Overview of Corrosion in the Oil
and Gas Industry
4/26/2017 Rice Univ. Corrosion Seminar 1
Guest Lecture at Rice University
MSNE 569 Corrosion Science and Engineering
James Skogsberg (modified by R C John)
April 26, 2017
Examples of Materials and Corrosion Issues in the
Oil and Gas Upstream Industry
1.0 Overview of Upstream Equipment
2.0 Materials Selection
3.0 Corrosion in Oil & Gas Production
4.0 Sulfide Stress Cracking of Carbon & Low Alloy Steels
5.0 Stress Corrosion Cracking of Corrosion Resistant Alloys
2Rice Univ. Corrosion Seminar4/26/2017
Upstream: Oil & Gas Production
WELLHEAD
FLOW LINES
MANIFOLD
RESERVOIR
OIL
GAS
H2O
CO2
H2S
SAND
SEPARATOR
SLUGCATCHER
TANKAGE
TRUNKLINE/
PIPELINE
TRUNKLINE/
PIPELINE
water disposal
Facilities downstream of choke valve separate oil/gas/water and remove
acid gases (CO2 + H2S).
Low P & T
Rice Univ. Corrosion Seminar 34/26/2017
1.0 Overview of Upstream Equipment
• Upstream operations deal with production and transportation of oil
and gas.
• Downhole completions produce oil and gas.
– Pressures may be 10,000 psi with temperatures up to 350 F.
– HPHT wells may be 20,000 psi with temperatures up to 500 F.
• Facilities downstream of the completions separate oil/gas/water
phases and remove chlorides, CO2 and H2S + CO2 contaminants.
– Lower pressures may be 1,000 psi and lower temperatures.
• Corrosion of alloys is caused by water wet environments - aqueous
electrochemical corrosion
4Rice Univ. Corrosion Seminar4/26/2017
2.0 Materials Selection
1. Design life may be 10 years or 20 years – no tolerance for failure
2. Establish economic risk: HPHT, high H2S, subsea or deep water
3. Determine alloy strength requirements based upon design.
4. Choose alloy to prevent general corrosion.
A. CO2 corrosion
B. H2S corrosion
C. Organic acids
5. Consider localized corrosion resistance (pitting & under-deposit corrosion)
A. Chlorides
B. Sulfur
6. Choose alloy to resist environmental cracking – NACE MR 0175 / ISO 1516.
A. Sulfide stress-cracking and
B. Stress-corrosion cracking
7. Supplement field experience and literature with laboratory study and tests.
5Rice Univ. Corrosion Seminar4/26/2017
Environments which Cause Corrosion and Cracking
Production Environment: short-term & long-term
• Water cut, bubble point, velocity, pH, & chlorides.
• Partial Pressures of H2S & CO2 - reservoir souring?
• BHT & surface or mud-line temperatures
• BHP & FTP
• Contaminants – organic acids
• Desired project life: 5 yrs, 10 yrs, or 20 yrs.
Annular Environment: short-term & long-term
• Chlorides – NaCl, NaBr2, ZnBr2, pH, oxygen scavenger, corrosion inhibitor and biocide
• Effect of acid gas leaks up the annulus
Workover: short-term
• Acidizing, clear brines without inhibitor & oxygen scavenger, & mixing with sour gases during flow back.
• Flow back through subsea equipment
• Shut in conditions (weeks, months to years)
6Rice Univ. Corrosion Seminar4/26/2017
7
3.0 Corrosion in Oil & Gas Production
1. O2 (present as a contaminant in water injection/flood operations)
2. CO2 (natural in formations)
3. Acids (natural and introduced in operations)
1. Organic from oil and gas production
2. Inorganic (HCl/HF) from work over operations
4. H2S (“sour”) (natural and introduced in operations)
5. Bacteria (natural and introduced in operations)
Rice Univ. Corrosion Seminar4/26/2017
8
What might Damage by CO2 Corrosion Look Like?
Mesa-type corrosion in a
West Texas wellCorrosion in Electrical Submersible
Pump (ESP)
ChokeRice Univ. Corrosion Seminar4/26/2017
9 9
CO2 Corrosion Mechanisms
CO2 + H2O H2CO3 HCO3- + H+ CO3
2- + H+
Fe
½ H2
+
e-
Fe2
+
FeCO3
+
e-
HCO3-
+
½ H2
+
CO2
GAS
AQUEOUS
PHASE
+ +
Hydration
Dissociation
Electrochemical
reactions
Iron carbonate
precipitation
Mass
transport
Affected by:
1. Temperature (major influence),
2. Pressure (determines partial pressure
of CO2),
3. Velocity (can stimulate mass transfer &
break down corrosion product layers),
4. pH and ferrous ion concentration
(determines precipitation of FeCO3).
Rice Univ. Corrosion Seminar4/26/2017
10
immune
Potential - pH or
Pourbaix of Iron Constructed from
Nernst equations,
& solubility of
metal compounds.
Used to:
• Predict
corrosion
product
compositions
• Predict
solution
changes to
reduce
corrosion.
Not used for
corrosion
rates.
Passive regions
Active corrosion
Corrosion Products - Pourbaix Diagram for CO2
Corrosion
Flow Rate can be Important in CO2 Corrosion Rate
Equation by De Waard & Milliams
𝐿𝑜𝑔 𝑉𝑐𝑜𝑟 = 5.8 −1710
273 + 𝑡+ 0.67 log𝑃𝐶𝑂2
Where Vcor = corrosion rate in mm/yr
T = temperature, ˚C,
PCO2 = Partial pressure of CO2, bar
Subsequent corrections have been added for:
– Corrosion product films, T>60˚C
– pH due to presence of organic acids
– Effects of system pressure
– Top of the line corrosion for wtr condensing on the upper walls of pipe
– Glycol & methanol effects
– Crude oil effects
– Velocity
– Inhibition
12
C. De Waard and D. E. Milliams,
“Carbonic Acid Corrosion of Steel”,
Corrosion, Vol 31, 5, (1975), 177.
C. De Waard and U.Lotz,
“Prediction of CO2 Corrosion of
Carbon Steel,” NACE 93069.
Primarily a concern for surface equipment and pipelines
transporting oil & gas. Difficult to use for well environments.
4/26/2017
H2S Corrosion
• H2S in water/oil/gas will cause corrosion.
• Reactions forming iron sulfides from H2S are generally faster than
those forming carbonates from CO2.
– H2S and CO2 are competitive mechanisms
– Ratios of H2S / CO2 determine which mechanism predominates
• Passive films may form and lower corrosion rates.
• There are no industry methods to predict H2S corrosion
13Rice Univ. Corrosion Seminar4/26/2017
H2S Corrosion (Sour Corrosion)
14
pCO2/pH2S=20
CO2 REGIME
SWEET
H2S REGIME
SOUR
CO2 + H2S REGIME
MIXED
pCO2
pH2S
pCO2/pH2S=500
Pourbaix Diagram for S Species in Water
Effect of H2S on Corrosion Products of Fe Alloys
2nd European Symposium on Corrosion, 1965
Industry Uses NACE MR 0175 / ISO 15156
to Guide Selection of Metals in Sour Service
An International Standard to provide guidance for safe use of metal
alloys in sour service for oil and gas production wells and facilities:
Provides metallurgical properties for CRAs and environmental limits
to prevent environmental cracking (SSC, SCC, & other mechanisms)
Does not provide advice on other corrosion mechanisms
Is a guideline only and NOT a warranty against cracking
17Rice Univ. Corrosion Seminar4/26/2017
Types of Hydrogen Damage in Upstream Oil &
Gas Operations – due to Presence of H2S
Damages due to interaction with atomic H
Hydrogen Embrittlement
• Sulfide Stress Cracking (SSC) in presence of H2S
• Low-temperatures
• Sensitivity increases with hardness
Wet H2S Cracking
• Rolled plate and welded pipe
• Low - temperatures
• Related to plate-like inclusions
• Not hardness dependent
• Hydrogen-Induced-Cracking (HIC)
• Step-Wise-Cracking (SWC)
18
19
Hydrogen Embrittlement
Atomic H diffuses into steel causing embrittlement, which shows as a loss of ductility and brittle fractures.
Fracture
surface
Intergranular features of fracture
Failure Analysis: Most likely HE caused by the zinc plating process.
HIC/SWC and SOHIC Definitions
20
HIC caused by build-up of hydrogen gas
pressure at sulfide inclusions. SWC is the
stepwise link-up of these cracks through
thickness.
T
SOHIC is stacked array
of HIC cracks linked
perpendicular to tensile
tensile stress.
σ
Form of SSC that may occur when
steel contains a local “soft zone” of
low yield strength material (e.g. HAZ).
4.0 Sulfide Stress Cracking of Carbon & Low
Alloy Steels
Main Corrosion Failure Mechanism at Lower
Temperatures in Upstream Oil and Gas Operations
Rice Univ. Corrosion Seminar 214/26/2017
Environmental Stress Cracking: Critical Issue for
Choosing Materials CRA’s are used to resist corrosion but can fail by SCC
Stress Corrosion Cracking (SCC) –
Cracking of a metal alloy involving
anodic processes of localized
corrosion and tensile stresses in the
presence of water and H2S.
(NACE MR 0175 / ISO 15156)
Associated with chlorides, pitting
corrosion, higher temperatures and
all alloys.
(anodic stress corrosion cracking)
Sulfide Stress Cracking (SSC) –
Cracking of a metal alloy involving
corrosion and tensile stress in the
presence of water and H2S.
(NACE MR 0175 / ISO 15156)
Associated with hydrogen, lower
temperatures and 13 % Cr alloys.
(cathodic stress corrosion cracking).
22Rice Univ. Corrosion Seminar4/26/2017
Environmental Stress Cracking:
SSC & SCC – Failure Below the Yield Stress
Chlorides – Higher
Temps: SCC
Water Wet H2S lower
Temperature: SSC
Rice Univ. Corrosion Seminar 234/26/2017
SCC: Cold -
Worked CRAs
Stress can be
residual or applied.
Overview of Stress Corrosion Cracking (SCC)
• SCC is defined by NACE MR 0175 / ISO15156 as:
– The cracking of metal involving anodic processes of localized
corrosion and tensile stresses in the presence of water and H2S.
• SCC is a potential failure mechanism for all CRA’s.
• SSC is associated with cracking of carbon steels, low alloy steels,
martensitic stainless steels (13 % -17% Cr), and duplex stainless
steels. (22% Cr & 25% Cr).
• SCC is associated with chlorides and oxidants (oxygen), which
increase the likelihood to cracking.
– Solid sulfur deposits are oxidizing and increase SSC.
• For carbon steels, low alloy steels, chances of SSC increase with
decreasing water pH and increasing PH2S.
• However, risk of to SCC increases with increasing temperature.
Rice Univ. Corrosion Seminar 244/26/2017
When is an environment “sour”?
Rice Univ. Corrosion Seminar 25
Traditional NACE approach before 2003 uses
severity of the environment for SSC is
measured by PH2S.
4/26/2017
European Federation of Corrosion Definitions
of Sour Service Cracking Regions. In-situ
water pH defines severity with PH2S. Regions
3>2>1 for cracking severity.
Why is SSC Important?
• SSC commonly occurs at stresses below the alloy yield strength.
– Traditional safety factors for design are not valid to prevent failure.
– High strength alloys (high hardness) are more susceptible to SCC.
• SSC can occur within hours of exposure to wet H2S.
– Corrosion may take years to cause failure.
– There is no short-term selection for materials in sour service.
• SSC results in brittle type fractures.
– Nil ductility and typical of cast iron ruptures.
– Easily catastrophic and without warning.
Rice Univ. Corrosion Seminar 264/26/2017
Lack of ductility is typical of SSC failures
P110 Failure
Paper 0512, CORROSION/2005
Rice Univ. Corrosion Seminar 274/26/2017
Quasi Cleavage SSC Failure SSC
fracture surface – brittle with little
ductility.
Paper 05116, CORROSION/2005
SSC is Brittle
Ductile Collapse Failure – Unlike SCC
Rice Univ. Corrosion Seminar 28
Ductile failure shows much deformation before tubing collapse and leak.
Bruce Craig: Oilfield
Metallurgy & Corrosion
4/26/2017
Ductile rupture surface with no SSC -
Paper 05104 - CORROSION/2005
SSC Mechanism
• SSC is a form of hydrogen stress cracking (HSC) due to
embrittlement of the alloy by atomic H produced by cathodic
reduction on the metal surface.
• The corrosion rate when H2S is present can be lower in a CO2
environment because of the formation of protective sulfide films.
Dense phase H2S and elemental sulfur may both cause rapid
localized corrosion.
• Cracking is the main concern for materials in subsea equipment for
sour environments, with corrosion resistance as a secondary issue
• H2S will:
– Accelerate H evolution, which is the cathodic reduction reaction
in acidic environments.
– Suppress the recombination of H atoms to H2 and make more H
absorb into the alloy.
Rice Univ. Corrosion Seminar 294/26/2017
SSC Mechanism
Rice Univ. Corrosion Seminar 30
Reference - Sumitomo Metals: OCTG Materials & Corrosion
4/26/2017
Sulfide Stress Cracking (SSC) Variables
• Metallurgical Variables
– Higher hardness increases SSC susceptibility.
>22 HRC is a rule for most carbon and low alloy steels.
– Higher YS and TS correlate with hardness and increases SSC.
– Finer grain size and a higher percentage martensite in the
microstructure increases resistance to SSC.
• Environmental Variables
– Lower temperatures (<175 F) are more severe.
– Higher PH2S increases SSC.
– Higher fraction of water in systems promotes wetting of the
equipment and increases SSC.
– Lower pH’s increase SSC.
Rice Univ. Corrosion Seminar 314/26/2017
5.0 Stress Corrosion Cracking of Corrosion
Resistant Alloys
Rice Univ. Corrosion Seminar 324/26/2017
Corrosion Resistant Alloys for
Completion of Sour Service Wells
• Corrosion resistant alloys (CRA’s) are
used for tubing and liners. These
include both heat treatable alloys
such as the 13 % Cr and also cold
worked alloys such as duplex
stainless steels and Ni-based alloys.
• CRA’s are used for tree valves,
packers, hangers, & packers. These
may include age-hardenable Ni-based
alloys like 718 & 925.
• Low alloy steels are used for casing.
Rice Univ. Corrosion Seminar 33
A
20” 5400’
16”7100’
11 3/4”11300 –
14000’
9 5/8”15000 – 19000’
7” or 7 5/8”
28”
36”
B
4/26/2017
Why do we care about SCC?
• SCC commonly occurs below the yield strength of the alloy.
– Traditional design safety factors are not used to prevent failure.
– Higher strength alloys with higher hardnesses are more
susceptible to SCC.
• SCC can occur within hours to days of exposure to wet H2S.
– Corrosion may take years to cause failure.
– There is no “short-term” basis for a materials selection in sour
service.
• SCC results in brittle type fractures - nil ductility and typical of cast
iron ruptures.
Rice Univ. Corrosion Seminar 344/26/2017
Rice Univ. Corrosion Seminar 35
Failure of 17-4 PH SS Tubing Hanger
Note the lack of ductility with a brittle fracture
as with SSC.Hanger in service with PH2S
>permitted in 2003 Edition.
4/26/2017
Examples of Corrosion and Materials Issues in the
Petroleum Refining Industry
1.0 Overview of Corrosion In Refining Industry
2.0 Low Temperature Refinery Corrosion
3.0 High Temperature Refinery Corrosion
4.0 Stress Corrosion Cracking (SSC)
4/26/2017 Rice Univ. Corrosion Seminar 36
1.0 Overview of Corrosion In Refining Industry
• High temperature (gas phase) and low temperature (aqueous phase)
corrosion mechanisms are present
• Alloys used have much lower yield strengths than those in upstream
oil and gas production.
– Pressures are lower (1,000 – 1,500 psi)
– Temperatures are higher (up to 1,500 F)
• Equipment may be inspected during shut downs and during operation
- internal inspections are rare for upstream and subsea operations
• Often use corrosion allowances in corrosive environments with
carbon steels - not possible in upstream operations
4/26/2017 Rice Univ. Corrosion Seminar 37
Simplified Refinery Process
2.0 Low Temperature Corrosion
• Temperatures < 450 F to 500 F
– Aqueous corrosion is an electrochemical process.
– Similar as upstream processes except more corrodents.
• Also includes stress corrosion cracking (SSC)
– Many more corrodents compared to upstream.
4/26/2017 Rice Univ. Corrosion Seminar 39
Example Cathodic Reactions for Corrosion of
Carbon and Stainless Steels in Refineries:
Low- Temperature Corrosion
• Anodic oxidation reaction (dissolution) same as for upstream :
Fe = Fe+2 + 2e-
• Cathodic reactions – hydrogen evolution in low pH (acidic)
environments same as for upstream:
2H+ + 2e- = H2
and
2HS−
+ 2e- = H2 + 2S-2
4/26/2017 Rice Univ. Corrosion Seminar 40
Low – Temperature Corrosives in the Refinery
• Sulfur
– Results in surfurous and polythionic acids:
– SCC of sensitized 300 series stainless steels during plant shut
downs
• Naphthenic Acid
– Velocity enhanced corrosion of carbon steels at intermediate
temperatures, where condensed hydrocarbons are present
– 350 F to 750 F
– Use of 300 series SS in crude units
• Chlorides
– Pitting of all alloys
– Prevalent in crude unit overheads
4/26/2017 Rice Univ. Corrosion Seminar 41
Thermodynamics of Sulfur Phases at Equilibrium
Upstream
Corrosion
Refinery
Corrosion
Low – Temperature Corrosives in the Refinery
• CO2
– Hydrogen plants and Catalytic Cracking Units
– High & low temperature corrosion of carbon steel
• NH3
– Cracking of hi-nitrogen feed stocks
– Corrosive salts – localized corrosion
– Ammonium bisulfide can cause rapid corrosion of carbon steel
piping & heat exchangers
• CN-
– Cracking of hi-nitrogen feed stocks
– Hydrogen recombination poison leads to corrosion and cracking
4/26/2017 Rice Univ. Corrosion Seminar 43
Low – Temperature Corrosives in the Refinery (cont.)
• HCl
– HCl formed from hydrolysis of salts in crude column overheads
– Crude Units
• H2S
– Wet low pH and high pH corrosion of alloys
– High temperature corrosion (sulfidation)
• HF & Sulfuric Acids
– Alkylation Plants
– Velocity-enhanced corrosion of carbon steels
• Amines
– Gas plants
– Chlorides & degradation products contaminants
– stainless steels resist erosion/corrosion better than carbon steels
4/26/2017 Rice Univ. Corrosion Seminar 44
3.0 High Temperature Refinery Corrosion
• Temperatures above 450F - 500F - 825 F in hydroprocessing units.
• Boilers and process fired heater furnace tubes may reach 1,800 F
on the fireside.
– Oxidation, sulfidation, CO2 corrosion, erosion, fly-ash corrosion
– Limit carbon steel in oxidation service to about 1,050 F.
– Increase Cr-Mo content (5 Cr, 9Cr, 12 Cr etc.) to slow oxidation.• Solid state electrochemical reactions in the corrosion products.
• Mixed phases (gases/liquids/sulfides) can cause corrosion,
corrosion fatigue, erosion corrosion, cavitation and stress corrosion.
4/26/2017 Rice Univ. Corrosion Seminar 45
High – Temperature Refinery Corrosion
Sulfidation with H present (H2/H2S corrosion) at temperatures
above 450 F is common with S-containing crude oils.
• Fe + H2S = FeS + H2
• Crude units
• Slower corrosion by increasing Cr content in steel
• Slower corrosion by use of Fe-Cr-Ni stainless steels
• Corrosion found in hydrotreaters, hydrocrackers,
hydroprocessing plants
4/26/2017 Rice Univ. Corrosion Seminar 46
High Temperature Hydrogen Attack (HTHA)
• Carbon and low-alloy steels
• Temperatures above 430 F & PH2above 200 psi
• Long-term degradation by formation of methane bubbles in
the steel microstructure
• HTHA found in hydroprocessing plants and hydrogen
manufacturing plants
• H penetrates steels, causing decarburization & blistering (methane
fissures, voids etc.)
• HTHA resistance increases with increasing Cr and Mo content by
increasing the stabilities of carbides in the alloy (see Nelson curves -
API Pub. 941)
4/26/2017 Rice Univ. Corrosion Seminar 47
API Nelson Curves for High-Temperature
Hydrogen Attack of Carbon and Low alloy Steels
4.0 Stress Corrosion Cracking in The Refinery
• Alloys in refinery operations are subject to cracking.
• More cracking mechanisms than in upstream oil & gas operations
– Requires:
• Exposure to chemical environment
• Tensile stresses: applied or residual – may need to stress
relieve welded piping and vessels
• Sensitive alloys due to microstructure or composition
• Results in brittle fracture below the yield strength.
4/26/2017 Rice Univ. Corrosion Seminar 49
Alloy – Environments Sensitive to SCC
Alloy Family Environment – cracking agents
Carbon Steel Sulfides, Caustic, Anhydrous
Ammonia, Nitrates, Amines, &
Carbonates
Austenitic Stainless Steels (300
series)
Chlorides, Caustic, Sulfurous Acid, &
Polythionic Acids
Nickel - Based Alloys (annealed) HF & High-temperature Caustic
Martensitic & Precipitation Hardening
Stainless Steels
Seawater, Chlorides, and H2S
Copper – Based Alloys Amines & Ammonia Compounds
4/26/2017 Rice Univ. Corrosion Seminar 50