Corrosion Damage (Forms of Corrosion)

Engineering Encyclopedia Saudi Aramco DeskTop Standards

CORROSION DAMAGE (FORMS OF CORROSION)

Note: The source of the technical material in this volume is the Professional Engineering Development Program (PEDP) of Engineering Services. Warning: The material contained in this document was developed for Saudi Aramco and is intended for the exclusive use of Saudi Aramco’s employees. Any material contained in this document which is not already in the public domain may not be copied, reproduced, sold, given, or disclosed to third parties, or otherwise used in whole, or in part, without the written permission of the Vice President, Engineering Services, Saudi Aramco.

Chapter : Corrosion File Reference: COE-101.02

For additional information on this subject, contact PEDD Coordinator on 874-6556

Engineering Encyclopedia

Corrosion Basics Corrosion Damage (Forms of Corrosion)

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CORROSION DAMAGE (The Various Forms of Corrosion) .......................................... 6 Engineering Failures ................................................................................. 6 Corrosion Risks ........................................................................................ 7 GENERAL CORROSION (UNIFORM METAL WASTAGE) ......................................... 10 LOCALIZED CORROSION .......................................................................................... 16 Galvanic Corrosion ............................................................................................ 16 Intergranular Attack ........................................................................................... 23 Sensitization and Weld Decay ........................................................................... 25 Exfoliation .......................................................................................................... 27 Pitting Corrosion ................................................................................................ 29 CRAs/Passive Metals ............................................................................. 30 Pitting in Sour Service............................................................................. 35 Crevice Corrosion, Under Deposit & Under Insulation Corrosion ...................... 37 Fretting .............................................................................................................. 42 VELOCITY RELATED ATTACK ................................................................................... 44 Flow Assisted Corrosion.................................................................................... 46 Erosion- Corrosion............................................................................................. 48 Impingement Attack........................................................................................... 53 Cavitation Damage ............................................................................................ 54 ENVIRONMENTALLY ASSISTED CRACKING ........................................................... 59 Stress Corrosion Cracking (SCC)...................................................................... 61 SCC Mechanisms ................................................................................... 65 Hydrogen Embrittlement (HE)............................................................................ 69 Hydrogen Damage Of Oil Field Equipment In Sour Service .............................. 72 Saudi Aramco DeskTop Standards

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Sulfide Stress Cracking (SSC)........................................................................... 76 Stress Orientated Hydrogen Induced Cracking (SOHIC)................................... 78 Corrosion Fatigue .............................................................................................. 81 HIGH-TEMPERATURE DEGRADATION AND CORROSION ..................................... 85 High Temperature Micro-structural Changes and Embrittlement....................... 86 High Temperature Oxidation.............................................................................. 89 Sulfidic Corrosion .............................................................................................. 90 Hydrogen Attack (Decarburization).................................................................... 95 Carburization and Metal Dusting ....................................................................... 98 Hot (Molten Salt) Corrosion ............................................................................. 101 GLOSSARY ............................................................................................................... 103

LIST OF FIGURES Figure 1 “Bath tub” Curve of Failure Rate / Hazard Function versus Age ..................... 7 Figure 2 General or Uniform Corrosion Mechanisms .................................................. 10 Figure 3 Corrosion Allowance Concept ....................................................................... 11 Figure 4 Predicted CO2 Corrosion Rates [] .................................................................. 12 Figure 5 General Corrosion – Field Observations ....................................................... 13 Figure 6 Representation of Galvanic Corrosion .......................................................... 16 Figure 7 Stainless Steel Fastener in a Galvanized Sheet – Lack of Insulation Washer caused Accelerated Corrosion of Zinc Coating and Steel Substrate ............................................ 17 Figure 8 Dissimilar Metal Couple Mechanism ............................................................. 18 Figure 9 Weldment Corrosion in a Condensate Line (CO2 system) ............................ 18 Figure 10 Area Principle for Galvanic Corrosion ......................................................... 21 Figure 11 Example of Design Detailing Required to Control Galvanic Corrosion........ 22

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Figure 12 Intergranular Corrosion of Pump Impeller ................................................... 24 Figure 13 End Grain Attack (Intergranular Corrosion initiated in Crevice) of Washer fabricated from 420 SS after 3 years Wash Water Duty ............ 24 Figure 14 Representation of a Sensitized Grain Boundary in 304 Stainless Steel ...... 25 Figure 15 Schematic Illustration of Weld Decay .......................................................... 26 Figure 16 Exfoliation of Rolled Aluminum Alloy Sheet................................................. 27 Figure 17 Pitting Corrosion.......................................................................................... 29 Figure 18 Pitting of 410 SS Bubble Caps & Tray (NGL stripper column), Typical of Pit Morphology on Stainless Steels and CRAs Exposed to Cl- & H2S,........ 30 Figure 19 Polarization Curve of 304 SS in a Chloride Containing Solution showing Passivation, Film Breakdown Transients and the Pitting Potential ............. 31 Figure 20 Electrochemical Noise Transients from Pitting Events ................................ 33 Figure 21 Resistance to Pitting & Crevice Corrosion with Alloying Additions .............. 34 Figure 22 Corrosion Pit in C-Steel in a Sour System................................................... 35 Figure 23 Crevice Corrosion under a Gasket between Water Box and End Plate ...... 37 Figure 24 Initial Stage in the Development of Crevice Corrosion between Two Bolted Plates........................................... 39 Figure 25 Later Stages of Crevice Corrosion – Concentration Cell............................. 40 Figure 26. Perforation of Web of Pipe Bridge Support due to Corrosion under Fire Protection Insulation (a form of crevice corrosion)..................... 41 Figure 27 Fretting Between Two Surfaces .................................................................. 43 Figure 28 Effect of Fluid Flow on Rates of General Corrosion .................................... 47 Figure 29 Representation of Erosion-Corrosion .......................................................... 48 Figure 30 Erosion-Corrosion of a Copper Alloy Tube, Seawater Cooling.................... 49 Figure 31 CO2 “Mesa” Corrosion - a form of Erosion-Corrosion.................................. 49 Figure 32 Increased Metal loss due to Erosion Corrosion........................................... 51 Figure 33 Erosion-Corrosion of CRAs in a Choke valve Well Test.............................. 52 Figure 34 Impingement Attack .................................................................................... 53

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Figure 35 Steps in Cavitation Damage........................................................................ 55 Figure 36 Cavitation Damage at “T” in an LPG line, caused by Mixing of Two Streams that Contained Traces of Water, (Better to allow Mixing in a Tank)................................................................ 56 Figure 37 Cavitation Damage of Pump Impeller.......................................................... 57 Figure 38..Factors that Combine to cause Environmental Cracking ............................ 59 Figure 39 Example of a Stress Raiser......................................................................... 60 Figure 40 Stress Corrosion Cracking .......................................................................... 61 Figure 41 Chloride Induced Cracking of Austenitic Stainless Steel ............................. 63 Figure 42 Stress Corrosion Crack in Brass ................................................................. 63 Figure 43 Caustic Cracking of C-Steel and Inter-granular Micrograph of Fracture...... 64 Figure 44 Carbonate/bicarbonate Cracking Under Tape Wrap on a Pipeline.............. 65 Figure 45 SCC in Duplex SS Test Specimen .............................................................. 66 Figure 46 Typical SCC Data for Selection of Materials ............................................... 67 Figure 47 Illustration of Data from Crack Growth Tests............................................... 68 Figure 48 Hydrogen Embrittlement of Cadmium Plated Bolt (10 years Service) ......... 69 Figure 49 Canopy Collapse due to Hydrogen Embrittlement ...................................... 70 Figure 50 Molecular Hydrogen Gas Bubbles Formed in Most Acids but Diffusion of Atomic Hydrogen into Steel in Sour Systems..................... 72 Figure 51 Hydrogen Damage Processes .................................................................... 73 Figure 52 Diffusion of Hydrogen Atoms Through the Wall of a Tank or Pipe That Results in the Formation of a Blister....................................... 74 Figure 53 Hydrogen Blister.......................................................................................... 74 Figure 54 Hydrogen Induced Cracking (HIC) & Stepwise Cracking (SWC)................. 75 Figure 55 Sulfide Stress Cracking ............................................................................... 77 Figure 56 Pipe Rupture of Wet Sour Gas Line After 6 Weeks Service........................ 78 Figure 57 Alternating Tensile and Compressive Stresses in a Rotating Shaft ............ 81

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Figure 58 Curves of Stress Amplitude (S) versus Number of Stress Cycles (N) ......... 82 Figure 59 Appearance of Corrosion Fatigue Failure ................................................... 83 Figure 60 Steam Leak Failure in a Boiler due to Creep Rupture................................. 86 Figure 61 Liquid Metal Attack of Alloy 800 .................................................................. 88 Figure 62 Oxidation of 316 Stainless Fitting................................................................ 90 Figure 63 Effect of Sulfur Content on Corrosion Rates Predicted by Modified McConomy Curves in 290°- 400° C (550°-750°F) Temperature Range...... 91 Figure 64 Modified McConomy Curves Show the Effect of High Temperatures on the Sulfidic Corrosion Rate of Carbon Steel and Various Chromium Steels .................................. 92 Figure 65 Mechanism for High-Temperature Sulfidic Corrosion.................................. 93 Figure 66..Sulfidation of Alloy 600................................................................................ 95 Figure 67 Effect of Hydrogen on Sulfidic Scales ......................................................... 96 Figure 68 “Nelson” Curves for High Temperature Hydrogen Attack ............................ 97 Figure 69 Diffusion of Carbon into Steel or Nickel Alloy and Resulting Cracks ........... 98 Figure 70..Carburization and Subsequent Brittle Failure of Reformer Tube from Ethelyne Plant after 20 days due to poor control of Decoking, 1100°C ...... 99 Figure 71 Metal Dusting Pits ..................................................................................... 100 Figure 72 Hot Salt (Na2S4) Corrosion of 35Ni-19Cr-Cb Austenitic Steel at cyclic Temperatures between 150 - 927 °C (300 - 1700 °F) ................. 102 LIST OF TABLES Table 1 Failure Modes, Corrosion Damage and Loads ................................................. 9 Table 2 Saudi Aramco Corrosion Rate Guidelines ...................................................... 13 Table 3 Corrosion Potentials (Galvanic Series) in Flowing Seawater ......................... 20 Table 4 SCC Environments for Various Metals ........................................................... 62

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CORROSION DAMAGE (THE VARIOUS FORMS OF CORROSION) Most structures and oil/gas equipment are fabricated from C-Mn steels, an economic choice that carries potential risks from internal and external corrosion damage. The level of protection for any particular item/application must consider the material and the corrosive environment plus the desired service life, consequences of failure and financial requirements (life cycle costs and the rate of return on the investment). Some of the costs for corrosion control of C-Mn steel (use of inhibition, maintenance coatings, and replacement of galvanic anodes for CP), including increased inspection and repairs are delayed to the operational phase of the project. The alternative approach and employed for highly corrosive environments, is to use corrosion resistant alloys (CRAs) and materials but this requires increased investment during construction / fabrication. Understanding the causes of corrosion damage enables engineers to locate areas at risk and also identifies means of controlling future problems. There is seldom only one “correct” solution to a corrosion problem since each particular option depends on the risks, future benefits, time constraints and prior history/experience. Typical corrosion failures are presented below but further examples and case studies can be found in “Forms of Corrosion” edited by Aramco employees [1, 2]. Engineering Failures In engineering terms failures occur when equipment, items or components do not perform to either the design specification or to the operational criteria. All facilities have increased rates of failure when newly commissioned, or after a maintenance period, compared to normal operation. Failure rates also increase with age due to deterioration processes including corrosion.

1

“Forms of Corrosion, Recognition and Prevention”, Vol. 1, Edited by C. P. Dillon, Published by NACE International, Houston, TX. 2

“Forms of Corrosion, Recognition and Prevention”, Vol. 2, Edited by D. R. McIntrye, Published by NACE International, Houston, TX.

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Much of the corrosion damage observed in practice is “age related” typical of the “wear out” phase of equipment and is often a combined result of fouling build-up (scales and biofilms), corrosion and fracture (metal wastage, pitting, grooving and cracking). Older equipment therefore requires increased inspection and monitoring to identify potential failures. EARLY LIFE FAILURES

FAILURE RATE OR HAZARD FUNCTION

AGE RELATED FAILURES

RANDOM FAILURES

START UP DATE

OPERATIONAL LIFE

Figure 1 “Bath tub” Curve of Failure Rate / Hazard Function versus Age Failure rate statistics, or probability of failures, are typically expressed in terms of probability density functions or hazard functions. Early life failures follow a hyper-exponential distribution or decay, random failures have a negative exponential or constant rate, whilst age related failures have a normal distribution. The "bath tub” curve, Figure 1, combines these three failure types. Corrosion Risks A fundamental management process is the identification of hazards and use of risk assessments. A hazard has the potential to cause harm or damage. Produced hydrocarbons are flammable and some fluids also contain toxic hydrogen sulfide so that there is always a risk of death and injury from equipment failures in oil and gas production and downstream processing. Saudi Aramco DeskTop Standards

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Industrial risk evaluations as employed in risk based inspection (RBI – SAEP-343 Risk-Based Assessment for In-Plant Static Equipment) and loss prevention, involves evaluation of potential hazards that may affect the business. These include safety risks, integrity of assets, environmental risks, financial risks from various decisions and risks from poor corrosion control. Risk is the combination of: 1. the severity of the effect (the consequences), and 2. the likelihood of it happening (failure mode and probable frequency). Risk (Criticality) = Effect (Consequences) x Likelihood (Mode) Failure criticality –potential failure risks are examined to predict the severity of each failure in terms of safety, decreased performance, total loss of function and environmental hazards. Failure effect - potential failures are assessed to determine probable effects on performance and the consequences of component failures on each other. Failure mode - anticipated operational conditions are used to identify most probable failure modes, their likely frequency, damage mechanisms and locations. In the case of corrosion related failures the failure mode is the result of interaction of corrosion damage on operational and accidental loads. Corrosion is not a cause of failure but provides a major contribution to the mode of failure. Failures are usually the result of poor decisions in materials selection, chemical treating, inadequate inspection/monitoring, operation & maintenance. Corrosion damage is typically found as: •

uniform corrosion - metal loss due to general corrosion, for example, atmospheric corrosion / rusting

•

galvanic corrosion - accelerated corrosion due to the effect of mixed metals or compositional/metallurgical factors as in the corrosion of weldments

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•

localized attack - pitting, crevice corrosion, often the result of a small anode area in a large cathode

•

flow induced corrosion – erosion corrosion, cavitation, impingement attack, the result of high fluid velocities, changes in pressure and second phases such as sand

•

environmentally assisted cracking – cracks that initiate with specific metal – environment combinations (stress corrosion cracking), corrosion fatigue

The relationships between the failure modes, corrosion damage and loads are illustrated in Table 1. Table 1 Failure Modes, Corrosion Damage and Loads Failure mode:

local leakage longitudinal / transverse rupture collapse or buckling

Corrosion damage (corrosion morphology):

uniform corrosion and erosion isolated pitting flow induced localised corrosion (mesacorrosion) & erosion longitudinal & transverse cracking longitudinal & transverse grooving (for example, weld corrosion)

Loads:

pressure (internal and external) forces (tensional / hoop stresses, compressive, bending / torsional) impacts (collisions, dropped objects)

Catastrophic failures / structural collapse / rupture of high pressure vessels and gas lines have obvious safety and environmental implications. These events are rare because codes of practice, safety standards / operational procedures aim to prevent extreme cases of failure. The industry is also making increased use of criticality and risk based methods that aim to identify potential failure modes and areas at increased risk (RBI), see Module 8 for further details.

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GENERAL CORROSION (UNIFORM METAL WASTAGE) General corrosion is attack over the entire exposed surface, or a large area, of a metal. The corrosion mechanism involves microscopic corrosion cells that comprise anodic areas of high metal content (for example, ferrite) and small associated cathodic areas (for example, iron carbide/cementite), Figure 2.

Fe2+

Electrolyte

Fe2+

H+ Fe2+

H+

Fe2+

eeCathode

e-

eAnode

Cathode Electrolyte

Metal

Current Flow

Cathode Area Anode

e

Metal

Figure 2 General or Uniform Corrosion Mechanisms

The metal loss is distributed uniformly across the exposed surface. The rate often decreases with time of exposure as semi-protective corrosion product films grow across the surface, for example, iron carbonate in CO2 systems or iron sulfide in H2S systems. In some acidic solutions, such as hydrochloric acid, a protective film is not formed and the corrosion rate increases with time as the cathodic cementite is exposed.

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Examples of general corrosion include active dissolution in acidic solutions, CO2 and H2S corrosion in produced waters, atmospheric corrosion, corrosion in boilers and natural environments. The assumption that uniform attack will occur is the basis of many designs that employ C-steel fabrications, the designer uses the concept of a “corrosion allowance”. Corrosion Allowance - the additional thickness above that required to retain the operational pressure. The aim is to provide time for metal wastage (general corrosion) during the life of the project. It assumes a gradual and controlled metal loss.

Corrosion Allowance

Extra thickness that is lost during service life

Thickness for strength

Figure 3 Corrosion Allowance Concept

For example, linepipe specification API 5L lists wall thickness in 1.6 mm increments for 16” dia lines. If a thickness of 11.1 mm is required to contain the pressure then the wall thickness would have to be increased to 15.9 mm to provide a minimum corrosion allowance of 4 mm. In principle, general corrosion should be the easiest to deal with in terms of risk to an operation. Handbooks/data sheets are available, including the Aramco materials standards. Corrosion models that use spread sheets for assessment of rates in CO2 and H2S systems, both with and without inhibition, can also be used. An example of the prediction of general corrosion rates in CO2 systems is shown in Figure 4. Such models are used during the design process to assess the likely operational life and determine the required corrosion allowance.

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Figure 4 Predicted CO2 Corrosion Rates [3]

3

“CO2 Corrosion Rate Calculation Model” M-506, Norwegian Technology Standards Institution, http://www.nts.no/norsok

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In practice, the observed surface may look roughened and look like very shallow pitting, Figure 5, due to slight differences in local stress levels in the metal or minor variations in diffusion due to thermal convection/low flow rates.

Figure 5 General Corrosion – Field Observations

Table 2 Saudi Aramco Corrosion Rate Guidelines General Corrosion Rate Rating

Pitting Rate

(µpy)

(mpy)

(µpy)

(mpy)

96

Low

Very severe

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Note the corrosion units, either micron is 10-6 meter) or

µpy – microns per year (a

mpy – mils (thousandths of inch per year, 10-3 / yr).

Saudi Aramco’s goal in oil/gas production systems constructed of C-steel is to keep average corrosion rates below 125µpy (5mpy). Higher pit penetration rates may be tolerated compared to the general corrosion rate. The concept is that pitting has to penetrate the full wall thickness to cause leakage, whereas general corrosion/metal loss over a relative large area could under high internal pressures result in local plastic deformation of the ductile steel and possible fracture/rupture. The failure mode with general corrosion is often rupture of pipelines, vessels or pipework due to thinning of the metal plus the operating pressure but sometimes the area of damage is limited and local leakage occurs. Inspection and monitoring for general corrosion includes: Corrosion Monitoring Methods

Corrosion Inspection Methods

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Corrosion control will depend on the material of construction, the corrosive environment and the particular application. In most production systems C-steels are the materials of first choice because of cost implications. C-steels often require the use of corrosion control to mitigate the effects of corrosion.

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Methods used to Control General Corrosion Corrosion Control

Internal Environments

External Environments

Use corrosion resistant materials Apply coatings Use corrosion inhibitors Apply cathodic protection Remove oxygen from environment Add corrosion allowance during design

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LOCALIZED CORROSION Galvanic Corrosion Galvanic corrosion is the increase in corrosion that occurs when two dissimilar metals are electrically connected and exposed to a conductive corrosive environment. The two metals are called a galvanic couple. In a galvanic couple, the more active metal (lower potential) becomes the anode and corrodes faster. The metal with the higher corrosion potential becomes the cathode (the more noble metal) and is protected. Galvanic corrosion is represented by the illustration in Figure 6.

Anodic metal

Original surface

Cathodic metal

Surface after corrosion

Figure 6 Representation of Galvanic Corrosion Examples of galvanic corrosion include: Mixed metal combinations, iron / copper, galvanized steel / stainless steel, cathodic protection by sacrificial/galvanic anodes, Figure 6. Corrosion involving metallic coatings, cathodic coatings (galvanized or zinc rich paints) protect steel substrates by sacrificial action. Perforation of anodic coatings (nickel plate, tin plate in cans) causes accelerated substrate corrosion, Figure 7.

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Corrosion at repairs, replaced metals have a different metallurgical and surface condition, than the original corroded / filmed metal. For example, with new / repaired fittings welded to vessels / pipework the new / clean metal often becomes an anode and corrodes faster when put into service unless protected by inhibition or CP, Figure 8. Replacement rebar is cathodic in repaired chloride contaminated concrete. Corrosion of weldments, usual practice is to use a cathodic weld metal to prevent a small active anode area in a large cathodic area of parent plate. However, nickel containing weldments (used for strength in oil industry fabrications) that are cathodic can still exhibit high corrosion rates in CO2 environments of low conductivity (dilute brines and condensate lines), Figure 9.

Figure 7 Stainless Steel Fastener in a Galvanized Sheet – Lack of Insulation Washer caused Accelerated Corrosion of Zinc Coating and Steel Substrate

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Current Flow Old Pipe

New Pipe

Old Pipe

Figure 8 Dissimilar Metal Couple Mechanism

Figure 9 Weldment Corrosion in a Condensate Line (CO2 system)

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Mechanism of Galvanic Corrosion Galvanic corrosion is caused by the potential difference between two dissimilar metals or between a weld metal and the parent plate. The metal with the more negative potential is anodic. It corrodes faster when it is part of a galvanic couple. The metal with the more positive potential is cathodic. It corrodes slower when it is part of a galvanic couple. Some combinations are engineered to allow the anode to corrode, for example, thin copper tubes and a thick steel tube plate. The corrosion potential of a particular metal varies in different environments and depends on temperature and electrolyte composition, the hydrogen ion concentration or the presence of oxygen. It cannot be assumed that a particular metal will remain anodic to another metal in all environments. Lists of metals arranged according to their corrosion potentials in a specific electrolyte are called galvanic series. A galvanic series for metals freely corroding in sea water is shown in Table 3. Potential values will vary depending on conditions (type of soil, sea water, soil, process fluid) and the reference electrode used. The magnitude of the coupling current (and the corrosion rate of the anode) depends on: 1.

the relative corrosion potentials of the metals/alloys in a galvanic series for the particular corrosive environment, Table 3

2.

the conductivity of the liquid electrolyte (low conductivity can intensify the local attack, see Figure 9)

3.

the ratio of the areas of the anode and cathode, Figure 10 (small anodes have higher metal loss/penetration rates) cell is driven by large current generated at cathode by corrodant.

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Table 3 Corrosion Potentials (Galvanic Series) in Flowing Seawater (Volts vs Saturated Calomel Reference Electrode, SCE)

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Note CRAs that rely on a passive film for protection can corrode by active corrosion (lower potentials as shown by the black boxes in the series). This can occur when a galvanic cell is set up between a crevice (anode – no oxygen) and the outer metal surface (cathode – dissolved oxygen environment). Area Principle - The area principle controls the rate of corrosion (current density) of each metal and the amount of current flow (galvanic coupling current) between the anode and cathode in a galvanic couple. The anode corrosion rate is the combination of its natural corrosion current plus the coupling current. The anode current density is the current divided by the surface area of the anode. The cathode current density is the current divided by the surface area of the cathode.

Anode Corrosion Rate

For a given amount of current, the metal with the smallest area has the largest current density. For example, the current density of a small anode is very large. The current density of a relatively large cathode is very small. If a small anode is used with a large cathode, the anode will corrode very rapidly. The area principle, shown graphically in Figure 10, states that the anode corrosion rate increases with the ratio of the cathodic to anodic areas.

1

2

3

4

5

Ratio (Cathode Area / Anode Area) Cathode Area

Anode Area

Figure 10 Area Principle for Galvanic Corrosion Saudi Aramco DeskTop Standards

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Failure mode with galvanic corrosion includes local leakage, due to local metal thinning and perforation, and transverse rupture of pipes and pipework, due to grooving, the loss of weld metal in low conductivity CO2 systems and high velocity fluids.

Figure 11 Example of Design Detailing Required to Control Galvanic Corrosion

Corrosion inspection and monitoring for galvanic corrosion includes: Corrosion Monitoring Methods

Corrosion Inspection Methods

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Methods used to Control Galvanic Corrosion Corrosion Control

Internal Environments

External Environments

Use metals close together in galvanic series Do not use small anode areas with large cathodes Insulate dissimilar metals completely Apply and maintain coatings Use corrosion inhibitors Apply cathodic protection Add corrosion allowance to anodic sections or design for easy replacement

Intergranular Attack Intergranular attack (IGA) is preferential corrosion at, or adjacent to, the grain boundaries of some alloys and metals (stainless steels, nickel alloys, chromium-nickel alloys and aluminum alloys). The driving force is the difference in corrosion potential (galvanic effect) between the matrix grains and the grain boundary. This is caused by differences in chemical composition, migration of impurities and formation of second phases during alloy manufacture and fabrication (examples include, Mg5Al8, CuAl2 in aluminum alloys, Fe3C, Cr23C6 in iron based alloys and stainless steel, and Mo6C in Ni-Cr-Mo alloys). Intergranular attack initiates at the surface but then develops as small pits and local cracks that follow the grain boundary. The crack width is sometimes widened by further corrosion and whole grains may fall out.

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Figure 12 Intergranular Corrosion of Pump Impeller Residual stress from fabrication can enhance the attack and local areas of stress assisted intergranular corrosion may be found. With rolled aluminum alloys the aluminum oxide corrosion product is trapped between the grains and exfoliation occurs (a form of swelling or laminar / layered corrosion discussed below). Extruded rods of ferrous and non-ferrous alloys are also prone to end-grain attack, another example of intergranular corrosion.

Figure 13 End Grain Attack (Intergranular Corrosion initiated in Crevice) of Washer fabricated from 420 SS after 3 years Wash Water Duty Saudi Aramco DeskTop Standards

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The metallurgy and chemistry of the alloy is important for the control of IGA; heat treatments and cold work affect both grain size / shape and composition/location of constituents. Solution heat treatments (to just below the melting point) tend to dissolve alloying elements but rapid quenching holds elements in the super saturated solid solution and constituents tend to precipitate out. This precipitation of second phases is increased by heating during the rolling, drawing or welding process.

Sensitization and Weld Decay Sensitization, the formation of chromium carbide precipitates (Cr23C6), occurs when some stainless steels (e.g., Type 300) are heated to 400 to 900 °C (800 to 1600 °F) in the rolling mill / fabrication shop or during site welding. In this temperature range, carbon rapidly diffuses to grain boundaries where it reacts with chromium to form chromium carbide (Cr23C6). This process is dependant on both the temperature and time that the metal is held at the temperature. The high temperature solid state reaction uses up, or depletes, chromium on both sides of the grain boundaries, Figure 14 and Figure 15. Chromium-depleted areas have lower corrosion resistance than the grains (these contain > 12% chromium). Stainless steels with > 0.02% carbon are susceptible to sensitization and IGA. For example, commonly used austenitic stainless steels (e.g., Type 316 and particularly 304) can contain up to 0.08% carbon. It is therefore often preferable too specify lo carbon L-grade stainless steels, 3,000. This dimensionless group is given by Re = µvd/ρ where µ = viscosity, v = velocity, d = pipe diameter and ρ = fluid density. The use of dimensionless groups or numbers is a standard engineering procedure that allows different hydrodynamic conditions (e.g. various pipe diameters) to be compared on the same basis. Turbulent flow means virtually all the fluid is highly mixed by eddy motion. Transfer processes between the bulk fluid and the wall take place across a thin boundary layer of stagnant fluid attached to the wall. With turbulent flow the boundary layer is continuously penetrated by eddies or vortices, that significantly increase the transfer processes (heat, mass and energy transfer).

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Heat transfer at the wall causes heating or cooling/condensation of the fluid that can locally increase corrosion rates. Energy transfer to the wall (determined by the fluid to wall shear stress, τ Pa) is responsible for pressure drops / head losses in pipes. For example, the pressure drop P = 4 L/d over a length L is normally expressed by the dimensionless group ( / v2) and a dimensionless correlation can be used to relate momentum transfer to the velocity:  vdρ  τ = 0.0395 2 ρv  µ 

−0.25

The continuous impact of eddies can also cause fatigue cracking of corrosion product scales and this can lead to erosion-corrosion in some systems (high velocity lines and tubulars). Corrosion and Mass Transfer Processes Eddy penetration across the boundary layer increases the rate of diffusion at the wall of both corrodant (dissolved oxygen or acidic gas species) and reaction products (removal of ferrous ions), that in turn increases the rate of corrosion product film dissolution. The corrosion rate (icorr) at a film free surface is related to the mass transfer coefficient (k, m s-1) by the equation i = nFk(Cb - Cs) where F is the Faraday, n is the number of electrons in the reaction and Cb and Cs are the bulk and surface concentrations respectively. Momentum (τ) and mass transfer (k) processes are similar (they are controlled by eddy transport across the boundary layer) hence both k and τ can be correlated to fluid velocity, v, using dimensionless equations of the form:

k v

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 µ     ρD 

2/3

=

τ = constant Re a ρv 2

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The equation shows that corrosion rates are a complex function of velocity. This approach is the basis of corrosion predictions in CO2 systems (NORSOK model) but these are also modified by the effect of corrosion product films. Films decrease corrosion rates by controlling mass transport through the film, 1/Koverall = 1/kfluid + 1/kfilm (de Waard-Miliams and ECE models). The effect is seen in Figure 28. Film coefficients depend on film thickness and film porosity. The above transfer processes that cause increases in corrosion rates can occur with single phase fluid flow. Corrosion damage is often increased by the presence of a second phase, for example, particles (sand in produced fluids), liquid droplets in gas streams (gas wells and steam return lines) and gas bubbles in liquid streams (oil/gas wells). These can also give rise to erosion-corrosion and impingement attack as outlined below.

Flow Assisted Corrosion Effect of fluid flow General corrosion rates increase as corrosive liquids pass through pipework or over metal surfaces. Corrosion rates are controlled by the concentrations of reactive species at the metal surface and the boundary between the film and the bulk fluid. Increased fluid flow increases the rate of transport of corrodent to the metal surface and also increases the rate of diffusion of metal ions away from the surface of the film. The effect of fluid flow on general corrosion is illustrated by the predicted corrosion rates of steel in a CO2 system, Figure 28.

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Figure 28 Effect of Fluid Flow on Rates of General Corrosion The corrosion rate data in Figure 28, which uses shear stress as the fluid flow parameter, shows that corrosion increases significantly as the fluid flow increases from stagnation through laminar flow up to about 10 Pa. The rate of metal loss then increases more slowly under turbulent flow conditions at shear stresses greater than 20 Pa. The film has an increased influence on the corrosion process at high flow rates. Increased wall thinning is often seen at local areas such as bends and down stream of protrusions / flow disturbances. This is because of the higher turbulence intensity and regions of back flow with developing boundary layers or flow separation with unstable boundary layers. These conditions cause high mass transfer and high corrosion rates. These areas are also subject to erosion-corrosion, where the films are removed locally.

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Measures to control flow assisted corrosion include the use of corrosion inhibitors, selection of resistant materials, decreasing the flow velocity, minimizing turbulence promoters (i.e. smoothing the hydrodynamics), installation of wear plates and baffles in vessels and tanks and design for replacement sections such as elbows.

Erosion- Corrosion Erosion corrosion is the corrosion increase that results from loss of films under high velocity / highly turbulent fluid flow. A simple concept is that the fluid (a liquid, or a wet gas) washes away the protective corrosion film on a metal. In practice, the mechanism is more complex, high turbulence intensity increases the energy transfer from fluid to the wall / fluid to surface shear stress leading to the rupture of protective films, such as iron carbonate, by a fatigue mechanism. Increased turbulence also increases the dissolution rate of the protective film and sometimes even prevents the re-adsorption of the film forming species. Erosion-corrosion often causes a metal surface to have smooth grooves or waves with a directional pattern as shown in Figure 29. It is often observed as a pattern of undercut pits, Figure 30.

Original surface

Surface after corrosion

Flow

Figure 29 Representation of Erosion-Corrosion

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Figure 30 Erosion-Corrosion of a Copper Alloy Tube, Seawater Cooling

Figure 31 CO2 “Mesa” Corrosion - a form of Erosion-Corrosion

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Erosion-corrosion is characterized by a rapid increase in corrosion above a critical flow condition or velocity, Figure 32. The industry standard, API RP 14E, is also used in SAES-1-033 to asses the erosional velocity as given by:

Ve = where:

C dm

Ve = fluid erosional velocity, feet/second

dm = density of the gas & liquid mixture at operating pressure and temperature, lbs/cu-ft C = an empirical constant where for C-steel C = 100 for continuous service, C = 125 for non-continuous service. (For solid-free fluids where corrosion is not anticipated or when corrosion is controlled by inhibition or by employing corrosion resistant alloys, values of "C" up to 150 to 200 may be used for continuous service. When "C" values higher than 100 for continuous service are used, periodic surveys to assess pipe wall thickness should be considered). Figure 32 illustrates the increase in corrosion rate in a brine / CO2 test at a C-value of ~100 equivalent to a shear stress of between 50 to 100 Pa.

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Figure 32 Increased Metal loss due to Erosion Corrosion Erosion-corrosion cells may also be formed due to local turbulence or flow separation down stream of protrusions / bends or within valves or pumps or in the entry section of heat exchanger tubes. The effect is increased by multiphase flow, entrained bubbles and slugging. With C-steel fabrications the use of suitable corrosion inhibitor packages can control most of the observed metal loss rate, for example, in high production multiphase wells or pipelines with slug flow. However, as the flow rate increases even higher then the inhibitor effectiveness will decrease and may even fail.

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Measures to control erosion-corrosion include the selection of resistant materials, decreasing the flow velocity, minimizing turbulence promoters (i.e. smooth hydrodynamics, use of slow bends), installation of wear plates and baffles, selection of appropriate inhibitors and design for replacement sections. CRAs require increasing amounts of Cr, Ni and W to provide protection against erosion corrosion in, for example, high velocity gas systems.

Figure 33 Erosion-Corrosion of CRAs in a Choke valve Well Test

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Impingement Attack The presence of second phase in a fluid, for example, bubbles and sand particle or liquid droplets in gas / steam lines, can impact on the metal surface. This can cause damage to the metal substrate and loss of protective films. Hard particles, scale / sand, may cause sufficient abrasion to produce sharp profiles or grooves in the substrate.

Solids in solution

Figure 34 Impingement Attack It is sometimes difficult to distinguish between erosion-corrosion and impingement attack. Erosion corrosion usually has a smooth surface profile whilst impingement attack often results in roughened surface (the surface of tubulars and lines that have suffered sand impingement usually have very sharp protrusions).

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Measures to control impingement attack include the selection of resistant materials, filtering out unwanted solids, installing water traps in steam lines, installation of wear plates and baffles in tanks and vessels, and design for replacement sections.

Cavitation Damage Cavitation in fluids results from the formation of fluid vapor bubbles followed by the bubble collapse. The vapor bubbles form in a low pressure zone and subsequently collapse (implode) in a higher pressure region. This causes a local hammering action and mechanical damage of surfaces. Repeated implosions of vapor bubbles on a surface can damage the protective film and locally deform metals. Mechanism At a given temperature, a fluid can exist as liquid and vapor at a pressure called its vapor pressure. Cavitation occurs when the absolute pressure at a point in the liquid decreases to or below the vapor pressure of the fluid. The process is seen when a fluid (water) is in a cylinder fitted with a piston (Figure 35).

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1 Prote

Nucle

4

2

3

5

6

Corrosion occurs

Figure 35 Steps in Cavitation Damage The sequence of events that causes cavitation is: (1) The pressure on the water is reduced when the piston is pulled away from the water. If the pressure is reduced to or below the vapor pressure of the water, then voids or bubbles will form at nucleation sites. (2) When the piston is pushed against the water, the pressure increases and the bubbles collapse. (3) The collapse of a bubble produces very strong shock waves. Cavitation damage occurs when shock waves create holes (4) in the surface film and metal surface. (5) A new vapor bubble forms at the same place. (6) The bubble collapses and destroys the film. (7) The exposed area corrodes and the film reforms. Local pressure drops in pumps and at restrictions / expansions can cause cavitation (the formation of vapor bubbles from the flowing liquid). The local and intense concentration of collapsing vapor bubbles then damages films and metallic substrates.

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These effects must be considered in the selection of pumps (need a net positive suction head) and the design and operation of plant and lines Figure 36. A poorly designed / maintained pumping system such as a control valve or a partially blocked filter upstream of the pump can cause damage as shown in Figure 37.

Figure 36 Cavitation Damage at “T” in an LPG line, caused by Mixing of Two Streams that Contained Traces of Water, (Better to allow Mixing in a Tank)

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Figure 37 Cavitation Damage of Pump Impeller Control measures for cavitation damage include:

•

careful material selection: (1) use of hard metals, alloys containing high levels of nickel, chrome, cobalt and tungsten (work hardenable surfaces are more resistant) or (2) for some pump impellers use a soft rubber coating / plastic that adsorbs the cavitation energy

•

operation at pressures below the vapor pressure of the liquid (good design is the key factor preventing cavitation but clogging of upstream filters can cause operational problems).

•

good design to avoid areas of large hydrodynamic pressure differentials, includes smooth surface finishes

Pumps should be selected with appropriate suction heads, or be of a super cavitating pump design where the cavitation zone is formed beyond the pump impeller (as with outboard motors and hydrofoils). The use of resilient coatings which absorb cavitation energy (rubber lined pumps). The temporary injection of air or gas bubbles upstream of the pump can absorb cavitation forces in the fluid, this lowers the pump efficiency but protects the pump until an improved pump or design is employed.

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Failure mode with flow assisted corrosion is leakage or rupture depending on the location and extent of the corrosion damage. Valves can experience thinning of internal components and linings whilst with pumps there will be excessive vibration due to loss of metal on the impeller. Corrosion inspection and monitoring for flow assisted corrosion includes: CorrosionInspection

s Vi

Yes

l ua

CorrosionMonitoring is No

e

e i e ta l p to is at m t li p ca ra r ni z s i n a i c e y o e r a m C S h P a r M l e t ic t p e lR en ra ch ol ne Po en on ns on ca g i e o i g h s g r o t r r i o o n P t a t a ll w up di e dr tra ec br ec te ne Do El Ra Dy In Co Li El Vi Ul Hy

c pe s In

tio

No

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Yes

No

Yes

Methods Used to Control Flow related Corrosion Damage (erosion-corrosion, impingement & cavitation) Corrosion Control

C-steels

CRAs

Design within erosional velocity limitations Improve flow design, use slow bends, minimize local high turbulence intensity areas Use specially selected corrosion inhibitors Increase corrosion allowance on elbows, etc Apply coatings Apply cathodic protection Select materials with better protective films Remove / filter out solids, reduce water droplets in steam Design to minimize hydraulic pressure difference, use pumps with appropriate suction head

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ENVIRONMENTALLY ASSISTED CRACKING

Environmentally assisted cracking, sometimes called environmental fracture, are general terms that encompasses various phenomena such as stress corrosion cracking (SCC), sulfide stress cracking (SSC), hydrogen cracking or hydrogen embrittlement, and corrosion fatigue. The material cracking process is the combined action of a corrosive environment, temperature and mechanical stresses. Many fatigue induced failures are probably corrosion fatigue cracks due ingress of water or corrosive liquids, often the result of poor detail design or poor maintenance practice.

SUSCEPTIBLE MATERIAL

CORROSIVE ENVIRONMENT

SCC

STRESS RESIDUAL & APPLIED

Figure 38..Factors that Combine to cause Environmental Cracking

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The stresses may be static (residual stresses from welding during fabrication or repair), applied (the working load) or fluctuating (the normal operating condition with rotating equipment and piping systems carrying pumped fluids). Surface defects, sharp corners and corrosion pits can act as stress raisers, Figure 39. Stress raisers concentrate tensile forces at local areas. Some environments are not only able to initiate local attack that form pits but can then produce local corrosive conditions in the pits that accelerate the corrosion damage by a cracking process.

Figure 39 Example of a Stress Raiser

A major concern with environmentally assisted cracking is premature failure of components because of rapid propagation of cracks. It is therefore important when selecting materials for service in corrosive environments that appropriate Aramco standards are used. In some applications it is vital that a corrosion expert is consulted and a literature check is carried out to eliminate materials susceptible to stress cracking.

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Stress Corrosion Cracking (SCC) Sress Corrosion Cracking is caused by the combined action of a mechanical load / tensile stress plus a specific corrosive environment and temperature on a susceptible alloy. Stress corrosion cracking (SCC) may be considered as a brittle type of failure in what is a normally ductile material.

C o r r o s io n p ro d u c t film M 2+

M 2+

T e n s ile

T e n s ile

F o rc e s

F o rc e s

M e ta l

A d v a n c in g c ra c k

Figure 40 Stress Corrosion Cracking

Residual stress alone may promote this form of attack, for example from welding during fabrication, hence it can occur without applying an external load. SCC is a severe form of localized corrosion that gives rise to transgranular cracks (hydrogen embrittlement or active metal path dissolution), intergranular cracks (differences in composition due to segregation), or both, see for example Figure 41 to Figure 43.

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Most alloys will undergo stress corrosion cracking in specific corrosive environments, Table 4 SCC Environments for Various Metals. Some combinations are of particular concern in oil/gas production, for example, hydrogen cracking and sulfide stress cracking. Some environments are formed during shut down, for example, polythionic acid produced from reaction of sulfide deposits with atmospheric oxygen in hydrocrackers and catalytic reformers. In practice SCC can appear to be unpredictable in that minor changes of composition or heat treatment can affect the susceptibility. Advice from a corrosion specialist should be obtained for specification of materials to control SCC.

Table 4 SCC Environments for Various Metals Alloy

Environment

Carbon steel

Hot nitrate, hydroxide, carbonate solutions

High-strength steels

Aqueous solutions that contain H2S

Austenitic stainless steels

Hot chloride solutions, acid chloride solutions (e.g., MgCl2, BaCl2), contaminated steam

High-nickel alloys

High purity steam

Copper alloys

Ammoniacal solutions, ammonia vapor, amines

Aluminum alloys

Aqueous Cl-, Br-, and I- solutions

Titanium alloys

Aqueous Cl-, Br-, and I- solutions, organic liquids, N2O4

Magnesium alloys

Aqueous Cl- solutions

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Common problems include trans-granular / inter-granular SCC of austenitic stainless steels in chloride containing environments (seawater and oil field brines) at above 60°C, Figure 41.

Figure 41 Chloride Induced Cracking of Austenitic Stainless Steel Copper alloys in contact with fluids that contain ammonia or amines are often at risk from SCC. Early examples were see in the mid 1800’s by the British Army in India where brass cartridge cases in contact with ammonia vapors cracked in humid monsoon conditions (season cracking of brass).

Figure 42 Stress Corrosion Crack in Brass Saudi Aramco DeskTop Standards

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Caustic cracking of carbon steels occurs in the presence of sodium hydroxide at elevated temperature, >46 °C (115 °F) depending on the caustic concentration but at > 5% NaOH is highly likely at > 82 °C (180 °F). The key factor is usually the local metal temperature.

Figure 43 Caustic Cracking of C-Steel and Inter-granular Micrograph of Fracture

Cracking can occur in C-steel distillation columns where caustic is used for pH control, off-line were equipment corrodes during steam cleaning or where steam tracing lines are left heated, in boiler feedwater equipment , including piping bolts where water leaks occur past gaskets. Post-fabrication stress relieving (Post Weld Heat Treatment, PWHT) is a major control method. Many early catastrophic failures of caustic cracking were in the 1800’s with riveted steam raising boilers. Heated crevices tended to concentrate sodium ions from the water and cause a build up of hydroxyl ions. Remedial action was the introduction of appropriate water treatments.

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A major cause of failure of older Aramco pipelines (>20 y) is external SCC referred to as carbonate / bicarbonate cracking, Figure 44. This is due to the slow pH change that occurs next to steel exposed to soils due to coating damage or tape wrap disbondment. The pH change is the result of oxygen reduction and occurs both with and without CP. Many old lines are now being recoated to mitigate the risk of failures.

Figure 44 Carbonate/bicarbonate Cracking Under Tape Wrap on a Pipeline

SCC Mechanisms The three basic mechanisms include: (1)

Active path corrosion where the protective film is fractured by the stress allowing active metal dissolution at the crack tip

(2)

Hydrogen embrittlement where the hydrogen produced by a corrosion reaction diffuses into the metal and embrittles the zone in front of the crack tip

(3)

Film induced cleavage where the film undergoes brittle failure and the propagating crack penetrates the metal.

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The morphology - transgranular cracks or intergranular cracking, is a characteristic of the specific metal-environment combination. Segregation at grain boundaries means different local corrosion behavior and possibly inter-granular active path dissolution or hydrogen embrittlement. Trans-granular cracks look like cleavage along crystallographic planes, this suggests a film induced cleavage or hydrogen embrittlement process. Research is continuing to provide understanding of SCC mechanisms. Laboratory testing can provide guidance on the use of materials and information on cracking phenomena. A typical test specimen used in testing is shown in Figure 45, the specimen is pre-loaded to a known applied stress value and immersed in the test solution.

Figure 45 SCC in Duplex SS Test Specimen

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Figure 46 Typical SCC Data for Selection of Materials

Mechanical and corrosion processes are illustrated from predictions of crack propagation rates determined from plots of stress intensity factor, K, versus log (crack velocity), Figure 47. Crack growth does not occur below a threshold stress intensity factor, KIscc. Increasing the load causes the crack velocity to increase until it is limited by the corrosion reaction rates. As K approaches Kc, (the critical stress intensity factor for fracture in an inert environment) mechanical fracture processes increase the crack velocity and crack velocity increases again.

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Figure 47 Illustration of Data from Crack Growth Tests

Dissolution processes can limit the rate of metal dissolution in a crack, so aluminum (a reactive metal) has a maximum crack growth rate of ~10-6 m/s. For hydrogen embrittlement (hydrogen induced SCC) the limiting factor is hydrogen diffusion at the crack tip and crack velocities can be up to 1 m/s.

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Hydrogen Embrittlement (HE) Hydrogen embrittlement occurs when hydrogen atoms diffuse into a metal and cause a loss of ductility and tensile strength. This conversion of a ductile steel into a brittle type material can result in sudden failure, for example, cracking / fracture, Figure 48 and Figure 49. Metallurgical factors can influence susceptibility. High strength body centered cubic materials are more susceptible with face centered cubic materials (austenitic steels) being less susceptible. Quenched and tempered C-steel (hard material) is susceptible to hydrogen embrittlement. Cracking takes place above the critical tensile stress. Even atmospheric corrosion can generate sufficient atomic hydrogen to embrittle high tensile fasteners and cause failures, Figure 48.

Figure 48 Hydrogen Embrittlement of Cadmium Plated Bolt (10 years Service)

A major catastrophic failure was the collapse of a large canopy over the entrance of the Berlin Congress Hall, Figure 49, the result of water penetration onto high strength steel tendons.

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Many post-/ pre-tensioned concrete structures such as pretensioned and post-tensioned bridge beams, bund walls and concrete pipes (where high strength steel wire is spirally wound and covered with mortar) have failed catastrophically when the steel has become exposed to rain water due to loss of concrete / mortar cover.

Figure 49 Canopy Collapse due to Hydrogen Embrittlement

High strength wires, used in civil engineering constructions for ground anchors and for pre-tensioned concrete beams, are usually produced by a patenting process (a drawn pearlitic structure) that is more resistant to damage by hydrogen. Ground anchors used in wet saline conditions are usually designed with double protection against water ingress. High strength steel fabrications are particularly at risk from hydrogen embrittlement. Examples include nodes on offshore platforms from hydrogen generated from impressed current cathodic protection systems that are providing over protection.

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Post-weld Cracking due to HE Cracking can also occur post fabrication due to the introduction of hydrogen produced during welding of moist surfaces. Steels with higher carbon content are more susceptible to cracking caused by hydrogen entry during welding. Hydrogen generated in arc welding from the welding flux dissolves more readily in the liquid weld metal as atomic hydrogen than in solid metal but after the weld metal solidifies, the atomic hydrogen will diffuse from the weld metal into the heat affected zone where higher stresses may lead to failure from hydrogen embrittlement.

Measures to control stress corrosion cracking include: (1)

Careful material selection, usually the most cost effective method. For example, duplex and ferritic stainless steels are more resistant to chloride induced stress corrosion cracking than austenitic stainless steels.

(2)

Reduction of the stress, can be effective if caused by residual stresses, for example post weld heat treatments

(3)

Modification of the environment, not always possible

(4)

Lower the potential to below the SCC range cathodic protection and even inhibition can control some processes.

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Hydrogen Damage Of Oil Field Equipment In Sour Service Hydrogen damage is not a specific form of corrosion. It is a general description of the corrosion related damage found in sour systems - hydrogen embrittlement, hydrogen-induced cracking (HIC), blistering of steel, sulfide stress cracking (SSC), stress orientated hydrogen induced cracking (SOHIC). In most acids hydrogen generated by the corrosion reaction is produced as gas bubbles in the process fluid but in sour systems the sulfide film assists the atomic hydrogen to diffuse into the steel, Figure 50. Only the hydrogen atom (H) is small enough to diffuse through metal. Cyanides and arsenic compounds in the electrolyte also inhibit the formation of molecular hydrogen and help hydrogen to enter into steel. Once a hydrogen atom enters the metal several damage processes may occur in a susceptible steel, for example, blistering, Figure 53, and HIC, Figure 54.

Acid Solution

H+

H2 H+

Fe 2+ H Anode

H Cathode

Fe2+

Metal

H+

H+

e

e

H H H

Figure 50 Molecular Hydrogen Gas Bubbles Formed in Most Acids but Diffusion of Atomic Hydrogen into Steel in Sour Systems

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In a susceptible steel the atomic hydrogen can form molecular hydrogen gas at a void or other defect. The build up of pressure from molecules of hydrogen gas trapped at the defect in the steel can cause a blister as found in older low-strength steels, Figure 52. Hydrogen blisters seldom lead to rupture of metal walls and they rarely cause brittle failure.

Hydrogen Induced Cracking

HIC Stepwise Cracking Hydrogen Blistering

Sulfide Stress Cracking

SSC A form of stress corrosion cracking often associated with high hardness and high stress, for example welds

Stress Orientated Hydrogen Induced Cracking

SOHIC Combination of HIC and SSC

Figure 51 Hydrogen Damage Processes

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Air

Metal

Void H2 H H2 H2

Blister

H2 H2

H2 H H2 H2 H

H2

H2 H H2

H

H2 H2 H

H Hydrogen atom

Figure 52 Diffusion of Hydrogen Atoms Through the Wall of a Tank or Pipe That Results in the Formation of a Blister

Figure 53 Hydrogen Blister

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The hydrogen gas molecules trapped at the defect can also give rise to hydrogen induced cracking (HIC) and stepwise cracking (SWC) in susceptible steel, Figure 54. The process is again due to the high internal hydrogen pressure and increased local stresses that cause adjacent small blisters to link up.

Figure 54 Hydrogen Induced Cracking (HIC) & Stepwise Cracking (SWC)

HIC tends to link up long adjacent cracks by a ductile tearing to form stepwise cracking. With older steels, that have a banded type of microstructure, HIC (along the centre line) and blisters (close to the surface) invariably form along the rolling direction with cracks aligned parallel to the surface. Modern manufacturing specifications can now produce C-Mn steels that meet demands for increased strength, low temperature toughness, weldability and increased resistance to hydrogen sulfide. Use of “clean” steels, control of inclusions and alloying additions, modification of casting processes and multistage rolling to optimize grain refinement (thermo-mechanical treatments plus accelerated cooling) produces a microstructure that has high strength and small grain size that is less susceptible to HIC in sour service.

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Sulfide Stress Cracking (SSC) Sulfide stress cracking is the term used by the oil and gas industry for the stress corrosion cracking that occurs in sour environments. SSC is a special case of hydrogen stress cracking a form of hydrogen embrittlement. Hydrogen enters the steel when the metal corrodes in sour oil field waters. Hydrogen entry may be increased by cathodic protection in sour environments. Temperature affects sulfide stress cracking, hydrogen embrittlement and hydrogen-induced cracking of steels in H2S service. SSC and hydrogen embrittlement are most likely to occur at temperatures up to 65°C (150°F). Sulfide stress cracking (SSC) affects high-strength carbon steels with a hardness above 22 Rockwell C. Other alloys have different hardness limits in sour environments. Sulfide stress cracks may begin at surface notches or pits on the metal surface (Figure 55). Cracks can also begin within the metal at discontinuities or defects such as inclusions, carbides, or grain boundaries. Both tensile stresses and hydrogen entry into the steel are required for SSC to occur.

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T e n s ile

T e n s ile

F o rc e s

F o rc e s H y d ro g e n a to m s

H H H

H

H H H H

H

H

A d v a n c in g c ra c k

H

M e ta l

Figure 55 Sulfide Stress Cracking

SSC does not occur below a certain threshold stress intensity for a particular metal structure. Increasing the hydrogen pressure within the metal increases the chances for SSC. SSC is also most likely to occur at temperatures of about 20°C (70°F). Failures due to SSC do not always occur rapidly.

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Stress Orientated Hydrogen Induced Cracking (SOHIC) SOHIC is where a stacked array of small blisters are joined by hydrogen induced cracks aligned in the through-thickness direction of the steel. The main feature is that the cracks propagate along the heat affected zone of the seam welds in spirally wound pipe. The process can be considered as a combination of hydrogen induced cracking and stepwise cracking, and in some cases, the hydrogen embrittlement form of stress corrosion cracking. It usually occurs in the base metal adjacent to the HAZ where residual stresses (from welding) and from the applied stresses (operating pressure) are highest. High residual stress combined with stress raisers caused by the geometry of the weld crown can accelerate the initiation processes.

Figure 56 Pipe Rupture of Wet Sour Gas Line After 6 Weeks Service

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The line shown in Figure 56 had a further 20 failures during hydrotesting following repair. The line was de-rated to limit the hoop stress to 0.25% C is due to martensite formation that occurs when steel is heated to above the upper critical temperature followed by rapid cooling, a problem during welding and severe overheating as in a fire. Sigma phase embrittlement is due to formation of the ironchromium brittle phase (FeCr) from ferrite in high chromium alloys and austenitic stainless steels (>17% Cr) during heating to 430 540 - 815 °C (1000 - 1500 °F) for short periods or 370 °C (800 °F) for extended periods. This increases the tensile strength and hardness but also decreases the ductility to the point of brittleness. Sigma phase embrittlement causes cracking on cooling from operational temperatures in cast supports and tubes in process heaters, pyrolysis furnaces, catalytic regenerators or after welding of Type 316 and 347 stainless weldments. Limiting the ferrite content of stainless to 15% Cr and 5% Al and ~ 5% Cr to become Al2O3 formers. Al2O3 scales are susceptible to cracking and spalling in service at high temperatures unless reactive elements such as yttrium or cerium are added to the alloys.

Figure 62 Oxidation of 316 Stainless Fitting The furnace outlet manifold fitting, Figure 62, was thermally insulated which caused a temperature increase to 850 °C (1500 °F). Mo in 316 can oxidize at 775– 800 °C (1420 – 1470 °F).

Sulfidic Corrosion High-temperature corrosion caused by oxidation from sulfur compounds is called sulfidic corrosion. Most high-temperature corrosion in refineries is caused by sulfur containing gases produced by sulfur compounds in crude oil. Sulfur compounds are usually reported as total weight percent sulfur. There are many types of sulfur compounds in crude oils. Most of these compounds are converted to H2S under refinery conditions.

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The formation of liquid sulfides can destroy protective scales locally and may penetrate the alloy in an intergranular manner. Even if the sulfide does not form a melt on the surface of the metal in the diffusion of metal ions in the scale can be rapid giving high rates of scale growth and metal loss. The corrosion rate of steels increases with the weight percent of sulfur. Figure 63 shows the effect of higher sulfur content on the corrosion rate of the steels for temperatures between 290° and 400°C. According to Figure 63, increasing the sulfur content of a crude oil from 0.5 weight percent to 1.0 weight percent will increase the corrosion rate about 20 percent.

10

Sulfur Content, wt %

5 2 1 0.5 0.2 0.1

0.05 0.02 0.01 0.4

0.8 1.2 1.6 Corrosion rate multiplier

2.0

Figure 63 Effect of Sulfur Content on Corrosion Rates Predicted by Modified McConomy Curves in 290°- 400° C (550°-750°F) Temperature Range

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Figure 64 shows the effect of temperature on the sulfidic corrosion rate of carbon steel and several chromium steels. All of the steels in Figure 64 were exposed to crude oil with a sulfur content of 0.6 weight percent. Notice that the corrosion rate is lower for steels with higher amounts of chromium.

Temperature, °C 100 50

250

300

350

400

Sulfur content : 0.6 wt %

10.

10 5

0.1

2 1 0.5

0.01

0.2 0.1

Corrosion rate, mm/yr

Corrosion rate, mpy

20

10-3

0.05 0.02 0.01 450 500 550 600 650 700 750 800

Temperature, °F Figure 64 Modified McConomy Curves Show the Effect of High Temperatures on the Sulfidic Corrosion Rate of Carbon Steel and Various Chromium Steels

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Diffusion processes can be used to describe high-temperature corrosion mechanisms. Figure 65 is a diagram that shows sulfidic corrosion of a steel surface. Hydrogen sulfide is first absorbed at favorable sites on the metal. Then the hydrogen sulfide reacts with iron to form iron sulfide according to the following chemical reaction. 2+ Fe + Ferrous Ion

H2S ⇒ Hydrogen Sulfide

H2⇑ Hydrogen Gas

FeS + Iron Sulfide

A scale of iron sulfide corrosion deposits forms on the metal surface. The scale then grows until it covers the metal surface. The iron sulfide scale also becomes thicker. Ferrous ions diffuse away from the metal surface through the scale. Sulfide ions diffuse from the hydrocarbon stream through the scale toward the metal. The iron and sulfide ions react to form iron sulfide. Electrons also diffuse through the sulfide scale to the hydrocarbon interface where they reduce hydrogen ions to hydrogen atoms.

S-2 Metal ions and electrons

Fe2+

H2S

H2S

e

e Fe2+

S-2

H2S

S-2 Sulfide ions

e

e Fe2+

H2S

S-2

H2S

Figure 65 Mechanism for High-Temperature Sulfidic Corrosion

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The composition of the iron sulfide scale depends upon the amount of hydrogen sulfide in the hydrocarbon stream and other process conditions. The scale next to a steel surface will contain a higher concentration of iron than sulfur. The corrosion product scale near the hydrocarbon stream will usually contain a higher concentration of sulfur than iron. The corrosion resistance of an alloy is determined by the rate of diffusion of ions and electrons through the iron sulfide scale. In many environments protection against sulfidic corrosion is provided by the oxides formed from the alloy additions that form chromium oxide (Cr2O3), alumina (Al2O3) or silica (SiO2). If the sulfur activity (partial pressure, concentration) of the environment is high then sulfide phases will form. Sulfidic attack will occur at breaks in the protective oxide scale. Sulfur in the alloy then reacts with the alloying elements to form sulfides, which redistributes the protective elements and interferes with the reformation of the oxides. The sulfur tends to penetrate down grain boundaries. At higher temperatures, the melting point and vapor pressure of the scale become important factors. A scale with a low melting point or a high vapor pressure will not be retained and will not provide protection against corrosion. Note that many high temperature alloys are designed to form protective oxides not protective sulfides. Sulfides of alloying elements that form low melting eutectics include: Melting point (°C)

Alloying Element

Phase

Ni

Ni3S2

645

Fe

FeS

986

Co

Co2S4

880

Cr

CrS

~1350

Al

AlS

~1070

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Figure 66..Sulfidation of Alloy 600

Time to failure of the 18 inch diameter, ¾ inch thick tube was 1 month for the nickel based alloy operating at 1040 °C (1900 °F). The scanning electron microscope micrograph showed excessive chromium and nickel rich sulfides. The proposal was to replace the NiCrFe alloy 600 with FeCrCoNi alloy 556.

Hydrogen Attack (Decarburization) High temperature hydrogen attack occurs in c-steels and low alloy steels exposed to high partial pressures of hydrogen above 200 °C (390 °F). This is not a low temperature embrittlement process but is the result of a hydrogen reaction with carbon from the carbide matrix of the alloy. H2 → 2H (dissociation of hydrogen) Fe3C → 3Fe + C (dissociation in solid solution) 4H + C → CH4 (decarburization reaction)

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The presence of hydrogen modifies the sulfide reaction at iron sulfide scales, Figure 67.

Figure 67 Effect of Hydrogen on Sulfidic Scales The corrosion damage is in two forms: (1) internal decarburization, with attack along grain boundaries in the alloy followed by fissuring due to a build up of methane reaction product (2) surface decarburization, again from reaction of the carbides with atomic hydrogen but with diffusion and escape of the methane from the surface. Internal fissuring tends to occur with c-steels, C½Mo and Cr-Mo steels at higher partial pressures of hydrogen, whilst surface decarburization is more common in Cr-Mn steels at higher temperatures and lower partial pressures. Improved resistance is achieved by increasing the chromium and molybdenum alloying additions, Mo has four times the resistance than Cr to high temperature hydrogen attack.

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Industry practice is to rely on corrosion resistance predictions presented as a series of curves (Nelson curves) for c-steel and low alloy steels at different hydrogen partial pressures and temperatures, Figure 68. (API RP 941 “Steels for Hydrogen Service at Elevated Temperatures and Pressures in Petroleum Refineries and Petrochemical Plant.)

Figure 68 “Nelson” Curves for High Temperature Hydrogen Attack

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Carburization and Metal Dusting Carburization and metal dusting are forms of high temperature attack that occur in reducing environments containing high concentrations of carbon, for example, methane (CH4), carbon monoxide (CO), carbon dioxide (CO2) and light hydrocarbons. Carburization is the process of high temperature diffusion of carbon into an alloy and its reaction with alloying elements to form carbides. It occurs at very low oxygen partial pressures when the carbon content of the environment at the metal surface is high. Examples include carbon monoxide in reformer tubes or under coke deposits on furnace tubes. Diffusion of carbon through nonporous scales of chromium oxide (Cr2O3) or alumina (Al2O3) is slow (chromium and aluminum are alloying additions). However, in practice the oxides are layered in areas where the scale has cracked and re-formed (self repair).

Figure 69 Diffusion of Carbon into Steel or Nickel Alloy and Resulting Cracks

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Gaseous species concentrate in the outer more porous regions and this assists the diffusion gradient that allows carbon to enter the alloy and react to form carbides. This leads to changes in mechanical properties and also to loss of oxidation resistance. Austenitic steels tend to be less resistant than ferritic (high solubility of carbon in austenite), whilst >20% Cr can adsorb considerable amounts of carbon to form (CrFe)23C6 and ferrite.

Figure 70..Carburization and Subsequent Brittle Failure of Reformer Tube from Ethelyne Plant after 20 days due to poor control of Decoking, 1100°C

Metal dusting is a rapid, often catastrophic, localized carburization of steels in the temperature range 430 – 815 °C (800 - 1500 °F) exposed to environments rich in mixtures of hydrogen and carbon, for example, methane (CH4), carbon monoxide (CO), carbon dioxide (CO2) and light hydrocarbons. Failures are found in dehydration units, fired heaters, ethylene cracking units and gas turbines. The environment is reducing which means that retention of protective oxides is difficult to achieve with many alloys.

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The corrosion attack produces small pits filled with carbon or a dust mixture of graphite, carbides, oxides and metal powder. The mechanism involves local saturation of the surface layers with carbon, leading to carbide (Fe3C) precipitation and growth followed by decomposition to iron and graphite. Figure 71 shows the pitting type attack observed with metal dusting. This metal dusting example is from an ethylene pyrolysis furnace tube in an environment containing 31% H2, 10% CO, 19% CO2, 5.5 % CH4. The recommendation was to replace the nickel-chromium alloy, Alloy 800, with a lower nickel alloy

Figure 71 Metal Dusting Pits

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Hot (Molten Salt) Corrosion Hot corrosion is a general tem used to describe the attack by molten salts, for example, liquid pollutants produced in combustion gases that contain small amounts of impurities, particularly sodium, sulfur and vanadium. The impurity pollutant can be in the fuel or the air. For example, turbine engines that burn sulfur containing oil or gas and also operate in a salt containing atmospheres such as marine or subkha regions can form a sodium sulfide melt on the blades. Fuel ash corrosion can be a serious problem with fired boilers or hydrocarbon furnaces. Oils used as fuels can deposit on super heaters and convection tubes to form melts that cause a severe form of corrosion damage due to the liquid type electrolylitic flux. Alkali-metal sulfates are solid below 450 °C ( °F) and the rate of attack is slow. Above their dew point, 980 °C (390 °F) for sodium sulfate, the attack is again low. Between these temperatures the rate of hot corrosion increases with catastrophic attack at around the melting point of the salt. The breakdown of the scale involves either mechanical fracture or an electrochemical corrosion in the molten salt electrolyte (either an acidic or basic salt fluxing mechanism).

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Figure 72 Hot Salt (Na2S4) Corrosion of 35Ni-19Cr-Cb Austenitic Steel at cyclic Temperatures between 150 - 927 °C (300 - 1700 °F) Vanadic slags such as sodium vanadate (Na2O⋅6V2O5) are formed with some oils by the reaction of vanadium pentoxide vapor (V2O5) with sodium sulfate (Na2SO4). The vanadium slag dissolves the protective oxide scale from the metal (as a flux). Corrosion increases with temperature and vanadium content of the oil. For example, with between 20 – 150 ppm vanadium the tube temperature should be restricted to between 650 °C (1200 °F) and 850 °C (1550 °F) depending on sulfur content and the sodium / vanadium ratio. Above 150 ppm vanadium the temperature should be limited to 650 °C (1200 °F). Alloys with high nickel content and particularly with a high chromium content are more resistant. Firing a boiler with a low excess air (