Dana has been a non-operated partner in the Bittern field since 2010, holding a 4.73% stake in the field until the acquisition of Hess’ 28.3% share in February this year. As one of the majority stakeholders in Bittern, Dana noted interest in taking over operatorship of the Triton FPSO and officially became operator on Monday 1 October 2012.
The Triton FPSO is located in block 21/30 approximately 120 miles east of Aberdeen, and produces oil and gas from the Bittern, Clapham, Pict, Saxon, Guillemot West and North West fields.
Triton is our first major operated asset in the UK, it consolidates our strong position in the Central North Sea and is a core part of our strategy to acquire more operated positions where there is a strong commercial and operational rationale to do so.
The synergies realised from Dana’s operatorship of both the Greater Guillemot Area subsea facilities and the Triton FPSO will help maximise value from our interests in the area.
In addition to the direct operational benefits associated with operatorship of Triton, it will also give us valuable operational experience of FPSOs as we look forward to our $1.5bn Western Isles Development Project in the Northern North Sea, which involves the construction of a new-build circular FPSO, with first oil expected in 2015 at c.40,000 boepd.
Joint venture partners in the Triton FPSO area are: Dana (52%), Tailwind (46%) and Endeavour (2%).
- Triton FPSO producing oil and gas from the Bittern, Guillemot West & North West fields Clapham and Pict and Saxon fields
- Location UK Central North Sea, Block 21/30, approximately 193km (120 miles) east of Aberdeen
- Integrated teams are led as follows:
- FPSO – Dana (duty holder)
- Bittern – Dana (operator)
- Guillemot W & NW – Dana Petroleum
- Clapham, Pict and Saxon fields developed as subsea tie-backs to the Triton FPSO by operator Dana Petroleum
- Fields tied back to FPSO via subsea facilities comprising a series of pipelines and manifolds:
- Bittern 20kms from FPSO
- Guillemot West 12kms from FPSO
- Export Oil via shuttle tanker
- Gas via Fulmar gas line to St Fergus
- Drilling carried out by mobile drilling units over the respective fields.
- Dana Petroleum
- Endeavour Energy
- Tailwind Energy
Infrastructure Code of Practice
To ensure that new and smaller players in the UKCS can develop and bring onstream discoveries which require third party infrastructure, the industry developed a Code of Practice for third party access to infrastructure, known as ICoP. Adopted in 2004, the ICoP outlines the best practice and expected behaviour of those who conduct negotiations for the access to infrastructure. Guidance notes introduced in 2009 help companies to implement the ICoP principles. In 2012 the ICOP was revised and updated following a review of the documentation by the PILOT Infrastructure Access Group (IAG).
The purpose of ICoP is to facilitate the utilisation of infrastructure for the development of remaining UKCS reserves through timely agreements for access on fair and reasonable terms, where risks taken are reflected by rewards. By their endorsement of the ICoP, parties make a commitment to be guided by its principles and procedures.
The ICoP is relevant to all companies currently doing or prospectively seeking business in the UKCS. It calls on all UKCS licensees, infrastructure owners, operators and prospective users to adhere to its principles.
- Parties uphold infrastructure safety and integrity and protect the environment
- Parties follow the Commercial Code of Practice (CCoP)
- Parties provide meaningful information to each other prior to and during commercial negotiations
- Parties support negotiated access in a timely manner
- Parties undertake to ultimately settle disputes through the Automatic Referral Notice (ARN) process which involved the Secretary of State
- Parties resolve conflicts of interest
- Infrastructure owners provide transparent and non-discriminatory access
- Infrastructure owners provide tariffs and terms for unbundled services, where requested and practicable
- Parties seek to agree fair and reasonable tariffs and terms, where risks taken are reflected by rewards
- Parties publish key, agreed commercial provisions
Water Depth 90m
Installed Mar 2000
Total Processing Capacity:
- Oil ('000 b/d) 105
- Gas (mmcfd) 140
- Water ('000 b/d) 130
Total Injection Capacity:
- Water ('000 b/d) 155
- Storage (‘000bbl) 630
- Accommodation 80 POB
- Topsides (t) 7000
- DWT 105000
- Risers 11
- Length (m) 244
The following specifications apply to all users of the Triton FPSO and to all produced fluids which are within the relevant design specification parameters of the joint facilities and which can be processed by the Triton FPSO facilities such that:
- any resulting gas meets the re-delivery specification for gas;
- any resulting dry oil can be delivered to the dry oil redelivery point and does not adversely affect the value of existing dry oil production; and
- it does not adversely affect the Triton FPSO facilities capacity.
The relevant design specification parameters of the Joint Facilities are:
Flow-rates and Metering:
This is dependent upon the capacity of the plant and the spare risers, and the gas to oil ratio (GOR) of the field production streams. Slugging into the joint facilities is to be minimised and no liquid slug is to exceed 15 cubic metres for the Bittern Field Flowline System and 10 cubic metres for the Guillemot West Flowline System.
The maximum separator off-gas molecular weight should be in the order of 22 to 25.
Maximum FPSO arrival temperature is 50° Celsius. Minimum normal arrival temperature is 30° Celsius.
The minimum delivery pressure is 20 barg at the riser top. Maximum shut-in pressure to be advised and the sub-sea system is to be designed for this pressure. Joint facilities are designed for 179 barg. In-field pipeline settle-out pressure to be advised to the Triton Operator.
Petroleum produced from any field shall not contain emulsions which cannot be destabilised by heating to 70° Celsius and the application of electrostatic coalescence. Any chemical demulsifiers required must be compatible with those already in use.
Produced water from the fields is not to contain levels of Strontium or Barium ions which may cause precipitation of scales if commingled with sea water or other formation water present. The total dissolved solids is not to exceed 75,000 milligrams per litre.
The absolute viscosity of the stabilised crude, is not to exceed 3.5 centipoise at 40° Celsius or 2.5 centipoise at 50° Celsius. Any non-Newtonian behaviour is to be notified to the Triton Operator.
Wax Content and Appearance point:
The wax appearance point temperature is not to be greater than 35° Celsius. The wax content and the nature of its precipitation are to be notified to the Triton Operator. The Field Operator shall advise the Triton Operator of the need and operating policy for avoiding wax build-up in the sub-sea system.
The gravity of the stabilised crude oil shall be in the order of 28° to 40° API.
The solid content of the field production stream is not to exceed 6 lbs per thousand barrels.
Petroleum must exhibit a low foaming tendency when processed alone and when mixed with existing field production streams in the joint facilities.
Asphaltenes are not to precipitate in processing equipment or storage tanks when processed alone, or when mixed with existing field production streams in the joint facilities.
Petroleum salt content shall not exceed 25lbs per thousand barrels at a BS&W of 0.1%.
Field petroleum shall not contain more than 3.0 ppm volume of hydrogen sulphide at first stage separator conditions.
Field petroleum shall contain no detectable mercaptans at first stage separator conditions.
Field petroleum shall contain no detectable carbon disulphide at first stage separator conditions.
Field petroleum shall not contain more than 13.5 ppm volume total sulphur measured as hydrogen sulphide at first stage separator conditions.
Field petroleum shall not contain more than 2. 7 mole % of carbon dioxide at first stage separator conditions.
Aggregate total of non-hydrocarbon content of first stage separator gas shall not exceed 5.0-mole%.
Field petroleum shall not contain more than 0.01 micrograms of mercury per m3 of gas at first stage separator conditions.
Triton third party potential capacity
The processing facilities on the Triton FPSO have limited potential future processing capacity. In particular total liquids (oil plus water) is a bottleneck as well as produced water treatment. The schedule below indicates the expected availability based upon the traffic light system suggested under ICOP (Industry Code of Practise).
|Dry oil capacity|
5% to 25%
Parties interested in accessing this capacity on the Triton FPSO should in the first place contact the Triton operator, stating their interest. The Triton operator will then invite the field operators to advise and respond regarding their expected available capacities and ability to offer third party services.