Materials Performance

SEP 2018

Materials Performance is the world's most widely circulated magazine dedicated to corrosion prevention and control. MP provides information about the latest corrosion control technologies and practical applications for every industry and environment.

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41 MATERIALS PERFORMANCE: VOL. 57, NO. 9 SEPTEMBER 2018 one length of the pipe tube body at a posi- tion near the connection made up in the field. The circumferential length of frac- tures and cracks on 10 pin vanish point specimens and their depths in the well are shown in Figure 2. Fi gure 2 sh ow s that fra cture s and cracks of tubing were at well depths of 4,146 to 4,712 m , with a total range of 566 m. Ten lengths of tubing failed at the pin vanish point of the connection made up in the mill, which accounted for 91% of the total failures. Results of Fractography and Metallography Fractures and cracks of the S13Cr-110 tubing with premium joints were the result of SCC that developed under conditions that included tensile stress in a corrosive medium (Figures 3 and 4). Fatigue failure also took place due to alternating loads borne on the tubing string (Figure 5), and many corrosion pits produced in the early stage that accelerated SCC and fatigue cracking. The tubing material performance was in accordance with I S O 1 3 6 8 0 a n d th e owner's requirements, but it did not per- form well when exposed to the HPHT and aggressive environment where corrosive chloride, sulfide, and carbon dioxide (CO 2 ) were present. Discussion Analysis of the Failure Position in the Well The tensile load borne by the tubing string was greater near the wellhead than the bottom of the well because of the tub- ing weight. 6 Th e tubing fractures and cracks were located at depths of 4,146 to 4,712 m, and not where the maximum ten- sion load on the tubing string was present. The load borne by the tubing string in the well included tensile stress from its weight and contraction with cold, as well as compressive load caused by heat expan- sion and internal, external, and vibrational loads. The stress condition of the tubing string under these loads is illustrated by FIGURE 1 Fracture and erosion morphology of Segment No. 432 tubing at the pin plane of the thread vanish point (API SPEC 5B). The connection was made by the mill. FIGURE 2 The transverse crack (fracture) length vs. well depth for 10 tubing samples. Figure 6. Tubing string elon- gation deformation due to its weight is shown in Figure 6(a), tubing string elongation d e f o r m a t i o n d u e t o i t s weight and compression is shown in Figure 6( b), and tu b i n g st r i n g e l o n g a t i o n d e f o r m a t i o n d u e t o i t s weight and tension is shown in Figure 6(c). Th e tubin g strin g e x- panded from heat during gas production. Because the tub- ing string was fixed to the wellhead by the oil produc- tion tree and held in place by the packer near the bottom of the well, it experienced bend- ing as shown in Figure 6(b). In this case, the more the tubing string was bent, the more likely the tubing would crack. Alternatively, the tubing string con- tracted from cold during the acidifying pro- cess. The stress condition of tubing string at the beginning of acidification is shown in Figure 6(c). When the tubing string tem- perature was reduced, it gradually short- ened and became straighter. Additionally, the tubing string was subjected to internal pressure and vibration load from the natu- ral gas flow rate change and pump pressure f luctuation during acidification injection and discharge. The tubing failed from SCC, however, corrosion fatigue failure charac- teristics were also found on the fracture surfaces, which indicated alternating loads were borne by the tubing string during these processes.

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