The Stybarrow Field is a moderately sized biodegraded 22° API oil accumulation reservoired in Early Cretaceous sandstones of the Macedon Formation in the Exmouth Sub-Basin, offshore Western Australia. The reservoir is comprised of excellent quality, poorly consolidated turbidite sandstones up to 20m thick. The field lies in approximately 800m of water and has been developed with five near-horizontal producers and three water injection wells. The Stybarrow development came online at an initial rate of 80,000BOPD in November 2007.
Due to the lack of significant aquifer support, water injection was planned from start-up for pressure maintenance. Acquisition of a variety of data types have enabled key subsurface challenges to be addressed both before and during production. Structural and stratigraphic complexities influence connectivity and therefore must be fully evaluated in order to achieve optimal sweep. A feasibility study concluded that Stybarrow would be a good candidate for 4D seismic monitoring. Two monitor surveys were acquired and, along with other reservoir surveillance techniques, have been used to refine the geological model.
The first monitor survey at Stybarrow was recorded in November 2008. The results of this survey were in agreement with prior 4D modelling and supported the drilling of a successful development well in the north of the field. A second monitor survey was recorded in May 2011, three and a half years after first oil and at 70% of expected ultimate recovery. This survey is currently being analysed to determine if sweep patterns have changed.
The 4D surveys have proven to be an important tool for understanding subsurface architecture and dynamic fluid-flow behaviour. The results of both 4D seismic surveys have provided significant contributions to understanding the dynamic behaviour within the reservoir to facilitate optimal reservoir management.
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.
Demand for natural gas is increasing more rapidly than anticipated in Far East markets because (1) China has modified its policies in order to increase reliance on gas, in part to mitigate the growth in its coal consumption (which now stand at almost half of world coal production), (2) Japan has announced its intention to eventually shutdown its nuclear power industry, and (3) India, which currently has more than 400 million people without electricity, desires to accelerate electrification. This analysis investigates the potential role of stranded gas from Central Asia, Russia, Southeast Asia, and Australia in meeting Asia's future demand for gas imports. It initially surveys the discovered or known gas in stranded gas accumulations in Central Asia, Russia, Australia, Indonesia, and Malaysia. It then examines the primary gas import markets of China, India, Japan, and South Korea by describing energy use, gas demand trends, and domestic gas supplies to establish boundaries that encompass the wide variation in gas import demands in these markets during the two decades following 2020.
Then the cost of developing and delivering gas through overland pipelines from selected stranded gas fields in Central Asia and Russia to China is examined. Analysis shows that for the Shanghai market in China, the costs of developing and delivering Russia's stranded gas from the petroleum provinces of eastern Siberia are competitive with costs estimated for stranded gas from Central Asia. However, for the Western Siberian Basin, delivered gas costs are at least 3 US dollars per thousand cubic feet (USD/Mcf) higher than delivered gas from Central Asia.
The extraction and transport costs to a liquefaction plant for gas from stranded gas fields located in Australia, Indonesia, Malaysia, and the basins of eastern Siberia are then evaluated. The resource cost functions presented show development and extraction costs as a function of the volume of stranded gas developed for each country. The analysis demonstrates that, although the Russian fields in areas of eastern Siberia are large with relatively low extraction costs, distances to a potential liquefaction plant at Vladivostok make them initially the high cost suppliers of the liquefied natural gas (LNG) market. For the LNG markets examined, Australia and Malaysia are initially the lowest cost suppliers. For the Shanghai market, a comparison of the cost of supplying gas by pipeline with the cost of supplying LNG shows that the pipeline costs from areas of eastern Siberia and Central Asia are generally lower than delivered cost of gas as LNG from the LNG supply sources considered.
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.
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)
Jia, Hu (Southwest Petroleum University) | Yuan, Cheng-dong (Southwest Petroleum University) | Zhang, Yuchuan (Southwest Petroleum University) | Peng, Huan (Southwest Petroleum University) | Zhong, Dong (Southwest Petroleum University) | Zhao, Jinzhou (Southwest Petroleum University)
High-Pressure Air Injection (HPAI) in light oil reservoirs has been proven to be a valuable IOR (Improved Oil Recovery) process and caused more attention worldwide. In this paper, we give an overview of the recent progress of HPAI technique, based on a review of some representative HPAI projects including completed and ongoing projects. Some most important aspects for HPAI field application are discussed in depth, including reservoir screening criterion, recognition of recovery mechanism, laboratory study, numerical simulation, gas breakthrough control, tubing corrosion consideration and safety monitoring. With the successful HPAI application in Zhong Yuan Oil Field in China, it is estimated that foam or polymer gel assisted air injection should continue to grow in the next decade as a derived technology of HPAI for application in high-temperature high-heterogeneity reservoirs. The purpose of this paper is to investigate the ranges of some key parameters, new understanding based on laboratory test and successful field application, thus to provide lessons learnt and best practices for the guideline to achieve high-performance HPAI project.
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.
This paper presents an overview of wet gas multiphase metering and a new meterdesign to meet future offshore challenges. The design introduces new microwaveelectronics, transmission as well as resonance measurements, a salinitymeasurement system, reduced PVT dependence and a new HP/HT design.
Building on the success of wet gas metering in accuracy and reliability, thenew meter increases operators' ability to detect the onset of formation waterproduction and accurately measure flow rates where an increasing amount ofliquid and water is present in the flow (due to gas wells produced over a widerrange of process conditions).
The new meter design will have an increased importance for subsea tiebacksapplications. While today's wet gas meters are well suited for subsea tiebacks,current subsea developments require longer horizontal production pipelines,where accurate and sensitive measurement of water is crucial to ensure flowassurance and maintain maximum production capacity of the pipeline.
Furthermore, the restrictive and remote nature of subsea fields means that thecosts for subsea interventions and periodic fluid sampling (PVT) are high. Thenew meter is more robust to changes in PVT (fluid composition) and reduces theneed for frequent fluid sampling.
The paper will describe the development and technology choices of the newinstrument and how it will meet future subsea field demands.
It will explain how the new microwave electronics provides more stable andaccurate measurements; how transmission and resonance measurements extend theoperating range to 80-100% GVF and 0-100% WLR; how two complementarytechnologies - a salinity probe for liquid film measurements at low GVF andFormation Water Detection Function software for droplets measurements at highGVF, provide the first complete salinity measurement system in wet gasapplications.
The paper will also show how multivariate analysis and new measurements enablethe meter to compensate automatically for changes in produced fluidcomposition.
The paper will be highly significant to oil and gas operators looking toincrease flow assurance and oil & gas production from wet gas fields andmeet the growing offshore challenges of varying process conditions,intervention costs, and subsea tie-backs.