Lower Tertiary Sequence Research Articles

Stratigraphy of Upper Cretaceous-Palaeogene sequences in the southern and eastern Menderes Massif (western Turkey)

The stratigraphy of the uppermost levels of the Menderes Massif is controversial and within its details lie vital constraints to the tectonic evolution of south-western Turkey. Our primary study was carried out in four reference areas along the southern and eastern Menderes Massif. These areas lie in the upper part of the Menderes metamorphic cover and have a clear stratigraphic relationship and contain datable fossils. The first one, in the Akbuk–Milas area, is located south-east of Bafa Lake where the Milas, then Kizilagac and Kazikli formations are well exposed. There, the Milas formation grades upwards into the Kizilagac formation. The contact between the Kizilagac and the overlying Kazikli formation is not clearly seen but is interpreted as an unconformity. The Milas and Kizilagac formations are also found north of Mugla, in the region of Yatagan and Kavaklidere. In these areas, the Milas formation consists of schists and conformably overlying platform-type, emery and rudist-bearing marbles. Rudists form the main palaeontological data from which a Santonian–Campanian age is indicated. The Kizilagac formation is characterized by reddish–greyish pelagic marbles with marly-pelitic interlayers and coarsening up debris flow deposits. Pelagic marbles within the formation contain planktonic foraminifera and nanoplankton of late Campanian to late Maastrichtian age. The Kazikli formation is of flysch type and includes carbonate blocks. Planktonic foraminifera of Middle Palaeocene age are present in carbonate lenses within the formation. In the Serinhisar–Tavas area, Mesozoic platform-type marbles (Yilanli formation) belonging to the cover series of the Menderes Massif exhibit an imbricated internal structure. Two rudist levels can be distinguished in the uppermost part of the formation: the first indicates a middle-late Cenomanian age and the upper one is Santonian to Campanian in age. These marbles are unconformably covered by the Palaeocene–Early Eocene Zeybekolentepe formation with polygenetic breccias. In the Cal–Denizli area, the Menderes massif succession consists of cherty marbles and clastic rocks with metavolcanic lenses. The Lower–Middle Eocene Şalvan formation lies unconformably on this sequence and is interpreted as equivalent to the marble horizons at Serinhisar but with pelagic facies. The Şalvan formation consists of shale, mafic volcanic rock, lenses of limestone and blocks of recrystallized limestone. The Şalvan formation is dated here for the first time by Early–Middle Eocene foraminifera and nanoplankton from the matrix of the formation. An angular unconformity exists between the Upper Cretaceous and Lower Tertiary sequences, suggesting that a phase of deformation affected the southern and eastern part of the Menderes Massif at this time. This deformation may be caused by initial obduction of the Lycian ophiolite onto the passive margin to the north of the Menderes carbonate platform during the latest Cretaceous. Drowning of the platform led to termination of carbonate deposition and deposition of deep water flysch-like clastic sediments.

The characteristics of the Geological structures of the Tertiary basins on the continental margin in the northern part of the South China Sea

The superimposed assemblages of structural lines trending northeast, east-northeast and west-northwest form the major structural framework of the continental margin in the northern South China Sea. The northeast structural trend represents Mesozoic basement trends, those in early Paleogene sedimentary layers. The east-northeast or west-northwest structural lines developed in post-Eocene-Oligocene sedimentary layers as a result of superimposition of northeast trends. The Tertiary sedimentary basins have been produced and developed in block structures formed by these structural trends. Tertiary deposits at the continental margin of the northern South China Sea reach a maximum thickness of 10 km. Lower Tertiary sequences are usually absent from the high points but are commonly present in the splintered segments, with continental deposits dominating. The Upper Tertiary section is well developed, and extensively overlaps the high points and the splintered segments, with marine deposits dominating. Tertiary sediments can be divided into four subcycles of Paleocene-Early Oligocene, Late Oligocene-Early Miocene, Mid-Miocene-Late Miocene, and Late Miocene-Pliocene ages. The early Pliocene transgression was the greatest since late Oligocene time. During Early-Late Miocene time, regression was most extensive. All or part of the Upper Miocene is absent in many basins. The known productive formations (Eocene Lower Oligocene, Upper Oligocene-Lower Miocene and Mid-Miocene) are all closely related to the middle stages of the sedimentary subcycles. Tertiary basins have different structural positions depending on basement features. Multisite-type faulting depressions are developed within the basin causing splintering. The basins are shaped like grabens and pan-type depressions, and had an initial stage of faulting, a middle stage of depression, and a late stage of overlapping and coverage by sediments. The development of normal faults within the basin, high heat flow, and the lack of compressive folding show that the basins were formed by extension. The development of basins was influenced by four plate movements during Cenozoic time. The Tertiary basins in the north of the South China Sea are related to the gradual disintegration of the northern continental margin or the South China Sea, the frequent movement of the plates around the South China Sea, and the spreading of the South China Sea Basin. Thus basins were formed with different structural attributes but similar sedimentary cycles.

Habitat of Oil in Abu Gharadig and Faiyum Basins, Western Desert, Egypt

The Abu Gharadig and Faiyum basins are areas which have some of the greatest hydrocarbon potential in the Western Desert of Egypt. Several extensive cycles of marine transgression and regression occurred in these territories through geologic time. The depositional cycles combined with at least 3 tectonic cycles--(1) the Hercynian orogeny at the end of the Paleozoic, (2) from Late Jurassic to early Tertiary, and (3) from Late Cretaceous to middle Tertiary--resulted in a highly deformed, thick sedimentary sequence. This organic-rich Jurassic-Upper Cretaceous-lower Tertiary sequence in large areas of these basins was subjected to enough heat and depth to generate hydrocarbons. It is evident from recent discoveries that these source rocks generated large amounts of high-quali y oil and gas. The Abu Gharadig and Faiyum basins are separated structurally by a major ridge. Both basins are bounded on the north by another major ridge associated with Cretaceous and Tertiary faulting. A major platform with thin sedimentary cover forms the southern boundary. The hydrocarbon potential exists in cyclic sequences of sandstone, shale, and carbonate, having moderate porosities and permeabilities. An important hydrologic phenomenon prevails in major parts of the basins; fresh water has flushed the early Cenomanian and older reservoirs. The eastern part of the Faiyum basin, the southern platform, the Kattaniya high, and the southern and western rims of the Abu Gharadig basin are completely flushed, leaving little chance for hydrocarbon preservation in these localities. Exploration efforts should be concentrated on deep structures close to the main depocenters and inside or very close to the 150°F (65°C) geothermal contour. Contemporaneous structures on the northern rims of the basins should have high potential, resulting from migration of hydrocarbons from the south across major faults. The Jurassic in the northeastern part of the Abu Gharadig basin may provide good hydrocarbon potential. The lower Tertiary sequence present in the troughs also may have large amounts of oil entrapped in situ or resulting in short-distance migration to the northern structures or to the Late Cretaceous-early Tertiary Syrian arc traps.

New Zealand and Southwest Pacific Islands

In New Zealand, new incentives by the government have greatly stimulated interest in exploration. On land, four wells were completed during 1980 at a total depth of 10,120 m. One well was a commercial oil and gas discovery. Offshore, the first exploratory well since 1978 was spudded shortly before the end of 1980. Offshore concession areas have increased over ten-fold, to 107,044 km2; on-land licenses, which are all owned by the government company Petrocorp, decreased to 11,591 km2. During 1980, the combined output of Kapuni and Maui gas was 1,069.049 × 106 m3, a decrease of 18.23%. This reflects the new gas-recycling operation at the Kapuni field, which started in April. Combined condensate production was down only 12.15%, amounting to 418,941 m3. Natural gasoline was down 17.44%, to 7,093 m3, whereas LPG production went up 39.44%, to 27,301 m3. In Tonga, 925 km of offshore multichannel seismic, gravity, and magnetic surveys run in 1979 have been processed and interpreted. Firm drilling proposals must be submitted by July 1, 1981, otherwise the Petroleum Agreement will be terminated. Outside the presently held license area of 15,540 km2, CCOP/SOPAC have conducted two single-channel seismic surveys: a 900-km survey north of Vava'u and a 2,140-km survey over the Tonga Platform south of Tongatapu. Widespread occurrence of relatively thick sediments has been encountered, particularly in the southern area. In Fiji, the first two exploratory wells ever drilled were dry. Total depths of the wells were 2,743 m and 2,839 m. The wells were drilled in Bligh Water north of the island of Viti Levu and terminated in a lower Tertiary sequence without reaching basement. In Vanuatu, the newly independent republic of the former New Hebrides Condominium, no petroleum legislation has so far been introduced. CCOP/SOPAC and ORSTOM jointly ran a 4,000-km single-channel reflection seismic survey between the northern islands. Several sedimentary basins with over 2,500 m of slightly deformed sediments of Miocene-Pliocene age have been delineated. However, the water depth is generally about 2,000-3,000 m. In the Solomon Islands, there is still no petroleum legislation, but the draft of the Petroleum (Exploration and Development) Act has been completed and will go before Parliament during 1981. In Papua New Guinea, one well was drilled to 3,027 m and abandoned as dry. It confirmed the regional stratigraphic interpretation and had encouraging hydrocarbon indications in the Mesozoic part of the sequence. Concession holdings increased to 815 blocks, with another 394 blocks under application.

PETROLEUM PROSPECTS OF TASMAN AND GOLDEN BAY AREAS, SOUTHERN COOK STRAIT, NEW ZEALAND

Petroliferous sediments of Lower Tertiary age are preserved in a number of sub-basins, basin synclines and graben along the western portions of both islands of New Zealand.These form part of the extensively disrupted lineal and platform-like Cretaceous-Tertiary "West Basin" or geosyncline which is separated from a comparable "East Geosyncline" by the geanticlinal backbone of the New Zealand island-chain.Sedimentation in the West Basin was thick (10,000 to 20,000 feet or more) and continuous throughout much of the Cretaceo- Tertiary interval. Unconformities, where present, tend to be local features, but may still represent marked erosional and/or structural breaks. Lithologic and facies changes are not infrequent on a small scale, but these are superimposed on regional sequences that are traceable over the full longitudinal extent of the overall basin.Cretaceous to Lower Tertiary sequences tend to be freshwater and coal-bearing, but may be "paralic" locally. More marine facies are predicted beneath Cook Strait. Later Tertiary sediments are more predominantly marine, and include big thicknesses of mudstone and limestone.Oil seepages occur in a number of situations in the West Basin, and are associated with Lower Tertiary coal measures. In the Taranaki sub-basin the small oil field at New Plymouth has produced a total of 200,000 barrels of oil and 65 million cubic feet of gas, while the more recently discovered (1959) Kapuni condensate-gas field is capable of producing 60 million cubic feet of gas per day, of which 40 per cent is CO, accompanied initially by 4,500 million barrels per day of condensate.The Nelson and Farewell Spit sub-basins of present interest respectively plunge north beneath Tasman and Golden Bays on either side of the Pikikirunl Range "horst". They then coalesce beyond Separation Point and link with the Kapuni sub-basin beneath Cook Strait as part of the modern continental shelf. These graben-like developments are characterised by strong north plunge.Geophysical surveys leading to the better understanding of basin sub-structure about southern Cook Strait are discussed, followed by consideration of possible petroleum potential. Gravity anomalies in both the Tasman and Golden Bay areas, supported by seismic surveys, have confirmed anticlinal structure. Structural and stratigraphic traps for petroleum are predicted in relation particularly to these developments.