bluuebunny/crossref_metadata_2025 huggingface dataset:
Welltest analysis of hydraulically fractured tight gas reservoirs: a field example from Perth Basin, Western Australia
Authors: Bahrami Hassan , Jayan Vineeth , Rezaee Reza , Hossain Dr Mofazzal
Published: August 2017

Welltest interpretation requires the diagnosis of reservoir flow regimes to determine basic reservoir characteristics. In hydraulically fractured tight gas reservoirs, the reservoir flow regimes may not clearly be revealed on diagnostic plots of transient pressure and its derivative due to extensive wellbore storage effect, fracture characteristics, heterogeneity, and complexity of reservoir. Thus, the use of conventional welltest analysis in interpreting the limited acquired data may fail to provide reliable results, causing erroneous outcomes. To overcome such issues, the second derivative of transient pressure may help eliminate a number of uncertainties associated with welltest analysis and provide a better estimate of the reservoir dynamic parameters.
This paper describes a new approach regarding welltest interpretation for hydraulically fractured tight gas reservoirs—using the second derivative of transient pressure. Reservoir simulations are run for several cases of non-fractured and hydraulically fractured wells to generate different type curves of pressure second derivative, and for use in welltest analysis.
A field example from a Western Australian hydraulically fractured tight gas welltest analysis is shown, in which the radial flow regime could not be identified using standard pressure build-up diagnostic plots; therefore, it was not possible to have a reliable estimate of reservoir permeability. The proposed second derivative of pressure approach was used to predict the radial flow regime trend based on the generated type curves by reservoir simulation, to estimate the reservoir permeability and skin factor. Using this analysis approach, the permeability derived from the welltest was in good agreement with the average core permeability in the well, thus confirming the methodology’s reliability.
Evaluation of free porosity in shale gas reservoirs (Roseneath and Murteree formations case study)
Authors: Ahmad Maqsood , Hussain Ali , Koo Reuben , Nguyen's Hoang , Haghighi Manouchehr
Published: August 2017

Organically rich shale rocks represent a voluminous, long-term, global source of natural gas and could be referred to as shale gas. Unlike conventional gas reservoirs, shale gas reservoirs have very low effective porosity and permeability. Therefore, an evaluation of porosity in such a tight rock is a challenge. The Roseneath and Murtree shale formations in the Cooper Basin are believed to be potential shale gas reservoirs in SA. Core samples of Murteree and Roseneath carbonaceous shales from the Della–4 and Moomba–46 wells were collected to measure interstitial and intergranular porosity in these prospective shale gas reservoirs in the Nappamerri Trough.
After initial preparation, the shale core samples were investigated to determine the pore size classification and effective free porosity using the mercury injection capillary pressure technique (MCIP). The focused ion beam/scanning electron microscopy (FIB/SEM) technique was then employed to obtain micro and nano scale images of the core samples. Then, helium porosimetry was used on the samples to measure their effective porosity. Finally, the pyknometry method was used on the crushed samples to measure their total intergranular porosity.
MICP techniques revealed that the samples were mainly comprised of meso-porosity, with the pore throat diameters between 2–50 nanometres and an effective porosity of less than 2%. Helium porosimetry also showed an average porosity of less than 2%. Liquid pyknometry revealed an average absolute porosity of 30.5% for Murteree shale and 39% for the the Roseneath shale, which is much higher than the results from the MCIP technique and helium porosimetry. This is an indication of having very high isolated porosity and very low permeability. The findings were analysed and validated by the use of SEM images, displaying high amounts of isolated porosity, confirming the high porosity measurement from the pyknometry technique. The results achieved strongly emphasised that gas prone, over-mature, carbonaceous shales have very low effective but very high total porosity.
Therefore, it is envisaged that total intergranular porosity holding compressed gas in over-mature source rocks cannot be evaluated using the helium porosimetry and mercury injection techniques. The pyknometry technique supported by the SEM images is an alternative method; however, this method can only measure total, rather than effective, porosity.
Simulation and history matching of a shale gas reservoir using different models in Eagle Ford Basin
Authors: Xu Bingxiang , Haghighi Manouchehr , Cooke D
Published: August 2017

Eagle Ford Shale in South Texas is one of the recent shale play in the US, which began developing in late 2008. To evaluate the reservoir performance and make the production forecasting for this reservoir, one multi-stage fractured horizontal well was modelled and history matching was done using the available 250 days of production data.
Two different flow models of dual-porosity and multi-porosity have been examined. In the multi-porosity model, both approaches of instant and time-dependent sorption have been investigated. Also, two approaches of negative skin and transverse fractures were used to model the effect of hydraulic fracturing.
For history matching of early production data, all the models were successfully matched; however, all models predict differently for production forecasting. Comparing both production forecasts for 10 years, the multi-porosity model forecasts 14% more than dual-porosity model. This is because in the dual-porosity model, only free porosity is considered and no adsorbed gas in micro-pores is assumed; in multi-porosity model, both macro and micro porosities are active in shale gas reservoir.
It is concluded that the early production data is not reliable to validate the simulation and make the production forecasting. This is because in early production data, all gas are produced from the fracture system and the matrix contribution is not significant or it has not been started yet. Furthermore, the effect of matrix sub-division on the simulation was studied: the free gas in matrix can contribute to production more quickly when matrix sub-cells increase.
Maintaining your competitive edge in a world of open innovation
Authors: Rintoul Kate
Published: August 2017

Technology clearly plays an increasingly important role in upstream petroleum exploration and development. There is the need to visit more challenging places to access traditional reserves and consider unconventional sources; at the same time, there is the need to reduce energy consumption and emissions. Open innovation: the new imperative for creating and profiting from technology is a book written by Henry Chesbrough and published by Harvard Business Press in 2003. Since open innovation was coined by Chesbrough, it has gained traction, including in senior management teams in oil and gas companies.
This extended abstract describes what open innovation is and what it is not. Open innovation is sometimes wrongly believed to be open source, which is the way an entity deals with the output of its research and development efforts (for example, by putting it into the public domain subject only to limited restrictions). In contrast, open innovation refers to the use of external ideas (as well as internal ideas) to generate that output.
The benefits and challenges of open innovation and identification of issues for an entity to consider before engaging in open innovation are discussed. The focus is on the need to make early decisions about the approach to intellectual property (particularly confidential information and patents) to ensure it is harnessed, if appropriate, to provide a source of competitive advantage.
The PowerPoint presentation is not provided to APPEA.
A new tool in the subsea industry: the Autonomous Inspection Vehicle (AIV)
Authors: Cormell Darren
Published: August 2017

A new tool for subsea inspection in the offshore oil and gas industry is now going through performance and qualification testing. The Autonomous Inspection Vehicle (AIV) has been designed and built by Subsea7 and SeeByte Ltd to provide the industry with a valuable tool capable of making a positive contribution to life-of-field operations. The station keeping and hovering ability of the AIV is the next step in the evolution of autonomous systems in the marine environment.
Survey class autonomous vehicles have already shown their value with improved data quality and efficiencies compared with traditional methods. The first commercial AIV will be capable of many of the inspection tasks presently carried out by remotely operated vehicles (ROV). Regular inspection data of risers, pipelines, and seabed equipment can be gathered using a single AIV operating directly from an offshore facility.
A more rapid assessment of a field can be made using multiple systems operating together from a single support vessel. This has not been done before with a commercial vehicle; hence, AIV is leading-edge technology. This extended abstract outlines some of the technical challenges in creating the vehicle and how the use of advanced simulation linked to practical testing is being used to ensure the performance of the system. Also discussed is a parallel with the evolution of subsea infrastructure that has fully enabled the capability of the ROV; how the introduction of autonomous technology should be considered with confidence is also demonstrated.
Analysis of predictive performance in the Eromanga Basin
Authors: McIntyre Steven
Published: August 2017

Strategic and operational management in the exploration and production business is characterised by prediction and decision making in a data-rich, high-uncertainty environment. Analysis of predictive performance since the 1970s by multiple researchers indicates that predictions are subject to over-confidence and optimism negatively impacting performance. The situation is the same for other areas of human endeavour also operating within data-rich, high-uncertainty environments.
Research in the fields of psychology and neuroscience indicates the way in which the human brain perceives, integrates and allocates significance to data is the cause. Significant effort has been dedicated to improving the quality of predictions. Many individual companies review their predictive performance during long periods, but few share their data or analysis with the industry at large. Data that is shared is generally presented at a high level, reducing transparency and making it difficult to link the analysis to the geology and data from which predictions are derived.
This extended abstract presents an analysis of predictive performance from the Eromanga Basin where pre-drill predictions and detailed production data during a period of decades is available in the public domain, providing an opportunity to test the veracity of past observations and conclusions. Analysis of the dataset indicates that predictions made using both deterministic and probabilistic methodologies have been characterised by over-confidence and optimism. The reasons for this performance are discussed and suggestions for improving predictive capability provided.
Trap integrity framework for the offshore northern Perth Basin
Authors: Langhi Laurent , Zhang Yanhua , Nicholson Chris , Rollet Nadege , Bernardel George , Kempton Richard , Kennard John , Schaubs Peter
Published: August 2017

The presence of hydrocarbon accumulations and several palaeo-oil columns in Permian reservoirs across the offshore northern Perth Basin attests to a widespread charge system and suggests that trap integrity is a critical exploration risk. The local structural evolution between the Beagle Ridge and the Wittecarra Terrace and the impact of renewed mid-Jurassic extension on a series of prospects (Cliff Head, Dunsborough, Lilac and Morangie) is assessed to define a regional trap integrity framework.
The focus is on the potential development of pathways through the Early Triassic Kockatea Shale regional top seal caused by reactivation of trap bounding faults and/or interaction with newly formed overlying structures. A series of 3D geo-mechanical models are constructed to simulate the Mid-Jurassic deformation and to evaluate the first-order factors controlling the partitioning of reactivation stresses/strains and the development of seal bypass.
In parallel, the local fault seal potential is assessed by focusing on the likelihood of the fault surfaces to reactivate and conduct fluid within the Jurassic stress regimes. The stress data are also used to compute the risk of reactivation in terms of the increase in pore fluid pressure required to bring a fault segment to a state of instability. The overall risk of top seal bypass is primarily driven by the reservoir-bounding faults orientation and dip. The distribution of jogs, the interactions between fault tips, the fault density, the location of regional major fault, the fault propagation mechanisms and top seal brittleness also control locally the integrity of the top seal.
Higher-resolution palynostratigraphy of the Norian-Carnian (Triassic) Upper Mungaroo Formation, offshore Carnarvon Basin
Authors: Dixon Matt , Morgan Roger , Goodall Jeffery , Van Den Berg Martine
Published: August 2017

Palynostratigraphic correlations within the Triassic fluvio-deltaic upper Mungaroo Formation (M. crenulatus and upper S. speciosus zones) of the Carnarvon Basin have proven to be difficult. Although two reliable pollen extinction datums have long been established in the uppermost 200 m of the formation, correlations within the sector below (up to 1,500 m) have had to rely on broad algael and pollen acmes, with variable results.
A revised palynostratigraphic scheme is presented in this extended abstract, which has been largely in use within Shell and Morgan-Goodall Palaeo Associates since mid/late 2010, and which has not been previously published in detail. For consistency, the subzone names remain the same as those in previous use; however, crucially, a framework for their reliable identification in more recently-analysed wells is provided by several Morgan gradational sub-types of key pollen species (viz. of Cycadopites stonei, Ephedripites macistriatus and Samaropollenites speciosus).
Within this robust framework that is based on top-ranges, base-ranges and rapid switches in the ratios of gradational and related morphotypes, numerous thin marine incursions and regional to sub-regional swampy phases are evidenced. Lateral and vertical relationships between marine incursions and swampy phases are sometimes apparent, and clustering of a few of the above pollen events at these levels hints at condensation.
The revised framework has been successfully used in the high-resolution, regional-stratigraphic interpretation of both seismic and well data and is contributing to an increasing understanding of the variability of the Upper Mungaroo depositional system in the Greater Carnarvon Basin.
Building competitive advantage: the business case for social licence to operate
Authors: Lunsford Liz , Snashall David , Haddon Matt , Edgell Linden , McCrea Sam
Published: August 2017

A social licence to operate and reputational capital, contrary to common perception, are not simply the green arm of philanthropy. Rather, they are multi-dimensional and intrinsically linked to a corporation’s market value in time. Corporations benefit from a full understanding of the business case for comprehensive and leading-edge strategies to manage and build reputational capital, thus ensuring long-term social license to operate.
A reputational capital typically represents about 80% of a firm’s intangible assets. Further, global markets demonstrate a preference for corporations that institutionalise sustainability. More than ever, in today’s operating environment, corporations have a significant market opportunity to benefit from making enterprise and project-level decisions based on the balance of social, environmental, and economic capital.
This extended abstract explores the specific activities that contribute to and degrade reputational capital, and ultimately, a corporation’s social licence to operate. More specifically, how risk management, HSE (health, safety, and environment) performance, impact assessment, the safety case, organisational culture, and asset management are inextricably linked to community risk and ultimately a social licence to operate. Each of these elements have the potential to build reputational capital such that access to key markets, cost of capital, and project net present value (NPV) are optimally advantaged.
It is understood within the oil and gas industry that informed business strategies that can be acted on are made more difficult because of the challenging nature of a social licence to operate and community risks. To this end, the authors aim to introduce a community risk-assessment tool and methodology, which can be implemented at the enterprise or project-specific level.
Networked InField Compression for CSG field development
Authors: Hodgson Guy , Edwards Vernon
Published: August 2017

Driven by the LNG feed gas volume demand, recent large CSG field development in Queensland has been developed around large centralised compressor stations, designed and constructed on conventional gas project guidelines. Experience in the United States and Canada during more than four decades, however, has shown the best CSG reservoir performances and lifecycle costs are achieved with low capital cost, flexible infrastructure, and infield compression close to well heads. The Networked InField Compression System offers CSG producers significant advantages compared with centralised systems.
The model comprises a grid network of well heads; low, intermediate, and high pressure pipelines; integral infield compressors, and booster compression stations. The model differs from traditional models in a number of ways. The majority of wellhead infrastructure and compression is relocated back in the field, reducing costs and inspection requirements. Low horsepower integral infield compressors are gas driven, pipeline losses are reduced and use 30–40 % less BHP than screw compressors, and skid-mounted for simple and cost-effective relocation.
Coiled high pressure, low diameter flexible piping is used, which requires a narrow right of way, few connections, and can be ploughed in multiple lines from up to 5–8 km per day, depending on soil conditions.In addition to 30-40 % improvements in capital expenditure and installation time, the Networked InField Compression model offers 20–30 % lower operating costs and 10–20 % more gas from increased flow levels and/or extended well life. Further, environmental impact is decreased by 20–40%, as land use, CO2 emissions; crew sizes and peak water flow are significantly reduced compared with centralised systems.
Amplitude-versus-offset (AVO) screening in frontier basins: an example from the Gulf of Papua, Papua New Guinea
Authors: Harrington Amanda , Reiser Cyrille , Burmaz Bob , Reed Rod
Published: August 2017

A resurgent interest in the gas potential of the Gulf of Papua has been enhanced by the recent announcement of developing new LNG facilities in Port Moresby. Petroleum Geo-Services (PGS) has recently acquired a 6,000-km2 Multi-Client 3D (MC3D) survey in the gulf. Although most of the discoveries in PNG are from the highland areas, the gulf is a proven hydrocarbon province with gas/condensate accumulations previously discovered in several reef build-ups.
It is thought that sediments from the Papuan Fold Belt produced clastic dominated deltas in the Gulf area. Although this play is untested offshore, there is evidence these sandy facies exist and could contain hydrocarbons. On the first phase of acquisition/interpretation, an efficient screening workflow called Prospect Scanner, developed to highlight areas of AVO effects in large 3D seismic datasets, was tested. It uses pre-stack seismic time migrated (PSTM) gathers to extract AVO attributes that are then inverted to derive relative acoustic and shear impedance volumes. Using idealised cross-plots, the relationship between Vp/Vs ratio and the Ip values gives a good indication of the fluid and lithology of the tested interval.
The results are loaded into a conventional interpretation package for interpretation/visualisation. Prospect Scanner has highlighted previously undrilled turbidite and basin floor fan prospects in the region. The Vp/Vs versus Ip cross-plot shows clustering of the sand anomaly and good separation from the majority of the plot. These points correspond to the idealised location for a gas sand. Past concerns about lateral prediction of reservoir presence and quality associated with the basin floor fans can be addressed through this workflow.
Female workforce participation in the Australian oil and gas industry—a global comparison
Authors: Marinelli Melissa , McGrath Kristy
Published: August 2017

As the Australian oil and gas industry faces a continued shortage of skilled employees, increasing the representation of women in this industry is a business imperative. Economic success and competitive advantage may depend on attracting and retaining the skills of women. Research shows that a gender-diverse workforce can also be linked to improved business performance, innovation and corporate governance.
While women make up 46% of the Australian workforce and more than 50% of university graduates, present statistics show that on average 13% of workers in the Australian oil and gas industry are women. This is a lower proportion than comparable industries in Canada and Norway: women make up 21% and 19% of workers, respectively. In Norwegian oil companies, this level is as high as 30% (4).
This extended abstract briefly discusses the present research about women's retention and progression within the Australian resource sector. It outlines the initiatives being undertaken by government, industry bodies and organisations to increase the representation of women in the Australian sector, and comparable industries in Norway and Canada.
This extended abstract concludes with a case study about the challenges and lessons learnt in establishing a corporate initiative to increase female participation at Clough Limited. Women@Clough is a professional forum established in April 2011 to improve the attraction, retention and progression of women in the Clough workforce. Strategies and key success factors in the establishment of the program are also examined.
Permeability prediction from mercury injection capillary pressure: an example from the Perth Basin, Western Australia
Authors: Al Hinai Adnan , Rezaee Reza , Saeedi Ali , Lenormand Roland
Published: August 2017

For shale gas reservoirs, permeability is one of the most important and difficult parameters to determine. Typical shale matrix permeabilities are in the range of 10 microdarcy–100 nanodarcy, and are heavily dependent on the presence of natural fractures for gas transmissibility. Permeability is a parameter used to measure the ability of a rock to convey fluid. It is directly related to porosity and depends on the pore geometry features, such as tortuosity, pore shape and pore connectivity. Consequently, rocks with similar porosity can exhibit different permeability.
Generally, permeability is measured in laboratories using core plugs. In some cases, however, it is difficult to obtain suitable core plugs. In these instances, other approaches can be used to predict permeability, which are chiefly based on mathematical and theoretical models. The approach followed in this peer-reviewed paper is to correlate permeability with capillary pressure data from mercury injection measurements. The theoretical and empirical equations, introduced in the literature for various conventional and unconventional reservoir rocks, have been used to predict permeability. Estimated gas shale permeabilities are then compared with results from transient and steady state methods on small pieces of rocks embedded in a resin disk. The study also attempts to establish a suitable equation that is applicable to gas shale formations and to investigating the relationship between permeability and porosity.
Australia as an international capital centre and headquarters for oil and gas investments
Authors: Wee Kenneth
Published: August 2017

Oil and gas projects inherently require significant sums of capital investments. Uncertainty in the global financial climate, coupled with volatile commodity prices and unrelenting cost escalations, is contributing to the risk of a world-wide credit crunch. In an ever-tightening capital market, investors are forced to compete globally for equity amidst rising costs of capital and an unprecedented demand for accountability by capital providers.
Despite tough economic times, Australia has remained one of the world’s leading centres for raising capital for global oil and gas exploration and development exploits. Many players increasingly access Australia’s liquid capital markets to fund emerging oil and gas ventures in locations including Africa, Asia and the Americas.
Australia has conducive regulatory and fiscal rules, which make it an attractive holding company jurisdiction to locate either global or regional oil and gas headquarters. There are, however, many aspects of Australia’s fiscal rules that are often overlooked and can prove costly for the global tax effectiveness of investing through Australia and the flow-on impact on global after-tax funding costs in a capital-constrained environment. This peer-reviewed paper seeks to canvass the following:

overview of Australia’s holding company tax regime, including Australia’s participation exemption, branch profits exemption and controlled foreign company rules;
accidental permanent establishment risks for Australian entities operating abroad;
treatment of equity-raising costs;
cost allocations for management, technical services and head office support;
funding of foreign operations and subsidiaries;
holding intellectual property rights and conducting research and development in Australia versus abroad; and
Australia’s arm’s length rules.
2013 offshore petroleum exploration acreage release
Authors: Constable Tania
Published: August 2017

Exploration is essential for the future of Australia’s resources sector, to enhance our international competitiveness and ensure the long-term growth of this important industry while maintaining Australian energy security and that of our major energy trading partners. Encouraging investment in offshore petroleum exploration is facilitated though the annual Offshore Petroleum Exploration Acreage Release prepared in collaboration between the Department of Resources, Energy and Tourism, and Geoscience Australia. The annual release is underpinned by a stable economic environment, and a regulatory framework that provides the industry with a variety of investment opportunities.
Australia has abundant natural gas reserves and is experiencing a rapid expansion of its LNG production capacity. Today, Australia is the world’s fourth-largest exporter of LNG, with a total export capacity of 24.3 million tonnes per annum from its three operational projects. Capacity will further increase to around 80 million tonnes per annum in 2017 once the seven projects presently under construction come online. These projects represent more than US$175 billion in capital expenditure announced since mid-2007, and result in Australia becoming the only country to use three LNG production models: conventional offshore gas with onshore LNG production; FLNG production; and, CSG-based LNG production.
This paper will provide detail about the acreage included in the 2013 Offshore Petroleum Exploration Acreage Release. Areas are carefully selected to offer the global petroleum industry a variety of investment opportunities. This paper will also discuss the supporting regulatory environment and new government initiatives, including the introduction of a five-year exploration strategy for acreage release and the introduction of a cash bidding system as part of future offshore petroleum acreage releases.
A petroleum geological overview of the 2013 offshore acreage release for petroleum exploration
Authors: Bernecker Thomas
Published: August 2017

The Australian Government formally releases new offshore exploration areas at the annual APPEA conference. The previous two releases were characterised by several large, gazetted areas in underexplored regions, a trend that is maintained this year with several frontier areas comprising more than 100 graticular blocks on offer. The recent uptake of new exploration permits in the Bight Basin, the offshore North Perth Basin, and the Roebuck Basin indicates a continuing strong industry interest in offshore frontier exploration.
A total of 31 areas in 13 geological provinces are formally released in 2013, and work program bids are invited for two rounds closing on 21 November 2013, and 22 May 2014. Area gazettal was, again, well supported by industry nominations.
The areas on offer are represented by an even mix of shallow and deepwater areas, as well as by areas close and distant to previous discoveries and producing fields. The Northern Carnarvon, Browse, and Bonaparte basins dominate new exploration opportunities in the 2013 release, while only four areas were gazetted in the North Perth, Otway, and Gippsland basins. These also deserve attention as they have exploration potential in underexplored parts of the basins and offer opportunities to test new play concepts.
Data coverage varies from being excellent in more mature areas to sparse in underexplored areas such as the North Perth Basin. The Australian Government continues to assist offshore exploration activities by providing free access to a wealth of open-file geological and geophysical data.
New exploration opportunities in the offshore Houtman and Abrolhos sub-basins, northern Perth Basin, WA
Authors: Rollet Nadege , Nicholson Chris , Jones Andrew , Grosjean Emmanuelle , Bernardel George , Kennard John
Published: August 2017

The 2013 Acreage Release Areas W13-19 and W13-20 in the offshore northern Perth Basin, Western Australia, cover more than 19,000 km2 in parts of the Houtman, Abrolhos, Zeewyck and Gascoyne sub-basins. The Release Areas are located adjacent to WA-481-P, the only active offshore exploration permit in the Perth Basin, granted to joint venture partners Murphy Australia Oil Pty Ltd, Kufpec Australia Pty Ltd and Samsung Oil and Gas Australia Pty Ltd in August 2012. Geoscience Australia recently undertook a regional prospectivity study in the area as part of the Australian Government’s Offshore Energy Security Program, which provides fresh insights into basin evolution and hydrocarbon prospectivity.
A sequence stratigraphic framework, based on new biostratigraphic sampling and interpretation, and an updated tectonostratigraphic model, using multiple 1D burial history models for Permian to Cenozoic sequences, have been developed. New geochemical studies of key offshore wells demonstrate that the oil-prone source interval of the Lopingian–Lower Triassic Hovea Member extends regionally offshore into the Abrolhos Sub-basin and potentially as far as the Houtman Sub-basin. This is supported by fluid inclusion data that provide evidence for palaeo-oil columns within Permian reservoirs in wells from the Abrolhos Sub-basin. Oil trapped in fluid inclusions in Houtman-1 can be linked to Jurassic source rocks, suggesting that multiple petroleum systems are effective in the Release Areas. The presence of active petroleum systems is also supported by the results of a recent marine survey. Potential seepage sites on the seafloor over reactivated faults correlate with hydroacoustic flares, pockmarks and dark colored viscous fluids that were observed over the areas. This may indicate an active modern-day petroleum system in the Houtman Sub-basin. Finally, a trap integrity analysis was undertaken to mitigate exploration risks associated with trap failure during Early Cretaceous breakup and provides a predictive approach to prospect assessment.
These results provide strong support for the presence of active petroleum systems in the offshore northern Perth Basin and upgrade the prospectivity of the Release Areas.
Onshore petroleum exploration acreage release
Authors: Green Peter
Published: August 2017

The petroleum industry in Australia is going through a major development phase with export LNG projects under construction on both the east and west coasts. Initial exploration for shale and tight gas has opened up new plays as well as increasing interest in many sedimentary basins that have been overlooked. Access to land onshore in Australia for petroleum exploration is, in some States, through a formal release process by the relevant jurisdiction. This is a compilation of material supplied by the States and Northern Territory in relation to land being made available onshore for petroleum exploration. Not all jurisdictions have new acreage available for exploration. In these cases, new initiatives being undertaken that directly relate to accessing land for exploration or the present state of exploration activity will be highlighted. Land that is being made available for exploration will generally be accompanied by information regarding its geological setting and petroleum potential. Previous exploration activity may be in summaries, including information in relation to the amount of pre-existing data available to future explorers. Exploration opportunities may include conventional and unconventional targets. The review of the areas may also include maps and sections related to the land being made available.
2012 PESA production and development review
Authors: Jurinak Jeff , Anderson Bruce
Published: August 2017

2012 was a pivotal year for Australian petroleum development and production, during a dynamic time in our region, and globally. Australian activity headlines are LNG, the continuing pace and scale of the development of major projects, and record national petroleum production. LNG development in Australia is proceeding apace, with seven sanctioned projects under construction in WA and Queensland. The scale of the major projects underway is being felt with competition for skills, materials and services driving cost inflationary pressures and, coupled with other factors—such as an historically high Australian dollar—has resulted in several announced budget increases and schedule slippages. In addition, the regulatory framework is evolving, as regulators adapt to new industry trends and technologies. Proponents of future developments and expansions will be seeking to sanction in a tougher, but potentially better-informed development environment.
Overall, national hydrocarbon production increased to a record high in 2012, attributable to a number of factors, but not least of which was the commissioning and successful start of commercial production of the Woodside-operated Pluto LNG development from the Pluto and Xena fields in the Carnarvon basin. Pluto was the first commissioned project since 2006, and may be viewed as the first of a number of developments that will be coming on-stream in the next few years, and will elevate Australia’s position in the ranking of world LNG production. Adding production from Pluto has allowed Woodside to take the lead position as the highest petroleum producer from BHP Billiton during 2012.
Activity is not limited to LNG. Other highlights for 2012 included the opening of the Devil Creek project on the North West Shelf, WA’s third domestic gas hub, with the potential to supply around 20% of the state’s needs. Cost increase and schedule delay is not limited to LNG either, with Yolla mid-life enhancement and the Kipper offshore development facing cost and schedule pressure.
In the broader global sphere, the highlight of 2012 is the extraordinary rise of unconventional oil in the US to the point of speculation about future US self-sufficiency. This parallels the rise of US unconventional gas in recent years, with gas supplies exceeding existing domestic demand and driving down the previously high domestic prices. Presently, only one US LNG project is approved for export; however, with an ongoing policy debate in the US about significant gas export verses retention to spur domestic growth, and favourable location of potential US access to the Asian market, the outcome is important for future competition to Australia’s cost-challenged LNG industry.
Among this the announcement by Santos of the connection of the first shale gas well in Australia to sales delivery—albeit as an appraisal well—is a notable occurrence as a potential forerunner of shale gas production in Australia.
Coal seam gas associated water treatment and management—opportunities and limitations
Authors: Jia Huanfei , Poinapen Johann
Published: August 2017

Coal seam gas (CSG) is a new major export for Australia. The production of CSG releases a significant amount of brackish water to the surface, known as associated water. Queensland’s Department of Environment and Heritage Protection (DEHP) has predicted that the peak yearly flow of the associated water could range between 100-280 gigalitres (GL) per year. This presents a major challenge to the CSG industry in water and its by-product (brine) management.
CSG water quality varies across regions, but is typically high in total dissolved solids, bicarbonate, hardness, and silica. Consequently, CSG water without treatment is unsuitable for beneficial uses. To date, reverse osmosis (RO) desalination processes with suitable pre-treatment steps have been employed to remove elevated salts and other compounds before CSG water can be used beneficially. One type of beneficial reuse of the treated water that has gained acceptance and prominence in recent times is the irrigation of agricultural crops and forestry.
RO brine, a highly saline stream, requires a managed response to ensure a socially, environmentally and financially sound outcome. Conventional evaporation in brine ponds is not considered favourably under existing government directions and, consequently, alternative solutions are sought. Thermal processes, such as brine concentrators, have been used in the treatment of CSG RO brine. The resulting high-quality distillate produced by thermal processes can be used in a number of applications along with a greater proportion of water recovered from such processes.
This peer-reviewed paper concludes that a thermal process in conjunction with a high-recovery RO membrane plant, configured as a hybrid membrane/thermal configuration, is probably a suitable solution to meet policy direction by improving system recovery as a precursor to advance associated water treatment and brine management. The discussion is generated out of MWH’s experience with CSG water treatment and management processes, which totals a number of significant projects in the CSG industry.
Quantifying fault reactivation risk in the western Gippsland Basin using geomechanical modelling
Authors: Swierczek Ernest , Zhen-dong Cui , Holford Simon , Backe Guillaume , King Rosalind , Mitchell Andy
Published: August 2017

The Rosedale Fault System (RFS) bounds the northern margin of the Gippsland Basin on the Southern Australian Margin. It comprises an anastomosing system of large, Cretaceous-age normal faults that have been variably reactivated during mid Eocene-Recent inversion. A number of large oil and gas fields are located in anticlinal traps associated with the RFS, and in the future these fields may be considered as potential storage sites for captured CO2. Given the evidence for geologically recent fault reactivation along the RFS, it is thus necessary to evaluate the potential impacts of CO2 injection on fault stability. The analysis and interpretation of 3D seismic data allowed the authors to create a detailed structural model of the western section of the RFS. Petroleum geomechanical data indicates that the in-situ stress in this region is characterised by hybrid strike-slip to reverse faulting conditions where SHmax (40.5 MPa/km) > SV (21 MPa/km) ~ Shmin (20 MPa/km). The authors performed geomechanical modelling to assess the likelihood of fault reactivation assuming that both strike-slip and reverse-stress faulting regimes exist in the study area. The authors’ results indicate that the northwest to southeast and east-northeast to west-southwest trending segments of the RFS are presently at moderate and high risks of reactivation. The authors’ results highlight the importance of fault surface geometry in influencing fault reactivation potential, and show that detailed structural models of potential storage sites must be developed to aid risk assessments before injection of CO2.
Low-cost flow-rate estimate in separate layers along gas wells from temperature and pressure profiles
Authors: Barrett Emile , Abbasy Imran , Wu Chii-Rong , You Zhenjiang , Bedrikovetsky Pavel
Published: August 2017

Estimation of rate profile along the well is important information for reservoir characterisation since it allows distinction of the production rates from different layers. The temperature and pressure sensors in a well are small and inexpensive; while flow meters are cumbersome and expensive, and affect the flow in the well. The method presented in this peer-reviewed paper shows its significance in predicting the gas rate from temperature and pressure data. A mathematical model for pressure and temperature distributions along a gas well has been developed. Temperature and pressure profiles from nine well intervals in field A (Cooper Basin, Australia) have been matched with the mathematical model to determine the flow rates from different layers in the well. The presented model considers the variables as functions of thermal properties at each location, which is more accurate and robust than previous methods. The results of tuning the mathematical model to the field data show good agreement with the model prediction. Simple and robust explicit formulae are derived for the effective estimation of flow rate and thermal conductivity in gas wells. The proposed approach has been applied to determine the well gas rate and formation thermal conductivity from the acquired well pressure and temperature data in field A. It allows for recommending well stimulation of layers with low production rates.
Lowering the phase-trap damage in tight-gas reservoirs by using interfacial tension (IFT) reducers
Authors: Lu Yangfan , Bahrami Hassan , Hossain Mofazzal , Jamili Ahmad , Ahmed Arshad , Qiu Chaolang
Published: August 2017

Tight-gas reservoirs have low permeability and significant damage. When drilling the tight formations, wellbore liquid invades the formation and increases water saturation of the near wellbore area and significantly deceases permeability of this area. Because of the invasion, the permeability of the invasion zone near the wellbore in tight-gas formations significantly decreases. This damage is mainly controlled by wettability and capillary pressure (Pc).
One of the methods to improve productivity of tight-gas reservoirs is to reduce IFT between formation gas and invaded water to remove phase trapping. The invasion of wellbore liquid into tight formations can damage permeability controlled by Pc and relative permeability curves. In the case of drilling by using a water-based mud, tight formations are sensitive to the invasion damage due to the high-critical water saturation and capillary pressures. Reducing the Pc is an effective way to increase the well productivity. Using the IFT reducers, Pc effect is reduced and trapped phase can be recovered; therefore, productivity of the TGS reservoirs can be increased significantly.
This study focuses on reducing phase-trapping damage in tight reservoirs by using reservoir simulation to examine the methods, such use of IFT reducers in water-based-drilled tight formations that can reduce Pc effect. The Pc and relative permeability curves are corrected based on the reduced IFT; they are then input to the reservoir simulation model to quantitatively understand how IFT reducers can help improve productivity of tight reservoirs.
Managing the risks and responsibilities of resource companies providing potable water
Authors: Hewitson Chris , Dec Eva , Lines Tony
Published: August 2017

This peer-reviewed paper examines the risks and responsibilities of water providers and the process resource companies should undertake to document how they will deliver a safe and secure water supply to their employees and contractors, and the communities in which they operate, thereby reducing the risks of water quality incidents and managing the impact to the organisation should an incident occur.
Water quality incidents can have major impacts to human health and the brand perception of the resource company supplying the water, and can potentially shutdown resource abstraction. Resource companies have a duty of care to provide a secure and safe drinking water supply. This is reinforced by state health departments directing resource organisations to comply with the Australian Drinking Water Guidelines (ADWG), which were updated in 2011 (National Health and Medical Research Council, 2011).
Organisations in the CSG industry experience an additional challenge—managing water by-product from gas extraction. There are drivers for the beneficial use of this water—including irrigation, aquifer recharge and municipal supply—resulting in changes to legislation in Queensland (DERM, 2010) that require a process similar to ADWG recommendations, where beneficial use or disposal may impact potable supplies.
The ADWG provides clear guidance to potable water providers—whether they are supplying a few consumers or major towns requiring a Drinking Water Quality Management System (DWQM System). This guidance includes documenting a clear process to securing a clean water source, making the water safe to consume and proving it is safe.
Developing a DWQM System enables resource companies to understand issues in supplying drinking water through regular review and improvement, while minimising and managing the health risks to consumers.
A new structural analysis of the Browse Basin, Australian North West Margin
Authors: Lawrence Sophie , Thompson Mark , Rankin Adrian , Alexander Joanna , Bishop Daniel , Boterhoven Ben
Published: August 2017

A new structural analysis is presented for the Browse Basin of the Australian North West Margin, integrating new observations based on a regional 2D seismic data-set and potential field data. Previously published plate reconstructions and gravity inversion modelling were used to understand the mega-regional context of this interpretation and propose a new history of basin evolution.
Key basin-forming northeast to southwest structural elements were developed during Carboniferous to Permian rifting, inherited fabrics from relaxed Proterozoic fold belts. Long-lived highs formed during this time delineated the structure of the basin through later Mesozoic rifting. Rifting was accommodated initially by inheritance of large basin-bounding Paleozoic listric faults and then development of new planar faults in the basin. This led to the formation of both rotated syn-rift sediment wedges and tilted fault block geometries. Structures related to several phases of inversion have been mapped, including a previously little-documented Early Cretaceous event. The influence of inherited structural trends and location of inversion structures is discussed.
This work provides a new understanding of structural inheritance and rift architecture, and highlights the complexity of the inversion history of the Browse Basin. It has implications for petroleum systems development and the timing of potential hydrocarbon trap formation.