HYDROCARBON PROSPECTIVITY OF THE TORQUAY SUB-BASIN, OFFSHORE VICTORIA

1994 ◽  
Vol 34 (1) ◽  
pp. 479 ◽  
Author(s):  
Mark A. Trupp ◽  
Keith W. Spence ◽  
Michael J. Gidding
Keyword(s):  
Lower Cretaceous ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Structural Deformation ◽  
Hydrocarbon Generation ◽  
Fault Block ◽  
Complex Fault ◽  
Wild Dog ◽  
Reservoir Potential ◽  
Gippsland Basin

The Torquay Sub-basin lies to the south of Port Phillip Bay in Victoria. It has two main tectonic elements; a Basin Deep area which is flanked to the southeast by the shallower Snail Terrace. It is bounded by the Otway Ranges to the northwest and shallow basement elsewhere. The stratigraphy of the area reflects the influence of two overlapping basins. The Lower Cretaceous section is equivalent to the Otway Group of the Otway Basin, whilst the Upper Cretaceous and Tertiary section is comparable with the Bass Basin stratigraphy.The Torquay Sub-basin apparently has all of the essential ingredients needed for successful hydrocarbon exploration. It has good reservoir-seal pairs, moderate structural deformation and probable source rocks in a deep kitchen. Four play types are recognised:Large Miocene age anticlines, similar to those in the Gippsland Basin, with an Eocene sandstone reservoir objective;The same reservoir in localised Oligocene anticlines associated with fault inversion;Possible Lower Cretaceous Eumeralla Formation sandstones in tilted fault blocks and faulted anticlines; andLower Cretaceous Crayfish Sub-group sandstones also in tilted fault block traps.Maturity modelling suggests that the Miocene anticlines post-date hydrocarbon generation. Poor reservoir potential and complex fault trap geometries downgrade the two Lower Cretaceous plays.The Oligocene play was tested by Wild Dog-1 which penetrated excellent Eocene age reservoir sands beneath a plastic shale seal, however, the well failed to encounter any hydrocarbons. Post-mortem analysis indicates the well tested a valid trap. The failure of the well is attributed to a lack of charge. Remaining exploration potential is limited to the deeper plays which have much greater risks associated with each play element.

scholarly journals Oil generation from coal source rocks: the influence of depositional conditions and stratigraphic age

2005 ◽  
Vol 7 ◽  
pp. 9-12 ◽  
Author(s):  
Henrik I. Petersen
Keyword(s):  
North Sea ◽  
Liquid Hydrocarbon ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Oil Generation ◽  
Generation Capacity ◽  
The Subject ◽  
Coal Composition ◽  
Gippsland Basin ◽  
Australasian Region

Although it was for many years believed that coals could not act as source rocks for commercial oil accumulations, it is today generally accepted that coals can indeed generate and expel commercial quantities of oil. While hydrocarbon generation from coals is less well understood than for marine and lacustrine source rocks, liquid hydrocarbon generation from coals and coaly source rocks is now known from many parts of the world, especially in the Australasian region (MacGregor 1994; Todd et al. 1997). Most of the known large oil accumulations derived from coaly source rocks have been generated from Cenozoic coals, such as in the Gippsland Basin (Australia), the Taranaki Basin (New Zealand), and the Kutei Basin (Indonesia). Permian and Jurassic coal-sourced oils are known from, respectively, the Cooper Basin (Australia) and the Danish North Sea, but in general only minor quantities of oil appear to be related to coals of Permian and Jurassic age. In contrast, Carboniferous coals are only associated with gas, as demonstrated for example by the large gas deposits in the southern North Sea and The Netherlands. Overall, the oil generation capacity of coals seems to increase from the Carboniferous to the Cenozoic. This suggests a relationship to the evolution of more complex higher land plants through time, such that the highly diversified Cenozoic plant communities in particular have the potential to produce oil-prone coals. In addition to this overall vegetational factor, the depositional conditions of the precursor mires influenced the generation potential. The various aspects of oil generation from coals have been the focus of research at the Geological Survey of Denmark and Greenland (GEUS) for several years, and recently a worldwide database consisting of more than 500 coals has been the subject of a detailed study that aims to describe the oil window and the generation potential of coals as a function of coal composition and age.

THE LA BELLA AND MINERVA GAS DISCOVERIES, OFFSHORE OTWAY BASIN

1995 ◽  
Vol 35 (1) ◽  
pp. 405 ◽  
Author(s):  
C.W. Luxton ◽  
S. T. Horan ◽  
D.L. Pickavance ◽  
M.S. Durham.
Keyword(s):  
Late Cretaceous ◽  
Oil And Gas ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Production Test ◽  
Water Contact ◽  
Excellent Quality ◽  
Fault Block ◽  
Well Location ◽  
Gas Fields

In the past 100 years of hydrocarbon exploration in the Otway Basin more than 170 exploration wells have been drilled. Prior to 1993, success was limited to small onshore gas fields. In early 1993, the La Bella-1 and Minerva-1 wells discovered significant volumes of gas in Late Cretaceous sandstones within permits VIC/P30 and VIC/P31 in the offshore Otway Basin. They are the largest discoveries to date in the basin and have enabled new markets to be considered for Otway Basin gas. These discoveries were the culmination of a regional evaluation of the Otway Basin by BHP Petroleum which highlighted the prospectivity of VIC/P30 and VIC/P31. Key factors in this evaluation were:geochemical studies that indicated the presence of source rocks with the potential to generate both oil and gas;the development of a new reservoir/seal model; andimproved seismic data quality through reprocessing and new acquisition.La Bella-1 tested the southern fault block of a faulted anticlinal structure in the southeast corner of VIC/P30. Gas was discovered in two Late Cretaceous sandstone intervals of the Shipwreck Group (informal BHP Petroleum nomenclature). Reservoirs are of moderate to good quality and are sealed vertically, and by cross-fault seal, by Late Cretaceous claystones of the Sherbrook Group. The gas is believed to have been sourced from coals and shales of the Early Cretaceous Eumeralla Formation and the structure appears to be filled to spill as currently mapped. RFT samples recovered dry gas with 13 moI-% CO2 and minor amounts of condensate.Minerva-1 tested the northern fault block of a faulted anticline in the northwest corner of VIC/ P31. Gas was discovered in three excellent quality reservoir horizons within the Shipwreck Group. Late Cretaceous Shipwreck Group silty claystones provide vertical and cross-fault seal. The hydrocarbon source is similar to that for the La Bella accumulation and the structure appears to be filled to spill. A production test was carried out in the lower sand unit and flowed at a rig limited rate of 28.8 MMCFGD (0.81 Mm3/D) through a one-inch choke. The gas is composed mainly of methane, with minor amounts of condensate and 1.9 mol-% C02. Minerva-2A was drilled later in 1993 as an appraisal well to test the southern fault block of the structure to prove up sufficient reserves to pursue entry into developing gas markets. It encountered a similar reservoir unit of excellent quality, with a gas-water contact common with that of the northern block of the structure.The La Bella and Minerva gas discoveries have greatly enhanced the prospectivity of the offshore portion of the Otway Basin. The extension of known hydrocarbon accumulations from the onshore Port Campbell embayment to the La Bella-1 well location, 55 km offshore, demonstrates the potential of this portion of the basin.

scholarly journals Petrography of the quartz sand deposits of the Lower Cretaceous of Bornholm, Denmark

1986 ◽  
Vol 10 ◽  
pp. 1-24
Author(s):  
Peter Gravesen
Keyword(s):  
Quartz Sand ◽  
Lower Cretaceous ◽  
Source Area ◽  
Source Rocks ◽  
Heavy Minerals ◽  
Fault Block ◽  
Basement Rocks ◽  
Provenance Areas ◽  
Lowermost Part ◽  
Shape Analyses

The quartz sand of the Lower Cretaceous Robbedale Formation and lowermost part of the Jydegard Formation in the Arnager-Sose fault block of Bornholm has been investigated with respect to mineralogy, grain-size, grain rounding and grain shape. Analyses of both light and heavy minerals have been carried out for 18 samples from different localities and facies. The purpose of the investigation was to try to recognize the possible types of source rocks and provenance areas. The Precambrian basement rocks of Bornholm are not the main sources of the sand, especially not the heavy minerals, but parts of the sand may have originated from the basement. The Palaeozoic sandstones and siltstones have delivered only a small amount of material. Parts of the older Mesozoic sediments of the Bornholm Group and Homandshald Member may have been redeposited in the Lower Cretaceous as they contain the same kinds of heavy minerals as the Robbedale and Jydegard Formations, although in differing amounts. It seems very possible, however, that most of the Mesozoic sediments of Bornholm have had a source area outside Bornholm, and this source area has been nearly the same during the whole span of time. The Fenno-Scandian Shield seems to be the most obvious provenance area, but eastern and southern areas are possibilities too. It is concluded that most of the Lower Cretaceous sands are first deposition cycle sediments of both local and distant origin combined with minor amounts of polycyclic sediments of mainly local origin.

Tectonostratigraphic development and hydrocarbon reservoir quality on a convergent margin: East Coast, North Island, New Zealand

2009 ◽  
Vol 49 (2) ◽  
pp. 600
Author(s):  
Brad Field ◽  
Jan Baur ◽  
Kyle Bland ◽  
Greg Browne ◽  
Angela Griffin ◽  
...  
Keyword(s):  
Late Cretaceous ◽  
East Coast ◽  
Fractured Reservoirs ◽  
Hydrocarbon Exploration ◽  
Passive Margin ◽  
Source Rocks ◽  
Reservoir Quality ◽  
High Porosity ◽  
Hydrocarbon Reservoir ◽  
Reservoir Potential

Hydrocarbon exploration on the East Coast of the North Island has not yet yielded significant commercial reserves, even though the elements of a working petroleum system are all present (Field et al, 1997). Exploration has focussed on the shallow, Neogene part of the succession, built up during plate margin convergence over the last ∼24 million years. Convergent margins are generally characterised by low-total organic carbon (TOC) source rocks and poor clastic reservoir quality due to poor sorting and labile grains. However, the obliquely-convergent Hikurangi subduction margin of the East Coast has high TOC source rocks that pre-date the subduction phase, and its reservoir potential, though variable, has several aspects in its favour, namely: deep-water rocks of high porosity and permeability; preservation of pore space by overpressure; the presence of fractured reservoirs and hybrid reservoirs, where low clastic permeability is enhanced by fractures. The East Coast North Island is a Neogene oblique subduction margin, with Neogene shelf and slope basins that developed on Late Cretaceous-Paleogene passive margin marine successions. The main hydrocarbon source rocks are Late Cretaceous and Paleocene and the main reservoir potential is in the Neogene (Field et al, 2005). Miocene mudstones with good seal potential are common, as is significant over-pressuring. Neogene deformation controlled basin development and accommodation space and strongly-influenced lateral facies development and fractured reservoirs. Early to Middle Miocene thrusting was followed by later Neogene extension (e.g. Barnes et al 2002), with a return to thrusting in the Pliocene. Local wells have flow-tested gas shows.

scholarly journals 3D-Basin Modeling of the Changling Depression, NE China: Exploring Petroleum Evolution in Deep Tight Sandstone Reservoirs

Energies ◽  
2019 ◽  
Vol 12 (6) ◽  
pp. 1043
Author(s):  
Jinliang Zhang ◽  
Jiaqi Guo ◽  
Yang Li ◽  
Zhongqiang Sun
Keyword(s):  
Lower Cretaceous ◽  
Large Scale ◽  
Measurement Data ◽  
Source Rocks ◽  
Fault System ◽  
Hydrocarbon Generation ◽  
Hydrocarbon Accumulation ◽  
Basin Modeling ◽  
Ne China ◽  
Tight Sandstone

The Changling Depression is the largest and most resource-abundant reservoir in the South Songliao Basin, NE China. The petroleum evolution rules in the Lower Cretaceous deep tight sandstone reservoir are unclear. In this study, 3D basin modeling is performed to analyze the large-scale petroleum stereoscopic migration and accumulation history. The Changling Depression has a complex fault system and multiple tectonic movements. The model is calibrated by the present formation temperatures and observed maturity (vitrinite reflectance). We consider (1) three main erosion episodes during the burial history, one during the Early Cretaceous and two during the Late Cretaceous; (2) the regional heat flow distribution throughout geological history, which was calibrated by abundant measurement data; and (3) a tight sandstone porosity model, which is calibrated by experimental petrophysical parameters. The maturity levels of the Lower Cretaceous source rocks are reconstructed and showed good gas-generation potential. The highest maturity regions are in the southwestern sag and northern sag. The peak hydrocarbon generation period contributed little to the reservoir because of a lack of seal rocks. Homogenization temperature analysis of inclusions indicated two sets of critical moments of gas accumulation. The hydrocarbon filling in the Haerjin and Shuangtuozi structures occurred between 80 Ma and 66 Ma, while the Dalaoyefu and Fulongquan structures experienced long-term hydrocarbon accumulation from 100 Ma to 67 Ma. The homogenization temperatures of the fluid inclusions may indicate a certain stage of reservoir formation and, in combination with the hydrocarbon-accumulation simulation, can distinguish leakage and recharging events.

Characterization and origin of large Campanian depressions within the Chalk Group of the Danish Central Graben – implications for hydrocarbon exploration and development

2020 ◽  
pp. SP509-2019-126
Author(s):  
Florian W. H. Smit ◽  
Lars Stemmerik ◽  
Mikael Lüthje ◽  
Frans S. P. van Buchem
Keyword(s):  
Lower Cretaceous ◽  
Current System ◽  
Isotope Analysis ◽  
Fault Reactivation ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Bottom Current ◽  
Current Activity ◽  
Fluid Venting ◽  
Gas Bearing

AbstractThis study re-examines large and deep U-shaped reflections (2–4 km wide and 100–200 m deep) within the Upper Cretaceous–Danian Chalk Group in the inverted Roar Basin of the Danish North Sea, previously interpreted as a moat associated with a contour-parallel current system and/or erosive channels formed by gravity-driven turbidites. Improved 3D seismic data quality and seismic interpretation techniques helped to identify overlooked reflection terminations, which suggest that rather than a linear depression, the U-shaped reflections outline several bowl-shaped depressions. In addition, vertical high-amplitude columns and vertical discontinuity zones within and below the depressions were recognized and interpreted to indicate the presence of small fluid pipes, suggesting that the formation of the depressions is more complex. Carbon isotope analysis of high acoustic impedance beds within the underlying Lower Cretaceous chalk showed negative δ13C values down to −20‰, and are interpreted to indicate sediments influenced by methane-derived authigenic carbonates. Permo-Triassic half-grabens seem to have been a major source of gas-bearing fluids, as evidenced by hydrocarbon leakage phenomena within Triassic–Lower Cretaceous strata. In areas where Zechstein salt is present, the leakage root lies at salt welds, causing the formation of focused seismic reflection wipe-out and dim zones. In areas where salt was absent, the leakage root comprises a much more diffuse zone across the fault boundaries of the Permo-Triassic half-graben, and gas chimneys are characterized seismically as broad vertical dim zones up to 10 km wide. Campanian inversion tectonics caused fault reactivation and several hundreds of metres of uplift in the Roar Basin, which created an instability for the trapped gas-bearing fluids. Gentle fluid venting through observed pipes caused sediment suspension and entrainment, which could be carried away by bottom-current activity, causing localized zones of non-deposition and the formation of individual depressions. This model thus does not disregard the role of bottom-current activity in the formation of the depressions, yet it includes a fluid-venting element that fits better with the architecture and overall evidence for fluid-venting features in pre-chalk strata, as well as in the Chalk Group. Importantly, it shows that prior to the thermogenic maturation of the main source rock (i.e. the Bo Member of the Farsund Formation in the Late Miocene), fluid venting had already occurred on the Late Cretaceous seafloor from deeper source rocks that are at present overmature.

Revealing new hydrocarbon potential through Q-compensated prestack depth imaging at Wenchang Field, South China Sea

2019 ◽  
Vol 38 (8) ◽  
pp. 604-609
Author(s):  
Lin Li ◽  
Lie Li ◽  
Tao Xu ◽  
Min Ouyang ◽  
Yonghao Gai ◽  
...  
Keyword(s):  
South China Sea ◽  
South China ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Fault System ◽  
Depth Image ◽  
Hydrocarbon Potential ◽  
China Sea ◽  
Complex Fault ◽  
Complex Fault System

Wenchang Field in the South China Sea contains a well-developed fault system, resulting in complex subsurface geology. Imaging the complex fault system plays an important role in hydrocarbon exploration in this area since the fault system forms a link between the source rocks and reservoirs. However, it is difficult to obtain a high-quality depth image of the fault system due to the effects of complex velocity and seismic absorption. Inaccurate depth velocities lead to fault shadows and structure distortions at the target zone. Absorption effects further deteriorate seismic imaging as they cause amplitude attenuation, phase distortion, and resolution reduction. We demonstrate how a combination of high-resolution depth velocity modeling and Q imaging work together to resolve these challenges. This workflow provides a step change in image quality of the complex fault system and targeted source rocks at Wenchang Field, significantly enhancing structure interpretation and reservoir delineation. A couple of commercial discoveries have been made, and several other potential hydrocarbon reservoirs have been identified based on the reprocessed data, which reveal new hydrocarbon potential in this region.

THE EROMANGA BASIN

1989 ◽  
Vol 29 (1) ◽  
pp. 379
Author(s):  
H.R.B. Wecker
Keyword(s):  
Middle Triassic ◽  
Significant Proportion ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Structural Deformation ◽  
Tectonic Activity ◽  
Hydrocarbon Generation ◽  
Basin Region ◽  
Migration Pathways ◽  
Eromanga Basin

The Eromanga Basin, encompassing an area of approximately 1 million km2 in Central Australia, is a broad intracratonic downwarp containing up to 3000 m of Middle Triassic to Late Cretaceous sediments.Syndepositional tectonic activity within the basin was minimal and the main depocentres largely coincide with those of the preceding Permo- Triassic basins. Several Tertiary structuring phases, particularly in the Early Tertiary, have resulted in uplift and erosion of the Eromanga Basin section along its eastern margin, and the development of broad, northwesterly- to northeasterly- trending anticlines within the basin. In some instances, high angle faults are associated with these features. This structural deformation occurred in an extensional regime and was strongly influenced by the underlying Palaeozoic structural grain.The Eromanga Basin section is composed of a basal, dominantly non- marine, fluvial and lacustrine sequence overlain by shallow marine deposits which are in turn overlain by another fluvial, lacustrine and coal- swamp sequence. The basal sequence is the principal zone of interest to petroleum exploration. It contains the main reservoirs and potential source rocks and hosts all commercial hydrocarbon accumulations found to date. While the bulk of discovered reserves are in structural traps, a significant stratigraphic influence has been noted in a number of commercially significant hydrocarbon accumulations.All major discoveries have been in the central Eromanga Basin region overlying and adjacent to the hydrocarbon- productive, Permo- Triassic Cooper Basin. The mature Permian section is believed to have contributed a significant proportion of the Eromanga- reservoired hydrocarbons. Accordingly, structural timing and migration pathways within the Permian and Middle Triassic- Jurassic sections are important factors for exploration in the central Eromanga Basin region. Elsewhere, in less thermally- mature areas, hydrocarbon generation post- dates Tertiary structuring and thus exploration success will relate primarily to source- rock quality, maturity and drainage factors.Although exploration in the basin has proceeded spasmodically for over 50 years, it has only been in the last decade that significant exploration activity has occurred. Over this recent period, some 450 exploration wells and 140 000 km of seismic acquisition have been completed in the pursuit of Eromanga Basin oil accumulations. This has resulted in the discovery of 227 oil and gas pools totalling an original in- place proved and probable (OOIP) resource of 360 MMSTB oil and 140 BCF gas.Though pool sizes are generally small, up to 5 MMSTB OOIP, the attractiveness of Eromanga exploration lies in the propensity for stacked pools at relatively shallow depths, moderate to high reservoir productivity, and established infrastructure with pipelines to coastal centres. Coupled with improved exploration techniques and increasing knowledge of the basinal geology, these attributes will undoubtedly ensure the Eromanga Basin continues to be a prime onshore area for future petroleum exploration in Australia.

TECTONICS OF THE JACKSON-NACCOWLAH AREA, COOPER-EROMANGA BASINS, SOUTHWEST QUEENSLAND, AND THEIR IMPLICATIONS FOR HYDROCARBON ACCUMULATION

1985 ◽  
Vol 25 (1) ◽  
pp. 85
Author(s):  
A.W. Nelson
Keyword(s):  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Oil Accumulation ◽  
Basement Faults ◽  
Model Study ◽  
Fault Bend ◽  
Exploration Drilling ◽  
Wrench Fault ◽  
Occurrence Patterns

The Naccowlah-Jackson Trend in the Cooper-Eromanga Basins, southwest Queensland, has been the scene of a high hydrocarbon exploration drilling success ratio during the 1980s. The structural trend is mainly the result of sinistral convergent wrenching, which has given rise to a series of major reverse faults and two distinct series of relatively minor parallel and orthogonal basement faults. A parallel is drawn with fault patterns shown on a clay model study of a 15° convergent wrench fault. Productive structures result from intermittent growth on the fault trends since Early Permian, although original wrenching may have been pre-Permian. A releasing (divergent) fault bend is identified as an area of accumulation of a thick sequence of potential Permian source rock. Although this accumulation is well placed to have sourced the largest known oil accumulation on the trend, other drilling results tend to downgrade the potential of the local Permian sequence as a source.Structural growth due to wrenching has been responsible for a favourable integration of the components necessary for hydrocarbon generation and accumulation, but also appears to be responsible for crestal faulting which in several cases is interpreted to have led to the escape of hydrocarbons.Two basic oil types (Hutton type and Murta type) are known. The occurrence patterns of these are consistent with the Hutton type being derived from Jurassic source rocks, mature in the Nappamerri Trough, and the Murta type being sourced intra-formationally from source rocks which are marginally mature over most of the study area.

GIFFSLAND HYDROCARBONS - A PERSPECTIVE FROM THE BASIN EDGE

1984 ◽  
Vol 24 (1) ◽  
pp. 91 ◽  
Author(s):  
J. G. Stainforth
Keyword(s):  
Heat Flow ◽  
Upper Cretaceous ◽  
Oil And Gas ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Lower Tertiary ◽  
Late Tertiary ◽  
Carbonaceous Shales ◽  
Basin Edge ◽  
Gippsland Basin

Permit VIC/P19 lies palaeogeographically seaward of the main producing part of the Gippsland Basin. Deposition of the Latrobe Group commenced with volcanics and continental 'rift-stage' sediments during the Late Cretaceous. This phase was succeeded first by paludal sedimentation in the failed rift during the Campanian and Maastrichtian, and then by cyclic paralic sedimentation during the Paleocene and Eocene.Analysis of the hydrocarbons recovered during recent exploration of permit VIC/P19 shows that they were sourced from moderately mature coals and carbonaceous shales in the Campanian/-Maastrichtian paludal sequence.A maturation model that assumes elevated but decreasing heat flow, related to sea-floor spreading, produces an excellent fit to the observed maturity data and predicts a long history of hydrocarbon generation during the Tertiary. The maturity of the Upper Cretaceous source sequence depends more on the thickness of the overlying Lower Tertiary clastic Latrobe sediments than on the thickness of the Upper Tertiary carbonate wedge. The Late Tertiary phase of burial had relatively little effect on maturation because of its rapidity and the lower heat flow and higher thermal conductivities of the deeper sequence at the time. Overpressures in mature Upper Cretaceous source rocks, resulting from hydrocarbon generation, have driven pore fluids, including hydrocarbons, laterally up-dip into normally pressured reservoirs.The main oil province of the Gippsland Basin has a greater thickness of Lower Tertiary than has VIC/P19. As a result, source rocks are more mature there, and became wholly so by the end of deposition of the Latrobe Group. This facilitated charge of traps at the top of the Latrobe Group, which contain most of the oil and gas discovered to date in the Basin.

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