Experimental Study on Corrosion of J55 Casing Steel and N80 Tubing Steel in High Pressure and High Temperature Solution
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Experimental Study on Corrosion of J55 Casing Steel and N80 Tubing Steel in High Pressure and High Temperature Solution Containing CO2 and NaCl Lu Cui1 · Wenquan Kang1 · Hongjuan You2 · Jiarui Cheng1 · Zhen Li1 Received: 26 July 2020 / Revised: 16 October 2020 / Accepted: 10 November 2020 © Springer Nature Switzerland AG 2020
Abstract The downhole casing and tubing in thermal recovery wells are the main channels for fluid flow. The corrosion for casing and tubing in high pressure (5 MPa) and high temperature (200 °C) (HPHT) fluid can cause string failure due to wall thinning, deformation, and fracture. In order to study the corrosion characteristics of J55 casing steel and N80 tubing steel in HPHT environment containing C O2 and NaCl, corrosion and corrosion inhibition experiments were carried out using a rotating autoclave at a pressure of 5 MPa and 50–200 °C environment. Morphologies and compositions of corrosion products were analyzed by SEM and XRD. HPHT corrosion process was discussed by Arrhenius equation and the transition state equation. Results showed that the corrosion rates of the two materials increased with CO2 partial pressure while increased initially and then decreased with increasing temperature. In CO2–NaCl solution, the saturate NaCl decreased the CO2 corrosion rates at low temperature (inhibition) and increased C O2 corrosion rates at high temperature. Meanwhile, SEM results showed that the surfaces of C O2 corrosion became more dense and uniform at high temperature. The increase of NaCl leaded to pitting and high concentration NaCl solution causes granular products to appear on the C O2 corrosion surface. The carbon steel corrosion rate is mainly controlled by kinetic parameters of activation; the activation parameters were increased by the increase in temperature and NaCl concentration. Oil-soluble imidazoline acts as a good inhibitor for corrosion of J55 and N80 in this work. Keywords Tubing and casing failure · HPHT corrosion · CO2–NaCl solution · Flow-induced corrosion · Multi-component fluid · Corrosion inhibition
1 Introduction Steam injection and horizontal well recovery are effective methods for heavy oil recovery, which can be applied for injection and exploitation of thermal fluid. In the process of multi-component fluid injection and production, casing and tubing are inevitably subjected to HPHT corrosion damage [1], which is expected to increase the corrosion failure risk. Among them, the corrosion failure caused by CO2 is serious * Zhen Li [email protected] 1
School of Mechanical Engineering, Xi’an Shiyou University, Xi’an 710065, People’s Republic of China
Engineering Technology Research Institute of Xinjiang Oilfield Company of Petro China, Karamay 834000, People’s Republic of China
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[2] and its mechanism is complex. However, the presence of NaCl in multi-component fluid during production makes the effect factors of C O2 corrosion more serious and complicated [3, 4]. Weight loss during C O2 corrosion is generally related to environmental conditio
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