The Pyrenees Development comprises three oil and gas fields: Ravensworth, Crosby and Stickle. The fields are located in production licenses WA-42-L and WA-43-L, offshore Western Australia, in the Exmouth Sub-basin and are operated by BHP Billiton (Fig. 1). Eighteen subsea wells, including 14 horizontal producers, 3 vertical water disposal wells and 1 gas injection well have been constructed to date and additional wells are planned for infill and to develop additional resources. First oil was achieved during February 2010 and production exceeded 50 million barrels in November 2011.
The Pyrenees fields are low relief, with oil columns of approximately 40 metres within excellent quality reservoirs of the Barrow Group. The 19° API crude has moderate viscosity, low gas / oil ratio (GOR), and a strong emulsion forming tendency which makes oil/water separation and accurate well test metering difficult. Early in the project design phase it was identified that the complex subsea gathering system and the need to reduce measurement uncertainties would dictate special attention to production measurement.
Subsea multiphase flow meters (MPFMs) were specified to meet the challenges of production optimization and allocation while at the same time minimizing production deferral for separator testing. Each oil producer is monitored by a dedicated MPFM. With 14 meters, Pyrenees is among the largest subsea MPFM installations worldwide.
This paper describes the process of MPFM qualification and commissioning together with their performance over 2 years in the field. We show how close cooperation between the Operator and MPFM Vendor has enabled quality rate measurements of emulsified production despite large changes in producing gas/oil ratio and water cut.
While the primary justification for Pyrenees subsea MPFMs was production allocation and optimization, interpretation of transient water cut and GOR data proved valuable for production and reservoir engineering applications. Examples of proactive reservoir and production management including optimizing drawdown of Inflow Control Device (ICD) equipped wells, optimizing well lineup and gas lift to commingled wells are presented.
Producing and delivering North West Australia (NWA) deepwater gas reserves to LNG plants poses unique challenges. These include extreme metocean conditions, unique geotechnical conditions, long distances to infrastructure and high reliability/availability requirement of supply for LNG plants. A wet or dry tree local floating host platform will be required in most cases. Whereas semisubmersible, TLP, Spar and floating LNG (FLNG) platform designs all have the attributes to be a host facility, none has been installed in this region to date.
This paper will address important technical, commercial and regulatory factors that drive the selection of a suitable floating host platform to develop these deepwater gas fields off NWA. Linkages between key reservoir and fluid characteristics and surface facility requirements will be established. A focus will be on the unique influence of regional drivers and site characteristics including metocean and geotechnical conditions, water depths and remoteness of these fields.
There have been 17 FPSOs producing oil in Australian waters. These facilities have been chosen because of the remoteness of the fields and the lack of pipeline and process infrastructure. Storing oil on the FPSO for offloading and shipping from the fields becomes an obvious solution. Semisubmersible, TLP or Spar platforms show little advantage in such developments.
For deepwater gas developments, the product has to be processed, compressed and piped to shore for liquefaction. As host processing facilities, Semisubmersible, TLP and Spar platforms have clear advantages over FPSOs because of their superior motion performance in the harsh Australian metocean environment and other benefits such as facilitating drilling, dry tree completion and well services. FPSOs or FSOs may be applied for storage of associated oil and condensates. For marginal and remote gas field developments, an LNG FPSO (FLNG) may be an attractive option as it eliminates long pipelines and land-based liquefaction plants.
As discussed by Dorgant and Stingl (2005), a deepwater field development life cycle following discovery usually involves five distinct phases, Figure 1. The "select?? phase occurs after a discovery has been appraised sufficiently to further evaluate it for development. It consists of evaluating multiple development concepts and scenarios and selecting the one that will most likely achieve the identified commercial and strategic goals. Selecting a floating platform and its functions for a deepwater development is an important subset of the select phase and the overall field development planning.
The process of field development planning involves a complex iterative interaction of its key elements (subsurface, drilling and completions, surface facilities) subject to regional and site constraints (D'Souza, 2009). The objective is to select a development plan that satisfies an operator's commercial, risk and strategic requirements. It entails developing a robust and integrated reservoir depletion plan with compatible facility options. The selection occurs while uncertainty in critical variables that determine commercial success (well performance, reserves) is high. One of the challenges is to select a development plan that manages downside reservoir risk (considering the very large capital expense involved) while having the flexibility to capture its upside potential.
Napalowski, Ralf (BHP Billiton) | Loro, Richard (BHP Billiton) | Anderson, Calan Jay (BHP Billiton) | Andresen, Christian Andre (ResMan AS) | Dyrli, Anne Dalager (ResMan AS) | Nyhavn, Fridtjof (ResMan AS)
This paper describes the interventionless approach that was successfully executed during the Pyrenees early production phase to identify the timing and location of water breakthrough. Chemical inflow tracers were installed in key production wells within the lower completion along the horizontal production sections. Results from this work have supported the reservoir simulation history matching process and confirmed the performance of the inflow control devices (ICDs). These data in conjunction with the real time rate information from subsea multiphase meters has allowed proactive reservoir and production management that has contributed to the early identification of additional infill opportunities.
The design team for the Wheatstone offshore platform successfully deployed an ‘Inherently Safe Design' (ISD) approach to engineering the gas processing complex. Through a program of initiatives focused on ISD, a substantial improvement in the safe design of the platform has been delivered.
Major accident events:
The Texas City incident in 2005 initiated the most detailed and far reaching investigation ever undertaken by the US Chemical Safety and Hazard Investigation Board (CSB) at the time. The CSB report included a recommendation that BP form an independent panel to conduct a review of the company's corporate safety culture, safety management systems, and corporate safety oversight at its U.S. refineries. This independent review was conducted and a separate report known as the Baker Report was developed, with the key conclusion being that the process safety culture was deficient.
Major incidents such as the Macondo and Montarra well blow-outs still occur. NOPSA newsletter Issue 86, February 2010 presented data on gas releases, a recognised precursor to major accident events and showed "Design problems at root of most major gas releases??.
The paper will consider the implementation of the
safety case in the oil and gas industry internationally post -Macondo and Montara.
The National Commission Report into the Deepwater Horizon / Macondo blowout stated:
"The immediate causes of the Macondo well blowout … …. that reveal such systematic failures in risk management that they place in doubt the safety culture of the entire industry. "
In their letter to Minister Ferguson on 22 March 2011, the NOPSA Board stated:
"The Montara and Macondo incidents each demonstrate technical ignorance and a poor safety culture including complacency regarding low probability, high consequence risks. There is a clear need to improve industry safety culture, accountability and leadership."
The paper will examine these criticisms and consider how the industry
needs to improve its process safety and risk management. The implementation of a safety case in the USA may only occur "in the typical rule-making process that takes up to two years" (Michael Bromwich, Director of BOEMRE). Knowledge, understanding and application of key aspects of process safety management and the safety case process are not uniform. The paper will suggest how, in this context, the safety case can be applied to achieve the required outcomes.
The paper will draw from specific findings from the Macondo and Montara incidents.
There are echoes of Piper Alpha in the performance of emergency systems on Deepwater Horizon. The inadequate application of hazardous area classification is a key issue which the paper will examine in order to provide greater understanding. Whilst in Australia, issues of consistency and quality arise with matters such as performance standards. The paper will discuss the need for a standard for "performance standards" that goes beyond current regulatory guidelines.
Overall, the paper will seek to propose a way forward for the industry in several practical areas.
Conference review - No abstract available.
Li, Zhigang (Offshore Oil Engineering Co. Ltd.) | He, Ning (Offshore Oil Engineering Co. Ltd.) | Duan, Menglan (Offshore Oil/Gas Research Center, China University of Petroleum) | Wang, Yingying (Offshore Oil/Gas Research Center, China University of Petroleum) | Dong, Yanhui (Offshore Oil/Gas Research Center, China University of Petroleum)
Wang, Alan (Installation Division, Offshore Oil Engineering Co., Ltd.) | Yang, Yun (Installation Division, Offshore Oil Engineering Co., Ltd.) | Zhu, Shaohua (Installation Division, Offshore Oil Engineering Co., Ltd.) | Li, Huailiang (Installation Division, Offshore Oil Engineering Co., Ltd.) | Xu, Jingkuo (Installation Division, Offshore Oil Engineering Co., Ltd.) | He, Min (Installation Division, Offshore Oil Engineering Co., Ltd.)