bluuebunny/crossref_metadata_2025 huggingface dataset:
Why are decisions for oil and gas projects not always made the way they ‘should' be?
Authors: Newman David , Begg Steve , Welsh Matthew
Published: May 2018

The outcomes of many business decisions do not live up to expectations or possibilities. A literature review of neuroscience and psychological factors that affect decision making has been undertaken, highlighting many reasons why it is hard for people to be good decision makers, particularly in complex and uncertain situations such as oil and gas projects.
One way to diminish the impact of these human factors is to use the structured methodology and tools of Decision Analysis, which have been developed and used over 50 years, for making good decisions. Interviews with senior personnel from oil and gas operating companies, followed up by a larger-scale survey, were conducted to determine whether or how Decision Analysis and Decision Quality are used and why they are used in particular ways.
The results showed that Decision Analysis and Decision Quality are not used as often as the participants think they should be; some 90% of respondents believed that they should be used for key project decisions, but only ~50% said that they are used.
Six propositions were tested for why Decision Analysis and Decision Quality are not used more, and the following three were deemed to be supported:
• Decision Analysis and Decision Quality are not well understood.
• There is reliance on experience and judgment for decision-making.
• Projects are schedule-driven.
Further research is proposed to determine the underlying causes, and tackle those, with the aim being to improve business outcomes by determining how to influence decision makers to use Decision Analysis and Decision Quality more effectively.
How to monitor your safety instrumented system performance
Authors: Yam Andy
Published: May 2018

With the impending release of Edition 2 of the International Electrotechnical Commission (IEC) Standard 61511 in Australia, it is timely to revisit the topic of safety instrumented system (SIS) performance monitoring. Operators need to monitor the performance of their SISs to ensure that design assumptions are correct. Any incorrect assumption or error introduced during operation can result in an unsafe plant situation. Questions to consider include: how do operators know their plants are adequately protected; are protection systems performing as required, and do operators need to re-assess the safety of their plant’s process vis-à-vis the implemented safety instrumented systems; what are end-user obligations; how and is it possible to meet these obligations; and what additional requirements are there, and how much more prescriptive is Edition 2?
If any of the above questions are of concern, or if plant personnel are aware of their obligation to maintain and monitor the SIS during operations but are still not 100% sure if they are on the right track or need to do more, then this paper will prove useful.
In addition to knowing all the requirements to comply, actual implementation and maintenance of a program to monitor the performance of SIS can prove overwhelming. Not only do you need to be adept in maintaining a database, but you also need to understand how to consolidate various critical information sources in order to make sense of all the data collected.
Fortunately, there are solutions in the market to help end-users overcome these hurdles to effectively monitor SIS performance. This paper looks at some key areas that a complete solution should cover and what some of the features of such a solution are.
Decommissioning: taking control of your committed investment
Authors: Polson Robin
Published: May 2018

At the APPEA 2017 Conference in Perth, Bernadette Cullinane and Susan Gourvenec drew our attention to the looming challenge for Australia’s oil and gas industry in decommissioning its aging assets (Cullinane and Gourvenec 2017). While Cullinane and Gourvenec’s paper focussed on the experience challenge for the Australian industry, this paper will drill down to explore the funding and financial challenges and opportunities for decommissioning in the decades ahead.
In approaching the decommissioning of their assets, oil and gas companies must consider a broad range of stakeholders, beyond their immediate shareholders and board members. As we have seen in the development of new projects, Australian Government, environmental organisations and community groups, all have increasingly significant impact. These stakeholders have been considered and managed with (at best) varying degrees of effectiveness in the recent past. This impact will continue to grow for decommissioning of existing assets.
However, right now, with few decommissioning projects in play, the industry has a limited window of opportunity to set the agenda for how, when and under what kind of funding arrangements and financial structures decommissioning can take place. By getting ahead of the game and establishing best practices from the outset, the industry can demonstrate to Australian Government, environmental organisations and community groups a level of commitment and accountability that will allow us to move ahead on decommissioning, with reduced outside interference.
The window of opportunity is closing. The time to act is now.
‘Zero Routine Flaring by 2030': a new global industry standard
Authors: Cutler Jane , Hamso Bjorn , Sucre Francisco
Published: May 2018

The World Bank-introduced ‘Zero Routine Flaring by 2030’ (ZRF) Initiative is well on its way to establishing a new global industry standard; one that is very important if governments and industry are to make significant strides to help mitigate climate change.
Launched in 2015 by the UN Secretary-General and World Bank President, ZRF commits governments and oil companies to (a) not routinely flare associated gas in new oil field developments, and (b) to end routine flaring at existing (legacy) fields by 2030. (Routine flaring is defined as flaring during normal oil production operations in the absence of sufficient facilities or amenable geology to re-inject the produced gas, utilise it on-site, or dispatch it to a market. The ZRF Initiative clearly states that venting is also not an acceptable substitute for flaring.)
A review of the governments and companies that have already endorsed ZRF reveals that many of the major producers recognise the value of making a public commitment and working to end a 150-year-old industry practice. There are now over 70 endorsers, but more governments and companies must join the global effort if there is to be real progress and establishment of a de facto industry standard. Those that have endorsed the ZRF Initiative say it has other tangible benefits. For example, the many international oil companies that already have a no-flaring policy for new oil field developments consider the Initiative a positive contribution because it will level the playing field – other companies would adopt the same good practice and governments would require it. So, the Initiative also reduces regulatory uncertainty and risk.
To achieve ZRF on a global scale, collaborative action such as through the Global Gas Flaring Reduction Partnership (GGFR) – a public-private initiative comprising international and national oil companies, national and regional governments, and international institutions – will be required. GGFR is focused on increasing the use of natural gas associated with oil production by helping remove technical and regulatory barriers to flaring reduction, conducting research, disseminating best practices, and developing country-specific gas flaring reduction programs.
GGFR is also focused on helping develop financing tools for flare-out projects, such as a new program with the Global Infrastructure Facility (GIF) to fund feasibility studies of solutions to monetize flared or vented gas from onshore and offshore oil production facilities.
Navigating the Great Australian Bight using system models
Authors: Fulton Elizabeth A. , Bulman Cathy M. , Goldsworthy Simon
Published: May 2018

The expanding blue economy means the oil and gas industry is just one of many activities in marine and coastal ecosystems. The future management of ecosystems such as the Great Australian Bight (GAB) should be based on a sound knowledge of the physical, ecological, economic and social interactions among the human and natural system components. The Great Australian Bight Research Program (GABRP) has generated extensive new knowledge about the GAB system, making it one of the most well understood deep-water Australian ecosystems. It is a complicated system, with novel and newly recognised ecosystem pathways. A set of system models have been developed to help navigate this complexity, to integrate the new information and establish improved understanding of system processes and the implications of any activities in the region – including monitoring and management.
An experimental investigation into surface roughness of a hydraulic fracture
Authors: Movassagh Abbas , Haghighi Manouchehr , Kasperczyk Dane , Sayyafzadeh Mohammad , Zhang Xi
Published: May 2018

The fracture surface roughness is an essential characteristic of the hydraulic fracturing process and has not been fully explored. The surface asperities play a significant role in proppant flow and settlement, fluid leak-off and fracture tip movement. In this study, we performed an experimental investigation to evaluate the fracture surface roughness of a hydraulic fracture generated in the lab tests. The experiments were conducted using a polyaxial cell and a cuboid siltstone block with dimensions of 20 cm × 20 cm × 16.5 cm. The fracturing fluid was injected into a drilled hole in the specimen to initiate and propagate the hydraulic fracture in nearly homogeneous siltstone material. Low injection rates were applied to all lab tests to maintain slow and stable fracture propagation as in the field. The fracture surfaces were digitised by surface mapping techniques utilising high-resolution laser scanning method and analysed using a standard statistical way. Our results showed that the surface topography and roughness parameters are different in various selected segments. However, they follow an increasing trend in radial directions from the initiation point at the wellbore wall toward the specimen borders.
Radical disruption – renewables, technology and the arrival of ‘peak gas'
Authors: Thompson Gavin
Published: May 2018

Debate on the timing of peak oil has become mainstream, as shifting energy demand patterns are compounded by the accelerating threat from disruptive technology such as EVs. At the same time, natural gas demand is seen as a beneficiary of these changes – the much-vaunted transition fuel to a low carbon future. But what might happen to long-term gas demand when factors that could radically reshape energy markets become entrenched? Improvements in energy efficiency, growth in renewables, major advances in energy storage technologies and access to decarbonised electricity are now raising the prospect of ‘peak gas’.
In this paper, Wood Mackenzie presents an examination of the key uncertainties impacting the future of gas demand globally, including:
• How quickly can technologies such as batteries and storage be developed and what constraints might they face?
• Could environmental policy and falling costs mean we are currently underestimating the future growth in renewables – specifically wind and solar power?
• How are oil and gas companies responding to the challenges that lie ahead?
The impact of these developments will be critical for gas and liquefied natural gas (LNG) producers as they assess the timing, returns and demand for future gas supply. Indeed, for Australian developers these uncertainties could be enough to stop multi-billion-dollar LNG projects taking final investment decisions as early as the 2020s. Wood Mackenzie argues that the time for companies to address peak gas is now – the dynamics of marginal change will likely mean markets will be reshaped sooner than the industry is currently prepared to acknowledge.
The smart money: driving shareholder value through better capital allocation
Authors: Reid Stephen , Decker Frank
Published: May 2018

As shareholder activism has grown both in its scope and influence, management teams are under increasing pressure to justify their decisions around the allocation of capital – whether it be through dividends, share buybacks, an expansion project, M&A or a greenfield project. However, for the oil and gas sector, much like the mining sector, it has been historically difficult to demonstrate continued excellence in capital decision making. In the past, capital intensive, long-dated projects (multi-billion dollar LNG developments) and large-scale M&A saw returns and pay-offs that were both distant and uncertain. Now, with so much investor scrutiny and focus on short term performance, demonstrated capital discipline is paramount – oil and gas leaders must think very carefully about where they allocate capital. Although they present their own challenges, capital allocation decisions, unlike commodity prices or the macroeconomic climate, are within the control of companies, and if a model can be developed to deliver long-term value, these decisions will position shareholders and their management teams well for the future. This paper will chart the performance of a sample of oil and gas companies against their decisions around capital allocation and cost-reduction. The paper will demonstrate to oil and gas leaders the importance of aligning their organisational strategies and balance sheet investments to create future value for shareholders.
Empowering Australia in the global oil and gas standardisation initiative
Authors: Woodhams Andrew , Fletcher Ted , Weustink Menno , Taylor Miranda
Published: May 2018

The World Economic Forum has identified the oil and gas industry’s poor productivity performance as a significant barrier to the sanction of large capital projects. 75% of large exploration and production projects between 2010 and 2014 exceeded their budget by 50% on average and 50% of these projects exceeded schedule by almost 40%. A major cause of these poor productivity outcomes is the lack of standardisation. In Australia, the Productivity Commission raised similar concerns about Australian projects. In 2015, the government launched its competitiveness agenda that saw the formation of six industry growth centres, including National Energy Resources Australia (NERA) for oil and gas, coal and uranium.
In 2017, NERA, as part of the global standardisation initiative being pursued through the International Oil and Gas Producers Association, successfully delivered a project to elevate Australia to full participating member status of the International Standards Organisation’s Technical Committee for oil and gas, petrochemicals and energy. Australia’s participation is coordinated through Standards Australia’s committee, ME-092, that also oversees several working groups progressing specific initiatives to enhance Australia’s competitiveness.
This paper describes Australia’s position within the global oil and gas standardisation initiative, highlights the strategy being pursued to maximise productivity through the adoption of international standards and discusses areas being led by Australian initiatives as part of the international program. Information will be provided on how opportunities can be realised through this initiative and on the role of professionals in supporting Australia’s drive to build a regional oil and gas hub that will attract capital investment for decades to come.
Repositioning gas in the power generation mix
Authors: Wilkes Martin
Published: May 2018

Since the turn of the century, gas has been highlighted as the transition fuel to a lower emissions world, and, in 2011, the International Energy Agency published a special report entitled ‘Are we entering the golden age of gas’, which indicated that gas use could rise by over 50% to provide more than 25% of world energy demand by 2035.
Even though gas use has risen in tandem with the increase in renewable energy, over the past decade, coal has been the fastest growing fuel because developing countries choose cheap power to provide their growing energy needs. Gas has been, and continues to be, subject to a green, cheap squeeze; squeezed by cleaner renewables on the one hand, and cheaper coal on the other.
This paper will look at the impact that increasing amounts of renewable energy has on existing power generation and supply systems, and provide insights into the potential range of outcomes in emission levels, and the need to not only discuss renewable energy target, but to also understand the total energy mix, and the need to reposition gas from a transition fuel to the natural long-term companion of renewables.
Building a world-class Australian decommissioning industry
Authors: Bills Kym
Published: May 2018

Collaboration in decommissioning offshore infrastructure could save both industry and taxpayers billions of dollars and facilitate new industries and exports for Australia, especially in the Asia-Pacific region. At the end of the liquefied natural gas (LNG) plant construction boom, Australia must not miss out on this major new opportunity.
The 2017 bid for Commonwealth funding to establish a Decommissioning Offshore Infrastructure Cooperative Research Centre (DOI-CRC) involved more than 30 participants and many other collaborators. High-level commitments were made by Chevron, Woodside, Shell, BHP, ExxonMobil, Quadrant, The University of Western Australia, Curtin University, the University of New South Wales, Deakin University, Australian Maritime College, CSIRO and Australian Institute of Marine Science. A Perth-based DOI-CRC was supported by National Energy Resources Australia, National Offshore Petroleum Safety and Environmental Management Authority and other Australian Government bodies and by the Western Australian Government and its Chief Scientist and agencies but did not receive sufficient support from the CRC Advisory Committee.
Meeting decommissioning challenges in the North West Shelf, Bass Strait and the Northern Territory in a timely, robust, scientific, efficient and cost-effective manner that contributes to a sustainable marine environment should draw upon and augment international best practice with local capability and expertise. Good science and innovative engineering are needed to support regulatory approval of options such as ‘rigs to reefs’ and commercial opportunities such as in waste management and expanded fishing and tourism.
APPEA and operators wish to maintain DOI-CRC’s momentum and learn from UK research arrangements through funding marine science projects. But we must be much broader if we are to build a sustainable world-class Australian decommissioning industry. In particular, we need to work more closely with state and federal regulators and policymakers and undertake more engineering science research and innovation.
From hydrocarbons to electrons: creating new opportunities for the oil and gas sector
Authors: Cullinane Bernadette , Wood Michael , Ladbrook Barry
Published: May 2018

Today’s energy and resources companies must address many challenges to their traditional business models including the rapid emergence of available and economic renewable energy sources, ever tightening greenhouse gas emission policies and increased stakeholder expectations around transparency. While there is uncertainty regarding the impact of these developments, enormous opportunity exists for companies to forge pathways to a decarbonised future while at the same time creating new markets, products and services and increasing revenues.
Several leading Australian resources companies have recently embarked on programs to transition to a lower carbon and more diversified energy portfolio. These initiatives focus on integrating alternative forms of energy across value chains, making energy consumers central to their business models and increasing energy security for their companies and the country.
This paper discusses the drivers underlying these challenges, draws on case studies of how oil and gas companies are managing their journey, considers the impact such programs on the companies’ financial and operational performance and outline some implications and possible approaches.
Tectonostratigraphic framework of the Lower Keraudren Formation, Bedout Sub-basin: interplay of tectonics and sedimentary systems
Authors: Minken Jon , Thompson Melissa , Woodward Jack , Fernandes Fred , Fabrici Rylan
Published: May 2018

Recent drilling activity and new seismic data have contributed to the understanding of the Lower Keraudren Formation in the Bedout Sub-Basin. The Lower Keraudren Formation is a thick (>5 km) succession of strata that was deposited rapidly during the Anisian of the Middle Triassic. Distinctive characteristics related to sediment provenance, sediment supply and accommodation have facilitated subdivision of the Formation into eight informal units: the Milne, Crespin, Baxter, Caley, Hove, Barret, Palma, and Huxley members. Tectonic elements of the East Gondwana Interior Rift and the Bedout High influenced the Sub-basin geometry during deposition of the Lower Keraudren. Extensional tectonics of the East Gondwana Interior Rift generated a series of Palaeozoic tilted fault blocks and grabens, which influenced the stratigraphic architecture, sediment dispersal patterns and distribution of reservoir and source rock facies. The structurally proud Bedout High, a roughly circular (~60 km wide) igneous feature, created a northern boundary to deposition. Seismic stratigraphic interpretation has characterised the interval as a series of north west prograding wedges. Well based data indicates the section is dominated by fluvio-deltaic deposits. Separating the Caley and Hove Members is a significant unconformity that is associated with renewed uplift of the Bedout High and a change in sediment provenance. Chemostratigraphy and petrology indicates the Caley and older strata were derived from a more mature sediment source, whereas the Hove and younger a more immature metamorphic source. Distinct changes in reservoir quality are observed above and below the Caley–Hove unconformity. Below the unconformity, the older, more mature sandstones exhibit superior reservoir quality compared with the younger, more immature sandstones.
Geomechanical insights in the Bedout Sub-basin: exploiting technologies for understanding reservoir settings
Authors: Castillo David A. , Kuek David , Thompson Melissa , Fernandes Fred , Minken Jon , Colson Toby
Published: May 2018

An extensive collection of drilling and wireline data, core and lab strength tests, pressure tests and advanced geomechanical techniques has provided an unprecedented data set to better understand the impact that the stress regime has on characterising reservoir in the Bedout Basin area.
An important cost effective method for collecting data while drilling has been the deployment of logging-while-drilling image data followed by wireline image data to document the immediate impact that drilling has on well integrity and potential time-dependent wellbore integrity. Reliable estimates of the minimum horizontal stress (Shmin) were based on carefully executed extended leak-off-tests.
Fine-scale observations of drilling-induced isotropic wellbore breakouts, tensile cracks, anisotropic breakouts, and drilling-enhanced natural fractures were collectively used to constrain the Bedout Basin stress regime to be strike-slip (SHmax > SV > Shmin, where SV is the vertical stress and SHmax is the maximum horizontal stress) with stress magnitudes sufficiently high to induce shear failure and fracture permeability on a selected population of natural fracture orientations.
Advanced geomechanical modelling of breakouts in the Phoenix South-2 and Roc-2 wells indicated that a unique set of natural fracture induced anisotropic breakouts, which could not be explained as isotropic breakouts because of the high rock strength. In many situations, the responsible natural fracture or joint was undetectable in the image data, but the effect of the natural fracture systems was evident in the anisotropic breakouts.
The Phoenix South-2 well suddenly encountered elevated pore pressures (1.56 SG or greater) at total depth where there was no pronounced indication of a systematic pore pressure ramp in the overburden. Geomechanical modelling was used to independently confirm near normal pore pressures in the overburden by predicting that excessive breakouts would have formed if there was a pressure ramp given the ~1.1 SG mud weight used to drill the well.
Psyllium husk performance in drilling fluid at elevated temperature and pressure conditions
Authors: Ly Son , Yu Xiao , Zhang Xinsong , Salmachi Alireza
Published: May 2018

High performance water-based drilling fluid alternatives that meet performance objectives with minimal environmental impact must continually be developed. Drilling fluid performance is dependent on fluid characteristics, and among those most critical are viscosity and filtration. One avenue to improve drilling fluid performance is through enhancement by use of potent, water-soluble natural polymers.
Psyllium husk powder is an environmentally friendly natural polymer derived from ground-up surfaces of psyllium seeds (Plantago ovata). When in contact with water, psyllium husk powder forms a gel-like, extraordinarily viscous substance at very low concentrations. It was previously shown that pure psyllium husk is an excellent viscosity and filtration agent for water-based drilling fluid under standard conditions. Psyllium husk can also be used as a clay-extender to enhance viscosity and filtration performance of bentonite mud; however, further laboratory testing of this performance enhancement under elevated temperatures and pressures is required.
Extensive laboratory experiments were therefore conducted to test husk performance in bentonite mud under such conditions. An electronic rheometer and a temperature and pressure adjustable API filter press were used to evaluate viscoelastic and filtration mud characteristics respectively. Concentrations of 0.05–0.4% husk with 5% bentonite were tested at 25−120°C under 1500 psi. An optimal husk concentration of 0.1% was determined, increasing bentonite viscosity and yield point by up to 46.9% and 68.1% respectively. Filtrate loss rate and filtration cake thickness were reduced by up to 25.8% and 35.3% respectively. The optimal concentration was useable up to 70°C (~2800 m) before deflocculating was required.
Low-salinity waterflooding in non-polar oil
Authors: Al-Sarihi A. , Zeinijahromi A. , Bedrikovetsky P.
Published: May 2018

Enhanced oil recovery by low-salinity waterflooding is considered to have positive results only when polar components exist in oil. This study shows that low-salinity brine can result in incremental recovery for non-polar oil through fines-assisted waterflooding. Despite the traditional view of fines migration that it should be avoided because of its detrimental effect on reservoir permeability, this work shows that permeability decline is a main mechanism in the low-salinity effect on non-polar oil. Laboratory coreflood tests were performed on a clay-rich Berea outcrop core and a clean sand core to investigate the effect of clay migration when the core is saturated with non-polar oil. The results show that fines migration reduces residual saturation by 18%. In addition, a decrease in the water volume production was observed due to the decrease in water relative permeability.
Low permeability coal seam gas productivity enhancement by cyclic nitrogen injection technique (an adsorption simulation study)
Authors: Nguyen Hoa T. , Sayyafzadeh Mohammad , Haghighi Manouchehr
Published: May 2018

Coal seam gas (CSG) usually contains high levels of methane, which is mostly in the adsorbed state on micropores. For coal that is not highly permeable, stimulation may be required to enhance productivity. In this study, we propose a new technique to increase near wellbore productivity in tight CSG. This technique comprises three stages: injection, soaking and production. Firstly, nitrogen is introduced to the target formation while maintaining high reservoir pressure. Next, the well is shut for a period of time before the gases are flown back to the surface. The technique is based on competitive adsorption of methane and nitrogen during the shut-in period, which yields pressure build-up. Hence, with this combination of desorption, the coal matrix shrinks and permeability eventually increases. The proposed technique was tested by adsorption simulation at core scale. The model was constructed for crushed samples and the extended Langmuir isotherm and micro–macro kinetics models were applied in ASPEN adsorption software. Tight coal was then simulated with different porosity and sorption characteristics. Finally, we used the stress-sensitive permeability model Palmer–Mansoori to predict permeability changes. The results show that permeability is improved based on pressure variations. We observed 10% pressure increments with greater than 150% permeability enhancement. The model indicates the feasibility of the newly proposed technique to produce the ‘unproducible’. However, more experimental and simulation studies at a reservoir scale are needed to fully confirm the technique.
A new approach to value creation – stranded gas resource commercialisation via low-cost small scale floating LNG projects
Authors: Cha Daein
Published: May 2018

There are ~240 discovered, but stranded, offshore gas resources within the range of ~0.5 to 5.0 trillion cubic feet (TCF) of estimated ultimate recovery (EUR) of which ~40 such fields, representing 65 TCF of EUR, resides within Australian jurisdiction. Operators are challenged to commercialise these gas resources due to several factors such as:
• lack of materiality within their oil and gas resource portfolio,
• remote location, and
• lack of a low-cost development concept.
For such resources, a predetermined low-cost, small scale (∼1.0 million tonnes per annum production capacity) floating liquefied natural gas vessel and subsea wells tie-back development concept can be deployed to achieve commercialisation. Furthermore, the following should be promoted for the adoption to commercialise such gas resources:
• target breakeven liquefied natural gas (LNG) price as a key metric to confirm fit of the resource and the development concept,
• innovative financing and commercial structures to be co-developed among key stakeholders to enable project development within the constraint of a target breakeven LNG price, and
• differentiated LNG offtake value proposition for securing LNG offtake contracts that underpin project bankability.
BP's evolution in the face of Australia's transforming fuel supply chain: ensuring business sustainability as well as security of supply for the nation's demands
Authors: Tyzack Daniel , Sullivan Luke
Published: May 2018

BP has embraced the changing landscape of the fuel supply chain in Australia. Historically, fuel supply in Australia has been manufactured and supplied nationally. However, Australia’s future fuel supply will rely on a globalised supply chain in order to meet local needs. In response, BP has (among other initiatives) transformed its operations and maintenance approach to terminals and fuel distribution within Australia to guarantee a sustainable business model, offsetting the trend of high asset ownership costs and low efficiency.
When it comes to terminal management, BP’s creation of Australian Terminals Operation Management (ATOM), a joint venture between BP and UGL, differentiates BP from its peers. This model has proven fundamental to maintaining a competitive position in the Australian fuel industry. BP’s unique approach to meeting customer demands through the ATOM business is a success story that comes from pre-empting and embracing change.
Shining the spotlight on the petroleum resource rent tax
Authors: Wee Kenneth
Published: May 2018

The petroleum resource rent tax (PRRT), a 40% profits-based upstream tax that applies to Australian oil and gas projects, has come under significant scrutiny as to its effectiveness in providing an appropriate return to the community for the exploitation of Australia’s petroleum resources.
The April 2017 independent Callaghan review into the design and operation of the PRRT found that it remained the preferred way of achieving a fair return to the community from petroleum exploration and recovery, without discouraging investment into the sector. However, the Callaghan review recommended possible changes to the regime to improve its sustainability and compatibility with the current state of the industry, while ensuring fiscal stability for existing investments.
In response to the findings and recommendations of the Callaghan review, Australian Treasury embarked on a consultation process to investigate potential reform options to the PRRT. Government has yet to announce its decision on the way forward. What the future holds for the PRRT and the consequential impact on existing and new or proposed projects remain to be seen pending the Government’s chosen policy direction.
This paper covers the following:
• a survey of the economic rent theory underpinning the framework of the PRRT regime, including its pros and cons compared with other forms of resource taxation
• a review of key recent developments in the administration and interpretation of the PRRT law, and
• how the PRRT regime is anticipated to change and the associated repercussions on the after-tax economics and practical compliance for existing and future projects.
The importance of optimal geological zonation and choice of rock parameters in dynamic reservoir simulation: a case study for the Laminaria field
Authors: Behrenbruch Peter , Hoang Tuan G. , Bui Khang D. , Do Huu Minh Triet , Kennaird Tony
Published: May 2018

The Laminaria field, located offshore in the Timor Sea, is one of Australia’s premier oil developments operated for many years by Woodside Energy Ltd. First production was achieved in 1999 using a state-of-the-art floating production storage and offloading vessel, the largest deployed in Australian waters. As is typical, dynamic reservoir simulation was used to predict reservoir performance and forecast production and ultimate recovery. Initial models, using special core analysis (SCAL) laboratory data and pseudos, covered a range of approaches, field and conceptual models. Initial coarser models also used straight-line relative permeability curves. These models were later refined during history matching.
The success of simulation studies depends critically on optimal gridding, particularly vertical definition. An objective of the study presented is to demonstrate the importance of optimal and detailed vertical zonation using Routine Core Analysis data and a range of Hydraulic Flow Zone Unit models. In this regard, the performance of a fine-scale model is compared with three alternative, more traditional and coarse models. Secondly the choice of SCAL rock parameters may also have a significant impact, particularly relative permeability. This paper discusses the use of the more recently developed Carman-Kozeny based SCAL models, the Modified Carman-Kozeny Purcell (MCKP) model for capillary pressure and the 2-phase Modified Carman-Kozeny (2p-MCK) model for relative permeability. These models compare favourably with industry standard approaches, the use of Leverett J-functions for capillary pressure and the Modified Brooks-Corey model for relative permeability. The benefit of the MCK-based models is that they have better functionality and far better adherence to actual laboratory data.
Exploration of the south-eastern part of the Frontier Amadeus Basin, Northern Territory, Australia
Authors: Bache Francois , Walshe Paul , Gusterhuber Juergen , Menpes Sandra , Sheridan Mattilda , Vlasov Sergey , Holmes Lance
Published: May 2018

The Neoproterozoic to Late Paleozoic-aged Amadeus Basin is a large (~170 000 km2) east–west-trending basin, bounded to the south by the Musgrave Province and to the north by the Arunta Block of the Northern Territory. Commercial oil and gas production is established in the northern part of the basin but the southern part is still a frontier exploration area. Vintage and new seismic reflection data have been used with well data along the south-eastern Amadeus Basin to construct a new structural and depositional model. Three major phases of deformation controlling deposition have been identified. The first phase is characterised by a SW–NE trending structural fabric and is thought to be older than the deposition of the first sediments identified above basement (Heavitree and Bitter Springs formations). The second phase corresponds to the Petermann Orogeny (580–540 Ma) and trends in a NW–SE orientation. The third phase is the Alice Springs Orogeny (450–300 Ma) and is oriented W–E to WNW–ESE in this part of the basin. This tectono-stratigraphic model involving three distinct phases of deformation potentially explains several critical observations: the lack of Heavitree reservoir at Mt Kitty-1, limited salt movements before the Petermann Orogeny (~300 Ma after its deposition) and salt-involved structures that can be either capped by the Petermann Unconformity and overlying Cambrian to Devonian sediments, or can reach the present day surface. Finally, this model, along with availability of good quality seismic data, opens new perspectives for the hydrocarbon exploration of the Amadeus Basin. Each of the tectonic phases impacts the primary petroleum system and underpins play-based exploration.
Decommissioning – What's the fuss about?
Authors: Saraceni Pat , Liddle Keely
Published: May 2018

Offshore decommissioning is complex, challenging (both legally and operationally) and costly. With the rise in the number of fields approaching end of life (or economic viability), the interest in decommissioning in and around Australian waters is set to increase in the near to medium future. The lack of established federal laws regulating all aspects of decommissioning opens the door for Australia to show innovative leadership in how best to tackle end of life asset management in the oil and gas sector.
Australia’s learning in this area will be aided by the laws of jurisdictions that are better-versed and more experienced in offshore decommissioning, such as the United Kingdom, the United States and Norway. This paper will explore Australia’s current legal framework and the issues faced by Australia in this area. While clear policies and regulations are essential, this does not equate to a single rigid approach. A flexible (but consistent) approach is the ideal. By considering how international regulatory regimes for decommissioning may be adapted to Australia, the paper will propose actions regulators and participants in the industry can take now to prepare for and ride (rather than drown in) the decommissioning wave.
Unravelling the Triassic Mungaroo Formation within North Carnarvon Basin using Regional Stratal Slice Volumes
Authors: Marsh Tony , Kowalik Bill , Welch Rhonda , Powell Anne , Howe Heidi , Hallager Bill
Published: May 2018

Chevron has developed a new method for viewing, rendering and interpreting multiple, proportionally-flattened seismic surveys (US patent). The products of this method are referred to as Regional Stratal Slice Volumes (RSSVs). Within the Northern Carnarvon Basin (NCB), local RSSVs contain a patchwork of 22 3D seismic surveys covering an area of approximately 68 000 km2 and comprising a 4+ km-thick succession of alluvial to shallow-marine deposits of the Late Triassic Mungaroo Formation. Seismic slices for each constituent volume were spliced together, correlated with adjacent volumes and combined with supporting structural, cultural and well-based data. This has created a temporal series of unbroken, regionally-extensive, seismic snapshots which, when viewed successively, capture the evolving geomorphology and palaeogeography of the basin from east of Gorgon and Wheatstone out to the Exmouth Plateau.
Through the integration of the RSSVs and well data, the shoreline and marginal marine to non-marine transitions were identified and accurately mapped at an approximately 20 m vertical spacing throughout the Mungaroo Formation. This work resulted in an in-depth understanding of changing depositional environments at a regional scale. Observed, temporally-systematic fluctuations of the shoreline on the RSSVs provide a highly predictive stratigraphic framework for the basin. Additionally, RSSVs have been used to provide insight into regional NCB studies and to support localised prospect and field scale evaluations. Over the past three years, RSSVs combined with automatically generated closures have been used to identify significant additions to Chevron’s prospect portfolio.
Financing a mega LNG project and ‘raising the bar' in securing a social licence to operate
Authors: Tokunaga Yuko
Published: May 2018

A significant part of the development funds for the INPEX-operated Ichthys liquefied natural gas (LNG) Project comes from a record-breaking US$20 billion project financing package, which involves commitments from eight export credit agencies and over 24 global banks. Due to the scale and complexity of the project and the size of the investment, there is a high level of ongoing scrutiny by the project’s lenders with a particular focus on social and environmental performance. Financing from lenders demanded extra requirements to obtain and maintain the project’s social licence. This included a commitment to ensure the project’s plans for managing environmental and social issues met additional obligations, including International Finance Corporation’s Environmental and Social Performance Standards.
While these extra commitments posed some challenges, they have also supported INPEX and the project to improve its approach in engaging and working with local communities, including Aboriginal and Torres Strait Islander peoples, in the areas in which the project operates.
The auditing of these requirements also provided independent and objective performance reviews that have supported INPEX and the project to continuously improve performance. The requirements have also encouraged INPEX to engage effectively and more openly with stakeholders to further develop and deepen positive and trusted relationships with key stakeholders.
Through delivering on commitments to lenders, INPEX has raised the bar, to deliver higher standards of social performance. This has reaffirmed the Company’s commitment to community and social engagement and strengthened our performance within Australia, by adopting best practice approaches.
The future of safety in the oil and gas industry
Authors: De Nichilo Stephenie
Published: May 2018

A focus on safety is at the heart of oil and gas work practices. Often the number one objective for companies operating in the oil and gas industry is to ensure everyone goes home from work without injury or illness. Industry has historically held a view that best practice in safety is demonstrated if a workplace has an absence of accidents or when injury rates are reduced to zero. However, research has shown that this approach limits the ability to develop a resilient safety culture.
Santos has established a future view of safety and developed a new 3-year strategy that has been built around six fundamental safety principles. Safety initiatives that are designed to embed the safety principles have commenced, and, as a result, safety conversations in the workplace are changing from injury rates and statistics to a focus on the prevention of harm, effectiveness of critical controls for high-risk exposures, learning and workforce leadership and risk competency.
Reliable cost-efficient distributed energy systems with a high renewable penetration: a techno-economic case study for remote off-grid regional coal seam gas extraction
Authors: Bamberger Joachim , Chang Ti-Chiun , Mason Brian , Mesanovic Amer , Münz Ulrich , Priest Warner , Thompson Ross , Szabo Andrei , Wu Xiaofan
Published: May 2018

As our energy systems evolve with the adoption of more variable renewable energy resources, so will our oil and gas industry play a pivotal role in what is expected to be a lengthy transitional phase to a greater mix of renewables with a reliance on fast, reliable gas peaking power generation, which have lower greenhouse gas emissions, and short delivery periods to construct. Oil and gas companies are also rapidly moving towards becoming integrated energy companies supplying a mix of gas, oil, photovoltaic power, wind power and hydrogen, coupling these into the electrical and gas grids.
We discuss some of the components and tasks of a distributed energy system in its various system guises that contribute to a more cost effective, reliable and resilient energy system with lower greenhouse gas emissions. We discuss the role that hydrogen will play in the future as oil and gas companies explore alternatives to fossil fuels to address their need to reduce their carbon footprint, substituting or supplementing their conventional gas supply with renewably produced hydrogen.
We talk about how Australia with its excellent renewable resources and the opportunity to potentially develop a new industry around the production of renewable fuels, power-to-X, such as hydrogen, with the potential for the oil and gas industry to leverage its existing assets (i.e. gas pipelines) and future embedded renewable assets to produce hydrogen through electrolysis with the intention of supplementing their liquefied natural gas exports with a portion of renewably produced hydrogen.
Thermal Conductivity Enhancement Phenomena in Ionic Liquid-Based Nanofluids (Ionanofluids)
Authors: Oster Kamil , Hardacre Christopher , Jacquemin Johan , Ribeiro Ana P. C. , Elsinawi Abdulaziz
Published: May 2018

The dispersion of nanoparticles into ionic liquids leads to enhancement of their thermal conductivity. Several papers report on various enhancement values, whereas the comparison between these values with those from theoretical calculations is not always performed. These thermal conductivity enhancements are desired due to their beneficial impact on heat transfer performance in processes requiring the utilisation of heat transfer fluids. Moreover, on the one hand, the theoretical modelling of these enhancements might lead to an easier, cheaper, and faster heat transfer unit design, which could be an enormous advantage in the design of novel industrial applications. On the other hand, it significantly impacts the enhancement mechanism. The aim of this work is to discuss the enhancement of thermal conductivity caused by the dispersion of nanoparticles in ionic liquids, including the analysis of their errors, followed by its theoretical modelling. Furthermore, a comparison between the data reported herein with those available in the literature is carried out following the reproducibility of the thermal conductivity statement. The ionic liquids studied were 1-butyl-3-methylimidazolium dicyanamide, 1-butyl-3-methylimidazolium bis(trifluoromethylsulfonyl)imide, 1-ethyl-3-methylimidazolium ethylsulfate, 1-butyl-1-methylpyrrolidinium bis(trifluoromethylsulfonyl)imide, and 1-hexyl-3-methylimidazolium hexafluorophosphate, while carbon nanotubes, boron nitride, and graphite were selected as nanoparticles to be dispersed in the investigated ionic liquids to design novel heat transfer fluids.