THE PETROLEUM POTENTIAL OF THE GUNNED AH BASIN AND OVERLYING SURAT BASIN SEQUENCE, NEW SOUTH WALES

1988 ◽  
Vol 28 (1) ◽  
pp. 218 ◽  
Author(s):  
D.S. Hamilton ◽  
C.B. Newton ◽  
M. Smyth ◽  
T.D. Gilbert ◽  
N. Russell ◽  
...  
Keyword(s):  
Vitrinite Reflectance ◽  
Source Rocks ◽  
Lower Permian ◽  
Petroleum Potential ◽  
Shallow Marine ◽  
North West ◽  
South Wales ◽  
Oil Generation ◽  
Origin Of Oil ◽  
Auto Fluorescence

The Permo-Triassic Gunnedah Basin has good potential for the discovery of commercial petroleum. Gas shows have been reported from the Porcupine-Watermark, Black Jack and Digby Formations, and from the basal sandstone of the Purlawaugh Formation in the overlying Surat Basin sequence. Gas flowed on drill stem test from the Porcupine-Watermark Formation in the Wilga Park No. 1 discovery well although the find was sub-commercial. An oil show was observed in Lower Permian volcanics, and oil staining has been observed in the Pilliga Sandstone in several wells. The origin of oil staining in the Pilliga Sandstone is unknown, however, and may have been the result of diesel contamination during drilling operations.Structural style within the basin sequence is characterised by north-south and north-north-west/south- south-east trending anticlines which formed in response to periodic compressive and left lateral strike-slip movements along the main Hunter Mooki Thrust Fault. These anticlines are attractive exploration targets.Westerly-derived quartz-rich sandstones occur at several stratigraphic levels within the Black Jack Formation and within the upper Digby Formation. Sandstones of the western bed-load fluvial system (lower Black Jack Formation) are most prospective with thick sections (up to 8 m) giving permeabilities from several hundred to several thousand millidarcies. Marine reworked easterly-derived sandstones up to 12 m thick in the Black Jack and Watermark Formations have minor reservoir potential with permeabilities in the order of tens of millidarcies. All potential reservoirs within the sequence are considered to be adequately sealed. Regionally extensive shaly units deposited either by marine incursion or lacustrine inundation overlie most reservoir horizons; remaining reservoirs are capped by intraformational shales.Organic petrology and geochemistry indicate the best potential source rocks within the Gunnedah Basin are floodplain, lacustrine and shallow marine facies of the Purlawaugh, Napperby, Watermark, Maules Creek and Goonbri Formations. The shallow marine Arkarula Sandstone Member within the Black Jack Formation also has significant potential for oil generation. Vitrinite reflectance, liptinite auto-fluorescence and TAI values indicate Lower Permian sediments are marginally mature to mature for oil generation. Combining the data on source quality and quantity with thermal maturity, the Permian sediments - in particular the Watermark Formation - have the best potential for generating oil.

PETROLEUM GEOLOGY OF WESTERN NEW SOUTH WALES

1977 ◽  
Vol 17 (1) ◽  
pp. 42 ◽  
Author(s):  
P. R. Evans
Keyword(s):  
Middle Devonian ◽  
New South ◽  
New South Wales ◽  
Early Carboniferous ◽  
Strike Slip ◽  
Petroleum Potential ◽  
Shallow Marine ◽  
Marine Deposits ◽  
South Wales ◽  
Petroleum Generation

The only area of Western New South Wales considered to have petroleum potential is the intracratonic, fault-bounded Darling Basin, which evolved during Late Silurian to Early Carboniferous time and which contains up to 7000 m of sediments. Initially deposition was controlled by a shallow marine transgression from the east. Regression during the Middle Devonian was followed by basin-wide extension of alluvial sedimentation, which prevailed until the Early Carboniferous. Strike slip movements during Late Devonian time along old basement trends fragmented the basin into distinct troughs. Movements along the same trends during the Carboniferous modified the troughs' configuration. Permian, Mesozoic and Cenozoic sag-like downwarps in various parts of the region had negligible effect on bedding attitudes.The only play of the Basin thought to have a chance for significant petroleum generation and entrapment lies in the Lower and (?) Middle Devonian, where marginal marine deposits flank highs created by strike slip movements. This play is regarded as one of high risk for modest returns, but its continued exploration seems warranted in view of proximity to markets and to the Moomba-Sydney pipeline.

A geochemical investigation into the resource potential of the Lawn Hill Platform, northern Australia

2020 ◽  
Vol 60 (2) ◽  
pp. 722
Author(s):  
Amber J. M. Jarrett ◽  
Adam E. H. Bailey ◽  
Christopher J. Boreham ◽  
Tehani Palu ◽  
Lisa Hall ◽  
...  
Keyword(s):  
Organic Geochemistry ◽  
Source Rocks ◽  
Geochemical Data ◽  
Northern Australia ◽  
Hydraulic Stimulation ◽  
Petroleum Potential ◽  
North West ◽  
North Eastern ◽  
Resource Exploration ◽  
Geochemical Investigation

The Lawn Hill Platform (LHP) is a sedimentary province in north-eastern Northern Territory and north-western Queensland that hosts a significant Paleoproterozoic–Mesoproterozoic sequence, often referred to as 'the ‘Isa Superbasin’, and includes the overlying South Nicholson Group. Shale gas resources and base-metals mineralisation are known in north-west Queensland, but the larger basin is underexplored. The Australian Government’s Exploring for the Future (EFTF) 2016−2020 program aims to boost resource exploration in northern Australia. New precompetitive geochemical data obtained in this program includes source rock geochemistry, kerogen kinetics, bitumen reflectance, biomarker and δ13C n-alkanes for understanding the petroleum potential, organic geochemistry of source rocks and fluids, stratigraphic correlations and mineralogy to determine the brittleness of shales. All data and derived reports are accessible on the EFTF portal (www.eftf.ga.gov.au), providing a central location for informed decision making. The results in this study demonstrate fair to excellent source rocks in multiple supersequences that are brittle and favourable to hydraulic stimulation. A comparison to the greater McArthur Basin demonstrates, that although there are many similarities in bulk geochemistry, LHP mudstones are largely heterogeneous, reflecting local variations that may be inherited from variations in contributing biomass, microbial reworking, depositional environment, sediment input and paleoredox conditions.

Late Cretaceous – Tertiary sediments offshore central West Greenland: lithostratigraphy, sedimentary evolution, and petroleum potential

1985 ◽  
Vol 22 (7) ◽  
pp. 1001-1019 ◽  
Author(s):  
Flemming Rolle
Keyword(s):  
Upper Cretaceous ◽  
Source Rocks ◽  
Petroleum Potential ◽  
Shallow Marine ◽  
West Greenland ◽  
Reservoir Rocks ◽  
Sedimentary Sequences ◽  
Sedimentary Evolution ◽  
Petroleum Generation ◽  
Exploratory Wells

Five dry exploratory wells were drilled through Upper Cretaceous and Tertiary sediments on the West Greenland shelf in 1976 and 1977. Two of these entered Precambrian basement, two bottomed in Paleocene or Upper Cretaceous basalt, and one in Campanian mudstone. On the basis of samples and logs supplied to the Geological Survey of Greenland the sedimentary sequence has been divided into seven new formations: the Campanian Narssarmiut Formation, consisting of coarse basement wash and black mudstone; the Campanian to Eocene Ikermiut Formation, consisting of marine organic-rich mudstone; the Upper Paleocene to Eocene Hellefisk Formation, comprising shallow-marine to paralic sandstone and mudstone; the Eocene Nukik Formation, consisting of turbiditic sandstone and mudstone; the Eocene to Oligocene Kangâmiut Formation of shelf to shallow-marine clean and argillaceous sandstone; the Oligocene to Neogene Manîtsoq Formation, consisting of coarse paralic to fan delta sandstone; and the Neogene Ataneq Formation, consisting of protected shallow-marine mudstone.The sedimentary evolution of the area fits well with earlier proposed models for the tectonic evolution of the Baffin Bay–Labrador Sea region.Potential petroleum source rocks are present in the Upper Cretaceous to Paleocene mudstone, and, even though they are largely immature in the drilled sections, they are expected to have entered the petroleum generation zone in the deeper parts of the basin. Their potential is mainly for gas, but some oil potential is also present. No reservoir rocks were encountered in the deeper parts of the sedimentary sequences, and the porous sandstones that occur higher in the sequence lack seals.

scholarly journals A Novel Redox Indicator based on Relative Abundances of C31 And C32 Homohopanes in the Eocene Lacustrine Dongying Depression, East China

2021 ◽  
Author(s):  
Chong Jiang ◽  
Haiping Huang ◽  
Zheng Li ◽  
Hong Zhang ◽  
Zheng Zhai
Keyword(s):  
Vitrinite Reflectance ◽  
Source Rocks ◽  
East China ◽  
Peak Oil ◽  
Dongying Depression ◽  
Anoxic Environments ◽  
Oil Generation ◽  
Shahejie Formation ◽  
The Impact ◽  
Fourth Member

Abstract A suite of oils and bitumens from the Eocene Shahejie Formation (Es) in the Dongying Depression, East China was geochemically characterized to illustrate the impact of source input and redox conditions on the distributions of pentacyclic terpanes. The fourth member (Es4) developed under highly reducing, sulfidic hypersaline conditions, while the third member (Es3) formed under dysoxic, brackish to freshwater conditions. Oils derived from Es4 are enriched in C32 homohopanes (C32H), while those from Es3 are prominently enriched in C31 homohopanes (C31H). The C32H/C31H ratio shows positive correlation with homohopane index (HHI), gammacerane index (G/C30H), and negative correlation with pristane/phytane (Pr/Ph) ratio, and can be used to evaluate oxic/anoxic conditions during deposition and diagenesis. High C32H/C31H ratio (> 0.8) is an important characteristic of oils derived from sulfidic, hypersaline anoxic environments, while low values (< 0.8) indicate non-sulfidic, dysoxic conditions. Extremely low C32H/C31H ratios (< 0.4) indicate strong oxic conditions of coal depsoition. Advantages to use C32H/C31H ratio as redox condition proxy compared to the HHI and gammacerane indexes are wider valid maturity range, less sensitive to biodegradation influence and better differentiation of reducing from oxic environments. Preferential cracking of C35-homohopanes leads HHI to be valid in a narrow maturity range before peak oil generation. No C35 homohopane can be reliably detected in the Es4 bitumens when vitrinite reflectance is > 0.75%, which explains the rare occurrence of high HHI values in Es4 source rocks. Gammacerane is thermally more stable and biologically more refractory than C30 hopane, leading G/C30H ratio more sensitive to maturation and biodegradation than C32H/C31H ratio. Meanwhile, both HHI and gammacerane index cannot differentiate level of oxidation. The C32H/C31H ratio can be applied globally as a novel redox proxy in addition to the Dongying Depression.

THE PETROLEUM PROSPECTIVITY OF THE CLARENCE-MORETON BASIN IN NEW SOUTH WALES

1985 ◽  
Vol 25 (1) ◽  
pp. 15
Author(s):  
P. Ties ◽  
R.D. Shaw ◽  
G.C. Geary
Keyword(s):  
Source Rock ◽  
Seismic Data ◽  
New South ◽  
New South Wales ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
South Wales ◽  
Oil Generation ◽  
Single Fold ◽  
Coal Measures

The Clarence-Moreton Basin covers an area of some 28 000 km2 in north-eastern New South Wales and south-eastern Queensland. The basin is relatively unexplored, with a well density in New South Wales of one per 1600 km2. Since 1980, Endeavour Resources and its co-venturers have pursued an active exploration programme which has resulted in the recognition of significant petroleum potential in the New South Wales portion of the basin.Previous studies indicated that the Upper Triassic to Lower Cretaceous Clarence-Moreton Basin sequence in general, lacked suitable reservoirs and had poor source- rock potential. While exinite rich, oil-prone source rocks were recognised in the Middle Jurassic Walloon Coal Measures, they were considered immature for oil generation. Moreover, during the 1960's the basin acquired a reputation as an area where seismic records were of poor quality.These ideas are now challenged following the results of a new round of exploration which commenced in the New South Wales portion of the basin in 1980. This exploration has involved the acquisition of over 1000 km of multifold seismic data, the reprocessing of some 200 km of existing single fold data, and the drilling of one wildcat well. Over twenty large structural leads have been identified, involving trapping mechanisms ranging from simple drape to antithetic and synthetic fault blocks associated with normal and reverse fault dependent and independent closures.The primary exploration targets in the Clarence- Moreton Basin sequence are Lower Jurassic sediments comprising a thick, porous and permeable sandstone unit in the Bundamba Group, and channel and point-bar sands in the Marburg Formation. Source rocks in these and the underlying Triassic coal measures are gas-prone and lie at maturity levels compatible with gas generation. In contrast, it was established from the results of Shannon 1 that the Walloon Coal Measures are mature for oil generation and this maturity regime is now considered to be applicable to most of the basin in New South Wales.A consideration of reservoir and source rock distribution, together with structural trends across the basin in Petroleum Exploration Licences 258 and 259, has led to the identification of three prospective fairways, two of which involve shallow oil plays. Exploration of these fairways is currently the focus of an ongoing programme of further seismic data acquisition and drilling.

scholarly journals Geochemistry and petrology of selected sediments from Bukit Song, Miri, Sarawak, Malaysia, with emphasis on organic matter characterization

2021 ◽  
Vol 11 (10) ◽  
pp. 3663-3688
Author(s):  
Amin Tavakoli
Keyword(s):  
Organic Matter ◽  
Depositional Environment ◽  
Vitrinite Reflectance ◽  
Xrd Analysis ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Thermal Maturity ◽  
Petroleum Potential ◽  
Type Iv ◽  
Two Samples

AbstractThe aim of this study is to provide a better understanding of the type of source input, quality, quantity, the condition of depositional environment and thermal maturity of the organic matter from Bukit Song, Sarawak, which has not been extensively studied for hydrocarbon generation potential. Petrological and geochemical analyses were performed on 13 outcrop samples of the study location. Two samples, having type III and mixed kerogen, showed very-good-to-excellent petroleum potential based on bitumen extraction and data from Rock–Eval analysis. The rest of the samples are inert—kerogen type IV. In terms of thermal maturity based on vitrinite reflectance, the results of this paper are akin to previous studies done in the nearby region reported as either immature or early mature. Ph/n-C18 versus Pr/n-C17 data showed that the major concentration of samples is within peat coal environment, whilst two samples were associated with anoxic marine depositional environment, confirmed by maceral content as well. Macerals mainly indicated terrestrial precursors and, overall, a dominance of vitrinite. Quality of the source rock based on TOC parameter indicated above 2 wt. % content for the majority of samples. However, consideration of TOC and S2 together showed only two samples to have better source rocks. Existence of cutinite, sporinite and greenish fluorescing resinite macerals corroborated with the immaturity of the analysed coaly samples. Varying degrees of the bitumen staining existed in a few samples. Kaolinite and illite were the major clays based on XRD analysis, which potentially indicate low porosity. This study revealed that hydrocarbon-generating potential of Bukit Song in Sarawak is low.

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.

GEOCHEMICAL TOOLS FOR EVALUATING PETROLEUM GENERATION IN MIDDLE PROTEROZOIC SEDIMENTS OF THE McARTHUR BASIN, NORTHERN TERRITORY, AUSTRALIA

1994 ◽  
Vol 34 (1) ◽  
pp. 692 ◽  
Author(s):  
Roger E. Summons ◽  
Dennis Taylor ◽  
Christopher J. Boreham
Keyword(s):  
Vitrinite Reflectance ◽  
Land Plant ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Strongly Correlated ◽  
Petroleum Potential ◽  
Petroleum Generation ◽  
Early Palaeozoic ◽  
Geochemical Analyses ◽  
Rock Eval

Maturation parameters based on aromatic hydrocarbons, and particularly the methyl-phenanthrene index (MPI-1), are powerful indicators which can be used to define the oil window in Proterozoic and Early Palaeozoic petroleum source rocks and to compare maturities and detect migration in very old oils . The conventional vitrinite reflectance yardstick for maturity is not readily translated to these ancient sediments because they predate the evolution of the land plant precursors to vitrinite. While whole-rock geochemical tools such as Rock-Eval and TOC are useful for evaluation of petroleum potential, they can be imprecise when applied to maturity assessments.In this study, we carried out a range of detailed geochemical analyses on McArthur Basin boreholes penetrating the Roper Group source rocks. We determined the depth profiles for hydrocarbon generation based on Rock-Eval analysis of whole-rock, solvent-extracted rock, kerogen elemental H/C ratio and pyrolysis GC. Although we found that Hydrogen Index (HI) and the Tmax parameter were strongly correlated with other maturation indicators, they were not sufficiently sensitive nor were they universally applicable. Maturation measurements based on saturated biomarkers were not useful either because of the low abundance of these compounds in most Roper Group bitumens and oils.

Prospect Evaluation Based on Integrated Petroleum System Analysis: Block E Case Study, South-Eastern Edge of Precaspian Basin Kazakhstan

2021 ◽  
Author(s):  
Ainura Zhanserkeyeva ◽  
Akzhan Kassenov
Keyword(s):  
Vertical Migration ◽  
Oil And Gas ◽  
Source Rocks ◽  
Late Triassic ◽  
Lower Permian ◽  
Type Ii ◽  
Thermal Maturity ◽  
Type Iii ◽  
South Eastern ◽  
Oil Generation

Abstract Positive geological and geochemical prerequisites have been identified for the purpose of increasing hydrocarbon resource potential in the under-explored study area. A methodology has been developed for assessing the hydrocarbon potential and prospecting for new promising oil and gas accumulation zones using the technology of basin modeling, provided there is a lack of initial data. A high hydrocarbon source rock generative potential and the degree of thermal maturity of the Lower Permian, Mid Carboniferous and Upper Devonian strata of the south-eastern part of the Precaspian depression have been revealed. Seismostratigraphic and geodynamic analysis was carried out and the main stages of the geodynamic evolution of the study area were reconstructed based on combination of all available geological and geophysical information, recent exploration drilling results and unpublished subsurface studies. The results of thermotectonic modelling confirm the possibility of vertical migration of hydrocarbons generated in Paleozoic sediments. A revision of the previously performed interpretation of 3D seismic data has been carried out; and for the first time, intrasalt sedimentary packets of presumably Upper Permian age have been identified as independent objects, which can be potential hydrocarbon traps. For the Lower Permian deposits, type III kerogen predominates, which may be associated with an increase in collisional processes in the Late Paleozoic time and an active input of plant organic matter. For Mid Carboniferous sediments, mixed type II / III kerogen or type II kerogen prevails. Analysis of the evolution of thermal maturity indicates the unevenness of the entry of potential oil and gas source strata into the main zone of oil generation. For kerogen type III of the Lower Permian source rocks, the peak of oil generation falls on the Late Cretaceous. For predominantly carbonate and terrigenous-carbonate Middle Carboniferous source rocks the peak of generation falls on the Jurassic. The most submerged Devonian source rocks are located mainly in the zone of wet gas generation. The development of salt tectonics from the Late Triassic to the Cenozoic contributed to the vertical migration of hydrocarbons into the post-salt complex. The identified oil fields in the Upper Triassic-Jurassic stratigraphic section are mainly confined to the four-way dip structural closured above the steep flanks of salt structures.

Hydrocarbon Generation Indication from Source Rock to Reservoir Rock: Case Studies of Anambra and Abakaliki Basins South-Eastern Nigeria

2016 ◽  
Author(s):  
Samuel Salufu ◽  
Rita Onolemhemhen ◽  
Sunday Isehunwa
Keyword(s):  
Case Studies ◽  
Source Rock ◽  
Oil And Gas ◽  
Vitrinite Reflectance ◽  
Source Rocks ◽  
Reservoir Rock ◽  
Hydrocarbon Generation ◽  
Geochemical Analysis ◽  
Anambra Basin ◽  
Oil Generation

ABSTRACT This paper sought to use information from outcrop sections to characterize the source and reservoir rocks in a basin in order to give indication(s) for hydrocarbon generation potential in a basin in minimizing uncertainty and risk that are allied with exploration and field development of oil and gas, using subsurface data from well logs, well sections, seismic and core. The methods of study includes detailed geological, stratigraphical, geochemical, structural,, petro-graphical, and sedimentological studies of rock units from outcrop sections within two basins; Anambra Basin and Abakaliki Basin were used as case studies. Thirty eight samples of shale were collected from these Basins; geochemical analysis (rockeval) was performed on the samples to determine the total organic content (TOC) and to assess the oil generating window. The results were analyzed using Rock wares, Origin, and Surfer software in order to properly characterize the potential source rock(s) and reservoir rock(s) in the basins, and factor(s) that can favour hydrocarbon traps. The results of the geological, stratigraphical, sedimentological, geochemical, and structural, were used to developed a new model for hydrocarbon generation in the Basins. The result of the geochemical analysis of shale samples from the Anambra Basin shows that the TOC values are ≥ 1wt%, Tmax ≥ 431°C, Vitrinite reflectance values are ≥ 0.6%, and S1+S2 values are &gt; 2.5mg/g for Mamu Formation while shale samples from other formations within Anambra Basin fall out of these ranges. The shale unit in the Mamu Formation is the major source rock for oil generation in the Anambra Basin while others have potential for gas generation with very little oil generation. The shale samples from Abakaliki Basin shows that S1+S2 values range from&lt; 1 – 20mg/g, TOC values range from 0.31-4.55wt%, vitrinite reflectance ranges from 0.41-1.24% and Tmax ranges from423°C – 466°C. This result also shows that there is no source rock for oil generation in Abakaliki Basin; it is either gas or graphite. This observation indicates that all the source rocks within Abakaliki Basin have exceeded petroleum generating stage due to high geothermal heat resulting from deep depth or the shale units have not attained catagenesis stage as a result of S1+S2 values lesser than 2.5mg/g despite TOC values of ≥ 0.5wt% and vitrinite reflectance values of ≥ 0.6%. The novelty of this study is that the study has been able to show that here there is much more oil than the previous authors claimed, and the distribution of this oil and gas in the basins is controlled by two major factors; the pattern of distribution of the materials of the source rock prior to subsidence and during the subsidence period in the basin, and the pattern and the rate of tectonic activities, and heat flow in the basin. If these factors are known, it would help to reduce the uncertainties associated with exploration for oil and gas in the two basins.

Sign in / Sign up

Export Citation Format

Share Document