A Typical Material Selection Report

CONTENTS

1. INTRODUCTION...............................................................................................................1

1.1 Objective of Document......................................................................................................1

1.2 Scope................................................................................................................................ 1

1.3 Abbreviations..................................................................................................................... 2

1.4 Units of Measurement.......................................................................................................3

1.5 Codes and Standards........................................................................................................4

2. SUMMARY........................................................................................................................ 5

3. DESIGN DATA................................................................................................................11

3.1 Sources of Data...............................................................................................................11

3.2 Design Life...................................................................................................................... 11

3.3 Fluid Compositions..........................................................................................................11

3.3.1 Oil Composition..................................................................................................11

3.3.2 Gas Lift Composition..........................................................................................11

3.3.3 Produced Water Analysis....................................................................................12

3.4 Pressures and Temperatures..........................................................................................13

3.5 Availability....................................................................................................................... 14

3.6 Corrosion Model Cases...................................................................................................14

3.6.1 Gas Lift (3”) Pipeline...........................................................................................14

3.6.2 Gas Lift (4”) Pipeline...........................................................................................16

3.6.3 Gas Lift Header and Flowlines............................................................................18

3.6.4 Production Flowlines (6 off) and Test Headers...................................................19

3.6.5 Production Headers............................................................................................21

3.6.6 Export Pipelines (Seamless Linepipe, Grade 415 MPa).....................................23

3.6.7 Export Pipelines (HFI Linepipe, Grade 415MPa)................................................25

3.6.8 Produced Water Effect Modelling.......................................................................26

4. METHODOLOGY............................................................................................................28

4.1 Potential for Corrosion.....................................................................................................28

4.1.1 Corrosion Mechanisms and Considerations.......................................................28

4.1.2 CO2 Corrosion.....................................................................................................28

4.1.3 Top of Line Corrosion.........................................................................................29

4.1.4 Sulphide Stress Corrosion Cracking...................................................................29

4.1.5 Hydrogen Induced Stress Cracking....................................................................30

4.1.6 Hydrogen Embrittlement.....................................................................................30

4.1.7 Chloride Stress Corrosion Cracking....................................................................31

4.1.8 Erosion................................................................................................................32

4.1.9 Subsea External Corrosion.................................................................................32

4.1.10 Topside Atmospheric Corrosion..........................................................................32

4.1.11 Corrosion of the Line Pipe During Transportation...............................................33

4.1.12 Microbially Induced Corrosion.............................................................................33

4.1.13 Under Deposit Corrosion....................................................................................34

4.1.14 Galvanic Corrosion.............................................................................................34

4.1.15 Corrosion in Dead Legs and Stagnant Zones.....................................................35

4.2 Selection of a Corrosion Model.......................................................................................35

4.2.1 General...............................................................................................................35

4.2.2 Limitations of the Corrosion Model.....................................................................37

4.2.3 Prediction of Top of Line Corrosion....................................................................37

4.3 Mechanical Material Selection.........................................................................................38

4.3.1 Brittle Facture and Embrittlement.......................................................................38

4.3.2 Fatigue................................................................................................................39

5. CORROSIVITY ASSESSMENT AND CORROSION MITIGATION.................................40

5.1 Corrosivity Assessment Results......................................................................................40

5.2 Corrosion Inhibition Philosophy.......................................................................................43

5.2.1 General...............................................................................................................43

5.2.2 Chemical Performance.......................................................................................45

5.2.3 Chemical Injection System Design.....................................................................45

5.2.4 Operation and Reliability.....................................................................................48

6. PIGGING REQUIREMENTS...........................................................................................49

6.1 Operational Pigging.........................................................................................................49

6.2 Intelligent Inspection Pigging...........................................................................................50

6.2.1 General...............................................................................................................50

6.2.2 Intelligent Pigging Requirements........................................................................50

6.2.3 Pigging Frequency..............................................................................................50

7. SPECIFIC MATERIAL APPLICATIONS..........................................................................52

7.1 Use of Corrosion Resistant Alloys...................................................................................52

7.1.1 Grade 304/304L Austenitic Stainless Steels.......................................................52

7.1.2 Grade 316/316L Austenitic Stainless Steels.......................................................52

7.1.3 6Mo Super-Austenitic 254 SMO (UNS S31254).................................................54

7.1.4 Duplex Stainless Steel........................................................................................54

7.1.5 Selection of CRA for Pipe and Vessels...............................................................56

7.2 Use of Glass Reinforced Plastic (GRP)...........................................................................56

7.2.1 Piping Systems...................................................................................................56

7.2.2 GRP Tanks and Vessels.....................................................................................57

7.3 Selection of Elastomeric Seals........................................................................................61

7.4 Bolting Materials..............................................................................................................61

8. MATERIALS SELECTION –AND XX PLATFORM..........................................................63

8.1 Wellhead Equipment (Including Chokes and Flowline Isolation Valves)..........................63

8.2 Process Equipment.........................................................................................................63

8.2.1 General...............................................................................................................63

8.2.2 Gas Lift First Valve On (FVO), Gas Lift Header and Flowlines...........................64

8.2.3 Production Flowlines...........................................................................................64

8.2.4 Test Header........................................................................................................67

8.2.5 Production Header, Pig Launcher and Last Valve Off........................................69

8.3 Utility Equipment.............................................................................................................71

8.3.1 Fuel Gas Systems..............................................................................................71

8.3.2 Open Drains........................................................................................................72

8.3.3 Vent and Closed Drains and Vent Scrubber.......................................................73

8.3.4 Chemical Injection Package................................................................................74

8.3.5 CCVT Power Generation....................................................................................74

8.3.6 Hydraulic Piping Systems...................................................................................74

8.3.7 Instrumentation...................................................................................................74

8.3.8 Wash Down Water System.................................................................................77

9. MATERIAL SELECTION - PIPELINES............................................................................78

9.1 Materials and Corrosion Allowance.................................................................................78

9.1.1 Linepipe Manufacturing Processes.....................................................................78

9.1.2 Pipelines & Risers - Export.................................................................................79

9.1.3 Pipelines & Risers – Gas Lift..............................................................................80

9.1.4 Pipeline Fittings..................................................................................................81

9.1.5 Chemical Injection line (Flat-Pack).....................................................................81

9.1.6 Clamping and Strapping materials......................................................................81

9.2 Coating Systems.............................................................................................................82

9.2.1 Pipeline Anti-Corrosion Coating System.............................................................82

9.2.2 Riser Coating Systems.......................................................................................82

9.3 Cathodic Protection.........................................................................................................83

9.3.1 Sacrificial Anode System....................................................................................83

9.3.2 Corrosion Protection System Isolation – MIJs....................................................83

10. ASSET INTEGRITY MANAGEMENT..............................................................................85

10.1 General Philosophy.....................................................................................................85

10.2 Recommended Routine Maintenance Activities..........................................................85

10.3 Possible Unplanned Activities.....................................................................................86

11. CORROSION MONITORING..........................................................................................87

11.1 Aim.............................................................................................................................. 87

11.2 Monitoring and Testing Facilities.................................................................................87

11.3 Monitoring Methods....................................................................................................88

11.4 Corrosion Monitoring Techniques and Equipment......................................................89

11.4.1 Electrical Resistance (ER) Probes......................................................................89

11.4.2 Coupons.............................................................................................................89

11.4.3 Bacterial Monitoring and Bioprobes....................................................................90

11.5 Process Stream Monitoring.........................................................................................91

11.6 Corrosion Monitoring Instrumentation.........................................................................91

12. CORROSION DATA MANAGEMENT AND ASSESSMENT...........................................92

12.1 General Requirements................................................................................................92

12.2 Data Collection Frequency..........................................................................................92

12.3 Data Storage...............................................................................................................92

12.4 Data Assessment........................................................................................................92

12.5 Corrosion Reporting....................................................................................................92

13. CORROSION PERFORMANCE TRACKING..................................................................94

13.1 General Requirements................................................................................................94

13.2 Key Performance Indicators........................................................................................94

13.3 Corrective and Preventative Action.............................................................................95

14. References...................................................................................................................... 96

APPENDIX 1 – TEMPERATURE AND PRESSURE PROFILES (2 PAGES)

APPENDIX 2– CORROSION MODEL RESULTS (2 X A3 PAGES)

APPENDIX 3– LIST OF UNINHIBITED EVENTS (2 PAGES)

APPENDIX 4– CHEMICAL DATASHEETS (5 PAGES)

APPENDIX 5– LABORATORY TEST OF HFW SEAM CORROSION SUSCEPTIBILITY (1 PAGE)

1. INTRODUCTION

1.1 Objective of Document

1.2 Scope

The scope of this document is to select suitable materials for the construction of platform topside

equipment, riser, production and the gas lift pipelines and risers; and, chemical injection tubing (Flat

Pack) based on the available fluid and process data.

Scope of the subsea component of this study also includes the review and recommendation of:

Anticorrosion coating for the riser and pipeline submerged zone;

Riser splashzone;

Riser atmospheric zone;

Anode material selection;

Piping flanges and fittings;

Clamping and strapping materials.

Scope of the platform topside component of this study also includes the review and recommendation

of:

Selection of materials for process equipment and piping;

Selection of materials for utility and ancillary topside equipment;

Specification of corrosion allowances to be applied across all equipment;

Specification of materials for bolting and polymeric seals.

This document recommends a Corrosion Management Plan to manage the corrosion of the assets

within the bounds described in this document.

1.3 Abbreviations

The following abbreviations have been used in this document:

CA Corrosion allowance

CO2 Carbon dioxide.

CP Cathodic protection.

CR Corrosion rate

CSCC Chloride Stress Corrosion Cracking

EN Electrochemical noise

ER Electro-resistance

H2S Hydrogen sulphide.

Page 1

HAZ Heat Affected Zone.

HDPE High Density Polyethylene

HE Hydrogen embrittlement.

HISC Hydrogen Induced Stress Cracking

ID Inside diameter.

IP Intelligent pig

KP Kilometre point.

LPR Linear polar resistance

NORSOK Norwegian Technical Standards for Petroleum Operations

OD Outside diameter.

pCO2 Partial pressure of CO2.

pH2S Partial pressure of H2S.

ppm parts per million

PVDF Polyvinyldene Fluoride

ROV Remotely operated vehicle

SCNF Strain concentration factor

SSCC Sulphide Stress Corrosion Cracking

TOLC Top of line corrosion.

TSA Thermal Sprayed Aluminium

UDC Under Deposit Corrosion

WT Wall thickness.

1.4 Units of Measurement

The following units of measurement have been used in this document:

C temperature, degrees Celsius.

bar system pressure, bar.

g/l solids concentration, grams per litre.

g/m2s condensation rate, grams per sq meter per second.

HV hardness, Vickers.

km linear measure, kilometres.

kPag gauge pressure, kiloPascals.

m3 volume, cubic metres.

mg/l solids concentration, milligrams/litre.

Page 2

mm linear measure, millimetres.

mm/year corrosion rate, millimetres per year.

MMscfd gas flowrate, million million standard cubic feet per day.

MPa pressure or stress, megaPascals.

MSm3/day gas flowrate, million standard cubic metres per day.

Pa fluid wall shear, Pascal.

Sm3/day liquids flowrate, standard cubic metres per day.

1.5 Codes and Standards

The following Codes and Standards have been used in this document:

API 5L Specification for Linepipe

API 6A Specification for Wellhead and Christmas Tree Equipment

ASTM A193

Standard Specification for Alloy-Steel and Stainless Steel Bolting Materials

for High Temperature or High Pressure Service and Other Special Purpose

Applications

ASTM A194Standard Specification for Carbon and Alloy Steel Nuts for Bolts for High

Pressure or High Temperature Service, or Both

ASTM A320Standard Specification for Alloy-Steel and Stainless Steel Bolting Materials

for Low-Temperature Service

ASTM A694

Standard Specification for Carbon and Alloy Steel Forgings for Pipe

Flanges, Fittings, Valves, and Parts for High-Pressure Transmission

Service

ASTM G4 Conducting Corrosion Coupon Tests in Plant Equipment

ASTM G31 Laboratory Immersion Corrosion Testing of Metals

ASTM G46 Practice for Examination and Evaluation of Pitting Corrosion

ASTM G81 Practice for Preparation of Metallurgical Specimens

DNV OS-F101 Offshore Standard - Submarine Pipeline Systems 2000

NACE MR-0175

(now also ISO 15156)Sulfide Stress Cracking Resistant Metallic Materials for Oilfield Equipment

NACE RP 0775Preparation and Installation of Corrosion Coupons and Interpretation of

Test Data in Oilfield Operations

Page 3

2. SUMMARY

A summary of the materials selected, as part of this study, is included in Table 2-1.

Table 2-1 Summary of materials xx platforms and pipelines selected as part of this study.

Equipment Name Recommended Material Alternatives

Wellheads API 6A Material Class FF-13.8kPa

Stainless Steel (XX)

API 6A Material Class FF-14.5kPa


Choke Valves API 6A Material Class FF-13.8kPa


API 6A Material Class FF-14.5kPa


Gas Lift Pipeline DNV OS F101 Grade 450 ISPD (coiled line

pipe) + 3mm C.A.

DNV OS F101 SML Grade 415

ISD + 3mm C.A.

Gas Lift Riser DNV OS F101 SML Grade 415 ISD + 3mm

C.A. External splash zone protection using

polychloroprene rubber 12mm thick.

Gas Lift First Valve

On

Carbon Steel Body with 316L trim

Gas Lift Pig

Receiver

Carbon Steel + 3.0mm C.A (Sour)

Gas Lift Header Carbon Steel + 3.0mm C.A (Sour)

Gas Lift Flowlines Carbon Steel + 3.0mm C.A (Sour)

Production Flowlines 22Cr Duplex Stainless Steel. External

coating to be 180μm thick Thermally

Sprayed Aluminium and sealed with an

Alkyd Silicone.

1: Carbon Steel + (7mm XX,

6mm XX) C.A (Sour)

externally coated with

180μm Thermally Sprayed

Aluminium and sealed using

an Alkyd Silicone topcoat.

2: Carbon Steel + 3mm C.A

(Sour) externally coated with

180μm Thermally Sprayed

Aluminium and sealed using

an Alkyd Silicone top coat. -

Flowline Isolation

Valves

Solid 22 Cr Duplex valve body Carbon steel body with Inconel

625 overlay for wetted parts.

Production Header Carbon Steel + 6mm C.A (Sour) externally

coated with 180μm Thermally Sprayed

Carbon Steel + 3mm C.A (Sour)

externally coated with 180μm

Page 4


Aluminium and sealed using an Alkyd

Silicone topcoat.

Thermally Sprayed Aluminium

and sealed using an Alkyd

Silicone top coat -

Test Header Carbon Steel + 7mm C.A (Sour) externally

coated with 180μm Thermally Sprayed

Aluminium and sealed using an Alkyd

Silicone topcoat.

Carbon Steel + 3mm C.A (Sour)

externally coated with 180μm

Thermally Sprayed Aluminium

and sealed using an Alkyd

Silicone top coat. -

Export Pig Launcher Carbon Steel + 3.0mm C.A (Sour)

Export Last Valve

On

Carbon steel body with Inconel 625 overlay

for wetted parts.

Export Pipeline DNV OS F101 SML Grade 415 ISD + 6mm

C.A. (i.e. Seamless, X60 strength linepipe

for sour service and improved dimensional

control).

1: DNV OS F101 SML Grade

415 ISD + 3mm C.A. (i.e.

Seamless, X60 strength

linepipe for sour service and

improved dimensional

control –

2: DNV OS F101 HFW Grade

415 ISD + 6mm C.A. (i.e.

High Frequency Welded,

X60 strength linepipe for

sour service and improved

dimensional control)1.

Export Pipeline Riser DNV OS F101 SML Grade 415 ISD + 6mm


CS sleeve 12mm with Monel 400 cladding

(3mm)


ISD + 3mm C.A. External

splash zone protection using

CS sleeve 12mm with Monel

400 cladding (3mm) -

Export Pipeline Riser

at XX

DNV OS F101 SML Grade 415 ISD + 6mm


CS sleeve 12mm with Monel 400 cladding

(3mm)


ISD + 3mm C.A. - streams (due

to lower arrival temperatures <

80ºC) External splash zone

protection using

polychloroprene rubber 12mm

thick.

Fuel Gas System Carbon Steel + 3mm (Sour)

Fuel Gas System

Valves

Carbon Steel with 316L trim

Open Drain Lines GRP-C Carbon Steel + 6mm C.A

1

Page 5


Open Drain Valves Nickel Aluminium Bronze Rubber lined carbon steel

Open Drain Vessel

(Sump)

UNS S32205 Duplex Stainless Steel If a larger diameter vessel can

be accommodated. Then a

heavy wall thickness carbon

steel drain vessel, with

removable weirs, and internally

coated with a Glass Flake

epoxy will be acceptable.

Open Drain Pump Carbon Steel with Stainless Steel impeller

Vent and Closed

Drain Lines

Carbon Steel + 3mm C.A

Closed Drain Valves Carbon steel with 316L trim

Vent Scrubber

Vessel

Carbon steel with internal glass flake epoxy

coating or Belzona 1391 coating

Vent Scrubber Pump Carbon Steel with Stainless Steel impeller

Hydraulic Piping ASTM A269 Grade 316L with min 2.5% Mo If T>60°C

25 Cr super duplex (UNS

S32750)

or

Hastelloy C276 (UNS N10276)

Instrument Tubing ASTM A269 Grade 316L with min 2.5% Mo If T>60°C

25 Cr super duplex (UNS

S32750)

or

Hastelloy C276 (UNS N10276)

Instrumentation Refer to Table 8-12 on page 60

Wash Down Water

Tank and Piping

GRP-C with 316L tank fittings Polypropylene

Wash Down System

Valves

Nickel Aluminium Bronze Polypropylene

or;

GRP

The current design basis does not provide for permanent gas lift launchers and receivers; this

arrangement is satisfactory if corrosion inhibition is continuously injected into the gas lift pipelines. If

the corrosion inhibition is to be only injected when the gas lift gas goes off dew point (wet gas

operation) then it is recommended that permanent launchers and receivers are installed to permit

periodic sweeping of free water from the gas lift pipeline and running batch corrosion inhibitor. The

Page 6

corrosion allowance for the gas lift pipelines assume that the pipeline will be operated for no more

than 60 days per year with off-specification gas. Operation of the pipeline with wet gas for periods

longer than 60 days per annum will result in corrosion damage greater than 3.0mm over the 20-year

design life.

Section 8 and 9 present further detail on the topside and pipeline material selection.

It is also noted that as the basis of the pipeline design is to be DnV OS F101 then it is a requirement

to produce a Fracture Control Plan to define the minimum material property requirements (eg Charpy

values) for the line pipe specification.

Page 7

3. DESIGN DATA

3.1 Sources of Data

The following data was used to build the corrosivity models and to review corrosion reliability models

and total corrosion damage / corrosion allowance calculations. Flowrates and temperatures have

been obtained from the Design Basis [Ref 1]. Temperature and pressure profiles were obtained from

the “base case” temperature-pressure profiles provided in Appendix 1 of this report. Pipeline sizing for

the gas lift and export pipelines were obtained for Grade 415MPa linepipe from calculation sheet

3.2 Design Life

Design life is 20 years. Production profiles and hence corrosion rates have been modelled for the

following periods over the design life:

Years 1 and 2 (2008-2010);

Years 3 to 7 (2011-2015); and

Years 8 to 20 (2016-2028).

3.3 Fluid Compositions

3.3.1 Oil Composition

A basis composition of the produced fluids has been assumed in accordance with Table 6.3 in the

Design Basis [Ref 1]. The critical components are as follows:

CO2 Content = 5 - 10 wt%, assumed 10% for corrosion models.

H2S Content = 20 - 1000ppm.

3.3.2 Gas Lift Composition

Gas lift composition is in accordance with Design Basis Section 5.1 [Ref 1] and the critical

components are as follows:

CO2 Content = 8 wt%;

H2S Content = 1000ppm.

3.3.3 Produced Water Analysis

A produced water analysis based on PF filed data is presented Design Basis]. The critical

components for corrosion modelling and materials selection are as follows:

Bicarbonate = 1690.82 mg/L and 1726.54mg/L, assumed applicable for XX and XX platforms

respectively for corrosion modelling purposes;

Ionic Strength = 50 g/L

Density = 1.0524 g/L, assume 1050 kg/m3, which is the NORSOK model limit and model found

to be tolerant of large changes in density without effect on the corrosion rate, so model limit is

not significant.

Page 8

Chloride content = 4212.34 mg/L to 4650.43mg/L, taken as 4500mg/L for materials selection

purposes.

Table 3-2 Produced Water Analysis

ANALYSIS NO. 2/06293 2/06303

Taken from (source) PB # 7 PG # 3

Lithium (Li) mg/l 8.13 9.89

Boron (B) mg/l 59.98 70.38

Silicon (Si) mg/l 15.07 15.27

Aluminium (Al) mg/l 0.060 0.11

Phosphorous (P) N.D. N.D.

Zinc (Zn) N.D. N.D.

Lead (Pb) N.D. N.D.

Calcium (Ca) mg/l 64.40 50.29

Magnesium (Mg) mg/l 12.22 21.17

Barium (Ba) mg/l 0.24 0.24

Strontium (Sr) mg/l 8.53 6.50

Total Iron mg/l 0.062 0.31

Sodium (Na) mg/l 4031 4023

Potassium (K) mg/l 67.13 124

Carbonate (mg/l) 46.85 58.56

Bicarbonate (mg/l) 1690.82 1726.54

Chloride (Cl) mg/l 4212.34 4650.43

Density (gm/l) 1.0524 1.0532

Resistivity (ohms) 0.0737 0.066

pH 7.78 7.59

Total Dissolved Solids 10072.0 11416.0

Dissolved CO2 (mg/l) ** 34.35 42.94

Dissolved H2S mg/l* N.D. N.D.

Determination of residual phosphates

(Test method for residual phosphate = Champion 2121) <0.1 <0.1

Organic Acid

Formic acid content N.D. N.D.

Page 9

Acetic acid content 0.23 mg/l 0.25 mg/l

Propionic acid content N.D. N.D.

Butyric acid content N.D. N.D.

Note: N.D. = not detected, detection limit 0.010 mg/l, detection limit 0.1 mg/l for * and detection limit

1.0 mg/l for **

3.4 Pressures and Temperatures

Temperature and pressure profiles for the pipelines were obtained from the “base case” temperature-

pressure profiles provided in Appendix 1 of this report. The following pressures and temperatures

were used for the topsides and wellhead assessments

1_STHP = 2000 psig

2_STHP = 2100psig

3_FTHP = 280psig

4_FTHP = 280 psig

separator pressure = 230 psig

Maximum FTHT and topside temperatures = 110°C

3.5 Availability

Equipment availability is stated in the Hydra Design Basis as 98% for the topsides facilities and

therefore a utilities and process equipment availability of 99% is required. The use of 98% availability

has been adopted for the corrosion inhibition system. The facility requirement to achieve a 98%

corrosion inhibition system availability is discussed in Section 5.2.3.

3.6 Corrosion Model Cases

3.6.1 Gas Lift (3”) Pipeline

xx Platform 2008 to 2010 2011- 2015 2016 & Beyond

Pipe Diameter 88.9mm

Pipe Wall

Thickness

5.1mm

Inside Diameter 78.7mm

Wt% CO2 8.0 8.0 8.0

Temperature –

Inlet

40°C 40°C 40°C

Temperature -

Outlet

27°C 27°C 27°C

Page 10

Gas / Liquid /

Multiphase

Dehydrated gas,

possibility of intermittent

wet gas.

Dehydrated gas,


wet gas.

Dehydrated gas,


wet gas.

Pressure 1250 psig 1250 psig 1250 psig

Gas Flowrate 0.17 MSm3/d 0.17 MSm3/d 0.17 MSm3/d

Oil Rate 0 0 0

Water Rate 0 0 0

Liquids Flowrate1 0.01 Sm3/day 0.01 Sm3/day 0.01 Sm3/day

Water Cut 0% 0% 0%

Inhibitor

Efficiency2

95% 95% 95%



Pipe Wall

Thickness

5.1mm


Wt% CO2 8.0 8.0 8.0

Temperature –

Inlet

40°C 40°C 40°C

Temperature –

Outlet

27°C 27°C 27°C

Gas / Liquid /

Multiphase

Dehydrated gas,


wet gas.

Dehydrated gas,


wet gas.

Dehydrated gas,


wet gas.



Oil Rate 0 0 0

Water Rate 0 0 0


Water Cut 0 0 0

Inhibitor

Efficiency2

95% 95% 95%

Notes:

Page 11

1. For NORSOK M506, liquids flowrate must be greater than 0. Assumed 0.01 Sm3/day for

worst-case considerations. Gas lift gas will be dehydrated on the xx platform and may from

time to time be exported over the dew point specification for the gas.

2. Inhibitor efficiency assumed to be lower than is typical for the Champion Technologies

Cronox inhibitors used throughout the xx and xx fields as continuous inhibition is not

anticipated for this line. Inhibition should be slugged dosed periodically and continuously

injected only when it is exported from xx over the gas lift dew point specification.

3.6.2 Gas Lift (4”) Pipeline



Pipe Wall

Thickness

6.4mm


Wt% CO2 8.0 8.0 8.0

Temperature –

Inlet

40°C 40°C 40°C

Temperature -

Outlet

27°C 27°C 27°C

Gas / Liquid /

Multiphase

Dehydrated gas,


wet gas.

Dehydrated gas,


wet gas.

Dehydrated gas,


wet gas.



Oil Rate 0 0 0

Water Rate 0 0 0


Water Cut 0% 0% 0%

Inhibitor

Efficiency2

95% 95% 95%



Pipe Wall

Thickness

6.4mm


Wt% CO2 8.0 8.0 8.0

Page 12

Temperature –

Inlet

40°C 40°C 40°C

Temperature –

Outlet

27°C 27°C 27°C

Gas / Liquid /

Multiphase

Dehydrated gas,


wet gas.

Dehydrated gas,


wet gas.

Dehydrated gas,


wet gas.



Oil Rate 0 0 0

Water Rate 0 0 0


Water Cut 0 0 0

Inhibitor

Efficiency2

95% 95% 95%

Notes:


worst-case considerations. Gas lift gas will be dehydrated on the xx platform and may from






3.6.3 Gas Lift Header and Flowlines



Pipe Wall

Thickness

5.1mm


Wt% CO2 8.0 8.0 8.0

Temperature –

Inlet

27°C 27°C 27°C

Temperature -

Outlet

- - -

Page 13

Gas / Liquid /

Multiphase

Dehydrated gas,


wet gas.

Dehydrated gas,


wet gas.

Dehydrated gas,


wet gas.


Gas Flowrate 0.17 Sm3/d 0.17 Sm3/d 0.17 Sm3/d

Oil Rate 0 0 0

Water Rate 0 0 0


Water Cut 0% 0% 0%

Inhibitor

Efficiency2

95% 95% 95%



Pipe Wall

Thickness

5.1mm


Wt% CO2 8.0 8.0 8.0

Temperature –

Inlet

27°C 27°C 27°C

Temperature –

Outlet

- - -

Gas / Liquid /

Multiphase

Dehydrated gas,


wet gas.

Dehydrated gas,


wet gas.

Dehydrated gas,


wet gas.


Gas Flowrate 0.17 Sm3/d 0.17 Sm3/d 0.17 Sm3/d

Oil Rate 0 0 0

Water Rate 0 0 0


Water Cut 0 0 0

Inhibitor

Efficiency2

95% 95% 95%

Notes:

Page 14


worst-case considerations. Gas lift gas will be dehydrated on the XX platform and may from






3.6.4 Production Flowlines (6 off) and Test Headers



Pipe Wall

Thickness

10.97mm


Wt% CO2 10% 10% 10%

Temperature –

Inlet

110°C 110°C 110°C

Temperature -

Outlet

110°C 110°C 110°C

Gas / Liquid /

Multiphase

Multiphase Multiphase Multiphase

Pressure 19.4 Bar 19.4 Bar 19.4 Bar

Gas Flowrate 0.1 MSm3/day 0.13 MSm3/day 0.12 MSm3/day

Oil Flowrate 954 Sm3/day 795 Sm3/day 477 Sm3/day

Water Flowrate 1272 Sm3/day 4769.6 Sm3/day 3179.7 Sm3/day

Liquids Flowrate1 2226 Sm3/day 5564.6 Sm3/day 3656.7 Sm3/day

Water Cut Note 2 Note 2 Note 2

Inhibitor

Efficiency3

95% 95% 95%



Pipe Wall

Thickness

10.97mm


Wt% CO2 10% 10% 10%

Page 15

Temperature –

Inlet

110°C 110°C 110°C

Temperature -

Outlet

110°C 110°C 110°C

Gas / Liquid /

Multiphase





Water Flowrate 477 Sm3/day 2385 Sm3/day 1272 Sm3/day

Liquids Flowrate1 954 Sm3/day 2703 Sm3/day 1431 Sm3/day


Inhibitor

Efficiency3

95% 95% 95%

Notes

1. Liquids flowrate is divided evenly over 6 flowlines, i.e. 954Sm3/day divided by 6 =

159Sm3/day.

2. Water cut provided in the design basis as 10-90%. A review of the effect on water cut on the

corrosion model was performed and found to have insignificant effect. Assumed to be 50%.

3. Inhibitor efficiency assumed to be 95% (also modelled for 90% and 95%) as mixing will still be

occurring from the choke valves and may not provide complete coverage for the first 5 to 10

diameters of the flowline.

3.6.5 Production Headers

xx Platform Up to 2010 2011- 2015 2016 & Beyond


Pipe Wall

Thickness

17.48mm


Wt% CO2 10% 10% 10%

Temperature –

Inlet

110°C 110°C 110°C

Temperature -

Outlet

110°C 110°C 110°C

Gas / Liquid /

Multiphase


Page 16





Liquids Flowrate 2226 Sm3/day 5564.6 Sm3/day 3656.7 Sm3/day


Inhibitor

Efficiency(3)

95% 95% 95%



Pipe Wall

Thickness

17.48mm


Wt% CO2 10% 10% 10%

Temperature –

Inlet

110°C 110°C 110°C

Temperature -

Outlet

110°C 110°C 110°C

Gas / Liquid /

Multiphase








Inhibitor

Efficiency3

95% 95% 95%

Notes


159Sm3/day.



3. Inhibitor efficiency assumed to be 95% - refer to section 5.2.1.

Page 17

3.6.6 Export Pipelines (Seamless Linepipe, Grade 415 MPa)

xx Platform Up to 2010 2011- 2015 2016 & Beyond


Pipe Wall

Thickness

16.4mm


Wt% CO2 10% 10% 10%

Temperature –

Inlet

110°C 110°C 110°C

Temperature -

Outlet

58°C 72°C 76°C

Gas / Liquid /

Multiphase






Liquids Flowrate1 2226 Sm3/day 5564.6 Sm3/day 3656.7 Sm3/day


Inhibitor

Efficiency3

99% 99% 99%



Pipe Wall

Thickness

16.4mm


Wt% CO2 10% 10% 10%

Temperature –

Inlet

110°C 110°C 110°C

Temperature -

Outlet

27°C 38°C 34°C

Gas / Liquid /

Multiphase




Page 18





Inhibitor

Efficiency3

99% 99% 99%

Notes:


159Sm3/day.



3. Inhibitor efficiency assumed to be 99% as mixing will be performed upstream of the choke

valves and flow will be annular / slug flow that provides full pipe wetting.

3.6.7 Export Pipelines (HFI Linepipe, Grade 415MPa)

See Note 1 for this service

xxPlatform Up to 2010 2011- 2015 2016 & Beyond


Pipe Wall

Thickness

13.0mm


Wt% CO2 10% 10% 10%

Temperature –

Inlet

110°C 110°C 110°C

Temperature -

Outlet

58°C 72°C 76°C

Gas / Liquid /

Multiphase






Liquids Flowrate 2226 Sm3/day 5564.6 Sm3/day 3656.7 Sm3/day

Water Cut Notes 3 Note 3 Note 3

Page 19

Inhibitor

Efficiency

99% 99% 99%

xxx Platform 2008 to 2010 2011- 2015 2016 & Beyond


Pipe Wall

Thickness

13.0mm


Wt% CO2 10% 10% 10%

Temperature –

Inlet

110°C 110°C 110°C

Temperature -

Outlet

27°C 38°C 34°C

Gas / Liquid /

Multiphase







Water Cut Notes 3 Note 3 Note 3

Inhibitor

Efficiency4

99% 99% 99%

Notes:

1. Modelled only once to review effect of larger ID on wall shear. Effect found to be negligible.


159Sm3/day.



4. Inhibitor efficiency assumed to be 99% as mixing will be performed upstream of the choke

valves and flow will be annular / slug flow that provides full pipe wetting.

3.6.8 Produced Water Effect Modelling

The effect of produced water chemistry can be profound on the corrosion rate due to the pH buffering

as a result of the bicarbonate content of the produced water. The effect of produced water chemistry

has been investigated as part of this corrosion study. Initial modelling described by the scenarios

above assumed only water of condensation is present in the produced liquids and this results in low

pH predictions. Separate models have been run for all the production side assets with produced

Page 20

water, which is closer to the true production scenario and less conservative. The NORSOK M506

model uses bicarbonate concentration and ionic strength to characterise the produced water

chemistry. A bicarbonate concentration of 1691 mg/l for xx and 1726 mg/l for xxhas been used for the

models and an ionic strength of 50 g/l, which is a typical value for produced water. To further

characterise the produced water, an increase in density has been included in the corrosion model,

density is 1052 kg/m3 for xxand xx, but was limited to 1050 kg/m3, the models water density limit.

The produced water chemistry described in Section 3.3.3 is typical of the xx fields and was taken from

the xx and xx well analysis. To understand the sensitivity of the corrosion model to variations in the

produced water chemistry additional models have been run to show the effect on the xx production

export pipeline at 90% bicarbonate level and 75% bicarbonate level.

Page 21

4. METHODOLOGY

4.1 Potential for Corrosion

4.1.1 Corrosion Mechanisms and Considerations

The following sections discuss the corrosion mechanisms that could be experienced during the life of

the xx field. The factors that contribute to these mechanisms are highlighted along with an

assessment of the possibility of the corrosion mechanism occurring and what can be done to mitigate

the corrosion risk.

4.1.2 CO2 Corrosion

The xx production fluids contain approximately 8 Wt% CO2 [Ref 1] along with water of condensation

and later in the field life, produced water. The reaction of CO2 with water in the pipeline can result in

the formation of carbonic and acetic acid. The carbonic and acetic acid reduces the pH of the

production stream and at collection points (i.e. topographic low points, dead legs and stagnant zones

or at miscibility gaps) the acidified solution can cause general corrosion, pitting corrosion and mesa-

type corrosion of steels.

Localised corrosion may take many forms, from pitting to mesa type attack, where corrosion appears

as large, flat-bottomed localised areas of damage. Pitting may occur over the full range of operating

temperatures under stagnant to moderate flow conditions. Pitting rates are a function of temperature,

pressure, flow velocity and characteristics and CO2 concentration, with the propensity for pitting highly

dependent on the chemistry and surface finish of the steel. Pitting may arise close to the dew point

temperature, and can be associated with water of condensation and is often referred to as Top of Line

Corrosion (TOLC), refer to Section 4.1.3. There is no real way of predicting the occurrence and extent

of pitting as opposed to general corrosion mechanisms for steel.

Mesa type attack is a form of localised CO2 corrosion that occurs under moderate flow conditions

where carbonate scales may form but are not strongly stable. This form of attack results from

localised spalling of the carbonate scale, exposing the underlying bare metal surface that then

corrodes. The scale, when formed, may experience high intrinsic stresses within the scale film,

resulting in repeated spalling of the same area. This type of attack generally occurs at 60°C to 100°C,

as the scale formed tends to be less adhesive than those formed at temperatures greater than 100°C.

Mesa attack may also result from self-sustaining galvanic reactions between passive and active

corrosion films.

Flow induced localised corrosion in CO2 corrosion systems starts from corrosion pits, welds or other

surface discontinuities where localised turbulence may be created. The localised turbulence, in

addition with stresses contained within the growing scales, may result in the destruction of existing

scales, and prevent the reformation of further protective scales. This type of corrosion is typically

observed as parallel grooves extending in the flow direction. Flow induced localised corrosion may

occur in systems with relatively high flowing velocities.

The CO2 corrosion mechanism is considered to be the dominant corrosion mechanism for the Hydra

development. A model has been used to calculate the corrosion as the result of CO2 corrosion of

steel. The model is discussed further in Section 4.2 and the results presented in Appendix 2.

Page 22

4.1.3 Top of Line Corrosion

Top of line corrosion (TOLC) is not a large problem in general, but is known to occur in specific

production situations. TOLC is the result of wet gas cooling and allowing water and hydrocarbon to

condense on the top of the pipe. For stratified flow, liquid hydrocarbons and chemical inhibitors

protect the lower portion of the pipe, whereas the top section is unprotected. TOLC depends on

temperature, rate of water condensation, distribution of corrosion inhibitor and the flow regime. At

very high condensation rates the corrosion product on the top surface of the pipe is continuously

washed away and therefore there is nothing to stifle the corrosion rate. Under high condensation

rates the rate of corrosion is directly related to the condensed water pH. At lower condensation rates

the corrosion products formed on the top of the line will stifle the corrosion rate.

TOLC may only be considered for the gas lift lines if the gas exported from the XX platform is not

dehydrated properly due to process upsets or the like. The exposure to TOLC is therefore considered

low in this case. The export pipelines will have annular/slugging flow regimes that will ensure

corrosion inhibitor and oil is splashed around the entire annulus of the pipe thereby stifling corrosion

reactions.

4.1.4 Sulphide Stress Corrosion Cracking

The H2S level of the Hydra fluids is significant. The environmental conditions described by ISO 15156

/ NACE MR0175 specify that SSCC is not a risk for carbon steel materials when the partial pressure

of H2S is less than 0.05 psi (0.35kPa). For the gas lift the H2S partial pressure is 8.6kPa and for the

produced liquids the H2S partial pressure is 0.22kPa. It is therefore assumed that sour service

conditions prevail for the gas lift (even though it is only intermittently run wet) and it is considered

good practice to assume the produced fluids are sour given the accuracy of data provided at this time.

One of the causes for field souring is the result of poor practices during well intervention work (eg. the

use of drilling mud infected with sulphate reducing bacteria), which contaminates the formation.

Controls should be implemented by xx to prevent this from occurring.

Linepipe designed in accordance with DNV OS F101 shall be specified with the 'S' supplementary

requirements.

The commonly used oil and gas industry materials have varying responses to the presence of H2S.

These responses are generally complicated by factors such as pH, temperature, and the presence of

chlorides and free sulphur. Accordingly, ISO 15156 should be consulted to ensure materials used in

sour service conditions are acceptable under the prevailing xx conditions.

4.1.5 Hydrogen Induced Stress Cracking

HISC occurs when atomic hydrogen generated by a corrosion reaction diffuses through the steel and

then accumulates as gaseous (molecular) hydrogen at non-metallic inclusions, particularly when

these have been flattened by rolling or drawing operations. As more hydrogen enters the voids the

pressure rises, deforming the surrounding steel so that blisters become visible on the surface. The

steel around the crack or inclusions in the microstructure becomes highly strained and this can cause

linking of adjacent cracks to form what is know as step-cracks or induce further cracks to form in the

surrounding stress field. Carbon steels are susceptible to HISC. This can occur when carbon steel is

exposed to H2S. HISC can occur in steel at much lower H2S levels than SSC limits set by NACE MR

0175 / ISO 15156. There is no minimum pressure limit where HISC will not occur.

Page 23

The risk of HISC can be reduced by ensuring linepipe carbon steel is specified for sour surface under

DNV OS F101. This will ensure there is control of elemental sulphur (and hence inclusions) in the

steel as well as subjecting the steel to testing to EFC Publication 16 [Ref 4].

4.1.6 Hydrogen Embrittlement

Hydrogen induced cracking caused by adsorption of hydrogen formed at the cathode site (bare metal

being protected) as a result of cathodic protection is known to embrittle and in some circumstances

crack the parent material when sufficient residual or service stresses are present. The propensity for

cracking is known to be crystal structure sensitive, with face centred cubic materials (eg austenitic

stainless steels) being more resistant than body centred cubic materials (e.g. carbon steel) and not

likely to crack unless very high levels of strength/cold work are developed. Body centred and related

cubic structures are know to be susceptible depending upon strength (hardness) and degree of cold

working (plastic strain), with hardness usually accepted as the defining property as far as propensity

to cracking is concerned.

Normal carbon steels such as those used to manufacture DNV OS F101 line pipe are essentially not

susceptible to HE, due to the strength levels of these materials, provided the hardness of the heat

affected zones of welds are less than about 350 HV. Hardness levels above this may result in

cracking in the HAZ if the hardened area is uncoated and thus exposed to the CP system. It is

prudent therefore to specify hardness levels less than 350 HV in HAZ of weld procedure qualification

tests and HFW linepipe manufacturing specifications.

Duplex stainless steels contain microstructures that are susceptible to HE. There are known failures

of uncoated super duplex and duplex stainless steel equipment due to HE. These failures are

exceptional as there have been many successful, relatively long service life subsea installations of

pipelines, manifolds and similar equipment fabricated from 22Cr duplex stainless steel. The failure

details are not widely published, however from recently published information (Ref. 8), hydrogen

embrittlement induced cracking in these types of materials appears to be due to a number of factors.

These factors include:

Susceptible microstructures that are bare surfaces where hydrogen can adsorb

Plastic deformation produced during fabrication, installation and in-service caused by stresses,

which were not predicted or incorrectly calculated.

It should be noted however that plastic deformation occurring whilst the CP system is applied (when

submerged) has been considered the most critical factor to cause cracking (Ref. 8). It would appear

that a high integrity coating system and design to ensure absence plastic deformation in service, (for

example due to pipeline instability/thermal stresses) are essential to mitigate this risk in duplex

stainless steel materials.

In October 2005, NORSOK published a Workshop Agreement as the “Design guideline to avoid

hydrogen induced stress cracking in subsea duplex stainless steels” (Ref. 9). The key design

considerations for avoiding HISC in duplex stainless steel are as follows:

Global principal strain to be limited to ≤ 0.4% for duplex stainless steels;

Local peak strain (total strain) due to SCNFs and residual strains to be limited to ≤ 0.7%;

Forgings shall be forged as closely as practicable to the specified shape and size;

Transition fillet welds shall have a radius not less than one third of the wall thickness;

Page 24

Polymeric coating shall not be relied upon to reduce current demand and hence HISC as

holidays in the coating will cause excessive hydrogen production and hence HISC.

CP potential is to be limited to –600mV (Ag/AgCl) where the duplex elements are completely

isolated from items protected at –1050mV

Austenite spacing in the duplex stainless steels is to be limited to ≤ 30μm. For heavy forgings

an austenite spacing of 60μm should be aimed for

The subsea use of duplex stainless steel is not envisaged for the Hydra development at this stage.

4.1.7 Chloride Stress Corrosion Cracking

Chloride stress corrosion cracking occurs when a susceptible material is placed under a tensile load

in a chloride rich environment, i.e. seawater. Nearly all fabricated items contain stresses, be it

operating pressure stresses, thermal stresses or residual stresses from welding and forming. So it

should be assumed that all materials used on the topsides or subsea will have a certain tensile load

on them for the purpose of considering whether CSCC is a risk. Carbon steel is resistant to chloride

stress corrosion cracking in the temperature range that the xx field will be operating in. The use of

stainless steels is described in Section7.1, and these materials vary considerably from one grade to

the next. Other alloys that may be selected for use as flowlines and for the subsea completions

should be selected in accordance with data supplied by the material suppliers.

It is important to note that on platform topside service all materials will be coated with a layer of

chlorides from sea spray. Surfaces heated by internal process temperatures or solar radiation tends

to dry the chlorides on the surface thereby concentrating the salt over time. So selection of materials

must assume a critical amount of chloride is always present and that temperatures may exceed the

critical CSCC temperature for the material through being heated up by solar radiation.

4.1.8 Erosion

The effect of erosion from entrained solids in the process stream on the candidate materials is less

well defined as the amount of entrained solids is not yet known.

The erosion velocities should be calculated in accordance with DNV RP0501 (Ref. 5) to confirm the

materials selected for various components throughout the production and transportation systems are

acceptable. A more detailed study will be required later once more information about the well fluids is

obtained to determine actual erosion velocities. Erosional velocity limits for CRA materials are

provided in Section 7.1 for information purposes. In general terms duplex stainless steels show

superior erosion resistance over carbon steels.

4.1.9 Subsea External Corrosion

External corrosion due to exposure to oxygenated seawater is expected for the pipelines and

especially the risers. All of the candidate linepipe materials require external coatings and cathodic

protection to protect them from external corrosion from the seawater environment. Special coating

systems for the risers are provided in Section 9.2.2.

4.1.10 Topside Atmospheric Corrosion

The topside equipment and structures will be exposed to a marine environment, which can typically

result in corrosion of steel at a rate of approximately 0.15 to 0.20 mm/year (3mm to 4mm in 20 years).

Therefore, all carbon steel shall be protected with anti-corrosion coatings. Where items are located

Page 25

such that maintenance of the coating system is difficult them it is recommended that either a CRA

material is used or a suitable corrosion allowance is applied to account for external corrosion as well

as internal corrosion.

4.1.11 Corrosion of the Line Pipe During Transportation

Linepipe materials are invariably transported from Asia and Europe via a separate coating yard. It is

during the trans-shipment activities that some materials are exposed to a corrosive marine

environment and sometimes even raw seawater. Carbon steel when exposed to a marine

environment will corrode, however the rate is such that the exposure time would have to be several

years before significant damage is incurred.

All of the potential corrosion mechanisms described above can be prevented by the application of end

caps (not just bevel protectors) that are firmly fixed to the pipeline. Stowing the line pipe below the

deck of the ship’s hold can also reduce corrosion risk. The vessel hold should be checked to ensure

it is dry and the hold doors should be proven to be watertight. The application of a water repellent oil

or corrosion inhibitor is also recommended as part of the transportation procedure.

4.1.12 Microbially Induced Corrosion

Contamination of flowlines with anaerobic bacteria and the resultant microbially induced corrosion

(MIC) can render flowlines unserviceable in very short periods. The microbial contamination of

subsea pipelines is commonly attributed to bad well work-over practices where contaminated drilling

muds are used and sulphate-reducing bacteria is introduced to the formation. Another recognised

cause is the inappropriate or non-existent treatment of seawater used for pre-commissioning. That is

to say insufficient biocide concentrations have been applied to the water used to flood the flowline and

the bacteria establish themselves once the production fluids are transmitted through the flowline.

In order to establish them and cause MIC they must have an anaerobic environment and some

nutrient source; typically sulphate ions from produced water, in the case of sulphate reducing

bacteria. These microbes typically become active at temperatures below about 45ºC, and are known

to corrode corrosion resistant alloys as well as carbon steels. As such all the candidate materials are

equally susceptible to this type of corrosion mechanism. The only way of preventing this form of

attack in anaerobic flowline environments below 45ºC is by excluding the bacteria from the flowline

environment or preventing nutrient from being provided. Once these microbes become established

and form colonies and associated bio-masses, the only way of managing their presence is by the

introduction of biocides in order to control their numbers and therefore the corrosion rates. Typically

this is done by continuous injection of biocides at appropriate concentrations of the order of 20-40

ppm depending upon raw chemical activity. They can also be controlled through batch dosing by

introducing very high concentrations of biocide in slugs between pigs or introduction of concentrated

amounts of biocide into relatively low volumes of produced water (>2,000 ppm).

The largest risk comes from pre-commissioning flooding of the pipeline with seawater. Condensed

water will not contain sulphate ions or other nutrient sources and should serve to flush any bacteria

through the pipeline. Carbon steel linepipe should be cleared of any internal scale by pigging as part

of the commissioning procedures. This will reduce the amount of sites where bacteria can become

lodged. Where duplex or super duplex stainless steel is used, the flushing effect of the fluids will be

enhanced, as there will be no surface scale where the bacteria can lodge. As a contingency there

needs to be facilities made available to inject biocide into the pipeline via the chemical injection lines.

In order to mitigate the risk in general the installation procedures need to be cogniscent of the issues

of bacteria contamination, with measures to ensure appropriate levels of biocide within the flooding

Page 26

water, control measures during tie-ins to ensure raw seawater ingress is kept to a minimum and that

residual biocide levels are sufficient to kill bacteria introduced in this manner. Other measures such

as introducing slugs of biocide between pigs during the dewatering activities are also recommended.

Operational procedures need to ensure that water produced within the first few months of production

is checked for bacteria and if found, appropriate treatment procedures applied.

4.1.13 Under Deposit Corrosion

Under deposit corrosion is where solid materials such as reservoir sands, corrosion products and

scale or mill scale settle out of solution in areas of low or stagnant flow. The deposits of solid material

tend to shield the material below from the beneficial effects of corrosion inhibitors and protective

scales. The deposits also create a galvanic differential potential between the covered area and the

areas covered by the surrounding bulk fluids, this leads to accelerated corrosion of the underlying

material. The deposits are also known to be good starter sites for microbial populations and can

result in rapid corrosion rates due to MIC as discussed in Section 4.1.12.

UDC is commonly incurred by carbon steels and the austenitic steels, but can also be found, to a

much lesser extent due to their higher tolerance, in the higher alloy duplex stainless steels and nickel

alloys.

The governing design principle for avoiding UDC is to firstly eliminate solids from the system where

possible through the use of slug catchers, separators or filters. The elimination of dead legs and

stagnant zones is also considered an important part of reducing the UDC risk and this is discussed in

Section 4.1.15. Where solids are expected to drop out of solution then facilities should be provided to

allow the clean-out of that area or for pipelines then the pipelines should be routinely cleaned using a

cleaning pig.

4.1.14 Galvanic Corrosion

Galvanic corrosion occurs when two, or more, dissimilar metals are placed in electrical contact in the

presence of a conductive and corrosion electrolyte (eg sea water or high humidity marine

atmospheres). The material that is more electronegative will corrode in preference to the adjoined

material when in the presence of an electrolyte. This results in corrosion forming around the joint

between the two materials. The rate and extent of the corrosion is governed by the following factors:

The galvanic potential difference between the materials;

The resistance of the contact between the materials and resistance of the electrolyte;

The electrochemical kinetics of the corrosion processes in the electrolyte;

The relative exposure of the materials to the electrolyte, i.e. exposure of cathodic material

versus anodic material (the material that will corrode) and the distances between the exposed

materials);

The presence of barriers between the exposed materials such as coatings and films that

prevent ionic flow through the bulk electrolyte between the bulk materials;

Dissimilar metal joints should be avoided wherever practical. Where it is unavoidable then the

individual joint details should be assessed. Options such as the provision of insulating joints or

coatings should be considered. Isolating joints are often inadvertently short circuited on offshore

platforms due to bridging the isolated joint between pipe supports or racks, which are electrically

continuous with the underlying structure.

Page 27

Coatings are used to reduce the relative cathodic to anodic surface area. It is often a good idea to

coat the cathodic material (the more noble material) instead of the anodic material so that should a

holiday form in the coating covering the anodic material it does not suffer corrosion from a large

differential in current density created by a very large cathode versus a small anode.

4.1.15 Corrosion in Dead Legs and Stagnant Zones

In wet gas systems corrosion can be abnormally high where water of condensation is collected in

areas of low flow or vertical dead legs. In wet oil systems water can set out of the main flow and be

captured in stagnant areas or vertical dead legs. Corrosion inhibitors often do not protect these areas

of low flow or stagnancy and corrosion is exacerbated by the presence of deposits and/or

microbacteria.

The design of piping and process equipment should ensure that instrument lines and tees to areas

not normally flowing be oriented vertically upward and not downwards. Where lines are slow flowing,

then the line should be designed to self-drain and vessels should be designed such that there are no

stagnant zones or are capable of being drained. Areas of intermittent flow such as the open and

closed drain systems are often affected by stagnant areas and particular care should be taken to

make the system free draining.

4.2 Selection of a Corrosion Model

4.2.1 General

There are a number of models used to predict corrosion caused by CO2 in wet gas. Most models are

proprietary and generally owned by one of the major oil companies. Of the non-proprietary models

available, one of the most popular is the NORSOK M506 CO2 corrosion model [Ref 3]. Revision 2 of

the NORSOK M506 model was issued in July 2005 and has been used for the calculation of CO2

corrosion in this document.

The NORSOK model is an empirical model mainly based on laboratory data for the low temperature

range and a combined laboratory and field data set for temperatures above 100°C. The model is

available via the NORSOK web site and is based on MS Excel spreadsheet routines. The model was

developed by the Norwegian oil companies: Statoil; Norsk Hydro; and Saga Petroleum. The basis of

the model is grounded in the same work as the DeWaard, Milliams and Lotz [Ref 7] studies (i.e. from

the Institute for Energy (IFE) Laboratory in Norway). The difference between the NORSOK model

and DeWaard et al comes from the empirical data developed for temperatures greater than 100°C. A

more in depth discussion on the other CO2 corrosion models used around the world is provided by

Nyborg [Ref 10]. The other models tend to be proprietary systems available only to the Universities

and oil companies responsible for their development. Only the Predict software from InterCorr and

HydroCorr software from Shell takes account of the effects of H2S scales on stifling CO2 corrosion. All

the other programs used, including NORSOK, do not take H2S scale formation into account. By not

accounting for the scales formed by H2S the corrosion rates predicted by NORSOK M506 are

therefore regarded as conservative.

The uninhibited corrosion rates have been used to calculate an overall corrosion rate based on the

inhibitor availability and life cycle approach described by Rippon [Ref 6]:

CR = f × CRi + (1-f) × CRU

where:

CR = overall corrosion rate (mm/year);

Page 28

CRi = inhibited corrosion rate (mm/year, assumed for gas lift to be 0.05 mm/year in

accordance with Table 6 of Rippon [Ref 6], ie a corrosion rate in the temperature range

< 70C and for production piping and export pipelines to be 0.1mm/year. i.e a corrosion

rate in the temperature range 70C≤ T≤120C);

CRu = uninhibited corrosion rate as calculated using NORSOK M506 (mm/year);

f = inhibitor injection system availability factor (0.90, 0.95, 0.98 and 0.99, for 36.5 days,

downtime per year, 18.75 days downtime per year, 7.3 days downtime per year and

3.65 days downtime per year respectively).

This is a simplified approach that takes no account of the inhibitors persistency and assumes that

production will continue during this downtime as well. The availability chosen for XX and XX will be a

trade off between the amount of steel required for the pipeline corrosion allowance and the amount of

equipment required for a high reliability inhibitor injection system.

4.2.2 Limitations of the Corrosion Model

The NORSOK M506 corrosion model is regarded throughout the industry as being conservative, i.e. it

over estimates corrosion rates. The corrosion rates predicted by the model do not take into account

the effects of H2S, free oxygen, etc. Furthermore, the model is based on empirical data collected from

the Kjeller Sweet Corrosion research program at Institute for Energy Technology in Norway.

Therefore, the range of temperatures is limited (20C to 160C), CO2 fugacity (Note 2) is limited (0-10

bar) and pH is limited (3.5 to 6.5). The Hydra process parameters used for the corrosion models all fit

within the bounds of the model and therefore the results should be within the reliable range of the

model.

4.2.3 Prediction of Top of Line Corrosion

In order to predict the probability of TOLC a process model needs to be developed to predict the point

of condensation for each well. Once the point of condensation is known and a rate of condensation is

calculated then a modified de Waard-Milliams [Ref 7] method can be used as shown below:

CRTOLC = Fcondensation.CR

where:

Fcondensation = 0.4 × (Condensation Rate, g/m2s)

CRTOLC = Top of Line Corrosion Rate

CR = overall corrosion rate calculated by the CO2 corrosion model.

The process data at this stage for Hydra is not sufficient to enable the development of condensation

models. TOLC may be an issue when the gas lift gas is exported from the XX platform over the dew

point specification. TOLC is not expected to be a problem on the production side of the platform as

2 A measure of the tendency of a gas to escape or expand. Fugacity (fi) is the pressure value needed

at a given temperature to make the properties of a non-ideal gas satisfy the equation for an ideal gas,

i.e.,

fi = iPi

where i is the fugacity coefficient and Pi is the partial pressure for component i of the gas. For an ideal

gas, i =1.

Page 29

multiphase liquid with an annular type flow is expected. This will ensure that corrosion inhibitor is

evenly distributed across all internal surfaces of topside production piping and the export pipeline.

The only practical means of determining whether TOLC is a corrosion risk worthy of consideration in

this case is to run OLGA dynamic process simulations to determine the rate of water condensation on

the top of the pipeline. The OLGA model should also be able to show where the maximum

condensation occurs. For Hydra the TOLC risk should only be considered significant if the following

criterion is exceeded:

Condensation rate is less than 7.5 g/m2s (Note 3) in the carbon steel pipeline;

Methods to mitigate TOLC include the use of diethylamine based inhibitors combined with the

ordinary amine based filming inhibitor and injected as one product at a treatment rate of ~0.5 - 0.8L

per MMSCF/day. Alternatively, where TOLC is deemed to be a major risk then CRA materials can be

used for the first section of the pipeline until after the condensation has completed and the production

fluids are at equilibrium with the seabed temperature. However, this is an expensive option and can

extend the condensation zone due to the different thermal conductivity of the CRA materials.

4.3 Mechanical Material Selection

4.3.1 Brittle Facture and Embrittlement

Brittle fracture is the rapid fracture of metals without appreciable deformation. The risk of brittle

fracture is increased when a material is exposed to temperatures below its ductile/brittle facture

transition temperature. This temperature varies from material to material and is reliant on the

crystallographic structure of the material. For materials such as aluminium, austenitic stainless steels

and nickel alloys, they have a face centred cubic (FCC) structure, which contains a greater degree of

slip planes. These slip planes improve the materials resistance to brittle fracture and as such FCC

materials are generally immune to brittle fracture.

Materials such as steels, and duplex stainless steels (50% is ferritic) have a body centred cubic

(BCC) structure, which has only limited slip planes and therefore is prone to shear failures. The

temperature at which the material is unable to slip to adjust to external forces is called the ductile to

brittle transition temperature.

Material selection should be based on the minimum design temperature of the component under

consideration. For gaseous service, the effects of the Joules-Thompson effect should be considered

when deciding on the minimum design temperature for the material. The design codes all specify a

minimum temperature for materials. These materials can then only be used at lower temperatures if

they are impact tested at the lower temperature using the Charpy V-notch impact test and /or the

Drop Weight Tear Test (DWTT) (mainly used for plate and pipeline steels).

For the pipeline design to DNV OS F101 there is a requirement to produce a fracture control plan. It

is recommended that the principals described in PRCI document PR-3-9113 [Ref 11] be considered

when developing a pipeline fracture control plan.

3 From the equations in 4.2.3, Condensation Rate = F/0.4 and F = CRTOLC/CR where CRTOLC is

assumed to be the corrosion allowance 3mm / 20 years and CR is 0.05 mm/year from the corrosion

model

F = 0.15 / 0.05 = 3.

Condensation Rate = 3.0 / 0.4 = 7.5 g/m2s

Page 30

4.3.2 Fatigue

Thermal and vibration induced fatigue can be prevented by the use of appropriate design standards

and materials and through maintenance and inspection. Vibration induced fatigue can be

experienced by pipe work attached to rotating equipment or where very high flows are experienced

through piping with flow upsets such as orifice plates and / or bends etc. This can be prevented

through the use of adequate pipe supports, correct material sizing or the use of pulsation dampeners.

A system should be regularly monitored once operation begins to ensure areas not considered at risk

during design don’t begin to vibrate due to harmonics from adjacent equipment or remote sources.

Also, the design details such as pipe supports are often left off during construction or become loose

with time, resulting in excessive vibration of the piping. It is for this reason that a regular inspection

regime should be put in place to check for vibration and areas that are insufficiently supported or

restrained.

Page 31

5. CORROSIVITY ASSESSMENT AND CORROSION MITIGATION

5.1 Corrosivity Assessment Results

The corrosivity assessment showed that the corrosion rates for the gas lift pipeline, gas lift piping,

production piping and export pipelines can be manufactured using carbon steel with a corrosion

allowance and continuous (98%availability) corrosion inhibition. The results of the corrosion

modelling are provided in Appendix 2.

A conservative approach has been taken with the gas lift service assuming that there will be water

carry over into the pipeline from time to time. The NORSOK model assumes that the gas lift gas is

saturated with water all of the time that the gas lift line is flowing. However, this will not be the case

and therefore corrosion will not be active all of the time. To adjust the NORSOK corrosion model to

account for the duration that gas is off specification (i.e. wet gas operation) it has been assumed that

the gas is wet for 20% of the time the gas lift operates (i.e approximately 70 days per year). During

wet gas operation it is assumed that the corrosion inhibitor system is operational and that the pipeline

will corrode at the inhibited rate assuming an inhibitor efficiency of 95% and an inhibitor availability of

100%. Inhibitor efficiency is assumed at 95% as the corrosion inhibitor will only be intermittently

injected and therefore there will be a delay until full film thickness and inhibition is achieved.

It is believed that with the measures described by this report regarding operational pigging and routine

corrosion inhibition, then it is possible that the corrosion allowance for the gas lift system could be

kept to 3mm or less.

A lot of work was done to review the corrosion allowance for the production flowlines and the

production and test manifolds. These lines run very hot (110°C) and therefore corrosion rates can be

slightly higher than expected due to corrosion inhibitor performance dropping. This drop in

performance is taken into account using the life cycle approach adopted to calculate the corrosion

allowances for the xx and xx assets. A corrosion inhibitor efficiency of 95% for flowlines and headers

and 99% for riser and pipelines has been considered and a corrosion inhibitor system availability of

98% has been adopted in line with the Equipment Availability, section (7.4.1) of the Project Basis of

Design [Ref 1], which requires topside facilities to be design for 98% up time. A full discussion of the

inhibitor injection philosophy is provided in Section 5.2.3.

The Hydra corrosion model was developed on the basis of:

a) conservatively ignoring the pH buffering due to bicarbonate content of any produced water

being present; and,

b) including effects of pH buffering due to presence of bicarbonates in the produced water

(based on xx and x produced water composition).

The produced water analysis used in the model was provided by xx and is understood to be taken

from PB#7 and PG#3 well analyses. WorleyParsons make no comment as to the reliability of the

produced water analysis or likelihood of the produced water chemistry used in this analysis being

appropriate at xxand xx over their design life. The corrosion allowances for the topside production

equipment is described in Table 5-3. Table 5-3 shows the calculated corrosion allowance with and

without the benefit of buffering from produced water.

Table 5-3 WHP Topside Production Equipment Corrosion Allowances

Equipment Calculated Metal Loss and Corrosion Allowance (mm)

Page 32

Model a) Water of

Condensation Only

Model b) Water of Condensation +

Produced Water

Internal Metal

Loss

Total CA Internal Metal

Loss

Total CA

Production Flowlines

- xx

- xxP

5.14

4.55

7.0

6.0

1.33

1.26

3.0

3.0

Test Header

-xx

xx

5.14

4.55

7.0

6.0

1.33

1.26

3.0

3.0

Production Header

-xx

- xx

4.73

4.17

6.0

6.0

1.29

1.23

3.0

3.0

The corrosion of the topside equipment should also account for external corrosion where piping

running at an elevated temperature will be prone to coating breakdown and hence exposure of the hot

steel surface to a marine environment. Considering that bothxx and Sxx wellhead platforms are

unmanned it is considered that a 1.5mm external corrosion allowance be added to the production

piping. The total corrosion allowance (CA) for the flowlines and headers for the two corrosion model

cases are presented in Table 5-3.

The corrosion allowances for the production export pipelines on xx and xx are described below in

Table 5-4.

Table 5-4 Production Export Pipeline Internal Corrosion Allowances (20 years)

Pipeline Inlet Accumulated

Corrosion (mm)

Outlet Accumulated

Corrosion (mm)

Corrosion Allowance

(mm)

Model a) Water of Condensation Only

xx Production Export 4.51 5.53 6.0


Model b) Water of Condensation + Produced Water



Refer to Section 8.2.3 for recommendation of alternative materials.

The corrosion rate for the export pipelines from xx and xx to xx are very sensitive to the pH buffering

effect of the produced water. Variability in the bicarbonate concentration in the produced water

analysis (as provided by XXEPIL) was found to have little effect on the corrosion rate and this is

demonstrated in Table 5-5.

Page 33

What is unknown about the produced water chemistry is how much H2S and CO2 will react with the

water during the long exposure time along the pipelines length. The typical produced water chemistry

provided in Section 3.3.3 is a separator chemistry and was not exposed to a long duration of mixing

with a CO2 (10wt%) and H2S (100ppm) laden production liquid which may become more acidic and

hence more corrosive over time. It is also important to note that the NORSOK M506 corrosion model,

as is the case for most CO2 corrosion models, does not account for the effect of H2S on the overall

corrosion rate. The corrosion rate including H2S varies through different temperature zones, which is

mainly because the different scales that form on the steel have different structures and hence have

varied porosity and adhesion properties. All of which effects the passivation of the steel and whether

it corrodes or not.

Table 5-5 Sensitivity Analysis of Produced Water Chemistry (xx Export Pipeline)

Bicarbonate Level Accumulated Corrosion Damage (20 years)

(98% inhibitor availability and 99% inhibitor efficiency)

100% Chemistry (1691 mg/l) 1.28mm

90% Chemistry (1522mg/l) 1.28mm

75% Chemistry (1268mg/l) 1.29mm

5.2 Corrosion Inhibition Philosophy

5.2.1 General

Corrosion inhibitor will be assessed as the primary means of corrosion management in wet process

streams and pipelines to allow the use of carbon steel with an acceptable corrosion allowance,

provided the chemicals used and the method of injection can effectively and reliably control the

corrosion rate.

The inhibitor effectiveness comprises the efficiency of the chemical in the process (how much it

reduces the native uninhibited corrosion rate when dosed properly), and the reliability of the injection

process (how often inhibitor is actually injected and available to inhibit corrosion in the process). For

this project, the values for the inhibited corrosion rate and inhibitor availability to be used for material

selection and corrosion allowance determination purposes for the xx (or xx) to xx subsea pipelines will

be in accordance with the following Table 5-6 from Rippon [Ref 6]:

Table 5-6 Inhibited Corrosion Rates and Inhibitor Availability [Ref 6]

Temperature Range

(C)

Inhibited Corrosion Rate

(mm/y)

Specified Inhibitor Injection Availability

(%)

Manned Platform Unmanned Platform

Up to 70C 0.05 99% 95%

> 70C and 120C 0.1 99% 95%

> 120C and 150C 0.2 99% 95%

Above 150C Inhibition not recommended without specific testing

For unmanned facilities with chemical storage and injection facilities located on the platform Rippon

recommends a 95% mechanical availability of the chemical injection system. However, in this case it

Page 34

is the current design premise to have the chemical injection pumps and chemical storage located on

the xx platform, which is manned. For this scenario it is considered good practice to assume a

corrosion inhibitor availability of 98%. Projects such as BHP Billiton Minerva (Australia, Otway Basin),

Nexus Energy Longtom (Australia, Bass Strait) and Santos Casino (Australia, Otway Basin) are

remote subsea developments controlled by onshore facilities (up to 60km) away and these projects all

assume 99% chemical injection availability. A field arrangement similar to xx is used in the Kerr

McGee China Petroleum Development in Bohai Bay, Northern China. KMGCP have unmanned

wellhead platforms that are supplied with inhibitor and other chemicals from remote manned

production platforms and FPSO. KMGCP operate using 98% corrosion inhibitor availability for their

unmanned wellhead platforms.

For the topside production and test headers through to the export pipeline the corrosion inhibitor will

be supplied through multiple injection points (i.e. one per flowline, upstream of the choke valve) and

therefore a complete unavailability of inhibitor would require multiple failures of the injection points.

For the individual flowlines, when the injection system fails, the flowline will go without corrosion

inhibition and therefore the 98% availability may not be obtainable and hence either a CRA material or

a large corrosion allowance (>6mm) is to be considered for the flowlines. A list of possible uninhibited

events is provided in Appendix 3 with suggested control options.

Pipelines operate under fairly well defined flow regimes with constant pipe diameter; whereas topside

production and process plant systems operate with variable pipe diameters, flow regimes and fluid

velocities. They can also possess areas of high flow, flow disturbances, impingement, dead legs,

crevices, etc., that can reduce the performance of the corrosion inhibitor. Consequently, an inhibitor

overall inhibitor effectiveness (i.e. taking account of the inhibitor efficiency and inhibitor availability)

limit of 95% is recommended for topside pipework.

As part of the materials selection process, the inhibitor effectiveness required to allow a desired

corrosion allowance to be achieved for the design life has been calculated for each process stream.

Should the inhibitor fail to achieve the performance standard assumed in the materials selection,

excessive corrosion may occur giving rise to the risk of premature failure.

It is critical that the target inhibitor availability and effectiveness is achieved, by:

Ensuring that the inhibitor chemical specified is able to achieve the specified inhibited corrosion

rate (e.g. 0.05mm/yr for T<70°C) irrespective of the corrosivity of the environment (see

Section 5.1).

Ensuring that the dose of chemical is sufficient to be able to achieve this level of protection

throughout the system to be protected, and that facilities to check this effectiveness (corrosion

monitoring and sample points) are provided at appropriate positions in the process.

Ensuring that the inhibitor is injected in a manner that the full performance efficiency of the

chemical can be achieved throughout the system, by the appropriate location of injection

points, and the specification of the proper injection axxratus (i.e. quills/atomiser).

Ensuring that the chemical injection system is sufficiently reliable to provide chemical injection

for a defined percentage of the design life (e.g. at least 98% of the time for an unmanned

platform), usually by the use of motor (not air/gas) driven pumps, provision of alarms or

indicators when injection stops, regular operator surveillance, etc. (see Section 5.2).

Ensuring that the onsite facilities are equipped with sufficient chemical storage capacity to

provide continuous supply of chemical for the maximum duration between supplies, taking into

account such factors as storms preventing offloading.

Page 35

Failure to ensure the target inhibitor effectiveness is met will reduce the life of the system, potentially

below the required 20-year design life.

5.2.2 Chemical Performance

The chemicals currently used in the xx and xxfields are as follows:

Corrosion Inhibitor: Champion Technologies Cronox ML-5694;

Scale Inhibitor: Champion Technologies Grypton IT-266.

Details of these chemicals are provided in Appendix 4. The chemical’s ability to achieve the target

inhibited corrosion rate must be proven for the xx and xx conditions prior to deployment, particularly in

highly corrosive systems, where the consequences of not meeting the specified inhibition target could

be very high.

5.2.3 Chemical Injection System Design

The detailed design of the system (i.e. placement of injection points, design of injection quills, design

of chemical supply systems, availability of pumps, potential for blockages, provision of alarms and

backups, quality of equipment purchased) will dictate the base mechanical reliability of the system,

and so have a strong effect on the overall effectiveness of the inhibitor treatment over the life of the

field.

The Inhibitor System Design Criteria given in Table 5-7 must be incorporated into the overall facility

design to meet the required target system availability (see Section 10) for the remote, unmanned

xxand xx wellhead platform. For comparison, the table provides the inhibitor system design criteria

that would be required to achieve a 95%, 98% and 99% availability targets.

Table 5-7 Criteria for Inhibitor System Design to Meet a Specified System Availability

Item Inhibitor Availability

95% 98% 99%

Inhibitor demonstrated as

suitable for the application

Inhibitor injection pumps Standard High reliability High reliability

Back up pumps Automated Preferable for

Remote Sites

Automated

Check that pump is operating Daily Manual Check Automated Alarm for

Remote Sites

Automated Alarm

Pump planned maintenance Annual Annual Annual

Inhibitor tank levels Daily Manual Check Automated Alarm for

Remote Sites

Automated Alarm

Page 36


95% 98% 99%

Report on inhibitor used (or

report on compliance with key

performance indicators) to

responsible corrosion

engineer

Monthly Weekly Weekly

Quarterly manual check on

pump injection rate

No flow alarm (zero

differential pressure across a

critical component, or in line

flow meters)

for Remote Sites

Liquid samples for analysis of

residual inhibitor levels and

water chemistry

Monthly Monthly Monthly

Corrosion monitoring system

response time.

Response time such

that total number of

events x time to

respond is <18 days

Response time such that

total number of events x

time to respond is <8

days

Response time such

that total number of

events x time to

respond is <4 days

Typical choices for corrosion

monitoring equipment and

system response times

At least annual

manual corrosion

measurements

On line ER probes;

response time 1-4 days

and daily inhibitor

injection concentration

On line ER probes;

response time 1-4

days and daily inhibitor

injection concentration

Comprehensive review of

uninhibited events

Desirable Required Required

Persistency taken into

account

Allowed days inhibitor system

downtime per year

18 8 4

Shut-in if inhibition system

goes down for greater than a

defined period of time

Effectively never an

issue

Possibly (depending on

corrosivity of system)

Possibly (Note:

Probably for high

corrosivity systems)

Check for worst-case

corrosion in shutdown

conditions

Effectively never an

issue

Possibly (depending on

corrosivity of system)

Possibly (Note:

Probably for high

corrosivity systems)

Identify Operations

Technician with responsibility

for the inhibition injection

system

Page 37


95% 98% 99%

Corrosion Engineering

Involvement

Monthly Review Fortnightly Review Weekly Review

Key Performance Indicators

set for Operations

Technicians and Corrosion

Engineers

As indicated in Section 5.1, carbon steel is viable for a 20 year design life. If carbon steel flowlines

are used on xx and xx, corrosion inhibitor would need to be injected upstream of the choke on each

wellhead, which would provide thorough mixing and distribution of the inhibitor into the fluids.

If the corrosion inhibitor is prone to clogging the injection lines and fittings then dilution of the inhibitor

in diesel oil to improve the inhibitors viscosity should be considered. The dilution of the inhibitor and

the effect on its effective injection rate should be calculated in conjunction with the field’s chemical

supplier, Champion Technologies. If the inhibitor is diluted with diesel then a larger volume of fluid

will have to be pumped and hence the injection pump sizes should be increased accordingly.

If CRA flowlines are used and corrosion inhibitor is required for protection of the xxto xx pipeline and

xx-xx pipeline, an atomising injection quill should be used downstream of the production flowline to

ensure that the inhibitor is effectively distributed in the gas phase. This system can be designed with

automatic back-up pumps to improve the system reliability, as opposed to the use of multiple injection

pumps for each wellhead.

Provision will need to be made for corrosion inhibitor injection on xx for protection of the dehydrated

gaslift pipeline in the event of dehydration upsets. This should be coordinated with dewatering pigs to

remove water that may have settled at low spots in the pipeline.

5.2.4 Operation and Reliability

The quality of operation of the chemical injection system is critical to the effectiveness of the inhibitor

treatment and therefore to the reliability of carbon steel systems. Factors include the quality and

consistency of chemical supply, regular operator checks / control room surveillance, pump and

injector maintenance, injection adjustment and performance verification.

Page 38

6. PIGGING REQUIREMENTS

6.1 Operational Pigging

Pipeline pigging can have a major impact on the operational and technical integrity of a pipeline.

Pigging can have a number of operational purposes:

Cleaning of the pipeline prior to an intelligent pig inspection;

Intelligent pig runs;

Cleaning to prevent flow restrictions (wax, asphaltene and scale build-up);

Liquids inventory management;

Internal corrosion control; and

Inhibitor distribution.

The subsea production pipelines will have pig launchers and receivers fitted to enable operational

pigging.

The current design basis does not provide for permanent gas lift launchers and receivers; this

arrangement is satisfactory if corrosion inhibition is continuously injected into the gas lift pipelines. If

the corrosion inhibition is to be only injected when the gas lift gas goes off dew point (wet gas

operation) then it is recommended that permanent launchers and receivers are installed to permit

periodic sweeping of free water from the gas lift pipeline and running batch corrosion inhibitor.

Pigging for corrosion control may be required for a number of reasons:

For new and existing lines, the lines should be cleaned and batch pigged with a filming inhibitor

prior to commencement of continuous inhibitor injection to ensure access of the inhibitor to the

pipe wall to maximise inhibitor effectiveness from start up. The continuous inhibitor takes a

finite time to travel down the pipeline from start-up and the batch inhibitor will prevent any

corrosion from occurring.

Pigging should be performed during commissioning in order to remove any mill scale and loose

surface corrosion from the pipe walls. This will help to improve corrosion inhibitor efficiency by

reducing the surface area available in the pipe where corrosion inhibitor can be adsorbed and

removed from the corrosion inhibition of the steel.

Distribution of inhibitor containing bottom fluids to the top of the line (TOL) where TOL corrosion

is a concern.

Removal of stagnant water pools in stratified flow regimes, where continuously injected inhibitor

may be less effective and/or require higher dose rates than more turbulent systems.

Removal of sand and other solids that may adversely affect the performance of the inhibitor.

Scraper pigs are generally sent through the pipeline ahead of intelligent pigging operation to ensure

that the intelligent pig does not get stuck in the pipeline. The debris collected by the scraper pig will

be deposited in the pig receiver. Samples of this material should be taken and analysed.

Page 39

6.2 Intelligent Inspection Pigging

6.2.1 General

Deterioration of the pipeline is primarily a result of corrosion by aggressive contaminants. Control of

the deterioration will be through chemical treatment. To ensure the integrity of the pipeline, it may be

necessary to undertake a number of maintenance and inspection pigging routines throughout the life

of the pipeline.

6.2.2 Intell igent Pigging Requirements

Under a safety case regime, there are no definitive inspection periods for intelligent pigging. The

requirements for intelligent pigging are determined through a consultative process whereby the

regulator and pipeline license holder set an agreed inspection period, based on the following

parameters:

Predicted corrosion rate;

Corrosion management program;

Corrosion monitoring program;

Operating history; and

Operator experience.

The base intelligent pigging frequency will be based on a set interval (typically 5 years), minimum,

with additional IP runs performed as needed based upon the above parameters.

6.2.3 Pigging Frequency

There are two approaches to determining the requirements for intelligent pigging. To get the

maximum benefit from performing intelligent pigging inspections, the inspection tool shall only be run

when it is expected that anomalies are present at levels detectable by the inspection tool. For typical

high-resolution magnetic flux leakage tools, this detection limit is generally 10% of wall thickness or 1

mm, whichever is greatest.

Therefore, in determining the pigging frequency, the expected corrosion rate should be used to

ensure that intelligent pigging is not performed unnecessarily. The corrosion rate used in determining

the frequency of pigging is typically the uninhibited corrosion rate.

However, the pipeline shall be designed so that the corrosion inhibitor is injected continuously and

should approach 100% availability.

If this corrosion management philosophy is confirmed by in-line corrosion monitoring devices (e.g. the

probes or sensor spools), then potentially regular intelligent pigging will not be required for the life of

the pipeline based on the detection limit and a maximum inhibited corrosion rate.

Generally, the local regulatory body insists on intelligent pigging of wet CO2 pipelines on a regular

frequency. This frequency is typically every 3 to 5 years, depending on the history of the pipeline, the

experience of the operator, and the corrosion monitoring and mitigation programs in place.

Page 40

7. SPECIFIC MATERIAL APPLICATIONS

7.1 Use of Corrosion Resistant Alloys

7.1.1 Grade 304/304L Austenitic Stainless Steels

Grade 304/304L stainless steels shall not be used in critical service for pipework, tubing, vessels,

equipment, bolting or fixings exposed to marine or salt-laden air, or aerated chloride-containing water,

due to the risk of pitting, crevice corrosion or chloride-induced stress corrosion cracking at any

temperature above ambient.

Rogue 304 stainless steel materials regularly turn up on offshore facilities due to its use in vendor

standard valve bolting. All valves used offshore in pressure containing service should be specified as

“No 304 Stainless Steel (B8) materials permitted”.

7.1.2 Grade 316/316L Austenitic Stainless Steels

Grade 316/316L shall not be used in critical service for any piping or for the externals of equipment

above a temperature of 60°C due to the risk of external chloride-induced pitting and stress corrosion

cracking (CSCC).

Consideration should be given to the use of 316L clad carbon steel rather than solid 316L vessels

(particularly in a marine environment) unless cladding is shown to be significantly less economic.

Grade 316L may be used as a cladding material or for vessel internals in sweet (i.e. only CO2)

hydrocarbon service providing oxygen and/or H2S are not present.

Before solid material is used (particularly in a marine environment), consideration shall be given to the

possibility of an increase in the external skin temperature above 60C due to solar radiation or heat

from surrounding equipment, which may also cause chloride concentration due to surface

evaporation. In these conditions, 316L is not acceptable for critical service. Consideration can be

given to the use of factory applied thermal spray aluminium (TSA) as an external coating to act as a

surface barrier and shift the stainless steel potential out of the SSC regime, but the effectiveness of

such a coating over a 20 year design life shall be considered for critical service. Consideration shall

also be given to the practicality of site application of TSA at field joints, since this has been shown to

be problematical and to adversely affect the performance of the coating.

In the absence of CO2 and H2S, Grade 316L stainless steel shall not be used in critical service for

process or utility streams containing oxygen above 60C if the chloride content is above 300 ppm.

The material shall not be used for any heat transfer surface applications in such streams at any

temperature or chloride content due to the risk of chloride concentration effects.

Grade 316/316L stainless steel piping for pressure retaining purposes may be used above 60C if it is

not insulated and is located indoors under HVAC control. For un-insulated instrument tubing

downstream of a shut-off valve, normally no extra precaution is required providing there is no flow in

the instrument piping and the process media temperature is less than 85C.

Material limits and manufacturing controls for 316/316L stainless steel are summarised in Table 7-8.

Page 41

Table 7-8– Material Limits and Manufacturing Controls for 316/316L Stainless Steel

Type of Service

Produced

Fluids

Oil (no

water)

Wet

Gas

Dry

Gas

Produced

Water

Temperature Limits (°C)

Min Service Temp Without

Impact Testing

All thicknesses -105 -105 -105 -105 -105

Min Service Temp With Impact

Testing

All thicknesses -196 -196 -196 -196 -196

Max Service Temp - Uncoated Atmospheric

Marine (Low

Hazard)

60 60 60 60 60

Flow Velocity Limits Without Sand (m/s)

Flow Velocity Limit 50 50 50 70 50

Manufacturing Limits & Controls

Compositional Constraints Min

Molybdenum

for thin wall

tubing

2.5 2.5 2.5 2.5 2.5

Solution Anneal & Quench for

Pipe & Fittings

YES YES YES YES YES

7.1.3 6Mo Super-Austenitic 254 SMO (UNS S31254)

6Mo super-austenitic stainless steel such as 254 SMO (UNS S31254) can be regarded as resistant to

CO2 corrosion but shall be limited to an operating temperature of 120°C in an external saliferous (i.e.

salt laden air) environment. The minimum design temperature shall be -101°C without impact testing

or -196°C with impact testing.

7.1.4 Duplex Stainless Steel

Duplex stainless can be considered resistant to external chloride induced stress corrosion cracking

(CISCC) up to temperatures of 100C for 22Cr duplex and 110C for 25Cr super duplex stainless

steels. Cracking above these temperatures is only likely if the vessel or pipework is lagged and

saline/seawater gets trapped under the lagging or is dripped continuously onto hot pipework.

Nevertheless, as a precaution, it is recommended to TSA coat duplex stainless steel equipment

operating above these temperatures in an offshore marine environment.

Duplex stainless steels can be considered to be resistant to weight loss corrosion and pitting

corrosion in sweet hydrocarbon production environments (i.e. CO2 only) at CO2 partial pressures up to

100 bar, temperatures up to 200C and up to 20,000 ppm (200g/l) NaCl.

Page 42

Material limits and manufacturing controls for 22Cr duplex stainless steel are summarised in Table 7-

9 below. Typically throughout this document when 22Cr is referenced, the basic specification UNS

S31803 is inferred. However, where a higher pitting risk is perceived then the higher specification

22Cr, UNS S32205, will be specified as it contains a guaranteed minimum molybdenum content of

2.5%, which ensures a greater pitting resistance than the base grade duplex stainless steel.

Table 7-9 – Material Limits and Manufacturing Controls for 22Cr Duplex Stainless Steel

Type of Service

Produced

Fluids

Oil (no

water)

Wet

Gas

Dry Gas Produced

Water



Impact Testing

≤ 6mm -50 -50 -50 -50 -50


Impact Testing

> 6mm 0 0 0 0 0


Testing

> 6mm -50 -50 -50 -50 -50


Marine

100 100 100 100 100

Max Temp Due to

Embrittlement

ASME B31.3

Table A-1

315 315 315 315 315




Metallurgical Constraints Ferrite Content 35 – 65% 35 –

65%

35 –

65%

35 –

65%

35 – 65%

Minimum PREn 33 33 33 33 33

Minimum Nitrogen Content (%) 0.15 0.15 0.15 0.15 0.15

Solution Anneal & quench for

Pipe & Fittings

YES YES YES YES YES

Material limits and manufacturing controls for 25Cr super duplex stainless steel are summarised in

Table 7-10 below.

Page 43

Table 7-10 – Material Limits and Manufacturing Controls for 25Cr Super Duplex Stainless Steel

Type of Service

Produced

Fluids

Oil (no

water)

Wet

Gas

Dry

Gas

Produced

Water



Impact Testing

≤ 6mm -50 -50 -50 -50 -50


Impact Testing

> 6mm 0 0 0 0 0


Testing

> 6mm -50 -50 -50 -50 -50


Marine

120 120 120 120 120

Max Temp Due to Embrittlement ASME B31.3

Table A-1

315 315 315 315 315




Metallurgical Constraints Ferrite Content 35 – 65% 35 –

65%

35 –

65%

35 –

65%

35 – 65%

Minimum PREn 40 40 40 40 40

Solution Anneal & quench for

Pipe & Fittings

YES YES YES YES YES

7.1.5 Selection of CRA for Pipe and Vessels

The use of CRA clad carbon steel is becoming increasing difficult due to the high worldwide demand

for clad steel and there being only 4-5 manufactures in the world to provide the materials. It is for this

reason that clad pipe and vessels are not considered as part of this material study.

7.2 Use of Glass Reinforced Plastic (GRP)

7.2.1 Piping Systems

The properties and performance characteristics of glass-reinforced plastic (GRP) are dependent on

the resin used for the composite matrix and the method of manufacture. Such factors shall be taken

into account when selecting a particular product for a service application.

GRP pipe may be considered for open drains, produced water piping, injection lines, potable water,

systems, sanitary systems and drain lines subject to confirmation of the suitability of the resin type for

Page 44

the intended service and the pressure and temperature rating for the pipe. Examples of pressure

ratings and resins used in GRP pipe from various manufacturers are show in Table 7-11

Temperature ratings are usually of the order of 90°C for epoxy based systems, but can be up to

~120°C for polysiloxane-phenolic based systems.

It should be emphasised that design, fabrication and installation of GRP systems, including pipe

supports, joining systems and expansion bellows, are specialised processes and require experienced

personnel to ensure good quality and performance. It is extremely important that GRP pipe be

installed by bonders and inspectors who have been trained and certified to a specification approved

by the owner.

Engineering analysis of GRP piping systems is critical to the prevention of premature failures due to

inadequate support, improper location of supports, water hammer, etc. ISO 14692 (Parts 1 to 4) is

now recognised as the Industry Standard for the design, purchase, manufacturing, qualification

testing, handling, storage, installation, commissioning and operation of GRP piping systems in the

petrochemical and natural gas industries. It provides terms and definitions, describes the philosophy

and provides guidance on the range of suitable applications, and defines limitations to the materials of

construction for the specification, manufacture, testing and installation of glass-reinforced plastic

(GRP) piping installations. Its primary focus is associated with offshore applications on both fixed and

floating topsides facilities for oil and gas industry production and processing, but may also be used as

guidance for the specification, testing and installation of GRP systems in similar onshore applications,

such as firewater and produced water systems.

Severe impact events can cause crazing in the pipe wall and therefore GRP pipe should be located to

reduce the occurrence of impact loads wherever possible, or physically protected.

Although industry standards are available to govern the specification of GRP piping systems, GRP

pipe manufacturers will provide system engineering assistance, supply material, fabricate spools,

provide onsite construction and inspection, and conduct proof tests. It is advisable to use the services

of the manufacturer as much as possible.

7.2.2 GRP Tanks and Vessels

Typical applications for GRP vessels include water filters, water storage, and chemical storage. GRP

vessels can be used to store hydrocarbons such as diesel fuel, gasoline and lube oil when approved

by the governing regulatory body.

Vessel manufacturers include Forbes, Balmoral, Garlway, RL-Industries, Inc., Ershigs, Inc., and

Lincoln Composites. Generally, the cost of GRP is between that of carbon steel and stainless steel.

Low-pressure GRP vessels and tanks are available for storage or process applications. Low-

pressure vessels can be very large. Pressure ratings go up to 15 psig plus the hydrostatic head.

Governing standards are ASME RTP-1 and BS 4994.

High-pressure GRP vessels are also available. High-pressure vessels must be qualified to ASME

Section X. Class I vessels may have pressure ratings to 150, 1500 or 3000 psig, depending on the

construction of the vessel, and are qualified by test of a prototype to destruction. Class II vessels may

have pressure ratings ranging from 15 to 200 psi depending on the diameter and the design method.

Class II vessels are qualified by non-destructive testing.

Design and fabrication of nozzles and other attachments with good durability is an engineering issue.

Good procurement specifications are important. The fabrication quality control plan and user

inspections are important considerations.

Page 45

Table 7-11 Examples of Pressure Ratings and Resins Used in GRP Pipe

Manufacturer Product Series Typical Application Resin Pressure Rating

(PSI)

Ameron

International

Bondstrand 2000M General Application & Firewater Ring

Main

Epoxy 250 (1” to 16”)

225 (18” to 40”)

2000M-FP Dry Deluge Piping Epoxy 250 (1” to 16”)

2420 Potable, saltwater, brackish water

and seawater lines

Fire protection systems

Waste water, drainage and sewage

systems

Epoxy 290 (2” to 40”)

5000M Seawater Chlorination Vinyl Ester 450 (2”)

350 ((3” & 4”)

250 (6’ to 8”)

150 (>12”)

7000M Antistatic piping for Refined Products Epoxy 250 (1” to 16”)

225 (18” to 40”)

PSX-L3 Firewater Ring Main Polysiloxane-Phenolic 250 (2” to 6”)

225 (8” to 16”)

PSX-JF Dry Deluge Piping Polysiloxane-Phenolic 225 (1” to 12”)

EDO Speciality

Plastics

Fiberbond 20 HV General Application Iso Polyester 200 (2” to 12”)

150 (14” to 18”)

100 (20” to 24”)20 FRE Firewater Ring Main Vinyl Ester

20 JF Dry Deluge Piping Vinyl Ester 200 (2” to 10”)

Page 46

Manufacturer Product Series Typical Application Resin Pressure Rating

(PSI)

Smith Fibercast Green Thread 175 General Application Epoxy 175 (2” to 26”)

250 General Application & Firewater Ring

Main

Epoxy 250 (1” to 36”)

250 -F Dry Deluge Piping Epoxy 250 (1” to 24”)

Future Pipe Waivistrong EST 20 General Application Epoxy 250

Page 47

7.3 Selection of Elastomeric Seals

The following materials may take up product and are therefore susceptible to explosive

decompression. They should not be used for ‘O’-rings in hydrocarbon service:

Viton A

NBR (Nitrile Butadiene or Standard Rubbers)

Elast-O-Lion 101 HNBR (does not perform on larger sections)

Materials with proven and acceptable performance in hydrocarbon service include:

James Walker 58/90 (Viton ‘B’)

James Walker 58/98

Dowty 9730

Greene Tweed 826

Nitrile (NBR) and hydrogenated nitrile (HNBR) elastomers are acceptable in non-hydrocarbon service

with low levels of H2S if the temperature remains below 60C.

PTFE is a plastic which has excellent chemical (and H2S) resistance, but account should be taken of

the fact that plastics require different sealing configurations to elastomers.

In all instances, elastomer selection should take into account the complete operating conditions to be

encountered, especially the presence of amines from corrosion inhibitors. Amines are curing agents

for Buna and Nitrile rubbers causing such products to over-age and embrittle. As a result, glass-filled

PTFE seals are required for inhibitor handling equipment such as pumps and valves, and good amine

resistance of TFEP or FFKM elastomers may be required in critical locations in hydrocarbon service

where high amine/inhibitor concentrations could be encountered.

Viton is rapidly degraded by methanol and should not be used in any system that will be exposed to

methanol.

7.4 Bolting Materials

Bolting for carbon steel piping is normally specified as low alloy, quenched and tempered Cr-Mo

steels to either ASTM A193 Gr B7 and/or A320 Gr L7, but additional protection is required for offshore

marine applications.

Carbon steel bolting is commonly cadmium plated and PTFE coated. However, the PTFE coating is

only partially effective, since damage will always occur during installation and maintenance. These

coatings usually comprise only 30µm of PTFE and 8µm of plated cadmium, so limited protection is

afforded where the PTFE is damaged. Some operators have experienced corrosion of the bolts by

the time of commissioning or within 1-2 years, leading to seizing of the nuts in the long term.

The use of hot dip spun galvanized steel (HSG) bolting to ASTM A193 grade B7 (nuts to ASTM A194

grade 2H) should also be considered, since a number of operators have had poor performance with

electroplated Zn/Cd and PTFE coatings in aggressive marine environments. HSG bolting provides a

much thicker coating than the Cd/Zn electroplate and offers a cost-effective alternative in the long

term.

Page 48

BS 14713 gives the average corrosion rate of zinc in a highly saline atmosphere as 4-8 m/yr,

whereas the minimum zinc thickness when galvanizing to BS 729 is 43 m. This would give an

average life expectancy of the galvanized layer of 5 and 10 years before the galvanic protection from

the zinc is lost and corrosion of the steel substrate commences. In practice, the galvanizing thickness

tends to be greater than 43 m, which provides longer coating life.

Apart from corrosion, the main issue that is frequently raised with galvanized steel is liquid metal

embrittlement (LME) of adjacent stainless steels. This is mainly an issue with austenitic stainless

steels, but can affect duplex stainless, which have an austenite/ferrite matrix. It requires the

simultaneous presence of molten zinc, high tensile stress and temperatures over 750C. However, in

the event of a fire that could lead to these temperatures, the mechanical properties of the stainless

steel will have been greatly reduced before the critical LME temperature is reached. The additional

risk of failure due to LME is therefore low and the use of galvanized bolting on stainless steel piping is

regarded by some operators (e.g. BPAmoco) as acceptable.

If galvanised steel bolting is used, bolts with a diameter above 25mm should be impact tested to the

same requirements as for the steel to be bolted. Extra clearance is required on the threads to allow

for the zinc coating thickness and it must be ensured that galvanised nuts are not fitted to

PTFE/electroplated bolts.

Bolting for subsea service shall be in accordance with the requirements of DNV OS F101 Table 7-2

as amended in January 2003.

Page 49

8. MATERIALS SELECTION – XX AND XX PLATFORM

8.1 Wellhead Equipment (Including Chokes and Flowline Isolation Valves)

Wellhead equipment is defined in the xx Design Basis [Ref1] and is a proprietary supplied item. The

materials shall be selected in accordance with the requirements of API 6A. According to API 6A for

the conditions prescribed for xx and xx the API Material Class will be “FF”, which is moderately

corrosive sour service. Sour service has been prescribed in this case based on the STHP (2000psi

for xx and 2100psi for xx) and the upper figure for H2S in Section 3.3.1, i.e. 1000ppm. This results in

a H2S partial pressure of 13.8kPa for xxand 14.5kPa for xx. The protocol for specifying wellhead

material class is to state the material class with the H2S partial pressure added as a suffix, eg. FF-

1.5kPa. Therefore, the specification for the wellheads, chokes and flowline isolation valves shall be

as follows:

XX = FF-13.8kPa Stainless Steel.

XX = FF-14.5kPa Stainless Steel

8.2 Process Equipment

8.2.1 General

The following tables summarise the materials to be used for the process equipment on both the xx

and xx wellhead platforms. Unless specifically stated, these recommendations apply equally to both

platforms.

Page 50

8.2.2 Gas Lift First Valve On (FVO), Gas Lift Header and Flowlines

Operating

Service

Dehydrated natural gas with composition defined in Section 3.3.2.

Topside piping exposed to marine environment.

Maximum

Temperature

40°C

Pressure 1250 psi (8620kPa)

Corrosion

Damage

Mechanism(s)

Internal corrosion due to wet gas from intermittent process upsets or residual

water from pre-commissioning. See corrosion rates in Appendix 2 calculated

using NORSOK M506 and discussion in Section 5.1. Corrosion will only be due

to occasional upsets of the XX platform dehydration unit. So corrosion is

expected to be marginal.

H2S partial pressure is 8.6kPa, which is greater than the level prescribed by

NACE MR0175 / ISO 15156 for sour service (0.3kPa). So sour service rated

materials are required.

External corrosion from marine environment. Mitigate corrosion using protective

coatings.

Materials Piping, Flanges and Fittings: Carbon Steel

Valves (First Valve On): Carbon Steel Body with 316L trim.

Fasteners: Refer to Section 7.4 for guidance.

Corrosion

Allowance

3.0mm

Other Internal

Corrosion

Protection

The piping should be isolated from the incoming gas lift riser using a Monolithic

Isolation Joint (MIJ) located before the First Valve On.

Page 51

8.2.3 Production Flowlines

Operating

Service

Multiphase fluid containing oil, produced water and gas with composition

described in Section 3.3.

High temperature topside piping exposed to marine environment.

Maximum

Temperature

110°C

Pressure 280 psig (19.4 barg)

Corrosion

Damage

Mechanism(s)

Corrosion from high temperature saturated hydrocarbon with high CO2 and H2S

composition.

H2S partial pressure is 0.22kPa system, which is less than the level prescribed by

NACE MR0175 / ISO 15156 for sour service (0.3kPa). However, given that the

H2S composition is close to the sour level it is good industry practice to specify

sour service requirements to allow for accidental well souring etc.

External corrosion of high temperature piping in a marine environment. Piping

will be prone to high coating breakdown and when coupled with the fact the

piping is on unmanned platforms, then an external corrosion allowance of 1.5mm

should be considered.

Instead of using carbon steel, duplex stainless steel may be used. The duplex

stainless steel must be coated to operate at 110°C.

Materials Carbon steel according to the corrosion model outputs shown in Appendix 2

shows good resistance to corrosion with a predicted metal loss between 1.3-

5.2mm. However, the inhibitor system injects corrosion at one point for each

flowline. If this single point fails then the flowline will go without inhibition for a

short period of time (as it is an unmanned platform) and this will lead to high

amounts of corrosion than was predicted by the NORSOK models. Also, due to

the high external temperatures there is a concern with the use of organic

coatings due to high coating breakdown factors and that maintenance will be

minimal given that the flowlines are on an unmanned platform. The use of 22Cr

duplex stainless steel at 110°C would not require an internal corrosion allowance

but would still have to be coated to guard against severe pitting corrosion. A

22Cr duplex stainless steel has a critical pitting temperature of 80°C and should

not be used above this temperature without an external coating. The cost

difference to go to a 25Cr super duplex stainless steel is prohibitive (ie Carbon

steel versus 22Cr DSS and 25Cr SDSS is US$1500/tonne, US$28,500/tonne.

and US$32,000/tonne respectively) and not warranted in this case.

At elevated temperature the organic coatings tend to break down and resultant

external corrosion can be quite severe. Many operators tend to use a Thermally

Sprayed Aluminium coating on high temperature piping in a marine atmosphere.

The thickness of the coating is a compromise of obtaining suitable pore overlap

whilst maintaining thermal expansion compatibility with the substrate. In this

case a coating of 180μm thick is deemed suitable. The coating shall be sealed

using a alkyd silicone topcoat.

1. Piping flanges and fittings: The recommendation is externally coated duplex

Page 52

stainless steel; external coating to be 180μm thick Thermally Sprayed Aluminium

and sealed with an Alkyd Silicone.

Valves: 22Cr duplex solid valve body.


As an alternative (if schedule and cost become a project driver):

2. Piping, flanges and fitting: Sour service carbon steel with a corrosion

allowance and externally coated with 180μm thick Thermally Sprayed Aluminium

and sealed with an Alkyd Silicone.

Valves: Carbon steel body with Inconel 625 overlay of wetted areas and

externally coated with 180μm thick Thermally Sprayed Aluminium and sealed

with an Alkyd Silicone.

Corrosion

Allowance

1. 0 mm if the recommended duplex is selected

2. (7mm XX, 6mm XX) if the alternate (option 2) described above is selected

and no credit given to pH buffering from produced water.

3. 3mm if the alternate (option 2) described above is selected and XXEPIL

accept credit due to pH buffering from produced water.

Other Internal

Corrosion

Protection

Corrosion inhibition to be injected upstream of the choke valve.

Page 53

8.2.4 Test Header

Operating

Service




Maximum

Temperature

110°C


Corrosion

Damage

Mechanism(s)


composition.







piping is on unmanned platforms, then an external corrosion allowance of 1.5mm

should be considered.

Materials Carbon steel according to the corrosion model outputs shown in Appendix 2

shows good resistance to corrosion with a predicted metal loss between 1.3-

5.2mm.. The corrosion model is known to be well within its limits for the flowline

conditions presented here. The test header will be supplied with corrosion

inhibitor from multiple flowlines and therefore inhibition effectiveness should

remain high.

At elevated temperature the organic coatings tend to break down and resultant

external corrosion can be quite severe. Many operators tend to use a Thermally

Sprayed Aluminium coating on high temperature piping in a marine atmosphere.

The thickness of the coating is a compromise of obtaining suitable pore overlap

whilst maintaining thermal expansion compatibility with the substrate. In this

case a coating of 180μm thick is deemed suitable. The coating shall be sealed

using a alkyd silicone topcoat.

Piping, flanges and fitting: Sour service carbon steel with a corrosion allowance

and externally coated with 180μm thick Thermally Sprayed Aluminium and sealed


Valves: Carbon steel body with Inconel 625 overlay of wetted areas and

externally coated with 180μm thick Thermally Sprayed Aluminium and sealed



Corrosion

Allowance

1. (7mm xx 6mm xx) if no credit given to pH buffering from produced water.

2. 3mm if xx accept credit due to pH buffering from produced water.

Other Internal

Corrosion

Corrosion inhibition to be injected upstream of the choke valve to ensure header

is covered by the inhibition.

Page 54

Protection

Page 55

8.2.5 Production Header, Pig Launcher and Last Valve Off

Operating

Service




Maximum

Temperature

110°C


Corrosion

Damage

Mechanism(s)


composition. The diameter of the lines that make up the production header and

pig launcher are bigger than those for the flowlines and test header (exposed to

the same conditions) which means the amount of shear along the wall is lower

and hence the inhibition is more effective. Also, the corrosion inhibitor is supplied

to the production header through multiple injection sites, so if one injector goes

down, there is still a good supply of corrosion inhibitor supplied through the other

flowlines. Refer to Appendix 2 for the corrosion model results.







piping is on unmanned platforms, then a corrosion allowance of 1.5mm should be

considered.

Instead of using carbon steel, duplex stainless steel may be used. The duplex

stainless steel must be coated to operate at 110°C

Materials Piping, Flanges and Fittings: Sour service carbon steel with corrosion allowance

and externally coated with 180μm thick Thermally Sprayed Aluminium and sealed


Valves, (including LVO): Carbon steel body with Inconel 625 overlay of wetted

areas and externally coated with 180μm thick Thermally Sprayed Aluminium and

sealed with an Alkyd Silicone.


Corrosion

Allowance

1. 6.0mm Including (1.5mm external) if no credit given to pH buffering from

produced water.

2. 3mm if xx accept credit due to pH buffering from produced water.

Other

Corrosion

Protection

Corrosion inhibitor to be injected upstream of the choke valves.

The piping should be isolated from the incoming gas lift riser using a Monolithic

Isolation Joint (MIJ) located after the Last Valve Off.

Page 56

8.3 Utility Equipment

8.3.1 Fuel Gas Systems

Operating

Service

Dehydrated natural gas with composition defined in Section 3.3.2.

Topside piping exposed to marine environment.

Maximum

Temperature

40°C

Pressure 1250psi (8620kPa)

Corrosion

Damage

Mechanism(s)

Internal corrosion due to wet gas from intermittent process upsets or residual

water from pre-commissioning. See corrosion rates in Appendix 2 calculated

using NORSOK M506 and discussion in Section 5.1. Corrosion will only be due

to occasional upsets of the XX platform dehydration unit. So corrosion is

expected to be marginal.

H2S partial pressure is 8.6kPa, which is greater than the level prescribed by

NACE MR0175 / ISO 15156 for sour service (0.3kPa). So sour service rated

materials are required.

External corrosion from marine environment. Mitigate corrosion using protective

coatings.

Materials Piping, fittings and flanges: Sour service carbon steel with corrosion allowance.

Valves: Carbon Steel Body with 316L trim.


Corrosion

Allowance

3.0mm

Other Internal

Corrosion

Protection

Nil

Page 57

8.3.2 Open Drains

Operating

Service

Spillages from chemical injection system, lubricants, fuel gas skid pans, pig

receiver debris.

Topside piping exposed to marine environment

Maximum

Temperature

40°C

Pressure Atmospheric

Corrosion

Damage

Mechanism(s)

The open drain system is to be resistant to a variety of hydrocarbons and

chemicals. The drains will be exposed to acidified water from process trains.

Corrosion rates are not expected to be high given the drains are at ambient

temperature and atmospheric pressure. The drains will collect solid matter and

therefore will be exposed to under deposit corrosion.

Due to the intermittent use of the drains there is a risk that the piping will be

exposed to stagnant fluids. Open drains are often contaminated with

microbacteria, which leads to fouling and blockage and MIC failure of most

metals.

Materials such as GRP-C will provide suitable corrosion resistance and require

less inspection. Open drain systems are often left off inspection programs.

Alternatively heavy wall carbon steel can be used.

The open drain vessel is 2000mm long x 900mm diameter and contains 2 weirs

and a downcomer. Due to the size of this vessel and the complexity of the

internal appurtenances, it is recommended that the vessel be made of duplex

stainless steel. UNS S32205 is recommended in this case as it is supplied with a

minimum guaranteed molybdenum content which will help impart better corrosion

resistance.

If a larger diameter vessel can be accommodated on the XX and XX platform

topsides, then the vessel may be manufactured using heavy wall carbon steel.

The inside of the vessel is to be coated with a glass flake epoxy or Belzona 1391.

The weirs shall be made to be bolted into place after the vessel is coated. The

edges of the weirs should be rounded to ensure and an even coating over the

edge which will be susceptible to damage if not thick enough. The weirs shall be

coated using the same system used for the vessel internal coating.

Materials Piping: Glass Reinforced Plastic (GRP-C)

Heavy wall carbon steel.

Valves: Nickel aluminium bronze is common for GRP piping systems.

For carbon steel piping used rubber lined carbon steel valves


Open drain vessel should be fabricated form UNS S32205 Duplex Stainless

Steel.

Pump: Carbon steel with martensitic stainless steel impellers.

Page 58

Corrosion

Allowance

6mm for carbon steel.

Other Internal

Corrosion

Protection

Piping to be free draining and free from low spots and dead legs.

Provision for the intermittent dosing of biocide shall be included on each drain

leg.

Internal weirs of the carbon steel vessel to be removable for easier coating.

8.3.3 Vent and Closed Drains and Vent Scrubber

Operating

Service

Collection of liquid and vapour stream from flowline drains and vents, and liquids

from the open drain sump.

Maximum

Temperature

40°C

Pressure 150 psi.

Corrosion

Damage

Mechanism(s)

Fluids entering the closed drains from the process should be at low pressure,

thus allowing the use of carbon steel with a 3mm corrosion allowance.

To reduce the risk of damage from stagnant fluids the pipe work must be design

to be free draining avoiding low spots and dead legs.

Materials Piping, flanges and Fittings: Carbon steel

Vessel and Piping Valves: Carbon steel with 316L trim


Vent scrubber: Carbon steel and internally coated with a Glass Flake Epoxy or

Belzona 1391.

Pump: Carbon steel with stainless steel impellers

Corrosion

Allowance

3.0mm

Other Internal

Corrosion

Protection

Piping to be free draining and free from low spots and dead legs.

8.3.4 Chemical Injection Package

Chemical injection will be from the xxx platform with only piping, distribution manifold, chokes and

injection points provided on the xx and xx platforms. Piping shall be ASTM A269 Grade 316L with a

guaranteed minimum2.5% Molybdenum and maximum Rockwell B hardness of 80. Fittings shall also

be 316L with a guaranteed minimum2.5% Molybdenum.

Page 59

8.3.5 CCVT Power Generation

The Closed Cycle Vapour Turbines (CCVT) is a proprietary supplied items and the vendor shall be

responsible for ensuring the materials of construction are suitable. As a minimum the CCVT shall be

supplied in UNS S31603 austenitic stainless steel in compliance with ISO15156.3 / NACE MR0175.

8.3.6 Hydraulic Piping Systems

Hydraulic piping shall be ASTM A269 Grade 316L with a guaranteed minimum 2.5% Molybdenum

and maximum Rockwell B hardness of 80. Fittings shall also be 316L with a guaranteed

minimum2.5% Molybdenum. If piping is to be exposed to temperatures greater than 60°C then tubing

and fittings shall be 25Cr super duplex stainless steel or Hastelloy C276 (UNS N10276).

8.3.7 Instrumentation

Due to the sour service conditions in the xx field, the instrumentation used in direct contact with the

production and gas lift equipment and piping shall be constructed out of materials in compliance with

ISO 15156. In all cases, the instrument supply vendor shall check the materials of their instrument for

compatibility with the process conditions.

Instrumentation piping (including compression fittings, and screen devices) is acceptable for XX and

XX in UNS S31600, provided the exposure temperature of the tubing is maintained below 60°C. If the

exposure temperature is greater than 60°C, then the tubing, compression fittings and associated

tubing elements, shall be 25Cr super duplex stainless steel (UNS S32750) or Hastelloy C276 (UNS

N10276). All tubing shall comply with the requirements of ISO 15156-3 for maximum sour service

exposure conditions (temperature, and pH2S) and material hardness. UNS S30400 (Grade 304 and

its derivatives) shall not be used for any equipment on xx or xx. UNS S30400 is susceptible to

chloride stress corrosion cracking at temperatures close top ambient conditions and therefore cannot

be used for pressure containment. UNS S30400 is highly susceptible to pitting in marine

environments and therefore is not appropriate for instrument enclosures or junction boxes.

Materials selection information for all other instrumentation is provided in Table 8-12.

Table 8-12 Instrumentation Material Selection Chart

Instrumentation Service Material

Thermowell Temp < 60°C UNS S31600

Temp > 60°C UNS N10276 (Hastelloy C276)

Pressure Gauge/

Switch / Element

/ Socket

Temp < 60°C UNS S31600

Temp > 60°C UNS N10276 (Hastelloy C276)

Level

Instruments

Temp < 60°C Body / Chamber – UNS S31603 (316L)

Displacer / Float – UNS S31603 (316L)

Temp > 60°C Body / Chamber – N10276 (Hastelloy C276)

Displacer / Float – N10276 (Hastelloy C276)

Transmitter / Temp < 60°C Body - UNS S31603 (316L)

Page 60

Instrumentation Service Material

Controller Element - UNS S31603 (316L)

Temp > 60°C Body - N10276 (Hastelloy C276)

Element - N10276 (Hastelloy C276)

Control Valves /

Mono-Block

Valves

Temp < 60°C Body - UNS S31603 (316L)

Trim - UNS S31603 (316L)

Temp > 60°C Body – Carbon Steel (Sour Service)

Trim - N10276 (Hastelloy C276)

Safety Valves Temp < 60°C Body/Bonnet - UNS S31603 (316L)

Nozzle / Disc – UNS S31603 (316L)

Spring / Bellows – UNS N06625 (Inconel 625)

Temp > 60°C Body/Bonnet – Carbon Steel (Sour Service)

Nozzle / Disc – UNS N10276 (Hastelloy C276)

Spring / Bellows - UNS N06625 (Inconel 625)

Orifice Plate Temp < 60°C Flange Body - UNS S31603 (316L)

Plate - UNS S31603 (316L)

Temp > 60°C Flange Body - UNS N10276 (Hastelloy C276)

Plate - UNS N10276 (Hastelloy C276)

Multiphase

Flowmeter

Materials to be advised by the vendor for approval by

XXEPIL.

Page 61

8.3.8 Wash Down Water System

Operating

Service

Water collected from the helideck

Topside marine environment.

Maximum

Temperature

Ambient

Pressure Atmospheric

Corrosion

Damage

Mechanism(s)

Water from the helideck will contain chlorides washed from the surface.

Materials Tank: GRP or Polypropylene (PP) with UNS S31603 austenitic stainless steel

fittings.

Valves: GRP, PP or Nickel aluminium bronze for GRP piping

Piping: GRP or PP.

Corrosion

Allowance

Nil

Other Internal

Corrosion

Protection

None

Page 62

9. MATERIAL SELECTION - PIPELINES

9.1 Materials and Corrosion Allowance

9.1.1 Linepipe Manufacturing Processes

For the linepipe sizes (DN80, DN100, D350) considered for the Hydra development there are two

linepipe manufacturing processes commonly used, they are:

Seamless linepipe manufacture by Pilger or Mannesmann processes;

High Frequency Induction (or Resistance) Welded linepipe (HFW).

Both processes are extensively used through the oil and gas industry for the transport of oil and gas

products in both sour and non-sour applications. Traditionally, HFW linepipe has not been the

preferred choice for gaseous service due to the risk of the welded seam splitting. There have been

very few incidents of subsea HFW pipelines splitting along the seam since welding frequencies have

increased to well above 80kHz in the early 1970’s. Common welding frequencies are now of the

order of 150-300kHz and this produces consistent high quality welds. However, it has not been until

2000’s that HFW pipe has been used extensively for gaseous service. There are several examples in

Australia where HFW has been used for gaseous service; these include sales gas in the Tasmania

Gas Pipeline (300+ km long) and raw gas at the Santos Patricia Baleen development (42km long). A

review of the supply records of two Japanese linepipe mills and one Korean linepipe mill shows that

sour HFW linepipe has been used offshore by Arco in the UK, Woodside in Australia and Norsk Shell

in Norway with strength levels equivalent to those considered for the Hydra development (X60 to

X65). These were ordered as early as 1990. Specific details about the chemistry for these fields are

not detailed on the mills supply history sheets. Nippon Steel in Hikari City, Japan, claim to be

producing a lot more sour service DNV linepipe with 250 tonnes of sour linepipe produced per month

by this mill (20% of production). Problems such as preferential corrosion of the weld seam under high

CO2 and sour service conditions are no longer a problem due to the improved homogeneity achieved

with modern linepipe welding machines, this is demonstrated in the laboratory report from Nippon

Steel in Appendix 5. Modern mill NDT techniques utilise automatic ultrasonic testing to inspect the

strip edges prior to welding, the full pipe body and then the weld seam to ensure the weld seam is

defect free. This level of NDT is unprecedented for any other linepipe form. Oil has been long

transported subsea in HFW pipes. When HFW pipe is used to and from platforms it is a normally

accepted practice to make the risers out of seamless linepipe in place of the HFW.

With the cost of HFW in 2007 currently at $US950/tonne and seamless linepipe currently at $US2200-

US$2500/tonne the use of HFW is increasing within the oil and gas industry. If cost and schedule

become priority drivers for the Hydra project then it is recommended that further investigation be

carried out on the viability of HFW pipe in sour multiphase service by surveying the various linepipe

mills supplying DNV OS F101 compliant HFW linepipe. Until such further investigation can be

undertaken to demonstrate the suitability of HFW for the xx project then it is recommended that the

FEED proceeds on the basis of seamless line pipe throughout.

9.1.2 Pipelines & Risers - Export

The pipelines and risers for the xx and xx export pipelines to xxshall be designed and manufactured in

accordance with DNV OS F101. The linepipe shall be rated for sour service even though the H2S

partial pressure is just below the critical level defined in ISO 15156 / NACE MR0175. The linepipe will

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require a 6mm corrosion allowance based on the conservative corrosion modelling (refer to Appendix

2) results and not taking credit for potential benefit of pH buffering from any produced water that may

be present in the production stream. This corrosion allowance is based on a corrosion inhibitor

efficiency of 99% and availability of 98%, which is in line with the production up time specified in the

Hydra Design Basis for equipment availability [Ref 1. Section 7.4.2]. The choice of process of

manufacture is at xx discretion, the DNV OS F101 designations are summarised below.

DNV OS F101 SMLS Grade 415 ISD

DNV OS F101 HFW Grade 415 ISD.

According to the designations above the linepipe has the following supplementary requirements:

SMLS, seamless linepipe;

HFW, High Frequency Welded linepipe;

Grade 415, 415MPa SMYS or equivalent to API 5L X60;

Level 1 NDT, required for gaseous and multiphase service;

Sour service supplementary requirement (S);

Enhanced dimensional properties (D), to assist with constructability.

The riser splash zone shall require protection over and above that for the submerged riser and the

topside piping due to the wet, chloride aerated environment.

An external corrosion allowance for the atmospheric and splash zones based on the following rule of

thumb:

Riser corrosion allowance = 2mm+1mm [(T-20)/10]

So for the xx and xx risers at 110°C, the extra corrosion allowance would require to be 11mm. This

corrosion allowance is impractical and conventional polychloroprene (neoprene) coatings are not

suitable for operating continuously at high temperatures as they will age harden and fracture.

Therefore it is proposed to install a Monel clad steel sleeve in the riser splash zone using a carbon

steel sleeve between the Monel and the riser pipe, the carbon steel sleeve in effect becomes the

corrosion allowance. It is proposed that the sleeve be fabricated from a 12mm rolled plate and the

Monel cladding be 3mm.

For the risers at xx, the external corrosion allowance for the XX riser can be reduced due to the lower

arrival temperature of 38°C at XX and 76°C at XX. However, given the importance of these risers and

the severity of the corrosion environment it is recommended to duplicate these Monel clad sleeves at

all production risers.

XXEPIL have directed that the pipeline and riser material wall thickness should be identical.

9.1.3 Pipelines & Risers – Gas Lift

The pipelines and risers for the xx gas lift pipelines to xx and xx shall be designed and manufactured

in accordance with DNV OS F101. The linepipe shall be rated for sour service. . The corrosion

modelling (refer to Appendix 2) results have over-estimated the corrosion rate as the model assumes

the gas is saturated, which is not the case. In order to temper the over-estimation of the corrosion

allowance a value for the amount of time the pipeline will be exposed to wet gas was derived and

used to proportion the corrosion rate down. In this instance it was assumed that the pipeline will be

exposed to up to 60 days per year (16%) of off-specification gas and hence will be exposed to

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corrosive conditions. The corrosion allowance was derived as 16% of the calculated corrosion rate

assuming that the corrosion inhibitor injection system is 100% available for the short durations the gas

is off-specification. The model for the gas pipeline does not assume the gas lift pipeline will be

operated when the gas is off-specification and the inhibitor system is offline, as this would be

considered double jeopardy. It is recommended that if the inhibition is offline and the gas dehydration

train also goes down, then production is shut in until either unit is brought back on line. The corrosion

allowance derived for the gas lift line is 3.0mm based on the outlet conditions. The pipeline will

transport for most of the time with dehydrated sales gas. In case of upsets it is recommended that the

pipeline be pigged to clear any water out of low lying areas in the pipeline. For a small diameter gas

pipeline it is recommended that the pipe be manufactured using the seamless process.

DNV OS F101 SMLS Grade 415 ISD (Double Random Length); or,

DNV OS F101 Grade 450 ISPD Coiled Line Pipe with DNV OS F101 SML Grade 415 ISD for

the risers.

According to the designations above the linepipe has the following supplementary requirements:

SMLS, seamless linepipe;

Grade 415, 415 MPa SMYS or equivalent to API 5l X60;

Level 1 NDT, required for gaseous and multiphase service;

Sour service supplementary requirement (S);

Enhanced dimensional properties (D), to assist with constructability;

Line pipe exposed to plastic deformation exceeding 2% supplementary requirement (P)

required for Coiled Line Pipe.

The gas lift risers at xx and xxwill operate continuously at temperatures less than 40°C, and a

splashzone coating provided by a high quality polychloroprene will be sufficient. As for the export

pipeline, the ID of the riser should be matched to that of the pipeline to ensure free passage of pigs.

For the gas lift pipelines it may be required to procure a small order of riser pipe (DRL) if pipeline is

procured as coiled line pipe. In this case the riser procurement will be less than 50 tonnes and

according to DNV OS F101 the linepipe mill is not required to conduct manufacturing procedure

qualification testing. This is acceptable provided the mill performs Charpy V-notch impact testing over

a range of temperatures form +20°C to -60°C to show that the risers have sufficient low temperature

toughness at the minimum design temperature for the pipeline.

9.1.4 Pipeline Fittings

Pipeline fittings shall be manufactured in accordance with DNV OS F101 Section 7 and shall be

forged in accordance with the requirements of ASTM A694. Any subsea flanges shall have a ring

groove type gasket. The gasket shall be manufactured from Inconel 625 and the ring groove shall be

weld overlayed with Inconel 625.

9.1.5 Chemical Injection line (Flat-Pack)

The chemical injection system will be supplied from the xx using either a flat pack or conventional

umbilical. The flat pack umbilical is a simple four steel hose umbilical with a polymeric outer sheath.

It is recommended that the flat pack be made up using continuous 316L tubing and a polypropylene

outer sheath, if the vendor cannot guarantee the performance or quality of the external coating of the

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tubing over the design life then consider duplex stainless steel. The umbilical vendor shall warrant

the design of the flat-pack, including material performance.

9.1.6 Clamping and Strapping materials

The Flat-Pack may be piggybacked from xxto xx and xx on the gas lift pipeline. If this is done, then

the Flat-Pack should be strapped using a compliant, yet tough strapping material. A metallic strap is

not recommended if the strap is to contact the Flat-Pack outer sheath as the metallic strap can cut

into the umbilical outer sheath. Other operators installing piggyback lines have used Kevlar tm 4 straps

to secure the pipes together. The Kevlar is very strong and tends not to have the sharp edges that

metallic straps create. Kevlar strapping is more expensive than metallic banding.

9.2 Coating Systems

9.2.1 Pipeline Anti-Corrosion Coating System

FBE coatings become increasingly hydroscopic with increase in operating temperature – this leads to

disbondment of the coating from the steel substrate. It is for this reason that FBE applied to

submarine pipelines is limited to a maximum continuous operating temperature somewhat lower than

that specified in dry conditions.

The maximum operating temperature of FBE in submersed wet service is some 20 degree lower than

for dry service; it is not recommended to consider FBE coatings for subsea service at continuous

operating temperatures in excess of 90ºC.

As the production pipeline operates at a temperature over 100°C then the practical choice of linepipe

coating recommended is a 2mm 3-layer polypropylene coating.

The temperature profiles generated during the flow assurance studies show that the production line

temperature will not drop below 90°C for at least 3000m from the xxriser base and 2000m from the

XX riser base. Anti- slip bands may be necessary to be fixed to the polypropylene coating to stop the

concrete weight coating from slipping off the pipe during installation.

For the low temperature gas lift pipelines (maximum continuous operating temperature~40°C) the

recommended coatings are:

2mm 3LPE – for coiled line pipe installation

0.5mm FBE for risers and double random length line pipe

The gas lift pipeline will not be concrete weight coated.

9.2.2 Riser Coating Systems

ATMOSPHERIC ZONE

The atmospheric zone above the riser hang-off flange shall be coated using an Ultra High Build

epoxy. The coating shall be applied to a DFT of 1000-1500μm and shall be applied to a Class 2.5

(near white metal) blast cleaned surface with a 75-100 μm angular profile. The atmospheric zone

between the top of the splash zone coating / sheath system to the (and including) the riser hang-off

flange shall be coated using a flame sprayed polypropylene. The flame sprayed coating shall be

2500μm thick and be free from porosity (test using a holiday tester). The flame spraying procedure

4 Kevlar is a registered tradename of the DuPont organisation.

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shall be qualified and tested prior to application to the xx and xx risers. The Coating Procedure

Qualification shall be witness by xx or its representative.

SPLASH ZONE

Riser splash zones are typically coated with Polychloroprene rubber for temperatures up to 90°C and

for temperatures above this, then Monel 400 (UNS N04400 cladding or sheaths and used). For xxand

xx where temperature of the export riser is 110°C, then Monel 400 is the best choice for splash zone

protection. If external Monel cladding is used the minimum thickness shall be 3mm clad over carbon

steel rolled plate of 12mm thickness. The bottom end (500mm) of the Monel sheath shall be shop

coated using the same coating system as the submerged zone coating to minimize the potential for

galvanic attack. Similarly, the top section. shall be coated for a distance of 300mm with the

atmospheric zone coating to avoid galvanic attack.

For the gas lift risers it is recommended that Polychloroprene rubber be used for the riser splash zone

protection.

SUBMERGED ZONE

The submerged zone shall be coated in accordance with the coating used for the main pipeline

coating.

0.5mm FBE for gas lift risers

2.0mm for the 3-layer polypropylene risers.

9.3 Cathodic Protection

9.3.1 Sacrificial Anode System

The pipeline systems shall be protected using sacrificial anodes. The anodes shall be of the bracelet

type made of Galvanum III. The design of the amount and position of bracelet anodes shall be in

accordance with DNV RP B401; this is more conservative than DNV RP F103 [Ref 12] but will provide

greater protection should coating application not be in strict accordance with DNV RP F106, which RP

F103 is dependent.

9.3.2 Corrosion Protection System Isolation – MIJs

The subsea pipeline and riser shall be electrically isolated from the platform jacket CP system and the

topside piping. The insulation should be made using high integrity insulation joint such as a

monolithic isolation joint. Care shall be taken to ensure that the MIJ is not short circuited by pipe

supports or through contact between the riser and the jacket clamps. Riser clamps shall be lined with

Neoprene rubber to ensure the riser is electrically isolated from the jacket CP system.

Insulating gaskets sets shall be used to isolate the duplex stainless steel flowlines from the production

and test headers. Any drain or vent connections made to the duplex stainless steel flowlines shall

also be electrically insulated using insulating gasket kits.

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10. ASSET INTEGRITY MANAGEMENT

10.1 General Philosophy

There should be an integrity management plan developed for the xx Platform based and subsea

assets. This integrity management plan should aim to provide the following outcomes:

Provide a documented and auditable system that enables owner to measure and manage the

on-going risk of the xx and xx platforms and intrafield pipelines;

Ensure that the environmental and safety integrity of the system is maintained by detecting any

deterioration before leakage of production fluids;

Ensure that the assets remain fit for purpose;

Ensure that the assets function in accordance with the legislative approvals for the

development;

To ensure the assets continue to meet the production requirements of the development;

To prevent breakdowns and unplanned outages;

To enable corrective action to be carried out in a timely manner and to maintain the systems

failure risks to As Low as Reasonably Possible (ALARP).

These outcomes should be obtained by documenting a system that considers all of the corrosion

activities as part of the system operation. The following activities are considered core corrosion

engineering activities, which form a part of the Integrity Management Plan:

Corrosion mitigation (refer to Sections 8 and 9);

Corrosion monitoring (refer to Section 11);

Corrosion data collection and assessment (refer to Section 12).

This system is best documented prior to the commissioning of the system and should incorporate

input from both the corrosion / inspection engineer as well as operations staff who will be responsible

for a lot of the data gathering and corrosion mitigation equipment operation.

10.2 Recommended Routine Maintenance Activities

Planned/routine activities are defined as those activities that have defined intervals and locations in

which they are carried out. This section details the type of activities that shall be included as part of

the Panna integrity management system.

The type of activities, locations and intervals in which they are conducted can vary depending on the

following:

Variation in operating conditions;

The detection of anomalies/failures;

Advent of new technology.

It is recommended that xxL prepare a risk based inspection plan to assist in the preparation of a

traceable and auditable platform and pipeline management plan. Such a plan shall document and

justify activities, locations and return periods required to manage on-going risk.

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It is the responsibility of the Corrosion and/or Inspection Engineer to have the most up to date

knowledge of the process, corrosion mechanisms and monitoring technologies available and

references in the xx and xx integrity management system.

10.3 Possible Unplanned Activities

Unplanned or non-routine activities relate to items such as corrosion failures (i.e. leaks, ruptures or

loss of facilities/utilities), and unplanned or opportunistic inspections (such as having an ROV

available during subsea interventions). While it is impossible to provide long term plans for these

situations, it is possible to have in place procedures, or response plans, that enable the capture and

assessment of inspection results arising from these activities.

Opportunistic inspections may result from an anomaly generated from other inspections or monitoring

activities. Information from these activities should be processed in the same manner as the routine

inspections, including the use of the data as input into the corrosion risk assessment.

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11. CORROSION MONITORING

11.1 Aim

The aim of corrosion monitoring is to ensure that the design life will not be adversely compromised

during service and to ensure the safe and economic operating life of a facility. The monitoring may

also be used to optimise inspection intervals as part of a risk-based inspection (RBI) programme and

to detect changes in corrosivity that will invalidate inspection periods or endanger the plant.

The primary philosophy is that corrosion monitoring will be specified when:

1. Changes in the operating environment can lead to significant increase in the corrosivity of the

environment towards carbon steel, either with or without corrosion inhibitors.

2. Loss of corrosion inhibition will lead to rapid metal loss.

3. The outcome of corrosion monitoring can lead to timely re-assessment and adjustment of the

system of corrosion management.

4. Monitoring could lead to optimisation of inhibitor dosing.

The functional requirement of the corrosion monitoring system is that it shall detect and quantify

trends in the corrosivity of the fluids and shall do so within a time frame short enough to enable the

Operator to instigate or adjust corrosion mitigation measures before significant metal loss has

occurred.

11.2 Monitoring and Testing Facilities

Systems potentially at risk of corrosion will require corrosion monitoring facilities, such as corrosion

coupons or corrosion probes. Where monitoring is required, two access fittings should be installed for

the purpose of monitoring with electrical resistance (ER) probes and corrosion coupons. The probes

and coupons shall be of a type and dimension such that the sensitive element shall be in the water

phase.

The following points shall also be taken into consideration:

Some systems will also need sampling points for chemical analysis.

Systems at risk of bacteria contamination will require bio-probes and/or sample points.

Other testing facilities relevant to corrosion and integrity management will be necessary in the

appropriate system.

All carbon steel systems will require Non Destructive Testing at some point in their service life.

Some systems will require routine (e.g. monthly or quarterly) NDT at Sentinel points.

All equipment should be designed and located considering the requirement for corrosion-

monitoring technician and/or inspector access.

All locations for corrosion monitoring and sampling should be clearly marked on P&IDs and

Isometric drawings. Locations for Key Point UT at Sentinel points should be marked on

Isometric drawings.

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11.3 Monitoring Methods

Corrosion monitoring should not rely on just one method and should use any method that enables an

operator to estimate or measure the corrosion rate occurring in service of an item of plant, or the

corrosivity of a process stream. The main methods fall into the following categories:

1. On-line corrosion monitoring techniques to assess corrosion rates and changes in corrosivity

with time, such as electrical resistance probes, electrochemical probes, field signature

monitoring (FSM), flexible ultrasonic transducer mats (Fleximats), bio-probes and corrosion

coupons.

2. Analysis of process streams for pressure, temperature, production rates, fluid chemistry, CO2

and H2S gas concentrations, water content, dew point, dissolved oxygen, pH, corrosion

product (Fe and/or Mn) concentrations, bio-activity, chemical treatments (e.g. dose rate,

frequency and residual levels).

Monitoring and inspection are overlapping tasks that need to be put in place to confirm:

1. Actual versus predicted corrosion rates

2. Process parameters are within design limits

3. Correct operation of control measures

4. Current condition of equipment

Monitoring encompasses the ongoing monitoring of the corrosion process and the measures taken to

control it, whereas inspection provides mechanical integrity assurance and datum points against

which corrosion monitoring can be related, calibrated and quantified.

Inspection techniques to assess changes in wall thickness, calibrate on-line corrosion monitoring and

detect material defects, pitting and cracking, include ultrasonics (UT), radiography, thermography,

visual examination, dye-penetrant, eddy current and magnetic particle inspection. Detailing of

inspection requirements is outside the scope of this document.

11.4 Corrosion Monitoring Techniques and Equipment

The following monitoring techniques shall be used. Where corrosion monitoring is to be performed at

an identified location, access fittings should be provided for the use of both an ER Probe and a

corrosion coupon.

11.4.1 Electrical Resistance (ER) Probes

ER probes shall be used in hydrocarbon process environments such as gas and condensate

lines.

Flush mounted ER probes mounted at the 6 o’clock position may be used in sweet (i.e. non-

H2S containing) gas/oil/water environments.

Tubular ER probes shall be used if space access prevents the location of access fittings for

flush mounted probes at the 6 o’clock position (or where there are concerns in produced water

lines that iron sulphide deposits may cause bridging and crevice corrosion). Where tubular ER

probes are used, particularly for gas circuits and if mounted at the 12 o’clock position, they shall

be of sufficient length that the sensitive element is positioned at 5mm above the bottom of the

line.

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Probes shall be of the retractable type, with elements manufactured from steel of the same type

as the piping system being monitored, rated for the pressure of the system being monitored.

The probes shall be supplied complete with a probe adaptor to make cable connection to the

probe.

For each probe supplied an identical probe shall be supplied as a spare. All spare elements

shall be properly protected in VCI paper to eliminate corrosion or contamination prior to use.

Remote Data Collectors (RDCs) should be used in remote locations and/or in critical systems

where loss of corrosion inhibition or process control could result in rapid metal loss.

Measurement frequencies should be set initially at 60-minute intervals, but this can be

increased or decreased (down to 5-15 minutes if required) depending on the service

experience. For highly critical systems, such as at the inlet to the MTA-TCPP pipeline, the use

of data transmitters linked to the TCPP control room should be considered in order to provide

audible and visual alarms and initiate corrective action if preset KPIs are exceeded.

11.4.2 Coupons

Coupons should be installed wherever ER probes are used to provide supplementary

information, particularly for corrosion morphology (e.g. pitting, erosion/erosion-corrosion).

Coupons should be removed at intervals of 1 to 3 months depending on the corrosivity of the

environment and or the likelihood of loss of inhibition or process control.

Coupons may be strip type, ladder type or flush disc type.

Where strip type coupons are used in access fittings mounted at the 12 o’clock position, the

length of the coupon and coupon holder should be ordered such that tip of the coupon is held

approximately 5mm from the pipe bottom.

Each coupon holder shall be a retractable type and allow positioning of the coupons as

required to obtain the optimum position at the bottom of the pipe where the corrosive aqueous

phase is most likely. Coupon holders should be supplied without coupons. Strip and ladder

type coupon holders shall be capable of holding twin coupons.

Each coupon shall be supplied pre-weighed with a serial number and the weight clearly shown.

For each coupon holder, 4 (four) pairs of coupons should be supplied to provide a minimum of

one years monitoring. Coupons should be supplied individually wrapped and protected.

Industry accepted standards for the use of coupons covering coupon preparation, cleaning and

inspection, and reporting of information include:

a. ASTM G4 Conducting Corrosion Coupon Tests in Plant

Equipment

b. ASTM G46 Practice for Examination and Evaluation of Pitting

Corrosion

c. ASTM G81 Practice for Preparation of Metallurgical Specimens

d. ASTM G31 Laboratory Immersion corrosion Testing of Metals

(covers cleaning of coupons)

e. NACE RP 0775 Preparation and Installation of Corrosion Coupons

and Interpretation of Test Data in Oilfield Operations

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11.4.3 Bacterial Monitoring and Bioprobes

In order to detect and quantify the propensity for microbially induced corrosion (MIC) it is necessary to

quantify both the planktonic (mobile) and sessile (surface adhering) bacteria in accordance with API

RP 38. Bacterial monitoring using bioprobes will not be required for the xx and xx pipelines, but

planktonic bacteria should be assessed periodically (e.g. 6 monthly) by removing a sample from the

respective pig receivers on xx after pigging operations into a sealed standard serial dilution kit at the

sample site.

11.5 Process Stream Monitoring

Process stream monitoring for the production system should comprise:

Flow rate (gas/condensate)

Temperature and pressure

CO2 in the gas phase

Water chemistry and iron/manganese counts in the water from the pipelines

Solids production

Production chemical additions (rate and type) and periodic measurement of inhibitor residuals

Planktonic and sessile bacteria monitoring in the water from the pipelines

Corrosion product examination and bacteria analysis after cleaning pig runs

Process stream monitoring for dehydrated gas streams systems should also comprise testing

of the water dew-point of the gas.

11.6 Corrosion Monitoring Instrumentation

Where specified, corrosion measurements for ER probes should be taken by either hand-held

portable instruments or fixed instrumentation, as follows:

Portable instruments used to take periodic readings for temporary storage and download to a

personal computer or laptop computer. This may be appropriate for ER probes located at the

xxplatform where there will be sufficient staff to perform the required duties, but fixed

instruments would be more appropriate for an unmanned wellhead platform such as xand xxP.

Fixed instruments (Data Collection Units) for continuous monitoring at regular intervals and the

storage of the corrosion data to removable memory module for subsequent download to a

personal computer or laptop computer. This is highly recommended for an unmanned offshore

platform such as xx and xx

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12. CORROSION DATA MANAGEMENT AND ASSESSMENT

12.1 General Requirements

Data management is an important part of the corrosion management system. The overall purpose is

to maintain records of relevant data for analysis purposes.

12.2 Data Collection Frequency

Data collection will be dependent on the inspection program developed for the Panna and Mukta

assets and the sampling rate for the process conditions and corrosion monitors. It is recommended

that this data be stored on a database that interfaces with the plant control systems for operational

data. Corrosion data should be managed as part of the overall pipeline integrity management system.

12.3 Data Storage

Data storage shall be controlled in accordance with the quality assurance requirements of the

operation and the relevant legislative requirements. Most data will be electronic and therefore should

be backed-up as part of the routine disaster recovery system for the operations computer system. A

database is recommended for collating inspection and process data as well as controlling hard copy

inspection records, photographs and reports.

12.4 Data Assessment

Data assessment should include the review of process trends and corrosion monitoring equipment

results. In addition to the operational data, an assessment of the field inspection and maintenance

performance with regard to the inhibitor injection system availability should also be carried out. The

trends and instantaneous results should be reviewed against a benchmark or KPI for the asset.

Where adverse trends are starting to form then corrective action needs to be put into place by the

field corrosion/inspection engineer in conjunction with other disciplines involved in operating the

assets as appropriate. Procedures should be developed to ensure standard methods are employed

that are industry based and ensure repeatability.

12.5 Corrosion Reporting

Corrosion reporting shall include all the latest data and comparisons of this data with the historical

data. The report should detail the current operational conditions if different from normal, if there are

any corrective actions required and follow-up to corrective actions made previously. A standard

report format is recommended to make the report easier to read by the various end users and to allow

repeatability and comparison of previous data. The report should have a section for conclusions and

recommendations

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13. CORROSION PERFORMANCE TRACKING

13.1 General Requirements

It is important to be able to monitor and evaluate the performance of the corrosion management

system. The methodology below presents one possible evaluation standard.

The process of performance measurement includes consideration of:

Setting performance measures (key performance indicators (KPI’s));

Frequency; and

Corrective Actions.

13.2 Key Performance Indicators

KPIs take into account five key performance areas, these being:

Health, Safety and Environment KPIs.

Operational KPIs.

Budget KPIs.

People KPIs.

Transition KPIs.

The specific KPIs are unique to each process, and are outside the scope of this document.

In particular, the following KPIs are recommended:

Chemical corrosion inhibitor system availability, target 98%.

Off-specification gas lift gas (i.e. wet), target < 60 days per annum.

Scale inhibitor system availability, target 99%

Sand detection measurement and system availability, target 99%.

Pipeline corrosion monitoring availability and temperature and corrosion rate correlations to

predictions, target 99%.

Pig run plan performance, planning and analysis, target plan completion including analysis

within 4 weeks of planned activity.

Process sample monitoring and analysis (including gas, liquid and solids sample analysis),

target analysis and reporting within 1 week of planned activity.

Typically, the KPI’s shall be used to report against during the quarterly and annual reporting to

Management.

13.3 Corrective and Preventative Action

Substandard performance shall be investigated and reported if improvements are to be made and

mistakes eliminated. It shall follow the formal Technical Change Management processes.

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Where KPI’s have not been achieved it is important that the cause(s) are identified and that any

necessary measures to ensure that the system can be improved are implemented. It is the constant

re-examination and incorporation of lessons learnt that leads to improvement of any integrity

management system.

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14. REFERENCES

x

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Appendix 1 – Temperature and Pressure Profiles (1 Page)

Appendix

Appendix 2– Corrosion Model Results (2 x A3 Pages)

Appendix

Appendix 3– List of Uninhibited Events (2 Pages)

Appendix

UNINHIBITED EVENTS

A listing of potential uninhibited events that should be considered is given in the table below. This is

not an exhaustive list; other event may occur in specific installations.

Table 1: Uninhibited Events

Event Detection system Control system

options

Comment/

Impact

Incorrect inhibitor arrives at site:

Inhibitor formulation changed by supplier

(or their suppliers)

Supply mix up from supply base

Interference in supply

Physical tests on

inhibitor when it

arrives on site.

Probably detectable

by inhibitor residuals

QC system on

inhibitor supply

Inhibitor runs out at the wellsite due to

inadequate stock levels on site or supply

base

Monitoring amounts

used and cross

checking

Stock control

system

Automatic level

gauges

Tie in to control

room alarms

KPIs

Wrong inhibitor loaded into tank by

operators

Probably detectable

by inhibitor residuals

Training and

Procedures

KPIs

Inhibitor tank allowed to run empty Inhibitor returns Training and

Procedures

Tie in to control

room alarms

KPIs

Inhibitor incorrectly diluted Monitoring amounts

used and cross

checking

Training and

Procedures

Inhibitor Pump Breakdown Inhibitor returns Manual

checking

Flowmeters

Backup pump

options (none,

available in store,

available on site,

automatically

switched over)

Power failure to pump, with production

still continuing

Pump could be

alarmed

Inhibitor returns

Manual

checking

Flowmeters

Final option is to

shut down

production

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Event Detection system Control system

options

Comment/

Impact

Power failure to pump, with which also

stops production

Pump could be

alarmed

Manual

checking

Flowmeters

May have little or

no impact

(depends on

corrosion rate and

inhibitor

persistency in

non-flowing

conditions)

Inhibitor delivery from tank to injection

location fails (line blockage, failure)

Inhibitor returns Flowmeters Inhibitor selection

related.

Use portafeed

type tanks

(cleaned

regularly), rather

than permanent

tanks which may

build up deposits

Injection rate incorrectly set Monitoring amounts

used and cross

checking

Training and

Procedures

Operating conditions change, requiring a

change of injection rate which is not

carried out

Training and

Procedures

Pigging required for distribution of

inhibitor and not carried out.

Training and

Procedures

Oxygen allowed to enter the system;

corrosion inhibitor ineffective against

Oxygen corrosion

KPI

Bacteria allowed to enter the system;

corrosion inhibitor ineffective against

Microbiologically induced corrosion

Cultures from water

samples

KPI

Operating environment changes and

inhibitor becomes totally ineffective

replacement

inhibitor has to be

selected

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Appendix 4– Chemical Datasheets (5 pages)

Appendix

Appendix 5– Laboratory Test of HFW Seam Corrosion Susceptibility (1 page)

Appendix

A Typical Material Selection Report

Documents

Transcript of A Typical Material Selection Report