overview of corrosion in the oil and gas industry

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


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.


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)


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


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


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


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).


Environmental Stress Cracking:

SSC & SCC – Failure Below the Yield Stress

Chlorides – Higher

Temps: SCC

Water Wet H2S lower

Temperature: SSC


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.


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.


Lack of ductility is typical of SSC failures

P110 Failure

Paper 0512, CORROSION/2005


Quasi Cleavage SSC Failure SSC

fracture surface – brittle with little

ductility.

Paper 05116, CORROSION/2005

SSC is Brittle

Ductile Collapse Failure – Unlike SCC


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.


SSC Mechanism


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.


5.0 Stress Corrosion Cracking of Corrosion

Resistant Alloys


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.


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.



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)


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


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.


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


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


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


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


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.


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


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)


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.


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


overview of corrosion in the oil and gas industry

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