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Haghighi, M (The University of Adelaide) | O'Reilly, DI (Chevron Australia Pty Ltd, The University of Adelaide) | Hunt, AJ (Chevron Australia Pty Ltd) | Sze, ES (Chevron Australia Pty Ltd) | Hopcroft, BS (Chevron Australia Pty Ltd) | Goff, BH (Chevron Australia Pty Ltd)
This paper demonstrates how good technical evaluations and focused operational application can enhance the value of a mature asset. The Windalia reservoir underlies Barrow Island (BWI), situated 56 km from the coast of Western Australia, and has produced oil since 1965. Waterflooding commenced shortly after initial production, in 1967, and remains the main drive mechanism in the field today. Throughout the life of this onshore field, water injection and oil production have varied according to asset strategy and economic conditions. In this case study, we share how recent improvements made in the areas of Reservoir Surveillance and Operations activities have increased water injection efficiency and total oil recovery.
Through the use of new methods and workflows, the BWI Sub-Surface team was able to target specific areas of the field to distribute water to in order to increase injection and maximise oil production. For example, new workflows were built with the real-time PI monitoring system to analyse Pressure Fall Off (PFO) tests from each of the 147 waterflood patterns in detail. Capacitance-Resistance-Modeling was also leveraged to guide individual well target injection-rates. Operationally, several projects were also initiated to increase water injection into the right areas of the field.
The new Reservoir Management approach has significantly increased the volume of water being injected into the areas of need, supporting improved levels of oil production. For the first time in almost 10 years, the stream-day water injection rate has exceeded 90,000 bwipd. The results from PFO transient interpretation and pattern balancing proved effective in directing water to low-pressure, high-GOR areas of the field. They also provided valuable information about formation perm-thickness and skin. The phenomenon of water-cycling was also largely avoided, owing to close monitoring of production well tests and water injector transient surveys.
The present work addresses reservoir and operational aspects of Australia's largest active waterflood. The lessons shared are highly applicable to a low oil price environment, as they show how fit-for-purpose and low-cost acquisition of reservoir data can lead to improved field performance.
The Barrow Island Oil Field lies 56 kilometres off the northwest coast of Western Australia and has produced oil since 1965. The field is located on Barrow Island in a Class A Nature Reserve and currently produces around 5,000 barrels of oil per day from 468 oil producers and injects 80,000 barrels of water per day from 268 water injectors, which in the 2016 oil price environment creates some significant business challenges. A change in the Operator's asset leadership team coupled with a falling oil price environment through 2014 and 2015 provided an opportunity to change the way the asset was being managed. Change was facilitated by two key factors: the new asset personnel brought new perspectives, experiences and skills to the asset and the falling oil price provided a case for urgency. These two factors resulted in an enhanced focus on business purpose, minimum business needs/work scope and execution focus.
DI, O'Reilly (Chevron Australia Pty Ltd, The University of Adelaide) | BS, Hopcroft (Chevron Australia Pty Ltd) | KA, Nelligan (Chevron Australia Pty Ltd) | GK, Ng (Chevron Australia Pty Ltd) | BH, Goff (Chevron Australia Pty Ltd) | M, Haghighi (The University of Adelaide)
Barrow Island (BWI), 56 km from the coast of Western Australia, is home to several mature reservoirs that have produced oil since 1965. The main reservoir is the Windalia sandstone, and it has been waterflooded since 1967, while all the other reservoirs are under primary depletion. Due to the maturity of the asset, it is economically critical to continue to maximise oil production rates from the 430 online, artificially lifted wells. It is not an easy task to rank well stimulation opportunities and streamline their execution. To this end, the BWI Subsurface Team applied Lean Six Sigma processes to identify opportunities, increase efficiency and reduce waste relating to well stimulation and well performance improvement.
The Lean Sigma methodology is a combination of "Lean Production" and "Six Sigma" these are methods used to minimise waste and reduce variability respectively. The methods are used globally in many industries, especially those involved in manufacturing. In this asset, we applied the processes specifically to well performance improvement through stimulation and other means. The team broadly focused on categorising opportunities in both production and injection wells and ranking them, specifically: descaling wells, matrix acidising, sucker rod optimisation, reperforating and proactive workovers. The process for performing each type of job was mapped and bottlenecks in each process isolated.
Upon entering "Control" phase, several opportunities had been identified and put in place. Substantial improvements were made to the procurement, logistics and storage of hydrochloric acid (HCl) and associated additives, enabling quicker execution of stimulation work. A new programme was also developed to stimulate wells that had recently failed and were already awaiting workover, which reduced costs. A database containing the stimulation opportunities available at each individual well assisted with this process. The project resulted in the stimulation of several wells in the asset with sizable oil rate increases in each.
This case study will extend the information available within the oil-industry literature regarding the application of Lean Sigma to producing assets. It will assist other Operators when evaluating well stimulation opportunities in their fields. Technical information will be shared regarding feasibility studies (laboratory compatibility work and well transient testing results) for acid stimulation and steps that can be taken to streamline the execution of such work. Some insights will also be shared regarding the most efficient manner to plan rig-work regarding stimulation workovers.
Towler, Brian F. (School of Chemical Engineering, The University of Queensland) | Firouzi, Mahshid (School of Chemical Engineering, The University of Queensland) | Holl, Heinz-Gerd (Centre for Coal Seam Gas, The University of Queensland) | Gandhi, Randeep (QGC Pty. Ltd) | Thomas, Anthony (QGC Pty. Ltd)
Many field trials have been conducted to explore the effectiveness of using hydrated bentonite as a sealing material for plugging and abandoning (P&A) operations of oil and gas wells. Many of those trials are reviewed here, including trials in Texas, New Mexico, Oklahoma, Wyoming and Queensland, most of which have not been previously reported. All of these trials have been successful, even though a few wells have been eliminated from the programs because they were found to be unsuitable. In most jurisdictions regulation changes are necessary to allow bentonite to be used in order to plug wells. This has been done in California, Texas and Oklahoma. In Wyoming it is currently permitted as the bottom plug in coal-bed methane wells. In Queensland a field trial has been allowed under the experimental materials clause in the regulations.
The Gorgon project represents a tremendous vote of confidence in the hydrocarbon potential of the Carnarvon Basin, with foundation field resources underpinning a lifecycle of future gas supply projects developing the wider deepwater resource base. With the foundation development costs mostly sunk and production ramping up, investment exposure is at its lifecycle peak and there is intense focus on safe and reliable operations.
However, there is also a need to continue to mature upstream gas supply opportunities. Projects to continue developing the foundation fields are already moving through the planning and development process. Looking beyond those, activities are in progress for selecting the first wave of future gas supply projects and beginning their first steps of development planning.
Distant, deepwater developments carry multiple risks with complex geology, costly and therefore limited data acquisition and record-breaking flow assurance requirements. Long development schedules result in limited ability to respond to uncertainty in foundation subsurface outcomes. Opportunities to maximise lifecycle value include standardisation of "subsea building blocks" and careful planning of new infrastructure to capture geographical and execution synergies.
Chevron and its joint venture participants have invested in an extensive deepwater exploration and appraisal program and are well-positioned to plan for the future. Building a gas supply plan involves a complex combination of portfolio and project principles and processes, drawing upon multiple disciplines and functions in the value chain including exploration and appraisal, early concept project planning, major capital project execution and base business operations.
At this early stage in the Gorgon lifecycle, a pragmatic approach has been taken to deliver effective portfolio planning, providing both the long term view and driving the near term selection decisions for the next wave of supply projects. This paper describes some of the insights and trade-offs being learned and applied in developing the gas supply plan.
Arresting the loss of biodiversity is one of the challenges of our era. One of the primary drivers of this loss is the introduction on non-indigenous species where such species overcome the normal factors that contain and constrain population growth to become pest species that out compete the indigenous species resulting in the marginalisation and in the extreme case extinction of the native species. The lack of biosecurity not only risks biodiversity but also risks our economy and our way of life. Introduced diseases threaten animal production, weeds degrade agricultural output and pest species erode our amenity values in our neighbourhood. With the progression of globalisation and the associated increase in trade and development, proliferation of travel and large-scale migration between nations, the risk of translocating species that may become invasive increases as well. An invasive species episode imposes a costly externality on ecosystems in terms of composition, structure and function and all too often a cost to the socio-economic environment?
The search for new energy reserves and the subsequent development of newly discovered assets push deeper into the remote frontiers of our world. Proponents can expect to be challenged by interested and affected parties opposed to exploration or any proposal that involves development. These stakeholder groups not only are the stakeholders on the local or the national scene but more often than not also include large international non-government organisations. As such, companies and governments are under increased pressure to set new benchmarks and new best practices in order to gain or issue regulatory approvals and the ‘social licence’ to operate, often resulting in the bar for environmental approvals being raised.
This was indeed the case when thegovernment, on the advice of the community and subject matter experts, imposed a challenging condition on the approval of the Gorgon Joint Venture to develop the Gorgon Project on Barrow Island. This paper provides a high-level explanation of the Quarantine Management System developed in response to a requirement ensure no non-indigenous species is introduced or proliferated on Barrow Island and its performance.
The bulk of Chevron Australia's field operations are carried out in hot areas of Western Australia (WA). The climate, the work environment and the nature of tasks being carried out mean that heat stress management is a critical element in the Company's health protection efforts. Heat illness produces outcomes that vary from mild levels of fatigue and discomfort through to life threatening conditions such as heat stroke. Additionally, it is well recognised that excessive deep body temperature and dehydration are connected with a decrement in both physical and mental performance, and hot conditions may thereby give rise to accidents and significant productivity loss.
Many of the logistical, earthworks and construction tasks now underway in advance of the Gorgon Project's operational phase are carried out in the open, with an accompanying high risk of UV exposure. As such, skin cancer protection is an important additional consideration.
What sets this work apart from the work of others is:
? The project was applied in a challenging, construction work environment characterised by constant change and many newcomers
? There was a focus on connecting well established scientific understanding with day-to-day practice in the field
? The project centred on an integrated approach to dealing with the twin issues of heat stress and UV protection
? Several new training packages, checklists, surveys and field trials were introduced
? There was a close connection with external stakeholders, including the Cancer Council Western Australia (CCWA), WorkSafe WA and the Commission for Occupational Safety and Health
The project involved the development and communication of expectations, procedures and processes to support leading practice management of heat stress and UV exposure.
The paper describes a comprehensive approach to both heat management and sun protection. It should have broad applicability to Oil and Gas Industry operations in warmer parts of the world.
In Western Australia, Chevron leads the development of the Gorgon and Wheatstone natural gas projects, two of Australia's largest-ever resource projects. In addition, the Company manages an equal one-sixth interest in the North West Shelf Venture, is a participant in the proposed Browse LNG Development and operates Australia's largest onshore oilfield on the Barrow Island and Thevenard Island oilfields. It is expected that first gas for the Gorgon Project will be in 2014, while that for Wheatstone will be in 2016. The construction workforce for each project will peak at approximately 5,000 workers.
Biosecurity is one of the emerging priorities of the 21st century. Biosecurity threatens biodiversity, economic output and our lifestyles as invasive species establish and proliferate at a pace not witnessed before. As globalization progresses, trade and travel increase and the risk of invasive species being introduced to new environments and habitats increases. Coupled with potential ecosystem changes (perhaps the consequence of climate change) biosecurity has become one of the focus areas of this generation. Within that focus area, arresting the loss of biodiversity as the consequence of non-indigenous species introduction has emerged as a world wide priority.
As exploration and resource extraction advances into remote and often sensitive areas of the world, resource companies must expect to be challenged by stakeholder groups who have a very different agenda to that of proponents of such exploration or extraction projects. In this process the barriers to entry will consistently be raised, new environmental management benchmarks will continue to be set and impact mitigation will continue to include areas previously not considered as part of project cost.
Biosecurity is rapidly becoming a new project discipline as the community struggles to internalize the inter-generational impact that biosecurity incidents present on communities. Historically, governments were held responsible for funding biosecurity legacy issues. This tax payer funded ‘clean-up' is fast coming to an end with a purposeful drive that ‘risk makers' must be responsible for the biosecurity risks that accompany their activities. This was witnessed by the position West Australians, the West Australian Government and other subject matter experts took when it was proposed that a gas processing facility be located on an offshore protected area with irreplaceable conservation values. This paper addresses the process that was followed and the management system that was developed to protect the conservation values of this protected area.
A screening study and subsequent chemical EOR application pilot strategy for a complex, low-permeability waterflood is presented. Our focus has been on developing appropriate field application options allowing flexibility of operation against a background of reservoir complexity and uncertainty.
Australia's Barrow Island Windalia reservoir, the nation's largest onshore waterflood, was developed in the late 1960's. Cumulative oil production to date is approximately 288 MMSTBO. Planning a chemical EOR scheme needs to address the following reservoir and production characteristics:
Despite 40 years of production involving water flooding, well-work, and changes in operating philosophy, the nature of the reservoir presents significant uncertainties. These uncertainties flow-on to difficulty in constructing predictive reservoir models.
Initial screening recommended that polymers be considered for sweep improvement and conformance control although reservoir complexity presented a challenge. Subsequent laboratory work focused on issues of polymer injectivity, rheology, and retention, in parallel with an assessment of how SCAL properties are measured in the laboratory and related to water flood performance. Dynamic modelling studies have assessed field response and economics for a range of chemical EOR pilot designs.
We have focused on developing options for field application of polymers, as opposed to extensive stand-alone laboratory and dynamic modelling studies, in order to address reservoir uncertainties and forecast production response. Results from the proposed polymer pilot flood will allow assessment of further chemical EOR applications and potential field-wide scale up.
We propose a mechanism, termed in-depth flow diversion (IFD), which may operate in low permeability, fractured injector water flood. This would allow polymer EOR to operate in lower permeability water flood than currently envisaged.
Large scale implementation of CO2 Capture and Storage is under serious consideration by governments and industry around the world. The pressing need to find solutions to the CO2 problem has spurred significant research and development in both CO2 capture and storage technologies. Early technical success with the three existing CO2 storage projects and over 30 years experience with CO2-EOR have provided confidence that long term storage is possible in appropriately selected geological storage reservoirs. Monitoring is one of the key enabling technologies for CO2 storage. It is expected to serve a number of purposes - from providing information about safety and environmental concerns, to inventory verification for national accounting of greenhouse gas emissions and carbon credit trading. This paper addresses a number of issues related specifically to monitoring for the purpose of inventory accounting and trading carbon credits. First, what information would be needed for the purpose of inventory verification and carbon trading credits? With what precision and detection levels should this information be provided? Second, what monitoring methods and approaches are available? Third, do the instruments and monitoring approaches available today have sufficient resolution and detection levels to meet these needs? Theoretical calculations and field measurements of CO2 in both the subsurface and atmosphere are used to support the discussions presented here. Finally, outstanding issues and opportunities for improvement are identified.