABSTRACT Five oil samples reservoired in the Cretaceous Mishrif Formation from the Ratawi, Zubair, Rumaila North and Rumaila South fields have been analysed using Gas Chromatography – Mass Spectroscopy (GC-MS). In addition, fifteen core samples from the Mishrif Formation and 81 core samples from the Lower Cretaceous and Upper Jurassic have been subjected to source rock analysis and palynological and petrographic description. These observations have been integrated with electric wireline log response. The reservoirs of the Mishrif Formation show measured porosities up to 28% and the oils are interpreted as being sourced from: (1) Type II carbonate rocks interbedded with shales and deposited in a reducing marine environment with low salinity based on biomarkers and isotopic analysis; (2) Upper Jurassic to Lower Cretaceous age based on sterane ratios, analysis of isoprenoids and isotopes, and biomarkers, and (3) Thermally mature source rocks, based on the biomarker analysis. The geochemical analysis suggests that the Mishrif oils may have been sourced from the Upper Jurassic Najma or Sargelu formations or the Lower Cretaceous Sulaiy Formation. Visual kerogen assessment and source rock analysis show the Sulaiy Formation to be a good quality source rock with high total organic carbon (up to 8 wt% TOC) and rich in amorphogen. The Lower Cretaceous source rocks were deposited in a suboxic-anoxic basin and show good hydrogen indices. They are buried at depths in excess of 5,000 m and are likely to have charged Mishrif reservoirs during the Miocene. The migration from the source rock is likely to be largely vertical and possibly along faults before reaching the vuggy, highly permeable reservoirs of the Mishrif Formation. Structural traps in the Mishrif Formation reservoir are likely to have formed in the Late Cretaceous.
33
Ambrose, G., M. Scardigno, and A. J. Hill. "PETROLEUM GEOLOGY OF MIDDLE–LATE TRIASSIC AND EARLY JURASSIC SEQUENCES IN THE SIMPSON BASIN AND NORTHERN EROMANGA BASIN OF CENTRAL AUSTRALIA." APPEA Journal 47, no. 1 (2007): 127. http://dx.doi.org/10.1071/aj06007.
Full textAbstract:
Prospective Middle–Late Triassic and Early Jurassic petroleum systems are widespread in central Australia where they have only been sparsely explored. These systems are important targets in the Simpson/Eromanga basins (Poolowanna Trough and surrounds), but the petroleum systems also extend into the northern and eastern Cooper Basin.Regional deposition of Early–Middle Triassic red-beds, which provide regional seal to the Permian petroleum system, are variously named the Walkandi Formation in the Simpson Basin, and the Arrabury Formation in the northern and eastern Cooper Basin. A pervasive, transgressive lacustrine sequence (Middle–Late Triassic Peera Peera Formation) disconformably overlies the red-beds and can be correlated over a distance of 500 km from the Poolowanna Trough into western Queensland, thus providing the key to unravelling Triassic stratigraphic architecture in the region. The equivalent sequence in the northern Cooper Basin is the Tinchoo Formation. These correlations allow considerable simplification of Triassic stratigraphy in this region, and demonstrate the wide lateral extent of lacustrine source rocks that also provide regional seal. Sheet-like, fluvial-alluvial sands at the base of the Peera Peera/Tinchoo sequence are prime reservoir targets and have produced oil at James–1, with widespread hydrocarbon shows occurring elsewhere including Poolowanna–1, Colson–1, Walkandi–1, Potiron–1 and Mackillop–1.The Early Jurassic Poolowanna Formation disconformably overlies the Peera Peera Formation and can be subdivided into two transgressive, fluvial-lacustrine cycles, which formed on a regional scale in response to distal sea level oscillations. Early Jurassic stratigraphic architecture in the Poolowanna Trough is defined by a lacustrine shale capping the basal transgressive cycle (Cycle 1). This shale partitions the Early Jurassic aquifer in some areas and significant hydrocarbon shows and oil recoveries are largely restricted to sandstones below this seal. Structural closure into the depositional edge of Cycle 1 is an important oil play.The Poolowanna and Peera Peera formations, which have produced minor oil and gas/condensate on test respectively in Poolowanna–1, include lacustrine source rocks with distinct coal maceral compositions. Significantly, the oil-bearing Early Jurassic sequence in Cuttapirrie–1 in the Cooper Basin correlates directly with the Cycle–1 oil pool in Poolowanna–1. Basin modelling in the latter indicates hydrocarbon expulsion occurred in the late Cretaceous (90–100 Ma) with migration into a subtle Jurassic age closure. Robust Miocene structural reactivation breached the trap leaving only minor remnants of water-washed oil. Other large Miocene structures, bound by reverse faults and some reflecting major inversion, have failed to encounter commercial hydrocarbons. Future exploration should target subtle Triassic to Jurassic–Early Cretaceous age structural and combination stratigraphic traps largely free of younger fault dislocation.
34
James, David. "BEAUMONT, E. A. & FOSTER, N. H. (eds) 2000. Exploring for Oil and Gas Traps. AAPG Treatise of Petroleum Geology; Handbook Series. xiv+1146 pp. Tulsa: American Association of Petroleum Geologists. Price US $49.00 (hard covers). ISBN 0 89181 602 X." Geological Magazine 138, no. 4 (July 2001): 499–508. http://dx.doi.org/10.1017/s001675680122559x.
Full text
35
Razzaq, Harith, Manal Al-Kubaisi, and Suhail Muhsin. "Subsurface Structural Image of Galabat Field, North East of Iraq Using 2D Seismic Data." Iraqi Geological Journal 56, no. 1C (March 31, 2023): 129–75. http://dx.doi.org/10.46717/igj.56.1c.11ms-2023-3-22.
Full textAbstract:
This research had been achieved to identify the image of the subsurface structure representing the Tertiary period in the Galabat Field northeast of Iraq using 2D seismic survey measurements. Synthetic seismograms of the Galabat-3 well were generated in order to identify and pick the reflectors in seismic sections. Structural Images were drawn in the time domain and then converted to the depth domain by using average velocities. Structurally, seismic sections illustrate these reflectors are affected by two reverse faults affected on the Jeribe Formation and the layers below with the increase in the density of the reverse faults in the northern division. The structural maps show Galabat field, which consists of longitudinal Asymmetrical narrow anticline of Fatha and Jeribe formations, where the Southeastern limb is steeper than the Northeastern limb. The seismic interpretation shows that Galabat Field has a positive inverted structure, it is an anticline at the level of the Tertiary Period. The direction of the anticline axis and the major reverses faults are Northwest -Southeast. It is concluded from the study that reverse faults originated due to Zagros tectonism which is widespread in the area are a major conduit that channeled petroleum flow from source to Miocene traps. In addition, these faults were caused by the presence of salt accumulation within the Fatha Formation and led to high variation in the thickness in the crest and limbs of the Galabat structure.
36
Davidson, John K. "Plate tectonic structural geology to detailed field and prospect stress prediction." APPEA Journal 48, no. 1 (2008): 153. http://dx.doi.org/10.1071/aj07010.
Full textAbstract:
Arguably the first successful application of the theory of continental drift to petroleum exploration was in 1959 by the pioneers S. W. Carey and L. G. Weeks whose collaboration led to the discovery of the world class Gippsland Basin. Plate tectonics, as the theory is now known, was still nascent and not prominent during peak global oil exploration success in the 1960s. As discovery rates continue to decline, large scale description of separating and colliding continents has become increasingly impotent in the ever more complex hunt for the next barrel. Emphasis is turning from new basins and plays to smaller intra-basin discoveries related to a more detailed understanding of basin forming faults and their local stress effects on traps and trap geometries. Improved oil recovery is not only about finding new fields, but also demands detailed stress information for horizontal wellbore stability to economically and effectively increase reserves and recovery rates by extracting new oil from old fields. As a result, expensive wellbore based measurements have been deployed in the past 15 years. These precision measurements have then been averaged between wells for stress prediction but stress directions are known to vary abruptly by up to 90° over distances of less than 3 km. A solution lies in the seismic recognition of globally synchronous compressional pulses which, like a heartbeat, have added predictability of stress fields hence to stress analysis. This repetition of stress provides a workflow for stress consistent seismic interpretation that can predict horizontal and vertical changes in the direction of the maximum horizontal compressional component of a stress SH (SHD) and also in the magnitude of the stress, SHM. It is now possible to derive pre-drill at any desired point, important exploration and production variables such as stress related fault seal and open fracture orientation. Similarly, important reservoir development parameters such as fracture gradients and wellbore stability prediction will maximise recovery efficiencies and reduce development costs. This technique will also aid in effective carbon dioxide sequestration, a challenging new field of endeavour.
37
Selly, R. C. "N. H. Foster, & E. A. Beaumont, (compilers) 1993. Structural Traps VIII. Treatise of Petroleum Geology, Atlas of Oil and Gas Fields Series, xii + 328 pp. Tulsa: American Association of Petroleum Geologists. Price not stated (hard covers). ISBN 0 08918 590 2." Geological Magazine 132, no. 3 (May 1995): 361–62. http://dx.doi.org/10.1017/s0016756800013728.
Full text
38
Geert, Konert, Abdulkader M. Afifi, Sa’id A. Al-Hajri, and Henk J. Droste. "Paleozoic Stratigraphy and Hydrocarbon Habitat of the Arabian Plate." GeoArabia 6, no. 3 (July 1, 2001): 407–42. http://dx.doi.org/10.2113/geoarabia0603407.
Full textAbstract:
ABSTRACT The Paleozoic section became prospective during the early 1970s when the enormous gas reserves in the Permian Khuff reservoirs were delineated in the Gulf and Zagros regions, and oil was discovered in Oman. Since then, frontier exploration has targeted the Paleozoic System throughout the Middle East, driven by various economic considerations. The Paleozoic sequences were essentially deposited in continental to deep marine clastic environments at the Gondwana continental margin. Carbonates only became dominant in the Late Permian. The sediments were deposited in arid to glacial settings, reflecting the drift of the region from equatorial to high southern latitudes and back. Following late Precambrian rifting that formed salt basins in Oman and the Arabian Gulf region, the Cambrian-Devonian sequences were deposited on a peneplained continental platform. The entire region was affected by the Hercynian Orogeny, which climaxed during the Carboniferous. The orogeny manifested itself in a change in basin geometry, inversion tectonics, regional uplift and tectonism along the Zagros fault zone. This deformation caused widespread erosion of the Devonian-Carboniferous and older sections, and was probably caused by collision along the northern margin of Gondwana. The Paleozoic tectonic super cycle ended with the onset of break-up tectonics in the Permian, and the deposition of Khuff carbonates over the newly formed eastern passive margin. A major Paleozoic petroleum system embraces reservoir seal pairs spanning the Silurian to Permian sequences. Hydrocarbons occur in a variety of traps, and are sourced by the Silurian ‘hot shale’. A second petroleum system occurs in areas charged from upper Precambrian source rocks in the salt basins. Hydrocarbon expulsion estimates, taking into account secondary migration losses, suggest that some one trillion barrels of oil equivalent (BOE) may have been trapped from the Silurian ‘hot shale’ alone. However, the long and complex hydrocarbon geological evolution of the basin, combined with low acoustic contrasts between target rock units, difficult surface conditions, tight reservoirs, and deep subsurface environments, posed significant challenges to exploration and development. The critical success factor is the continuous innovative effort of earth scientists and subsurface engineers to find integrated technology solutions, that will render the Paleozoic plays economically viable.
39
Jackson, Christopher A. L., Craig Magee, and Carl Jacquemyn. "Rift-related magmatism influences petroleum system development in the NE Irish Rockall Basin, offshore Ireland." Petroleum Geoscience 26, no. 4 (January 9, 2020): 511–24. http://dx.doi.org/10.1144/petgeo2018-020.
Full textAbstract:
Large volumes of hydrocarbons reside in volcanically influenced sedimentary basins. Despite having a good conceptual understanding of how magmatism impacts the petroleum systems of such basins, we still lack detailed case studies documenting precisely how intrusive magmatism influences, for example, trap development and reservoir quality. Here we combine 3D seismic reflection, borehole, petrographical and palaeothermometric data to document the geology of borehole 5/22-1, NE Irish Rockall Basin, offshore western Ireland. This borehole (Errigal) tested a four-way dip closure that formed to accommodate emplacement of a Paleocene–Eocene igneous sill-complex during continental break-up in the North Atlantic. Two water-bearing turbidite-sandstone-bearing intervals occur in the Upper Paleocene; the lowermost contains thin (c. 5 m), quartzose-feldspathic sandstones of good reservoir quality, whereas the upper is dominated by poor-quality volcaniclastic sandstones. Palaeothermometric data provide evidence of anomalously high temperatures in the Paleocene–Eocene succession, suggesting the poor reservoir quality within the target interval is likely to reflect sill-induced heating, fluid flow, and related diagenesis. The poor reservoir quality is also probably the result of the primary composition of the reservoir, which is dominated by volcanic grains and related clays derived from an igneous-rock-dominated, sediment source area. Errigal appeared to fail due to a lack of hydrocarbon charge: that is, the low bulk permeability of the heavily intruded Cretaceous mudstone succession may have impeded the vertical migration of sub-Cretaceous-sourced hydrocarbons into supra-Cretaceous reservoirs. Break-up-related magmatism did, however, drive the formation of a large structural closure, with data from Errigal at least proving high-quality, Upper Paleocene deep-water reservoirs. Future exploration targets in the NE Irish Rockall Basin include: (i) stratigraphically trapped Paleocene–Eocene deep-water sandstones that onlap the flanks of intrusion-induced forced folds; (ii) structurally trapped, intra-Cretaceous, deep-water sandstones incorporated within intrusion-induced forced folds; and (iii) more conventional, Mesozoic fault-block traps underlying the heavily intruded Cretaceous succession (e.g. Dooish). Similar plays may exist on other continental margins influenced by break-up magmatism.Supplementary material: Borehole-related reports, and litho- and composite logs are available at https://doi.org/10.6084/m9.figshare.c.4803267
40
Saboorian-Jooybari, Hadi, and Peyman Pourafshary. "Potential Severity of Phase Trapping in Petroleum Reservoirs: An Analytical Approach to Prediction." SPE Journal 22, no. 03 (August 26, 2016): 863–74. http://dx.doi.org/10.2118/183631-pa.
Full textAbstract:
Summary This study focuses on the evaluation and diagnosing of the potential severity of petroleum reservoirs for establishment of phase traps. In this area, very few diagnostic methodologies have been presented in the literature. Unfortunately, there is no universal agreement on the key influential factors in a phase-trapping phenomenon because each of the correlations was established on the basis of different sets of reservoir parameters (e.g., k,ϕ,Swi,σ) by use of the results of a number of aqueous-phase-trap tests over a limited range of rock and fluid properties. In the present work, an accurate technique is presented on the basis of the infiltration theory for prediction of the potential severity of phase-trapping damage. The fluid-saturation distribution around a well is analytically derived by linearizing and solving the governing partial-differential equation (PDE). Then, the calculated saturation profile in the vicinity of the wellbore is used to develop a new analytical diagnostic index, which is called a phase-trapping index (PTI). Knowing the fact that the saturation of the affected zone may be reduced to the irreducible rather than the initial value because of the capillary mechanics of the formation, interpretation guidelines are proposed to identify the regions that are susceptible to intense, serious, medium, and weak damage. Compared with other correlations, PTI offers several advantages such as generality, being founded on theory, and taking into account most of the key influential parameters. An example of a synthetic tight gas reservoir is presented to clearly demonstrate how the new technique can be applied.
41
Li, Xiaoshan, Hong Pan, Yuxiao Wu, Guanxing Luo, Junqiang Song, Liu Yang, Kaifang Gu, et al. "Main Control Factors and Hydrocarbon Accumulation Model of Volcanic Oil Reservoirs with Complex Oil–Water Relationships: A Case Study of the Carboniferous in the Chepaizi Uplift, the Junggar Basin, China." Minerals 12, no. 11 (October 26, 2022): 1357. http://dx.doi.org/10.3390/min12111357.
Full textAbstract:
In order to study the main control factors of volcanic reservoirs with complex oil–water relationships, the Carboniferous in the Chepaizi Uplift of the Junggar Basin was taken as an example and the lithofacies characteristics, main control factors, and hydrocarbon accumulation model of volcanic reservoirs were investigated by combining the petroleum geology with field testing (data of core analysis, well logging, formation testing, and production testing). The results show that the Carboniferous in the Chepaizi Uplift experienced three stages of volcanic activities and developed seven volcanic lithofacies bodies, distributed in a bead-string connected planar form along the Hongche fault. There is no unified oil–water interface across the whole study area and there are multiple oil–water systems within one fault block. The Carboniferous volcanic reservoir experienced two stages of hydrocarbon accumulation from two different source rocks. The distribution of faults penetrating hydrocarbon kitchens and source rocks controls the macro-scale distribution of reservoirs. The physical properties of reservoirs affect the pattern of oil and water differentiation in volcanic rock bodies, while the lithofacies body-controlled hydrocarbon accumulation mode highlighting “one rock body for one reservoir” determines the distribution of reservoirs. The matching between the paleo-structure and hydrocarbon accumulation stage controls the accumulation and adjustment of hydrocarbon distribution. The Permian source rocks in the Shawan Sag serve as the lateral hydrocarbon supply and hydrocarbons accumulate in the Carboniferous structural-lithologic traps, which are summarized as the two stages of hydrocarbon accumulation of newly generated hydrocarbons into older reservoir rocks. This study of the hydrocarbon accumulation pattern in volcanic rocks aims at guiding the development of Carboniferous reservoirs with complex oil and water relationships in this area.
42
Maksimov, L. A., and G. V. Vedernikov. "APPLICATION OF THE TECHNOLOGY OF PASSIVE–ACTIVE CDP SURVEY (CDP PAS) FOR REGIONAL EVALUATION OF PETROLEUM POTENTIAL OF THE SEPANOVSKOYE DOME-SHAPED UPLIFT OF THE EAST PAIDUGINA DEPRESSION." Geology and mineral resources of Siberia, no. 2 (2021): 46–55. http://dx.doi.org/10.20403/2078-0575-2021-2-46-55.
Full textAbstract:
The results of application of the innovative CDP PAS technology on the materials of seismic operations along regional CDP profiles with a total length of 2171 linear km clarifying the southeastern part of the Tomsk region are given. This technology is based on the analysis of spatial-temporal intervals of CDP seismograms up to the first arrivals of induced waves, which provides additional characteristics of emission waves. The working results are presented by spectra and graphs of activity of geodynamic noises in comparison with time sections and the scheme of the spatial position of these data. Areas of anomalous noise values that allow researchers to predict the presence of hydrocarbon accumulations within their boundaries have been identified for all profiles. The results obtained make it possible to assess the oil bearing capacity of this territory rather highly. In Tomsk region, these prospects should be associated mainly with specific non-anti cline traps located near suture zones- long-lived tectonic faults that are possible channels for the migration of deep hydrocarbons. The data obtained indicate an increase in petroleum potential in the southern direction, that is important for the development strategy of this district. The territory of the Stepanovskoye dome mesoelevation appears to be the primary target for the buildup of prospecting and exploration here.
43
DeVito, Steve, and Hannah Kearns. "Overview of the exploration potential of offshore Argentina – insight from new seismic interpretations." Petroleum Geoscience 28, no. 2 (January 19, 2022): petgeo2020–132. http://dx.doi.org/10.1144/petgeo2020-132.
Full textAbstract:
Argentina's offshore sedimentary basins cover a vast area on one of the widest continental margins on the planet, yet they remain underexplored today. Previous exploration drilling has failed to encounter commercial volumes of hydrocarbons, in part due to the poor seismic imaging of legacy 1960s–1990s 2D seismic data, and to the majority of wells being drilled on structural highs outside of the source rock kitchens. In this study, we reviewed 52 000 km of recently acquired (2017–2018) regional 2D long-offset seismic data with broadband pre-stack time (PSTM) and depth migration (PSDM) processing. We identified five major structural domains with hydrocarbon prospectivity on the Northern Margin of Argentina and four on the Southern Margin, and the presence of previously unseen structural and stratigraphic traps involving sequences assigned to proven regional source rocks and reservoirs in Permian, Jurassic and Cretaceous rocks. The source and reservoir rocks, petroleum systems, and play types present in the deepwater of the undrilled Argentina Basin represent a true frontier for hydrocarbon exploration. Pseudo relief attribute seismic displays and amplitude v. angle (AVA) analysis are demonstrated to be valuable tools in predicting the stratigraphy of the basins. A new framework for understanding the oil and gas prospectivity of the study area is presented.
44
Bathurst, R. G. C. "Carbonate Diagenesis as a Control on Stratigraphic Traps, Mark W. Longman. Eucations Course Note Series No. 21 of the American Association of Petroleum Geologists, 1982. No. of pages: 159. Price: U.S. $7.00. (Soft cover)." Geological Journal 18, no. 2 (April 30, 2007): 190. http://dx.doi.org/10.1002/gj.3350180216.
Full text
45
Abetov, A. E., and D. B. Mukanov. "Structure and interpretation of the anomalous magnetic field of the South Turgay petroleum region." Naukovyi Visnyk Natsionalnoho Hirnychoho Universytetu, no. 5 (October 30, 2023): 5–11. http://dx.doi.org/10.33271/nvngu/2023-5/005.
Full textAbstract:
Purpose. Study on the deep structure of the South Turgay petroleum region to assess the influence of magnetic causative masses on the processes of generation, migration, accumulation and conservation of hydrocarbon (HC) accumulations, taking into account the evolution of rift development modes of the same sedimentary basin. Methodology. The combination of regional magnetometry data is applied with deep drilling data using a priori data on historical-geological, structural-formation, reservoir qualities and other factors. With the complex spatial anisotropy of the geomagnetic field and the distribution of magnetization of rocks in the Earth’s crust, the physical prerequisites of magnetic survey data provide quite correct geological interpretation of the results obtained. Findings. Classification and zoning of geomagnetic field anomalies by their morphology, intensity values, gradient and size was conducted, which made it possible to perform identification and geological forecast of magnetically causative bodies and determine their qualitative (structural) features.Various degrees of magnetization of different-age rocks of the South Torgay Petroleum region, as well as their relative location, structure, and depths of occurrence were established. It was revealed that the sedimentary cover and the upper part of the basement here are composed of low-magnetic and non-magnetic formations, and the upper edges of the magnetically disturbing masses lie at different depths in the consolidated crust, but, in general, deeper than the intervals of the section penetrated by deep drilling. Originality. The genetic, historical, geological, and tectonic-magmatic features of the South Torgay basin differ sharply from those of the adjacent Lower Syrdariya arch and Shu-Sarysu Depression. At the present stage of evolution, South Torgay sedimentary basin has a significant endogenous warming of the lithosphere in contrast to the adjacent Lower Syrdariya arch and Shu-Sarysu depression. To some extent, it indicates the inheritance in the regime of development of the South Turgay sedimentary basin from the Paleozoic and Mesozoic stages of rifting. Practical value. The depth of occurrence of magnetically causative objects significantly expand the stratigraphic interval of sediments that can be involved in the exploration process. The inherited mode of rift evolution of the basin suggests a favorable combination for the formation of a wide range of hydrocarbon traps, oil and gas source rocks, migration pathways, accumulation and preservation of HC accumulations.
46
Silliman, Alan H., and Rick Schrynemeeckers. "Microseepage through evaporite sequences — A Gulf of Suez example." Interpretation 10, no. 1 (December 24, 2021): SB39—SB47. http://dx.doi.org/10.1190/int-2021-0078.1.
Full textAbstract:
Salt is one of the most effective agents for trapping oil and gas. As a ductile material, it can move and deform surrounding sediments and create traps. However, effective sealing of reservoirs for movement of hydrocarbons along breaching faults or fracture swarms (i.e., macroseepage) is a different mechanism than the movement of hydrocarbons on a molecular scale along grain boundaries and microfractures as happens with microseepage. To address salt seal integrity, Forum Exploration has chosen to evaluate the applicability of passive surface geochemical surveys for mapping hydrocarbons in their onshore West Gebel El Zeit lease in part due to difficulties in seismic imaging through salt and anhydrite sequences. Two economic producing wells have been drilled in the lease, but due to compartmentalization and complexity in the area, three dry wells also have been drilled. Target formations include the Kareem Formation at approximately 2700 m and the Rudeis Formation at approximately 3000 m. The geochemical survey encompasses 100 passive geochemical modules. Passive samplers also have been deployed around two producing wells and one dry well for geochemical calibration. Calibration data indicate positive thermogenic signatures around the two producing wells in contrast to the background or baseline signature from around the dry well. The Kareem Formation calibration signature ranges from approximately C6 to C12 with the Rudeis Formation calibration signature ranging from C5 to C9. This suggests that the Rudeis calibration signature is lighter than the Kareem, in agreement with independent measurement of American Petroleum Institute (API) gravity on produced oil samples (API gravity 41° oil for the Rudeis and 35° oil for the Kareem). A postsurvey well, Fh85-8, has been drilled based on combined geochemical and seismic data results. The well is a Kareem oil discovery, with an initial production of approximately 800 barrels of oil per day. We have developed evidence in this Gulf of Suez example to show that microseepage occurs through substantial salt sequences. Consequently, ultrasensitive passive surface geochemical surveys provide a powerful tool for derisking salt plays.
47
Susantoro, Tri Muji, S. Suliantara, Herru Lastiadi Setiawan, Bambang Widarsono, and Ketut Wikantika. "Heavy Oil Potentials in Central Sumatra Basin, Indonesia Using Remote Sensing, Gravity, and Petrophysics Data: From Literature Review to Interpretations and Analyses." Indonesian Journal of Science and Technology 7, no. 3 (October 10, 2022): 363–84. http://dx.doi.org/10.17509/ijost.v7i3.51288.
Full textAbstract:
Central Sumatra basin is located on Sumatra Island, Indonesia, and is considered an oil prolific basin that produces heavy oil. The basin is believed to have unexplored heavy oil potential. Therefore, this study aims to map the heavy oil potential distribution in the basin using surface and subsurface lineaments analyses interpreted from satellite imagery and gravity data, and assisted by well log/petrophysics analysis. A thorough basin analysis was conducted based on surface/subsurface structures’ control and source rock location settings to map all potential heavy oil traps. The gravity anomaly data interpretation identified the low areas and lineaments in NW – SE, and N – S directions. The interpretation of satellite imageries showed very similar lineament patterns with the same general direction. It was observed that there is continuity between subsurface and surface lineament features, which provide contact between reservoirs and surface water sources, thereby facilitating heavy oil generation. Overlapping the lineament interpretation of gravity and satellite imagery data, supported by petroleum system understanding and verification from wells data have confirmed 7 heavy oil trap potential areas within the sedimentary basin.
48
Bouroullec, Renaud, Paul Weimer, and Olivier Serrano. "Petroleum geology of the Mississippi Canyon, Atwater Valley, western DeSoto Canyon, and western Lloyd Ridge protraction areas, northern deep-water Gulf of Mexico: Traps, reservoirs, and tectono-stratigraphic evolution." AAPG Bulletin 101, no. 07 (July 2017): 1073–108. http://dx.doi.org/10.1306/09011610093.
Full text
49
Wecker, H. R. B. "THE EROMANGA BASIN." APPEA Journal 29, no. 1 (1989): 379. http://dx.doi.org/10.1071/aj88032.
Full textAbstract:
The Eromanga Basin, encompassing an area of approximately 1 million km2 in Central Australia, is a broad intracratonic downwarp containing up to 3000 m of Middle Triassic to Late Cretaceous sediments.Syndepositional tectonic activity within the basin was minimal and the main depocentres largely coincide with those of the preceding Permo- Triassic basins. Several Tertiary structuring phases, particularly in the Early Tertiary, have resulted in uplift and erosion of the Eromanga Basin section along its eastern margin, and the development of broad, northwesterly- to northeasterly- trending anticlines within the basin. In some instances, high angle faults are associated with these features. This structural deformation occurred in an extensional regime and was strongly influenced by the underlying Palaeozoic structural grain.The Eromanga Basin section is composed of a basal, dominantly non- marine, fluvial and lacustrine sequence overlain by shallow marine deposits which are in turn overlain by another fluvial, lacustrine and coal- swamp sequence. The basal sequence is the principal zone of interest to petroleum exploration. It contains the main reservoirs and potential source rocks and hosts all commercial hydrocarbon accumulations found to date. While the bulk of discovered reserves are in structural traps, a significant stratigraphic influence has been noted in a number of commercially significant hydrocarbon accumulations.All major discoveries have been in the central Eromanga Basin region overlying and adjacent to the hydrocarbon- productive, Permo- Triassic Cooper Basin. The mature Permian section is believed to have contributed a significant proportion of the Eromanga- reservoired hydrocarbons. Accordingly, structural timing and migration pathways within the Permian and Middle Triassic- Jurassic sections are important factors for exploration in the central Eromanga Basin region. Elsewhere, in less thermally- mature areas, hydrocarbon generation post- dates Tertiary structuring and thus exploration success will relate primarily to source- rock quality, maturity and drainage factors.Although exploration in the basin has proceeded spasmodically for over 50 years, it has only been in the last decade that significant exploration activity has occurred. Over this recent period, some 450 exploration wells and 140 000 km of seismic acquisition have been completed in the pursuit of Eromanga Basin oil accumulations. This has resulted in the discovery of 227 oil and gas pools totalling an original in- place proved and probable (OOIP) resource of 360 MMSTB oil and 140 BCF gas.Though pool sizes are generally small, up to 5 MMSTB OOIP, the attractiveness of Eromanga exploration lies in the propensity for stacked pools at relatively shallow depths, moderate to high reservoir productivity, and established infrastructure with pipelines to coastal centres. Coupled with improved exploration techniques and increasing knowledge of the basinal geology, these attributes will undoubtedly ensure the Eromanga Basin continues to be a prime onshore area for future petroleum exploration in Australia.
50
Rousseau, Mathieu, Gilles Dromart, Henk Droste, and Peter Homewood. "Stratigraphic organisation of the Jurassic sequence in Interior Oman, Arabian Peninsula." GeoArabia 11, no. 1 (January 1, 2006): 17–50. http://dx.doi.org/10.2113/geoarabia110117.
Full textAbstract:
ABSTRACT A Stratigraphic model is proposed for the Jurassic sequence in Interior Oman. The model is based on regional well-log correlations, outcrop analysis and integration of Biostratigraphy. Large-scale architectures are restored using a well-to-well correlation technique, after the well-log markers of the relevant surfaces of sequence stratigraphy are identified. This identification is achieved by comparing well-log signatures to lithological and sedimentological columns of nearby exposed sections. The subsurface dataset consists of 19 wells arranged in two east-west profiles, 341 km and 332 km long. The Jurassic sequence in Interior Oman shows a general easterly thinning wedge and includes two hiatuses with marked age-gaps. Three major depositional episodes are identified: (1) a Pliensbachian-Toarcian coastal encroachment in a southward direction, represented by the dominantly clastic deposition of the Lower Mafraq Formation upon the Permian carbonates; (2) a general late Bajocian marine flooding (hybrid facies of marginal-marine environments of the Upper Mafraq Formation), followed through the Bathonian-Callovian by the carbonate Dhruma-Tuwaiq System which evolved through time from a low-angle, homoclinal ramp dipping in a (north) westwards direction, to a purely aggradational, flat-topped platform (upper Dhruma and Tuwaiq Mountain formations); (3) a Kimmeridgian-Tithonian onlap in an eastwards direction of finegrained limestones (Jubaila-Rayda) upon the post-Tuwaiq unconformity. Depositional hiatuses in the early Liassic and at the Early-Middle Jurassic transition are likely to reflect major eustatic sea-level lowstands. In contrast, subsurface correlations of the MFSs through the Dhruma-Tuwaiq indicate that the post-Tuwaiq unconformity is a low-angle (0.001 degrees) angular unconformity associated with tilting and truncation of the underlying sequences. Oxfordian sequences were probably never deposited in Interior Oman because of a lack of accommodation space and prolonged subaerial exposure. It is here proposed that the Upper/Middle Jurassic angular unconformity in Interior Oman was planed-off by subaerial carbonate dissolution during a steady, tectonically-driven uplift of the whole eastern Arabian shelf edge. The proposed geological model has several implications for the petroleum systems of Interior Oman. The geometric model predicts the distribution of the sedimentary facies, including source rocks, clastic and carbonate reservoirs, and seal facies. The occurrence of isolated Upper Mafraq-producing reservoir sands (i.e. Sayh Rawl field) are believed to be restricted to central and eastern Interior Oman. There are two other reservoir/seal combinations, both related to the Upper/Middle Jurassic unconformity: (1) truncation traps of the Dhruma-Tuwaiq below the unconformity (i.e. Hadriya and Uwainat reservoirs); (2) updip pinch-out trap of the Hanifa above the unconformity. Finally, it is believed that the early Late Jurassic general uplift and truncation of eastern Oman may have caused local remobilisation, updip migration, and loss to the surface of oil in reservoirs, initially generated from the prolific Al Huqf source rocks of Late Precambrian-Early Cambrian age.