bluuebunny/crossref_metadata_2025 huggingface dataset:
Hydrocarbon charge history of the Gippsland Basin
Authors: Liu Keyu , Eadington Peter , Mills David , Kempton Richard , Volk Herbert , O'Brien Geoffrey , Tingate Peter , Goldie Divko Louise , Harrison Michael
Published: August 2017

As part of a larger petroleum system analysis and resource re-evaluation research program in the Gippsland Basin, over 400 samples from 29 selected wells in the Gippsland Basin were investigated using quantitative fluorescence techniques developed by CSIRO Petroleum, including the quantitative grain fluorescence (QGF) and QGF on extracts (QGF-E) and the total scanning fluorescence (TSF) techniques. Preliminary results have provided new insight into the hydrocarbon migration and charge history of the Gippsland Basin.
The investigation has revealed:

widespread occurrence of palaeo oil columns in some of the major gas fields, indicating that a significant amount of oil was charged into these reservoirs prior to a subsequent gas accumulation;
that some of the current oil intervals appear to have received a relatively late oil charge, either through new charge or through palaeo oil re-distribution due to adjustments within the petroleum system;
palaeo oil columns appear to be restricted to a certain distance range from the major source kitchens; and,
evidence of a sequential oil migration and displacement along structural highs where reservoirs distal to the source kitchens received progressively lighter and more mature palaeo oils.
These findings are consistent with the oil generation and migration model proposed by O’Brien et al (2008). Fluid inclusion petrographic investigations and molecular composition of inclusions (MCI) analysis are currently underway that will provide additional information on the hydrocarbon charge history in the Gippsland Basin.
The effect of mercury contaminants in major gas developments
Authors: Henderson Malcolm , Hansen Kevin
Published: August 2017

Over the past ten years the region has witnessed the unforeseen presence of mercury during gas production which has affected projects not only in southeast Asia but more recently in Australian waters. This has caused major operational challenges and has often involved costly production impairment, loss of condensate sales value and major brownfield modifications.
Today–s awareness of mercury has seen a new vigilance in well testing programmes intended to address the identification of mercury in gas streams during the early appraisal and concept development phases of an asset lifecycle.
This paper looks at the ways in which operating companies have resolved the issue of unforeseen mercury production to date, and the operational experience and lessons learned.
The paper describes some of the fundamental testing programmes as well as the available technologies for treatment and removal of mercury from production and effluent streams. It also identifies the impact of mercury on the design and operation of specific parts of the process as well as the overall impact on facility topsides.
The impact of mercury on a development is shown to be manageable and least costly where identified and addressed during the conceptual stage of a project development. Technical, environmental, safety and regulatory issues associated with mercury can be tackled, minimising risk of production deferment, and the costs incurred can be quantified and incorporated into economic models.
Unlocking Australia's oil future—exploration to exploitation
Authors: Cullen Frances , Webber Paul
Published: August 2017

Since 2000 Australia has ceased to be self-sufficient in terms of oil production and petroleum demand. As a net importer of crude oil it is expected that imports will continue to fulfil a growing percentage of the country’s liquid petroleum needs. Analysts are predicting a decline in oil production over the next decade with current producing fields and discovered resources failing to fill the gap created by rising consumption. In an increasingly gas focussed industry, oil is competing with both liquefied natural gas (LNG) and coal seam gas (CSG) projects for investment. As one of the top 20 oil consumers in the world, Australia’s growing demand for petroleum liquids continues to highlight the declining domestic supply.
This poster will identify and review the various components that will play a role in arresting the predicted decline curve. Exploration success in frontier basins is crucial along with the development of discovered resources in mature regions. In addition, future near-field and satellite exploration, with developments using existing infrastructure, will be instrumental in the stabilisation of oil production. This poster will also highlight planned high-impact exploration wells and examine the effect that potential discoveries could have on the country’s petroleum resources.
Australia’s oil future could see a reduced dependence on imported crude, resulting from frontier exploration success opening up new oil provinces. Future options for oil production also include a re-evaluation of oil prone regions using new technology to develop discovered reserves and target higher risk and overlooked plays.
New exploration opportunities in the offshore northern Perth Basin
Authors: Jones Andrew
Published: August 2017

The petroleum prospectivity of the northern Perth Basin has been assessed by Geoscience Australia (GA) as part of the Australian Government’s Offshore Energy Security Program, in support of the 2011 offshore acreage release. This assessment includes the first published synthesis of data from fourteen new field wildcat wells drilled in this part of the basin since the Cliff Head 1 discovery (2001), and the interpretation of new regional 2D seismic data acquired during GA survey 310.
Most petroleum accumulations in the northern Perth Basin are associated with Permian and Triassic source and reservoir intervals, and are found onshore and nearshore (ie. Cliff Head, Frankland, Dunsborough and Perseverance discoveries). In addition to the technical and commercial successes, numerous wells in the offshore part of the basin have intersected residual oil columns indicative of trap breach.
New and legacy palynological data from Permian to Cretaceous strata in offshore wells have been used to provide age constraints for a sequence stratigraphic framework for this part of the basin. New seismic data show Permo-Triassic strata that are stratigraphic equivalents of the productive onshore and nearshore Perth Basin petroleum system, also occur within Permian half-graben in the outer Abrolhos and Houtman sub-basins. Source rock, oil stain and fluid inclusion sampling from this interval suggest that the proven onshore petroleum system is also effective in the offshore. A refined tectono-stratigraphic model for the offshore basin provides insights into basin evolution, prospectivity and contributing factors driving trap breach. Geochemical sampling in the context of the new detailed sequence framework, including from recently dredged rock samples from incised canyons, has also provided insight into the potential effectiveness of a Jurassic/Cretaceous petroleum system in the Houtman and Zeewyck sub-basins.
Kick detection and well control in a closed wellbore
Authors: Nas Steve
Published: August 2017

Closing the wellbore at the top with a rotating control device (RCD) for some kinds of managed pressure drilling (MPD) operations raises a number of issues with regards to well control and kick detection. The wellbore is closed and the standard flow check of looking into the well is no longer possible. The use of a RCD provides drillers with an additional level of comfort because it is a pressure management device, but it doesn’t eliminate the need to have well control as a primary objective. In recent MPD operations, it has already been observed that well control procedures are relaxed as a result of managed pressure drilling. Is managed pressure drilling the same as primary well control, and how do we deal with kicks in managed pressure drilling operations? At what point in a well control process do we hand over from MPD to drillers’ well control, and who is responsible?
This paper will present some of the issues that need to be considered when planning and conducting MPD operations. Early kick detection and annular pressure control are promoted as an essential part of MPD operations, but there can be confusion as to where the responsibility for well control lies. Does the responsibility remain with the drilling contractor and operator or with the provider of the MPD services. The paper provides some case studies where MPD and well control conflicted, causing a number of issues that in some cases led to the loss of wells.
A new, field-proven, cost-effective solution for MEG regeneration unit issues in offshore Australia gas production
Authors: Sanford Elizabeth , Alapati Rama
Published: August 2017

Several gas fields are being developed off the coast of Western Australia. The risk for hydrate blockages in these fields is high and presents several challenges for hydrate inhibition, including high subcoolings, low water salinities, and high system temperatures. The current strategy is to use mono-ethylene glycol (MEG) for hydrate inhibition, which includes MEG regeneration units (MRUs) in the design of the facilities. The installation and maintenance of MRUs capable of handling the large required volumes of MEG is costly and other issues such as scale, foaming, and accumulation are a concern when using an MRU. Therefore, the use of a low dosage hydrate inhibitor (LDHI) is being considered for some developments.
Kinetic hydrate inhibitors (KHIs) are typically considered for gas fields, not anti-agglomerate low dosage hydrate inhibitors (AA-LDHIs). KHIs, however, are not effective at high subcoolings and can become unstable when subjected to the high temperatures of the MRUs. Instead, a new generation of AA-LDHI chemistry can be considered for Australian gas fields.
Field data will be presented supporting the new AA-LDHI’s effectiveness in inhibiting hydrate blockages in a gas/condensate field, eliminating the need for MEG and the MRU. The new AA-LDHI chemistry is being evaluated for several Australia projects, and data supporting the chemistry’s stability at temperatures greater than 150°C and its effectiveness with low-water salinities will also be presented. The new AA-LDHI chemistry could eliminate the need for MEG or greatly reduce the volume of MEG required for inhibition, which would reduce CAPEX and OPEX.
A study of subsurface integrity issues for the Mondarra underground gas storage field
Authors: Serfaty Jonathan , Pogson Mark , Haq Bashirul
Published: August 2017

In gas reservoirs, issues related to declining deliverability and injectivity, well integrity and reservoir integrity are often found. These may become more common, however, in fields used for underground gas storage (UGS). This may be due to extreme operating conditions–primarily cyclical phases of production and injection often associated with large pressure and temperature fluctuations within the reservoir and wellbore, in addition to operating with significant pressure depletion.
This study identifies specific sub-surface integrity issues that have affected the Mondarra gas storage facility. The Mondarra facility is Western Australia’s only UGS operation, owned and operated by the APA Group: Australia’s largest natural gas infrastructure business. Specific sub-surface integrity issues related to UGS were investigated. Results indicate that the production and injection cycles have decreased deliverability by 4.4% annually since 2007, primarily by plugging pore throats with inorganic precipitates, such as siderite and organic residues from the reciprocating compressor.
Reservoir integrity, represented as a reduction in effective connected volume, has been identified as an issue following early re-pressurisation of the field. Detailed production monitoring and reservoir modelling has been used to investigate this risk and determine the likely range of outcomes. The mechanism of this reduced effective connected volume is uncertain; however, suggested reasons include: pressure-induced changes in the conductivity of micro-fractures and transmissibility of faults; compaction of the reservoir; or, water encroachment post depletion. Furthermore, sub-surface modelling has indicated a complex connectivity picture with multiple compartments and variable permeability layers impacting gas storage operations.
Small company economics–net present value versus net cash flow
Authors: Scott Michael
Published: August 2017

This paper is primarily written for the benefit of the small company that survives hand-to-mouth on a day-to-day basis. Personnel working in large profitable oil companies that spin off lots of positive cash flow may have difficulty empathising with the example.
Net present value is a commonly accepted method of project valuation. Globally, projects are valued, ranked, justified, bought and sold using this technique.
For all companies, however, cash is considered to be king. Cash funds exploration activities and corporate costs and allows companies to continue trading without returning to shareholders for additional funds. Both the solvency of the company and the dilution of share value are extremely important considerations for company directors.
For a small company with income being generated from a single small field, an example is presented where a simple decision is considered: keep the field and live off the annual income or sell the field and live off the declining balance.
This is an extremely simple example used to demonstrate the power of cash flow. No alternative investment is available and no exploration success from continued exploration drilling is experienced–the directors are only focused on funding the company’s ongoing obligations.
The conclusion from the analysis is that cash flow from a project may be preferred over selling a project for net present value and then funding the company’s obligations from the proceeds of the sale and declining funds balance.
The ultimate lesson for companies is that cash flow, however insignificant, can greatly increase their chances of long-term survival.
Total Depth Solutions' technologies provide effective, efficient and safe well construction method to mitigate borehole problems
Authors: Whitby David , Utama Budi , Reading Richard
Published: August 2017

Permit TL/2 in the Carnarvon Basin, WA, presents several challenges for top hole drilling and casing running operations. Previous experience showed that drilling the 16” hole section and running 13⅜” casing was typically a time consuming phase of the well due to fluid losses and tight hole conditions, consequently requiring the use of seawater to drill, back reaming, wiper trips and occasional spotting of pills.
The initial solution delivered to the operator as an alternative method to get 13⅜” casing to total depth (TD) was to employ a casing drill bit to ream the casing to bottom while also delivering an improved drill-out time. This would be coupled with a sophisticated, unique, reliable and simply operated top drive casing running system that was already installed on the rig. Reviewing the Weatherford Total Depth Solutions teamâs systems with cost, time and capabilities analysis, the operator was certain that the application of a complete drilling with casing system (DwC™) would mitigate the known hole problems and yield a safe and more cost-effective surface hole operation, significantly reducing non-productive time (NPT).
This paper reviews: the problems that were traditionally encountered during conventional surface hole drilling and casing running operations; the decision-making process that the operator followed prior to employing DwC technology; and, the hazard mitigation and economic benefits realised through a one-way trip to total depth of about 1,000 m TVDRT, which broke to date the longest Weatherford 13⅜” DwC interval globally by the service company and operator.
Integrated operations program with Statoil
Authors: Haake David
Published: August 2017

Several years ago, IBM established its Smarter Planet vision: to bring a new level of intelligence to how the world works—to how every person, business, organisation, government, natural system, and man-made system interacts. Mr Haake will present a case study from our collaboration with Statoil on integrated operations.
Statoil defines integrated operations (IO) as: collaboration across disciplines, companies, organisational and geographical boundaries—made possible by real-time data and new work processes—to reach safer and better decisions faster. To help identify the methods, technologies and work processes necessary to integrate its operations, Statoil appointed a research and development consortium consisting of ABB, IBM, SKF and Aker Kvaerner. The Statoil TAIL IO project was aimed at improving operations at fields approaching the end of their life-spans—the stage where production rate is declining, the facilities are aging, and the cost of operation is high.
The result is a set of integrated operations solutions based on industry standards that offer great promise.
“Our efforts to bring more integration and collaboration to our production processes are critical to the future of the offshore industry. IBM has shown a strong commitment to helping us achieve this goal.”—Adolfo Henriquez, head of Integrated Operations, Statoil.
IBM Research, is the world’s largest private research institution.
The IBM annual research and development budget is nearly $6 Billion. IBM is also an active member and participant in the development and leadership of multiple petroleum industry standards bodies: Mimosa and Open Operations & Maintenance Integrated Operations of the High North (IOHN) Energistics, coordinating WITSML and PRODML.
Coal seam gas exploration and production in NSW: the new access argument
Authors: Fulcher Jonathan , Klapper Martin
Published: August 2017

The legal frameworks around access to coal seam gas (CSG) resources in NSW are perhaps less developed than in Queensland. Coal appears to be favoured in terms of accessibility over CSG in the premier state. This paper will examine the rules relating to access to CSG resources in NSW; explain the long-standing policy favouring coalover CSG; and, will argue that the state may have to move to amend or overhaul its gas land access arrangements in the next few years.As CSG players look for further reserves in the largely untapped area of NSW coal provinces, the legal arguments about access to extant coal reserves are likely to heat up.
Global environmental review processes for oil and gas projects
Authors: Gorham Bill
Published: August 2017

The environmental review processes for major oil and gas projects vary significantly worldwide. Three LNG projects in WA (Gorgon, Browse and Wheatstone), one in NT (Ichthys), four in Queensland (Queensland Curtis LNG, Gladstone LNG, Australia Pacific LNG, and Shell Australia LNG), and one in Commonwealth waters (Prelude) have all experienced—or are in the midst of—the Australian environmental review processes.
The foundation of the environmental review of these projects is anchored in existing state and federal statutes and regulations, but the application to each project varies according to the specific characteristics of each proposal. Similar large scale LNG projects in other countries are subject to analogous processes. Some are as rigorous as those in Australia but there are also some with less well-developed environmental review processes. In the latter cases, either corporate and/or financial institution standards dictate the environmental review processes.
This extended abstract reviews the processes that the present above-mentioned LNG projects have gone through or are going through and compares them to similar processes in other countries where large-scale oil and gas projects have been proposed or permitted. The authors compare both the strategic assessment approach taken for the Browse LNG project to the more traditional approach of environmental impact statement/environmental review and management plan used for other recent or present oil and gas projects.
The authors also evaluate these reviews in relation to comparable multi-jurisdictional reviews taken in the US, Canada and the UK for their joint federal/state/regional environmental review processes.
Liabilities of industry stakeholders for pollution caused in Australian waters
Authors: Ball Simon
Published: August 2017

There is no doubt that the recent Montara and Deepwater Horizon oil spills were catastrophic; the clean up continues and litigation is likely to drag on for several years. Who is held liable for the cost and clean up of an oil pollution event? Are these spills likely to change the field—if so, in what ways? Will the present contracting and insurance practices of Australian industry players be sufficient to protect them in the future?
Offshore petroleum and gas production activities are covered by a range of sometimes confusing international, federal and state or territory laws. Operators, directors, contractors, financiers, co-venturers and other stakeholders may all have legal responsibilities in relation to pollution and other environmental impacts of offshore exploration and production activities. The Montara Commission of Inquiry has not yet been released, but the 2009 Productivity Commission Report has already focused attention on these issues.
With reference to contracting practices in the Australian offshore petroleum and gas production industry—in particular indemnities and provisions purporting to limit or exclude liability—this paper outlines the potential extent of stakeholders’ liabilities under relevant international conventions, federal and state or territory legislation, and the common law. It considers the effect of anticipated changes to the operating environment in Australia and lessons to be learned after Montara. This paper will be of interest to any prudent investors, operators or others involved in the industry.
Petroleum potential of the offshore southern Carnarvon Basin—insights from new Geoscience Australia data
Authors: Borissova Irina , Nelson Gabriel
Published: August 2017

In 2008–9, under the Offshore Energy Security Program, Geoscience Australia (GA) acquired 650 km of seismic data, more than 3,000 km of gravity and magnetic data, and, dredge samples in the southern Carnarvon Basin. This area comprises the Paleozoic Bernier Platform and southern part of the Mesozoic Exmouth Sub-basin. The new seismic and potential field data provide a new insight into the structure and sediment thickness of the deepwater southernmost part of the Exmouth Sub-basin.
Mesozoic depocentres correspond to a linear gravity low, in water depths between 1,000–2,000 m and contain between 2–3 sec (TWT) of sediments. They form a string of en-echelon northeast-southwest oriented depressions bounded by shallow-dipping faults. Seismic data indicates that these depocentres extend south to at least 24°S, where they become more shallow and overprinted by volcanics.
Potential plays in this part of the Exmouth Sub-basin may include fluvio-deltaic Triassic sandstone and Lower–Middle Jurassic claystone source rocks sealed by the regional Early Cretaceous Muderong shale. On the adjoining Bernier Platform, minor oil shows in the Silurian and Devonian intervals at Pendock–1a indicate the presence of a Paleozoic petroleum system. Ordovician fluvio-deltaic sandstones sealed by the Silurian age marine shales, Devonian reef complexes and Miocene inversion anticlines are identified as potential plays.
Long-distance migration may contribute to the formation of additional plays close to the boundary between the two provinces. With a range of both Mesozoic and Paleozoic plays, this under-explored region may have a significant hydrocarbon potential.
2011 PESA industry review: exploration
Authors: Cooney Phillip
Published: August 2017

A continuing high and stable oil price through the latter part of 2011, oscillating around US$120 in the case of Tapis Crude, underpinned a small increase in exploration in 2011 in Australia compared with 2010, although there were marked regional differences between the northwest and southeast parts of the country. Exploration continued to be focused on the northwest offshore seeking incremental reserve additions of conventional gas to support planned and proposed liquid natural gas (LNG) projects and although information is hard to confirm, in general this program appears to have been successful with a number of relatively smaller discoveries and at least one major find, Zola–1.
In the Cooper Basin exploration activity resumed after almost being shut down by floods in 2010, although flooding continued to be a problem in 2011. In the South Australian part, 27 new field wildcat (NFW) wells were drilled in 2011 compared with 8 in 2010. The program was also marked by a high rate of success.
The other current major area of activity, the Queensland coal seam gas (CSG) program was also affected by flooding early in 2011 with 524 coal seam gas (CSG) wells drilled this year, compared with 648 in 2010 and more than 900 in 2009.
In many jurisdictions shale gas or shale oil wells are not reported separately and are included in conventional petroleum wells in this report.
Exploration for geothermal resources continued at a relatively low level with only 10 wells drilled in Australia in 2011, the most active state was Victoria with five wells.
Despite the increase in activity, preliminary indications are that total exploration expenditure in 2011 will be less than in 2010. It is interesting to note that while the exploration effort in terms of wells and seismic has not changed much in the last few years the total expenditure has steadily increased in part reflecting the movement into deeper water drilling.
Reservoir characterisation using artificial bee colony optimisation
Authors: Sayyafzadeh Mohammad , Haghighi Manouchehr , Bolouri Keivan , Arjomand Elaheh
Published: August 2017

To obtain an accurate estimation of reservoir performance, the reservoir should be properly characterised. One of the main stages of reservoir characterisation is the calibration of rock property distributions with flow performance observation, which is known as history matching. The history matching procedure consists of three distinct steps: parameterisation, regularisation and optimisation. In this study, a Bayesian framework and a pilot-point approach for regularisation and parameterisation are used. The major focus of this paper is optimisation, which plays a crucial role in the reliability and quality of history matching.
Several optimisation methods have been studied for history matching, including genetic algorithm (GA), ant colony, particle swarm (PS), Gauss-Newton, Levenberg-Marquardt and Limited-memory, Broyden-Fletcher-Goldfarb-Shanno. One of the most recent optimisation algorithms used in different fields is artificial bee colony (ABC). In this study, the application of ABC in history matching is investigated for the first time. ABC is derived from the intelligent foraging behaviour of honey bees. A colony of honey bees is comprised of employed bees, onlookers and scouts. Employed bees look for food sources based on their knowledge, onlookers make decisions for foraging using employed bees’ observations, and scouts search for food randomly.
To investigate the application of ABC in history matching, its results for two different synthetic cases are compared with the outcomes of three different optimisation methods: real-valued GA, simulated annealing (SA), and pre-conditioned steepest descent. In the first case, history matching using ABC afforded a better result than GA and SA. ABC reached a lower fitness value in a reasonable number of evaluations, which indicates the performance and execution-time capability of the method. ABC did not appear as efficient as PSD in the first case. In the second case, SA and PDS did not perform acceptably. GA achieved a better result in comparison to SA and PSD, but its results were not as superior as ABC’s.
ABC is not concerned with the shape of the landscape; that is, whether it is smooth or rugged. Since there is no precise information about the landscape shape of the history matching function, it can be concluded that by using ABC, there is a high chance of providing high-quality history matching and reservoir characterisation.
The Vesta oil and gas field, Vulcan Sub-basin, Timor Sea, Australia
Authors: Ellis Grant
Published: August 2017

The Vesta oil and gas field is located in the Swan Graben of the Vulcan Sub-basin. The structure consists of a number of separate tilted fault blocks located on a northwest-trending accommodation zone that forms a high, separating the southeast-dipping half-graben of the Swan Graben North from the northwest-dipping half-graben of the Swan Graben South.
Drilled in 2005, Vesta–1 intersected a 17 m thick oil-bearing slope-fan sandstone of the Late Jurassic Elm Sandstone in the Lower Vulcan Formation. Drill-stem testing flowed oil and gas and indicated that the reservoir is normally pressured surrounded above and below by over-pressured claystone. In 2007, Vesta–2 intersected gas-bearing sandstone in a separate fault compartment.
Understanding the geometry of the hydrocarbon-bearing Elm Sandstone reservoir has proved a challenge due to the very poor 3D seismic imaging, the variable sandstone thickness and quality, and abundant evidence of thin steeply-dipping injected sandstones above and below the main reservoir sandstone.
The Lower Vulcan and Upper Vulcan Formation claystone provides the vertical and lateral seal for the Elm Sandstone. This thick seal has protected the Vesta oil and gas accumulations from the effects of the Late Tertiary tectonism, which had a significant effect on the integrity of the palaeo-oil filled closures on the adjacent Eclipse Trend.
Three phases of hydrocarbon charge of the Vesta structure have been identified with oil-source correlation indicating a Lower Vulcan Formation marine source. The source interval intersected in Vesta–1 is presently post-mature, with oil and gas generation associated with high heat flow in the Late Jurassic. Expulsion of hydrocarbons from the source was most likely compaction-driven, with gas expulsion in the Early Cretaceous, and oil expulsion much later with increasing hydrocarbon saturation.
Temperature effect on methane sorption and diffusion in coal: application for thermal recovery from coal seam gas reservoirs
Authors: Salmachi Alireza , Haghighi Manouchehr
Published: August 2017

Investigating the effects of in situ thermal treatment on coal seams requires adequate knowledge of gas sorption and its kinetics in coal at various temperatures. Methane sorption onto two Australian coal samples (high-volatile bituminous) at dry state and different temperatures was measured. Methane adsorption isotherms were measured at pressures up to 7 MPa by the gas adsorption manometric method. Adsorption isotherms data at two temperatures were used to investigate the effects of in situ thermal treatment on critical desorption pressure, ultimate gas recovery and the diffusion coefficient in coal. An increase of experimental temperature from 308 to 348 K resulted in a 50% reduction in the adsorption affinity of the coal sample and an insignificant reduction in the saturation capacity of the isotherms. At higher experimental temperatures, Langmuir isotherms exhibit downward shift with the initial gas content of the coal seam being constant, resulting in critical gas desorption pressure increase. According to the measured Langmuir isotherms at different temperatures, an increase in reservoir temperature by 1 K leads to a 2% and 1.2% increase in total recovery for the tested coal seams. Gas left in the coal seam at the abandonment pressure can only be recovered at a higher reservoir temperature.
Diffusion coefficients of coal seam samples were calculated for different experimental temperatures. Fractional uptakes of the first coal sample show a good agreement with the results obtained using the unipore diffusion model with the diffusion coefficient to be 4.7 × 10–12 m2/s at 348 K. For the second coal sample, the unipore diffusion model fairly matches the uptake data. A bidisperse diffusion model was also applied to measure the adsorption kinetics of the second coal sample, resulting in an improved agreement with the experimental uptake data. Both coal samples exhibited a reduction of the diffusion coefficient with an increase in equilibrium pressure; this effect was more pronounced at equilibrium pressures below 0.045 MPa. It was observed that the diffusion coefficient change with pressure becomes flat at high pressures, with the pressure effect diminishing much faster at lower temperatures.
New play type, southern Bonaparte Basin-Petrel Sub-basin—WA-442-P and NT/P81 exploration permits
Authors: Hildick-Pytte Margaret
Published: August 2017

Recent investigation, including mapping re-processed seismic data, suggests there is deeper hydrocarbon potential in the WA-442-P and NT/P81 exploration permits beneath the Early Carboniferous Tanmurra Formation horizon. Earlier interpretation of the area showed tilted fault blocks commonly thought of as economic basement in the vicinity of the Turtle and Barnett oil fields and extending to the northwest to connect with the Berkley Platform. The deep-gas play type is structural and is believed to be two nested three-way dip anticlines developed against a large bounding fault to the northeast, with axial trends northwest to southeast, and axial plane curving towards the northeast for the deeper structure. This play type is believed to be associated with structural compression and movement along the master fault with incremental re-activation most recently during the Cainozoic as recorded in overlying sediments.
The Nova Structure and the deeper Super Nova structure have closures of about 450 and 550 km2, respectively. The sediments beneath the Nova horizon are believed to be of Devonian Frasnian-Famennian age but have not been drilled offshore in the Southern Bonaparte Basin (Petrel Sub-basin). Earlier work suggests that there are two petroleum systems present in the southern Bonaparte Basin, a Larapintine source from Early Palaeozoic Devonian to Lower Carboniferous source rocks, and a transitional Larapintine/Gondwana system sourced from Lower Carboniferous to Permian source rocks. Hydrocarbon charge for the structures is most likely from the Larapintine source rock intervals or yet to be identified older intervals associated with the salt deposition during the Ordovician and Silurian. Independent estimates place close to 7 TCF (trillion cubic feet) of gas in the Nova Structure. New 3D seismic data acquisition is planned over the structures to better define the geology and ultimately delineate well locations.
Production of methane from hydrate deposits beneath the Nankai Trough
Authors: Ballantyne John , Sheil Henry
Published: August 2017

The U.S. Geological Survey (USGS) has estimated there is upwards of 100,000 trillion cubic feet (Tcf) of global methanehydrate resources, worldwide (Collett, 2011).
The Japan Oil Gas and Metals National Corporation (JOGMEC) has been actively evaluating the potential of developing methane hydrate marine sediments as a resource. There have been trials in onshore Canada in 2007 and 2008; and, there are plans to test offshore production in the next few years.
Existing plans involve two well tests in the eastern Nankai Trough, offshore Japan. An initial short-term well test of up to one month will be followed by an extended well test of up to six months.
The production method trialled in Canada and planned for the offshore well tests is depressurisation. This involves drilling from the surface (or seabed) to a subsurface methane
hydrate zone and reducing the formation pressure to a point where the methane hydrates dissociate to methane and water. The gas and water are then transferred to the surface, the water is treated for disposal and the gas is treated for exportation.
Recent research was done to confirm the technical feasibility of the planned offshore well tests. This research examined:
production mechanism and flow assurance;
production host functional specification;
subsea equipment including flowlines, production riser and electro-hydraulic umbilical;
topsides well test equipment; and,
procurement and installation methodology.

The main conclusion made was confirmation of the technical feasibility of the proposed offshore well test. The key challenges, uncertainties and areas for future focus in the lead up to the proposed offshore well tests were also highlighted.
Using relative permeability curves to evaluate phase trapping damage caused by water- and oil-based drilling fluids in tight-gas reservoirs
Authors: Murickan Geeno , Bahrami Hassan , Rezaee Reza , Saeedi Ali , Mitchel Tsar
Published: August 2017

Low matrix permeability and significant damage mechanisms are the main signatures of tight-gas reservoirs. During the drilling and fracturing of tight formations, the wellbore liquid invades the tight formation, increases liquid saturation around the wellbore, and eventually reduces permeability at the near wellbore zone. The liquid invasion damage is mainly controlled by capillary pressure and relative permeability curves.
Due to high critical water saturation, relative permeability effects and strong capillary pressure, tight formations are sensitive to water invasion damage, making water blocking and phase trapping damage two of the main concerns with using a water-based drilling fluid in tight-gas reservoirs.Therefore, the use of an oil-based mud may be preferred in the drilling or fracturing of a tight formation. Invasion of an oil filtrate into tight formations, however, may result in the introduction of an immiscible liquid-hydrocarbon drilling or completion fluid around the wellbore, causing the entrapment of an additional third phase in the porous media that would exacerbate formation damage effects.
This study focuses on phase trapping damage caused by liquid invasion using a water-based drilling fluid in comparison with the use of an oil-based drilling fluid in water-sensitive, tight-gas sand reservoirs. Reservoir simulation approach is used to study the effect of relative permeability curves on phase trap damage, and the results of laboratory experiments of core flooding tests in a West Australian tight-gas reservoir are shown, where the effect of water injection and oil injection on the damage of core permeability are studied. The results highlight the benefits of using oil-based fluids in drilling and fracturing of tight-gas reservoirs in terms of reducing skin factor and improving well productivity.
Induced and natural fracture interaction in tight-gas reservoirs
Authors: Rahman Mohammad , Rahman Sheik
Published: August 2017

This paper investigates the interaction of an induced hydraulic fracture in the presence of a natural fracture and the subsequent propagation of this induced fracture. The developed, fully coupled finite element model integrates a wellbore, an induced hydraulic fracture, a natural fracture, and a reservoir that simulates interaction between the induced and natural fracture.
The results of this study have shown that natural fractures can have a profound effect on induced fracture propagation. In most cases, the induced fracture crosses the natural fracture at high angles of approach and high differential stress. At low angles of approach and low differential stress, the induced fracture is more likely to be arrested and/or break out from the far-end side of the natural fracture. It has also been observed that the propagation of the induced fracture is stopped by a large natural fracture at a high angle of approach, when the injection rate remains low. At a low angle of approach, the induced fracture deviates and propagates along the natural fracture. Crossing of the natural fracture and/or arrest by the natural fracture is controlled by the shear strength of the natural fracture, natural fracture orientation, and the in situ stress state of the reservoir.
In tight-gas reservoir development, the optimum well spacing and induced hydraulic fracture length are correlated. Therefore, fracturing design should be performed during the initial reservoir development planning phase along with the well spacing design to obtain an optimal depletion strategy. This model has a potential application in the design and optimisation of fracturing design in unconventional reservoirs including tight-gas reservoirs and enhanced geothermal systems.
Integrated approach to drilling dynamics challenges in the Browse Basin
Authors: Arevalo Yezid , O'Sullivan Cathal , Fernandes Ashley
Published: August 2017

The use of drilling dynamics measurements has traditionally focused on improving downhole tool reliability. This, however, is a limited scope and in recognition of this, drilling dynamics is approached as a process that starts early in the planning stage of a project and targets the performance of the complete drillstring. Failures or inefficiencies associated with drillstring dynamics continue to occur in spite of the sophistication of today's measurements, particularly in exploratory projects that extend the present drilling envelope.
Several methodologies were integrated to address the challenges of drilling dynamics and overcome frequent failures observed on the initial exploratory work on the Browse Basin. A steep learning curve was achieved by accelerating the improvement cycle using advanced modelling techniques and obtaining optimum designs without the need of multiple trial and error cycles.
This extended abstract also describes the use of real-time dynamics measurements to quantify the risks related to drillstring vibration, a critical need for the drilling environment observed in the basin that ties planning work into the execution stage. Finally, the project cycle is closed with the evaluation of drilling performance using data-handling tools that allow the effective use of large amounts of drilling data generated during the execution and feedback into a new planning cycle.
The extended abstract describes the implementation of drilling dynamics modelling to assist performance improvement, but more importantly, the methodology to incorporate it into a real-time decision-making process that maximises the value of technology implementation.
Structural and stratigraphic architecture of Australia's frontier onshore sedimentary basins: the Western Officer and Southern Carnarvon basins, Western Australia
Authors: Carr Lidena , Korsch Russell , Mory Arthur , Hocking Roger , Marshall Sarah , Costelloe Ross , Holzschuh Josef , Maher Jenny
Published: August 2017

During the past five years, the Onshore Energy Security Program, funded by the Australian Government and conducted by Geoscience Australia, in conjunction with state and territory geological surveys, has acquired deep seismic reflection data across several frontier sedimentary basins to stimulate petroleum exploration in onshore Australia.
This extended abstract presents data from two seismic lines collected in Western Australia in 2011. The 487 km long Yilgarn-Officer-Musgrave (YOM) seismic line crossed the western Officer Basin in Western Australia, and the 259 km long, Southern Carnarvon Seismic line crossed the Byro Sub-basin of the Southern Carnarvon Basin.
The YOM survey imaged the Neoproterozoic to Devonian western Officer Basin, one of Australia's underexplored sedimentary basins with hydrocarbon potential. The survey data will also provide geoscientific knowledge on the architecture of Australia's crust and the relationship between the eastern Yilgarn Craton and the Musgrave Province.
The Southern Carnarvon survey imaged the onshore section of the Ordovician to Permian Carnarvon Basin, which offshore is one of Australia's premier petroleum-producing provinces.
The Byro Sub-basin is an underexplored depocentre with the potential for both hydrocarbon and geothermal energy. Where the seismic traverse crossed the Byro Sub-basin it imaged two relatively thick half graben, on west dipping bounding faults. Structural and sequence stratigraphic interpretations of the two seismic lines are presented in this extended abstract.
An emerging shale gas play in the Northern Territory
Authors: Johnson Ray , Hokin Geoff , Warner David , Dawney Rod , Dix Mike , Ruble Tim
Published: August 2017

As attention to unconventional oil and gas resources increases, historical oil and gas flows in shale reservoirs across the world are being given renewed attention. Such is the case of the shaly and carbonate deposits of the McArthur and Nathan groups in the Northern Territory.
The Batten Trough is a Proterozoic depocenter with potential for a shale gas play in the Barney Creek Shale and potential for conventional gas accumulations in the underlying Coxco Dolomite. This Barney Creek Shale gas play is evidenced by a number of mineral exploration drill holes that encountered live oil and gas shows within the McArthur Group. The most prominent was a mineral exploration hole drilled at the Glyde River prospect by Amoco in 1979.
This well reportedly flowed gas and condensates at 140 psi for six months before it was sealed at the surface, which certainly shows permeability values greater than micro-darcies reported for many North American shale plays; thus, an exploration program of this prospective area has been planned by Armour Energy in EP 171 on several targets adjacent to the Emu Fault Zone near both Glyde and Caranbirini, along with other anticline related targets adjacent to the Abner Range. This extended abstract details how the targets were identified, the plan for data acquisition (e.g. seismic, drilling, logging and testing), and the proposed completion strategy to test this highly prospective target.
3D seismic analysis of the geometrical characteristics of the Rosedale Fault System, west Gippsland Basin, Victoria
Authors: Swierczek Ernest , Holford Simon , Backé Guillaume , Mitchell Andy
Published: August 2017

One of the main risks associated with the underground storage of CO2 is the possibility of leakage from the reservoir to the surface. Among the most likely pathways for CO2 migration are permeable fault systems and highly fractured caprocks. It is thus important to develop a detailed understanding of geometrical characteristics of fault systems to assess the long-term storage and reactivation potential of fault dependent reservoirs.
This extended abstract describes the results from a detailed structural analysis of the Rosedale Fault System (RFS) in the Gippsland Basin, Victoria, which is undergoing assessment for CO2 storage, using high-fidelity 3D seismic data. The RFS is a long-lived fault system that has experienced significant reactivation since the late Miocene and continued activity on this fault. Conventional structural mapping has been supported by seismic attribute analyses using a dip-steering cube.
The coupling of seismic attribute analysis with fault displacement analysis has enabled the geometry of the RFS to be defined and to delineate associated damage zone. This extended abstract's analysis shows that the RFS is an anastomosing normal fault system that displays lateral changes in the degree of late Miocene-onwards reverse reactivation, which has affected the Latrobe Group and older units.
This analysis has also revealed an extensive polygonal fault-system confined to post-Top Latrobe (Eocene) sediments, showing that this component of the stratigraphy is structurally decoupled from the older sedimentary section. This extended abstract concludes by assessing the roles that both the RFS and the polygonal fault system play in fluid migration in the western Gippsland Basin.