APPLICATIONS OF AROMATIC HYDROCARBONS: THE LIQUID REACTION ENVIRONMENT IN SOURCE ROCKS—A FUNDAMENTAL STAGE IN OIL FORMATION

2001 ◽  
Vol 41 (1) ◽  
pp. 549
Author(s):  
B.G.K. van Aarssen ◽  
R. Alexander ◽  
R.I. Kagi
Keyword(s):  
Source Rock ◽  
Source Rocks ◽  
Crude Oils ◽  
Rock Matrix ◽  
North West ◽  
Sedimentary Sequences ◽  
The North ◽  
Liquid Reaction ◽  
Oil Generation ◽  
Oil Formation

The ratio of two trimethylnaphthalenes in sediment extracts can be used to indicate the establishment of a liquid reaction environment in the source rock. The abundance of 1,3,6-TMN relative to 1,3,7-TMN (denoted here as 136/137) is near constant in crude oils. In sediments however, there is a much larger variation. This difference is attributed to the presence of two different reaction environments in the source rock: a liquid organic phase which is the direct precursor of crude oils, and the kerogen / rock matrix onto which compounds are adsorbed. In the liquid reaction environment, methylated naphthalenes undergo many reactions, leading to a near constant value for 136/137. On the other hand, when they are adsorbed onto kerogen or minerals, different reactions prevail and an excess of 1,3,6-TMN is formed. When measured in sediment extracts, the closer 136/137 is to the value typical for oils, the better the liquid reaction environments established in the source rock. This concept was used to study the behaviour of 136/ 137 with depth in 10 sedimentary sequences from the North West Shelf. The results showed that sediments from several wells were capable of establishing a liquid reaction environment, a necessary step in the formation of oil. Results from other wells indicated that little or no liquid reaction environment could be established, suggesting that these sediments were unlikely to be capable of oil formation. The 136/137 parameter is a convenient indicator for determining the extent to which the liquid reaction environment has been established in the source rock and may be useful in determining oil generation potential.

ACCURATE RECOGNITION OF SOURCE ROCK CHARACTER IN THE JURASSIC OF THE NORTH WEST SHELF, WESTERN AUSTRALIA

1992 ◽  
Vol 32 (1) ◽  
pp. 289 ◽  
Author(s):  
John Scott
Keyword(s):  
Source Rock ◽  
Organic Material ◽  
Source Rocks ◽  
Higher Plant ◽  
Pyrolysis Gas ◽  
Screening Analysis ◽  
North West ◽  
The North ◽  
Potential Source Rock ◽  
Rock Eval

The main potential source rock intervals are generally well defined on the North West Shelf by screening analysis such as Rock-Eval. The type of product from the source rocks is not well defined, owing to inadequacies in current screening analysis techniques. The implications of poor definition of source type in acreage assessment are obvious. The type of product is dependent on the level of organic maturity of the source rock, the ability of products to migrate out of the source rock and on the type of organic material present. The type of kerogen present is frequently determined by Rock-Eval pyrolysis. However, Rock-Eval has severe limitations in defining product type when there is a significant input of terrestrial organic material. This problem has been recognised in Australian terrestrial/continental sequences but also occurs where marine source rock facies contain terrestrially-derived higher plant material. Pyrolysis-gas chromatography as applied to source rock analysis provides, by molecular typing, a better method of estimating the type of products of the kerogen breakdown than bulk chemical analysis such as Rock-Eval pyrolysis.

scholarly journals Are Carboniferous coals from the Danish North Sea oil-prone?

2007 ◽  
Vol 13 ◽  
pp. 13-16 ◽  
Author(s):  
Henrik I. Petersen ◽  
Hans P. Nytoft
Keyword(s):  
Source Rock ◽  
North Sea ◽  
Upper Jurassic ◽  
Source Rocks ◽  
Lower Carboniferous ◽  
North West ◽  
The North ◽  
Single Well ◽  
The North Sea ◽  
Clay Formation

The Central Graben in the North Sea is a mature petroleum province with Upper Jurassic – lowermost Cretaceous marine shale of the Kimmeridge Clay Formation and equivalents as the principal source rock, and Upper Cretaceous chalk as the main reservoirs. However, increasing oil prices and developments in drilling technologies have made deeper plays depending on older source rocks increasingly attractive. In recent years exploration activities have therefore also been directed towards deeper clastic plays where Palaeozoic deposits may act as petroleum source rocks. Carboniferous coaly sections are the most obvious source rock candidates. The gas fields of the major gas province in the southern North Sea and North-West Europe are sourced from the thick Upper Carboniferous Coal Measures, which contain hundreds of coal seams (Drozdzewski 1993; Lokhorst 1998; Gautier 2003). North of the gas province Upper Carboni-ferous coal-bearing strata occur onshore in northern England and in Scotland, but offshore in the North Sea area they have been removed by erosion. However, Lower Carboniferous strata are present offshore and have been drilled in the Witch Ground Graben and in the north-eastern part of the Forth Approaches Basin (Fig. 1A), where most of the Lower Carbon iferous sediments are assigned to the sandstone/shale-dominated Tayport For mation and to the coal-bearing Firth Coal Formation (Bruce & Stemmerik 2003). Highly oil-prone Lower Carboniferous lacustrine oil shales occur onshore in the Midland Valley, Scotland, but they have only been drilled by a single well off shore and seem not to be regionally distributed (Parnell 1988). In the southern part of the Norwegian and UK Central Graben and in the Danish Central Graben a total of only nine wells have encountered Lower Carboniferous strata, and while they may have a widespread occurrence (Fig. 1B; Bruce & Stemmerik 2003) their distribution is poorly constrained in this area. The nearly 6000 m deep Svane-1/1A well (Fig. 1B) in the Tail End Graben encountered gas and condensate at depths of 5400–5900 m, which based on carbon isotope values may have a Carboniferous source (Ohm et al. 2006). In the light of this the source rock potential of the Lower Carboniferous coals in the Gert-2 well (Fig. 1C) has recently been assessed (Petersen & Nytoft 2007).

AGE DETERMINATION OF CRUDE OILS IN THE BARROW SUB- BASIN USING PALAEOCLIMATE RELATED VARIATIONS IN HIGHER PLANT BIOMARKERS

1999 ◽  
Vol 39 (1) ◽  
pp. 399
Author(s):  
B.G.K. van Aarssen ◽  
T.P. Bastow ◽  
R ◽  
Alexander ◽  
R.I. Kagi
Keyword(s):  
Source Rock ◽  
Age Groups ◽  
Age Determination ◽  
Source Rocks ◽  
Crude Oils ◽  
Higher Plant ◽  
Sedimentary Sequences ◽  
And Migration ◽  
Oil Source ◽  
Migration Pathways

Variations in higher-plant-derived biomarkers in sedimentary sequences reflect changes in the palaeoclimatic conditions at the time of deposition. It is thought that changes in climate affect the distribution of higher plant populations growing on the hinterland, thus changing the contribution of these plants into the sediments. These variations can be measured using the abundances of three aromatic hydrocarbons: retene, cadalene and iP-iHMN. This was done for a Jurassic sedimentary sequence from the Koolinda–1 well in the Barrow Sub-basin, The obtained profile was related to an absolute time-scale. Measurement of the higher-plant-derived biomarkers in crude oils from the Barrow Sub-basin enabled accurate measurement of the age of their source rocks by using the Koolinda–1 profile as a reference. Most of these oils correlate with the Jurassic W. spectabilis dinoflagellate zone in the Oxfordian. Within this zone the oils fall into four age groups, reflecting four oil-prone intervals each separated by approximately 0.2 My. The oils that have been generated from each group can be found in specific reservoirs in the sub-basin, showing a pattern of migration away from the depocentre with decreasing age of the source rock. This method of determining the source rock age of crude oils enables detailed oil-source rock correlations. On a basin-wide scale it can provide insight into the location of major source rocks and migration pathways.

scholarly journals Effective source rock selection and oil–source correlation in the Western Slope of the northern Songliao Basin, China

2021 ◽  
Vol 18 (2) ◽  
pp. 398-415
Author(s):  
He Bi ◽  
Peng Li ◽  
Yun Jiang ◽  
Jing-Jing Fan ◽  
Xiao-Yue Chen
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Thermal Evolution ◽  
Songliao Basin ◽  
Source Rocks ◽  
Crude Oils ◽  
Western Slope ◽  
Geochemical Parameters ◽  
Group I ◽  
Oil Source

AbstractThis study considers the Upper Cretaceous Qingshankou Formation, Yaojia Formation, and the first member of the Nenjiang Formation in the Western Slope of the northern Songliao Basin. Dark mudstone with high abundances of organic matter of Gulong and Qijia sags are considered to be significant source rocks in the study area. To evaluate their development characteristics, differences and effectiveness, geochemical parameters are analyzed. One-dimensional basin modeling and hydrocarbon evolution are also applied to discuss the effectiveness of source rocks. Through the biomarker characteristics, the source–source, oil–oil, and oil–source correlations are assessed and the sources of crude oils in different rock units are determined. Based on the results, Gulong and Qijia source rocks have different organic matter primarily detrived from mixed sources and plankton, respectively. Gulong source rock has higher thermal evolution degree than Qijia source rock. The biomarker parameters of the source rocks are compared with 31 crude oil samples. The studied crude oils can be divided into two groups. The oil–source correlations show that group I oils from Qing II–III, Yao I, and Yao II–III members were probably derived from Gulong source rock and that only group II oils from Nen I member were derived from Qijia source rock.

The Wenlock sediments of north-west Galway, Ireland.

1970 ◽  
Vol 107 (4) ◽  
pp. 297-317 ◽  
Author(s):  
M. G. Laird ◽  
W. S. McKerrow
Keyword(s):  
Sediment Supply ◽  
Shallow Marine ◽  
North West ◽  
Sedimentary Sequences ◽  
The North ◽  
Upper Silurian

SummaryThis work describes the Wenlock sedimentary sequences south of Killary Harbour where the fullest successions in north-west Galway are exposed; much of the Upper Silurian in the east (Joyces Country) has been removed by erosion.The Wenlock beds (the Upper Owenduff and Killary Harbour Groups) rest on shallow marine and continental sediments (the Lower Owenduff Group) of Upper Llandovery (C5–6) age. Conglomerates near the base of the Wenlock are followed by 1,500 m of sandstones, which are mostly turbidites and which contain Middle Wenlock graptolites. These basin deposits are succeeded by a transitional sequence of rise, slope and shelf clastics, also of Middle Wenlock age. The youngest Silurian beds exposed are 800 m of red lagoonal deposits withLingula.During Wenlock times, the sediment supply to north-west Galway was mainly from the north and north-west. This observation fits well with the regional picture which places Galway near the north-west margin of a Silurian basin which extended eastwards across Ireland.

Biomarker geochemistry of crude oils and Lower Paleozoic source rocks in the Tarim Basin, western China: An oil-source rock correlation study

2018 ◽  
Vol 96 ◽  
pp. 94-112 ◽  
Author(s):  
Zhonghong Chen ◽  
T.-G. Wang ◽  
Meijun Li ◽  
Fuling Yang ◽  
Bin Cheng
Keyword(s):  
Source Rock ◽  
Tarim Basin ◽  
Correlation Study ◽  
Source Rocks ◽  
Western China ◽  
Crude Oils ◽  
Lower Paleozoic ◽  
Oil Source

Observations on the Lower Triassic petroleum prospectivity of the offshore Carnarvon and Roebuck basins

2016 ◽  
Vol 56 (1) ◽  
pp. 173 ◽  
Author(s):  
Stephen Molyneux ◽  
Jeff Goodall ◽  
Roisin McGee ◽  
George Mills ◽  
Birgitta Hartung-Kagi
Keyword(s):  
Regional Analysis ◽  
Lower Triassic ◽  
Source Rocks ◽  
Upper Permian ◽  
Regional Study ◽  
North West ◽  
Petroleum Systems ◽  
The North ◽  
Depositional Processes ◽  
Water Margin

Why are the only commercial hydrocarbon discoveries in Lower Triassic and Permian sediments of the western margin of Australia restricted to the Perth Basin and the Petrel Sub-basin? Recent regional analysis by Carnarvon Petroleum has sought to address some key questions about the Lower Triassic Locker Shale and Upper Permian Chinty and Kennedy formations petroleum systems along the shallow water margin of the Carnarvon and offshore Canning (Roebuck/Bedout) basins. This paper aims to address the following questions:Source: Is there evidence in the wells drilled to date of a working petroleum system tied to the Locker Shale or other pre-Jurassic source rocks? Reservoir: What is the palaeogeography and sedimentology of the stratigraphic units and what are the implications for the petroleum systems?The authors believed that a fresh look at the Lower Triassic to Upper Permian petroleum prospectivity of the North West Shelf would be beneficial, and key observations arising from the regional study undertaken are highlighted:Few wells along a 2,000 km area have drilled into Lower Triassic Locker Shale or older stratigraphy. Several of these wells have been geochemically and isotopically typed to potentially non Jurassic source rocks. The basal Triassic Hovea Member of the Kockatea Shale in the Perth Basin is a proven commercial oil source rock and a Hovea Member Equivalent has been identified through palynology and a distinctive sapropelic/algal kerogen facies in nearly 16 wells that penetrate the full Lower Triassic interval on the North West Shelf. Samples from the Upper Permian, the Hovea Member Equivalent and the Locker Shale have been analysed isotopically indicating –28, –34 and –30 delta C13 averages, respectively. Lower Triassic and Upper Permian reservoirs are often high net to gross sands with up to 1,000 mD permeability and around 20% porosity. Depositional processes are varied, from Locker Shale submarine canyon systems to a mixed carbonate clastic marine coastline/shelf of the Upper Permian Chinty and Kennedy formations.

Recent exploration results in the Lower Triassic, Bedout Sub-basin: Australia's next petroleum province?

2018 ◽  
Vol 58 (2) ◽  
pp. 871 ◽  
Author(s):  
Melissa Thompson ◽  
Fred Wehr ◽  
Jack Woodward ◽  
Jon Minken ◽  
Gino D'Orazio ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Lower Triassic ◽  
Effective Porosity ◽  
Petroleum System ◽  
Source Rocks ◽  
Commercial Development ◽  
North West ◽  
The North ◽  
Productive Potential ◽  
Detailed Interpretation

Commencing in 2014, Quadrant Energy and partners have undertaken an active exploration program in the Bedout Sub-basin with a 100% success rate, discovering four hydrocarbon accumulations with four wells. The primary exploration target in the basin, the Middle Triassic Lower Keraudren Formation, encompasses the reservoirs, source rocks and seals that have trapped hydrocarbons in a self-contained petroleum system. This petroleum system is older than the traditional plays on the North-West Shelf and before recent activity was very poorly understood and easily overlooked. Key reservoirs occur at burial depths of 3500–5500 m, deeper than many of the traditional plays on the North-West Shelf and exhibit variable reservoir quality. Oil and gas-condensate discovered in the first two wells, Phoenix South-1 and Roc-1, raised key questions on the preservation of effective porosity and productivity sufficient to support a commercial development. With the acquisition and detailed interpretation of 119 m of core over the Caley Member reservoir in Roc-2 and a successful drill stem test that was surface equipment constrained to 55 MMscf/d, the productive potential of this reservoir interval has been confirmed. The results of the exploration program to date, combined with acquisition of new 3D/2D seismic data, have enabled a deeper understanding of the potential of the Bedout Sub-basin. A detailed basin model has been developed and a large suite of prospects and leads are recognised across a family of hydrocarbon plays. Two key wells currently scheduled for 2018 (Phoenix South-3 and Dorado-1) will provide critical information about the scale of this opportunity.

scholarly journals Oil chemometrics and geochemical correlation in the Weixinan Sag, Beibuwan Basin, South China Sea

2020 ◽  
Vol 38 (6) ◽  
pp. 2695-2710
Author(s):  
Yao-Ping Wang ◽  
Xin Zhan ◽  
Tao Luo ◽  
Yuan Gao ◽  
Jia Xia ◽  
...  
Keyword(s):  
Source Rock ◽  
Principal Component ◽  
Sedimentary Basins ◽  
Oil Field ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Crude Oils ◽  
Geochemical Parameters ◽  
Group I ◽  
Oil Source

The oil–oil and oil–source rock correlations, also termed as geochemical correlations, play an essential role in the construction of petroleum systems, guidance of petroleum exploration, and definition of reservoir compartments. In this study, the problems arising from oil–oil and oil–source rock correlations were investigated using chemometric methods on oil and source rock samples from the WZ12 oil field in the Weixinan sag in the Beibuwan Basin. Crude oil from the WZ12 oil field can be classified into two genetic families: group A and B, using multidimensional scaling and principal component analysis. Similarly, source rocks of the Liushagang Formation, including its first, second, and third members, can be classified into group I and II, corresponding to group B and A crude oils, respectively. The principle geochemical parameters in the geochemical correlation for the characterisation and classification of crude oils and source rocks were 4MSI, C27Dia/C27S, and C24 Tet/C26 TT. This study provides insights into the selection of appropriate geochemical parameters for oil–oil and oil–source rock correlations, which can also be applied to other sedimentary basins.

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