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Is it necessary to install a downhole safety valve in a subsea oil/gas well?
functioning DHSV. In these cases a wireline intervention may be carried out providing a
locked open DHSV awaiting abandonment or a scheduled workover. This option is also
applicable if the DHSV fails with a FTC or LCP. The lost production may in these cases be
reduced by this option. An early DHSV failure, when the production is in its prime, will cause
a more substantial economic loss.
Recent studies show that 50 % of the shut-ins of a well leading to a workover is caused by
DHSV failure [25]. With a DHSV failure rate of 5.84E-6 [13] this means that the DHSV
causes a well workover approximately every 19.6 well year. At the Åsgard field there are 52
wells. Every 2.7 years they have to carry out an intervention. On the field the total loss of
production, equipment and rental cost will amount to approximately 20 million dollars (see
subsection 4.1.1). In a well lifetime (15 years), this will represent a total value of 111 million
dollars for the operating company. These numbers have not taken in account that the well may
have been abandoned as a consequence of DHSV failure.
4.4 Workover related risk
The workover risk is represented mainly by the risk of delay and the risk of blowout. Other
things may also occur, like failures causing a need for abandonment of the well or extra repairs
due to equipment failures. The risk of injured personnel is as for the installation phase always
present. The operators must be precautious and the operating companies must provide a safe
working environment.
A workover is more likely to cause severe pollution than the other stages of the well. The well
is perforated and the production zone is “alive” nearly all the time. During workover the
operators usually use solid-free workover fluids. A mud filter cake, which during drilling acts
as a seal against the formation, will not be created. As a result continuous losses of formation
occur and may lead to a loss of the well. The casings may have deteriorated due to the stress
they have been affected by in the well.
All blowouts cause economic losses. Downtime of the well involves lost production. Millions
of dollars may be lost if damage to well equipment or workover rigs also occurs. With such
large amounts of money at stake the prevention of a blowout is preferable in preference to
saving money during the completion phase.
None of the blowouts recorded in the SINTEF offshore blowout database has caused severe
pollution. The most severe blowout recorded in the period from 1980-94 of was an oil blowout
emitting 10 m 3 into the ocean [7]. Out of the 41 workover blowouts after January 1970, there
have been two reported blowouts with large spills. The Bravo blowout in 1977, 20.000m 3
spilled into the North Sea. The second one was in 1992 in the U.S. Timbalier Bay’s shallow
waters offshore Louisiana. 500m 3 of oil drifted ashore and caused damage to the wildlife [7].
The role of a DHSV in the workover process is vague. During the workover the DHSV is
pulled together with the tubing. This process will last slightly longer than if the DHSV was not
present. The control lines strapped onto the tubing mainly cause the delay. During the tubing
retrieval process the straps must be removed and the control lines handled with care. For a
completion without a DHSV the amount of control lines is reduced. Therefore the presence of
a DHSV will result in a more complex workover situation. A DHSV will not cause any
significant change of blowout risk during workover.
Diploma thesis, NTNU 2002
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