franks cra symposium vallourec presentationfranksinternational.com/wp-content/uploads/may...api 5cra...

This document contains proprietary information developed for the CRA Tubulars and Well Integrity Technical Symposium. None of the information contained herein may be disclosed, reproduced, distributed or used without prior written consent from Frank’s International. © 2017 Frank’s International. All rights reserved.

CRA Tubulars and Well Integrity page

CRA Tubulars and Well Integrity Technical Symposium

September 25, 2017

Introduction to CRA Tubulars: Metallurgy and Material Selection for Corrosive EnvironmentsSeptember 25th, 2017



Agenda

Corrosion Resistant Alloys

• Normative definition

• Basic metallurgy

Corrosion mechanisms

Material selection for CRA completions

Connector selection for CRA completions

2



What is a Corrosion Resistant Alloy (CRA)

“CRA is an alloy intended to be resistant to general and localized corrosion and/or environmental cracking in environments that are corrosive to carbon and low-alloy steels.” (ISO 13680)

• CRAs

• are used to control corrosion for the life time of the well.

• are chosen because other methods such as chemical inhibition are inadequate or not practical.

3

3



Normative Requirements for CRA Tubulars

API 5CRA / ISO 13680 specifications• Covering S13Cr up to Ni-base Alloys• 4 groups defined by their composition and mechanical properties• 2 Product Specification Levels (PSL) :

• PSL 1 is basis of API 5CRA• PSL 2 : restricted chemical composition & mechanical properties

Nota: Some alloys not available in PSL 2

NACE MR0175 / ISO 15156 :• Guideline for selection and qualification of metallic materials used in Oil & Gas • Part 3 of this specifications focuses on CRA :• Environmental limits for any equipment • Chemical composition per material type

Comment: in OCTG, CRA usually means pipe with minimum 22% Cr content

4



Martensitic Stainless Steels

13 % Chrome alloys:• L-80-13Cr covered in API5CT• Reasonable resistance to CO2 corrosion• Considered by some operators for very mild sour service• Most inexpensive solution to CO2 corrosion.

Super 13% Chrome alloys (13-5-2) UNS S41426 for PSL2• Covered by API5CRA

• ≥ 110ksi grade not covered by NACE MR0175• Improved pitting resistance (CO2 corrosion)

15% & 17% Cr alloys are being introduced with 125 ksi Yield Strength for HPHT wells• Improved SCC and Corrosion resistance at higher temperatures• Not covered by any API Standard

Strength for those alloys is achieved through heat treatment as with carbon steel (quench & temper)

5



Duplex Stainless Steel

22 % Cr & 25 % Cr alloys containing Nickel with “duplex” microstructure of ferrite and austenite

• Covered by API5CRA (PSL1 quality level for general service & PSL 2 for sour service)

• Improved CO2 corrosion resistance and chloride pitting resistance in mild sour service.

• Offer Generally limited to 0.3 psi to 3.0 psi H2S depending upon alloy composition.

• Super duplex SS with 25 % Cr (PREN>40) often used in water injection wells with oxygen excursions

Examples include:

• 22 % Cr (22-5-3) UNS S31803

• 25% Cr (25-7-4) UNS S32750

• 25 % Cr super duplex UNS S32760 & S39274

Strength for those alloys is obtained through cold-work process

6



Nickel Alloys

Best available alloys for completing wells with tubing and in severe environments. • Covered by API5CRA• PSL1 quality level for general service & PSL 2 for sour service• Increased resistance to pitting corrosion and environmental cracking

Examples• Alloys 28 Cr & 825 • Alloy G3 – higher limits for H2S and temp.• Alloy C 276 – best under all conditions

• Can be used in high partial pressures of H2S and sometimes elemental sulfur

Strength for those alloys is achieved through cold-work process

7



General Product Offer (covered by API5CRA)Structure

(as per API 5CRA)Names Category

Composition (mass%)Available Grades (ksi)

Cr Ni Mo

Martensitic

(Group 1)

Super 13Cr 13-5-2 13 5 2 80, 95, 110

- 13-1-0 13 0,5 80, 95, 110

Duplex steels

(Group 2)

22CR 22-5-3 22 5 3 65, 110, 125, 140

25CR 25-7-3 25 7 3 75, 110, 125, 140

Super-Duplex steels

(Group 2)S25CR 25-7-4 25 7 4 80, 90, 110, 125, 140

Austenitic steels

(Fe base)

(Group 3)

Alloy 28 27-31-4 27 31 4 110, 125, 140

- 25-32-3 25 32 3 110, 125, 140

- 22-35-4 22 35 4 110, 125, 140

Austenitic steels

(Ni base)

(Group 4)

Alloy 825 21-42-3 21 42 3 110, 125

G3 22-50-7 22 50 7 110, 125, 140

- 25-50-6 25 50 6 110, 125, 140

- 20-54-9 20 54 9 110, 125, 140

C276 15-60-16 15 60 16 110, 125, 140

8



Super13Cr (Martensitic Stainless Steel) – Production Process

1. Hot billets are pierced into hollows

2. Hollows are further processed by hot rolling to achieve OD and Wall Thickness

3. Strength is achieved through Quench and Temper process

9



CRA (≥ 22Cr content) – Production Process

1. Before cold working process, the billets are transformed into hollows using hot extrusion

2. Hollows are further processed by cold rolling/drawing to achieve OD and Wall Thickness

3. Strength is achieved through plastic deformation

Pilger ProcessCold Drawing Process

10



Corrosion

There are two basic requirements for carbon steel to corrode:

• First, liquid water must exist as a free and separate phase. • Water in oil as an emulsion will not cause corrosion.

• Second, liquid water must wet the surface of the carbon steel equipment or tubing.

The corrosivity of water will vary through a surface facility.

• Both CO2 and H2S can corrode steel. • Measure pH and chlorides.• Watch out for oxygen >10-20 ppb.• Track condensed vs. production water

Oil wells will be corrosive when water cut increases

Gas wells tend to be corrosive from the beginning

11



Environment Impacting Downhole Corrosion

Components that define the severity of the environment• Partial Pressure H2S • Partial Pressure CO2 • Chloride content• Produced water rate• Produced condensate/oil rate• Bicarbonate content HCO3• Bottom hole temperature• pH• Flow velocity• Free sulfur can occur as low as 4-5% H2S• Acid stimulation fluids: carefully evaluate inhibitors• Completion fluids: Certain fluids can be very aggressive.• Scale: some scales can be beneficial

12



Sulfide Stress Cracking

CO2 corrosion Pitting Corrosion Stress Corrosion Cracking

Main Corrosion (and Cracking) Mechanisms in OCTG

13

13



CO2 Corrosion - Mechanisms

• Chemical reaction either localized or generalized

• Without water no CO2 corrosion

• Temperature an CO2 partial pressure have major influence

• Carbonic acid is formed CO2 and water (CO2 + H2O = H2CO3)

• Carbonic acid is reacting with Iron (2Fe + H2CO3 = Fe2CO3 + H2)

• A complex process with high variation of corrosion rate

14



Pitting Corrosion - Mechanism

Localized attack of metal

Typically due to breakdown of passive layer

Most destructive and initiated by metallurgical and/or environmental factors

• Reinforced in presence of chlorides

• Difficult to predict by lab tests

• Difficult to stop

The higher the content in chromium, nickel and molybdenum, the lower the susceptibility

Self maintaining phenomenon (self-accelerating)

15



Chrome Steels to Avoid CO2 Corrosion

ppCO2 ≥ 2 psi will induce metal loss corrosion for Carbon Steels

Alloying with Cr alone, will not prevent corrosion

16

Increasing Cr-content

Incr

easi

ng

Co

rro

sio

n

wit

h p

pC

O2

13%Cr

16



Environmental Cracking – SSC and SCC

Failure occurs below the minimum yield strength

17

Susceptible Material

TensileStress

Environment

Temperature

Su

scep

tib

ility

to

cra

ckin

g

Sulfide Stress CrackingSSC

Stress Corrosion CrackingSCC



Overview of Stress Corrosion Cracking - SCC

Combination of corrosive environment and a mechanical stress

• localized corrosion and tensile stresses in the presence of water and H2S

• Creation of crack with multiple branches

• Progressive cracking with delayed failure

Potential failure mechanism of all CRAs and Chrome Steels

• Crack growth rate from mils/day to in/day

SCC will increase with

• decreasing water pH

• increasing ppH2S and Temperature

SCC is almost always associated with chlorides

• Elemental sulfur deposits are a powerful agent for SCC

SCC occurs below the yield strength of the alloy

• Traditional safety factors for design are no longer valid to prevent failure.

18



Overview of Sulfide Stress Cracking - SSC

Even with small amounts of H2S, steel become sensitive to H2S corrosion/cracking

Cracking is caused by hydrogen in the material• H collects at stressed locations • Material becomes brittle and fails below yield strength limit• Very quick propagation leading to sudden failure

SSC is generally associated with cracking of Carbon Steels, Martensitic Stainless Steels (13Cr, S13Cr) and Duplex Stainless Steels (22Cr & 25Cr)

SSC will increase with: • decreasing water pH and Temperature• increasing ppH2S

Higher water cut to promote water wetting of equipment can increase SSC

19



Options to Prevent Corrosion

Design • Use a corrosion allowance

• Regular replacement

Material selection• Selection of a Metallurgy immune to corrosion/cracking in a given environment

• Use Corrosion Resistant Alloy (CRA)

• Use Non-Metallic Material

Change the environment• Inhibitor: Chemical additives when added in small quantities stop or slowdown the corrosion.

• Maintenance: e.g. pigging

Coating• Short term

• Long term

20



Material Selection

21



Evaluation of Service Condition to Enable Material Selection

Define all environments that material will be exposed to over lifetime of completion

Production environment: short term & long term

• Water cut, bubble point, pH, chlorides

• Partial pressure H2S & CO2 (reservoir souring, SRBs)

• BHT & surface or mudline temp

• BHP

• Contaminants

• Desired project life

Annular Environment: short term & long term

• Chlorides – type of brines, NaCl, ZnBr2, pH, oxygen scavanger, corrosion inhibitor, biocides

• Effect of gas leaks up the anulus

Workover conditions

22



Tools For Material Selection

NACE MR0175/ISO15156 (Guideline only, no warranty and no advice on metal loss corrosion)• Part I: General Principals• Part II: Carbon & Low Alloy Steels• Part III: Corrosion Resistant Alloys

Company guidelines & philosophy

Literature & Publications

Software• Socrates• ECE

Actual Test Data• Material testing and qualification

23



Yes

Simplified Material Selection Decision Tree

24

Consider all potential scenarios

during well life

Verify Sour Service

limitations

Basis of Design(BoD)

Short or long term

Exposure to produced

fluid possible?

Asses metal loss corrosion

(CO2)

Assess Sour Service

(H2S)

Assess Sour Service

(H2S)

Standard low Alloy Carbon

Steel

Sour Service Grades

13% Chrome CRA

No Yes

No

Short

Long

No

Yes

YesNo

T and Cl-

limitations

24



Long Term Exposure – Risk of Metal Loss Corrosion

No industry standards available• 0.1mm/yr considered as “no” metal loss

Models and guidelines available to evaluate metal loss / corrosion rate• DeWard Milliams• NORSOK• Cassandra (BP)• PREDICT (Intercor)• etc.

25



H2S Limits for CRA Tubular Components

Alloy Material Group Table H2S Limit (psi)

Temp Limit (°F)

13Cr Grade L80 Martensitic SS A.19 1.5 (pH 3.5) None (*)

S-13Cr Grade 95 Martensitic SS A.19 1.5 (pH 3.5) None (*)

22CR / 25Cr Duplex (PREN 30-40) A.25 1,5 None (*)

S25CR Super Duplex (PREN>40) A.25 3 None (*)

825, 28CR Nickel Base (4C) A.14 200 350

Alloy G3 Nickel Base (4D) A.14 300 425

C-276 Nickel Base (4E) A.14 1000 450

26

(*) Temp limit was not necessarily determined but mechanical properties will suffer too much at very high temperatures

Other downhole environmental factors may have an influence on selecting the most appropriate alloy.

NACE MR0175/ISO15156 - Part 3



Simplified Material Selection Chart – CO2 > 2 psi

Usage Domaine of Chrome and Nickel Alloys

27

27



Testing and Material Qualification

Metallurgical analysis Numerical analysis and simulation

NACE testing (SSC resistance) Autoclave (crevice, pitting, SSC, HPHT)

Tests performed to evaluate

• Sulfide Stress Cracking – SSC

• Stress Corrosion Cracking – SCC

• Mass Loss Corrosion

Typical protocols/standards used

• NACE MR0175 (MaterialRecommendation & Part 3 Annex B)

• NACE TM0177

• NACE TM0198

• NACE RP0775

28



NACE TM0177 Testing Methods

Test method NACE A NACE B NACE C NACE D

Stressapplication

Tensile %of SMYS

3 pointsbent

C ring Wedge

Duration 720 hours 360 hours

ResultsRupture /

No ruptureSc

Rupture /No rupture

StressIntensityFactor

29



Considerations for Testing

Oxygen exclusion

• H2S and oxygen can react to alter the test environment

• Simulated downhole environments exclude oxygen to be representative of actual conditions

Corrosion of test specimen and effect on solution

• Especially corrosion of carbon & low alloy steels can effect the test environment and reduce severity

• Guidelines for solution volume-to-specimen surface area

Saturation of H2S test gas

• Rapid purge of gas for one hour or less

• Additional purge duration may be necessary for large vessels

Elevated temperature stress relaxation

• All specimen rely on fixture to apply stress to specimen

• At significantly elevated temperatures (>300°F) the fixturing may thermally expand and relax the applied load

Specimen surface finish

• Surface finish can effect test results

30



Connection Selection

31



Connection Selection

Connection shall meet the well loads and be qualified accordingly

• Load points and protocol to be agreed on

• Consider Temperature effect on yield and tensile properties

CRA specifics to be considered compared to Carbon Steel

• CRA tend to increase galling risk

• Anisotropic material behaviour of CRA (does not apply to martensitic steels)

32



Connection Qualification Protocol

In January 2017, API agreed and published the 4th edition of API RP 5C5

API RP 5C5 4th edition (Jan.2017) is now the latest standard for Premium Connection testing

33

ISO13679:2002

ISO113679:FDIS2011

API RP 5C5 2017

NAM TEO/3

CAL I CAL II CAL III CAL IV

CAL I CAL I-E CAL II CAL III-A CAL III / IV

CAL I (gas) CAL II CAL III CAL IV

VAM® TOP tubingVAM® TOP HCVAM® TOP HT

VAM® 21VAM® HTTC



Anisotropic Material Behaviour – Performance Impact

34

• Reduction in compression rating

• Smaller Envelope in Q2

TensionCompression

Internal Pressure

ExternalPressure

Q1Q2

Q3 Q4

Connection VME (95% AYS)

Pipe VME



Reduce Galling Risk

Operational savings in the

yard

Operational savings on the rig

- Running time reduction

Improved safety and reduced

environmental impact

Eliminates equipment

plugging issues and formation

damage

Dope Free Solution by VAM®

35



Conclusions

Operator often reluctant to buy CRA due to higher initial purchasing cost• Consider life of the well and TCO as well as risk of failure and associated safety hazard

Differentiate between Metal Loss Corrosion and Cracking

• No official standard to guide metallurgy selection to avoid meal loss corrosion• Only one official standard to support SSC and SCC decision making process

Complex process with a lot of uncertainties

• Consider complete well life and potential scenarios

Chrome and CRA resist metal loss corrosion but show varying performance of SSC and SCC• Verify suitability of product through material qualification / ask your supplier for corrosion test

data

Cold worked CRA mechanical performances are different than martensitic stainless and carbon steels• Latest API5C5 shows limitation in Q2 due to anisotropic behavior

36



page

CRA Tubulars and Well Integrity Technical Symposium

September 25, 2017

37

THANK YOU

franks cra symposium vallourec presentationfranksinternational.com/wp-content/uploads/may...api 5cra...

Documents