The Ceduna Sub-basin is one of the few remaining frontier basins in Australia today. Few exploration wells have been drilled in the basin and none have encountered hydrocarbons. The current study aims to investigate the hydrocarbon prospectivity of an area of interest (AOI) within the distal part of the Ceduna Sub-basin, where no well information is available.
The study uses 3D seismic data and employs principles from geophysics, structural geology, sedimentology, sequence stratigraphy, and petroleum systems analysis in a comprehensive investigation to understand the Ceduna Sub-basin. Multiple 2D basin models were created for the AOI to test different scenarios in a detailed risk analysis of the petroleum system and its major controls. They were identified from a comprehensive literature review and after a thorough interpretation of the 3D seismic survey in the AOI.
Results show that the best reservoir is located within the low stand systems tract (LST) deposits of the Hammerhead Sandstone (Ss) and Top Tiger Ss. The potential source rock occurs in the condensed high stand system tract (HST) deposits in the Base Tiger Ss and White Pointer Ss. 1D modeling showed that these source rocks may have generated hydrocarbons as their depth is <9 km. The critical moment during the source rock history was at 80 Ma coinciding with the deposition of the Hammerhead Ss.
Based on the regional structural framework, faults were initiated after source rock deposition. Several growth faults may pose a risk in terms of hydrocarbon leakage. Different 2D models have advanced the understanding of the petroleum systems in the AOI. The results showed that the most prospective areas are within a rollover anticline play and those areas where intra-formational seals are present. The model confirms that fault integrity represents the prime risk across the basin.
The current study contributes to understanding of the Ceduna Sub-basin by identifying two different plays in the AOI: rollover anticline and tilted fault block. Probability analysis of the different petroleum elements shows that the rollover anticline play has the highest geological probability of success.
Summary In the past decades, many exploration wells have drilled into igneous rocks by accident because of their similar seismic expression to the common intended targets such as porous carbonate mounds, sheet sands or deepwater sand-prone sinuous channels. In cases where sedimentary features such as channels or fans cannot be clearly delineated, the interpretation may be driven primarily by bright spot anomalies, and a poor understanding of the wavelet polarity may compound this problem. While many wells that are drilled into igneous rocks were based on interpretation of 2D seismic data, misinterpretation still occurs today using high quality 3D seismic data. We propose an in-context interpretation workflow in which the interpreter looks for key clues or parameters above, below and around the target of interest to confirm the interpretation. Introduction Using modern 3D seismic surveys, significant work has been achieved over the past two decades in accurately imaging the geometry of igneous bodies (Hansen and Cartwright 2006; Holford et al., 2012; Jackson et al., 2013; Magee et al., 2014).
AbstractThe Great Australian Bight(GAB) has been subjected to exploration for the past five decades with no major hydrocarbon discoveries, and could be defined as a new frontier for oil and gas development. BP has recently committed to a drilling campaign in the region and establishing key infrastructure indicating potential for a significant hydrocarbon discovery. The key challenges for developing in this area are; ➢Remoteness–Closest population 300km away, nearest oil & gas infrastructure +1,000km away➢Deep water – Area explored range from 1,000m to 3,000m➢Harsh Environment–100yr storm estimate significant wave height 13m, period 12s, andcurrent 1m/s➢Limited information for long term modelling of the environmentThis paper has focused on the evaluating different development options against the challenges, with mostof the data being based upon public information from BP drill sites. The focus of the technical feasibility assessment is on the potential production mechanism used to enable the development i.e. fixed or floating platform or other facility. This conceptual review forms the preliminary basis for concept selection for a field in this new and environmentally highly sensitive area and as such it is expected that several potential offshore development options are to be presented.
Identifying, risking, and maintaining subsurface integrity is of critical importance to a variety of geologic subsurface operations including geothermal, oil and gas production (conventional, unconventional, fractured crystalline, heavy-oil fields), mining, natural gas storage, and sequestration of CO2 and hazardous waste. Predicting and mitigating out-of-zone fluid migration includes but goes beyond maintaining well integrity: it relies on technical understanding of top and fault seals, reservoir and overburden deformation, production/injection-induced stress changes, reservoir management, completions design and engineering, hydraulic fracturing/height containment, wastewater disposal, induced seismicity/fracture reactivation, and reservoir monitoring (e.g., geodetic and downhole measurement and interpretation). Subsurface integrity excludes surface facilities and spill response but includes regulations regarding subsurface activities.
In this paper we present and synthesize examples of subsurface containment loss from oil and gas fields that are documented in the open literature. We then discuss common risk areas or themes in subsurface containment geomechanics that are important to subsurface integrity and illustrate with some general examples how some of these could be investigated by using geomechanical models.
Containment of produced or injected fluids within their intended wellbores or geologic subsurface zones in oil and gas fields is widely recognized as a critical part of exploration and production (E&P) activities in conventional and unconventional plays and reservoirs. For example, it is a primary objective while drilling exploration, appraisal, development, and production wells. Maintaining the integrity of wellbores and subsurface geologic elements can potentially minimize drilling and operational risk. Effectively managing injection pressures, volumes, and rates of fluids in producing fields depends critically on adequately defining the geomechanical limits set by geologic elements such as overburden, caprock, top seals, faults, and evolving in situ stress states (including reservoir pressures). Characterization of the mechanical integrity of the subsurface relies upon obtaining baseline measurements including lithology, petrophysical and mechanical properties, pore pressure, and stress state that are best obtained during field appraisal and development, before production begins. Because the consequences of subsurface containment loss to an operator or partner can be significant, including both direct and indirect costs (e.g., clean-up cost, loss of production, and damage to reputation), even for small events, containment-related activities have assumed a larger share of enterprise risk as technologically more challenging fields are evaluated and placed into production .
Righetto, G. L. (ATHENA) | Lautenschläger, C. E. R. (Computational Geomechanics Group, GTEP) | Inoue, N. (Group of Technology in Petroleum Engineering, PUC-Rio) | da Fontoura, S. A. B. (Pontifical Catholic University of Rio de Janeiro)
Aiming to increase hydrocarbon production, the oil industry has developed recovery methods whose purpose is to get more production. Thus, several problems may be encountered when making use of these techniques, mainly the conventional one. In addition, consideration of geological structures in reservoir engineering, such as fault zones, has fundamental character for determining realistic response for the production of hydrocarbons. In the case of faults zones, its consideration in the model has significant importance currently, especially with regard to the possibility of reactivation and possible loss of tightness of the reservoir. Thus, the aim of this study was assess reservoir models with a fault zone using partially coupled hydro-mechanical simulations. The methodology considers a fault zone whose behavior is given by the Mohr-Coulomb yield criterion. The plasticity model showed consistent results with the process of reactivation for the models. Thus, for the case where the objective is to determine the maximum flow rate of injection as well as its spatial configurations aimed at maintaining the field production, it is possible to establish the flow rate that may result in the initiation of the fault reactivation. Furthermore, the effect of surrounding rocks had a great influence in the time required to initiate the process of reactivation. As a general conclusion, it is stated that the consideration of fault zones in reservoirs, as well as surrounding rocks, must be taken into account to obtain more accurate response to the field behavior.
The exploitation of petroleum began from the drilling of the first well of petroleum in the XIX century in the United States. From this point, aiming increase the petroleum recovery, the oil industry developed recovery methods whose objective is to obtain a higher production than that which would be obtained only as a result of the natural energy of the reservoir (Thomas 2001). In this context, several problems can be faced when one uses recovery techniques, mainly through the fluid injection, in geologically complex reservoirs.
Besides that, the consideration of geological structures in the reservoir engineering, for instance faults, has fundamental importance for determining realistic responses related to oil recovery factor, compaction of reservoir, seafloor subsidence, among others. In the specific case of faults, its consideration and analyses has been reported for several authors (Morris et al. 1996, Wiprup & Zoback 2000, Mildren et al. 2002, Streit & Hillis 2004, Chiaramonte et al. 2006, Færseth et al. 2007, Rutqvist et al. 2007, 2008, Soltanzadeh & Hawkes 2008, Zhang et al. 2009, Cappa & Rutqvist 2010, Ducellier et al. 2011, Jain et al. 2012, McDonald et al. 2012; Leclère & Fabbri 2012), due, mainly by its reactivation possibility. In the fault reactivation perspective during the field development, the objective is to prescribe the highest injection flow rate or the highest bottom hole pressure that can be applied in injector wells in order to maintain the reservoir pressure, without the failure of the faults. The process of fault reactivation, due the stress state variation, can result in an emergence of a preferential path for the hydrocarbon, implying in the most critical cases, in the leakage of fluid and possible loss of tightness of the reservoir.
In late 2011 the Queensland State Government of Australia declared the Cooper Creek Basin in South West Queensland to be a Wild River Area under the Wild River Act 2005. The Wild River Area covers a significant proportion of Santos' current tenements and future development interests in the area.
The Wild Rivers Declaration is a highly prescriptive regulatory regime that sets out significant restrictions which would detrimentally impact on existing operations and future oil and gas development opportunities, including emerging coal seam and shale gas prospects in the proposed declaration area. It includes general prohibitions on certain activities across extensive areas of channel country and the imposition of setbacks for activities in proximity to watercourses.
The issue first arose in late 2010 when the Queensland Government indicated its intent to declare the Cooper Creek Basin as a Wild River through its issue of a Declaration Proposal. During the 12 month consultation period that followed, Santos engaged with the Queensland Government regulators and Ministers to assist the Government to make a Wild Rivers Declaration that achieves a balance between protecting the natural values of the Cooper Creek and allowing the continuation of the sustainable development of the petroleum resources within the Cooper and Eromanga Basins.
The paper will provide insight into Santos' experience in taking a lead role in responding to the significant new legislative regime proposed by Government. Key insights include the need for industry tobe proactive and take a role in educating the Government on the industry's operations andthe changes required to ensure compliance with the new regulatory requirements. It will also discuss broadlythe challenges associated with the changing regulatory environment including the role that politics can play and observes that we should continue to expect a ‘Wild' ride whenparticipating in thelegislative developmentprocess.
The significance of the Declaration is that the restrictions for petroleum activities imposed in the Cooper Creek Basin Wild Rivers Declaration may be imposed upon all Wild Rivers areas in Queensland. In addition, other Australian state governments are watching the implementation of Wild Rivers' legislation in Queensland and are considering the need for similar regulatory regimes in their jurisdictions.
Bradshaw, Marita (Geoscience Australia, GPO Box 378, Canberra A.C.T., 2601, Australia Email: firstname.lastname@example.org) | Foster, Clinton (Geoscience Australia, GPO Box 378, Canberra A.C.T., 2601, Australia Email: email@example.com) | Willcox, Barry (Geoscience Australia, GPO Box 378, Canberra A.C.T., 2601, Australia Email: firstname.lastname@example.org) | Struckmeyer, Heike (Geoscience Australia, GPO Box 378, Canberra A.C.T., 2601, Australia Email: email@example.com)
AUSTRALIA'S FRONTIER BASINS AND PROSPECTS FOR NEW PETROLEUM PROVINCES. Marita Bradshaw, Geoscience Australia, GPO Box 378, Canberra A.C.T., 2601, Australia Clinton Foster, Email: firstname.lastname@example.org Barry Willcox, Heike Struckmeyer Abstract Within Australia's marine jurisdiction (AMJ) there are at least ten deepwater basins related to Mesozoic rifted margins that have the potential to contribute at least one new petroleum province of global significance. Current offshore exploration activity in Australia is focussed around giant fields in the north west (North West Shelf) and in the south east (Bass Strait) quadrants of the AMJ, representing less than one percent of the prospective acreage. Frontier basins in deepwater along Australia's southern and eastern margins are vastly under-explored with only three exploration wells having been drilled in water depths beyond 500 metres and limited, sometimes only regional, seismic coverage. Despite this minimal exploration, active petroleum systems are indicated by remote sensing techniques (SAR, ALF), seismic evidence of bottom simulating reflectors (BSRs), flat spots and gas escape structures, beach strandings of asphaltites, and oil and gas shows in the few wells in this region. Key prospects for hydrocarbon exploration in the future include the basins of the Great Australian Bight, the west Tasmanian margin and the Lord Howe Rise. Australia's southern margin is conjugate with Antarctica and was the site of a major Mesozoic rift valley system approximately 4,000 kilometres long. At its eastern end the giant Gippsland Basin fields were discovered in the 1960s, but the western two-thirds of the margin is essentially unexplored. A giant Late Cretaceous delta complex is apparent even on present day bathymetry. It is comparable in area to the Niger Delta, with prograding sequences up to 5,000 metres thick. These sand-rich sequences overlie mobile units representing Albian and Turonian marine shales; and the total sedimentary section is up to 15,000 metres thick. Along the western margin of Tasmania and on the South Tasman Rise the break-up had a strong trans- current component producing a series of strike-slip basins up to 6,000 metres thick. Restricted marine environments were maintained along this part of the margin until the final separation of Australia and Antarctica in the Oligocene. The Lord Howe Rise is a large continental fragment lying between Australia, New Caledonia and New Zealand in the Tasman Sea. It covers an area of 740,000 square kilometres in waters shallower than 3000 metres. It is underlain by a number of sedimentary basins, some in excess of 4,000 metres thick. BSRs indicative of gas hydrates, flat spots and diapiric features have been observed on the limited seismic coverage. BLOCK 1 -- FORUM 2 157 AUSTRALIA'S FRONTIER BASINS AND PROSPECTS FOR NEW PETROLEUM PROVINCES Introduction Australia's marine jurisdiction covers 14.2 million square kilomet
INTEGRATED BASINWIDE MODELLING OF PETROLEUM-RELATED TRANSPORT PROCESSES IN M U LTI PHASE SYSTEMS Th. Hantschell, B. M. Krooss2 and B. Wygralal, Integrated Exploration Systems (IES) Juelich, Germany; Institute of Petroleum and Organic Geochemistry, Research Centre Juelich (KFA), Germany Abstract. Recent developments in numerical basin modelling in combination with increasingly efficient compu- tational processing provide the possibility of a detailed simulation of the dynamic evolution of hydrocarbon systems on a basinwide scale. This holds both for the time-resolution and for the number of different processes that can be handled within the models. Generation and migration of petroleum takes place in a complex multiphase system of fluid and solid phases. The fluid composition and flow behaviour during the various stages of petroleum migration are affected by different physical and chemical processes. A new modelling system has been designed for the numerical simulation of three-phase (water, oil, gas) fluid flow within the pore system of a rock matrix consisting of mineral and organic matter. A multiple source concept including compositional modelling is applied to monitor oil compound classes and the molecular com- position of the gas phase including hydrocarbon and non-hydrocarbon compounds. The modelling system takes into account the two basic transport mechanisms-separate phase flow and molecular diffusion. Mass transfer among the ñuid phases and between fluids and solids is controlled by equations of state. The system thus allows for the modelling of mixing and segregation processes and their effects on the geochemistry of the petroleum fluids. The new software was applied to several hydrocarbon systems in the Asian and Pacific area. Case studies will be presented to document the link between a basinwide quantification and timing of petroleum generation/ migration and the analysis of the dynamics of selected reservoir structures.
The understanding of the dynamics of complex systems is becoming one of the key tasks in modern scientific investigations. Computer modelling as an `experimental tool' plays an important role in applied analyses aimed at solving specific practical tasks, as well as in general scientific analyses used to further our basic knowledge of such processes. Espe- cially in the geosciences, commercial and scientific computer modelling software has been rapidly devel- oped during the last decade. The following frame- work in the analysis of sedimentary basins and petroleum systems has been well established in the petroleum industry, and is used to minimise explora- tion risks and to maximise production capacities. 1. Interpretation of seismic data (to model present 2. Structural modelling (for the interpretation of the geometry). paleogeometry). 3. Reservoir simulations (to optimise production 4. Basin modelling systems (for the analysis of basin scenarios), and developmen