Origin of Hemipelagic Source Rocks During Early and Middle Miocene, Monterey Formation, Salinas Basin, California

AAPG Bulletin ◽  
1989 ◽  
Vol 73 ◽  
Author(s):  
Karl A. Mertz, Jr. (2)
1994 ◽  
Vol 34 (1) ◽  
pp. 626
Author(s):  
B.G. West ◽  
V.L. Passmore

Despite 20 years of exploration between 1965 and 1992 in the northeastern part of the Bonaparte Basin, the region remains underexplored. Exploration has produced modest encouragement. The seven wells drilled in the area totalling more than 70 000 km2 include one dry gas and two gas/condensate discoveries. Explorers have targeted the Jurassic Plover Formation and Flamingo Group, but reservoir quality has often been poor in both units due largely to depth of burial.Recent regional studies of the northeastern part of the Bonaparte Basin, undertaken by the Bureau of Resource Sciences, indicate there is potential for generation and entrapment of hydrocarbons in the Cretaceous Bathurst Island Group. Geochemical results show the lower Bathurst Island Group contains good source rocks that are largely gas prone, but have the potential to charge large Cretaceous traps. Geohistory modelling suggests that the Bathurst Island Group may have entered the oil window around the Middle Cretaceous, after most of the structuring had occurred, and continued until the Middle Miocene or later. Potential reservoirs have been identified in Santonian, Campanian and Maastrichtian sands, and in fractured Albian Carbonates.Recent reports have predicted that by early next century there will be a significant increase in natural gas consumption in Australia, due to increased use for power generation and transportation, as well as further sales to the Asian market. New methanol technology could commercialise some marginal gas fields. The theme for this years APEA conference is `New Age—New Opportunities'. The Bonaparte Basin may provide the opportunity to explore for and develop new gas accumulations.


Author(s):  
Putri Dwi Afifah ◽  
Budhi Setiawan

The research location is geologically located in Jambi Sub-basin composed by Peneta Formation (KJp), Airbenakat (Tma), and Muara Enim (Tmpm). Specifically this research focuses on the physical characteristics and geochemistry of Middle Miocene black shale from Airbenakat Formation. The purpose of this research is to determine whether the black shale of this formation has the potential as a source rock. The method of this research are field observation that includes the description of rock samples and geological mapping, and laboratory analysis including rock geochemical analysis. Three samples were taken from black and fine-grained shale. Total organic carbon (TOC) values of the three samples taken ranged from 0.38-0.42%, the weight of TOC indicates a potentially close enough to produce hydrocarbons. the pyrolysis results show that the S1 data gives a value below 0.5 HC/g and S2 gives a value below 2.5 HC/g, so it can be seen that the three rock samples that tested are not sufficient enough to produce hydrocarbons. Overall the sample has a S2/S3 ratio ranging from 0.09-0.23 and Tmax-HI data has values ranging from 8-19 mg HC/g TOC, so it can be seen that the ratio S2/S3 less than 1 and the value of the index hydrogen below 50 mg HC/g TOC, It can be concluded that the samples are derived from type IV kerogen. The maximum temperature (Tmax) of pyrolysis shows a value of less than 4350C, where the values range from 350-4280C. So, it can be interpreted that the three samples are immature source rocks because the catagenesis phase to produce hydrocarbons has not been achieved. The conclusions is the three samples of black shale tested indicate potential as immature source rock and has the close enough ability to produce hydrocarbons. The result of the analysis then comparable with the result analysis of Airbenakat Formation Black Shale in Palembang Sub-basin which has fair-well ability to produce hydrocarbons.  


1985 ◽  
Vol 25 (1) ◽  
pp. 235 ◽  
Author(s):  
A.F. Williams ◽  
D.J. Poynton

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.


GeoArabia ◽  
2014 ◽  
Vol 19 (4) ◽  
pp. 59-108
Author(s):  
G. Wyn Hughes

ABSTRACT The Saudi Arabian Red Sea stratigraphy consists of a variety of lithologies that range from evaporites, deep- and shallow-marine siliciclastics and carbonates, biostratigraphically constrained to range from the Late Cretaceous, Campanian, to Late Pliocene. The succession consists of pre-rift Mesozoic and Palaeogene sediments, and syn-rift and post-rift late Palaeogene and Neogene sediments. Three main episodes of shallow-marine carbonate deposition can be determined, including those of the earliest Early Miocene Musayr Formation of the Tayran Group later Early Miocene Wadi Waqb Member of the Jabal Kibrit Formation and of the Pliocene Badr Formation of the Lisan Group. The Midyan area of the northern Red Sea offers a unique window into the Cretaceous and Miocene succession that is otherwise only present in the deep subsurface. The sediments are of hydrocarbon interest because of the presence of source rocks, siliciclastic and carbonate reservoirs. The Wadi Waqb reservoir is hosted within the Wadi Waqb Member of the Jabal Kibrit Formation, and is of latest Early Miocene to possibly earliest Middle Miocene age. It is considered to have formed a fringing reef complex that formed a steep, fault-influenced margin to a narrow platform, similar to Recent coralgal reefs of the Red Sea. The Wadi Waqb Member is exposed on the east and west flanks of the Ifal Plain. The bioclasts are considered to have traveled as a submarine carbonate debris flow 25 km from their presumed source to the east and possibly the west, and consist mostly of rhodoliths, echinoid and coral fragments together with the benthonic larger foraminifera Operculinella venosa, Operculina complanata, Heterostegina depressa and Borelis melo. The planktonic foraminifera include species of Globigerina, Globigerinoides and Praeorbulina; no specimens of the Middle Miocene planktonic foraminiferal genus Orbulina have yet been encountered in the thin sections. The presence of Borelis melo melo, and of B. melo curdica within the region, indicates a latest Early Miocene age. No specimens of the age-equivalent larger benthonic foraminiferal genera Miogypsina or Lepidocyclina have been observed, and this is consistent with evidence from the Wadi Waqb equivalent carbonates elsewhere in the Red Sea and Gulf of Suez. In the east, the Wadi Waqb is represented by discontinuous fringing rhodolith and coral reefs that are welded to steep cliffs of granitic basement. In Wadi Waqb, located in hills that form the western margin to the Ifal Plain, the Wadi Waqb carbonates consist of packstones containing autochthonous planktonic foraminifera and abundant shallow-marine microfossils that are considered to have been derived from the basement-founded rhodolith and coral reefs in the east. The Wadi Waqb reservoir is located beneath the central part of the Ifal Plain, approximately midway down a ramp between the in situ rhodolith-coral reefs and the mixed allochthonous and autochthonous facies at Wadi Waqb. The reservoir contains biofacies similar to those exposed in Wadi Waqb, and indicative of a deep-marine environment, in excess of 50 m water depth. The Wadi Waqb carbonates display sedimentological and petrographic features that closely resemble those described from stratigraphically equivalent carbonates from the localities along the west coast of the Gulf of Suez, including Abu Shaar, where three depositional facies have been defined. It is apparent that these shallow-marine carbonates were established along the west and east rift margins of the Red Sea-Gulf of Suez rift complex prior to their dislocation during the Late Miocene and Pliocene by the left-lateral Aqaba faulting.


2020 ◽  
Vol 9 (2) ◽  
pp. 59-65
Author(s):  
Huy Xuan Nguyen ◽  
Trang Thi Thu Nguyen ◽  
Van Nguyen Nguyen ◽  
Thi Hong Quyen Vo

The source rock maturity and the hydrocarbon generation history are evaluated in the deepwater Phu Khanh Basin. The average values of heat flow, paleo water depth, and surface-water interface temperatures range from 50.80–61.69 mW/m2, 150-3,500 m, and 2.30-250C, respectively. The Oligocene and Lower–Middle Miocene source rocks are presented. The Oligocene source rock is derived from the lacustrine environment; it is mature to overmature in the Southwest part of the Phu Yen Depression. The main oil phase started in the Early Miocene, and the amount of wet gas occurred only at the bottom part. The Lower-Middle Miocene source rock has been immature in both the Southwest and Northeast part of the Phu Yen Depression. Based on the geochemical analysis, these source rocks were predominantly a mixture of type II and type III kerogens. The total organic carbon and the hydrogen index values range from 1.8-2.5 % and 250-320 mg/g, respectively. The results can help define reservoir locations for future field development planning in the Phu Khanh Basin.


2013 ◽  
Vol 151 (3) ◽  
pp. 394-413 ◽  
Author(s):  
A. MARAVELIS ◽  
G. MAKRODIMITRAS ◽  
N. PASADAKIS ◽  
A. ZELILIDIS

AbstractThe Western flanks of the Hellenic Fold and Thrust Belt are similar to the nearby prolific Albanian oil and gas provinces, where commercial volumes of oil have been produced. The Lower Oligocene to Lower–Middle Miocene slope series at this part of the Hellenic Fold and Thrust Belt provides a unique opportunity to evaluate the anatomy and source rock potential of such a system from an outcrop perspective. Slope progradation is manifested as a vertical pattern exhibiting an increasing amount of sediment bypass upwards, which is interpreted as reflecting increasing gradient conditions. The palaeoflow trend exhibits a western direction during the Late Oligocene but since the Early Miocene has shifted to the East. The occurrence of reliable index species allowed us to recognize several nannoplankton biozones (NP23 to NN5). Organic geochemical data indicate that the containing organic matter is present in sufficient abundance and with good enough quality to be regarded as potential source rocks. The present Rock-Eval II pyrolytic yields and calculated values of hydrogen and oxygen indexes imply that the recent organic matter type is of type III kerogen. A terrestrial origin is suggested and is attributed to short transportation distance and accumulation at rather low water depth. The succession is immature with respect to oil generation and has not experienced high temperature during burial. However, its eastern down-slope equivalent deep-sea mudstone facies should be considered as good gas-prone source rocks onshore since they may have experienced higher thermal evolution. In addition, they may have improved organic geochemical parameters because there is no oxidization of the organic matter.


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