RIASSUNTO
Abstract
Three drillstring fatigue failures occurred while drilling two deep wells below 16,500 ft true-vertical depth (TVD) in the U.S.A. midcontinent region. All the failures occurred across 2°/100 ft to 3°/100 ft dogleg severity intervals from 6,000 ft 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, 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 rate of penetration (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 utilization 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 dogleg severity (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 U.S.A. midcontinent region's deep Anadarko basin. All 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.
Drillpipe Failures in Well A
Well A had been drilled to 11,409 ft TD. The hole was losing mud returns and starting to pack off because of hole instability. The drillstring was backreamed (rotating the drillstring while pulling out of the hole) with 325,000 lbf pickup weight to pull out of the hole. The hole finally partially packed off (circulation returns were lost) with very limited drillstring movement up or down at the 9?-in. bit depth of 10,530 ft. The drillstring was rotated for 1.5 hours at 10,530 ft (without circulation) before the failure.