Summary
Three drillstring fatigue failures occurred while drilling two deep wells
below 16,500 ft true-vertical depth (TVD) in the US midcontinent region. All
the failures occurred across 2°/100 ft- to 3°/100 ft-dogleg severity (DLS)
intervals from 6,000 to 8,000 ft. The well conditions (i.e., pipe condition and
directional plan) were not significantly different from other deep wells in the
area, which had not failed.
A deep-well drillstring failure study was conducted, which included a review
of drillstring-inspection reports, daily drilling reports, digital data,
technical literature, and engineering analysis for the two wells.
A cumulative fatigue analysis (CFA) modeling technique taking into account
specific well conditions [i.e., wellbore geometry, rotary speed, rate of
penetration (ROP), hook load, and drillstring configuration] was applied. The
model indicated that drillstring failures would occur across shallow doglegs
mainly because of high hang-down loads combined with slow ROP. The results of
the study led to the development of new deep-well design criteria and
implementation of new drilling guidelines. The new guidelines included the use
of look-ahead CFA modeling when approaching drillstring endurance limits to
minimize drillpipe-fatigue failures.
Look-ahead CFA modeling and the new drilling guidelines were used on two
subsequent deep wells in the area, leading to successful drilling to total
depth (TD) of 18,000 ft TVD without failure. One of the wells had a 1.4°/100-ft
DLS (calculated based on 100-ft survey spacing) at 1,500 ft, and drillpipe
shuffling was required to prevent drillstring failure in the deep-hole section.
The drillstring-fatigue failure prevention guidelines apply to deep wells
drilled worldwide.
Introduction
BP America, Inc. experienced three high-load cyclic fatigue tube failures
while drilling in the US midcontinent region’s deep Anadarko basin. All of the
failures occurred within a four-month period on two wells drilled by different
rigs. The three fatigue failures occurred in the highest shallow dogleg
interval of the wells, and all three failures were in the inclination-angle
dropping section of the well.
In Well A, poor mud properties caused the hole to pack off, leading to a
heat-related tensile failure of a crossover in the bottomhole assembly (BHA).
An unsuccessful fishing job for the remaining BHA led to a sidetrack. The
sidetrack around the fish created shallow doglegs and led to the two
drillpipe-fatigue failures in Well A.
Shallow directional walk problems combined with a small directional target
created shallow doglegs in Well B. The well scope was also changed at TD to
drill 375 ft deeper. Mud circulation was lost, and the drillstring was rotated
without circulation while building mud volume. Well B subsequently experienced
a fatigue failure while pulling out of the hole at TD of 16,628 ft.
After these failures occurred, a comprehensive study was performed to
understand why these two wells experienced drillpipe failures while other area
wells with similar conditions did not experience a failure. The study included
a review of drillpipe-inspection reports, daily drilling reports, digital
drilling recorder data, and engineering analysis.
© 2009. Society of Petroleum Engineers
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History
- Original manuscript received:
2 August 2007
- Meeting paper published:
11 November 2007
- Revised manuscript received:
19 October 2008
- Manuscript approved:
29 December 2008
- Published online:
27 July 2009
- Version of record:
23 December 2009
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