THE GEOLOGY AND EVOLUTION OF THE SOUTH PEPPER HYDROCARBON ACCUMULATION

1985 ◽  
Vol 25 (1) ◽  
pp. 235 ◽  
Author(s):  
A.F. Williams ◽  
D.J. Poynton
Keyword(s):  
Middle Miocene ◽  
Oil And Gas ◽  
Upper Jurassic ◽  
Lower Jurassic ◽  
Source Rocks ◽  
The South ◽  
Hydrocarbon Migration ◽  
Tectonic Event ◽  
The North ◽  
Migration History

The South Pepper field, discovered in 1982, is located 30 km southwest of Barrow Island in the offshore portion of the Barrow Sub-basin, Western Australia. The oil and gas accumulation occurs in the uppermost sands of the Lower Cretaceous Barrow Group and the overlying low permeability Mardie Greensand Member of the Muderong Shale.The hydrocarbons are trapped in one of several fault closed anticlines which lie on a high trend that includes the North Herald, Pepper and Barrow Island structures. This trend is postulated to have formed during the late Valanginian as the result of differential compaction and drape over a buried submarine fan sequence. During the Turonian the trend acted as a locus for folding induced by right-lateral wrenching along the sub-basin edge. Concurrent normal faulting dissected the fold into a number of smaller anticlines. This essentially compressional tectonic phase contrasted with the earlier extensional regime which was associated with rift development during the Callovian. A compressional tectonic event in the Middle Miocene produced apparent reverse movement on the South Pepper Fault but only minor changes to the structural closure.Geochemical and structural evidence indicates at least two periods of hydrocarbon migration into the top Barrow Group - Mardie Greensand reservoir. The earlier occurred in the Turonian subsequent to the period of wrench tectonics and involved the migration of oil from Lower Jurassic Dingo Claystone source rocks up the South Pepper Fault. This oil was biodegraded before the second episode of migration occurred after the Middle Miocene tectonism. The later oil is believed to have been sourced by the Middle to Upper Jurassic Dingo Claystone. Biodegradation at this stage ceased or became insignificant due to temperature increase and reduction of meteoric water flow. Gas-condensate, sourced from Triassic or Lower Jurassic sediments may have migrated into the structure with this second oil although a more recent migration cannot be ruled out.The proposed structural and hydrocarbon migration history fits regional as well as local geological observations for the Barrow Sub-basin. Further data particularly from older sections of the stratigraphic column within the area are needed to refine the interpretation.

New insights into the Hercynian Orogeny, and their implications for the Paleozoic Hydrocarbon System in the Arabian Plate

GeoArabia ◽  
2009 ◽  
Vol 14 (3) ◽  
pp. 199-228 ◽  
Author(s):  
Mohammad Faqira ◽  
Martin Rademakers ◽  
AbdulKader M. Afifi
Keyword(s):  
Oil And Gas ◽  
Seismic Imaging ◽  
Structural Features ◽  
Source Rocks ◽  
Arabian Plate ◽  
Arabian Shield ◽  
Tectonic Event ◽  
Angular Unconformity ◽  
The North ◽  
Hercynian Orogeny

ABSTRACT During the past decade, considerable improvements in the seismic imaging of the deeper Paleozoic section, along with data from new well penetrations, have significantly improved our understanding of the mid-Carboniferous deformational event. Because it occurred at the same time as the Hercynian Orogeny in Europe, North Africa and North America it has been commonly referred to by the same name in the Middle East. This was the main tectonic event during the late Paleozoic, which initiated or reactivated many of the N-trending block uplifts that underlie the major hydrocarbon accumulations in eastern Arabia. The nature of the Hercynian deformation away from these structural features was poorly understood due to inadequate seismic imaging and insufficient well control, along with the tectonic overprint of subsequent deformation events. Three Hercynian NE-trending arches are recognized in the Arabian Plate (1) the Levant Arch, which extended from Egypt to Turkey along the coast of the Mediterranean Sea, (2) the Al-Batin Arch, which extended from the Arabian Shield through Kuwait to Iran, and (3) the Oman-Hadhramaut Arch, which extended along the southeast coast of Oman and Yemen. These arches were initiated during the mid-Carboniferous Hercynian Orogeny, and persisted until they were covered unconformably by the Khuff Formation during the Late Permian. Two Hercynian basins separate these arches: the Nafud-Ma’aniya Basin in the north and Faydah-Jafurah Basin in the south. The pre-Hercynian Paleozoic section was extensively eroded over the arches, resulting in a major angular unconformity, but generally preserved within the basins. Our interpretation suggests that most of the Arabian Shield, except the western highlands along the Red Sea, is the exhumed part of the Al-Batin Arch. The Hercynian structural fabric of regional arches and basins continue in northern Africa, and in general appear to be oriented orthogonal to the old margin of the Gondwana continent. The Hercynian structure of arches and basins was partly obliterated by subsequent Mesozoic and Cenozoic tectonic events. In eastern Saudi Arabia, Qatar, and Kuwait, regional extension during the Triassic formed N-trending horsts and graben that cut across the NE-trending Hercynian mega-structures, which locally inverted them. Subsequent reactivation during the Cretaceous and Neogene resulted in additional growth of the N-trending structures. The Hercynian Arches had major impact on the Paleozoic hydrocarbon accumulations. The Silurian source rocks are generally preserved in the basins and eroded over the arches, which generally confined Silurian-sourced hydrocarbons either within the basins or along their flanks. Furthermore, the relict Hercynian paleo-topography generally confined the post-Hercynian continental clastics of the Unayzah Formation and equivalents to the Hercynian basins. These clastics contain the main Paleozoic oil and gas reservoirs, particularly along the basin margins where they overlie the sub-crop of the Silurian section with angular unconformity, thus juxtaposing reservoir and source rock.

The discovery of a new sedimentary basin: offshore Raukumara, East Coast, North Island, New Zealand

2008 ◽  
Vol 48 (1) ◽  
pp. 53 ◽  
Author(s):  
Chris Uruski ◽  
Callum Kennedy ◽  
Rupert Sutherland ◽  
Vaughan Stagpoole ◽  
Stuart Henrys
Keyword(s):  
New Zealand ◽  
Oil And Gas ◽  
East Coast ◽  
Plate Boundary ◽  
Source Rocks ◽  
Fault System ◽  
Northern Coast ◽  
The South ◽  
Petroleum Potential ◽  
The North

The East Coast of North Island, New Zealand, is the site of subduction of the Pacific below the Australian plate, and, consequently, much of the basin is highly deformed. An exception is the Raukumara Sub-basin, which forms the northern end of the East Coast Basin and is relatively undeformed. It occupies a marine plain that extends to the north-northeast from the northern coast of the Raukumara Peninsula, reaching water depths of about 3,000 m, although much of the sub-basin lies within the 2,000 m isobath. The sub-basin is about 100 km across and has a roughly triangular plan, bounded by an east-west fault system in the south. It extends about 300 km to the northeast and is bounded to the east by the East Cape subduction ridge and to the west by the volcanic Kermadec Ridge. The northern seismic lines reveal a thickness of around 8 km increasing to 12–13 km in the south. Its stratigraphy consists of a fairly uniformly bedded basal section and an upper, more variable unit separated by a wedge of chaotically bedded material. In the absence of direct evidence from wells and samples, analogies are drawn with onshore geology, where older marine Cretaceous and Paleogene units are separated from a Neogene succession by an allochthonous series of thrust slices emplaced around the time of initiation of the modern plate boundary. The Raukumara Sub-basin is not easily classified. Its location is apparently that of a fore-arc basin along an ocean-to-ocean collision zone, although its sedimentary fill must have been derived chiefly from erosion of the New Zealand land mass. Its relative lack of deformation introduces questions about basin formation and petroleum potential. Although no commercial discoveries have been made in the East Coast Basin, known source rocks are of marine origin and are commonly oil prone, so there is good potential for oil as well as gas in the basin. New seismic data confirm the extent of the sub-basin and its considerable sedimentary thickness. The presence of potential trapping structures and direct hydrocarbon indicators suggest that the Raukumara Sub-basin may contain large volumes of oil and gas.

GEOLOGY OF BARROW ISLAND OIL FIELD

1973 ◽  
Vol 13 (1) ◽  
pp. 49 ◽  
Author(s):  
Keith Crank
Keyword(s):  
Oil And Gas ◽  
Water Injection ◽  
Water Source ◽  
Upper Jurassic ◽  
Oil Field ◽  
Late Triassic ◽  
Low Permeability ◽  
High Porosity ◽  
The South ◽  
The North

The Barrow Island oil field, which was discovered by the drilling of Barrow 1 in 1964, was declared commercial in 1966. Since then 520 wells have been drilled in the development of this field which has resulted in 309 Windalia Sand oil producers (from about 2200 feet), eight Muderong Greensand oil wells (2800 feet), five Neocomian/Upper Jurassic gas and oil producers (6200 to 6700 feet), eight Barrow Group water source wells and 157 water injection wells.Production averages 41,200 barrels of oil per day, and 98% of this comes from the shallow Windalia Sand Member of Cretaceous (Aptian to Albian) age. These reserves are contained in a broad north-plunging nose truncated to the south by a major down-to-the-south fault. The anticline is thought to have been formed initially from a basement uplift during Late Triassic to Early Jurassic time. Subsequent periods of deposition, uplift and erosion have continued into the Tertiary and modified the structure to its present form. The known sedimentary section on Barrow Island ranges from Late Jurassic to Miocene.The Neocomian/Jurassic accumulations are small and irregular and are not thought to be commercial in themselves. The Muderong Greensand pool is also a limited, low permeability reservoir. Migration of hydrocarbons is thought to have occurred mainly in the Tertiary as major arching did not take place until very late in the Cretaceous or early in the Palaeocene.The Windalia Sand reservoir is a high porosity, low permeability sand which is found only on Barrow Island. One of the most unusual features of this reservoir is the presence of a perched gas cap. Apparently the entire sand was originally saturated with oil, and gas subsequently moved upstructure from the north, displacing it. This movement was probably obstructed by randomly-located permeability barriers.

The Beryl Field, Block 9/13, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 33-42 ◽  
Author(s):  
C. A. Knutson ◽  
I. C. Munro
Keyword(s):  
North Sea ◽  
Middle Jurassic ◽  
Oil And Gas ◽  
Upper Jurassic ◽  
Lower Jurassic ◽  
Gas Production ◽  
Upper Triassic ◽  
Oil Field ◽  
Oil And Gas Production ◽  
The North

AbstractThe Beryl Field, the sixth largest oil field in the UK sector of the North Sea, is located within Block 9/13 in the west-central part of the Viking Graben. The block was awarded in 1971 to a Mobil operated partnership and the 9/13-1 discovery well was drilled in 1972. The Beryl A platform was emplaced in 1975 and the Beryl B platform in 1983. To date, ninety-five wells have been drilled in the field, and drilling activity is anticipated into the mid-1990s.Commercial hydrocarbons occur in sandstone reservoirs ranging in age from Upper Triassic to Upper Jurassic. Structurally, the field consists of a NNE orientated horst in the Beryl A area and westward tilted fault blocks in the Beryl B area. The area is highly faulted and complicated by two major and four minor unconformities. The seal is provided by Upper Jurassic shales and Upper Cretaceous marls.There are three prospective sedimentary sections in the Beryl Field ranked in importance as follows: the Middle Jurassic coastal deltaic sediments, the Upper Triassic to Lower Jurassic continental and marine sediments, and the Upper Jurassic turbidites. The total ultimate recovery of the field is about 800 MMBBL oil and 1.6 TCF gas. As of December 1989, the field has produced nearly 430 MMBBL oil (primarily from the Middle Jurassic Beryl Formation), or about 50% of the ultimate recovery. Gas sales are scheduled to begin in the early 1990s. Oil and gas production is forecast until licence expiration in 2018.The Beryl Fields is located 215 miles northeast of Aberdeen, about 7 miles from the United Kingdom-Norwegian boundary. The field lies within Block 9/13 and covers and area of approximately 12 000 acres in water depths ranging from 350-400 ft. Block 9/13 contains several hydrocarbon-bearing structures, of which the Beryl Fields is the largest (Fig. 1). The field is subdivided into two producing areas: the Beryl Alpha area which includes the initial discovery well, and the Beryl Bravo area located to the north. The estimated of oil originally in place is 1400 MMBBL for Beryl A and 700 MMBBL for Beryl B. The fiel has combined gas in place of 2.8 TCF, consisting primarily of solution gas. Hydrocarbon accumulations occur in six reservoir horizons ranging in age from Upper Triassic to Upper Jurassic. The Middle Jurassic (Bathonian to Callovian) age Beryl Formation is the main reservoir unit and contains 78% of the total ultimate recovery.The field was named after Beryl Solomon, the wife of Charles Solomon, who was president of Mobil Europe in 1972 when the field was discovered. The satellite fields in Block 9/13 (Nevis, Ness and Linnhe) are named after Scottish lochs.

WANDOO—A NEW TREND

1994 ◽  
Vol 34 (1) ◽  
pp. 586
Author(s):  
Ernie Delfos ◽  
Malcolm Boardman
Keyword(s):  
Oil And Gas ◽  
Three Dimensional ◽  
Lower Jurassic ◽  
Source Rocks ◽  
Seismic Survey ◽  
Unconsolidated Sediments ◽  
North West ◽  
The North ◽  
Initial Discovery ◽  
A Minor

In June 1991 a flow of 4 560 barrels of 19° API oil per day, from a depth of 600 m, heralded the discovery of a new hydrocarbon trend along the eastern margin of the Dampier Sub-basin on the North West Shelf of Australia. Wandoo–1 recovered oil and gas from lower Cretaceous sands associated with the M.australis dinoflagellate zone (Barremian), and gas from lower Jurassic Aalenian sands.The main reservoir at Wandoo is the M. australis Sandstone Member of the Muderong Shale. This is interpreted to be a shelfal shoal sand deposited in a minor regression phase during the regional transgression of the Muderong Shale. This reservoir is split into two main lithotypes, a glauconitic subarkose to subarenite, and an overlying greensand. Oil and gas have been recovered from both units, which are considered contiguous for reservoir definition. General reservoir parameters are exceptional. Since the initial discovery a 3D seismic survey has been acquired and appraisal drilling has proven approximately 250 MMSTBOIP.The unusual features of the field necessitated innovative exploration techniques and the need for a strong appraisal program. These techniques included a six streamer, high resolution, three dimensional seismic survey and its associated processing; development of methods to recover and preserve core in extremely unconsolidated sediments; use of non destructive core analysis methods such as nuclear magnetic resonance; and petrophysical analysis that incorporates the resistivity suppression problems of glauconite. Without core a very pessimistic view would have been taken of the M. australis Sandstone reservoir.The Wandoo discovery is on an exciting new trend previously overlooked due to the shallowness of reservoirs, lack of locally recognised source rocks and the dominance of other oil and gas trends in the Dampier Sub-basin and Barrow Sub-basin to the south.

scholarly journals Modeling petroleum expulsion in sedimentary basins: The importance of igneous intrusion timing and basement composition

Geology ◽  
2019 ◽  
Vol 47 (10) ◽  
pp. 904-908 ◽  
Author(s):  
David Gardiner ◽  
Nick Schofield ◽  
Alex Finlay ◽  
Niall Mark ◽  
Liam Holt ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Sedimentary Basins ◽  
Upper Jurassic ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Burial Depth ◽  
Radiogenic Heat ◽  
Critical Moment ◽  
The North ◽  
Petroleum Generation

Abstract The concept of a critical moment in a petroleum system (the time of highest probability of entrapment and preservation of oil and gas) has underlain petroleum exploration for over 25 years. However, one area where understanding the critical moment is challenging is the Faroe-Shetland Basin (FSB; offshore UK). Isotopic dating of oils suggests that petroleum generation began between ca. 68 and 90 Ma; however, most basin models invoke an earlier generation beginning in the mid-Cretaceous at ca. 100 Ma, predating deposition of Paleocene and Eocene reservoirs. This time discrepancy has previously been explained by remigration from intermediary accumulations (“motel” hypothesis) and/or overpressure retardation of kerogen maturation. The FSB is characterized by a thick Cretaceous stratigraphic package (up to 5 km) that includes a large net thickness (up to 2 km) of Paleogene igneous material. In our model, separating sedimentary and igneous material and adding the igneous material at the correct time between ca. 58 and 55 Ma shallows the modeled burial depth of the Upper Jurassic source rocks during the Cretaceous sufficiently to delay maturation by 17 m.y. in comparison to results of previous studies. Additionally, previous studies have invoked crustal radiogenic heat production (RHP) based on the Phanerozoic crust averaging ∼2.8 µW/m3 in the North Sea (300 km to the east). However, the FSB basement is composed of significantly older, colder Neoarchean orthogneisses (ca. 2.7–2.9 Ga), reducing RHP by up to 50% to ∼1.6 µW/m3 (σ = 0.74). For the first time, our model unifies geological, geochronological, and geochemical observations, delaying the onset of petroleum expulsion by up to 40 m.y. in comparison to previous models.

scholarly journals PREDICTION OF PARAMETERS FOR COMMERCIAL OIL-AND-GAS CONTENT ZONES OF JURASSIC SEDIMENTS IN THE NORTH OF WESTERN SIBERIA

2019 ◽  
pp. 9-15
Author(s):  
Ya. I. Gladysheva
Keyword(s):  
Western Siberia ◽  
Oil And Gas ◽  
Upper Jurassic ◽  
Geological Structure ◽  
Lower Jurassic ◽  
Gas Content ◽  
Seismic Survey ◽  
The North ◽  
Industrial Productivity ◽  
Commercial Oil

Discovered hydrocarbon deposits in a number of fields are the characteristic of the industrial productivity of Jurassic sediments in the north of Western Siberia. Most of the deposits are in the Middle Jurassic sediments, the signs of hydrocarbons have been obtained in the Lower Jurassic sediments, single deposits have been obtained in the Upper Jurassic sediments. This uneven distribution of deposits in the Jurassic oil and gas bearing facility is associated with the complexity of its structure. Therefore, there is a need to conduct a comprehensive analysis of the geological structure of Jurassic sediments, to identify geological parameters to predict commercial oiland-gas content zones in the investigated territory.Based on the results of the study of deep drilling data, seismic survey in the north of Western Siberia, schematic maps of the depth zones of Jurassic sediments have been constructed, the author of the article determines the parameters of industrial productivity zones. The most significant parameter is abnormally high formation pressure. Based on the conducted researches, the author notes the prospective commercial oil-and-gas content zones for Jurassic sediments within NadymPur watershed.

Deep fluids and their role in hydrocarbon migration and oil deposit formation exemplified by supercritical СO2

2021 ◽  
pp. 1-11
Author(s):  
Sara LIFSHITS
Keyword(s):  
Supercritical Fluid ◽  
Oil And Gas ◽  
Gas Permeability ◽  
Sedimentary Rocks ◽  
Source Rocks ◽  
Reservoir Properties ◽  
Hydrocarbon Migration ◽  
Geological Processes ◽  
Before And After ◽  
Oil Source

ABSTRACT Hydrocarbon migration mechanism into a reservoir is one of the most controversial in oil and gas geology. The research aimed to study the effect of supercritical carbon dioxide (СО2) on the permeability of sedimentary rocks (carbonates, argillite, oil shale), which was assessed by the yield of chloroform extracts and gas permeability (carbonate, argillite) before and after the treatment of rocks with supercritical СО2. An increase in the permeability of dense potentially oil-source rocks has been noted, which is explained by the dissolution of carbonates to bicarbonates due to the high chemical activity of supercritical СО2 and water dissolved in it. Similarly, in geological processes, the introduction of deep supercritical fluid into sedimentary rocks can increase the permeability and, possibly, the porosity of rocks, which will facilitate the primary migration of hydrocarbons and improve the reservoir properties of the rocks. The considered mechanism of hydrocarbon migration in the flow of deep supercritical fluid makes it possible to revise the time and duration of the formation of gas–oil deposits decreasingly, as well as to explain features in the formation of various sources of hydrocarbons and observed inflow of oil into operating and exhausted wells.

Finnmark Platform Composite Tectono-Sedimentary Element, Barents Sea

2021 ◽  
pp. M57-2020-20
Author(s):  
E. Henriksen ◽  
D. Ktenas ◽  
J. K. Nielsen
Keyword(s):  
High Frequency ◽  
Oil And Gas ◽  
Barents Sea ◽  
Upper Jurassic ◽  
Source Rocks ◽  
Basement Rocks ◽  
Sea Bottom ◽  
Middle Carboniferous ◽  
Uralian Orogen ◽  
Glacial Periods

AbstractThe Finnmark Platform Composite Tectono-Sedimentary Element (CTSE), located in the southern Barents Sea, is a northward-dipping monoclinal structural unit. It covers most of the southern Norwegian Barents Sea where it borders the Norwegian Mainland. Except for the different age of basement, the CTSE extends eastwards into the Kola Monocline on the Russian part of the Barents Sea.The general water depth varies between 200-350 m, and the sea bottom is influenced by Plio-Pleistocene glaciations. A high frequency of scour marks and deposition of moraine materials exists on the platform areas. Successively older strata sub-crop below the Upper Regional Unconformity (URU, which was) formed by several glacial periods.Basement rocks of Neoproterozoic age are heavily affected by the Caledonian Orogeny, and previously by the Timanide tectonic compression in the easternmost part of the Finnmark Platform CTSE.Depth to crystalline basement varies considerably and is estimated to be from 4-5 to 10 km. Following the Caledonian orogenesis, the Finnmark Platform was affected by Lower to Middle Carboniferous rifting, sediment input from the Uralian Orogen in the east, the Upper Jurassic / Lower Cretaceous rift phase and the Late Plio-Pleistocene isostatic uplift.A total of 8 exploration wells drilled different targets on the platform. Two minor discoveries have been made proving presence of both oil and gas and potential sandstone reservoirs of good quality identified in the Visean, Induan, Anisian and Carnian intervals. In addition, thick sequences of Perm-Carboniferous carbonates and spiculitic chert are proven in the eastern Platform area. The deep reservoirs are believed to be charged from Paleozoic sources. A western extension of the Domanik source rocks well documented in the Timan-Pechora Basin may exist towards the eastern part of the Finnmark Platform. In the westernmost part, charge from juxtaposed down-faulted basins may be possible.

scholarly journals Evaluation of hydrocarbons generated from the Permo-Carboniferous source rocks in Huanghua Depression of the Bohai Bay Basin, China

2018 ◽  
Vol 36 (5) ◽  
pp. 1229-1244
Author(s):  
Xiao-Rong Qu ◽  
Yan-Ming Zhu ◽  
Wu Li ◽  
Xin Tang ◽  
Han Zhang
Keyword(s):  
Oil And Gas ◽  
Source Rocks ◽  
Bohai Bay ◽  
Hydrocarbon Generation ◽  
Burial History ◽  
Bohai Bay Basin ◽  
Important Conclusion ◽  
The North ◽  
Huanghua Depression ◽  
History Of

The Huanghua Depression is located in the north-centre of Bohai Bay Basin, which is a rift basin developed in the Mesozoic over the basement of the Huabei Platform, China. Permo-Carboniferous source rocks were formed in the Huanghua Depression, which has experienced multiple complicated tectonic alterations with inhomogeneous uplift, deformation, buried depth and magma effect. As a result, the hydrocarbon generation evolution of Permo-Carboniferous source rocks was characterized by discontinuity and grading. On the basis of a detailed study on tectonic-burial history, the paper worked on the burial history, heating history and hydrocarbon generation history of Permo-Carboniferous source rocks in the Huanghua Depression combined with apatite fission track testing and fluid inclusion analyses using the EASY% Ro numerical simulation. The results revealed that their maturity evolved in stages with multiple hydrocarbon generations. In this paper, we clarified the tectonic episode, the strength of hydrocarbon generation and the time–spatial distribution of hydrocarbon regeneration. Finally, an important conclusion was made that the hydrocarbon regeneration of Permo-Carboniferous source rocks occurred in the Late Cenozoic and the subordinate depressions were brought forward as advantage zones for the depth exploration of Permo-Carboniferous oil and gas in the middle-northern part of the Huanghua Depression, Bohai Bay Basin, China.

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