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 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.
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??.
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)
The Spar platform has developed into a well functioning solution for Gulf ofMexico environment. Considering use of this solution in the North Atlantic, themetocean conditions differ by long period swell and fatigue induced by normaloperational seas.
In order to meet these challenges, it is desirable to consider a classic Sparthat is more fatigue redundant than a truss, but the swell requires highnatural periods, to avoid parametric heave-pitch resonance.
A new version of the Spar in response to these requirements is the Belly Spar.It can be considered as a classic Spar with a Belly; starting below the wavesurface and extending down to the hard tank depth. A concrete Spar concept withreduced waterline diameter has also been developed by Aker Solutions for arcticapplication. This concept had the dual benefit of increasing the natural periodin heave as well as reducing the ice load from sea ice
The concept has been developed for a field in the Norwegian Sea, in water depthof 1,200m (4,000ft). The hydrodynamic analyses show excellent performance,however contain assumptions on damping. The design has been by model testing ofthe design in wave and current combination representing 10,000yr events, asshown by results and correlations in the paper.
The design opens up new areas for the Spar platform, with good motions that canaccommodate steel catenary and top tensioned risers. As for previous Sparconcepts, the application is in deepwater and ultradeepwater.
New oil and gas frontiers are presently looking at projects offshore of theGulf of Mexico and South Atlantic, including West African and Brazilian watersand soon after Asia Pacific. New technologies are required to performinstallation in a cost efficient and safe method; they must encompass the stateof art equipment in order to provide effective solutions. The new ships FDS2and CastorONE are Saipem's replies to the forthcoming challenges indeep/ultra-deep water field development and pipe lying. The new vessels willoperate by using new welding, NDT and field joint coating technologies,including innovative installation equipment able to generate added value forthe implemented solutions. Field development projects include complex risersystems and the new fleet is designed to offer reliable solutions for thefuture configurations, which are designed to route the oil and gas fluids tothe floating treatment units. Saipem FDS2 is described by indicating hercapabilities and her equipment, including those required for project in shallowwater and those specifically designed for deep waters installation.Furthermore, sea keeping and naval features are offered in order to demonstrateher versatility and ability to solve main installation challenges relevant tothe deep water fields. Trunk line projects will be addressed to transportationof large gas volumes over long distances across harsh environments and Saipemvessel CastorONE is presented by showing off her capabilities for the ultradeep water installation. Information on the new state of art rigid stinger isprovided together with some conceptual solutions designed to increase theefficiency of the working stations and of the method to transfer the pipes withspecific equipment. The paper concentrates on the installation requirements forthe in-field production gathering systems and on the oil and gas exportpipelines.
Field development: the leading market trends
Since 1998, numerous deep water field development projects, mainly in the SouthAtlantic region both in West Africa and in Brazil were carried outsuccessfully. The vision for the future leads towards two major trends: evendeeper waters and new surprising geographical regions. Moving in bothdirections, thanks to its top class technologies and assets, Saipem aim to leadthe path towards the even tougher future challenges.
The scope of the work of deep water projects, within EPCI type contracts, hasnormally included all major and minor technical aspect, supplies andinstallation/operations from A to Z, with contract values typically in therange of half to one billion USD. Key of this market segment - which nowrepresents a significant portion of turnover and backlog - has been theintegrated development of original technical solutions and dedicatedfit-for-purpose installation vessels.
Leveraging on its notable competence, track record and offshore constructionfleet, the two main lines of evolution for the offshore field developmentmarket were, are and will be tackled, namely ultra-deep waters and new frontierregions as follows:
• On one hand, the ultra-deep water developments, emerging in the traditionaloil provinces in the Gulf of Mexico and South Atlantic, will require theIndustry to make available new technologies and equipment to support the safeand effective implementation of the relevant production schemes;
• Simultaneously, the development of subsea oil and gas fields is taking placein new world regions bringing quite new challenges from both the technical andexecution standpoints.
Exploitation of oil and gas reservoirs in water depths in excess of 2,000m (?6600') is progressively emerging as the new market. Gulf of Mexico, offshoreBrazil and West of Africa are nowadays showing the greatest concentration offield development projects. In addition, subsea developments in new areas suchas East India, Indonesia, Offshore China and Western Australia are appearing inthe offshore oil and gas theatre both for relatively moderate and for deeperwater depths.
Perdido Regional Development in the Western Gulf of Mexico and the Walker Ridgearea in the Central Gulf of Mexico will be significant and challenging offshoreprojects.