Overcoming The Loss of a Primary Barrier in an HPHT well - Investigation and Solution
- Alan T. Humphreys (Total) | Robert Chapman Ross (Baker Oil Tools)
- Document ID
- Society of Petroleum Engineers
- SPE/IADC Drilling Conference, 20-22 February, Amsterdam, The Netherlands
- Publication Date
- Document Type
- Conference Paper
- 2007. SPE/IADC Drilling Conference
- 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 1.6 Drilling Operations, 5.6.4 Drillstem/Well Testing, 4.2.5 Offshore Pipelines, 4.1.2 Separation and Treating, 1.14 Casing and Cementing, 4.6 Natural Gas, 5.2.1 Phase Behavior and PVT Measurements, 4.1.5 Processing Equipment, 4.5.7 Controls and Umbilicals, 4.5 Offshore Facilities and Subsea Systems, 3 Production and Well Operations, 2 Well Completion, 4.2 Pipelines, Flowlines and Risers, 5.2 Reservoir Fluid Dynamics
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The failure of a primary barrier on a completed HPHT well in the West Franklin field in the UKCS in 2005 resulted in a significant pressure increase in the production annulus requiring a complex well kill operation to resolve. Following this incident an investigation programme was undertaken to determine the root cause of the failure and, thereafter, to develop a solution. The failure investigation looked at all aspects of the well design and operations and found no clear cause. A ‘failure test' was then carried out which recreated the exact downhole conditions on surface. This test demonstrated that very small irregularities in the internal casing profile would cause packer to casing seal failure under severe bottom hole conditions. A programme was then undertaken to develop a packer seal system, suited to the severe well environment, that could withstand a specified degree of casing irregularity. A rigourous qualification programme was also developed to verify the new systems capability in irregular casing.
The programe was completely successful and new packer seal systems have been qualified to these enhanced standards and deployed in the field.
Elgin/Franklin and the West Franklin Field
The Elgin and Franklin fields were discovered in 1991 and 1986 respectively. The joint field development was sanctioned in 1996 and first gas exported in March 2001. The fields lie approximately 140 miles North East of Aberdeen in the Central Graben region of the North Sea (Fig 1) and to date they represent the biggest high pressure / high temperature (HP/HT) development in the world.
The Elgin-Franklin complex comprises two wellhead platforms (WHP) directly over each of the Elgin and Franklin reservoirs, linked to the Elgin Process, Utilities & Quarters (PUQ) by a bridge and by a subsea pipeline bundle and umbilical, respectively. Drilling and completion of the wells has been carried out by heavy duty jack-ups (HDJU) in cantilever mode over the wellhead jackets.(fig 2)
The West Franklin field lies approx. 1.5km from Franklin and was discovered in 2003 by the exploration well 29/5b-F7z, which was drilled as a deviated well from the Franklin WHP. The field is an HP/HT sour gas condensate accumulation which will be produced via the existing Elgin PUQ.
The primary reservoir is the Fulmar Sands located at an approximate depth of 5800m (19000ft) TVDSS. Reservoir fluids within the Fulmar are gas condensate with a bottom hole pressure of 1150 bar (16700psi) and static temperature of 196°C (385°F). Shut-in wellhead pressures are 905bar (13100psi). Flowing temperatures of up to 217°C (423°F) have been measured in the tubing due to the Reverse Joule-Thomson heating of the gas condensate.
Franklin well F7z was spudded in September 2002 by HDJU over the Franklin platform. Following the drilling phase, in May 2003, the well was completed with an HPHT completion string. The string design was standard to the Elgin/Franklin fields (ref 1), as shown in fig 3. Due to problems experienced on the well with the initial completion and subsequently with a failed casing hanger, a workover was undertaken and new completion string was run, set and tested successfully. The well was production tested and then suspended awaiting availability of ullage in the production system. The HDJU was demobilised in October 2004.
Whilst shut-in all the well annuli were monitored. Pressures were normal and stable until March 2005 when the production annulus increased to 630bar (9130psi). It was concluded that a failure of the completion had occurred.
A task force was mobilised and a well kill was undertaken during March-May 2005, using a stimulation vessel along with jacket mounted intervention systems. This was a complex and challenging operation on the not-normally manned installation but was successfully completed without incident or injury. During these operations, an investigation, using PLT data and pressure tests, concluded that the production packer had failed. Following the well kill and intervention programme the well was left in a suspended state awaiting a full investigation of the failure cause and thereafter a strategy to allow recompletion.
This paper details the results of this investigation.
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