The Ichthys LNG Project
INPEX has begun construction of one of the world's largest oil and gas projects following the Final Investment Decision (FID) on the US $34 Billion Ichthys LNG Project in Australia on 13 January 2012. The Ichthys LNG Project is a joint venture between INPEX (Operator) and Total with Tokyo Gas, Osaka Gas, Chubu Electric and Toho Gas.
The Ichthys Field is situated in the Timor Sea approximately 200 kilometers off the Western Australian coast and over 800 kilometers from Darwin. Three exploratory wells drilled in 2000 and 2001 resulted in the discovery of an extremely promising gas and condensate field with resource estimates from two reservoirs totaling approximately 12TCF of gas and 500 million barrels of condensate. Conceptual studies, FEED and ITT followed and development leading to sanctioning of the Ichthys LNG Project by INPEX and Total.
Gas from the Ichthys Gas-Condensate Field in the Browse Basin will undergo preliminary processing offshore to remove water and extract condensate. The gas will then be exported to onshore processing facilities in Darwin via an 889 kilometer subsea Gas Export Pipeline (GEP). Most condensate will be sent to a Floating Production Storage and Offloading (FPSO) vessel for stabilization and storage prior to being shipped to global markets. The Ichthys LNG Project is expected to produce 8.4 million tons of LNG and 1.6 million tons of LPG per annum, along with approximately 100,000 barrels of condensate per day at peak.
Production from 20 subsea wells in the first phase - 50 will be drilled in total - will be sent to the Central Processing Facility via 8?? rigid lines connected to flexible risers. The flexibles will be supported by a 110 meter high jacket type riser support structure. You see, no aspect of the Ichthys LNG Project is small.
Effluents will be separated on the Central Processing Facility (CPF), a semi-submersible floater. Gas will be dried and compressed prior to being sent ashore via a GEP. Compression will be from four compressors, designed for 590.7 MMSCFD. Following initial treatment, most liquids will be transferred from the CPF to the nearby FPSO for processing and storage. The 330 meter-long FPSO will be a weather-vaning ship-shaped vessel that is permanently moored on a non-disconnectable turret. It has been designed with a storage capacity of nearly 1.2 million barrels. Loading of two offtake tankers in tandem will be possible from the FPSO.
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.
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)
All oil and gas wells inevitably shifts from asset to liability, whether the result of reaching its economic limit or sustaining irreparable damage. At the end of its life cycle, a subsea well and its supporting infrastructure must be carefully dismantled to
ensure they pose no safety or environmental threats and to salvage useable components. In addition to creating significant safety and environmental hazards, failure to properly abandon a subsea well can lead to a noncompliant status with regulatory
agencies and undermine an operator's image. Despite its multiple liabilities, abandonment offers no real return on investment, underscoring the importance of minimizing cost. The challenge is to retrieve the wellhead without damage so it can be used again, minimizing or eliminating damage not only to the wellhead but also to personnel and environment.
This paper will describe the technological tool system available to retrieve subsea wellheads in a single trip. This technology serves as an alternative to equipment that poses environmental and safety hazards, such as mobile offshore drilling units and explosive severance devices. By latching on to the external profile there is no damage to the internal seals. Also the external latch procedure allows more clearance to allow the cuttings to flow out of the ports and away from the working mechanism. The wellheads retrieved have a much greater chance of being re-used with minimal damage. The external latch design allow for more strength and less chance of tool failure. This paper will also discuss some global case histories.
This paper summarises original development work implemented by Ocean Resourceinto a new type of Unmanned Production Buoy facility, the Sea Producer. Thiswork, which is both comprehensive and wide-ranging, covers the use ofautonomous buoy technology to develop various offshore oil and gas productionscenarios which would otherwise be uneconomic or indeed impossible. Recentlythis technology has received considerable interest as it represents, for somesmaller developments, possibly the only sensible and economic way forward. Thedesign concept is flexible and has applications well beyond simple production.Ocean is carrying out on-going development work into the use of the concept forcarbon sequestration allied to enhanced oil recovery. This novel developmentwill provide an initiating technology for offshore carbon sequestration againat hitherto highly economic costs. The detail of this is, however, beyond thescope of this paper.
Ocean Resource has developed and pioneered the concept of remote offshore oilor gas production from an unmanned production buoy over a period of 20 yearsand is the only company with specific experience and expertise in this complexarea. Ocean has designed, built, operated and maintained its own high stabilitybuoy systems and has completed a number of buoy designs for working buoysystems in use with Apache, Mossgas Pty, Exxon-Mobil and others for oil relatedoperations. More recently Ocean Resource has been responsible for the design ofa 5MW Power Buoy for CNR International UK Ltd (Canadian Natural Resources).Unfortunately Monitor Oil PLC, the principle constructor, went into liquidationprior to completion of the project but it is envisaged that this unit, which is95% complete will shortly be redeployed on another field. The Power Buoylocated at Dundee is subject to an option agreement for this purpose.
Ocean Resource's low cost autonomous buoy systems represent a game-changingtechnology that will enable the economic development of hitherto unexploitableor stranded oil and gas reserves. The technology is generally branded as SeaCommander where it relates to field control buoys (a developed product) and SeaProducer where it relates to production.
Sea Producer enables a step-change in offshore development expenditure loweringcapital costs at the start of project together with greatly reduced operationalcosts leading to low "through-life" costs for standalone, step-out developmentsor early production scenarios. Furthermore the relatively minimal nature of theoffshore facilities comprising the buoy and storage system leads to rapiddeployment and hence faster income and profit return to any offshoreproject.
The unique autonomous buoy technology has been developed by Ocean Resource overa period of 20 years and is an evolution of existing systems first deploed inthe 1980's. It is therefore both mature and proven. It can be used for sub-seaoil and gas field control, remote pigging, multi-phase pumping, chemicalinjection, subsea production support and remote flaring.