This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 20136, “Research and Application of Fracture Failure Control Technology for 13Cr Tubing in HP/HT Gas Wells,” by Lei Ma, Hongtao Liu, and Hailong Geng, PetroChina, et al., prepared for the 2020 International Petroleum Technology Conference, Dhahran, Saudi Arabia, 13-15 January. The paper has not been peer reviewed. Copyright 2020 International Petroleum Technology Conference. Reproduced by permission.
Super 13Cr-110 tubing used in high-pressure, high-temperature (HP/HT) gas wells in the Tarim oil field has experienced numerous failures. After a series of investigations for root-cause analysis, the conclusion was that fracture of the tubing mechanistically is categorized as stress corrosion cracking (SCC) and is closely related to the application of phosphate-based completion fluid. Further tests indicated that Super 13Cr (S13Cr) tubing specimens experienced SCC with phosphate-based completion fluids contaminated with mud and oxygen, whereas formate-based completion fluid is compatible with S13Cr tubing. At present, 55 HP/HT gas wells in the field have used formate-based completion fluid with no tubing string fracture.
Introduction
Compared with the Gulf of Mexico, the North Sea, the South China Sea, the Qiongqiong Basin, and various Chinese oil and gas fields, the oil pipelines in the Tarim field are among the most difficult with regard to service conditions, which are characterized by extreme operating conditions such as high pump pressure and large displacement reform. Construction and high-yield alternating loads on tubing string and joint and a harsh, corrosive environment [chloride content greater than 80 000 mg/L, carbon dioxide (CO2) partial pressure greater than 1 MPa, and the presence of fresh and residual acid] pose significant challenges to the safe service of the tubing string. In the early stages of production, S13Cr oil pipe was selected as the completion string of the HP/HT gas well in the Kuqa mountain front, but in recent years, the S13Cr-110 pipe of the HP/HT gas well in the Tarim field has been continuously fractured. Failure accidents have caused serious economic losses. In the complete paper, through lateral comparison analysis of the failed tubing and indoor simulation experiments, the cause of the tubing fracture is discovered, solution measures are initiated, and good application results are achieved.
Comparative Analysis of Oil-Pipe Failures
Comparative Analysis of Fracture Macroscopic Morphology. When comparing the macroscopic topographic maps of oil-pipe failures seen in six studied wells, fracture locations of three wells are located in the coupling, while fracture locations of the other three wells are located on the body. In five wells (Wells A through E), the tubing fracture is neat, indicating brittle fracture with no plastic deformation. Well F, however, has a visible longitudinal crack on the surface of the tubing, and many burrs are visible at the fracture.
Comparison and Analysis of Working Conditions of Failed Tubing. Through comparative analysis, it was determined that five of the six wells have under-gone acidification. The service shaft temperature, pressure, CO2 content, and formation water salinity of the failed wells differ, but, in five of the six wells, the tubing was exposed to a phosphate-based completion fluid.
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