bluuebunny/crossref_metadata_2025 huggingface dataset:
Low-frequency seismic: the next revolution in resolution
Authors: Long Andrew , Reiser Cyrille
Published: August 2017

Ultra-low seismic frequencies less than about 7 Hz cannot be produced by conventional air gun arrays, for any configuration and for any towing depth. There is a profound difference between improving low-frequency recovery by removing source and receiver ghosts (achievable) and improving low-frequency injection on the source side (an unrealised dream).
If 1–7 Hz amplitudes could be usefully injected into the earth, it would be possible to facilitate much sharper seismic representation of geological contacts and internal features, and seismic inversion would yield robust and precise predictions of reservoir properties—without well control. The net result is fewer exploration and appraisal wells, greatly reduced exploration and development risks, and optimised recoverable reserves.
Furthermore, an emerging seismic pursuit known as full waveform inversion (FWI) makes the bold promise that raw seismic field gathers can be directly used to invert for the highest achievable velocity models, almost without any human intervention. These models will bypass the traditional lack of low-frequency information in band-limited seismic data, and facilitate the aforementioned ambition of seismic inversion without well control. FWI, however, is confronted by the paradox that ultra-low-frequency seismic gathers are the necessary input for stable results.
This paper describes new technologies that may enable the injection of strong 2–7 Hz amplitudes into the earth, and explains in simple terms how FWI can already be pursued as a robust complement to the prediction of accurate reservoir properties.
The low-frequency revolution is already here.
Minimising the impact of shale and tight gas projects in Western Australia: an assessment of the existing regulatory framework
Authors: Hunter Tina
Published: August 2017

This paper analyses the WA legal framework that regulates the impact of shale and tight gas project development, especially during the extended appraisal phase. It assesses whether the existing regulatory framework in WA is more suited to conventional petroleum projects, particularly regarding the application of the Environmental Plan requirements, and triggers for referral to the Environmental Protection Authority (EPA) during the extended appraisal phase of project development.
This paper not only seeks to understand whether the existing framework is suited to the commercial development of shale and tight gas resources in WA, it also provides information and points of discussion for industry and regulators so that there might be a consensus in the development of shale and tight gas (especially during the field appraisal and development phase) in the existing WA regulatory framework, and the development of shale gas resources in Australia generally.
The paper initially considers the existing regulatory framework of shale and tight gas activities in WA, including an examination of the Western Australian Department of Mines and Petroleum as the lead agency in the development of unconventional gas resources. It also assesses whether the existing regulatory framework for shale and tight gas activities in WA is best practice for the appraisal phase of shale and tight gas activities.
Tectono-sedimentary evolution and source rock distribution of the mid to Late Cretaceous succession in the Great South Basin, New Zealand
Authors: Sahoo Tusar , King Peter , Bland Kyle , Strogen Dominic , Sykes Richard , Bache Francois
Published: August 2017

The Great South Basin, off New Zealand’s southeast coast, has attracted renewed exploration interest from major petroleum companies since 2005. The distribution of the mid Cretaceous to Paleocene source rocks (coals and coaly mudstones) is a critical component in evaluating basin prospectivity. This paper delineates source rock distribution from seismic facies characterisation, and presents a series of updated paleogeographic maps over the initial (Cretaceous) phases of basin evolution.
Basin evolution has been analysed from mapped sequence stratigraphic boundaries and isochron maps. Seismic facies were characterised based on the amplitude, continuity, and stacking pattern of the reflection packages. The identified facies were calibrated with well data for age, gross lithology, and gross depositional environment. Areas of source rock deposition were demarcated using seismic attribute interval maps, from which a series of updated paleogeographic maps was prepared.
Four second-order sequences have been identified within the Cretaceous succession. The lower two sequences are mainly fault bounded and were deposited in a syn-rift phase. In contrast, the upper two sequences reflect a change in basin character from rifting to a post-rift thermal sag phase. Source facies within both the syn- and post-rift sequences were deposited in mainly non-marine to marginal marine settings, although there is also the possibility of lacustrine source rocks in isolated syn-rift depocentres. The wide geographic spread of source rock intervals within the Cretaceous sequences allows for a variety of petroleum generation and exploration play scenarios.
The Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations 2013
Authors: Webster Stuart , Patel Sandip
Published: August 2017

These Regulations have been proposed under the Petroleum and Geothermal Energy Resources Act 1967 to replace the existing Schedule of Onshore Petroleum Exploration and Production Requirements 1991 (Amended 21 May 2010).
The Department of Mines and Petroleum (DMP) is the agency that administers the regulations on behalf of the Minister and keeps the Minister informed of petroleum or geothermal energy resource activities. A draft was released on 5 April 2014 for public comment. The precise form and language of the proposed Regulations may change after public consultation, but the intent of the regulations will remain the same.
The regulations will provide the framework for administration and compliance for petroleum field developments, geothermal energy projects, well construction and data submission and release. Activities are expected to be carried out in accordance with good oilfield practice and be compatible with the optimum long-term recovery of petroleum or geothermal energy. The Resource Management and Administration Regulations (RMA) have moved from a prescriptive type of regime to an objectives-based risk management regime requiring operators to manage their operations ensuring world’s leading practice and a fit-for-purpose design.
It is expected that operators will apply the relevant standards appropriate for their activities. It is understood also that technology will change and that standards might be changed to embrace the new technology. It is this factor that makes objectives-based regulation more apt than prescription-based regulation. Another factor is that prescription is unlikely to cover every possible circumstance that might occur.
The focus is on a whole-of-life approach to exploration and development, from an initial exploration process, through any well interventions all the way to final decommissioning. This includes requiring titleholders to consider what maintenance and monitoring programs will be in place throughout the life of wells and to be ready for eventual decommissioning.
The DMP has a continuous improvement process which involves monitoring developments in regulation worldwide. Published papers on drilling, completion, hydraulic stimulation, cementing and production on both conventional reservoirs and also shale and tight sands have been, and continue to be, researched to ensure that the regulations cover all aspects of petroleum and geothermal resource development.
Prospectivity of the 2014 offshore acreage release areas for petroleum exploration
Authors: Bernecker Thomas , Edwards Dianne , Kuske Tehani , Lewis Bridgette , Smith Tegan
Published: August 2017

The Australian Government formally releases new offshore exploration areas at the annual APPEA conference. Industry nominations provided guidance for the selection of gazettal areas, and in 2014 all 30 areas are supported by such nominations. The release areas are located across various offshore hydrocarbon provinces ranging from mature basins with ongoing oil and gas production to exploration frontiers. Work program bids are invited for two rounds closing on 2 October 2014 and 2 April 2015, while the closing date for four cash bid areas is 5 February 2015.
Twenty-nine of the 2014 Release Areas are located along Australia’s northern margin within the Westralian Superbasin, which encompasses the rift-basins that extend from the Northern Carnarvon Basin to the Bonaparte Basin. Evolution during Gondwana break-up established a series of petroleum systems, many of which have been successfully explored, while others remain untapped.
Only one area was nominated and approved for release on Australia’s southern margin. The 220 graticular blocks cover almost the entire Eyre Sub-basin of the Bight Basin. In the context of the recent commencement of large-scale exploration programs in the Ceduna and Duntroon sub-basins, this release area provides additional opportunities to explore an offshore frontier.
Geoscience Australia’s new long-term petroleum program supports industry activities by engaging in petroleum geological studies that are aimed at the establishment of margin to basin-scale structural frameworks and comprehensive assessments of Australian source rocks underpinning all hydrocarbon prospectivity studies.
2013 PESA production and development review
Authors: O'Brien Geoff , Campi Monica , Bethune Graeme
Published: August 2017

The boom in Australian oil and gas development continued in 2013, with record overall investment of $60 billion. This investment resulted from spending on the seven LNG projects under development, together with that on numerous other oil and gas developments. These projects are expected to collectively contribute up to 665 million barrels of oil equivalent (MMboe) to Australia’s oil and gas production, which totaled 513.8 MMboe in 2013. LNG, presently Australia’s seventh largest export, is likely to soon rival the nation’s largest export, iron ore.
By the end of 2013, three of the LNG projects under construction—Gorgon, Queensland Curtis LNG (QCLNG) and Gladstone LNG (GLNG)—were more than 70% complete; first LNG will be before the end of 2014 for QCLNG and in 2015 for Gorgon, GLNG and Australia Pacific LNG (APLNG). The other three LNG projects—Wheatstone, Prelude and Ichthys—are close behind.
These new LNG projects follow Pluto, Australia’s third LNG project, which commenced production in 2012. A full year of production from Pluto drove increased gas production in 2013. Woodside also completed the North Rankin redevelopment and continued development of the Greater Western Flank, both of which will extend the life of the North West Shelf (NWS) project.
A number of other projects also commenced production.
In the Carnarvon Basin, oil production began at Santos’s Fletcher-Finucane Field, and at BHP Billiton’s Macedon project, domestic gas production started. In the Timor Sea, PTTEP’s Montara Field began production of oil.
In Victoria, the ExxonMobil Kipper-Turrum-Tuna project came online, with the production of gas from Tuna and oil from Turrum. Production of gas from Origin Energy’s Geographe Field (as part of the Otway Gas Project) commenced in mid-2013.
Onshore oil production grew in 2013, with the Cooper-Eromanga Basin now producing more oil than any other onshore Australian basin. A major effort is underway to increase production from the western flank oil trend and to develop both the conventional and unconventional gas fields in the Cooper Basin.
Spending on the development of new projects probably peaked in 2013 and there is growing concern about a dearth of future projects, with expansion of existing LNG projects and development of new projects being pushed back due to a combination of increased costs and growing international competition. There are also ongoing industry concerns about impediments to onshore gas exploration and development generally.
Projects and the community—coexistence in practice
Authors: Cotter John
Published: August 2017

Strong domestic and global demand for energy will continue to drive further gas exploration and development across Australia over coming years.
From Queensland’s onshore gas industry experience the key foundation stones that have helped to build community trust have included: clear and unambiguous industry policy for resources and agriculture; science based approach to managing and monitoring groundwater; fair and balanced approach to land access; greater transparency on industry data and activities; investment in long term community infrastructure such as roads and telecommunications; and genuine opportunities for local businesses to grow and succeed.
Queensland has this year also introduced a new regional planning framework that seeks to control what is appropriate development in areas of agricultural and environmental significance. The new approach gives landholders and communities a greater say upfront on how onshore gas and resource developments can occur.
As other East Coast States grapple to establish their own onshore gas industry, there is still much more to be done in Queensland as the major CSG-LNG export projects move from construction to operation and ongoing gas well development programs are rolled out into new areas and communities. In addition, exploration by the emerging shale gas industry is bringing similar community engagement challenges to other parts of the Queensland.
Formally established as an independent statutory body less than 12 months ago, the GasFields Commission Queensland seeks to manage and oversee the relationship between landholders, regional communities and the onshore gas industry in Queensland. It has and will continue to play an important role in helping identify and address community expectations about how the onshore gas industry develops and evolves.
The role of water management in unlocking unconventional resources
Authors: Crisp Gary , Walsh John , Shaw Mark , Hertle Chris
Published: August 2017

Water management for unconventional resources is a complex, multidisciplinary subject that cannot be overlooked. Traditional oilfield development strategies view water as an afterthought that must be dealt with once the field matures and water cut begins to escalate. When this strategy is employed for shale gas developments, water usage is higher than necessary, trucking costs become high, and site remediation becomes time consuming and costly. For shale gas developments, the high-volume and high-quality requirements of water during the lifecycle of field development are a game changer. Water management for unconventional resources requires logistics planning, engagement of field services providers, and technology selection. Each of these issues need to be addressed in the early planning stages and must be tailored for the location and water types involved.
This extended abstract takes a holistic view of water management for unconventional resource development across Australia. Management strategies are compared and contrasted for the different unconventional resource types, across different locations, considering all of the factors mentioned above, together with an understanding of regulatory differences, water source options, disposal options, and the different types of water involved. These factors are compared (in the context of North American developments) for CSG in Queensland, tight gas, and unconventional shale gas developments in the Cooper Basin and WA. As these different resources are developed, it is important to understand why the water management strategies are, and must be, different (as discussed in this extended abstract).
Construction of major LNG pipelines in Queensland—challenges, achievements, and lessons
Authors: Barrows Mark , Richards Leon , Byth Ben
Published: August 2017

Introduction
The Queensland economy has experienced a significant surge in investment in recent years through the unprecedented level of capital investment in the LNG sector. These major projects have required major pipeline connections between the Surat Basin and processing facilities on Curtis Island, near Gladstone. McConnell Dowell Constructors (Aust) Pty Ltd (in joint venture with Consolidated Contracting Company Australia Pty Ltd) have constructed the major pipeline infrastructure for the QCLNG and APLNG projects. This extended abstract and its presentation explore the challenges, achievements, and lessons through these projects including early contractor engagement, engineering, procurement, resourcing, safety, environment, stakeholder engagement, and construction.
The challenge
The team faced the challenge of delivering three significant construction projects concurrent with an unprecedented level of design and construction activity associated with other packages associated with the LNG investment activity. This scope included:

QCLNG Gas Collection Header (197 km, 42 inch) and QCLNG Export Pipeline (334 km, 42 inch)
APLNG Condabri Lateral (56 km, 36 inch) and APLNG Export Pipeline (357 km, 42 inch), and;
QCLNG Narrows Crossing was a challenging 13 km pipeline section spanning creeks, marshland, tidal areas and works on Curtis Island.
Techniques for the 5.35 km tidal/marine section included a 1.5 km horizontal directional drill (HDD) section, a 1.56 km coffer dam, and a 2.45 km dredged sub-sea crossing as well as extensive temporary works.
Developments in LNG pricing and price reviews under LNG SPAs in Asia-Pacific
Authors: Jones Angus , Young Michael
Published: August 2017

At a time when there is increasing, possibly unprecedented, discussion and speculation about the future structure for the pricing of Australian LNG into Asian markets, it is appropriate to reflect on the present market position, assess likely areas of risk and change, and discuss potential outcomes. Many in the LNG industry refer to a paradigm shift in pricing, others to a period of transition; either way, change is upon us and the implications for LNG sellers are significant. This extended abstract highlights the key drivers of this change and it discusses models for price reviews and how these reviews may evolve in coming years.
Remote area exploration—challenges and solutions
Authors: Casey Tom
Published: August 2017

In Australia, onshore oil and gas exploration is increasingly focusing on prospects in remote areas. While working in a remote area avoids many of the constraints and obstacles facing onshore development, it also presents a unique set of challenges such as logistics and mobilisation and the efficient delivery of required environmental surveys, cultural heritage management, and stakeholder and landholder engagement. The absence of integration between technical and subsurface-program planning and supporting functions such as approvals, native title and cultural heritage, and stakeholder engagement can substantially increase the risk of delays and cost overruns. Clear forward planning of short- and medium-term exploration activities can identify opportunities for cost savings and schedule efficiencies. Drawing examples from two unconventional oil and gas exploration programs in remote western Queensland, the extended abstract discusses some of the key challenges to working in a remote area including safety, the importance of early engagement with stakeholders and ways to manage some of the key risks to project schedules and delivery. Highlighting some of the innovative approaches to securing regulatory approval used by AMEC in securing approvals for seismic campaigns and drilling programs, the author examines the interaction between the subsurface program and the approvals required to allow subsurface activities to happen.
Balancing the people equation—how enhanced collaboration can help solve labour challenges in the LNG industry
Authors: Cann Geoffrey , Giles Steve
Published: August 2017

The operating environment of the LNG industry is increasingly complex as companies must balance the management of present and expected growth amidst growing economic uncertainty, volatile commodity prices, and increasing environmental and regulatory pressures. Additionally, growth in the industry is shifting workforce challenges and shaping human capital trends. These workforce challenges include:

attraction and retention of talent;
labour and skills shortages;
managing employee turnover/retention;
compensation expectations; and,
productivity and employee engagement.
As long as projects address this problem individually, the prospects for retaining skilled employees, improving sustainable productivity, and driving labour costs down are limited. A collaborative industry approach is required to minimise risk and cost for all, while still providing ample employment and development opportunities in the sector. This extended abstract explores industry collaboration as a means to addressing labour challenges, it presents evidence about how the Canadian Oil Sands industry approached this issue, and it discusses people collaboration opportunities for Australian LNG.
Sword or a shield? The changing dynamic of the regulatory landscape for Australian gas projects
Authors: Scott Gavin
Published: August 2017

From increased domestic opposition to CSG, to international legal challenges about the project financing of gas projects, the Australian gas industry is under siege from numerous stakeholders—communities, domestic governments and non-government organisations both in Australia and internationally. What this has meant for the industry is a significantly increased risk of in doing business in Australia. A key reason for this elevated risk is that stakeholders are becoming increasingly savvy in the legal and quasi-legal avenues for challenging a project—and regulators are increasingly providing stakeholders the tools to do this. During the past two years, we have seen a number of regulatory regimes used, not simply to protect stakeholders’ rights under these regimes, but as part of a strategy to undermine the legal, financial, and reputational foundations of project as a whole. These regimes include:

the domestic and international social and environmental impact standards for the financing and assessment of projects;
land access and compensation regimes; and,
the native title and cultural heritage protection regimes.

As a response to stakeholder action, regulators are also becoming more reactive and regulations more proscriptive. This extended abstract examines the financial and operational impacts of using regulatory regimes as a sword, rather than a shield, against gas proponents, using case studies including the challenge to US Ex-Im’s funding of the APLNG project and the James Price Point project. This extended abstract highlights how, in this new legal environment, proponents must balance compliance with relationships, domestic pressures with international standards and cost with exposure to risk.
Early engagement with NOPSEMA
Authors: Cahuzac Claude
Published: August 2017

The Ichthys LNG Project includes a central processing facility (CPF) that is the world’s largest semi-submersible platform. The Ichthys CPF is also the first semi-submersible in Australian waters. Given the novelty of the development concept, the complexity of the design, and the scale of the facilities, the Ichthys Project joint venture participants INPEX and Total wanted to gain a better understanding of what the Australian regulators would be looking for as part of the approval process prior to committing to a final investment decision (FID). On a voluntary basis, the project launched an early engagement with NOPSA (later NOPSEMA) in 2011 to review the design safety case for the CPF. This was the first time such an early engagement process had been undertaken by the regulator. A significant benefit of the early engagement process for both parties was good communication and feedback leading to the establishment of a mutually beneficial long-term relationship. The early engagement process identified no show stoppers at that stage. Feedback from the regulator was incorporated in the detailed engineering. The Ichthys Project considers that the early engagement process with NOPSEMA was positive and constructive. It contributed to an FID being taken in January 2012. INPEX continues to engage proactively with NOPSEMA.
Development planning of deepwater gas fields: the application of floating production platforms
Authors: Xia Jinzhu
Published: August 2017

Producing North West Australia (NWA) deepwater hydrocarbon reserves, particularly gas reserves to LNG plants, poses unique challenges. These include extreme metocean conditions, unique geotechnical conditions, long distances to infrastructure and LNG plants, as well as high reliability/availability of supply. This extended abstract addresses important technical, commercial, and regulatory factors that drive the field development planning, including the selection of suitable production facilities for these deepwater hydrocarbon developments off NWA. While all-subsea developments have been an inspiration for offshore engineers for a few decades, subsea gas compression, dehydration, power supply, and control are still technically and commercially demanding, especially for long distance tie-backs. Subsea well intervention and facility maintenance requirements also favour the application of dedicated floating platforms. A wet or dry-tree floating production platform, therefore, is required in most cases. Whereas Semisubmersible, TLP, Spar, FPSO, and FLNG (or LNG FPSO) designs all have the attributes to be a host gas production facility or a part of a production system, only oil FPSOs have been installed in this region to date. Linkages between key reservoir and fluid characteristics and surface facility functionalities are discussed in this extended abstract. Advantages and disadvantages of various platform designs are compared. A focus is on the influence of regional drivers and site characteristics, in particular, metocean and geotechnical conditions and remoteness of the NWA fields. The differentiation between oil and gas developments are addressed. It is emphasised that platform applicability and compatibility should be assessed in the context of field development planning for individual projects to achieve optimum risked life cycle financial values.
Unconventional reserves and resources in the Petroleum Resource Management System (PRMS): a square peg in a round hole?
Authors: Peacock Douglas
Published: August 2017

Estimation and reporting of unconventional hydrocarbon reserves and resources have been a subject of intense focus in recent years. As unconventional hydrocarbons become increasingly important, it is essential that practices keep pace with a rapidly changing industry. The PRMS was primarily developed for conventional hydrocarbons although it is applicable to all accumulations, including unconventional. Force-fitting the PRMS for use in unconventional reservoirs is problematic. Many key areas would benefit from better definition and guidance. These areas include: assessment and reporting of prospective resources, definition of a prospect, risk assessment, definition of a discovery, extent of discovery, and linkage of reserves to the definition of project. Unconventional gas developments for LNG export present particular challenges. One primary purpose of reserves and resources definitions is to provide consistency of terminology and reporting for all parties involved including operators, investors, governments, and regulatory bodies. Within the industry, there is widespread acceptance that unconventional hydrocarbons are different, not only in how they are developed but also in how reserves and resources are evaluated and reported. Present practices may not fit neatly into the PRMS requirements, so compromises must be made. In particular, the PRMS axes of risk and uncertainty become blurred with present unconventional practices. This extended abstract highlights the many issues that make estimation and reporting of unconventional resources problematic within the PRMS and it suggests possible solutions to enable a more appropriate set of definitions and guidelines to be prepared.
Australian oil and gas exploration: the dawn of a new fiscal regime?
Authors: Wee Kenneth , O'Hare Janelle
Published: August 2017

The ever-evolving Australian tax landscape has brought particular attention to the scope of exploration activities in the oil and gas industry in recent times. While recent developments have attempted to shed light on the interpretation of œexploration expenditure, the narrow view adopted has raised more questions than answers, which may significantly impact the after-tax economics of projects in the oil and gas industry. Examples include:

the recent AAT decision in the ZZGN case and the commissioner’s views set out in the draft taxation ruling TR 2013/D4 on the scope of deductible exploration expenditure in the PRRT context; and,
the then Labor-led federal government’s proposed changes in the 2013–14 federal budget to limit an upfront deduction on œgenuine exploration activities for income tax purposes, which would have a far-reaching impact.
Broadly, the recent reforms seek to limit the application of the exploration expenditure deductibility rules to the technical analytical work undertaken to evaluate/appraise the resource and expenditure incurred in direct relationship with said technical work. This presents various tax technical, commercial and practical issues that signal a new dawn in the approach to exploration expenditure for participants in the oil and gas industry. This extended abstract analyses the recent reforms and their impact on the oil and gas sector, provides an outlook of the new direction of potential fiscal change, and assesses what this might mean for the Australian oil and gas industry.
Assessment of shale gas pore systems
Authors: Al Hinai Adnan , Rezaee Reza , Esteban Lionel , Dargahi Hanieh Jafary
Published: August 2017

Assessing shale gas petrophysical properties is a major challenge in the industry mainly due to its ultra-low matrix permeability. The ability of a formation to convey fluid through a porous media ultimately depends on the pore geometry and pore network. Shale pore geometry is acknowledged as being exceptionally complex and limited research has been done on the characterisation of pore networks of shale formation because of constraint in sampling, measurement resolution, and the highly heterogeneous nature of the rock. This study focuses on characterising a Permo-Triassic shale gas reservoir in the Perth basin, WA by assessing pore structures, using mercury injection capillary pressure (MICP), nuclear magnetic resonance (NMR), and scanning electron microscopy (SEM). MICP porosity corresponding to total connected porosity showed a narrow range 3–3.5%. Samples with the lowest peak radius had the lowest permeability and least percentage of macro-pore volumes indicating poor connectivity. T2 NMR response from partially saturated samples has a mono-modal distribution centred around 0.35ms with an average of 3% porosity. Two populations are observed from brine saturated samples and a shift in the T2 peak toward longer T2 between 0.43 and 0.56 ms. The specimens are also studied by using SEM to identify different types of pores. This indicated that higher proportion of interparticle pores is promising a higher porosity and, in contrast, the specimen with dominant intraparticle pores is representative of low porosity. The combination of MICP, NMR, and SEM is an ideal approach to overcome their individual limits on pore size resolution and external influences.
Quantitative application of post-stack inversion of organic-rich shale based on rock physics linear relationship and 3D seismic data, Perth Basin, Western Australia
Authors: Altowairqi Yazeed , Rezaee Reza , Urosevic Milovan
Published: August 2017

Unconventional resources such as shale gas have been an extremely important exploration and production target. To understand the seismic responses of the shale gas plays, the use of rock physical relationship is important, which is constrained with geology and formation-evaluation analysis. Since organic-rich shale seismic properties remains poorly understood, seismic inversion can be used to identify the organic-rich shale from barren shale. This approach helps identify and map spatial distributions and of the organic rich shales. This study shows the acoustic impedance (AI), which is the product of compressional velocity and density, decreases nonlinearly with increasing total organic carbon (TOC) content. TOC is obtained using Roc-Eval pyrolysis for more than 120 core shale samples for the Perth Basin. By converting the AI data to TOC precent on the seismic data, we therefore can map lateral distribution, thickness, and variation in TOC profile. This extended abstract presents a case study of the northern Perth Basin 3D seismic with application of different approaches of seismic inversion and multi-attribute analysis with the rock physical relationships.
Application of logging-while-drilling spectroscopy to evaluate volume of clay, grain density, and porosity in a low porosity, high temperature environment—offshore Western Australia
Authors: Bartelucci Paolo , Firinu Mauro , Jones Anthony , Yan Ping
Published: August 2017

Formation evaluation in low porosity, low salinity, and high temperature reservoirs poses many challenges. The environment is hostile to many logging tools due to their temperature limits and there is greater uncertainty related to petrophysical parameters compared with conventional formations. Additionally, in low porosity and low salinity reservoirs, resistivity contrast between hydrocarbon and water filled rocks is often missing. This extended abstract presents a case study from offshore WA where a petrophysical model has been created with logging while drilling measurements including spectroscopy data to improve estimation of mineralogy, clay volume and porosity, thereby reducing saturation evaluation uncertainty. Spectroscopy measurements can be analysed to derive dry weight elemental concentrations of various elements such as silicon, calcium, iron, and sulfur. These concentrations have been subsequently used as input to compute a multi-mineral petrophysical model using a least squares inversion technique. We demonstrate that spectroscopy can be used independently to obtain an accurate volume of clay instead of gamma ray, spontaneous potential, or porosity logs. Moreover, matrix properties such as grain density, which enhance the accuracy of porosity estimation derived from bulk density, are also derived from spectroscopy dataset. Good agreement with core validates the petrophysical model. Also demonstrated is how the petrophysical model reduces the uncertainty in clay volume and porosity, from which more accurate water saturation can be derived in these tight reservoirs. Calibrating the spectroscopy information to core data allows the mineralogical and geological model to be extended to the intervals where core data are not available.
Using palaeogeographic reconstructions to understand lithological variability within the Early Cretaceous Gage Sandstone and South Perth Shale in the Vlaming Sub-Basin, offshore southern Perth Basin
Authors: Lech Megan , Southby Chris , Lescinsky David , Wang Luiqi , Jorgensen Diane , Borissova Irina , Johnston Stephen
Published: August 2017

The Early Cretaceous Gage Sandstone and South Perth Shale formations are a prospective reservoir-seal pair in the Vlaming Sub-basin. Plays include post-breakup pinch-outs in the Gage Sandstone with the South Perth Shale forming top seal. The Gage reservoir has porosities of 23–30% and permeabilities of 200–1,800 mD. It was deposited in palaeotopographic lows of the Valanginian breakup unconformity and is the lowstand component of the thick deltaic South Perth (SP) Supersequence. To characterise the reservoir-seal pair, a detailed sequence stratigraphic analysis was conducted by integrating 2D seismic interpretation, well log analysis and new biostratigraphic data. Palaeogeographic reconstructions for the SP Supersequence were derived from mapping higher-order prograding packages and establishing changes in sea level and sediment supply. Higher resolution Gage reservoir reconstructions were based on seismic facies mapping. The Gage reservoir forms part of a sand-rich submarine fan system and ranges from canyon confined inner fan deposits to middle fan deposits on a basin plain. Directions of sediment supply are complex, with major sediment contributions from a northern and southern canyon adjacent to the Badaminna Fault Zone. The characteristics of the SP Supersequence differ markedly between the northern and southern parts of the sub-basin due to variations in palaeotopography and sediment supply. Palaeogeographic reconstructions reveal a series of regressions and transgressions leading to infilling of the palaeo-depression. Palaeogeographic reconstructions for the SP Supersequence portray a complex early post-rift depositional history in the central Vlaming Sub-basin. The developed approach is applicable for detailed studies of other sedimentary basins.
Operational efficiency improvement by using logging while drilling (LWD) fluid sampling and pressure-testing device
Authors: Martin Steve J , Tran Pei-Chea , Marshall Steven
Published: August 2017

Abstract
An operator in Asia Pacific required a large sample volume from a gas reservoir for accurate non-hydrocarbon gas (NHCG) content analysis from two extended reach wells. This extended abstract highlights the use of an LWD fluid sampling and formation pressure-testing device to overcome numerous challenges, including a highly deviated wellbore, stuck pipe, oil-based mud (OBM) gas-sampling issues, and prevention of geo-chemical absorption.
Application
The choice to use an LWD fluid sampler was based on several factors that reduced significant risks. Due to the well’s deviated nature, the only traditional wireline fluid sampling solution would have required a pipe-conveyed logging mechanism. This would have added rig days to the project and increased the risk of stuck pipe. To prevent geo-chemical absorption, the storage tanks were manufactured with a specialised metallurgic design. This would be tested by applying a customer-requested coating to half the tanks and monitor differences in geo-chemical content. To prevent differential sticking, testing sequences would be limited to 90-minute intervals.
Results, observations, and conclusions
After two runs in separate wells, a total of 25 samples were acquired containing more than 19 litres of fluid. Due to the reduced invasion profile as a result of LWD technology, fluid stability was reached within the 90-minute threshold. Furthermore, results showed only 8% OBM contamination—half the amount seen in offsets from wireline produced fluid samples. Finally, due to the improved operation efficiency and the quality of the samples, the customer estimates that it saved nearly $10 million in rig costs and millions more in reduced retrofitting costs of the production facility.
Significance of subject matter
This extended abstract highlights a major step-change in fluid sampling technology. Operators no longer need to consider a well’s deviation in the ability to collect fluid samples. The recap of the two wells will offer additional best practices and risk mitigation techniques for future LWD sampling projects. It also adds yet another LWD technology that provides consistent wireline equivalent data.
Tracerco Discovery: the world's first subsea computed tomography (CT) scanner for non-intrusive pipeline inspection
Authors: Robins Lee
Published: August 2017

Tracerco Discovery is the world’s first subsea CT scanner, providing high-resolution wall integrity data plus detection of hydrates and other deposits for flow assurance purposes. It is deployed as a remotely operated vehicle (ROV) and the inspection is carried out from the outside of the pipeline. It is the only non-invasive technology capable of inspecting unpiggable coated pipelines and there is no need to remove and replace the pipe’s protective coating. Unpiggable pipelines, especially coated ones, have proven extremely difficult (and in most cases impossible) to inspect for integrity and wall loss issues. An externally deployed tool to do this is needed by the global pipeline industry. Gas hydrates and other pipeline deposits pose a large challenge for the oil and gas industry as they can form restrictions that can result in costly shutdowns and serious safety threats. It is, therefore, important to be able to locate such restrictions subsea with high accuracy to allow safe and efficient remediation operations.
Discovery benefits:

Production can continue and normal operations are not affected.
A high-resolution tomographic image of wall thickness and pipe contents at each scanning location is provided to 2 mm resolution.
Coating does not need to be removed.
Suitable for gas, liquid, or multiphase flow.
Suitable for rigid and flexible lines.
Pipe-in-Pipe lines and pipe-bundles can be inspected to measure the wall thickness of outer and inner pipes.
The presentation of this extended abstract covers the background of the development work, gives a description of the technology, and shows recent results.
Recovering large Brownfield projects in distress
Authors: Stewart Andrew
Published: August 2017

A large body of knowledge exists about how to plan and establish projects for success; from project management guidelines to staged gate-execution methodologies. Despite such prescriptive means to guarantee project success, the upstream oil and gas industry has a poor track record for delivering large projects. Little guidance exists on how to restore delivery assurance to partially executed projects in distress. Furthermore, recovery efforts for large brownfield projects, mid-way through their execution, are further complicated and highly constrained.
Operators and contractors alike are understandably concerned about the high failure rate of projects, particularly as Australia competes for global capital in the final investment decision for a project’s development. Issues cover the full spectrum of safety, cost, schedule, start-up, and operability. Furthermore, unanticipated issues such as industrial relations, resourcing, project controls, estimate basis, and design changes all play a central role in why projects find themselves in distress.
In a recent case study, a structured recovery approach restored delivery assurance to a $900 m upstream brownfield project. Despite the numerous challenges encountered during the recovery efforts, the project went on to deliver ahead of its revised cost and schedule commitment, while also achieving outstanding safety performance. The self-governance program was instrumental in restoring delivery performance through responsive decision making that was robust, repeatable and preserved free calendar time for early intervention on high value recovery issues. The journey of recovery also restored a fractured client and contractor relationship by fostering a project delivery environment that was highly collaborative.
Optimiser: automated design and optimisation of CSG and water gathering systems
Authors: van Wagensveld Steven , Garlick Paul
Published: August 2017

The capital-intensive nature of CSG upstream-gathering systems and the need to optimise the cost of the facilities in this industry place great focus on their cost optimisation by operating companies and design contractors. CSG-gathering networks present an ideal opportunity for design optimisation as they are highly branched, consisting of tens or hundreds of individual pipeline segments between nodes, with a wide range of available pipeline sizes. Determination of line sizes in these complex systems is not intuitive; analytical methods of line size selection is time consuming and cannot guarantee that the most cost-effective permutation of line sizes is selected. This extended abstract presents a software tool developed by Fluor that automates the hydraulic design of the CSG and water-gathering systems and determines the optimal set of line sizes based on capital cost for almost any network-routing configuration. Monte Carlo analysis is used to model the uncertainty associated with gas and water production rates and a genetic algorithm is implemented to determine the set of gathering system line sizes that provide the maximum gas and associated water deliverability for the minimum installed cost. This tool is both fast and robust, and has been proven through its application on a major CSG development project in eastern Australia. The tool is also highly flexible; it can be tailored to project specific requirements, conditions, and inputs; and, it can be applied to networks other than CSG with similar challenges.
Gorgon Project: environmental acoustic recognition sensor (EARS)
Authors: Barnard David
Published: August 2017

The Asian house gecko (Hemidactylus frenatus) presents a significant risk to the unique environment of Barrow Island, the location of the Chevron-operated Gorgon Project. The island’s climate would suit the establishment of this non-indigenous species, which could displace the five known native gecko species.
Originating in Asia, this pest has spread to almost 9 new locations by hitchhiking on international vessels and cargo. To help detect possible gecko activity on the Gorgon Project, a unique device has been developed to specifically detect the sound of the gecko call.
EARS can detect the sound of a gecko’s call from up to 2 m away. Connected to a wireless network, it sends an alert when a call is registered detailing time, location, and a sound file to aid detection. Placed on cargo and vessels travelling to Barrow, it is also deployed in Australian supply bases, international fabrication yards, and marine offloading facilities on the island.
EARS provide Gorgon Quarantine with a constant presence and are particularly useful for detecting nocturnal species. It complements Gorgon’s existing quarantine surveillance programs and is one of many measures to ensure Barrow Island remains free from non-indigenous species.
The Gorgon Project is operated by an Australian subsidiary of Chevron and is a joint venture of the Australian subsidiaries of Chevron (47.3%), ExxonMobil (25%), Shell (25%), Osaka Gas (1.25%), Tokyo Gas (1%) and Chubu Electric Power (0.417%).
How companies can manage community perceptions of the CSG industry
Authors: Commins Sally
Published: August 2017

In today’s digital age, individuals, companies, and entire industries have never been more exposed and publicly answerable for any actions or planned developments they may take. This has become particularly apparent in the case of Australia’s CSG industry. Community and broader public perception of the industry is, for the most part, unfortunately unfavourable—why is this? The present global transparency agenda, a phenomenon that is witnessed in many other emerging industries, is incredibly susceptible to misinformation. Any individual, through accessible mediums such as Twitter, Facebook, and YouTube can create a popular grassroots movement in an instant, which is often embraced by the public without any appropriate critique. How does an industry combat misinformation? How do industries tackle the issue of a public so willing to embrace a negative perception of an emerging industry without the normal processes of analysis and examination? This extended abstract offers insight about the mindset of these communities througha qualitative analysis of public perceptions of the CSG industry, practical advice about how to most effectively communicate your company’s message to the industry, and an insight about how communities consume their media and how this is changing.