RESERVOIR POTENTIAL OF GLACIO-FLUVIAL SANDSTONES: MERRIMELIA FORMATION, COOPER BASIN, SOUTH AUSTRALIA

1997 ◽  
Vol 37 (1) ◽  
pp. 154 ◽  
Author(s):  
A.J. Chaney ◽  
C.J. Cubitt ◽  
B.P.J. Williams
Keyword(s):  
South Australia ◽  
Sensu Stricto ◽  
Reservoir Quality ◽  
Compositional Variation ◽  
Freezing And Thawing ◽  
Gas Reservoirs ◽  
Environment Change ◽  
Provenance Data ◽  
Sandstone Facies ◽  
Cooper Basin

Sedimentological analysis of cored sections within the Merrimelia Formation (basal Gidgealpa Group, Cooper Basin, S.A.) reveals a complex glacigenic environment, including glacio-lacustrine, deltaic, shorezone, fluvial, aeolian and other terrestrial facies. These facies are observed within terminoglacial and proglacial environments, and interfinger constantly throughout the Merrimelia Formation, exhibiting rapid environment change related to position of the ice sheet. Detailed sedimentological and petrological analysis, suggests that Tirrawarra sandstone-type facies belongs within the Merrimelia depositional realm. Provenance data indicates that the lithic component of the Tirrawarra Sandstone, is sourced from reworked Merrimelia coeval depositional facies. A high proportion of labile grains, which are commonly observed in the Merrimelia Formation, are only observed rarely in the Tirrawarra Sandstone (sensu stricto). It is proposed that the fluvial sandstones of the Merrimelia Formation are part of the same fluvial deposystem as the Tirrawarra Sandstone (sensu stricto) and the two sandstone sequences are the natural progression of coarsening sediment as more detritus was released from melting glaciers. It is suggested that there no longer remains any sedimentological, stratigraphical or petrographical reasons why the Tirrawarra Sandstone should not be included within the Merrimelia Formation. It is further proposed that all the braided glacio- fluvial sandstones within the Merrimelia Formation and Tirrawarra Sandstone (sensu stricto) be grouped together as 'Tirrawarra-type' facies within the Merrimelia glacigenic domain.The concept that the glacio-fluvial sandstones within the Merrimelia Formation are of the same genetic origin as the Tirrawarra Sandstone (sensu stricto), must point to the economic potential of similar sandstones found throughout the Merrimelia Formation. The thickness, sediment style and lateral extent of the proglacial braidplains is controlled by the duration of glacial melting. The Merrimelia Formation reveals a sequence of major freezing and thawing episodes with the overlying Patchawarra Formation representing the cessation of glacial influence in the Cooper Basin. Therefore, the youngest 'Tirrawarra-type' sandstone facies found at the top of the Merrimelia Formation is likely to contain the least amount of labile grains, a highly rigid siliceous framework and will be well sorted. The risk of lower reservoir quality increases down section where, with time, freezing dominated over thawing and the sediments were less rinsed, and where the resultant sandstones are more likely to be thin, more poorly sorted and chemically immature with a high proportion of labile framework grains. Thus compositional variation, controlling the diagenetic overprint, together with sandstone facies and bedform style exert profound control on the reservoir quality in the Tirrawarra-Moorari Field area, on potential gas reservoirs in the Merrimelia Formation.

HIGH RESOLUTION PALAEOGEOGRAPHIC MAPPING OF THE FLUVIAL-LACUSTRINE PATCHAWARRA FORMATION IN THE COOPER BASIN, SOUTH AUSTRALIA

2002 ◽  
Vol 42 (1) ◽  
pp. 65 ◽  
Author(s):  
P.C. Strong ◽  
G.R. Wood ◽  
S.C. Lang ◽  
A. Jollands ◽  
E. Karalaus ◽  
...  
Keyword(s):  
High Resolution ◽  
South Australia ◽  
River System ◽  
Structural Features ◽  
Gas Reservoirs ◽  
Predictive Tool ◽  
Sequence Stratigraphic ◽  
Channel Belt ◽  
Reservoir Connectivity ◽  
Cooper Basin

Fluvial-lacustrine reservoirs in coal-bearing strata provide a particular challenge for reservoir characterisation because of the dominance of coal on the seismic signature and the highly variable reservoir geometry, quality and stratigraphic connectivity. Geological models for the fluvial gas reservoirs in the Permian Patchawarra Formation of the Cooper Basin are critical to minimise the perceived reservoir risks of these relatively deep targets. This can be achieved by applying high-resolution sequence stratigraphic concepts and finescaled seismic mapping. The workflow begins with building a robust regional chronostratigraphic framework, focussing on widespread lacustrine flooding surfaces and unconformities, tied to seismic scale reflectors. This framework is refined by identification of local surfaces that divide the Patchawarra Formation into high-resolution genetic units. A log facies scheme is established based on wireline log character, and calibrated to cores and cuttings, supported by analogue studies, such as the modern Ob River system in Western Siberia. Stacking patterns within each genetic unit are used to determine depositional systems tracts, which can have important reservoir connectivity implications. This leads to the generation of log signature maps for each interval, from which palaeogeographic reconstructions are generated. These maps are drawn with the guiding control of syn-depositional structural features and net/ gross trends. Estimates of fluvial channel belt widths are based on modern and ancient analogues. The resultant palaeogeography maps are used with structural and production data to refine play concepts, as a predictive tool to locate exploration and development drilling opportunities, to assess volumetrics, and to improve drainage efficiency and recovery during production of hydrocarbons.

Monitoring shale gas resources in the Cooper Basin using magnetotellurics

Geophysics ◽  
2016 ◽  
Vol 81 (6) ◽  
pp. A13-A16 ◽  
Author(s):  
Nigel Rees ◽  
Simon Carter ◽  
Graham Heinson ◽  
Lars Krieger
Keyword(s):  
Hydraulic Fracturing ◽  
Shale Gas ◽  
South Australia ◽  
Depth Range ◽  
Bulk Conductivity ◽  
Gas Reservoirs ◽  
Horizontal Fracture ◽  
Fluid Permeability ◽  
Fracturing Fluids ◽  
Cooper Basin

The magnetotelluric (MT) method is introduced as a geophysical tool to monitor hydraulic fracturing of shale gas reservoirs and to help constrain how injected fluids propagate. The MT method measures the electrical resistivity of earth, which is altered by the injection of fracturing fluids. The degree to which these changes are measurable at the surface is determined by several factors, such as the conductivity and quantity of the fluid injected, the depth of the target interval, the existing pore fluid salinity, and a range of formation properties, such as porosity and permeability. From an MT monitoring survey of a shale gas hydraulic fracture in the Cooper Basin, South Australia, we have found temporal and spatial changes in MT responses above measurement error. Smooth inversions are used to compare the resistivity structure before and during hydraulic fracturing, with results showing increases in bulk conductivity of 20%–40% at a depth range coinciding with the horizontal fracture. Comparisons with microseismic data lead to the conclusion that these increases in bulk conductivity are caused by a combination of the injected fluid permeability and an increase in wider scale in situ fluid permeability.

Impact of diagenesis on reservoir quality in a sedimentary geothermal play: a case study in the Cooper Basin, South Australia

2015 ◽  
Vol 28 (2) ◽  
pp. 252-272 ◽  
Author(s):  
Antoine Dillinger ◽  
Ludovic P. Ricard ◽  
Cameron Huddlestone-Holmes ◽  
Lionel Esteban
Keyword(s):  
South Australia ◽  
Reservoir Quality ◽  
Cooper Basin

DNA barcoding reveals multiple overlooked Australian species of the red algal order Rhodymeniales (Florideophyceae), with resurrection of Halopeltis J. Agardh and description of Pseudohalopeltis gen. nov.

Botany ◽  
2010 ◽  
Vol 88 (7) ◽  
pp. 639-667 ◽  
Author(s):  
Gary W. Saunders ◽  
Brian McDonald
Keyword(s):  
Dna Barcode ◽  
South Australia ◽  
Sensu Stricto ◽  
Cryptic Diversity ◽  
Additional Species ◽  
Australian Species ◽  
Lord Howe Island ◽  
Red Algal ◽  
Species Groups ◽  
Genetic Species

The DNA barcode (COI-5P) was used to investigate cryptic diversity among Rhodymenia spp. in southern Australia. Whereas eight species are currently recognized, we uncovered ca. 20 genetic species groups, phylogenetically assigned to four genera in two families. Procumbent specimens with molecular and anatomical signatures of the Fryeellaceae are assigned to Pseudohalopeltis tasmanensis gen. et sp. nov. Collections from Lord Howe Island recorded in the field as Rhodymenia / Fauchea sp. are assigned to the poorly known genus Microphyllum as Microphyllum robustum sp. nov. A cluster of species with distinct molecular and anatomical attributes is included in a resurrected Halopeltis J.G. Agardh, including Halopeltis australis (J. Agardh) comb. nov. (type species); Halopeltis austrina (Womersley) comb. nov.; Halopeltis cuneata (Harvey) comb. nov. [including Rhodymenia halymenioides (J. Agardh) Womersley]; Halopeltis gracilis sp. nov.; Halopeltis prostrata sp. nov.; and Halopeltis verrucosa (Womersley) comb. nov. Four additional species of Halopeltis from Lord Howe Island (LH1, LH2), Tasmania (TAS), and Western Australia are not characterized further. For Rhodymenia sensu stricto, similar levels of cryptic diversity were noted. Samples tentatively field-identified as “ Rhodymenia sonderi ,” but having affiliations to Rhodymenia rather than Halopeltis, are referred to Rhodymenia novahollandica sp. nov. Collections field-identified as R. obtusa are genetically distinct from that species and are assigned to Rhodymenia wilsonis (Sonder) comb. nov. Two highly divergent species currently identified as Rhodymenia leptophylla (LH from Lord Howe Island; TAS from Tasmania), as well as two additional cryptic previously unnamed taxa from South Australia (SA) and Victoria (VIC), are not characterized further.

Multiphase Flow Meter Health Monitoring Strategy: Maximizing the Value of Real-Time Sensors and Automation for Industrial Revolution 4.0

2021 ◽  
Author(s):  
Mohammad Al-Kadem ◽  
Mohammad Gomaa ◽  
Karam Al Yateem ◽  
Abdulmonam Al Maghlouth
Keyword(s):  
Industrial Revolution ◽  
Lower Cost ◽  
Critical Role ◽  
Cost Savings ◽  
Reservoir Quality ◽  
Hardened Cement ◽  
Gas Reservoirs ◽  
First Choice ◽  
Integrity Tests ◽  
Group 1

Abstract The Cement Packer approach has been successfully implemented to pursue and monetize minor gas reservoirs of poorer quality. Due to its critical role in power supply to meet the nation's needs, license to operate gas fields oftentimes come with contractual obligations to deliver a certain threshold of gas capacity. The cement packer method is a cheaper alternative to workovers that enables operators to build gas capacity by monetizing minor gas reservoirs at lower cost. Group 1 reservoirs are the shallowest hydrocarbon bearing sand with poorer reservoir quality and relatively thin reservoirs. The behind-casing-opportunities in Minor Group-1 reservoirs previously required a relatively costly pull-tubing rig workover to monetize the reservoir. Opportunities in two wells were optimized from pull –tubing rig workovers to a non-rig program by implementing Cement Packer applications. The tubing was punched to create tubing-casing communication and cement was subsequently pumped through the tubing and into the casing. The hardened cement then acted as a barrier to satisfy operating guidelines. The reservoir was then additionally perforated, flow tested and successfully monetized at a lower cost. Tubing and casing integrity tests prior to well entry demonstrated good tubing and casing integrity. This is critical to ensure that cement will only flow into the casing where the tubing was punched. Once the cement hardened, pressure test from the tubing and from the casing indicated that the cement has effectively isolated both tubulars. Subsequent Cement Bond Log and Ultrasonic Imaging Tool showed fair to good cement above the target perforation depth. These data supported the fact that the cement packer was solid and the reservoir was ready for additional perforation. Taking into account the reservoir quality, it was decided to perforate the reservoir twice with the biggest gun available to ensure the lowest skin possible. Post perforation, there was a sharp increase in the tubing pressure indicating pressure influx from the reservoir. Despite that, casing pressure remained low, confirming no communication and thus the success of the cement packer.The well was later able to unload naturally due to its high reservoir pressure, confirming the producibility of the reservoirs and unlocking similar opportunities in other wells. Additionally, the cement packer approach delivered tremendous cost savings between $6 – 8 mil per well. Besides confirming the reservoirs' producibility,the success also unlocked additional shallow gas behind casing opportunities in the area.This method will now be the first-choice option to monetize any hydrocarbon resources in reservoirs located above the top packer.

Exploring for stratigraphic traps in the Patchawarra Formation, Cooper Basin: an integrated seismic methodology

2018 ◽  
Vol 58 (2) ◽  
pp. 779
Author(s):  
Alexandra Bennett
Keyword(s):  
Complex Geometry ◽  
Imaging Techniques ◽  
South Australia ◽  
Seismic Interpretation ◽  
Seismic Survey ◽  
3D Seismic ◽  
Seismic Resolution ◽  
Seismic Reflectivity ◽  
Seismic Area ◽  
Cooper Basin

The Patchawarra Formation is characterised by Permian aged fluvial sediments. The conventional hydrocarbon play lies within fluvial sandstones, attributed to point bar deposits and splays, that are typically overlain by floodbank deposits of shales, mudstones and coals. The nature of the deposition of these sands has resulted in the discovery of stratigraphic traps across the Western Flank of the Cooper Basin, South Australia. Various seismic techniques are being used to search for and identify these traps. High seismic reflectivity of the coals with the low reflectivity of the relatively thin sands, often below seismic resolution, masks a reservoir response. These factors, combined with complex geometry of these reservoirs, prove a difficult play to image and interpret. Standard seismic interpretation has proven challenging when attempting to map fluvial sands. Active project examples within a 196 km2 3D seismic survey detail an evolving seismic interpretation methodology, which is being used to improve the delineation of potential stratigraphic traps. This involves an integration of seismic processing, package mapping, seismic attributes and imaging techniques. The integrated seismic interpretation methodology has proven to be a successful approach in the discovery of stratigraphic and structural-stratigraphic combination traps in parts of the Cooper Basin and is being used to extend the play northwards into the 3D seismic area discussed.

Chapter 5.2b Erebus Volcanic Province: petrology

2021 ◽  
pp. M55-2018-80 ◽  
Author(s):  
Adam P. Martin ◽  
Alan F. Cooper ◽  
Richard C. Price ◽  
Philip R. Kyle ◽  
John A. Gamble
Keyword(s):  
Mantle Convection ◽  
Sensu Stricto ◽  
Igneous Rocks ◽  
Compositional Variation ◽  
Garnet Lherzolite ◽  
Geochronological Data ◽  
Crustal Component ◽  
Volcanic Province ◽  
Mixed Spinel ◽  
Source Component

AbstractIgneous rocks of the Erebus Volcanic Province have been investigated for more than a century but many aspects of petrogenesis remain problematic. Current interpretations are assessed and summarized using a comprehensive dataset of previously published and new geochemical and geochronological data. Igneous rocks, ranging in age from 25 Ma to the present day, are mainly nepheline normative. Compositional variation is largely controlled by fractionation of olivine + clinopyroxene + magnetite/ilmenite + titanite ± kaersutite ± feldspar, with relatively undifferentiated melts being generated by <10% partial melting of a mixed spinel + garnet lherzolite source. Equilibration of radiogenic Sr, Nd, Pb and Hf is consistent with a high time-integrated HIMU sensu stricto source component and this is unlikely to be related to subduction of the palaeo-Pacific Plate around 0.5 Ga. Relatively undifferentiated whole-rock chemistry can be modelled to infer complex sources comprising depleted and enriched peridotite, HIMU, eclogite-like and carbonatite-like components. Spatial (west–east) variations in Sr, Nd and Pb isotopic compositions and Ba/Rb and Nb/Ta ratios can be interpreted to indicate increasing involvement of an eclogitic crustal component eastwards. Melting in the region is related to decompression, possibly from edge-driven mantle convection or a mantle plume.

scholarly journals Small-scale diagenetic facies heterogeneity controls porosity and permeability pattern in reservoir sandstones

2020 ◽  
Vol 79 (18) ◽  
Author(s):  
Matthias Heidsiek ◽  
Christoph Butscher ◽  
Philipp Blum ◽  
Cornelius Fischer
Keyword(s):  
Reservoir Rock ◽  
Rock Properties ◽  
Small Scale ◽  
Reservoir Quality ◽  
Permian Basin ◽  
Gas Reservoirs ◽  
Spatial Fluctuations ◽  
Porosity And Permeability ◽  
Reservoir Sandstones ◽  
Diagenetic Facies

Abstract The fluvial-aeolian Upper Rotliegend sandstones from the Bebertal outcrop (Flechtingen High, Germany) are the famous reservoir analog for the deeply buried Upper Rotliegend gas reservoirs of the Southern Permian Basin. While most diagenetic and reservoir quality investigations are conducted on a meter scale, there is an emerging consensus that significant reservoir heterogeneity is inherited from diagenetic complexity at smaller scales. In this study, we utilize information about diagenetic products and processes at the pore- and plug-scale and analyze their impact on the heterogeneity of porosity, permeability, and cement patterns. Eodiagenetic poikilitic calcite cements, illite/iron oxide grain coatings, and the amount of infiltrated clay are responsible for mm- to cm-scale reservoir heterogeneities in the Parchim formation of the Upper Rotliegend sandstones. Using the Petrel E&P software platform, spatial fluctuations and spatial variations of permeability, porosity, and calcite cements are modeled and compared, offering opportunities for predicting small-scale reservoir rock properties based on diagenetic constraints.

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