Handout Pims 04 -05 Sept 2020.pdf

04 - 05 September 2020

Virtual Educational Training Programme

Pipeline Integrity Management System 04 - 05 September 2020 Technical Program DAY - 1 08:45 - 09:00

Registration & Inauguration

09:00 - 10:00

Introduction to Integrity Management Plan Mr. N Manohar Rao,

10:00 - 11:00

Pre-Design Survey

former Executive Director, BPCL Mr. Pankaj Panchal Corrosion Protection Specialist Pvt Ltd

11:00 - 12:00

Coatings

Dr. Buddhadeb Duari

Lalita Infraprojects Pvt Ltd 12:00 - 13:00

Materials and Design

Prof V S Raja IIT Bombay

13:00 - 14:00

Pre-Commissioning Integrity

Mr. Sumeet Kataria Electro Corr-Damp Pvt. Ltd

09:00 - 11:00

Integrity Assessment Tool

Mr. Ashish Khera Allied Engineers

11:00 - 12:00

Data Analysis and Interpretation

Mr. Pankaj Panchal Corrosion Protection Specialist Pvt Ltd

12:00 - 13:00

Risk Assessment

Ms. Darshan Upama GM(Elect), IEOT, ONGC

13:00 - 14:00

Regulatory Requirements

Mr. N Manohar Rao former Executive Director, BPCL

14:00 - 14:15

Q & A and Valedictory session Correspondence Address

DAY- 2 :

NACE International Gateway India Section 305-A, Galleria, Hiranandani Gardens, Powai, Mumbai – 400076, India Tel: 022-25797354 Email: [email protected] / [email protected] Website: www.naceindia.org / www.corcon.org Contact Person : Mr. Rishikesh Mishra : 9820459356 / Mr. Manoj Mishra 9820631320

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PIPELINE INTEGRITY & CORROSIONAN OVERVIEW N Manohar Rao

PIPELINE INTEGRITY MANAGEMENT

World Energy Scenario Primary Energy consumption of India with respect to total world’s consumption • • • • • • •

US China Russia Japan India Canada Rest

20.4% 17.7% 6.0% 4.5% 3.8% 2.9% 44.7%

PIPELINE INTEGRITY MANAGEMENT

Energy Sharing in India 1% 1% 6% 31%

53%

Oil

 

Natural Gas

9%

Coal

Nuclear Energy

Hydro electric

Dependency

Coal

Oil

Gas

World

29%

35%

24%

India

53%

31%

9%

Share of OIL & Gas in world is 59%, in India 40% of Total Energy To push the growth, Hydrocarbon Vision 2025 introduced

Source: BP Statistical Review of World Energy- June 2010

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HYDROCARBON VISION 2025  Assure Energy Security domestic production and oil equity abroad  Cleaner Environment  Globally competitive industry  Free market, open competition  Total appraisal of sedimentary basins, to optimize exploration activities.  Acceleration of Exploration efforts

PIPELINE INTEGRITY MANAGEMENT

Key Developments • Increasing Domestic Oil & Gas Production • Acquisition of acreage in other countries • Better Reservoir Management

• APM dismantling • LNG import • Surplus refining and marketing capacity • Improving pipeline Connectivity PIPELINE INTEGRITY MANAGEMENT

Key Developments • Encouraging Laying of Transportation

Infrastructure • De licensing of various activities • Attractive fiscal regime for inviting private participation • Regulatory mechanisms • Strategic Storages PIPELINE INTEGRITY MANAGEMENT

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Modes of transportation



Road



Rail



Pipeline



Sea route

PIPELINE INTEGRITY MANAGEMENT

Limitations of road transport • • • • • • •

No. of road tankers will increase Hazards /risk will increase manifold Infrastructure required for additional traffic Diesel requirement to increase Vulnerable to calamities Pollution to increase Supply in discrete batches PIPELINE INTEGRITY MANAGEMENT

Advantages of pipeline transport • • • • • • • • •

Safe mode of transport Least contact with population- minimal hazards Reliable & regular supply Economic mode for large distances No/ less pilferage Reduced road congestion Enhance efficiency Most environment friendly system Ability to traverse most difficult terrain PIPELINE INTEGRITY MANAGEMENT

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Products transported through pipelines 

CRUDE OIL



PRODUCT



PETROL



DIESEL



ATF



NAPTHA



KEROSENE PIPELINE INTEGRITY MANAGEMENT

Petroleum & Gas Pipelines COMMON ISSUES - India Pipeline Right of Way Interferences Other Pipelines AC/ DC Electric Systems Public National Code & Practices Trained Manpower GOI / Corporate Policies

PIPELINE INTEGRITY MANAGEMENT

Manpower Requirements “Skilled manpower is the greatest Asset’”. Skilled manpower is essential to achieve the target set forth in the “ Hydrocarbon Vision 2025”. • Skill Shortage in Up Stream, Mid stream & Down stream Sector • Shortage is in the field of Corrosion as corrosion Engineer, Coating Inspector, Cathodic Protection Specialist etc.

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Manpower Requirements • Not enough talent is available to the sector at the entry level because no specific subject on corrosion in Engineering courses. • NACE can provide better facility in the field of corrosion to achieve “ Hydrocarbon Vision 2025”.

PIPELINE INTEGRITY MANAGEMENT

PIPEINE INTEGRITY MANAGEMENT  The energy demand in the form of Oil and Gas has been increased.  The energy exploration & transportation across continents have expanded 

More and stringent demands are inflicted upon the pipeline operators.

To face the challenges the Pipeline Integrity Management [PIM] has been developed and practiced widely in USA and Europe.

PIPELINE INTEGRITY MANAGEMENT

PIPEINE INTEGRITY MANAGEMENT 

Pipeline Integrity Management starts from the time the “Pipeline Project” is conceived



It involves ,

1. Total Design Review 2. During Construction 3. Maintenance Program/ Plan. 

PIM is a business process and a tool to mitigate failure causes and threat to the pipeline.



PIM maximizes the profitability and productivity of the pipeline assets through the proven strategies. PIPELINE INTEGRITY MANAGEMENT

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WHY PIPEINE INTEGRITY?  Fitness for the purpose and /or extending the life of the pipeline.  Accounting for accuracy and confidence level.  To detect damage or defects before they cause serious problems and ensures pipeline do not become defective or damaged and inoperative.  To determine extent of pipeline replacement and/ or repair work to ensure safe & Efficient working of Pipelines. PIPELINE INTEGRITY MANAGEMENT

WHAT IS ACHIEVED BY PIPEINE INTEGRITY? 

Demonstrate technical integrity of the pipeline throughout the asset life.



Reduction of pipeline failures resulting in cost advantages in million of Rupees.



Early risk characterization.



To provide world class oil and gas transportation system.



Ability to control operation effectively.



In short PIM ensures pipeline is safe and defect free.

PIPELINE INTEGRITY MANAGEMENT

MANAGEMENT OF PIPELINE INTEGRITY  Various techniques are available to access pipeline conditions including one or combination of the following techniques

 In line Inspection / Intelligent Pigging  Hydrostatic Testing.  Use of Corrosion Monitoring / Survey Data  Coating conductance Survey.

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DEFECTS DISTRIBUTION

PIPELINE INTEGRITY MANAGEMENT

CORROSION defined as deterioration of a substance (usually metal) or its properties because of reactions within its environment is a well-known natural phenomenon and one of most important factors that affects integrity & management Industrial & Infrastructure assets Source: Shri R P Nagar

PIPELINE INTEGRITY MANAGEMENT

PIPELINE INTEGRITY & CORROSION Route Cause Nos.

Name

Category Nos.

Remarks

Name

1

Internal Corrosion

1

Internal Corrosion

2

External Corrosion

2

External Corrosion

3

Stress Corrosio Cracking

3

Stress Corrosion Cracking

4

Defective Pipe Seam

4

Manufacturing and Related Defects

5

Defective Pipe

6

Defective Pipe Weld Girth

7

Defective Fabricaion Weld

5

Construction and Related Defects

8

Wrinkle Bend or Buckle

9

Striped Thread / Broken Pipe / Coupling

10

Gasket O'ring Failure

11

Control / Relief Equipment Malfunction

12

Seal Pump Packing Failure

13

Miscellaneous

Time Dependent

Stable

6

Equipment and Related Defects

Source: Shri R P Nagar

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PIPELINE INTEGRITY & CORROSION Route Cause Nos.

Category

Name

Nos.

14

Instantaneous Failure

15

Delayed Failure

16

Vandalism

17

Incorrect Operations and Procedures

18

Cold Weather

19

Lightning

20

Heavy Rains / Floods

21

Earth Movements

22

Unknown

Remarks

Name

7

Third-Party Inflicted Damage

8

Incorrect Operations and Procedures

9

Weather and Earth-Related and other outside Forces

Time Dependent

Source: Shri R P Nagar

PIPELINE INTEGRITY MANAGEMENT

SELECTION OF MATERIALS FOR ENGINNERING APPLICATIONS Safety Electrochemical

Cost & Availability

Mechanical Properties

Unique Chemical Corrosion Resistance

Material

Thermodynamic

Metallurgical Appearance

Fabricability

Physical Thermal & Electrical Characteristics

Corrosion Resistance is one of major factors for the selection of materials for engineering application PIPELINE INTEGRITY MANAGEMENT

RECOMMENDED ROAD MAP INCREASE AWARENESS OF

High Cost of Corrosion & Potential Savings CHANGE MISCONCEPTION

That nothing can be done about corrosion IMPROVE

Education & Training of Personnel & Corrosion Technology through Research Development & Implementation PIPELINE INTEGRITY MANAGEMENT

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RECOMMENDED ROAD MAP DEVELOP ADVANCED  Design practices for better Corrosion Management  Life Prediction & Performance Assessment Methods

INTRODUCE Policies, Regulations, Standards And Management Practices To increase Corrosion savings through Sound Corrosion Management PIPELINE INTEGRITY MANAGEMENT

Thank You ! PIPELINE INTEGRITY MANAGEMENT

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PRE-DESIGN SURVEY Presented by

Pankaj Panchal NACE, Corrosion Specialist NACE, Cathodic Protection Specialist

Mobile : +91 93772 76131 E-mail : [email protected]

Corrosion Cures Pvt. Ltd.

Pipeline Integrity Management System

OUTLINE

 Soil Resistivity  Soil Chemical Analysis  Parallel Pipeline Details  Existing CP System in vicinity  AC / DC Powerlines

Pipeline Integrity Management System

SOIL RESISTIVITY  Wenner – 4 Pin Method  Soil Box  Probe  Electromagnetic Induction Method

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SOIL RESISTIVITY – WENNER 4 PIN

Resistance Test Instrument C1 P1

a

a C1

C2 P2

P1

a P2

r=2paR

C2

Pipeline Integrity Management System

SOIL RESISTIVITY – WENNER 4 PIN

Pipeline Integrity Management System

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SOIL RESISTIVITY – SOIL BOX

Pipeline Integrity Management System

SOIL RESISTIVITY – EM INDUCTION

Pipeline Integrity Management System

SOIL ANALYSIS  pH  SRB  Chloride  Sulphates  Other

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Pipeline Integrity Management System

CORPS CORROSION ASSESSMENT I am CP Current and not following Owner, Project’s Paths. I always take shortest path.

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CORPS CORROSION ASSESSMENT

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CORPS CORROSION ASSESSMENT

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Minimum data required to design the CP system  Pipe to soil potential at nearest existing pipeline.  Existing cathodic protection station locations, rated and operating parameters.  Distance from existing anode bed to new pipeline.  Soil resistivity at existing anode bed locations (Note: Anode bed must be in OFF condition during the soil resistivity measurement).  Soil resistivity along the new pipeline route.  Soil resistivity at proposed new anode bed locations.  AC potential measurement at nearest existing pipeline (Specially in case of an existing nearby high tension AC Power line / Sub Station / Power Plant that is found in close vicinity). Pipeline Integrity Management System

BONDING WITH EXISTING P/L Bonding ■ Most common stray current mitigation method is the installation of a bond. ■ A resistor installed between the two structures.

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BONDING WITH EXISTING P/L Advantages of resistance bonds  Relatively inexpensive installation  Easy to adjust if stray current magnitude changes  High current capacity

Pipeline Integrity Management System

EXISTING STRUCTURES

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CORROSION ASSESSMENT

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Attenuation General

■ Attenuation is electrical losses in a conductor caused by current flow. ■ Attenuation is a major factor in the design of CP System for long pipelines. ■ The poorer the dielectric properties, the greater the attenuation. ■ Attenuation can be significantly reduced with the increase in dielectric properties of coating. ■ Good-quality coating will significantly diminish attenuation, also at the same time it will enhance the uniformity of current distribution.

Pipeline Integrity Management System

Pipeline equivalent circuit diagram

Pipeline Integrity Management System

Attenuation Ideal Current Distribution ■ ■

■ ■

The current must enter the structure from remote earth to complete the path. The resistance of the structure to remote earth is composed of an infinite number of individual parallel leakage resistances that are equal in value. Ideally the internal resistance of the structure is zero. Because the assumptions made to produce ideal current distribution are unrealistic, plus the fact that CP equipment cannot be located at remote earth, the ideal current distribution cannot be achieved in practice.

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Attenuation ■

■ ■

■

When new a buried pipeline is bonded with existing buried pipelines in a common corridor the attenuation for existing and new pipelines gets altered. Coating resistance for existing buried old pipeline and new proposed pipeline is not the same. Linear resistance for new pipeline and existing pipeline that may be different in diameter, wall thickness and also the materials of new pipeline may be different from existing one. The CP current density required for protecting the existing old poorly coated pipeline shall be different then the new pipeline.

Pipeline Integrity Management System

rs = unit linear resistance of structure (ohms) rL = unit leakage resistance (ohms) g = 1/ rL = unit leakage conductance (S) α = propagation of attenuation constant

Pipeline Integrity Management System

rsx = unit linear resistance of structure (ohms) rLx = unit leakage resistance (ohms) x = pipeline number / name

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Attenuation  The attenuation constant is dependent on unit linear resistance of pipeline, coating resistance and homogenous soil resistivity.  A general practice for the attenuation considerations in CP design of the pipelines to take an ideal equivalent circuit for the calculations, but with the use of bonding for interference mitigation, the equivalent circuit considered for remote earth to pipeline gets altered, hence formulas for attenuation calculations do not provide the realistic attenuation value for common buried pipeline corridor.

Pipeline Integrity Management System

Anode bed Gradient

Pipeline Integrity Management System

OFFSHORE – PIPELINES

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AC CORROSION

Pipeline Integrity Management System

AC CORROSION

Pipeline Integrity Management System

AC CORROSION

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RISK OF AC CORROSION DYNAMIC STAY CURRENT 

Crowded Right of Way



High Voltage AC Lines



Pipelines



High Voltage DC Lines



AC Tractions



Occasional Powerline Faults

Pipeline Integrity Management System

RISK OF AC CORROSION 

Caused by Current Exchange bet’n Soil and Metal



Depended on Induced Voltage on P/L.



Main Influencing Factors AC Current Density

Size of Coating Defect Local Soil Resistivity

Pipeline Integrity Management System

AC CORROSION FAILURES

 

Vary High Rate of Corrosion with Effective CP System AC Corrosion Density  NO CORROSION FOR ........... IAC < 20 A/m2  UNPREDICTABLE FOR ......... 20 A/m2 < IAC < 100 A/m2  CORROSION EXPECTED WHEN ... IAC > 100 A/m2

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We are Grateful to o Y u

Pipeline Integrity Management System

धन्यवाद | THANK YOU

Corrosion Cures Pvt. Ltd.

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Pipeline Coating Presented By

Dr. Buddhadeb Duari Director: Lalitainfraprojects Pvt. Ltd : [email protected] / : +919830017548 Pipeline - Integrity Management System

CURRICULUM VITAE Dr.Buddhadeb Duari is Director of Lalita Infraprojects Pvt Ltd who are major Manufacturer and Applicator of corrosion resistant organic coatings and linings. Dr.Buddhadeb Duari has done B. Tech (Hons) in Mechanical Engineering from I.I.T Kharagpur, MBA from Jamnalal Bajaj Institute for Management Studies (JBIMS) and Ph.D (Engg) in Metallurgy & Material Engineering from Jadavpur University. He is a NACE Corrosion Specialist, a NACE Protective Coating Specialist from NACE (National Association of Corrosion Engineers), Houston, USA and SSPC Protective Coating Specialist from SSPC (Society for Protective Coating), Pitsburgh , USA. He is a member of BIS (Bureau of Indian Standard) for CHD 20 (Chemical & Paint Division),CHD 21 (Raw Material for Paints),MTD 24 (Metallurgical Technical Division - Corrosion Protection Group) and MTD 19 (Pipes and Tubes). He has more than 35 years experience on Corrosion, Coating and Cathodic Protection of Metals, Structure and Concrete. He has published more than forty five (45) Technical Papers in reputed journals out of which fifteen (15) are international ones like MP Materials Performance, JPCL, Coating & Maintenance and Corrosion Management. Dr. Buddhadeb Duari is also guiding students for doing their Ph.D in Jadavpur University as well as IIT - Guwahati. Consultancy: Dr. Buddhadeb Duari has been roped in by the following companies as their principal consultant on corrosion related services : (a) Engineers India Limited, (b) Kolkata Metro Rail Corporation, (c) Siemens Power, (d) L&T Power, (e) Kolkata Municipal Corporation (KMC), (f) Different State Public Health Engineering Depts etc.

Pipeline - Integrity Management System

SIMPLIFIED RISK ASSESSMENT HIERARCHY Relative Risk

Consequences of Failure

Likelihood of Failure .... Third Party Damage

Corrosion

Design

Health and Safety

Environment

Service reliability

Coating type Coating Condition Cathodic protection Soil Type ……

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COATING IN CONJUNCTION WITH CATHODIC PROTECTION  Coating are the first line of defense and they play a major role in protecting steel (pipeline from corrosion).  A good coating system always balances the surface environment design to obtain desired performance and service life-cycle at least cost.  An ideal coating system which is 100% holiday or pinhole free is good enough to protect structural steel/ pipeline from corrosion.

 Practically it is not possible as there are damages during transportation and handling leading to several holidays.  Hence we need a secondary system know as cathodic protection in addition to primary coating system.  So coating in conjunction with cathodic protection to mitigate corrosion.

Pipeline - Integrity Management System

Coal Tar enamel wide range (plasticized)

1941

Polyethylene tape wrap

1952

Crosshead Extruded Polyethylene

1956

Fusion-bonded epoxy (FBE)

1961

Polyurethane

1970

3 Layer Polyethylene/Polypropelene

1979

Pipeline - Integrity Management System

Pipe Coating Extruded polyethylene: Crosshead Extruded Side-extruded Hard adhesive bonded

Plant Application

Field Application

Yes

No

Yes Yes

No No

Coal Tar enamel

Yes

Yes (Mainline/joints or re-hab)

Fusion Bonded Epoxy

Yes

Yes (Mainline/joints or re-hab)

Polyurethane

Yes

Yes (Mainline/joints or re-hab)

Polyethylene tape wrap

Yes

Yes (Mainline/joints or re-hab)

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SURFACE PREPARATION STANDARDS NACE/SSPC/ISO NON ABRASIVE CLEANING

NACE/SSPC

ISO 8501

Solvent Cleaning

SSPC SP-1

Hand Tool Cleaning

SSPC SP- 2

St2 or St3

Power Tool Cleaning

SSPC SP- 3/SP-11

St2 or St3

ABRASIVE CLEANING White Metal

NACE 1/ SSPC SP- 5

Near White Metal

NACE 2/ SSPC SP-10

Sa 3

Commercial

NACE 3/ SSPC SP- 6

Sa 2

Brush Off ( Light Blast)

NACE 4/ SSPC SP- 7

Sa 1

Pipeline - Integrity Management System

REFERENCE PHOTOGRAPHS AFTER SURFACE PREPARATION

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POLYETHYLENE TAPE WRAP COATING

Pipeline - Integrity Management System

POLYETHYLENE TAPE WRAP SITE COATING

Pipeline - Integrity Management System

POLYURETHANE COATING

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3 LAYER PE/PP

Pipeline - Integrity Management System

FUSION BONDED EPOXY

Pipeline - Integrity Management System

JOINT COATING WITH FBE

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JOINT COATING BY HEAT SHRINK SLEEVES

Pipeline - Integrity Management System

Basis of Selection of Main Line Coating PIPELINE OPERATING TEMPERATURE

PIPELINE DESIGN LIFE PIPELINE DIAMETER TYPE OF SOIL AMBIENT TEMPERATURE ROW CONDITIONS CONSTRUCTION PERFORMANCE ELECTRICAL INSULATION PROPERTIES

MOISTURE BARRIER PROPERTIES ADHESION PROPERTIES TO PIPE SURFACE RESISTANCE TO HOLIDAYS WITH TIME WITHSTAND NORMAL HANDLING, STORAGE (UV DEGRADATION) RESISTANCE TO DISBONDING

Pipeline - Integrity Management System

REASONS FOR DISBONDMENT  Blistering  Osmetic Blistering  Blistering by hydrogen evolution  Entrapped solvent blistering  Electroendosmosis  Saponification and Disintegration

 Blistering from wet and contaminated surface

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Basis of Selection of Main Line CoatingOperating Temperature

Hot Applied Coal Tar Enamel (120/5 grade)-80°C Polyethylene Coatings – 80°C Polypropylene Coatings – 120°C Fusion Bond Epoxy Coatings – 110°C Cold Applied PE Tapes – 100°C Polyurethane Coating – 100°C

Pipeline - Integrity Management System

Coating Thickness Coating

Thickness

Coal Tar enamel wide range (plasticized)

4 - 7 mm

Polyethylene tape wrap

2 – 3 mm

Fusion-bonded epoxy (FBE)

0.35 - 0.7 mm

Polyurethane

1 - 2 mm

3 Layer Polyethylene/Polypropelene

1.8 – 4 mm

Pipeline - Integrity Management System

Coaltar Enamel

PRIMER COALTAR ENAMEL WITH TWO LAYERS OF FIBERGLASS REINFORCEMENT

FIBREGLASS OUTER WRAP

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Polyethylene tape wrap

Pipeline - Integrity Management System

Polyurethane Coating

Pipeline - Integrity Management System

3LPE/PP and FBE/DFBE

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Internal Lining with FBE

LINING USED TO PROVIDE CORROSION MITIGATION AND FLOW EFFICIENCY IN WATER AND GAS TRANSMISSION ALSO PREVENT PRODUCT CONTAMINATION

Pipeline - Integrity Management System

STANDARDS 3 Layer PE / PP Coating DIN 30670: Polyethylene Coatings for Steel Pipes and Fittings ISO 21809-2011: Petroleum and Natural Gas Industries- External Coatings for Buried or Submerged Pipelines used in Pipeline Transportation Systems- Part 1 IS 15659 (Part 1) : Petroleum and Natural Gas Industries- External Coatings for Buried or Submerged Pipelines used in Pipeline Transportation of Gas and Liquid Hydrocarbon

Fusion Bonded Epoxy ISO 21809-2014: Petroleum and Natural Gas Industries- External Coatings for Buried or Submerged Pipelines used in Pipeline Transportation Systems- Part 2 IS 15659 (Part 2) : Petroleum and Natural Gas Industries- External Coatings for Buried or Submerged Pipelines used in Pipeline Transportation of Gas and Liquid Hydrocarbon

Solvent free Epoxy AWWA C-210 – Liquid Epoxy Coating Systems for interior and Exterior Steel Water Pipe and Fittings IS 16676 - Solventless Liquid Epoxy System for Application on Interior and Exterior Surface of Steel Water Pipeline

Pipeline - Integrity Management System

STANDARDS Coal Tar Enamel (Plasticized Pitch) IS 10221 :2008 : Coating and Wrapping of Underground Mild Steel Pipelines-Code of Practice AWWA C203-08: Coal- Tar Protective Coating and Linings for Steel Water Pipelines- Enamel and Tape- Hot Applied

Polyurethane Coating AWWA C222-18 : Polyurethane Coatings and Linings for Steel Water Pipe and Fittings IS 16719:2018 : Polyurethane Coatings for the Interior and Exterior of Steel Pipe And Fittings- Specification

Polyethylene Tape Wrap AWWA C214-14 : Tape Coatings for Steel Water Pipe BIS Draft : Cold Applied Tape Coating System For Exterior of Steel Pipeline

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Three Layer Polyethylene Coating Functional Properties DIN- 30670

ISO-21809-1

IS 15659(Part 1)

N-n (Normal)

Coating Thickness is a function of type of polyethylene,and dependent on service conditionswater/humidity,soil condition, transportation, laying method, pipe dimensions, weight & pipe

The selection of classification depends on the expected field duty. The more aggressive the soil is, the higher shall be the coating thickness.

Thickness (Minimum) Pipe Size

Min Thickness

DIN-100

1.8

DIN-250

2.0

DIN-500

2.2

DIN-800

2.5

>DIN 800

3.0

Table-2 “Minimum Thickness” ISO 21809-1

Table 2 Minimum Total Coating Thicknesses

Coating

N-v

Thickness of FBE Coating has been specified as 125μm

Thickness will be 0.7 mm greater for reinforced (v) coatings.

Adhesive Thickness-150μm (Minimum)

Adhesive thickness-not specified No thickness of 1st Layer FBE Coating Specified.

Pipeline - Integrity Management System

Three Layer Polyethylene Coating Functional Properties DIN-30670

ISO-21809-1

IS 15659 (Part 1)

Peel Strength (N/mm)@23°C ≥

N-n 3.5

S-n 3.5

A 10

B 15

C 25

A 15

B 25

Impact Strength J/mm @23°C >

N-n 5

S-n 5

A 5

B 7

C 10

A 7

B 10

Indentation(mm) -23°C ≤ -Tmax ≤

N-n 0.2 0.3

S-n 0.2 0.2

A 0.3 0.3

B 0.2 0.2

C 0.1 0.1

A 0.2 0.4

B 0.1 0.4

Cathodic Disbondment(mm) 23°C/28 days(-1.5V),Max 65°C/24hrs(-3.5V),Max T-max /28;-1.5V, Max Flexibility No cracking

7 7 15 At an angle 2.0° per pipe diameter length

7 7 15 At an angle 2.0° per pipe diameter length

Pipeline - Integrity Management System

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CONCLUSION Ranking (based on quality) Pipeline Coating I) II) III) IV) V)

3 Layer PE/PP FBE Polyurethane Cold Applied Tape Wrap Epoxy

Joint Coating I) II) III) IV)

Heat Shrink Sleeves FBE Polyurethane Epoxy

Rehabilitation Coating I) Polyurethane II) Cold Applied Tape Wrap III) Epoxy Pipeline - Integrity Management System

REFERENCES/ BIBLIOGRAPHY (1) Corrosion Prevention by Protective Coatings by C. G .Munger – NACE Publication (2) Fusion Bonded Epoxy (FBE) by J. Alan Kehr – NACE Publication (3) CIP Level 2 - NACE Publication (4) Coatings and Linings for Immersion Service – NACE Publication (5) Corrosion and Coatings by Richard W. Dvisko, PhD , James F. Jenkins – SSPC Publication (6) Surface Preparation Specification and Practices – SSPC Publication (7) Protective Coatings by Clive H. Hare – SSPC Publication (8) Paint Film Degradation by Clive H. Hare – SSPC Publication (9) Protective Coatings for Water and Waste water Facilities – SSPC Publication (10) Coating and Lining Inspection Manual –SSPC Publication (11) SSPC – VIS 1 - Guide and Reference Photographs for Steel Surfaces (12) SSPC – VIS 3 – Guide and Reference Photographs for steel Surfaces (13) ISO 8501 – 1 Preparation of steel substrates before application of paints.

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Materials and Design for Structural Integrity Against Corrosion Failure V.S. RAJA Professor Department of Metallurgical Engineering and Materials Science I.I.T Bombay, Mumbai, INDIA Email: [email protected] Tel:+91-9869769984

Corrosion Basics

Material

Environment Corrosion

Design

2

VS Raja, Aqueous Corrosion Laboratory

Corrosion: Deterioration of materials in presence of a chemical environment leading to loss in their function.

VS Raja, Aqueous Corrosion Laboratory

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Functional requirements of materials • Mechanical – – – –

• Physical

Strength Ductility Toughness Wear

– – – – –

• Dimensional Stability • Wear • Machinability

Thermal Conductivity Electrical Resistance Magnetic Optical acoustic

• Chemical – Catalytic

VS Raja, Aqueous Corrosion Laboratory

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Corrosion Tendency Exposure to Corrosive/chemical medium

Metal

Energy level Ore

State/time VS Raja, Aqueous Corrosion Laboratory

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Oxidation and Reduction reactions R Ox e

Metal

M+

e

M+

Environment

R Ox

VS Raja, Aqueous Corrosion Laboratory

Ox  Electron acceptor (H+, M+, O2 ) R  Reduced species (H2,OH-,M )

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What are these cathodic/reduction reactions? 2H+ + 2e  H2 (Hydrogen reduction reaction) O2 + 2H2O+ 4e  4(OH)(Reduction of dissolved O2 in water) M+ + e  M (Cu ions from return condensate) (metal deposition) Mn+ + e  M(n-1)+ (Ferric to ferrous) (metal ion reduction)

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Forms of corrosion Uniform Corrosion

Galvanic Corrosion

Crevice Corrosion

Pitting Corrosion

Intergranular Corrosion

Selective Leaching

Erosion/Cavitation Corrosion

Stress Corrosion Cracking/Hydrogen Assisted Failures

Microbial Corrosion

High Temperature Oxidation VS Raja, Aqueous Corrosion Laboratory

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b

IGC

HIC SCC

100 m

Cavitation

Microbe induced corrosion

Crevice Corrosion

Pitting

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Corrosion Control Management Strategies/Practices

Prevention Methods

 Start at the Design Board  Fabrication  Commissioning  Operation  Inspection  Maintenance  Education

Cathodic protection Inhibitors Protective coatings Selecting proper materials Design

VS Raja, Aqueous Corrosion Laboratory

Factors affecting service life/performance of equipment • • • • • • •

Design Materials of construction Specification Fabrication and quality control Operation Maintenance Environmental conditions

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Failure Causes Failure reasons in chemical process industries

Failure frequency

Plant design faults

60

incorrect application

52

poor process control

33

materials faults

32

human errors

27

lack of awareness of corrosion risk

22

contamination of product

20

instrument failure

7

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Environment: chemical Environment species, pH, temp….

Material: chemical, Material structural, microstructural Corrosion

Design: DesignStresses, geometry

Corrosion Basics VS Raja, Aqueous Corrosion Laboratory

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General materials of construction • Major uses – Cast Iron – Steels – Low alloy steels – Stainless steels

• Less use – Cu-alloys – Ni-base alloys – Al-alloys – Ti-alloys

Material

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Carbon steel

Temperature Applications Limit, oC, based on creep rate 450 fractionation towers, separator drums, heat-exchanger shells, storage tanks, most piping, and all structures are generally fabricated from carbon steel, liquified-propane storage, ammonia storage, solvent dewaxing units, and liquified petroleum gas (LPG) processing

0.5Cr-0.5Mo

510

2.25Cr-1Mo steel

540

5Cr-0.5Mo

620

7Cr-0.5Mo 9Cr-0.5Mo Type 304/316 stainless steel

635 650 595

Incoloy 800 (18Cr-35Ni) <900

reactor vessels, heat-exchanger shells, separator drums, and piping for processes involving hydrogen at temperatures above 260 °C sulfidic corrosion as well as to high-temperature hydrogen attack; furnace tubes, heatexchangers shells, and piping and separator drums. ( need post weld heat treatment) For sulfur corrosion in liquid hydrocarbons or for hydrogen service

include linings and tray components in fractionation towers; piping; heat-exchanger tubes; reactor cladding; tubes and tube hangers in furnaces; various components for compressors, turbines, pumps, and valves; and reboiler tubes. High temperature and reformer furnaces

High carbon 1100 centrifugally cast 25Cr20Ni VS Raja, Aqueous Corrosion Laboratory

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Nickel base alloys (sulfuric acid, hydrochloric acid, hydrofluoric acid, and caustic solutions) and resistance to SCC S.No

Alloy

Applications

1

Alloy 400 (N04400)

lining for carbon steel equipment to prevent corrosion by hydrochloric acid and chloride salts , tubes for HF

2

625 (N06625) and alloy 825 (N08825),

polythionic acid corrosion of flare-stack tips

3

Alloy B-2 (N10665)

hydrochloric acid at all concentrations and temperatures (including the boiling point), Only in reducing conditions

4

Alloy B-2 (N10665), alloy C-4 (N10002), and alloy C-276 (N10276

have excellent resistance to all concentrations of sulfuric acid up to at least 95 °C

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Steel Protection (atmospheric corrosion) : Coatings – Metallic • • • •

– Paints ( Basic resins)

Hot-dip Electro deposition Electroless deposition Thermal Spray

• • • • • • • • •

– Conversion • Phosphating • Chromating • Anodizing

Alkyd Epoxy ester Vinyl Acrylic Epoxy Polyurethanes Polyester Silicones Latex- Emulsion

• Inhibitors/Oils ( Temporary) VS Raja, Aqueous Corrosion Laboratory

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Hot dip coatings Coatings giving substantial galvanic protection Galvanized (Low Al additions <1%) coatings Galfan (5 wt% Al) coatings Corresponds to zinc aluminum eutectic Zinc-rich coating without intermetallics at coating/steel interface for improved formability

Galvalume (55 wt% Al) coatings Galvanneal coatings Hot-dip zinc-coated steel, heat-treated immediately after application of zinc to promote interdiffusion of zinc and iron

Zn-Al-Mg coatings Superior in corrosion resistance to all above Presence of Mg makes corrosion products more stable Difficult to produce and not been commercialized till date VS Raja, Aqueous Corrosion Laboratory

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General Guidelines for Materials Selection

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Basis for Materials Selection  Operating conditions and the possible failure mechanisms.  Design and Fabrication  Monitoring  Maintenance  Additional protection measures  Cost  Material availability  Data availability VS Raja, Aqueous Corrosion Laboratory

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Properties to watch out for • • • • • • •

Heat treatment Hardness (macro & micro) Tensile Toughness Ductile brittle transition temperature Stability against temperature Corrosion (Environment & Materials compatibility) VS Raja, Aqueous Corrosion Laboratory

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Stainless Steels At least 10.5 wt% Cr steels

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Some of the commonly used stainless steels are • Austenitic: 304, 304 L, 316, 347, 321, 904 L (prone to SCC) • Ferritic Grades: AISI Type 405, 409, (Lean Cr); 434, 436, 442 (prone to HE) • Martensitic, AISI type 403, 414 (prone to HE) • Duplex :2205, 2507, Ferralium 255 (resistant to SCC) • Precipitation Hardenable: 17-4 PH, 13-4 PH, 15-5 PH VS Raja, Aqueous Corrosion Laboratory

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Alloying elements Cr -

Corrosion resistance

Ni -

Stabilizes austenitic phase

Mn-

Stabilizes austenitic phase (Detrimental to corrosion resistance)

Mo-

Ferrite Stabilizer (Corrosion resistance)

C -

Enhances strength (Promotes weld decay)

N-

VS Raja, Aqueous Corrosion Laboratory Austenite Stabilizer (Improves corrosion resistance)

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Stainless steels composition-Pitting & Crevice Corrosion • PREN + % Cr + 3% Mo + 16% N. • An increase in PREN (Pitting Resistance Equivalent Number) means an increase in pitting resistance of a stainless steel. • The Adjective “Super” _ferritic, austenitic, duplexstainless steels ; based on PREN number ( 40) • Used this concept for selecting material for “A” beam for Dandi Memorial VS Raja, Aqueous Corrosion Laboratory

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Major problems associated with stainless steels 1. 2. 3. 4. 5.

Pitting Crevice corrosion Weld decay Stress corrosion cracking (austenitic) Hydrogen embrittlement (ferritic and martensitic)

VS Raja, Aqueous Corrosion Laboratory

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Chemical composition of some duplex SS S32760a

40-46

S39277

39-46

S39274, J93404

39-47

S32750

38-44

J93380

38-46

S32520

37-48

S31260

34-43

S32803b

33-41

S32550 S32950

32-44 32-43

J93345 S31200 30-36 30-34 J93370 27-32 S32404 26-35 S32900

31-47

PREN

Chemical compositions of some highly-alloyed austenitic stainless steels

S32654 J95370 S31266 J93254 42-47 S31254

N08926 N08925 N08320 N08904 N08020 S32200 N08007 20-23

54-60

48-54 46-62

42-45

41-48 40-47

34-43 32-40

29-40 29-40

25-32

N08367 PREN

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Performance of Stainless Steels on EAC Classification Ferritic (BCC)

SCC No

HE Yes

Austenitic (FCC) Martensitic (BCT) Duplex (BCC + FCC)

Yes* Yes No

No Yes Some what

Precipitation Hardenable

No

No

* Also, temperature limit ( 50 oC) Raja, Aqueous Corrosionfor Laboratory Nickel base alloys VSperform better HE/SCC

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Miss-understanding martensitic steel/stainless steels Location of the Problem: Process Condensate

VS Raja, Aqueous Corrosion Laboratory

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Welding • Stainless Steels • High Strength Low Alloy Steels

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Intergranular Corrosion  Welding causes such an IGC attack.  Selective attack of the grain boundaries  Grain boundary becomes highly active or phases prone to selective attack  Stainless steel subjected to heat treatment between 400-900 oC under goes (IGC)  Formation of Cr23C6 and the consequent grain boundary chromium depletion. VS Raja, Aqueous Corrosion Laboratory

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1) Oxalic acid test Polishing of specimen  Etch the specimen for 1.5 min. at 1.0 A/cm2 in oxalic acid  Determine the type of surface morphology :

 Step (Non sensitized)

 Dual (Partial)

VS Raja, Aqueous Corrosion Laboratory

 Ditch (Highly sensitized)

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Weld decay(sensitization) in austenitic stainless steel and methods for it’s prevention .Panel of four different AISI 300-series stainless steels were joined by welding and exposed to hot HNO3 and HF solution.The weld decay evident in the type 304 panel was prevented in the other panels by reduction in carbon content (type 304 L) or by addition of carbon stabilizing elements(Ti in 321, and Nb in 347 (ASM Handbook Vol 13) VS Raja, Aqueous Corrosion Laboratory

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Cleaning after welding (See ASTM A380) A. B. •

C.

Degrease in solvent or caustic Descale (remove heat tint,slig residue) Mechanical descale (avoid iron)  Grind  Sand  Grit Blast  Power brush Chemical descale (pickling) • 10-25% HNO3 + 2%HF • Pickle pastes containing HNO3 + HF • 10% H2SO4 followed by 10% HNO3

D.

Electrochemical(electropolishing)(not in ASTM A380) • • • •

50% H3PO4 (85%concentration)50%H2SO4 (concentrated) 12 volts DC power,3000 amps per m2 stainless as anode ,copper cathode VS Raja, Aqueous Corrosion Laboratory

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Welding high strength low alloy steels • • • •

Hardness raise Martensite formation at the heat affected zone Hydrogen pickup Post weld stress reliving treatment/tempering treatment

VS Raja, Aqueous Corrosion Laboratory

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Important properties to watch out for • • • •

Hardness Higher the strength more prone to SCC/HE Material processing like pickling, electroplating Heat treatment

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Care to be taken for Stainless Steels • • • • • •

Proper Heat treatment Proper Storage Passivation/surface cleanliness Better in Oxidizing Media Chlorides are issues Localized forms of corrosion

VS Raja, Aqueous Corrosion Laboratory

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Failure Investigation of Type 304L SS Tubes of Air Condenser - Fertilizer Company

MOC = SS 304

Cooling water outlet 42C – 45 C

Air Inlet at 150 C to 160C Pressure = 10 Kg./cm

1ST Stage Air Cooler

Air outlet 38C – 42 C

Cooling water Inlet 31C – 33 C

Tube leakages = 63 Nos.

COOLER IS IN OPERATION FOR 6 – 7 YEARS 38

VS Raja, Aqueous Corrosion Laboratory

TGSCC MOC change to DS 2205

VS Raja, Aqueous Corrosion Laboratory

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Failure Analysis of Nozzle of the Steam line in Hydrogen Generation Unit

Appearance of crack in the nozzle is shown. The crack seems to emanate from the pipeline-nozzle joint. Stress concentration seems to be the reason for the cracking

VS Raja, Aqueous Corrosion Laboratory

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Solution Replace type 304 ss with Cr-Mo steels

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Ferrous Group

Resistant To SCC

Resistant To Pitting/Crevice

Super Duplex SS Resistance To SCC

+N, +Cr

Resistant To SCC

+Ni (30%) +Cr ,-Ni

Pitting/Crevice Resistance

Cost Higher

Inconel

Duplex SS

Cu Base Alloys

SCC

304L,316L

+Mo, +N

IGC Resistant

316SS Super Austenitic/Ferrite

IGC Austenitic

High Strength Weld

Prone To Pitting, Crevice Corrosion

SS 3xx,2xx +Ni

Exhibit Passivity

Problems In Welding,low Strength HE

Ferritic +Cr/-C

Basic Structural Material

Poor Corrosion Resistance

C-steel -C

Lowest cost Structural Material

VS Raja, Aqueous CastCorrosion Iron Laboratory

Superferriitic stainless steels

Ni-Cr-Fe Alloys

409,430

Add S or Se for machinability

43

Superduplex stainless steels

Add Cr, Ni, Mo, N

309,310,314,330 No Ni, ferritic

347

303, 303Se

Add Ni for corrosion resistance in high temperature environment

Add Cr, Mo

321

Poor Fabrication

Add Cr and Ni for strength and oxidation resistance

Add Nb + Ta to reduce sensitization

Duplex stainless steels Add Cr, No, N, lower Ni for strength Add Cu, Ti, Al, lower Ni for precipitation hardening

304 Fe-19Cr-10Ni

Add Ti to reduce sensitization

Add Mo for pitting resistance

Precipitation-hardening stainless steels

Add Mn and N, lower Ni for higher strength

304L 316L

Lower C to reduce sensitization

316 201, 202

317L

Add more Mo for pitting resistance

Superaustenitic stainless steels

Add Ni, Mo, N for corrosion resistance

No Ni addition, lower Cr, martensitic

317 403, 410, 420

Resistant to Pitting, Crevice, Erosion Corrosion

Resistant to Erosion 3m/s

Ti- Alloys

Dry Chlorine not Stable

+Ni

Admiralty brass

(+P, As, Sb) High Strength

Low-S, high-N grades: 4565S, 2418 MoN, Rex 734

Prone to Ammonia, Chlorination

Cu, Ni

-Zn Resistant to Dezincification

Add Mo, N

Prone to Erosion Corrosion

+Sn)

Brass

Dezincification

+Zn Resistant to Pitting

Cu VS Raja, Aqueous Corrosion Laboratory

Low Strength 45

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Gas Turbines

Thermal Barrier Coating

High Strength

Super Alloys

High Strength, High temperature

Limited Life

Moderate temperature

Limited Temperature Application

Ti- Alloy

Loss in Strength, Low Temperature Application

Over Aged Alloy Heat Treatment High Strength

Prone to Pitting, Exfoliation SCC/HE

High Strength Al-Alloys +Cu, +Zn/Cu, +Mg

Good Corrosion Resistance

Al

Low Strength

Light Weight Material VS Raja, Aqueous Corrosion Laboratory

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Design and Fabrication and other processes Design that can affect o Stagnancy o Stresses ( Concentration) o Heat transfer o Bimetallic Systems

Fabrication and other material processing affect materials reliability o Welding o Cold work o Pickling o Electroplating

VS Raja, Aqueous Corrosion Laboratory

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Galvanic Corrosion • Unprotected underground plain carbon steel pipelines connected to above-ground tanks and other • Structures that are electrically grounded with buried copper rods or cables • Stainless steel shafts in "canned" pumps rotating in carbon or graphite bushings in a strong electrolyte • Copper-nickel or stainless steel heat exchanger tubes rolled in plain carbon steel tubesheets exposed to river water for cooling • Aluminum thermostat housings on cast iron auto engine blocks in contact with glycol-water mixtures VS Raja, Aqueous Corrosion Laboratory

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Source of chloride is hard to avoid • In water-cooled heat exchangers from chlorides in the cooling water • Under thermal insulation allowed to deteriorate and become soaked with water that leached chlorides from the insulation • Under chloride-bearing plastics, elastomers, and adhesives on tapes VS Raja, Aqueous Corrosion Laboratory

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SCC control under insulation • Addition of sodium metasilicate as an SCC inhibitor to the insulation ( >10 x chloride content) or metasilicate is painted . Works when the insulation becomes. But may get leached with service • Apply protective coating before insulation. – – – –

Catalyzed high build epoxy paints effective upto 100 °C catalyzed coal tar-epoxy enamels to about 150 °C (300 °F) silicone-base coatings 200 °C (390 °F). Sandblasting helps better ( surface profile depth of 0.01 to 0.1 mm) produces compressive stresses better for SCC

• Piping with aluminum foil under insulation: ( problem in alkaline conditions) – provides both a physical barrier to chloride migration to stainless steel surfaces – cathodic protection when the insulation becomes wet, ( effect between 60 and VS Raja, Aqueous Corrosion Laboratory 500 °C)

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Prevention Methods

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Landrum (1989) has suggested several remedial measures to prevent crevice corrosion. They are: 1. Specify that crevices be welded shut. 2. Improve the fit of parts. 3. Specify that the crevices be filled with a plastic or an elastomer or other nonporous materials. 4. Change the design to entirely eliminate the crevice. 5. Specify double-butt or double-lap weld joints when practical and possible. 6. When single-butt joints must be used for critical pipelines, consider using consumable or removable inserts. 7. For corrosive environments, specify continuous welds instead of skip welding. VS Raja, Aqueous Corrosion Laboratory

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8. Be especially careful when designing tank supports (especially for aluminum or stainless steel tanks) to assure as a few crevices as possible. 9. Seal weld tubes to tube sheets when practical. If seal welding cannot be specified, make sure that the tube installation procedure will result in a tight fit of tubes to tube sheet. 10. In critical rotating equipment, where crevices cannot be eliminated, open the crevices enough so that they will circulate the solution, thus avoiding crevice corrosion problems. 11. Do not specify that any material, which absorbs water, be placed next to metals or alloys. 12. If crevices cannot be eliminated use high PREN stainless steels or Ti alloys. VS Raja, Aqueous Corrosion Laboratory

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For corrosive environments, specify continuous welds instead of skip welding. Be especially careful when designing tank supports (especially for aluminum or stainless steel tanks) to assure as a few crevices as possible. Seal weld tubes to tube sheets when practical. If seal welding cannot be specified, make sure that the tube installation procedure will result in a tight fit of tubes to tube sheet. VS Raja, Aqueous Corrosion Laboratory

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 Do not specify that any material, which absorbs water, be placed next to metals or alloys.  If crevices cannot be eliminated use high PREN stainless steels or Ti alloys.  In critical rotating equipment, where crevices cannot be eliminated, open the crevices enough so that they will circulate the solution, thus avoiding crevice corrosion problems

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Take Away • Corrosion failures need to be addressed • Materials selection is one of the important ways to control corrosion • Corrosion failures are complex-there is no universal alloy/material that can withstand all types of corrosion • Technologies evolve, there is a continuous need to develop materials

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Remember the Basics • Environment? Material

Environment Corrosion

Design

– Chemistry, temperature, pressure, flow static, inhibitors,

• Design – Stresses – Stagnancy

• Materials – Compatibility – Fabrication – Process conditions – Coatings/lining/cathodic protection57 VS Raja, Aqueous Corrosion Laboratory

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Mechanical / Pre – Commissioning Integrity

Mechanical / Pre – Commissioning Integrity For Pipeline Integrity Management System (PIMS)

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Mechanical / Pre – Commissioning Integrity For Pipeline Integrity Management System (PIMS) By Sumeet Kataria Country Manager

International Certification Services Pvt. Ltd. 22-23, Goodwill Premises, Swastik estate, kalina, Mumbai 98. www.icsasian.com [email protected] 9324644271 Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity A Mechanical Engineer with A Diploma in Financial management followed by An Advanced Diploma In Industrial Safety. 25 Yrs plus Work Experience in:Offshore Hook-Up & Construction Services Pvt. Ltd. involved in more than 12+ construction projects at Bombay High covering module installation, hydrotest, jacket installation, revamping, pipe laying etc.. Rajesh Construction Company in laying of Main Line and Tie-Inn activities for Cross Country Pipelines including hydro testing, yard bending of pipes and coatings. Vijay Builders and Construction Pvt. Ltd. Involved in the construction of various POL Depots, LPG Bottling Plants and Retail Outlets covering Roads, Drains, Culverts, Driveways, Buildings, Foundations etc. Onland Offshore Engineering Services Pvt Ltd in the fabrication field covering Structural Steel, Three Plate Construction, Cold Roll Formed Sections, Pressure Vessels, Piping Components and Pipelines. Sumeet Kataria Onland Graphics India Pvt Ltd a 3M authorised converter for the manufacture of [email protected] Signages, Totems, Id Signs using Flex, Vinyls, Retro Reflective, ECF, ACP, etc also 9324644271 handled curtain wall and glazing works. ICS Technologies a NABL Accredited Laboratory, IRCA approved Training Institute; Institute approved by the MSBTE in the field of Training; a Recruitment Agency, Placement; Laboratory Testing and Calibration Services. Currently with International Certification Services Pvt Ltd a Conformity Assessment Body as a Country Manager responsible for the growth and development of Management of Certification and Inspection Services of the organisation.

Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity PHSMA-(Pipeline & Hazardous materials Safety Administration) DATA:

https://portal.phmsa.dot.gov/analytics/saw.dll?Portalpages&PortalPath=%2Fshared%2FPDM%20Public%20Website%2F_portal%2FGT%20Perf ormance%20Measures&Page=Onshore%20Significant%20Incident%20HCA.

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Pipeline integrity : Pipeline integrity means ensuring a pipeline and all its related components are running properly. In short, it's about keeping the pipeline safe for life. ... Pipeline operators use a variety of technologies to inspect their pipelines to ensure they are operating safely and efficiently. Pipeline integrity can be ensure by using number of methods at before commissioning and during operation phase. Mechanical method is one of the tool use for mechanical integrity of pipelines. Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity MECHANICAL INTEGRITY ASSESSMENT TOOLS CONSTRUCTION PHASE

 Design Requirements  Materials & Equipments specification and Integrity check  Pipeline route selection & maintaining inter distance between various facilities.  Development of procedures for construction and testing activities as per best engineering practices  Calibration, suitability and traceability check of instruments and equipments required for testing/inspection.  Qualifications requirement for welding procedures & welders.  Selection of NDT methods & qualifications and acceptance criteria.  Field Joint Coating Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity MECHANICAL INTEGRITY ASSESSMENT TOOL CONSTRUCTION PHASE

 Holiday test before lowering.  Concrete coating and quality requirement.  Top cover, pre & post padding  Backfill and others protections.  Protections equipment  Gauge pigging  In-line Inspection (ILI)  Pressure Testing  Maintaining inspection records.

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Design requirements

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Design requirements for Pipelines Reference Code’s and Standard’s ASME B31.8: Gas Transmission and Distribution ASME B31.4: Liquid petroleum transportation piping systems ASME B31.3: Standard for Process Piping ASME B31.11: Liquid slurry transportation piping systems NFPA 59A: Standard for the Production, Storage, and Handling of Liquefied Natural Gas (LNG) PNGRB Regulation: Technical Standards and G.S.R. 808(E). Specifications including Safety Standards for Natural Gas Pipelines PNGRB Regulation: Technical Standards and Specifications including G.S.R. 612(E). Safety Standards for City or Local Natural Gas Distribution Networks. ASME B31.8S: Managing System Integrity of Gas Pipelines Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity Design requirements for Pipelines Design requirements ; Piping Systems requirement as per ASME code- The design requirements are intended to be adequate for public safety under all conditions encountered in the gas industry. Conditions that may cause additional stress in any part of a line or its appurtenances shall be provided for, using good engineering practice. As per GSR 808 (E)- The selection of design for Natural gas pipelines shall be based on the gas properties, required flow rates, operating pressures and the environment. All components of the pipeline shall be designed to be suitable and fit for purpose throughout the design life. As per GSR 612 (E)- Supply of gas at a constant pressure at consumer end, and - The design should recognize the need for safe guard against malfunction of any equipment and provide sufficient redundancy to ensure that the supply is secured against such malfunctions. Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Design requirements for Pipelines Necessary calculations shall be carried out to verify structural integrity and stability of the pipeline for the combined effect of • pressure, • temperature, • bending, • soil/pipe interaction, • external loads and • other environmental parameters as applicable, during all phases of work from installation to operation. Such calculations shall include but not limited to the following: - Buoyancy control and stability analysis for pipeline section to be installed in areas subjected to flooding / submergence, - Crossing analysis of major rivers. - Evaluation of potential for earthquake occurrence along pipeline route and carrying out requisite seismic analysis to ensure safety and integrity of the pipeline system. Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Design requirements for Pipelines Steel Pipe Design Formula :

where S= specified minimum yield strength, psi (MPa), t = nominal wall thickness, in. (mm) D= nominal outside diameter of pipe, in. (mm) F= design factor obtained from Table 841. E= longitudinal joint factor obtained from T= temperature derating factor obtained from Table 841.1.8-1 P= design pressure, psig (kPa)

Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity Design requirements for Pipelines Additional Requirement for Nominal Wall Thickness - Overburden loads - Dynamic and seismic loads - Cyclic and vibratory loads - Internal pressure fluctuations -Geo-technical loads (including slides, differential settlement of piping, loss of support, and thermal effect of the pipeline on soil properties).

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Design requirements for Pipelines Location Classes for Design and Construction (a) Location Class 1. A Location Class 1 is any 1.6-km section that has 10 or fewer buildings intended for human occupancy. A Location Class 1 is intended to reflect areas such as wasteland, deserts, mountains. (b) Location Class 2 A Location Class 2 is any 1.6-km section that has more than 10 but fewer than 46 buildings intended for human occupancy. A Location Class 2 is intended to reflect areas where the degree of population is intermediate between Location Class 1 and Location Class 3, (c) Location Class 3. A Location Class 3 is any 1.6-km section that has 46 or more buildings intended for human occupancy except when a Location Class 4 prevails. (d) Location Class 4. Location Class 4 includes areas where multistory buildings are prevalent, where traffic is heavy or dense, and where there may be numerous other utilities underground. Multistory means four or more floors above ground including the first or ground floor. The depth of basements or number of basement floors is immaterial. Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Design requirements for Pipelines As per GSR 612 (E) regulations: Location Class 1, 2 and 3 shall be used only for re-certification of existing Installations and facilities, which were laid/built/constructed before the date of notification of GSR 612 (E) regulations. In any case minimum nominal thickness of pipe permitted as per this standard shall be 6.4 mm for pipe size 4 inch nominal dia and above, irrespective of the grade of the pipe material. In all existing cases where thickness of pipe is less than 6.4 mm for pipe size 4 inch and above. Quantitative Risk Assessment shall be carried out and the risk level shall be reduced to ALARP (As low as reasonably possible). Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity Design requirements for Pipelines For both aboveground and underground pipe size less than 4 inch nominal dia., the minimum nominal thickness shall be as per table below: Minimum Pipe Wall Thickness (Ref ASME B36.10 M) NPS

Identification

0.5

XS

Schedule No. 80

0.75

XS

80

1.0

XS

80

1.5

XS

80

2.0

XS

80

3.0

STD

40

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Design requirements for Pipelines Mainline /Sectionalizing valves : shall be installed on the pipeline for the operation and maintenance and control of emergencies. Spacing between mainline valves / sectionalizing valve in various Location Classes shall not exceed values given in Table 2. In plastic distribution mains valve spacing

should normally not be more than 1 km

In steel distribution mains valve spacing

should normally not be more than 3 km

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Design requirements for Pipelines Pigging Facilities : Main gas pipelines and feeder lines, spur lines and branch lines of 4" and above size and length greater than 10 km shall be provided with pigging facilities. Spacing between consecutive pigging stations shall be determined based on the diameter of pipeline, nature of pigging operation and capability of the pigs. Spacing in excess of 200 km shall be avoided. Pigging stations shall be provided with all weather access road from the nearest road

Pipeline Integrity Management System

6

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Mechanical / Pre – Commissioning Integrity Design requirements for Pipelines Bends The minimum radius of Cold Field Bend shall be as per Table Use of Mitre bends shall not be permitted. Insulating Joints Insulating joints shall be provided to electrically isolate the buried pipeline from the above ground pipeline and station piping Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Design requirements for Pipelines Branch Connections Branch connections of size below NPS 2 are not recommended in buried pipeline section. Flanged or Threaded joints, Bolts, Nuts, Gasket and other Fittings Threaded joints shall not be used in underground sections of cross country pipelines. Threaded joints may be permitted in above-ground stations / above ground section of SV stations, only if a welded isolation valve is provided before it. The flanged joint shall be made using either spiral wound metallic gaskets or metallic ring type gaskets. Plain asbestos sheet / reinforced gaskets / CAF gaskets shall not be used. Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Materials and Equipment & Integrity check

Pipeline Integrity Management System

7

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Mechanical / Pre – Commissioning Integrity Materials and Equipment & Integrity check Specifications of Piping Materials : All materials and equipment's forming a permanent part of any piping system constructed according to this standard shall comply with the design requirements and be suitable for the intended fabrication or construction methods. Materials to be used in facilities exposed to low ambient or low operating temperatures shall have adequate impact properties to prevent brittle fracture at such low temperatures. Steel Pipe As per Line Pipe Specification API 5L, shall be Seamless, Electric Arc Welded (EAW) or Longitudinal / Helical Submerged Arc Welded (LSAW/HSAW) conforming to (PSL 2). Carbon Equivalent Maximum limits on Carbon Equivalent for line pipes shall not be 0.43%. Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Materials and Equipment & Integrity check

Steel Pipe .... API 5L Specification for Line pipes (Mini Grade API 5LGr. B) ASTM A106 Seamless Carbon Steel Pipe for High Temperature Service. ASTM A333 Seamless and Welded Steel Pipe for Low-Temperature Service Mill Hydro Test Line pipes should be hydrostatically tested in pipe mill using test pressure that produces a hoop stress equal to 95% of SMYS irrespective of material grade. For new pipeline, the test pressure period 15 sec. Notch Toughness For steel pipes of size NPS 2 and above, notch toughness shall be specified Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity Materials and Equipment & Integrity check Specifications of Piping Materials – Valves API 6D : Pipeline Valves ASME B16.34: Valves Flanged, Threaded and Welding End BS EN ISO 15761: Steel gate, globe and check valves for sizes DN 100 and smaller, for the petroleum and natural gas industries BS EN ISO 17292: Metal ball valves for the petroleum, petrochemical and allied industries BS 1873 Specification for Steel globe and globe stop and check valves (flanged and buttwelding ends) for the petroleum, petrochemical and allied industries Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Materials and Equipment & Integrity check Specifications of Piping Materials - Valves BS 5352- Specification for steel wedge gate, globe and check valves 50 mm and smaller for the petroleum, petrochemical and allied industries BS 5351- Specification for steel ball valves for the petroleum, petrochemical and allied industries - Small Floating ball valve BS 1873- Specification for Steel globe and globe stop and check valves (flanged and butt-welding ends) for the petroleum, petrochemical and allied industries Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Pipeline Integrity Management System

9

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Mechanical / Pre – Commissioning Integrity Materials and Equipment & Integrity check Valves and Pressure Reducing Devices Valves body, bonnet, cover and/or end flanges components made of cast iron and / ductile iron (as per ASTM A 395) shall not be used in CGD networks. However, in case of regulators, the body or components may be made of material as permitted under the specific code as mentioned in GSR 612 (E) regulations. Valves used in service lines of size NPS 2 and below shall conform to BS EN 331 as mentioned in GSR 612 (E) regulations.

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Materials and Equipment & Integrity check

Specifications of Piping Materials Flanges : Flanges made of cast iron, ductile iron and non-ferrous materials (brass or bronze) shall not be used in CGD networks. Use of flanges in natural gas transmission and distribution piping is not permitted except for station piping e.g. CGS, DRS, MRS etc. For piping class 150 or above all the flanges shall be with raised face. • ASME B16.5 Steel pipe flanges and flanged fittings - Size upto 24" NB. • ASME B16.36 Orifice Flange • MSS SP-44 Steel Pipeline Flanges • API 590 Steel Line Blanks Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Pipeline Integrity Management System

10

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Mechanical / Pre – Commissioning Integrity Materials and Equipment & Integrity check Specifications of Piping Materials – Fittings other than Valves and Flanges Fittings made of cast iron and ductile iron shall not be used in CGD networks. ASME B16.9 Factory-Made Wrought Steel Butt welding Fittings MSS SP-75 Specification for High Test, Wrought, Butt Welding Fittings MSS SP 97 Integrally Reinforced Forged Branch Outlet Fittings Socket Welding, Threaded and Butt welding Ends IS 1239 (Part-2): Steel Tubes, Tubular and Other Steel FittingsSpecification-Part 2: Steel pipe fittings Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Materials and Equipment & Integrity check Specifications of Piping Materials --Fittings other than Valves and Flanges All plastic fittings used in CGD networks must have been type tested by an internationally recognized testing agency prior to their use. Thermoplastic / thermosetting fittings shall not be used in above ground piping system. Thermoplastic fittings conforming to ISO 4437 Part 3 or EN 1555 Part 3 shall be acceptable Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity Materials and Equipment & Integrity check Specifications of Piping Materials Stud Bolts and Nuts :All stud bolts and nuts used in CGD networks shall be hot dipped galvanized as per ASTM A 153 or equivalent. ASTM A194 Standard Specification for Carbon and Alloy Steel Nuts for Bolts for High Pressure or High Temperature Service, or both.' ASTM A193 Standard Specification for Alloy-Steel and Stainless Steel Bolting Materials for High Temperature or High Pressure Service and Other Special Purpose Applications ASME B18.2.1 Square and Hex Bolts and Screws, Inch Series ASME B18.2.2 Square and Hex Nuts Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Materials and Equipment & Integrity check Integrity Check : All materials and equipments shall specification and standard requirement.

confirm

design

,

Inspection shall be carried out by competenet inspection agency before installation. Inspected and Accepted material shall reched at site and same shall be verified with manufacture record and inspection reports/ rlease notes at site before installation. Material damaged during transportation shall not use.

Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity

Pipeline route selection & Inter distance between various facilities Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Pipeline Route : construction for crossing road, pipeline, cable, railway, river, canal and other existing obstacles. The risks associated with proposed pipeline, mains and service routes shall be assessed to ensure that all reasonably practicable steps have been taken to minimize the risks to people & property in the event of an unplanned release of Gas. Pipeline, which is constructed inside the area of high voltage lines, may be electrically influenced by this high voltage line. The voltage caused by the influence may at times be so high as to pose a danger to personnel working on the pipeline. If it is not possible for plant and / or materials to come beyond 50m of the centre of the high voltage system, special measures must be taken to prevent any pproach beyond that distance, Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity As per GSR 612 E- City Gate Station (CGS) As far as possible the CGS shall be installed at the periphery of populated area. The entity should make best endeavor to have more than one CGS for supply security. Facility shall be provided with proper boundary wall / fencing with gate(s) in line with Ministry of Home Affairs guidelines. Properly laid out roads around various facilities shall be provided within the installation area for smooth vehicular access. Platforms and crossovers shall be provided for ease of operation and maintenance Provision should be made for venting, purging and draining All vents shall be routed to a safe area. Gas detectors shall be installed Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity

(a) City Gate Station (CGS) : Inter distance between various facilities required at CGS shall be as per table: Sr.

From / To

1

2

3

4

5

6

1

Compound Wall

-

6

6

6

6

6

2

Control Room / Office Building / Store

6

-

12

12

2

15

3

Pressure Regulation and / or Metering

6

12

-

2

12

15

4

Odorant System

6

12

2

-

12

15

5

Electrical Sub Station

#

2

12

12

-

15

6

Gas fired heaters

6

15

15

15

15

-

Notes : 1. All distances are in meters. 2. For all the distance from the compound wall # As per State Electricity Board recommendations. Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity (a) As per GSR 808 (E) - MINIMUM INTER DISTANCES FOR VARIOUS STATION FACILITIES : All distances are in meters. Sr.

From / To

1

2

3

4

5

6

7

8

9

10

1

Small Compressor/ Pump House

-

15

15

15

16

30

15

15

15

16

2

Main Compressor House

15

-

15

15

30

30

15

15

30

30

3

Gas Handling System (PB /GC)

15

15

-

5

16

30

15

15

5

16

4

Equipment Room

15

15

5

-

-

30

15

15

5

16

5

Control Room /Office building

16

30

16

-

-

30

15

15

5

-

6

Fire Pump House/Fire water storage tanks

30

30

30

30

30

-

-

30

12

-

7

Water Spray Deluge Valve

15

15

15

15

15

-

-

15

-

16

8

Cold Blow Down

15

15

15

15

15

30

15

-

5

30

9

Compound wall

15

30

5

5

5

12

-

5

-

5

10

Elect Sub station,

16

30

16

16

-

-

16

30

5

-

Notes : PB - Pig receiver / Launcher Barrel, GC- Gas Coolers / Meters / filterste Electricity Board recommendations. Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Development of procedures for pipeline construction and testing

Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity Development of procedures for pipeline construction and testing Construction and testing Procedures shall developed before start construction activities for the below listed activities Material inspection at manufacturer premises Pipeline construction and laying Preparation of procedure for site safety Quality Assurance Plan / Inspection test Plan for materials required for pipeline & construction activities at site Transportation of material at site Drawings Issued for Construction (IFC) Right of use Route survey Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Development of procedures for pipeline construction and testing Hazard Identification & Risk Assessment (HIRA) – monitoring & control Right of way clearing & grading Cable locator survey Ground Penetrating survey for identification of underground utilities Trail Pit excavation Marking of pipeline center & trench width Line pipe stringing Excavation of trench Electrode batch qualification test Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Development of procedures for pipeline construction and testing Welding Procedure Specifications (WPS) Welding Procedure qualification tests Welder performance Qualification / Evaluation Fit up and Welding of pipeline joints Non-destructive test (NDT- RT,UT,PT & MT) Abrasive blasting Field joint coating Filed joint Holiday testing Inspection of pipeline section and Holiday testing Concrete coating (if water body crossing) Lowering of pipeline section in to trench Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity Development of procedures for pipeline construction and testing Top Padding -sot soil / sand Back filling of pipeline Compactions of Back filling soil All types of Crossings Cased (Boring) / Uncased (HDD/Open) like Rail, road, river, canal etc Critical Crossing including other utilities by HDD (Road, Canal, Pipelines, Drains, etc.) Pre-hydro testing of constructed pipeline for crossings Tie-in weld with crossing section NDT & field joint coating of tie-in joints Backfiliing & Restoration Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Development of procedures for pipeline construction and testing Installation of Pipeline route Markers Header installation at both ends Pipe book preparation Mechanical clearance Flushing & water filling Hydro testing Swabbing/ drying Installation of markers and final clean up Valves testing & Installation in pipeline Installation of Electric isolation / Monolithic insulation joints or Electrical Insulation. Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Development of procedures for pipeline construction and testing Construction of valve chambers / stations Purging Construction of Civil structures/building for operation & maintenance Painting Activity report and pipe book Material reconciliation – monitoring & control Pipeline Pneumatic test & Pressure Holding Final Pipe book and activity report Construction drawing as laid drawing Pipeline Integrity Management System

16

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Mechanical / Pre – Commissioning Integrity Development of procedures for pipeline construction and testing Deviation / variation analysis and obtain change order approvals from client Pipeline Integration Management System All Pipeline station construction work at Compressor station, SVs, IPs, Receipt / Dispatch Stations, CNG Stations etc. or related to various engineering disciplines namely Civil, Mechanical, Electrical, and Instrumentation. Installation of Cathodic Protection system (Temporary and Permanent) Differential Global Positioning System (DGPS) Interference & mitigation Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Development of procedures for pipeline construction and testing Cathodic protection (CP) – Performance test Project pre-commissioning including cleaning & pigging of pipeline & commissioning All quality aspect related to Civil/ Structural Construction Work. Commissioning

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Calibration, Suitability and Traceability check

Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity Calibration, suitability and traceability check

•All measuring Instrument / testing equipment shall be available be identified Sr./ID No. •All instrument/ equipment shall be in operation and good working condition •Reading scale should be clearly visible •Shall be free from any mechanical damage. •Instrument /equipment shall be suitable for measuring range / range. •Calibration shall be done from NABL accredited Lab. or master shall be traceability to national/international stanadrd. •Instrument identification/ Sr.no. shall be recorded Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Calibration, suitability and traceability check

Below information shall be recorded in calibration certificate. •Instrument identification/ Sr.no. •Instrument name. •Make. •Measuring / testing range. •Least count •Date of calibration •Date of expiry/next calibration Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Calibration, suitability and traceability check

•Detail (name, range, sr., least count, traceability, calibration) of master used for calibration. •Instrument reading and master reading in ascending and descending order covering complete testing / measuring range •Error in reading •Uncertainty •Signature of lab in-charge Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity

Qualifications of welding procedures & welders

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity QUALIFICATION OF PROCEDURES AND WELDERS Welding procedures and welders for welding of gas pipelines shall be qualified as per API 1104 and shall include toughness testing requirements as applicable for the line pipe. Welding procedures and welders, for station piping shall be qualified as per ASME Boiler and Pressure Vessel (BPV) Code Section IX or API 1104. When welders qualified under API 1104 are employed for station piping, their qualification shall be based on destructive mechanical testing as per API 1104. Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity GENERAL REPAIR OR REMOVAL OF DEFECTIVE WELDS Welds having defects shall be removed or repaired in accordance with API 1104 or ASME BPV code Section IX as applicable. Welders employed for repairs shall be qualified in accordance with "Qualification of Procedures and Welders". Weld repair areas shall be subjected to additional radiography or ultrasonic testing after repair. Notches or laminations on pipe ends are not permitted and must be removed by cutting the pipe as a cylinder and re- beveling of pipe end prior to welding. Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity

NDT Methods & Procedure Qualification

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity INSPECTION OF WELDS –NDT All Non Destructive Testing (NDT) including radiographic examination and / or ultrasonic testing shall be performed in accordance with the requirements of API 1104 Demonstration of the Testing Procedure shall be performed Prior to final written approval. A procedure demonstration report shall be generated and the results documented prior to use on actual field welds. The demonstration process shall be as follows. a) For UT: Welds containing defects and acceptable imperfections shall be prepared from actual production pipe material samples utilizing an approved welding procedure specification. Changes in wall thickness, bevel design, acoustic velocity, welding process, repair welds, and other variables that can have an effect on the detectability and resolution of the system shall require additional demonstration welds from other corresponding approved welding procedures. Radiographs shall be made of the welds and the results documented. Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity INSPECTION OF WELDS -NDT b) For RT: Radiographic film produced by the use of procedure shall have the density with in range, clarity, contrast & requisite sensitivity to define clearly the essential wire diameter of the proper image quality indicator (IQI) is required All NDT procedures shall be demonstrate before perform on job. Regardless of operating hoop stress as well as location class all carbon steel butt welds shall be 100% radiographed. In case radiography is not possible due to safety reasons, weld shall be examined by using ultra sonic techniques. All butt welded golden joints (i.e. welds joints which are not subjected to pressure testing, shall be subjected to 100% radiography as well as examination by ultrasonic techniques. Socket welded golden joins shall be tested by using Liquid Penetrant Inspection (LPI) method or wet Magnetic Particle Inspection (MPI) method. Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity Radiographic Testing (RT) Radiographic Testing (RT) is a non-destructive testing (NDT) method which uses either x-rays or gamma rays to examine the internal structure of manufactured components identifying any flaws or defects. In Radiography Testing the test-part is placed between the radiation source and film (or detector) The material density and thickness differences of the test-part will attenuate (i.e. reduce) the penetrating radiation through interaction processes involving scattering and/or absorption. The differences in absorption are then recorded on film(s) or through an electronic means. Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Radiographic Testing (RT) In industrial radiography there are several imaging methods available, techniques to display the final image, i.e. Film Radiography, Real Time Radiography (RTR), Computed Tomography (CT), Digital Radiography (DR), and Computed Radiography (CR). There are two different radioactive sources available for industrial use; X-ray and Gamma-ray. These radiation sources use higher energy level, i.e. shorter wavelength, versions of the electromagnetic waves. Because of the radioactivity involved in radiography testing, it is of paramount importance to ensure that the Local Rules is strictly adhered during operation. Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Radiographic Testing (RT) Gamma radiography is the method of using of radioactive isotopes to detect internal defects and inhomogeneities in material. Two of the more common industrial gamma-ray sources for industrial radiography are iridium-192 and cobalt-60. No power source is required for Gamma radiography hense it is more comfortable than x-ray radiography.

Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity Radiographic Testing (RT) Hazards When X-ray radiation is absorbed within our bodies, it can damage molecular structures and potentially cause harm. Very high doses of radiation cause damage to human cells, as evidenced by skin burns, loss of hair, and increased incidence of cancer. Radiation safety The guiding principle of radiation safety is “ALARA”. ALARA stands for “as low as reasonably achievable”. This principle means that even if it is a small dose, if receiving that dose has no direct benefit, you should try to avoid it Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Radiographic Testing (RT) Benefits Minimum surface preparation required Detects both surface and subsurface defects Provides a permanent record of the inspection Verify internal flaws on complex structures Isolate and inspect internal components Automatically detect and measure internal flaws Sensitive to changes in thickness, corrosion, flaws and material density changes Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Field Joint Coating integirity check

Pipeline Integrity Management System

22

29-08-2020

Mechanical / Pre – Commissioning Integrity Field Joint Coating A liquid epoxy coating layer, which may be applied onto the blast cleaned and pre-heated steel surface to improve the adhesion of the heat shrink sleeve to the pipe surface. Heat Shrink Sleeve : A type of field joint coating, applied to a pipeline in the form of a sleeve, which shrinks in the circumferential direction under the influence of heat for field coating. Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Field Joint Coating The ends of existing mill coating shall be inspected. Unbounded portions of the coating shall be removed and then suitably trimmed. Portions where parent coating is removed shall be thoroughly beveled, and cleaned as specified. If Humidity is greater than 85 % and pipe temperature is below or equal to 3°c compared to dew point than coating should be stopped. Using copper slag clean blast only the bare steel part of the girth weld area to SA 2½ and a roughness profile (anchor pattern) between 50 to 70 microns.

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Field Joint Coating

BEVELLING OF POLYETHYLENE COATING EDGES If not factory beveled, bevel the line coating edges on both sides of the weld bead to approximately 15°. Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity

Field Joint Coating The embossed pattern on the sleeve ( dimpled PCI – Permanent Change Indicator) of the backing should disappear and a smooth backing profile should be seen as illustrated below :

Dimples still visible = more heat Smooth profile = O.K Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Field Joint Coating The ends of the sleeve shall be firmly bonded to the mill coating. There shall be no upstanding edges. Adhesive flow shall be evident at both edges of sleeve around entire circumference of pipe / sleeve. The sleeve shall be smooth; there will be no dimples, cold spots, bubbles, punctures, burn holes or any signs of holidays. There shall be no signs of entrapment of foreign materials in the underlying adhesive. Sleeve shall overlap minimum 50mm onto the adjacent PE line coating on each side of joint. Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Field Joint Coating HOLIDAY INSPECTION TEST After complete cooling down, each sleeve shall pass holiday detection test. Holiday inspection shall be done using a voltage setting can go upto 25kv. The holiday test shall be carried out after 4 hrs. ADHESION PEEL STRENGHT TEST One out of every 50 sleeves, or alternatively one out of each day’s production (whichever is lower) shall be subjected to a manual peel test. The peel test shall be done after 24 hrs. Peel strength inspection shall be done at a sleeve temperature of around 23°C or 60°C in order to compare with Owner’s specification; both the substrate and the sleeve shall be at this temperature. Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity Field Joint Coating PEEL VALUE Vs. TEMPERATURE CHART Temperature in (°C) 23 30 35 40 45 50 55 60

Peel Value Peel value in ( N/cm) in Kg 9.0 7.75 6.5 5.0 3.8 2.5 2.0 1

35 30 25 20 15 10 7.5 5

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Holiday Test

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity HOLIDAY TEST A holiday test is a non-destructive test method applied on protective coatings to detect unacceptable discontinuities such as pinholes and voids. Holiday testing involves checking an electric circuit to see if current flows to complete the circuit. This testing is used to find coating film discontinuities that are not readily visible. A holiday test is usually performed buried structures and pipelines because of the importance of maintaining adequate coating protection in aggressive service environments.

Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity HOLIDAY TEST A holiday test is also known as a continuity test Pipeline section shall be holiday tested befor lower in the trench.  In addition the holiday detectors batteries shall be checked every 4 hours and replaced/ recharged if required.  Calibrate holiday detector daily  All holiday detection and holiday repairs shall be conducted to the satisfaction of the Coating Inspector.

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Concrete Coating

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Concrete Coated Pipe A pipeline coating is a cost-effective and sensible solution that is done purposely to maintain pipelines' integrity. This coating helps in providing a constant protective lining that helps in saving pipelines from the damaging effects of corrosion. ... Though, that corrosion can be removed it is the steel pipe external with concrete weight coating (Mixed with cement, aggregates, reinforced steel mesh and water), to provide the strong downward force protection or a negative buoyancy for the pipelines. This pipe is commonly used in subsea pipelines & water body crossing with adding the proper weight of the concrete coatings to support a resistant pressure against sea water. Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity Concrete Coated Pipe Before coating the concrete, the steel pipe normally shall be coated with an FBE coating. First is to calculate the proportioned quantity of cement, iron ore, sand and granite aggregate, them mixed them together to create a specified density required; During concrete buildup processes, control the steel wire mesh position will get a certain wire depth with the coating; Weighing each joints to verify if they meet the requirements of the project; Clean the concrete coated pipe ends and trimmed the excess wire. After curing in 30 days, the material could be ready for delivery. Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Concrete Coated Pipe Benefits of concrete coated pipe : • Mechanical protection and negative buoyancy • Anti-corrosion protection • Excellent Compatibility • Long-term adhesion to steel • Well suited to reel laying methods • High resistance to cathodic disbondment

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Top cover, pre & post padding

Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity

Cover Requirements for Buried Steel Pipelines and Mains : Location

Min. Cover (mtr.)

Normal / rocky terrain

1.0

Minor river / unlined canal / nala crossings, tidal areas and other watercourses

1. 5

Major river crossings

2.5

Rivers with rocky bed

1.5

Lined canals / drains / nalas etc.

1.5

Drainage ditches at roadways and railroads

1.0

Rocky Areas

1.0

Cased / uncased road crossings

1.2

Cased railroad crossings

1.7

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

In rocky areas and areas with hard soils / gravels, minimum 150 mm thick padding of soft soil / sand shall be provided all around the pipe. If required protective layer of rock-shield / rock guard or concrete coating may be provided to prevent damage to coating / steel pipe during installation and testing in place of soft padding, No dwellings or construction in any form shall be permitted within RoU.

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Clearance between Pipelines

Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity Clearance between Pipelines underground structures

or

Mains

and

other

(a) When a buried steel pipeline or main has to cross any existing underground pipeline, cable, drain or other services, the pipeline shall be laid at least 300 mm below from such services. (b) When laid parallel to any existing underground cable, drain or other utilities, the pipeline or main shall be laid with a clear distance of at least 300 mm from existing utility. (c) As far as practical, a minimum separation of three (3) meter should be maintained between the steel pipeline or main and footing of transmission tower. Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Clearance between Pipelines underground structures

or

Mains

and

other

(d) A clearance sufficiently large to avoid electrical fault current interference shall be maintained between the pipeline and the grounding facilities of electrical transmission lines. (e) While laying more than one new hydrocarbon pipelines or mains in the same trench, clear separation of minimum 500 mm shall be maintained between adjacent pipelines.

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Casing Requirements under Railroads, Highways, Roads or Streets Steel casing at road/railway crossings, when provided to meet statutory requirements, shall be designed in accordance with API 1102. Casing pipe diameter shall be minimum two pipe sizes bigger than carrier pipe. In case of PE, the casing can be RCC pipe of min NP3 class. Bends, Elbows and Miters in Steel Pipelines and Mains Miters bends and wrinkle bends are not permitted in pipelines and mains used in CGD networks regardless of operating hoop stress. Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity

Backfill and Others protections.

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Protections

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Backfilling shall be carried out immediately to the extent possible after the pipeline has been lowered into the trench. Excavated soil from the trench shall be used for backfilling unless the same is not suitable . The backfill material shall contain no extraneous material and / or hard lumps of soil, which could damage the pipe and / or coating or leave voids in the backfilled trench. In cultivable land and other specifically designated areas, top soil excavated from the trench and stored separately, shall be restored to normal conditions. Slope breakers or other measures shall be installed in trenches dug in steep areas (slope of generally 10 percent and more) to prevent erosion of the back fill. RoU should be provided with drainage ditches to allow water run-off and avoid backfill wash out . Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity

SAFETY DEVICES AND FEATURES

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity SAFETY DEVICES AND FEATURES The safety system for compression facilities transportation system shall consist of following:

and

gas

Emergency Shutdown System Compressor station shall be provided with an emergency shutdown system (ESD) for reliably and safely shutting down the station facilities in case of emergency and for venting out of gas when situation demands so. The ESD system shall have provision of shutdown all gas compressing equipments, all gas fired equipment, and shall de-energize the electrical facilities located in the vicinity of gas headers and in the compressor shed, except those that provide emergency lighting and those that are necessary for protection of the equipment. Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity Pressure Limiting Devices Over pressure shut off valves shall be provided upstream of pressure controlling system/ regulators along with alarm provision in case of failure of the pressure control system / regulators. Vent Lines Vent line shall be designed and installed to vent out the gas from relief valves , if provided, to atmosphere. Blow down piping connected to vent line should extend to location where the discharge of gas shall not create a hazard to the compressor station or the surrounding area. The discharge from safety valve shall be vented vertically upwards to atmosphere at an elevation of 3 meter (minimum) above working level Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Gauge Pigging

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Pipeline Gauging Pipeline gauging is the process of locating and identifying internal defects such as dents, debris or other internal restrictions that affect the I.D. of the pipeline. Why is this important? The pipeline is designed to deliver a certain throughput based on a minimum diameter. It is in the best interest of the construction company to ensure the minimum diameter isn’t lost before finalizing the project. Pipeline pigs are used to accomplish this task, but not just any pig, the pig must be dressed with a gauge plate.ig, Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity Pipeline Gauging In the early days of pigging, gauge plates were made from steel. Today’s gauge plates are made from aluminum to avoid causing damage to the pipe walls. The plate is sized proportionately to the minimum internal diameter of the pipeline, then added the appropriate style of pig, such as Steel Mandrel or MULTICAST™ depending on the application.

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

In-line Inspection (ILI)

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity In-line Inspection (ILI) In-line inspection (ILI) tools, sometimes referred to as “intelligent” or “smart” pigs, are used to inspect pipelines for evidence of internal or external corrosion, deformations, laminations, cracks, or other defects. Selecting the correct tool is typically based on the perceived threats to the pipeline integrity as well as the pipeline’s physical and operational characteristics. Magnetic Flux Leakage (MFL) and Ultrasonic Testing (UT) are the two primary methods for in-line inspection of pipelines and each have their own strengths and weaknesses. UT Intelligent Pigging is used for its higher accuracy and easier mobilization. Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity In-line Inspection (ILI) UT tools are well suited for heavy walled pipe. UT tools do require a liquid cuplant through which ultrasonic pulses can travel to and from the pipe wall. The presence of any gas between sensors and pipe wall will interfere with the inspection but gas pipelines can still be inspected using ultrasonic techniques by running the tool in a liquid slug between two high-sealing pigs. MFL tools have difficulty magnetizing heavy walled pipe to saturation meaning they have an upper wall thickness limit ranging from 12.7 to 25.4 mm (0.5 to 1.0 inches depending on the specific tools. Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity In-line Inspection (ILI) Both types of intelligent pig require a clean pipeline to function correctly & a pipeline cleaning program should be carried out before the intelligent pig is run through the line Most in-line inspection tools and hard body utility pigs are designed to negotiate bends with a radius of 3D or greater, Non pigable piping system with short radious bands are used in the CGD network hense ILI could not performed on the CGD network.

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Hydrostatic Testing

Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity Test Requirements for steel pipeline: Test Required to Prove Strength of Pipelines and Mains to operate at Hoop Stresses of 30% or more of Specified Minimum Yield Strength of Pipe All buried steel pipelines and mains shall be pressure tested after installation using water as a test medium. Minimum test pressure shall be equal to 1.4 times Maximum Allowable Operating Pressure. Hold-up time for the pressure testing shall be minimum 24 hours for underground and 4 hour aboveground pipeline. Testing equipments / instruments shall be properly inspected and shall have valid calibration certificates before they are used for testing. Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity Test duration shall be minimum 24 hours for plastic distribution mains of length greater than 1 km and minimum 4 hours for length shorter than 1 km. In case water is used as test medium, test duration shall start after achieving thermal stabilization. Suitable relief valve set at 5% higher than test pressure shall be fitted at the test heads to avoid over pressurization during testing.

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Hydro Test Header

Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity

Maintaining Construction & Inspection Records.

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Pipeline Integrity Management System

Mechanical / Pre – Commissioning Integrity

Pipeline Integrity Management System

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Mechanical / Pre – Commissioning Integrity

Pipeline Integrity Management System

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Pipeline Integrity Management Integrity Assessment Tool: Direct Assessment (DA) By: Ashish Khera, P.Eng

Date: 29th August 2020

Pipeline Integrity Management System

Integrity Threats from DA– Internal Corrosion

Internal Pitting Corrosion

TLC Pipeline Integrity Management System

Integrity Threats from DA - SCC External pitting corrosion inlaid with SCC

SCC

Pipeline Integrity Management System

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Integrity Threats from DA – External Corrosion & MIC

External corrosion MIC

Pipeline Integrity Management System

How DA helps in Pipeline Integrity (9 Q’s)?  Maintain safe, reliable operations with an increase in asset availability  1- Can the line remain in service?

 Assess the feasibility of increasing the severity of operations  2- Can I increase the through put of the line?

 Rationalising fabrication flaws from construction found by in-service inspections  3- Are immediate or scheduled repairs required?

 Re-rating of damaged equipment

 4- What is my P safe for EACH pipeline?

 Development of inspection plans and intervals

 5- When should I do my next inspection? What technology?

 Life extension

Maintain a safe asset! Find problems “proactively” and not “reactively” = No LEAKS or No Failures!

 6- What is the remaining life of my pipeline (days/months/ years)? Can I increase it?

 Shut-down planning

 7- Do I need to make a planned shut down to assist in integrity management for a pipeline?

 Repair planning/schedules/retrieval

 8- Repair plan and type of repair to manage my P safe and support the asset?

 Leak detection during Commissioning, Operation and Mapping?  9- How soon can I do confirmation of containment ($$$)?

Pipeline Integrity Management System

INTEGRITY VALIDATION TOOLS – ASME B31.8S?

HYDRO TEST

ILI - Piggable - Unpiggable Our team hired by NACE International to develop the 5-day DA course, launched in US in 2012launched in India 2014

DA (ECDA, ICDA, SCCDA)

Pipeline Integrity Management System

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OISD Std 233- Inspection of Non-Piggable pipelines..& US- DoT “For non piggable pipelines, primary assessment method like External Corrosion Direct Assessment (ECDA) and Internal Corrosion Direct Assessment (ICDA) can be used to identify potential threats.” “For pipeline systems where general external or internal corrosion or SCC may be a risk of concern, DA may be a more cost effective and rational approach to hydro testing or smart pigging.”

Pipeline Integrity Management System

What does OISD say about Non-piggable / Piggable Pipeline Inspection?

Why is OISD asking for ICDA or “complete wall thickness”?

When? If line < 25 years old then within 10 years of commissioning When? If line > 25 years old then within 26th years of commissioning

Pipeline Integrity Management System

DA Model Process Data collection and assessment, Corrosion/ leak History, Selecting DA regions, Appropriate IDI tools, Suspectibility Above ground inspection (EC)/ Corrosion modeling (ICPM)/ Terrain modeling (SCC), future threat areas, potential corrosion locations In the ditch investigation, Coating assessment, Environment classification, Corrosion deposits and areas, NDE, Remaining Strength Reassessment Intervals, Remaining Life, DA effectiveness & Health assessment

Pipeline Integrity Management System

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Benefits of Direct Assessment • • • • • •

Predict future problems (proactive) Applicable for both piggable as well as non-piggable pipelines. No productivity down time (non-intrusive) No modifications to the pipe required Performs root cause analysis (Why corrosion exists?) Provides a Mitigation plan (How to manage corrosion?) Very beneficial if the sole purpose is for pipeline’s integrity rather than a regulatory compliance

Pipeline Integrity Management System

NACE DA Standard Practices Title External Corrosion Direct Assessment (ECDA) NACE SP0502-2010

Applicable (Regulator??) General and/or localized external corrosion

External Corrosion – Confirmatory Direct Assessment (ECCDA) NACE SP0210-2010

Stress Corrosion Cracking Direct Assessment (SCCDA) NACE SP0204-2008

General and/or localized external corrosion (Must have a baseline already) External SCC on the pipe surface and underneath the coating (low and high pH)

- Buried lines only - Onshore Petroleum pipelines (all products) - All Coating types

Pipeline Integrity Management System

NACE DA Standard Practices Title Dry Gas (DG-ICDA) NACE SP0206-2006 Liquid Petroleum - (LP-ICDA) NACE SP0208-2008

Applicable (Regulator??) H2O < 112 µg/L (or 7 lbs/MMSCF) at STP. (infrequent short term water upsets)

Hydrocarbon liquid lines with BS&W < 5% by Vol.

Wet Gas (WG-ICDA) NACE SP0110-2010

On upstream systems, GLR > 5,000 (i.e., a ratio of 5,000 ft3 gas at STP/ 1 ft3 H2O ) or ~ 35 bbls H2O/MMSCF

Multiphase Flow (MP-ICDA) NACE SP0116-2016

BS&W > 5% by vol. STP: 15C at 1 atm

- Onshore/ Offshore - All products Pipeline Integrity Management System

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ICDA- Internal Corrosion Direct Assessment

Non-Intrusive Applicability through PROVEN models: - Onshore/ Offshore - Piggable/ Non Piggable - Dry Gas/ Wet Gas/ Liquid Petroleum/Multiphase/ Water products - Sweet/Sour Service Pipeline Integrity Management System

Why the ICDA Subject Matter Expert (SME) should be involved?

Pipeline Integrity Management System

Liquid sample collected to be analyzed

SEM analysis performed on prewashed solids

Diffraction pattern from XRD on washed solids

Pipeline Integrity Management System

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Pre-Assessment- ICDA Best Practices – Sample and Bacteria Testing at Field

Pipeline Integrity Management System

DNA - Taxonomic Breakdown of Identified Microbial Strains in Pipeline Firewater PipelineNitrosomonas

Nitrospira 3% Planctomyces 5% Extensimonas 6%

2%

Leptolinea 29%

Merismopedia 7%

Terrimonas 8%

Stenotrophomonas 10% Candidate_division_OP11 10%

Thauera 20%

East India- 36” x 8 kms Pipeline Integrity Management System

Terrain vs. Flow Regime

Courtesy of Nicholas Petalas and Khalid Aziz

Pipeline Integrity Management System

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Pipeline Inclination on Flow Regime

Flow pattern of gas-condensate system at +10o upward inclination

Flow pattern of gas-condensate system at 10o downward inclination

Pipeline Integrity Management System

Flow Regimes – Stratified Slug

Pipeline Integrity Management System

Flow Regimes – Stratified Bubble

Pipeline Integrity Management System

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Example: To show the different flow regimes encountered in a gas pipeline for a typical time period era. Total 4 flow regimes found and 15 ICDA sub-regions made for a 0.8 km gas pipeline

Pipeline Integrity Management System

Case Study 1- 8” Non-Piggable Gas Pipeline – Pre Assessment Units

8” Wankaner

Nominal Pipe Diameter

mm

219.1

Wall Thickness

mm

6.35

4

Operating Temperatures

oC

5

Operating Pressures

Psi

Scenario-1 & 2 = 435; Scenario-3 & 4 = 652

6

Gas Production Rate

m3/d

Multiple gas flow rates utilized. Please refer Item-2, page8 of IDI report submitted

7

Oil/Condensate Production Rate

m3/d

Gas Line. No oil flow assumed. Water flow rate assumed – as back calculated (please refer IDI report submitted for calculations of water flow rate)

8

Average CO2 Concentration (in Gas)

mol %

Multiple values utilized for different scenarios while modeling. Please refer IDI report.

9

H2S Concentration (in Gas)

mol %

No.

Parameter

1

Year of Commission

2

3

2010

25

Multiple values utilized for different scenarios while modeling. Please refer IDI report.

Is it really DRY GAS? Should we use NACE DG-ICDA or WG-ICDA and prove it as DG! Pipeline Integrity Management System

PrA:8” pipeline Google Earth View

Downstream Client Terminal

Upstream Operator Terminal Flow Direction (Current)

Pipeline Integrity Management System

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Internal Corrosion Predictive Modeling – Four Scenarios in past 4 years… • Scenario 1 – (Reverse flow – Current Client to Operator) 9 times within a period of 1 year • Scenario 2 – Shut-in under pressure - period for 1157 days before gas flow commenced from Operator terminal • Scenario 3 – Continuous flow from Operator to Current Client Terminal with a shut-in of around 2 hours per day – Total continuous flow days = 338 • Scenario 4 – Shut-in period as a result of the 2 hr shut-in that had occurred in the stipulated twelve months (Scenario – 3)

Pipeline Integrity Management System

8” Pipeline – Indirect Inspection

Inclination angle and Pressure drop profile for 8” gas line Bi-directional flow…… Pipeline Integrity Management System

8” Pipeline – Indirect Inspection

Liquid hold-up profile for 8” gas line Flow = Elongated Bubble and Stratified Wavy Flow

Pipeline Integrity Management System

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8” Pipeline – Indirect Inspection

General “uniform” corrosion rate profile for 8” gas line Pipeline Integrity Management System

Number of Locations??? Finally DA provides quantifiable DEx locations!! Minimum Number of Final Assessment Sites Continuous Pipeline Length of All WG-ICDA Regions and Subregions in Pipeline Segment (km) (1 km = 0.62 mi)

Low Wall Loss < 20%

Moderate Wall Loss 21–40%

High Wall Loss 41–60%

Severe Wall Loss > 60%

Minimum Number of Final Assessment Sites per Pipeline Segment

0.1–10.0

0(A)** or 1(B)**

1

1

1

4

10.1–50.0

1

1

2

2

6

50.1–100.0

1

2

2

3

8

100.1–500.0

1

2

3

4

10

> 500

2

3

4

5

14

** Please refer WG-ICDA standard page-21

Pipeline Integrity Management System

8” Pipeline – results from ICPM…

Wall loss profile considering pitting factor. The red circle indicate the sites recommended for direct examination Pipeline Integrity Management System

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Internal Corrosion Mapping

2

1

3

4

5 6 7 Pipeline Integrity Management System

• Documented lowest wall thickness measurements taken from UFD (not to use a UT D- meter for IC) for ICDA within EACH grid • Such grids with remaining wall thickness readings MUST be included within the report as part of the Dex step

Pipeline Integrity Management System

Direct Examination Results – 8” gas pipeline ICPM Predicted Internal Wall Loss with Pf (%)

Actual Measured Internal Wall Loss (%)

Absolute Difference in Wall Loss [Predicted – Measured] (%)

5

15.41%

12.3%

3.11%

3

4.19%

2.36%

1.74%

2

4.16%

0.78%

3.38%

7

17.39%

16.22%

1.17%

SITE

Nominal Wall Thickness (mm)

6.35

“Excellent Correlation” Operator managed to assess the integrity “non-intrusively” Pipeline Integrity Management System

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Post Assessment Key Ingredients for “Successful” ICDA: 1. Subject Matter Expert- SME 2. Internal Corrosion Predictive Model - ICPM (Solid, Liquid, Bacteria, Sour, CR- general and pitting) 3. SME + ICPM + ICDA Team = Experience of performing “successful” ICDA’s $$$$$ Pipeline Integrity Management System

Case Study 2: Offshore Crude Line • • • • •

48” x 19 kms “non-piggable” Offshore crude oil pipeline Commissioned in 2006 Line divided into 2 regions and multiple scenarios for EACH region Line experienced 100+ different crude compositions Up to 2013 in operation 35% of the time and after 2013 to present in operation 55% of the time • Hydrotest done every 6 months for flexible lines LP-ICDA performed in 2015 to FINALLY assess the UNKNOWN integrity of the pipeline Pipeline Integrity Management System

Pipeline Segment – 18.7 km

Region 1 – 8.5 km

Region 2 – 10.2 km

LFP Valve

Geographical layout of Crude Oil pipeline Pipeline Integrity Management System

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STEP 2 – Indirect Inspection • A few representative crude types were used for the internal corrosion predictive modeling. • These crude types were transported through pipeline most of the time during the lifetime of the pipeline.

Pipeline Integrity Management System

STEP 2 – Indirect Inspection • Each crude type resulted in specific corrosion rate. • The corrosion rates were layered up on each other to give a cumulative corrosion rate for each scenario for this particular pipeline

West India- 48” x 19 kms Pipeline Integrity Management System

STEP 2 – Indirect Inspection

SMART DIGGING

Pipeline Integrity Management System

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Based on the prediction of solids deposition and water accumulation, pitting factor and the cumulative % wall loss was calculated Comparison of ICPM with In-the-ditch direct UT measurements Location downstream of PLEM

Actual Measured Wall Thickness (mm)

8,515.47

15.9

9,017.88

14.8

10,820.47

14.8

12,341.91

14.8

13,483.85

14.8

15,583.67

-

17,747.96

-

ICPM Predicted Internal Wall Loss(%)

Worst Measured Internal Wall Loss (%)

% Difference Measured vs ICPM

22.45 15.88 15.89 15.93 15.6 15.65 15.65

27.09 18.91 21.06 21.06 16.21

4.64 3.03 5.17 5.13 0.61

Not performed

-

Not performed

-

“Excellent Correlation” Operator managed to assess the integrity of Offshore line “non-intrusively” and now way forward…… Pipeline Integrity Management System

STEP 4 – Post Assessment - Remaining Life calculations based on CR - Reassessment Intervals - Root cause Analysis:

“Why is Corrosion Occurring”

- Recommendation & Mitigation Measures: “How to Fix it” - DA effectiveness and Possible Finalization of Areas

Pipeline Integrity Management System

Case Study 3: Mutiple Refined Products Non-Piggable Lines UNITY PLOT: ICDA for Product Lines The predictions compared with the actuals are all within the average ±10% wall loss criteria as specified by the NACE International MP-ICDA (SP0116-2016) Standard Practice

Measured Actual Wall Loss (%)

20

-10% Tolerance

18

+10% Tolerance

16

12" WO-1 12" MS/LAN - R2

14

12 10 12" HSD/SKO - R2

8

24" MS/LAN

6 24" HSD CCK - R4

4 2 0

12" BO-1

12" HSD/SKO-R1 24" HSD/SKO

0

India- 8 pipelines

5

12" BO-2 12" MS/LAN - R1

10 Predicted Wall loss (%)

15

20

Average ICPM wall loss (%) and the measured actual wall loss (%) for the 8 pipelines

Pipeline Integrity Management System

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Case Study 3: To manage CR: Critical Velocities to Prevent Water-Wetting Pipelines transporting aromatic products (lower density) require higher critical velocities to entrain water in the product during transfer 5

4.57

4.5

Critical Velocity (m/s)

4.01 4 3.5

3.38

3.2

2.96

2.77

3

1.89

2

2.94

2.7

2.38 2.5

2.5

3.35

2.03

2.01

1.5 1

0.93 0.55 0.65

0.93 0.55 0.65

0.5

24” CCK

12” MS/LAN

MS

MS

LAN

MS

12” WO-1

LAN

LAN

HSD

SKO

24” HSD/SKO

Benzene

HSD

SKO

12” HSD/SKO

HFHSD

HSD

LDO

12” BO-2

HFHSD

LDO

12” BO-1

FO-380

FO-180

FO-380

FO-180

0

24” MS/LAN

Pipeline Integrity Management System

Case Study 3: Internal Corrosion Monitoring Recommended Monitoring Locations & Types 12” A

10

2 0 -2 0

5000

10000

Distance (m)

-4

Elevation (m)

8601.7 m, WA

1016 m , IC

4

Elevation (m)

6

10 8 6 4 2 0 -2 0

10 8 6 4 2 0 -2 0 -4

10

12” D and E

Elevation (m)

Elevation (m)

8

12” B and C

1356 m , IC

1285 m, IC

10000

24” F and G

5

1149.9 m , WA

8601.7 m, WA 5000 Distance (m)

3921.4 m , WA

0 0

2000

4000

8197 m, IC

6000

8000

-5 1000 Distance (m)

2000

Distance (m)

IC – Location selected based on identified Internal Corrosion during DEx step WA – Location selected based on ICPM

Pipeline Integrity Management System

Case study 4- ICDA - Root Cause & Mitigation of “Piggable” Pipeline - AFTER UT-ILI • Piggable line transports export quality crude oil • Runs parallel to 2 x identical service 34” pipelines and 1 x parallel 48” pipeline

- Why did the corrosion occur found by ILI? March 2009

May

Dec.

Jan. 2015

Jan.

Aug. 2016

- How to manage2014 such an2014 asset in future?2015

Present

Secondfor failure - What not to do in future design and Line removed from service operations from a “corrosion perspective” 1

Commissioning date

st

First failure – 1 km downstream of launcher

UT- ILI completed – Extensive metal loss found

PO for ICDA started in Aug. 2016

ME- 34” x 9.5 kms Pipeline Integrity Management System

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ICDA and ILI Compatibility as per NACE As per the MP-ICDA standard from 2016, ILI can be used during ICDA:

“This standard is intended to provide an integrity assessment methodology for internal corrosion for pipelines where ILI cannot be performed; however, the MP-ICDA methodology may also serve, complement, or assist in those cases in which ILI was conducted or is contemplated to demonstrate the reliability of the ICDA process. “It can also be used for optimizing the selection/justification, inspection frequency, or prioritization of pipelines that are subjected to ILI.” - NACE International SP0116-2016 Multiphase Flow Internal Corrosion Direct Assessment MP-ICDA Methodology for Pipelines

Pipeline Integrity Management System

Predicted General/Uniform Corrosion rates of 34” •

Predicted general/uniform corrosion rates were <1 mpy (<0.0254 mm/yr) • Too low to cause significant metal loss in ~5.8 years!!!

•

However, severe metal loss was found at North and South sections by using ILI tool Solids deposition, water accumulation, chlorides, and corrosive microbes???

1.20

Elevation (m)

2.00

115

1.80

110

1.60

0.80

100

0.60

95

0.40

90

0.20

Elevation (m)

105

0.00

80 1000

2000

115

3000

4000

5000

110

1.40

85

6000

105

1.20 100 1.00 95

0.80

90

0.60

85

0.40 0.20 0

500

Distance (m)

1000

1500 2000 Distance (m)

North

2500

3000

80 3500

South

Pipeline Integrity Management System

Prediction of Solids Deposition for 34” Pipeline 16 14

Critical velocity (m/s)

500, 13.64

12

Critical Velocity (m/s)

0

120 Cummulative wall loss (%) Elevation (m)

1.00

Metal loss (%)

120

Elevation (m)

Cummulative wall loss (%)

Metal loss (%)

• 1.40

10 8

250, 7.73

6

150, 5.40

4 2

50, 1.25

0 0

100

200

300 Solids particle size (microns)

400

500

600

Calculated critical velocity (m/s) for solids deposition as a function of the solids particle size

Pipeline Integrity Management System

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Prediction of Localized Pitting Corrosion- SME + ICPM Localized pitting corrosion was predicted at different Cl - ion and Fe2+ ion concentrations at average operating conditions (0.28 MPa, 41oC, 2.2 mol% CO2 and 35 ppm H2S)

•

The chlorides levels observed and the operating conditions indicate the pits formed in the pipeline was found to passivate in about 59 – 72 days.

•

Failures due to internal corrosion. • A result of synergistic contribution between the halophilic microbial activity and the elevated chloride levels aided by water accumulation and solids deposition 450 400 350 300 250 200 150 100 50 0

[Cl-] - 5659 ppm; [Fe2+] - 550 Minimum concentration measured ppm

Pitting Corrosion Rate is Never Linear!

[Cl-] - 13332 ppm; [Fe2+] - 133 Maximum ppm concentration measured [Cl-] - 20000 ppm; [Fe2+] - 50 Sensitivity test - 1 ppm

100 mpy = 2.5 mm/yr

0

10

20

30

[Cl-] - 30000 ppm; [Fe2+] - 50 Sensitivity test - 2 ppm 40

50

60

70

80

Days

Effect of chloride ion on pitting corrosion rate showing pit initiation & propagation and pit passivation

Pipeline Integrity Management System

Comparison between ICPM predictions and ILI measurements in pipeline •

Comparison between ICPM predictions and ILI measurements

100 90

enpICDA™

80

Wall Loss (%)

70 60 50 40 30 20 10 0 0

1000 tie-in

2000

3000 4000 Distance from Tie-in (m)

5000 Tankage

6000

NORTH Pipeline Integrity Management System

Comparison between ICPM predictions and ILI measurements •

Comparison between ICPM predictions and ILI measurements

100 90

ILI

enpICDA™

80 70

Wall Loss (%)

Pitting Corrosion Rate (mpy)

•

60 50 40 30 20 10

0 0

1000 tie-in

2000

3000 4000 Distance from Tie-in (m)

5000 Tankage

6000

NORTH Pipeline Integrity Management System

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Prediction of Water Accumulation in the Pipeline tie-in to northern tankage 0.9

130 Predicted Water Layer Thickness (m) - T2

0.8

Elevation (m) 110

0.6

90

0.5 70 0.4

0.3

Elevation (m)

Water layer thickness (m)

0.7

50

0.2 30 0.1 0

10 0

1000

2000

3000

4000

5000

6000

Distance (m)

Pipeline Integrity Management System

Prediction of Water Accumulation in the Pipeline tie-in to northern tankage

Science being proven!!

0.9

130 Predicted Water Layer Thickness (m) - T2

Actual Metal Loss (%) - ILI

0.8

110

Elevation (m)

90

0.5

70

0.4

0.3

Elevation (m)

0.6

Metal Loss (%) - ILI

Water layer thickness (m)

0.7

50

0.2 30 0.1

0

10 0

1000

2000

3000

4000

5000

6000

Distance (m)

Pipeline Integrity Management System

Prediction of Solids Deposition Vs. ILI NORTH 0.31 125

0.26 105

85 Predicted Solids Deposition - T2 (01 Jan 2010 - 31 Dec 2015)

0.16

65 Elevation (m)

0.11

45

Elevation (m)

Solids deposition (%)

0.21

0.06

25

0.01

5 0

1000

2000

3000

4000

5000

6000

Distance (m)

Pipeline Integrity Management System

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Prediction of Solids Deposition Vs. ILI NORTH

Science being proven!!

0.31

125

0.26

105

85

Elevation (m)

0.16

65

Actual Metal Loss (%)- ILI 0.11

45

0.06

Metal Loss (%) - ILI

Predicted Solids Deposition - T2 (01 Jan 2010 - 31 Dec 2015)

Elevation (m)

Solids deposition (%)

0.21

25

0.01

5

0

1000

2000

3000

4000

5000

6000

Distance (m)

Pipeline Integrity Management System

Root Cause Analysis- for Piggable Line from ICDA The contributing factors that led to metal degradation in a Middle East crude oil pipeline are: • Low flow velocity in the pipeline • Water accumulation • Solids Deposition • Initiation and acceleration of under-deposit pitting corrosion under a high chloride ion concentration • Microbiologically Influenced Corrosion (MIC)

Pipeline Integrity Management System

Mitigation of Internal Corrosion for 34”

Mitigation Scenarios- “What iff’g” Two different what-if scenarios are investigated to determine options for minimizing the current internal corrosion mechanisms Scenario 1: Transporting the crude oil through one (1) 34” line and one (1) 48” line instead of the existing three (3) parallel running 34” lines and one (1) 48” line = 2 lines instead of 4! Scenario 2: Transporting all the crude oil from through only one (1) 34” line; with the other three pipelines depressured, cleaned and subsequently suspended with proper anti-corrosion measures = 1 lines instead of 4!

Pipeline Integrity Management System

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Initial What If Scenarios…..then GO Forward Plan Calculated liquid velocities at the different pipeline regions for 34” for EACH Scenario….FUTURE CORROSION!

Region

Liquid Velocity in 34” current scenario (m/s)

R1&R2 R3 R4 R5&R6 R7 R8&R9 R10 R11

1.718 1.256 0.784 0.551 0.372 0.297 0.175 0.076

R12&R13 R14 R15 R16

Scenario 1: Liquid Velocity in one 34” line and one 48” line (m/s)

Regions – Flow to NORTH 5.154 3.768 2.352 1.653 1.116 0.891 0.525 0.228 CR137 regions – Flow to SOUTH 0.854 2.562 0.427 1.281 0.175 0.525 0.078 0.234

Scenario 2: Liquid Velocity in one 34” line (m/s)

8.59 6.28 3.92 2.755 1.86 1.485 0.875 0.38 4.27 2.135 0.875 0.39

Pipeline Integrity Management System

Learnings…… • Owner has realized the strength of for managing ICDA: integrity of piggable Key Ingredients forICDA “Successful” and non-piggable pipelines

1. SME’s • Now(Subject applying it Matter for their Experts) critical lines in the pre-FEED stage, engineering time, as a PROACTIVE assessment to design and operate within the Integrity

2. ICPM (Solid,Window Liquid,( IOW’s) Bacteria, Sour, CR- general and pitting, % Wall Operating Loss) •

Be informed about susceptible locations and corrosion rates BEFORE they occur and operate the asset safely

3. SME + ICPM + ICDA Team WITH Experience of performing “successful” ICDA’s 4 circle stepsof REACTIVE inspection and • Trying to get out offor the ALL vicious + Verymaintenance Keen and Mature Pipeline Owner • Increase the LIFE and VALUE of the asset Pipeline Integrity Management System

Deliverables of ICDA • • • • • • • • • • • • • • • • • • •

Inclination angle (critical angles of and velocity for liquid/ solid accumulation) Flow regime in each sub region Pressure variation Temperature drop Average pH in each sub region Water accumulation rates and locations Liquid and Solid hold-up rates and locations Uniform corrosion rate Sensitivity analysis- amount of gas/ water on CR, production rates, composition of gas variations TLC (water dew point and hydrocarbon dew point calculations) Assessment of MIC’s, Erosion and corrosion due to oxygen Root cause analysis Inhibitor/ biocide/ scavanger requirement and effectiveness- mitigation Remaining wall thickness Mitigation recommendation Types and locations for Monitoring Chemical Treatment engineering Reassessment interval ICDA effectiveness Pipeline Integrity Management System

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External Corrosion Direct Assessment (ECDA) It involves a 4-step process: 1) Pre-assessment (PrA) = Scrutinizing Previous data & field investigation 2) Indirect Inspection (IDi) = Above ground “indirect” surveys 3) Direct Examination (DEx) = On the pipe “direct” Investigation 4) Post Assessment (PoA) = Integration, remaining life & overall health Historically (prior to ECDA standards), managed external corrosion using some of the ECDA tools and techniques, especially for Indirect Inspection (IDi), but NOT in an “integrated way” Big revolution in technology has come in the 2nd step of IDi for the Traditional CP and Coating survey techniques – CP CIPS, DCVG, CAT, ACVG etc. Pipeline Integrity Management System

Pre-Assessment (1.2.2.1) • Collects historic and current data – must be sufficient to go on to the next points • Must be performed in a comprehensive and thorough fashion • Used to determine if ECDA is feasible • Defines ECDA regions • Selects indirect inspection tools • Document pre-assessment results and decisions

What other data is needed?

Pipeline Integrity Management System

ECDA- Start Pre-Assessment (Step 1) with a CP Audit Includes, historic review of data, directly visiting and testing of: •T/R’s (all that can affect surveys) •Anode bed with Anode Junction Boxes •Cathode Junction Box •Permanent reference electrodes and associated cables •TLP’s various types maybe? •IJ’s •Grounding cells •Surrounding lines with/ without CP system = Interference To Understand the Performance of all these Components

Pipeline Integrity Management System

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ECDA- Results of CP Audit • •

•

Gain confidence on the asset in hand Plan for “customized” CP surveys for each line to answer: • Which ones? • Where? • Unique procedures based on this asset? • How many? • Managing the unknown locations of underground bonding • Interference concerns affecting data? Ensure the correct settings are in place, all concerns and issues have been looked into by operator BEFORE the surveys get planned, otherwise will get INCORRECT data leading to an INCORRECT ECDA program. 2nd Step of Indirect Inspection can ONLY start upon COMPLETING the above…. Are we almost there??

Pipeline Integrity Management System

Table 2 – NACE SP0502 This table assists in survey tool selection based on the specific ECDA segment conditions and may be used as a guideline:

CONDITIONS

Close Interval Surveys (CIPS)

Current Voltage Gradient Surveys (ACVG and DCVG)

Pearson

Electro-magnetic

AC Current Attenuation Surveys

Coating Holidays

2

1, 2

2

2

1, 2

Anodic Zones on Bare Pipe

2

3

3

3

3

Near River or WaterCrossings

2

3

3

2

2

Under Frozen Ground

3

3

3

2

1, 2

Stray Currents

2

1, 2

2

2

1, 2

Shielded Corrosion Activity

3

3

3

3

3

Adjacent Metallic Structures

2

1, 2

3

2

1, 2

Near Parallel Pipelines

2

1, 2

3

2

1, 2

Pipeline Integrity Management System

CONDITIONS

Close Interval Surveys (CIPS)

Current Voltage Gradient Surveys (ACVG and DCVG)

Pearson

Electro-magnetic

AC Current Attenuation Surveys

Under High Voltage Alternating Current (HVAC) Overhead Electric Transmission Lines

2

1, 2

2

3

3

Shorted Casings

2

2

2

2

2

Under Paved Roads

3

3

3

2

1, 2

Uncased Crossings

2

1, 2

2

2

1, 2

Cased Piping

3

3

3

3

At Deep Burial Locations

2

2

2

2

2

Wetlands (limited)

2

1, 2

2

2

1, 2

3

Rocky Terrain/Rock Ledges/ Rock Backfill

3

3

3

2

2

Pipeline Integrity Management System

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As per NACE: ECDA is NOT Feasible i.e. - Coating and CP Surveys are NOT feasible when……

Reference: NACE ECDA Standard

Pipeline Integrity Management System

The Need for Technology for Indirect Inspection (IDi) • Traditional IDi coating inspection techniques do not record continuous raw survey data for the entire pipeline length • Only anomalies that the Surveyor identifies and subjectively assesses to be reportable are documented Legacy equipment resulted in subjectivity • Subjectivity in a survey that is already indirect (IDi) = unreliable or non-repeatable • Location of data readings may be un-reliable • Position over subject pipe cannot be confirmed – locator separate from survey • No way to audit results • Tedious to document anomalies (manually logged and manually integrate) Pipeline Integrity Management System

TRADITIONAL SURVEY OUTPUTS…. •

DCVG

•

• •

Typical outputs are spreadsheets that are manually editable for all CIPS, CAT, DCVG, ACVG etc. DCVG is subjective – based on Surveyors observation Data manually aligned is tedious No traceability where NIL DCVG indication is reported

Pipeline Integrity Management System

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Results of No Access!

Pipeline Integrity Management System

Typical problems faced during survey due to access..

Pipeline Integrity Management System

Typical problems faced during survey due to access..

Pipeline Integrity Management System

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Typical problems faced during survey due to access..

Pipeline Integrity Management System

Typical problems faced during survey due to access..

Pipeline Integrity Management System

12” – Surveyor Movement & CP Data Should ALWAYS be recorded

Pipeline Integrity Management System

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Ideal CIPS Waveform from “good” Interruption Cycle and Electrode Having a Good Soil Contact

This is what we want with PROOF! Pipeline Integrity Management System

New Age Surveys- Transperently show Bad data- Inaccurate data on Concrete

Pipeline Integrity Management System

New Age Surveys- Transperently show Bad data- Broken Copper Wire

CIPS wire breakdown due to frequent obstruction on ROW.

Pipeline Integrity Management System

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New Age SURVEY OUTPUTS- CIPS- If T/R switches off unscheduled momentarily on 4” Pipeline

Pipeline Integrity Management System

New Age Waveform: Detects & Records Interference in a 48” Pipeline

CP CIPS Chart PSP vs Distance

300mV positive / anodic Influence @ SAME location! Pipeline Integrity Management System

Influence (if any) from HT/LT/Railway Crossings

AC Interference nearby cluster of HT AC andInterference LT nearby Railway Crossing

Reference DCVG Waveform

Pipeline Integrity Management System

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New Gen. Integrated IIT= CP CIPS, DCVG, ACVG, ACCA, DOC, & Depth of Cover with Elevation profile

Pipeline Integrity Management System

New generation – GIS & Integrated IIT

Pipeline Integrity Management System

Copyright Spectrum XLI

Other Advantages of new age Survey reporting– Terrain data auto-exported with common DGPS

Pipeline Integrity Management System

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Improvement in pipeline Integrity Validation • Avoid False Positives/ False Negatives! • Pipeline integrity assessment techniques of ILI and Hydrotesting provides auditable records so why not Above ground surveys….within DA or just a survey!

New Age = Continuous recorded non-editable raw logs that are auto-integrated makes this possible Pipeline Integrity Management System

Indirect Inspection (IDI) results used for Direct Examination (Dex)

Pipeline Integrity Management System

Indirect Inspection (IDI) results used for Direct Examination (Dex)

Pipeline Integrity Management System

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DEx – Documentation- Data to collect  Description of Terrain Conditions  Characterization of Surrounding Soils  Correlate the IDI indication because of which Dex location selected  Assessment of Coating Conditions  Identification of Corrosion Deposits  External Corrosion Defect Mapping and MPI for SCC measurements  Define interacting anomalies as per Operator requirement and perform Engineering Analysis (Ex. ASME B31G Calculations) for anomaly cluster and get the P safe

 Assessment of any other threats found (IC, MIC, Dents etc) Pipeline Integrity Management System

Step-3: Direct Examination

GPS Soil measurements

Coatings NDT

Environment Anomalies

“Most Accurate” Pipeline Integrity Management System

Direct Examination (DEx) Program • Multiple in the ditch site investigation/ pipeline • Immediate (I) action sites investigated • At least 1 Null site / pipeline (n+1) • Not ‘bell holes’ but rather sites with at least a girth weld (approx. 15 m long) • Standardized inspection protocols • Multiple coatings assessed separately • Consistent and proven data collection procedures

Pipeline Integrity Management System

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Coating Condition – Before & During DEx:

Coal tar coating intact but non adhered to pipe surface

Pipeline Integrity Management System

Coating Assessment- Field Vs. Factory Applied: Outer wrap along with field applied coal tar coating on the girth weld is found to be very poorly adhered to the pipe surface.

Factory applied coal tar coating on the pipe body is found to be well bonded during DEx inspection.

Pipeline Integrity Management System

DA- Step 3 – Direct Examination- Coating Assessment 3LPE = Fail!

Pipeline Integrity Management System

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8” Gas line DEx-3LPE Factory Coatings

• Well Bonded FBE layer • Passed all peel tests • 100% of 3LPE classified as “Excellent- Well Bonded” Pipeline Integrity Management System

8” Gas line: DEx-Shrink Sleeves Field Coatings- Good

• An example of Passed Shrink Sleeve- only a few locations for subject line based on DEx

Pipeline Integrity Management System

8” Gas line : DEx- Shrink Sleeves Field Coatings- Bad

• • • •

Minimal adhesive present on pipe surface Bare pipe visible with no/ spotty substrate Failed peel tests in majority locations circumferentially 75% of inspected SS failed and was found to be in “Fair to Poor” condition Pipeline Integrity Management System

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10” Insulated line: DEx- Electrolyte Present between for PUF and HDPE

Pipeline Integrity Management System

Findings of DEx during an ECDA Program: Pipe Body G W FeCO3

Poorly adhered Tape Coating FeO

Coal tar coating disbonded but intact

Pipeline Integrity Management System

External Corrosion – Engineering Assessment

Pipeline Integrity Management System

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Corrosion Profile/ Feature Pit Depth (mm)

0

100

200

Effective Length

Inner Pipe Wall

300

400

500

600

0.0 -1.0 Output

-2.0 -3.0

Imperial

Effective Length of Corrosion:

5.000

in

Start:

10.000

in

Pit Depth (mm)

End:

-4.0 -5.0

Total Length of Corrosion:

15.000

in

19.000

in

Effective Area of Corrosion:

0.710

in2

Maximum Pit Depth:

0.240

in

-6.0 -7.0

Max. Pit Depth / Wall Thickness: -8.0

64.2%

-9.0

Modified B31G (0.85dL) Method:

Fail

Maximum Safe Pressure: -10.0

833

psig

Burst Pressure:

1067

psig

Factor of Safety:

0.84

ASME B31G Method:

Pit Length (mm)

Is my P Safe > P operating? If Not What can I do to bring my P safe higher?

Fail

Maximum Safe Pressure:

503

psig

Burst Pressure:

644

psig

Factor of Safety:

0.50

Pipeline Integrity Management System

External Corrosion Direct Assessment – after 4th step = Post Assessment: - Remaining Life calculations - Reassessment Intervals - Root cause Analysis - Recommendation & Mitigation Measures - DA effectiveness

For EACH Pipeline!

- Possible finalization of DA regions

Pipeline Integrity Management System

5-year DA Program- Post DA- Operator Action Planned / Pipeline • • • • • • • • • • • • •

Change in Operating pressure Use the DA reports as the baseline assessment Immediate Repairs AND Repair Plan for future Monitor Prioritized Sections Data Integration for each of the DA stages Revised Centerline Coating Rehabilitation Make the line Piggable or schedule for ILI Perform Hydrotest Line Not Fit for Service Rerun Risk Assessment & Re rank the lines Plan for turnkey DA based on reassessment interval Appropriate inhibitors ? and corrosion monitoring ? Pipeline Integrity Management System

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Conclusions…. • Direct Assessment is an integrity assessment process through which an operator may be able to assess and evaluate the integrity of a pipeline segment. • It is one of the regulatory approved and/or recognized methodologies to assess pipeline integrity: – Pressure testing – ILI – Direct Assessment • Direct Assessment methodologies are quite successfully applied to both new/old; piggable/non-piggable pipelines. • Direct Assessment is intended to address EC, IC, and SCC threats to pipeline integrity. Pipeline Integrity Management System

Conclusions…. • Direct Assessment will usually include the following stages: 1. 2. 3. 4.

Pre-assessment — Detailed data gathering and integrating corrosion threat factors Indirect inspection — Identify suspected areas of corrosion Direct examination — Confirm corrosion sites (i.e. most probable locations) Post-assessment — Evaluation

• Each DA methodology will employ at least one non-destructive (NDE) inspection technique to physically inspect and assess pipeline. • Provides Root Cause Analysis – Why is the Corrosion occurring? • Mitigation plan provided- How to manage the corrosion?

Pipeline Integrity Management System

ADVANTAGES OF DA Proactive and designed to prevent lapses in pipeline integrity Answers the key questions- Why corrosion exist? And How to mitigate it (go forward plan)? Defect modeling can be developed from the DA process which can be used for forecasting and “what if.. Scenarios” to optimize production with existing threats Provides input for prioritizing and planning remedial integrity activities When possible, complementary to ILI and Hydrostatic testing for greater data accumulation, data verification etc A pipeline need not be put out of service during the process of assessing, thus no productivity downtime No cost required for preparing the pipeline to enable the usage of this assessing technique

Pipeline Integrity Management System

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Data Analysis & Interpretation Presented by

Pankaj Panchal

NACE, Corrosion Specialist NACE, Cathodic Protection Specialist

Mobile : +91 93772 76131 E-mail : [email protected]

Corrosion Cures Pvt. Ltd.

Pipeline Integrity Management System

1

OUTLINE

 CIPL Survey Data  DCVG Survey Data  CAT Survey Data  Soil Resistivity Data  Inline Inspection

 Comparison

Pipeline Integrity Management System

2

CIPL SURVEY Voltmeter Copper Wire Test Station

Electrolyte

Pipe

Pipeline Integrity Management System

3

1

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CIPL SURVEY

4

Pipeline Integrity Management System

CIPL SURVEY

5

Pipeline Integrity Management System

CIPL SURVEY ON/Off Potentials

On/Off & Depolarized Potentials

Potential Profile ON

OFF

Depolarized

Pipeline Integrity Management System

6

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CIPL SURVEY

Pipeline Integrity Management System

7

CIPL SURVEY

Pipeline Integrity Management System

8

CIPL SURVEY

Pipeline Integrity Management System

9

3

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CIPL SURVEY

Pipeline Integrity Management System

10

CIPL SURVEY Distributed anodes

Expanded scale

Pipeline Integrity Management System

11

DCVG SURVEY

Pipeline Integrity Management System

12

4

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DCVG SURVEY

Pipeline Integrity Management System

13

DCVG SURVEY

Pipeline Integrity Management System

14

DCVG SURVEY  dA   SD  S A   SB  S A   dA  dB   where: SD = signal strength at defect (mV) SA = signal strength at Point A (mV) SB = signal strength at Point B (mV) dA = distance from A dB = distance from B

SD = 200 mV +

1372 m (300 mV -200 mV ) = 275 mV 1372 m+ 457m

Pipeline Integrity Management System

15

5

29-08-2020

DCVG SURVEY

Pipe-to-Remote Earth = Σ Earth Gradients = 25+15+6+4+3+1+1 mV = 55 mV 

55mV 10020% IR 275mV

Perpendicular line between electrodes intersects defect Pipeline Integrity Management System

16

DCVG SURVEY

Pipeline Integrity Management System

17

DCVG SURVEY

Pipeline Integrity Management System

18

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29-08-2020

DCVG SURVEY ACCEPTANCE CRITERIA  0 – 15% IR

Small Coating Fault (Minor)

 15% - 35% IR

Medium Coating Fault (Moderate)

 35% - 70% IR

Medium – Large Coating Fault (Large)

 70% - 100% IR

Large Coating Fault (Major)

Pipeline Integrity Management System

19

DCVG SURVEY  Wenner – 4 Pin Method

 Soil Box Probe  Electromagnetic Induction Method

Pipeline Integrity Management System

20

DCVG SURVEY

Pipeline Integrity Management System

21

7

29-08-2020

DCVG SURVEY

Pipeline Integrity Management System

22

DCVG SURVEY

Pipeline Integrity Management System

23

PIPELINE CURRENT MAPPING

Pipeline Integrity Management System

24

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PIPELINE CURRENT MAPPING

25

Pipeline Integrity Management System

PIPELINE CURRENT MAPPING

26

Pipeline Integrity Management System

AVERAGE & LAYER RESITIVITY

r1 avg

a1

r2 avg

a2

a3

r3

rL1

L1

rL2

L2

rL3

L3

avg

Pipeline Integrity Management System

27

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29-08-2020

LAYER RESISTIVITY

Resistances R1, R2, and R3 measured with respect to spacings a1, a2, and a3 or L1, L2 and L3

r1 avg L1 RL1 rL1

= 2a1R1 = a1 = R1 = 2L1 RL1

r2 avg L2 RL2 rL2

= 2a2R2 = a2 – a1 = (R1 R2)/(R1 – R2) = 2L2 RL2

r3 avg L3 layer RL3 rL3

= 2a3R3 = a3 – a2 = (R2 R3)/(R2 – R3) = 2L3 RL3

28

Pipeline Integrity Management System

LAYER RESISTIVITY

RESISTIVITY RESISTANCE

R (Ω)

AVERAGE rave (Ω–cm)

RL(Ω)

LAYER rlayer (Ω–cm)

10.0

10,000

10.0

10,000

10.44 [318.2]

7.4

14,795

28.46

28,450

15.66 [477.3]

3.1

9,295

5.33

5,328

RESISTIVITY

SPACING (ft) [cm]

RESISTANCE

5.22 [159.1]

LAYER

Pipeline Integrity Management System

29

IN LINE INSPECTION

Pipeline Integrity Management System

30

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IN LINE INSPECTION

Pipeline Integrity Management System

31

IN LINE INSPECTION

Pipeline Integrity Management System

32

DATA COMPARISON

Pipeline Integrity Management System

33

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धन्यवाद | THANK YOU

Corrosion Cures Pvt. Ltd.

Pipeline Integrity Management System

34

12

RISK ASSESSMENT

by: Upama Darshan GM(Elect) IEOT, ONGC Upama Darshan Pipeline Integrity Management System

Name : Upama Darshan Designation: General Manager (Electrical), IEOT, ONGC Qualification: M. Tech (Integrated Electronics), IIT Delhi B. Tech (Electrical), G.B. Pantnagar University - Gold Medalist Job Experience: 35 years in ONGC 16 years in the field of Safety Studies Currently working in Institute of Engineering & Ocean technology since 2004. Executed more than 120 HAZOP & QRA Studies for various Onshore & Offshore Installations of ONGC including some commercial projects for OPaL and Nicco. Training/ Professional Course: Certified HAZOP Leader Had 5 days Risk Analysis Training at IIT Mumbai. Had 5 days SAFETI Software Training from DNV-GL. Had 2 days Process Safety Training at Dubai Honorary faculty in training programmes of National Safety Council and IPSHEM Goa. Presented papers in International forums.

Pipeline Integrity Management System

HAZID/ HAZOP

Pipeline Integrity Management System

OUTLINE • • • • • •

Introduction to HAZID/ HAZOP HAZOP Guidewords HAZOP Methodology Benefits of HAZOP HAZOP Limitations Exercise

Pipeline Integrity Management System

WHAT IS HAZARD? Hazard is a “physical situation” with a potential to cause harm • To people (Fatalities/ Injuries) • To property (Equipment, Buildings) • To environment (Air, Water or Land) • To business (Production loss, Clean up)

Pipeline Integrity Management System

WHY HAZARD Inherent Nature Physical Property of Matter • Flammable •

Toxic

State of Matter • • • •

Pressure Temperature Kinetic Energy Potential Energy

Unsafe Work Practices Pipeline Integrity Management System

UNSAFE WORK PRACTICES

Pipeline Integrity Management System

ACCIDENTS TRIANGLE Herbert Heinrich showed that for every accident resulting in a fatality or major disabling injury, there are approximately 300 unsafe incidents.

Pipeline Integrity Management System

SOURCES OF HAZARD  Hardware Failures–Piping/Flanges/Valves/Fittings etc.  Operator Error - Failure to close / open valves - Failure to respond to an alarm  Management System Failure - Policies, Training - Operating/Emergency Procedures - Supervision/Monitoring  Natural Events - Earthquakes, Lightning, Storm etc.  Man-made Events - Sabotage, Collision, Dropped Objects etc.

Pipeline Integrity Management System

PREVENTIVE MEASURES • • • • • • • •

Hazard Identification (HAZID) Periodic Maintenance Inspection, Testing Condition Monitoring Corrosion Monitoring – Cathodic Protection Safe Operating Procedures Awareness Programmes Training Pipeline Integrity Management System

HAZID TECHNIQUE • Hazardous Events • Loss of Containment from piping, valves, flanges, fittings etc. • Causes • Corrosion, Impact, Material & Construction Defects, Inadequate Design, Improper Operation etc. • Consequences • Jet Fire, Pool Fire, Fireball, Explosion etc. • Safeguards • Prevention, Detection, Control & Mitigation • Recommendations • Further Actions required

• Close-out Responsibility Pipeline Integrity Management System

QUESTIONS CATEGORIES • Integrity Failures/ Loss of Containment • External & Internal Corrosion • External Effects or Influences • Material & Construction Defects • Design Defects • Operational Lapses

• Natural Hazards Pipeline Integrity Management System

HAZID METHODOLOGY • Identify hazards associated with facility/ activity • Assess consequence/ potential incident events for all identified major hazards

• Check for Preventive Measures for all consequences • Where necessary suggest suitable remedial measures • Record the workshop findings

Pipeline Integrity Management System

HAZID WORKSHEET FORMAT

Pipeline Integrity Management System

INFORMATION REQUIRED FOR HAZID • Knowledge of System/ Facility • Equipment Layouts • PFDs (Simulation Report) • Design Basis/ Criteria & Specifications

• F&G Detection Layout & Philosophy • Fire Fighting Equipment Layout & Philosophy • Safety Equipment Layout & Philosophy

Pipeline Integrity Management System

WHAT IS HAZOP? • Formal, systematic review of the process plant design to assess the hazard potential of maloperation/mal-function of individual items of equipment & their consequential effect on the facility as a whole. • Structured around a set of specific guide-words

• Performed by a team having knowledge & experience

Pipeline Integrity Management System

HISTORY OF HAZOP • In early 1960’s ICI (Imperial Chemical Industry) wanted a better Design Review process • Suggested a team to address deviations from

normal • Introduced a set of guidewords to identify possible deviations

Pipeline Integrity Management System

MAJOR ACCIDENTS • Flixborough, U.K 1974 – 28 lives lost due to Full bore release of 40 tons of pressurized cyclohexane as a connecting pipe failed. • Seveso, Italy 1976 - Highly toxic chemical dioxin released into atmosphere due to Spontaneous exothermic reaction. No fatality known but 2 square miles of land had to be sterilized. • Bhopal Tragedy 1984 - 30 metric tons of Methyl Isocynate (MIC) escaped into the atmosphere in 45 to 60 minutes. Govt. confirmed a total of 3,787 deaths. • Piper Alpha 1988 - Large riser exposed to pool fire failed catastrophically and resulted in loss of 167 lives. Pipeline Integrity Management System

HAZOP OBJECTIVES • Identify potential hazards in process • Rigorous, systematic check of design, for safety, operability and conformity to codes, etc. • Demonstrate that possible actions taken to eliminate hazards

Pipeline Integrity Management System

TIMING OF HAZOP STUDY • • • • • •

Concept Phase Design Phase Pre- Start Phase Operation Phase Modification Phase Expansion Phase

Pipeline Integrity Management System

HAZOP PREPARATIVE WORK • Obtain basic informations like P&ID’s, process description, SAFE charts, etc. • Plan the sequence of the study • Prepare a time and meeting schedule

Pipeline Integrity Management System

HAZOP TERMINOLOGY  Node • Locations at which process parameters are investigated for deviations • Points where the process parameters have an identified design intent

 Parameter • An aspect of the process that describes it physically, chemically, or in terms of what is happening

 Intention • Defines how the system is expected to operate at the nodes Upama Darshan Pipeline Integrity Management System

HAZOP TERMINOLOGY  Guide-words • Words or phrases used to qualify or quantify the intention & associated parameters in order to discover deviations

 Deviations • Departures from the design intention discovered by systematically applying the guide-words to the parameter at each node

 Causes • Reasons why deviations may occur

 Consequences • Results of the deviations Upama Darshan Pipeline Integrity Management System

HAZOP TERMINOLOGY  Safeguards • Protective provisions present either to reduce the chances of a deviation occurring or to mitigate the consequences

 Recommendations • Suggested actions necessary either to reduce the chances of a deviation occurring or to mitigate the consequences or for further study

 Recording • Documented in HAZOP worksheets

Upama Darshan Pipeline Integrity Management System

HAZOP TEAM COMPOSITION • Typically HAZOP team is Multi-disciplinary • Process Engineer • Design Engineer • Instrumentation Engineer • Operations Engineer • Health, Safety & Environment Engineer • Experts with different backgrounds can identify problems more efficiently when working together than if working separately and combining their individual results. • Team should have knowledge & experience on the facility under consideration Upama Darshan Pipeline Integrity Management System

HOW TO PERFORM HAZOP ? • Plant considered section-by-section, lineby-line and item-by-item but never in complete isolation. • Using guide-words, process deviations from design intention are identified and study considers: • Possible causes of deviations • Possible consequences of deviations • Checks for available safety measures • Suggests remedial action if required

Upama Darshan Pipeline Integrity Management System

HAZOP GUIDEWORDS No/Not/ None

:The complete negation of the intention

More of

:Quantitative increase

Less of

:Quantitative decrease

As well as

:Qualitative increase

Part of

:Qualitative decrease

Reverse

:Logical opposite of the intention

Other than

:Complete substitution

Upama Darshan Pipeline Integrity Management System

PROCESS GUIDEWORDS Guideword

Process parameters

Flow No, None Less

No Flow Less Flow

More

More Flow

Temp Less Temp More Temp

Presuure Less Pressure More Pressure

As well As Contamination Part of Reverse

Composition Reverse Flow Upama Darshan Pipeline Integrity Management System

Level Less Level More level

HAZOP WORKSHEET

Pipeline Integrity Management System

NO FLOW Wrong routing

Blockage Incorrectly fitted check valve Large leak, Rupture of Pipe

Equipment failure (isolation valve, pump etc.)

Upama Darshan Pipeline Integrity Management System

REVERSE FLOW Defective check valve Siphon effect Incorrect pressure differential Leakage/ Rupture

Upama Darshan Pipeline Integrity Management System

MORE FLOW  Exchanger tube leaks

 Increased pumping capacity,  Increased suction pressure, reduced delivery head  Restriction orifice plates deleted  Cross connection of systems  Control faults

Upama Darshan Pipeline Integrity Management System

LESS FLOW Line restrictions Clogged filter/ strainer Defective pumps

Upama Darshan Pipeline Integrity Management System

MORE LEVEL Outlet isolated or blocked Inflow greater than outflow Faulty level measurement

Upama Darshan Pipeline Integrity Management System

LESS LEVEL Inlet flow stops Leak Outflow greater than inflow

Draining of vessel

Upama Darshan Pipeline Integrity Management System

MORE PRESSURE Connection to high pressure system Defective isolation procedures for relief valves

Thermal overpressure PCV Malfunction

Upama Darshan Pipeline Integrity Management System

LESS PRESSURE Generation of vacuum condition

Condensation Restricted pump/compressor suction line Undetected leakage Vessel drainage PCV Malfunction

Upama Darshan Pipeline Integrity Management System

MORE TEMPERATURE Ambient conditions Fire situation Cooling water failure

Defective control

Pipeline Integrity Management System

LESS TEMPERATURE    

Ambient conditions Reducing pressure Leakage in exchanger tubes Loss of heating

Pipeline Integrity Management System

UTILITIES FAILURE Failure of Instrument air, steam, water, nitrogen Hydraulic power, electric power Telecommunications, computer and interfaces

Pipeline Integrity Management System

HAZOP METHODOLOGY

Pipeline Integrity Management System

HAZOP STEPS • • • •

Select a node, apply a guideword Develop a deviation Examine possible causes Examine consequences consider hazards, or operability problems • List existing safeguards • Decide upon action, make a record of the discussion and decision

Upama Darshan Pipeline Integrity Management System

PREVENTIVE MEASURES Awareness of Toxic and hazardous properties of

process

materials

Fire and gas detection Emergency shutdown Fire-fighting facility Testing of emergency equipment Emergency Response Plans Training Upama Darshan Pipeline Integrity Management System

HAZOP RECOMMENDATIONS  Recommendation must be: • • • • • •

Clear Concise Unambiguous Relevant Prioritised Follow the “3Ws” Rule • • •

What do you want? Where do you want it? Why do you want it?

Upama Darshan Pipeline Integrity Management System

WRITING HAZOP RECOMMENDATIONS •

Notes Remove the manual valve

Full Recommendation Remove the manual valve on the drain line from pH meter No. xyz, to prevent the meter being over-pressurised if the valve is closed.

Upama Darshan Pipeline Integrity Management System

WRITING HAZOP RECOMMENDATIONS Notes

Full Recommendation

Avoid small bore fittings

Small bore fittings should not be provided in the up-stream of the shutdown valve XSDV361

Upama Darshan Pipeline Integrity Management System

EXERCISE -1

Pipeline Integrity Management System

Worksheet -

EXERCISE -2

Upama Darshan Pipeline Integrity Management System

PROCESS FLOW

Upama Darshan Pipeline Integrity Management System

Worksheet -2

STRENGTHS OF HAZOP •Based on well- understood HAZOP approach •Uses experience of operating personnel as part of team •Systematic, comprehensive & can identify all process deviations •Aids to design of safe & operable plant •Helps in preparation of O&M manuals

Pipeline Integrity Management System

WEAKNESSES OF HAZOP • Benefits depend on experience of team leader and the knowledge of the team • Very time consuming process • Documentation is lengthy and difficult to audit

Upama Darshan Pipeline Integrity Management System

EXERCISE -1

Pipeline Integrity Management System

EXERCISE -1

Pipeline Integrity Management System

Back

EXERCISE -2

Pipeline Integrity Management System

EXERCISE -2

Pipeline Integrity Management System

EXERCISE -2

Pipeline Integrity Management System

EXERCISE -2

Pipeline Integrity Management System

EXERCISE -2

Pipeline Integrity Management System

Back

QUANTITATIVE RISK ASSESSMENT

Risk

WHAT IS RISK ? RISK IS A FUNCTION OF LIKELIHOOD

OF AND

POSSIBLE THE

UNDESIRED

MAGNITUDE

EVENTS

OF

ASSOCIATED CONSEQUENCES.

Upama Darshan Pipeline Integrity Management System

THEIR

RISK MANAGEMENT Understanding Risk

What can go

How

wrong?

likely is

it?

Pipeline Integrity Management System

What are the impacts?

OUTLINE •Introduction to QRA •Hazard Identification •Consequence Analysis •Frequency Analysis •Risk Estimation •Risk Criteria •Risk Assessment •Risk Presentation

Pipeline Integrity Management System

WHAT AT RISK  Human Life  Property  Environment  Corporate Reputation

Pipeline Integrity Management System

RISK MATRIX

Pipeline Integrity Management System

DRIVING FORCE FOR SAFETY STUDIES  Flixborough, U.K (1974) – VCE (28 fatalities)  Bhopal, India (1984) - Toxic Gas Release (4000 fatalities)  Piper Alpha, U.K (1988) – Fire & Explosion (167 fatalities)

Pipeline Integrity Management System

PIPER ALPHA, U.K (1988) Piper Alpha Accident • 6th July, 1988 • 226 people on board, 167 people killed • Production: 300,000 BOPD • Property Damage 1.4 billion US Dollars • QRA became mandatory since Piper Alpha accident

Pipeline Integrity Management System

WHY RISK ASSESSMENT? •Regulatory requirement •Decision-making tool •Good business practice

Pipeline Integrity Management System

INTRODUCTION TO QRA •Risk Analysis is a means of objectively measuring the risk from hazardous activities of a facility or operation. •The risks are quantified in terms of their probability and consequences.

•By comparison with suitable risk criteria, the results can be used to decide whether the facility is unacceptable, or whether improvements are necessary. Pipeline Integrity Management System

WHAT IS QRA? QRA tries to answer the following six simple questions: Question

Technical Term Used

• What can go wrong ?

Hazard Identification

• How bad ?

Consequence Analysis

• How often ?

Frequency Estimation

• What’s its cumulative effect ?

Risk Analysis

• So What ?

Risk Assessment

• What do I do ?

Risk Management

Upama Darshan Pipeline Integrity Management System

QRA METHODOLOGY Identify Hazards Evaluate Consequences

Estimate Frequencies

Risk Analysis Risk Criteria Options to Mitigate No Consequences

Risk Assessment Risks Controlled ?

No

Options to Decrease

Yes Optimize Options to Manage Risks

Upama Darshan Pipeline Integrity Management System

Frequencies

SYSTEM DEFINITION W/F COMPRESSOR

R E

C E

GDU

S

Well Manifold

Gas out

E P E R

I

A

V

T

E

O

R

R

SURGE TANK

Oil out MOL PUMP

Upama Darshan Pipeline Integrity Management System

HAZARD IDENTIFICATION  Hazard identification is one of the most critical steps in any risk analysis study. A hazard omitted is a hazard not analyzed.

 Hazard identification is a qualitative review of possible accident scenarios which may occur, in order to select a list of possible failure cases for quantitative modeling through QRA.

Upama Darshan Pipeline Integrity Management System

FREQUENCY ANALYSIS • Frequency analysis involves estimating the likelihood of each of the selected failure cases, which were defined in the hazard identification stage. Typical requirements are frequencies of pipe leaks, flange/valve/small bore fitting leaks, heat exchanger leaks, vessel leaks, pump leaks etc.

• Frequency is the expected number of occurrences of the event per unit time, usually a year. The frequency is usually presented in scientific notation, e.g. 6.5 x 10-3 yr-1.

Upama Darshan Pipeline Integrity Management System

FREQUENCY ESTIMATION • Fi = Fn/ Ni • where, Fi is individual equipment failure frequency per year • Fn is number of failures of that equipment in past • Ni is number of exposed equipment-years (number of that equipment multiplied by the number of years) • Ft = Fi * Nn • where, Ft is total failure frequency per year (future) • Fi is individual equipment failure frequency per year • Nn is number of that equipment present Upama Darshan Pipeline Integrity Management System

FREQUENCY ESTIMATION EXAMPLE • Example Description • Say, there were 30 valve leaks observed in a plant over a period of past 10 years among 3000 valves present of that type • Now, in a new plant it is proposed to install 10 valves of the same type • Then what is the likelihood of having a valve leak in the new plant?

Upama Darshan Pipeline Integrity Management System

Example

CONSEQUENCE ANALYSIS • Effect modelling to evaluate the physical effects of • • • •

Discharge (gas, liquid, 2-phase) Dispersion (gas, liquid) Fire (Jet fire, Pool fire, Flash fire, BLEVE/ fireball Explosion

Upama Darshan Pipeline Integrity Management System

RISK ESTIMATION SOFTWARE Software are available in the market for risk calculation. For offshore QRA : SAFETI Offshore For onshore QRA : SAFETI Onshore Shepherd (Shell projects only)

Non Integrated Software Risk Curve, Effect, Damage Upama Darshan Pipeline Integrity Management System

RISK PRESENTATION • Risk is generally expressed in two forms • Individual Risk • •

The risk experienced by an individual in a given time period, usually fatality risk as it is easy to measure. It reflects the severity of the hazards and the amount of time the individual is in proximity to them.

• Group (Societal) Risk • The risk experienced by a group of people in a given time period, usually fatality risk as it is easy to measure. • It reflects the severity of the hazard and the number of people in proximity to it. • When applied to general public, it is known as societal risk. Upama Darshan Pipeline Integrity Management System

RISK CRITERIA • Risk criteria are the standards which are used to translate numerical risk estimates (e.g. 10-7 per year) as produced by QRA into value judgement (e.g. negligible risk) which can be set against other judgement (e.g. high economic benefits) in a decision-making process.

• It comprise the technical aspect of the decisionmaking process, which is one of the key links which integrate QRA into risk management. Upama Darshan Pipeline Integrity Management System

RISK CRITERIA TERMINOLOGY • An Intolerable region, within which the risk is generally intolerable whatever the benefit may be. Risk reduction measures or design changes are considered essential. • A middle band (or ALARP region) where the risk is considered to be tolerable only when it has been made ALARP (As Low As reasonably Practicable). This requires risk reduction measures to be implemented if they are reasonably practicable, as evaluated by cost-benefit analysis.

• A Negligible region, within which the risk is generally tolerable, and no risk reduction measures are needed. Upama Darshan Pipeline Integrity Management System

INPUTS FOR QRA • PFD/ P&IDs Pressure Temperature Inventory Pipeline/ Equipment sizing Meterological Data Onsite Manning/ Offsite Population Data

Pipeline Integrity Management System

INTRODUCTION - SAFETI SOFTWARE

Pipeline Integrity Management System

SOFTWARE INPUT - PARAMETERS

Pipeline Integrity Management System

SOFTWARE INPUT - LEAK

Pipeline Integrity Management System

SOFTWARE INPUT – HOLE SIZE

Pipeline Integrity Management System

SOFTWARE INPUT – FREQUENCY

Pipeline Integrity Management System

SOFTWARE INPUT – PIPELINE

Pipeline Integrity Management System

SOFTWARE INPUT – PIPELINE

Pipeline Integrity Management System

SOFTWARE INPUT – PIPELINE PARAMETERS

Pipeline Integrity Management System

SOFTWARE INPUT – PIPELINE PARAMETERS

Pipeline Integrity Management System

SOFTWARE INPUT – WEATHER

Pipeline Integrity Management System

MATERIAL PROPERTIES

Pipeline Integrity Management System

SOFTWARE INPUT - LAYOUT

INPUT – PLANT LAYOUT

Pipeline Integrity Management System

SOFTWARE INPUT POPULATION INPUT - POPULATION

Pipeline Integrity Management System

SOFTWARE INPUT - IGNITION SOURCE

INPUT - IGNITION SOURCES

Pipeline Integrity Management System

IGNITION SOURCES • Static electricity • Welding and other hot work • Exhausts • Engine and motors • Flares

• Hot surfaces • Human activity • Impact Upama Darshan Pipeline Integrity Management System

SOFTWARE RUN SOFTWARE RUN

Pipeline Integrity Management System

VIEW RESULTS VIEW RESULTS

Pipeline Integrity Management System

SOFTWARE OUTPUT SOFTWARE OUTPUT

Pipeline Integrity Management System

SOFTWARE OUTPUT

Pipeline Integrity Management System

SOFTWARE OUTPUT

Pipeline Integrity Management System

QRA OUTPUT (PIPELINE) INDIVIDUAL RISK CONTOUR

QRA OUTPUT (PIPELINE) INDIVIDUAL RISK CONTOUR

Pipeline Integrity Management System

QRA OUTPUT SOCIETAL RISK F-N CURVE

QRA OUTPUT SOCIETAL RISK F-N CURVE

Pipeline Integrity Management System

QRA OUTPUT (PLANT) INDIVIDUAL RISK CONTOUR

QRA OUTPUT (PLANT) INDIVIDUAL RISK CONTOUR

Upama Darshan Pipeline Integrity Management System

QRA OUTPUT SOCIETAL RISK

Upama Darshan Pipeline Integrity Management System

INDIVIDUAL RISK CRITERIA

Upama Darshan Pipeline Integrity Management System

INDIVIDUAL RISK CRITERIA (Suggested by Health & Safety Executive, U.K) for onshore installations RISK LEVELS

PUBLIC (per year)

PLANT PERSONNEL (per year)

Maximum Tolerable

1x 10 -4

1x 10 -3

Negligible

1x 10 -6

1x 10 -6

Upama Darshan Pipeline Integrity Management System

SOCIETAL RISK CRITERIA

Upama Darshan Pipeline Integrity Management System

SOCIETAL RISK CRITERIA (Suggested by Health & Safety Commission, U.K) for onshore installations

Pipeline Integrity Management System

RISK MANAGEMENT 100% Safe?

Cost of accidents

Cost of safeguards

Absence of risk is hardly possible and very expensive

Degree of Safety Upama Darshan Pipeline Integrity Management System

CHALLENGES IN QRA •

Understanding Risk Profile

•

Lack of participation of field personnel in safety studies

•

Continuous modifications in facilities

•

Data Availability

•

Uncertainty of too many assumptions

•

Absence of Benchmarking Criteria

Upama Darshan Pipeline Integrity Management System

Upama Darshan Pipeline Integrity Management System

29-08-2020

Regulatory Requirements

N Manohar Rao Pipeline Integrity Management System

PNGRB NOTIFICTION for CGD IMS

PNGRB Notification No. F.No.INFRA/IMP/CGD/1/2013 Dated 16th May 2013 These regulations may be called the Petroleum and Natural Gas Regulatory Board (Integrity Management System for City or Local Natural Gas Distribution Networks Regulations, 2013.

Pipeline Integrity Management System

PNGRB NOTIFICTION for CGD IMS PNGRB Notification No. F.No.INFRA/IMP/CGD/1/2013, Dated 16th May 2013 These regulations may be called the Petroleum and Natural Gas Regulatory Board (Integrity Management System for City or Local Natural Gas Distribution Networks Regulations, 2013. Applicability shall apply to all the entities laying, building, operating or expanding city or local natural gas distribution networks Pipeline Integrity Management System

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PNGRB NOTIFICTION for CGD IMS PNGRB Notification No. F.No.INFRA/IMP/CGD/1/2013 Dt 16 May 2013 Scope shall cover all existing and new city gas distribution networks including sub-transmission pipelines, city gas station, distribution mains and piping facilities downstream of inlet isolation valve of city gate station (inclusive of primary, secondary and tertiary networks) including consumer meter for commercial or industrial customer and up to final isolation valve including connecting hose to gas appliances for domestic consumer. Pipeline Integrity Management System

PNGRB NOTIFICTION for CGD IMS Objectives. • evaluating the risk associated with city gas distribution networks and effectively allocating resources for prevention, detection and mitigation activities. • improving the safety of city gas distribution networks so as to protect the personnel , property, public and environment • bringing more streamlined and effective operations to minimize the probability of CGD network failure.

Pipeline Integrity Management System

PNGRB NOTIFICTION for CGD IMS

Requirement under other laws It shall be necessary to comply with all statutory rules, regulations and Acts in force as applicable and requisite approvals shall be obtained from the relevant competent authorities for the CGD networks.

Pipeline Integrity Management System

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PNGRB NOTIFICTION for CGD IMS Default and consequences

• compliance to the provisions of these regulations through implementation schedule as described in these regulations at Schedule 7 and Schedule 8 in conjunction to Appendix II.

Pipeline Integrity Management System

PNGRB NOTIFICTION for CGD IMS Default and consequences • In case of any shortfall, the entities shall be liable to face the following consequences, namely –  The entity shall be required to complete each activity within the specified time limit. Any deficiency in achieving in one or more of the activities, the entity shall submit a mitigation plan within the time limit for acceptance of the Board and make good all short comings within the time agreed by the Board.  In case the entity fails to implement the approved Integrity Management System, the Board may issue a notice to defaulting entity allowing it a reasonable time to implement the provisions of Integrity Management System. In case the entity fails to comply within the specified time, the relevant provisions of the Act and regulations shall apply. Pipeline Integrity Management System

PNGRB NOTIFICTION for CGD IMS Schedule 1 Objectives The objective of Integrity Management System (IMS) is to – ensure the integrity of CGD networks at all times to ensure public protection of environment, maximum availability of CGD networks and also minimizing business risks associated with operations of gas network. ensure the quality of CGD network integrity in all areas which have potential for adverse consequences promote a more rigorous and systematic management of CGD network integrity and mitigate the risk Increase the general confidence of the public in operation of CGD network optimize the life of the CGD network Pipeline Integrity Management System

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PNGRB NOTIFICTION for CGD IMS

Schedule 2 Introduction to the Integrity Management System (IMS) CGD network expose people, communities and the environment to risks in case of failure. CGD network are themselves exposed to external damages caused by third parties causing for network failure. the life-line of the masses in regard to domestic cooking of food and movement in vehicles are fully dependent on CGD network. In case of failure, normal life may be badly disrupted. It is, therefore, essential that a system is introduced which ensures maximum availability of the network with minimum disruption and damages. IMS for CGD networks provides a comprehensive and structured framework for assessment of CGD networks condition, likely threats, risks assessment and mitigation actions to ensure safe and incident free operation of CGD networks Pipeline Integrity Management System

PNGRB NOTIFICTION for CGD IMS Schedule 2 integrity management system essentially comprises of the following elements Integrity Management Plan (IMP): collection and validation of data, assessment of spectrum of risks, risk ranking, assessment of integrity with reference to risks, risks mitigation, updation of data & reassessment of risk; Performance evaluation of Integrity Management Plan: mechanism to monitor the effectiveness of integrity management plan adopted and for further improvement Communication Plan: a structured plan to regulate information and data exchange within and amongst the internal and external environment Management of Change Quality Control Pipeline Integrity Management System

PNGRB NOTIFICTION for CGD IMS Schedule 3 Description of CGD Network • • • • • •

Sub Transmission Pipeline (STPL) City Gas Station (CGS) Odorization System Steel pipeline networks Secondary PE networks Tertiary networks, PE, GI and/ or copper

Pipeline Integrity Management System

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PNGRB NOTIFICTION for CGD IMS Schedule 3 Description of CGD Network • • • • •

District Regulating Station (DRS) Isolation Valves (Steel, PE) Customer base (PNG, CNG, Industrial and Commercial) CNG station-Mother, Online, Daughter Booster Station (DBS) Individual Pressure Regulating Station (IPRS), Common Pressure Regulating Station (CPRS), Metering Station (MRS)

Pipeline Integrity Management System

PNGRB NOTIFICTION for CGD IMS Schedule 3

Description of CGD Network • • • • •

Control room and/or Master Control Station (if any) Instrumentation and Electrical systems Supervisory Control and Data Acquisition (if any) Safety Equipments Customer base (PNG, CNG, Industrial and Commercial)

Pipeline Integrity Management System

PNGRB NOTIFICTION for CGD IMS Schedule 3 Other description • Interfaces with other Geographical Area / pipeline / Facilities (if available); • Incident reporting; • Information on Documentation Relating to design, construction, operations, maintenance, etc.; • Statutory requirements

Pipeline Integrity Management System

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PNGRB NOTIFICTION for CGD IMS

Schedule 4 Selection of appropriate Integrity Management System Prescriptive type Integrity Management System if CGD industry has gathered a reasonable good experience of CGD operations and such CGD industry is fairly mature, a Performance based Integrity Management System are appreciated globally. Prescriptive type Integrity Management System where CGD networks are in developing stage. This is more rigorous as it considers the worst case scenario of the failures in the CGD networks Pipeline Integrity Management System

PNGRB NOTIFICTION for CGD IMS Schedule 4 Selection of appropriate Integrity Management System A prescriptive type mandates the implementation of an established process for addressing the risks, their consequences and proven methods for mitigation. A prescriptive type mandates the in-house development of Integrity Management Plan and Management of Change pertaining to technical aspects. In India till date, the preparation of prescriptive type has been considered for implementation to all CGD networks in India Pipeline Integrity Management System

PNGRB NOTIFICTION for CGD IMS Schedule 5 Integrity Assessment Tools Direct assessment and evaluation - External Corrosion Direct Assessment (ECDA) can be used for determining integrity for the external corrosion threat on CGD network segments Thickness assessment and periodic review against baseline values - Periodic thickness assessment for all CGD network skids and pressure vessels and comparison to baseline values shall be done once a year Pipeline Integrity Management System

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PNGRB NOTIFICTION for CGD IMS

Schedule 5 Integrity Assessment Tools Cathodic protection system surveys - to cover the entire steel network of pipelines so as to detect insufficient Cathodic Protection levels and other irregularities and anomalies in the steel pipeline. Pressure testing - Pressure testing shall comply with the requirements of applicable Petroleum and Natural Gas Regulatory Board regulations Pipeline Integrity Management System

PNGRB NOTIFICTION for CGD IMS Schedule 6 Designing applicable Integrity Management System for the CGD Network Initial data gathering, review and integration to support a risk assessment will vary depending on the threat being assessed. Four aspects should be visualized during data collection • Data alignment - Integration of disparate data sources to a common location • Data history - Ability to manage the temporal aspects of any data • Data Normalization - Integration of disparate data sources that analyze same attributes from different aspects • Data accuracy and confidence Pipeline Integrity Management System

•

PNGRB NOTIFICTION for CGD IMS Schedule 6 Identification of Threats Pipeline Research Council International (PRCI) represents 22 root causes (threats) for threat to pipeline integrity Time Dependent Threats: – External Corrosion – Internal Corrosion – Stress Corrosion Cracking Stable Threats: – Manufacturing related defects – Defective pipe seam – Defective pipe Pipeline Integrity Management System

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PNGRB NOTIFICTION for CGD IMS Schedule 6 Identification of Threats Welding /fabrication related • Defective pipe girth weld • Defective fabrication weld • Wrinkle bend or buckle • Stripped threads /broken pipe /coupling failure Equipment • Gasket O-ring failure • Control/relief equipment malfunction • Seal pump packing failure • Miscellaneous Pipeline Integrity Management System

PNGRB NOTIFICTION for CGD IMS Schedule 6 Identification of Threats Time independent Threats: Third party /mechanical damage: • Damage inflicted by first, second or third party (instantaneous /immediate failure) • Previously damaged pipe (delayed failure mode) • Vandalism • Rat bites • Electric Arching

Pipeline Integrity Management System

PNGRB NOTIFICTION for CGD IMS Schedule 6 Identification of Threats Incorrect operational procedure Weather related and outside force: • • • •

Weather related Lightning Heavy Rains or Floods Earth Movements

based upon the land pattern: • Creek Area effects • Muddy Land effects • River bed movements Pipeline Integrity Management System

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PNGRB NOTIFICTION for CGD IMS Schedule 6 Consequence and Impact Analysis Once the hazardous events are identified, the risk analysis is to analyse their consequences, i.e., estimate the magnitude of damage to the public, property and environment of all the indentified threats by using mathematical models . These consequences may include leak, fire, explosion, gas cloud etc

Identification of High Consequence Area (HCA) these are high-population-density areas, difficult-to-evacuate facilities (such as hospitals or schools), and locations where people congregate (such as places and worship, office buildings, or fields).

Pipeline Integrity Management System

PNGRB NOTIFICTION for CGD IMS Schedule 6 Risk Management and Risk Assessment Risk rating = Probability rating X Consequence rating Probability rating - based on industry experience and company’s past experience. scale 1 to 4, 1 to 5 or 1 to 6 may be applied. Consequence rating - these may be individually characterized under impact on people, environment, financial and business loss value and legal consequences. 1 to 4, 1 to 5 or 1 to 6 may be applied.

Pipeline Integrity Management System

PNGRB NOTIFICTION for CGD IMS Schedule 6 Risk Management and Risk Assessment A company should carry out the following activities as part of risk assessment –

– Carry out Cathodic Protection system and CP adequacy survey; – Carry out periodic analysis to determine the level of risks to assets; – Risk analysis and assessment for all reported asset-related incidents and findings; – Prepare, maintain and update a register of known risks to assets, including their risk rating. Pipeline Integrity Management System

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PNGRB NOTIFICTION for CGD IMS Schedule 6 Risk Management and Risk Assessment Risk results could be evaluated simply on a “high–medium-low”

basis or as a numerical value. Prioritization usually involves sorting risk ratings in decreasing order The risk ratings shall be reviewed and necessary changes made after a pre-decided interval or when changes take place or when additional data or information becomes available.

Pipeline Integrity Management System

PNGRB NOTIFICTION for CGD IMS Schedule 6 Integrity Assessment The following methods can be used for Integrity Assessment – Hydro testing before commissioning at test pressure as per T4S standards; – External Corrosion Direct Assessment(ECDA); – Cathodic protection system surveys etc The operator of a CGD networks shall develop a chart of most suited integrity assessment method and assessment interval for each threat and risk. The operator shall further develop appropriate specifications and quality control plan for such assessment Pipeline Integrity Management System

PNGRB NOTIFICTION for CGD IMS Schedule 6 Responses and Mitigation Responses may be immediately implemented, scheduled over a period of time or the system may be simply monitored based on the inspection outcome Some of the mitigation actions are listed below Actions for increasing the adequacy levels of Cathodic Protection, like increasing Cathodic Protection current levels, installation of additional capacity etc. – Replacement / repair of assets based on analysis outcomes – Consultation with equipment suppliers for deciding course of actions –

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PNGRB NOTIFICTION for CGD IMS Schedule 6 Performance Plan Performance evaluation should consider both threat-specific and aggregate improvements. Threat-specific evaluations may apply to a particular area of concern, while overall measures apply to the entire CGD network under the integrity management programme Performance indicator measures – Process measures – Operational measures – Direct integrity measures Pipeline Integrity Management System

PNGRB NOTIFICTION for CGD IMS Schedule 6 Communication Plan The CGD entity shall develop and implement a communications plan in order to inform about their integrity management efforts and the results of their integrity management activities to – appropriate company personnel – jurisdictional authorities – the public

Pipeline Integrity Management System

PNGRB NOTIFICTION for CGD IMS Schedule 6 Management of Change Plan management of change process includes the following – Reason for change – – – – – – – – –

Authority for approving changes Analysis of implications Acquisition of required work permits Documentation Communication of change to affected parties Time limitations Staff involved Planning for each situation Unique circumstances if any Pipeline Integrity Management System

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PNGRB NOTIFICTION for CGD IMS Schedule 6 Quality Control Plan The following activities are usually required – – Identify the processes – sequence and interaction of these processes – Prepare standard operation procedures and guidelines for critical processes – Provide the resources and information necessary to support the operation and monitoring of these processes – Monitor, measure, and analyze these processes – Implement actions necessary to achieve planned results and continued improvement of these processes Pipeline Integrity Management System

PNGRB NOTIFICTION for CGD IMS Schedule 6 Quality Control Plan Internal audits are conducted by the audit group nominated by Head of the Operations Team of the entity at least once in a year. Essential items will be focused for any internal and external audit – Baseline Plan is being updated and followed – qualifications of Operation and Maintenance personnel and contractors based on education qualification, formal training, demonstrated practical skills, and experience records – adequate documentation to support decisions made – Achievement of annual performance measures Pipeline Integrity Management System

PNGRB NOTIFICTION for CGD IMS Schedule 6 Quality Control Plan Essential items will be focused for any internal and external audit – written integrity management policy and program for all elements – written integrity management system procedures & task descriptions – responsible individual has been assigned for each task – all actions & non-conformances are closed in a timely manner – risk criteria used have been reviewed and documented – prevention, mitigation and repair criteria have been established, met and documented Pipeline Integrity Management System

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PNGRB NOTIFICTION for CGD IMS Schedule 7 Approval of Integrity Management System (IMS) A CGD networks Integrity Management System is a management plan in the form of a document that explains to operator’s employees, customers, regulatory authorities, etc., by stating – who is responsible for each aspect of the asset and its management – what policies and processes are in place to achieve targets and goals related to ensuring integrity of the assets – how they are planned for implementation – how Integrity Management System performance is measured – how the whole system is regularly reviewed and audited Pipeline Integrity Management System

PNGRB NOTIFICTION for CGD IMS Schedule 7 Approval of Integrity Management System (IMS) The document shall be agreed at Board level of the entity, constantly and systematically reviewed and updated, and all levels of management comply with its contents. Preparation of the document and approval steps – Step 1 - Prepared by In-house team or Consultant Step 2 - Checked by In-house team Head or Consultant head Step 3 - Provisional approval by Head of Operation team of entity Step 4 - Conformity of Integrity Management System document with the Regulation by Third Party Inspection Agency (TPIA) and duly approved by CEO or Full time Director of the Entity Pipeline Integrity Management System

PNGRB NOTIFICTION for CGD IMS Schedule 7 Preparation of the document and approval steps – Step 5 - Acceptance by Petroleum and Natural Gas Regulatory Board Step 6 - Approval of integrity management system document for implementation by the Board of the entity for the first time and approval of subsequent periodic review by CEO or Full time Director of the entity A certificate regarding the approval of integrity management system document duly approved shall be submitted to the Petroleum and Natural Gas Regulatory Board Pipeline Integrity Management System

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PNGRB NOTIFICTION for CGD IMS Schedule 8 Implementation Schedule of IMS Sr. No.

Activities

1

Compliance with Petroleum and Natural Gas Regulatory Board (Technical Standards and Specifications including Safety Standards for City or Local Natural Gas Distribution Networks) Regulations, 2008

YES/NO confirmation within 1 month from date of notification of the Petroleum and Natural Gas Regulatory Board (Integrity Management System for City or Local Natural Gas Distribution Networks) Regulations, 2013

Time Schedule

2

Preparation of Integrity Management System document and approval by Head of Operation team of the entity

1 year from date of notification of the Petroleum and Natural Gas Regulatory Board (Integrity Management System for City or Local Natural Gas Distribution Networks) Regulations, 2013

Pipeline Integrity Management System

PNGRB NOTIFICTION for CGD IMS Schedule 8 Implementation Schedule of IMS Sr. No.

Activities

Time Schedule

3

Conformity of Integrity Management System document with regulation by TPIA authorized by PNGRB

3 months from the approval by Head of Operation team of the entity

4

Submission of Integrity Management System document to PNGRBwith timelines for the actions

1 month from the conformity of Integrity Management System by TPIA

5

Approval by Petroleum and Natural Gas Regulatory Board for implementation by the entity

Within 3 months from submission of Integrity Management System document to PNGRB

6

Submission of Compliance Statement to Petroleum and Natural Gas Regulatory Board

Immediately after approval at Sr. No. 4 above

Pipeline Integrity Management System

PNGRB NOTIFICTION for CGD IMS Schedule 9 Review of The Integrity Management System Entities shall review their existing Integrity Management System every 3 years based upon – Revised Baseline data – Critical Inputs from various departments Review of Internal and External Audit – Internal Audit as per the checklist for CGD Networks provided by PNGRB shall be carried out by the CGD entity every year – External Audit (EA) by third party, approved by the Board, as per the methodology specified by the PNGRB once every 3 years Pipeline Integrity Management System

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PNGRB NOTIFICTION for CGD IMS Schedule 10 Adequacy of Manpower positioned at different stage of project Minimum Qualifications and experience for personnel involved in various CGD activities as per Appendix – III Design Stage – Construction Stage (Commissioning) – Facilities (erection, commissioning and O&M stage) – i.e. City Gate Station, Odorant stations, Pressure Reducing Station (PRS), Metering and Regulating Station (MRS) – Operation and Maintenance (gas network) –

Pipeline Integrity Management System

PNGRB NOTIFICTION for CGD IMS List of Critical Activities In CGD Network Sr. No. ActivitiesCritical infrastructure/ activity/ processes Time period for implementation 1

Cathodic Protection adequacy survey to ensure an integrated Cathodic Protection system

6 months for baseline survey

2

Odourant smell survey at farthest point (s) from odoriser

6 months

3

GIS mapping of the network

3 years

4

Establish system for testing of Compressed Natural Gas cascade

3 months

5

Gas Loss computation based on the mass or volume balance for 3 months or other selected interval depending upon the billing cycle.

6 months

6

Integrity inspection system for Galvanized Iron and copper piping forming part of tertiary network and the Last Mile Connectivity

6 months

Pipeline Integrity Management System

Pipeline Integrity Management System

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