bluuebunny/crossref_metadata_2025 huggingface dataset:
THE THYLACINE AND GEOGRAPHE GAS DISCOVERIES, OFFSHORE EASTERN OTWAY BASIN
Authors: Cliff D.C.B. , Tye S.C. , Taylor R.
Published: August 2017

The Thylacine and Geographe gas fields were discovered in mid-2001 in the offshore Otway Basin, in permits T/30P and VIC/P43 respectively. Geographe is 55 km south of Port Campbell and Thylacine is a further 15 km offshore, in the depo-centre of the Shipwreck Trough, in water depths of 80 m to 100 m. The Thylacine–1 well intersected a 277 m gas column in Turonian to Santonian aged reservoirs. Geographe–1 intersected a 233 m gas column in a similar sedimentary section. Thylacine–2, 5.7 km west of Thylacine–1, confirmed the field extent, and flowed gas at 28 MMSCFD (0.79 Mm3/D). Critical to the discovery of these fields was the Investigator 3D seismic survey, which covered about 1,000 km2 of the central Shipwreck Trough. The pre-drill chance of success of both structures was high-graded as a result of excellent structural imaging and the conformance of amplitude and AVO anomalies to mapped closures. The interpretation of this survey and the subsequent drilling of the Thylacine and Geographe Fields have dramatically increased the understanding of the structure and stratigraphy of the offshore eastern Otway Basin particularly in relation to the Shipwreck Trough and the Sorell Fault Zone.Combined dry gas reserves at the proved and probable level stand at 0.85 TCF and condensate reserves at 10.7 MMBBL. The fields are undergoing integrated sub-surface, development and environmental studies with the aim of supplying the nearby southeastern Australian gas markets. The preferred development concept is a small jacket structure at Thylacine, followed by a subsea tie-in of the Geographe Field with onshore processing facilities near Port Campbell.
THE RISE AND RISE OF COAL SEAM GAS IN THE BOWEN BASIN
Authors: Riley J.M.
Published: August 2017

The coal seam gas (CSG) industry has been active in Australia for almost three decades, with interest largely focussed on the Bowen and Sydney basins. Sporadic activity has also occurred in a number of other areas including the Galilee, Ipswich, Clarence–Moreton, Gunnedah, Gloucester, and Otway basins to name a few, with significant recent interest shown in the promising Surat Basin. Of these basins it is the Bowen Basin in eastern central Queensland which has continued to shine as the premier coal seam gas province in the country.From humble beginnings in the mid-1970s in the Moura area, CSG from the Bowen Basin now supplies around 20% of Queensland gas demand. Since the start of commercial production from the basin in 1996, production has grown to about 20 PJ per year from five separate fields, with three new fields under construction expected to more than double this volume over the next 2–3 years.The largest contribution to this growth will come from the Comet Ridge region which is proving itself to be a world class CSG deposit. The high-productivity fairway in the south of the region extends over an area about 80 km long and 20 km wide and includes the Tipperary Fairview field, and the Origin Energy Spring Gully project. In the last year proved and probable gas reserves have more than doubled to 1,500 PJ across the fairway, with upside recoverable gas estimated to be 4,700 PJ. The rapid rate of CSG reserves increase in the Bowen Basin demonstrates the key role this industry will play in the eastern Australia gas market.
GEOLOGICAL STORAGE OF CARBON DIOXIDE: MODELLING THE EARLY CRETACEOUS SUCCESSION IN THE BARROW SUB-BASIN, NORTHWEST AUSTRALIA
Authors: Gibson-Poole C.M. , Streit J.E. , Lang S.C. , Hennig A.L. , Otto C.J.
Published: August 2017

Potential sites for geological storage of CO2 require detailed assessment of storage capacity, containment potential and migration pathways. A possible candidate is the Flag Sandstone of the Barrow Sub-basin, northwest Australia, sealed by the Muderong Shale. The Flag Sandstone consists of a series of stacked, amalgamated, basin floor fan lobes with good lateral interconnectivity. The main reservoir sandstones have high reservoir quality with an average porosity of 21% and an average permeability of about 1,250 mD. The Muderong Shale has excellent seal capacity, with the potential to withhold an average CO2 column height of 750 m. Other containment issues were addressed by in situ stress and fault stability analysis. An average orientation of 095°N for the maximum horizontal stress was estimated. The stress regime is strike-slip at the likely injection depth (below 1,800 m). Most of the major faults in the study area have east-northeast to northeast trends and failure plots indicate that some of these faults may be reactivated if CO2 injection pressures are not monitored closely. Where average fault dips are known, maximum sustainable formation pressures were estimated to be less than 27 MPa at 2 km depth. Hydrodynamic modelling indicated that the pre-production regional formation water flow direction was from the sub-basin margins towards the centre, with an exit point to the southwest. However, this flow direction and rate have been altered by a hydraulic low in the eastern part of the sub-basin due to hydrocarbon production. The integrated site analysis indicates a potential CO2 storage capacity in the order of thousands of Mtonnes. Such capacity for geological storage could provide a technical solution for reducing greenhouse gas emissions.
ASSESSING RISK IN CO2 STORAGE PROJECTS
Authors: Bowden A.R. , Rigg A.
Published: August 2017

A key challenge to researchers involved with geological storage of CO2 has been to develop an appropriate methodology to assess and compare alternative CO2 injection projects on the basis of risk. Technical aspects, such as the risk of leakage and the effectiveness of the intended reservoir, clearly need to be considered, but so do less tangible aspects such as the value and safety of geological storage of CO2, and potential impacts on the community and environment.The RISQUE method has been applied and found to be an appropriate approach to deliver a transparent risk assessment process that can interface with the wider community and allow stakeholders to assess whether the CO2 injection process is safe, measurable and verifiable and whether a selected alternative delivers cost-effective greenhouse benefits.In Australia, under the GEODISC program, the approach was applied to assess the risk posed by conceptual CO2 injection projects in four selected areas: Dongara, Petrel, Gippsland and Carnarvon. The assessment derived outputs that address key project performance indicators that:are useful to compare projects;include technical, economic and community risk events;assist communication of risk to stakeholders;can be incorporated into risk management design of injection projects; andhelp identify specific areas for future research.The approach is to use quantitative techniques to characterise risk in terms of both the likelihood of identified risk events occurring (such as CO2 escape and inadequate injectivity into the storage site) and of their consequences (such as environmental damage and loss of life). The approach integrates current best practice risk assessment methods with best available information provided by an expert panel.The results clearly showed the relationships between containment and effectiveness for all of the four conceptual CO2 injection projects and indicated their acceptability with respect to two KPIs. Benefit-cost analysis showed which projects would probably be viable considering base-case economics, greenhouse benefits, and also the case after risk is taken into account. A societal risk profile was derived to compare the public safety risk posed by the injection projects with commonly accepted engineering target guidelines used for dams. The levels of amenity risk posed to the community by the projects were assessed, and their acceptability with respect to the specific KPI was evaluated.The risk assessment method and structure that was used should be applied to other potential CO2 injection sites to compare and rank their suitability, and to assist selection of the most appropriate site for any injection project. These sites can be reassessed at any time, as further information becomes available.
THE INFLUENCE OF FINANCIAL RISK ON RESERVES REPORTING AND INVESTMENT DECISIONS
Authors: Boardman J.S , Williams R.J. , Salter G.B.
Published: August 2017

The determination of petroleum resources is a technical function executed by geoscientists and reservoir engineers. The determination and valuation of petroleum reserves is a commercial function that requires input from development and cost engineers, economists and financial and risk analysts. While the technical aspects of both determinations are generally carried out with diligence, the financial considerations are frequently given scant regard. Of particular note are the infrequent acknowledgement of risk and the application of appropriately considered discount rates.It can be demonstrated that inappropriate selection of the discount rate can create material distortions in the determination and valuation of reserves.Our proposition is that the rate at which the cash flows are discounted should reflect the reserves uncertainty, specifically the relationship between the proved reserves, which can be financed out of debt, and probable reserves that are typically financed out of equity. Specifically, for the valuation of proved+probable reserves, rather than use a corporate WACC, i.e. one which reflects the average ratio of the costs of debt and equity, investors should instead use a WACC which is based on the ratio of proved: probable reserves weighted cost of debt: equity.
RECENT DEVELOPMENTS IN NATIVE TITLE LAW AND CULTURAL HERITAGE AFFECTING THE PETROLEUM INDUSTRY—CERTAINTY, BUT AT A PRICE
Authors: Young D. , Scott G. , Norris J.
Published: August 2017

The mosaic of the common law relating to Native Title, which underpins the Native Title and other Acts, continues to be filled in by the courts increasing certainty for all parties. Last year saw the High Court’s Ward decision—the most significant decision for the petroleum industry since Mabo in 1992. Since then there have been three more important decisions, which while not making new law, have shown how the principles enunciated in Ward and Yorta Yorta are being applied. Some of the cases examined include the Daniel and De Rose Hill decisions, which have application to petroleum tenements.This paper will outline the recent developments, and demonstrate how the decisions have reduced uncertainty, thereby narrowing the areas about which negotiation must occur. The hurdle for proving the existence of Native Title remains high.It has not all been in favour of industry, however. Increasingly, Native Title cases, such as Daniels have resulted in unexpected findings that some conventional titles had been invalidly granted. Titles which seemingly ought to have extinguished Native Title have turned out to be invalid, and in many cases irretrievably so. The paper looks at the implications of this for industry as well.
BUILDING CULTURAL CAPITAL IN THE AUSTRALIAN OIL AND GAS INDUSTRY
Authors: Doig L. , Griffiths R. , Robertson J.
Published: August 2017

One of the key barriers to significant cost-savings and harnessing opportunities for growth in the Australian oil and gas industry is lack of trust, openness and misalignment between companies, among teams and among individuals.In research undertaken for APPEA’s Australian Competitive Energy (ACE) initiative over the last three years, one of the top three barriers to growth continually cited by senior and middle level managers has been culture and behaviours. Examples include misalignment between operators and contractors, management and the workforce, joint venture partners, industry and government, and the industry and the community.In the next five years, the Australian oil and gas industry is facing a skills shortage, technically challenging projects with less people and adaptive challenges. Adaptive challenges (Heifetz and Laurie, 2000) are ones where the:problems and solutions are unclear;the solution does not work through command and control;requires a new way of thinking and acting; andrequires the entire organisation to be engaged.Examples of adaptive challenges for our industry are:finding new gas markets;exploration in sensitive areas;high rig mobilisation costs for a small market; andretaining a skilled workforce.These challenges require companies to find new ways of:Attracting and keeping talented people;Increasing profits and shareholder value; andIncreasing creativity and productivity.Adaptive challenges can be achieved by building cultural capital.This paper outlines:Research and feedback from Australian Operations Managers, Supply Managers, Project Managers and Drilling Managers about the need for improving the culture and behaviours;The business case for why building a high performance culture is considered the competitive advantage of the 21st century;How to measure culture including the diagnostic tool used for the CEO workshop;Results from the diagnostic of the CEO group and implications;andHow to move forward individually, as companies and as an industry.The purpose of this paper is to foster debate and discussion about developing a high performing culture in the Australian oil and gas industry. We intuitively know that valuing our people makes good business sense. To transform the industry’s culture, it is not the organisations that transform, but the people. Shifting the culture requires leadership, courage and commitment from the industry’s senior management.
PRODUCTION OPTIMISATION VIA MULTI-PHASE FLOW METERING
Authors: McArdle A.J. , McDiarmid A.J. , Asbey T.E.
Published: August 2017

Apache has developed a number of small oil fields using unmanned minimum facilities platforms close to Varanus Island, on the North West Shelf of Western Australia. Production from each platform is commingled into a single production trunkline. Wells producing at high watercut are artificially lifted using gaslift. Production monitoring and well allocation uses multi-phase flow meters situated on each platform. The use of these meters minimises total infrastructure cost, while still allowing the direct testing of each well. Test results are used for production optimisation of the individual wells, optimisation of the integrated production network, well and field production allocation and troubleshooting. Meter performance has been satisfactory, resulting in an additional unit being deployed on the Stag field where production is affected by high gas rates, slugging and sand production.
COAL SEAM GAS EXPLORATION, DEVELOPMENT AND RESOURCES IN AUSTRALIA: A NATIONAL PERSPECTIVE
Authors: Miyazaki S.
Published: August 2017

A total of 2,223 PJ of proved plus probable gas reserves has been identified in coal seam gas fields and pilot production areas in Australia. The production of coal seam gas is rapidly growing, reaching about 40 PJ per year in 2003. A total of more than 108 PJ will be supplied annually by the end of 2007 under existing contracts, representing about 9% of Australia’s projected total primary consumption of natural gas. About two thirds of Queensland’s natural gas consumption will be met by coal seam gas by the end of 2007. Further expansion of the coal seam gas industry depends largely on the medium-term production performance of the pioneering production projects now in operation.The long-term production performance of a coal seam gas well is not well understood. Analogues of conventional natural gas have often been applied to the estimation process of coal seam gas reserves without proper consideration of the fundamental differences in trapping mechanisms and production techniques. Definitions of petroleum reserves recommended by various organisations are not always applicable to coal seam gas, and the inconsistent application of reserves definitions may have resulted in inconsistencies in reserves reporting in Australia.
ADVANCES IN RISKING EXPLORATION PROSPECTS
Authors: Lowry D.C. , Suttill R.J. , Taylor R.J.
Published: August 2017

Assessment of prospect risk is a vital exploration activity, but technical literature on the subject shows few advances in methodologies in the last 20 years. Origin Energy has found that published procedures are not always adequate. Three perceived shortcomings are examined and techniques are proposed to overcome them.Cases where prospect risk is dependent on reserve size. Traditional methodologies assume the two are independent. This assumption is clearly inappropriate for, say, a prospect for which the success case value is based on the mapped closure, but which has suspect seal capacity that may limit the column height to something less than full-to-spill. A way forward is to build a variable risk array for a range of column heights and calculate the incremental risked NPV for each layer. The expected monetary value (EMV) is computed for a range of column heights based on the NPV of cumulative risked reserves;Cases where the estimation of chance of success (COS) based on traditional geological information needs to be combined with direct hydrocarbon indicators (DHIs) from seismic data. DHIs are not infallible indicators, however, and cannot be used to set the COS for elements such as charge to say 100%. Bayes’ Theorem can be used to combine the two sets of uncertain information.Cases where prospects are risked on very limited data. Traditional risking does not adequately incorporate the level of knowledge on which risk assessments are made. Inadequacies are identified in existing methodologies, but no simple and satisfactory solutions can be identified. We do suggest a way forward, however, for a related problem—testing the sensitivity of the EMV calculation for an exploration prospect for uncertainties in COS.
EMERGING CHALLENGES IN AUSTRALIA’S DOMESTIC GAS MARKET
Authors: Feenan J.P.
Published: August 2017

This paper considers emerging challenges to balancing gas supply and demand in Australia’s domestic market in the context of the global demand for Australian gas exports. Based on a major 2004 study by Wood Mackenzie, a series of scenario forecasts assessed the balance of gas allocation to domestic and export gas demand to 2020.Australia is destined to become an increasingly significant global supplier and exporter of gas, primarily as LNG. The recent emergence of major new LNG customers in China and (west coast) north America seeking to secure supplies has ignited a global gas demand-pull on Australia’s gas reserves that is competing with domestic demand.The States of Western Australia (WA) and the Northern Territory (NT) hold more than 130 Tcf or 90% of Australia’s total remaining gas reserves. For many years industry and politicians have proposed major transnational pipelines to transport gas out of the remote northwest or from Papua New Guinea to feed the energy-hungry southeast, and supplement existing gas production from the Cooper Basin and Bass Strait.Striking the right balance between export and domestic gas resource allocation and meeting the needs of producers, customers and policy-makers is emerging as a major challenge within Australia’s domestic gas market.
PROGRESS IN GEOTHERMAL ENERGY DEVELOPMENT, COOPER BASIN, SOUTH AUSTRALIA
Authors: Wyborn D. , Graaf L. de , Hann S. , Nicholson B.
Published: August 2017

Geodynamics Limited is nearing the completion of its ‘proof of concept’ hot fractured rock (HFR) program to extract superheated hot water for electricity generation from granite buried beneath the Cooper Basin. Difficult drilling conditions were discovered in the target granite when the Habanero–1 well penetrated permeable sub-horizontal fractures at more than 4,000 m depth. The well was completed at 4,421 m with overpressures in the fractures around this depth exceeding pressures projected from a hydrostatic gradient by more than 5,000 psi. The static rock temperature at the bottom of the well is about 250°C.The overpressures assisted in the development of the world’s largest underground heat exchanger, a volume of rock more than 0.7 km3 defined by more than 11,700 microseismic events located on-site during the injection of 23 ML of fresh water into the granite fracture network. The horizontal heat exchanger is more than 2 km north–south, more than 1 km east–west and more than 300 m thick. During its development there was no evidence of direct upwards growth towards the sedimentary cover, which is at about 3,700 m, though a small number of events were observed above the main cloud of events. From production logging surveys, a major fracture at a depth of 4,254 m is interpreted to have taken most of the flow during the injection.The second well (Habanero–2) was located 500 m southwest of the first. Before intersecting a major fracture, interpreted to be an extension of the dominant fracture in Habanero–1, it was drilled to a depth of 4,325 m. At this depth, total drilling circulation losses were encountered which were only partially overcome with the pumping of calcium carbonate lost circulation material. During the operation the lower 245 m of the drill stem was irretrievably lost, and the well was subsequently sidetracked to a total depth of 4,358 m, just below the main fracture.Flow and circulation testing between the two wells in early 2005 is designed to demonstrate the economic potential of the far-field geothermal system and the heat exchange volume between the two wells.
CAN GOVERNANCE INITIATIVES DELIVER VALUE TO THE OIL AND GAS INDUSTRY?
Authors: Puzey M.R. , Benson S.Q.
Published: August 2017

The objective of this paper is to provide food for thought to executives on how governance initiatives can deliver value—and not just be a compliance cost—with the focus on oil and gas organisations in Australia.We have seen increased governance legislation around the world following the collapse of companies such as Enron. In Australia we have the ASX governance principles.We will explore the lessons learnt from the implementation of compliance by US-listed companies with their Sarbanes-Oxley legislation and what it means to us in Australia.Governance initiatives can be costly—there is, therefore, a need for us to leverage off these initiatives, driving business value where we can, by proactively focussing in the right areas.This paper focusses on practical suggestions for obtaining value from governance initiatives, and is accessible to readers without a strong financial background.
CANNING BASIN AND GLOBAL PALAEOZOIC PETROLEUM SYSTEMS—A REVIEW
Authors: Carlsen G.M. , Ghori K. Ameed R.
Published: August 2017

There are more than 131 giant and super-giant oil and gas fields with Palaeozoic source and reservoir that are similar to the Canning Basin. These include Palaeozoic basins of North America, North Africa, and the North Caspian Basin of Kazakhstan and Russia.The productivity of these Palaeozoic petroleum systems depends on timing of generation and preservation of charge. Thick Ordovician, Permian, and Triassic evaporite deposits played a very important role in creating and preserving the North American, north Caspian, and north African giant oil and gas fields, respectively.The Mesozoic–Tertiary charged Palaeozoic systems are typically more productive than the Palaeozoic charged systems as exemplified by the north African basins.The Ordovician sourced and reservoired giant oil fields of the North American Mid-Continent are also highly productive. Within the Canning Basin, Ordovician sourced oil has been recovered on the Barbwire Terrace (in Dodonea–1, Percival–1 and Solanum–1) on the Dampier Terrace (in Edgar Range–1 and Pictor–1) and along the Admiral Bay Fault Zone (in Cudalgarra–1, Great Sandy–1, and Leo–1).The Canning Basin may be the least explored of the known Palaeozoic basins with proven petroleum systems. The Palaeozoic basins of North America are the most explored with 500-wells/10,000 km2 compared to the Canning Basin with only 4-wells/10,000 km2.The presence of five oil fields, numerous oil and gas shows and the well density in the Canning Basin (200 wells in 530,000 km2) suggests that further exploration is warranted. Critical analysis of the distribution of source rock, reservoir, seal, timing of generation versus trap formation and post accumulation modification for each tectonic unit of the Canning Basin is required.
APPROACHES TO PALAEOGEOGRAPHIC RECONSTRUCTIONS OF THE LATROBE GROUP, GIPPSLAND BASIN, SOUTHEASTERN AUSTRALIA
Authors: Bernecker T. , Partridge A.D.
Published: August 2017

In the Gippsland Basin, the seaward extent of paralic coal occurrences can be mapped in successive time slices through the Paleocene and Eocene to provide a series of straight to gently arcuate surrogate palaeoshorelines within the petroliferous Latrobe Group. Palaeogeographic reconstructions that incorporate this information provide a unique perspective on the changes affecting a siliciclastic depositional system on a passive continental margin where basin development has been primarily controlled by thermal sag. In contrast, the absence of calcareous marine fossils and lack of extensive, widespread and thick fine-grained sediments on the marine shelf and continental slope, beyond the seaward limits of coal accumulation, have contributed to the false impression that the Latrobe Group accumulated in a largely non-marine basin. Based on the proposed model for palaeoshoreline delineation, seismic data, sequence analysis, petrography and palynology can be integrated to subdivide the main depositional environments into distinct facies associations that can be used to predict the distribution of petroleum systems elements in the basin. The application of such palaeogeographic models to the older section of the Latrobe Group can improve the identification of these petroleum systems elements in as yet unexplored parts of the Gippsland Basin. Given the recent attention paid to the basin as a CO2 storage province, palaeogeographic interpretations may be able to assist with the selection of appropriate injection sites.
MANAGING HELICOPTER RISK
Authors: Hart J.
Published: August 2017

Annually, a million hours are flown by helicopters for the international petroleum industry. About 90% of this flying is offshore, and involves around 10 million passengers. Each year some 25–35 accidents are recorded, an average of 22 passengers and crew lose their lives, and a higher number are injured. Some 45% of these accidents stem from technical causes, a similar number are pilot related, and the remainder are linked to other causes. Helicopter accident rates are 10 times higher than those of airline travel.Strategies to tackle both technical failures and pilot related accidents have emerged, although application of these strategies around the world is inconsistent.One way in which helicopter technical issues have been addressed is by the introduction of Health and Usage Monitoring (HUMS) equipment. To tackle the pilot related accidents, lessons have been drawn from the airline industry’s use of Flight Data Management (FDM) programs, which allow pilots to learn from deviations from pre-defined normal parameters during routine flying. The helicopter version of FDM is the Helicopter Operations Monitoring Program (HOMP). Another important training tool is flight simulator training to allow simulated emergencies to be flown and practiced.Petroleum companies have the opportunity through their own aviation policy and standards to stipulate flight crew experience and training, the technical specifications for their contracted helicopters and the application of advanced safety programs, such as HUMS, and HOMP. Compliance and continuous improvement in line with these standards can be verified and facilitated through operational and technical audit. Only with such active involvement can helicopter risk be managed downwards.
PRODUCTION AND DEVELOPMENT HIGHLIGHTS 2004 — OUR FUTURE IN GAS
Authors: Jason Rick
Published: August 2017

The 2004 exploration and appraisal highlights are reviewed and awards given to companies which made significant contributions to increasing Australia’s self sufficiency. While 2004 saw no drilling in Australian frontier basins with most exploratory wells located in the seven producing basins offshore, and within only four onshore basins, overseas, smaller Australian explorers made significant discoveries or appraisals in Turkey, North America and Yemen. Twice as many onshore exploration wells were spudded compared to offshore exploration, a turn around from 2003 mostly due to increased activity in the onshore Cooper-Eromanga and Perth basins.
APPRAISING THE YOLLA FIELD IN THE BASS BASIN—HOW EFFECTIVE DATA COLLECTION, ANALYSIS AND INTEGRATION INCREASED ESTIMATED HYDROCARBON VOLUMES IN PLACE
Authors: Brooks D.M. , Pidgeon B.A. , Hall A.D. , Taylor R.J. , Parvar J.L.
Published: August 2017

Between June and October 2004, two development wells (Yolla–3 and –4) were drilled on the Yolla field in Bass Strait by the T/L1 joint venture. The top and intra-Eastern View Coal Measures (EVCM) hydrocarbon-bearing reservoirs in the field were intersected close to prognosis. A previously undiscovered oil-bearing intra-EVCM sand was encountered in Yolla–4 and the upper EVCM gas and oil bearing reservoir section was completed in Yolla–3 and its productivity confirmed.A key objective of the development drilling campaign was to collect detailed geological and engineering data to assist in field development and quantification of the resource. Subsequent interpretation of these data led to a revision of the depositional facies and reservoir parameters and provided new inputs into a complex 3D reservoir model.The new reservoir model resulted in an upward revision in calculated gas in-place volumes for the intra-EVCM gas reservoirs of about 100 bcf (2,832 m3 x106) or 20% of the pre-drill field size to 600 bcf (16,991 m3x106) and a corresponding increase in recoverable reserves estimates. The upper EVCM is now interpreted to hold 16.5 MMstb (2,623,005 kL) of oil-in-place and total gas-in-place including the gas cap and the solution gas in the oil leg of 33 bcf (934.5 m3x106). These volumes add to the gas reserves for the field, and it is expected that the volatile oil leg will contribute to a richer liquids yield when the zone is produced. The new oil pool in the intra-EVCM has been provisionally estimated at 3.2 MMstb (508,704 kL) oil-inplace with associated solution gas of 2.5 bcf (71 m3x106).
IMPROVING OUR UNDERSTANDING OF GIPPSLAND BASIN GAS RESOURCES—AN INTEGRATED GEOSCIENCE AND RESERVOIR ENGINEERING APPROACH
Authors: Hart T. , Mamuko B. , Mueller K. , Noll C. , Snow T. , Zannetos A.
Published: August 2017

The Barracouta and Marlin gas fields are located within the Gippsland Basin, offshore Australia, and have been on production for more than 36 years. Combined, these fields represent over 6.5 TCF of recoverable gas. Structurally the fields are relatively simple, but they are significantly warped in seismic two-way time by high velocity channels above the reservoir that make time to depth conversion and volumetric assessment difficult.Fundamental to management of these fields has been surveillance data and history matching based on simulation of detailed geologic models. In the late 90s, the observation was made that actual contact movement within the fields was lagging behind model predictions, suggesting that the fields were potentially larger than previously assessed.Results from the 3D seismic surveys acquired in Barracouta in 1999 and both fields in 2001 were used to help answer questions related to contact movement, resource size and remaining recoverable gas. Two significant outcomes from these surveys were the observation of double Direct Hydrocarbon Indicators (DHIs) across both fields, representing both the original and current gas-water contacts (OGWC and CGWC respectively), and mappable amplitude features related to depositional trends.The double DHIs were used to calculate contact movement and sweep uniformity. The original contact DHI was also used to assist in depth conversion. The position of shorelines and upper to lower delta plain boundaries were extracted from the seismic amplitude features to refine net-to-gross distribution.The interpreted 3D data are integrated with well logs and surveillance data to create detailed geologic models used for material balance simulation of reservoir performance. A good match was obtained between the model and field measured pressures and contact movement. Based on this work, the estimates of recoverable gas in the two fields were increased by 0.7 TCF, a 14% increase over the previous estimate.
THE PMR PROCESS, AN INNOVATIVE TECHNOLOGY FOR LARGE LNG TRAINS
Authors: Buijs C. , Pek J.J.B. , Meiring W.J.
Published: August 2017

The forecasts in market growth of LNG and the development of large gas fields are a great stimulus for further enhancing the capacity of LNG trains. The increasing cost of upstream development, including the managing of CO2, deepwater, ice, complex reservoirs and so on, makes downstream economies of scale an imperative. This paper addresses Shell’s approach to large LNG trains in the range of 7–10 Mtpa covering both mechanical and electrical drive options to develop innovative and cost effective designs.With the standard Propane Mixed Refrigerant (C3/MR) technology, capacities up to 5 Mtpa can be achieved with two GE Frame 7 gas turbines as drivers. Due to maximum size constraints of key equipment, an additional liquefaction cycle is required to realise higher LNG capacities. The following solutions are presently applied to extend the capacity above the 5 Mtpa range:adding an additional liquefaction cycle in a three-cycle in series line-up; and,a single pre-cool cycle followed by two parallel liquefaction cycles.Both liquefaction configurations, although of different concepts, have a similar number of equipment items. Shell Global Solutions has developed the latter option as the Parallel Mixed Refrigerant (PMR) process. For precooling either propane or a mixed refrigerant, as used in the Double Mixed Refrigerant (DMR) process, are used. With three well-proven GE Frame 7 gas turbines, 8 Mtpa of LNG production is achieved. With larger drivers such as GE Frame 9 or Siemens V84.2 gas turbines, the LNG capacity increases to above 10 Mtpa.The PMR process for large LNG trains has a number of attractive features:robustness through the use of well-proven equipment;high availability by parallel line-up of the liquefaction cycle. For example, the LNG production is designed to continue at 60% of train capacity if one of the liquefaction cycles trips; and,the optimal power balance between the pre-cool and the two parallel liquefaction cycles results in a high efficiency. Shell’s electrically driven DMR process is also very attractive, particularly for Greenfield applications. This concept is based on a parallel line-up of the refrigerant compressors around a common set of cryogenic spoolwound exchangers and achieves an LNG capacity of more than 8 Mtpa. The power station is driven by gas turbines. The following considerations play a key role in the selection process of electrically driven plants.The gas turbine maintenance is decoupled from LNG production, resulting in a lower downtime. A net increase up to 4% in stream days is possible.High efficiency gas turbines can be selected for the power station and efficiency can be further improved by a combined cycle power plant.The step change in efficiency achieved in a combined cycle power plant is very beneficial in lowering the CO2 and NOx emissions, as well as the feed gas intake.
IMPROVEMENTS IN SEISMIC IMAGING, IO JANSZ GAS FIELD NORTH WEST SHELF, AUSTRALIA
Authors: Hefti J. , Dewing S. , Jenkins C. , Arnold A. , Korn B.E.
Published: August 2017

The Io Jansz gas field is situated in the Carnarvon Basin on the North West Shelf of Australia. It is Australia’s largest gas field, estimated to hold over 20 TCF of gas reserves and covering an area of over 2000 km2. Following a series of appraisal wells and a 3D seismic survey, this field is moving rapidly towards development. Image quality of the 3D provided significant uplift over existing 2D surveys in the area. Expectations for resolution and business targets have been met through careful planning and the provision of staged deliverables.Despite the exceptional data quality, a number of technical challenges were encountered that led to operational changes and adaptations by the project team. Source height statics and severe image distortion due to overburden are examples of some of the challenges addressed. Consideration of the exploration history of this field and its associated imaging gives insight into the improvements in image quality that can be realised by careful selection of acquisition and processing parameters, high levels of quality control (QC) and modern processing algorithms. The ultimate success of this project was achieved through close cooperation within interdisciplinary teams comprised of partner technical staff and the seismic acquisition and processing contractor.
INITIAL REVIEW OF THE BIOSTRATIGRAPHY AND PETROLEUM SYSTEMS AROUND THE TASMAN SEA HYDROCARBON-PRODUCING BASINS
Authors: Cook R.A. , Crouch E.M. , Raine J.I. , Strong C.P. , Uruski C.I. , Wilson G.J.
Published: August 2017

Understanding the genesis and habitat of hydrocarbons in a sedimentary basin takes knowledge of that basin at many levels, from basic infill geology to petroleum systems, plays, prospects and detailed sequence stratigraphy. While geophysics can define the basins and their internal structures, biostratigraphy and paleogeography provide greater understanding of basin geology. Micropaleontology and palynology are the chief tools that we need to define both the environment and dimension of time.As an example, the reconstruction of the Tasman Sea region to the mid-Cretaceous (ca 120 Ma) shows that the hydrocarbon-producing Gippsland and Taranaki petroleum basins developed at similar latitudes and in similar geological contexts. Other basins within the region have been lightly explored and need evaluation as to the value of further exploration.As paleontology has developed separately in Australia and New Zealand, comparison of biostratigraphic zones and their chronostratigraphy is critical to understand the similarity or otherwise of the sedimentary record of the two regions. Recent refinement of the NZ timescale and comparative studies on Gippsland Basin wells by NZ paleontologists have provided some key insights that enable us to compare the geological history of both regions more closely, and to recognise similarities in petroleum systems that may enhance petroleum prospects on both sides of the Tasman Sea.
DEVELOPMENTS IN THE CENTRAL AND NORTHEASTERN EAST COAST BASIN, NORTH ISLAND, NEW ZEALAND
Authors: Uruski C.I. , Field B.D. , Funnell R. , Hollis C. , Nicol A. , Maslen G.
Published: August 2017

Oil production in the East Coast Basin began in the late 19th century from wildcat wells near oil seeps. By the mid-20th century, geology was being applied to oil exploration, but with little success. In the late 20th century, seismic techniques were added to the exploration arsenal and several gas discoveries were made. At each stage it was recognised that exploration in this difficult but tantalising basin required more information than was available. Continuing work by exploration companies, as well as by the Institute of Geological & Nuclear Sciences (GNS), has begun to reduce the risk of exploration. Source rocks have been identified and sophisticated thermal models show that petroleum is being generated and expelled from them as shown by numerous oil and gas seeps onshore. Many potential reservoir sequences have been recognised from outcrop studies and depositional models are being refined. All components of petroleum systems have been demonstrated to be present. The most important deficiency to date is the general lack of high-quality seismic data which would allow recognition of reservoir facies in the subsurface.During early 2005, Crown Minerals, the New Zealand government group charged with promoting and regulating oil and gas exploration, commissioned a high specification regional 2D survey intended to address some of the main data gaps in the offshore East Coast Basin. A broad grid was planned with several regional lines to be acquired with a 12,000 m streamer and infill lines to be acquired with a streamer 8,000 m long. It was expected that the long streamer would increase resolution of Paleogene and Cretaceous units. Several of the lines were actually acquired with a 4,000 m streamer due to unexpectedly high rates of unserviceability. The resulting 2,800 km data set consists of a series of northwest–southeast lines approximately orthogonal to the coast at a spacing of about 10 km as well as several long strike lines.GNS was contracted to produce a series of reports covering source rock distribution, a catalogue of reservoir rocks, a regional seismic interpretation, thermal models and structural reconstruction. The data package and reports are available free of charge to any interested exploration company to accompany the licensing round that was announced on 1 September 2005. The new data set has confirmed the existence of a large, little-deformed basin to the north of North Island and the Bay of Plenty; it has elucidated the complex structure of a large part of the East Coast Basin and has enabled generation of a general sequence stratigraphic model which assists in delineating reservoir targets. On 1 September 2005, the New Zealand government launched a licensing round covering about 43,000 km2 of the East Coast Basin, from the far offshore East Cape Ridge in the north to the northern Wairarapa coast in the south. Four blocks (I, J, K and L) were on offer for a competitive staged work programme bid, closing on 17 February 2006.
BASEMENT AND CRUSTAL CONTROLS ON HYDROCARBON MATURATION—LESSONS FROM BREMER SUB-BASIN FOR OTHER FRONTIER EXPLORATION AREAS
Authors: Goncharov A. , Deighton I. , Petkovic P. , Tassell H. , McLaren S. , Ryan D.
Published: August 2017

A consistent approach to the assessment of basement and crustal controls on hydrocarbon maturation in the Bremer Sub-basin, offshore southwest Australia, has been undertaken as part of the Australian Government’s Big New Oil initiative. Geoscience Australia acquired marine reflection seismic survey in this area during late 2004 in conjunction with recording of refraction seismic data by sonobuoys at sea and by land stations in the onshore/offshore observation scheme. One of the key findings of the refraction seismic study is that velocities in the basement are generally in the 5.0–5.7 km/s range, indicating that, contrary to prior expectations, basement in the area is mostly not granitic in composition. Results from the conjugate margin in Antarctica also show low velocities in the basement on the inner side of Antarctic continent-ocean boundary, consistent with results from the Australian margin. It appears that a ~400-km-wide zone in Gondwana prior to break up had basement velocities significantly lower than the normal continental values of 6.0–6.2 km/s most commonly associated with granites and gneisses. Low-grade metasediments of the Albany-Fraser Orogen and its Antarctic equivalent is the preferred interpretation of this observation. Granites, dredged from the sea floor in the Bremer area, may represent only a small fraction of the basement, as within the basement highs where higher velocities have been detected by refraction work. As metasediments produce substantially less heat than granites, a different scenario for hydrocarbon maturation in the Bremer Sub-basin is possible. To quantify possible heat production in the Bremer basement and crust below it we have used contents of radioactive elements in rock samples taken from outcrops of Yilgarn Craton and Albany-Fraser Orogen onshore, as well as in rock samples dredged from the sea floor in the Bremer Sub-basin. Advanced burial and thermal geohistory modelling in this area was carried out using Fobos Pro modelling software for the first time in Australia without relying on default or inferred values (such as heat flow or geothermal gradient). Modelling showed that subsidence curves can be matched in various basement composition scenarios, but the high heat-producing granitic scenario leads to a present-day surface heat flow of 68 mW/m2 predicted by the model—unrealistically high given the context of heat flow measurements on the Australian Southern Margin. Other basement compositions (low heat- producing granite, metasediments, basalts) lead to a present-day surface heat flow of 46–57 mW/m2 and cannot be ruled out on the basis of heat flow modelling and data alone. This work details a methodologically consistent approach to burial and thermal geohistory modelling for other frontier areas where appropriate geophysical data have been collected.
HYDRATES—A CHALLENGE IN FLOW ASSURANCE FOR OIL AND GAS PRODUCTION IN DEEP AND ULTRA-DEEP WATER
Authors: Freij-Ayoub R. , Rivero M. , Nakagawa E.
Published: August 2017

Offshore exploration and production is going to deep and ultra deep waters, driven by the depletion of continental shelf reserves and the high demand for hydrocarbons. This move requires the continued extension of existing technologies and the development of new technologies that will make the investment economically viable. Innovative flow assurance technology is needed to support ultra deepwater production, particularly within the concept of platform free fields where there is a need to minimise interventions.Hydrates present one of the major challenges in flow assurance. Deep and ultra deep water operations together with long tiebacks present the ideal conditions for the formation of hydrates which can result in pipeline blockage and serious operational and safety concerns. Methods to combat hydrates range between control and management. One main technique has been to produce the hydrocarbons outside of the thermodynamic stability domain of hydrates. This is achieved by keeping the temperature of the hydrocarbon above the stability temperature of hydrates by insulating the pipe line, or by introducing heat to the hydrocarbon. Another efficient way of combating hydrates has been to shift the hydrate phase boundary to lower temperatures by using chemicals like methanol and mono ethylene glycol (MEO) which are known as thermodynamic inhibitors. Within the last decade a new generation of hydrate inhibitors called low dosage hydrate inhibitors (LDHI) has been introduced. One type of these LDHI are kinetic hydrate inhibitors (KHI) that, when used in small concentrations, slow down hydrate growth by increasing the induction time for their formation and preventing the start of the rapid growth stage. Another approach to managing hydrates has been to allow them to form in a controlled manner and transport the hydrate-hydrocarbon slurry in the production pipe. In this paper we describe the various approaches used to combat hydrates to ensure flow assurance and we discuss the cons and pros of every approach and the technology gaps.
WHISTLEBLOWING, OIL, MONEY AND RISK
Authors: Young D.
Published: August 2017

Statutory whistleblower laws in the US have resulted in the recovery of billions of dollars of unpaid royalties from petroleum companies over the past decade. Eighteen months ago, Australia introduced whistleblower laws that could have achieved the same result if the royalty avoidance had occurred here. This paper examines the emergence and application of those laws, and policies of regulators which achieve a similar result. It also argues that the adoption of a whistleblower policy, which includes protection for the whistleblower, is not only desirable, but an essential tool for managing risk.At a secondary level, it looks at the types of reported actions, typically taken against whistleblowers, that are now outlawed by the new whistleblower protection provisions.