Australian School of Petroleum
Permanent URI for this community
The Australian School of Petroleum is Australia's pre-eminent centre for education, training and research in petroleum geoscience, engineering and management.
The Australian School of Petroleum was formed by the merger of the University's School of Petroleum Engineering & Management and the National Centre for Petroleum Geology & Geophysics.
News
Australian School of Petroleum
THE UNIVERSITY OF ADELAIDE
SA 5005
AUSTRALIA
Email: asp@adelaide.edu.au
Telephone: +61 8 8313 8000
Facsimile: +61 8 8313 8030
THE UNIVERSITY OF ADELAIDE
SA 5005
AUSTRALIA
Email: asp@adelaide.edu.au
Telephone: +61 8 8313 8000
Facsimile: +61 8 8313 8030
Browse
Browsing Australian School of Petroleum by Title
Now showing 1 - 20 of 946
Results Per Page
Sort Options
Item Metadata only 2001 exploration review(APPEA, 2002) Mackie, S.I.Exploration expenditure in 2001 was the highest ever and successful wildcats were drilled in all major petroleum basins. Much of the success can be attributed to the increasing use of 3D seismic data prior to drilling. Although 2001 saw the first onshore exploration permits awarded since the mid-90s the resolution of Native title still remains the highest concern for onshore exploration. Decreasing 2D acquisition may indicate failure to be exploring in frontier areas. The discovery of the Thylacine and Geographe fields in the offshore Otway recharged exploration on Australia's southern margins. The success of Cliff Head-1 in the offshore Perth Basin demonstrates that small independents can still play a major role in Australian exploration.Item Metadata only 3D geological modeling of the Trujillo block: insights for crustal escape models of the Venezuelan Andes(Elsevier, 2012) Dhont, Damien; Monod, Bernard; Hervouet, Yves; Backe, Guillaume Valery Raymond; Klarica, Stephanie; Choy, Jose E.; Australian School of PetroleumItem Metadata only 3D geological modelling of potential geothermal energy reservoirs in the Flinders Ranges, Australia(World Press, 2010) Backe, G.; Giles, D.; Baines, G.; Amos, K.; World Geothermal Congress (2010 : Bali, Indonesia)The Flinders Ranges in Australia are located within the well defined South Australian Heat Flow Anomaly. Anomalously high heat flow is recorded in this area, offering world-class opportunities for the development of significant and economically viable Enhanced Geothermal Systems (EGS). Here, we show how a combination of potential field data interpretation and modelling with surface and sub-surface geological constraints in addition to finite element thermal models, enable us to to best delineate potential geothermal reserves. This study could be used as a benchmark for any EGS exploration in the world.Item Metadata only 3D geomechanical modelling for CO₂ geologic storage in the Dogger carbonates of the Paris Basin(Elsevier Ltd, 2009) Vidal-Gilbert, Sandrine; Nauroy, Jean-Francois; Brosse, Etienne; Australian School of PetroleumCO2 injection into a depleted hydrocarbon field or aquifer may give rise to a variety of coupled physical and chemical processes. During CO2 injection, the increase in pore pressure can induce reservoir expansion. As a result the in situ stress field may change in and around the reservoir. The geomechanical behaviour induced by oil production followed by CO2 injections into an oil field reservoir in the Paris Basin has been numerically modelled. This paper deals with an evaluation of the induced deformations and in situ stress changes, and their potential effects on faults, using a 3D geomechanical model. The geomechanical analysis of the reservoir–caprock system was carried out as a feasibility study using pressure information in a “one way” coupling, where pressures issued from reservoir simulations were integrated as input for a geomechanical model. The results show that under specific assumptions the mechanical effects of CO2 injection do not affect the mechanical stability of the reservoir–caprock system. The ground vertical movement at the surface ranges from −2 mm during oil production to +2.5 mm during CO2 injection. Furthermore, the changes in in situ stresses predicted under specific assumptions by geomechanical modelling are not significant enough to jeopardize the mechanical stability of the reservoir and caprock. The stress changes issued from the 3D geomechanical modelling are also combined with a Mohr–Coulomb analysis to determine the fault slip tendency. By integrating the stress changes issued from the geomechanical modelling into the fault stability analysis, the critical pore pressure for fault reactivation is higher than calculated for the fault stability analysis considering constant horizontal stresses.Item Metadata only 3D seismic analysis of complex faulting patterns above the Snapper Field, Gippsland Basin: implications for CO₂ storage(Taylor & Francis, 2015) Swierczek, E.; Backe, G.; Holford, S.; Tenthorey, E.; Mitchell, A.Mechanical damage (e.g. faults and fractures) related to tectonic forces and/or variations in formation pore pressures may enable the leakage of fluids through otherwise effective seal rocks. Characterisation of faults and fractures within seals is therefore essential for the assessment of long-term trap integrity in potential CO2 storage sites. 3D seismic reflection data are used to describe a previously unrecognised network of extensive, small Miocene-age faults with displacement of generally <30 m and lengths that vary between ∼300 and 2500 m above the Snapper Field, in the Gippsland Basin. The Snapper Field is a nearly depleted oil and gas field that presents an attractive site for potential CO2 storage due its structural closure and because it has effectively retained significant natural hydrocarbon (including CO2) columns over geological time-scales. Volume-based seismic attributes reveal that this fault system is located within the Oligocene Lakes Entrance Formation of the Seaspray Group, which acts as the regional seal to the Latrobe Group reservoirs in the Gippsland Basin. Detailed analysis of fault lengths and linkages suggests that the Miocene faults are non-tectonic, polygonal faults, although the displacement analysis of fault segments reveals strong correlations with the both the structure of the underlying Top Latrobe surface and normal faults that segment the Latrobe Group reservoirs, suggesting that the development of this fault system has been influenced by underlying structures. The geological evidence for long-term retention of hydrocarbons within the Snapper Field suggests that this fault system has not compromised the integrity of the Lakes Entrance Formation seal, although elevated pore pressures during CO2 injection could potentially lead to reactivation of these structures.Item Metadata only 3D simulation of hydraulic fracturing by foam based fluids using a fracture propagation model coupled with geomechanics in an unconventional reservoir the Cooper Basin, South Australia(Springer, 2016) Fei, Y.; Gonzalez, M.; Pokalai, K.; Haghighi, M.; International Conference on Geo-mechanics, Geo-energy and Geo-resources (IC3G 2016) (28 Sep 2016 - 29 Sep 2016 : Melbourne, Australia)Energized fluids have been previously used in hydraulic fracture treatment in depleted and low permeable gas reservoirs and have proven to be highly efficient to aid well cleanup as well as to minimize liquid retention effect and clay swelling. On the other hand, the Australian Cooper Basin has a very complex stress regime where high fracture gradients, high tortuosity induced fractures and high pressure dependent leakoff are commonly observed. Therefore, the application and optimisation of this technology in unconventional reservoirs of the Cooper Basin which needs to be adapted to counter these and reservoir effects. The Murteree and Roseneath shale formations in the Cooper Basin are 8,500 ft in depth and have been targets for shale gas production by different oil and gas operators. In this paper, petrophysical evaluation of shale gas potential (Total Organic Carbon) from the Permian Murteree formation has been studied. Next, a geomechanical evaluation was carried out by generating a 1D vertical mechanical earth modelling (MEM) to define the stress regime and the principle stresses variation which requires full-wave sonic logs and a diagnostic fracture injection test (DFIT) to construct and calibrate the model. A 3D hydraulic fracture simulation in a vertical well was developed and validated with postfrac production data. Then, a sensitivity analysis was performed using a selection of different fracturing fluid treatments. In the fracture propagation model, a large number of cases were simulated based on different types of fracturing fluids. It was found that the foam quality could contribute to a higher fracture pressure. This is because higher viscosity of foam contributes to higher net pressure in the fracture by improved leakoff control, with greater proppant carrying capacity comparing with slickwater to increase fracture conductivity. Based on our reservoir inputs, the simulation results indicated that the optimum scenario is a foam quality of 70% for both N2 and CO2 as it generates the maximum gas productivity. Modelling predictions support the expectation of long term productivity gains through the use of foams fracturing fluid. It is concluded that the use of foam results in a more rapid clean-up of the fracture itself and inside the wellbore, which is expected to provide higher productivity.Item Metadata only 4D quantification of stress and strain tensors at Sheep Mountain Anticline (Wyoming, USA) using calcite twin analysis(American Geophysical Union, 2008) Amrouch, K.; Lacombe, O.; Daniel, J.; American Geophysical Union 2008 Fall Meeting (15 Dec 2008 - 19 Dec 2008 : San Francisco, California)We use the calcite twin analysis to investigate the relationship between fold development, stress and strain distribution. We chose for this study the Sheep Mountain Anticline (Wyoming, USA) as a natural laboratory. Because it's asymmetric and basement-cored fold, this anticline was formed during the Laramide orogeny in the Early Tertiary.The calcite twin have been measured in folded Lower Carboniferous to Permian age carbonates and sandstones. Calcite twin recorded both in the matrix and in the veins, highlight three different tectonic stages: the first phase is a pre-folding compression parallel to fold axis, a second one is also pre- folding compression but it's perpendicular to the future fold axis and the third stage is also perpendicular to the fold axis but it's a post-folding compression. Furthermore, calcite twin data provide information about the evolution of stress (Etchecopar's method) and strain (Groshong's method) through time and space. Both pre- folding and post-folding NE-directed compressional stress and/or shortening were recorded within pre-folding veins (set I) as well as in fold-related veins (sets II and III). Set III veins also recorded outer rim extension along the fold hinge line.Besides, calcite twin analysis allow us to quantify stress and strain. Our results point out both temporal and spatial evolution of stress and strain tensors. Spatially, we notice that both strain and particularly differential-stress in the backlimb are higher than in the forelimb. We are also able to show that differential-stress drops both in the backlimb and in the forelimb between pre-folding and post-folding stages. Our new dataset should putting better constrains on numerical models in order to increase our knowledge on fold mechanics.Item Metadata only A 100 ka record of fluvial activity in the Fitzroy River Basin, tropical northeastern Australia(Elsevier, 2011) Croke, J.; Jansen, J.; Amos, K.; Pietsch, T.Abstract not availableItem Metadata only A balanced 2D structural model of the Hammerhead Delta-Deepwater Fold-Thrust Belt, Bight Basin, Australia(Taylor & Francis Ltd., 2010) King, R.; Backe, G.The Hammerhead Delta-Deepwater Fold-Thrust Belt is located in the Ceduna Sub-Basin of the Bight Basin, offshore southern Australia. It is synonymous with the Hammerhead Supersequence and consists of three, Campanian to Maastrichtian, deltaic sediment packages. The Hammerhead Delta-Deepwater Fold-Thrust Belt is a short-lived gravity-gliding system that exhibits a distinctive spoon-shape in cross-section. The system detaches on a master horizon at the top of the Tiger Formation. Finite Element Method based two-dimensional restorations show that the Hammerhead Delta-Deepwater Fold-Thrust Belt is a near-balanced system with near equal amounts of up-dip extension and down-dip compression. Overall, there is only 2.4% additional extension in the Hammerhead Delta-Deepwater Fold-Thrust Belt. This near-balanced system is unusual in comparison with other passive margin Delta-Deepwater fold-thrust belts, which generally demonstrate large amounts of extension compared with shortening, due to the regional-scale progradational nature of the systems. The results suggest that sediment input to the Hammerhead Delta-Deepwater Fold-Thrust Belt was not sufficient to result in the regional-scale progradation of fault activity and that the sediment supply shutdown before the system could develop in an extensive passive margin Delta-Deepwater fold-thrust belt, hence demonstrating that it is sediment supply that drives ongoing gravitational deformation in Delta-Deepwater fold-thrust belts and not slope gradient.Item Metadata only A catchment-scale assessment of anabranching in the 143 000 km2 Fitzroy River catchment, northeastern Australia(John Wiley & Sons Ltd, 2008) Amos, K.; Croke, J.; Hughes, A.; Chapman, J.; Takken, I.; Lymburner, L.AbstractThis paper presents a catchment‐scale investigation of anabranching in the moderately large 143 000 km2 Fitzroy River catchment in north‐eastern Australia. The primary aim is to determine whether mapped and remotely sensed data can provide useful information about the characteristics of anabranching in a catchment of this scale. Anabranching comprises 6% of the total channel network by length, and 24% of higher‐order channels (those with catchment areas over 100 km2). Three anabranching planform morphologies are described, which occur in geographically distinct regions, and add to previous descriptions of anabranching rivers. Sinuosity and link length are calculated for all channels of the mapped channel network (a link is a stretch of river between two stream junctions). Slope, mean floodplain width, mean annual rainfall and underlying and catchment geology parameters are calculated for links of a stream network derived from a digital elevation model (DEM), in which each link has either a single channel or anabranching morphology. Anabranching and single channel links do not occupy different ranges of attribute values, and a logistic regression analysis was unable to predict anabranching. However, slope, catchment area, mean floodplain width, length and sinuosity parameters all have significantly different means when comparing single channel with anabranching links, although it is shown that the difference in mean floodplain widths is the result of its correlation with catchment area. Anabranching channels have a tendency towards shorter link lengths, lower sinuosities and lower valley slopes and occur at larger catchment areas than single channels. These differences are discussed in the context of published hypotheses regarding the cause of anabranching. However, the spatial resolution and precision of our data limit our ability to investigate controls on anabranching, which will require detailed measurement of variables at a reach scale. Copyright © 2007 John Wiley & Sons, Ltd.Item Metadata only A clastic fluvial-deltaic highstand system from the neoproterozoic of South Australia: an excellent outcrop analog for marginal marine deposits in the subsurface(AAPG/Datapages, 2015) Counts, J.; Amos, K.; AAPG/SEG International Conference & Exhibition (ICE) (13 Sep 2015 - 16 Sep 2015 : Melbourne,Vic.)Item Metadata only A comparative study of surfactant adsorption by clay minerals(Elsevier, 2013) Amirianshoja, T.; Junin, R.; Kamal Idris, A.; Rahmani, O.Abstract not availableItem Metadata only A comparison of competing amplitude variation with offset techniques applied to tight gas sand exploration in the Cooper Basin of Australia(Society of Exploration Geophysicists and American Association of Petroleum Geologists, 2015) Tyiasning, S.; Cooke, D.We have developed a tight gas amplitude variation with offset (AVO) case history from the Cooper Basin of Australia that addressed the exploration problem of mapping thin fluvial tight gas sand bodies. In the Cooper Basin, Permian Toolachee and Patchawarra sands are difficult to interpret on seismic data due to strong reflections from adjacent Permian coals. This is not the common AVO problem of distinguishing between coal and gas sand, but a more difficult class-I AVO problem of mapping fluvial sands beneath a sheet coal that varies in thickness. We have reviewed local rock properties and concluded that Poisson’s ratio is probably the most appropriate rock property to solve the above exploration problem. We have compared various seismic attributes made using the extended elastic impedance (EEI) technique and a rotation of near and far partial stacks. In a synthetic modeling study that included random noise and tuning, we compared the noise-discrimination abilities of three competing AVO crossplot techniques and “rotated” the attributes made from them. These three crossplots were as follows: intercept versus gradient (I-G), full-stack versus far-minus-near (Full-FmN), and near-stack versus far-stack (N-F). Previous papers on this subject have found that (I-G) crossplots had a spurious correlation in the presence of noise that did not occur with the (Full-FmN) and (N-F) crossplots. We found that for our class-I AVO case, (1) the advantage of the (Full-FmN) and (N-F) crossplots disappeared in the presence of tuning, (2) if tuning was present, the optimal rotation angle was determined by the “tuning angle,” not by the noise angle or some desired EEI angle, and (3) if the three different crossplots were rotated by their respective “tuning” angles, the results were identical.Item Metadata only A Comprehensive Model for Injectivity Decline Prediction during PWRI(Society of Petroleum Engineers, 2006) Paiva, R.; Bedrikovetski, P.; Furtado, C.; Siqueira, A.; de Souza, A.; EAGE Conference & Exhibition incorporating SPE Europec 2006 (68th : 12–15 June, 2006 : Vienna, Austria)Injectivity decline is a chronicle disaster during produced water re-injection (PWRI); the phenomenon has been widely reported in the literature for North Sea, Gulf of Mexico and Campos Basin fields. The damage happens due to solid and liquid particles in the re-injected water. The injectivity decline prediction is important for planning and design of PWRI, of injected water treatment and of well stimulation procedures, The reliable prediction should be based on mathematical modelling using well injectivity index history and laboratory data. The mathematical models for deep bed filtration of particles and for external filter cake formation have been developed and adjusted to coreflood and well data by numerous authors (Sharma, Khatib, Wennberg et. al.). Here we add modelling of external cake erosion during well closing by the growing cake and filling the well by the erosion particles and develop a comprehensive model. The comprehensive model predicts very peculiar injectivity index (II) curve: initial II increase due to displacement of oil by less viscous water, slow II decline due to deep bed filtration, fast II decrease during external filter cake formation, II stabilization due to cake erosion during the rat hole filling by the eroded particles and further II decrease during well column filling by erosion products. The model is implemented in Excel; the software SPIN Simulates and Predicts the INjectivity. We present in details the history matching for three injectors (field X, Campos Basin, Brazil), showing good agreement between modelling and well data. The obtained values of injectivity damage parameters lay in the same rage intervals as those calculated from laboratory corefloods. Copyright 2006, European Association of Geoscientists and Engineers.Item Metadata only A comprehensive model for injectivity decline prediction during PWRI(SPE, 2007) Paiva, R.; Bedrikovetski, P.; Furtado, C.; Siqueira, A.; de Souza, A.; European Formation Damage Conference (7th : 2007 : Scheveningen, The Netherlands)Injectivity decline is a chronicle disaster during produced water re-injection (PWRI); the phenomenon has been widely reported in the literature for North Sea, Gulf of Mexico and Campos Basin fields. The damage happens due to solid and liquid particles in the re-injected water. The injectivity decline prediction is important for planning and design of PWRI, of injected water treatment and of well stimulation procedures. The reliable prediction should be based on mathematical modelling using well injectivity index history and laboratory data. The mathematical models for deep bed filtration of particles and for external filter cake formation have been developed and adjusted to coreflood and well data by numerous authors (Sharma, Khatib, Wennberg et al.). Here we add modelling of external cake erosion during well closing by the growing cake and filling the well by the erosion particles and develop a comprehensive model. The comprehensive model predicts very peculiar injectivity index (II) curve: initial II increase due to displacement of oil by less viscous water, slow II decline due to deep bed filtration, fast II decrease during external filter cake formation, II stabilization due to cake erosion during the rat hole filling by the eroded particles and further II decrease during well column filling by erosion products. The model is implemented in Excel; the software SPIN Simulates and Predicts the INjectivity. We present in details the history matching for three injectors (field X, Campos Basin, Brazil), showing good agreement between modelling and well data. The obtained values of injectivity damage parameters lay in the same rage intervals as those calculated from laboratory corefloods.Item Metadata only A Cooper Basin simulation study of flow-back after hydraulic fracturing in tight gas wells(CSIRO, 2016) Sarkar, S.; Haghighi, M.; Sayyafzadeh, M.; Cooke, D.; Pokalai, K.; Mohamed Ali Sahib, F.After fluid injection (slickwater) during hydraulic fracturing, the flow-back of fracture fluid is necessary before gas production starts. A review of fracture treatments indicates that the incomplete return of treating fluids is a reason for the failure of hydraulic fracturing and is associated with poor gas production. The aim of this study is to investigate the parameters that limit flow-back in low permeability gas wells in the Cooper Basin. The authors used numerical simulation to find the critical controlling parameters to introduce the best practice for maximising the flow-back in the Cooper Basin. Several 3D and multiphase flow simulation models were constructed for three wells in the Patchawarra Formation during fracture fluid injection, soaking time and during flow-back. All models were validated using history matching with the production data. The results show that the drainage pattern is distinctly different in the following directions: vertically upward, vertically downward, and horizontal along the fracture half-length and along the matrix. The lowest recovery is observed during the upward vertical displacements due to poor sweep efficiency. Furthermore, it is observed that drawdown does not influence the recovery significantly for upward displacements. Surface tension reduction, however, can improve sweep efficiency and improve recovery considerably. Also, the wettability of the rocks has a significant impact on ultimate recovery when the effect of gravity is dominant. The authors conclude that a significant amount of injected fluid is trapped in the formation because of poor sweep efficiency and formation of gas fingers, which results from low mobility ratio and gravity segregation.Item Metadata only A fast inverse solver for the filtration function for flow of water with particles in porous media(Institute of Physics Publishing Ltd, 2006) Alvarez, A.; Bedrikovetski, P.; Hime, G.; Marchesin, A.; Marchesin, D.; Rodrigues, J.Models for deep bed filtration in the injection of seawater with solid inclusions depend on an empirical filtration function that represents the rate of particle retention. This function must be calculated indirectly from experimental measurements of other quantities. The practical petroleum engineering purpose is to predict injectivity loss in the porous rock around wells. In this work, we determine the filtration function from the effluent particle concentration history measured in laboratory tests knowing the inlet particle concentration. The recovery procedure is based on solving a functional equation derived from the model equations. Well-posedness of the numerical procedure is discussed. Numerical results are shown.Item Metadata only A fast simulator for hydrocarbon reservoirs during gas injection(Taylor & Francis, 2014) Sayyafzadeh, M.; Mamghaderi, A.; Pourafshary, P.; Haghighi, M.A fast simulator is presented to forecast quickly the performance of oil reservoirs during gas (miscible and immiscible) injection based on transfer functions (TF). In this method, it is assumed a reservoir consists of a combination of TFs. The order and arrangement of TFs are chosen based on the physical conditions of the reservoir that are ascertained by examining several cases. The selected arrangement and orders can be extended. The only required data of this method is production and injection history that are easily accessible. Injection and production rates act as input and output signals to these TFs, respectively. By analyzing input and output signals, matching parameters are calculated for each case study. The outcomes of the method are compared with those obtained by a grid-based simulator. The comparison indicates a good agreement.Item Metadata only A finite element post-processed Galerkin method for dimensional reduction in the non-linear dynamics of solids. Applications to shells(Springer, 2003) Sansour, C.; Wriggers, P.; Sansour, J.Item Metadata only A fractal approach for surface roughness analysis of laboratory hydraulic fracture(Elsevier, 2021) Movassagh, A.; Haghighi, M.; Zhang, X.; Kasperczyk, D.; Sayyafzadeh, M.Hydraulic fracturing treatment in rocks creates surfaces that are not smooth but rough in general. Accurate characterization of surface roughness is necessary to relate fracture deformation to fluid flow. In this study, we analyze the surface of an experimentally generated hydraulic fracture using a practical fractal approach which is capable of modeling applications. The hydraulic fracturing test is conducted using a nearly homogeneous siltstone cube in a true triaxial cell, and a fracture is created showing a perfectly radial pattern. To evaluate roughness, each surface profile is decomposed into large-scale fracture waviness and localized surface roughness considering various length scales. Despite the waviness, estimated roughness amplitudes follow a power-law relation up to a length-scale, showing a fractal nature. Unlike ideal brittle materials with an exponent of 0.5, the roughness exponent is found to vary in a narrow range of 0.1 but exceeds 0.5. The fractal dimension (box dimension) of the hydraulic fracture surface is estimated to be 1.4 showing a good match with roughness exponents. An increase in roughness exponent may indicate an increasing difficulty in fracture propagation and fluid and proppant transport along the fracture. As such, the topology of a hydraulic fracture surface is essential to hydraulic fracture growth to assess fracturing performance.