Summary
Well control can be an unpleasant experience. In its initial stages the
problem often appears unconquerable and weeks can pass without progress.
This paper is about the successful abandonment of such an episode of well
control, in deepwater (i.e. greater than 300 m water depth), that was initially
suspended with a closed-in subsea BOP. The BOP held in place a sheared 5-in.
drillpipe that had been intermittently blowing dry gas and formation cuttings
to the rig floor for 20 days.
The objective of the well-recovery operations was to re-enter the well and
properly abandon it without creating another uncontrolled situation. All
operations were to be conducted in compliance with HSE protocols.
It was paramount to have total control of the well at all times
necessitating two BOP stacks. This contingency resulted in the suspension of a
heavy load on the seabed, subject to excessive bending moments during bad
weather. The well head arrangement was essential but the time loss caused by
weather conditions was becoming intolerable. New and innovative plans made
during the well-control operations cut 3 to 4 weeks of uninterrupted operation
down to 5 days of operation. Cementing under pressure was the key abandoning
solution. Several scenarios were drawn up for this eventuality and this paper
elaborates on the decisions, choices, and solutions made during the final
abandonment operation.
Introduction
Pre-Intervention Status of Well. A blowout occurred on the exploration Well
A while drilling the 12 ¼-in. section, after having set the 13 3/8-in.
intermediate casing. The rig crew was safely evacuated. After the initial
blowout incident, the well flowed up the annulus for 4 days before the remotely
operated vehicle (ROV) activated closure of the lower pipe variable bore rams
(VBR) on the seabed (Fig. 1). Flow of dry gas and formation continued
intermittently up the drillstring for a period of 20 days until the ROV
activated the blind-shear ram (BSR). The well was left alone thereafter for
several months while a recovery plan was put in place. During this time the
seabed was monitored regularly and revealed gas leaking from the closed
BSR.
It was estimated that over 10,000 bbl of equivalent mass (solids) exited
from the drilled hole section during the blowout. Therefore, whether to expect
a large gas-filled void downhole or a collapsed wellbore owing to the
unconsolidation of the formation caused by the large amount of rock removal was
uncertain.
Because the status of the openhole section was unknown and gas was possibly
breaching out of the 13 3/8-in. casing shoe, simply bullheading kill-weight
fluid down the wellbore to control the well might not have been effective. Not
only would vast quantities of mud be required to fill the void, but removal of
such a large volume of gas would be an arduous and time-consuming operation
with no guarantee of success. The well-intervention philosophy was therefore
focused on achieving isolation within the 13 3/8-in. casing shoe. Kill-weight
mud would first be pumped into the formation to assess whether it could at
least control the wellhead pressures.
Well Intervention Objectives
The primary objective of the recovery phase was to isolate both drillpipe
and annulus from the blowout zone within the 13 3/8-in. casing, facilitating
long-term wellbore abandonment in a manner that posed no risk to personnel or
allowed further uncontrolled release of gas. The closed-in BOPs were also to be
recovered from the seabed. In the event that the intervention campaign was not
successful, the base case was to abandon the intervention operation and proceed
with drilling a relief well and intersecting the subject well for a well-kill
operation.
It was understood at the outset that an entry to a pressurized wellbore
would be attempted and as a result the first course of business was to
implement a dual-barrier policy wherever possible. Once well control at the
seabed was guaranteed, the well would be re-entered and the existing
"cut" pipe would be dressed off with a milling assembly, allowing a
tie-back string run to have full connection to surface. This wellbore
configuration would then allow pumping of fluids or carrying out activities
such as perforating the drillpipe at an optimum depth, isolating the drillpipe
with a bridge plug, and retrieving the pipe for cement abandonment. Fig. 2
illustrates the final configuration of the abandoned well. Coiled tubing (1
¾-in.) would also be used for cleaning out the drillpipe if it was found to be
plugged with debris at a depth shallower than the 13 3/8-in. casing shoe. It
was estimated that the well-abandonment operation would take approximately 5
weeks (ideal time) to complete.
© 2008. Society of Petroleum Engineers
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History
- Original manuscript received:
15 August 2006
- Meeting paper published:
16 October 2006
- Revised manuscript received:
19 November 2007
- Manuscript approved:
14 January 2008
- Version of record:
20 June 2008
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