This paper describes the selection, design, successful application and performance monitoring of Electrical Submersible pumps in the giant Mangala oil field and Thumbli water field situated in the Barmer basin in Rajasthan, India. Mangala oil field contains approximately 1.3 billion barrels of STOIIP in high-quality fluvial reservoirs. The field was brought on production in August 2009 and is currently producing at the plateau production rate of 150,000 bopd of which approximately 40% of the oil production is from the ESP oil wells.
To support the water requirement of Mangala and other satellite oil fields, Thumbli source water field was developed with 5 water production wells with up to 4 wells operating at a time. Each of these water wells is installed with 60,000 bwpd capacity pumps and the field is currently producing up to 225,000 bwpd to meet the water requirements of Mangala and other satellite fields.
The Mangala oil field is a multilayer, multi-Darcy reservoir, has waxy viscous crude with in-situ oil viscosity up to 22 cp and wax content in the range of 18 to 26%. The field was developed using hot water flood for pressure maintenance. Significant production challenges included unfavorable mobility ratio with early water cut and hence the early requirement of artificial lift to maintain the plateau production rate. The field has 12 horizontal producers and 100 deviated producers. ESP was selected as the artificial lift mode for the high rate horizontal producers while hot water jet pumping was selected as the artificial lift mode for low rate deviated oil wells. Each horizontal well is capable of producing up to 15,000 blpd and high rate ESPs were designed and installed to deliver the production requirement. Currently 8 of the 11 horizontal producers are on ESP lift and the remaining three wells are planned for ESP installation in the near future. Apart from two early ESP failures during installation, ESPs have had a good run life; the paper also describes lessons learnt from the infant mortalities.
The Thumbli water field, located ~20 km southeast of Mangala field has been developed to meet the water requirement of Mangala and other satellite fields. Thumbli water aquifer is a shallow water field which contains water of ~ 5000 ppm salinity with dissolved CO2, oxygen, chlorides and SRB. 5 high capacity water wells were drilled in Thumbli field to meet the huge water demand from Mangala for water injection in Mangala and satellite field injector wells, hot water circulation in oil production wells and associated water requirement for boilers etc. 1000 HP water well ESPs were designed to produce up to 60,000 bwpd from each well with installed water production capacity of up to 300,000 bwpd from Thumbli field.
Mosher, Charles C. (ConocoPhillips) | Keskula, Erik (ConocoPhillips) | Kaplan, Sam T. (ConocoPhillips) | Keys, Robert G. (ConocoPhillips) | Li, Chengbo (ConocoPhillips) | Ata, Elias Z. (ConocoPhillips) | Morley, Larry C. (ConocoPhillips) | Brewer, Joel D. (ConocoPhillips) | Janiszewski, Frank D. (ConocoPhillips) | Eick, Peter M. (ConocoPhillips) | Olson, Robert A. (ConocoPhillips) | Sood, Sanjay (ConocoPhillips)
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.
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)