LITHOFACIES STUDY ON THE TOOLACHEE FORMATION, GIDGEALPA-MOOMBA-BIG LAKE AREA, COOPER BASIN, SOUTH AUSTRALIA

1973 ◽  
Vol 13 (1) ◽  
pp. 41
Author(s):  
Roger C. N. Thornton
Keyword(s):  
South Australia ◽  
Flood Plain ◽  
Depositional Environments ◽  
Core Material ◽  
Upper Permian ◽  
Limited Area ◽  
Lake Area ◽  
Opposite Trend ◽  
Flow Gradient ◽  
Cooper Basin

A lithofacies study on the Upper Permian Toolachee Formation has been conducted in the Gidgealpa-Moomba-Big Lake area to determine the suitability of the technique in the reconstruction of depositional environments and palaeogeographic trends throughout the Cooper Basin. The Toolachee Formation is one of the main gas producing intervals in the basin, especially in the area of study, which is approximately 2,000 square kilometres. Thirty-one wells drilled in this region indicate that the formation ranges in thickness from 35 metres to over 115 metres.The Toolachee Formation, taken as a whole, is too thick to show any significant features on a lithofacies map over the limited area of investigation. However, lithofacies maps of three approximately chronostratigraphic subdivisions of the same formation show both vertical and lateral trends. Vertically, the percentage of sandstone decreases from the lowermost subdivision to the uppermost subdivision; coal percentages show the opposite trend; and core material shows fining upwards sequences. Laterally, isopachous thin areas (depositional highs) in most cases correlated with an increase in shale or coal lithologies. Histograms of coal cycles show that the lower and middle parts have similar composite sequences of, from the base upwards, sandstone mixture of sandstone and shale-shalecoal.The depositional model proposed is an aggradational flood-plain which, prior to the commencement of deposition, had been eroded to a peneplain. Sediments were deposited from rivers of gradually declining flow gradient until marsh and lacustrine conditions prevailed for long periods of time. Deposition ceased at the sediplain stage.

Emerging continuous gas plays in the Cooper Basin, South Australia

2012 ◽  
Vol 52 (2) ◽  
pp. 671
Author(s):  
Sandra Menpes ◽  
Tony Hill
Keyword(s):  
Shale Gas ◽  
South Australia ◽  
Flood Plain ◽  
Source Rocks ◽  
Early Permian ◽  
Gas Shale ◽  
Freshwater Lakes ◽  
Gas Desorption ◽  
Wet Gas ◽  
Cooper Basin

Recent off-structure drilling in the Nappamerri Trough has confirmed the presence of gas saturation through most of the Permian succession, including the Roseneath and Murteree shales. Basin-centred gas, shale gas and deep CSG plays in the Cooper Basin are now the focus of an escalating drilling and evaluation campaign. The Permian succession in the Nappamerri Trough is up to 1,000 m thick, comprising very thermally mature, gas-prone source rocks with interbedded sands—ideal for the creation of a basin-centred gas accumulation. Excluding the Murteree and Roseneath shales, the succession comprises up to 45% carbonaceous and silty shales and thin coals deposited in flood plain, lacustrine and coal swamp environments. The Early Permian Murteree and Roseneath shales are thick, generally flat lying, and laterally extensive, comprising siltstones and mudstones deposited in large and relatively deep freshwater lakes. Total organic carbon values average 3.9% in the Roseneath Shale and 2.4% in the Murteree Shale. The shales lie in the wet gas window (0.95–1.7% Ro) or dry gas window (>1.7% Ro) over much of the Cooper Basin. Thick Permian coals in the deepest parts of the Patchawarra Trough and over the Moomba high on the margin of the Nappamerri Trough are targets for deep CSG. Gas desorption analysis of a thick Patchawarra coal seam returned excellent total raw gas results averaging 21.2 scc/g (680 scf/ton) across 10 m. Scanning electron microscopy has shown that the coals contain significant microporosity.

SEISMIC AVO STUDIES ASSIST IN THE MAPPING OF A PERMIAN GAS SAND AT KERNA FIELD, COOPER BASIN

1991 ◽  
Vol 31 (1) ◽  
pp. 244
Author(s):  
J. Pinchin ◽  
A.B. Mitchell
Keyword(s):  
South Australia ◽  
Flood Plain ◽  
Seismic Facies ◽  
Gas Field ◽  
Seismic Modelling ◽  
Coal Beds ◽  
South Central ◽  
Amplitude Versus Offset ◽  
Modelling Studies ◽  
Cooper Basin

Kerna is a gas field within the south-central part of the Cooper Basin, 12 km southwest of the Dullingari Field and adjacent to the border of South Australia and Queensland. The trap is a domal anticline containing gas structurally trapped within the Early Permian Patchawarra Formation. The overlying Permian Epsilon Formation, above intervening shale, also contains gas, which may be stratigraphically trapped or restricted by permeability barriers around the southern and western flanks of the field.Seismic reflection amplitudes can be used to map the extent of the Epsilon gas sand. Seismic modelling studies show that the gas sand displays an amplitude-versus-offset (AVO) effect which distinguishes the gas sand from a wet sand or from a coal reflection at the same stratigraphic level. The spatial distribution of the AVO anomalies, and of the overall seismic stack response, has been mapped across the field. The interpreted 'seismic facies' map shows a meander belt across a coal swamp dominated flood plain. The distribution of AVO anomalies within and around this meander belt shows the likely occurrence of gas-bearing sandstones.This study has implications for other areas of the Cooper Basin where adequate separation between coal beds and gas sands allows the AVO effect of the latter to be observed. These AVO effects can then be used as a direct indicator of gas in stratigraphic and structural traps.

Fracture mapping and modelling in shale-gas target in the Cooper Basin, South Australia

2011 ◽  
Vol 51 (1) ◽  
pp. 397 ◽  
Author(s):  
Guillaume Backé ◽  
Hani Abul Khair ◽  
Rosalind King ◽  
Simon Holford
Keyword(s):  
Shale Gas ◽  
Seismic Data ◽  
Oil And Gas ◽  
South Australia ◽  
Horizontal Stress ◽  
Fracture Network ◽  
Low Permeability ◽  
Lake Area ◽  
Stress Regime ◽  
Cooper Basin

The success story of a shale-gas reserve development in the United States is triggering a strong industry focus towards similar plays in Australia. The Cooper Basin (located at the border of South Australia and Queensland) and the Otway Basin (extending both onshore and offshore South Australia and Victoria) could be prime targets to develop shale-gas projects. The Cooper Basin, a late-Carboniferous to mid-Triassic basin, is the largest onshore sedimentary basin producing oil and gas from tight conventional reservoirs with low permeability. Fracture stimulation programs are used extensively to produce the oil and gas. Furthermore, new exploration strategies are now targeting possible commercial gas hosted in low-permeability Permian shale units. To maximise production, the development of shale-gas prospects requires a good understanding of the: 1. structure of the reservoirs; 2. mechanical properties of the stratigraphy; 3. fracture geometry and density; 4. in-situ stress field; and, 5. fracture stimulation strategies. In this study, we use a combination of seismic mapping techniques–including horizon and attribute mapping, and an analysis of wellbore geophysical logs–to best constrain the existing fracture network in the basins. This study is based on the processing and analysis of a 3D seismic cube–the Moomba Big Lake survey–which is located in the southwestern part of the Cooper Basin. This dataset covers an area encompassing both a structurally complex setting in the vicinity of a major fault to the SE of the survey, and an area of more subtle deformation corresponding to the southernmost part of the Nappamerri Trough. Structural fabrics trending ˜NW–SE and NE–SW, which are not visible on the amplitude seismic data, are revealed by the analysis of the seismic attributes–namely a similarity (equivalent to a coherency cube), dip steering and maximum curvature attributes. These orientations are similar to those of natural fractures mapped from borehole images logs, and can therefore be interpreted as imaging natural fractures across the Moomba-Big Lake area. This study is the first of its kind able to detect possible fractures from seismic data in the Cooper Basin. The methodology developed here can offer new insights into the structure of sedimentary basins and provide crucial parameters for the development of tight reservoirs. In parallel, a tentative forward model of the generation of a fracture network following a restoration of the Top Roseneath horizon was carried out. The relatively good correlation between the fracture orientations generated by the model and the fractures mapped from geophysical data shows that fractures in the Moomba-Big Lake area may have formed during either a N–S compressive principal horizontal stress, or an E–W compressive principal horizontal tectonic stress regime. In addition, the orientations of the fracture interpreted through this study are also compatible with a generation under the present day stress regime described in this part of the basin, with an maximal horizontal stress trending E–W.

Lithofacies analysis and sequence stratigraphy of the Roseneath-Epsilon-Murteree gas plays in the Cooper Basin, South Australia

2017 ◽  
Vol 57 (2) ◽  
pp. 749
Author(s):  
Fengtao Guo ◽  
Peter McCabe
Keyword(s):  
South Australia ◽  
Flood Plain ◽  
X Ray Diffraction ◽  
Sedimentary Evolution ◽  
Facies Associations ◽  
Three Stages ◽  
Mouth Bar ◽  
Mouth Bars ◽  
Stacking Patterns ◽  
Cooper Basin

The early–middle Permian Roseneath-Epsilon-Murteree (REM) strata of the Cooper Basin, South Australia, has conventional and unconventional gas plays. To better understand the sedimentary evolution of the strata, eight key cored wells for the REM in the South Australia were selected and more than 1400 m cores have been characterised to study the lithofacies, facies associations and associated stacking patterns. Twelve lithofacies are identified and further categorised into eight facies associations: (1) open lacustrine, (2) lacustrine shoreface, (3) flood plain/interdistributary bay/channel fill, (4) fluvial channel/distributary channel, (5) crevasse channel/splay/natural levee, (6) distributary mouth bar, (7) prodelta, and (8) mire/swamp. Cyclic stacking patterns are distinguished both in cores and well logs. X-ray diffraction analysis indicates the lower and middle parts of the Murteree Shale mainly consist of claystone and are characteristic of deep water sediments. The upper Murteree Shale has a larger percentage of silt and sand, which suggests an overall regressive process. The Epsilon Formation displays three stages of deposition: (1) a lower, thin, upward-coarsening package of beach and lacustrine shoreline deposits with a continued regression from the underlying Murteree Shale; (2) a coaly, middle unit deposited by distributary channels, crevasse splays, mires and delta mouth bars; and (3) an upper unit of cyclic coarsening-upward claystone, siltstone and sandstone, deposited in shoreline environments with fluvial modifications. The Roseneath Shale resulted from transgression after deposition of the upper Epsilon Formation with a relatively rapid rise of lake level marked by transgressive lags. A final coarsening-upward sequence of shoreline deposits indicates an ending phase of regression.

THE DELIA FIELD, COOPER BASIN, SOUTH AUSTRALIA

1973 ◽  
Vol 13 (1) ◽  
pp. 58
Author(s):  
Martin Pyecroft
Keyword(s):  
Joint Venture ◽  
South Australia ◽  
Upper Permian ◽  
Gas Field ◽  
Water Contact ◽  
Reservoir Characteristics ◽  
Cooper Basin

The Della gas field of the Cooper Basin, South Australia, was discovered by Pursuit Oil No Liability and joint venture associates in July 1970. The field covers an area of approximately 17,000 acres in a discrete culmination on the Nappacoongee-Murteree anticlinal trend.Production is from several fluviatile sandstone units within the Toolachee Formation of the Upper Permian Gidgealpa Group. The trap is essentially structural with a maximum closure of some 450 ft on the top of the Toolachee Formation above a probable gas-water contact at 6,460 ft subsea.Five of the seven wells drilled to date in the field have been completed as potential gas producers. Production occurs between 6,270 and 6,670 ft and the average total depth is 7,180 ft. Net pay thicknesses vary from 37 to 98 ft and good reservoir characteristics are typical of the producing sands in the field. Twenty-two days are normally required to drill and complete a productive well.

Principal component analysis of textural characteristics of fluvio-lacustrine sandstones and controlling factors of sandstone textures

2021 ◽  
pp. 1-15
Author(s):  
Dong-Yu Zheng ◽  
Si-Xuan Wu
Keyword(s):  
Principal Component Analysis ◽  
Principal Component ◽  
Component Analysis ◽  
Controlling Factors ◽  
Depositional Environments ◽  
Upper Permian ◽  
Thin Sections ◽  
Textural Characteristics ◽  
Depositional Settings ◽  
Feldspathic Sandstone

Abstract Textures are important features of sandstones; however, their controlling factors are not fully understood. We present a detailed textural analysis of fluvio-lacustrine sandstones and discuss the influences of provenance and depositional environments on sandstone textures. The upper Permian – lowermost Triassic Wutonggou sandstones in the Bogda Mountains, NW China, are the focus of this study. Sandstone thin-sections were studied by point counting and their textures were analysed using statistical and principal component analysis. Fluvial lithic, fluvial feldspathic, deltaic lithic, deltaic feldspathic, littoral lithic and littoral feldspathic sandstone were classified and compared. These comparisons indicate that lithic and feldspathic sandstones from the same depositional settings have significant differences in graphic mean, graphic standard deviation and roundness; in contrast, sandstones from different depositional settings but with similar compositions have limited differences in textures. Moreover, three principal components (PCs) are recognized to explain 75% of the total variance, of which the first principal component (PC1) can explain 44%. In bivariate plots of the PCs, sandstones can be distinguished by composition where lithic and feldspathic sandstones are placed in different fields of the plots along the axis of PC1. However, sandstones from different depositional settings overlap and show no clear division. These results indicate that provenance, mainly the source lithology, is the most significant controlling factor on sandstone texture, whereas the depositional environment has limited influence. This study improves our understanding of textural characteristics of fluvio-lacustrine sandstones and their controlling factors, and shows the potentiality of principal component analysis in sandstone studies.

scholarly journals Sedimentology and geochemistry of Middle–Upper Permian in northwestern Turpan–Hami Basin, China: Implication for depositional environments and petroleum geology

2018 ◽  
Vol 36 (4) ◽  
pp. 910-941
Author(s):  
Jian Song ◽  
Zhidong Bao ◽  
Xingmin Zhao ◽  
Yinshan Gao ◽  
Xinmin Song ◽  
...  
Keyword(s):  
Depositional Environment ◽  
Saline Water ◽  
Depositional Environments ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Upper Permian ◽  
Late Permian ◽  
Humid Climate ◽  
Mountain Area ◽  
Volcanic Source

Studies have found that the Permian is another important stratum for petroleum exploration except the Jurassic coal measures within Turpan–Hami Basin recently. However, the knowledge of the depositional environments and its petroleum geological significances during the Middle–Late Permian is still limited. Based on the analysis about the sedimentological features of the outcrop and the geochemical characteristics of mudstones from the Middle Permian Taerlang Formation and Upper Permian Quanzijie Formation in the Taoshuyuanzi profile, northwest Turpan–Hami Basin, this paper makes a detailed discussion on the Middle–Late Permian paleoenvironment and its petroleum geological significances. The Middle–Upper Permian delta–lacustrine depositional system was characterized by complex vertical lithofacies assemblages, which were primarily influenced by tectonism and frequent lake-level variations in this area. The Taerlang Formation showed a significant lake transgression trend, whereas the regressive trend of the Quanzijie Formation was relatively weaker. The provenance of Taerlang and Quanzijie Formations was derived from the rift shoulder (Bogda Mountain area now) to the north and might be composed of a mixture of andesite and felsic volcanic source rocks. The Lower Taerlang Formation was deposited in a relatively hot–dry climate, whereas the Upper Taerlang and Quanzijie Formations were deposited in a relatively humid climate. During the Middle–Late Permian, this area belonged to an overall semi-saline water depositional environment. The paleosalinity values showed stepwise decreases from the Lower Taerlang Formation to the Upper Quanzijie Formation, which was influenced by the changes of paleoclimate in this region. During the Middle–Late Permian, the study area was in an overall anoxic depositional environment. The paleoenvironment with humid climate, lower paleosalinity, anoxic condition, and semi-deep to deep water during the deposition of the Upper Taerlang Formation was suitable for the accumulation of mudstones with higher TOC values.

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