Muderong Shale Research Articles

Mesozoic lithofacies palaeogeography and petroleum prospectivity in North Carnarvon Basin, Australia

The North Carnarvon Basin, which lies in the North West Shelf of Australia, is highly rich in gas resources. As a typical passive marginal basin, it experienced the pre-rifting, early rifting, main rifting, late rifting, post-rifting sagging and passive margin stages. The basin was mainly filled with thick Mesozoic-Cenozoic sediments, of which the Mesozoic hosts the principal source, reservoir and seal intervals. Mesozoic palaeogeography has an important control on the oil and gas distribution. Triassic gas-prone source rocks of deltaic origin determine the high endowment of natural gases in the North Carnarvon Basin. The more restricted distribution of oil accumulations is controlled by oil source rocks in the Upper Jurassic Dingo Claystone. The Muderong Shale deposited in the Early Cretaceous marine transgression provides the effective regional seal for the underlying oil and gas reservoirs.

Linking preferred orientations to elastic anisotropy in Muderong Shale, Australia

The significance of shales for unconventional hydrocarbon reservoirs, nuclear waste repositories, and geologic carbon storage has opened new research frontiers in geophysics. Among many of its unique physical properties, elastic anisotropy had long been investigated by experimental and computational approaches. Here, we calculated elastic properties of Cretaceous Muderong Shale from Australia with a self-consistent averaging method based on microstructural information. The volume fraction and crystallographic preferred orientation distributions of constituent minerals were based on synchrotron x-ray diffraction experiments. Aspect ratios of minerals and pores, determined from scanning electron microscopy, were introduced in the self-consistent averaging. Our analysis suggested that phyllosilicates (i.e., illite-mica, illite-smectite, kaolinite, and chlorite) were dominant with [Formula: see text]. The shape of clay platelets displayed an average aspect ratio of 0.05. These platelets were aligned parallel to the bedding plane with a high degree of preferred orientation. The estimated porosity at ambient pressure was [Formula: see text] and was divided into equiaxial pores and flat pores with an average aspect ratio of 0.01. Our model gave results that compared satisfactorily with values derived from ultrasonic velocity measurements, confirming the validity and reliability of our approximations and averaging approach.

Improvements in development strategy for the Stag Oil Field, North West Shelf, Australia—implications for production success and drilling risk minimisation

Located on the North West Shelf of Western Australia, the Stag Oil field has proven to be a prolific reservoir, having produced more than 55 million barrels (MMbbls) of oil since 1998. This has not been without its challenges, however; with premature water breakthrough from injection wells occuring in several wells, potentially stranding large volumes of oil in the ground. Using the multicomponent processing and joint amplitude-versus-offset (AVO) inversion of an ocean bottom cable (OBC) seismic survey acquired in late 2007, new light has been shed on the distribution of unswept oil. This data has led to the succesful drilling of six wells and a marked increase in field production. Additionally, the seismic data has also been used to minimise drilling risks by using seismic coherency to steer the well around potential problems with a significant impact on well costs due to reduction of wellbore problems associated with horizontal drilling in the Muderong shale. To date, four wells have been drilled using this technique, resulting in a significant decrease in non-productive time while drilling during the most recent drilling campaign, which has a significant impact upon the profitability of these late-stage development wells.

Petroleum potential of the offshore southern Carnarvon Basin—insights from new Geoscience Australia data

In 2008–9, under the Offshore Energy Security Program, Geoscience Australia (GA) acquired 650 km of seismic data, more than 3,000 km of gravity and magnetic data, and, dredge samples in the southern Carnarvon Basin. This area comprises the Paleozoic Bernier Platform and southern part of the Mesozoic Exmouth Sub-basin. The new seismic and potential field data provide a new insight into the structure and sediment thickness of the deepwater southernmost part of the Exmouth Sub-basin. Mesozoic depocentres correspond to a linear gravity low, in water depths between 1,000–2,000 m and contain between 2–3 sec (TWT) of sediments. They form a string of en-echelon northeast-southwest oriented depressions bounded by shallow-dipping faults. Seismic data indicates that these depocentres extend south to at least 24°S, where they become more shallow and overprinted by volcanics. Potential plays in this part of the Exmouth Sub-basin may include fluvio-deltaic Triassic sandstone and Lower–Middle Jurassic claystone source rocks sealed by the regional Early Cretaceous Muderong shale. On the adjoining Bernier Platform, minor oil shows in the Silurian and Devonian intervals at Pendock–1a indicate the presence of a Paleozoic petroleum system. Ordovician fluvio-deltaic sandstones sealed by the Silurian age marine shales, Devonian reef complexes and Miocene inversion anticlines are identified as potential plays. Long-distance migration may contribute to the formation of additional plays close to the boundary between the two provinces. With a range of both Mesozoic and Paleozoic plays, this under-explored region may have a significant hydrocarbon potential.

Variation of vertical stress in the Carnarvon Basin, NW Shelf, Australia

Variations in vertical stress magnitudes can be attributed to lateral facies variations, diagenesis, localized uplift and disequilibrium compaction overpressure. Vertical stress magnitudes have been calculated using density and checkshot data from 47 wells in the Carnarvon Basin, on the NW Shelf of Australia. The vertical stress ranges from 20.2 MPa km − 1 to 23.8 MPa km − 1 below seabed; demonstrating a significant variation across the basin. The largest vertical stress magnitudes were calculated for the Dampier Sub-Basin, the eastern Barrow Sub-Basin and on the Peedamullah Shelf. The smallest vertical stress magnitudes were calculated in the Kangaroo Syncline, the western Barrow Sub-Basin and offshore across the Exmouth Plateau. High rock densities, thus, high vertical stress magnitudes, can be due to uplifted rock that is over-compacted relative to its current depth. In the Carnarvon Basin, areas of elevated vertical stress magnitudes correspond to areas of identified uplift. Uplift at the Bambra Anticline has previously been estimated to be approximately 900 m. Calculations within the Bambra-4 well demonstrate that a 900 m increase in burial depth of a regionally consistent lithostratigraphic unit (the Muderong Shale) equates to a 0.22 g cm − 3 increase in rock density. Thus, the difference between uplifted, over-compacted rock and normally-compacted rock (no uplift) is equivalent to a difference in the vertical stress magnitude of 2.1 MPa km − 1 at the Bambra Anticline. This value, totalling the difference between over-compacted (uplifted) and normally-compacted sedimentary rock (2.1 MPa km − 1 ), accounts for some part of the 3.6 MPa km − 1 variation in vertical stress magnitude observed across the Carnarvon Basin. Therefore, recent tectonic uplift has had a significant impact on the present-day magnitude of the vertical stress and is interpreted to be responsible for the majority of observed variation of vertical stress in the Carnarvon Basin.

Carbon dioxide storage potential of shales

Options for the geologic storage of carbon dioxide vary from saline aquifers and depleted oil and gas reservoirs to unminable coal seams and abandoned coal mines. Important aspects include the sealing integrity of the cap rock and potential changes in this integrity, owing to the interaction with CO 2. In this study, diffusive transport and gas sorption experiments on one well characterised shale sample (Muderong Shale, Australia) and different clay minerals were performed to obtain information on the sealing integrity and the CO 2 storage potential of these materials. All measurements were performed under reservoir conditions relevant for CO 2 storage ( T = 45–50 °C; p < 20 MPa). Repeat diffusion experiments on one shale plug yielded increased effective diffusion coefficients and a decrease in the concentration of the bulk CO 2 volume in the sample. The latter is believed to be dissolved in formation water, sorbed to mineral surfaces or involved with geochemical reactions. For the Muderong Shale, bulk volume CO 2 concentrations are greater within the experimental time frame (222–389 mol/m 3), when compared to coal and cemented sandstone (3–4 and 8–10 mol/m 3), respectively. This high CO 2 storage potential could not fully be explained by CO 2 dissolution in water alone. Thus, gas sorption experiments were performed on crushed shale and various clay minerals. High CO 2 sorption capacities (e.g. up to 1 mmol/g for the Muderong Shale) show that the high CO 2 concentration is related to a combination of CO 2 dissolution in water and gas sorption on clay minerals. Additionally, changes in specific surface areas before and after the sorption experiments and variations in the CO 2 sorption and diffusion behaviour due to repetitive experiments on the identical sample were observed, possibly related to geochemical alteration of the Muderong Shale and the clay minerals. These could not be quantified however and seemed to occur only at high pressures. Results obtained in this study provide a more positive view on the sealing integrity of intact cap rock formations. Carbon dioxide that migrates from a storage reservoir into the cap rock through the pore network will be immobilised to a certain extent, hence minimising (slow, diffusion-driven) leakage and providing additional CO 2 storage potential.

Impact of fabric, microcracks and stress field on shale anisotropy

Few data are available on shales in terms of seismic to ultrasonic properties and anisotropy, although all are important with regards to imaging problems often encountered in such lithologies. Additionally, mechanisms causing changes in these properties are not well documented due to the fine grain size of such materials and time required for testing under controlled pore pressure conditions. The results presented here are derived from a set of experiments run on Muderong Shale with pore pressure control in order to evaluate the effect of stress magnitude and stress anisotropy on ultrasonic response. This shale was noted to have a linear velocity-mean effective stress response and extremely high anisotropy, both likely the result of the presence of fluid-filled cracks in a low- permeability porous medium. Changes in velocity and Vp/Vs ratios are dependent on both stress and smectite content. S-wave velocity is significantly affected by the presence of smectite in this and other shales and at low stress (<20 MPa) is less sensitive to stress change than P-wave velocity. Vp/Vs ratios are noted to increase in this shale up to 20 MPa effective stress, then decrease slightly due to stress-induced loss of interlayer water in smectite. Intrinsic anisotropy comes from composition, a strong compaction fabric and the presence of microfractures; changes to ultrasonic anisotropy are the result of the magnitude of the stresses, their orientation with respect to the fractures and the degree of stress anisotropy.

Reservoir characterization of the Flag Sandstone, Barrow Sub-basin, using an integrated, multiparameter seismic AVO inversion technique

Editor's note: This material was presented at the 17th ASEG Geophysical Conference and Exhibition. A series of oil and gas fields have been discovered since 1979 in the Early Cretaceous Flag Sandstone in the Barrow Sub-basin of Western Australia's Carnarvon Basin. The Flag Sandstone is a lowstand complex of gravity flow sandstones deposited beyond the shelf edge of the Barrow delta. Figure 1 shows a stratigraphic chart. The permeable Flag Sandstone forms a consistent, high-quality reservoir that is capped by the impermeable Muderong shale. In the area immediately adjacent to and south of Varanus Island, the main trapping mechanism is four-way dip-closed anticlines, formed by drape compaction. Structural closure alone does not appear sufficient for oil emplacement as a limited number of prominent closed structures have been drilled and found water-wet. The known oil fields are nearing depletion and the goal is to properly locate additional wells to ensure complete development of the area. Figure 1. Stratigraphic chart for Carnarvon Basin showing the Early Cretaceous Flag Sandstone and overlying Muderong Shale (Barrow Sub-basin). The identification of the closed anticlinal structures on seismic data is complicated due to a poor P-impedance contrast between the Flag Sandstone and the overlying Muderong Shale. However, a strong V p / V s contrast exists between the sandstone and shale, resulting in reasonably consistent AVO class II effects. A far-angle stack with an angle range of 30–45° has been used successfully to map the structure on the top of the Flag Sandstone. The difficulty with this mapping technique is that it is subject to tuning effects and assumes a consistent AVO response. However, some wells in the area demonstrate an AVO response that does not match a simple model. Thus, a more robust technique was required that could model the true AVO response, provide an accurate pick …

GEOLOGICAL STORAGE OF CARBON DIOXIDE: MODELLING THE EARLY CRETACEOUS SUCCESSION IN THE BARROW SUB-BASIN, NORTHWEST AUSTRALIA

Potential sites for geological storage of CO2 require detailed assessment of storage capacity, containment potential and migration pathways. A possible candidate is the Flag Sandstone of the Barrow Sub-basin, northwest Australia, sealed by the Muderong Shale. The Flag Sandstone consists of a series of stacked, amalgamated, basin floor fan lobes with good lateral interconnectivity. The main reservoir sandstones have high reservoir quality with an average porosity of 21% and an average permeability of about 1,250 mD. The Muderong Shale has excellent seal capacity, with the potential to withhold an average CO2 column height of 750 m. Other containment issues were addressed by in situ stress and fault stability analysis. An average orientation of 095°N for the maximum horizontal stress was estimated. The stress regime is strike-slip at the likely injection depth (below 1,800 m). Most of the major faults in the study area have east-northeast to northeast trends and failure plots indicate that some of these faults may be reactivated if CO2 injection pressures are not monitored closely. Where average fault dips are known, maximum sustainable formation pressures were estimated to be less than 27 MPa at 2 km depth. Hydrodynamic modelling indicated that the pre-production regional formation water flow direction was from the sub-basin margins towards the centre, with an exit point to the southwest. However, this flow direction and rate have been altered by a hydraulic low in the eastern part of the sub-basin due to hydrocarbon production. The integrated site analysis indicates a potential CO2 storage capacity in the order of thousands of Mtonnes. Such capacity for geological storage could provide a technical solution for reducing greenhouse gas emissions.

THE INFLUENCE OF COMPOSITION, DIAGENESIS AND COMPACTION ON SEAL CAPACITY IN THE MUDERONG SHALE, CARNARVON BASIN

The Muderong Shale blankets most of the northern Carnarvon Basin and is the top seal to over 90% of all commercial discoveries. This study examines the influence that vertical effective stress, mineralogy and diagenesis have on regional variations of seal capacity. Throughout the basin, threshold pressures (determined from Mercury Injection Capillary Pressure (MICP) analyses), range from less than 1,000 psi (equivalent to ~100 m gas column) up to 10,000 psi (~1,000 m gas column). Because the Muderong Shale varies in thickness (5 m to &gt;900 m) and burial depth (~0.5–3.5 km), effective stresses and temperatures also vary. Effective stress and temperature significantly control pore geometry at different depths through compaction and diagenesis. The data from this study show that shale grain size has no direct influence over seal threshold pressure except that finer-grained Muderong Shale (36–45% particles 2.5 km) along the Northern Alpha Arch and Rankin Platform, total illite content is only moderate.

Geomechanical properties related to top seal leakage in the Carnarvon Basin, Northwest Shelf, Australia

The Muderong Shale is the regional top seal in the Carnarvon Basin on the Northwest Shelf of Australia. Evidence for top seal breach in this area comes from post-Muderong plays and hydrocarbon shows. Capillary pressure tests show this shale has the capability of restraining gas columns in excess of 250 m height, a value which is unlikely to be reached due to the intrinsic weakness of the Muderong Shale. Apart from one example, all hydrocarbon columns so far encountered in the Carnarvon Basin are well below this limit. Geomechanical testing of the Muderong Shale indicates it is a weak rock, commensurate with its high illite–smectite content. Comparison of laboratory-generated failure envelopes with in situ stress conditions suggest that intact Muderong Shale is not generally at risk of hydrofracture but that pre-existing faults and fractures may well be critically stressed in the present-day stress field. It is postulated that such faults and fractures may be responsible for top seal failure in the Muderong Shale and the resultant presence of hydrocarbons in the post-Muderong succession.

Microstructural and petrophysical characterization of Muderong Shale: application to top seal risking

Analysis of the Muderong Shale from the Carnarvon Basin suggests the shale is dominated by interstratified illite–smectite with a high percentage of illite interlayers. Capillary pressure measurements indicate that gas columns of c . 250 m could be sealed by such shale, although the choice of drying method used does influence the accuracy of this calculation. Freeze drying yielded the most consistent threshold pressure results, whereas air drying and vacuum drying showed a greater range of values. Similar calculations in regard to carbon dioxide sequestration indicate column heights of between 550 m and 750 m could be retained. Column height variation is primarily dependent on the contact angle of supercritical carbon dioxide with shale. Microstructurally, the shale is clay supported, exhibiting differential compaction of clays around more rigid grains and containing numerous high aspect ratio discontinuous fractures. These fractures do not affect the capillary properties of the shale, even when injection is fracture-parallel, suggesting they are unlikely to influence reservoir-scale fluid-flow properties. Comparison of the Muderong Shale laboratory data with hydrocarbon column heights from Carnarvon Basin discoveries indicate that top seal failure by capillary breakthrough is unlikely given the maximum lengths of hydrocarbon columns encountered to date. Potential for top seal failure is more likely to be influenced by formation integrity, pore pressure and in situ stress conditions.

DETECTING OVERPRESSURE USING POROSITY-BASED TECHNIQUES IN THE CARNARVON BASIN, AUSTRALIA

Overpressure has been encountered in many wells drilled in the Carnarvon Basin. Sonic logs are used to estimate pore pressure in shales in the Carnarvon Basin using the Eaton and equivalent depth methods of estimating pore pressure from velocity data with reference to a normal compaction trend. The crux of pore pressure estimation from the sonic log lies in the determination of the normal compaction trend, i.e. the acoustic travel time (Δt)/depth (z) trend for normally pressured sediments. The normal compaction trend for shales in the Carnarvon Basin was established by fitting an Athy-type exponential relationship to edited sonic log data, and is: Δt = 225 + 391exp(-0.00103z) Vertical stress estimates are also needed for the Eaton and equivalent depth methods used herein. A vertical stress (σv) relationship was obtained by fitting a regression line to vertical stress estimates from the density log, and is: σv = 0.0131 z1.0642 The Eaton and equivalent depth methods yield similar pressure estimates. However, the equivalent depth method can only be applied over a limited range of acoustic travel times, a limitation that does not apply to the Eaton method. The pressure estimates from the Eaton method were compared to pressures measured by direct pressure tests in adjacent permeable units. There is a good correlation between Eaton and test pressures in normally pressured intervals in three wells and overpressured intervals in two wells. Eaton pressure estimates underestimate overpressured direct pressure measurements in four wells by up to 13 MPa. This is consistent with overpressure being generated (at least in part) by a fluid expansion mechanism or lateral transfer of overpressure. The Eaton pressures in one well are, on average, 11 MPa lower than hydrostatic pore pressure recorded in direct pressure measurements below the Muderong Shale. The sediments in this well appear to be overcompacted due to exhumation. Mud weights can be used as a proxy for pore pressure in shales where direct pressure measurements are not available in the adjacent sandstones. The Eaton pressure estimates are consistent with mud weight in the Gearle Siltstone and Muderong Shale in 4 of the 8 wells studied. The Eaton pressures are on average 10 Mpa in excess of mud weight in the Muderong Shale and Gearle Siltstone in three wells. It is unclear whether the predicted Eaton pressures in these three wells accurately reflect pore pressure (i.e. the mud weights do not accurately reflect pore pressure), or whether they are influenced by changes in shale mineralogy (because the gamma ray filter does not differentiate between shale mineralogy).

ACOUSTIC PROPERTIES OF MUDERONG SHALE

The presence of smectitic shales often causes serious problems for drillers in the form of both overpressures due to low permeability and wellbore stability problems resulting from the presence of swelling clays. Prediction of overpressures in such sediments is hampered by interlayer water in the mineral structure that is not accounted for in porosity determinations whether by wireline methods or laboratory drying techniques. This study looks at the detailed physical properties and microstructure in relation to acoustic response of the Muderong Shale, a smectitic shale from the Carnarvon Basin on the Northwest Shelf of Australia. Porosity determined from acoustic or standard drying techniques is far in excess of that determined by both helium and mercury porosimetry, but correcting for interlayer water results in the values determined by the latter techniques. Physical properties are intimately tied to the acoustic response of the Muderong Shale at both sonic and ultrasonic frequencies. The presence of smectite results in anomalously low velocities in the Muderong Shale and the development of both compaction fabrics and induced microfracture generation result in significant acoustic anisotropy. Velocity variations from downhole shales in wells from the Carnarvon Basin can mainly be tied to smectite content but also to overpressure. The high degree of anisotropy of the Muderong Shale at ambient pressure can be related to the presence of both a sedimentary compaction fabric and high aspect ratio compliant microfractures. Determination of the relative contributions of these two causes of anisotropy in shales may provide a method by which to distinguish overpressure-generating mechanisms from acoustic data.

SEISMIC EXPRESSION OF ABNORMAL GEO-PRESSURE IN THE BARROW SUB-BASIN

Drilling uncertainties related to abnormal geopressure are common in the Barrow and Dampier Sub-basins of the North West Shelf. These uncertainties contribute to increased drilling risk and costs. There have been a number of published studies in this area which have been directed towards understanding the mechanisms and modelling of the expected pressures. These studies, however, have been in general isolated and have concentrated on non-seismic related methods. This paper provides an empirical analysis of the seismic response in an area with known variation of overpressure, and critically is integrated with a comprehensive research effort looking at aspects of overpressure from a laboratory, empirical and theoretical perspective.The study was conducted using data taken from permit WA-25-P (P25) in the Barrow Sub-basin. These data included 3D surface seismic and VSP, well logs, mud weight and pressure data from the wells. The results of a mineralogical analysis conducted on core samples and basin-wide geological modelling studies were also incorporated into the study. The Muderong Shale, which comprises the principal seal in the area and is believed to be overpressured was selected as the prime target for the analysis. Initially we assess the potential of existing methods, such as velocitybased methods, for remote prediction of excessive pore pressure in the area P25. This is extended to amplitude related effects involving an analysis of reflectivity in the presence of a velocity transition zone over the overpressured interval. Finally the relationship of well data, VSP and surface seismic derived attributes is described.The available data in the P25 area was sparse and consequently we could not rely on statistical based associations. Current industry methods that rely on a limited number of calibration points suggest that the application of either velocity or AVO based methods may produce unreliable predictions of pore pressure. Ambiguities in inferring overpressure introduced by a variable mineral composition of shales and the presence of a strong velocity gradient, which distorts the wave shape, reduces the reliability of these methods.A detailed analysis using VSP data acquired in a highly overpressured well was found to be crucial for understanding the response of various seismic attributes to changes in effective stress. This enabled us to propose a new qualitative, but efficient approach for remote prediction of overpressure, particularly suited for underexplored areas such as P25. The applicability of the method, which uses single and combined seismic sequence and trace multi-attributes to predict overpressured zones, is demonstrated with the Venture-Carey 3D data recorded in the Barrow Sub-basin.

THE JOHN BROOKES GAS DISCOVERY—AN EVOLVING STORY

John Brookes–1 was drilled as part of a work commitment for the WA-214-P Joint Venture in 1998 and discovered an 85 m gross dry gas column. The objective of the well was to test a structural closure at the base of the Muderong Shale regional seal on the Tryal Rocks anticline, up-dip from Tryal Rocks–1, drilled in 1970. Tryal Rocks–1, the 31st offshore well to be drilled within the Carnarvon Basin, WA, was initially considered a dry hole. However, a review of the well data in 1997–98 suggested that Tryal Rocks–1 might contain a hydrocarbon column. The mapping of the structure using initially 2D seismic data acquired post Tryal Rocks–1, then 3D data, indicated that Tryal Rocks–1 was drilled within closure, but off crest, and that significant closure existed up-dip. The John Brookes–1 location was selected to test this updip potential. The John Brookes–1 discovery confirmed the validity of the structural mapping. However, the unexpected nature of the reservoir, interpreted as a well developed turbiditic channel of Birdrong Sandstone age, changed the emphasis from purely structural to a play with structural/stratigraphic potential. An amalgamated turbidite complex model was invoked which infers that the John Brookes–1 reservoir represents a confined channel system cut into the underlying substrate. This model explains the results to date, with the John Brookes–1 gas reservoir being in direct continuity with the sandstones at Tryal Rocks–1. A review of the 3D seismic data across the field and seismic modelling support the stratigraphic model developed from the palynological interpretation.

Acoustic analysis of overpressure: from modeling to wireline observation

A comparison between acousto-elastic modeling, surface seismic, and wireline responses to overpressure suggests that acoustic responses to overpressure are not uniform among the data of different sources. Acousto-elastic modeling underestimates the effect of the in-situ formation pressures on acoustic properties of waves. That seismic energy decreases with increasing pore pressure is evident for either very low overpressure or extremely high overpressure, but becomes less definite for moderate overpressure. Sonic logs in conjunction with wireline pressure measurements in a number of wells are used to establish a common understanding of acoustic-pressure relationship in the Muderong Shale of the northern Carnarvon Basin. The velocity-pressure relationship in the Muderong Shale seems to be controlled by stratigraphic factors. In the same stratigraphic category, acoustic velocity changes across wells are found to be consistent with pore-pressure variations in our examples. Investigation of velocity-pressure relationships for the Muderong Shale indicates that pore-pressure prediction should be based on the detailed lithologic classification.

Barremian Foraminifera from the Muderong Shale, oldest marine sequence in the Cretaceous of the southern Carnarvon Basin, Western Australia

Other| April 01, 2001 Barremian Foraminifera from the Muderong Shale, oldest marine sequence in the Cretaceous of the southern Carnarvon Basin, Western Australia Barry A. Taylor; Barry A. Taylor University of Western Australia, Department of Geology and Geophysics, Nedlands, West. Aust., Australia Search for other works by this author on: GSW Google Scholar David W. Haig David W. Haig Search for other works by this author on: GSW Google Scholar Author and Article Information Barry A. Taylor University of Western Australia, Department of Geology and Geophysics, Nedlands, West. Aust., Australia David W. Haig Publisher: Micropaleontology Press First Online: 03 Mar 2017 Online ISSN: 0026-2803 Print ISSN: 1937-2795 GeoRef, Copyright 2004, American Geological Institute. Micropaleontology (2001) 47 (2): 125–143. https://doi.org/10.2113/47.2.125 Article history First Online: 03 Mar 2017 Cite View This Citation Add to Citation Manager Share Icon Share Facebook Twitter LinkedIn MailTo Tools Icon Tools Get Permissions Search Site Citation Barry A. Taylor, David W. Haig; Barremian Foraminifera from the Muderong Shale, oldest marine sequence in the Cretaceous of the southern Carnarvon Basin, Western Australia. Micropaleontology 2001;; 47 (2): 125–143. doi: https://doi.org/10.2113/47.2.125 Download citation file: Ris (Zotero) Refmanager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex toolbar search Search Dropdown Menu toolbar search search input Search input auto suggest filter your search All ContentBy SocietyMicropaleontology Search Advanced Search Abstract To clarify foraminiferal biogeographic affinities and the degree of differentiation of the inner shelf fauna from deeper water assemblages in the juvenile Indian Ocean, an assemblage of siliceous organic-cemented agglutinated foraminifera characteristic of the Ammobaculites Association described from the Southern Carnarvon Basin. The typical Muderong Shale assemblage is associated with the dinoflagellate Muderongia australis Zone, and is distinct from coeval foraminiferal assemblages known from Exmouth Plateau and the Argo Abyssal Plain. Lithofacies and biofacies suggest that the Muderong fauna inhabited dysaerobic sea-floor muds in the upper offshore zone (10-50 m water depth) in a sea with a very gentle sea-floor gradient deepening slightly toward the north. Faunal comparisons suggest that the Barremian ocean was well stratified on the mid-western Australian margin. This content is PDF only. Please click on the PDF icon to access. You do not have access to this content, please speak to your institutional administrator if you feel you should have access.

GEOLOGICAL CONTROLS ON OVERPRESSURE IN THE NORTHERN CARNARVON BASIN

A small, but significant fraction of wells drilled in the Northern Carnarvon Basin have encountered problems with overpressure: better pore pressure prediction would improve safety and economy for drilling operations. In the Northern Carnarvon Basin the occurrence of overpressure and likely mechanisms are under investigation as part of the Australian Petroleum Cooperative Research Centre (APCRC) Research Program on Pore Pressure Prediction. Previous workers have proposed a number of mechanisms as the main cause of overpressure including undercompaction, hydrocarbon generation, horizontal stress and clay reactions.A preliminary regional study was undertaken incorporating over 400 well completion reports which identified approximately 60 wells with mud weights greater than 1.25 S.G. A subset of these wells was investigated and more reliable but much scarcer pressure indicators such as kicks or direct pressure measurements were examined. Depth-pressure profiles of wells across the region are variable and commonly show pressure compartmentalisation. Using a range of indicators, it was observed that overpressured strata in the Barrow Subbasin:occur over a wide depth range (2,500 to 4,000+ mbsl);occur over a wide stratigraphic range (Late Triassic to Late Cretaceous);are not regionally limited by major structural boundaries;are associated with sequences dominated by finegrained sediments with variable clay mineralogy; and in depositionally, or structurally, isolated sandstones; andmainly to the west of the Barrow and Dampier Subbasins around the Alpha Arch and Rankin Trend, coinciding with thickest Tertiary deposition.Previous published work in the study area has tended to support hydrocarbon generation as the primary cause of overpressure, though more recent publications have emphasised compaction disequilibrium. The log response (DT, RHOB and NPHI) of overpressured clay-rich strata has been investigated to constrain the type of overpressure mechanism. A normal compaction trend has been derived for four stratigraphic groupings; Muderong Shale, Barrow Group, Jurassic and Triassic. All overpressure occurrences were accompanied by an increase in sonic transit time. Not all wells have suitable log data for evaluation, but all stratigraphic groups show some evidence of elevated porosity associated with overpressure consistent with disequillibrium compaction as a dominant mechanism. Overpressures in the Barrow Group in Minden-1 and the Jurassic section within Zeepaard–1 do not have accompanying porosity anomalies suggesting a different overpressure mechanism model is needed.

Quantification of uplift in the Carnarvon Basin based on interval velocities

Sonic velocities in the Toolonga Calcilutite (Upper Cretaceous), the Gearle Siltstone and Haycock Marl (mid‐Cretaceous), and the Muderong Shale (Lower Cretaceous) were each used to independently quantify apparent uplift (height above maximum burial depth) in the Carnarvon Basin. Apparent uplift is given by the difference in depth between the present‐day velocity‐depth trend for a unit in a particular well and the reference trend (unaffected by uplift) of the unit. Apparent uplift results derived from the Toolonga Calcilutite, Gearle Siltstone and Muderong Shale are statistically similar. The consistency of results from carbonate and clastic units suggests that, at the formation and regional scale, overcompaction (i.e. anomalously high interval velocity) in these three units reflects previously greater burial depth, rather than sedimentological and/or diagenetic processes, and validates the use of lithologies other than shale in maximum burial‐depth studies. The proposed magnitudes of apparent uplift are greatest along some of the main structural highs of the Carnarvon Basin. Apparent uplift of approximately 800 m was determined along the Legendre Trend, and along the Barrow Arch. In excess of 900 m of apparent uplift was determined on the Bambra Anticline. The consistency of results from units of Early to Late Cretaceous age suggests that uplift must have post‐dated the youngest (Late Cretaceous) unit analysed.