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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Open Access
A 3-D seismic interpretation of the Palaeo-Fluvial geomorphology of the off-shore Gippsland Basin utilising seismic attibutes
(2015) Neden, Luke; Bunch, Mark; Australian School of Petroleum
The stratigraphy of the offshore Gippsland Basin exhibits extensive channelization features which developed during periods of lowstand that lowered base level causing incision and sediment bypass. These features are well documented at shallow depths but deeper in the stratigraphy the extent and geometry are less well defined. Traditional structural traps in the basin are becoming depleted and these features represent possible new targets. Equally their presence where down-cut into sealing lithologies represent a risk to the seal integrity/capacity overlying potential reservoirs concerned with CO2 storage. Seismic attributes, specifically coherence (variance) and sweetness, are co-rendered and mapped on stratal slices of the Gippsland Megasurvey 3D seismic dataset to enhance seismic images and establish the extent and geometry of channelisation in the offshore Gippsland Basin. These findings may help to identify new targets and determine potential for greenhouse gas storage, as well as helping to account for seismic anomalies that have been responsible for the misplacement of drilling targets in the past.
Open Access
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.
Open Access
Characterisation of carbonate cemented zones in the Paaratte Formation of the Victorian Otway Basin and Bass Megasequence of the Bass Basin using wireline log data
(2014) Armener, Kapila J.M.; Daniel, Richard Francis; Bunch, Mark; Australian School of Petroleum
The identification and modelling of carbonate cemented zones represents one of the many challenges facing the world leading Carbon Capture and Storage (CCS) CO2CRC Otway Project in Victoria. Carbonate cemented zones are low permeability dolomite-dominated zones that form at the meteoric-saline water interface within winnowed tidal bar sandstones deposited in deltaic-marginal marine environments. Successful identification of these zones from wireline log data requires the creation of empirical tools that combine statistical analysis with geological interpretation. The Mean-Probability Log and the Vshale Facies Log are two empirical tools that, when combined, can successfully identify carbonate cemented zones from well log data. The Mean-Probability Log is derived from available well data contained at CRC-2 which includes the CCA_20 log (Elemental Capture Spectroscopy) and CarbCmnt log (carbonate cemented zones prediction log). These logs, combined with conventional raw and derived logs (Gamma, Sonic, Neutron, Density, Shallow Resistivity, Deep Resistivity, and Ratio) were used to create binned distributions required for a probability distribution model. Probability values from the model were incorporated into individual carbonate cement predictions logs for each of the raw and derived logs. An average of these logs resulted in the creation of a carbonate cemented prediction Mean-Probability Log. Flexibility of the Mean-Probability Log revealed only a variance of 13 samples when compared to Mean-Probability Logs lacking one of the key logs (e.g. Gamma). Calculation of a statistically derived cutoff was incorporated using the mode, standard deviation and a fixed spread (variance). Creation of a Vshale Facies Log was undertaken to assist accuracy of the Mean-Probability Log in predicting carbonate cemented zones within winnowed sandstones. The facies component of the log was derived from reclassification of an existing core-derived facies log used at CRC-2, whilst the clay-content (Vcl) of the log was derived from an existing Petrolog algorithm used in the Darling Basin of NSW. A cutoff value for CRC-2 (Vcl value of 0.6) was established for sandstones that are hosts for known carbonate cemented zones. Both the Mean-Probability Log and the Vshale Facies Log were successfully applied to both selected Otway Basin (onshore and offshore) and Bass Basin wells. Carbonate cemented zone analysis revealed a total of 126 carbonate cemented zones in onshore Otway Basin, 53 in offshore Otway Basin, and 7 in the Bass Basin. Interpretation of carbonate cemented zone results revealed a decrease in thickness and increase in clay-content from the Port Campbell Embayment to Shipwreck Trough in the Otway Basin, and a localised accumulation along the Pelican and Dondu Troughs within the Bass Basin.
Open Access
Comparison of seismic migration strategies: The Ceduna Sub-basin of the Great Australian Bight, South Australia.
(2011) Cooke, Frances A; Mitchell, Andy; Australian School of Petroleum
Migration is an important process applied to seismic reflection data to improve the quality of the sub-surface image. There are a variety of migration techniques available, with the choice of imaging greatly influenced by the complexity of the sub-surface. 3D seismic data acquisition was carried out in the Great Australian Bight in 2006 by Woodside. An area of 400km² – the ‘Trim 3D’, within the area of prime coverage in the Ceduna Sub-basin was selected for processing by PGS on behalf of BP in January 2011. Two integral pre-stack migration methods were applied to the Trim 3D volume datasets. The migration datasets employ Controlled Beam migration (CBM) and Kirchhoff summation migration (KSM) techniques. The advanced technique of PGS proprietary CBM includes more dips in the algorithm and has the ability to run at higher frequencies. This advanced technique is designed to target the shallow section of the Beam volume. The output amplitudes from the CBM are known to be poor; therefore, KSM is used as a comparison to ensure that all appropriate events are present. The inconsistencies observed between the two processed products forms the basis of the investigation. Seismic interpretation of faults and horizons were carried out on the two datasets. The fault image was observed to be clearer on the Beam coherency slices with a more coherent fault shadow zone. A greater number of fault plane reflections were also present on the Beam volume. The KSM displayed greater structural detail with improved imaging of the minor faults. It is hypothesised that structurally the Beam and Kirchhoff products are very similar. This is true for the positioning of faults in one volume relative to the other, though products were dissimilar in the structural imaging of the smaller faults. The improvement to signal to noise ratio in the CBM results in greater lateral smoothing of the seismic reflections. This not only affects the detail of the minor faults but the stratigraphic detail of channels and other features such as potential patch reefs. The coherency volume attribute was found to be the most useful attribute for the stratal and stratigraphic imagery. The complex trace attribute ‘slope of reflection strength’ also gave potential insight into the use of attributes for facies analysis. Limited well penetration in the Ceduna Sub-basin has resulted in a dependence on detailed seismic facies. The image quality of the KSM is optimal for geological interpretation and is more likely to influence future processing in the Ceduna Sub-basin.
Open Access
Controls on porosity in the Pab Sandstone, Kirthar Basin, Pakistan
(1996) Enman, Travis; National Centre for Petroleum Geology and Geophysics
Open Access
Controls on shallow marine reservoir development, Jansz-IO Field, Northern Carnarvon Basin
(2015) Plotnek, Elizabeth K.; Kaldi, John George; Rarity, Frank; Australian School of Petroleum
The Jansz-Io field is a gas-bearing sandstone reservoir in the Northern Carnarvon basin off the North West Shelf of Australia. The field is part of the prolific Greater Gorgon gas field and has an exploration history dating back to 1953. The aim of this study is to log the available core and integrate other datasets such as wireline and biostratigraphy to establish geological and stratigraphic models that can give fresh perspectives and insights into this field and develop these learnings to apply to other shallow marine clastic reservoirs. The results of the study show a coarsening upwards package of siltstones and sandstones that indicate an increase in energy and shallowing water depths. The WAVE classification was used to define the respective wave, tidal and fluvial influences, in combination with ichnology, to produce a range of possible depositional environment outputs. The proposed model for the deposition of the Jansz sandstone reservoir is an offshore transition at the most distal, above storm wave base (50-75 meters) and below fair-weather wave base (5-15 meters). The most proximal deposition was in the upper shoreface to foreshore where waves broke on the beach in water depths less than 5 meters. The level of uncertainty associated with the geologic model for the reservoir has implications for future development and production.
Open Access
Controls on the morphology of fluvial and tidal influenced channels in the Gulf of Carpentaria, Australia.
(2013) Okafor, Rosemary N.; Nanson, Rachel; Rarity, Frank; Australian School of Petroleum
The influence of wave, tide and fluvial processes interact to control sediment erosion, transport and deposition in clastic coastal environments. This results in mixed-process coastal systems, which can form good quality, yet geometrically complex reservoir deposits. Channels in modern analogue mixed process environments provide useful insights into how wave, tide and fluvial processes affect paleochannels and can aid subsurface stratigraphic correlation and palaeoenvironmental reconstruction. The Gulf of Carpentaria is an epicontinental sea which formed as a result of sea level rise during the last marine transgression. Holocene deposits have prograded over low gradient bathymetry and display a range of channel forms. The channels that traverse these coastal plains cannot be satisfactorily characterised by simple morphological classification. They have morphologically complex patterns which have developed in response to the seasonal variations in fluvial, tide and wave energy. A numerical examination of the effects of fluvial, tidal and wave energy on the geometry and morphology of 70 single and distributary channels in the Gulf Carpentaria was undertaken using desktop based statistical analyses. Catchment area was used as a proxy for fluvial discharge in these largely ungagged catchments while wave height and tidal range was applied directly from available gauged data. These channels were divided into two subsets based on whether their channel mouths were best described by linear or exponential trends and by the channels being either distributary or single channels. These four groups were then tested separately to assess their geometrical characteristics, including the rate of decrease in channel width downstream of equi-width (fluvial) reaches, and the wave, tide and fluvial ratios. Of the analysed channels 65% where found to have a linear width profile, and their parallel banked profile was further enhanced by a strong positive correlation with catchment which exhibited very low slope of distance to equi-width. These parallel banked (linear) channels were found to be fluvial dominated while the other 35% had an exponential width profile with their entrance width visually exhibiting a strong funnelling characteristic, and the channels having a wider entrance width and a longer distance to equi-width. These exponential channels are more tidally dominated. There was a general decrease in tidal energy and wave influence with increase in distance to equivalent width in the channels, this relationship implies that a channel's distance to equivalent width can be used to identify where the fluvial energy is least effective moving downstream indicating that another process is dominant which is usually tidal or in some cases wave energy. It is also shown that there are characteristic relationships between geometric variables like entrance width at the channel mouth and the rate of decrease in channel width downstream of equivalent - width (slope) with proxies of fluvial influences and tidal range. These relationships may overlap as a result of the complex morphodynamic feedbacks between fluvial discharge, tidal propagation and wave height in this tropical monsoonal environment.
Open Access
Depositional environments of 3D surveys for potential CO2 sequestration in the Northern Caswell Sub-basin, Browse Basin, North West Shelf, Australia
(2014) Thurlow, Brenden James; Australian School of Petroleum
The Browse Basin is a northeast-trending, Palaeozoic depocentre on Australia’s North West Shelf. It covers an area of approximately 140,000km², contains in excess of 15km of Palaeozoic to Cenozoic sediments and host significant gas and condensate reserves. Reactivation and inversion of older structures, as well as the generation of anticlines within the Browse Basin has occurred. The Browse Basin holds two very large Miocene inversion structures, the Lombardina and Lyner structures, interpreted to be transpressional anticlines that continued to grow throughout the Late Miocene (Keep, 1998). The reservoir/seal thicknesses are similar to what would be expected of those deposited in a regressive/lowstand environment, with thicker accumulations of strata most likely to be encountered basinward, or in this case to the west/northwest. The prospect that an adequate system exists for the capture and storage of CO₂ within all three surveys cannot be adequately determined from this study. All three of the 3D surveys showed valid reservoir and seal pairs exist, with the thicknesses varying greatly. The lack of any structural high within the Canis and North Browse 2 surveys despite the presence of a valid reservoir/seal pair automatically precludes these survey areas from being considered for a potential CCS project.
Open Access
Detecting the occurrence of dolomite cemented zones in the Otway Gippsland Basins
(2014) Al-Shukaili, Amira; Bunch, Mark; Daniel, Richard Francis; Australian School of Petroleum
Dolomite cemented zones have been recognized in both Otway and Gipssland Basins. These cemented zones have significant effects on the reservoir performance as they can degrade or enhance reservoir sweep. The CO2CRC CO₂ sequestration project in Otway Basin may be affected by these carbonate cemented zones, where it has been detected in CRC-2 and CRC-1. Therefore, the aim of this project is to generate an empirical model using well log data to detect the dolomite cemented zones in the Otway and Gippsland Basins. To achieve this goal, log data have been analyzed to firstly create a motif of cemented zones in the on-shore lower Paaratte Formation of Otway Basin. Then, verify cemented zones in the Casino Field of the Shipwreck Trough (offshore Paaratte Formation). As a result, the dolomitisation interval motifs will be generated from Paaratte Formation of Otway Basin and will be used to detect the cemented zones in the Gippsland basin.
Open Access
The effect of stress regime, pre-existing natural fracture geometric and hydraulic parameters and stimulation design parameters on fracture stimulation and fluid flow dimensions in the Otway Basin
(2014) Benson, Robert; Abul Khair, Hani; Australian School of Petroleum
The development of unconventional oil and gas resources is becoming increasingly important as conventional reserves start to decline. In order to make the recovery of unconventional resources from low permeability reservoirs economically viable, the process of hydraulic fracturing is critical. At present, only engineering measures are implemented in the design phase to enhance the stimulation process as there is very little understanding of how the geometry and properties of pre-existing natural fractures influences hydraulic fracturing. This study analyses the effect of the in-situ stress regime and pre-existing natural fracture intensity, orientation, hydraulic parameters and stimulation treatment design parameters on fracture stimulation and fluid flow dimensions. Wellbore image logs from 6 wells in the Otway Basin were used for the analysis of fracture orientation, intensity and size distribution. This was used to generate a model of the natural fracture network for simulation and evaluation of pressure transient testing and fracture stimulation. Discrete fracture network modelling is an effective approach for evaluating hydraulic fracturing and fluid flow dimensions in naturally fractured reservoirs. It was found that hydraulic fractures do not necessarily propagate as a symmetrical bi-wing fracture exactly parallel to the direction of maximum principal stress. Propagation occurs in the direction of maximum principal stress, in a complex manner, involving initiation, connectivity and reactivation of the fractures. The microseismic-event density, percolation zone size and stimulated reservoir volume, as a result of fracture stimulation is directly correlated to pre-existing natural fracture intensity, fracture compressibility and stimulation pump rate, pump pressure and slurry density. Pressure derivatives show very different characteristics and therefore fluid flow dimensions with different fracture intensity and fracture orientation.
Open Access
The effect of the stress regime and pre-existing natural fracture densities, orientations and hydraulic parameters on fracturing stimulation and fluid flow dimension in the Cooper Basin
(2014) Ibraheem, Kazeem A.; Abul Khair, Hani; Australian School of Petroleum
Fracture stimulation has played a key role in making oil and gas unconventional resources economically viable and has contributed towards domestic energy production. This has (to some extent) been a very similar situation in the Moomba field of the Cooper Basin. In order to further increase the gas fluid flow for commercial production, it is important to understand the stress state and pre-existing natural fracture densities, orientations and hydraulic parameters which are the critical parameters influencing the shale gas production from unconventional reservoirs. Pressure transient tests analysis (to test the reservoir deliverability and stimulation treatment evaluation) conducted on discrete fracture networks (DFN) (generated from image log data) showed that change in diffusivity, storativity, mobility and transmissivity of the reservoir fluid due to the changes in the hydraulic parameters will determine the relative lag time of the fracture radial and linear flow regimes on the pressure derivative plot and the well test speed. This also affected the radius of investigation growth with respect to the fracture boundary. Fracture stimulation was conducted focusing on the effects of geomechanic properties (elastic modulus, fracture size, and shear stress) of unconventional reservoir rocks and controllable fracture stimulation operation parameters (flow rate, pump pressure, and slurry density) on stimulated reservoir volume (SRV) and total percolation area. High elastic modulus (HEM) rock property was found to be the critical parameter affecting this reservoir performance. Further fracture stimulation studies were conducted focusing on the relationship between the controllable fracture stimulation operation parameters and HEM rock property. High flow rate (HQ) or low pump pressure (LPP) was found to be the controllable parameter that would further enhance the gas production from an unconventional reservoir with HEM. This study, therefore, suggests that fracture densities and orientations (fracture distributions) played a major role in the enhancement of SRV and total percolation area. Fracture density improved the connectivity of the stimulated fractures (and hydraulic fractures) for fluid flow and hence the total percolation area. The scenarios that resulted in low SRV and total percolation area were predominantly caused by low fracture density and increased pump pressure and this situation caused a “tip screen-out” effects around the wellbore.
Open Access
Evaluating structural controls on Eocene igneous activity in the Ceduna Sub-Basin, Bight Basin offshore South Australia
(2014) Prasongtham, Pattarapong; Holford, Simon Paul; Mitchell, Andy; Australian School of Petroleum
The presence of Middle Eocene extrusive and intrusive rocks within and overlying the Late Cretaceous to Holocene section in the Ceduna Sub-basin presents a potential risk to the associated petroleum systems, especially in exploration blocks EPP44 and EPP45. Igneous activity could possibly have reactivated normal faults in the area, resulting in the elimination of pre-existing fault-related traps. Therefore, igneous activity after hydrocarbon migration and accumulation presents an additional risk that needs to be understood. 2D seismic data was utilised in this study to assess the impact of Eocene igneous activity on hydrocarbon prospectivity in the Ceduna Sub-basin, and in particular, to evaluate the role that normal faults have played in permitting the transfer of magma to shallow crustal levels. Igneous features were mapped. Two-way time maps were generated for the bases of the Dugong, Wobbegong and Hammerhead Supersequences. Volcanogenic mounds, hydrothermal vents and sills identified on the two-way time maps appear to be spatially linked with normal faults, as they display consistent distribution along the WNW-ESE to NW-SE fault strikes. 80% of mapped volcanogenic mounds and 29% of interpreted hydrothermal vent are related to normal faults. Timing of igneous activity was likely to have occurred “at” or “after” with the last normal faulting event, based on relative chronological analysis between igneous intrusions and normal faults. All results suggest that the magma probably made its way up to shallow crustal levels by using pre-existing normal faults pathways. Fault-dependent traps in block EPP45 and the eastern part of block EPP44 appear to be at high risk of faults reactivation, due to the igneous activity in these areas. The future petroleum exploration program in the central and eastern part of Ceduna Sub-basin should take the impact of igneous activity on trap integrity into account, since fault-dependent traps are the main prospects.
Open Access
A facies atlas for the wave to tide-dominated Gulf St Vincent (South Australia)
(2015) Swiatek, David; Nanson, Rachel; Rarity, Frank; Australian School of Petroleum
Marginal marine depositional systems represent a significant proportion of the world’s known and exploitable hydrocarbons; however, they are complex environments containing varying modes of deposition and heterogeneity. Marginal marine process classifications have historically lacked adequate interpretation of the variability in mixed-process systems. Modern analogues provide the most accurate planform geometries of marginal marine elements for input into reservoir models. Observations made during deposition of similar systems can supplement seismic, core and geological outcrop datasets, thus improving 3D models. This research develops a facies atlas for Gulf St Vincent as a modern analogue, examining process variability of marginal marine elements resulting from wave and tide-dominant processes. Gulf St Vincent is a shallow, inverse estuary in South Australia that connects to the Southern Ocean. Gulf St Vincent was flooded by the most recent Holocene post-glacial marine transgression. The sediments that form the marginal marine deposits accumulated along the eastern coast of Gulf St Vincent are interpreted to be derived from the reworking of the gulf floor as the sea level transgressed to its present location. Analysis of data collected along the eastern coast of Gulf St Vincent displayed evidence that wave height and energy, along with tidal range, control the geomorphology of the shoreline and sediment heterogeneity. Depositional environments changed as the shoreline transitioned from wave to tide-dominated processes. The carbonate-rich sediments in the tide-dominated northern region indicate they were very different depositional environments from the homogeneous quartz-rich medium-grained sands produced in the wave-dominated areas to the south. The dominant process controls vary from wave through tide in a northerly direction.This research has determined that four types of depositional environments dominate the eastern coastline of Gulf St Vincent, which were linked to process controls and characterised by their shore face slope, sedimentary deposits and architecture. They were linked to distinct arrangements of depositional elements with their own sedimentary signatures. This study also suggests that the observed carbonate sediments can be classified using the Ainsworth et al. (2011) and Vakarelov and Ainsworth (2013) marginal marine mapping and classification systems. The facies atlas presented herein has the potential to inform hydrocarbon reservoir modellers by providing data on the internal architecture of 2D mapped depositional elements.
Open Access
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.
Open Access
Geocellular modelling and connectivity analysis of a tide-influenced channel belt system: example from the Mitchell River Delta, Gulf of Carpentaria, Australia
(2014) Al Quwaitii, Reham Said; Amos, Kathryn; Holford, Simon Paul; Australian School of Petroleum
The interaction of tidal and fluvial processes in marginal marine settings, particularly tidally influenced channel systems, can produce profound lateral and vertical facies heterogeneity, in forms such as Lateral Accretion Packages (LAPs) and Inclined Heterolithic Stratification (IHS). LAPs form at the convex banks of sinuous channels, and can be composed of either homogeneous or heterogeneous deposits. Within tidal reaches, they are often comprised of IHS deposits. IHS deposits are inclined alternating shale and sand layers that form by laterally accreting fluvial-estuarine point bars. Understanding the 3D distribution of tidally influenced channel architectures in modern channel systems has important implications for the effective modelling of subsurface channel reservoir distribution, connectivity and fluid flow. In this research, 3D geocellular modelling of a selected modern point bar from the Mitchell River system, Gulf of Carpentaria (GoC), Queensland, Australia, is used to predict heterogeneity and connectivity associated with a tidally influenced channel reservoir system. The modelling workflow consisted of four main stages: (a) data integration, (b) mapping, (c) geocellular modelling and (d) connectivity assessment. Analysis of high-resolution satellite imagery merged with Shuttle Radar Topography Mission Digital Elevation Models data for an area of 14.57 km × 2.34 km allowed direct mapping and measurement of dimensions and orientation of the stratigraphic architecture of the selected point bar geometry. Core and auger well log data and a stratigraphic cross section oriented perpendicular to the channel axis were used in order to constrain the stratigraphic architecture and the facies distribution. Five facies were identified in the studied point bar strata, including Lag Sand Deposits with rippled sandstone 2.5 m thick, which is common in upstream locations on the point bar, and heterogeneous sand and mud facies. Inclined heterolithic mud deposits (IHS) are confined to the upper 3 m of the point bar. As the focus of this project is the impact of IHS on reservoir connectivity, a new approach was proposed to resolve the heterogeneity associated with tidally influenced channel systems, by developing three geological models based on the presence and continuity of IHS deposits (the products of fluvial and tidal interaction processes). Connectivity analysis of the three realisations showed marked contrast between models using point bar geobodies. The tide-dominated, fluvial-influenced channel system represents the worst reservoir connectivity in the subsurface, as the volume contains considerable bodies of mainly mud facies. Although there are significant objects in this point bar model, the majority of these bodies are very small and supposedly form 75% mudstone of the total volume. In scenario two (Ft channel system; fluvial dominated, tidally influenced channel system), the model suggests fluid flow will preferentially concentrate in the lower part of the point bar, where clean sand sediments form a continuous body. The geo-volume in realization three (F channel system; fluvial dominated channel system) reflects the connectivity of the channel comprised of just the point bar object, which can represent best reservoir continuity and limited compartmentalization. Thus, reservoir quality increases as the fluvial process in the channel system becomes more dominant. We recommend that further field work, such as a new stratigraphic cross sections, should be obtained parallel to the channel axis in order to capture 3D heterogeneity within tidally influenced channel systems, and that the Fullbore Formation Microimager tool should be used to obtain the corrected inclination of IHS deposits.
Open Access
Geomechanical modelling of stress magnitude and orientation across fault and its relation to hydraulic fracturing
(2012) Karatela, Ehtesham; Australian School of Petroleum
With intense exploration around the world, easily extractable hydrocarbons are getting more and more difficult to find. Major conventional hydrocarbon accumulations have been targeted and are being produced; but increased world’s consumption has led petroleum exploration and production industry to consider exploiting targets that were not believed to be economical. Tight reservoirs include shale gas, shale oil, coal seam gas (CSG) and tight sands. This concept has changed the conventional view of shales from being source and seal rock to unconventional perception –as reservoir. These reservoirs have minimal porosity and permeability which is not sufficient to produce at economic rates. Developing these reserves may require hydraulic fracturing to create a predictable network of fractures with height of several hundred feet through which hydrocarbons can easily flow towards borehole. Even if these reservoirs are fracture stimulated at best of the knowledge and skills; production from two wells in the same field is never the same. For a successful fracturing treatment, it is necessary to understand impact of existing fractures, faults and stress regimes in the subsurface. Geologic structures influence the stress field locally and show deviation from the regional trend of stress pattern. This study utilizes geomechanical modeling with static elastic moduli to depict stress magnitude and orientation around faults. For the purpose, stress magnitudes estimated by Reynolds et al., (2006) are used. Strike-slip stress regime prevails in at the depth interval selected. A thorough study using different lithologies, σH azimuth and fault size is carried out. Stress concentrate at the fault tips on opposite quadrants of the fault tips. Fluctuation in stress magnitude increases with increase in fault size. However, the variation diminishes after fault size of 1500 meters. These models help in understanding the orientation of fractures during hydraulic fracturing and help to recognize stress barriers that may affect production from an unconventional reservoir.
Open Access
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.
Open Access
Palaeogeographic mapping of the basal Epsilon Formation, southern Cooper Basin, South Australia: what are the controls determining the organic enrichment of the uppermost part of the Murteree Shale?
(2014) Fraser, Brayden D.; McCabe, Peter; Mitchell, Andy; Australian School of Petroleum
To support the voracious worldwide demand for energy resources into the future, a significant focus by energy companies is likely to be on the exploration and development of unconventional resources. One such unconventional resource that has started to attract more attention in recent times is the extraction of 'shale gas' - natural gas that is trapped within fine-grained sedimentary lithologies. Of particular interest is the Munkarie gas field, located in the southern Cooper Basin, South Australia. Within this field, the Munkarie-2 and Munkarie-4 wells contain a relatively high Total Organic Carbon (TOC) concentration from the top of the Murteree Shale. This project was charged with determining what were the controlling factors regarding the organic richness in the uppermost part of the Murteree Shale. Ironically, it is the overlying Epsilon Formation that may possibly determine what may be the cause of the 'sweet spot' for the Murteree Shale. Core logging was performed at Munkarie-2 and Toolachee-17 to gain a better understanding of the core. This confirmed that part of the Munkarie-2 cored interval was a barrier island complex that existed in a microtidal lacustrine environment - the Murteree Lake. Using Schlumberger Petrel, both 20 and 30 models were created from a total of 420 wells within the study area. The large quantity of data helped construct an assortment of geocellular models, subsea depth maps, isopach and sandstone percentage maps, culminating in the construction of a palaeogeography map. The palaeogeography map is a palinspastic restoration for the basal segment of the Epsilon Formation, exposing the depositional environments and reconstructing the fluvio-deltaic processes that were operative at the time. As deltaic progradation occurred, it is hypothesised that fluvial run-off from nearby floodplains created prosperous conditions for bacteria and algal organisms. Thus, a semi-enclosed lagoon caused by the existence of the barrier islands may have become anoxic due to the prolific multiplication of the organisms. Nourished by a nutrient supply from nearby fluvial systems, a proliferation of algae may have led to a dramatic increase in organic carbon on the lake floor. This study is proposing that the presence of barrier island complexes, situated in the basal part of the Epsilon Formation, could be connected to a localised organic TOC enrichment zone that has been recognised in the upper Murteree Shale (just below the lithostratigraphic boundary of the Epsilon Formation).
Open Access
Palaeogeography of the Roseneath Shale in the south-western Cooper Basin, South Australia.
(2013) Matali, Muiz Hj; Menpes, Sandy; Australian School of Petroleum
The Cooper Basin comprises the Early Permian non-marine sediments of the Gidgealpa Group including the Roseneath Shale which is the major focus of the study. Lithologically, the Roseneath Shale has been identified as the thick lacustrine shale unit which was deposited in a large freshwater lake (the ‘Lake Roseneath’) extending across the basin. Previous studies were more focussed in the major troughs where the thickest units were observed such as the Nappamerri Trough. This study is concentrated on the Patchawarra Trough towards the southwestern of the basin to understand the possibility of facies variations in the study area. The combination of wireline log analysis, sequence stratigraphy and palynology permitted the study to create a new chronostratigraphic framework for the Roseneath Shale. To achieve this, palynological data was used to confine the APP41 interval of the Roseneath Shale in the regional wireline correlation. A flooding surface was interpreted within the unit leading to identification of two distinct time-equivalent units; APP41a and APP41b units. The interpreted wireline cross section data was utilised for the construction of isopach maps and lithofacies maps. The isopach maps were used to understand the sediment distribution and to recognise thickness trends whereas the lithofacies maps were used to predict the source of the sediment supply and the regional facies variations. Core data of Moomba 065 was studied to understand the Epsilon-Roseneath transition. Derived from all the analysed data, palaeogeograhic maps for the two subunits were reconstructed. Based on the wireline log analysis, five depositional environments were recognised in the study area and these include lacustrine, prodelta, distributary mouth bar, distributary channel and coal swamp deposits. The APP41a interval represents a delta progradation from the north/northeast into the Lake Roseneath owing to an increase in sediment supply. The APP41b interval marks the increase in lake level and transgression of the lake toward the north. Regional subsidence and differential subsidence are the possible controls on the stratigraphic framework of the Roseneath Shale. Sedimentation of thin Roseneath Unit on the ridges along the Gidgealpa-Merrimelia-Innamincka Trend was proposed based on thickness trend shown in the isopach maps as well as the presence of preserved unit in some wells along this trend.
Open Access
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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