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.
Bream Field, in Australia’s Gippsland Basin, was originally developed in 1987 as a thin oil column development with gas cap re-injection. A satellite platform was installed in 1996 to capture resource not reachable from the original platform. After achieving 68% recovery, oil rates had fallen to the point that gas cap blowdown was commenced. Given the extremely strong natural pressure support seen in the Gippsland basin, a controlled blowdown was carried out to maximize oil recovery during gas export. As the water level approached the top of the structure, an assessment was carried out to determine the best use of the field infrastructure.
The result of this effort was a decision to utilize the field for gas storage while simultaneously achieving enhanced recovery. By refilling the Bream reservoir with dry gas from the Longford gas plant during the summer months, high liquid yield fields are able to be produced consistently throughout the year. Additionally, Bream gas deliverability capacity is increased in the high gas demand periods. As the dry gas moves through the reservoir, it contacts both residual oil and rich gas, becoming re-saturated with gas liquids. When this gas is re-produced, it will yield more liquids, raising the overall recovery of the oil by approximately 1%. Re-injection into the Bream reservoir began in 2013 and is proceeding as planned.
This paper will discuss the history of the Bream development, highlighting the analysis and planning that led to the recently implemented project. The management of this field demonstrates a number of techniques for maximizing hydrocarbon recovery over the life of a field, as well as considerations for maximizing economic value of the infrastructure.
Bream Field, in the southwestern part of the Gippsland Basin (Australia), was originally discovered in 1969 and first developed in 1987. It is produced by the Gippsland Basin Joint Venture (between Esso Australia Resources Pty Ltd and BHPBilliton Petroleum (Bass Strait) Pty Ltd), with EARPL as the operator. GBJV offshore infrastructure includes 19 platforms, 4 subsea installations, and a network of pipelines feeding the Longford Gas Plant (see Figure 1). Approximately 98% of the production from the basin has come from the GBJV, since start-up in 1969. Bream Field and its development have been described in several publications, including:
The Bream development history, along with the forward plan described here, provide an interesting case study that demonstrates how available technology and the market demands drive development decisions.
This paper was selected for presentation by an OTC program committee following review of information contained in an abstract submitted by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. The abstract must contain conspicuous acknowledgment of OTC copyright. Abstract Burial of submarine pipelines and cables is common practice in the North Sea where potentially damaging threats such as fishing gear interaction and dragged anchors are high, or where burial is required for flow assurance. Whilst the requirement to bury pipelines in Asia-Pacific has not had the same imperative as in the North Sea, there is now a growing requirement for pipelines to be trenched, particularly to increase mechanical protection and improve on-bottom stability. Trenching is considered to be one of the offshore activities that carry most commercial risk. It is therefore important to ensure that the correct tool is selected for the anticipated field conditions and to establish realistic performance criteria based on regional experience in the prevailing seabed soils. This paper compares the primary differences between seabed sediments of the North Sea to those that prevail in Asia-Pacific and discusses where differences in these conditions can affect the choice of burial equipment and tool performance when planning trenching in this region. Performance benchmarks for most trenching systems are based on experience and empirical relationships developed for seabed soils typically found in more northern latitudes. Consequently, the main body of burial performance data does not account for the carbonate rich seabed sediments for example that are prevalent in the Asia-Pacific region. Carbonate cemented soils and weak rocks pose a significant challenge to burial and trenching experience in these materials remains very limited. A trenching case study is presented which highlights the challenges of designing an appropriate protection and burial strategy for this region and provides indications of actual performance that can be expected in some of the carbonate sediments typically found in an Asia-Pacific location. It is hoped that this paper will go some way to address the gaps associated with performance predictions in carbonate sediments and will provide a reference point on which to plan trenching work in Asia-Pacific region.
Process surveillance of the Offshore Snapper Platform in Bass Strait identified an exponential increase in differential pressure in the 17.5km subsea oil pipeline after the 2008 Rig 175 Snapper-Moonfish infill drilling campaign. The increase was attributed to a build-up of wax which resulted when the crude (with pour points between 25 and 45°C) was cooled to the 15°C operating temperature of the pipeline. Process upsets and an increase in platform backpressure resulted. Further, the crude gel strength as determined by laboratory tests was such that the pressure required to reinstate flow in the pipeline exceeded that available from the existing platform facilities, resulting in a threat to continued production if the platform was to shutdown.
An understanding of the wax characteristics specific to the Snapper & Moonfish crude was obtained by leveraging expertise from ExxonMobil's global organization including ExxonMobil Upstream Research Company, local technical experts, external consultants and research groups. To reduce the risk of a blocked pipeline the frequency of pigging was increased and a minimum water cut of 40% was imposed as a short term risk reduction measure while facilities to continuously inject a wax inhibitor were pursued.
Differing crude mixes, water cuts, emulsions, and pipeline cooling properties are all factors which impact wax behaviors in subsea oil pipelines. Rheological tests showed that the shear yield stress of the pipeline fluid decreased with increasing water cut, with the Moonfish crude having a yield stress approximately double that of the Snapper crude. By comparing these results to proven operating practices, operating boundaries under which the pipeline could be reliably operated were established. A 40% water cut minimum was implemented to ensure the pipeline could be restarted.
Further tests determined the selection of a suitable wax inhibitor and the required dosage rate. The application of a wax inhibitor chemical resulted in the formation of weaker wax matrices which improved restart performance and hence operational confidence in the event of a shutdown. The design of the retrofit facilities required consideration of operational, safety and financial implications to ensure a reliable system was installed.
Monitoring of changing platform conditions allowed the early identification of a financial risk which had not previously been present. Understanding theoretical and practical wax characteristics enabled this risk to be mitigated and the crude and condensate platform production rate to be sustained. The continuous injection facilities removed the need for the 40% water cut minimum, reduced corrosion inhibitor costs, and relieved pressure on downstream water handling facilities.
The discovery of a wax deposition and gelling issue in the SNA oil pipeline highlighted the importance of technical monitoring programs. Further, the studies conducted have led to an enhanced knowledge of wax behavior in subsea oil pipelines and specifically an understanding of how changes in water cut impact pipeline restart which has application beyond this pipeline and Bass Strait.
Australia - No abstract available.
ExxonMobil subsidiary Esso Australia Pty Ltd has implemented a Sand Management System to minimise the impact of sand to its operations in the Bass Strait. Some of these facilities have been in operation for more than 30 years and no downhole sand control was installed during original drilling completions. Over time, with increased water production, sand production has become more problematic.
This paper examines the strategies used to minimise the impact of sand production on facilities including the impact of corrosion and erosion on downhole, offshore topsides and pipeline infrastructure. The Sand Management System defines a management structure, with assigned responsibilities to ensure that guidelines are followed and continuous improvement opportunities are enacted. The system includes operational instructions for flowing wells, monitoring sand production, and installing retrofit sand control where required.
The hazards of oil and gas facilities are well known to the league of operators, hardware providers, designers and lieges of contractors and consultants who work supporting the industry. Since Piper Alpha in 1988 safety is and has been a priority and the driver of countless modifications to ensure the well being of personnel in operating environments.
The oil and gas industry overall has shown a declining trend in fatalities and injury rates around the world demonstrating that learnings from mistakes have been taken on board so that they are not to be repeated. With the advent of deepwater production, bigger equipment items, changing field conditions and extended field lives, the financial rewards have become potentially even greater than ever to the industry, but at what risk?
The drivers are changing just like in the Le Mans 24 hour car race, the impact of safety risk is less prevalent as people are removed and other risks comes to the fore.
This paper discusses some of the issues that Granherne and the author has experienced in its provision of safety services to the oil and gas industry and provides an insight into how safety principles can still be focused even without the people present.
Before looking at some of the observed trends and risk challenges in the oil and gas industry it is important to ensure that some key definitions are understood.
Risk Trends and Challenges for Today's Industry
The following describes observed risk trends in the oil and gas industry that Granherne and the author have seen through consulting. Each risk trend is identified and key issues highlighted in order to promote discussion of some current and anticipated future issues.
Safety in Design
Designing a facility that is functional efficient and safe at reasonable cost has always been at the heart of the design process. Designers have always been aware of accidents at other facilities and have endeavoured to incorporate these learning's to ensure that the same accident does not happen again. It has been important since the advent of the Safety Case in Australia in 1995 that these learnings should always be incorporated into other operations. This philosophy is highlighted in both the Australian onshore Major Hazard Facility guidelines (Ref. NOHSC, 2002) and National Offshore Petroleum Safety Authority guidelines (Ref. NOPSA, 2004). This is also one of the key principles in the United Kingdoms HSE assessment for offshore facilities (Ref. UKHSE, 2006).
Asset performance can often be improved through continuous monitoring and/or through better utilization of information extracted from the high frequency data that are becoming more readily available in today's digital world. ExxonMobil has a long history of applying advanced technologies in asset management. Today, we continue to use new hardware, integrated software, and improved data infrastructure to enhance asset management workflows. ExxonMobil is taking an enterprise-wide approach (Reece et. al. 2008) to implementing digital technology in asset management.
This paper presents four examples where ExxonMobil has taken advantage of high frequency data for timely asset management decisions. These four examples represent implementation at four different operational scales: for reservoir management, for well management, for facility management, and for plant management. The four examples are: (1) For a West African reservoir: Permanent downhole pressure gauge data have added value in reservoir modeling that in turn provided a method for calculating reservoir rates; (2) For South Texas gas wells: Real-time data access and charting capabilities were implemented and advanced data analysis explored to identify well events and manage well work-over activities aided by artificial intelligence; (3) For Norwegian oil fields: An integrated facility model was developed and tuned for surveillance and operation of a network of wells and production facilities that are shared by multiple fields; (4) For an Australian production plant complex: Production from offshore platforms, a gas plant, a crude stabilization plant, a fractionation plant, and a tank farm was optimized with high frequency data and automatic process control.