WELL SERVICING Minimal intervention on HP/HT wells

Elf aiming to reduce intervention needs on Central Graben development

Negative trends in Britain's gas production sector have stopped Elf from rushing through the central North Sea Elgin and Franklin developments.

Findings suggest that the quality and quantity of these gas condensate reservoirs in blocks 29/5b and 22/30c is good enough to warrant a standalone development, with first production possible in 2000. Elf's main concern now is that its preferred gas export system, the proposed Interconnector pipeline to Zeebrugge, hurdles current challenges to siting of the onshore compressor station near Bacton.

Elf felt confident enough to outline its current thinking on drilling, completion and workover requirements for the Elgin/Franklin wells. The aim is to keep intervention to a minimum, not the easiest of tasks considering that both are deep, hot, high pressure and sour fields in the Central Graben area.

Franklin and Elgin were discovered in 1986 and 1989, with appraisal well programs completed respectively in 1991 and 1995. Temperatures vary from 189degC at 5,364 metres TVD, where the Upper Jurassic `Franklin' sands come in, to over 200C at the base of the Middle Jurassic Pentland sands which appear 240 metres further down. At 5,364 metres pressures are 1,091bar for Franklin and 1,111bar for Elgin. And during well tests, H2S has been detected at stabilised levels of 20-30 ppm, occasionally rising to 80 ppm.

Ingress of sands over time at various points, with consequent subsidence, has affected reservoir quality, creating problems for the well designers. The extent to which permeability is a function of pressure as regards sandface productivity is not clear. Production of hydrocarbons, therefore, may cause a reservoir collapse, leading to compaction that in turn could lower permeability and, in turn, production.

Proposed field layout

Elf's design team has opted for a central processing complex at Elgin bridge-linked to a wellhead platform, with a normally unmanned satellite wellhead platform at Franklin tied back to the complex through multiphase flowlines. Template pre-drilling on Elgin could start this October, using one harsh environment jack-up; Franklin pre-drilling is unlikely before May 1998.

Elgin's drilling wellhead platform will have two wellbays, each with eight slots (to allow for simultaneous drilling by two jack-ups), whereas Franklin's remote platform will have 12 slots. The drilling wellheads will be disaligned relative to the xmas tree to facilitate valve plug removal.

The selected tree will be 4-1/6 15ksi. This will comprise surface safety master valves, one of which may have wireline cutting capability; shutdown valve; swab valve for vertical access; kill inlet; chemical injection (methanol, inhibitor). The drilling wellhead will be installed on 20-inch casing, providing hanging and sealing for 13 3/8, 10 3/4 and 7 5/8-inch casing and 5-inch tubing.

Equipment up to and including the choke on the central complex and satellite platforms will be designed to 15,000psi and 204C.

Well intervention

If possible, heavy workovers will be delayed until wellhead shut-in pressure (WHSIP) is below 10,000psi. Wireline conveyed perforating of long intervals is to be avoided, although under or over-balanced perforating with a tubing conveyed or coiled tubing perforator is permissible, within equipment performance constraints.

Slick line wireline intervention in wells with WHSIP above 10,000psi is limited to failure-related operations: should wellhead pressure reduction be necessary, this will be done by squeezing methanol or gas oil in the tubing. Other Elgin/Franklin guidelines include:

No deep wireline operation to be conducted in heavy mud
Coiled tubing operations limited to failure-related operations
Snubbing units with 15,000psi rating allowable for emergency workover operations during HP period.

The only planned well interventions are wireline runs for reservoir management purposes - when pressure allows, and if a permanent downhole gauge is not available.

Unplanned well intervention

Possible problems include first annulus pressure following failure of the completion system (tubing, hanger, packer or liner tie-back) requiring completion replacement. In this case a jack-up or tender-assisted rig will be used for the intervention.

TRSCSSV failure will necessitate lock-out and running a back-up wireline SCSSV. A wireline unit will be used, working under reduced wellhead pressure if needed. Should a control line leak to the annulus, a full workover will be required.

Sand production, following perforation failure, may not be stemmable merely through reducing drawdown (choking the well back). In this case, sand control will likely be performed using a rig suitable for tubing retrieval.

Production decline is possible due to scale/salt deposit, permeability reduction or perforations plugging. These may be addressed through intervention with a wireline, coiled tubing or snubbing unit.

A surface leak at xmas tress level would require change-out of the tree or work on the master valves. Safeguarding the well would necessitate use of a wireline unit. Finally, capping for a blowout would be achieved using a 13 5/8-inch or 11-inch 15,000psi capping BOP.

Reference:

Gibson, M, Hull, T., Seguineau, J., Coronel, M., "The Development Philosophy of Elgin/Franklin HPHT Wells," 9th Offshore Drilling Technology Conference, Aberdeen, November, 1995.