Mr. Erik Milito - The House Committee on Natural Resources ...

46 API STANDARD 65-2
<strong>The</strong> high number of BOP failures, such as the “BOP not in place” and other types of BOP failures, was a key focus
area for the API Work Group and is addressed accordingly within 3.7. For example, MMS regulation 30 CFR 250.422
(b) requires that if the operator plans to nipple down the diverter or BOP stack during the 8-hour or 12-hour WOC time
period, the operator should determine when it will be “safe” to do so. <strong>The</strong> decision should be based on the operator’s
knowledge of the formation, cement composition, effects of nippling down, potential drilling hazards, well conditions,
and past experience. Even though this regulation is currently in force, the API Work Group determined that more
specific guidance (see 3.7) is needed since well control incidents, with this category (BOP failures) involved, are still
occurring.
A.5 Studies of Annular Flows in the United Kingdom
Hinton [28] with the Offshore Safety Division of United Kingdom’s Heath and Safety Executive reported in SPE 56921
that 11 % of all wells drilled in the U.K. continental shelf from 1988 to 1998 have experienced reportable kicks during
well construction operations. Of these 22 % were in HPHT wells (>10,000 psi and 300 °F). Other U.K. sources cited
by Gao et al [29] in SPE 50581 claim that HPHT wells have much higher reportable kick incident rates (1 to 2 kicks per
1 well) compared to non-HPHT wells (1 kick per 20 to 25 wells). Some of the most frequent causes of kicks in drilling
U.K. wells were also found in the U.S. wells such as lost circulation in the same hole section with potential flow zones,
drilling fluid weight too low, and uncertainty in flow zone existence, flow potential, location, or other important
characteristics.
<strong>The</strong> following quote (SPE 56921, p.3, 1st paragraph) on other types of barrier failures during casing installation
operations is significant. “Exactly half the kicks associated with casing operations occurred when liner overlaps or
casing shoes leaked when drilling fluid weight was reduced.” <strong>The</strong> liner overlap failures mentioned in SPE 56921
included one case history of a well with a 7,500 psi shut in drill pipe pressure caused by a leaking liner top packer.
<strong>The</strong>se two types of barrier failures (liner overlaps and casing shoes) present opportunities to help prevent future
incidents by implementing the updated guidance on proven practices contained herein.
A.6 Studies of Annular Flows in Canada
Gas migration is reported by the Canadian government authorities to exist in many wells in Canada. A recent article
by Lang [30] reported on annular flows in Canada’s shallow to moderate depth wells in the areas of Alberta and
Saskatchewan “historically have had problems with gas migration developed leaks after primary cementing in 57 % of
the cases, on average.” In 2003, Getzlaf and Watson [31] stated that a database that registers gas migration in Alberta
“currently has over 5000 recorded vent flows, some serious, but most recorded as non-serious.” A vent flow is the
local name for an annular gas flow.
In the time period from April 1998 to March 1999, the Alberta Energy and Utilities Board [32] cites the following LWC
statistics for 7094 new wells drilled and included in the new total of over 129,000 active wells.
Table A.2—Drilling and Service Well Control Occurrences, 1998/1999
Drilling
Servicing
Blowouts 9 1
Blows 1
Kicks 101 N/A