ETAP partners make economic sense out of disparate reservoirs
Topside and subsea hardware and pipeline routes for the ETAP development. [14,985 bytes] The Mungo wellhead platform jacket at Kvaerner's Methil yard in Scotland. [18,871 bytes] Pipe welding on the Marnock central processing platform jacket at Barmac in Ardersier, Scotland. [32,911 bytes] British Petroleum dubs ETAP a "pseudo" field, as this central North Sea development combines seven distinct and widely dispersed reservoirs - one lying 35 km from the central processing platform - with
Degree of difficulty heightened by salt saturation and HP/HT fluids
- Topside and subsea hardware and pipeline routes for the ETAP development. [14,985 bytes]
- The Mungo wellhead platform jacket at Kvaerner's Methil yard in Scotland. [18,871 bytes]
- Pipe welding on the Marnock central processing platform jacket at Barmac in Ardersier, Scotland. [32,911 bytes]
British Petroleum dubs ETAP a "pseudo" field, as this central North Sea development combines seven distinct and widely dispersed reservoirs - one lying 35 km from the central processing platform - with differing ownership and operatorship.
Four fields - Marnock, Mungo, Monan and Machar - are operated by BP with the other three, Heron, Egret and Skua, run by Shell. During the current development phase, Shell/Esso will run ETAP as two separate field centers, but BP will assume operatorship when production begins in October 1998.
When the Eastern Area Trough Project (ETAP) was granted UK government approval in January 1996, then Energy Minister Tim Eggar commented that "it marks a new milestone in the development of oil and gas fields in the UK Continental Shelf". This was not simply because of the "unique level of collaboration among all the partners," but also because of the high level of innovation.
The individual reservoirs would not have been commercially viable as standalone developments. But total reserves are 400 million bbl of oil, 35 million bbl of natural gas liquids, and 1.1 tcf of sales gas. Dave Blackwood, BP's ETAP asset manager, says that the UKP1.6 billion project (UKP900 million for BP's fields, UKP300 million for drilling costs, and UKP400 million for Shell's facilities and drilling program) will apparently come in substantially under budget and would be below the benchmarks set by BP's recent Andrew project.
The partners share in the development costs but there will be no unitization as there is no communication between the various reservoirs. Peak production, estimated to last three years, is put at 180,000 b/d of oil and 350 MMcf/d of gas.
20-year historyIt has been a long haul since Machar was discovered in 1976. This was followed by other discoveries and various development plans were discussed and discarded. In 1992, BP and the eight partners in the various fields (since changed) signed a joint integration studies agreement to explore the practicality of an integrated development. This study established the feasibility of a development plan.
The concept is simple - one central pro cessing, drilling and riser platform (CPF) on Marnock bridge linked to a quarters and utilities platform with a normally unmanned platform on Mungo. Machar, Mungo, Heron, Skua and Egret will produce through subsea manifolds tied back to the central processing facility.
Investment has also been made on the CPF to handle future receipt of production from two other fields, Scoter and Mirren, in a few years when the first clusters come off plateau. Each will require three to four subsea wells tied back to the CPF.
Brendon Connolly, Shell's project manager, has said: "There are very few analogous developments worldwide and none has the cocktail of technical challenges found on ETAP".
For example, the three Heron cluster fields represent the first development by Shell Expro of fluids from reservoirs in the Triassic Skagerrak formation, some 4,500 meters below the seabed. All are high pressure/high temperature reservoirs.
Two 22-km, 10-in. flowlines will connect them to the CPF. Shell has opted to insulate them using a pipe-in-pipe system designed to operate at up to 160 degrees C and a shut-in pressure of 9,600 psi.
The fields are salt saturated. According to Connelly, if deposition/scaling remained uncontrolled, around 36 ton of salt would be produced daily. With every liter of produced water, there will be 420 grams of salt. "This," he says, "is a massive amount compared with the 80 g/liter typically found in fields".
BP, Shell and Esso have set up a task force to develop chemicals to cope with the situation. Salts will be kept in solution by injecting treated seawater, known as washwater, into the well through a novel injection valve mandrel.
All three Shell fields will have production wells only - no water injection is required, as the reservoirs are above normal pressure. Heron will have three wells with provision for one follow-up well, depending on reservoir performance. Egret will have one well with provision for an additional well, while Skua gets two horizontal wells with provision for two more.
Three of BP's reservoirs - Mungo, Monan and Machar - are associated with subsea salt diapirs. Machar, which is 35 km from the CPF and therefore be one of the longest subsea tiebacks in the North Sea, is a fractured chalk reservoir.
Predicting performance in chalk reservoirs is more difficult than with a typical sandstone reservoir. So BP adopted a phased approach to Machar. Phase 1, from June 1994 to May 1995, examined reservoir performance under natural depletion. Some 7.7 million bbl of oil was produced from two test wells.
Phase 2, from September 1995 to June 1996, consisted of a pilot scheme to test reservoir performance under water injection. Around 9 million bbl of water were injected and nearly 7 million bbl of oil produced. This established that Machar was viable with remaining reserves of 60 million bbl under natural depletion and 120 million bbl under a waterflood scheme, with peak production of 35,000 b/d.
A subsea pump will be installed along with a 12-in. water injection flowline through which injected water will be used to power the pump to return the produced fluid.
Alliance recordThe ETAP facilities alliance for BP is thought to be the largest such undertaken in the North Sea. Construction work started early in 1996 and the 7,200-ton jacket for the Marnock-based CPF (built by Barmac at Ardersier, Scotland), the jackets for the Mungo wellhead platform, and the Marnock utilities and quarters platform (Kvaerner's Methil yard) were installed by crane barge DB102 last month.
Topsides for the CPF (Amec) and the utilities platform (Kvaerner again) are 70% complete and will be installed next March. Infield pipelaying was completed this June and the pipelayer Castoro Sei began to lay the export oil line last month.
The ETAP Wells Alliance Agreement (EWAA) comprises BP, Schlumberger for well services and Neddrill and Santa Fe for drilling rigs. This, says BP, is a further development of alliancing because of the scale and complexity of the development, which consumes five rig years of mobile rig activity.
The agreement provides financial incentives for drilling and engineering of the wells through the establishment of risk/reward arrangements. EWAA combines all three allied services - well construction, well management and data acquisition - into a single alliance with a 50/50 risk/reward agreement, capped at 10% target cost overrun.
The scope of the program is:
- Marnock - six horizontal near HP/HT wells
- Mungo - 12 S-shaped wells and tieback of one pre-existing high angle well
- Monan - three high angle wells
- Machar - two new conventional wells and two re-completions.
The Noble Ton van Langeveld (ex-Neddrill 6) has drilled three Mungo wells and is currently drilling Monan's first well, after which it will move to Machar. The rig is on contract until the end of 1998. The Santa Fe Monarch has drilled three Marnock wells and will move to Mungo around year-end. It is expected to be on contract until 2000.
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