SSC Resistance of QT-900 and QT-1000 Coiled Tubing

SSC Resistance of QT-900 and QT-1000 Coiled Tubing Terry H. McCoy; Terry H. McCoy Halliburton Energy Services Group Search for other works by this author on: This Site Google Scholar Jeffrey Thomas Jeffrey Thomas Halliburton Energy Services Group Search for other works by this author on: This Site Google Scholar Paper presented at the SPE/ICoTA Coiled Tubing Conference & Exhibition, The Woodlands, Texas, USA, April 2006. Paper Number: SPE-99557-MS https://doi.org/10.2118/99557-MS Published: April 04 2006 Cite View This Citation Add to Citation Manager Share Icon Share Facebook Twitter LinkedIn Email Get Permissions Search Site Citation McCoy, Terry H., and Jeffrey Thomas. "SSC Resistance of QT-900 and QT-1000 Coiled Tubing." Paper presented at the SPE/ICoTA Coiled Tubing Conference & Exhibition, The Woodlands, Texas, USA, April 2006. doi: https://doi.org/10.2118/99557-MS Download citation file: Ris (Zotero) Reference Manager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex Search nav search search input Search input auto suggest search filter All ContentAll ProceedingsSociety of Petroleum Engineers (SPE)SPE/ICoTA Well Intervention Conference and Exhibition Search Advanced Search AbstractLaboratory sulfide stress cracking (SSC) tests were performed on specimens taken from QT-900 and QT-1000 coiled tubing (CT) test strings in an attempt to define zones of acceptable sour service. Acceptable pH-PH2S zones of service for QT-900 CT were proposed in SPE 93786.1 This paper presents additional QT-900 CT test data to further refine acceptable zones of service, with and without use of a chemical inhibitor. In addition, SSC testing was undertaken on QT-1000 CT. The SSC tests on QT-1000 CT were performed in manner similar to that conducted on QT-900 CT, using acidified aqueous solutions with H2S partial pressures ranging from 0.00345 to 100 bars and pH from 3.5 to 6.5, with and without inhibitor. Both as-milled and pressure-cycled tubing was tested. Test specimens were taken from parent metal and bias weld locations. The test data was used to construct acceptable zones of service on a pH-PH2S diagram.IntroductionHigh-pressure, high-temperature (HPHT) deep wells containing hydrogen sulfide (H2S) increasingly challenge the ability to service these wells by exclusively using lower strength CT70 and CT80 grades of coiled tubing.2 In some HPHT wells, only higher strength CT can be used.3 However, preventing catastrophic CT failures is of utmost importance; risk factors must be known and caution exercised to the fullest extent possible. Several factors affect the hydrogenation of steel, of which the most important are H2S concentration, pH, and temperature.4 Therefore, control and understanding of the environment to which the CT may be exposed is crucial. And while other factors such as chemical composition, fatigue, strength, hardness, mechanical damage, etc. are important, they are not as critical as the environment.It is believed that the use of chemical inhibition to mitigate hydrogenation and the possibility of environmental cracking can play an important role in preventing unexpected failures. It has been shown in lab tests that the addition of inhibitor to the aqueous solutions containing H2S can have significant beneficial effects and is thought to be able to extend the use of CT to more aggressive sour environments.1Field ExperienceSince the recommendations were made from the work presented in SPE 93786,1 no failures have resulted to the author's knowledge by following the proposed SSC-No SSC zones. Note that this paper basically confirms the QT-900 CT SSC-No SSC zones but adds an area of uncertainty at the low pH-low PH2S area (non-inhibited environments). However, additional precautions are being taken, especially in western Canada, to help prevent failures by routine use of chemical inhibition. The tubing OD is coated with inhibitor CG using an injector sub below the stripper as it is run in the well; in addition, the inhibitor is mixed with nonacidic fluids pumped through the coiled tubing. The proposed "No SSC" zone for environments containing inhibitor CG was expanded up to 100 bars PH2S based on test results reported in this paper. For acid systems, a different H2S inhibitor (not tested for this paper) is being utilized.Environmental DomainsSSC testing was undertaken with the ultimate goal of being able to identify sour service severity domains where QT-900 and QT-1000 CT could be reliably used. Defining severity domains is a common approach for carbon and low-alloy steel components used in sour service production. This concept has been adopted by EFC Publication Number 164 and NACE MR0175/ISO 15156.5 It has also been recognized by a consortium of major oil and gas and steel producers6 for use with API 5L linepipe steels and their welds. Since CT grades QT-900 and QT-1000 are high-strength, low-alloy (HSLA) steels, similar in composition to the steels in the above references, it is therefore expected that hydrogenation of these steels is also similar. However, it is recognized that CT operations place higher demands on the material than most other applications (due to repeated plastic deformation), and therefore, more restrictive conditions may be applicable. Keywords: Upstream Oil & Gas, bias weld, ssc-no ssc zone, NF bias Weld, Production Chemistry, fpbb sample, steel, coiled tubing, Corrosion Inhibition, H2S management Subjects: Production Chemistry, Metallurgy and Biology, Corrosion inhibition and management (including H2S and CO2) This content is only available via PDF. 2006. Society of Petroleum Engineers You can access this article if you purchase or spend a download.

Fetched live from OpenAlex and de-inverted. Abstracts are not stored in this database: the inverted indexes are 8.6 GB of the frame’s 9.3 GB of text, and the host has 13 GB free.