Nace mr0175 certified user my reading 8 by charlie Chong

Understanding NACE MR0175-Carbon Steel Written Exam Code-Keyword Search

Reading 8

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Oil And Gas Production Industry

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Oil And Gas Production Industry

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Oil And Gas Production Industry

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过五关斩六将

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NACE MR0175-Carbon Steel Written Exam NACE-MR0175-Carbon Steel -001 Exam Preparation Guide May 2017

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NACE MR0175-Carbon Steel Written Exam NACE-MR0175-Carbon Steel -001 Exam Preparation Guide May 2017

Introduction The MR0175-Carbon Steel written exam is designed to assess whether a candidate has the requisite knowledge and skills that a minimally qualified MR0175 Certified User- Carbon Steel must possess. The exam comprises 50 multiple-choice questions that are based on the MR0175 Standard (Parts 1 and 2).

multiple-choice Fion Zhang/ Charlie Chong

https://www.naceinstitute.org/uploadedFiles/Certification/Specialty_Program/MR0175-Carbon-Steel-EPG.pdf

EXAM BOK Suggested Study Material  NACE MR0175/ISO 15156 Standard (20171015-OK)  EFC Publication 17  NACE TM0177  NACE TM0198 NACE TM0316 Books  Introductory Handbook for NACE MR0175

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ASTM.

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ASTM. 7.3.2 Parent metals For ferritic steels, EFC Publication 16 shows graphs for the conversion of hardness readings, from Vickers (HV) to Rockwell (HRC) and from Vickers (HV) to Brinell (HBW), derived from the tables of ASTM E140 and ISO 18265. Other conversion tables also exist. Users may establish correlations for individual materials.

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A.2.1.3 Carbon steels acceptable with revised or additional restrictions a) Forgings produced in accordance with ASTM A105 are acceptable if the hardness does not exceed 187 HBW. b) Wrought pipe fittings to ASTM A234, grades WPB and WPC are acceptable if the hardness does not exceed 197 HBW.

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A.2.1.6 Cold deformation and thermal stress relief Carbon and low-alloy steels shall be thermally stress-relieved following any cold deforming by rolling, cold forging or other manufacturing process that results in a permanent outer fibre deformation greater than 5 %. The minimum stress-relief temperature shall be 595 Â°C (1 100 Â°F). The final maximum hardness shall be 22 HRC except for pipe fittings made from ASTM A234 grade WPB or WPC, for which the final hardness shall not exceed 197 HBW. Cold-worked line pipe fittings of ASTM A53 Grade B, ASTM A106 Grade B, API 5L Grade X-42, ISO 3183 Grade L290, or lower-yield-strength grades with similar chemical compositions, are acceptable with cold strain equivalent to 15 % or less, provided the hardness in the strained area does not exceed 190 HBW.

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Summarizing Carbon steels acceptable with revised or additional restrictions ASTM Grade

Descriptions

Revised Hardness Limitation

ASTM A105

Standard Specification for Carbon Steel Forgings for Piping Applications

187 HBW

ASTM A234, grades WPB and WPC

Standard Specification for Piping Fittings of Wrought Carbon Steel and Alloy Steel For Moderate and High Temperature Service

197 HBW

A.2.1.6 Cold deformation and thermal stress relief With cold strain equivalent to 15 % or less ASTM A53 Grade B

Standard Specification for Pipe, Steel, Black and Hot-Dipped, Zinc-Coated, Welded and Seamless

190 HBW (Bended/ Stressed)

ASTM A106 Grade B

Standard Specification for Seamless Carbon Steel Pipe for HighTemperature Service

190 HBW (Bended/ Stressed)

API 5L Grade X-42

Specification for Line Pipe

190 HBW (Bended/ Stressed)

ISO 3183 Grade L290

Petroleum and natural gas industries â&#x20AC;&#x201D; Steel pipe for pipeline transportation systems

190 HBW (Bended/ Stressed)

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ASTM A105 Standard Specification for Carbon Steel Forgings for Piping Applications This specification covers standards for forged carbon steel piping components, that is, flanges, fittings, valves, and similar parts, for use in pressure systems at ambient and higher-temperature service conditions. Materials shall be subjected to heat treatment (annealing, normalizing, tempering, or quenching). Material shall conform to chemical contents. The forgings shall be subjected to tension, hardness and hydrostatic tests, Material shall adhere to mechanical and hardness requirements.

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ASTM A216 WCB - Standard Specification for Steel Castings, Carbon, Suitable for Fusion Welding, for High-Temperature Service

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ASTM A216 WCB - Standard Specification for Steel Castings, Carbon, Suitable for Fusion Welding, for High-Temperature Service

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ASTM A216 WCB - Standard Specification for Steel Castings, Carbon, Suitable for Fusion Welding, for High-Temperature Service

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http://www.isgec.com/steel-castings/ba-steel-castings-overview.php

Forged Valve ASTM A105 WPC

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Forged Valve ASTM A105 WPC

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Forged Valve ASTM A105 WPC

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Forged Valve ASTM A105 WPC

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Forged Valve ASTM A105 WPC

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What is A234 WPB Steel pipe fitting? A234 WPB steel pipe fittings mean the pipe fitting which material is ASTM A234 WPB , they are used for the pressure piping systems of moderate and high temperature services. ASTM A234 is the standard of pipe fittings material , it indicates the materials properties of different kinds of carbon steel and alloy steel, WPB is one of the steel grade in this standard. W means weldable, P means pressure, B is grade b ,refer to the minimum yield strength , like the ASTM A106 A53, Gr.B or API 5L Gr.B. A234 WPB is the most common carbon steel pipe fittings material .

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Cold-worked line pipe fittings of ASTM A53 Grade B, ASTM A106 Grade B, API 5L Grade X-42, ISO 3183 Grade L290, or lower-yield-strength grades with similar chemical compositions, are acceptable with cold strain equivalent to 15 % or less, provided the hardness in the strained area does not exceed 190 HBW.

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Table A.2 â&#x20AC;&#x201D; Examples of tubular products that can comply with A.2.1

A.2.1.6 Cold deformation and thermal stress relief With cold strain equivalent to 15 % or less ASTM A53 Grade B

Standard Specification for Pipe, Steel, Black and Hot-Dipped, Zinc-Coated, Welded and Seamless

190 HBW (Bended/ Stressed)

ASTM A106 Grade B

Standard Specification for Seamless Carbon Steel Pipe for HighTemperature Service

190 HBW (Bended/ Stressed)

API 5L Grade X-42

Specification for Line Pipe

190 HBW (Bended/ Stressed)

ISO 3183 Grade L290

Petroleum and natural gas industries â&#x20AC;&#x201D; Steel pipe for pipeline transportation systems

190 HBW (Bended/ Stressed)

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Table A.4 â&#x20AC;&#x201D; Acceptable bolting materials

Additional requirement that it meet a Charpy Test at 150 degrees F is needed. Such fasteners are commonly used for low temperature service.

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ASTM A193 specification covers (1) alloy steel and (2) stainless steel bolting material for pressure vessels, valves, flanges, and fittings for high temperature or high pressure service, or other special purpose applications. Several grades are covered, including ferritic steels and austenitic stainless steels designated B5, B8, and so forth. Selection will depend upon design, service conditions, mechanical properties, and high temperature characteristics. Material according to ASTM A193 B7 is often available in national coarse (UNC) thread pitches, if being used in traditional applications, threads are specified 8 threads per inch (tpi) for diameters above one inch. Below is a summary of a few of the common grades.

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Bolt

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http://www.portlandbolt.com/technical/specifications/astm-a193/

Bolt

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http://www.portlandbolt.com/technical/specifications/astm-a193/

NUT

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http://www.portlandbolt.com/technical/specifications/astm-a194/

4.4.

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http://www.portlandbolt.com/technical/specifications/astm-a194/

1. The markings shown for all grades of A194 nuts are for cold formed and hot forged nuts. When nuts are machined from bar stock, the nut must additionally be marked with the letter 'B'. The letters H and M indicate heat treated nuts. 2. Properties shown are those of coarse and 8-pitch thread heavy hex nuts. 3. Hardness numbers are Brinell Hardness. 4. Nuts that are carbide-solution treated require additional letter A - 8A or 8MA. 5. All nuts shall bear the manufacturerâ&#x20AC;&#x2122;s identification mark. Nuts shall be legibly marked on one face to indicate the grade and process of the manufacturer. Marking of wrench flats or bearing surfaces is not permitted unless agreed upon between manufacturer and purchaser. Nuts coated with zinc have an asterisk (*) marked after the grade symbol. Nuts coated with cadmium shall have a plus sign (+) marked after the grade symbol. 6. Other less common grades exist, but are not listed here. Fion Zhang/ Charlie Chong

http://www.portlandbolt.com/technical/specifications/astm-a194/

ASTM A193/A193M is a specification from the Association of Standards & Materials that primarily govern industrial piping applications. In the assembly of an industrial plant, many complex components are bolted together of which include parts such as valves, piping, & pressure vessels. ASTM A193 defines the methodology to procure and certify externally threaded fasteners according to specific chemical and mechanical criteria. It is standards such as this that allow industrial process applications to be safely engineered so they do not exceed the tensile strength of the fasteners that hold them together.

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COMMON ASTM FASTENER SPECIFICATIONS FASTENER GRADES INCLUDE: ASTM A193 Grade B7 Chromium Molybendum steel, normally AISI 4140, heat treated to 2832Rockwell Hardness, 125,000 PSI tensile strength, 105, 000 PSI yield. It will hold itâ&#x20AC;&#x2122;s strength to 1000 degrees F. ASTM A193 Grade B7M It has the same chemistry as B7. Physicals have max hardness of 235 Brinell or RC22. 100,000 PSI tensile and 80,000 PSI yield. Used in areas where H2S is present. ASTM A193 Grade B16 Chromium, molybendum, Vanadium steel. It has the same physicals as B7. Added vanadium allows it to hold itâ&#x20AC;&#x2122;s strength to 1100 degrees Fahrenheit. ASTM A193 Grade B8 18-8 Grade stainless, non magnetic, good corrosion resistance. 75,000 PSI tensile strength. Same material as AISI type 304 stainless steel. ASTM A193 Grade B8M This is similar to B8 fasteners except with added Molybdenum. It has better corrosion resistance than B8. Hex Bolts, studs and other fasteners are common to the B8M spec. ASTM A193 Grade B8 Class 2 Studs, bolts, and other fasteners found in this grade are considered the same as B8 except strain hardened. This is a cold working process which increases physical properties. 100,000-125,000 PSI Tensile Strength. ASTM A193 Grade B8M Class 2 Same as B8M except strain hardened, 90,000-125,000PSI Tensile Strength. ASTM A193 Grade BC 18-8 grade stainless with additional element of Columbium- same as type 347 type stainless steel. ASTM A193 Grade B8T 18-8 grade of stainless with additional element of Titanium. Same as type 321 Stainless Steel.

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ASTM A193 Grade B6 This has the same chemistry as AISI type 410 stainless steel, but it is heat treated. 110,000 PSI tensile strength. ASTM A193 Grade B5 Fasteners under the B5 spec have the same chemistry as AISI type 501 SS but they are heat treated to 100,000 PSI tensile strength.

ASTM A320 Grade L7 Bolts, studs, and other fasteners under the L7 grade have the same chemical and physical properties as B7. Additional requirement that it meet a Charpy Test at 150 degrees F is needed. Such fasteners are commonly used for low temperature service. ASTM A320 Grade L7M

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http://lightningboltandsupply.com/reference.html

A.2.4 Requirements for the use of cast irons A.2.4.1 General Ferritic ductile iron in accordance with ASTM A395 is acceptable for equipment unless otherwise specified by the equipment standard.

ASTM A395/A395M, Standard Specification for Ferritic Ductile Iron Pressure-Retaining Castings for Use At Elevated Temperatures

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Table A.5 — Cast irons acceptable for packers and other subsurface equipment

• ASTM A536, Standard Specification for Ductile Iron Castings • ASTM A571/A571M, Standard Specification for Austenitic Ductile Iron Castings for Pressure-Containing Parts Suitable for Low-Temperature Service • ASTM A602, Standard Specification for Automotive Malleable Iron Castings • ASTM A278/A278M, Standard Specification for Gray Iron Castings for PressureContaining Parts for Temperatures up to 650 °F (350 °C) • ASTM A48/A 48M, Standard Specification for Gray Iron Castings

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Packer

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Packer

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A.2.4.3 Compressors and pumps Grey cast iron (ASTM A278, Class 35 or 40) and ductile (nodular) cast iron (ASTM A395) are acceptable as compressor cylinders, liners, pistons and valves.

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Compressors and pumps

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Sulfur.

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6 Evaluation and definition of service conditions to enable material selection Factors, other than material properties, known to affect the susceptibility of metallic materials to cracking in H2S service include H2S partial pressure, in situ pH, the concentration of dissolved chloride or other halide, the presence of elemental sulfur or other oxidant, temperature, galvanic effects, mechanical stress, and time of exposure to contact with a liquid water phase. 3.9 free-machining steel steel to which elements such as sulfur, selenium, and lead have been added intentionally to improve machineability

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6 Factors affecting the behaviour of carbon and low alloy steels in H2Scontaining Environments e) presence of sulfur or other oxidants; 7.2.2 SOHIC and SZC NOTE The occurrence of these phenomena is rare and they are not well understood. They have caused sudden failures in parent steels (SOHIC) and in the HAZ of welds (SOHIC and SZC). Their occurrence is thought to be restricted to carbon steels. The presence of sulfur or oxygen in the service environment is thought to increase the probability of damage by these mechanisms.

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8 Evaluation of carbon and low alloy steels for their resistance to HIC/SWC The probability of HIC/SWC is influenced by steel chemistry and manufacturing route. The level of sulfur in the steel is of particular importance, typical maximum acceptable levels for flat-rolled and seamless products are 0.003 % mass fraction and 0.01 % mass fraction, respectively. Conventional forgings with sulfur levels less than 0.025 % mass fraction, and castings, are not normally considered sensitive to HIC or SOHIC. NOTE 2 The presence of rust, sulfur, or oxygen, particularly together with chloride, in the service environment is thought to increase the probability of damage.

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Q1. You urgently need a replacement carbon steel valve to handle a sour fluid. You are offered a wrought steel valve with 0.020% sulphur from one supplier and a cast one with 0.026% sulphur from another. Both have hardness below 22HRC, but neither has been HIC tested. What is the position of the standard about accepting these two valves? a. Neither wrought nor cast is acceptable b. Wrought is not acceptable but cast is acceptable c. Wrought is acceptable but cast is not acceptable d. Both are acceptable 8 Evaluation of carbon and low alloy steels for their resistance to HIC/SWC The probability of HIC/SWC is influenced by steel chemistry and manufacturing route. The level of sulfur in the steel is of particular importance, typical maximum acceptable levels for flat-rolled and seamless products are 0.003 % mass fraction and 0.01 % mass fraction, respectively. Conventional forgings with sulfur levels less than 0.025 % mass fraction, and castings, are not normally considered sensitive to HIC or SOHIC. NOTE 2 The presence of rust, sulfur, or oxygen, particularly together with chloride, in the service environment is thought to increase the probability of damage.

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Table E.2 â&#x20AC;&#x201D; Additional information for SSC testing and other special cases

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UNS G

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A.2 SSC-resistant carbon and low-alloy steels and the use of cast irons A.2.2 Application to product forms A.2.2.3 Downhole casing, tubing, and tubular components A.2.2.3.2 Tubulars and tubular components made of Cr-Mo low-alloy steels (UNS G41XX0, formerly AISI 41XX, and modifications), if quenched and tempered in the tubular form, are acceptable if their hardness does not exceed 30 HRC and they have SMYS grades of 690 MPa (100 ksi), 720 MPa (105 ksi), and 760 MPa (110 ksi). The maximum yield strength for each grade shall be no more than 103 MPa (15 ksi) higher than the SMYS. SSC resistance shall be demonstrated by testing each test batch and shall comply with B.1 using the UT test.

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A.2.2.3.3 Tubulars and tubular components made of Cr-Mo low-alloy steels (UNS G41XX0, formerly AISI 41XX and modifications), if quenched and tempered in the tubular form, are acceptable if the hardness does not exceed 26 HRC. These products should be qualified by SSC testing in accordance with B.1 using the UT test. A.2.3.2.2 Shear rams Rams manufactured in quenched and tempered Cr-Mo low-alloy steels (UNS G41XX0, formerly AISI 4IXX, and modifications) are acceptable if the hardness does not exceed 26 HRC. If the hardness of these alloys exceeds 22 HRC, careful attention shall be paid to chemical composition and heat treatment to ensure their SSC resistance. SSC testing, as agreed with the equipment user, shall demonstrate that the performance of the alloy meets or exceeds that of field proven material.

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A.2.3.3 Compressors and pumps A.2.3.3.1 Compressor impellers UNS G43200 (formerly AISI 4320) and a modified version of UNS G43200 that contains 0.28 % mass fraction to 0.33 % mass fraction carbon are acceptable for compressor impellers at a maximum yield strength of 620 MPa (90 ksi) provided they have been heat-treated in accordance with the following three step procedure. a) Austenitize and quench. b) Temper at 620 째C (1 150 째F) minimum temperature, but below the lower critical temperature. Cool to ambient temperature before the second temper. c) Temper at 620 째C (1 150 째F) minimum, but lower than the first tempering temperature. Cool to ambient temperature.

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A.3 SSC-resistant steels for use throughout SSC region 2 A.3.2 Downhole casing, tubing, and tubular components Casing, tubing and tubular components made of Cr-Mo low-alloy steels (UNS G41XX0, formerly AISI 41XX, and modifications) have proven acceptable in the quenched and tempered condition. Typically, the actual yield strength of acceptable steels has been no more than 760 MPa (110 ksi) [an SMYS of approximately 550 MPa (80 ksi)] and their hardness has been no more than 27 HRC. Other requirements shall be in accordance with the applicable manufacturing specification.

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A.4 SSC-resistant steels for use throughout SSC region 1 A.4.2 Downhole casing, tubing, and tubular components Casing, tubing and tubular components made of Cr-Mo low-alloy steels (UNS G41XX0, formerly AISI 41XX and modifications) have proven acceptable in the quenched and tempered condition. Typically, the actual yield strength of acceptable steels has been no more than 896 MPa (130 ksi) [an SMYS of approximately 760 MPa (110 ksi)] and their hardness has been no more than 30 HRC. Other requirements shall be in accordance with the applicable manufacturing specification.

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UNS G Only the following; UNS G41 UNS G43

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Q2. You require an ESP pump to handle a sour fluid containing 12kPa H2S and 100g/L chloride at 70°C. You are offered a pump with an alloy K-500 (UNS N05500) shaft. Which statement below best represents the position of the standard? a. UNS G41420 steel that has been cold straightened, stress relieved at 620°C and has a hardness of 321 Brinell. b. UNS G41420 steel that has been cold straightened, stress relieved at 460°C and has a hardness of 26 HRC. c. UNS G41400 steel that has been cold straightened, stress relieved at 605°C and has a hardness of 26 HRC. d. UNS G51400 steel that has been cold straightened, stress relieved at 605°C and has a hardness of 24 HRC. e. UNS G41400 steel that has a flush joint connection that has been cold formed with about 8% cold work, stress relieved at 575°C and has a hardness of 26 HRC.

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Q2. You require an ESP pump to handle a sour fluid containing 12kPa H2S and 100g/L chloride at 70°C. You are offered a pump with an alloy K-500 (UNS N05500) shaft. Which statement below best represents the position of the standard? a. UNS G41420 steel that has been cold straightened, stress relieved at 620°C and has a hardness of 321 Brinell. (A.2.2.3.3 Tubulars and tubular components made of Cr-Mo lowalloy steels (UNS G41XX0, formerly AISI 41XX and modifications), if quenched and tempered in the tubular form, are acceptable if the hardness does not exceed 26 HRC. These products should be qualified by SSC testing in accordance with B.1 using the UT test.)

b. UNS G41420 steel that has been cold straightened, stress relieved at 460°C and has a hardness of 26 HRC. (If tubulars and tubular components are cold-straightened at or below 510 °C (950 °F), they shall be stress-relieved at a minimum temperature of 480 °C (900 °F).)

UNS G41400 steel that has been cold straightened, stress relieved at 605°C and has a hardness of 26 HRC. (Tubulars and tubular components made of Cr-Mo low-alloy steels (UNS G41XX0, formerly AISI 41XX and modifications), if quenched and tempered in the tubular form, are acceptable if the hardness does not exceed 26 HRC. These products should be qualified by SSC testing in accordance with B.1 using the UT test.)

d. UNS G51400 steel that has been cold straightened, stress relieved at 605°C and has a hardness of 24 HRC. (G51400 not in the spec) e. UNS G41400 steel that has a flush joint connection that has been cold formed with about 8% cold work, stress relieved at 575°C and has a hardness of 26 HRC. (If tubulars and tubular components are cold-formed (pin-nosed and/or box-expanded) and the resultant

permanent outer fibre deformation is greater than 5 %, the cold-formed regions shall be thermally stress-relieved at a minimum temperature of 595 °C (1 100 °F).)

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321 Brinell = HRC 67.5

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A.2.2.3.4 If tubulars and tubular components are cold-straightened at or below 510 °C (950 °F), they shall be stress-relieved at a minimum temperature of 480 °C (900 °F). If tubulars and tubular components are coldformed (pin-nosed and/or box-expanded) and the resultant permanent outer fibre deformation is greater than 5 %, the cold-formed regions shall be thermally stress-relieved at a minimum temperature of 595 °C (1 100 °F).

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For 41xx0 the requirements; 1. These products should be qualified by SSC testing in accordance with B.1 using the UT test. 2. if quenched and tempered in the tubular form, are acceptable if the hardness does not exceed 26 HRC 3. If tubulars and tubular components are cold-straightened at or below 510°C (950°F), they shall be stress-relieved at a minimum temperature of 480 °C (900 °F). 4. If tubulars and tubular components are cold-formed (pin-nosed and/or box-expanded) and the resultant permanent outer fibre deformation is greater than 5 %, the cold-formed regions shall be thermally stressrelieved at a minimum temperature of 595°C (1100°F).

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For 41xx0 the requirements; 1. 26 HRC 2. cold-straightened stress-relieved at a minimum temperature of 480 째C (900 째F). 3. cold-formed stress-relieved at a minimum temperature of 595째C (1100째F).

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For 43xx0 the requirements; A.2.3.3.1 Compressor impellers UNS G43200 (formerly AISI 4320) and a modified version of UNS G43200 that contains 0.28 % mass fraction to 0.33 % mass fraction carbon are acceptable for compressor impellers at a maximum yield strength of 620 MPa (90 ksi) provided they have been heat-treated in accordance with the following three step procedure. a. Austenitize and quench. b. Temper at 620 째C (1 150 째F) minimum temperature, but below the lower critical temperature. Cool to ambient temperature before the second temper. c. Temper at 620 째C (1 150 째F) minimum, but lower than the first tempering temperature. Cool to ambient temperature.

NOTE: No hardness requirement?

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HRC 22

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A.2 SSC-resistant carbon and low-alloy steels and the use of cast irons NOTE 1 The carbon and low-alloy steels described/listed previously in NACE MR0175 (all revisions) were identified by extensive correlations of field failures/successes and laboratory data. The hardness limit of HRC 22 applied to most carbon and low-alloy steels is based on correlations of heat treatment, chemical composition, hardness and failure experience. The higher hardness limits for the chromium-molybdenum steels are based on similar considerations.

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22 HRC

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A.2.1.2 Parent metal composition, heat treatment and hardness Carbon and low-alloy steels are acceptable at 22 HRC maximum hardness provided they contain less than 1 % mass fraction nickel, are not freemachining steels and are used in one of the following heat-treatment conditions: a) hot-rolled (carbon steels only); b) annealed; c) normalized; d) normalized and tempered; e) normalized, austenitized, quenched, and tempered; f) austenitized, quenched, and tempered.

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A.2.1.4 Welding Carbon steel, carbon manganese and low-alloy steel weldments that do not comply with other paragraphs of this subclause shall be post weld heat treated after welding. The heat treatment temperature and its duration shall be chosen to ensure that the maximum weld zone hardness, determined in accordance with 7.3, shall be 250 HV or, subject to the restrictions described in 7.3.3, 22 HRC.

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Table A.1 â&#x20AC;&#x201D; Maximum acceptable hardness values for carbon steel, carbon-manganese steel and low-alloy steel welds

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A.2.1 General requirements for carbon and low alloy steels A.2.1.6 Cold deformation and thermal stress relief Carbon and low-alloy steels shall be thermally stress-relieved following any cold deforming by rolling, cold forging or other manufacturing process that results in a permanent outer fibre deformation greater than 5 %. Thermal stress relief shall be performed in accordance with an appropriate code or standard. The minimum stress-relief temperature shall be 595 Â°C (1 100 Â°F). The final maximum hardness shall be 22 HRC except for pipe fittings made from ASTM A234 grade WPB or WPC, for which the final hardness shall not exceed 197 HBW.

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A.2.2.3.4 If tubulars and tubular components are cold-straightened at or below 510 °C (950 °F), they shall be stress-relieved at a minimum temperature of 480 °C (900 °F). If tubulars and tubular components are cold-formed (pinnosed and/or box-expanded) and the resultant permanent outer fibre deformation is greater than 5 %, the cold-formed regions shall be thermally stress-relieved at a minimum temperature of 595 °C (1 100 °F). If the connections of high-strength tubulars with hardnesses above 22 HRC are cold-formed, they shall be thermally stress-relieved at a minimum temperature of 595 °C (1 100 °F).

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Stress-relieved At A Minimum Temperature

A. Cold-straightened - 480 °C (900 °F). B. Cold-formed (pin-nosed and/or box-expanded) and the resultant permanent outer fibre deformation is greater than 5 % - 595 °C (1 100 °F). C. Cold-formed- 595 °C (1 100 °F). (permanent outer fibre deformation?)

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A.2.3.2.2 Shear rams Rams manufactured in quenched and tempered Cr-Mo low-alloy steels (UNS G41XX0, formerly AISI 4IXX, and modifications) are acceptable if the hardness does not exceed 26 HRC. If the hardness of these alloys exceeds 22 HRC, careful attention shall be paid to chemical composition and heat treatment to ensure their SSC resistance. SSC testing, as agreed with the equipment user, shall demonstrate that the performance of the alloy meets or exceeds that of field proven material.

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26 HRC

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A.2.2.3 Downhole casing, tubing, and tubular components A.2.2.3.3 Tubulars and tubular components made of Cr-Mo low-alloy steels (UNS G41XX0, formerly AISI 41XX and modifications), if quenched and tempered in the tubular form, are acceptable if the hardness does not exceed 26 HRC. These products should be qualified by SSC testing in accordance with B.1 using the UT test. A.2.3.2.2 Shear rams Rams manufactured in quenched and tempered Cr-Mo low-alloy steels (UNS G41XX0, formerly AISI 4IXX, and modifications) are acceptable if the hardness does not exceed 26 HRC. If the hardness of these alloys exceeds 22 HRC, careful attention shall be paid to chemical composition and heat treatment to ensure their SSC resistance. SSC testing, as agreed with the equipment user, shall demonstrate that the performance of the alloy meets or exceeds that of field proven material.

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Fion Zhang/ Charlie Chong

NACE MR0175-Carbon Steel Written Exam NACE-MR0175-Carbon Steel -001 Exam Preparation Guide May 2017

Table of Contents Introduction .................................................................................................................................................. 3 Target Audience ........................................................................................................................................ 3 Requirements ............................................................................................................................................ 4 Exam Blue Print ............................................................................................................................................. 5 Types of Questions ........................................................................................................................................ 6 Description of Questions ........................................................................................................................... 6 Sample Questions ..................................................................................................................................... 6 Answer Key................................................................................................................................................ 6 Preparation ................................................................................................................................................... 7 Training ..................................................................................................................................................... 7 Reference Material ................................................................................................................................... 7 Books ......................................................................................................................................................... 7 Papers ....................................................................................................................................................... 7 Standards .................................................................................................................................................. 7 Other ......................................................................................................................................................... 7 Reference Material Provided During the Exam ............................................................................................. 7 Calculator ...................................................................................................................................................... 8

NACE- MR0175-Carbon Steel Written Exam NACE-MR0175-Carbon Steel -001 4 hours 50 Computer Based Testing (CBT) Pass/Fail

Target Audience An MR0175 Certified User-Carbon Steel is recognized as persons working in the following areas:      

User oil and gas production equipment Equipment designers Manufacturers, suppliers and purchasers Construction and maintenance contractors Equipment operators Industry regulators

Requirements MR0175-Carbon Steel

Requirements for MR0175- Carbon Steel: 1 Core Exam Work Experience Requirements: Two (2) years relevant experience (documented) and a degree in one of the following: metallurgy, material science, chemical engineer, applied chemistry, mechanical engineer, corrosion OR Five (5) years relevant experience, including 2 years of responsible charge. Core Exam Requirements The following exam is required: MR0175 Carbon Steel Written Exam

Certification Application is required - An application must be submitted prior to taking the examination to allow time for NACE to verify work experience requirements. The application is subject to approval. Certification renewal requirements – Recertification application* required every 3 years – including the following:   

A minimum of 1.5 years of Carbon Steel sour service work experience A completed re-certification application (subject to approval) A minimum of 20 Professional Development hours (PDHs) per year/60 PDHs every 3 years.

Upon successful completion of all requirements, the candidate will be awarded a MR0175 Certified User Carbon Steel. *Approval required

Knowledge and Skills Areas Tested DOMAIN 1.

2. 3.

4. 5.

9. 10.

Understanding the significance of sour service, and the roles and responsibilities for the selection of materials for use under such conditions. Evaluation, & definitions of service conditions to enable materials selection Understanding how personnel work together: purchasing, project engineers, consulting, and others to consider all factors in materials selection, to define roles and responsibilities with respect to information gathering evaluation, and execution of materials selection Basic understanding of the materials types included in the standard Understanding and demonstrating compliance with metallurgical properties that govern the behavior of materials in H2S containing environments Understanding the significance of changes to materials brought about by fabrication on their resistance to H2S, and their measurement. Basic Understanding of the oil/gas equipment/components included in the standard Understanding/auditing the process of materials selection for sour service using the standard Basic understanding of laboratory testing methods Applying the standard to respond to case studies similar to those provided in the examination's study resources

Percent of Items 16 - 20 %

16 - 20 % 8 - 12 %

8 - 12 % 2-6%

14 - 18 %

1-5% 4-8% 10 - 14 % 2-6%

Types of Questions Description of Questions The questions on this exam are multiple-choice and based on the knowledge and skills required in the industry for a certified user of the MR0175 Standard- Carbon Steel. While the NACE MR0175 Seminar is an excellent method of preparation, it is strongly recommended but not required. The primary reference used in the development of the questions is the MR0175 Standard. Additional references can be found in the Reference section . Sample Questions The sample questions are included to illustrate the formats and types of questions that will be on the exam. Your performance on the sample questions should not be viewed as a predictor of your performance on the actual test. 1. You urgently need a replacement carbon steel valve to handle a sour fluid. You are offered a wrought steel valve with 0.020% sulphur from one supplier and a cast one with 0.026% sulphur from another. Both have hardness below 22HRC, but neither has been HIC tested. What is the position of the standard about accepting these two valves? a. Neither wrought nor cast is acceptable b. Wrought is not acceptable but cast is acceptable c. Wrought is acceptable but cast is not acceptable d. Both are acceptable 2. You require an ESP pump to handle a sour fluid containing 12kPa H2S and 100g/L chloride at 70°C. You are offered a pump with an alloy K-500 (UNS N05500) shaft. Which statement below best represents the position of the standard? a. UNS G41420 steel that has been cold straightened, stress relieved at 620°C and has a hardness of 321 Brinell. b. UNS G41420 steel that has been cold straightened, stress relieved at 460°C and has a hardness of 26 HRC. c. UNS G41400 steel that has been cold straightened, stress relieved at 605°C and has a hardness of 26 HRC. d. UNS G51400 steel that has been cold straightened, stress relieved at 605°C and has a hardness of 24 HRC. e. UNS G41400 steel that has a flush joint connection that has been cold formed with about 8% cold work, stress relieved at 575°C and has a hardness of 26 HRC. Answer Key 1. D Reference: Section 8 2. C Reference: Table A.2.2.3

Preparation Training (Strongly Recommended) One day NACE MR0175 Workshop Designed to help you and your company prevent corrosion stress cracking in H2S containing oil production environments, attend a NACE MR0175/ISO 15156 One-Day Seminar to understand how the standard can be implemented to improve the quality of your companyâ&#x20AC;&#x2122;s assets and what you can do to comply with the standard. NACE Internationalsâ&#x20AC;&#x2122; MR0175/ISO 15156 is the premier standard to reference in combatting corrosion cracking through material selection and qualification and the seminar is for anyone from entry level to experienced oil production professionals to gain a thorough knowledge of this globally mandated standard.

Suggested Study Material NACE MR0175/ISO 15156 Standard EFC 17 NACE TM0177 NACE TM0198 NACE TM0316

Books Introductory Handbook for NACE MR0175

Other Materials Performance inquires and answers (see NACE website) http://www.nace.org/resources/magazines-and-journal/

Reference Material Provided During the Exam MR0175 Standard/ISO 15156 Standard (electronic)

Add Calculator here please.

technical monograph 34 Sulfide Stress Cracking and the Commercial Application of NACE MR0175-84 Mark Adams Senior Product Manager

James L. Gossett Technical Consultant, Materials

Fisher Controls

Sulfide Stress Cracking and the Commercial Application of NACE MR0175-84 Mark Adams Senior Product Manager James L. Gossett Technical Consultant, Materials

The NACE Standard MR0175, "Sulfide Stress Corrosion Cracking Resistant Metallic Materials for Oil Field Equipment'' is widely used throughout the world. The standard specifies the proper materials, heat treat conditions and strength levels required to provide good service life in sour gas and oil environments. NACE International (formerly the National Association of Corrosion Engineers) is a worldwide technical organization which studies various aspects of corrosion and the damage that may result in refineries, chemical plants, water systems and other types of industrial equipment. MR0175 was first issued in 1975, but the origin of the document dates to 1959 when a group of engineers in Western Canada pooled their experience in successful handling of sour gas. The group organized as NACE committee T-1B and in 1963 issued specification 1B163, "Recommendations of Materials for Sour Service.'' In 1965, NACE organized the nationwide committee T-1F-1 which issued 1F166 in 1966 and MR0175 in 1975. The specification is now revised on an annual basis. NACE committee T-1F-1 continues to have responsibility for MR0175. All revisions and additions must be unanimously approved by the 500 plus member committee T-1, Corrosion Control in Petroleum Production. MR0175 is intended to apply only to oil field equipment, flow line equipment and oil field processing facilities where H2S is present. Only sulfide stress cracking (SSC) is addressed. Users are advised that other forms of failure mechanisms must be considered in all cases. Failure modes, such as severe general corrosion, chloride stress corrosion cracking, hydrogen blistering or step-wise cracking are outside the scope of the document. Users must carefully consider the process conditions when selecting materials. While the standard is clearly intended to be used only for oil field equipment, industry has taken MR0175 and applied it to many other areas including refineries, LNG plants, pipelines and natural gas systems. The judicious use of the document in these applications is constructive and can help prevent SSC failures wherever H2S is present. The various sections of MR0175 cover the commonly available forms of materials and alloy systems. The requirements for heat treatment, hardness levels, conditions of mechanical work and post-weld heat treatment are addressed for each form of material. Fabrication techniques, bolting, platings and coatings are also addressed. Figures 1 and 2 taken from MR0175 define the sour systems where SSC may occur. Low concentrations of H2S at low pressures are considered outside the scope of the document. The low stress levels at low pressures or the inhibitive effects of oil may give satisfactory performance with standard commercial equipment. Many users, however, have elected to take a conservative approach and specify NACE compliance any time a measurable amount of H2S is present.

GRAINS H2S PER 100 SCF 1

10,000

100

1000

0. 05 PS IA PA TI A L PR ES SU R E

TOTAL PRESSURE, PSIA

1000

SULFIDE STRESS CRACKING REGION

100

265 PSIA TOTAL PRESSURE

10 .0001

.001

.01

100

MOL% H2S IN GAS PPM H2S IN GAS

1000

10,000

100,000

Fig. 1: Sour gas systems (see Paragraph 1.3.1). GRAINS H2S PER 100 SCF 1

10,000

100

1000

0. 05 PS IA PA

SULFIDE STRESS CRACKING REGION

TI A L PR ES SU R E

265 PSIA TOTAL PRESSURE

100

L A TI R PA RE IA SU PS ES 10 PR

TOTAL PRESSURE, PSIA

1000

15% H2S

10 .0001

.001

.01

100

MOL% H2S IN GAS PPM H2S IN GAS

1000

10,000

100,000

Fig. 2: Sour multiphase systems (see Paragraph 1.3.2). The decision to follow MR0175 must be made by the user based on economic impact, the safety aspects should a failure occur and past field experience. Legislation can impact the decision as well. MR0175 must now be followed by law for sour applications under several jurisdictions; Texas (Railroad Commission), off-shore (under U.S. Minerals Management Service) and Alberta, Canada (Energy Conservation Board).

The Basics of Sulfide Stress Cracking SSC develops in aqueous solutions as corrosion takes place on the surface of a material. Hydrogen ions are a product of many corrosion processes (Figure 3). These ions pick up electrons from the base material producing hydrogen atoms. At that point, two hydrogen atoms may combine to form a hydrogen molecule. Most molecules will eventually collect, form hydrogen bubbles and float away harmlessly. However, some percentage of the hydrogen atoms will diffuse into the base metal and embrittle the crystalline structure. When a certain critical concentration of hydrogen is reached and combined with a tensile stress exceeding a threshold level, SSC will occur. H2S does not actively participate in the SSC reaction; however, sulfides act to promote the entry of the hydrogen atoms into the base material. In many instances, particularly among carbon and low alloy steels, the cracking will initiate and propagate along the grain boundaries. This is called intergranular stress cracking. In other alloy systems or under certain specific conditions, the cracking will propagate through the grains. This is called transgranular stress corrosion cracking. Sulfide stress cracking is most severe at ambient temperature, particularly in the range of 20 to 120°F (-7 to 49°C). Below 20°F (-7°C) the diffusion rate of the hydrogen is so slow that the critical concentration is never reached. Above 120°F (49°C) the diffusion rate is so fast that the hydrogen passes through the material in such a rapid manner that again the critical concentration is not reached. The occurrence of stress corrosion cracking above 120°F (49°C), however, is still very likely and must be very carefully considered when selecting materials. In most cases, however, the stress corrosion cracking will not be SSC but some other form. Chloride stress corrosion cracking is likely in deep sour wells as most exceed 300°F (149°C) and contain significant chloride levels. The susceptibility of a given type of material to SSC is directly related to its strength or hardness level. This is true for carbon steels, stainless steels and nickel base alloys. As an example, when carbon or alloy steel is heat treated to progressively higher hardness levels, the time to failure decreases rapidly for a given stress level (See Figure 4). Years of field experience have shown that good SSC resistance is obtained below 22 HRC for the carbon and low alloy steels. SSC can still occur below 22 HRC, but the likelihood of failure is greatly reduced.

Carbon Steel Carbon and low alloy steels have acceptable resistance to SSC provided their processing is very carefully monitored. The hardnesses must be less than 22 HRC. If welding or significant cold working is done, stress relief is required. Even though the base metal hardness of a carbon or alloy steel is less than 22 HRC, areas of the heat effected zone will be harder. Post-weld heat treatment will eliminate these excessively hard areas. ASME SA216 grades WCB and WCC and ASME SA105 are the most commonly used body materials. It is Fisher's policy to stress relieve all welded carbon steels that are supplied to MR0175. ASME SA352 grades LCB and LCC are very similar to WCB and WCC. They are impact tested at -50°F (-46°C) to insure good toughness in low temperature service. LCB and LCC are used in the northern U.S., Alaska and Canada where temperatures commonly drop below the -20°F (-32°C) permitted for WCB. All welded LCB and LCC castings to MR0175 are also stress relieved.

H H

S-2

H H+

H H H M

M+

H+

H e-

S-2 +

H+

S-2

H+

BOLT FAILURES IN CUMULATIVE PERCENT

Fig. 3: Schematic showing the generation on entry of hydrogen producing SSC. 100 80 60 40 20 0

100

1,000

10,000

TIME TO FAILURE IN HOURS RANGE OF BOLT HARDNESS Rc 55-57 Rc 39-43 Rc 34-38 Rc 27-33

Fig. 4: Effect of hardness on time to failure of AISI 4140 steel bolts in H2S + water at 104Â°F and 250 PSI Cast Iron Gray, austenitic and white cast irons cannot be used for any pressure retaining parts, due to low ductility. Ferritic ductile iron to ASTM A395 is acceptable when permitted by ANSI, API or other industry standards.

Stainless Steel UNS S41000 (410 stainless steel SST) and other martensitic grades must be double tempered to a maximum allowable hardness level of 25 HRC. Post-weld heat treatment is also required. S41600 (416 SST) is similar to S41000 (410) with the exception of a sulfur addition to produce free machining characteristics. Use of free machining steels is not permitted by MR0175.

CA6NM is a modified version of the cast S41000 stainless steel. MR0175 allows its use, but specifies the exact heat treatment required. Generally, the carbon content must be restricted to 0.3% maximum to meet the 23 HRC maximum hardness. Post-weld heat treatment is required for CA6NM. The austenitic stainless steels have exceptional resistance to SCC in the annealed condition. The standard specifies that these materials must be 22 HRC maximum and free of cold work to prevent SSC. The cast and wrought equivalents of 302, 304, 304L, 305, 308, 309, 310, 316, 316L, 317, 321, 347 and N08020 (alloy 20) are all acceptable per MR0175. Post-weld heat treatment of the 300 Series SST is not required. The corrosion resistance may be affected by welding. However, this can be controlled by using the low carbon grades, or low heat input levels and low interpass temperatures. Wrought S17400 (17-4PH) stainless steel is allowed, but must be carefully processed to prevent SSC. The standard now gives two different acceptable heat treatments for S17400. One treatment is the double H1150 heat treatment which requires exposing the material at 1150°F (621°C) for four hours followed by air cooling and then exposing for another four hours at 1150°F (621°C). A maximum hardness level of 33 HRC is specified. The second heat treatment is the H1150M treatment. First, the material is exposed to two hours at 1400°F (760°C), then air cooled and exposed for four hours at 1150°F (621°C). The maximum hardness level is the same for this condition. CB7Cu-1 (Cast 17-4PH) in the double H1150 condition is approved per MR0175 for internal valve and regulator components. Many users have successfully applied it for trim parts in past years. Two high strength stainless steel grades are acceptable for MR0175. The first is S66286 (grade 660 or A286) which is a precipitation hardening alloy with excellent resistance to SSC and general corrosion. The maximum hardness level permitted is 35 HRC. The second material is S20910 (XM-19) which is commonly called Nitronic 50. This high strength SST has excellent resistance to SSC and corrosion resistance superior to S31600 or S31700. The maximum allowable hardness is 35 HRC. The "high strength'' condition, which approaches 35 HRC, can only be produced by hot working methods. Cold drawn S20910 is also acceptable for shafts, stems and pins. It is our experience that the SSC resistance of S20910 is far superior to S17400 or other austenitic stainless steels at similar hardness levels. The only other materials with similar stress cracking resistance at these strength levels are the nickelbased alloys which are, of course, much more expensive. A few duplex stainless steels are now acceptable per MR0175. Wrought S31803 (2205) and S32550 (Ferralium 255) are both acceptable to 28 HRC. Wrought S32404 (Uranus 50) is acceptable to 20 HRC. Only one cast duplex SST is acceptable for unrestricted application, alloy Z 6CNDU20.08M, NF A 320-55 French National Standard. Fisher has supplied valves cast in this material. Other duplex stainless steels are also acceptable, however, there are several environmental restrictions. Wrought duplex stainless steel UNS S32760 (Zeron 100) is acceptable in the solution-annealed and cold-worked condition at a maximum hardness of 34 HRC. The cast version UNS J93380 (or CD3MWCuN) is acceptable in the solution-annealed and quenched condition at a maximum hardness of 24 HRC. Both are restricted for use in sour environments containing up to 120,000 mg/l chloride ion if the partial pressure of H2S does not exceed 0.020 MPa (3.0 psi). If the chloride ion concentration is always less than 15,000 mg/l and the pH of the aqueous phase is always greater than 5.6, then this material condition is acceptable if the partial pressure of H2S does not exceed 0.10 MPa (15 psi)

Nonferrous Alloys The final category in MR0175 is the nonferrous materials section. In general, the nickel-base alloys are acceptable to a maximum hardness level of 35 HRC. All have excellent resistance to SSC. Commonly used acceptable materials include nickel-copper alloys N04400 (alloy 400), M35-1 and M35-2 (cast alloy 400) and N04405 (alloy 405) and the precipitation hardening alloy N05500 (K500). The nickel-iron-chromium alloys include alloys N06600 (alloy 600) and N07750 (alloy X750). The acceptable nickel-chromium-molybdenum alloys include alloys N06625 (alloy 625), N10276 (alloy C276) and CW2M (Fisher’s standard cast alloy C). The precipitation hardening grade N07718 (alloy 718) is also acceptable to 40 HRC. Where high strength levels are required along with good machinability, Fisher uses N05500, N07718, N07750 or N07725 (alloy 725). They can be drilled or turned, then age hardened. Several cobalt base materials are acceptable, including R30035 (alloy MP35N), R30003 (Elgiloy) and R30605 (Haynes 25 or L605). Aluminum base and copper alloys may be used for sour service, but the user is cautioned that severe corrosion attack may occur on these materials. They are seldom used in direct contact 2 with H S. Several wrought titanium grades are now included in MR0175. The only common industrial alloy is wrought R50400 (grade 2). Cast titanium is not included in MR0175.

Springs Springs in compliance with NACE represent a difficult problem. To function properly, springs must have very high strength (hardness) levels. Normal steel and stainless steel springs would be very susceptible to SSC and fail to meet MR0175. In general, very soft, low strength materials must be used. Of course, these materials produce poor springs. The two exceptions allowed are the cobalt based alloys, such as R30003, which may be cold worked and hardened to a maximum hardness of 60 HRC and alloy N07750 which is permitted to 50 HRC.

Coatings Coatings, platings and overlays may be used provided the base metal is in a condition which is acceptable per MR0175. The coatings may not be used to protect a base material which is susceptible to SSC. Coatings commonly used in sour service are chromium plating, electroless nickel (ENC) and nitriding. Overlays and castings commonly used include CoCr-A (Stellite or alloy 6), R30006 (alloy 6B), and NiCr-C (Colmonoy 6) nickel-chromium-boron alloys. Tungsten carbide alloys are acceptable in the cast, cemented or thermally sprayed conditions. Ceramic coatings such as plasma sprayed chromium oxide are also acceptable. ENC is often used by Fisher as a wear resistant coating. As required by MR0175, it is applied only to acceptable base metals. ENC has excellent corrosion resistance in sour, salt containing environments.

Stress Relieving Many people have the misunderstanding that stress relieving following machining is required by MR0175. Provided good machining practices are followed using sharp tools and proper lubrication, the amount of cold work produced is negligible. SSC resistance will not be affected.

MR0175 actually permits the cold rolling of threads, provided the component will meet the heat treat conditions and hardness requirements specified for the given parent material. Cold deformation processes such as burnishing are also acceptable.

Bolting Bolting materials must meet the requirements of MR0175 when bolting is directly exposed to a sour environment. Standard ASTM A193 grade B7 bolts or A194 grade 2H nuts can be used per MR0175 provided they are outside of the sour environment. If the bolting will be deprived atmospheric contact by burial, insulation or flange protectors, then grades of bolting such as B7 and 2H are unacceptable. The most commonly used fasteners for "exposed'' applications are ASTM A193 grade B7M bolts and A194 grade 2M nuts. They are tempered and hardness tested versions of the B7 and 2H grades. HRC 22 is the maximum allowable hardness. Many customers use only B7M bolting for bonnet, packing box, and flange joints. This reduces the likelihood of SSC if a leak develops and goes undetected or unrepaired for an extended time. It must be remembered, however, that use of lower strength bolting materials such as B7M often requires pressure vessel derating. Fisher offers special S17400 double H1150 bolting at the full B7 rating to overcome the derating problem.

Bolting Coatings ENC coating is acceptable on pressure-retaining and non-pressure-retaining fasteners. For some reason, there is often confusion regarding the acceptability of zinc plated fasteners per NACE MR0175. NACE MR0175 does not preclude the use of any coating, provided it is not used in an attempt to prevent sulfide stress cracking of an otherwise unacceptable base material. However, zinc plating of pressure-retaining bolting is not recommended by Fisher Controls due to metal-induced embrittlement concerns.

Composition Materials MR0175 does not address elastomer and polymer materials. However, the importance of these materials in critical sealing functions cannot be over-looked. User experience has been successful with elastomers such as nitrile, neoprene and the fluoro- and perfluoroelastomers. In general, fluoropolymers such as TFE can be applied without reservation within their normal temperature range.

Codes and Standards Applicable ASTM, ANSI, ASME and API standards are used along with MR0175 as they would normally be used for other applications. The MR0175 requires that all weld procedures be qualified to these same standards. Welders must be familiar with the procedures and capable of making welds which comply.

The Commercial Application of NACE Special documentation of materials to MR0175 is not required by the standard and NACE itself does not issue any type of a certification. It is the producers responsibility to properly monitor the materials and processes as required by MR0175.

It is not uncommon for manufacturers to "upgrade'' standard manufactured components to MR0175 by hardness testing. This produces a product which complies with MR0175, but which may not provide the best solution for the long-term. If the construction was not thoroughly recorded at the outset, it may be difficult to get spare parts in the proper materials. The testing necessary to establish that each part complies is quite expensive. And, due to the "local'' nature of a hardness test, there is also some risk that "upgraded'' parts do not fully comply. With proper in-house systems, it is quite simple to confidently produce a construction which can be certified to MR0175 without the necessity of after manufacture testing. This eliminates many cost extras and additionally provides a complete record of the construction for future parts procurement. An order entry, procurement and manufacturing system which is integrated and highly structured is required in order to confidently and automatically provide equipment which complies. Due to its hierarchical nature and its use by all company functions, the Fisher system is ideal for items such as MR0175 which requires a moderate degree of control without undue cost. In order to illustrate the system used by Fisher, an example will be used. Most products produced by Fisher (including products to MR0175) will be specified by a Fisher Standard (FS) number. These numbers (e.g. FSED-542) completely specify a standardized construction including size, materials and other characteristics. The FS number is a short notation which represents a series of part groups (modules) describing the construction. One module may represent, for instance, a 3'' WCC valve body with ANSI Class 300 flanges, another may specify a certain valve plug and seat ring. The part numbers which make up these modules are composed of a drawing number and a material/finish identifier. The drawing describes the dimensions and methods used to make the part while the material/finish reference considers material chemistry, form, heat treatment and a variety of other variables. The part number definition also includes a very specific "material reference number'' which is used to identify a material specification for purchase of materials. The material specification includes the ASME designation as well as additional qualifiers as necessary to assure compliance with specifications such as NACE MR0175 (see Figure 5). For NACE compliant products an FS number and a NACE option are generally specified. The FS number establishes the standard construction variation. The option modifies the construction and materials to comply totally with MR0175 requirements. The option eliminates certain standard modules and replaces them with NACE suitable modules. Each part in a NACE suitable module has been checked to assure that it complies to the specification in form and manufacturing method and that it is produced from an appropriate material. It is due to this top to bottom system integrity that Fisher can be confident of MR0175 compliance without the need for extensive test work. At each level of the system documentation, there are specific references to and requirements for compliance to MR0175. Further, since the construction is permanently documented at all levels of detail, it is possible to confidently and simply procure spare parts at any future date. Test documentation is available in a variety of forms, including certificates of compliance, hardness test data, chemical and physical test reports and heat treat reports. Since these items will have some cost associated with them, it is important to examine the need for documentation in light of the vendors credibility and his manufacturing control systems. Fisher's normal manufacturing processes and procedures assure that all NACE specified products will comply without the need for additional test expense. Fisher has been producing equipment for a variety of sour conditions and specifications since the mid-1950's and have thousands of devices in service. MR0175 has been shown to be an excellent technical reference for solving the complex application problems found in the handling of sour fluids. As more sour hydrocarbons are produced, it grows in importance and applicability.

UNS Numbers AWS 5.13

Material Designation or Tradename CoCr-A Stellite 6 Alloy 6

Hastelloy C Alloy C CW12MW CW2M

N10276

Hastelloy C276

A-286 Grade 660

R05200

Commercially Pure Tantalum

Monel 400 Alloy 400 M35-1 M35-2

R30003

Elgiloy

R30004

Havar

R30035

MP35N

R30260

Duratherm 2602

R30605

L605 Haynes Alloy 25

R50400

Titanium Grade 2 RMI 40 Ti-50A ALSMet Gr 2 Cabot Ti-40

R53400

Grade 12 Ti Code-12

R56260

RMI 6A1-2Sn-4Zr-6Mo Alpha-Beta

R58640

Beta Ti Ti-38-6-44 Ti-3A1-8V-6Cr-4Zr-4Mo

S15700

PH15-7Mo 15-7Mo

NiCr-C Colmonoy 6

British Standard Aerospace Series HR3

Nimonic 105

K66286 (now S66286) N04400

N05500

N09925

Material Designation or Tradename Incoloy 925 Alloy 925

N10002 AWS 5.13

N04405

UNS Numbers

Monel R405 R Monel Alloy R405 Monel K500 K Monel K500

N06002

Hastelloy X Pyromet Alloy 680

N06007

Hastelloy G

N06110

Allcorr

N06600

Inconel 600 Alloy 600 CY40

N06625

Inconel 625 Alloy 625 CW6MC

N06985

Hastelloy G-3

N07031

Pyromet 31

S20910

N07718

Inconel 718 Alloy 718 Pyrotool 7

Nitronic 50 22Cr-13Ni-5MN ASTM Grade XM19

S17400

17-4PH Custom 630

Inconel X750 Alloy X750

S45000

Custom 450

S20910 ASTM Grade XM19

Nitronic 50 22Cr-13Ni-5MN

S31803 DIN 1.4462

SAF2205 2205

S32550

Ferralium Alloy 255

S45000

Custom 450

Z6CNDU20.08M

Uranus 50M

N07750

N08020

Carpenter 20Cb-3 Alloy 20 Duromet 20 CN7M

N08028

Sanicro 28

N08800

Incoloy 800 Alloy 800

N08825

Incoloy 825 Alloy 825

Fig. 5: Fisher material purchase specification citing compliance to NACE MR0175 in addition to other standard parameters.

The contents of this publication are presented for informational purposes only, and while every effort has been made to ensure their accuracy, they are not to be construed as warranties or guarantees,express or implied, regarding the products or services described herein or their use or applicability. We reserve the right to modify or improve the designs or specifications of such products at any timewithout notice. ÂŠ Fisher Controls International, Inc. 1999; All Rights Reserved Fisher, Fisher-Rosemount, and Managing The Process Better are marks of the Fisher-Rosemount Group of companies. All other marks are the property of their respective owners.

Fisher Controls International, Inc. 205 South Center Street Marshalltown, Iowa 50158 Phone: (641) 754-3011 Fax: (641) 754-2830 Email: fc-valve@frmail.frco.com Website: www.fisher.com D350412X012 / Printed in the U.S.A./8-99

Paper No.

06121 MATERIALS DESIGN STRATEGY: EFFECTS OF H2S/CO2 CORROSION ON MATERIALS SELECTION Bijan Kermani, KeyTech, Camberley, UK John Martin, BP Exploration, Sunbury on Thames, UK Khlefa Esaklul, BP Kuwait, Kuwait

ABSTRACT Corrosion remains a key obstacle to sustaining operational success in hydrocarbon production. Its continued occurrence affects the economy and has consequences for the safety of people and integrity of facilities. A central element in the design of facilities and corrosion mitigation is the correct choice and deployment of materials which are both economical and suitable to provide satisfactory performance over the design life. This paper captures the current understanding of corrosion mechanisms in the combined presence of H2S and CO2 acidic gases and discusses a systematic approach to materials design strategy for hydrocarbon production systems. The paper does not deal with the important environmental cracking aspects associated with sour service, but rather concentrates purely on metal loss degradation process. The combination of H2S and CO2 modifies the corrosion characteristics significantly as compared to damage caused in the sole presence of CO2 or H2S. An H2S/CO2 ratio is introduced to indicate the trends governing corrosion mechanism, i.e. dominated by CO2, H2S or a mixed mode of damage. A simple guideline has been produced offering a rule of thumb in addressing respective corrosion damages. Keywords:

Carbon and Low Alloy Steels, Corrosion, Integrity Management, Materials Selection Strategy, Production, Sour Service, Sweet Corrosion. INTRODUCTION

Corrosion in hydrocarbon systems manifests itself in several forms amongst which CO2 corrosion (sweet corrosion), H2S corrosion (sour corrosion) in the production systems and oxygen corrosion in water injection systems are by far the most prevalent forms of attack [1]. The environmental sensitive cracking damage caused by H2S and consequent materials optimisation are other very important aspects in these systems, but these are already covered in detail elsewhere [2, 3]. Corrosion in water injection systems is also outside the scope of the present overview. An Copyright ÂŠ2006 NACE International. Requests for permission to publish this manuscript in any form, in part or in whole must be in writing to NACE International, Conferences Division, 1440 South Creek Drive, Houston, Texas 77084. The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association. Printed in the U.S.A.

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additional key element affecting corrosion is the presence of elemental sulfur in the production stream, which is again beyond the scope of the present paper. The majority of oilfield failures result from CO2 corrosion of carbon and low alloy steels (CLASs), primarily due to inadequate knowledge/predictive capability and the poor resistance of carbon steels to this type of attack [1]. Its understanding, prediction and control are key challenges to sound facilities design, operation and subsequent integrity assurance. Extensive research over the past five decades has focused on the mechanistic and engineering understanding of CO2 corrosion of CLASs, with a view to develop a realistic model to predict its occurrence. These are broadly covered in a review elsewhere [1]. Despite this, the majority of existing quantitative models remain unreliable in predicting the actual long-term CO2 corrosion rate of CLASs [1]. The anomalies are attributed to "field artefacts" with no clear indication of the cause. One key cause of the difference is now attributed to the effects of organic acid [4,5] a chemical normally ignored by many. An added complication is the presence of H2S which in turn affects potential corrosivity, insitu pH and interferes with the formation of corrosion product. This review article captures the current understanding and means of dealing with H2S in CO2 corrosion evaluations for CLASs in hydrocarbon production. It provides information on the mechanisms, highlights key parameters affecting the complementary influence of the two acid gases and draws attention to areas requiring further research. The primary focus has been placed on two key parameters affecting CO2 corrosion in the presence of H2S including (i) the nature of the surface film and (ii) development of an engineering guide for dealing with the risk of H2S-CO2 corrosion in production conditions. A brief overview of the specific material choice route for different production areas is provided within the context of a materials design strategy. The review has highlighted key areas of progress and has drawn attention to the future direction of research and development to enable improved and economical design of facilities for oil and a gas production. Background Both CO2 and H2S are acid gases that when produced with the hydrocarbon phase can render the associated water (condensed or formation) corrosive and lead to severe degradation. Corrosion resulting from each of these two acidic gases has its unique characteristics and, as a result, has received considerable industry attention, both to understand the corrosion mechanisms associated with the particular acid gas and the options available to mitigate the resulting corrosion [1-9]. Each of these gases occurs naturally in some of the producing reservoirs or may result from external contamination of the reservoir, such as the case of reservoir souring that may result when seawater is injected for secondary recovery or the use of gas injection for reservoir pressure maintenance. Selection of materials to combat corrosion relies mainly on the type of corrosion anticipated (e.g. whether general or localised [pitting]), the confidence in predicting the rate and type of corrosion, risk of failure and life cycle cost. While the primary concern in selection of materials in H2S containing systems is the sulfide stress cracking (SSC), the issue of corrosion should not be underestimated. SSC and other forms of cracking in H2S containing environments are well understood [2,3] and are not covered in this review. The focus of this paper is on the wastage corrosion in the combined presence of H2S and CO2. Relative Corrosiveness of CO2 and H2S and O2 While the respective corrosion mechanisms of the two acid gases prevailing in hydrocarbon systems, plus oxygen that can occur as a contaminant, are vastly different, a simple comparison under specific conditions was presented by Jones [10]. This is shown in Figure 1. The data are based on corrosion rates measured and computed by exposing clean carbon steel samples to water solutions containing various concentrations of each gas at 25oC. It has been claimed that these rates compare favourably with field data [10]. It is important to note that the synergistic effects of these gases are extremely influential in materials design and a point of consideration. A simple addition of respective damage rates does not necessarily lead to the overall damage as the complementary process is very complex. Furthermore, such a simple correlation does not bear in mind localised type of attack wherein the damage rate can be significantly higher than the overall

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rate. However, the information provides a general idea of comparative corrosiveness of the three important gases at low temperature. TYPES OF CORROSION DAMAGE This section refers to the types of damage encountered in hydrocarbon production systems in CO2 only, H2S only and mixed CO2-H2S containing conditions. CO2 Containing Streams CO2 is usually present in produced fluids and although it does not generally by itself cause the catastrophic failure mode of cracking associated with H2S [2,3] its presence in contact with an aqueous phase can nevertheless result in very high corrosion rates, especially where the mode of attack is localised (e.g. mesa corrosion) [1]. CO2 Corrosion occurs primarily in the form of general corrosion and three variants of localised corrosion, i.e. pitting, mesa attack and flow-induced localised corrosion [1,11]: x x

Pitting corrosion normally occurs under relatively stagnant conditions (around the dew point for gas systems) – there are no certain rules to predict when such attack will occur. Mesa attack is a form of localised corrosion occurring under low to medium flow conditions (resulting from the localized removal of the protective carbonate film) – attack showing a large flat attack bottom steps with sharp edges– excessive rates at these areas occurs around temperature where carbonate can form but not stable Flow induced localised corrosion occurring at high flow conditions - corrosion takes the form of pits at sites of highly turbulent flow (often considered a form of erosion-corrosion)

CO2 corrosion is influenced by a number of parameters including environmental, physical and metallurgical variables [1]. The majority of these have been extensively covered by a number of authors and captured elsewhere [1,11]. Notable parameters affecting CO2 corrosion include: x

Fluid make-up as affected by water chemistry, organic acids, pH, water wetting, hydrocarbon characteristics and phase ratios

CO2 and H2S content (and possible oxygen contaminants)

Temperature

Steel surface including corrosion film morphology, presence of wax and ashphaltene

Fluid dynamics

Steel chemistry

All parameters are interdependent and can interact in many ways to influence CO2 corrosion as described elsewhere [1]. H2S Containing Streams; The Mechanism H2S results in a weak acid when dissolved in water. It affects CLASs in a similar manner to that of CO2 with all influential parameters outlined earlier for CO2 corrosion affecting its process and mechanism. The type of damage caused by H2S appears in the form of localised corrosion or general corrosion, depending upon the type and nature of corrosion product formed. H2S corrosion has been claimed to be strongly dependent on chloride ion concentration with severe damage rate in some situations, although the presence of other corrosive agents and fluid chemistry on this rate of degradation is unknown [12-15]. The corrosion reaction often leads to the formation of iron sulfide (FeS) scales, which under certain conditions are highly protective. However, their breakdown (i.e. under turbulent flow conditions) can lead to very severe localised corrosion in a similar manner to that for FeCO3 breakdown in the case of CO2 corrosion [1]. The kinetics and nature of FeS film formation, stability and its contribution to reducing corrosion are key to affording protection. Also, like CO2 corrosion, the corrosion rate is affected by fluid chemistry, organic acids and flow velocity in addition to the presence of elemental sulfur [13].

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The ability of H2S to affect acidity is indicated by its ionisation as follows [11]: H2S Äź H+ + HS-

(1)

As the H is removed through cathodic reaction of hydrogen reduction, more is formed and hydrogen gas readily appears on steels exposed to oxygen free water containing H2S as follows: 2H+ + 2e Äş 2H (atomic hydrogen) Äş H2 (molecular hydrogen) (2) The anion (HS-) dissociates further to S2- and H+. The S2- ion reacts with iron to form the black FeS corrosion product commonly found in service. H2 may not be present in the bulk solution, but it forms locally within the corrosion layer as a cathodic corrosion product diffusing from its electrochemical production at the metal surface to its final dispersion in the bulk at the outer surface [16]. Mixed H2S/CO2 Containing Streams Ignoring the environmental sensitive cracking aspects of corrosion problems associated with sour service, low levels of hydrogen sulfide can affect CO2 corrosion in different ways. H2S can either increase CO2 corrosion by acting as a promoter of anodic dissolution through sulfide adsorption and affecting the pH or decrease sweet corrosion through the formation of a protective sulfide scale. The exact interaction of H2S on the anodic dissolution reactions in the presence of CO2 is not fully understood [1]. For similar conditions, oil and gas installations could experience lower corrosion rates in sour conditions compared to completely sweet systems. This is due to the fact that the acid created by the dissolution of hydrogen sulfide is about 3 times weaker than that of carbonic acids, but H2S gas is about 3 times more soluble in hydrocarbon phase than CO2 gas. As a result the effect of both CO2 and H2S gases on lowering the solution pH and potentially increasing corrosion rate are fundamentally the same. In addition, hydrogen sulfide may play a significant role on the type and properties of the corrosion films, improving or undermining them [1,11]. Many papers have been published on the interaction of H2S with CLASs. However, literature data on the interaction of H2S and CO2 is still limited since the nature of the interaction is highly complex. The majority of open literature indicates that CO2 corrosion rate is reduced in the presence of H2S at ambient temperatures. Nevertheless, it must be emphasised that H2S may also form a non-protective layer and that it may catalyse the anodic dissolution of bare steel [45]. Steels may experience some form of rapid, localised corrosion in the presence of H2S, although very little information is available. Published laboratory work has proved inconclusive, indicating that there is a need to carry out further studies in order to clarify the mechanism. In spite of the work on H2S corrosion of steels, no equations or models are available to predict corrosion, as is the case for CO2 corrosion of steels [1,11]. As a general rule in CO2 containing environments the presence of H2S can [1,16,45]: x

Increase the corrosion risk by either: o

facilitating localised corrosion, at a rate greater than the general metal loss or localised rate expected from CO2 corrosion, or

preferentially forming an FeS corrosion product that is less protective than an iron carbonate corrosion product

Decrease the corrosion risk by promoting the formation of an FeS corrosion product film through either o

replacing a less protective iron carbonate film, or

forming a combined protective layer of iron sulphide and iron carbonate

In the presence of both acid gases the corrosion process is governed by the dominant acid gas. The presence of H2S in CO2 containing producing environments has been reviewed by Pots et al [14]. They have introduced a notion of CO2/H2S ratio and considered three different corrosion domains based on the dominance of corrosion mechanism as affected by the dominating acid gas. These are tabulated in Table 1 and shown in Figure 2 [14] as follows:

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CO2/H2S < 20 o

Corrosion dominated by H2S

Mixed CO2/H2S corrosion dominance

FeS as the main corrosion product

20 < CO2/H2S < 500 A mixture of FeS and FeCO3 as the main corrosion products

CO2/H2S > 500 o

CO2 corrosion dominates

FeCO3 as the main corrosion product.

These limits will be subject to environmental conditions highlighted in CO2 containing streams and described in a later section. This is in support of other investigations [17,18] in which it has been concluded that the CO2/H2S ratio determines the nature of scale and in turn the corrosion mechanism. Dunlop [17] proposed that as a general rule for CO2/H2S > 500, corrosion is dominated by CO2 and FeCO3 will form. When the ratio is < 20, FeS scale will form and H2S corrosion dominates as outlines in Figure 2 [14]. Smith [19] identified that the corrosion rate limiting step is determined by the type of corrosion product that forms as a result of the chemical reactions of CO2 and H2S. He goes on and describes the protectiveness or lack of it based on the thermodynamic stability of different compounds. Smith also developed a relationship that determines the boundaries of the FeCO3 and mackinawite scales by extending the Dunlop correlation and proposed the equilibrium boundary between mackinawite and FeCO3. It is difficult to extrapolate laboratory based data generated over a short period to real life corrosion reactions and describe kinetically driven corrosion processes in terms of thermodynamic data. It is worth noting that protective layers are always thin as they progressively reduce ionic transport and corrosion reaction, whereas non-protective layers are normally thick or even profuse [4,45]. Therefore, regarding a threshold in term of corrosion rate, the simple corrosion product layer thickness could be an indicator of the nature of sulfide formed, apart from thermodynamic data in potential-pH diagrams. The explanation for the disparity in protectiveness of corrosion product in CO2 and H2S containing media has been explained in terms of diffusion transport phenomena through the liquid phase within the corrosion product layer [16,45]. It is argued that depending on the dominant process, three possible types of corrosion control processes are plausible; soluble, insoluble cationic (IC) and insoluble anionic (IA) layers. He goes on to say that in H2S-containing media through the formation of IA-type deposit can explain the presence of a layer of highly soluble corrosion products, including FeCl2, between an outer layer of virtually insoluble FeS and a corroding steel substrate. It is said that this is also true for the very high corrosion rates observed beneath thick profuse mackinawite deposits. Furthermore, a protective IC layer formed in the presence of excess H2S can explain the formation of pyrite, FeS2, while a nonprotective IA layer, produced under a deficiency of H2S, can explain the formation of mackinawite, FeS1-e. Therefore, it is probably more correct to consider that it is the mechanism of protectiveness which determines the nature of the solid deposit, rather than the opposite [16,45]. The in-situ pH is also a key parameter governing corrosion in wet hydrocarbon production conditions affecting the formation and retainment of a protective layer. The in-situ pH is influenced by three controlling buffer systems [5]: x

CO2/HCO3- through reaction (3)

H2S/HS- through reaction (1)

HAc/Ac - (or other organic acids or other organic) through reaction (4) CO2 + H2O ļ HCO3- + H

(3)

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HAc ļ Ac- + H+

(4)

The carbonic, sulfidic and acetic buffers are represented by the mass action laws of their respective dissociation equilibrium as outlined in reactions 1, 3 and 4. When several buffers are simultaneously present, they react together since H+ is a common species in their respective dissociation equilibriums (5) and (6): HAc + HCO3- ļ Ac- + CO2 + H2O -

(5)

H2S + HCO3 ļ HS + CO2 + H2O

(6)

These and the corresponding in-situ pH in turn influence the corrosion process. The synergistic interaction of these three buffering (and others) reactions govern corrosivity as influenced by the formation of protective scales and they should constitute the basis of any corrosion analysis in hydrocarbon production systems. KEY FACTORS INFLUENCING H2S/CO2 CORROSION The operational parameters affecting CO2-H2S corrosion include those outlined earlier for CO2 containing conditions, notably: x

CO2/H2S ratio

Temperature

Fluid Chemistry (water chemistry, pH, organic acids, water cut, oil wetability, phase ratios, etc.)

The hydrocarbon phase

Flow characteristics and fluid velocity

Steel surface, including corrosion products, scales, wax and asphaltene

Steel chemistry

These parameters, highlighted in Figure 3, are interdependent and can interact in many ways to influence the corrosion process and the exact influence of many of these is still unknown. In particular the effect of hydrocarbon phase on corrosion behaviour still remains unanswered, not only in the case of CO2 corrosion, but also when both H2S and CO2 are present [1,10,11]. However, an overview of the current understanding of these parameters is captured in this section. As explained earlier, the interaction of the buffering reactions is a key consideration in the corrosion process. Effect of Chlorides Bich [12] reported very high corrosion rates in the order of 30 mm/y, in a failed gas pipeline with high level of chlorides while other lines with low level of chlorides did not exhibit the high corrosion rates. The high corrosion rate was attributed to the effect of chlorides on breaking down of the protective FeS scale and initiation of pitting corrosion. However, this may have been related to the influence of other constituents of the solution affecting the in-situ pH or organic acids, the presence of which was not fully established. Foroulis [20] reported large increase in corrosion rate with an increase in chloride content in solutions saturated with H2S and suggested that the increase is due to the increase in conductivity and the interference of the chloride ions with the formation of FeS protective film. Agrawal et al [18] reported that there is strong correlation between the corrosion rate and the CO2/H2S ratio and the relation followed a bell-shape curve, with the peak corrosion rate occurring at an order of magnitude higher CO2/H2S ratio when the chlorides increased from 0.01 to 10% NaCl. This may suggest that chloride ions interfere with the formation of protective scales. Furthermore, they concluded that any damage in the protective film can lead to an accelerated corrosion unless and until the FeS protective film is reformed. Hence, the role that chloride content of the environment plays is not fully established. However, its influence on corrosion of carbon and low alloy steels in CO2-H2S containing media is often

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considered insignificant at low chloride contents. Nevertheless, chloride may have a role in affecting the in-situ pH. Chloride also has some affinity to interfere with the formation of protective FeCO3 or pyrite and the tendency to influence its formation and growth on CLASs [4,16]. The observations reported on the effect of chloride [12,20] may have been related to the influence of other constituents of the media affecting the in-situ pH or organic acids the presence of which were not fully reported. A critical chloride concentration of 10,000 ppm has been conservatively proposed [14] based on field experience and laboratory testing. It has been concluded that above a concentration of 10,000 ppm, the chloride ion can destroy the protective FeS scales and can lead to increased corrosion rate. The role of chloride needs further clarification and a subject which should be taken in the context of solution chemistry and the nature of corrosion product. Effect of H2S Concentration Russ and Rainsford [21] reported that change in the CO2/H2S ratio from 3 mole % CO2/700 ppm H2S to 3.75 mole % CO2/350 ppm H2S resulted in significant increase in corrosion of oil pipelines. In-line inspection revealed that the section of the line with CO2/H2S ratio of 43 had low or non detectable corrosion while the one that had a ratio of 88 showed localized area representing 2.5% of the length of the line with pits 20-35% of the wall thickness. The difference in flow rate expressed as the shear stress was reported as 0.2 Pa for the segment with no corrosion and 1.0 Pa in the segment that showed corrosion. These shear stresses were low so that corrosion could not be due to the increase in fluid velocity. Again the full fluid chemistry has not been reported. Smith and de Waard [22] proposed an H2S reduction factor in their corrosion rate prediction model for CO2 corrosion. The factor is a function of the partial pressure ratio of H2S and CO2 as follows: F

H2S

= 1 / (1 + 1800 (pH2S/pCO2))

(7)

They state that this factor is speculative since the protective FeS layer can suffer breakdown. In cases where FeS breakdown occurs the corrosion rate can be an order of magnitude higher than the corresponding rate for pure CO2. This high corrosion rate in the presence of H2S is a result of drop in the pH due to the reduction of the dissolved iron ions that occurs with FeS precipitation and galvanic couple formed between the steel and corrosion scale. Brown, Parakala and Nesic [23] studied the effect of low levels of H2S on CO2 corrosion and showed that in the absence of protective iron carbonate and iron sulfide scales very small amounts of H2S < 10 ppm in the gas phase can lead to rapid and significant reduction in the CO2 corrosion rate. The trend is arrested and somewhat reversed at higher H2S concentration. Protective adherent films formed at 60Âş C with 25 ppm H2S and 7.9 bar pressure at pH of 6.0. Effects of Low H2S Partial Pressures on CO2 Corrosion Rates Recognising the importance of trace H2S on CO2 corrosion, a limited number of tests were carried out using an ambient pressure corrosion loop facility [24]. The programme assessed the effects of low H2S partial pressures on CO2 corrosion. The partial pressures of H2S used were 1.5x10-3, 1.5x10-2 and 1.5x10-1 psi (0.0001, 0.001 and 0.01 bar) corresponding to H2S concentrations of 100, 1,000 and 10,000 ppm (in the gas phase), respectively at an atmospheric pressure. Tests were carried out on linepipe steel grade X65 at 30, 50 and 75oC in the presence of 1 bar CO2 (14.5 psia) under two environmental conditions as shown in Table 1. Corrosion rates were determined by continuous LPR monitoring over a 24 hoursâ&#x20AC;&#x2122; period [24]. The results are summarised in Figures 4 and 5 for two conditions: x

Chloride containing fluid with no buffering agent at a pH range of 3.8 to 4.0

Formation water with strong buffering agents at a pH range of pH Range 5.5 to 5.8

Also included are the predicted corrosion rates for these conditions, using the de Waard and Milliams model [25]. The respective values under sweet conditions are somewhat higher than those predicted by the model, particularly at lower temperatures.

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Despite the inability to extrapolate the outcome of this limited study to develop a trend of corrosion rate versus H2S, it can be seen that low levels of H2S has a strong influence on CO2 corrosion by lowering the general rate of attack irrespective the environmental conditions. The lowering of damage rate increased progressively with increasing test temperature, although the magnitude of the reduction in corrosion rates was smaller in the buffered solution. The reduction in corrosion rates were considered to be due to the formation of a semi-protective FeS film or by stabilising an iron carbonate film. It seems that the partial pressure range investigated was above that required for semi-protective films to form but below that necessary to cause increased corrosion rates. While the degree of damage by localised corrosion was examined, the results were not conclusive. Nevertheless, the rate of pit propagation was considered unlikely to exceed the predicted general surface corrosion rate predicted determined by CO2 corrosion rate prediction models. The results indicate that at low levels of H2S which are defined as levels generally below the ‘occurrence of SSC’ limits (i.e. Region 0 of ISO 15156/NACE MR0175 at <0.05 psi) can reduce corrosion by a factor of 3 to 4 [24]. Effect of Flow and Temperature Brown and Nesic [26] showed that mackinawite FeS scale is protective when the flow conditions do not disturb the FeS scale but becomes less effective under turbulence flow conditions. Under conditions of porous film formation, the scale becomes less effective barrier and the corrosion rate increases. The key parameters in determining the film morphology are the FeCO3 and FeS supersaturation values. It has been claimed that the mechanisms of corrosion product film growth can produce multilayer films with some leading to increased corrosion rate and probability of localised corrosion [26]. Omar et al. [27] showed that CO2-H2S corrosion is not dependent on temperature and flow velocity for test conditions of 25 – 80ºC and 1 – 5 m/sec and the measured corrosion rates were lower than the predicted corrosion rates from pure CO2. At the highest velocity 5 m/sec they reported a tendency toward localised corrosion attacks and development of pitting corrosion which they attributed to the local breakdown of the protective films due to the high shear stresses or flow eddies close to the film. The magnitude of shear stress at this flow velocity is near 77 Pa. This raises the issue of pitting corrosion under conditions where film breakdown may occur due to high flow rates. In addition, they reported that at 80º C multiple layers of corrosion product formed with the inner layer close to the steel contained substantial fractions of iron oxides. The oxides would typically form due to the limited sulfide ions indicating that the corrosion products act as diffusion barriers and slow the corrosion attack. The effect of iron oxide presence on the long term integrity of the FeS protective layer is a major concern, although its presence may be related to laboratory test conditions as it is not a field produced corrosion product in CO2 environments. Effect of Organic Acids The significance role of organic acids on the performance of CLASs in CO2 containing hydrocarbon production systems is gaining due considerations over the past few years [4,28-31]. This remains a challenging topic as various mechanisms prevails and the subject is complex and still under extensive scrutiny. While in gas producing wells, the free acetic acid (HAc) content is physically dissolved from the produced gas phase, in oil producing conditions free HAc is chemically produced from the reaction between dissolved CO2 and the acetate ions present in water. In general term, organic acids change the solubility of corrosion product (i.e. dissolved iron, Fesat, at the saturation of corrosion product in FeCO3) and hence interfere with the formation of FeCO3 protective layer. This has a strong influence on CO2 corrosion and hence affects corrosivity assessment and prediction [4]. The synergistic interaction of the buffering reactions described earlier governs corrosivity. In CO2H2S containing systems, the effect or organic acids is not yet fully known, although their role is

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expected to be similar to the effect in CO2 systems and need to be accounted for in both chemical analyses as well as corrosion and predictions and mitigation. Effect of Microstructure There is limited data on the true effect of metal surfaces and steel microstructure on the corrosion behaviour of H2S-CO2 corrosion. Data reported by Perdomo et. al. [32] showed different behaviour of API 5L X52 steel from API 5L Grade B. The corrosion rate for Grade B increased with increase in H2S, reached a maximum then decreased where for the X 52 steel the corrosion rate continued to increase for the ranges of H2S tested. The difference has been attributed to the less compact and less uniform FeS layer on the X52 steel. However, new generation of low carbon microalloyed 3%Cr steel, has shown improved properties compared with conventional grades of CLASs with enhanced CO2, H2S and O2 corrosion resistance, satisfactory sulphide stress cracking (SSC) performance together with more than acceptable mechanical properties [33-34]. Effect of Corrosion Product Scales Smith and de Waard [35] reported the effectiveness of the corrosion product protective scales that form even with small amount of H2S. The corrosion is effectively mitigated with the protective scales when combined with corrosion inhibitors. They reported corrosion rates below 0.05 mm/y in the surface facilities of 25 gas fields that had H2S/CO2 ratio in the range of 1 to 750 where downhole inhibitors injection was used. The piping and vessels were coated with a sulfide rich film even in areas where inhibitors carryover was expected to be minimal. In support of other studies [14,17] Srinivasan and Kane [36] identified that the effect of H2S on CO2 corrosion depends on the ratio of CO2 to H2S. At low levels of H2S (< 0.01 psia) H2S has minimal or no influence on corrosion. At small amounts of H2S (CO2/H2S > 200) protective iron sulfide films form and reduce corrosion. Below 120ยบ C, the dominant film is mackinawite and its formation depends on pH and temperature. In conditions where H2S is the dominant acid gas (partial pressure CO2/H2S < 200) meta-stable iron sulfide films form preferentially over FeCO3 scale in the range of 60 to 240ยบ C. The protective film is initially mackinawite and at higher H2S concentration and temperature, the more stable pyrhotite iron sulfide forms which is more protective. At below 60 C and above 240ยบ C the presence of H2S exacerbates corrosion since H2S prevents the formation of the protective FeCO3 scale and the FeS scale becomes unstable and porous. Pots et al [14] reported that testing at partial pressure ratio between 20 and 500 revealed that the highest pitting corrosion rate was never worse than the sweet corrosion rate. The corrosion product films were a mixture of FeCO3 and FeS. Irrespective of the CO2/H2S ratio, pyrite is the most stable ferrous sulfide in pure H2S or in mixed H2S/CO2.as seen in field removed samples. However, its stability may be locally jeopardized by generation of cathodically produced molecular hydrogen. Therefore, the degree of hydrogen evolution affects the nature of corrosion product in H2S containing conditions in which high H2 evolution results in high corrosion rate as it does not allow a protective layer to form readily. It is apparent that hydrogen transport needs to be taken on board when addressing protectiveness of FeS layer. This is due to the fact that transport in the surface layer governs the liquid surface state, which in turn governs both corrosion rate and the solid surface state present in-situ or observed afterwards. A similar analogy has been made on the possible multiple steady state corrosion rates in CO2 corrosion [37, 45]. Notable Remarks The data in the literature and field experience clearly indicate that, in certain conditions the presence of H2S leads to the formation and growth of FeS protective scale and decreases the corrosion rate. However, there is substantial evidence that this protective scale behaves in a similar manner to FeCO3 in CO2 containing fluids [37,45] wherein protectiveness is not universal and certain conditions render it ineffective resulting in severe localised corrosion. The corrosion rates under these conditions can be significantly higher than the corrosion rates for CO2 corrosion

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either measured or predicted [12,13,41-45]. The primary concern with the presence of H2S is the potential failure of the FeS protective scale and the risk of high pitting corrosion rate, as described earlier. The evidence also suggests that the data generated to date is still not sufficient to characterise the issues related to H2S-CO2 corrosion and the general understanding that in the presence of H2S, corrosion increases initially until the FeS scale forms and then the corrosion rate decreases significantly. This behaviour is not well defined such that it cannot be relied on for the selection of materials since conditions may vary within the facility or during its operating life. Nevertheless, the data in the literature clearly shows that corrosion inhibitors can be effective in controlling H2S-CO2 corrosion if/when the correct inhibitor is selected to match the operating conditions and is effectively deployed. Therefore, H2S-CO2 corrosion can be effectively controlled with inhibition but requires that inhibitor selection and application be specific for the environment of concern and not be based on pure CO2 or H2S. MATERIALS SELECTION STRATEGY There is a growing desire to have a corrosion design philosophy for production facilities to transport wet hydrocarbons. Such an approach can be used in the technical/commercial assessment of new field development and in prospect evaluation and for handling of sour fluids by facilities not normally designed for sour service [39]. A universal method of preventing oilfield corrosion is through selection of the most appropriate material for a specific application. Optimum choice of materials is governed by a number of key parameters including adequate mechanical properties, corrosion performance, weldability (where appropriate), availability and cost. The choice of material is governed by the nature of its application and generally falls into two categories of production and injection. A simple chart outlining the necessary steps in selection of materials is shown in Figure 6 [39]. This methodology captures a systematic approach to determining potential deployment of CLASs as the first reference point. Having established the degradation rate of CLASs, the second, although key parameter, is its resistance to SSC in the presence of H2S. The majority of these steps are covered elsewhere [1,2,39] and this section briefly outlines specific measures required to allow selection of the most appropriate materials for a particular duty. In general there is no consensus on applicability of corrosion models to H2S-CO2 corrosion [38]. Some of the data gathered both in the field and in the laboratory indicate that the corrosion rate for H2S-CO2 corrosion is lower than the predicted corrosion rate for CO2 alone with localised corrosion rate rarely exceeding CO2 corrosion predicted rates. This suggests that use of CO2 corrosion prediction models, although conservative, may provide good estimate for the maximum corrosion rate expected [12,22,24,36] when FeS scale is formed. Bearing these in mind, simple rules for the prediction of corrosion damage rate in H2S-CO2 containing streams are included in Table 2. It should be noted that a major consideration in materials design strategy is careful attention to acid flow back. In these conditions, the effluentsâ&#x20AC;&#x2122; property may render it highly corrosive if not neutralised. It can contain very high chloride brine with low pH fluids and additionally unknown fluid chemistry. The prevailing FeS or FeCO3 scales might not be stable under such fluid chemistry. MATERIALS ROUTES A brief summary of materials selection route for different aspects of production is given in this section acting as an overview guide in a holistic materials selection strategy. It is important to note that while CLASs are chosen primarily based on their corrosion resistance with adequate resistance against SSC, CRAs are normally selected based on their resistance to environmental cracking with secondary consideration to their general corrosion behaviour. These include SSC and Cl-SCC (chloride stress corrosion cracking) or a combination of these types of damage as affected by the operating temperatures [2,3]. The exception to this overview for CRAs is under extreme

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conditions (a combination of high temperature, low pH, high CO2 and H2S) where general corrosion may have to be considered in the overall selection strategy. Downhole and Well Heads Selection of materials for these applications are typically controlled by the need for resistance to both corrosion and to SSC. The latter is important even at low levels of H2S due to the high pressure and the need for long term reliability to avoid potential safety risks and unnecessary workover costs. Uses of low alloy steels with continuous inhibition for low to moderate corrosive conditions have proven to be successful in certain conditions. However, such systems can often prove impractical or too costly (e.g. deepwater subsea developments) such that they are not always the best approach. For highly corrosive conditions CRAs remain the most effective and economic option. Flowlines and Unprocessed Fluids Pipelines Two scenarios are considered here: i.

Highly Corrosive or High Risk applications For these applications CRAs often remain the most cost effective option since the risk of corrosion failure is high and use of corrosion inhibition with carbon and alloy steels is often either impractical, costly or poses too high a risk.

ii.

Low to Moderate Corrosiveness or Low Risk applications CLAS with corrosion inhibition or pH stabilisation is an effective option. The corrosion inhibitor must be selected appropriately in accordance with field conditions and operating parameters. On-line corrosion monitoring and frequent pigging may be required to ensure effective inhibition and inhibitor replenishments particularly where deposits may drop or accumulate within the flowlines (velocity of the fluids below the entrained velocity). Nonmetallic liners have been used successfully to reduce failures and inhibition cost with HDPE and special grades of Nylon (Rilsan), although the limits of applicability for such liners needs to be taken into account.

Process Facilities In general, process facilities will require the same materials selection and corrosion mitigation strategy as pure H2S with vessels requiring internal corrosion barriers to prevent under deposit corrosion and corrosion inhibition for carbon steel components. Selection of organic coatings vs. CRA cladding will depend on the corrosivity of the processed fluids and the potential impact of H2S presence on degradation of organic coatings such as blistering, etc. Heat exchangers particularly gas coolers will require CRA material at minimum for the heat exchanger tubes and heads or shell depending on the design of the unit. Process piping can be either CRAs or CLASs with corrosion inhibition (depending upon the piping configuration, quantities, etc,) except for high temperature areas (> 100oC) where CRAs are more suitable. Non-metallic materials such as HDPE, FRP and lined piping are practical alternatives for produced water handling and are becoming more widely used. Gas Treating Plants Except for the high corrosive sections of the plants such as amine towers, glycol reboilers and gas coolers where cladding or solid CRAs is required, carbon and alloy steels with corrosion inhibition are acceptable options. Export Pipelines Export pipelines for systems with significant level of H2S and CO2 requires the use of inhibited CLASs to mitigate any corrosion that may occur.

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Seals and Elastomers H2S even at low concentration can cause severe degradation to elastomers and increases the propensity for elastomers embrittlement and explosive decompression. Selection of seals and elastomers for H2S/CO2 environments must follow the same selection guidelines for pure H2S environments. CONCLUSIONS The review and analyses captured in the present paper demonstrate that the current understanding of combined H2S-CO2 corrosion is far from complete and many of the issues affecting its occurrence remain unresolved. The current state of knowledge points to the following conclusions: 1.

In the combined presence of CO2 and H2S, there is a competitive interaction between FeCO3 and FeS corrosion products that may lead to affording protection or breaching the layers with resultant progressive localised corrosion

Subject to the type and nature of the corrosion product, H2S may lead to an increase in CO2 corrosion until certain concentration threshold after which weight loss corrosion may be reduced and in many cases results in a significant reduction. The integrity of the FeS protective layer may be affected by the operating conditions. In this, it is more accurate to consider that it is the mechanism of protectiveness which determines the nature of the solid deposit, rather than the opposite

The CO2/H2S ratio is an acceptable means of categorising metal loss corrosion damage caused in the combined presence of H2S and CO2 â&#x20AC;&#x201C; this ratio affects the nature of corrosion product and together with other key operational parameters can be considered in corrosion prediction models

A systematic materials optimisation strategy has been introduced integrating key parameters of past successes, present understanding of corrosion processes in hydrocarbon production, whole life costing and application regime of conventional as well as proprietary grades hence allowing the selection of the most suitable, safe and economical material option and corrosion control procedures

H2S-CO2 corrosion damage can be mitigated with a correct materials selection strategy and implementation of corrosion control measures. In this, appropriate corrosion inhibitors have shown effective mitigating measures

While CLASs are chosen primarily based on their corrosion resistance with adequate resistance against SSC, CRAs are normally selected based on their resistance to environmental cracking with secondary considerations to their general corrosion behaviour

There remains a need to develop clear understanding of H2S-CO2 corrosion process and the interaction of other key environmental, metallurgical and hydrodynamic parameters affecting the phenomenon and the formation of corrosion products. The interaction between these parameters is a key to determining their accumulative effect and means of mitigation through effective materials selection and corrosion control strategy. ACKNOWLEDGEMENTS

Thanks are due to Mr Dominic Paisley (BP) for his contribution to the development of this paper. Valuable comments and contributions from Dr Jean Louis Crolet (Consultant) and Mr Don Harrop (BP) are highly appreciated. REFERENCES 1. 2.

M B Kermani and A Morshed, Corrosion Vol. 59 No. 8, 2003, p.659 â&#x20AC;&#x201C; 683. M B Kermani, Paper No 00156, NACE, Orlando, March 2000

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3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26. 27. 28. 29. 30. 31. 32. 33. 34. 35. 36. 37. 38. 39. 40. 41. 42. 43. 44. 45.

Petroleum and natural gas industries – Materials for use in H2S containing environments in oil and gas production ISO 15156, Parts 1-3, 2003 M R Bonis and J L Crolet, NACE Annual Corrosion Conference, Paper 05272, 2005 J L Crolet, Eurocorr 2004, (London UK; The Institute of Materials, 2004) Metals Handbook, “Corrosion”, Volume 13 (ASM International, Materials Park, Ohio, 1987), p. 1233. B Craig, SPE Monograph Volume 15, Society of petroleum Engineers, Richardson, Texas, p. 22-29, 1993 R H Hausler, NACE Annual Corrosion Conference Paper No. 04732, 2004 R.N. Tuttle, Journal of Petroleum Technology, p 756-762, 1987 L W Jones, Corrosion and Water Technology for Petroleum Producers; OGCI, Tulsa, 1988 CO2 Corrosion Control in Oil and Gas Production - Design Considerations, eds. M B Kermani and L M Smith, European Federation of Corrosion Publication No 23, 1997. N N Bich and K Goerz, NACE Annual Corrosion Conference, Paper No 26, 1996 N N Bich, “Fundamental of Wet Sour Gas Corrosion”, Presentation/Private communication, 1999 F M Pots, R C John, I J Rippon, M J J Simon Thomas, S D Kapusta, M M Girgis and T Whitman, NACE Annual Corrosion Conference, Paper 02235, 2002 S N Smith and R.S. Pakalapati, NACE Annual Corrosion Conference, Paper 04744, 2004 J L Crolet, private communications, 2005 A K Dunlop, H L Hassell and P R Rhodes, NACE Annual Corrosion Conference, Paper No 46, 1983 A K Agrawal, C Durr and G H Koch, NACE Annual Corrosion Conference, Paper 04383, 2004 S N Smith and J L Pacheco, NACE Annual Corrosion Conference, Paper 02241, 2002 Z Foroulis, Werkstoffe and Korrosion, pp.463-470,1980 P R Russ and C Rainsford, SPE Asia Pacific Oil and Gas Conference and Exhibition, Paper No 88570, October 2004 L M Smith and C de Waard, NACE Annual Corrosion Conference, Paper 05648, 2005 B Brown, S R Parakala and S Nesic, NACE Annual Corrosion Conference, Paper 04736, 2004 D Paisley, BP Internal Report, 1993 C de Waard and U Lotz, NACE Annual Corrosion Conference, Paper No. 69, 1993 B Brown and S Nesic, NACE Annual Corrosion Conference, Paper 05625, 2005 I H Omar, Y M Gunaltun, J Kvarekval and A Dugstad, NACE Annual Corrosion Conference, Paper 05300, 2005 J A Dougherty, NACE Annual Corrosion Conference, Paper 04376, 2004 M W Joosten, J Kolts, J W Hembree and M Achour, NACE Annual Corrosion Conference, Paper 02294, 2004 M W Joosten, G D Harris, R L Hudgins, D A Daniels, and K M Cloke, NACE Annual Corrosion Conference, Paper 05114, Corrosion 2005 W M Hedges and L McVeigh, NACE Annual Corrosion Conference, Paper No 21, 1999 J J Perdomo, J L Morales, A Viloria and A J Lusinchi, Materials Performance, pp 54-58, March 2002 M B Kermani, J C Gonzales, G L Turconi, T Perez and C Morales, NACE Annual Corrosion Conference, Paper 04111, 2004 L Pigliacampo, J C Gonzales, G L Turconi, T Peres, C Morales and M B Kermani, NACE Annual Corrosion Conference, Paper 06133, 2006 L M Smith and C de Waard, Industrial Corrosion, p 14-18, 2004. S Srinivasan and R D Kane, NACE Annual Corrosion Conference, Paper No. 11, 1996 J L Crolet, S Olsen, W Wilhelmsen, NACE Annual Corrosion Conference, Paper 127, 1995 R Nyborg, NACE Annual Corrosion Conference, Paper 02233, 2002 M B Kermani, J C Gonzales, G L Turconi, T Perez and C Morales, NACE Annual Corrosion Conference, Paper 05111, 2005 J L Crolet and M R Bonis, SPE Production Engineering, pp. 449-453, Nov, 1991 A Ikeda, M Ueda and S Mukai, Advances in CO2 Corrosion Volume 2, pp 1-22, NACE International, 1985 K. Videm and J. Kvarekval, NACE Annual Corrosion Conference, Paper No. 94012, 1994 J Kvarekval, EUROCORROSION 97, Trondheim, Norway. A Valdes, R Case, M. Ramirez and A. Ruiz, NACE Annual Corrosion Conference, Paper No. 22, 1998 J L Crolet, in “Modelling Aqueous Corrosion From Individual Pits to System Management”, ed. K R Trethewey and P R Roberge, NATO ASI Series, Series E: Applied Sciences, Vol 266, pp 1-28, 1994.

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Table 1 The analysis of the synthetic produced waters used in the tests Component

Formation Water (ppm)

Chloride SO4-Bicarbonate Sodium Potassium Calcium Magnesium Acetate pH

52,000 10 500 29,500 380 3200 500 50 5.5-5.8

Chloride Containing Fluid (ppm) 42500

27540

3.8-4.0

Table 2 H2S-CO2 Corrosion Dominance and Prediction Guides (A Rule of Thumb)

CO2/H2S Ratio

< 20

Sub category

Operating Parameters

Dominating Corrosion Process

Primary Corrosion Product

Low: Subject to the formation of a protective FeS Mixed - the highest localised corrosion rate does not exceed predicted sweet corrosion rate.

Known

H2 S

FeS

Known

Mixed H2S/CO2

FeS and FeCO3

Fully known

Mixed H2S/CO2

FeS and FeCO3

Mixed â&#x20AC;&#x201C; Corrosion rate determined by the nature of FeS

Known

CO2

FeCO3

CO2 driven

1000

Fully known

CO2

FeCO3

CO2 driven

10000

Fully known

CO2

FeCO3

CO2 driven

>10000

Fully known

CO2

FeCO3

CO2 driven

20 to 500

100

> 500

Corrosion Damage Risk Factor (A Rule of Thumb)

Possible Pattern of Corrosion Damage

CO2 Corrosion Model CO2 Corrosion Model with possible reduction of 4 CO2 Corrosion Model with possible reduction of 4 CO2 Corrosion Model with possible reduction of 3 CO2 Corrosion Model with possible reduction of 3 CO2 Corrosion Model

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Figure 1.

Comparative corrosiveness of three common gases in water solutions (25oC, 5-7 day exposure, 2-5 g/litre NaCl, HCO3 alkalinity < 50 mg/l â&#x20AC;&#x201C; computed from several data sources) [after Ref 11].

Figure 2. CO2-H2S corrosion domains [after Ref 14].

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Figure 3. Parameters affecting CO2-H2S corrosion.

Figure 4.

Corrosion rate of X65 linepipe steel under sweet and mildly sour conditions in chloride containing conditions at pH 3.8-4.0 [24].

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Figure 5.

Corrosion rate of X65 linepipe steel under sweet and mildly sour conditions in simulated formation water at pH 5.5-5.8 [24].

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Materials optimisation strategy flow chart [after Ref 39]. Figure 6.

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NACE SP0296-2010 (formerly RP0296-2004) Item No. 21078

Standard Practice Detection, Repair, and Mitigation of Cracking in Refinery Equipment in Wet H2S Environments This NACE International standard represents a consensus of those individual members who have reviewed this document, its scope, and provisions. Its acceptance does not in any respect preclude anyone, whether he or she has adopted the standard or not, from manufacturing, marketing, purchasing, or using products, processes, or procedures not in conformance with this standard. Nothing contained in this NACE International standard is to be construed as granting any right, by implication or otherwise, to manufacture, sell, or use in connection with any method, apparatus, or product covered by Letters Patent, or as indemnifying or protecting anyone against liability for infringement of Letters Patent. This standard represents minimum requirements and should in no way be interpreted as a restriction on the use of better procedures or materials. Neither is this standard intended to apply in all cases relating to the subject. Unpredictable circumstances may negate the usefulness of this standard in specific instances. NACE International assumes no responsibility for the interpretation or use of this standard by other parties and accepts responsibility for only those official NACE International interpretations issued by NACE International in accordance with its governing procedures and policies which preclude the issuance of interpretations by individual volunteers. Users of this NACE International standard are responsible for reviewing appropriate health, safety, environmental, and regulatory documents and for determining their applicability in relation to this standard prior to its use. This NACE International standard may not necessarily address all potential health and safety problems or environmental hazards associated with the use of materials, equipment, and/or operations detailed or referred to within this standard. Users of this NACE International standard are also responsible for establishing appropriate health, safety, and environmental protection practices, in consultation with appropriate regulatory authorities if necessary, to achieve compliance with any existing applicable regulatory requirements prior to the use of this standard. CAUTIONARY NOTICE: NACE International standards are subject to periodic review, and may be revised or withdrawn at any time in accordance with NACE technical committee procedures. NACE International requires that action be taken to reaffirm, revise, or withdraw this standard no later than five years from the date of initial publication and subsequently from the date of each reaffirmation or revision. The user is cautioned to obtain the latest edition. Purchasers of NACE International standards may receive current information on all standards and other NACE International publications by contacting the NACE International FirstService Department, 1440 South Creek Dr., Houston, Texas 77084-4906 (telephone +1 281-228-6200).

Revised 2010-03-13 Revised 2004-02-12 Reaffirmed 2000-09-13 Approved 1996-03-30 NACE International 1440 South Creek Drive Houston, Texas 77084-4906 +1 281-228-6200 ISBN 1-57590-013-0 ÂŠ 2010, NACE International

SP0296-2010

________________________________________________________________________ Foreword NACE International Task Group T-8-16, “Cracking in Wet H2S Environments,” was formed in 1988 to conduct an organized study on the incidence and mechanisms of cracking in pressure vessels operating in refinery wet hydrogen sulfide (H2S) environments. Specific objectives were to (a) define the nature and extent of the problem by means of an industry survey; (b) define mechanisms for the type of cracking found, to be accomplished primarily through a literature survey; (c) establish inspection guidelines for existing vessels; and (d) develop repair and mitigation guidelines for cracked vessels. Four work groups were formed to address these tasks. In 1990, a fifth work group was formed with a fifth objective, (e) to investigate material specifications and fabrication practices for new pressure vessels. This standard practice summarizes objectives (a), (c), and (d) listed above. A technical committee report (NACE Publication 8X294)1 was issued to address objective (b). Finally, objective (e) was handled by another technical committee report (NACE Publication 8X194).2 This standard is intended for use primarily by refinery corrosion and materials engineers and inspection, operations, and maintenance personnel. Information and guidance presented in this standard reflect the work of many individuals representing numerous companies worldwide. The titles and source information of the codes, specifications, and standards referred to or discussed in this standard are provided in Appendix A (nonmandatory) rather than listed in footnotes throughout the standard. Confining this information to one appendix should help readers who have any interest in further research. This standard was originally prepared in 1996 by former Task Group (TG) T-8-16, “Cracking in Wet H2S Environments.” It was reaffirmed in 2000 by Group Committee T-8, and revised in 2004 and 2010 by TG 268, “Wet H2S Cracking in Petroleum Refinery Pressure Vessels.” TG 268 revised this standard in 2010 to address a number of items raised by Specific Technology Group (STG) 34 members as well as to respond to revisions in other applicable NACE standards such as SP0472.3 The original emphasis of this standard was on pressure vessels, and this emphasis remains. However, with this revision, some limited information on piping has been included at the request of TG 268 members and other members of STG 34. TG 268 is administered by STG 34, “Petroleum Refining and Gas Processing.” This standard is issued by NACE International under the auspices of STG 34.

In NACE standards, the terms shall, must, should, and may are used in accordance with the definitions of these terms in the NACE Publications Style Manual. The terms shall and must are used to state a requirement, and are considered mandatory. The term should is used to state something good and is recommended, but is not considered mandatory. The term may is used to state something considered optional.

________________________________________________________________________

NACE International

SP0296-2010 ________________________________________________________________________

NACE International Standard Practice Detection, Repair, and Mitigation of Cracking in Refinery Equipment in Wet H2S Environments Contents 1. General ............................................................................................................................ 1 2. Mechanisms of Cracking ................................................................................................. 2 3. Inspection for Cracking ................................................................................................... 4 4. Repair of Cracked or Blistered Equipment .................................................................... 11 5. Mitigation Considerations for Operation ........................................................................ 14 References ........................................................................................................................ 15 Bibliography ...................................................................................................................... 16 Appendix A: Cited Codes, Specifications, and Standards ................................................ 17 Appendix B: Nature and Extent of Problem—Results from 1990 T-8-16a Survey ........... 19 Appendix C: Typical Cracks Found in Wet H2S Environments ......................................... 25 FIGURES Figure C1: SSC in HAZ of head-to-shell weld of FCCU absorber tower. The crack is on the ASTM A 516-70 shell side. The numbers in the photograph are Knoop hardness values. (nital etch) ................................................................................................................................ 25 Figure C2: Hydrogen blister in ASTM A 516-70 amine contactor/water wash tower. ...... 26 Figure C3(a): Hydrogen blisters on ID surface of amine contactor/water wash tower. ... 27 Figure C3(b): Cross-section of plate shown in upper photo illustrating HIC (“stepwise” cracking)............................................................................................................................ 27 Figure C4: SOHIC in soft base metal extending from the tip of SSC in a hard HAZ of a repair weld in the shell of a primary absorber (deethanizer) column in an FCCU gas plant. The ASTM A 212-B steel shell was given PWHT at original fabrication, but the repair weld was not. (nital etch) ....................................................................................... 28 Figure C5: ASCC (carbonate cracking) of non-PWHT ASTM A 285-C steel shell of FCCU main fractionator overhead accumulator. Cracking was found near welds in the lower portion of vessel. ............................................................................................................... 29 TABLES Table B1: Overall Summary .................................................................................................. 19 Table B2: Cracking Reported by Company..............................................................................20 Table B3: Cracking by Process Unit ................................................................................. 20 Table B4: Cracking vs. Operating Temperature ............................................................... 21 Table B5: Cracking vs. H2S Concentration ....................................................................... 21 Table B6: Cracking vs. Steel Specification ........................................................................ 22 Table B7: Cracking vs. Steel Grade ................................................................................. 22 Table B8: Cracking vs. PWHT ..................................................................................................22 Table B9: Cracking vs. Blistering History ..................................................................................23 Table B10: Cracking vs. Weld Repairs......................................................................................23 Table B11: Depth of Cracking ........................................................................................... 23 Table B12: Crack Penetration ...................................................................................................24 Table B13: Disposition of Cracked Pressure Vessels ....................................................... 24 ________________________________________________________________________

NACE International

SP0296-2010 ________________________________________________________________________ Section 1: General 1.1 This standard is intended to be a primary source of information on cracking in wet H2S petroleum refinery environments and provides guidelines on the detection, repair, and mitigation of cracking of existing carbon steel refinery equipment in wet H2S environments. 1.1.1 For the purposes of this standard, the term equipment refers to pressure vessels and piping made of carbon steel plate material. Refinery pressure vessels include items such as, but not limited to, columns or towers, heat exchangers, drums, reboilers, and separators. 1.1.2 Limited cracking has been noted in seamless piping; therefore, the information in this standard concentrates on longitudinally seam-welded pipe fabricated from plate. 1.1.3 Information on fabrication and inspection practices for new pressure vessels (never in service) is in NACE Publication 8X194. 1.2 For the purposes of this standard, the term wet H2S environments includes, but is not limited to, refinery process environments known to cause wet H2S cracking resulting from hydrogen entry into the steel, as defined in NACE Standard MR0103.4 Some environmental conditions known to cause wet H2S cracking are those containing an aqueous phase and: (a) > 50 ppmw total sulfide content in the aqueous phase; or (b) ≥ 1 ppmw total sulfide content in the aqueous phase and pH < 4; or (c) ≥ 1 ppmw total sulfide content and ≥ 20 ppmw free cyanide in the aqueous phase and pH > 7.6; or (d) > 0.3 kPa absolute (0.05 psia) partial pressure H2S in the gas phase associated with the aqueous phase of a process. However, the threshold total sulfide content in the aqueous phase required for cracking to occur has not been clearly established. Therefore, selective application of this standard may be appropriate when experience has indicated the presence of cracking or blistering in comparable service, regardless of total sulfide content. Alkaline environments such as alkanolamine solutions that contain sulfides and carbonate-containing sour waters also are included in the term wet H2S environments and thus are within the scope of this standard. Two forms of alkaline stress corrosion cracking (ASCC) are commonly found in these alkaline wet H2S environments. Amine stress corrosion cracking (commonly referred to as amine cracking) can occur in amine service under certain conditions, which are discussed in API(1) RP 945.5 Alkaline carbonate stress corrosion cracking (commonly referred to as carbonate cracking) can occur in alkaline carbonate-containing sour waters under certain conditions. NACE Publication 341086 describes where carbonate cracking has occurred in process equipment in petroleum refining service, the refining community’s current theory(ies) on the conditions and mitigation techniques that may have an impact on this type of cracking, and analytical and inspection techniques that have been used to address the issue. 1.3 Increased industry attention to the potential for cracking of carbon steel pressure vessels began in 1984 with the rupture of a monoethanolamine (MEA) absorber tower at a Lemont, Illinois refinery. The ensuing explosion and fire resulted in fatalities and extensive damage to the facility.7 In response to this incident, NACE Task Group T-814, “Stress Corrosion Cracking of Carbon Steel in Amine Solutions,” was formed in the fall of 1984. An industry survey to determine the nature and extent of the cracking problem was conducted by T-8-14. The results of the T-814 effort have been reported separately.8

(1)

American Petroleum Institute (API), 1220 L St. NW, Washington, DC 20005-4070.

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SP0296-2010 1.4 In 1988, some new results on vessel inspections and the cracking found were reported to the industry.9 Among the significant findings was the observation that cracking problems were occurring in other wet H2S environments, not just in MEA. It was further reported that inspection techniques commonly used at the time (visual, liquid penetrant, and dry magnetic particle testing) were not sensitive enough to find these cracks. In response to this new information, NACE Task Group T-8-16, â&#x20AC;&#x153;Cracking in Wet H2S Environments,â&#x20AC;? was formed in the spring of 1988. Work Group T-8-16a conducted a survey of cracking experiences in wet H2S environments to better identify the extent of the problem. Appendix B (nonmandatory) summarizes the 1990 T-8-16a survey findings. ________________________________________________________________________ Section 2: Mechanisms of Cracking 2.1 The objective of this section is to define the terms used to describe cracks that occur because of exposure to wet H2S environments and describe the mechanisms of cracking. Photographs of typical cracks found in wet H2S environments are shown in Appendix C (nonmandatory). 2.2 Definitions 2.2.1 Sulfide Stress Cracking (SSC): Cracking of a metal under the combined action of tensile stress and corrosion in the presence of water and H2S. SSC is a form of hydrogen stress cracking resulting from absorption of atomic hydrogen that is produced by the sulfide corrosion process on the metal surface. SSC usually occurs more readily in high-strength steels or in hard weld zones of steels. (See Figure C1.) 2.2.2 Hydrogen Blistering: The formation of subsurface planar cavities, called hydrogen blisters, in a metal resulting from excessive internal hydrogen pressure. Growth of near-surface blisters in low-strength metals usually results in surface bulges. Hydrogen blistering in steel involves the absorption and diffusion of atomic hydrogen produced on the metal surface by the sulfide corrosion process. The development of hydrogen blisters in steels is caused by the accumulation of hydrogen that recombines to form molecular hydrogen at internal sites in the metal. In its molecular state, hydrogen is too large to diffuse through the steel. Typical sites for the formation of hydrogen blisters are large nonmetallic inclusions, laminations, or other discontinuities in the steel. This differs from the voids, blisters, and cracking associated with high-temperature hydrogen attack. Hydrogen blistering is much more common in plate materials used for pressure vessels or longitudinally seamwelded pipe than in seamless pipe materials or forgings. (See Figure C2.) 2.2.3 Hydrogen-Induced Cracking (HIC): Stepwise internal cracks that connect adjacent hydrogen blisters on different planes in the metal, or to the metal surface (also known as stepwise cracking). No externally applied stress is needed for the formation of HIC. In steels, internal cracks that may develop (sometimes referred to as blister cracks) tend to link with other cracks by a transgranular plastic shear mechanism. This occurs because of internal pressure resulting from the accumulation of hydrogen. The link-up of these cracks on different planes in steels has been referred to as stepwise cracking to characterize the nature of the crack appearance. HIC is commonly found in steels with (a) high impurity levels that have a high density of large planar inclusions, and/or (b) regions of anomalous microstructure produced by segregation of impurities and alloying elements in the steel. Because HIC is caused by the same fundamental mechanism that causes hydrogen blistering, it also is much more common in plate materials used for pressure vessels or longitudinally seam-welded pipe than in seamless pipe materials or forgings. (See Figure C3.) 2.2.4 Stress-Oriented Hydrogen-Induced Cracking (SOHIC): Arrays of cracks, aligned nearly perpendicular to the stress, that are formed by the link-up of small HIC cracks in steel. Tensile stress (residual or applied) is required to produce SOHIC. SOHIC is commonly observed in the base metal adjacent to the heat-affected zone (HAZ) of a weld, oriented in the through-thickness direction. SOHIC may also be produced in susceptible steels at other high stress points such as from the tip of mechanical cracks and defects, or from the interaction of hydrogen blisters on different planes in the steel. (See Figure C4.) 2.2.5 Alkaline Stress Corrosion Cracking (ASCC): Cracking of a metal produced by the combined action of corrosion in an aqueous alkaline environment containing H2S, CO2, and tensile stress (residual or applied). The 2

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SP0296-2010 cracking is branched and intergranular in nature, and typically occurs in non-stress-relieved carbon steels. This form of cracking has often been referred to as carbonate cracking when associated with alkaline carbonatecontaining sour waters, and as amine cracking when associated with alkanolamine treating solutions. NACE Publication 34108 discusses carbonate cracking and API RP 945 discusses amine cracking. ASCC may occur in both vessels and piping. (See Figure C5.) 2.3 Environmental Parameters Affecting Cracking 2.3.1 Several cracking mechanisms in wet H2S environments, including SSC, hydrogen blistering, HIC, and SOHIC, are related to the absorption and permeation of hydrogen in steels. The key variables involved in hydrogen permeation in steels are pH and the composition of the service environment. Typically, the hydrogen permeation flux in steels has been found to be minimal in neutral solutions (pH 7), with increasing flux at both lower and higher pH values. Corrosion at low-pH values is caused by H2S, whereas corrosion at high-pH values is caused by increasing concentrations of ammonium bisulfide (higher ammonia levels in H2S-dominated environments). 2.3.2 Hydrogen permeation has also been found to increase with increasing H2S partial pressure and with the presence of cyanide at alkaline pH levels. 2.3.3 SSC susceptibility increases with increasing H2S partial pressure. Based on investigations in oil and gas production environments, 0.3 kPa absolute (0.05 psia) and greater partial pressure of H2S in the presence of free water may produce SSC in susceptible steels. 2.3.4 ASCC can occur over a wide range of temperatures, but susceptibility appears to increase with increasing temperature. ASCC generally occurs in alkaline solutions with a pH in the 8 to 11 range, but its occurrence is highly dependent on the solution composition. This form of cracking has occurred in refinery services such as sour water streams and alkanolamine solutions containing H2S and CO2. ASCC is promoted by carbonates in the presence of weak sulfiding agents such as thiosulfate and thiocyanate. The mode of cracking involves local anodic dissolution of iron at breaks in the normally protective corrosion product film on the metal surface. Laboratory tests have shown that cracking occurs in a relatively narrow range of electrochemical potential that corresponds to a destabilized condition of the protective film. This film destabilization occurs at very low ratios of the sulfide concentration to the carbonate/bicarbonate concentration in the solution, and is possibly affected by a number of contaminants in the solution.10,11 This form of cracking is not directly associated with the above-mentioned forms of hydrogen-related damage. However, in sour waters and alkanolamine services containing H2S, cracking as a result of HIC, SOHIC, and SSC is possible, in addition to ASCC. 2.4 Material Parameters Affecting Cracking of Carbon Steels in Wet H2S Environments 2.4.1 Sulfide Stress Cracking 2.4.1.1 SSC has not generally been a concern in the carbon steel base metals typically used for pressure vessels and piping in refinery wet H2S environments because these steels generally have a tensile strength less than 620 MPa (90 ksi). 2.4.1.2 Carbon steel weld metal is generally considered resistant to SSC if its hardness is limited to 200 HBW maximum in corrosive petroleum refining environments in accordance with NACE SP0472.3 However, weldments (weld metal, HAZ, and adjacent base metal zones subject to residual stresses from welding) may contain localized zones of high hardness. SSC in carbon steel weldments frequently is limited to hard HAZs of the last weld pass, which are not tempered by subsequent weld passes. Data show that, depending on the severity of the service environment, small hard regions of up to 248 HV (237 HBW) can be tolerated without the occurrence of SSC. The Rockwell Superficial Hardness equivalent to 248 HV is 70.5 HR15N. These values are a direct conversion from the 22 HRC maximum specified in NACE Standard MR0103 for ferritic materials to be used in petroleum refining environments.

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SP0296-2010 2.4.1.3 SSC has generally not occurred in seamless carbon steel piping that has been welded from one side only because it does not contain hard weldments that are exposed to the process on the inside diameter (ID) of the piping. The initial weld pass is usually tempered by the subsequent weld passes, which helps to control the hardness. 2.4.2 Hydrogen Blistering and Hydrogen-Induced Cracking 2.4.2.1 Hydrogen blistering and HIC have been encountered in the lower-strength carbon steels plate materials typically used in refinery wet H2S environments for pressure vessels and longitudinally seamwelded piping. 2.4.2.2 These cracking mechanisms are associated with the formation of hydrogen blisters caused by an accumulation of molecular hydrogen at internal laminations, nonmetallic inclusions, or other discontinuities in the steel. Reducing the inclusion level of the steel by lowering the sulfur content increases the resistance to hydrogen blistering and HIC. In addition, control of sulfide inclusion morphology by calcium or rare earth metal additions to produce a spheroidal sulfide shape, in conjunction with use of lower-sulfur steels, has been found to increase resistance to hydrogen blistering and HIC. 2.4.2.3 Base metal heat treatments, such as normalizing or quenching and tempering above 593 Â°C (1,100 Â°F), increase resistance to crack growth. 2.4.3 Stress-Oriented Hydrogen-Induced Cracking 2.4.3.1 Generally, the material parameters affecting hydrogen blistering and HIC are expected to apply to SOHIC. 2.4.3.2 Susceptibility to SOHIC is increased by increasing local tensile stresses. Notch-like weld discontinuities and/or local differences in microstructure present in the area of a weldment may increase the localized stresses. Postweld heat treatment (PWHT) is expected to reduce the susceptibility to SOHIC when it is influenced by residual stress. PWHT can also reduce local HAZ hardness, thereby reducing the possibility for SSC, which can initiate SOHIC. 2.4.3.3 SOHIC has been found in pressure vessels constructed with conventional steels in refinery wet H2S environments. In laboratory tests, SOHIC has been produced in a variety of steels. In severe hydrogen-charging laboratory tests, SOHIC has also been produced in steels processed to optimize resistance to HIC. 2.4.4 Alkaline Stress Corrosion Cracking 2.4.4.1 ASCC has occurred in a variety of steels. Field experience to date has not indicated any significant correlation between susceptibility to ASCC and steel properties or product form. 2.4.4.2 Susceptibility to ASCC increases with increasing tensile stress level. Areas of deformation resulting from cold forming or localized high residual stresses in weldments are more prone to ASCC. Surface discontinuities, especially in areas adjacent to welds, often serve as initiation sites for ASCC because they act as localized stress raisers. ASCC can be effectively controlled by PWHT and proper heat treatment after cold forming. ________________________________________________________________________ Section 3: Inspection for Cracking 3.1 The objective of this section is to provide guidelines on inspection for cracking of existing carbon steel pressure vessels and piping made from carbon steel plate in petroleum refinery wet H2S environments. Where appropriate, guidelines are also included for piping. 4

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SP0296-2010 3.2 The scope of this section is the inspection of weldments. This includes pressure-retaining circumferential, longitudinal, and nozzle welds, and internal attachment welds to the pressure boundary. 3.3 Inspection guidelines for new pressure vessels (never in service) are beyond the scope of this standard. However, initial inspection of new vessels during fabrication with methods of comparable sensitivity to anticipated inservice inspection methods is of significant value in assessing subsequent inspection results. 3.4 These guidelines incorporate risk-based principles to determine the need and frequency for inspection. (Risk is defined as the likelihood [or probability] of failure times the consequence of failure.) See API RP 58012 and API RP 581.13 Also included are guidelines for inspection personnel qualifications, nondestructive examination (NDE) procedures, areas of inspection, surface preparation, inspection techniques, acceptance criteria, reporting of results, and reinspection. 3.5 Application of these inspection guidelines shall be made by engineers and/or inspection personnel who are knowledgeable in the technical aspects of this section. 3.6 Inspection Priorities and Intervals 3.6.1 Each refinery should prioritize equipment in wet H2S environments. When prioritization is done, the ranking for equipment shall consider the consequences of a leak or a failure on the surrounding area, operating conditions (temperature, pressure, and contents), criticality of the equipment, and the fabrication, inspection, and repair history. Priorities can be established by assessing the risk that cracking represents to the refinery. Evaluation of risk should use industry-approved approaches such as those in API RP 580, API RP 581, ASME(2) PCC-3,14 or similar procedures/methodologies unique to the owner/user. Regardless of the approach used, the risk assessment process shall address the likelihood of cracking and the consequence of failure. 3.6.2 Some factors that should be considered when assessing the likelihood of cracking and blistering in wet H2S environments are the following. These guidelines are based on survey data, literature information, and industry experience. (a) History of cracking and blistering. Equipment with a history of blistering is more likely to be cracked. Also, equipment in service comparable to that of other equipment that has cracked is more likely to be cracked. (b) Materials, fabrication, and repair history. Equipment without PWHT or those with non-postweld-heattreated repairs should be given higher priority when setting inspection requirements. NACE Publication 8X194 provides some background information on materials and fabrication practices typically used for vessels in wet H2S service. (c) Type of vessel. Trayed columns or drums in which an aqueous phase can condense, splash, or accumulate are more susceptible to cracking and blistering. Vapor spaces where condensation occurs or where sections are intermittently wetted are often the most severely damaged. (d) Type of piping. Piping fabricated from plate material, such as large-diameter, longitudinally seamwelded piping, is potentially susceptible to wet H2S cracking similar to vessels. The plate material used to fabricate longitudinally seam-welded pipe is similar to that used to fabricate pressure vessels. Seamless piping, forgings, and castings are generally considered to be resistant to wet H2S cracking. Although several factors have been identified to explain this favorable experience with these product forms, a frequently cited reason is the shape and distribution of impurities in these product forms. However, for seamless piping, the fabrication history, environment, and experience should be considered because some instances of wet H2S cracking of seamless piping have been reported.

(2)

ASME International (ASME), Three Park Avenue, New York, NY 10016-5990.

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SP0296-2010 (e) Severity of the process environment. Equipment in the following environments should be considered more susceptible to cracking or blistering. A process temperature between ambient and 149 °C (300 °F), and: •

high total sulfide content in the aqueous phase (generally > 2,000 mg/L [2,000 ppmw]) and pH above 7.8; or

•

total sulfide content > 50 mg/L (50 ppmw) in the aqueous phase and pH < 5.0; or

•

presence of free cyanide > 20 mg/L (20 ppmw) in the aqueous phase; or

•

alkaline environments with potential for cracking by other mechanisms such as ASCC (e.g., amine cracking, carbonate cracking); or

•

other environments with high potential for hydrogen activity as a result of aqueous corrosion.

(f) Type of process unit. The data presented in Table B3 of Appendix B may be useful in prioritizing inspection of equipment in various process units. In addition, the following list highlights specific areas within certain process units in which significant cracking in wet H2S environments has been found: •

catalytic cracking unit fractionation and light ends recovery sections, especially in the overhead systems;

•

hydrocracking and hydrotreating unit separation and fractionation sections;

•

coker fractionation and light ends recovery sections, especially in the overhead systems;

•

sour water stripping unit overhead systems; and

•

alkanolamine acid gas removal unit contactor (absorber), rich amine flash drum, stripper (regenerator), and stripper bottoms and overhead systems.

3.6.3 Some of the factors that should be considered when assessing the consequences of failure or leakage are as follows: (a) Nature of the process fluid (e.g., tendency to form a vapor cloud, flammability, combustibility, and toxicity); (b)

Total release inventory;

(c) Autorefrigeration tendency of the fluid (e.g., liquefied petroleum gas [LPG]), which could result in brittle fracture; (d)

Potential impact on plant operations and/or surrounding community;

(e)

Total pressure on the system; and

(f)

Leak scenario vs. rupture scenario.

3.6.4 Changes to the operating conditions or processing scheme can change the susceptibility to cracking and possibly the consequences associated with cracking. Such changes shall be considered when establishing both initial and reinspection practices.

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SP0296-2010 3.7 Extent of Inspection 3.7.1 Pressure Vessels 3.7.1.1 The extent of initial inspection shall be sufficient to provide a representative sample of the various areas of concern. The areas of concern include longitudinal, circumferential, and nozzle welds, and internal attachment welds to the pressure boundary. For those pressure vessels warranting inspection based on prioritization, the intent of inspection should be based on the risk the vessel represents to the owner/user. If environmental cracks are found, the inspection coverage shall be increased as necessary to adequately define the extent of cracking. 3.7.1.2

Areas to be inspected should specifically include repair or vessel alteration welds.

3.7.1.3 Areas to be inspected shall also include portions of the vessel that exhibit visible blistering or significant corrosion in close proximity to weldments. 3.7.1.4 In pressure vessels such as distillation columns or towers that include various environments, the inspection shall focus on areas considered more susceptible to cracking (e.g., cooler areas in which an aqueous phase may be present). 3.7.2 Piping 3.7.2.1 Longitudinally seam-welded piping made from plate shall be considered for inspection if the risk of cracking is unacceptably high using the same risk-based assessment considerations described for pressure vessels. If the risk assessment justifies an inspection, the inspection shall include longitudinal seam welds and also should include butt welds. If indications are found, the inspection shall be extended to establish the severity and extent of cracking. 3.7.2.2 Seamless piping, castings, and forgings are usually exempted from inspection for wet H2S cracking based on experience. Where inspection is deemed necessary by an appropriate expert, the extent of inspection shall be specified. 3.8 Inspection Methods 3.8.1 Several NDE techniques can be used to detect cracks and blisters in pressure vessels. These include wet fluorescent magnetic particle testing (WFMT), ultrasonic testing (UT) (including shear wave, longitudinal wave, time-of-flight diffraction [TOFD], and phased array [PA]), acoustic emission (AE) testing, alternating current field measurement (ACFM), eddy current testing (ECT), wet or dry magnetic particle testing (MT), liquid penetrant testing (PT), and visual methods (VT). The usefulness of these methods is dependent on the tightness, severity, and location of cracks, as well as proper application of the method, which includes a reasonable understanding of its benefits and limitations. The results of all of these techniques are techniciandependent. The following additional guidelines are provided on some of these NDE techniques used for detecting cracks in equipment exposed to wet H2S environments. 3.8.2 Wet Fluorescent Magnetic Particle Testing 3.8.2.1 For surface-breaking cracks, WFMT is sensitive, demonstrates reproducible results, and is one of the most commonly used methods for internal pressure vessel inspection. 3.8.2.2 Surfaces to be inspected shall be prepared to a finish that will facilitate inspection and not mask indications. In order to perform a satisfactory WFMT inspection, the surface of the weld and adjacent base metal for a distance of about 150 mm (6 in) on both sides should be cleaned of all scale and residue. Care should be taken to ensure that the surface preparation method does not deform the metal surface and mask

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SP0296-2010 indications. Abrasive blasting to a near-white finish in accordance with NACE No. 2/SSPC(3)-SP 1015 should be performed. Other methods, such as high-pressure water or CO2 blasting, may be used if they provide a suitable surface for inspection. In some instances, the use of flapper disc polishing has been necessary to enhance the detection sensitivity of fine, tight cracks. 3.8.2.3 Alternating current (AC) yoke WFMT should be used instead of direct current (DC) or prod methods. DC methods are not as sensitive for surface-breaking cracks and prod methods may leave arc strikes that, if not ground out, can serve as crack initiators. 3.8.2.4 AC yoke WFMT is a sensitive technique that may detect discontinuities not detected by other NDE methods. Some indications may be irrelevant. A representative number and type of indications shall be evaluated to determine their relevance and severity. 3.8.2.5 Surface preparation, magnetic particle materials, magnetic testing equipment, processing techniques, sequence of operation, levels of magnetizing fields, etc., should be monitored periodically to ensure proper inspection. Methods for checking system performance and sensitivity are detailed in ASME SE-70916 or equivalent. 3.8.2.6 Based on limited laboratory data and field experience, concern exists that in certain instances, removal of protective scales associated with surface preparation for WFMT may increase the likelihood of cracking when the vessel is returned to service.17 Depending on the severity of the environment and specific startup conditions, a short period of higher-than-normal hydrogen flux that could lead to cracking in a susceptible base metal or weldment may occur. 3.8.2.7 Limitations exist on the use of WFMT for the detection of cracking in wet H2S environments. These include: (a) WFMT requires internal vessel access, and some areas of the vessel may be inaccessible. Piping is most often not available for internal inspection except in the case of large-diameter lines that may be made from plate; (b)

WFMT may not detect subsurface cracks;

(c)

Surface preparation removes protective scales and requires cleanup;

(d)

WFMT can reveal many small irrelevant indications; and

(e)

Costs and time constraints are associated with removal of internals (e.g., trays).

3.8.3 Ultrasonic Testing 3.8.3.1 UT methods (manual or automated) may be used to detect surface cracking, subsurface cracking, and hydrogen blistering, for inspection on-stream and for nonintrusive inspection from the external surface. UT methods used include shear wave, longitudinal wave, TOFD, PA, and combinations of these UT methods. UT can be used to evaluate blister size and depth and detect deeper surface-connected defects (greater than 3.18 mm [0.125 in] deep). Other than destructive grinding of cracks, UT is the most frequently used method for sizing cracks for fitness-for-service evaluations. The use of external UT can alleviate potential future hydrogen-charging concerns associated with cleaning ID surfaces for WFMT, as stated in Paragraph 3.8.2.6. 3.8.3.2 Limitations on the use of UT methods for the detection of cracking and blistering in wet H2S environments exist. Achieving consistently reliable interpretation of results is difficult because of weld geometry, joint design, shadowing effect of multiple defects, and the need for more highly qualified NDE (3)

The Society for Protective Coatings (SSPC), 40 24th St., 6th Floor, Pittsburgh, PA 15222-4656.

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SP0296-2010 personnel experienced in the detection of cracking in wet H2S environments. Potential cost and time constraints include external scaffolding, insulation removal and replacement, surface preparation (e.g., grinding weld crowns), and slow production rates. 3.8.3.3 Carefully planned and executed automated UT procedures can provide some advantages in mapping specific areas, compared to manual UT, especially when follow-up inspection for crack growth is anticipated. 3.8.3.4

External shear wave UT should be used to inspect the weldments in piping.

3.8.4 Acoustic Emission Testing 3.8.4.1 AE testing is a global inspection method that may be used to detect surface-breaking cracks, subsurface cracks, and blisters. AE testing is typically used when the equipment is subjected to higher than normal tensile loading, normally accomplished by hydrostatic testing, pneumatic testing, or in-service pressurization above normal operating pressure. AE testing can be used both for inspection on-stream and for nonintrusive inspection from outside the equipment during a shutdown. 3.8.4.2 During AE testing, defect growth is detected by an AE sensor array attached to the external surface of the equipment. The AE sensors transmit signals to a central computerized data collection system. The data are evaluated using software developed for this purpose. 3.8.4.3 Limitations on the use of AE testing for the detection of damage in wet H2S environment exist. These include: (a) AE testing detects only cracks that are active during the conditions of the test. Therefore, the absence of AE indications does not ensure that the equipment is free of discontinuities. (b) AE testing methods currently used in the refining industry cannot discriminate the type or nature of the defect and cannot determine the defect size or exact location (although zonal location is possible). (c) AE testing is a sensitive technique with a relatively high occurrence of false indications (or overcalls). These can result from rain hitting the sensors, mechanical rubbing/squeaking of equipment internals or attachments, flange leaks, etc. AE testing personnel must be aware of and take into account potential extraneous influences and their effect on test results. (d) AE testing requires considerable skill and experience on the part of the personnel conducting the test and evaluating the data. The availability of both AE testing hardware and qualified personnel can be limited. (e) A stress analysis may need to be performed to ensure that the components of interest are adequately stressed during the test. 3.8.4.4 Because of the limitations stated above, AE testing should not be used as a stand-alone inspection method for the detection of cracking in wet H2S environments. Follow-up inspection with other appropriate NDE techniques shall be performed on any significant AE source area that potentially represents a location of cracking. When AE testing is used as a global screening technique, it should be used in conjunction with other NDE methods. 3.8.5 Alternating Current Field Measurement 3.8.5.1 ACFM is an electromagnetic technique that can be used to detect and size surface-breaking cracks in ferrous materials. The method can be applied through thin coatings and does not require extensive surface preparation.

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SP0296-2010 3.8.5.2 ACFM is best used as a screening tool for rapid detection of cracking along welds and/or HAZs with little or no surface preparation. It can be used in lieu of WFMT. 3.8.5.3 The sensitivity of ACFM to cracks decreases with an increase in the coating thickness and loose scale on the examination surface. ACFM can size crack length reliably. It can also assess the depths of nonbranched through-wall oriented cracks. However, its crack-depth sizing can yield erroneous values when ACFM is applied on highly branched, closely spaced, or tilted (i.e., not exactly in the through-wall direction) cracks, such as cracks resulting from ASCC. 3.8.5.4 ACFM data interpretation is much more complicated than WFMT. Highly skilled, experienced operators are essential to the success of ACFM inspection. 3.8.5.5 Application of the ACFM technique requires access to the internal (process) surfaces of the equipment. 3.8.6 Eddy Current Testing 3.8.6.1 ECT can be used to detect surface-breaking cracks. The method can be applied through thin coatings and does not require extensive surface preparation. 3.8.6.2 ECT is best used as a screening tool. It can be used in lieu of WFMT. It is not effective in finding very shallow cracks (less than about 1.5 mm [0.06 in] deep). 3.8.6.3

Increasing coating or scale thickness decreases the sensitivity of ECT.

3.8.6.4 ECT data interpretation is simpler than interpreting ACFM results. However, skilled operators are required to obtain accurate results. 3.8.6.5

Application of ECT requires access to the internal (process) surfaces of the equipment.

3.9 NDE Personnel Qualifications 3.9.1 NDE personnel performing nondestructive examinations shall be those recognized by the owner/user as having been trained in accordance with ASNT(4) SNT-TC-1A18 or equivalent, to a minimum of Level I. Interpretation of indications detected by NDE methods should be made by personnel trained to a minimum of Level II or equivalent. Refinery inspectors interpreting results and following up on repair procedures should be certified to ANSI(5)/API 510,19 ANSI/API 570,20 ANSI/NBBPVI(6) NB-23,21 ASME PCC-2,22 or other applicable industry code or standard. 3.9.2 Personnel interpreting results, especially characterization and sizing, should be familiar with the features of these cracking mechanisms to minimize errors in interpretation. 3.10 NDE Procedures 3.10.1 NDE procedures for crack detection by methods outlined in Paragraph 3.8.1 shall be in accordance with the appropriate article in Section V of the ASME Boiler and Pressure Vessel Code23 (e.g., Article 5 for UT, Article 7 for MT), or other applicable industry code or standard. In addition, special procedures may be required for detection and sizing of environmental cracking. 3.10.2 NDE procedures should be developed and approved by personnel with a demonstrated understanding of potential damage morphologies and with certification to ASNT Level III, or other qualified personnel. (4)

American Society for Nondestructive Testing (ASNT), P.O. Box 28518, 1711 Arlingate Lane, Columbus, OH 43228-0518. American National Standards Institute (ANSI), 25 West 43rd St., 4th Floor, New York, NY 10036. (6) National Board of Boiler and Pressure Vessel Inspectors (NBBPVI), 1055 Crupper Avenue, Columbus, OH 43229-1183. (5)

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SP0296-2010 3.11 Determining the Extent and Magnitude of Cracking and Blistering 3.11.1 A representative number and type of linear indications shall be explored for length and depth, using appropriate methods such as grinding, arc gouging followed by grinding, or UT sizing techniques. 3.11.2 A UT survey of areas with hydrogen blisters or cracks should be made to determine the extent of subsurface blistering, HIC, and/or SOHIC. The area adjacent to welds shall be targeted for this inspection. 3.12 Analysis of Inspection Results Based on the extent and magnitude of cracking and hydrogen blistering, an evaluation of the need for repair shall be made by engineers or inspection personnel who are recognized by the owner/user as qualified to make such evaluations. This evaluation may include a fitness-for-service analysis in accordance with a recognized methodology such as API 579-1/ASME FFS-124 or equivalent. API 579-1/ASME FFS-1 includes a part titled, â&#x20AC;&#x153;Assessment of Hydrogen Blisters and Hydrogen Damage Associated with HIC and SOHIC.â&#x20AC;? Discontinuities judged to be allowable by such an evaluation may remain in the equipment with no repairs required. Increased monitoring or mitigation may be necessary. 3.13 Records Permanent records of inspection results should be maintained for the life of the equipment. The location, orientation, length, and depth of significant indications, blisters, and cracks should be documented. 3.14 Reinspection 3.14.1 Reinspection intervals should be based on the risk that the equipment represents to the owner/user, recognizing prior inspection results, disposition of indications, weld repairs or alterations, changing process conditions, processing scheme, or requirements of ANSI/API 510 or other applicable industry code or standard. In general, if the risks are such that reinspection is warranted, the reinspection should be done using techniques discussed in this standard. 3.14.2 In assessing risk, other issues to be considered include possible growth of subsurface damage, possible accelerated hydrogen flux caused by surface cleaning prior to inspection, and changes to the process environment that may change the hydrogen-charging rate. ________________________________________________________________________ Section 4: Repair of Cracked or Blistered Equipment 4.1 The objective of this section is to provide guidelines for the repair of existing carbon steel equipment that has experienced cracking and/or hydrogen blistering when exposed to a petroleum refinery wet H2S environment. Decisions on the type of repair and procedure shall be made by engineers or inspection personnel who are recognized by the owner/user as qualified to make such evaluations. 4.2 All repairs shall be performed in accordance with ANSI/API 510 for vessels, ANSI/API 570 for piping, National Board Inspection Code (NBIC), ASME PCC-2, or another recognized industry code or standard. All welding procedure specifications, procedure qualifications, and welder performance qualifications shall be in accordance with the requirements of the ASME Boiler and Pressure Vessel Code, Section IX25 or other applicable industry code or standard. 4.3 In some cases, grinding or welding operations can cause cracks to initiate or propagate because of the hydrogen-charged nature of the steel. In such instances, a hydrogen bake-out procedure involving heating the area to diffuse atomic hydrogen should be used to aid reparability. Molecular hydrogen trapped in blisters and HIC typically does not dissociate at temperatures below full PWHT temperatures. Some owner/users heat the vessel or NACE International

SP0296-2010 piping to a temperature above 204 °C (400 °F) and hold for up to four hours. Although no standard calculations exist, based for example on Fick’s law, to determine the efficacy of bake-out treatments, much longer holding times and higher temperatures may be needed to reduce the diffusible hydrogen content to prevent subsequent cracking during repairs. For example a 25 mm (1 in) thick plate may require three hours at 426 °C (800 °F) or six hours at 315 °C (600 °F) to reach 1 ppm of residual hydrogen. Hydrogen flux monitor may be considered for use in determining what hydrogen bake-out is sufficient. Bake-out temperatures up to those required for full PWHT may be used for holding times shorter than specified for PWHT. 4.4 Repair of Hydrogen Blisters 4.4.1 Hydrogen blisters may be evaluated in accordance with the provisions of API 579-1/ASME FFS-1, an equivalent fitness-for-service document, or applicable industry code or standard. If it is determined that hydrogen blisters are present to the extent that repairs are necessary, the following options may be used. 4.4.1.1 Surface blisters less than 50 mm (2 in) in diameter may be drilled to relieve the internal pressure. Appropriate caution shall be taken to protect the operator from injury during hydrogen venting. An engineering analysis shall be performed prior to drilling blisters larger than 50 mm (2 in) in diameter to ensure that the remaining net section of metal will hold the internal pressure. 4.4.1.2 Blistered steel plates may be removed from the vessel and replaced with new steel. Hydrogen bake-out in accordance with Paragraph 4.3 may be required prior to thermal cutting or welding. CAUTIONARY NOTE: Hydrogen blisters are typically filled with molecular hydrogen, which will not diffuse during the bake-out described in Paragraph 4.3 or during PWHT. As a result, the blisters may grow or rupture during the bake-out or PWHT. In addition, molecular hydrogen remaining in blisters after the bakeout may cause cracking during subsequent repair or PWHT. High-temperature hydrogen attack may also result from PWHT.26 4.5 Removal of Cracks 4.5.1 Cracks may be evaluated in accordance with the provisions of API 579-1/ASME FFS-1, an equivalent fitness-for-service document, or an applicable industry code or standard. When crack removal is determined to be necessary, cracks may be removed by any suitable method (e.g., grinding or arc gouging). If arc gouging or another method that will heat the steel above its lower critical temperature is used, subsequent grinding shall be used to remove all heat-affected material. 4.5.2 The excavated area should be reinspected with WFMT to ensure that all cracks have been removed. 4.5.3 Once the cracks have been removed, the need for weld repair shall be determined based on the minimum required wall thickness or an engineering fitness-for-service analysis. Local areas thinned beyond the corrosion allowance may be acceptable under some conditions, such as those outlined in ANSI/API 510, API 579-1/ASME FFS-1, or other applicable industry code or standard. 4.6 Blend Grinding Repairs The cavities formed by removing the cracks that are not subsequently weld repaired shall be contoured to eliminate notches in accordance with the provisions of API 579-1/ASME FFS-1 or other applicable industry code or standard. An appropriate taper or radius is recommended to avoid sharp edges that could act as stress raisers and lead to further cracking, or confuse interpretation of subsequent UT inspections. 4.7 Weld Repairs 4.7.1 If weld repairs are determined to be necessary, they shall be made in accordance with a recognized code such as ANSI/API 510, ANSI/API 570, or other applicable industry code or standard.

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SP0296-2010 4.7.2 Preheat should be applied to the repair area when deemed necessary. When possible, the preheat should be applied from the outside of the vessel and measured on the inside. This method of applying preheat ensures that the required temperature has been achieved through the full material thickness. 4.7.3 Low-hydrogen welding electrodes should be used and handled in accordance with ASME SFA-5.1,27 or other applicable industry code or standard, and the electrode manufacturerâ&#x20AC;&#x2122;s recommendations to minimize the potential for delayed hydrogen (cold) cracking. 4.7.4 Arc strikes should be removed by blend grinding. 4.7.5 The repair area should be given a PWHT in accordance with the ASME Boiler and Pressure Vessel Code, Section VIII,28 Division 1 or Division 2 as appropriate, or other applicable industry code or standard after welding, especially if PWHT was performed in original fabrication. Heat treatment at lower temperatures (below 593 Â°C [1,100 Â°F]) for longer times, as allowed by the ASME code, should not be used. 4.7.5.1 Certain microalloying elements that can be present in pressure vessel steels can retard the softening effect of PWHT. When microalloying elements are known to be present, consideration should be given to increasing the PWHT temperature such that suitable softening of the weld and HAZ is accomplished. 4.7.5.2 PWHT of vessels containing blisters or HIC can result in additional cracking. See the cautionary note in Paragraph 4.4.1.2. 4.7.5.3 As an alternative to conventional PWHT, welding techniques that soften the HAZ, such as temper bead welding in accordance with ANSI/API 510, may be used. This may control HAZ hardness, but has no significant impact on residual stress levels, which often govern SSC and ASCC. Consideration may also be given to the mitigation techniques outlined in Section 5. 4.7.6 Repair weld hardness control shall be in accordance with methods and procedures in NACE SP0472 suitable for the repair welding being performed, which may include the following: (a) Weld deposit hardness control. This control impacts SSC concerns resulting from high weld hardness, but may not ensure freedom from SOHIC or ASCC. (b) Thermal methods and preproduction weld procedure thermal-related reporting and controls. thermal methods are cooling time control, PWHT control, and temper bead welding. (c)

The

Preproduction weld procedure HAZ hardness controls and testing for the weld deposit.

Some procedures in NACE SP0472 may have limited applicability for repair welds, such as the following: (a) Base metal chemistry control. The base metal chemistry and susceptibility to wet H2S damage is fixed because the repair is to existing equipment that has experienced damage. However, this may be used as part of repair in accordance with NACE SP0472 where new material is being used as part of the repair. (b) Preproduction weld procedure HAZ hardness controls and testing for the base material. Implementing this method effectively for the base material requires the procedure to be qualified with materials closely matching those of the component being repaired. This may not be feasible for a repair. (c)

Preproduction weld procedure base metal chemistry controls and reporting.

4.7.7 The repair area should be reinspected after welding and, when specified, PWHT. When delayed hydrogen (cold) cracking is a concern, a minimum interval of 48 hours should be provided between welding and final inspection for repairs that do not undergo PWHT immediately after welding, or not at all. Delayed cracking can take some time to present itself, but owner/users often do not wait the full 48 hours. Any new cracks or NACE International

SP0296-2010 defects found should be repaired according to the steps outlined above. If a subsequent welded repair is required (repair of a repair), other remedial steps (e.g., hydrogen bake-out or higher preheat temperature) should be considered. 4.7.8 Radiographic testing (RT) or UT according to ASME Boiler and Pressure Vessel Code, Section VIII or other applicable industry standard should be considered for major repairs. RT, however, is not very sensitive for detecting smaller, tighter cracks. 4.7.9 Permanent records of repairs should be maintained for the life of the vessel. All relevant information, such as location, size, and depth of repair, repair method, preheat temperature (if any), and PWHT temperature and hold time (if any), should be recorded. 4.8 Replacing a section of the vessel or replacing the entire vessel are acceptable options to performing repairs. Replacement of piping is likewise an acceptable repair. Where size permits, seamless piping should be used instead of longitudinally seam-welded piping. ________________________________________________________________________ Section 5: Mitigation Considerations for Operation 5.1 The objective of this section is to outline several methods that may be used to decrease the likelihood or severity of cracking in wet H2S environments. 5.1.1 To the extent that modifications are acceptable from a process standpoint, process changes that may decrease the likelihood of cracking include control of water carry-over into downstream equipment, dilution or removal of corrosive constituents by water washing, or use of additives. The use of additives, such as polysulfide or other corrosion inhibitors, or the use of water washing to reduce concentrations of ammonium bisulfide and cyanide in the aqueous phase, have been shown to reduce hydrogen permeation at alkaline pH levels. Polysulfide may provide a resistant corrosion product film and it converts cyanides in the aqueous phase into thiocyanates. (NOTE: Polysulfide does not react with cyanides in the gas phase.) 5.1.2 Corrosion inhibitors injected into the process stream may decrease the corrosion reaction, which tends to lower the cathodic evolution of atomic hydrogen and hence lower the potential for hydrogen entry into the steel and subsequent blistering and cracking. 5.1.3 Organic or inorganic coatings may be used as a barrier to corrosion. Care should be taken to select a suitable coating that will perform in the process environment and during shutdown operations such as depressurizing and steam-out. Periodic inspection and maintenance of the coating should be performed over the life of the equipment to ensure continuing protection. If coating deterioration is evident, consideration should be given to inspecting the internal steel surfaces periodically for cracking. 5.1.4 A corrosion-resistant alloy in the form of cladding, weld overlay, or strip lining can be applied to the equipment interior as a permanent corrosion barrier. 5.1.4.1 Plate that is clad by the hot-rolling or explosive-bonding process can be used for replacement parts of existing equipment. 5.1.4.2 Weld overlay can be applied in situ or installed as a replacement part. Weld overlay should not be applied directly to the surfaces of materials containing cracks or hydrogen blisters. 5.1.4.3 Attachment of strip lining by welding can also be used to cover existing areas of equipment. Periodic inspection and maintenance of strip lining should be performed over the life of the equipment to ensure protection. Cracking of the strip-lining attachment welds because of issues such as differential expansion may result in process fluids entering the gap between the lining and the base metal. Subsequent cracking of the base metal beneath the lining can occur as a result of exposure to wet H2S. Additionally, 14

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SP0296-2010 cracking into the base metal at the termination point of the strip lining has been shown to occur in laboratory testing.29 This latter issue has not been shown to be a significant problem in actual service, however. 5.1.5 An on-stream corrosion-monitoring program may be used to detect corrosion activity that may produce conditions leading to cracking. This also helps to determine whether certain corrosion control methods, such as chemical injection (e.g., polysulfide injection) or water washing, are effective. The corrosion-monitoring program may include corrosion coupons and/or corrosion probes, hydrogen probes, and UT measurements. ________________________________________________________________________ References 1. NACE Publication 8X294 (latest revision), “Review of Published Literature on Wet H2S Cracking of Steels Through 1989” (Houston, TX: NACE). 2. NACE Publication 8X194 (latest revision), “Materials and Fabrication Practices for New Pressure Vessels Used in Wet H2S Refinery Service” (Houston, TX: NACE). 3. NACE SP0472 (formerly RP0472) (latest revision), “Methods and Controls to Prevent In-Service Environmental Cracking of Carbon Steel Weldments in Corrosive Petroleum Refining Environments” (Houston, TX: NACE). 4. NACE Standard MR0103 (latest revision), “Materials Resistant to Sulfide Stress Cracking in Corrosive Petroleum Refining Environments” (Houston, TX: NACE). 5.

API RP 945 (latest revision), “Avoiding Environmental Cracking in Amine Units” (Washington, DC: API)

6. NACE Publication 34108 (latest revision), “Review and Survey of Alkaline Carbonate Stress Corrosion Cracking in Refinery Sour Waters” (Houston, TX: NACE) 7. H.I. McHenry, D.T. Read, T.R. Shieves, “Failure Analysis of an Amine-Absorber Pressure Vessel,” MP 26, 8 (1987): p. 18. 8. J.P. Richert, A.J. Bagdasarian, C.A. Shargay, “Stress Corrosion Cracking of Carbon Steel in Amine Systems,” MP 27, 1 (1988): p. 9. 9.

R.D. Merrick, “Refinery Experiences With Cracking in Wet H2S Environments,” MP 27, 1 (1988): p. 30.

10. J.H. Kmetz, D.J. Truax, “Carbonate Stress Corrosion Cracking of Carbon Steel in Refinery FCC Main Fractionator Overhead Systems,” CORROSION/90, paper no. 206 (Houston, TX: NACE). 11. H.U. Schutt, “Intergranular Wet Hydrogen Sulfide Cracking,” MP 32, 11 (1993): pp 55-60. 12. API RP 580 (latest revision), “Risk-Based Inspection” (Washington, DC: API). 13. API RP 581 (latest revision), “Risk-Based Inspection Technology” (Washington, DC: API). 14. ASME PCC-3 (latest revision), “Inspection Planning Using Risk-Based Methods” (New York, NY: ASME). 15. NACE No. 2/SSPC-SP 10 (latest revision), “Near-White Metal Blast Cleaning” (Houston, TX: NACE). 16. ASME SE-709 (latest revision), “Standard Guide for Magnetic Particle Examination” (New York, NY: ASME). 17. API Publication 939-A, “Research Report on Characterization and Monitoring of Cracking in Wet H2S Service” (Washington, DC: API).

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SP0296-2010 18. ASNT SNT-TC-1A (latest revision), “Personnel Qualification and Certification in Nondestructive Testing” (Columbus, OH: ASNT). 19. ANSI/API 510 (latest revision), “Pressure Vessel Inspection Code: In-Service Inspection, Rating, Repair, and Alteration” (New York, NY: ANSI and Washington, DC: API). 20. ANSI/API 570 (latest revision), “Piping Inspection Code: In-Service Inspection, Rating, Repair, and Alteration of Piping Systems” (New York, NY: ANSI and Washington, DC: API). 21. ANSI/NBBPVI NB-23 (latest revision), “National Board Inspection Code” (New York, NY: ANSI and Columbus, OH: NBBPVI). 22. ASME PCC-2 (latest revision), “Repair of Pressure Equipment and Piping” (New York, NY: ASME). 23. ASME Boiler and Pressure Vessel Code, Section V (latest revision), “Nondestructive Examination” (New York, NY: ASME). 24. API 579-1/ASME FFS-1 (latest revision), “Fitness for Service” (Washington, DC: API and New York, NY: ASME). 25. ASME Boiler and Pressure Vessel Code, Section IX (latest revision), “Welding and Brazing Qualifications” (New York, NY: ASME). 26. J.L. Hau, C.H. Molina, “Hydrogen Damage Inspection and Evaluation of H2S Absorber Column,” CORROSION/92, paper no. 446 (Houston, TX: NACE, 1992). 27. ASME SFA-5.1 (latest revision), “Specification for Carbon Steel Electrodes for Shielded Metal Arc Welding” (New York, NY: ASME). 28. ASME Boiler and Pressure Vessel Code, Section VIII (latest revision), “Rules for Construction of Pressure Vessels” (New York, NY: ASME). 29. API Publication 939-B (latest revision), “Repair and Remediation Strategies for Equipment Operating in Wet H2S Service” (Washington, DC: API). ________________________________________________________________________ Bibliography Bartz, M.H., and C.E. Rawlins. “Effects of Hydrogen Generated by Corrosion of Steel.” Corrosion 4, 5 (1948): p. 187. Berkowitz, B.J., and H.H. Horowitz. “The Role of H2S in the Corrosion and Hydrogen Embrittlement of Steel.” Journal of Electrochemical Society 129, 3 (1982): p. 468. Bulla, J.T., and J.T. Chikos. “Case History—FCCU Absorber Deethanizer Tower Hydrogen Blistering and Stepwise Cracking.” CORROSION/89, paper no. 264. Houston, TX: NACE, 1989. Cayard, M.S., R.D. Kane, L. Kaley, and M. Prager. “Research Report on Characterization and Monitoring of Cracking in Wet H2S Service.” API Publication 939. Washington, DC: API, October 1994. Gutzeit, J. “Process Changes for Reducing Pressure Vessel Cracking Caused by Aqueous Sulfide Corrosion.” MP 31, 5 (1992): p. 60.

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SP0296-2010 Hildebrand, E.L. Aqueous Phase H2S Cracking of Hard Carbon Steel Weldments—A Case History, Proceedings API, vol. 50 (III). Washington, DC: API, 1970: p. 593. Kotecki, D.J., and D.G. Howden. Weld Cracking in a Wet Sulfide Environment, Proceedings API, vol. 53 (III). Washington, DC: API, 1973: p. 573. Kotecki, D.J., and D.G. Howden. Wet Sulfide Cracking of Submerged Arc Weldments, Proceedings API, vol. 52 (III). Washington, DC: API, 1972: p. 631. Merrick, R.D., and M.L. Bullen. “Prevention of Cracking in Wet H2S Environments.” CORROSION/89, paper no. 269. Houston, TX: NACE, 1989. Neill, W.J. Jr. “Prevention of In-Service Cracking of Carbon Steel Welds in Corrosive Environments.” Materials Protection and Performance 10, 8 (1971): p. 33. Schuetz, A.E., and W.D. Robertson. “Hydrogen Absorption, Embrittlement, and Fracture of Steel.” Corrosion 13, 7 (1957): p. 437t. Schutt, H.U. “New Aspects of Stress Corrosion Cracking in Monoethanolamine Solutions.” MP 27, 12 (1988): p. 53. Van Gelder, K., M.J.J. Simon Thomas, and C.J. Kroese. “Hydrogen Induced Cracking: Determination of Maximum Allowed H2S Partial Pressures.” Corrosion 42, 1 (1986): p. 36. ________________________________________________________________________ Appendix A Cited Codes, Specifications, and Standards (Nonmandatory) This appendix is considered nonmandatory, although it may contain mandatory language. It is intended only to provide supplementary information or guidance. The user of this standard is not required to follow, but may choose to follow, any or all of the provisions herein. ASME International Boiler and Pressure Vessel Code Section II, Part C

“Specifications for Welding Rods, Electrodes, and Filler Metals”

Section V

“Nondestructive Examination”

Section VIII

“Rules for Construction of Pressure Vessels”

Section IX

“Welding and Brazing Qualifications”

SE-709

“Standard Guide for Magnetic Particle Examination”

PCC-2

“Repair of Pressure Equipment and Piping”

PCC-3

“Inspection Planning Using Risk-Based Methods”

ASTM International(7) A 53/A 53M (7)

“Standard Specification for Pipe, Steel, Black and Hot-Dipped, Zinc-Coated, Welded and Seamless”

ASTM International (ASTM), 100 Barr Harbor Dr., West Conshohocken, PA 19248-2959.

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SP0296-2010 A 70

“Specification for Low and Intermediate Tensile Strength Carbon Steel” (withdrawn 1947—replaced by A 285/A 285M)

A 106/A 106M “Standard Specification for Seamless Carbon Steel Pipe for High-Temperature Service” A 201

“Specification for Carbon-Silicon Steel Plates of Intermediate Tensile Ranges for Fusion-Welded Boilers and Other Pressure Vessels” (withdrawn 1967—replaced by A 515/A 515M)

A 212

“Specification for High Tensile Strength Carbon-Silicon Steel Plates for Boilers and Other Pressure Vessels” (withdrawn 1967—replaced by A 515/A 515M)

A 285/A 285M “Standard Specification for Pressure Vessel Plates, Carbon Steel, Low- and Intermediate-Tensile Strength” A 515/A 515M “Standard Specification for Pressure Vessel Plates, Carbon Steel, for Intermediate- and HigherTemperature Service” A 516/A 516M “Standard Specification for Pressure Vessel Plates, Carbon Steel, for Moderate- and LowerTemperature Service” NACE International MR0103

“Materials Resistant to Sulfide Stress Cracking in Corrosive Petroleum Refining Environments”

NACE No. 2/SSPC-SP 10 SP0472

“Near-White Metal Blast Cleaning”

“Methods and Controls to Prevent In-Service Environmental Cracking of Carbon Steel Weldments in Corrosive Petroleum Refining Environments”

American Society for Nondestructive Testing (ASNT) SNT-TC-1A

“Personnel Qualification and Certification in Nondestructive Testing”

American Petroleum Institute (API) ANSI/API 510

“Pressure Vessel Inspection Code: In-Service Inspection, Rating, Repair, and Alteration”

ANSI/API 570

“Piping Inspection Code: In-Service Inspection, Rating, Repair, and Alteration of Piping Systems”

API 579-1/ASME FFS-1

“Fitness-for-Service”

API RP 580

“Risk-Based Inspection”

API RP 581

“Risk-Based Inspection Technology”

National Board of Boiler and Pressure Vessel Inspectors (NBBPVI) NB-23

“National Board Inspection Code” (NBIC)

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SP0296-2010 ________________________________________________________________________ Appendix B Nature and Extent of Problem—Results from 1990 T-8-16a Survey (Nonmandatory) This appendix is considered nonmandatory, although it may contain mandatory language. It is intended only to provide supplementary information or guidance. The user of this standard is not required to follow, but may choose to follow, any or all of the provisions herein.

B1 The objective of this section is to report the frequency and severity of cracking of existing carbon steel pressure vessels in petroleum refinery wet H2S environments. B2

Survey of Inspection Results B2.1 A survey was conducted in 1990 by Work Group T-8-16a to determine the nature and extent of cracking problems in wet H2S environments in the petroleum refining industry. Insufficient information was reported about the type of cracking found to correlate cracking incidence with cracking mechanism. In addition to asking for crack inspection results, the survey requested information about original fabrication details, service environment, prior inspection history, and disposition of cracked vessels (e.g., type of repairs, replacement). B2.2 The use of various inspection techniques, such as visual inspection for hydrogen blisters and magnetic particle testing and liquid penetrant testing for crack detection, was reported. However, most of the inspections for cracks were performed using WFMT, which is a very sensitive inspection technique for detection of surface discontinuities. Therefore, in addition to detecting service-related cracks, a number of linear indications that may have been discontinuities present from original fabrication, repair, or alteration of the pressure vessels were found. Subsurface cracks may not be detected by this method. Reporting of discontinuities was not uniform; some companies reported all discontinuities, some excluded obvious fabrication discontinuities, and others excluded very shallow indications that could easily be ground out. In the context of this appendix, the terms “cracks” and “cracking” refer to all linear indications reported by the survey respondents. B2.3 Survey responses covering inspection results for almost 5,000 pressure vessels were received. Overall, cracking was reported in 26% of the inspected pressure vessels, as shown in Table B1. Table B1 Overall Summary Number of Pressure Vessels Inspected Number of Pressure Vessels Cracked Cracking Incidence

4,987 1,285 26%

B2.4 Cracking incidence reported by different companies varied from a low of 10% to a high of 73%. The cracking incidence reported by each company is shown in Table B2.

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SP0296-2010 Table B2 Cracking Reported by Company Company A B C D E F G H I J K L + Misc.

Number Inspected 45 1,358 968 55 179 104 85 129 172 71 141 1,680

% Cracked 47 13 11 15 20 43 21 34 16 10 73 41

B2.5 The task group believes that a number of factors have influenced the wide disparity in cracking incidence reported by various companies, although not all were factors considered in the survey. These include, but are not limited to, differences in (1) surface preparation prior to inspection; (2) extent of inspection; (3) reporting of cracks, e.g., whether fabrication flaws or shallow indications were excluded; (4) process units inspected; (5) crude feed compositions; and (6) original fabrication practices. B2.6 Cracking was reported in pressure vessels in essentially all refinery process units with wet H2S environments. Table B3 shows the cracking incidence in each of the common refinery process units. B2.7 Cracking incidence varied from a low of 18 to 19% in crude units and coker fractionation units to a high of 45% in fluid catalytic cracking unit (FCCU) light-ends sections. Other process units also experiencing high cracking incidence include FCCU fractionation (41%), liquefied petroleum gas (LPG) (41%), and atmospheric light ends (38%). Table B3 Cracking by Process Unit Process Unit Crude Coker Fractionation Vacuum Amine Other Hydrotreating Sulfur Recovery Hydrocracking Sour Water Stripper Amine/Caustic Coker Light Ends Flare Catalytic Reformer Atmospheric Light Ends FCCU Fractionation LPG FCCU Light Ends 20

Number Inspected 300 44 71 574 364 368 96 156 132 811 91 23 134 140

% Cracked

252 49 704

41 41 45

18 19 21 21 23 25 27 28 28 29 30 30 34 38

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SP0296-2010 B2.8 Some companies reported that a significant percentage of cracking detected in FCCU fractionation was carbonate cracking, a form of ASCC in alkaline sour waters with high carbonate/bicarbonate concentration. Cracking was also prevalent in amine and caustic services. B2.9 The survey data show no strong correlation between cracking incidence and operating temperature. Throughout the entire range of operating temperatures, the cracking incidence only varied between 23% and 37%, as shown in Table B4. The highest cracking incidence occurred in the 65 to 93 °C (150 to 200 °F) operating temperature range. Table B4 Cracking vs. Operating Temperature Operating Temperature °C °F < 38 < 100 38–65 100–150 65–93 150–200 93–121 200–250 121–149 250–300 > 149 > 300

Number Inspected 284 926 385 312 237 356

% Cracked 23 34 37 33 27 29

B2.10 In general, cracking incidence increased with increasing H2S concentration in the water phase, as shown in Table B5. The most noteworthy observation is the 17% cracking incidence for pressure vessels in services containing less than 50 mg/L (50 ppmw) H2S dissolved in an aqueous phase. This is considered a high rate for a service environment previously thought not to be a concern. However, inclusion of fabrication-related discontinuities in some of the survey responses probably had an impact on this cracking incidence. The practical difficulty of measuring actual concentration of H2S in the aqueous phase, especially at low concentrations, also might have had an impact. In addition, upset conditions with higher H2S concentrations may have produced the cracking encountered in the cases with low reported H2S concentrations. Table B5 Cracking vs. H2S Concentration H2S Concentration (mg/L [ppmw]) < 50 50–250 250–500 500–1,000 1,000–2,500 2,500–5,000 5,000–10,000 > 10,000

Number Inspected 94 309 35 76 134 83 137 378

% Cracked 17 23 26 36 27 45 42 39

B2.11 The cracking incidences for refinery pressure vessels fabricated from the most commonly used ASTM specification steel materials are listed in Table B6. No correlation between cracking incidence and the specification of the steel plates used for fabrication of pressure vessels in wet H2S service was apparent. It was evident that the cracking incidence in pipe steels, such as ASTM A 53 and A 106, was much lower than that in plate steels.

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SP0296-2010 Table B6

Cracking vs. Steel Specification ASTM Steel Specification A 70 A 201 A 212 A 285 A 515 A 516 A 53 A 106

Number Inspected 230 102 277 907 293 681 129 103

% Cracked 20 32 30 29 36 27 9 12

B2.12 The cracking incidences for refinery pressure vessels fabricated from steel plates of the commonly used steel grades (with corresponding minimum tensile strength) are listed in Table B7. No trend between cracking incidence and plate steel grade was apparent. The lowest cracking incidence was experienced with Grade 60 materials, but this was based on far less data than those for Grades 55 and 70. Table B7 Cracking vs. Steel Grade Steel Grade(A) Grade 55 Grade 60 Grade 65 Grade 70

Number Inspected 1,187 202 35 1,085

% Cracked 28 22 31 31

(A)

Steel grade levels correspond to minimum tensile strength requirements (e.g., ASTM A 285 Grade C is included in Grade 55). B2.13 The cracking incidences for the two most common plate steel materials were 29% for A 285 Grade C, and 27% for A 516 Grade 70. Among the steel plate materials for which at least 100 inspection results were reported, the highest cracking incidence (36%) was experienced by pressure vessels fabricated with ASTM A 515 Grade 70 steel. B2.14 Table B8 lists the cracking incidence for pressure vessels with and without PWHT. The cracking incidence for pressure vessels with PWHT (25%) was only marginally lower than that for pressure vessels without PWHT (30%). The survey data included some fabrication flaws, as well as hydrogen blistering and HIC that would not be expected to benefit from PWHT. PWHT would be expected to be beneficial for resistance to SSC, SOHIC, and ASCC. Table B8 Cracking vs. PWHT Pressure Vessel Condition Non-PWHT PWHT

Number Inspected 2,325 1,132

% Cracked 30 25

B2.15 A strong correlation between cracking incidence and the hydrogen blistering history of the pressure vessel was evident, as shown in Table B9. Pressure vessels with a history of hydrogen blistering had approximately twice the cracking incidence (54%) of pressure vessels with no prior history of blistering (25%).

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SP0296-2010 Table B9 Cracking vs. Blistering History Pressure Vessel Condition No Blisters Blisters

Number Inspected 2,256 216

% Cracked 25 54

B2.16 The presence of weld repairs in pressure vessels did not appear to have a significant effect on cracking incidence, as shown in Table B10. Pressure vessels with prior weld repairs had only a marginally higher cracking incidence (30%) than pressure vessels without weld repairs (27%). Table B10 Cracking vs. Weld Repairs Pressure Vessel Condition No Weld Repairs Weld Repairs

Number Inspected 2,022 506

% Cracked 27 30

B2.17 The maximum depth of cracking reported is shown in Table B11. Only 38% of the cracked pressure vessels experienced cracking with a maximum depth of less than 3.18 mm (0.125 in). Conversely, more than 60% of the cracked pressure vessels experienced cracking deeper than 3.18 mm (0.125 in). Approximately 20% of the cracked pressure vessels had cracking deeper than 9.53 mm (0.375 in). Table B11 Depth of Cracking Crack Depth mm in < 1.59 < 0.0625 1.59–3.18 0.0625–0.125 3.18–4.78 0.125–0.188 4.78–6.35 0.188–0.250 6.35–9.53 0.250–0.375 9.53–12.7 0.375–0.500 12.7–19.1 0.500–0.750 19.1–25.4 0.750–1.00 > 25.4 > 1.00

Number of Vessels 83 185 67 124 99 45 77 10 14

Percent 12 26 10 18 14 6 11 1 2

B2.18 Crack penetration, a ratio calculated by dividing the maximum depth of cracking by the wall thickness of the pressure vessel, is shown in Table B12. Approximately 40% of the cracked pressure vessels experienced less than one-quarter penetration through the wall thickness. Approximately 40% of the cracked pressure vessels experienced cracking more than halfway through the wall thickness.

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SP0296-2010 Table B12 Crack Penetration Crack Penetration (% of Wall Thickness) < 10 10–24 25–49 50–74 75–99 100

Number of Vessels 59 120 106 99 37 36

Percent 13 26 23 22 8 8

B2.19 Table B13 summarizes the reported disposition of the pressure vessels that were found to contain cracks. In 43% of the cracked pressure vessels, the cracks were sufficiently shallow that they could be ground out and weld repairs were not required to restore vessel integrity. Approximately 38% required weld repairs to restore vessel integrity. One of five was replaced after the inspection or a replacement was planned for the near future. Table B13 Disposition of Cracked Pressure Vessels

Pressure Vessel Disposition

Number

Percent

Cracks Ground Out

476

Weld Repaired

426

Replaced (Done/Planned)

214

Summary of Observations B3.1 The extent and magnitude of cracking of pressure vessels in wet H2S environments is a significant concern in the petroleum refining industry. B3.2

All process units containing wet H2S environments appear to be affected, but to varying degrees.

B3.3 A strong correlation between cracking incidence and a history of hydrogen blistering in pressure vessels exists. B3.4 A strong correlation between cracking incidence and any singular process parameter, such as operating temperature or stream chemistry, does not exist in this particular survey. Nevertheless, recommendations in Paragraph 3.6.2 (e), which also take industry experience into account, are valid. B3.5 A strong correlation between cracking incidence and material and fabrication factors such as specification and grade of steel commonly used for pressure vessels, PWHT, or prior weld repairs is not apparent in this particular survey. However, it is generally recognized that PWHT is beneficial for prevention of certain types of cracking mechanisms (see Paragraph 2.4.3.2 and recommendations in Paragraphs 3.6.2 [b] and 4.7.5). B3.6 A significant (17%) incidence of cracking was reported in pressure vessels exposed to process environments with less than 50 mg/L (50 ppmw) H2S in the aqueous phase. However, inclusion of fabrication-

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SP0296-2010 related discontinuities by some respondents or difficulty in measuring low concentrations of H2S in the aqueous phase probably had an impact on this result. B3.7 The number of pressure vessels involved and the required corrective action demonstrates the potential impact of this problem on refinery production losses and maintenance costs. However, despite the high incidence of cracking reported in this survey, few in-service failures of carbon steel vessels in wet H2S environments have been reported. ________________________________________________________________________ Appendix C Typical Cracks Found in Wet H2S Environments (Nonmandatory) This appendix is considered nonmandatory, although it may contain mandatory language. It is intended only to provide supplementary information or guidance. The user of this standard is not required to follow, but may choose to follow, any or all of the provisions herein.

Figure C1: SSC in HAZ of head-to-shell weld of FCCU absorber tower. The crack is on the ASTM A 516-70 shell side. The numbers in the photograph are Knoop hardness values. (nital etch)

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Figure C2: Hydrogen blister in ASTM A 516-70 amine contactor/water wash tower.

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Figure C3(a): Hydrogen blisters on ID surface of amine contactor/water wash tower.

Figure C3(b): Cross-section of plate shown in upper photo illustrating HIC (â&#x20AC;&#x153;stepwiseâ&#x20AC;? cracking).

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Figure C4: SOHIC in soft base metal extending from the tip of SSC in a hard HAZ of a repair weld in the shell of a primary absorber (deethanizer) column in an FCCU gas plant. The ASTM A 212-B steel shell was given PWHT at original fabrication, but the repair weld was not. (nital etch)

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Figure C5: ASCC (carbonate cracking) of non-PWHT ASTM A 285-C steel shell of FCCU main fractionator overhead accumulator. Cracking was found near welds in the lower portion of vessel.

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NACE SP0472-2010 (formerly RP0472) Item No. 21006

Standard Practice Methods and Controls to Prevent In-Service Environmental Cracking of Carbon Steel Weldments in Corrosive Petroleum Refining Environments This NACE International standard represents a consensus of those individual members who have reviewed this document, its scope, and provisions. Its acceptance does not in any respect preclude anyone, whether he or she has adopted the standard or not, from manufacturing, marketing, purchasing, or using products, processes, or procedures not in conformance with this standard. Nothing contained in this NACE International standard is to be construed as granting any right, by implication or otherwise, to manufacture, sell, or use in connection with any method, apparatus, or product covered by Letters Patent, or as indemnifying or protecting anyone against liability for infringement of Letters Patent. This standard represents minimum requirements and should in no way be interpreted as a restriction on the use of better procedures or materials. Neither is this standard intended to apply in all cases relating to the subject. Unpredictable circumstances may negate the usefulness of this standard in specific instances. NACE International assumes no responsibility for the interpretation or use of this standard by other parties and accepts responsibility for only those official NACE International interpretations issued by NACE International in accordance with its governing procedures and policies which preclude the issuance of interpretations by individual volunteers. Users of this NACE International standard are responsible for reviewing appropriate health, safety, environmental, and regulatory documents and for determining their applicability in relation to this standard prior to its use. This NACE International standard may not necessarily address all potential health and safety problems or environmental hazards associated with the use of materials, equipment, and/or operations detailed or referred to within this standard. Users of this NACE International standard are also responsible for establishing appropriate health, safety, and environmental protection practices, in consultation with appropriate regulatory authorities if necessary, to achieve compliance with any existing applicable regulatory requirements prior to the use of this standard. CAUTIONARY NOTICE: NACE International standards are subject to periodic review, and may be revised or withdrawn at any time in accordance with NACE technical committee procedures. NACE International requires that action be taken to reaffirm, revise, or withdraw this standard no later than five years from the date of initial publication and subsequently from the date of each reaffirmation or revision. The user is cautioned to obtain the latest edition. Purchasers of NACE International standards may receive current information on all standards and other NACE International publications by contacting the NACE International FirstService Department, 1440 South Creek Dr., Houston, Texas 77084-4906 (telephone +1 281-228-6200).

Revised Revised 2010-03-13 2010-03-13 Revised 2008-11-07 2008-11-07 Revised Revised 2005-12-02 2005-12-02 Revised Reaffirmed 2000-09-13 2000-09-13 Reaffirmed Revised October Revised October 1995 1995 Revised March 1987 NACE International Reaffirmed 1974 1440 SouthApril Creek Dr. Approved 1972 Houston, Texas 77084-4906 NACE International +1 281/228-6200 1440 South Creek Dr. ISBN 1-57590-114-5 Houston, Texas 77084-4906

ÂŠ 2010, International +1NACE 281-228-6200 ISBN 1-57590-114-5 ÂŠ 2010, NACE International

SP0472-2010

________________________________________________________________________ Foreword This NACE standard defines standard practices for producing weldments in P-No. 1 steels resistant to environmental cracking in corrosive petroleum refining environments. It is intended to be used by refiners, equipment manufacturers, engineering contractors, and construction contractors. Most petroleum refining equipment are constructed from carbon steel having a minimum specified tensile strength of 480 MPa (70,000 psi) or less, and in almost every case, the equipment is fabricated by welding. The welds for refinery equipment are made to conform to various codes and standards, including the ASME(1) Boiler and Pressure Vessel Code, Section VIII1 for pressure vessels, ASME/ANSI(2) B31.32 for process piping, or API(3) Standards 6203 and 6504 for tanks. According to these codes and standards, these carbon steels are classified as P-No. 1, Group 1 or 2, and in this standard, they are referred to as P-No. 1 steels. Petroleum refineries as well as oil- and gas-processing plants have predominantly used P-No. 1 steels for services containing wet hydrogen sulfide (H2S), or sour services. They are the basic materials of construction for pressure vessels, heat exchangers, storage tanks, and piping. Decades of successful service have shown them to be generally resistant to a form of hydrogen stress cracking (HSC) called sulfide stress cracking (SSC). HSC occurs in high-strength materials or zones of a hard or high-strength microstructure in an otherwise soft material. With commonly used fabrication methods, P-No. 1 steels should be below the strength threshold for this cracking. NACE Standard MR01035 provides guidance for materials in sour oil and gas environments in refinery services, including limiting the hardness of P-No. 1 steels and reducing the likelihood of SSC. NACE MR0175/ISO(4) 151566 provides additional guidance for materials in sour oil and gas environments in production services. In the late 1960s, a number of SSC failures occurred in hard weld deposits in P-No. 1 steel refinery equipment. To detect hard weld deposits caused by improper welding filler metals or procedures, the petroleum refining industry began requiring hardness testing of production weld deposits under certain conditions and applied a criterion of 200 Brinell hardness (HBW) maximum. These requirements were given in previous editions of this standard and in API RP 942.7 In the late 1980s, instances of heat-affected zone (HAZ) cracking were reported in P-No. 1 steel equipment that met the 200 HBW weld deposit hardness limit. Some cases were determined to be SSC that was caused by high hardness in the HAZ. Some were

__________________________________________ (1) (1) ASME International (ASME), Three Park Avenue, New York, NY 10016-5990. (2) ASME International (ASME), Three Park Avenue, New York, NY 10016-5990. (2) American National Standards Institute (ANSI), 25 West 43rd St., 4th Floor, New York, NY 10036. (3) American National Standards Institute (ANSI), 25 West 43rd St., 4th Floor, New York, NY 10036. (3) American Petroleum Institute (API), 1220 L St. NW, Washington, DC 20005-4070. (4) American Petroleum Institute (API), 1220 L St. NW, Washington, DC 20005-4070. (4) International Organization for Standardization (ISO), 1 ch. de la Voie-Creuse, Case postale 56,

CH-1211, Geneva 20, International Organization for Standardization (ISO), 1 ch. de la Voie-Creuse, Case postale 56, CH-1211, Geneva 20, Switzerland. Switzerland.

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identified as another form of hydrogen damage called stress-oriented hydrogen-induced cracking (SOHIC).8 These cracks propagated primarily in the HAZs of weldments and were found in both high- and low-hardness HAZs. Other HAZ cracking instances in specific corrosive refinery process environments were attributed to alkaline stress corrosion cracking (ASCC), which can occur as a result of high residual stress levels. HAZ hardness controls and reduction of residual stresses in weldments were outside the scope of early editions of this standard, which covered only weld deposit hardness limits. The 1995 revision of this standard was expanded to cover the entire weldment and the various in-service cracking mechanisms (HSC in the weld deposit, HSC in the weld HAZ, and ASCC) that can occur in corrosive petroleum refining environments. This standard was originally prepared in 1972 by NACE Task Group (TG) T-8-7, which was composed of corrosion consultants, corrosion engineers, and other specialists associated with the petroleum refining industry. It was reaffirmed in 1974, and revised in 1987 and 1995. It was reaffirmed in 2000 by Specific Technology Group (STG) 34, “Petroleum Refining and Gas Processing,” and revised in 2005, 2008, and 2010 by TG 326, “Weldments, Carbon Steel: Prevention of Environmental Cracking in Refining Environments.” API previously published a standard, API RP 942, with similar objectives. The API standard has been discontinued with the intention of recognizing this NACE standard as the industry consensus standard. This standard is issued by NACE International under the auspices of STG 34. In NACE standards, the terms shall, must, should, and may are used in accordance with the definitions of these terms in the NACE Publications Style Manual. The terms shall and must are used to state a requirement, and are considered mandatory. The term should is used to state something good and is recommended, but is not considered mandatory. The term may is used to state something considered optional. ________________________________________________________________________

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________________________________________________________________________

NACE International Standard Practice Methods and Controls to Prevent In-Service Environmental Cracking of Carbon Steel Weldments in Corrosive Petroleum Refining Environments Contents 1. General ......................................................................................................................... 1 2. Prevention of Hydrogen Stress Cracking ..................................................................... 5 3. Prevention of Alkaline Stress Corrosion Cracking ..................................................... 14 References ........................................................................................................................ 15 Bibliography ...................................................................................................................... 17 Appendix A: Rationale for Guidelines for Prevention of Hydrogen Stress Cracking ........ 18 Appendix B: Rationale for Guidelines for Prevention of Alkaline Stress Corrosion Cracking ........................................................................................................... 26 Appendix C: Summary of Cooling Time (t8/5) Concept ..................................................... 27 FIGURES Figure 1: Interrelationships of the various cracking mechanisms. ...................................... 2 Figure 2: Hardness test locations.. .................................................................................. 10 Figure 3: Hardness test details.. ...................................................................................... 11 Figure C1: Types of heat flow during welding.................................................................. 27 Figure C2: Transition plate thickness (dt) from three-dimensional to two-dimensional heat flow as a function of heat input (Q) for different preheat temperatures (Tp). ............ 28 Figure C3: Cooling time (t8/5) for three-dimensional heat flow as a function of heat input (Q) for different preheat temperatures (Tp). ...................................................................... 31 Figure C4: Cooling time (t8/5) for two-dimensional heat flow as a function of heat input (Q) for different preheat temperatures (Tp) and plate thicknesses (d). ............................. 32 TABLES Table 1: â&#x20AC;&#x153;Road Mapâ&#x20AC;? for SP0472 ....................................................................................... 4 Table 2: Welding Process/Filler Metal Combinations Exempt from Weld Deposit Hardness Testing ................................................................................................................ 5 Table A1: Level of Base Metal Chemistry Control as a Function of Butt Weld Joint Configurations and HAZ Hardness Control Method Used ................................................ 21 Table C1: Shape Factors for Influence of the Form of Weld on t8/5 ................................................... 30 ________________________________________________________________________

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SP0472-2010 ________________________________________________________________________ Section 1: General 1.1 This standard establishes guidelines to prevent most forms of environmental cracking of weldments in carbon steel refinery equipment, including pressure vessels, heat exchangers, piping, valve bodies, and pump and compressor cases. Weldments are defined to include the weld deposit, base metal HAZ, and adjacent base metal zones subject to residual stresses from welding. 1.2 This standard covers only carbon steels classified as P-No. 1, Group 1 or 2. These classifications can be found in the ASME Boiler and Pressure Vessel Code, Section IX9 for pressure vessels, ASME/ANSI B31.3 for process piping, or API Standards 620 and 650 for tanks. It excludes steels with greater than 480 MPa (70,000 psi) minimum specified tensile strength. Other materials may be vulnerable to cracking, but these materials are outside the scope of this standard. 1.3 The types of equipment covered by this standard include pressure vessels, heat exchangers, piping, valve bodies, and pump and compressor cases. All pressure-containing weldments or internal attachment weldments to the pressure boundary are included. External attachment weldments are sometimes included as discussed in Paragraph 3.5.1. In addition, this standard may be applied to weldments in some non-pressure-containing equipment, such as atmospheric storage tanks. 1.4 Both new fabrication and repair welds are within the scope of this standard. The practices included herein are intended to prevent in-service cracking and are not intended to address cracking that can occur during fabrication, such as delayed hydrogen cracking. In most cases, however, these practices are also helpful in minimizing these fabrication problems. Useful information for preventing delayed hydrogen cracking is provided by F.R. Coe, et al.10 1.5 Welding processes covered by this standard include shielded metal arc welding (SMAW); gas metal arc welding (GMAW); flux-cored arc welding (FCAW); gas tungsten arc welding (GTAW); and submerged arc welding (SAW). Almost all types of weld configurations are included. For specific exceptions, such as hot taps, hardness limits and postweld heat treatment (PWHT) requirements should be reviewed on a case-by-case basis. 1.6 Corrosive refinery process environments covered by this standard can be divided into two general categories: services that could cause cracking as a result of hydrogen charging, and services that could cause ASCC. However, identification of the specific environments to which the guidelines set forth in this standard are to be applied to prevent various forms of in-service environmental cracking is the responsibility of the user. Figure 1 is a simplified schematic showing the interrelationships of the various cracking mechanisms discussed in this standard.

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SP0472-2010

ENVIRONMENTAL CRACKING(A) OF CARBON STEEL

ALKALINE STRESS CORROSION CRACKING (ASCC)(A)

CRACKING AS A RESULT OF HYDROGEN CHARGING

HYDROGEN STRESS (A,B) CRACKING (HSC)

HYDROGEN (A,C) BLISTERING

ENVIRONMENTS SUCH AS: -Caustic

NONSULFIDE ENVIRONMENTS SUCH AS:

SULFIDE STRESS CRACKING (SCC)(A)

HYDROGEN-INDUCED (A,C) CRACKING (HSC)

Hydrofluoric acid STRESS-ORIENTED HYDROGEN-INDUCED CRACKING (SOHIC)(C) SEE FOOTNOTE

-Alkanolamine solutions containing CO2 and/or H2S -Alkaline sour waters containing carbonates

(B)

_______________________________ (A) Refer to the NACE Glossary of Corrosion-Related Terms11 for definitions (including stress corrosion cracking). (B) The forms of environmental cracking included within the double lines are commonly referred to as wet H2S cracking when they occur in wet H2S environments. (C) This form of environmental cracking can also occur in nonsulfide environments such as hydrofluoric acid.

Figure 1: Interrelationships of the various cracking mechanisms. 1.6.1 Services that could cause cracking as a result of hydrogen charging: 1.6.1.1 In these services, the environment or corrosion reactions result in diffusion of atomic hydrogen into the base metal and weldment. In high-strength or high-hardness areas, this hydrogen can result in HSC. In petroleum refining processes, the primary manifestation of HSC is SSC of hard weldments in process environments containing wet H2S. Information regarding the definition of wet H2S refinery services is given in NACE Standard MR0103. However, other processes that promote aqueous corrosion of steel and promote hydrogen charging (such as hydrofluoric acid) can also cause HSC. Controlling both the weld deposit and HAZ hardness using the guidelines in Section 2 prevents HSC in most cases. 1.6.1.2 SOHIC can also occur in the services described above, but it does not require high strengths or high hardnesses. Hence, limiting weldment hardness does not prevent this form of cracking. Reducing weldment hardness and residual stress is believed to reduce the likelihood of this cracking, so the guidelines in Sections 2 and 3 may still be helpful. However, additional steps, such as the use of special clean steels, water washing, corrosion inhibitors, or corrosion-resistant liners, may be needed for some services. An overview of the materials selection, fabrication, PWHT, and testing practices that have been applied to new pressure vessels for preventing SOHIC is in NACE Publication 8X194.12 1.6.1.3 Cases of cracking of hard welds have occurred as a result of short-term upset, start-up, or transient conditions in non-stress-relieved P-No. 1 steel refinery equipment in which hydrogen sulfide is not normally present.

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SP0472-2010 1.6.1.4 Although this standard covers only P-No. 1 steels, welds have also cracked in tanks and pressure vessels constructed of non-stress-relieved P-No. 10A and 10C carbon-manganese steels. 1.6.2 Services that could cause ASCC: 1.6.2.1 Figure 1 provides examples of services that could cause ASCC, including caustic stress corrosion cracking, amine stress corrosion cracking, and alkaline carbonate cracking (commonly referred to as carbonate cracking). Section 3 provides common practices used to prevent these types of ASCC. Severity of cracking is often dependent on temperature, concentration, level of residual tensile stresses, and other factors. Controlling weldment hardness does not prevent ASCC because high tensile stresses still may be present. 1.6.2.2

Further information about caustic cracking and its prevention is in NACE SP0403.13

1.6.2.3

Further information about amine cracking and its prevention is in API RP 945.14

1.6.2.4

Further information about carbonate cracking and its prevention is in NACE Publication 34108.15

1.6.2.5 It is outside the scope of this standard to detail all the specific environments causing ASCC of PNo. 1 steels. Various reference books and publications contain information on ASCC environments and preventive measures.13â&#x20AC;&#x201C;16 1.7 One possible environmentally induced cracking mechanism in carbon steel weldments that is not addressed in this standard is high-temperature hydrogen attack. API RP 94117 gives recommendations on materials selection to avoid this problem. Other types of in-service cracking not addressed by this standard are primarily mechanical in nature (e.g., fatigue, creep, and brittle fracture). 1.8 This standard was reorganized in 2008 to present the standard practices in a specification format in the main body. All other supporting information and guidance are now in appendixes. 1.8.1 Appendix A (nonmandatory) provides the rationale for the guidelines in Section 2 for prevention of HSC. The paragraphs in Appendix A are numbered to correspond with the related paragraph in the main body of the standard for which it is providing the rationale (e.g., Paragraph A.2.3.2 in Appendix A corresponds to Paragraph 2.3.2 in Section 2). 1.8.2 Appendix B (nonmandatory) provides the rationale for the guidelines in Section 3 for prevention of ASCC. The paragraphs in Appendix B are numbered to correspond with the related paragraph in the main body of the standard for which it is providing the rationale. 1.8.3 Appendix C (nonmandatory) provides a summary of the cooling time (t8/5) concept discussed in Paragraph 2.3.5.2. 1.9 Table 1 provides an overview (â&#x20AC;&#x153;road mapâ&#x20AC;?) of the guidelines applicable to the various types of cracking.

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SP0472-2010 Table 1 “Road Map” for SP0472 General Service: Possible Cracking Mechanism(A) Wet H2S service: HSC or SSC

Weldment Component

Cracking Prevention and/or Hardness Control Method

Hardness Limit

Referenced Guidelines(B)

Weld deposit

Use of exempt welding process/filler metal combinations

Hardness testing not required

Paragraph 2.2.3

Hardness testing of production welds

200 HBW

Paragraph 2.2.6

HAZ

Base metal chemistry control PLUS One or more of the three thermal methods listed below: Thermal methods: 1. Cooling time (t8/5) control 2. PWHT control(E)

Paragraph 2.3.4

248 HV10(C)

Paragraph 2.3.5 Paragraph 2.3.5.2 Paragraph 2.3.5.3

3. Temper bead welding PLUS HAZ hardness survey during welding procedure qualification(D)(E)

Paragraph 2.3.5.4 Paragraph 2.3.5.5

ASCC service: Caustic cracking

Entire weldment

PWHT

Not applicable(C)

Paragraph 3.1 Paragraph 3.3

Amine cracking

Entire weldment

PWHT

Not applicable(C)

Paragraph 3.1 Paragraph 3.3

Carbonate cracking

Entire weldment

PWHT

Not applicable(C)

Paragraph 3.1 Paragraph 3.4

_______________________________________ (A)

Specific services requiring controls, and the optimum control method, shall be defined by the user. Many qualifiers and additional details are given in the referenced paragraphs and nonmandatory appendixes. (C) Weld deposit hardness shall also be controlled to 200 HBW maximum (also see Paragraph 2.2.1). (D) Preproduction testing specified to validate control options is capable of reducing HAZ hardness. (E) PWHT approach is exempt from HAZ hardness survey during welding procedure qualification, provided a 93 °C (200 °F ) minimum preheat is used during any welding of small welds such as attachments (see Paragraph 2.3.5.3.5). (B)

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SP0472-2010 ________________________________________________________________________ Section 2: Prevention of Hydrogen Stress Cracking 2.1 This section contains guidelines for prevention of HSC in weldments. Paragraph 2.2 addresses control of weld deposit hardness and Paragraph 2.3 addresses control of HAZ hardness. 2.2 Weld Deposit Hardness Control 2.2.1 The hardness of the completed weld deposit shall not exceed 200 HBW. 2.2.2 Filler metals for the following welding processes shall be certified in accordance with the listed specifications from the ASME Boiler and Pressure Vessel Code, Section II, Part C18 or from the American Welding Society (AWS):(5) (a) SMAW: ASME SFA-5.119 or AWS A5.1;20 (b) GTAW and GMAW: ASME SFA-5.1821 or AWS A5.18;22 (c) FCAW: ASME SFA-5.2023 or AWS A5.20;24 and (d) SAW: ASME SFA-5.1725 or AWS A5.17.26 2.2.3 Weld Deposit Hardness Testing Exemptions 2.2.3.1 Weld deposits produced using welding process and filler metal combinations listed in Table 2 do not require production hardness testing, unless otherwise specified by the user. Table 2 Welding Process/Filler Metal Combinations Exempt from Weld Deposit Hardness Testing

Welding Process SMAW

GTAW

GMAW (spray, pulsed, and globular transfer modes only)

Filler Metal Specification ASME SFA-5.1 or AWS A5.1 ASME SFA-5.18 or AWS A5.18

ASME SFA-5.18 or AWS A5.18

Filler Metal Classification

Compositional Restrictions (See Paragraph 2.2.3.1)

E60XX or E70XX

None

ER70S-2, ER70S-3, or ER70S-4

None

ER70S-6

Carbon (C) 0.10 wt% max Manganese (Mn) 1.60 wt% max Silicon (Si) 1.00 wt% max

ER70S-2, ER70S-3, or ER70S-4

None

ER70S-6

Carbon (C) 0.10 wt% max Manganese (Mn) 1.60 wt% max Silicon (Si) 1.00 wt% max

__________________________________________ (5) (5) American

Welding Society Society (AWS), (AWS), 550 550 N.W. N.W. LeJeune LeJeune Road, Road, Miami, Miami, FL FL 33126. 33126. American Welding

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SP0472-2010 2.2.3.2 Unless otherwise agreed, production GTAW, GMAW, FCAW, and SAW weld deposits shall meet the A-No. 1 chemical composition shown in Table QW-442 of the ASME Boiler and Pressure Vessel Code, Section IX. 2.2.3.3 Filler metal classifications listed in Table 2 with compositional restrictions should not be used unless actual chemical analysis is performed on the filler metal, indicating that the corresponding compositional restrictions have been met. The chemical analysis may be obtained by any of the following methods: (a)

Purchasing the filler metal with a certification of the actual chemical analysis;

(b) Performing a chemical analysis on a sample of a specific heat of candidate filler metal in accordance with the requirements listed in Section 10 of ASME SFA-5.18; or (c) Performing a chemical analysis on a weld deposit produced using the specific heat of candidate filler metal. If this method is used, the weld pad in accordance with Figure 3 in ASME SFA-5.18 shall be produced using the welding process and welding procedure specification used in production. The heat input, filler metal size, preheat, and interpass temperature shall be controlled as specified in the production welding procedure specification. The chemical analysis shall be performed in accordance with the requirements listed in Section 10 of ASME SFA-5.18. A hardness test shall also be performed when this method is used. The weld deposit hardness shall not exceed 200 HBW. 2.2.4 When welding process/filler metal combinations in accordance with Table 2 are used in lieu of production weld deposit hardness testing, a process shall be implemented to control and document the identification and use of these filler metals in production welding. 2.2.5 This production hardness testing waiver may be applied, even if a different filler metal is used for the root pass, provided that the root pass is produced with filler metal that meets the A-No. 1 chemical composition requirements. 2.2.6 Weld deposit hardness testing may be waived for repair welds in cast, forged, or plate components produced using welding process/filler metal combinations other than those listed in Table 2 if they have been prequalified using the following process: 2.2.6.1 A weld test patch shall be created on a test plate with a specific heat of filler metal (and flux, in the case of SAW) using parameters in accordance with the welding procedure specification to be used in production. The test patch shall then be tested to verify that the weld deposit hardness meets the 200 HBW maximum requirement, which then qualifies that heat of the filler metal (and flux, in the case of SAW) to be used for production weld repairs, in accordance with that welding procedure specification, without actual production weld deposit hardness tests. 2.2.6.2 When welding filler metal (and flux, in the case of SAW) is qualified using this method, a process shall be implemented to control and document the identification and use of this filler metal (and flux) in production welding. 2.2.7 Weld Deposit Hardness Testing 2.2.7.1 Hardness testing on completed production welds, when required, shall be done after any PWHT. Only weld deposits require hardness testing unless otherwise specified by the user. 2.2.7.2 Weld deposits shall be hardness tested, where required, on the side contacted by the process, whenever possible. If access to the process side is impractical, such as on piping or small-diameter vessels, hardness testing shall be done on the opposite side.

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SP0472-2010 2.2.7.3 Hardness readings, where required, shall be taken with a Brinell hardness tester in accordance with ASTM(6) E 1027 or with a comparison hardness tester in accordance with ASTM A 833.28 Other hardness testing techniques may be used if approved by the user. 2.2.7.4 For vessel or tank butt welds where hardness testing is required, a minimum of one location per weld seam shall be hardness tested. Unless otherwise specified by the user, one hardness test should be made for each 3 m (10 ft) of weld seam. In addition, one hardness test shall be made on each nozzle flange-to-neck and nozzle neck-to-shell/head weld. Each unique welding procedure used shall be hardness tested. 2.2.7.5 When hardness testing of welds is required, fillet weld deposit hardness testing should be done when access is feasible. The number of hardness tests and locations required shall be approved by the user with Paragraph 2.2.7.4 as a guide. 2.2.7.6 For piping welds on which hardness testing is required, a minimum of 5% of butt welds shall be hardness tested, unless otherwise specified by the user. 2.2.7.7 Repair welds in cast, forged, or plate components shall be hardness tested, when required, in accordance with the following requirements: 2.2.7.7.1

Hardness testing shall be performed on each component that has been weld repaired.

2.2.7.7.2 At least one hardness test shall be performed for each unique welding process/filler metal heat number combination used on the component. 2.2.7.7.3 Hardness testing shall be performed on actual weld repairs when the weld repair area is accessible, large enough to accommodate an indentation, and in a location where an indentation can be tolerated. 2.2.7.7.4 When actual weld repairs cannot be hardness tested, weld test patches shall be created on an accessible area of the component to allow hardness testing. 2.2.7.8 Weld deposits found to exceed the maximum hardness criterion in Paragraph 2.2.1 are unacceptable and shall be reported to the user. Unless accepted by the user, hard welds shall be either removed and rewelded, or heat treated to reduce the hardness to an acceptable value. The specific approach to be used to correct the high-hardness condition shall be subject to the userâ&#x20AC;&#x2122;s approval before any corrective action is taken. Regardless of the method of corrective action taken, the weld deposits shall be retested to ensure that the corrective action has resulted in acceptable hardness values. Also, additional welds should be hardness tested for each high-hardness weld that is found, at a rate determined by the user. 2.3 HAZ Hardness Control 2.3.1 HAZ hardness shall be controlled by the use of base metal chemistry control in conjunction with one or more thermal methods. The thermal methods promote a soft HAZ microstructure by either (a) using slow cooling rates to prevent the initial formation of a hard HAZ microstructure, or (b) tempering the HAZ microstructure to reduce the hardness. The thermal method(s) and associated base metal chemistry control selected from the list below shall be specified and documented by the producer of the subject components or the fabricator of the equipment.

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ASTMInternational International(ASTM), (ASTM),100 100Barr BarrHarbor HarborDr., Dr.,West WestConshohocken, Conshohocken,PA PA19428-2959. 19428-2959. ASTM

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SP0472-2010 2.3.2 Alternate controls based on scientific knowledge, experience, and/or risk-based analysis may be used in specific instances when approved by the user. 2.3.3 The user may review and approve and may dictate methods, limits, and/or controls for any given application. 2.3.4 Base Metal Chemistry Control 2.3.4.1 Base metal chemistry control shall be accomplished by specifying and monitoring the base metal carbon equivalent (CE), as determined by the formula in Equation (1).

CE = wt%C +

wt%Mn (wt%Ni + wt%Cu) (wt%Cr + wt%Mo + wt%V) + + 6 15 5

(1)

2.3.4.2 The maximum level of niobium (Nb) and vanadium (V), whether deliberately added or present as residual elements, shall be specified. 2.3.5 Thermal Methods 2.3.5.1 One or more of the following thermal methods (cooling time control, PWHT control, or temper bead welding) shall be selected: 2.3.5.2

Cooling Time Control

Cooling time control involves controlling the time for the weldment to cool from 800 °C to 500 °C (1,470 °F to 930 °F), denoted as t8/5, to avoid formation of a hard microstructure in the HAZ. The minimum t8/5 for production welding shall be specified. Appendix C is a summary of the cooling time (t8/5) concept and provides information on parameters and methods that are used to determine t8/5. 2.3.5.3

PWHT Control

2.3.5.3.1 PWHT involves heat treatment after welding at a temperature high enough to ensure softening of the HAZ microstructure by tempering. The PWHT temperature shall be 620 °C (1,150 °F) minimum and the hold time shall be specified to ensure complete heat treatment. If lower PWHT temperatures or shorter times are considered necessary by the manufacturer or fabricator, because of concerns with strength or impact toughness, this shall be reviewed and agreed with the user. 2.3.5.3.2 Regardless of the thickness of the base metal, a one hour minimum hold time shall be specified to ensure complete heat treatment. 2.3.5.3.3 A PWHT procedure shall be developed prior to heat treating. It should include the type of heating process, the number and locations of thermocouples, supporting details, heat-up and cool-down rates, maximum allowable temperature differentials, gradient control, hold time, and PWHT temperature range. 2.3.5.3.4 The user shall specify whether submittal of the PWHT procedure is required for approval prior to the use of PWHT. 2.3.5.3.5 When PWHT control is specified as the thermal method for HAZ hardness control, the requirement for preproduction weld procedure hardness testing may be waived by the user if a minimum 93 °C (200 °F) preheat is used for small welds (e.g., attachment welds). An example may be fillet welds with weld leg lengths up to approximately 9.5 mm (0.38 in).

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SP0472-2010 2.3.5.4

Temper Bead Welding

2.3.5.4.1 Temper bead welding techniques involve sequencing of weld passes such that the heat input from weld beads tempers the HAZ microstructure formed by previous weld passes. 2.3.5.4.2 The temper bead technique shall involve proper sequencing of the weld beads to produce a tempering effect in the HAZ. Nomenclature and diagrams for temper bead welding are provided in QW462.12 of the ASME Boiler and Pressure Vessel Code, Section IX. Proper sequencing of the weld beads against the base metal and the first layer temper beads shall be controlled, with particular attention to the cap layer passes, to ensure that effective tempering occurs. The surface temper beads shall not contact the base metal. The distance from the edge of the surface temper beads to the toe of the weld, as defined in QW-462.12, shall be 3.0 mm (0.12 in) maximum and 1.5 mm (0.060 in) minimum. The successful execution of this technique requires consistent heat input and deposition rate from bead to bead. Therefore, care must be taken when welding is performed using manual welding processes to ensure consistent heat input and deposition rates. Such care is especially important for manual GTAW, which inherently has higher heat input than other manual welding processes as a result of the restricted travel speed of GTAW relative to the other welding processes. 2.3.5.4.3 When the temper bead technique is used to repair minor defects in cast, forged, and plate components, the defect shall be excavated to a minimum diameter of four times the filler metal diameter prior to welding. The weld shall be built up using at least two layers until the cavity is filled above the prevailing base metal surface. The final cap layer shall be applied such that it does not contact the base metal, and such that the distance from the edge of the surface temper beads to the toe of the weld, as defined in QW-462.12, shall be 3.0 mm (0.12 in) maximum and 1.5 mm (0.060 in) minimum. 2.3.5.4.4 If the final cap pass results in an unacceptable profile, as determined by construction code requirements or the user, the excess weld shall be removed by grinding. 2.3.5.5

Preproduction Weld Procedure HAZ Hardness Controls and Testing

2.3.5.5.1 To verify that the methods used effectively control the HAZ hardness, preproduction hardness testing may be included in the weld procedure qualification process to ensure that the hardness in the HAZ and the weld deposit is acceptable. 2.3.5.5.2 Production welding procedures shall be qualified using the ASME Boiler and Pressure Vessel Code, Section IX procedure qualification rules, with the addition of the selected HAZ hardness control method(s). 2.3.5.5.3 Preproduction hardness surveys shall be performed using the Vickers method with a 10 kg load in accordance with ASTM E 92.29 The surveys shall be performed in accordance with the layouts in Figures 2 and 3, which show hardness test locations and details, respectively, for butt welds and fillet welds. 2.3.5.5.4 The hardness survey in accordance with Figures 2 and 3 shall be performed at a distance (A) of 1.5 Âą 0.5 mm (0.06 Âą 0.02 in) from the surface. One of the HAZ hardness measurements shall be made at a distance (B) not to exceed 0.5 mm (0.02 in) from the weld interface (commonly known as the fusion line). If the fusion line is not distinct, a pair of indentations shall be placed 1 mm (0.04 in) apart, straddling the apparent center of the indistinct fusion line, and equidistant from the apparent center of the fusion line. The distance (L) between hardness measurements shall be 1 mm (0.04 in). 2.3.5.5.5

The maximum allowable HAZ hardness shall be 248 HV 10.

2.3.5.5.6 Weld deposit hardness shall also be evaluated. No readings shall exceed 248 HV (70.5 HR 15N), and the average weld deposit hardness shall not exceed 210 HV 10.

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SP0472-2010

(a) Typical butt weld—single side

(b) Typical butt weld—double sided

(d) Typical fillet weld—double sided

Figure 2: Hardness test locations. Distance A shall be 1.5 ± 0.5 mm (0.06 ± 0.02 in) from the surface.

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SP0472-2010

BASE METAL HEAT-AFFECTED ZONE WELD METAL WELD DEPOSIT

(a) Butt weldâ&#x20AC;&#x201D;in any given location in Figure 2(b).

BASE METAL HEAT-AFFECTED ZONE WELD METAL WELD DEPOSIT

(b) Fillet weld

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SP0472-2010 BASE METAL HEAT-AFFECTED ZONE WELD METAL WELD DEPOSIT

(c) Overlay or repair weld—if overlay terminates in exposed environment. Figure 3: Hardness test details. Distance A shall be 1.5 ± 0.5 mm (0.06 ± 0.02 in) from surface Distance B shall be ≤ 0.5 mm (0.02 in) from fusion line Distance L shall be 1 mm (0.04 in) between indentations NOTE: This survey shall be done adjacent to both surfaces of the cap and root of welds. 2.3.5.5.7 Hardness surveys performed prior to the issuance of this edition of SP0472 that used the survey layouts in NACE MR0175/ISO 15156 are acceptable. 2.3.5.5.8 Microhardness testing using Knoop or Vickers tests with ≤ 500 g loads may be considered; however, the effects of surface preparation, etching, mounting procedures, appropriate criteria, and other details shall be reviewed and approved by the user before being used. Guidance on these microhardness test techniques is given in ASTM E 384.30 2.3.5.5.9 Individual HAZ hardness readings exceeding the value permitted by this standard are considered acceptable if the average of three hardness readings taken in the equivalent HAZ profile location adjacent to the hard HAZ reading (by repolishing the existing procedure qualification specimens or extracting additional procedure qualification specimens) does not exceed the values permitted by this standard and no individual hardness reading is greater than 10 HV 10 units above the acceptable value. 2.3.5.5.10 The hardness test results shall be appended to the ASME procedure qualification record (PQR). The results shall include a sketch of the hardness test locations and corresponding results. The weld procedure specification (WPS) shall reflect the limits imposed by the specified limits for hardness control. The user may require that both forms be submitted for approval prior to production welding.

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SP0472-2010 2.3.5.6

Preproduction Weld Procedure Base Metal Chemistry Controls and Reporting

2.3.5.6.1 Actual production base metal chemistry shall be limited based on the base metal chemistry of the procedure qualification specimen. 2.3.5.6.2 The WPS shall state that the maximum CE of the production base metal shall not exceed the CE of the procedure qualification specimen by more than 0.03%. The base metal chemistry of the procedure qualification specimen shall be reported in the PQR. All base metal chemistry requirements shall be applied to ladle analyses, unless otherwise specified by the user. 2.3.5.6.3 For product forms in which deliberately added microalloying elements (such as Nb [columbium {Cb}], V, titanium [Ti], and boron [B]) are used, the maximum content shall not exceed the corresponding value on the procedure qualification specimen. Deliberate additions are generally considered to be values greater than 0.01 wt% for each of Nb (Cb), V, and Ti, and greater than 0.0005 wt% of B. All base metal chemistry requirements shall be applied to ladle analyses, unless otherwise specified by the user. 2.3.5.7

Preproduction Weld Procedure Thermal-Related Controls and Reporting

2.3.5.7.1 If cooling time control is used, the WPS shall control production welding such that the calculated t8/5 is equal to or greater than the t8/5 calculated for the procedure qualification specimen. The user may specify a minimum t8/5 required for future repair or alteration scenarios. 2.3.5.7.2 Preheating may also be applied to thermal cutting and tack welding (if subsequent grinding is not done). Guidelines for when to preheat and minimum preheat temperatures are given in applicable design codes (e.g., the nonmandatory Appendix R in the ASME Boiler and Pressure Vessel Code, Section VIII, Division 1). 2.3.5.7.3 Small fillet welds on large sections are often prone to high HAZ hardnesses. The user shall determine whether this configuration is necessary in production, which may define the limiting t8/5 required for procedure qualification. 2.3.5.7.4 For SMAW, an alternative simplifed thermal control method may be based on the maximum weld bead size and the maximum length of weld bead per unit length of weld rod used in the welding of the procedure qualification specimen, which shall be the basis for limits applied to production welding. 2.3.5.7.5 For GMAW and FCAW, the filler metal size used for production welding should be the same as that used during procedure qualification tests. For other welding processes, only one size variation between the filler metal size used for the procedure qualification tests and for subsequent production welding should be permitted. 2.3.5.7.6 For fillet weld procedure qualification tests, position should be an essential variable; however, tests on welds made in the overhead position shall qualify all other fillet weld positions. 2.3.5.7.7 If PWHT is used, the welding procedure shall require PWHT at a minimum temperature and minimum hold time, stated as a function of metal thickness, equal to or greater than the temperature and hold time used to PWHT the procedure qualification specimen. 2.3.5.7.8 If a temper bead welding technique is used during procedure qualification, the production procedure shall require that the cap pass be applied so that the edges of the weld beads come within 3.0 mm (0.12 in) of the base metal, but not touch the base metal. If this results in an unacceptable profile, the excess weld deposit should be removed by grinding, machining, or other low-heat input processes.

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SP0472-2010 2.4 During original fabrication, weldments shall be inspected for defects such as lack of fusion, delayed hydrogen cracking, or severe undercut and any relevant defects found should be removed. Appropriate definition of relevant defects shall be established and approved by the user. ________________________________________________________________________ Section 3: Prevention of Alkaline Stress Corrosion Cracking 3.1 PWHT shall be used to reduce residual stresses when prevention of ASCC is specified by the user. In services where both ASCC and HSC/SSC are concerns, weldment hardness controls shall be applied in addition to PWHT. 3.2 ASME Boiler and Pressure Vessel Code, Section VIII, allows PWHT to be performed at lower than the normally specified temperature if it is held for a longer time. However, when PWHT is being performed for prevention of ASCC, these lower temperatures shall not be used. 3.3 For amine and caustic cracking services, an effective PWHT procedure shall consist of heating weldments to 635 ± 15 °C (1,175 ± 25 °F) for a hold time of one hour for each 25 mm (1.0 in), or a fraction thereof, of metal thickness, with a minimum hold time of one hour. 3.3.1 When PWHT is used for ASCC, the requirements for HAZ hardness control for SSC as defined in Paragraph 2.3 also must be considered for services exposed to both SSC and ASCC. The allowable variation in the chemical composition of steels could be considerable, even within the same grade. In conjunction with welding variables, this can produce high hardness in HAZs that might not be adequately softened by this specified thermal stress relief. Each situation should be evaluated to determine whether this thermal stress relief is adequate. 3.4 For carbonate cracking services, an enhanced stress-relieving heat treatment should be used. The heat treatment temperature should be 649 to 663 °C (1,200 to 1,225 °F) for a hold time of one hour for each 25 mm (1.0 in) of thickness, with a minimum hold time of one hour. 3.4.1 In addition to the higher heat treatment temperature, the guidelines provided in Paragraph 5.2.3.1 of API RP 945 and AWS D10.1031 should be incorporated into the heat treatment procedures to minimize the residual stresses that remain after the stress-relieving heat treatment. 3.5 When heat treatment is used to prevent ASCC, all welds and weld heat-affected areas shall receive PWHT, including all pressure-containing welds, seal welds, internal attachment welds, nozzle-reinforcing pad welds, temporary fabrication attachment welds, and arc strikes. 3.5.1 External attachment welds often generate residual stresses extending through the entire wall thickness. If they do, they shall also receive PWHT. Only if an evaluation shows that the residual stresses do not extend through wall may PWHT be considered optional. 3.6 Experience has shown that heating bands wider than required by codes (approximately > 250 mm [10 in]) are sometimes necessary. This applies primarily to weldments in large-diameter (> 250 mm [10 in]) piping. 3.7 After PWHT, actions that reintroduce high residual stresses, such as straightening, should be avoided. If these actions have been done, a second PWHT should be performed when deemed necessary by the user. 3.8 The shot peening process should not be used for applications in ASCC environments as a substitute for PWHT. 3.9 Alternative welding methods such as temper bead welding and controlled-deposition welding shall not be used for prevention of ASCC. 3.10 During original fabrication, weldments should be inspected for defects such as lack of fusion, delayed hydrogen cracking, or severe undercut. Any defects found should be removed. 14

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SP0472-2010 ________________________________________________________________________ References 1. ASME Boiler and Pressure Vessel Code, Section VIII (latest revision), “Pressure Vessels” (New York, NY: ASME). 2. ASME/ANSI B31.3 (latest revision), “Process Piping” (New York, NY: ASME). 3. API Standard 620 (latest revision), “Design and Construction of Large, Welded, Low-Pressure Storage Tanks” (Washington, DC: API). 4. API Standard 650 (latest revision), “Welded Tanks for Oil Storage” (Washington, DC: API). 5. NACE Standard MR0103 (latest revision), “Materials Resistant to Sulfide Stress Cracking in Corrosive Petroleum Refining Environments” (Houston, TX: NACE). 6. NACE MR0175/ISO 15156 (latest revision), “Petroleum and natural gas industries—Materials for use in H2Scontaining environments in oil and gas production” (Houston, TX: NACE, and Geneva, Switzerland: ISO). 7. API RP 942 (discontinued), “Controlling Weld Hardness of Carbon Steel Refinery Equipment to Prevent Environmental Cracking” (Washington, DC: API). 8. R.D. Merrick, “Refinery Experiences with Cracking in Wet H2S Environments,” CORROSION/87, paper no. 190 (Houston, TX: NACE, 1987). 9. ASME Boiler and Pressure Vessel Code, Section IX (latest revision), “Welding and Brazing Qualifications” (New York, NY: ASME). 10. F.R. Coe, et al., Welding Steels Without Hydrogen Cracking, 2nd ed. (Abington, Cambridge, UK: Abington Publishing, The Welding Institute, UK, 1993). 11. NACE International Glossary of Corrosion-Related Terms (latest revision) (Houston, TX: NACE). See also NACE/ASTM G 193 (latest revision), “Standard Terminology and Acronyms Relating to Corrosion” (Houston, TX: NACE and West Conshohocken, PA: ASTM). 12. NACE Publication 8X194 (latest revision), “Materials and Fabrication Practices for New Pressure Vessels Used in Wet H2S Refinery Service” (Houston, TX: NACE). 13. NACE SP0403 (latest revision), “Avoiding Caustic Stress Corrosion Cracking of Carbon Steel Refinery Equipment and Piping” (Houston, TX: NACE). 14. API RP 945 (latest revision), “Avoiding Environmental Cracking in Amine Units” (Washington, DC: API). 15. NACE Publication 34108 (latest revision), “Review and Survey of Alkaline Carbonate Stress Corrosion Cracking in Refinery Sour Waters” (Houston, TX: NACE). 16. D. McIntyre, C.P. Dillon, Guidelines for Preventing Stress Corrosion Cracking in the CPI, MTI Publication No. 15 (Columbus, Ohio: Materials Technology Institute,(7) March 1985).

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Materials Materials Technology Technology Institute Institute (MTI), (MTI), 1215 1215 Fern Fern Ridge Ridge Parkway, Parkway, Suite Suite 206, 206, St. St. Louis, Louis, MO MO 63141-4405. 63141-4405.

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SP0472-2010 17. API RP 941 (latest revision), “Steels for Hydrogen Service at Elevated Temperatures and Pressures in Petroleum Refineries and Petrochemical Plants” (Washington, DC: API). 18. ASME Boiler and Pressure Vessel Code, Section II, Part C (latest revision), “Specifications for Welding Rods, Electrodes and Filler Metals” (New York, NY: ASME). 19. ASME SFA-5.1/SFA-5.1M (latest revision), “Specification for Carbon Steel Electrodes for Shielded Metal Arc Welding” (New York, NY: ASME). 20. AWS A5.1/A5.1M (latest revision), “Specification for Carbon Steel Electrodes for Shielded Metal Arc Welding" (Miami, FL: AWS). 21. ASME SFA-5.18/SFA-5.18M (latest revision), “Specification for Carbon Steel Electrodes and Rods for Gas Shielded Arc Welding” (New York, NY: ASME). 22. AWS A5.18/A5.18M (latest revision), “Specification for Carbon Steel Electrodes and Rods for Gas Shielded Arc Welding" (Miami, FL: AWS). 23. ASME SFA-5.20/SFA-5.20M (latest revision), “Specification for Carbon Steel Electrodes for Flux Cored Arc Welding” (New York, NY: ASME). 24. AWS A5.20/A5.20M (latest revision), “Specification for Carbon Steel Electrodes for Flux Cored Arc Welding" (Miami, FL: AWS). 25. ASME SFA-5.17/SFA-5.17M (latest revision), “Specification for Carbon Steel Electrodes and Fluxes for Submerged Arc Welding” (New York, NY: ASME). 26. AWS A5.17/A5.17M (latest revision), “Specification for Carbon Steel Electrodes and Fluxes for Submerged Arc Welding" (Miami, FL: AWS). 27. ASTM E 10 (latest revision), “Standard Test Method for Brinell Hardness of Metallic Materials” (West Conshohocken, PA: ASTM). 28. ASTM A 833 (latest revision), “Standard Practice for Indentation Hardness of Metallic Materials by Comparison Hardness Testers” (West Conshohocken, PA: ASTM). 29. ASTM E 92 (latest revision), “Standard Test Method for Vickers Hardness of Metallic Materials” (West Conshohocken, PA: ASTM). 30. ASTM E 384 (latest revision), “Standard Test Method for Microindentation Hardness of Materials” (West Conshohocken, PA: ASTM). 31. AWS/ANSI D10.10/D10.10M (latest revision), “Recommended Practices for Local Heating of Welds in Piping and Tubing” (Miami, FL: AWS). 32. N. Yurioka, “Prediction of Weld Metal Strength,” IIW(8) Document IX-2058-03 (Roissy, France: IIW, 2003). 33. E.L. Hildebrand, “Aqueous Phase H2S Cracking of Hard Carbon Steel Weldments—A Case History,” Proceedings of the 1970 API meeting, held May 1970 (Washington, DC: API, 1970), pp. 593-613.

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InternationalInstitute Institute Welding (IIW), 51362 Villepinte, International ofof Welding (IIW), BPBP 51362 Villepinte, 95995942 Roissy CDG, Cedex, France.

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SP0472-2010 34. D.J. Kotecki, D.G. Howden, “Weld Cracking in a Wet Sulfide Environment,” Proceedings of the 1973 API meeting, held May 1973 (Washington, DC: API, 1973), pp. 631-653. 35. D.J. Kotecki, D.G. Howden, “Final Report on Wet Sulfide Cracking of Weldments,” API paper (Washington, DC: API, May 1973). 36. D.J. Kotecki, D.G. Howden, “Submerged Arc Weld Hardness and Cracking in Wet Sulfide Service,” Welding Research Council Bulletin No. 184, June 1973. 37. A.C. Gysbers, “Chemistry Considerations of P1 Base Materials to Mitigate Hydrogen Embrittlement Exposure,” CORROSION/2006, paper no. 575 (Houston, TX: NACE, 2006). 38. ISO 15614-1 (latest revision), “Specification and qualification of welding procedures for metallic materials – Welding procedure test – Part 1: Arc and gas welding of steels and arc welding of nickel and nickel alloys” (Geneva, Switzerland: ISO). 39. BS EN 288-9 (latest revision), “Specification and approval of welding procedures for metallic materials. Welding procedure test for pipeline welding on land and offshore site butt welding of transmission pipelines” (London, UK: BSI(9)). 40. BS EN 1011-2 (latest revision), “Welding. Recommendations for welding of metallic materials. Arc welding of ferritic steels.” (London, UK: BSI). ________________________________________________________________________ Bibliography Ebert, H.W., and J.F. Winsor. “Carbon Steel Submerged Arc Welds—Tensile Strength vs. Corrosion Resistance.” Welding Research Supplement to the Welding Journal, July 1980. Gulvin, T.F., D. Scott, D.M. Haddrill, and J. Glen. “The Influence of Stress Relief on the Properties of C and C-Mn Pressure-Vessel Plate Steels.” Conference on the Effect of Modern Fabrication Techniques on the Properties of Steels, paper no. 621. The West of Scotland Iron and Steel Institute, May 12, 1972. NACE Publication 8X294 (latest revision). “Review of Published Literature on Wet H2S Cracking of Steels Through 1989.” Houston, TX: NACE. Neill, W.J. “Prevention of In-Service Cracking of Carbon Steel Welds in Corrosive Environments.” CORROSION/71, paper no. 43. Houston, TX: NACE, 1971. Omar, A.A., R.D. Kane, and W.K. Boyd. “Factors Affecting the Sulfide Stress Cracking Resistance of Steel Weldments.” CORROSION/81, paper no. 186. Houston, TX: NACE, 1981. Stout, R.D. “Hardness as an Index of Weldability and Service Performance of Steel Weldments.” WRC Bulletin No. 189. New York, NY: WRC, November, 1973. Welding Research Council(10) Bulletin No. 145. “Interpretive Report on Effect of Hydrogen in Pressure Vessel Steels.” New York, NY: WRC, October, 1969.

__________________________________________ (9) (9) BSI British British Standards Standards (BSI), (BSI), 389 389 Chiswick Chiswick High High Rd., Rd., London London W4 W4 4AL, 4AL, United United Kingdom. Kingdom. BSI (10) (10)

Welding Research Research Council Council (WRC), (WRC), PO PO Box Box 201547, 201547, Shaker Shaker Heights, Heights, OH OH 44120. 44120. Welding

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SP0472-2010 ________________________________________________________________________ Appendix A Rationale for Guidelines for Prevention of Hydrogen Stress Cracking (Nonmandatory) This appendix is considered nonmandatory, although it may contain mandatory language. It is intended only to provide supplementary information or guidance. The user of this standard is not required to follow, but may choose to follow, any or all of the provisions herein. The rationale statements in this nonmandatory appendix are numbered to correspond with the associated paragraphs in Section 2 of this standard plus use of the prefix A for clarity. A2.2 For most refinery services, weld deposit hardness is often controlled, even if not exposed to an internal operating environment that can cause HSC. This practice primarily helps avoid the use of improper welding filler metals (and fluxes), welding procedures, or heat treatment. It also minimizes the risk of HSC from external wet atmospheric corrodents, process upsets, or future changes in service. A2.2.1 A number of SSC failures occurred in the late 1960s in hard weld deposits in P-No. 1 steel refinery equipment. The petroleum refining industry established a maximum hardness limit of 200 HBW for P-No. 1, Group 1 and 2 steels to ensure that weld deposits would be resistant to HSC. The 200 HBW maximum hardness requirement is lower than the 22 HRC (237 HBW) maximum hardness requirement listed in NACE MR0175/ISO 15156 and previous editions of NACE Standard MR0175. The lower limit was applied to compensate for both the nonhomogeneity of some weld deposits and the normal variations in production hardness test results that are obtained using a comparison hardness tester. A2.2.2 AWS or ASME certified filler metals are required to ensure that the composition and quality of the filler metals are consistent, which is the basis of the exemptions from weld deposit hardness testing within this standard. The compositional restrictions listed in Table 2 are in addition to the requirements specified by the filler metal specification. These compositional restrictions are based on hardenability calculations performed in accordance with methods described in IIW Document IX-2058-03.32 A2.2.3 This standard originally specified production hardness testing of all weld deposits. However, experience eventually indicated that hardness values above 200 HBW rarely occurred in weld deposits produced using SMAW, GTAW, and GMAW (spray, pulsed, or globular transfer) welding processes in combination with certain filler metal classifications. Hence, it is generally not considered necessary to perform production hardness testing on weld deposits produced with these welding process/filler metal combinations. A2.2.3.1 High weld deposit hardnesses can occur with SAW when using a low- or medium-Mn wire in combination with an active flux.33,34,35 Also, some SAW welds with high Mn and Si contents can have highly localized hard zones that are not softened significantly by PWHT.36 Most welding consumable manufacturers recommend against the use of active fluxes for multipass welds. Some GTAW, GMAW, and FCAW filler metal classifications allow high Mn concentrations. Hence, the chemistry of weld deposits must be restricted to the A-No. 1 composition in accordance with ASME Boiler and Pressure Vessel Code, Section IX to ensure achieving weld deposit hardness limits. A2.2.3.2 Use of additional compositional restrictions for the common GMAW filler metal classification ER70S-6 for exemption requires a confirmation of the actual filler metal chemistry because the standard specification is much broader than the A-No. 1 compositional limit. The same welding process and welding variables are specified to be used for this method because the relationship between filler metal chemistry and weld deposit chemistry is a function of the welding process and variables. For example, in GMAW welding using CO2 mixtures, oxygen generated by breakdown of the CO2 causes oxidation of Mn and Si in the weld metal, thus reducing the concentration of these elements in the weld deposit matrix. Reductions of 0.3 wt% in Mn and 0.2 wt% in Si are common in GMAW deposits produced using 100% CO2. ER70S-2 has 18

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SP0472-2010 been reported on occasion to cause hard weld deposits in conjunction with very high cooling rates and with high levels of residual Ti. A2.2.4 Exemption from weld deposit hardness testing based on the Table 2 filler metal exemptions will require that quality control procedures be in place to ensure that only these exempted filler metals are being used in production. A2.2.5 Because it is not possible to perform production hardness testing on the root pass, the hardness test is usually waived even if a different filler metal is used for the root pass. However, to ensure that the root pass weld deposit is not hard, the same restriction to use only A-No. 1 chemical composition is specified in accordance with ASME Boiler and Pressure Vessel Code, Section IX. A2.2.6 Base metals can undergo weld repairs as part of their specification. This paragraph addresses the need to ensure that these weld deposits are also produced to the requirements of this section. Because base metals are manufactured around the world and other filler metals than those specified herein may be used, this paragraph provides a qualification practice for these filler metals because production testing may not be practically possible (e.g., inner surfaces of components). A2.2.6.1 This paragraph specifies how each heat of filler metal is hardness tested in a sample weld production that includes welding within the parameters of the production welding procedure to ensure similar cooling times. A2.2.6.2 Once the qualification is complete, there is a need by the component manufacturer to ensure that only the tested filler metal is used in production. A2.2.7 The hardness testing practices in this and subsequent paragraphs are used in services covered by the scope of this standard, except for the waiver given to some SMAW, GTAW, and GMAW welds in Paragraph 2.2.3, unless otherwise specified by the user. The practices may also be applied to other services for the reasons given in Paragraph 1.6.1.1. A2.2.7.1 PWHT can provide temper softening of weld deposits. Typically, the macrohardness testing techniques in this section cannot detect the narrow HAZ hardenability zone of P-No. 1 steels, so weld deposits are what are specified to be tested. A2.2.7.2 Exposure to the hydrogen charging environment of the process service can cause HSC. A2.2.7.3 Both laboratory-type Brinell testers that can be used for procedure qualification or the more typical field comparison hardness tests are the standard technique for evaluating weld deposit hardness. There may be other acceptable portable techniques (e.g., dynamic/rebound or ultrasonic) based on evaluation of their capability and approval by the user. A2.2.7.4 Guidelines are provided so that production welding is adequately sampled to ensure weld deposits meet the hardness requirement of this standard. A2.2.7.5 Fillet welds may represent a difficult profile or may be difficult to access, though there are smaller size Brinell devices that can facilitate weld deposit hardness testing. Requirements for frequency of testing for fillet welds may use frequency guidelines suggested for butt welds in the previous paragraph. A2.2.7.6 Guidelines are provided so that piping production welding is adequately sampled to ensure weld deposits meet the hardness requirement of this standard. A2.2.7.7 Guidelines are provided to ensure that weld repairs often used in base metals are sampled and that weld deposits meet the hardness requirements of this standard. In some cases, internal access may not allow weld deposit testing; therefore, alternative testing guidelines are provided.

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SP0472-2010 A2.2.7.8 High hardness weld deposits are addressed by the user and are required to be included in the corrective action decision. Guidelines are provided for retesting to verify the hardness of the repaired or heat-treated weld deposit. Further testing of other welds to validate the extent of the problem is discussed. A2.3

HAZ Hardness Control

A2.3.1 High-hardness microstructures in HAZs may be susceptible to cracking, even with soft weld deposits in severely corrosive petroleum refinery services. For these services, several options are available to the fabricator or user to control the maximum HAZ hardness. Most users and fabricators have found that it requires base metal chemistry control plus one or more thermal methods to ensure HAZ hardness is effectively controlled. This is supported by Gysbers,37 who demonstrated the interrelationship between base metal chemistry and its impact on both as-welded hardenability and temper-softening response during PWHT. The concept of the cooling time (t8/5) during welding is used to summarize the impact of preheat, heat input, joint configuration, and component thickness. The degree and type of base metal chemistry control needed depends on the type of thermal method(s) selected. The thermal methods are: 1. Cooling time control; 2. PWHT control; and 3. Temper bead welding. Table A1 summarizes the influences that various combinations of welding parameters and thermal methods have on the level of necessary base metal chemistry controls for butt welds.

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SP0472-2010

Table A1 Level of Base Metal Chemistry Control as a Function of Butt Weld Joint Configurations and HAZ Hardness Control Method Used Thermal Method

Weld Type

Layers per Side

PWHT control

Onesided

Multilayer

PWHT control

Twosided

Multilayer

PWHT control

Twosided

Single layer

PWHT control

Onesided

Single layer

Temper bead welding

Onesided

Multilayer

Temper bead welding Cooling time control

Twosided Onesided

Multilayer

Cooling time control

Twosided

Multilayer

Cooling time control

Twosided

Single layer

Cooling time control

Onesided

Single layer

Temper bead welding

Twosided

Single layer

Temper bead welding

Onesided

Single layer

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Multilayer

Comments Because this is multilayer, bead tempering occurs naturally in the HAZ adjacent to the root pass, which is in contact with the sour process, making it even more likely that it is soft after PWHT. Because this is multilayer, bead tempering occurs naturally in the HAZ adjacent to all layers except possibly the cap layers, one of which is in contact with the sour process. Therefore, the HAZ adjacent to all layers other than the cap layers experiences both bead tempering and PWHT. The heat from the pass on the second side welded may produce some bead tempering of the HAZ produced adjacent to the pass on the first side welded, reducing the likelihood of a hard throughwall HAZ. The PWHT alone must temper any hard HAZ locations that remain. Because this is a one-pass weld, there is no opportunity for bead tempering, and as such, it is possible that there is a hard throughwall HAZ. The PWHT alone must temper any hard HAZ locations. Bead tempering occurs naturally in the HAZ adjacent to the root pass, which is in contact with the sour process. The remainder of the HAZ should be soft if temper bead welding techniques are used for the remainder of the layers. The entire HAZ should be soft if temper bead welding techniques are used for all layers. Bead tempering occurs naturally in the HAZ adjacent to the root pass, which is in contact with the sour process. The remainder of the HAZ should be soft if the cooling time and base metal chemistry controls are well matched. Because this is multilayer, bead tempering occurs naturally in the HAZ adjacent to all layers except possibly the cap layers, one of which is in contact with the sour process. The HAZ adjacent to the cap layer on the process side should be soft if the cooling time and base metal chemistry controls are well matched. Because bead tempering occurs to some degree on the first side welded when the second side is welded, this is less risky than a one-sided, single-layer weld, but the entire HAZ adjacent to the weld on the second side could be hard if base metal chemistry and cooling time are not controlled. Because a single layer weld could produce a through-wall HAZ that is excessively hard, base metal chemistry and cooling time both need to be well controlled. The heat from the pass on the second side welded may produce some bead tempering of the HAZ produced adjacent to the pass on the first side welded, reducing the likelihood of a hard throughwall HAZ. The second side welded does not experience bead tempering. If this technique were to be used, the first pass would have to be located on the side exposed to the sour process. Not possible.

Level of Base Metal Chemistry Control Least Stringent

Most Stringent Not Recommended

Not Acceptable

SP0472-2010 A2.3.2 In some instances, users successfully perform certain types of welding without base metal chemistry controls (e.g., piping). The combination of the base metal chemistry control and thermal methods to control HAZ hardness may vary depending on user needs and other demands (toughness, strength) of the weldment. Examples of instances in which certain controls may not be acceptable include the following: (a) Restrictive base metal chemistry controls may not allow weldment strength and toughness requirements to be achieved; (b)

Welding controls may not be practical for some field configurations and conditions; and

(c) PWHT may not be practical for some welds on valves, pumps, compressor casings, or compressor heads, especially after final machining. A2.3.3 Although the manufacturer or fabricator has primary responsibility for selecting the controls that are used for complying with HAZ hardness requirements of this standard, there may be user-based decision issues (service exposures, risks, etc.) that may warrant input into the decisions for control options. A2.3.4 Control of the base metal chemistry of all production base metals for a given application can contribute to controlling the HAZ microstructure and hardness. A2.3.4.1 The equation for calculating the CE provided in this paragraph is commonly used as a nominal hardenability index for carbon steel base metals within the cooling times typically found during most welding. This equation uses the specified elements (C and Mn) and the residual elements (Ni, Cu, Cr, Mo, and V) that are controlled in carbon steels assigned to the P-No. 1 grouping in Section IX of the ASME Boiler and Pressure Vessel Code. A steel should be selected for welding procedure qualification with a base metal chemistry at the maximum level that would be experienced in production welding. This ensures that the production base metals will be no more hardenable than the steel used in qualification testing. There is no industry consensus on what levels of CE should be specified, and some examples of CE levels used are discussed in NACE Publication 8X194. A2.3.4.2 P-No. 1 steels in accordance with Paragraph 1.2 that have deliberate additions of microalloying elements may require additional preheat and higher PWHT temperatures to obtain acceptable HAZ hardnesses. These heat treatments needed to obtain acceptable HAZ hardnesses may adversely affect toughness values. There is a general consensus that this applies to steels with Nb (Cb) plus V contents greater than 0.03 wt%, or total content of unspecified elements greater than 0.5 wt%. Deliberate additions are generally considered to be greater than 0.01 wt% for each of Nb (Cb), V, and Ti, and greater than 0.0005 wt% of B. The maximum level of alloying elements (whether used deliberately or as residual) Nb (Cb) and V must be defined and be consistent with the base metal used with the preproduction qualification process, in accordance with Paragraph 2.3.5.6. A2.3.5 Thermal methods seek to control weld HAZ hardness by either preventing a hard microstructure from ever forming or by tempering the microstructure. A2.3.5.2.1 The temperature/time cycles during welding have a significant effect on the mechanical properties (hardness, impact toughness) of the HAZ of a welded joint. These are particularly influenced by the metal thickness, the form of weld, the heat input during welding, and the preheating temperature. Generally, the cooling time (t8/5) is chosen to characterize the temperature/time cycle of an individual weld run during welding and is the time taken, during cooling, for a weld run and its HAZs to pass through the temperature range from 800 째C to 500 째C (1,470 째F to 930 째F). For a given base metal chemistry, a preproduction test done at the shortest (minimum) cooling time (highest HAZ hardness potential) that passes the required HAZ hardness maximum can qualify for any production welding done at cooling times greater than this preproduction test. The minimum cooling time determines the maximum hardness a certain base metal chemistry is able to achieve. As discussed in Appendix C, this is a function of thickness, joint configuration, and preheat and 22

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SP0472-2010 welding heat input. Hence, a single minimum specified cooling time can be applied to a wide variety of production welding provided the cooling time used in production is greater than the cooling time the preproduction testing has demonstrated. A2.3.5.3.1 PWHT temper softens hard HAZ constituents. The ASME Boiler and Pressure Vessel Code, Section VIII, Division 1, allows PWHT to be performed at temperatures below the minimum specified temperature provided the temperature is held for a longer time (see Paragraph UCS-56 of the ASME Boiler and Pressure Vessel Code, Section VIII, Division 1). The general trend in the industry has been to specify higher PWHT temperatures (see NACE Publication 8X194) to both facilitate tempering of the hard HAZ (particularly with residual alloying elements) and improve residual stress reduction. A2.3.5.3.2 Both temperature and time are needed to adequately soften hard HAZ microstructures. Shorter hold times may not consistently provide proper tempering. A2.3.5.3.3 A documented procedure is typically necessary to ensure consistent application of the PWHT process as well to avoid improper heat treatments that may generate insufficient tempering or create inadvertent residual stresses. A2.3.5.3.4 PWHT can have significant variation in procedures that can impact the effectiveness of this thermal method. This paragraph allows users to review the procedures in detail so they are satisfied with the viability. A2.3.5.3.5 This paragraph explains that PWHT has provided good industry experience in reducing HSC damage without having to verify the weld HAZ hardness via weld procedure hardness profiles. The residual risk with the PWHT control thermal method is that PWHT may not be able to reduce HAZ hardness sufficiently for short cooling time (t8/5) type of welds, such as fillet welds for attachments that create high-hardness HAZ not sufficiently recoverable with PWHT. To support waiving the prequalification testing for the PWHT control thermal method, preheat is suggested for these types of welds, which increases the cooling time (t8/5) to reduce the initial HAZ hardness these type welds would create. A2.3.5.4 Temper bead welding uses heat from subsequent weld passes to temper the HAZ caused by previous weld passes. A2.3.5.4.1 Proper sequencing of beads is imperative, especially in the cap layer, because this is where hard HAZ readings usually occur. Extra caution is advised and steps have been identified to ensure last pass tempering. It is important to avoid recreating a hard HAZ caused by a new weld bead too close to the base metal. A2.3.5.4.2 ASME Boiler and Pressure Vessel Code, Section IX has specific procedures for qualifying temper bead weld procedures. In addition, this paragraph flags that care should be taken in using some techniques (such as manual GTAW), for which it can be very difficult to reproduce tempering sequences, particularly in field situations without standard configuration. Manual GTAW has been used in shop temper bead repairs of castings, where control is more achievable. A2.3.5.4.3 Minor weld repairs in base metal components are commonly performed in one layer containing one pass. This affords no opportunity for the bead tempering concept to work. Therefore, application of at least two layers (most likely consisting of one pass each) is required, and the top layer is not allowed to contact the base metal; otherwise it will form another hard HAZ. A2.3.5.4.4 The final cap pass of temper bead welding may cause a high profile that can be removed by grinding, machining, or other low heat-input methods. A2.3.5.5 The effectiveness of the combination of base metal chemistry control and thermal method(s) (cooling time control, PWHT control, and/or temper bead welding) used are validated by performing HAZ NACE International

SP0472-2010 hardness testing during welding procedure qualification. Additional practices are needed to ensure that the hardness tests are representative of production weldments. Base metal, filler metals, and welding conditions used for the procedure qualification tests are discussed in subparagraphs, as compared to what is used for the production welding. A2.3.5.5.2 ASME Boiler and Pressure Vessel Code, Section IX methods provide a commonly accepted basis for welding procedure development, and this discusses supplementing the procedure qualification with the hardness verification of this standard. A.2.3.5.5.3 The Vickers 10 kg method is sensitive enough to identify hard HAZ regions without being overly sensitive to microscopic hard spots. Details are provided on where to hardness test to ensure that the most likely locations of the highest hardness are thoroughly evaluated. A2.3.5.5.4 The HAZ hardness adjacent to the fusion line, particularly at the last pass surfaces, is the critical area for determining the successful application of the controls to achieve hardness below the specified maximum. This requires the use of small indentation hardness methods. The Vickers HV 10 procedure is the standard used throughout the industry (e.g., in QW-290 of the ASME Boiler and Pressure Vessel Code, Section IX, and in Paragraph 7.4.6 of ISO 15614-1).38 Care is required to avoid indentations too close to each other or to the surface, as this has an impact on the reading. In accordance with ASTM E 92, the minimum allowed spacing is an inverse function of hardness (e.g., for a 150 HV 10, the indentation spacing from the edge or from one another cannot be closer than 0.8 mm [0.03 in]). Hence, the 1 mm (0.04 in) specified adequately covers the expected range in the HAZ of PNo. 1 steels. In addition, guidance is provided when the fusion line may be indistinct when examined to ensure that the hardness survey is still targeted to detect the immediate HAZ in this area. The term “fusion line” is used in lieu of the official AWS term “weld interface” because this is the common term used by many users of this document. A2.3.5.5.5 248 HV 10 is equivalent to 22 HRC, the commonly referenced maximum hardness level for carbon steel to resist SSC. A2.3.5.5.6 During the hardness surveys, the weld metal typically is included to ensure coverage through the very narrow HAZ adjacent to the weld deposit. 210 HV 10 is equivalent to 200 HBW, the maximum hardness allowed in weld deposits. A2.3.5.5.7 Some companies may have already created WPSs based on hardness surveys performed in accordance with other standards (such as the layouts included in NACE MR0175/ISO 15156). The use of NACE MR0175/ISO 15156 hardness survey results are included here, as the two readings required in the HAZ near each side of the cap pass in NACE MR0175/ISO 15156 are intended to identify the most likely hard HAZ regions. A2.3.5.5.8 Microhardness tests are much more sensitive to very small regions of high hardness. It is uncertain whether those very small hard regions will significantly affect SSC resistance in production welds; as such, microhardness test results may be overly conservative. A2.3.5.5.9 Individual readings may indicate very small regions that are excessively hard. This paragraph provides a means for acceptance if the region is demonstrated to be very small by providing guidelines on how to retest the hard area. A2.3.5.5.10 This paragraph discusses requirements for documentation with the weld procedure qualification and the resulting WPS, providing particulars of the hardness surveys performed, as these are performance proof to the user of the capability of the weld procedure to achieve soft HAZs. A2.3.5.6.1 CE is not an absolute index of hardenability. As such, a steel with a lower CE value can exhibit higher weld HAZ hardness than a steel with a higher CE value, and vice versa, depending on the cooling time. It may be very difficult to purchase and control to a tight single value. Therefore, it is 24

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SP0472-2010 reasonable to allow some flexibility in the CE value of a production base metal with respect to the CE value of the procedure qualification specimen. BS EN 288-939 provides the basis for the + 0.03 allowance used here. A2.3.5.6.2 The base metal chemistry of the procedure qualification specimen and the hardness test results are discussed here, and they are to be added to the PQR for future review and validation purposes. A2.3.5.6.3 The base metal chemistry of the procedure qualification specimen is discussed with respect to the microalloying levels expected for the production welding. A2.3.5.7.1 This paragraph discusses the requirements to calculate the cooling time in the weld procedure qualification if cooling time control is used. Production welding can be performed at cooling times no shorter than in the weld procedure qualification. A2.3.5.7.2 Other processes, such as thermal cutting and tack welding, can also create hard HAZs. Appropriate preheating should be considered to mitigate this. A2.3.5.7.3 Small fillet welds onto components may have short cooling times (low t8/5 values), making them especially susceptible to creation of hard HAZs. Cooling time control as a thermal method for procedures that may entail this type of production welding are flagged to ensure that qualification of procedures consider these joint configurations. A2.3.5.7.4 This paragraph describes a simple approach for cooling time control by estimating the heat input for the SMAW process. This technique is not precise, so user approval is recommended. A2.3.5.7.5 This paragraph describes a simple approach for cooling time control by estimating the heat input for other welding processes. These techniques are not precise, so user approval is recommended. A2.3.5.7.6 Fillet weld heat input and cooling time can be sensitive to the weld position, so these are critical variables to include in qualification tests. Because overhead welding creates the shortest cooling times, it has the ability to qualify for other higher heat-input positions. A2.3.5.7.7 The extent of tempering by PWHT is a function of the time at temperature, so to ensure that adequate tempering in production welding occurs, PWHT used for production should have times and temperatures equal to or greater than those used in the procedure qualification, which includes metal thickness. A2.3.5.7.8 Qualification with temper bead welding should be consistent with the requirements in this standard. A2.4 In some cases, environmental cracking (both HSC and ASCC) has initiated from pre-existing weldment fabrication defects. Keeping defects to a minimum can be accomplished by doing thorough inspections upon fabrication to help reduce the onset of in-service damage. In addition, future defect inspections may be carried out to help users understand whether findings were generated by in-service exposure.

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SP0472-2010 ________________________________________________________________________ Appendix B Rationale for Guidelines for Prevention of Alkaline Stress Corrosion Cracking (Nonmandatory) This appendix is considered nonmandatory, although it may contain mandatory language. It is intended only to provide supplementary information or guidance. The user of this standard is not required to follow, but may choose to follow, any or all of the provisions herein. The rationale statements in this nonmandatory appendix are numbered to correspond with the associated paragraphs in Section 3 of this standard plus use of the prefix B for clarity. B3.1 The occurrence of ASCC requires three factors: a crack-inducing environment, a susceptible material, and a tensile stress exceeding a threshold value. Residual stresses from welding and/or forming are the most common sources of the tensile stress necessary for cracking. Residual tensile stresses in weldments are usually highest in the HAZ, but can sometimes extend up to 50 mm (2.0 in) away from the weld deposit. Hence, these are the most common locations for ASCC, with the cracks typically oriented parallel to the weld. PWHT is an effective method of preventing ASCC because it reduces residual stresses from welding. B3.2 PWHT procedures, including temperatures, times, heating rates, and cooling rates, are given in the ASME Boiler and Pressure Vessel Code. PWHT requirements for preventing ASCC differ somewhat from those listed in the ASME Boiler and Pressure Vessel Code. B3.3 It has been demonstrated that a higher PWHT temperature and a minimum hold time of one hour at temperature has been required to significantly reduce residual stresses. B3.4 Carbonate cracking has occurred in equipment that was stress relieved using the standard heat treatment procedures for other types of ASCC. This is believed to be attributable to a lower threshold stress for carbonate cracking. Field welds (especially in piping) have been found to be particularly vulnerable to carbonate cracking because of the difficulties often associated with field heat treatment (e.g., hold times and temperature control) and the presence of other local high stresses (e.g., bending stresses associated with elbows). B3.5.1 Variables affecting the depth of residual stresses are welding heat input, base metal thickness, and attachment weld size. B3.8 Mechanical stress-relief methods are not universally accepted as effective methods to prevent ASCC in these environments. A concern is that, although shot peening produces a surface layer with compressive stresses, this layer may eventually corrode away, exposing subsurface metal that still has residual tensile stresses. B3.9 Alternative welding methods, such as temper bead welding and controlled-deposition welding, are not effective in preventing ASCC. These methods do not sufficiently reduce residual stress and therefore should not be considered in lieu of thermal stress relief. B3.10 In some cases, environmental cracking (both HSC/SSC and ASCC) has initiated from pre-existing weldment fabrication defects, so these should be minimized.

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SP0472-2010 ________________________________________________________________________ Appendix C Summary of Cooling Time (t8/5) Concept (Nonmandatory) This appendix is considered nonmandatory, although it may contain mandatory language. It is intended only to provide supplementary information or guidance. The user of this standard is not required to follow, but may choose to follow, any or all of the provisions herein. Determination of cooling time (t8/5) This information has been primarily derived from Annex D of BS EN 1011-2.40 There are three steps in determining t8/5 for a given set of weld joint configuration and welding conditions. The first step is to determine the type of heat flow during welding, that is, whether the heat flow is either two- or threedimensional. The second step is to calculate the heat input. The third step is to determine t8/5 using either the calculation method or the graphical method. Step 1â&#x20AC;&#x2022;Determining two- or three-dimensional heat flow The determination of the type of heat flow during welding, whether two- or three-dimensional, depends on the thickness of the components that impact the heat flow, as shown conceptually in Figure C1.

Weld run

(a)

Weld run

(b)

Key (a) Three-dimensional heat flow. Relatively thick plates; plate thickness does not affect cooling time. (b) Two-dimensional heat flow. Relatively thin plates; plate thickness has a decisive influence on cooling time.

Figure C1: Types of heat flow during welding. Figure C2 is a diagram that provides information regarding the relationship between the transition thickness (dt, in mm), heat input (Q, in kJ/mm), and preheat temperature (Tp, in Â°C), for any type of weld and any welding process. This diagram indicates whether the heat flow is two- or three-dimensional for any particular combination of plate thickness, heat input, and preheat temperature.

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SP0472-2010

Three-dimensional heat flow

dt Two-dimensional heat flow

0.5

Q Key dt Q

Transition thickness (mm) Heat input (kJ/mm)

Figure C2: Transition plate thickness (dt) from three-dimensional to two-dimensional heat flow as a function of heat input (Q) for different preheat temperatures (Tp). Step 2―Calculating the heat input The heat input (Q, in kJ/mm) can be calculated using Equation (C.1): Q = ε x U x (I / v) / 1,000 (kJ/mm)

(C.1)

Where: E U I v ε

= = = = =

total welding heat input welding voltage (V) welding current (A) travel speed (mm/s) thermal efficiency of the welding procedure GTAW ε = 0.48 SMAW ε = 0.85 GMAW ε = 0.85 SAW ε = 1.0

Step 3―Determining t8/5 by the calculation method The relationship between the welding conditions and t8/5 can be described by equations that differentiate between two- and three-dimensional heat flow. 28

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SP0472-2010 For three-dimensional heat flow in unalloyed and low-alloyed steels, t8/5 can be determined using Equation (C.2): (C.2)

Where: t8/5 Tp Q F3

= = = =

cooling time (s) preheat temperature (Â°C) heat input (kJ/mm) calculated in accordance with Equation (C.1) appropriate shape factor for three-dimensional heat flow from Table C1.

For two-dimensional heat flow in unalloyed and low-alloyed steels, t8/5 can be determined using Equation (C.3):

(C.3) Where: t8/5 Tp Q F2 d

= = = = =

cooling time (s) preheat temperature (Â°C) heat input (kJ/mm) calculated in accordance with Equation (C.1) appropriate shape factor for two-dimensional heat flow from Table C1. thickness

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SP0472-2010 Table C1 Shape Factors for Influence of the Form of Weld on t8/5 Shape Factor Form of Weld

F2 two-dimensional heat flow

F3 three-dimensional heat flow

Run on plate

Between runs in butt weld

0.9

Single run fillet weld on a corner joint

Single run fillet weld on a T-joint

0.9 to 0.67

0.67

0.45 to 0.67

0.67

Step 3â&#x20AC;&#x2022;Determining t8/5 by the graphical method The cooling time (t8/5) can be determined using Figures C3 and C4, having first established the type of heat flow using Figure C1 and calculated the heat input (Q) using Equation (C.1). Figures C3 and C4 can also be used to determine the heat input for a given cooling time. For three-dimensional heat flow, the relationship between the cooling time (t8/5), the heat input (Q), and the preheat temperature (Tp), is given in Figure C3 for a run on plate weld with a shape factor of 1.0. Figure C3 is based on Equation (C.2). If Figure C3 is applied to another form of weld, consideration should be given to the corresponding shape factor (F3) given in Table C1. If the cooling time is to be determined for a particular combination of heat input and preheat temperature, the heat input should first be multiplied by F3. If, however, the heat input is to be determined for a particular combination of cooling time and preheat temperature, it should be divided by F3.

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t8/5

0.5

Q Key t8/5 Q

Cooling time (s) Heat input (kJ/mm)

Figure C3: Cooling time (t8/5) for three-dimensional heat flow as a function of heat input (Q) for different preheat temperatures (Tp). For two-dimensional heat flow, the relationship between the cooling time (t8/5), the heat input (Q), and the preheat temperature (Tp), is given in Figure C4 for a run on plate weld with a shape factor of 1.0 for different plate thicknesses (d). Figure C4 is based on Equation (C.3). If Figure C4 is applied to another form of weld, consideration should be given to the corresponding shape factor (F2) given in Table C1. If the cooling time is to be determined for a particular combination of heat input and preheat temperature, the heat input should first be multiplied by (F2)1/2. If, however, the heat input is to be determined for a particular combination of cooling time and preheat temperature, it should be divided by (F2)1/2. If, in the case of two-dimensional heat flow, the actual plate thickness does not correspond exactly to the plate thickness shown on one of the diagrams in Figure C4, the diagram closest to the actual plate thickness should be used. The cooling time should then be corrected in accordance with the plate thickness ratio. To do this, the cooling time taken from the diagram is multiplied by the square of the plate thickness taken from the diagram, and then divided by the square of the actual plate thickness.

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SP0472-2010

t8/5

t8/5 Three-dimensional heat flow

0.5 Q Key t8/5 Q

Cooling time (s) Heat input (kJ/mm)

Figure C4: Cooling time (t8/5) for two-dimensional heat flow as a function of heat input (Q) for different preheat temperatures (Tp) and plate thicknesses (d).

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NACE Standard RP0472-2005 Item No. 21006

Standard Recommended Practice Methods and Controls to Prevent In-Service Environmental Cracking of Carbon Steel Weldments in Corrosive Petroleum Refining Environments This NACE International standard represents a consensus of those individual members who have reviewed this document, its scope, and provisions. Its acceptance does not in any respect preclude anyone, whether he or she has adopted the standard or not, from manufacturing, marketing, purchasing, or using products, processes, or procedures not in conformance with this standard. Nothing contained in this NACE International standard is to be construed as granting any right, by implication or otherwise, to manufacture, sell, or use in connection with any method, apparatus, or product covered by Letters Patent, or as indemnifying or protecting anyone against liability for infringement of Letters Patent. This standard represents minimum requirements and should in no way be interpreted as a restriction on the use of better procedures or materials. Neither is this standard intended to apply in all cases relating to the subject. Unpredictable circumstances may negate the usefulness of this standard in specific instances. NACE International assumes no responsibility for the interpretation or use of this standard by other parties and accepts responsibility for only those official NACE International interpretations issued by NACE International in accordance with its governing procedures and policies which preclude the issuance of interpretations by individual volunteers. Users of this NACE International standard are responsible for reviewing appropriate health, safety, environmental, and regulatory documents and for determining their applicability in relation to this standard prior to its use. This NACE International standard may not necessarily address all potential health and safety problems or environmental hazards associated with the use of materials, equipment, and/or operations detailed or referred to within this standard. Users of this NACE International standard are also responsible for establishing appropriate health, safety, and environmental protection practices, in consultation with appropriate regulatory authorities if necessary, to achieve compliance with any existing applicable regulatory requirements prior to the use of this standard. CAUTIONARY NOTICE: NACE International standards are subject to periodic review, and may be revised or withdrawn at in accordance with NACE technical committee procedures. NACE International requires that action be taken to reaffirm, revise, or withdraw this standard no later than five years from the date of initial publication. The user is cautioned to obtain the latest edition. Purchasers of NACE International standards may receive current information on all standards and other NACE International publications by contacting the NACE International FirstService Department, 1440 South Creek Dr., Houston, Texas 77084-4906 (telephone +1 281/228-6200). Revised 2005-12-02 Reaffirmed 2000-09-13 Revised October 1995 Revised March 1987 Reaffirmed 1974 Approved April 1972 NACE International 1440 South Creek Dr. Houston, Texas 77084-4906 +1 281/228-6200 ISBN 1-57590-114-5 ÂŠ 2005, NACE International

RP0472-2005 ________________________________________________________________________ Foreword Most petroleum refining equipment and piping are constructed of carbon steel having a minimum specified tensile strength of up to 480 MPa (70,000 psi), and in almost every case, the equipment and piping are fabricated by welding. The welds for refinery equipment and piping are made to conform to various codes and standards, including the (1) 1 (2) 2 ASME Boiler and Pressure Vessel Code, Section VIII, the ASME/ANSI B31.3 for (3) 3 4 process piping, or API Standards 620 and 650 for tanks. According to these codes and standards, these carbon steels are classified as P-No. 1, Group 1 or 2, and in this standard they are referred to as “P-No. 1 steels.” Petroleum refineries as well as oil- and gas-processing plants have used P-No. 1 steels widely for wet hydrogen sulfide (H2S) or “sour” services. They are the basic materials of construction for pressure vessels, heat exchangers, storage tanks, and piping. Decades of successful service have shown them to be generally resistant to a form of hydrogen stress cracking (HSC) called sulfide stress cracking (SSC). HSC has been found to occur in high-strength materials or zones of a hard or high-strength microstructure in an otherwise soft material. With commonly used fabrication methods, P-No. 1 steels should be below the strength threshold for this cracking. 5

Some useful information is given in NACE Standard MR0103. NACE Standard MR0103 provides guidance for materials in sour oil and gas environments in refinery services including limiting the hardness of P-No. 1 steels, reducing the likelihood of SSC. (4) 6 Additional useful information is given in NACE Standard MR0175/ISO 15156, a standard that provides guidance for materials in sour oil and gas environments in production services. In the late 1960s, a number of SSC failures occurred in hard weld deposits in P-No. 1 steel refinery equipment and piping. The high hardnesses were found to be caused by submerged arc welding (SAW) with active fluxes and/or additions of alloying elements, both of which primarily resulted in increased hardenability of the weld deposit. High hardnesses were also found in gas metal arc welds with high manganese and silicon contents. To detect hard weld deposits caused by improper welding materials or procedures, the petroleum refining industry began requiring hardness testing of production weld deposits under certain conditions and applied a criterion of 200 Brinell (HBW) maximum. These requirements were given in previous editions of this standard 7 and in API RP 942. The current P-No 1 hardness limit of 200 HBW maximum is lower than the 22 HRC (237 HBW) hardness limit listed in NACE MR0175/ISO 15156. Reasons for applying a lower limit were to compensate for nonhomogeneity of some weld deposits and normal variations in production hardness testing using a portable Brinell tester. In the late 1980s, numerous cracks were discovered in P-No. 1 steel equipment that met the 200 HBW weld deposit hardness limit. Some of these cracks have been identified as another form of hydrogen damage, labeled as stress-oriented hydrogen-induced cracking 8 (SOHIC). These cracks propagated primarily in the heat-affected zones (HAZs) of weldments and were found in both high- and low-hardness HAZs. Also, cases of SSC were reported in HAZs of weldments that met the 200 HBW weld deposit hardness limit. In these cases, the HAZ exhibited high hardnesses, often higher than 240 HBW. However, HAZ hardness limits and testing were outside the scope of the previous editions of this standard, which covered only weld deposit hardness limits. _____________ (1)

ASME International (ASME) Three Park Avenue, New York, NY 10016-5990. American National Standards Institute (ANSI), 11 West 42nd St., New York, NY 10036. (3) American Petroleum Institute (API), 1220 L St. NW, Washington, DC 20005. (4) International Organization for Standardization (ISO), 1 rue de Varembe, Case Postale 56, CH-1121, Geneve 20, Switzerland. (2)

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RP0472-2005

In 1991, NACE Task Group T-8-7 agreed that this standard should be more comprehensive, covering the entire weldment and various in-service cracking mechanisms that can occur in corrosive petroleum refining environments. Experience has shown that accurate HAZ hardness measurements cannot be obtained effectively on most shop and field production welds using portable hardness testing methods. Therefore, some companies in the refining industry are using one or more of the following practices to control HAZ hardnesses: • • •

Use of controlled base material chemistries with lower hardenability when welded; Use of postweld heat treatment (PWHT); or Use of welding procedures that have been qualified with HAZ hardness testing.

Each of these practices is addressed in this standard. In some specific corrosive refinery process environments, cracking of weldments can occur because of residual stresses. Generally, residual stresses are reduced by PWHT. This type of cracking and the use of PWHT as a prevention method are also addressed in this standard. This standard was originally prepared in 1972 by NACE Task Group T-8-7, which was composed of corrosion consultants, corrosion engineers, and other specialists associated with the petroleum refining industry. It was reaffirmed in 1974 and revised in 1987 and 1995. It was reaffirmed in 2000 by Specific Technology Group (STG) 34 on Petroleum Refining and Gas Processing, and revised in 2005 by NACE Task Group (TG) 326 on Weldments, Carbon Steel: Prevention of Environmental Cracking in Refining Environments. API previously published a standard, API RP 942, with similar objectives. The API standard has been discontinued with the intention of recognizing this NACE standard as the industry consensus standard. This standard is issued by NACE International under the auspices of STG 34 on Petroleum Refining and Gas Processing.

In NACE standard, the terms shall, must, should and may are used in accordance with the definitions of these terms in the NACE Publications Style Manual, 4th ed., Paragraph 7.4.1.9. Shall and must are used to state madatory requirements. Should is used to state something considered good and is recommended but is not mandatory. The term may is used to state something considered optional.

________________________________________________________________________

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RP0472-2005

________________________________________________________________________

NACE International Standard Recommended Practice Methods and Controls to Prevent In-Service Environmental Cracking of Carbon Steel Weldments in Corrosive Petroleum Refining Environments Contents 1.General ............................................................................................................................ 1 2.Hardness Criterial and Guidelines. .................................................................................. 3 3.Weld Deposit Hardness Testing ...................................................................................... 5 4.Materials and Fabrication Variables Affecting Weldment Hardness................................ 6 5.Welding Procedure Qualification Hardness Testing for Weldments................................ 7 6.Prevention of Weldment Cracking by Control of Residual Stress ................................... 9 References........................................................................................................................ 10 Bibliography ...................................................................................................................... 12 Appendix A: Suggested Guidelines for Portable Brinell Hardness Testing of Welds .......................................................................................................................... 13 Figure 1: Interrelationships of the Various Cracking Mechanisms..................................... 2 Figure 2: Typical Hardness Test Locations—Butt Weld .................................................... 8 Figure 3: Typical Hardness Test Locations—Fillet Weld ................................................... 9 Table 1: “Road Map” for RP0472....................................................................................... 3 Table 2: Process/Filler Material Combinations Exempt from Weld Deposit Hardness Testing .......................................................................................................... 4 ________________________________________________________________________

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RP0472-2005 ________________________________________________________________________ Section 1: General 1.1 This standard establishes guidelines to prevent most forms of environmental cracking of weldments in carbon steel refinery equipment and piping. Weldments are defined to include the weld deposit, base metal HAZs, and adjacent base metal zones subject to residual stresses from welding. 1.2 This standard covers only carbon steels classified as P-No. 1, Group 1 or 2. These classifications can be found 9 in the ASME Boiler and Pressure Vessel Code, Section IX, ASME/ANSI B31.3 Code for process piping, or API Standards 620 and 650 for tanks. It excludes steels over 480 MPa (70,000 psi) minimum specified tensile strength. Other materials may be vulnerable to cracking, but these materials are outside the scope of this standard. 1.3 The types of equipment covered by this standard include pressure vessels, heat exchangers, storage tanks, piping, valve bodies, and pump and compressor cases. All pressure-containing weldments or internal attachment weldments to the pressure boundary are included. In addition, weldments in some nonpressure-containing equipment, such as storage tanks, are included. External attachment weldments are sometimes included as discussed in Paragraph 6.4.6. 1.4 Both new fabrication and repair welds are within the scope of this standard. However, the practices recommended herein are intended to avoid in-service cracking, and are not intended to address cracking that can occur during fabrication, such as delayed hydrogen cracking. Useful information is provided by F.R. Coe, et. 10 al. In most cases, however, these practices are also helpful in minimizing these fabrication problems. 1.5 Welding processes covered by this standard include shielded metal arc welding (SMAW); gas metal arc welding (GMAW); flux-cored arc welding (FCAW); gas tungsten arc welding (GTAW); and submerged arc welding (SAW). Almost all types of weld configurations are included. Some specific exceptions include hot taps or weld build-ups. Hardness limits and PWHT requirements for these exceptions (i.e., weld configurations) should be reviewed on a case-by-case basis. 1.6 Corrosive refinery process environments covered by this standard can be divided into the two general services listed below. However, identification of the specific environments to which the guidelines set forth in this standard are to be applied to prevent various forms of inservice environmental cracking is the responsibility of the user. Figure 1 is a simplified schematic showing the interrelationships of the various cracking mechanisms discussed in this standard. 1.6.1 Services that could cause cracking due to hydrogen charging:

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1.6.1.1 In these services, the environment or corrosion reactions result in diffusion of atomic hydrogen into the base metal and weldment. In high-strength or high-hardness areas, this hydrogen can result in HSC. In petroleum refining processes, the primary manifestation of HSC is SSC of hard weldments in process environments containing wet H2S. Information regarding the definition of wet H2S refinery services is given in NACE MR0103. However, other processes that promote aqueous corrosion of steel and promote hydrogen charging (such as hydrofluoric acid) can also cause HSC. Controlling both the weld deposit and HAZ hardness using the guidelines of Section 2 prevents HSC in most cases. 1.6.1.2 SOHIC can also occur in the services described above, but it does not require high strengths or high hardnesses. Hence, limiting weldment hardness does not prevent this form of cracking. Reducing weldment hardness and residual stress is believed to reduce the likelihood of this cracking, so the guidelines given in Sections 2 and 6 may still be helpful. However, additional steps, such as the use of special clean steels, water washing, corrosion inhibitors, or corrosion-resistant liners, may be needed for 11 some services. An overview of the materials selection, fabrication, PWHT, and testing practices that have been applied to new pressure vessels for mitigating SOHIC is provided in NACE 11 Publication 8X194. 1.6.1.3 Cases of cracking of hard welds have occurred as a result of short-term upset, start-up, or transient conditions in nonstress-relieved P-No. 1 carbon steel refinery equipment and piping in which hydrogen sulfide is not normally present. While this standard covers only P-No. 1 materials, it should be noted that welds have also cracked in tanks and pressure vessels constructed of nonstress-relieved P-No. 10A and 10C carbonmanganese steels. 1.6.2 Services that could cause alkaline stress corrosion cracking (ASCC): 1.6.2.1 Figure 1 provides examples of services that can cause ASCC, including caustic cracking, amine cracking, and carbonate cracking. Section 6 provides common practices used to avoid these types of ASCC. Severity of cracking is often dependent on temperature, concentration, level of residual tensile stresses, and other factors. Controlling weldment hardness does not prevent ASCC because high tensile stresses may still be present.

RP0472-2005

FIGURE 1 Interrelationships of the Various Cracking Mechanisms _______________________________ Refer to the NACE Glossary of Corrosion-Related Terms for definitions (including “stress corrosion cracking”). (B) The forms of environmental cracking included within the double lines are commonly referred to as “wet H2S cracking” when they occur in wet hydrogen sulfide environments. (C) This form of environmental cracking can also occur in nonsulfide environments such as hydrofluoric acid. (A)

1.6.2.2 Further information about caustic cracking and its prevention can be found in NACE Standard 12 RP0403. 1.6.2.3 Further information about amine cracking 13 and its prevention can be found in API RP 945. 1.6.2.4 Further information about carbonate cracking and its prevention will be forthcoming in a technical committee report currently being 14 developed by NACE TG 347. 1.7 For most refinery services, weld deposit hardness should be controlled as discussed in Paragraph 2.2. This practice primarily helps avoid the use of improper welding materials, welding procedures, or heat treatment. It also minimizes the risk of HSC from external wet atmospheric corrodents, process upsets, or from future changes in services.

1.8 In some cases, environmental cracking (both HSC and ASCC) has initiated from pre-existing weldment fabrication defects. Hence, during original fabrication, weldments should be inspected for defects such as lack of fusion, delayed hydrogen cracking, or severe undercut. Any defects found should be removed. 1.9 One possible environmentally induced cracking mechanism in carbon steel weldments that is not addressed in this standard is high-temperature hydrogen attack. API 15 RP 941 gives recommendations on materials selection to avoid this problem. Other types of in-service cracking not addressed by this standard are primarily mechanical in nature. Examples are fatigue, creep, and brittle fracture. Table 1 provides an overview (“road map”) of the guidelines applicable to the various types of cracking.

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RP0472-2005 TABLE 1: â&#x20AC;&#x153;Road Mapâ&#x20AC;? for RP0472 General Service/Possible Cracking (A) Mechanism

Weldment Component

Cracking Prevention and/or Hardness Control Method

Hardness Limit

1. Wet H2S service/HSC or SSC concerns

Weld deposit

Hardness testing of production welds

200 HBW

Paragraphs 1.6.1, 1.7, and 2.2

Section 3

HAZ

Three options: 1. Base metal chemistry controls,

Not (C) applicable

Paragraphs 1.6.1 and 2.3.1

2. PWHT, or

Not (C) applicable

Paragraphs 1.6.1 and 2.3.1.2

Paragraph 4.2 and NACE Publication 11 8X194

3. HAZ hardness tests during welding procedure qualification

248 HV (70.5 HR 15N)

Paragraphs 1.6.1, 2.3.1.3, and 2.3.2

(C)

Application (B) Guidelines

Test Method and Implementation (B) Guidelines

Paragraph 4.3 Section 5

2. ASCC: Caustic Cracking

Entire weldment

PWHT

Not (C) applicable

Paragraph 1.6.2.2

Section 6 and Paragraph 6.4.3

Amine Cracking

Entire weldment

PWHT

Not (C) applicable

Paragraph 1.6.2.3

Section 6 and Paragraph 6.4.3

Carbonate Cracking

Entire weldment

PWHT

Not (C) applicable

Paragraph 1.6.2.4

Section 6 and Paragraph 6.4.4

(A)

Specific services requiring controls, and the optimum control method, shall be defined by the user. Many qualifiers and additional details are given in the referenced sections and paragraphs. (C) Weld deposit hardness should also be controlled to 200 HBW maximum (see Paragraphs 1.7 and 6.2). (B)

________________________________________________________________________ Section 2: Hardness Criteria and Guidelines 2.1 This section provides acceptable hardness limits for (a) production weld deposits and (b) laboratory hardness tests on weldments performed during welding procedure qualification. It also provides guidelines on filler metal selection to help meet the production weld deposit hardness criteria. 2.2 Production Weld Deposit Hardness Criteria and Filler Metal Selection Guidelines

2.2.1 For services in which control of the deposited weld metal hardness is considered necessary, the hardness of the completed weld deposit shall not exceed 200 HBW. 2.2.2 Filler materials for the following welding processes shall be certified in accordance with the listed specifications from the ASME Boiler and 16 Pressure Vessel Code, Section II, Part C or from the (5) American Welding Society (AWS) :

___________________________ (5)

American Welding Society (AWS), 550 NW LeJeune Rd., Miami, FL 33126.

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(a) SMAW: ASME SFA-5.1 or AWS A5.1;

(b) GTAW and GMAW: ASME SFA-5.18 20 A5.18; 21

(d) SAW: ASME SFA-5.17 or AWS A5.17.

or AWS

2.2.3 Experience indicates that hardness values above 200 HBW rarely occur in weld deposits produced using the welding process and filler material combinations listed in Table 2. Hence, these weld deposits do not require hardness testing unless otherwise specified by the user. This waiver may be applied even if a different consumable is used for the root pass.

and

Table 2: Process/Filler Material Combinations Exempt from Weld Deposit Hardness Testing

Welding Process SMAW

GTAW

GMAW (spray, pulsed, and globular transfer modes only)

Filler Specification ASME SFA-5.1 or AWS A5.1 ASME SFA-5.18 or AWS A5.18

ASME SFA-5.18 or AWS A5.18

Filler Grade

Compositional Restrictions (See Paragraph 2.2.3.1)

E60XX or E70XX

None

ER70S-2, ER70S-3, or ER70S-4

None Carbon (C) Manganese (Mn) Silicon (Si)

ER70S-6 ER70S-2, ER70S-3, or ER70S-4

2.2.3.1 The compositional restrictions listed in Table 2 are in addition to the requirements specified by the parent filler material specification. These compositional restrictions are based on hardenability calculations performed in (6) accordance with methods described in IIW 25 Document IX-2058-03. 2.2.3.2 Filler grades listed in Table 2 with compositional restrictions may not be used unless actual chemical analysis is performed on the filler material indicating that the corresponding compositional restrictions have been met. The chemical analysis may be obtained by any of the following methods: (a) Purchasing the filler material with a certification of the actual chemical analysis; (b) Performing a chemical analysis on a sample of a specific heat of candidate weld rod in accordance with the requirements listed in Section 10 of ASME SFA-5.18; or (c) Performing a chemical analysis on a weld deposit produced using the specific heat of candidate material. If this method is used, the weld pad in accordance with Figure 3 in ASME

ER70S-6

0.10 wt% max 1.60 wt% max 1.00 wt% max

None C Mn Si

0.10 wt% max 1.60 wt% max 1.00 wt% max

SFA-5.18 shall be produced using the welding process and welding procedure used in production. The heat input, wire size, preheat, and interpass temperature shall be controlled as specified in Paragraphs 5.2.4 through 5.2.8 of this standard. The chemical analysis shall be performed in accordance with the requirements listed in Section 10 of ASME SFA-5.18. A hardness test shall also be performed when this method is used. The hardness of the deposit shall not exceed 200 HBW. Note: The same welding process and welding variables shall be used for this method because the relationship between filler metal chemistry and weld deposit chemistry is a function of the welding process and variables. For example, in GMAW welding using CO2 mixtures, oxygen generated by breakdown of the CO2 causes oxidation of Mn and Si in the weld metal, thus reducing the concentration of these elements in the weld deposit matrix. Reductions of 0.3 wt% in Mn and 0.2 wt% in Si are common in GMAW deposits produced using using 100% CO2.

___________________________ (6)

International Institute of Welding (IIW), ZI Paris Nord 2 50362, F95942 Roissy CDG, Cedex, France.

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RP0472-2005 2.2.3.3 When welding process/filler combinations in accordance with Table 2 are used in lieu of production weld deposit hardness testing, a process shall be implemented to control the identification and use of these filler materials in production welding. 2.2.4 High weld deposit hardnesses can occur with SAW when using a low- or medium-Mn wire in 26,27,28 combination with an active flux. Also, some SAW welds with high Mn and Si contents can have highly localized hard zones that are not softened significantly 29 by PWHT. Most welding consumable manufacturers recommend against the use of active fluxes for multipass welds. Hence, unless otherwise agreed, production SAW weld deposits shall meet the A-No. 1 chemical composition shown in Table QW-442 of the ASME Boiler and Pressure Vessel Code, Section IX. 2.2.5 Some GTAW, GMAW, and FCAW wire classifications allow high Mn concentrations. Therefore, production weld deposits made with these welding processes should also meet the A-No. 1 chemical composition shown in Table QW-442 of the ASME Boiler and Pressure Vessel Code, Section IX. 2.2.6 Weld deposit hardness testing guidelines are provided in Section 3. 2.3 HAZ Hardness Criteria and Application Guidelines 2.3.1 High-hardness microstructures in HAZs may be susceptible to cracking even with soft weld deposits in severely corrosive petroleum refinery services. For these services and equipment, as identified by the user, one or more of the following methods of obtaining acceptable HAZ hardnesses should be specified by the user:

2.3.1.1 Use and control of base material chemistries, preheat, and welding heat input such that a hard HAZ microstructure is not likely to be formed. 2.3.1.2 PWHT at a temperature high enough to ensure softening of the HAZ microstructure. NOTE: Details on the use of the methods given in Paragraphs 2.3.1.1 and 2.3.1.2 are provided in Section 4 and in NACE Publication 8X194. 2.3.1.3 Preproduction HAZ hardness testing during the welding procedure qualification using Vickers (HV) or Rockwell Superficial Hardness (HR 15N) testing. 2.3.2 When preproduction welding procedure qualification HAZ hardness testing is used, the maximum allowable HAZ hardness shall be 248 HV (70.5 HR 15N). 2.3.2.1 Both laboratory testing and field experience with carbon and low-alloy steel weldments have shown that microstructures with hardness values less than 248 HV (70.5 HR 15N) 30,31,32 have a low susceptibility to SSC. 2.3.2.2 The Brinell test method is considered unacceptable for HAZ hardness testing because it creates too large an indentation to obtain hardness values strictly from the HAZ and results in a bulk hardness value that is not representative of the peak HAZ hardness. 2.3.2.3 Guidelines for testing during welding procedure qualification and practices for ensuring that the test results are representative of production welds are given in Section 5.

________________________________________________________________________ Section 3: Weld Deposit Hardness Testing 3.1 The practices in this section should be applied to all services covered by the scope of this standard, except for the waiver given to some SMAW, GTAW, and GMAW welds in Paragraph 2.2.3, unless otherwise specified by the user. The practices may also be applied to other services for the reasons given in Paragraph 1.7. 3.2 When required, hardness testing on completed welds shall be done after any PWHT. Only weld deposits require hardness testing unless otherwise specified by the user.

3.3 Weld deposits shall be hardness tested on the side contacted by the process whenever possible. If access to the process side is impractical, such as on piping or smalldiameter vessels, hardness testing shall be done on the opposite side. 3.4 Hardness readings shall be taken with a portable (7) 33 Brinell hardness tester, in accordance with ASTM A 833. Additional hardness testing technique guidelines are given in Appendix A. Other hardness testing techniques may be employed if approved by the user.

___________________________ (7)

ASTM International (ASTM), 100 Barr Harbor Dr., West Conshohocken, PA 19428-2959.

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RP0472-2005 3.8.3 Hardness testing shall be performed on actual weld repairs when possible. Hardness testing can be performed on an actual weld repair area if the repair is accessible, large enough to accommodate an indentation, and in a location where an indentation can be tolerated.

3.5 For vessel or tank butt welds, a minimum of one location per weld seam shall be hardness tested. Unless otherwise specified by the user, one hardness test should be made for each 3 m (10 ft) of weld seam. In addition, one hardness test shall be made on each nozzle flange-to-neck and nozzle neck-to-shell/head weld. Each welding procedure used shall be hardness tested. 3.6 Hardness testing of fillet weld deposits should be done when feasible. The number of hardness tests and locations required shall be approved by the user with Paragraph 3.5 as a guide. 3.7 For piping welds, a percentage of butt welds shall be hardness tested. A minimum of 5% should be hardness tested, unless otherwise specified by the user. 3.8 Casting repair welds shall be hardness tested in accordance with the following requirements: 3.8.1 Hardness testing shall be performed on each casting that has been repaired. 3.8.2 At least one hardness test shall be performed for each unique â&#x20AC;&#x153;welding process/filler metal heat numberâ&#x20AC;? combination used on the casting.

3.8.4 In cases in which actual weld repairs cannot be hardness tested, weld test patches shall be created on an accessible area of the casting to allow hardness testing. 3.9 Weld deposits found to exceed the maximum hardness criteria given in Paragraph 2.2.1 are unacceptable and shall be reported to the user. Unless accepted by the user, hard welds shall be either removed and rewelded, or heat treated to reduce the hardness to an acceptable value. The specific approach to be used to correct the high-hardness condition shall be subject to the userâ&#x20AC;&#x2122;s approval before any corrective action is taken. Regardless of the method of corrective action taken, the weld deposits shall be retested to ensure that the corrective action has resulted in acceptable hardness values. Also, additional welds should be hardness tested for each high-hardness weld that is found, at a rate determined by the user.

________________________________________________________________________ Section 4: Materials and Fabrication Variables Affecting Weldment Hardness 4.1 Various references give general discussions on the effects of material composition, welding procedure, and PWHT on weld deposit and HAZ hardnesses. From this literature and field experience, the following methods of controlling weldment hardness have been determined.

CE = wt % C +

wt% Mn 6

(wt%Ni + wt% Cu) 15

4.3 PWHT almost always reduces weldment hardnesses to acceptable levels. PWHT concerns and issues are: 4.3.1 Required temperature ranges and hold times are given in various codes; however, a one-hour minimum hold time should be specified to ensure complete heat treatment. 4.3.2 A PWHT procedure should be developed prior to heat treating. It should include the type of heating process, the number and locations of thermocouples, supporting details, heat-up and cool-down rates, maximum allowable temperature differentials, soak time, and PWHT temperature range. The user may require submittal of the procedure for approval prior to the start of PWHT.

4.2 Control of the base material chemistry of all production material for a given application can be an effective method of controlling the HAZ microstructure and hardness. This is generally done by controlling the carbon equivalent (CE), as determined by the formula given in Equation (1), total concentration of unspecified elements, and microalloying element additions. Examples of possible base material chemistry controls are provided in NACE Publication 8X194.

(wt%Cr + wt% Mo + wt% V) 5

(1)

4.3.3 PWHT is not practical for some welds on valves, pumps, compressor casings, or compressor heads, especially after final machining. Other techniques of reducing HAZ hardness should be used (see Paragraph 2.3.1). 4.3.4 The ASME Boiler and Pressure Vessel Code Section VIII, Division 1, allows PWHT to be performed at temperatures below the minimum specified temperature as long as the temperature is held for a longer time (see Paragraph UCS-56 of ASME Section VIII, Division 1). A lower temperature PWHT would be expected to be effective in preventing SSC in most PNo. 1 weldments because of the reduction of residual stresses; however, when the PWHT is being performed to reduce HAZ hardness, these lower temperatures may not be sufficient. (See Paragraph 4.3.5.)

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RP0472-2005 4.3.5 P-No. 1 steels in accordance with Paragraph 1.2 that have deliberate additions of microalloying elements may require additional preheat and higher PWHT temperatures to obtain acceptable HAZ hardnesses. These heat treatments needed to obtain acceptable HAZ hardnesses may adversely affect 11 toughness values. There is a general consensus that this applies to steels with niobium (Nb) (columbium [Cb]) plus vanadium (V) contents greater than 0.03 wt% or total content of unspecified elements greater than 0.5 wt%. Welding procedures for such steels should be qualified in accordance with Section 5. Note: The definition of deliberate addition of a microalloying element for use with this standard is given in Paragraph 5.2.3. 4.4 Preheating and high heat inputs during welding are generally beneficial in reducing weldment hardness because they reduce the cooling rate of the weldment. Preheating may also be applied to thermal cutting and tack welding (if subsequent grinding is not done). Guidelines for when to preheat and minimum preheat temperatures are given in applicable design codes, e.g., the nonmandatory Appendix R in ASME Boiler and Pressure Vessel Code, Section VIII, Division 1. Additional information on the use of preheat and heat input to control weldment hardness (and susceptibility to delayed hydrogen cracking during fabrication) is available.

4.5 Small fillet welds on large sections are often prone to high HAZ hardnesses. This is because such welds often have low heat inputs and the large sections act as significant heat sinks that result in high cooling rates. One example is tray-attachment welds in vessels. Hardness problems can be minimized by using the techniques discussed in Paragraphs 4.2, 4.3, or 4.4. 4.6 The highest hardness in weldments is generally in the HAZ of the last weld pass. Therefore, one-sided welds with no backwelding are of less concern than two-sided or backwelded welds, because the highest hardness zones are not in direct contact with the process. Problems on twosided or backwelded welds can be minimized by using the techniques discussed in Paragraphs 4.2, 4.3, or 4.4, or by using a temper bead technique. With the temper bead technique, the cap pass should be applied so that the edges of the weld beads come within 3.0 mm (0.12 in.) of the base material, but do not touch the base material. If this results in an unacceptable profile as determined by the user, the excess weld may be removed by grinding.

________________________________________________________________________ Section 5: Welding Procedure Qualification Hardness Testing for Weldments 5.1 ASME Boiler and Pressure Vessel Code, Section IX, requires qualification of welding procedures to ensure that room-temperature tensile strength and ductility of the weldment meet minimum values. Welding must be performed within the essential variables specified for the welding process used. The ASME Boiler and Pressure Vessel Code has no requirements for hardness testing during procedure qualification tests. The following practices for hardness testing during procedure qualification tests have been developed and apply primarily to weldments in which PWHT or base material chemistry controls are not used. The user shall specify when this hardness testing is required and which of the following practices are required, after reviewing the intended service for the weldment. 5.2 When HAZ hardness testing is being used during welding procedure qualification, additional practices are needed to ensure that the hardness tests are representative of production weldments. Materials and welding conditions used for the procedure qualification tests should be equivalent to what is used for the equipment or piping. This should be done by applying the following additional essential variables, as appropriate. Some of the following practices may conflict with the ASME Boiler and Pressure Vessel Code, Section IX, supplemental essential variables for applications with notch toughness testing requirements. For these cases, the other options of PWHT or base

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material chemistry controls (Paragraphs 2.3.1.1 or 2.3.1.2) should be used. 5.2.1 Production materials should be of the same ASME specification and class or grade as the material used for the qualification hardness testing. 5.2.2 Maximum CE should not exceed the corresponding values obtained on the test sample. All chemical requirements should be applied to ladle analyses, unless otherwise specified by the user. 5.2.3 Maximum contents for each deliberately added microalloying element (such as Nb [Cb], V, titanium [Ti], and boron [B]) should not exceed the corresponding value on the test sample. Deliberate additions are generally considered to be greater than 0.01 wt% for each of Nb (Cb), V, and Ti, and greater than 0.0005 wt% of B. All chemical requirements should be applied to ladle analyses, unless otherwise specified by the user. 5.2.4 For all welding processes, the heat input during production welding should not vary by more than +25/10% from the heat input used on the test sample. Heat input shall be calculated using Equation (2):

RP0472-2005 HI =

(V × A × 60)

(2)

(TS)

where: HI V A TS

= = = =

Heat Input (J/mm or J/in.); Voltage (V); Amperage (A); and Travel Speed (mm/min or in./min).

5.2.5 As an alternative for SMAW, the maximum bead size and the minimum length of weld bead per unit length of electrode used in the welding of the test sample shall be the limits applied to production welding. 5.2.6 For SAW, the flux and wire, and for FCAW, the wire used for production welding shall be the same brand name and type as that used in the qualification tests. 5.2.7 For GMAW and FCAW, the wire size used for production welding should be the same as that used during qualifaction tests. For other welding processes, only one size variation between the electrode or filler metal size used for the qualification tests and for subsequent production welding should be permitted.

5.2.8 Preheat and interpass temperatures used during production welding should be greater than or equal to that used in the welding procedure qualification tests. 5.2.9 For welds that are not preheated, the maximum thickness allowed on production materials should be equal to the test sample thickness. 5.2.10 Weld bead sequence of the cap pass can affect the hardness of the HAZ. If a temper bead technique is used during qualification, the production procedure should require that the cap pass be applied so that the edges of the weld beads come within 3.0 mm (0.12 in.) of the base material, but not touch the base material. If this results in an unacceptable profile as determined by the user, the excess weld may be removed by grinding. 5.2.11 For fillet weld qualification tests, position should be an essential variable; however, tests on welds made in the overhead position shall qualify all other fillet positions. 5.3 Figures 2 and 3 show typical hardness test locations for butt welds and fillet welds, respectively. The maximum allowable HAZ hardness shall be 248 HV (70.5 HR 15N) as given in Paragraph 2.3.2. Using these hardness test methods, the maximum weld deposit hardness should be 248 HV (70.5 HR 15N), and the average weld deposit hardness should not exceed 210 HV (91.5 HR 15T). Note: 210 HV is equivalent to 200 HBW.

FIGURE 2 Typical Hardness Test Locations—Butt Weld

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RP0472-2005

FIGURE 3 Typical Hardness Test Locationsâ&#x20AC;&#x201D;Fillet Weld NOTE: Figures 2 and 3 are schematic only. In both types of welds, hardness test results have typically been obtained from the points in which the hardness traverses cross the weld fusion lines and from representative areas of the heataffected zones. 5.4 Microhardness testing using Knoop or Vickers tests with loads â&#x2030;¤500 g may be considered; however, the effects of surface preparation, etching, mounting procedures, appropriate criteria, and other details should be reviewed and approved by the user before these test techniques are used. 5.5 Guidance on these hardness test techniques is given in 34 35 ASTM E 384 and ASTM E 18.

5.6 Individual HAZ hardness readings exceeding the value permitted by this standard are considered acceptable if the average of three hardness readings taken within close proximity does not exceed the values permitted by this standard and no individual hardness reading is greater than 10 HV (1 HR 15N) units above the acceptable value. 5.7 The fabricator shall add the hardness test results to the ASME Procedure Qualification Record (PQR). The results should include a sketch of the hardness test locations and corresponding results. The weld procedure specification (WPS) should be revised to reflect the limits imposed by the essential variables applied from Paragraph 5.2. The user may require that both forms be submitted for approval prior to production welding.

________________________________________________________________________ Section 6: Prevention of Weldment Cracking by Control of Residual Stress 6.1 This section deals with the prevention of ASCC. ASCC generally has three requirements: a crack-inducing environment, a susceptible material, and a tensile stress. Residual stresses from welding and/or forming are the most common sources of the tensile stress necessary for cracking. Residual tensile stresses are usually highest in the HAZ, but can sometimes extend up to 50 mm (2.0 in.) away from the weld deposit. Hence, these are the most common locations for ASCC, with the cracks typically oriented parallel to the weld. 6.2 Weldment hardnesses usually have no effect on ASCC susceptibility. However, in services in which both ASCC and HSC are concerns, weldment hardness controls are applicable. 6.3 PWHT is an effective method of mitigating ASCC. This is because PWHT has two primary benefits: lowering weldment hardness (that helps resist HSC) and reducing residual stresses from welding. By reducing residual stresses, PWHT helps prevent ASCC.

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6.4 PWHT procedures, including temperatures, times, heating and cooling rates, etc., are given in the ASME Boiler and Pressure Vessel Code. The guidelines for PWHT differ somewhat for avoiding ASCC versus HSC. Guidelines for the latter are given in Paragraph 4.3. When PWHT is being performed to avoid ASCC, the following guidelines apply: 6.4.1 ASME Boiler and Pressure Vessel Code, Section VIII, allows PWHT to be performed at lower than the normally specified temperature, as long as it is held for a longer time. However, when PWHT is being performed to avoid ASCC, these lower temperatures may not be used, because they may not be as effective in reducing residual stresses. 6.4.2 Although some codes allow shorter hold times, a minimum of one hour should be used to ensure effective stress relieving.

RP0472-2005 6.4.3 For improving cracking resistance in amine and caustic services, an effective procedure consists of heating weldments to 635 ±14° (1,175 ±25°F) for a hold time of one hour for each 25 mm (1.0 in), or fraction thereof, of metal thickness, with a minimum of one hour holding time. It should be noted that the allowable variation in the chemical composition of steels could be considerable, even within the same grade. In conjunction with welding variables, this can produce high hardness in HAZs that might not be adequately softened by this specified thermal stress relief. Each situation should be evaluated to determine whether this recommended thermal stress relief is adequate.

6.4.6 When heat treatment is used to avoid ASCC, all welds and weld heat-affected areas require PWHT, including all pressure-containing welds, seal welds, internal attachment welds, nozzle-reinforcing pad welds, temporary fabrication attachment welds, arc strikes, etc. External attachment welds often generate residual stresses extending through the entire wall thickness, and if so, they should also receive PWHT. Only if an evaluation shows that the residual stresses do not extend through-wall should PWHT be considered optional. Variables affecting the depth of residual stresses are welding heat input, base material thickness, and attachment weld size.

6.4.4 Carbonate cracking has occurred in equipment and piping that were stress relieved using the standard heat treatment procedures for other ASCC. This is believed to be attributable to a lower threshold stress for carbonate cracking. Field welds (especially in piping) have been found to be particularly vulnerable to carbonate cracking because of the difficulties often associated with field heat treatment (e.g., hold times and temperature control) and the presence of other local high stresses (e.g., bending stresses associated with elbows). Therefore, an enhanced stress-relieving heat treatment should be used to avoid carbonate cracking. The heat treatment temperature should be 649 to 663°C (1,200 to 1,225°F) for a hold time of one hour for each 25 mm (1.0 in.) of thickness, with a minimum of one hour holding time. In addition to the higher heat treatment temperature, the guidelines provided in API RP 945 Paragraph 5.2.3.1 and AWS 36 D10.10 should be incorporated into the heat treatment procedures in order to minimize the residual stresses that remain after the stress-relieving heat treatment.

6.4.7 After PWHT, actions that reintroduce high residual stresses, such as straightening, should be avoided. If these actions have been done, a second PWHT should be performed when deemed necessary by the user.

6.4.5 Experience has shown that heating bands wider than required by codes (roughly >250 mm [10 in.]) are sometimes necessary. This applies primarily to weldments in large-diameter piping (>250 mm [10 in.]).

6.5 Mechanical stress-relief methods are not universally accepted as effective methods to mitigate ASCC in these environments. The “peening” stress-relief process should not be used for applications in ASCC environments because of the limited success of this technique in corrosive service. A concern is that shot peening produces a surface layer with compressive stresses, and this layer may eventually corrode away exposing subsurface material that still has residual tensile stresses. 6.6 Alternative welding methods such as temper bead welding and controlled-deposition welding are not effective in mitigating ASCC. These methods do not sufficiently reduce residual stress, and therefore should not be considered in lieu of thermal stress relief. 6.7 It is outside the scope of this standard to detail all the specific environments causing ASCC of P-No. 1 steels. Various reference books and publications contain information on ASCC environments and preventive 13,37 measures.

________________________________________________________________________ References 1. ASME Boiler and Pressure Vessel Code, Section VIII (latest revision), “Pressure Vessels” (New York, NY: ASME).

5. NACE Standard MR0103 (latest revision), “Materials Resistant to Sulfide Stress Cracking in Corrosive Petroleum Refining Environments” (Houston, TX: NACE).

2. ASME/ANSI B31.3 (latest revision), “Process Piping” (New York, NY: ASME).

6. NACE Standard MR0175/ISO 15156 (latest revision), “Petroleum and natural gas industries—Materials for use in H2S-containing environments in oil and gas production” (Houston, TX: NACE and Geneva, Switzerland: ISO).

3. API Standard 620 (latest revision), “Design and Construction of Large, Welded, Low-Pressure Storage Tanks” (Washington, DC: API). 4. API Standard 650 (latest revision), “Welded Steel Tanks for Oil Storage” (Washington, DC: API).

7. API RP 942 (discontinued), “Controlling Weld Hardness of Carbon Steel Refinery Equipment to Prevent Environmental Cracking” (Washington, DC: API).

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RP0472-2005 8. R.D. Merrick, “Refinery Experiences with Cracking in Wet H2S Environments,” CORROSION/87, paper no. 190 (Houston, TX: NACE, 1987).

23. ASME SFA-5.17 (latest revision), “Specification for Carbon Steel Electrodes and Fluxes for Submerged Arc Welding” (New York, NY: ASME).

9. ASME Boiler and Pressure Vessel Code, Section IX (latest revision), “Welding and Brazing Qualifications” (New York, NY: ASME).

24. AWS A5.17 (latest revision), “Specification for Carbon Steel Electrodes and Fluxes for Submerged Arc Welding” (Miami, FL: AWS).

10. F.R. Coe, et. al., Welding Steels Without Hydrogen Cracking, 2nd ed. (Abington, Cambridge, UK: Abington Publishing, The Welding Institute, UK, 1993).

25. N. Yurioka, “Prediction of Weld Metal Strength,” IIW Document IX-2058-03 (Roissy, France: IIW, 2003).

11. NACE Publication 8X194 (latest revision), “Materials and Fabrication Practices for New Pressure Vessels Used in Wet H2S Refinery Service” (Houston, TX: NACE). 12. NACE Standard RP0403 (latest revision), “Avoiding Caustic Stress Corrosion Cracking of Carbon Steel Refinery Equipment and Piping” (Houston, TX: NACE).

26. E.L. Hildebrand, “Aqueous Phase H2S Cracking of Hard Carbon Steel Weldments—A Case History,” API paper (Washington, DC: API, May 1970). 27. D.J. Kotecki, D.G. Howden, “Weld Cracking in a Wet Sulfide Environment,” API paper (Washington, DC: API, May 1973).

13. API RP 945 (latest revision), “Avoiding Environmental Cracking in Amine Units” (Washington, DC: API).

28. D.J. Kotecki, D.G. Howden, “Final Report on Wet Sulfide Cracking of Weldments,” API paper (Washington, DC: API, May 1973).

14. Work in Progress by Task Group 347, Petroleum Refineries, Environmental Cracking: Review of Carbonate Stress Corrosion Cracking (Houston, TX: NACE).

29. D.J. Kotecki, D.G. Howden, “Submerged Arc Weld Hardness and Cracking in Wet Sulfide Service,” Welding Research Council Bulletin No. 184, June 1973.

15. API RP 941 (latest revision), “Steels for Hydrogen Service at Elevated Temperatures and Pressures in Petroleum Refineries and Petrochemical Plants” (Washington, DC: API).

30. T.G. Gooch, “Hardness and Stress Corrosion Cracking,” The Welding Institute Research Bulletin, August 1982.

16. ASME Boiler and Pressure Vessel Code, Section II (latest revision), “Materials Specifications, Part C, Welding Rods, Electrodes and Filler Metals” (New York, NY: ASME). 17. ASME SFA-5.1 (latest revision), “Specification for Carbon Steel Electrodes for Shielded Metal Arc Welding” (New York, NY: ASME). 18. AWS A5.1 (latest revision), “Specification for Carbon Steel Electrodes for Shielded Metal Arc Welding” (Miami, FL: AWS). 19. ASME SFA-5.18 (latest revision), “Specification for Carbon Steel Electrodes and Rods for Gas Shielded Arc Welding” (New York, NY: ASME). 20. AWS A5.18 (latest revision), “Specification for Carbon Steel Electrodes and Rods for Gas Shielded Arc Welding” (Miami, FL: AWS). 21. ASME SFA-5.20 (latest revision), “Specification for Carbon Steel Electrodes for Flux Cored Arc Welding” (New York, NY: ASME). 22. AWS A5.20 (latest revision), “Specification for Carbon Steel Electrodes for Flux Cored Arc Welding” (Miami, FL: AWS).

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31. T.G. Gooch, N. Bailey, “The Effect of Environment on Threshold Hardness for Hydrogen Induced Stress Corrosion Cracking of C-Mn Steel Welds,” Fifth International Symposium of the Japanese Welding Society, held April 17-19, 1990. 32. R.J. Pargeter, “Factors Affecting the Suspectibility of CMn Steel Welds to Cracking in Sour Environments,” ASTM Symposium on Environmental Assisted Cracking, held November 9-11, 1987 (West Conshohocken, PA: ASTM, 1987). 33. ASTM A 833 (latest revision), “Standard Practice for Indentation Hardness of Metallic Materials by Comparison Hardness Testers” (West Conshohocken, PA: ASTM). 34. ASTM E 384 (latest revision), “Standard Test Method for Microindentation Hardness of Materials” (West Conshohocken, PA: ASTM). 35. ASTM E 18 (latest revision), “Standard Test Methods for Rockwell Hardness and Rockwell Superficial Hardness of Metallic Materials” (West Conshohocken, PA: ASTM). 36. AWS/ANSI D10.10/D10.10M (latest revision), “Recommended Practices for Local Heating of Welds in Piping and Tubing” (Miami, FL: AWS).

RP0472-2005 37. D. McIntyre, C.P. Dillon, Guidelines for Preventing Stress Corrosion Cracking in the CPI, MTI Publication No. (8) 15 (Columbus, Ohio: Materials Technology Institute, March 1985).

________________________________________________________________________ Bibliography Ebert, H.W., and J.F. Winsor. “Carbon Steel Submerged Arc Welds—Tensile Strength vs. Corrosion Resistance.” Welding Research Supplement to the Welding Journal, July 1980.

Neill, W.J. “Prevention of In-Service Cracking of Carbon Steel Welds in Corrosive Environments.” CORROSION/71, paper no. 43. Houston, TX: NACE, 1971.

Gulvin, T.F., D. Scott, D.M. Haddrill, and J. Glen. “The Influence of Stress Relief on the Properties of C and CMn Pressure-Vessel Plate Steels.” Conference on the Effect of Modern Fabrication Techniques on the Properties of Steels, paper no. 621. The West of Scotland Iron and Steel Institute, May 12, 1972.

Omar, A.A., R.D. Kane, and W.K. Boyd. “Factors Affecting the Sulfide Stress Cracking Resistance of Steel Weldments.” CORROSION/81, paper no. 186. Houston, TX: NACE, 1981.

NACE Publication 8X294 (latest revision). “Review of Published Literature on Wet H2S Cracking of Steels Through 1989.” Houston, TX: NACE, 1994.

Welding Research Council Bulletin No. 145. “Interpretive Report on Effect of Hydrogen in Pressure Vessel Steels.” New York, NY: WRC, October, 1969. Stout, R.D. “Hardness as an Index of Weldability and Service Performance of Steel Weldments.” WRC Bulletin No. 189. New York, NY: WRC, November, 1973.

________________________________________________________________________ Appendix A: Suggested Guidelines for Portable Brinell Hardness Testing of Welds 1. Grind the hardness test area flush with the base metal. A smooth, relatively flat surface improves the accuracy of hardness readings, and one method to achieve this is finish grinding with an 80 or finer grit sandpaper disc. Do not take hardness readings on scaled or discolored areas. 2. Insert the hardness test bar into the holder with the spacing button in the extreme forward position. 3. Ensure that the hardness test block is flat on the test surface. 4. Make the impressions by striking the anvil nut squarely with a 1.4- to 2.3-kg (3.0- to 5.0-lb) hammer. Pull the hammer away so it does not rebound or restrike the anvil. 5. Measure the impression on the weld hardness test site by placing the microscope so that the impression is approximately in the center of the scale. Adjust the eyepiece so the scale and the top of the impression are in sharp focus. Measure the diameter of the impression to the nearest half division (0.050 mm [0.002 in.]); it should be between 3.0 to 4.0 mm (0.12 to 0.16 in.) (if not, discard the

hardness test and redo it). Rotate the eyepiece 90 degrees and obtain a second diameter reading. If the two diameter readings vary by more than 0.100 mm (0.004 in.) (i.e., the impression is oblong), discard the hardness test and redo it. If acceptable, average the two diameter readings for the recorded result. 6. Repeat the procedure in Step 5 to measure the impression on the hardness test bar. 7. To do subsequent hardness testing, move the spacing button one notch toward the rear. This ensures that the impressions on the hardness test bar are properly spaced and avoids double impressions. Continue this practice for succeeding impressions until one-half of one side of the bar is covered with impressions. Then remove and reverse the bar, and again move the spacing button to the extreme front position.

___________________________ (8)

Materials Technology Institute (MTI), 1215 Fern Ridge Parkway Suite 206, St. Louis, MO 63141-4405.

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RP0472-2005 8. Determine the Brinell hardness number by using the slide calculator supplied by the manufacturer or by using Equation (3): 2 ⎛ Db ⎞ (3) H w = Hb x ⎜ ⎜ D ⎟⎟ ⎝ w⎠

10. All hardness impressions at one test location should have at least 6.4 mm (0.25 in.) between their nearest edges.

where: Hw Hb Db and Dw

9. Subtract the determined weld hardness from the test bar hardness. The difference should be -10 to +50; if not, discard the hardness reading and do a retest with a new hardness test bar. The new hardness test bar should have a hardness closer to the weld hardness to improve the hardness reading accuracy.

= = =

Hardness of weld; Hardness stamped on the hardness test bar; Diameter of impression in the hardness test bar;

11. Hardness impressions can be made on only two adjacent sides of the hardness test bars.

Diameter of impression in weld.

12. Replace the indenter ball when it is out-of-round.

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