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.
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 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.
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.
Gorgon project - No abstract available.
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.
Air injection is an Enhanced Oil Recovery (EOR) technique with limited exposure in the Asia-Pacific region and no previous application in Australia. Analogy with successful air injection projects in the USA, suggests that it could be a suitable EOR process for onshore light oil fields in Australia; no evaluation has been conducted to date.
Using open file data, high level screening criteria are used in this study to identify prospective petroleum basins, and an individual candidate reservoir is examined through a simulation study. Key issues in the application of the technique are discussed, as are directions for implementation in Australia.
Air injection involves the continuous injection of high-pressure air into the reservoir. The oxygen in the air reacts with the reservoir crude, consuming 5-10 % of the Original-Oil-In-Place (OOIP) and generating flue gases in-situ. This creates a gas drive process and acts to re-pressurize the reservoir. The process does not require water as a mobility control agent; a significant advantage in water-scarce Australia. It could also replace hydrocarbon (HC) miscible floods, freeing cleaner HC gases for energy use. Ideally the process is suited to deep, high-temperature, light oil reservoirs, and is applicable to both secondary and tertiary recovery.
The Cooper-Eromanga Basin, Carnarvon Basin (Barrow Island) and the Surat-Bowen Basin were identified as the most prospective. The simulation study conducted for ‘Reservoir A' in the Cooper Basin indicated the potential for spontaneous ignition and propagation of a stable combustion front within the reservoir; hence it is a potentially good candidate for EOR by air injection.
Given the ‘high' oil price and maturity of Australia's oil provinces, significant value is associated with EOR. Air injection is potentially suitable for Australian onshore application. The process warrants further evaluation and consideration as an alternative to accepted EOR techniques.
It has been known that infill drilling can improve the recovery of hydrocarbon by accelerating the hydrocarbon productions because most reservoirs in the real world are not homogeneous. With the increasing demand for energy and higher oil and gas prices, more and more fields all over the world are undergoing infill drilling. This paper describes the development of infill drilling in the petroleum industry and summarizes what petroleum engineers have learnt in the past 20 years about infill drilling. Various field examples are discussed on the successfulness and failure of the infill drilling campaigns in the industry. The results of our study indicate that when the reservoirs become more heterogeneous, the infill drilling works better.
The importance of enhanced oil recovery technology (EOR) cannot be overemphasized, especially in the context of a mature petroleum province or a country, such as the U.S., with declining domestic production and increasing imports. The decline of domestic production and increasing of petroleum imports reminds us of our increasing dependence on foreign petroleum supplies. Combined with the fact that the probability of finding new discoveries is continually decreasing reinforces the need for EOR oil recovery technology.
The significance of EOR lies in the promise it holds for increasing the expected production from existing oil fields. In mature petroleum provinces, such as the onshore US in general, growth of reserves in existing oil fields typically contributes more to the industry's continued viability than the discovery of new fields. In other words, in thoroughly explored provinces, better technology, more accurate reservoir characterization, and more effective production from known fields typically add new reserves faster than exploration for new fields.
It has been known that infill drilling can improve the recovery of hydrocarbon by accelerating the hydrocarbon productions because most reservoirs in the real world are not homogeneous.1-7 Driscoll1 and Gould et al..2, 4 summarized the various factors that contribute to increased recovery after infill drilling in 1980s:
• Improved areal sweep
• Areal heterogeneity
• Improved vertical sweep
• Lateral pay connectivity
• Recovery of “wedge-edge” oil
• Reduced economic limits
Recently, with the increasing demand for energy and favourable oil and gas prices, more and more fields all over the world are undergoing infill drilling. The advances in reservoir management provide a much clear picture of hydrocarbon distribution in the reservoirs which helps petroleum engineers to plan highly effective well profiles and the advanced imaging technologies allow the hydrocarbon field operators to select the best locations for infill drilling to optimize well placement.
In the past 20+ years, many infill drilling projects have been put into production and lots of valuable experiences have been gained on infill drilling. Therefore, the purpose of this paper is to present lessons learned and best practices on infill drilling from published literatures and provides a concise compendium to the current understanding of current industry infill drilling practice.
The Stybarrow Oil Field is located in Block WA-255-P offshore Western Australia, in an average water depth of 800m. This paper is a work-in-progress case-study of the process of discovery and appraisal of the Stybarrow field, and the influence on appraisal and development decisions of integrating the various types of geological, geophysical, and engineering data and techniques available to the modern oil company and their partners.
In the fault bounded Stybarrow structure, medium viscosity, medium GOR oil is reservoired in high quality but friable sandstones of the Lower Cretaceous Macedon Member. The average reservoir depth is around 2200mSS. High quality 3D seismic data has been used to both significantly reduce uncertainty in modelling the Stybarrow structure, and attempt to predict reservoir quality and distribution using well-calibrated seismic inversion to relative acoustic impedance. Results from the use of seismic inversion have been fundamental in constructing static reservoir models. The static geological modelling has been used in the construction of simulation models, with the view to simulating flow of the near-saturated oil through the relatively thin Macedon reservoir and thus predicting production. Pre-project feasibility simulation results were used to select a preferred reservoir management scheme. A simulation derived Integrated Production Model was then constructed. This allowed examination of the interaction of reservoir with a proposed processing and facilities under given processing facility design constraints.
The influence of a number of data types on appraisal decision making and development planning is discussed. Elaboration is also made on the impact of near-field exploration potential, and the possible influence of this potential on Stybarrow development planning is also discussed.
Key Words: integration, geological modelling, seismic inversion, simulation, production engineering, exploration, appraisal, development planning, infrastructure.