The challenges and insights presented in this paper provide a unique case study of Australia’s evolving offshore petroleum industry from a regulatory lens. It documents how a regulating agency’s unique perspective can identify opportunities to optimise recovery, contribute towards improvements in good oil practice and ultimately adapt to the changing requirements of industry. This paper sets out the regulatory landscape, as well as the challenges that exist in managing an innovative, adaptive and evolving offshore petroleum industry. Australia’s offshore resource stewardship strategies must now respond to a more established, maturing, more ‘crowded’ and dynamic petroleum landscape. This challenges regulators to be increasingly responsive, adaptive, continuously improve practices and be well-informed regarding global trends, such as those affecting mature provinces. Opportunities to exchange ideas, collaborate and incorporate key learnings from other offshore regulatory regimes are considered key enablers towards achieving these goals. Australia’s maturing petroleum provinces are impacted by long distances, (relatively) low infrastructure density and greater water depths; whilst increasingly challenged to integrate smaller, deeper and economically marginal resources. Conversely, emerging/recently established production areas are now facing an increasingly dense infrastructure landscape with multiple potential development pathways. In contrast to traditional system-wide blanket or "title-by-title" approaches (particularly with respect to optimal use of existing infrastructure), effective resource stewardship requires an increased level of consideration of "area" or "regional" developments. A more responsive and adaptive approach, which fosters collaboration and effective dialogue between the regulator and industry, improves regional understanding and contributes toward optimum resource recovery (via lower life-cycle costs and accelerated production opportunities).

Acid gas removal mainly CO 2 and H 2 S from natural gas is an essential treatment process in the oil and gas industry to increase the heating value of sales gas, prevent corrosion of pipeline and process equipment’s and avoid crystallization during the liquefaction process ( Ahmad et al ., 2010 ). Among the popular acid gas removal technologies, the amine-based acid gas absorption process that relies on chemical absorption of acid gas into aqueous amine solution followed by thermal regeneration is one of the technologies that is widely used in the oil and gas industry for acid gas treatment ( Brau et al ., 2017 ; Yu et al ., 2012 ; Tay et al ., 2017 ). For amine-based acid gas removal technology, contactors play an important role to ensure efficient and economical separation processes. Membrane contactor technology is one of the promising alternatives to existing conventional contactors that provides a large surface area per unit volume, independent gas and liquid flow rate and ease of scale-up for the acid gas absorption process. In this study, the feasibility of using membrane contactor technology for CO 2 and H 2 S co-removal at high pressure was investigated. The effect of operating parameters such as gas flow rate, liquid flow rate and amine concentration on CO 2 and H 2 S removal performance using activated MDEA as liquid absorbent was conducted using the design of experiment approach. Results from experimental runs have shown that the H 2 S target outlet which is ≤50 ppm was achieved at all operating conditions but not for CO 2 outlet. The target CO 2 outlet which is 6.5 mol% was only achieved at experimental runs where the condition of gas flowrate is the lowest, liquid flowrate is the highest and amine concentration is the lowest. The results achieved have proven that there is a high potential to use membrane contactor technology for co-removal of CO 2 and H 2 S from natural gas.

The Jurassic Plover Formation is one of two reservoirs in the Ichthys Field, North West Shelf of Australia. It consists of fluvial to shallow-marine sandstones, shales and igneous rocks. The objective of this study is to build multiple scenario-based models to optimise development planning in preparation for the upcoming production phase. We have integrated data and interpretations of thin sections, cores, well logs and seismic data to create multiple geological concepts for the field and to identify key geological uncertainties. As the reservoir is geologically complex and many uncertainties were initially identified, it is essential to single out those uncertainties which have a significant impact on the development planning. We have established the key uncertainties and optimal model design for practical use through multi-disciplinary discussions and by running sensitivity models to check the production performance. A rock type (RT) scheme has been devised based on detailed petrographic observations and justified in terms of sedimentology and diagenesis. Using the scheme, a wide range of permeability variations in the sandstones has been captured and modelled. Environments of deposition (EOD) are firstly interpreted at core and well-log scales, then upscaled to the model zone scale. The EOD interpretations are laterally extended using lithology (sandstone, shale and igneous rock) probability maps derived from quantitative seismic interpretation (QSI). Multiple EOD scenarios are generated to capture the possible range of reservoir distributions. Each EOD is characterised by a unique net-sand porosity and RT proportion based on the well data. These values are used to define multiple possible porosity trends and RT proportions, guided by the EOD maps. The distribution and quality of the reservoir sandstones have been identified as key uncertainties. Another key uncertainty is reservoir compartmentalisation, thought to be mainly caused by sheet-like igneous intrusions. Subtle seismic lineaments are regarded as possible indications of such igneous intrusions, and multiple compartmentalisation scenarios have been prepared based on our understanding of igneous activity across the field. Reservoir structure and water saturation are also recognised as key uncertainties. Integrating the key uncertainties, we have established a practical modelling workflow and built multiple scenario-based models to cover a sufficient range of geological uncertainty. The workflow is also adaptive for future history matching, enabling us to flexibly edit the model properties under geological constraints. A decision tree for development planning, which defines a series of decisions for the well sequence depending on the well results, will be prepared based on the multiple scenario-based models delivered in this study. This will enable us to prepare for any potential decision-making in advance. The development planning will be continuously optimised throughout the production phase by simply selecting the scenario-based models most in line with the well results.

As the oil and gas industry enters the digital era, openness is a key enabler to realizing the vision of transforming the industry for the better. The practice of reservoir engineering and reservoir simulation is no exception. In this paper, an openness mechanism in a reservoir simulator using Python scripting language is introduced. It empowers engineers to utilize simulation in new ways. It extends simulator capabilities and enables people to implement flexible-control logic to solve field management challenges. The new openness mechanism in the simulator allows engineers to program and include Python scripts in a simulation model. These scripts interrogate and interact with the simulator. The scripts are executed by the simulator while running the model. Flexibility is available to execute the scripts at every Newton iteration, before and after every simulation timestep, at specified times, or when a criterion is met. Simulation model properties can be queried through the scripts, such as well connections, well properties, group properties, grid region properties, network entities, current simulation time, etc. The scripts can set properties such as well constraints, well and connection productivity index (PI), group production target, pausing or stopping the run, etc. Customized control logic, if not directly available in the simulator, can be implemented in the scripts that interrogate and drive the simulator. Such customization can be packaged as Python libraries and shared with team members, enabling continuous value creation. Public Python libraries, such as NumPy, pandas and pywin32 or win32com, can also be loaded in the scripts to extend even further what the simulator can do. The openness mechanism is demonstrated on case examples. They include customized action to acidize wells when production drops, approximating the geomechanical effect of decreasing well pressure, modeling the effect of fines in injected water on well injectivity, and connecting to a network simulator. Examples are also given on customized reporting for model diagnostics and result interpretation, setting production constraints based on economics calculated in an Excel sheet with complex fiscal regime, advanced gas accounting, management of sulphur content, dual-optimization to meet gas demand while honoring oil treatment capacity, and integrated asset modeling from reservoir to surface networks to processing facilities. the ability to extend built-in functionalities of a reservoir simulator and customize field management controls using user scripting language. It embraces innovation and enables continuous value creation in reservoir simulation.

The Wheatstone Project is an LNG development located in Western Australia, incorporating the Chevron Australia operated Wheatstone and Iago fields and third-party gas fields. Production commenced in mid-2017. The start-up of the Wheatstone and Iago fields was a unique opportunity to acquire reservoir surveillance information that was able to provide valuable reservoir insights. A key component of the analysis was the observation of pressure interference between wells from the initial well clean-ups. The design of the well clean-up sequence, discussed in a previous paper ( Flett & Connell, 2019 ) was influenced by operational guidelines and the application of Ensemble Variance Analysis to determine an optimised start-up strategy for interference testing with the objective of reducing subsurface uncertainties. The well clean-up sequence was executed safely and achieved the reservoir surveillance and operational objectives of the start-up program. Flexibility in the optimised well clean-up sequence allowed changes to the start-up strategy in response to changing operating conditions, without impacting the reservoir surveillance objectives. High quality pressure interference data was acquired, enabling clear determination of zonal reservoir connectivity within the Wheatstone and Iago reservoirs. Interpretation of pressure interference results with reservoir models, incorporating Ensemble Variance Analysis led to a change in approach for initial history matching and revision of static and dynamic model development for Wheatstone and Iago fields.

The sustained increase in global demand for cleaner fuels continues to drive the gas industry growth. Liquefied natural gas (LNG) has been a key enabler for this growth by making sizeable remote gas re-serves, which are unreachable by pipeline, accessible to the major and emerging gas markets. Every segment of the LNG supply chain has its own set of technical challenges. On the upstream side, many gas resources require significant pre-treatment before liquefaction, and the feed gas to the LNG facility is typically a mixture of various compositions from multiple sources; this composition mix evolves over the life of the project. The main challenge is development planning for the contributing reservoirs under the constraints imposed by the processing facility– managing reservoir deliverability, scheduling & sequencing of wells, and downtime management while maintaining the inlet stream specification. To aid with long-term planning for such assets, a virtual field management system is needed that can emulate a real-world hydrocarbon producing asset by capturing all operational constraints, resource lim-its, and complex operating logic. This paper describes a comprehensive field management framework that can create an integrated vir-tual asset by coupling reservoir, wells, network, and facilities models and provides an advisory system for efficient asset management. The field management component can replicate any operational logic, exercises holistic control over the sub-surface model, integrates with the surface network model, and provides optimization capabilities. This paper demonstrates this for a complex LNG asset that is fed by sour gas of different compositions from multiple reservoirs. We describe the different levels of constraints the asset needs to operate under, including treatment plant capacity, the LNG production capacity, the contractual LNG specifications, the disposal of gas impurities and imposes them on the model by utilizing a flexible and extensible logic framework. Con-straints applied at different levels can be mutually competing and their combination with recovery opti-mization goals increases complexity. The unified field management system uses a robust scheme to bal-ance the coupled system under these constraints while optimizing overall recovery. The optimization is enabled through the ability provided by the field management system to query and retroactively control flow entities during the simulation at the desired frequency. Customization through scripting was necessary to implement this advanced logic and was enabled by the extensible nature of the field management framework. This extensibility, along with native capabili-ties, ensures that any level of complexity can be captured, and the workflow described in this paper can be applied to any hydrocarbon producing asset for short-term and long-term development planning.

The Gorgon gas plant produces 15.6 Million Tonnes per Annum (MTPA) Liquified Natural Gas (LNG) from the Gorgon and Jansz-Io subsea gas fields. First LNG production commenced on the Barrow Island, Australia facility in 2016. One of the first systems commissioned was the wastewater treatment, collection and disposal system, a critical support utility for production operations. The Produced Water Disposal (PWD) facility is unique on Barrow Island due the location's national nature reserve status, and all treated waste must be disposed downhole. The objective of this paper is to review key lessons from design, startup and steady state operations. Perspectives will be given on facility/well management and production operations of PWD at the Gorgon plant. Wastewater on Barrow Island is generated from several sources: Condensed water originating from hydrocarbon gas (separated at gas dehydration and Mono-Ethylene Glycol (MEG) regeneration facilities), drainage and runoff water from the plant, treated sewage effluent and other ad hoc liquid waste. These sources are collected and treated before the final product is pumped into two available onshore disposal wells. One of the challenges initially faced was that the disposal water quality did not meet the design specification required to maintain well performance. This problem reduced as the plant reached steady state operations and the team gained a better understanding of well performance over time. Other current challenges include hydrocarbon carryover and water polishing, so Engineering and Operations work together closely to ensure reliable water disposal and hence LNG production. This case study will explore the success and lessons learnt in Gorgon PWD through a summary of field data, facility descriptions and experiences. An overview of the design will be given along with photographs of key components. The required design performance will be compared against actual operating data. In the new energy landscape, the Upstream Operators' social license to operate centers around our environmental performance. In our work we demonstrate that it is possible to treat and dispose of waste liquids responsibly while generating cashflow through LNG production.

This paper presents details of a comprehensive array of technical and commercial challenges associated with the feasibility of a long distance deepwater Middle East to India Deepwater Pipeline (MEIDP) providing information on the technical and commercial feasibility of the deepwater gas transportation system, which will reach a record water depth of 3450m, cross two continental slopes, an earthquake subduction zone (the Owen Fracture Zone) and outfall debris of the river Indus fan in 2500m water depth. It examines the techniques, analysis and technology development now available to make such challenging routes increasingly feasible. The economic and political drivers for such a project are presented together with details of the overall project cost and tariff calculation to allow successful gas utilization by India's gas starved and stranded power stations. The challenges faced by the project from both a design and installation perspective are discussed together with some of the detailed geohazard assessments performed for the pipeline crossing and active fault zone (OFZ) and the Indus Fan. High pressure trunk lines have proved to be the safest, cheapest way of transporting gas to market for short to medium distances up to 2,500 kilometers, making the proposed SAGE - Middle East to India Deepwater Pipeline the optimal solution for gas delivery to the Indian Subcontinent. Linking Middle East gas fields of Saudi Arabia, UAE and Oman to India across the Arabian Sea for an offshore distance of 1200 kilometers. The MEIDP gas transmission pipeline is designed to transport up to 1.1BCFD gas into the Indian energy markets. The qualification plan developed with DNVGL is described together with details of the future construction schedule for first Gas. The Middle East to India Deepwater Pipeline

In 2012, the International Energy Agency (IEA) released the ‘Golden Rules for a Golden Age of Gas’ - a set of best practice guidelines for unconventional gas development designed to address key environmental and social risks and gain public acceptance of the industry. This study sought primarily to understand the extent to which the experience of developing a large-scale coal seam gas (CSG) to liquefied natural gas (LNG) industry in Queensland, Australia was seen to have aligned with the Golden Rules, and how well the Golden Rules were seen to contribute to public acceptance of the industry. An evaluation tool was developed where the seven Golden Rules and their subclauses were adopted as criteria in a scorecard approach. We conducted interviews with 32 senior people who had been directly involved in the development of the CSG industry in Queensland, from local, state and federal governments, gas companies, host communities as well as researchers and consultant ‘experts’. The Queensland experience of unconventional gas development rated reasonably well in relation to the Golden Rules, with scores of three or higher out of five for four of the seven rule categories. Across all the Golden Rules, industry performance scored more highly than the effectiveness of the policy/regulatory environment, highlighting the complex and sometimes conflicted roles of governments in developing a new industry. The rules addressing baseline measurement, full disclosure and engagement were seen as most important for public acceptance. This study developed a new tool to evaluate perceived social and environmental performance of industry and effectiveness of governance in unconventional gas development applicable across different jurisdictional contexts. This application suggests that baseline measurements, open disclosure and public engagement should be the focus for building public acceptance. For new gas developments, these findings highlight the importance of having a robust regulatory environment in place that can coordinate activities and manage cumulative impacts.

This paper discusses the tank management optimization or automation of floating Storage Unit vessels in Peninsular Malaysia. The objective of automation is to determine which tanks need to be emptied for the incoming cargo (unloading process) and for the gas product from the regasification to be maximized. The FSU and jetty regasification unit (JRU) are in the same location, and both are offshore. Therefore, efficient production strategic planning is required. Tank management of the FSU unit has two procedures that must be fulfilled during the unloading and send-out activities: (i) The calculation must be developed beginning with the unloading – send -out activity. The activity is conducted when new cargo comes and fill the tank in the FSU (unloading). Meanwhile, the send-out activity is also conducted to manage high boil off gas (BoG) generation (re-condensation of the BoG) resulting from the unloading activity. The send-out activity must be conducted from the tank to the regasification unit. (ii) The send-out activity occurs after the unloading-send-out activity (previous activity) to fulfill the requirement from the regasification unit (nomination). The liquified natural gas (LNG) storage does not allow for mixed cargo to be stored in the same tank. Automation will provide an optimum send-out plan from each tank and each FSU. Currently, the range of cargo volumes that comes to the FSU is between 130 to 145 K M3. Using the proposed method, larger cargo could be scheduled and maximum gas from regasification at the JRU increases. Tank management automation will consider the first-in-first-out (FIFO) method regarding unloading time, boil off gas (BoG) temperature condition, and tank send-out sequence to ensure FSU balance. The FSU balance must be considered for the safety of the entire LNG regasification operation. Automation will provide an indication for the inter-tank transfer strategy when the volume of the incoming cargo requires more space compared to the available space. This is the first concept developed to create the best strategy for utilizing FSU and JRU units. The same concept could be implemented around the world for different cases, such as FSUs located offshore and JRUs located onshore, different tank sizes, and different regasification units.

With the increasing energy demand and call for cleaner energy, industry has ventured out for challenging environment such as deepwater and unconventional natural gas resources. While new development is necessary, improvement in gas supply can also be achieved by relooking into the current system. Currently, associated gas produced from oil well are mainly used in petroleum operations, while the remaining gas are either flared or vented to the atmosphere. Inefficient usage of associated gas which has high heating value impose a great value leakage to the company. This paper introduces a new concept that demonstrates more efficient usage and monetization of gas by utilizing associated gas and non associated gas based on its composition instead of volume and sales agreement. The value addition of this new concept was evaluated across the process chain from the upstream operator, host authority, to the downstream plant processing and end product at customer level, using a case study at Field A and Field B. Field A is a brownfield which utilizes produced associated gas for petroleum operations including gas reinjection. Field B is a non-associated gas green field which is tied in to Field A’s processing facilities prior to gas export. Both gas from field A and field B were evaluated based on their gas composition, gross heating value and customer requirement to determine the best option of gas utilization to maximize its value. Feasibility study was carried out to ensure the practicality of the job execution and at the same time commit to the legal and sales requirements. Field A and B belongs to the same PSC, and gas sales are purely based on the heating value and contractual volume requirement. Hence, Field B lower heat value gas can be used for injection provided that the similar volume was replaced for sales. The gas swapping for optimization can be conducted through simple flowline modification with minimal cost. A portion of gas from field B will be directed for gas reinjection at field A, while the associated gas at field A originally intended for injection will be utilized for sales. Injecting gas with leaner hydrocarbon composition will not hinder the oil recovery efficiency of field A. However, gas sales using associated gas from field A allow additional 11% profit gain for the operator from existing scenario. The products of processing the swapped associated gas will reap more profits to the downstream sector, as the gas has higher ethane, propane, and butane molecules. In the current situation, existing fields have always considered gas utilization individually. There is potential for all fields to utilize gas more effectively to increase the economic value of the field and downstream facilities.

Natural gas produced from underground reservoir is saturated with water and hydrocarbon vapor. The moisture content in natural gas steream is dependent of temperature and pressure, the higher temperature and the lower pressure, the higher moisture content. As the wellhead pressure continue to declline, the water content of produced gas will continue to rise. The dehydration process at Cluster 4 consists of two stages, namely Low Pressure (LP) Dehydration System and High Pressure (HP) Dehydration System which has different operating pressure and temperature. Currently, the performance of LP Dehydration and HP Dehydration System is under-perform that can be seen from the difference in the gas outlet chiller temperature between design condition and actual condition. Based on the root cause anaylsis, there are some equipment suspected do not work properly, such as pressure control valve in HP Chiller and Propane Compressur Anti-surge Controller (CCC). To maintain the desire moisture content of the gas at 36 lbs of water per MMSCF of gas, the suspected equipment that do not work properly need to be repaired or upgraded. After the dehydration system work properly, the operating temperature of the Porpane Chiller need to be reduced accordingly to maintain the desired water content. For the high pressure gas after booster compressor unit at pressure 335 psig, the chiller outlet temperature neet to be maintained at 55°F to prevent hydrates formation.

The oil and gas supply and demand pattern, "two supply belts, three consumption centers", remains basically unchanged. However, the unconventionaloil and gas output in the United States continues to grow rapidly, resulting in an oversupply of oil and gas around the world, which has an impact on the international oil price, so there is a profound impact on global exploration and development under the background of the low oil price. First, OPEC and Russia continued to cut supply, while the production growth of unconventional oil and gas in the United States realized its oil and gas exports, driving the change of the oil and gas geopolitical structure. Second, the global demand for crude oil grew moderately, slower than that for natural gas. Third, exploration investment plummeted under the low oil price, while newly proven reserves around the world continued to decrease. Fourth, development investment returned to low-cost and high-quality mature oil fields, while new capacity was reduced. However, with the gradual recovery of the international oil price in the future, the global oil and gas development will show a new trend. It is expected that the upstream construction costs will rise, with onshore costs recovering faster than that of the sea areas. If the global exploration and development investment continues to decline in the future, the global oil and gas will be in short supply in the next three to five years, which will once again affect the current tight balance between oil and gas supply and demand. Therefore, it is expected that both the oil price and the exploration and development investment will increase in 2018, and the game between OPEC and the United States will continue.

In an oil and gas project life cycle, commissioning is notably the moment of truth where the engineered, procured and constructed facilities are verified functioning for the first time. Inability to recognize a project's Commissioning and Start-Up (CSU) unique requirements would increase the risk of project failure. The risk could be mitigated by adopting the right mindset–begin with end in mind. This paper outlines the application of project management processes associated with commissioning discipline. A multinational operating company undertook a complex mega scale project that aimed to develop an integrated gas field and Enhanced Oil Recovery (EOR) in offshore Sarawak, Malaysia. The project, executed by multiple Package Contractors, is composed of a new central processing platform (CPP), 2 new wellhead platforms, 6 new pipelines, 1 submarine cable, 9 brownfield platforms, 16 new wells and 4 workover wells. Commissioning Team was mobilized as early as Front-End Engineering Design (FEED) and adopted Systemization to decompose the project complexity into manageable constituents. The CSU Philosophy was designed to formulate the Integrated CSU (ICSU) Strategy that systematically drives the construction completion and synergizes the efforts. Without the strategy, each package would have been focusing in delivering individual objectives that could have compromised the chance of overall project success. However, the timely deployment of it has realigned the execution strategies, noting that offshore project environment is largely dependent on marine vessels arrangement. The strategy managed also to break the silo mentality and encouraged collaboration and communication among the packages and Operations even before the start of the main offshore campaign. The teamwork, of 1200 manpower and 25 marine vessels at peak, was continued offshore and has materialized the introduction of hydrocarbon to CPP 40 days ahead of schedule. Subsequently, the first gas achievement was accelerated by two months ahead of schedule. Additionally, the risk of commercial exposure due to standby of marine vessels and resources caused by clashing of activities, was successfully mitigated. The experience and lessons learnt from the project can benefit others to undertake similar projects safely and successfully in terms of strategizing, planning and execution.

Brunei Shell Petroleum (BSP) has a complex production gathering network that comprises of multiple onshore and offshore Assets. Gas and oil is produced under different pressure regimes, and with varying compositions. The production from each asset can be routed in multiple ways to different customers, each with their own compositional requirements. Crude oil and gas is routed to Brunei Liquified Natural Gas (BLNG) and Seria Crude Oil terminal (SCOT) for further processing before export to external customers. Apart from export, other customers include BMC (Brunei Methanol Company), Brunei Shell Refinery (BSR) and Department of Electrical Services (DES), fueling Brunei's vehicles, homes and local industries. Currently this complex production network is managed by a dedicated Operations Control Centre (OCC). The central OCC team coordinates, monitors and controls the hydrocarbon activities to meet customers' quality and quantities demand by engaging with the 4 individual Asset Operation teams, as well as customers, to optimize production at the Pan-BSP system level. With the introduction of the Integrated Production Monitoring and Optimisation System (IPMOS) tool, the Pan-BSP production optimisation can be automated, in real-time. The IPMOS tool performs a high-level production optimisation built on top of existing real-time well production surveillance models, and it dynamically adjusts the system capacity in the event of upsets. In this way, the tool provides day to day advisory of production optimisation during both normal operations as well as during different production upset scenarios, and it also eliminates the need for OCC team to maintain multiple MS Excel sheets/macros to cater for those scenarios. This is a step forward in production system optimisation through digitalisation.

The Australia Pacific LNG (APLNG) Downstream Project comprised construction of a two-train LNG plant, two 160,000 m 3 LNG storage tanks, a LNG loading jetty, and associated infrastructure on Curtis Island, near Gladstone, Queensland. The facility utilises ConocoPhillips’ proprietary Optimized Cascade ® process to liquefy natural gas. Project planning began in 2008 and construction commenced in 2011. LNG production from Train 1 began in December 2015 and Train 2 came on line in October 2016. In August 2017, the final 90-day two-train lenders test was successfully concluded and included an operational component in which the LNG Facility operated at ten per cent above nameplate capacity for the 90-day period. This successful outcome was achieved through collaboration, integration and robust execution plans by the APLNG Operations, APLNG Project, ConocoPhillips LNG Technology and Licensing and Commissioning and Start-up work teams. In an effective strategy to support the drive to APLNG first cargo, the combined teams formed a fully Integrated Completions Team in 2015. This team worked together enabling rapid development of the operations workforce capability and resulted in both trains achieving performance tests at first attempt. The APLNG Project operability assurance and operations readiness program commenced with a collaborative workshop, attended by Operations, Projects and Commissioning and Start-up representatives. A focus on high collaboration and integration between the teams backed by ConocoPhillips’ Operability Assurance (OA) and Operations Readiness (OR) principles identified 370 critical business deliverables. Learnings were leveraged from across ConocoPhillips assets (including Darwin LNG) as they pertained to readiness best practice. APLNG Readiness Assurance guidance was established to create specific functional readiness trackers to measure every action supporting the 370 deliverables. A simple and effective tool was developed and supported by robust monthly review forums where each action was tracked and rolled up to S-Curves. These deliverables translated to over 7,000 unique line items tracked over the entirety of the readiness implementation. This work was leveraged by the Integrated Completions Team which implemented robust lessons learned from Train 1 to realize immediate results, delivering a 33% reduction in the Train 2 start-up schedule. The combined efforts of the teams delivered two highly operational trains within the 2016 calendar year resulting in the production of additional cargoes. The successful execution and implementation of OA/OR principles combined with strong integration of APLNG Operations into the APLNG Project phase laid the foundation for exceptional first year operational and production performance. This meant the APLNG Operations Team moved from a newly formed team to a high functioning and critically evolving team in support of the APLNG Downstream LNG Facility.

Australia is uniquely positioned globally as a major energy provider, but this comes with multiple challenges that must be overcome to realize its full potential. LNG developments that are nearing fruition are set to make Australia the largest supplier of LNG in the world. The Asian LNG market continues to be the growth market. The development of the world's first coal bed methane (coal seam gas) to LNG projects on the east coast has created a robust east coast LNG export market, which in the near future is expected to coincide with domestic energy shortages arising from low exploration activity, maturing fields, higher costs, the interaction of government policy, commercial decisions and activism. As a result, unique approaches to project management and community relations have been developed that are complementary to the Australian consumer's needs for reliable, affordable and cleaner energy. The east coast demand for gas is likely to trigger new development of onshore Northern Territory gas in the short term, if political opposition can be managed. In Western Australia, new approaches leverage technologies such as floating LNG, and more utilization of existing infrastructure and plant capacity to achieve lower costs. This paper outlines Australia's natural gas supply & demand and the challenges to be faced in the coming years.

Commencement of initial field production is a unique opportunity to acquire reservoir surveillance information that can inform future reservoir performance. When a field is perturbed from original conditions with first production, there is potential for reservoir property uncertainty reduction by observing pressure measurements at non-producing wells with downhole pressure gauges and comparing the observed signal to a range of simulation model results. The Wheatstone field, located offshore northwest Australia, has recently commenced production start-up to supply gas to the Wheatstone LNG facility. The operational guidelines required each development well to commence with a single well cleanup flow to the Wheatstone platform. The initial single well cleanup flows of the Wheatstone field allowed scope for the selection of a well flow sequence with observation at non-producing wells. The recommended sequence of initial cleanup flows was designed with a focus on reducing reservoir uncertainties via the use of Ensemble Variance Analysis (EVA). EVA is a statistical correlation technique which compares the co-variance between two sets of output data with the same set of inputs. For the Wheatstone field well cleanup flow sequence selection, the EVA workflow compared the full field Design of Experiments (DoE) study of field depletion and a series of short early production reservoir simulation DoE studies of the gas field. The co-variance between the two DoE studies was evaluated. The objective of the EVA approach was to determine the startup sequence that would allow for the best opportunity for subsurface uncertainty reduction. This objective was met by ranking multiple cleanup flow sequence scenarios. The key factors considered for sequence selection ranking were the impact on business objectives such as future drilling campaign timing and location of infill wells, as well as insights on reservoir connectivity, gas initially in place and permeability. The recommended sequence of well cleanup flows uses super-positioning of pressure signal to boost response at observation wells, which improves measurement resolvability. The selected sequence preserves key observation wells for each manifold and reservoir section for as long as possible before those wells were required to be flowed to meet operational requirements. Operational constraints and variations of the startup plan were considered as part of the evaluation.

Mercury is found in raw and untreated oil and gas produced from in-situ reservoir and must be removed for stable production and response to environmental issues. For optimization of Mercury Removal Unit (MRU) in production facilities, it is important to know accurately mercury concentration and chemical form of mercury species in production fluids. In design phase of production facilities, specification of MRU may be determined based on mercury concentration in production fluids collected during Drill Stem Test (DST). However, mercury concentration and chemical form of mercury species in DST may be unstable and different from those in stable production phase, because brine and drilling fluids containing dissolved oxygen flow in wells during DST. In this paper, the sampling and mercury analysis on production fluids after acid washing in a natural gas well was conducted to investigate influences of fresh brine containing dissolved oxygen on mercury concentration and chemical form of mercury species in flowback fluids in unsteady production phase like DST and just after well workover. As the result of the sampling and analysis, particulate mercury was detected in filtered solids collected from condensate and flowback water. In addition, mercury sulfide (β-HgS: metacinnabar and γ-HgS: hypercinnabar) was identified in the filtered solids by X-ray diffractometer. These particulate mercury concentration reached a peak (condensate: 1693 µg Hg/l, flowback water: 7751 µg Hg/l) around 40 hours elapsed from the beginning of clean up flow, and then went down with the passage of time afterward. After around 2700 hours elapsed, they decreased to 72.1 µg Hg/l (condensate) and 131 µg Hg/l (flowback water). At the same time, pH and total iron concentration in flowback water at that time were close to those in stable production phase. Hence, these results indicate that particulate mercury in production fluids was generated by the reaction of dissolved oxygen in workover fluids with hydrogen sulfide and elemental mercury in natural gas. Therefore, the occurrence of particulate mercury in flowback fluids after the well workover is considered to be temporary, and not to be produced in stable production phase. Although further investigations will be needed for the interpretation of mercury analysis results in the sampling and analysis, these results will be an important knowledge for interpretation of mercury analysis at DST.

Stress corrosion cracking (SCC) is one failure mode that may occurred on hot insulated austenitic stainless steel pressure vessels and piping. In 2007, Badak LNG experienced this problem on its Amine Regenerator pressure vessel where the shell are insulated and made of Austenitic Stainless Steel Grade 304L. The paper will share the fact and findings, failure analysis, improvement to prevent recurrence, repair methods and inspection. During the Train E overhaul in May 2007, cracks were observed on the shell exterior of Amine Regenerator pressure vessel. The cracks mostly occurred above the external vessel stiffening rings. Results of the failure analysis concluded that the pressure vessel failed by chloride induced stress corrosion cracking, due to moisture accumulation and the presence of chlorides at the affected locations in combination with a vessel operating temperature of 99 °C to 125 °C. Repairs were made by a combination of flush patching and weld built up methods. In addition to a 100% non destructive examination (NDE), a pneumatic leak test was conducted to ensure the integrity of the pressure vessel. Some improvements were implemented to prevent problem recurrence, i.e. coating application on shell external wall surface, implement new specification of thermal insulation and modify the stiffener ring. Further thorough inspections to ensure that no more SCC exists on the pressure vessel were performed using precise NDE tools, i.e. AE (Acoustic Emission) and TOFD (Time of Flight Diffraction). The results were no more cracks indication found. Currently, the pressure vessel has been in service for almost 10 years and no operational issues found related with SCC.