Recommendations could improve the serviceability of drillstring components - oil wells

World Oil, July, 1998 by Anatoly Baryshnikov, Francesco Donati, Gilberto Toffolo, Paolo Ferrara

Field experience and engineering design work spur new technical specifications that would increase rotary shouldered connection life

Considerable experience in analyzing drillstring component serviceability has been developed by an international operator. This knowledge, obtained under combined tension and torsion, in addition to dynamic loading, is described below. Agip has accumulated this experience through development of four joint/internal research projects, seven SPE and ASME papers and two patents. As a result, company representatives were invited to attend a standardization conference called to revise API RP 7G, RP 7A1 and Spec. 7, which cover drillstring component serviceability under static and dynamic loads.

Also discussed are drillstring failure case histories, which show the effects of over-torquing during stuck pipe conditions. Additionally, recommendations are given for further developing technical specifications for reliable drillstring components.

IMPORTANCE OF SERVICEABILITY

Drillstring (DS) component serviceability means that DS strength and mechanical parameters fully comply with specified operational requirements. Serviceability is then the critical factor in achieving cost effective and low risk drilling practices. Drilling cost grows exponentially for high risk operations, especially when DS failures lead to a fishing job or cause well control problems. Severe downhole conditions, together with ID and OD limitations, create considerable difficulties in designing and using reliable DS equipment. Downhole tools should be stable under the following primary load conditions:

* Axial tension due to weight of the lower part of the drillstring

* Compression and bending due to weight on bit

* Torsion due to drillstring and bit rotation

* Pin tension and box compression from make-up

* Differential pressure caused by internal and external drilling mud

* Cyclic bending due to downhole tool buckling and rotation in doglegs

* Dynamic loads while tripping

* Dynamic loads (axial, radial and torsion) due to downhole tool vibrations and bit dynamics.

In accordance with existing RP (Recommended Practices), DS strength is designated under tension loads, but this type of failure is quite rare.l Resistance to torsion and dynamic loads has not been studied closely, and usually, DS components, especially rotary shouldered connections (RSC), have not been analyzed under these loads before being qualified for operations. It has been shown that fatigue and over-torquing are the primary cause of 60-80% of DS failures.[5,18] Thus to improve DS reliability, new specifications and recommended practices are needed, especially for optimum make-up pre-load conditions, combined tension and torsion loads, dynamic loads, etc.

CASE HISTORIES

DS twist-off in an offshore well. A tool joint twistoff occurred in Agip's Sabine Pass 11-1 well (offshore Louisiana). The DS configuration was as follows: 616.8 ft (188 m) of BHA; 4,367 ft (1,331 m) of 3 1/2-in. drill pipe (DP); 10,437 ft (3,181 m) of 5-in. DP. While drilling from 14,580 to 15,454 ft (4,444-4,710 m), two bit runs were made, drilling 874 ft (266 m) of hole in 86.7 rotating hours (10.1 ft/hr average). These bits were used to drill out the 7in. liner, which was set at 15,577 ft (4,443 m). The mud was a 17.6 ppg, dispersed K-52 system. Maximum bottomhole recorded temperature was 140 [degrees] C.

After changing out the mud motor, the last bit (5.875-in., NTC D262G) was run in the hole at 15,454 ft (4,710 m). While breaking circulation, the bit became stuck 46 ft (14 m) off bottom at 15,408 ft (4,696 m). While attempting to work the pipe free (tension on weight indicator was 1.33 times greater than weight while tripping) and applying 18,955 ft-lb (25.7 kN-m) of torque, it twisted off, leaving 3,271 ft (997 m) of 3 1/2-in. DP in the hole, Fig. 1. Top of fish was at 12,127 ft (3,696 m). The 3 1/2-in. DP was equipped with NC38, 4 3/4-in. OD, tool joints. A minimum tool joint OD of 4 9/16 in. is needed to pass inspection. Thread compound used for tool joint make-up was ZN-50 from Bestolife. The last joint of DP had a belled box on the top fish at 12,127 ft (3,396 m). Belied tool joints were also found on some other 3 1/2-in. DP.

DS twist-off in an onshore well. While pulling out the hole from 21,129 ft (6,135 m) in the Agip Trecate 9 D well (Crema district, Italy) with drainhole open at 18,832 ft (5,740 m), the 3 1/2-in. DS became differentially stuck at 19,991 ft (6,093 m). Sticking occurred at the MWD tools, 23 ft (7 m) from the bit. DS configuration was as follows: 118 ft (36 m) of BHA; 1,385 ft (422 m) of 3 1/2-in., Grade E, 15.5 ppf DP; 696 ft (212 m) of drill collars; 6,532 ft (1,991 m) of 3 1/2-in., Grade G, 15.5 ppf DP; and 11,260 ft (3,432 m) of 3 1/2in., Grade S, 15.5 ppf DP. Weight on hook before getting stuck was 255,233 lb (1,137 kN). After pipe failure, it was 167,238 lb (745 kN). The NC38 DP tool joints were 4 3/4-in. OD. The applied tool joint make-up torque was 8,703 ft-lb (11,8 kN-m). Thread compound used was Z50 Jet-Lube Bestolife.