CORROSION AND ITS PROTECTION IN OIL & GAS PRODUCTION
CORROSION IN OIL FILED : INTERNAL AND EXTERNAL THREATS
INTERNAL THREATS
CORROSION CAUSES WELL TREATMENT INFLUENCED WATER CARRY OVER UNDERDOSING DEMULSIFIER INJECTION PUMP with LOW CAPACITY UNDERDOSING CORROSION INHIBITOR WATER SETTLE OUT
Typical E&P process conditions •
•
•
Temperature – Typical E&P process temperatures range from -100ºC to >200ºC – Corrosion rates increase with temperature Pressure – Pressure: up to 10,000psi – Increase partial pressure of dissolved gases Flowrate & flow regime – High-flow: erosion and corrosion-erosion. – Low-flow or stagnant conditions promote bacteria 5
Internal corrosion Hydrocarbon phase • Not normally corrosive at temperatures experienced in production systems • Corrosivity depends on extent and distribution of the aqueous and hydrocarbon phases.
Aqueous phase • Responsible for corrosion • Corrosion exacerbated by acid gases & organic acids • CO2, H2S and O2 are the most aggressive species • Chlorides increase corrosion • Generally, – ‘no water, no corrosion’ 6
Internal (process-side) damage mechanisms •
H 2S
•
CO2
• • •
Solids & velocity effects Chlorides – pitting, stress corrosion cracking Oxygen (crevice / under deposit / differential aeration) Galvanic corrosion Preferential weld corrosion (PWC) Microbially induced corrosion (MIC) Liquid metal embrittlement (LME) Chemicals
• • • • •
7
TYPICAL REACTIONS
Dissolved gas - effect on corrosion
Corrosion Rate of Carbon Steel
Corroded seawater injection 25 20 15
O2 CO2 H2S
10 5 0 O2 H02S 0 CO 2
0
0 100
1
1200 2 3003
2
3
50
100
150
4 4 400 200
5 5 500 250
6
7
8
300
350
400
6 600 7700 8 800
Dissolved Gas Concentration in Water Phase, ppm
There is no species more corrosive on a concentration basis than oxygen! 9
H2S CORROSION
10
H2S corrosion – metal loss – Formation of a thin protective FeS surface film often means general corrosion rates are low on steels – Main risk is localised pitting corrosion where film is damaged – Pitting will be galvanically driven
11
Wet H2S corrosion • H2S is soluble in water – Produces a weak acid and lowers the pH H2S H+ + SH– At low concentrations, H2S helps form protective FeS film – Main risk is localised pitting corrosion which can be rapid • H2S also poisons combination of atomic hydrogen into molecular hydrogen Atomic H+ + e- H hydrogen H + H H2
X
dangerous to steels!!
12
Cracking in sour service H+
H2 H
H
Applied Stress Higher Strength Steels YS > 500 MPa
Fe2+ S2FeS Film Metal Matrix
No Applied Stress Low Strength Steels YS < 550 MPa
H2
H H HH H
H2 13
Sulphide stress cracking (SSC) Key parameters: • pH and pH2S – Domain diagrams for carbon steel • Material hardness – High strength steels and areas of high hardness susceptible. • Temperature – Maximum susceptibility at low temperatures for carbon steels (15-25°C), higher for CRAs (570°C). • Stress – Cracking promoted by high stress levels e.g. residual welding
HAZ
WELD HAZ
Hardness readings
14
Protection against SSC • •
Avoid wetness Minimise hardness – Guidance on limits in ISO 15156 • Optimise microstructure and minimise residual stresses
Upgrade to CRAs • Martensitic and duplex stainless steels have limited resistance • H2S limits for duplex and super-duplex steels are complex – Function of temperature, pH, chlorides, pH2S • Nickel-base alloys such as 625 and 825 have high resistance • Testing: NACE TM0177
15
ISO 15156 SSC zones for carbon steel
0.0034bar a 0.05psia
Service Domain
Max hardness (parent metal, HAZ, weld metal)
0
No requirements
1
300HV
2
280HV
3
250HV root 275HV cap
16
SSC limits for selected CRAs Alloy
pH2S limit (bara)
13% Cr martensitic
0.008
22% Cr duplex
0.10
25% Cr super-duplex
0.25
Alloy 825
No limit
Alloy 625
No limit
17
HIC / SWC / blistering • Laminar cracking in plane of inclusions or blistering (HIC). • Transverse cracking between laminar cracks on different planes (SWC).
Step-wise cracking
Hydroge n blisters
Blistering of CS plate
18
Avoiding HIC / SWC • • • • •
Avoid plate steels (rolled) – otherwise qualify by HIC test Control impurities e.g. S, P Uniform microstructure Use internal coatings – isolate steel from process fluid Testing: NACE TM0284
Banded
Uniform
19
ISO 15156 (NACE MR0175) • ISO 15156 combination of – NACE MR0175 and NACE testing requirements TM0177 & TM0284 – European Federation of Corrosion Guidelines No.16 & 17 • Part 1: General principles for selecting crack-resistant materials • Part 2: Cracking resistant carbon & low-alloy steels & cast iron • Part 3: Cracking resistant corrosion resistant alloys (CRAs) • Covers all cracking mechanisms • Goes beyond application of the 0.05 psia pH2S threshold for sour service • It is the equipment user’s responsibility to select suitable materials • HIC/SWC of flat rolled carbon steel products for environments containing even trace amounts of H2S to be evaluated • BP ETP: GP 06-20 Materials for Sour Service
20
Designing for H2S service •
• •
Materials requirements – Reference ISO 15156 and GP 06-20 – pH2S and pH – Temperature – Chlorides – Hardness limits Welding QA/QC (HIC) – Maintain hardness limits HIC testing for plate products
21
CO2 CORROSION
22
CO2 - containing environments •
CO2 always present in produced fluids – Corrosive to carbon steel when water present – Most CRAs have good resistance to CO2 corrosion.
Mechanism CO2 + H2O H2CO3 H2CO3 + e- HCO3- + H 2H H2 Fe Fe2+ + 2eFe + H2O + CO2 FeCO3 + H2
23
Types of CO2 damage
General & pitting corrosion
Mesa corrosion
Flow-assisted-corrosion (CO2)
Localised weld corrosion
24
CO2 corrosion in a production flowline
• 6” CS production flowline (Magnus, 1983) • 25mm thick, 90bar, 30°C, 2%CO2 • Heavily pitted pipe wall and welds (not necessarily uniform corrosion) • Didn’t fail – removed due to crevice corrosion of hub sealing faces 25
Factors in CO2 corrosion •
For an ideal gas mixture, the partial pressure is the pressure exerted by one component if it alone occupied the volume. Total pressure is the sum of the partial pressures of each gas component in the mixture
Main factors pCO2, temperature, velocity, pH -– CO2 prediction model
Temperature, (ºC)
pCO2 (bar) Carbon steel corrosion rate (mm/yr)
130
0.6
7
75
0.6
6
149
30
>50
26
Effect of sand on CO2 corrosion • •
Produced sand can affect inhibitor efficiency – Inhibitor adsorption loss Sand (and other solid) deposits give increased risk of localised corrosion; – Prevent access of corrosion inhibitor to the metal – Provide locations for bacteria proliferation – Galvanic effects (area under deposit at more negative potential than area immediately adjacent to deposit) – Formation of concentration cells/gradients
27
Mitigation of CO2 corrosion •
•
Internal CO2 corrosion of carbon steel needs to be managed – Usually mitigate by chemical inhibitors – Simple geometries only (mainly pipelines) Assume inhibitor availability (90-95%) – Inhibited corrosion rate of 0.1mm/year – Remaining time at full predicted corrosion rate – Apply a corrosion allowance for the design life – If calculated corrosion allowance >8mm use CRAs
28
CO2 corrosion inhibition • • • •
Filming type Retention time Continuous injection Adsorption onto clean surfaces
Clean steel
29
CO2 + H2S corrosion – metal loss
•
CO2/H2S > 500
CO2 dominates
500 > CO2/H2S > 20
mixed CO2/H2S
20 > CO2/H2S > 0.05
H2S dominates
H2S corrosion (CO2/H2S < 20) – Initial corrosion rate high – Protective FeS film quickly slows down corrosion to low level – The corrosion rate is much less than the Cassandra prediction
30
)r ab(2
H2S + CO2 materials selection guide Duplex SS 13% Cr SS
Nickel-based alloys
er pl ai tr aP
Carbon/low alloy steels
Partial pressure H2S (bar)
EROSION & EROSIONCORROSION
32
Flow regimes • Various multi-phase flow regimes possible; − erosion characteristics − distribution of phases − carrier phase for solids • Flow regimes with particles in the gas show higher erosion rates than those with particles in the liquid phase.
Liq uid Bubble (bubbly) flow
Ga s Liq uid Stratified
G as
Plug flow
Ga s Liq uid Wave (wavy) flow
flow
Gas Liq Annular uid
Ga Liq s uid Slug flow
flow
Churn flow
Mist (spray) flow 33
Erosion & erosioncorrosion •
•
Erosion – Caused by high velocity impact & cutting action of liquid and/or solid particles – Erosion failures can be rapid Erosion-corrosion – Occurs in environments that are both erosive and corrosive. – Erosion and corrosion can be independent or synergistic.
Erosion of tungsten carbide choke trim
34
Typical vulnerable areas for erosion •
Areas wherever flow is restricted or disturbed – T-pieces, bends, chokes, valves, weld beads
• • Trinidad
Areas exposed to excessive flow rates Sand washing – Washing infrequently allowing sand to accumulate – High pressure drop during washing of separators
•
Sea water systems – High flow areas in water injection / cooling systems
Algeria (duplex) 35
Erosion in piping •
Sand accumulation – Build up of sand in a test separator
•
Pressure drop – Large pressure drop across sand drain pipework during washing
•
Rapid failure – Occurred within 2 minutes of opening the drain
Erosion at bend 36
Erosion in a vessel • Sand allowed to accumulate in separator – Wash nozzles embedded in sand • PCV not working properly – High pressure / flowrate – Nozzle not erosion-resistant – Erosion of wash nozzle – Spray changed to a jet causing erosion of shell • Local changes to operating procedures not communicated – Frequency of sand washing – Risk not captured or assessed in RBI
Water spray
Water jet
37
Erosion of sandwash nozzle
Progressive
nozzle
damage 38
Erosion-corrosion • Occurs in environments that can be erosive and corrosive. • Erosion and corrosion can either be: – independent of each other; • wastage equals sum of individual wastage rates – synergistic; • wastage rate > sum of individual rates • localised protective film breakdown at bends, elbows areas of turbulence
39
Impingement
• Water speed or local turbulence damages or removes protective film • 90-10 Cu-Ni susceptible to internal erosion-corrosion (impingement) at velocities >3.5ms-1 • Water-swept pits (horse-shoe shaped) 40
Cavitation • •
• •
Occurs at high fluid velocities Formation & collapse of vapour bubbles in liquid flow on metal surface. No solids required Typical locations – Pump impellers (rapid change in pressure which damages films) – Stirrers, hydraulic propellers
•
Use erosion resistant materials – Stellite, tungsten carbide
41
CORROSION IN SEAWATER
42
Raw seawater •
• • •
•
Composition of raw seawater varies around the world – Temperature, pH, salinity, dissolved oxygen, marine life Very corrosive to unprotected carbon steel, other materials susceptible to pitting and crevice corrosion Select seawater resistant materials – Super-duplex grades, 6Mo, CuNi, titanium Consider galvanic corrosion – Most seawater resistant grades of stainless steel and Ni-Cr-Mo alloys are compatible with each other in seawater. Seawater can cause SCC of 300-series, duplex grades and 6Mo 43
Pitting resistance of stainless steels • • • •
•
Pitting Resistance Equivalent Number (PREw) Formula for comparing relative pitting resistance Applicable to stainless steels & Ni-Cr-Fe alloys Typically PREw ≥40 required for exposure to raw sea water <30ºC Alternatively, use titanium or GRE
Alloy
PREw
13Cr
13
316ss
23
Alloy 825
28
22Cr duplex
33
25Cr superduplex
40
Alloy 625
46
PREw = %Cr + 3.3x (%Mo + 0.5%W) + 16%N
44
Internal & external pitting
Internal pitting
• • •
Section of 3” 316L pipe fitting Failed due to internal corrosion (pinhole leak) Poor hydrotest practice - seawater left within spool 45
Failure of a seawater pump cooling coil……
Indication on coil
External surface of coil
Internal surface of coil
316 SS coil, raw seawater service, hypochlorite added Shellside: lube oil up to 50°C Tubeside: seawater inlet ~6°C, return ~18°C Failed due to localised internal pitting – 316 SS has low PREw • Material upgrade required • • • •
46
Oxygen - concentration cells
Crevice corrosion under baffle
• Crevice corrosion – O2 is consumed in the crevice and becomes the anode – pH decreases in the crevice increasing attack • Differential aeration cells – Air/water interfaces with attack below the water line e.g. splash zone – Pipelines in soils containing different amounts of oxygen • Under deposit corrosion – Deposits of scale, sand or sludge – Produces differential concentration – SRBs thrive - H2S pitting
47
Galvanic corrosion •
• • • •
Three conditions are required for galvanic corrosion; – A conducting electrolyte (typically seawater). – Two different metals in contact with the electrolyte. – An electrical connection between the two metals. Relative positions within the electrochemical series (for given electrolyte) provides driving potential and affects rate. Corrosion of base metal (anode) stimulated by contact with noble metal (cathode). Relative area of anode and cathode can significantly affect corrosion rate. Higher conductivity increases corrosion e.g. presence of salts
48
Galvanic corrosion – firewater piping • • • •
Firewater – CuNi / super duplex stainless steel connections. 4”CuNi pipe with a 550mm isolation spool (i.e. 5x OD) Leaks experienced on CuNi spools at welds Same problems with CuNi / 6Mo
49
Galvanic corrosion - seal rings • •
ETAP platform Techlok joints in a firewater piping system – Piping: super-duplex – Seal rings: 17-4PH
50
Dealloying of brass • Brass tubesheet in seawater service – Brass is Cu-Zn alloy – Cu is more noble than Zn – Zn dissolves preferentially leaving Cu behind • Result – Loss of strength – Difficult to seal • Remedy – Add arsenic to the brass
51
Mitigation of galvanic corrosion •
• • •
Avoid dissimilar materials in seawater system designs – MoC for later changes Avoid small anode/large cathode Avoid graphite gaskets & seals Avoid connecting carbon steel to titanium alloys – Galvanic corrosion or hydrogen charging of titanium may occur
• Electrical isolation between different alloy classes • Install distance spools, separation of at least 20x pipe diameters – Solid non-conducting spool e.g. GRP – Line the noble metal internally with an electrically nonconducting material e.g. rubber • Apply a non-conducting internal coating on the more noble material. Extend coating for 20 pipe diameters. 52
Example : CuNi-Super duplex
Distance spool: solid, non-conducting material e.g. GRP
Distance spool: noble metal internally lined with an electrically non-conducting material such as rubber
Apply a non-conducting internal coating on the more noble 53 material.
Cathodic protection (CP) – what is it? • By connecting an external anode to the component to be protected and passing a dc current, it becomes cathodic and does not corrode. – External anode may be a galvanic (sacrificial) anode, the current is the result of the potential difference between the two metals – External anode may be an impressed current anode, current is supplied from an external dc power source. • CP is mostly applied to coated, immersed and buried structures – The coating is the primary protection, acting as a barrier between the metal and the environment – CP protects steel at coating defects • Coating + CP is most practical and economic protection system. – Primary principle in GP 06-31
54
Cathodic protection – how does it work? • CP works by making the component to be protected the cathode in an electrolytic cell • When two metals are connected in an electrolyte, electrons flow from the anode to the cathode due difference in the electrical potential
ANODIC
Magnesium Zinc Aluminium Iron (steel) Copper Stainless steels Titanium Graphite CATHODIC
Corrosion of steel by copper plating
Cathodic protection of steel by zinc 55 plating
Galvanic (sacrificial) CP •
•
•
Aluminium anodes: require alloy additions to become active e.g. Zn + In, high efficiency (>90%). – Typically used in seawater applications. Zinc anodes: ambient applications only. Alloyed with Al or Cd to improve efficiency. – Typically used on coated pipelines in seawater Magnesium anodes: large driving potential, alloyed with e.g. Al or Zn to reduce rapid activation, limited efficiency Sacrificial anodes, (50-60%) new and wasted – Used in soils and other high-resistance environments (risk of over(therefore working!) protection/rapid consumption in seawater). 56
Applications of internal CP •
Anodes in shell & tube seawater cooler water boxes
•
Oil storage tanks (in water bottom) Water tanks
•
•Stainless steel piping systems in warm/hot chlorinated seawater. −To avoid high anode consumption rates, resistor controlled CP (RCP) systems should be considered. −E.g. RCP + 25Cr super duplex piping instead of titanium or other higher-alloy CRA. −Used on Greater Plutonio 57
Chloride stress corrosion cracking (SCC) •
•
•
•
Susceptibility varies considerably (no absolutes); – Material grade, strength, residual stress, chlorides, oxygen and temperature 300-series austenitic stainless steels susceptible to at temps >50°C Highly-alloyed austenitic and duplex SS have improved resistance Nickel-base alloys with Ni ≥ 42% are highly resistant, e.g. 825 58
Chloride SCC (22Cr duplex vessel drain)
• 22Cr duplex drain ex-production separator − heat-traced to 60°C (vessel temp up to 105°C) • Internal chloride SCC (cracking in parent metal, HAZ and weld metal) • Contributory factors: − Susceptible material − Local stress concentration (weld toe and lack of support) − Environment (elevated temperature, chlorides).
59
Water injection systems (deaerated)
Oxygen: • Trace amounts corrosive to carbon steel. As a guide: – <20ppb O2 maintains general corrosion rates <0.25mm/yr – Stricter limits often applied e.g. <10ppb if 13Cr completions Microbial-induced Corrosion, MIC • SRB require anaerobic conditions – deaerated water – conditions within and under biofilms • SRB use sulphate in water in their metabolisms to generate H2S
Fluid Velocity: • Areas of high fluid velocity or turbulence and O2 – O2 from poor deaeration or air ingress – susceptible areas include pump discharge piping, bends tees and reducers.
60
Mitigation & monitoring • Deaeration and supplementary O2 scavenging – Monitor O2 concentrations on-line (orbisphere) or colorimetric analysis – Maintain oxygen scavenger residual to mop-up oxygen spikes. • Chlorination u/s of deaerator, biocide applied into or d/s of deaerator • Effective biociding based on; – Type, frequency, dosage, duration • Bacterial monitoring (sidestreams, scrapings or bioprobes) • Corrosion monitoring
Leaking deaerator
Seawater injection tubing
61
Preferential weld corrosion (PWC) • •
The selective corrosion of weld zones (WM/HAZ) Relevant factors include; – Electrochemical properties of the materials and any corrosion cell forming around the weld joint – Water phase liquid film thickness and conductivity – Temperature and tendency to form protective scale – Corrosion inhibitor effectiveness, (film formation, composition) – Weld joint metallurgy – Flow pattern and flow induced shear stress • PWC rate of attack can be high, up to 12mm/yr observed 62
Preferential weld corrosion (1%Ni) Water Injection: Wet hydrocarbon service: • 1% Ni-containing welds beneficial for avoiding PWC in WI systems. • Weld cathodic to parent metal, protected by large area of parent metal.
• Lower conductivity, no benefit of selecting ‘cathodic’ weld metal • Reliant on intrinsic corrosion resistance of the weld metal • Require corrosion inhibitor for protection (test against WM and PM) • Attack of weld metal promoted by under-dosing of inhibitor (WM needs more inhibitor than PM)
Welds exposed to hydrocarbon service
63
Lomond drains - PWC • • • • • •
TEG contactor scrubber drain pipework (hydrocarbon) Carbon steel parent metal ~2%Ni deposited in weld metal Groove along 6 o’clock position Accelerated corrosion at the weld Large number of isolations, extensive inspection and repair 64
MIC &
DEADLEG CORROSION
65
Microbially induced corrosion (MIC) • Anaerobic environments often support development of biofilms. • Sulphate reducing bacteria (SRB) thrive in anaerobic conditions • SRB biofilms generate H2S • FeS corrosion product cathodic to bare steel, increasing corrosion rate. • MIC of carbon steel usually localized pitting under biofilm. • Corrosion rates of 5-10 mm/yr seen • CRAs also susceptible
66
Bacterial growth factors • pH MIC growth in pH 5-9.5 range • Temperature SRB can grow in temps of 5-100°C. Optimum temp <45ºC. • Sulphates – Necessary for SRB activity. – Growth restricted if <10 ppm
• Carbon source SRB growth restricted if organic carbon (volatile fatty acids) not available (<20ppm) • Nitrogen Important but at levels which are difficult to detect • Flow – Highest corrosion rates in stagnant conditions. – Biofilms unstable at high flows.
67
Deadlegs – types & locations •
• • •
A deadleg is a section of pipework or vessel which contains hydrocarbon fluids and/or water under – stagnant conditions (permanent or intermittent) – or where there is no measurable flow. Permanent or physical deadlegs (long term stagnation by design) Operational deadlegs (stagnant for operational reasons) Unprotected mothballed items (plus those temporarily out of service)
68
Examples of deadlegs
69
Deadlegs – assessment factors • • • • • • • • • • • •
Consequence of failure Location of pipework Nutrients replenished by regularly opening /closing valves? Is draining of pipework possible? Is removal of deadleg possible? Presence of SRBs, deposits, biocide? Material of construction Wall thickness Fluid type (aqueous phase, sulphates, nutrients, oxygen ingress) Temperature Stagnant – permanent/intermittent Prior history of corrosion
70
Example of deadleg corrosion
Pin Hole leaks Releasing water
• Crude oil recycle cooler bypass • Scale-inhibited seawater left in line after leak test (of u/s valve) • Severe corrosion rate at and around pinhole. • Fortunately, a leak of water not crude. • Two week shutdown
71
Root causes • Failure to identify the bypass line as an operational deadleg
North
• No deadleg register • Failure to recognise introduction of new corrosion hazard • No mitigation measures. Photo 1 250 mm
80 mm
Area of internal corrosion 4.2 mm tapering out to average wall thickness of 10.0 mm
30 mm 110 mm
Area of internal corrosion reading from 3.5 mm tapering out to average of 10.7mm
VIEW LOOKING WEST
Corroded area approx 80mm x72 110mm.
Mitigation & inspection • Flush system of deposits and treat with biocide, nitrate • Out of service items – Biocide treat or mothball procedure • Use treated water – Hydrotest & washing • Profile radiography or UT scanning – low points, bottom of vertical sections etc. • Lowest parts of vessel bridle together with any associated level gauges. 73
OTHER CORROSION MECHANISMS
74
Corrosion due to chemicals • • •
Chemicals can be corrosive Carbon steel OK for non-corrosive chemical piping, e.g. methanol Corrosive chemicals (e.g. concentrated solutions of inhibitors and biocides) require CRAs – vendor will specify – 316 SS is typical
•
Notable exceptions: – Hypochlorite: very corrosive, titanium or GRP piping required – Avoid titanium alloys in dry methanol service due SCC
SCC of a titanium seal exposed to pure methanol instead of 5% water content
75
Corrosion due to chemicals • Carbon steel open drain pipework. • Seepage of scale inhibitor (passing valve) • Scale inhibitor pH <2. • Chemical entered drains, not flushed
76
Injection point issues • Inadequate mixing – corrosion • Intermittent use – switch off when not flowing • Areas affected – Impingement / turbulent areas – Bends and low points • Use quill/other mixer – Upgrade material – Thicker schedule • Valve arrangement – Make self-draining – Enable quill removal
Injected Fluid
Main Flow
Impingement
77
High temperature corrosion • •
•
Environments less common in E&P – Flare tips, fired heaters, boilers Oxidation – Oxidation significant >530°C – Oxidation rate varies with temp, gas composition and alloy Cr content • Firetubes: usually CS, but CrMo alloys needed for high temps • Flare tips: 310 SS, alloy 800H Other high temperature mechanisms – sulphidation (H2S and SO2) – carburizing, metal dusting, hot salt – thermal fatigue and creep
78
Amine stress corrosion cracking • • •
•
Material: carbon/low-alloy steels Environment: aqueous amine systems Cracking due to residual stresses at/next to non-PWHT’d weldments – Cracking develops parallel to the weld Mitigation: – PWHT all CS welds including repair and internal/external attachment welds. – Use solid/clad stainless steel • 304 SS or 316 SS
Intergranular cracking
Amine piping welds require PWHT to avoid SCC
79
Corrosion in glycol system • •
• •
Glycol usually regarded as benign Corrosion in glycol regeneration systems usually due to; – Acid gases absorbed by rich glycol or – Organic acids from oxidation of glycol and thermal decomposition products Condensation of low pH water giving carbonic acid attack. Risk recognised in design – On-skid: CRA piping & clad vessels – However, off-skid piping mix of regular CS and LTCS 80
Corrosion fatigue • Combined action of cyclic tensile stress and a corrosive environment • Fatigue is caused by cyclic stressing below the yield stress – Cracks start at stress raisers – Can occur due to vibration e.g. smallbore nozzles & with heavy valve attachments • Presence of corrosive environment exacerbates the problem – Can lead to pitting, which acts as stress concentrators
81
Example of corrosion fatigue • 2” A106 GrB carbon steel piping • Wet gas service, 1.2%CO2 and 160ppm H2S • Operating @ 120°C and 70bar • Elbow exposed to vibration (used in a gas compression train) • Crack located at 12 o'clock position • Crack initiated internally
82
EXTERNAL CORROSION – SURFACE FACILITIES
83
External corrosion • • • • • •
External corrosion of unprotected steel surfaces External corrosion of coated surfaces Corrosion under insulation (CUI) Corrosion under fireproofing (CUF) Pitting & crevice Corrosion Environmental cracking
84
Where does it occur? • • • • • •
Bare steel surfaces At locations of coating breakdown Under deposits such as dirt, adhesive tape or nameplates Mating faces between pipe/pipe support saddles & clamps Isolated equipment not maintained or adequately mothballed Water sources include: – sea spray and green water (FPSO or semi-sub) – rain – deluge water – leaking process water – condensation – downwind of cooling towers.
85
What does it look like?
• Damage can be extensive or localised. • Corrosion can be general attack, pitting or cracking. • Seen as flaking, cracking, and blistering of coating with corrosion of the substrate.
86
Appearance • Carbon/low alloy steels usually covered in compact scale/thick scab • Stainless steels have light stains on the surface possibly with stained water droplets and / or salts. • Corroding copper alloys covered in blue/green corrosion products.
87
Piping, supports & clamps
88
Not just carbon steel • • • • •
25Cr super-duplex (PREN ≥40) Seawater service 12 months exposure in tropical climate External corrosion along welds Poor quality fabrication
89
Corrosion of bolts and fasteners •
•
• • • •
Bolted joints – Onshore and offshore: exposed to frequent wetting Low alloy bolts – General or localised corrosion – Galvanic corrosion in stainless steel flanges CRA bolts susceptible to pitting and/or SCC Crevice corrosion under bolt heads and nuts Hydrogen embrittlement possible Fatigue
90
Corrosion of bolts and fasteners
General corrosion
Crevice corrosion
Galvanic corrosion
Stress corrosion cracking
91
Flanged connections • Corrosion – General surface corrosion – Galvanic corrosion • e.g. 316 SS / carbon steel • Use of graphite gaskets • Potential problems – Failure of flanged connection due to corroded fasteners – Joint leak • Corrective actions – Change gasket/fastener materials – Replace graphite gaskets with non-asbestos or rubber material 92
Corroded fasteners (seawater service)
Location of graphite gaskets
93
Structures / valves • Valves – Valve handles – Chain-wheels – Valve body • Structures – Stairways and walkways – Gratings, ladders, handrails – Cable trays and unistruts • Threaded plugs – Valve bodies, xmas trees, piping – Dissimilar metals
94
Coating damage and breakdown • Deterioration of coating with time – All paints let water through - continuously wet areas will fail • Poor original surface preparation / paint application • Mechanical damage – Small area of damage can lead to major corrosion
95
External cathodic protection •
Types of structures with external CP – Buried pipelines / structures / piping / tanks – Floors of above-ground storage tanks – Submerged jetty structures
•
Factors affecting corrosion – Extent of wetness – Oxygen – depends on depth – Resistivity of soil & presence of salts – Equipment temperature
96
Impressed current CP • Adjustable dc source – Negative terminal connected to the steel structure – Positive terminal connected to the anodes • Typically used on larger structures where galvanic anodes cannot economically deliver enough current.
97
Corrosion under insulation (CUI) and Corrosion under fireproofing (CUF) •
•
CUI – Water seeps into insulation and becomes trapped, results in wetting and corrosion of the metal – Carbon steel corrodes in the presence of water due to the availability of oxygen. CUF – Same mechanism except water gets behind the fireproofing.
98
Insulation • Typical insulation types; – Process – Personnel protection (PP) – Winterisation – Acoustic • Challenge the need – Remove unnecessary insulation – Replace PP with cages
Mitred joint
‘Lobster-back’ joint
Pre-formed bends
99
CUI incident • • • • • • •
4” gas compression recycle line Operating pressure, 35bar – 3 bar pressure surge Temperature: 50ºC 6.02mm nominal WT Rockwool insulation Extensive corrosion – rupture Unusual, burst rather than leaked
100
CUI gas leak • 2” fuel gas piping outside edge of platform - exposed • CS, heat-traced, Rockwool • Operating @ 5bar, 45°C, 5.4mm NWT • Failed during plant start-up • External corrosion scale, CUI
• • •
Focus on internal corrosion Previous survey found defect in an adjacent line. Failed line in survey but not failed area. – Features selected from onshore not site survey
101
piping CUI • 4” CS hydrocarbon line • 55°C, inlet to PSV (153 bar) • Thermally-sprayed aluminium (TSA) • CUI found, radiographed – ok to refurbish. • Found during needle-gunning (paint removal) • Max pit depth 10mm • Insulation permanently removed 102
CUI on pressure vessel • CS offshore vessel • Operating at 85°C and 11 bar • PFP coating (passive fire protection) • Extensive corrosion scabbing on both sides of vessel. • Scaling runs in two horizontal distinct lines along each side. • Scaling directly above lower seam of insulation – location of water retention.
400x300x30mm
400x100x25mm
103
External pitting & crevice corrosion • Stainless steels in marine environments (chlorides, O2) – 316L stainless steel commonly used for instrument tubing – Particularly susceptible at supports and fittings. • Primary mitigation is materials selection (higher PREw) – Tungum, 6Mo, super-duplex • Alternative mitigation methods (coating, cleaning), not easy or practical.
104
Instrument tubing (316 SS and super-duplex) 316 SS tubing
super-duplex tubing
316 SS (pitting/crevice corrosion) pitting)
super-duplex (no
105
Crevice corrosion under clamps/supports • Pitting and crevice corrosion of 316ss piping – Clamps – Plastic retaining blocks
106
External chloride stress corrosion cracking • •
Mechanism same as internal chloride SCC however: Numerous variables influence susceptibility therefore guidance differs – Material, stress, chlorides, oxygen and temperature – No absolute guidance available, seek expert advice
Chloride SCC is characterised by transgranular crack paths
107
External stress corrosion cracking • •
•
• •
UK HSE: – Coat 22Cr duplex >80°C NORSOK M-001 SCC temp limits: – 22Cr duplex >100°C – 25Cr super-duplex >110°C Recent testing has shown failures at 80°C – now recommend 70°C as limit Reliant on external coatings to act as barrier (isolate from environment) Beware solar heating - can raise external temperature above threshold limits! – SCC failure of 316L 108
