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51318-10920-High strength steel SSC evaluation in mild sour environments at ambient and high temperatures

Picture for High strength steel SSC evaluation in mild sour environments at ambient and high temperatures
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There is an increasing need to define the operating envelope for materials typically used as oil country tubular goods. This paper reports results of sulfide stress cracking (SSC) tests that were performed in mild sour environment at temperatures below 107°C.

Product Number: 51318-10920-SG
Author: James Wei / Manuel Gonzalez / Brian Chambers / Boris Thomas
Publication Date: 2018
Industry: Oil and Gas Production
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High strength steels with yield strength greater than 965 MPa (140 ksi) typically used as oil country tubular goods (OCTG) have very limited use in marginally sour wells. Currently, NACE(1) MR0175 / ISO(2)15156-21 provides caution on the use of these materials even in the non-sour Region 0. However, high pressure high temperature (HPHT) wells are requiring these grades to meet design requirements. Consequently, there is an increasing need to define the operating envelope for these materials.

To establish the operating envelope, sulfide stress cracking (SSC) tests were performed at various temperatures lower than 107 °C (225 °F) in mild sour environment. This paper reports SSC test results at low temperatures and the issues experienced at high temperatures. It was found that high strength material has very limited sour resistance in Region 0 when the material yield strength reaches 965 MPa (140 ksi). At low temperatures, testing in Region 0 using NACE TM01772 Standard Method A (30 days) may not be adequate to detect cracking susceptibility. In addition, SSC data suggests that 4 °C (40 °F) may be worse than ambient temperature.

For SSC testing at high temperatures, significant general corrosion and large pH drift proved to be challenging issues. Several Method A samples exhibited significant corrosion after 720 hours to an extent that rendered the evaluation of cracking impossible and the higher corrosion rates resulted in a significant drift of pH during test. The effect of different buffer solutions on the pH and corrosion was investigated and recommendations on high temperature testing are discussed.

Key words: SSC, Hydrogen embrittlement, mild sour, DCB (double cantilever beam), OCTG, HPHT, acetic acid, buffers.

High strength steels with yield strength greater than 965 MPa (140 ksi) typically used as oil country tubular goods (OCTG) have very limited use in marginally sour wells. Currently, NACE(1) MR0175 / ISO(2)15156-21 provides caution on the use of these materials even in the non-sour Region 0. However, high pressure high temperature (HPHT) wells are requiring these grades to meet design requirements. Consequently, there is an increasing need to define the operating envelope for these materials.

To establish the operating envelope, sulfide stress cracking (SSC) tests were performed at various temperatures lower than 107 °C (225 °F) in mild sour environment. This paper reports SSC test results at low temperatures and the issues experienced at high temperatures. It was found that high strength material has very limited sour resistance in Region 0 when the material yield strength reaches 965 MPa (140 ksi). At low temperatures, testing in Region 0 using NACE TM01772 Standard Method A (30 days) may not be adequate to detect cracking susceptibility. In addition, SSC data suggests that 4 °C (40 °F) may be worse than ambient temperature.

For SSC testing at high temperatures, significant general corrosion and large pH drift proved to be challenging issues. Several Method A samples exhibited significant corrosion after 720 hours to an extent that rendered the evaluation of cracking impossible and the higher corrosion rates resulted in a significant drift of pH during test. The effect of different buffer solutions on the pH and corrosion was investigated and recommendations on high temperature testing are discussed.

Key words: SSC, Hydrogen embrittlement, mild sour, DCB (double cantilever beam), OCTG, HPHT, acetic acid, buffers.

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Black tar-like fouling material was driving frequent shut-downs of a gas plant. Analysis indicated that the nitrogen containing corrosion inhibitor (CI) polymerized with sulfur compounds in a vulcanization process. Testing confirmed the role of the CI in creating this fouling.
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