corrosion in oil gas

7/28/2019 Corrosion in Oil Gas

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CORROSION AND

ITS PROTECTION

IN OIL & GAS PRODUCTION



CORROSION IN OIL FILED :

INTERNAL AND EXTERNAL THREATS



INTERNAL THREATS



WELL TREATMENT

INFLUENCED

WATER CARRY OVER

UNDERDOSING

DEMULSIFIER

INJECTION PUMP with

LOWCAPACITY

UNDERDOSING

CORROSION

INHIBITOR

WATER SETTLE OUT

CORROSION CAUSES



5

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



6

Internal corrosion

Hydrocarbon phase

• Not normally corrosive at

temperatures experienced in

production systems

• Corrosivity depends onextent 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’



7

Internal (process-side) damage

mechanisms

• H2S

• 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



TYPICAL REACTIONS



9

There is no species more corrosive on a concentration basis than

oxygen!

Corroded seawater injectio

Dissolved gas - effect on corrosion

0

5

10

15

20

25

0 1 2 3 4 5 6 7 8 C o r r o s i o n R

a t e

o f

C a r b o n S

t e e l

O2

CO2

H2S

Dissolved Gas Concentration in Water Phase, ppm

0 1 2 3 4 5 6 7 8

0 100 200 300 400 500 600 700 800

0 50 100 150 200 250 300 350 400

O2

H2S

CO2



10

H2S CORROSION



11

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



12

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

H+ + e- H

H + H H2

X

Atomic hydrogen -

dangerous to steels!!



13

Cracking in sour service

H H H

H

H

Higher Strength Steels YS > 500 MPa Low Strength Steels YS < 550 MPa

Applied Stress No Applied Stress

H 2

H 2

H 2

H + S 2-

Fe 2+

H

H

FeS Film

Metal Matrix



14

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 lowtemperatures for carbon steels (15-25°C), higher for CRAs (5-70°C).

•

Stress – Cracking promoted by high stress

levels e.g. residual welding

HAZ WELD HAZ

Hardness readings



15

Protection against SSC

• Avoid wetness

• Minimise hardness

– Guidance on limits inISO 15156

•Optimise microstructureand minimise residualstresses

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



16

ISO 15156 SSC zones for carbon steel

0.0034bara 0.05psia

Service

Domain

Max hardness (parent metal,

HAZ, weld metal)

0 No requirements

1 300HV

2 280HV

3 250HV root 275HV cap



17

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



18

HIC / SWC / blistering

• Laminar cracking in plane of

inclusions or blistering (HIC).

• Transverse cracking

between laminar cracks on

different planes (SWC).

Step-wise cracking Blistering of CS plate

Hydrogen blisters



19

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 TM0284Banded

Uniform



20

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



21

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



22

CO2 CORROSION



23

CO2 - containing environments

• CO2 always present in produced

fluids

– Corrosive to carbon steel

when water present

– Most CRAs have goodresistance to CO2 corrosion.

Mechanism

CO2 + H2O H2CO3

H2CO3 + e-HCO3- + H

2HH2

Fe Fe2+ + 2e-

Fe + H2O + CO2 FeCO3 + H2



24

Types of CO2 damage

Mesa corrosion

Localised weld corrosionlow-assisted-corrosion (CO2)

General & pitting corrosion



25

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



26

Factors in CO2 corrosion

• 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

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



27

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



28

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



29

CO2 corrosion inhibition

• Filming type

• Retention time

• Continuous injection

• Adsorption onto clean surfaces

Clean steel



30

CO2 + H2S corrosion – metal loss

• 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

CO2/H2S > 500 CO2 dominates

500 > CO2/H2S > 20 mixed CO2/H2S

20 > CO2/H2S > 0.05 H2S dominates



H2S + CO2 materials selection guide

Carbon/low alloy steels

Duplex SS

Nickel-based alloys

Partial pressure H2S (bar)

P a r t i a l p r e s s u r e C O 2

( b a r )

13% Cr SS



32

EROSION & EROSION-CORROSION



33

Flow regimes

Liquid

Gas

Bubble (bubbly) flow

Stratified flow

Gas

Liquid

Annular flow

Churn flow

Gas iquid

Gas

Liquid

Plug flow

Wave (wavy) flow

Liquid Gas

Slug flow

Mist (spray) flow

• 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.



34

Erosion & erosion-corrosion

• 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



35

Typical vulnerable areas for erosion

• Areas wherever flow is restricted ordisturbed

– T-pieces, bends, chokes, valves, weldbeads

• 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

Trinidad

Algeria (duplex)



36

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



37

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



38

Erosion of sandwash nozzle

Progressive nozzle damage



39

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



40

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)



41

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



42

CORROSION IN SEAWATER



43

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



44

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 super-duplex 40

Alloy 625 46

PREw = %Cr + 3.3x (%Mo + 0.5%W) + 16%N



45

Internal & external pitting

• Section of 3” 316L pipe fitting

• Failed due to internal corrosion (pinhole leak)

• Poor hydrotest practice - seawater left within spool

Internal pitting

Failure of a seawater pump cooling



46

Failure of a seawater pump cooling

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

Internal surface of coilxternal surface of coilndication on coil



47

Oxygen - concentration cells

• Crevice corrosion

– O2 is consumed in the crevice andbecomes the anode

– pH decreases in the crevice increasingattack

• Differential aeration cells

– Air/water interfaces with attack belowthe water line e.g. splash zone

– Pipelines in soils containing differentamounts of oxygen

• Under deposit corrosion

– Deposits of scale, sand or sludge

– Produces differential concentration

– SRBs thrive - H2S pitting

Crevice corrosion under

baffle



48

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 givenelectrolyte) provides driving potential and affects rate.

• Corrosion of base metal (anode) stimulated by contact with noblemetal (cathode).

• Relative area of anode and cathode can significantly affectcorrosion rate.

• Higher conductivity increases corrosion e.g. presence of salts



49

Galvanic corrosion – firewater piping

•Firewater – CuNi / super duplexstainless 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



50

Galvanic corrosion - seal rings

• ETAP platform

• Techlok joints in a firewater

piping system

– Piping: super-duplex

– Seal rings: 17-4PH



51

• Brass tubesheet in seawater

service

– Brass is Cu-Zn alloy

– Cu is more noble than Zn

–

Zn dissolves preferentiallyleaving Cu behind

• Result

– Loss of strength

– Difficult to seal

• Remedy

– Add arsenic to the brass

Dealloying of brass



52

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 non-

conducting material e.g. rubber

• Apply a non-conducting internal

coating on the more noble material.

Extend coating for 20 pipe diameters.



53

Example : CuNi-Super duplex

Apply a non-conducting internal coating on the more noble material.

Distance spool: solid, non-conducting material e.g. GRP

Distance spool: noble metal internally lined with an electrically non-conducting material such as rubber



54

Cathodic protection (CP) – what is it?

•By connecting an external anode to the component to be protected andpassing 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

Cathodic protection – how does it



55

Cathodic protection how does it

work?

ANODIC

Magnesium

Zinc

Aluminium

Iron (steel)

CopperStainless steels

Titanium

Graphite

CATHODIC

Corrosion of steel by copper

plating

Cathodic protection of steel by

zinc plating

•

CP works by making the component to be protected the cathode in anelectrolytic cell

• When two metals are connected in an electrolyte, electrons flow from theanode to the cathode due difference in the electrical potential



56

Galvanic (sacrificial) CP

• Aluminium anodes: require alloy additions tobecome active e.g. Zn + In, high efficiency (>90%).

– Typically used in seawater applications.

• Zinc anodes: ambient applications only. Alloyedwith 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 rapidactivation, limited efficiency (50-60%)

– Used in soils and other high-resistanceenvironments (risk of over-protection/rapid

consumption in seawater).

Sacrificial anodes, new and wasted

(therefore working!)



57

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

Chloride stress corrosion cracking



58

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% arehighly resistant, e.g. 825

Chloride SCC (22Cr duplex vessel



59

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).



60

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 underbiofilms

• SRB use sulphate in water in their

metabolisms to generate H2S

Fluid Velocity:

• Areas of high fluid velocity orturbulence and O2

– O2 from poor deaeration or airingress

– susceptible areas include pump

discharge piping, bends teesand reducers.



61

Mitigation & monitoring

•Deaeration and supplementary O2 scavenging

– Monitor O2 concentrations on-line(orbisphere) or colorimetric analysis

– Maintain oxygen scavenger residual tomop-up oxygen spikes.

• Chlorination u/s of deaerator, biocideapplied 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



62

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



63

Preferential weld corrosion (1%Ni)Water Injection:

• 1% Ni-containing weldsbeneficial for avoiding PWC inWI systems.

• Weld cathodic to parentmetal, protected by large area

of parent metal.

Wet hydrocarbon service:

• Lower conductivity, no benefit of selecting ‘cathodic’ weld metal

• Reliant on intrinsic corrosion resistanceof the weld metal

• Require corrosion inhibitor for

protection (test against WM and PM)• Attack of weld metal promoted by

under-dosing of inhibitor (WM needsmore inhibitor than PM)

Welds exposed to hydrocarbon service

L d d i PWC



64

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



65

MIC & DEADLEG CORROSION

Mi bi ll i d d i (MIC)



66

Microbially induced corrosion (MIC)

• Anaerobic environments often supportdevelopment 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



67

Bacterial growth factors

•

pHMIC 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.

D dl t & l ti



68

Deadlegs – types & locations

• A deadleg is a section of pipework or vessel which contains hydrocarbonfluids 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)



69

Examples of deadlegs



70

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

E l f d dl i



71

Example of deadleg corrosion

•

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

Pin Hole leaks

Releasing water

Pin Hole leaks

Releasing water

R t



72

Root causes

110mm

80mm

Area of internal corrosion

reading from 3.5 mm

tapering out to average of

10.7mm

Area of internal

corrosion 4.2 mm

tapering out to

average wall

thickness of 10.0 mm

VIEW LOOKING WEST

Photo1

North

30mm

250mm

Corroded area approx 80mm x 110mm.

• Failure to identify the bypass line as an operational

deadleg

• No deadleg register

• Failure to recognise introduction of new corrosion

hazard

• No mitigation measures.

Miti ti & i ti



73

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.



74

OTHER CORROSION MECHANISMS



75

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 servicedue SCC SCC of a titanium seal exposed to

pure methanol instead of 5%

water content




76


• Carbon steel open drain pipework.

• Seepage of scale inhibitor (passing valve)

• Scale inhibitor pH <2.

• Chemical entered drains, not flushed

Injection point issues



77

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

Main Flow

Injected Fluid

Impingement

High temperature corrosion



78

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 Cr-Mo

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

Amine stress corrosion cracking



79

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

Corrosion in glycol system



80

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

Corrosion fatigue



81

Corrosion fatigue

• Combined action of cyclic tensile stressand a corrosive environment

• Fatigue is caused by cyclic stressingbelow the yield stress

– Cracks start at stress raisers

– Can occur due to vibration e.g.smallbore nozzles & with heavyvalve attachments

• Presence of corrosive environmentexacerbates the problem

– Can lead to pitting, which acts asstress concentrators

Example of corrosion fatigue



82

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



83

EXTERNAL CORROSION – SURFACEFACILITIES

E l i



84

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

Wh d it ?



85

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.

What does it look like?



86

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.

Appearance



87

Appearance

•Carbon/low alloy steels usuallycovered 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 inblue/green corrosion products.

Piping supports & clamps



88

Piping, supports & clamps

Not just carbon steel



89

Not just carbon steel

• 25Cr super-duplex (PREN ≥40)

• Seawater service

• 12 months exposure in tropicalclimate

• External corrosion along welds

• Poor quality fabrication

C i f b lt d f t



90

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




91


General corrosion Galvanic corrosion

Crevice corrosion Stress corrosion cracking

Flanged connections



92

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 tocorroded fasteners

– Joint leak

• Corrective actions

– Change gasket/fastener materials

–Replace graphite gaskets with non-asbestos or rubber material

Corroded fasteners (seawater service)



93

Corroded fasteners (seawater service)

Location of graphite gaskets

Structures / valves



94

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

Coating damage and breakdown



95

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

External cathodic protection



96

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

Impressed current CP



97

Impressed current CP

• Adjustable dc source

– Negative terminal

connected to the

steel structure

–

Positive terminalconnected to the

anodes

• Typically used on larger

structures where

galvanic anodes cannot

economically deliver

enough current.

Corrosion under insulation (CUI) and

d f f ( )



98

Corrosion under fireproofing (CUF)

• CUI

– Water seeps into insulation and

becomes trapped, results in

wetting and corrosion of the metal

–

Carbon steel corrodes in thepresence of water due to the

availability of oxygen.

• CUF

– Same mechanism except water

gets behind the fireproofing.

Insulation



99

Insulation

•Typical insulation types; – Process

– Personnel protection (PP)

– Winterisation

– Acoustic

• Challenge the need

– Remove unnecessary

insulation

– Replace PP with cages‘Lobster-back’ joint

Mitred joint

Pre-formed bends

CUI incident



100

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

CUI gas leak



101

CUI gas leak

•

2” fuel gas piping outside edgeof 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 fromonshore not site survey

piping CUI



102

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

CUI on pressure vessel



103

CUI on pressure vessel

• CS offshore vessel

• Operating at 85°C and 11 bar

• PFP coating (passive fire

protection)

•

Extensive corrosion scabbing onboth 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

External pitting & crevice corrosion



104

p g

• 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.

Instrument tubing



105

(316 SS and super-duplex)316 SS tubing super-duplex tubing

316 SS (pitting/crevice corrosion) super-duplex (no pitting)

Crevice corrosion under

l / t



106

clamps/supports

• Pitting and crevice

corrosion of 316ss piping

– Clamps

– Plastic retaining blocks

External chloride stress corrosion

ki



107

cracking

• Mechanism same as internal chloride SCC however:

• Numerous variables influence susceptibility therefore guidancediffers

– Material, stress, chlorides, oxygen and temperature

– No absolute guidance available, seek expert advice

Chloride SCC is characterised by trans-

granular crack paths

External stress corrosion cracking



g

•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

corrosion in oil gas

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