Australian School of Petroleum

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https://hdl.handle.net/2440/84916
This collection contains Honours, Masters and Ph.D by coursework theses from University of Adelaide postgraduate students within the Australian School of Petroleum. The material has been approved as making a significant contribution to knowledge.

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Browsing Australian School of Petroleum by Advisors "Amrouch, Khalid"

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    4D fracture distribution in the Cooper Basin
    (2014) Wei, Liu; Amrouch, Khalid; Australian School of Petroleum
    The Cooper basin is located in central Australia and is made from non-marine sedimentary rocks which were formed in the Late Carboniferous to Middle Triassic period. The basin was formed due to thermal subsidence, and it can be attributed to prior granite emplacement and uplift due to high heat flow. 4D Fracture Distribution is used to identify the effect of stress orientations caused by different tectonic events in the study area by interpreting fractures and faults from image log data. This study focuses on the section of Cooper Basin in South Australia where an intra-cratonic basin is located and, specifically, where it is entirely overlain by the Eromanga Basin and partially underlain by the Warburton Basin. Stress influences tectonic orogeny in this study area from the Warburton Basin stratigraphy (Pando formation) to the Eromanga Basin (Bulldog Shale) section. The image log data provides information on fractures and faults which indicate that fractures and faults were created by different stress mechanisms through time. Firstly, these fractures are interpreted by stereonet and separated to different sets according to the different formations and stress regimes created. Secondly, these fracture and fault interpretations are related to tectonic events in the Cooper Basin. The tectonic events stress influences are shown in wells location map after data cooperation. In conclusion, tectonic events can be seen which include (listed in older of age) Ross-Delamerian Orogeny, Alice Springs Orogeny, Kanimblan Orogeny, Sakmarian uplift, Hunter-Bowen Orogeny, Late Eocene Oilgocene, Mid Miocene Orogeny and an unknown stress which indicate stress directions and time in the area studied. In some events, stress directions are not unitive because well location may lie near fault belts which could obstruct stress conduction.
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    Four-dimensional fracture distribution in the Cooper Basin using image logs
    (2014) Al Barwani, Khalda; Amrouch, Khalid; Kulikowski, David; Australian School of Petroleum
    An understanding of four-dimensional fracture distribution in the Cooper Basin can be used to optimise the development of well placements and fracture stimulation treatments used in tight gas and shale gas reservoirs. Comprehension of the paleo-stress, current stress, natural fractures and tectonic history of the basin can facilitate the exploitation of hydrocarbon resources in the basin. Natural fracture distribution and orientation were analysed using borehole image logs of 13 wells in the NW of the Cooper Basin. Additionally, in situ stress was evaluated in these locations, and paleo-stress evolution was interpreted based on the structures analysed. Through drilling-induced tensiles fracture and breakouts observed in the image logs, the maximum horizontal stress is oriented WNW-ESE in Patchawarra Trough and Sub-Patchawarra Trough. It has been observed that older and deeper buried formations have a higher number of fractures per thickness ratio (fracture density) than shallow formations. Stress history is recorded in ancient formations; therefore, the age of the formation may affect the number of fractures per thickness. However, the contribution of lithology must be taken into consideration. Rocks with low tensile strength have a more common rock failure than stiffer lithologies. Correspondingly, fine-grained lithologies such as siltstone, shale and mudstone have more natural fractures than sandy lithologies. Various fracture sets were determined in the analysed wells. The NW-SE extension fracture sets of Adelaidean rifting were observed in two wells. This was followed by a compression of Kanimblan/Alice Springs, which is proposed to accompany the WNW-ESE strike-slip regime. The NW-SE compression fracture sets of Permian formations were related to the Sakmarian uplift. The Daralingie uplift is also proposed to be evident in the analysed image logs. Local heterogeneous kinematics are suggested to affect the Daralingie uplift, and it is associated with an extension event. The Hunter Bowen Orogeny ended the deposition of Cooper Basin formations. It has been suggested that E-W compression events affected the basin during the Late Cretaceous. During the Cenozoic Era, E-W to N-S compression might have affected the basin, as shown by the N-S and NE-SW compression fracture system in the analysed image logs. Present-day maximum horizontal stress is attributed to the NW-SE compression and extension fracture sets of the Eromanga Formations.
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    Palaeogeographic mapping and depositional trends of the Patchawarra Formation within the Tenappera Region, Cooper Basin
    (2014) Kobelt, Sam J.; Amrouch, Khalid; McCabe, Peter; Australian School of Petroleum
    The Patchawarra Formation is a coal dominated fluvio-lacustrine environment. These environments have complex geometries and facies distribution is difficult to predict spatially. This study defined palaeogeographic reconstructions using log-signature responses from equivalent chronostratigraphic intervals, modern fluvial analogues and regional TWT isochrons. This resulted in the definition of spatial distribution of fluvio-lacustrine facies throughout the Tenappera region, Cooper Basin, South Australia. 379 wells were correlated into 21 chronostratigraphic intervals wireline log responses. 6 electrofacies were identified from the gamma ray and sonic velocity log motifs. These were combined with modern fluvial analogues to yield 4 facies assemblages. Multiple modern analogues were considered suitable for the Patchawarra Formation in the Tenappera Region. The Ob River, Siberia is considered more suitable for depositional facies whereas the McKenzie River, Northwest Territories demonstrated the influence of a compressional stress regime on fluvial avulsion patterns and styles. In order to map channel belt width within a chronostratigraphic interval empirical relationships from previous studies were applied. By measuring bankfull depth from well data an estimate of channel belt width is obtained. 532 bankfull measurements were taken giving a maximum bankfull depth of 8.2m, a minimum of 1.4m and a mean value of 5.1m. Channel belt width ranges were then estimated by applying bankfull population statistics to applicable linear regression curves. Channel belt width calculations gave a range of variability from 76m to 3625m, with an average channel belt width range from 1639-1908m. For the interpreted Patchawarra Formation intervals there were eight populations with similar channel belt ranges. High resolution palaeogeographic reconstruction of the Patchawarra Formation within the Tenappera Region allows for better prediction of facies distribution. There are two distinguishable periods of fluvial deposition deposition in the upper and lower Patchawarra Formation. Ultimately, the paleogeographic maps aid assessment of field prospects by defining depositional channel fairways which control reservoir distribution. These techniques could be applied to other fluvial dominated petroleum systems.
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    Pre-salt playing hydrocarbon trap evaluation within the Callanna Group in the eastern Officer Basin, South Australia, from recent drilling results
    (2014) Sahuri; Amrouch, Khalid; Mitchell, Andy; Australian School of Petroleum
    The Officer Basin represents one of the last remaining onshore frontier exploration areas in Australia. It has potential to contain several very large oil fields within horsts capped by thick salt. The pre-salt trap within the Callanna Group in eastern Officer Basin has never been studied because of lack seismic coverage and deep well controls. The Callanna Group sequence upward consists of Pindyin Sandstone and Alinya shale-salt-dolomite. Some oil shows have been correlated to Alinya shale source rock. The full sequence was intersected by three wells drilled recently, one in the eastern and two wells in western parts of the basin. These intersected units are well-correlated with its type section based on lithology, superposition and wireline logs. The Pindyin Sandstone shows primary porosity and permeability and the overlying salts are thick and seismically mappable. Though these wells failed to find hydrocarbon accumulations, they have significantly improved the understanding the petroleum potential in the basin. The salt related structures in eastern Officer Basin are not as common as in Western Officer, Amadeus, Flinders Ranges, Eastern Siberia and South Oman Basins. The salt in eastern Officer Basin has been mobilized, while the salt in the western part of the basin is relatively stable. Salt features have been identified including salt anticlines, salt thickening and salt withdrawal collapse structures. At least seven salt anticlines are present but the outlines are uncertain because of poor seismic quality and coverage. They might have potential traps for the younger reservoir rocks e.g Murnaroo and Tarlina Sandstone. This study focuses on pre-salt hydrocarbon trap identification and evaluation (Pindyin Lead) through seismic mapping. Four structural time and depth maps have been generated and a total of 24 Pindyin Leads identified. The leads were classified into four groups: 1) a simple anticline, 2) drag rollover or anticline associated with reverse fault, 3) a gentle anticline or rollover associated with tilted graben due to an igneous intrusion or normal fault reactivation (reversed) and 4) Pindyin on-lapping against the sealing faults bounding the graben. The best pre-salt structural trap would be the simple anticline which has four way dip closure but it is not common in the basin and very deep to the target. The exploration should focus to identify this type of pre-salt play down dip the Murnaroo Platform where the depth to the Pindyin Sandstone is reachable. The second best Pindyin Lead is a gentle anticline in Manya and Wintinna Troughs, but it was defined by inadequate seismic controls. The most common pre-salt structural trap is a drag rollover or anticline associated with reverse faults, but it has high risk of the fault breach and poor reservoir rocks. Further study is needed to assess the trap closures, fault seal integrity, hydrocarbon generation and migration into trap.
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    The unconventional petroleum potential of the Officer Basin, Australia
    (2013) Revie, Daniel J.; Holford, Simon Paul; Amrouch, Khalid; Australian School of Petroleum
    The Officer Basin is a Neoproterozoic Basin located in Central Australia. This study looks at the unconventional prospectivity of the source rocks in the depocentres of the Officer Basin. The Savory, Gibson, Yowalga, Gibson and Lennis sub-basins are located in the Western Australian section of the Officer Basin. The Birksgate Trough, and the Munyarai, Tallaringa, and Manya Troughs, are located in the South Australian section of the Officer Basin. The Munyarai Trough contains the Observatory Hill Formation, the most prospective source rock in the Officer Basin. In the region of the Marla Overthrust Zone on the northern margin of the Munyarai Trough, the Observatory Hill Formation is the most prospective region for shale gas continuous accumulations. The thrust faulting in the Marla Overthrust Zone, and also in the Yowalga Sub-Basin, in combination with salt diapirism in these zones, poses a risk to the lateral continuity of a continuous accumulation of shale gas in these regions. The Officer Basin contains pre-Devonian source rocks which are devoid of plant material, containing algal-sourced hydrocarbons. Triaromatic hydrocarbons such as methylphenanthrene can be exploited as a measure of maturity and distribution, and have been used to map the maturity of the source rocks in the basin. The sampled data available in the underexplored Officer Basin indicates that the basin is a high risk exploration target for continuous gas accumulations. The sampled data indicates that the Officer Basin shale formations do not meet the minimum requirements outlined by the U.S. Geological Survey (USGS) for highly productive shale gas. However due to the limited sampling and exploration undertaken in the Officer Basin, there may exist other regions outside of those sampled that have the characteristics that do meet the USGS minimum requirements for highly productive shale gas systems. Three key findings of this investigation include: • The Officer Basin is a very high risk exploration target for shale gas continuous petroleum accumulations, and sampling has not been shown to meet all of the USGS minimum requirements for a highly productive shale gas system. • The Yowalga Sub-basin and the Marla Overthrust Zone contain thrust faulting and salt piercement structures related to halotectonics, affecting the lateral distribution of any continuous accumulations that may occur in the region. • The Officer Basin is underexplored, particularly in the Savory, Lennis, Gibson, Waigen and Birksgate Sub-basins, and should not be excluded from potentially hosting formations which may meet the USGS minimum requirements of a shale gas system.