GSPC Pipeline AIM Format

INTEGRITY MANAGEMENT MANUAL & INSPECTION REPORTING REQUIREMENTS

FOR

DEEN DAYAL FIELD OFFSHORE INSTALLATIONS

GUJARAT STATE PETROLEUM CORPORATION LTD

Doc Ref.: GSPC/AIMS/MAN/01

Gujarat State Petroleum Corporation Limited

GSPC/AIMS/MAN/01 REV NO. 0

ASSET INTEGRITY MANUAL & IRR DATE: 12/11/2013

The use of this Manual is mandatory as per the Asset Integrity Management Policy of the company.

Notes:

1. Revision numbers, starting in alphabetic letters indicate “Draft Issues “for Review /

comments. 2. Revision numbers, starting from „ Zero” in Numeric letters indicate “Issue for

implementation & revision number of subsequent revisions will go upwards like 1, 2, 3 etc., onwards.

3. Any change to this Manual requires a formal Management of Change in accordance with company procedure.

Revision Control Sheet

Revision No DESCRIPTION DATE

Approved by : George Mathew

Reviewed by Rajesh/P.Senthil Kumaran Rev-0 Issued for use. 12/11/2013 Rev- Draft A Manual draft issued for comments by GSPC 08/11/2013

Revision A Draft Manual prepared by ABS Industrial Verifications, issued for internal review. 25/10/2013

This document is confidential. No part of this document shall be duplicated or used, or disclosed for any other purpose with out prior permission from GSPC.




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Table of Contents

1 INTRODUCTION ............................................................................................................. 3 1.1 OBJECTIVE ............................................................................................................... 3 1.2 BASIS FOR THE INTEGRITY MANUAL .............................................................. 3

2 SCOPE OF THIS MANUAL ............................................................................................ 4

3 INTEGRITY MANAGEMENT SYSTEM DOCUMENTATION ................................ 4

4 INTEGRITY MANAGEMENT PROCESS .................................................................... 5

5 SAFETY CRITICAL ELEMENTS (SCE) ...................................................................... 6 5.1 SELECTION OF SCEs .............................................................................................. 6 5.2 INPSECTION MANAGEMENT PROGRAM & IRR ............................................ 11 5.3 SCE COMPONENTS & INTEGRITY PROGRAMS. ............................................ 12

6 INSPECTION MANUALS & REPORTING REQUIRMENTS (IRR). .................... 14

7 INTEGRITY MANAGEMENT PROGRAM IMPLIMENTATION. ........................ 14

8 INSPECTION DATA BASE MANAGEMENT. .......................................................... 16

9 MANAGEMENT OF CHANGE (MOC). ...................................................................... 16

10 INCIDENT INVESTIGATION, ANALYSIS AND REPORTING. ............................ 16

11 DE-COMMISSIONING. ................................................................................................. 17

12 ORGANISATION, ROLES AND RESPONSIBILITIES. ........................................... 18

13 THIRD PARTY CERTIFICATIONS AND FOLLOW UP AUDITS. ....................... 18

14 REFERENCE DOCUMENTS ........................................................................................ 18

15 ABBREVIATIONS: ........................................................................................................ 19

16 ANNEXURES .................................................................................................................. 19

• Annexure-I : Inspection Manual & IRR for Jacket Structures DDW1 & PLQP

• Annexure-II : Inspection Manual & IRR Deck structure & Topside facilities.

• Annexure-III : Inspection Manual & IRR for Pipelines.




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1 INTRODUCTION Gujarat State Petroleum Corporation Ltd. (GSPC), Gandhinagar, a Government of Gujarat Undertaking is the operator of the Deen Dayal Field, an offshore exploration block KG-OSN-2001/3 located on the East Coast of India. GSPC (Company) have discovered significant reserves of gas in the Deen Dayal West (DDW) area and accordingly installed an Early Production System (EPS) by setting up of Offshore Wellhead Platform at KG #8 (exploration well) located 15 KM offshore from Yanam-Kakinada Coast of Andhra Pradesh, India in 57 M water depth along with the Process Platform and multiphase pipeline to transport gas and condensate to the Onshore Gas Terminal (OGT) at Mallavaram, East Godavari, Andhra Pradesh for gas processing.

1.1 OBJECTIVE The objective of this Manual is to provide guidance for implementing an Integrity Management system to ensure that all assets from offshore to the onshore terminal are safely operated and maintained during its life cycle in a manner that the health, safety and environmental requirements are adequately met. In accordance with the Asset Integrity Policy, this manual is designed to support GSPC to implement a proactive inspection and maintenance management program prioritising the activities/ tasks on a risk based approach, maintaining integrity and preventing incidents that can harm the people, environment or property.

1.2 BASIS FOR THE INTEGRITY MANUAL This Manual is developed to meet the requirements of the following: (1) Company Integrity Management Policy and requirements. (2) Company HSE Management requirements. (3) Design Basis and various specification requirements. (4) GSPC Maintenance policy. (5) Regulatory requirements as per P&NG Rule 2008. P&NG Rule has set the following to be addressed in the inspection, maintenance programme by the operator for offshore facilities to ensure safety, health & environment related requirements are met during operation. Chapter-VI, Clause 27 (4).The operator shall establish monitoring parameters

within each areas of activity in order to monitor matters of significance to health, safety and environment, including the degree of achieving objectives.

Chapter-XVII, Clause 154, 155 & 156. The operator shall establish maintenance program for the facilities including machinery & equipment such




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that the fault modes which constitute a risk to health, safety or environment, shall be systematically prevented by means of a maintenance programme.

2 SCOPE OF THIS MANUAL

The scope of this Manual covers the following facilities installed in the Deen Dayal offshore field. 1. PLQP Process cum LQ Platform & DDW1 Well Head Platform that consists of

the following: a. Well Head, X-mas Tree, SSV, SSSV and accessories. b. Jacket, Risers and Appurtenance. c. Deck Structure including heli-deck. d. Topside facilities consists of:

i) Wellhead assemblies. ii) Hydrocarbon production & processing facilities. iii) Mechanical equipment, Cranes. iv) Electrical, Instrumentation and control system. v) Utility system. vi) Living quarters. vii) Flare system. viii) Personnel protection, escape and emergency system. ix) Fire & Gas detection, control and mitigation system. x) Passive Fire protection. xi) Process control & Emergency Shutdown system. xii) Emergency escape, evacuation facilities etc.

2. Pipeline system: Pipeline from offshore to Onshore = 2 nos.

a. Launchers and ESD Valves. b. Risers, SSIV. c. Subsea Pipeline section. d. Shore approach, Landfall and Onshore pipeline section. e. Receiver, ESD Valve etc. f. Emergency shutdown system.

3 INTEGRITY MANAGEMENT SYSTEM DOCUMENTATION Integrity Management system documentation has following the Hierarchy in documentation:

a. Asset Integrity Manual. b. Manual-Inspection Program & Reporting Requirements for:




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• Jackets and Risers. • Topside Facilities.

Process system (Equipment, piping, control system). Fire & Gas detection and control system. Emergency system, evacuation and rescue. Deck structure & Heli Pad, Crane etc.

• Pipeline system. c. Formats for Reporting

4 INTEGRITY MANAGEMENT PROCESS The Company philosophy is formulated to ensure the safe operation of the facilities for their designed life (or greater) with all the risks kept as low as reasonably practicable (ALARP). Integrity management process follows the “Plan Do Check Act (PDCA)” cycle to ensure that the desired integrity is achieved throughout the life cycle of the assets. The first step in the process is development of the integrity management program on a risk based approach, identifying all Safety Critical Elements (SCE) and developing suitable integrity management program consisting of inspection, monitoring & testing activities at appropriate intervals to ensure adequacy of their performance throughout the design life of the facility. The Integrity management program consists of:

• Maintenance Management program. • Corrosion Management program. • Inspection /Monitoring program.

These programs include applicable tasks and procedures, job plans and inspection reporting requirements (IRR) for surveillance, monitoring, preventive maintenance, inspection, and testing activities etc. Integrity management Plan (IM Plan) is developed by carrying out detailed assessment of the threats / damage mechanism and specifying the type of monitoring / inspection, required location of hotspots and assigning suitable monitoring intervals based on risk level of the safety critical element.




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5 SAFETY CRITICAL ELEMENTS (SCE) The company has established appropriate HSE and integrity management system which are implemented at stages of design, procurement, manufacturing and installation of the project. The company has identified potential major accidental hazard events (MAHE) and taken adequate mitigation and control measures to ensure that the HSE risk during the life of the installation are brought to as low as reasonably practical (ALARP). The company has carried out several safety studies such as Hazid, Hazop, QRA etc., at various stages of the project identifying major hazards and implementing necessary barriers for control of the hazards. Asset Integrity Management is focused on the Safety Critical Elements (SCE) that are responsible for the safe performance of the offshore facilities. Suitable integrity management program is developed by identifying potential threats and damage mechanism that can impact the SCE’s during its life cycle and relevant inspection reporting requirements (IRR). The integrity management programme comprises of activities for monitoring performance and technical condition, which will ensure that fault modes that are developing or have occurred are identified and corrected timely. The programme also contains activities for monitoring and control of failure mechanisms that may lead to such fault modes.

5.1 SELECTION OF SCEs Safety Critical Elements (SCEs) are those systems and components that provide a safety benefit or could result in an increase in risk upon failure. The Safety Critical Elements (SCEs) are defined as the safeguards that are capable of preventing, detecting, controlling and/or mitigating the effects of a Major Accident Hazard (MAH). SCEs are identified from the various Safety Assessments such as studies e.g. HAZID etc. SCE’s responsible for MAHs , and their risk level are evaluated based on a risk matrix. The following steps are adopted in the SCE determination process. Step 1 - Identifying Major Accident Major Accident Hazards (MAHs) are hazards that would initiate Major Accident and consequently lead to high risk level. It follows that the MAHs will fall within the unacceptable region of the Risk Matrix (see below) or be shown to lie in the tolerable region (yellow). In addition, for an event to be classified as a Major Accident, one of the following criteria must be met.




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• A fire, explosion or the release of a dangerous substance involving death or serious personnel injury to a person on the installation or who is engaged in an activity in connection with it.

• Any event involving major damage to the structure of the installation or plant affixed thereto or any loss in the stability of the installation.

• The collision of a helicopter with the installation. • Any other event arising from a work activity involving death of a single

person or serious injury to five or more persons on the installation or who is engaged in an activity in connection with it.

Step 2 - Determination of Causes Once the Major Accident Events are identified, their potential causes are to be established. An example would be overpressure. Other potential mechanisms or causes of failures are listed below:

• Degradation • Corrosion • Erosion • Fatigue • Overpressure / over temperature • External loading • Defective equipment • Human error.

Risk Matrix

1 2 3 4 5

Rating

Harm to People

Loss or Damage to Assets

Effect on the

Environment

Reputation

Unlikely Not heard

off

Has occurred

in the industry

Has occurred in our group

Has occurred in our group

Has occurre

d in this

facility

5 Multiple Fatalities

( >5)

Extensive damage

Massive effect

International

impact,

4 Major Major

damage

Major effect

National

impact,

3

Loss time/

Injury or Health

Local damage

Moderate effect

Considerable

impact

2 First Aid Injury

Minor damage

Minor or Localized

effect

Limited impact

1 Minor injury

Slight damage

Slight effect

Slight impact

HIGH RISK MEDIUM RISK LOW RISK




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Following SCE’s are identified for the PLQP, DDW1 and the pipelines.

Safety Critical Items

Functional role towards risk reduction. Scope MAJOR COMPONENTS

Management

Prevent failures by proactively managing integrity by implementing Standard operating procedures, training of personnel involved to control human errors, change management etc. to maintain Risk with in ALARP.

Jacket, Topsides Pipeline

Management of • Quality, safety, integrity

through SOPs; Trainings etc. • Change management. • Helicopter operations • Reviews, assessments &

continuous improvements.

Structure- Jacket

Prevention of failure due to loads and fatigue, extreme environmental loads, marine corrosion etc.

Jacket Jacket structure, Piles & foundations, Riser guards and supports.

Structure Deck

Prevention of failure due to loads and fatigue, extreme environmental loads.

Topsides Deck structure including helideck

Critical equipment, Valves, Pumps..

Prevent failure due to malfunctioning, deterioration etc.

Topsides Wellhead system, X-mas tree and SSV, SSSV, Pumps, compressors etc

Pipelines and Risers

Prevention of failure due to loads, extreme environmental loads, exceeding safe operating limits and other potential threats.

Pipeline Pipelines and risers including all fittings, coatings, supports and corrosion protection system.

Process Equipment, Vessels, Piping etc.

Prevention of failure due to loads, all kind of recognized potential threats and exceeding safe operating limits.

Topsides Hydrocarbon process equipment, Vessels, Vent Scrubber, Closed Drain Vessel, Exchanges, etc.

Chemical Injection System

Prevention of deterioration due to corrosion beyond design limits.

Topsides Chemical injection storage, Handling & injection facilities, control of injection rates, Injection system monitoring & control system etc.,




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Monitoring & control devices

Prevention of failure due to parameters exceeding safe operating limits.

Topsides

Monitoring & control devices input to DCS, Remote control panel (WHCP); Process control system (PCS)

Relief, Vent & Shutdown system

Control of emergency situations when parameters exceeding limits.

Topsides PSVs, SDVs, process control instruments, ESDVs, BDVs, Flare system

Fire and Gas Detection

Detection of gas leaks and fire. Topsides

F&G System, interface with Emergency and Process shutdown systems ESD, FSD.

Passive Fire Protection Mitigation of a fire event Topsides PFP at pipeline ESDVs etc.

Active Fire Protection Mitigation of a fire event Topsides

Fire water system, Fire extinguishers, Helideck firefighting system).

Hazardous Area Classification

Prevention fire in the event of hydrocarbon leaks by Control of Ignition.

Topsides All Electrical Equipment located in Hazardous area

Emergency Communications

Emergency Response in controlling a hazardous event.

Topsides Alarms, Safety critical communication system & Navigational Aids.

Emergency power & lighting

Ensure support to all critical equipment & system required for managing Emergency situation.

Topsides Diesel portable generator set Uninterruptible power supplies.

Evacuation, Muster, Escape & Rescue

Ensure safety of personnel in case of Emergency.

Topsides

Escapes routes, Emergency lighting including integral battery supply. Personal Safety Equipment & LSA;

Pedestal Crane Prevention of failures & damages due to dropped objects, collisions.

Topsides Pedestal crane- DDW1 & PLQP




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SCE Functional Role towards Risk Reduction Prevention approach to risk reduction minimizes exposure (likelihood) to the Major Accident Hazard. Examples are: Vessels designed in accordance to API & ASME codes; Pressure relieves are provided on vessels and designed in accordance with API RP 520; High pressure alarms are provided etc. Detection approach to risk reduction enables timely detection and transmitting information to control point to avoid the situation reaching a level breaching the limits and Major Accidents. Examples are: HC gas and flame detection system to be designed for early detection by Gas detectors suitable for the expected hazard as per API RP 14C requirement etc. Control approach to risk reduction minimizes/limits scale, intensity and duration of consequences from Major Accident. Examples are: Process control system which prevents the parameters not getting beyond safe operating envelope; Mitigation approach to risk reduction minimizes (i.e. limit and/: ESD system designed to initiate a shutdown in case there is breach of safe operation limits. Firefighting system designed to control the fire event and helps to maintain 1hour rating for the platform structure in withstanding the fire event.




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5.2 INPSECTION MANAGEMENT PROGRAM & IRR Critical functions, for which the SCE’s are responsible, are studied for failures in detail through a failure mode effect and criticality assessment (FMECA) and main cause of failures are identified. For each failure mode, the appropriate technical measures for the prevention, detection, control and mitigation of major accident events are determined relevant to the major accident hazards. Evaluation of the failure modes helps in development of relevant monitoring & inspection tasks/program and taking suitable corrective actions when required. The SCE’s are designed for safe performance during its life for the following aspects: Reliability: An item / system’s ability to operate and perform its intended

function under given conditions for a given time interval. Availability: a measure of the system’s ability (state of readiness) to

operate (perform a required function) at any given instant of time under given conditions.

Survivability: a system’s capability to withstand the effects of an incident prior to, and during, its operation (E.g.: fire, explosion etc.)

The inspection and monitoring programs are expected to confirm the ability of the SCEs and components to continue their functions as specified during the life cycle.




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5.3 SCE COMPONENTS & INTEGRITY PROGRAMS. Details of the SCE’s and their components and applicable programs are as following.

Safety Critical Items Major Components Integrity Management Programs

Management

Management of quality, safety, integrity through reviews, assessments for safety and SOPs for DDW1 & PLQP

HSE Management; Integrity Management (MMS, PIMS,WIMS), Standard Operating programs, Audit & Review, Competency management & Trainings.[ Refer respective Manuals / documents for program elements and implementation program ]

Structure- Jacket

Jacket structure, Piles & foundations, Riser guards and supports.

Detailed integrity management program & inspection reporting requirements ref: Manual for under water structures-IRR Annexure-I.

Structure Deck Deck structural including helideck

Detailed integrity management program & inspection reporting requirements ref: Manual for Deck & Topsides structures-IRR Annexure-II

Critical equipment, Valves, Pumps.

Wellhead system, X-mas tree and SSV, SSSV, Pumps, compressors etc

Integrity management program & inspection reporting requirements ref: Manual for Deck & Topsides structures-IRR Annexure-II

Pipelines and Risers

Pipelines and risers including all fittings, coatings, supports and corrosion protection system.

Integrity management program & inspection reporting requirements ref: Manual for Pipelines -IRR Annexure-III

Process Equipment, Vessels, Piping etc.

Hydrocarbon process equipment, Vessels, Vent Scrubber, Closed Drain Vessel, Exchanges, etc.

Program based on Risk Based Inspection (RBI) assessment to be developed and followed for pressure vessels & piping.

Chemical Injection System

Chemical injection storage, Handling & injection facilities control of injection rates, Injection system monitoring & control system etc.,

Program based on Risk Based Inspection (RBI) assessment to be developed and followed pressure vessels & piping.




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Monitoring & control devices

Monitoring & control devices input to DCS, Remote control panel (WHCP); instruments and control system for process system. APM


Relief, Vent & Shutdown system

PSVs, SDVs, process control instruments, ESDVs, BDVs, Flare system.


Fire and Gas Detection

F&G System, panels, associated logic in SCE listing, interface with Emergency and Process shutdown systems.

Passive Fire Protection PFP at pipeline ESDVs etc?

Active Fire Protection

Fire water system, Fire extinguishers, Helideck firefighting system).

Hazardous Area Classification

All Electrical Equipment located in Hazardous area

Emergency Communications

Alarms, Safety critical communication system & Navigational Aids.

Emergency power & lighting

Diesel portable generator set Uninterruptible power supplies.

Evacuation, Muster, Escape & Rescue

Escapes routes, Emergency lighting including integral battery supply. Personal Safety Equipment & LSA;

Pedestal Crane Pedestal crane- DDW1 & PLQP




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6 INSPECTION MANUALS & REPORTING REQUIRMENTS (IRR). Inspection maintenance program details for the facilities in Deen Dayal field is developed as Inspection Manuals (IRR) and attached to this document as below.

• Annexure-I : Inspection Manual & IRR for Jacket Structures DDW1 & PLQP.(A

• Annexure-II : Inspection Manual & IRR Deck structure & Topside facilities. • Annexure-II : Inspection Manual & IRR for Pipelines.

These documents includes the details on

• Inspection / maintenance tasks • Applicable components & locations for inspection / testing. • Inspection schedules/frequencies. • Guidance / methodology for inspection & maintenance tasks • Reporting requirements and formats,

7 INTEGRITY MANAGEMENT PROGRAM IMPLIMENTATION.

In the operation Phase, inspection, monitoring & testing activities are performed according the integrity management program / IRR. IN overall, the program shall cover following activities.

• Preparation of appropriate schedules. • Development of inspection/ monitoring work packs. • Performing inspections in accordance with the approved annual inspection

plan and inspection procedures. • Documenting the results & reports. • Data input to the database (if available). • Review / evaluation of findings and anomalies. • Review the anomaly acceptance criteria and make suitable

recommendations. • Review and approval of the findings and recommendations by the

authorised person. • Implementation of mitigation/ repairs or remedial works if required.




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• Revision of annual inspection plans based on inspection/ monitoring carried out.

The program implementation shall include following activities:-

• Perform inspections in accordance with the approved annual inspection plan and inspection procedures.

• Issue reports and create baseline data. • Assess the inspections, review findings and record anomalies. • Carry out repairs or remedial works. • Compile and issue report in accordance with the procedure on fitness of the

system. • Formal review of the Integrity Manual and update if required. • Review the anomaly acceptance criteria and change if required. • Produce revised annual inspection plans based upon the recently

performed risk assessments. • Produce inspection work packs. • Perform inspections. • Develop and recommend required mitigating or corrective actions as

necessary.

Planning & scheduling: The tasks identified for monitoring/ inspection / maintenance are grouped and included in monthly, semi-annual, annual programs etc for the ease of planning and execution of the activities, and follow up of the program.

Follow up reviews & assessment: Where inspections / monitoring shows results that is beyond acceptable limits, it shall be thoroughly investigated to find the root cause and make appropriate correction in the operation. It shall follow below steps.

• Investigate the problem. • Identify the root cause. • Recommend corrective or mitigating actions. • Re-visit the IM Plan/IRR and revise the inspection/ monitoring interval.




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8 INSPECTION DATA BASE MANAGEMENT. Maintenance and Inspection Management data shall be managed in such a manner that these are accessible as and when required. This database shall contain the asset register, design and operating data, inspection history etc. Appropriate data base shall be developed structuring the asset hierarchically and referring to the specification, data sheet and detailed drawing to help the implementation of IRR/IM Plan as well as to help in collection and collation of data for further use and updating during the operation phase.

9 MANAGEMENT OF CHANGE (MOC). All changes to the integrity organisation shall be in accordance with the approvals as per the Management of Change procedures by authorised personnel. It shall include:

• Changes to Asset components. • Changes to the organisation. • Changes in the program, plans and procedures. • Changes in the operating conditions. • Modifications & Repairs.

All changes shall be within the permissible boundaries of the operating and design envelope of the system. Any modification beyond these limits shall require re-validation of the system. 10 INCIDENT INVESTIGATION, ANALYSIS AND REPORTING. Incident Investigation and Reporting shall be considered most important aspect for maintenance of the integrity of the systems. All accidents, incidents and near misses shall be reported, investigated in accordance with HSE Management System. Additionally all integrity related incidents should be assessed and if necessary investigated for potential impact to health, safety and environmental damage.




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11 DE-COMMISSIONING.

DE-COMMISSIONING OF ASSETS / SYSTEMS. Systems and components shall be replaced when the integrity objectives can no longer be achieved. The replacement decision shall be made by the asset owner in consultation with the support group from concerned discipline of engineering, corrosion and materials engineering. The asset shall then be left in a safe condition and arrangements made to write it off. Some conditions for replacement are: • The asset / system can no longer be operated within the desired operating

envelope, e.g. required increase in capacity cannot be catered for or MAOP has to be derated.

• Projected operating expenditure is no longer economical, which shall include all anticipated repair costs, clean-up costs of spills and loss of income.

If a future need for the asset in-situ or the materials is foreseen, then the systems shall be mothballed in accordance with the Mothballing procedure. If no future use is foreseen, then the asset shall be removed from site with removal executed under asset ownership of the respective Business Unit and in accordance with the Decommissioning Procedures.




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12 ORGANISATION, ROLES AND RESPONSIBILITIES. Company have defined the Integrity management organisation for the Deen Dayal field operations, which is part of the Company Operation Manual.

13 THIRD PARTY CERTIFICATIONS AND FOLLOW UP AUDITS. The Deen Dayal field facilities are under third party certifications for fit for use, and the integrity management programs are under periodic audits and reviews to establish continued adequacy and compliance to regulatory requirements and for safe operations. Third party audits by the certifying agency shall be included in the Integrity management program and shall be implemented appropriately.

14 REFERENCE DOCUMENTS

• P&NG Rules 2008 • GSPC HSSE Philosophy • GSPC Offshore facilities HAZID and QRA Reports for DDW1 and PLQP. • Electrical Design Basis • Instrumentation Design Basis • Process Design Basis • Structure Design Basis ‘xx-xx. • Safety Study documents such as QRA, Hazid etc.




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15 ABBREVIATIONS: The following abbreviations are used in this document.

• AIMS Asset Integrity management System • ALARP As Low As Reasonably Practicable BU Business Unit • CMS Corrosion Management System • CP Cathodic Protection • ESDV Emergency Shutdown Valve • IMS Inspection Management System • IP Intelligent Pigging • MAOP Maximum Allowable Operating Pressure • MMS Maintenance Management System • PEMS Pressure Equipment Management System • PIMS Pipeline Integrity Management System • RBA Risk Based Assessment • RBI Risk Based Inspection • SCE Safety Critical Element • WIMS Well Integrity Management System

Definitions

Asset: In the context of this document an asset is the facility such as Platform, Pipelines etc.

Integrity: An asset has integrity if it operates as designed for its assigned life (or greater) with all its risks kept as low as reasonably practicable.

16 ANNEXURES

• Annexure-I : Inspection Manual & IRR for Jacket Structures DDW1 & PLQP.(A

• Annexure-II : Inspection Manual & IRR Deck structure & Topside facilities. • Annexure-III : Inspection Manual & IRR for Pipelines.


PIPELINE

FOR

DEEN DAYAL OFFSHORE INSTALLATIONS


DOC. REF: AIMS/PIPELINES/IRR-01

Gujarat State Petroleum Corporation Limited GSPC/AIMS/PL/IRR-01 Rev No.0

ASSET INTEGRITY MANUAL & IRR

DATE: 12/11/2013

ii


Notes:






Revision No DESCRIPTION DATE


Reviewed by : Rajesh Pillai Rev- 0 Issued for use. 12.11.2013 Rev – Draft A Manual draft issued for comments by GSPC. 08.11.2013

Revision A Prepared by ABS Industrial Verifications India.-issued for internal review 28.10.2013


Gujarat State Petroleum Corporation Limited GSPC/AIMS/PL/IRR-01 Rev No.0


DATE: 12/11/2013

iii

TABLE OF CONTENTS:

1 INTRODUCTION ......................................................................................................................... 4

2 PURPOSE ...................................................................................................................................... 4

3 SCOPE ............................................................................................................................................ 4

4 MANUAL CONTENTS ................................................................................................................ 4

5 SAFETY CRITICAL ELEMENTS (SCE) .................................................................................. 4 5.1 Safety Critical Items ................................................................................................................ 5

6 INSPECTION MANAGEMENT PROGRAM ........................................................................... 6 6.1 Risk Assessment & IM Planning ............................................................................................. 6 6.2 PIPELINE DATA .................................................................................................................... 9 6.3 Critical Components & Inspection Program: ........................................................................ 10

7 INSPECTION METHODOLOGY ............................................................................................ 14 7.1 General Survey (GVI) ........................................................................................................... 14 7.2 Requirments for CVI: ............................................................................................................ 14 7.3 Wall thickness measurements: .............................................................................................. 15 7.4 Weld inspections: .................................................................................................................. 15 7.5 Risers section below sea-level ............................................................................................... 15 7.6 Subsea Pipeline ...................................................................................................................... 15 7.7 Onshore pipelines .................................................................................................................. 16 7.8 Coating Health Survey .......................................................................................................... 17 7.9 Internal Corrosion Monitoring .............................................................................................. 17 7.10 Inspection of components ...................................................................................................... 18

8 INSPECTION REPORTING REQUIREMENTS: .................................................................. 19 8.1 Anomaly acceptance criteria & reporting ............................................................................. 19 8.2 Anomaly reporting ................................................................................................................ 20 8.3 Inspection Reports ................................................................................................................. 20

9 REVISIONS TO THIS MANUAL ............................................................................................. 20 9.1 Events initiating revisions ..................................................................................................... 20

10 REFERENCE DOCUMENTS .................................................................................................. 21

11 DEFINITIONS/ TERMINILOGY ............................................................................................. 21

12 ANNEXURE ................................................................................................................................ 21 Annexure-I reporting formats.

Gujarat State Petroleum Corporation Limited GSPC/AIMS/PL/IRR-01 REV NO. 0


DATE : 12/11/2013

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1 INTRODUCTION Gujarat State Petroleum Corporation Limited (GSPC) is the operator of the Deen Dayal Field (Block- KG-OSN/2001/03) situated at offshore from the Yanam-Kakinada coast of Andhra Pradesh, India.

This Inspection and Maintenance Management Manual is developed for the Subsea Pipeline, Risers, Riser Clamps, structural supports, onshore section of the pipeline including the shore approach, subsea isolation valves (SSIV), PLEMs, Launchers and receivers etc. installed in the Deen Dayal field, Linking offshore facilities of Process Platform (PLQP) and well head platform (DDW1) in the KG Basin to the onshore terminal..

This Manual describes the philosophy and the scope for the inspection and maintenance program, inspection frequencies, technical performance of inspection work and the requirements for inspection documentation.

This document shall be treated as a guide for implementing the inspection and maintenance program in compliance to various requirements.

2 PURPOSE The objective of this manual is to provide suitable guidelines and the frame work for maintaining the integrity of the Topside systems & processing facilities at the offshore platform facilities to facilitate effective management of the inspection and maintenance programs and demonstrate that the safety critical elements are capable, suitable and continue to function safely throughout the operation phase achieving the required level of integrity to assure safety and serviceability.

3 SCOPE The scope of this Manual covers the following pipeline facilities linking the Deen Dayal offshore field Platforms to the onshore that consists of the following:

• 20” Ø Multiphase (Sour Gas + Condensate) Pipeline from PLQP to OGT

• 10” Ø Effluent disposal pipeline form ETP to diffuser

4 MANUAL CONTENTS This Manual consists of the following:

a. Inspection program and reporting requirements. b. Reporting formats.

5 SAFETY CRITICAL ELEMENTS (SCE) The company has established appropriate HSE and integrity management system which are implemented at stages of design, procurement, manufacturing and installation of the project. Details on the process of selection of SCE’s are given in Section 5 of the Asset Integrity Manual. SCEs applicable for the Pipelines are given below.



DATE : 12/11/2013

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5.1 Safety Critical Items Pipeline system is identified as the main safety critical element (SCE) having following sub items.

No. Safety Critical Items Function Description Applicable Major

Components

1 Management Prevention

Management of safety & integrity through reviews, assessments , SOPs, Training etc. for Pipeline

system

HSE Management; Integrity Management

2 Pipeline Topsides Prevention Integrity of Pipeline Launcher and

ESD system. Detailed program ref:

section.

5 Pipeline Riser Prevention Riser, Clamps, splash zone

coatings, pipe line up to 20M from Jacket.

Detailed program ref: manual for underwater

structures.

5 Pipeline Offshore Prevention Pipeline system, CP system, weight

& anti-corrosion coatings, SSIV etc. Detailed program ref:

section.

5 Pipeline Onshore Prevention Pipeline, CP system, Receiver,

HIPPS System Detailed program ref:

section.



DATE : 12/11/2013

6

6 INSPECTION MANAGEMENT PROGRAM Integrity Management Program (IM Plan) is developed based on the DNV-RP-F116 "Integrity Management of Submarine Pipeline Systems" Risk Assessment of Pipeline System is performed by following process.

• The pipeline network is broken into pipeline systems • The pipeline system is separated into sections and components • Potential threats are identified for each section

Assessment is performed on the Pipeline System for the identified threats for each section. The Likelihood of Failure and Consequences of Failure are qualitatively assessed to determine the preliminary risk level.

• Component risk assessment is qualitatively performed for each component in the Pipeline System, based on detailed inspection data and technical documents.

• Hotspot assessment performs risk calculations for a given point registered in pipeline. • The condition of the whole pipeline system is assessed, based on the risk assessments

performed of the individual components. • The Results from the risk assessment are aggregated and presented in summary reports.

The evaluated risk is utilised to prepare detailed inspection plans. This also assists in optimising the inspection activities based on criteria of risk, and provide a program for integrity management during their remaining life.

6.1 Risk Assessment & IM Planning Risk assessment techniques Different risk assessment approaches can be used. The ASME B31.8S outlines four of them, which are the Subject Matter Experts, the Relative Assessment Models, the Scenario-Based Models and the Probabilistic Models. Common for all the models is an evaluation of the probability of an event and the consequences that this event will impose. The risk matrix shall be defined including annual PoF, CoF and risk categories. The matrix should preferably be defined by the operator and used across different assets. Work selection matrices should also be defined, e.g. recommended inspection intervals dependent on location in the risk matrix. Probability of failure assessment This recommended practice is primarily focused on structural integrity. Failure is caused by an event resulting in either of the following:

— loss of component or system function; or — Deterioration of functional capability to such an extent that the safety of the installation,

personnel or environment is significantly reduced. Consequence Assessment. Assessment of consequences of failure is to take the following into consideration:

— Safety (personnel) — Environment --- Economy



DATE : 12/11/2013

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Simple qualitative assessments is used using required detailing level depending on the objective of the actual risk assessment e.g. basis for inspection planning or assessment of a critical finding. A leveled approach is therefore recommended as detailed below. Each segment is assessed against applicable threats to arrive at a probability (PoF) and consequence (CoF) of failure factor. Segments are then ranked based on the PoF and LoF factors and plotted as a 5 X 5 Risk Matrix. The five PoF categories considered in the matrix are, insignificant, remote, in-frequent, occasional and frequent. CoF categories are minor, moderate, major, critical and catastrophic. A segment with HIGH risk ranking is examined for reasons of its high ranking and measures are taken to bring down the risk level. These measures may include an increase in frequency of existing inspection techniques, introducing a additional inspections etc. There are a variety of different systems in use for conducting risk assessments on pipelines. For this study all point scoring methodology as following is adopted. POINT SCORING Point scoring systems have been developed by a number of industry experts. These involve assigning points relating to different aspects of pipeline design, operation, history and environment. This system is based on ASME B 31.8 S. Detailed methodology adopted is as under.

o Pipeline failure and subsequent leakage are being caused mainly by external corrosion, internal

corrosion, pipe manufacturing defects, construction defects, operations mistakes, third party damages, equipment (component) failure, outside force.

o Based on the Statistical number of occurrence of leakage incidents in the industry as given in ‘PARLOC 2001’-the update of loss of containment data for offshore pipeline by - The Health and Safety Executive, The UK Offshore Operators Association and The Institute of Petroleum, a incident weight factor is arrived at for the analysis.

o High, medium and low categories of risk assessment due to external corrosion is based on life of the pipeline, size, wall thickness of the pipeline, operating stress, environmental /soil corrosivity characteristics, last date of assessment of hydro test, coating type, coating condition, cathodic protection monitoring, hydro statistic test inspection results, last inspection result, Risk factor values are assigned for high ,medium and low categories respectively 5, 2.5, and 1

o For Internal corrosion, assessment is based on life of the pipeline, size ,wall thickness of the pipeline, operating stress, MCI monitoring/bacteria culture, last date of assessment of hydro test, availability of corrosion monitoring methods, operating parameters for corrosive environment, expected flowing product analysis, implementation of periodical cleaning pigging policy, performance of corrosion inhibitor dosing, bactericide dosing, hydro test results,. Risk factor values are assigned for high ,medium and low categories respectively 5, 2.5, and 1

o For manufacturing defects, assessment is based on age of the pipeline, pipe material composition, age of pipe manufacturing process, operating pressure history, pipe seam type, and joint factor taken during design. Risk factor values are assigned for high ,medium and low categories respectively 5, 2.5, and 1

o For construction defects, assessment is based on selection of pipe material, existence of wrinkle or buckles, proper welding procedures, girth weld reinforcement, NDE information of



DATE : 12/11/2013

8

welds, hydro statistic test inspection results, operating pressure and cyclic loading history. Risk factor values are assigned for high, medium and low categories respectively 5, 2.5,and 1.

o For incorrect operations or mistakes, assessment is based on availability operating procedure review, audits of the operation, history of occurrence of failure due to incorrect operation. Risk factor values are assigned for high , medium and low categories respectively 5, 2.5, and 1.

o For failure of pipelines due to third party operations, assessment is based on method of laying, policy of evaluation before berthing vessel on anchor, existence of pipeline near to the port/ harbour, position of pipeline crossing of international navigational channel, consideration of trenching and burial in the laying stage, history of occurrence of failure in the past, availability of information with the port authorities regarding the existence of pipeline, ROU encroachment records by third parties. Risk factor values are assigned for high, medium and low categories respectively 5,2.5, and 1.

o For failure of pipelines due to equipment/ component, assessment is based on year of manufacture of equipment /component, failure/maintenance information regarding ESD/control valve/PLEM/SSIV/actuator of SSIV/riser/flange gasket, availability of procedure/policy/protocol for monitoring and maintenance. Risk factor values are assigned for high, medium and low categories respectively 5,2.5, and 1.

o For failure of pipelines due to Weather Related and Outside Force, assessment is based on pipeline age, pipe jointing method, Topography and Soil conditions, nearness to Earthquake Fault, Ground Acceleration, and consideration of external loading due to outside force and weather in the Stress Calculations in the design stage. Risk factor values are assigned for high, medium and low categories respectively 5,2.5, and 1.

o From the above consideration of risk probability information , for each considered segment risk probability score is computed and converted into Likely hood of failure ( in the scale of 1 to 5)

o Consequence damage due to failure of pipeline- Impact factor assessment is based on hazard nature of flowing product, flow rate, pipeline size, and distance between sectioning valves, accessibility & Emergency Response Preparedness, Shut down Response Time, nearness to environmentally sensitive areas, population density, and pollution. From the above consideration of impact factor information, for each considered segment consequence of failure score is computed and converted into the scale of 1 to 100.



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6.2 PIPELINE DATA

A. 20" Sour Gas + Condensate Pipeline (21.5 Kms Offshore and 3 Kms. Onshore) Design Pressure 161 Kg/Sq. cm (g)

Origin PLQP End OGT Design Life 30 years

Riser 28.6mm thk Pipeline 19.1mm thk Water Depth 58.1 M at PLQP 0 M at LFP

Topside components

Pig Launcher ESDV NRV

Riser Monel @Splash Zone

Riser Riser Clamps Bracelet anodes

Subsea Pipeline

SSIV- HPU [Ball valve] Hydrualic Umbilicals Lateral/Ball valves & relief valve on lateral

Sacrificial anodes

Onshore Pipeline IJ at LFP MOV 1901 at IVS

OGT

MOV 1902 at OGT (SIV) IJ at OGT MOV 1903 @ Pig Barrel Pig Barrel

B. 10" Effluent Disposal Pipeline (13.5 Kms offshore and 3 Kms. onshore) Design Pressure 20 Kg/Sq. cm (g)

Origin Effluent Treatment Plant (ETP) Onshore End Diffuser, Offshore

Design Life -- Pipeline thk. 12.7mm

Water Depth 0- 13 meter

Subsea Pipeline Diffuser

Sacrificial anodes

Onshore Pipeline

IJ at LFP Ball valve at IVS NRV at IVS ICCP System

OGT

IJ at OGT MOV 1101



DATE : 12/11/2013

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6.3 Critical Components & Inspection Program:

A. 20” Multiphase Pipeline (PLQP TO OGT) – Integrity Management (IM) Plan

Segment Identification

Ris

k Le

vel

Thre

ats

of C

once

rn

Insp

ectio

n/ m

onito

ring

Task

Rec

omm

ende

d In

spec

tion

Inte

rval

Rem

arks

From pig barrel

(Launcher)up to riser at splash zone

LOW

Internal Corrosion

Inline Inspection (ILI) 5 yearly OISD -139 Clause 5 UT survey-Pig Barrel, associated piping 3 yearly

Pigging for internal cleaning & residue analysis

Yearly OISD -139 Clause 4.3

External Corrosion General Survey 2 yearly Ultrasonic Wall thickness survey 2 yearly

Equipment Failure SDV inspection/Testing 6 months OISD -139 Clause 4.8

From Riser at splash zone to

SSIV

LOW

Internal Corrosion

Inline Inspection (ILI) 5 yearly OISD -139 Clause 5 UT survey at splash zone Yearly

Ultrasonic Wall thickness survey 5 yearly Diver/ ROV Survey



External Corrosion

Visual inspection Diver /ROV survey 5 yearly UT survey at splash zone Yearly

General visual inspection of monel sheeting at splash zone

Yearly

UT survey 3 yearly riser underwater segment CP monitoring 5 year OISD 139 Clause 4.5 Anode monitoring 3 yearly Diver survey

Mechanical Riser -Clamps & coating 5 yearly

Equipment Failure SSIV functional test 6 monthly OISD 138 Clause 4.8

SSIV Inspection 3 yearly

Third Party Damages

ROV survey 5 yearly ROV survey shall be performed after major construction activities.

SSIV to Land Fall Point M Internal Corrosion

Inline Inspection (ILI) 5 yearly OISD -139 Clause 5





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External Corrosion

Anode monitoring 3 yearly OISD -139 Clause 4.4

CP monitoring 5 yearly OISD 139 Clause 4.5

Visual inspection ( ROV/ROTV Survey) 5 yearly Diver survey

Weather Related & Outside Forces

( ROV/ROTV Survey)- free span monitoring 5 yearly

( ROV/ROTV Survey)- Lateral Displacement Survey / Pipeline exposure

5 yearly

Third Party Damages Monitoring against un authorized vessel entry

Continuous

Land Fall Point to pig barrel (Pig Receiver at

OGT)

M

Internal Corrosion

Inline Inspection (ILI) 5 yearly OISD -139 Clause 5 Pigging for internal cleaning & residue analysis


UT Survey -Pig Barrel & associated piping 3 years

External Corrosion

CP monitoring at all feed points Monthly

CP monitoring at all test station Quarterly

Coating health survey CAT / DCVG 5 yearly

Continuous potential logging (CPL) survey 5 yearly

Visual inspection Yearly Visual inspection at Road/ rail crossing Quarterly

Visual inspection at inter tidal zone

6 monthly

UT Survey, if exposed 2 yearly

Third Party Damages ROW & ROU survey; Pipeline marker, KM Post & signboard survey

Yearly

Equipment Failure

Isolation valve inspection /Testing

6 monthly

Functional test of Insulation joint Yearly

General Monitoring

1 Water Content, H2S & CO2 Crude quality monitoring Every shift At OGT

2 Corrosion Rate ER Probe On line At OGT , if available

3 Corrosion Rate Corrosion products analysis Every pigging

Pigging product analysis

4 Microbial Corrosion MIC/SRB Monthly At OGT



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5 Corrosion Inhibitor Efficiency Efficiency monitoring of

inhibitor & biocide

With product batch/ lot change.

Establish the optimised corrosion injection program.

6 Iron Count Check Iron count in free water 15 days



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B. 10” Effluent disposal Pipeline from ETP to Diffuser - Integrity Management (IM)

Plan

Segment Identification

SEG

MEN

TS N

o.

Thre

ats

of

Con

cern

Insp

ectio

n/

mon

itorin

g Ta

sk

Rec

omm

ende

d In

spec

tion

Inte

rval

Rem

arks

Effluent Treatment Plant ( ETP) to LFP

1

Internal Corrosion UT Survey 2 Yearly

Thickness measurement at selected critical locations. Examination of the corrosive components present in the service fluid. UT survey frequency shall be reviewed based results of two consecutive surveys.

External Corrosion

CP monitoring at all feed points Monthly

CP monitoring at all test station Quarterly

Coating health survey CAT / DCVG 5 yearly

Continuous potential logging (CPL) survey

5 yearly

Visual inspection Yearly Visual inspection at Road/ rail crossing Quarterly

Visual inspection at inter tidal zone 6 Monthly

Third Party Damages

Visual Inspection along pipeline route yearly

Equipment Failure

Isolation valve function Testing 6 Monthly

Functional test of Insulation joint Yearly

From LFP to Diffuser 2

Internal Corrosion UT Survey 5 Yearly

Frequency may be decided based on thickness results obtained for onshore segment

External Corrosion

Anode monitoring Once in 5 year

CP monitoring Once in 5 year OISD 139 Clause 4.5

Anode Monitoring 5 yearly Diver survey

Weather Related & Outside Forces

ROV/ ROTV survey - Free span 5 Yearly

ROV/ ROTV survey - Lateral Displacement / Pipeline exposure

5 Yearly

Third Party Damages

Monitoring against un authorized vessel entry

Continuous

Equipment Failure Cleaning of diffuser Yearly This frequency shall be reviewed

based on results of yearly cleaning.



DATE : 12/11/2013

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7 INSPECTION METHODOLOGY

7.1 General Survey (GVI)

Perform close visual inspection of the Riser & pipeline on topside, pig barrel, joints, supports and bends to detect,

• Signs of wall thickness loss • Pitting corrosion • Coating damages • Mechanical abrasion or dents/ deformation • Loose or damaged supports • Signs of leakages

Refer Appendix- 1, inspection report format for the respective item.

7.2 Requirments for CVI: Close Visual Inspection (CVI) is defined as a visual inspection close enough to be able to touch the component and clean it with a hand brush if necessary. CVI of components is not accessible on foot and requires the use of scaffolding. As per the GVI, signs of local failure and possible causes of failure shall be looked for during CVI.

CVI provides more detailed information than GVI and will detect smaller anomalies. CVI shall include the following activities:

o If the area inspected is wet it shall be dried using rags.

o If loose paint, scale or corrosive products are present it shall be cleaned off using a hand wire brush and/or a chipping hammer.

o If lighting is not sufficient to closely inspect the area a torch shall be used to light up the area.

o Visual inspections will be carried out in order to determine corrosion levels in structure; piping and critical equipment’s to identify the cause of corrosion.

o Visual inspection will be carried out for passive Fire Protection (PFP) in order to determine any damage.

o CVI shall reveal any anomalies that can be detected by visual observations. Operations outside the defined limits, change in physical appearance, and changes in locations, size, and condition of the item under observations can be detected. CVI also will give an understanding on the nature of damages, and the cause of such damages.

Refer Appendix- 1, inspection report format for the respective item.



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7.3 Wall thickness measurements:

Wall thickness measurements shall be made using digital Ultrasonic Testing (UT) equipment having valid calibration certificate.

If satisfactory readings cannot be obtained on heavily corroded or pitted surfaces then the surface should be fully cleaned and any loose coating, scale or other foreign deposits must be removed.

A detailed procedure for UT shall be provided by the NDT Contractor. Refer Appendix- 1, UTM-01 R0 for report format.

7.4 Weld inspections: Removal of well-adhered paint coat is discouraged, hence weld-inspection, as far as possible, shall be done using UT, that can be processed through coating instead of Magnetic Particle Inspection (MPI). The use of MPI requires paint removal, which increases the risk of external corrosion of the items inspected. However, if MPI is carried out for the detection of such items as surface defects of fillet welds and any other where UT is not considered feasible, appropriate paint-coat shall be immediately applied thereafter.

All surface flaw indications shall be confirmed by MPI after the removal of coating. The purpose of MPI is to identify surface weld defects, locate them and measure their length.

Detailed procedures for MPI, UT, etc. shall be provided by the inspection Agency.

7.5 Risers section below sea-level

Refer to section 7 of IRR Manual for under water structures for details. Refer Appendix- 1, RI-01 R0 , RClamp-01-R0 for report format.

7.6 Subsea Pipeline

Cathodic protection (CP) monitoring

Scope: Cathodic Potential measurements shall be carried out throughout the entire length of the pipeline to check if,

• Protection potential is within acceptable limits for steel

CP monitoring Methodology shall be established and approved prior to use. ROV/ ROTV Survey

Scope: Visual inspection using ROV or diver shall be combined with a side scan sonar survey on exposed pipelines to check,

• Route and location



DATE : 12/11/2013

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• Mechanical damage • Pipeline lateral movement • Debris • Free span locations and lengths • Kinks • Anchor scars and scouring • Seabed general conditions and features • Crossings and associated support locations • Rig spud can prints (if applicable) • Movements from previous known locations

Deliverables include scaled route drawings indicating water depth at 50-metre intervals and locations in easting and northing.

Remotely-operated vehicle (ROV) survey

Scope: Confirm free spans, damages, debris or other anomalies found by the Side Scan Sonar Survey.

Diver inspection

Scope: Diver survey shall be carried out only when required, in place of ROV Surveys to perform the following functions.

• Wall thickness measurements where corrosion is suspected. • Detailed inspection and NDT on selected locations of pipeline where removal of

marine growth or coating is required. • CP measurements where ROV cannot access.

Diver Inspection, when required shall be integrated with any Subsea Survey of Offshore Structures and Subsea Pipelines in the vicinity.

7.7 Onshore pipelines

Buried segment (Visual inspection) Scope: Visual Inspection is carried out to check pipeline for,

• Right of way • Route and location • Damage coating holidays (at accessible areas) • CP systems (transformer-rectifier) • wall thickness (at accessible areas)

Where pipelines are inaccessible, possible corrosion or damage may be assessed by monitoring the performance of the CP system or coating conditions.

Above ground / Exposed segment

Scope: Visual Inspection is carried out to check pipeline for,



DATE : 12/11/2013

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• Right of way and crossings • Pipeline marker, KM Post & signboard survey • Signs and extent of any corrosion • Mechanical damage • CP systems (transformer-rectifier) • Coating deterioration and damage • Supports • Extent of vegetation • Human Activities • Wall thickness at selected locations • Soil erosion, scouring and free spans at intertidal zone

Note: NDT shall be conducted where signs of corrosion or damage are present. Internal inspection shall be carried out in selected important accessible areas.

Refer report formats RoW-01-R0IJ-01-R0, CPcurrent-01-R0, PSP 01-R0, CJB-01-R0, TRper01-R0, Casing On-Off-01-R0, Inst On-Off-PSP at TLP -01-R0, given in Appendix 1.

7.8 Coating Health Survey Scope: Current Attenuation Survey, CAT is used to measure the overall condition of the coating on a pipeline based on the application of electromagnetic field propagation theory.

Data collected may include,

• Depth, • Coating resistance and conductance • Anomaly location, and anomaly type.

Direct-Current Voltage Gradient (DCVG) test is used to locate coating holidays and characterize corrosion activity by measuring,

• Change in electrical voltage gradient in the soil along and around a pipeline.

7.9 Internal Corrosion Monitoring

In Line Inspection

Scope: Intelligent Pigging tools, capable of measuring both internal and external damage are used to check,

• Diameter reductions • Corrosion / erosion features, both external and internal • Rate of corrosion • Pipeline integrity • Residual life

ILI methodology & procedure shall be established and approved shed prior to carrying out the inspection.



DATE : 12/11/2013

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Cleaning Pigging and Residue Analysis

Scope: To descale and clean the inside of pipeline and conduct pig residue examination to understand the condition of pipeline and decide subsequent pigging frequency.

Residue examination may provide,

• Evidence of microbial action • Iron count in water • Indicative corrosion rate

Note: Internal surface shall be monitored for corrosion and erosion by suitable methods such as probes, weight loss coupons, sampling, thickness gauging and monitoring fluid characteristics.

7.10 Inspection of components Inspection of Valves Scope: To check and confirm if the condition of the Valve and accessories is suitable for operation. Inspection shall check the following.

• Accessibility for operation • Condition of valve platforms • Hand wheels for manual operation • Remote/ buttons for auto • Lubrication, where applicable • Flanges and seals • Condition of motor and electric connections, where applicable • Integrity of umbilical and end connections

Function test of Valves Scope: To check and confirm if the Valve is maintained in good condition so that it is available for service, when required. Function test shall include the following.

• Shut down using auto and manual modes for ESDV • Operation of Hydraulic Power unit • Remote operation of SSIV • Manual operation of SSIV • Partial closure MOV using auto and manual modes.

Refer ESDV-01-R0, SSIV-01-R0, Appendix 1, for report formats



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8 INSPECTION REPORTING REQUIREMENTS: Urgent reports shall be generated for anomalies detected during the survey, as per the Anomaly table below. Report of the work shall be made on the completion of each activity as per the formats included in this manual.

8.1 Anomaly acceptance criteria & reporting All anomalies and their acceptance criteria for structure, piping and static equipment shall be as per this table.

ANOMALY REJECT CRITERIA REPORTING REQUIREMENTS Weld defects

Any cracks, incomplete or absent welds

o Record weld, position, extent and type of anomaly on drawing.

o If surface weld crack suspected, do MPI to investigate weld

o Take Photograph o Fill in anomaly datasheet.

Corrosion

Greater than 3 mm depth, on at least 15% of circumferential area for tubulars or surface area for beams.

o Measure area of corrosion, % cover in area, max. depth and diameter of pits, and average depth and diameter of pits.

o Record component, position and details on drawing.

o Take UT Wall Thickness reading on worst corroded area and take nominal WT next to corroded area.

o Photograph, stand off of area, close up of largest pit.

o Fill in anomaly datasheet, with sketch and details of UT readings.

Thickness

Less than 75 % nominal wall thickness (based on wall thickness of surrounding good material), covering at least 15 % of circumferential area or surface area

o Record component, position and details on drawing

o Take (additional) UT Wall Thickness readings to establish extent of anomalous area

o Photograph o Fill in anomaly datasheet, with sketch and

details of UT readings. Physical damages

Any major damage due to physical impact / overload or relative movement, leading to rupture or severance

o Dimension damage. o Record component, position and details

on drawing. o Take close-up and stand-off photography. o Cordon/barrier off affected areas.

Vibrations

Any prolonged vibration. o Notice severity, frequency and effect (amount of deflection).

o Identify reason or source. o Record affected components and details

of vibration on drawing.



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Degradation of coatings/ rusting Damage to paintings

Rusting to the extent of 15 to 20% of surface rusted

o Record component, position, description of damage and area size in m2 on drawing.

o Photograph damage.

Lack of Integrity

Any insecure, loose, misaligned or broken components that can lead to accident. Example: o Loose handrail o Loose grating (without clips) o Grating too small o Missing grating o Hazardous debris which may

fall and hit someone o grating installed the wrong

way o protruding steel

o Record component, position and describe on drawing.

o Reinstate if possible (e.g. loose bolts), and note on drawing action taken.

o Take close-up and stand-off photographs if not reinstated.

8.2 Anomaly reporting Reporting shall be as per attached format in Appendix.

8.3 Inspection Reports To demonstrate that the safety critical system and the components are suitable and continue to meet their performance requirements, inspection /monitoring records shall be maintained. Such records must be retained for the life of the installation, and shall be covered under a suitable Data Management system and kept updated.

The Certification Agency (CA) shall verify and confirm periodically by audit and witnessing compliance to the recommended inspection monitoring program. The inspection reports along with the CA recommendations shall be maintained and followed up. The reports shall also contain information on the scope and extent of the examination undertaken, and clearly identify the equipment verified. Formats appended to this document shall be used for reporting.

9 REVISIONS TO THIS MANUAL

9.1 Events initiating revisions

This manual may require changes that are triggered by events such as:

• Physical changes to installation (e.g. modifications, additions). • Damage / incidents. • Change in record-keeping systems. • Results feed-back from completed verification activities. • Results of any safety assessments. • Out-come of any studies/ analyses, etc. carried out.



DATE : 12/11/2013

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Updates may also be initiated based on: • the results from inspection, monitoring and testing activities • the results from any integrity assessment • changes in operating parameters or any other changes that may affect the total threat picture, or • if any changes occur in the authority requirements or in any other premises and assumptions for the period in question.

10 REFERENCE DOCUMENTS ASME B 31.4 ASME B 31.8 ASME B 31.8 S ASME B 31 G P & NG Regulations OISD Standards & Guidelines 138 and 139

11 DEFINITIONS/ TERMINILOGY

ABBREVIATION/TERM MEANING CVI Close Visual Inspection, defined as being close enough to be

able to touch the component and clean it with a hand brush, if necessary. CVI of components not accessible on foot requires abseiling, or the use of scaffolding

GVI General Visual Inspection, without need to clean, prepares a site, or arranges special access. If normal access is not available, GVI is done from a distance, with the help of binoculars.

MPI Magnetic Particle Inspection N/A Not applicable NDT Non-Destructive testing UT Ultrasonic Testing

12 ANNEXURE • Reporting formats.

INSPECTION REPORTING FORMATS

for

PIPELINES

DEEN DAYAL OFFSHORE FIELD

GUJARAT STATE PETROLEUM CORPORATION LIMITED

DOC. REF: AIMS/PIPELINE/IRR-01

GUJARAT STATE PETROLEUM CORPORATION LTD.

Report No: ……………………………………….. Date of previous inspection. : ………………Date of report:…………………………………

Platform name : ………………………………… Service Fluid : ……………………………….Pipeline Size & Designation : …………………………Inspection contractor: …………………………..……………………………………………………………Inspected by: …………………………………Drawing No.:……………………………………………………….

1 2 3 4

Top Bottom Top Bottom Top Bottom

Sketch:

Comments:

9 O'clock

Location Clamp No. & Type Clamp No. & TypeClamp No. & Type

Clamp Clearance

RISER CLAMP MONITORING

3 O'clock6 O'clock

12 O'clock

CP values at Riser Clamp (-ve)Riser Clamp Tag No: Remark

Visual Inspection Clamp No. & Type Visual inspection of clamp Visual inspection of welds



Platform name : ………………………………… Pipeline thickness: …………………………….Pipeline size & Designation : ……… Service fluid : ……………………………….……………………….………………………Drawing No.:…………………………………… UT contractor:……………………………………

Equipment Make & Serial No: Type of Probe:Frequency: Couplant:Size: Calibration:

12 O'clock 3 O'clock 6 O'clock 9 O'clockUT 01UT 02UT 03UT 04UT 05UT 06UT 07UT 08UT 09UT 10

Sketch:

General Survey, Visual Inspection Observations

Comments

Notes:

UT THICKNESS MEASUREMENT

UT equipment Details :

From ToDetails of section where UT is carried out

UT Location:

Location on pipeline Remarks:

1. For all pipeline, thickness measurement to be carried out as per above figures.2. All UT locations shall be permanently marked for evaluation of corrosion rates.3. Thickness measurement to be carried out at 100 mm grid pattern



Platform name : ………………………………… Pipeline thickness: …………………………….Pipeline size & Designation : …………………………Service fluid: ……………………………….

Riser From: ………………To: …………………….Drawing No.: Inspection Contractor:…………………………

Design Thickness

Available thickness (Range)

Overall Riser

condition

Clamp Type &

condition

Coating type &

condition

Damage / Corrosion

Weld Joint condition Remark

Sketch:

Observations

Comments

RISER INSPECTION


Report No: ……………………………………….. Last Date of inspection: ………………………Date of report:…………………………………

Service fluid:………………………………... Pipeline size /designation : ……………………… Pipeline thickness: ……………………………. Pipeline ID : …………………………………Drawing no: ……………………………………..

Position ( Verticle / Horizontal): …………………………………………………………………………..Visual Inspection: …………………………………………………………………………………………..Relief Valve : …………………………………………………………………………………………………Pressure Gauge: ……………………………………………………………………………………………Vent Connection: ……………………………………………………………………………………………Drain Connection: ……………………………………………………………………………………………Closure: ………...……………………………………………………………………………………………Pure Connectors: ……………………………………………………………………………………………Pig Indicators: ……………………………………………………………………………………………….Main Line Valve: …………………………………………………………………………………………….Kicker Valve: …………………………………………………………………………………………………Barrel ( Internal): …………………………………………………………………………………………….

Remarks: …………………………………………………………………………………………………………………………………………………………………………………………………………………………………………………………………………………………………………………………………………………………………………………………………………………………………………….

BARREL INSPECTION RECORD


Report No: ……………………………………….. Date of previous inspection : ………………Date of report:…………………………………

Platform name : ………………………………………… Service fluid: ……………………..Pipeline size & designation : ……………………………. Acceptance standard / Verification documents: ………………………...………………………………………….. Inspection Contractor: ………………………………………….P&ID /Drawing no.: ……………………… Inspected by: …………………………………………………………..

Ope

n

( 0

- 10

0 %

)C

lose

( 0 -

100

%)

Ope

n

( 0

- 10

0 %

)C

lose

( 0 -

100

%)

Ope

n

( 0

- 10

0 %

)C

lose

( 0 -

100

%)

Ope

n

( 0

- 10

0 %

)C

lose

( 0 -

100

%)

Ope

n

( 0

- 10

0 %

)C

lose

( 0 -

100

%)

Yes

No

Turn

ing

angl

e

Com

plet

enes

s of

Ope

ratio

n

Seal

ant

Inje

ctio

n

ESDV MONITORINGSi

ze

Oil

Leve

l

Oil/

Gas

leak

age

if an

y

Thro

ugh

SCAD

A (R

emot

e m

ode)

Loca

tion

Appr

oach

Det

ails

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Voltage (V) Current (A) Voltage (V) Current (A)

Type of reading

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PIPE TO SOIL POTENTIAL (P.S.P) MONITORING

TLP No

Type of TLP Remark

Other ReadingPSP (V)Location Chainage

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1 Report No: ……………………………………….. Pipeline size/ Designation : …………………………….2 Date of report:………………………………… Service fluid: …….………………………………………3 4567

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11Sector Name Chainage Jan Feb March April May June July Aug Sept Oct Nov Dec

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GUJARAT STATE PETROLEUM CORPORATION LTD.ROW SURVEY



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UNDERWATER INSTALLATIONS

FOR

DEEN DAYAL OFFSHORE INSTALLATIONS


DOC. REF: AIMS/UW/IRR-01

Gujarat State Petroleum Corporation Limited GSPC/AIMS/UW/IRR-01 Rev No.0

INSPECTION REPORTING REQUIRMENTS

DATE: 12/11/2013

ii


Notes:







Revision No. DESCRIPTION DATE


Reviewed by : Stephen Pinto Rev-0 Issued for use 12/11/2013

Rev- Draft A Manual draft issued for comments by GSPC 08/11/2013

Revision A Manual prepared by ABS Industrial Verifications, issued for internal review. 25/10/2013

This document is confidential. No part of this document shall be duplicated or used, or disclosed for any other purpose without prior permission of GSPC.



DATE: 12/11/2013

iii

TABLE OF CONTENTS:

1. INTRODUCTION .............................................................................................................................. 5

2. PURPOSE ......................................................................................................................................... 5

3. SCOPE ............................................................................................................................................... 5

4. MANUAL CONTENTS ..................................................................................................................... 5

5. SAFETY CRITICAL ELEMENTS (SCE) ....................................................................................... 6 5.1 Safety Critical Elements........................................................................................................ 6

6. INSPECTION MANAGEMENT PROGRAM ................................................................................ 7 6.1 Inspection Program ............................................................................................................... 7 6.1.1 SCE Components & Inspection Program - PLQP ...................................................... 7 6.1.2 SCE Components & Inspection Program-DDW1 ....................................................... 8

7. INSPECTION METHODOLOGY .................................................................................................. 10 7.1 As-Built Survey ..................................................................................................................... 10 7.2 Spider Deck .......................................................................................................................... 10 7.3 Splash-Zone ......................................................................................................................... 11 7.4 Monitoring the corrosion trends ......................................................................................... 11 7.5 Marine Growth Survey ........................................................................................................ 12 7.6 Marine Growth Removal ..................................................................................................... 12 7.7 Debris Survey/Removal ...................................................................................................... 12 7.8 Monitoring Scour / Mud mats ............................................................................................. 13 7.9 Exposed Piles ....................................................................................................................... 13 7.10 Conductor / Conductor Guides .......................................................................................... 14 7.11 Cathodic Protection Survey................................................................................................ 14 7.12 Visual Weld Inspections...................................................................................................... 15 7.13 Critical weld Inspections [Type II & III] ............................................................................. 16 7.14 Riser Inspection ................................................................................................................... 17 7.15 Pipeline Inspections ............................................................................................................ 20 7.16 Appurtenances ..................................................................................................................... 20 7.17 Damages ............................................................................................................................... 21 7.18 Flooded Member Detection ................................................................................................ 22 7.19 Suggested Remedial works ............................................................................................... 22

8. SELECTION OF DIVING AGENCY ............................................................................................ 25

9. INSPECTION JOB PACKS .......................................................................................................... 28

10. INSPECTION REPORTING REQUIREMENTS ........................................................................ 29 10.1 Anomaly acceptance criteria & reporting ......................................................................... 29 10.2 Anomaly reporting................................................................................................................ 32 10.3 Inspection Reports ............................................................................................................... 32

11. REVISIONS TO THIS MANUAL .................................................................................................. 32



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11.1 Events initiating revisions ................................................................................................... 32

12. REFERENCE DOCUMENTS ...................................................................................................... 33

13. DEFINITIONS/ TERMINILOGY ................................................................................................. 34

14. ANNEXURES .................................................................................................................................. 34

• Annexure-A: Recommended schedules for Inspection & Maintenance of Jacket structures

• Annexure-B: Reporting formats.

Gujarat State Petroleum Corporation Limited GSPC/AIMS/TOP/IRR-01 Rev No.0


DATE: 12/11/2013

5

1. INTRODUCTION Gujarat State Petroleum Corporation Limited (GSPC) is the operator of the Deen Dayal Field (Block- KG-OSN/2001/03) situated at offshore from the Yanam-Kakinada coast of Andhra Pradesh, India.

This Inspection and Maintenance Management Manual is developed for the underwater structures viz. Jacket, Risers, Riser Clamps, Piles, Conductors, Barge Bumpers, and other structural appurtenances etc. installed for offshore facilities of Process Platform (PLQP) and well head platform (DDW1) in the KG Basin.

This Manual describes the philosophy and the scope for the inspection and maintenance program, inspection frequencies, technical performance of inspection work and the requirements for inspection documentation.

This document shall be treated as a guide for implementing the inspection and maintenance program in compliance to various requirements.

2. PURPOSE The objective of this manual is to provide suitable guidelines and the frame work for maintaining the integrity of the Topside systems & processing facilities at the offshore platform facilities to facilitate effective management of the inspection and maintenance programs and demonstrate that the safety critical elements are capable, suitable and continue to function safely throughout the operation phase achieving the required level of integrity to assure safety and serviceability.

3. SCOPE The scope of this Manual covers the following facilities installed in the Deen Dayal offshore field: PLQP Process cum LQ Platform & DDW1 Well Head Platform that consists of the following: a. Jacket Structure. b. Risers and Riser Clamps. c. Appurtenances.

4. MANUAL CONTENTS This Manual consists of the following: a. Inspection program and reporting requirements. b. Reporting formats.



DATE: 12/11/2013

6

5. SAFETY CRITICAL ELEMENTS (SCE) The company has established appropriate HSE and integrity management system which are implemented at stages of design, procurement, manufacturing and installation of the project. Details on the process of selection of SCE’s are given in Section 5 of the Asset Integrity Manual. SCEs applicable for the underwater structures are given below.

5.1 Safety Critical Elements

No. Safety Critical Element

Function Description Applicable Components

1 Management Prevention

Management systems Prevent failures by proactively managing integrity by implementing Standard operating procedures, training of personnel involved to control human errors, change management etc. to maintain Risk within ALARP.

• HSE management • Operation

Management • Integrity

Management. • SOPs, etc

2 Structure Jacket Prevention

Integrity of Jacket, supporting the Platform Topsides. Prevention of failure due to loads and fatigue, extreme environmental loads, marine corrosion etc.

Jacket structure, Piles & foundations, Riser guards and supports.



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6. INSPECTION MANAGEMENT PROGRAM Critical functions, for which the SCEs are responsible, are studied for failures in detail through a failure mode effect and criticality assessment (FMECA) and the main causes of failures are identified. For each failure mode, the appropriate technical measures for the prevention, detection, control and mitigation of major accident events are determined that are relevant to the major accident hazards. Evaluation of the failure modes helps in development of relevant monitoring & inspection tasks/program and taking suitable corrective actions when required.

The inspection and monitoring programs are expected to confirm the ability of the SCEs and components to continue their functions as specified during the life cycle.

6.1 Inspection Program

Details of the SCEs and their components and applicable programs are as follows:

6.1.1 SCE Components & Inspection Program - PLQP

S. No. Component Failure Causes Risk

Category Inspection/ maintenance task. Frequency

Reference

1 Jacket Primary

members

Overload due to static, problems related to the environment, over-stressing critical joints etc.

H

Critical joints identified from analysis reports, monitored through CVI & NDT.

Once in 5 years P&NG Rule-30 Max- 5

years

Load due to excess marine growth.

H

Maintain marine growth within the design thickness limits.

Survey 1st & 2nd year, thereafter twice in 5 years

OISD

Failure due to Fatigue loads and developing cracks.

H Critical joints identified from analysis reports, monitored through CVI & NDT.

Once in 5 years

Certification Primary members affected by external impacts causing dents and damages.

H

Condition survey- GVI. If severe such as holes, etc. analysis would be required.

Condition based.

2 Anodes Corrosion leading to loss of thickness and failure of members.

M

CP level & Wall-thickness monitoring.

Survey 1st & 2nd year, thereafter once in 5 years

OISD / Certification

3 Splash Zone Marine Corrosion. L

Wall thickness, CP monitoring Twice in 5 years

4 Flooded member

Internal corrosion and failure of members.

L

Visual survey & NDT if required.

Conditional, in case any holes or cracks noticed.

5

Spider Deck &

appurtenances

Accelerated corrosion due to sea water splashing. Coating damages.

L

GVI. UT Wall-thickness monitoring paint condition.

Annual –GVI. Others conditional.

6 Riser & supports.

Support clamp damages & increase in load to supporting members, riser failure.

H GVI. Twice in 5 years.

Corrosion due to splash zone coating failure /

M

CVI. CP & UT Wall-thickness 5 yearly.



DATE: 12/11/2013

8

external damages. monitoring.

7 Pipeline Pipeline free span / un supported sections.

M Visual survey


8 Piles Exposed piles. M Visual surveys


10 Conductors

Failure of guide support members due to conductor movements when guides missing.

L Visual surveys Twice in 5 years.

6.1.2 SCE Components & Inspection Program-DDW1

S. No. Component Failure Causes Risk Category

Inspection/ maintenance task. Frequency

Reference

1 Jacket Primary

members

Overload due to static, problems related to the environment, over-stressing critical joints etc.

M


Once in 5 years P&NG Rule-30 max- 5

years

Load due to excess marine growth.

M

Maintain marine growth within the design thickness limits.

Survey 1st & 2nd year, thereafter twice in 5 years

OISD

Failure due to Fatigue loads and developing cracks.

M


Once in 5 years

Certification

Primary members affected by external Impacts causing dents and damages.

M

Condition survey- GVI. If severe such as holes, etc. analysis would be required.

Condition based.

2 Anodes Marine corrosion leading to loss of thickness and failure of members.

M

CP level & Wall-thickness monitoring.


OISD / Certification

3 Splash Zone Marine Corrosion. L

Wall thickness monitoring CP monitoring.

Twice in 5 years

4 Flooded member

Internal corrosion and failure of members.

L

Visual survey & NDT if required.

Conditional in case any holes or cracks noticed.

5 Spider Deck & appurtenance

s

Accelerated corrosion due to sea water splashing. Coating damages.

L

GVI. UT Wall-thickness monitoring paint condition.

Annual –GVI. Others conditional

6 Riser & supports.

Support clamp damages & increase in load to supporting members, riser failure.

L

GVI. Twice in 5 years.

Corrosion due to splash zone coating failure / external damages.

M

CVI. CP & UT Wall-thickness monitoring.

5 yearly.

7 Pipeline Pipeline free span / un supported sections.

M Visual survey Survey 1st & 2nd

year, thereafter



DATE: 12/11/2013

9

once in 5 years

8 Piles Exposed piles. M Visual surveys


10 Conductors

Failure of guide support members due to conductor movements when guides missing.

L Visual surveys Twice in 5 years

Note: The inspection frequencies specified above are based on OISD guidelines, current international practices and best industry practices. These shall be updated with more detailed engineering analysis based on RBI assessments or advanced structural analyses in future.



DATE: 12/11/2013

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7. INSPECTION METHODOLOGY Inspection of jackets shall cover the items from (+) 2 m above the spider deck level down up to 30 meters away from riser/pipeline weld or flanged joint at sea-bed level, and includes:

• The leg/pile transitions. • The jacket structure including mud mats. • Pipeline up to 30 m from riser/pipeline flanged joint. • Appurtenances such as:

o Boat Landing. o Barge Bumpers. o Boat Fenders etc.

• Conductor & guide supports. • Riser and Riser supports.

7.1 As-Built Survey As-built survey is carried out to confirm that the Jacket installation confirms to the as-built drawings. Verify the presence, integrity and arrangement of all legs, bracings, skirt piles, conductors, conductor frames, sumps, pump caissons, anodes and miscellaneous attachments. Any variations from the AS-BUILT drawings are to be highlighted. If additional members are to be observed, measure the diameter and wall thickness and take adequate metrology along with a suitable sketch. Reporting requirements: Report any deviations with respect to structural members and number of anodes if it is not matching with the drawings.

7.2 Spider Deck Visually inspect the following for degradations due to marine corrosion, coating damages, external damages etc.

• Hand-rails.; Gratings. • Spider Deck tubular members. • Leg/pile weld joints [‘castellated weld joint’]. • Conductor guides. • Sump/pump caissons. • Any other miscellaneous piping and attachments.

Visually inspect the condition of the above- water structural members at the splash zone area. Take photographs of any defects/anomalies found.



DATE: 12/11/2013

11

Reporting requirements:

• Photographs. • Damage/ Anomaly reports.

7.3 Splash-Zone The splash zone area will be as defined in the applicable drawings and/or Scope of Work and/or Job-Pack.

• Carry out a detailed splash zone coating inspection [type, extent, damage, etc.] on all surface breaking structural members [Legs and vertical diagonal members (VDM)] close to the mean sea level as the sea conditions permit. • Take one (1) wall thickness measurement if submerged and • One (1) CP measurement on the parent metal [without damaging the coating, if

any] of each leg and main member. In case of degradations, corrosion damages or any other anomalies noticed, carry out detailed visual inspections (DVI) followed by NDT. More readings will be required in case of any anomaly. It shall be reported with photographs and inspection details. Reporting requirements

• Photographs. • Damage/ Anomaly reports. • Wall thickness survey reports.

7.4 Monitoring the corrosion trends To monitor corrosion and Marine growth over a period of time, subject one weather-side leg to additional inspection as follows:

• Remove a vertical strip of marine growth approximately 100mm wide from the top of the zone of fouling, down to EL (-) 3m. or the lowest tide level, whichever is deeper.

• In the presence of well bonded, uniform epoxy or paint coating, the coating shall not be removed. In such cases the presence of coating shall be highlighted in the final report.

• Visually inspect the cleaned strip and report any corrosion or damage.

Reporting requirements Wall thickness survey reports

• Commencing at EL (+) 6m or 2m above spider deck level, (whichever is higher, and finishing at the bottom of the cleaned strip) take wall thickness readings at the following locations: o At 0.5m intervals down the leg. o In all areas of corrosion where loss of wall thickness is apparent. In the

case of pitting, pit-depths shall be measured with an approved instrument.



DATE: 12/11/2013

12

o At any locations specifically requested by the Client and/or Third Party Inspection/ Certification agency.

7.5 Marine Growth Survey

Select member identified for thickness survey and carry out similar measurements on the Marine growth.

• Weather-side Leg: o Take measurement at 5 meter intervals down the leg from the sea level to

elevation (-) 40 meters inclusive & thereafter at 10 meter intervals down the leg from EL (-) 50 meter to the seabed.

o Take the above measurement either through a circumferential reading or depth gauge.

o Briefly describe the species composition of the fouling at each level. • All members:

o Make a general visual assessment of the extent of marine fouling on all braces. This may be carried out as a part of the AS-BUILT survey.

o Estimate the average thickness of 'firm' marine growth on each member. o Estimate the maximum thickness of 'firm' marine growth on each member.

• Anodes: o Estimate the thickness of marine growth on each anode.

Reporting requirements

• Photographs. • Marine Growth thick ness readings.

7.6 Marine Growth Removal Remove all marine growth off all members, bracings, risers, conductors, clamps, Anodes etc.

7.7 Debris Survey/Removal Debris is materials lying in and around the Jacket, which can interfere with the CP of the Jacket.

• Carry out a full debris survey of the structure and the surrounding seabed out to 10 meters from the structure, on all risers and out to 20meters from the tube-turn along all the pipelines.

• Remove all debris from the jacket, riser, pipelines, (out to 20meter) where possible without the aid of rigging or tuggers etc.

• Wherever an item of debris which is in contact with a part of the jacket / risers / pipelines is removed, the under lying area is to be inspected for signs of damage and/or corrosion. o DVI & NDT is to be carried out for any damage found.



DATE: 12/11/2013

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• Report the location and description of all the major items of debris on the jacket / risers / pipelines which could not be removed.

7.8 Monitoring Scour / Mud mats Visually inspect the condition of the mud mats and report during the base line survey. During subsequent surveys, this shall be limited to a visual survey and CP monitoring. Reporting requirements

• Measure the profile of the seabed relative to the bottom level horizontal bracings, and record the water depth during the Base line survey.

• Four equi-spaced (90 degree apart) intervals around all main legs and skirt piles. • The node and further at 2 meter intervals along all major (leg or leg /skirt pile)

bracings out to four meter from the nearest leg / skirt pile. • In case of scouring, measure the water-depth at 2.0m intervals along the seabed

out to 4 meters from the structure. • If the member is buried, measure the depth of burial from the seabed to the top

of the members or indicate the percentage burial depth. If the member is partially-buried report the percentage burial.

• Measure the profile of the seabed relative to all pipelines at 2m intervals along the pipeline out to 20 meters from the tube turn or the end of any unsupported suspension.

• In the case of bracing/ pipelines unsupported at seabed, the measurement is to be taken with reference to the bottom of the member to the seabed at the locations indicated in fig. 2.1 and 5.5.81.

7.9 Exposed Piles Monitoring is limited to exposure and CP readings. Reporting requirements

• Note the presence of any exposed piles at the seabed and measure the length of the pile visible at 4 equi-spaced points around it (i.e. 90 degrees apart).

• Take one Cathodic potential reading on all exposed piles. • Take two wall thickness readings spaced 180 degrees apart on all exposed piles.



DATE: 12/11/2013

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7.10 Conductor / Conductor Guides

Carry out a general visual inspection of the conductor and the conductor guide frame assemblies at each jacket level, noting areas of damage or movement. Wherever conductor guides are missing, same shall be reported. Visually inspection conductor guides weld joints for any damages.

7.11 Cathodic Protection Survey

Carry out a general visual inspection of the Anodes, their locations, attachments and confirm the numbers and report following:

• Verify the presence of all the anodes on all members, launch trusses, risers and pipelines out to 20m from the tube turn or the touchdown point of any unsupported span, whichever is further.

• Confirm the attachment status [by physically shaking] all the anodes. • Note any missing or damaged anodes. Where such anomalies are found the

member to which the affected anode is/was attached shall be cleaned at that point and inspected for damage. Report any damage found and remedial action taken.

• If low cathodic potential readings are obtained in a particular region of the structure, remove all major marine growth and corrosion product from the anodes in that area and retake the C.P. readings 24 hours later.

• Estimate the volumetric wastage of all the anodes as follows:

A. 0% to 25% depleted B. >25% to 50% depleted C. >50% to 75% depleted D. >75% depleted

Cathodic Potential Measurement All Cathodic potential measurements shall be carried out in accordance with approved procedures.

• Cathodic potential readings shall be taken as follows, unless otherwise specified that one reading is to be taken at each location. They shall be taken:

• On all members in the splash zone, on all nodes, midpoint between nodes on main legs and braces, and all exposed piles.



DATE: 12/11/2013

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• In the case of skirt piles, to confirm good pile to pile guide cathodic protection continuity, one reading shall be taken at the top of each sleeve and one on the corresponding pile immediately above the sleeve.

• On all the areas of damage. • On all the areas affected by coating damage in the splash zone. • At all locations where evidence of corrosion has been found. • On all conductors and conductor guides. • On nodal welds. • On risers. • On pipelines.


• Take still photos of all damaged anodes, remains or old attachment points of all missing anodes.

• CP Readings shall be reported for all members. • C.P readings lower than the specified limit shall be included in an urgent report. • The minimum acceptable level of protection on a cathodic protected structure in

seawater is -800mV (-0.800V) relative to a standard silver/silver chloride half-cell. The C.P. readings obtained should be within the range of -850 to -1000mV and any readings which are less negative than -840mV should be reported immediately.

• Report if the depletion level is more than 50% for further necessary actions.

7.12 Visual Weld Inspections Node/Weld Identification Welds are identified simultaneously along with the designation of chord [the member/node which is continuous through the joint and on to which all other intersecting components are attached] at which the weld is located followed by the brace designation. For example: NE11/MD51, NE11/ME51, MJ95/MJ74.

Inspection Requirements:

• Clean the complete weld on all selected welds. Cleaning is to encompass a 50mm wide margin on either side of the weld cap at each location and is to be of a standard that is sufficient to allow detailed visual inspection of the cleaned area to satisfy the diver/inspector.



DATE: 12/11/2013

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• Where protective coating is present it shall not be removed. In such cases the coating condition as well as any obvious defects is to be reported.

• All cleaned areas shall be visually inspected and the location, orientation and size of any significant defects recorded.

• Take one cathodic potential reading in the centre of the weld cap in each cleaned area.

• During the base line inspection, (as built/baseline' inspection) carryout one wall thickness reading on the parent metal on either side of the weld cap in each area. Where well-bonded, even protective coating is present the reading shall be taken through the coating. In such cases the presence of the coating shall be highlighted when the readings are presented in the final report.

7.13 Critical weld Inspections [Type II & III] Type II & III welds are those identified as critical ones with higher probability of failure due to high stress caused because of operating loads, environmental loads and fatigue loads etc. These shall be identified from design & engineering analysis documents and issued along with the job packs for inspection. Preparation

• Remove marine growth using an H.P. water-blaster or a similar item. Clean the weld cap to a bare metal finish, heat affected zone (H.A.Z.) and a margin 100mm wide to either side of the weld cap, using a grit blaster and/or hydraulic wire brush.

• Clean the metal surface according to the Swedish Standard 21/2A or equivalent, which specifies a dull/flat finish. Hydraulic wire brushing produces a shiny surface unsuitable for video or photography; hence this method shall only be used as a contingency in the event of grit-blaster failure. Hand wire brushing or any other hand-cleaning technique is not acceptable under any circumstances.

• Remove all areas of foreign material, for example slag, within the toe of the weld or the weld cap itself, if possible, prior to any inspection since such inclusions may mask any underlying defect.

• After cleaning, and prior to any inspection, make suitable [oil based crayon or similar] datum reference markings on the entire length of the specified weld without any damage [i.e. no more than 2mm deep into the metal].

Visual Inspection

• Inspect every section of the weld and the adjacent parent metal. • Measure the location of each and every anomaly observed during visual

inspection or M.P.I. and record according to the datum marks, to an accuracy of +/- 1mm. Report the side of the weld on which the anomaly is located.



DATE: 12/11/2013

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For Type-II inspection the weld shall be checked at two diametrically opposite sides 150mm long each. For Type-III, it shall be full circumference inspection. Non-Destructive Testing (ACFM, LIZARD/EMA, M.P.I., U.T. and C.P) Carry out ACFM or LIZARD/EMA, or Magnetic Particle inspection at specified locations, or a visual inspection, if a significant defect is located which requires further investigation. Take UT wall thickness readings adjacent to all the welds as follows:

• Both sides of the weld cap, at four equi-spaced locations (i.e. 90 degrees apart) around the length of the weld.

Take Cathodic Potential readings on the weld cap at two diametrically opposite locations for nodal and girth welds and at one point midway along the length for seam welds. Reporting requirements

• DVI. • NDT reports. • Photographs. • CP & wall thickness report.

7.14 Riser Inspection Scope commences at the insulation joint or 2 meters above the spider deck, whichever is higher, and finishes at the bottom butt- weld or flanged joint of the tube turn.

General

• After metrology, prepare a sketch / key plan of the structure with the location of all risers, size from (platform) to (platform), service (oil/gas/well fluid/gas lift/water injection), operating pressure and temperature, diameter, type/location of coating, bare metal areas, location of clamps, tube-turn, etc.

• Record any abrasion, distortion or other physical damage to either the coating or the riser itself.

• Measure the position of each riser at all horizontal-bracing framings in the following manner: o Measure from the inside of the nearest main leg to the centre back of the

riser. o Measure from the outside of the horizontal member to the back of the

riser. • Record the location of the bottom butt weld of the tube turn relative to the

structure.



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• Remove all debris around the riser / clamps / tube turn. • Record all areas of bare metal. Clean all such areas and carry out wall thickness,

C.P measurement, and visual inspection for damage and/or corrosion to the parent metal.

• Record the position of the tube turn relative to the seabed. If the tube turn is firmly supported, remove any clamped knee brace.

• Measure the touchdown point from the tube turn. Support using sand-bags, if the free span is in excess of the allowable limit as per design. Only after the free span support is provided, any knee brace present is to be removed.

Marine Growth Removal Marine growth removal shall be done such that it shall not exceed the design criteria Riser Clamps

• Using water blast clean all riser clamps, support stubs, attachment welds and 0.5m of the riser above and below each clamp.

• Report the type of clamp present at each level. Clamps will be identified by their standard “Mark" numbers.

• Inspect all clamps (including telescope and brace clamps) for damage / misalignment. Check the condition of all clamps bolts. Check bolts’ tightness using a suitable wrench. All loose /missing bolts are to be tightened or replaced.

• Replace any missing or severely damaged clamps. • Inspect all riser clamps for the presence of neoprene liners. In the case of non-

concrete-coated risers, the replacement of any missing clamp liners is mandatory. In the case of concrete coated risers, the missing liner needs to be replaced only where its absence results in tolerance between the clamp and the riser.

• Visually inspect and confirm the integrity of all attachment welds and jacket bracing(s), particularly at the end of all gusset plates.

• Measure all (riser, telescopic, member) clamp tolerances and if it is unacceptable, (i.e. the clamp is not secure) the packing is to be installed.

• Report/record any evidence of vibration or movement of risers. • When an area of bare metal extends behind a clamp, report to the Client / TPIC

Representative. [As per an approved procedure, the clamp may have to be opened, and the riser cleaned and inspected prior to the application of new coating.]

• Inspect the riser for corrosion / damage at the clamp edges.

Wall Thickness Wall thickness readings shall be taken on all risers at (a) 4 cardinal points on all bare metal areas and (b) all areas of corrosion/pitting.



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Splash Zone

• Clean the corroded / rusted portion of the riser to bare metal by hydraulic / pneumatic wire brush at points where the splash zone coating is not present.

• Make 100mm grid in the bare metal areas of the riser and record the minimum thickness reading in each grid. In the case of risers which have diameters that are 4 inches or less, grids shall be drawn at 4 equal spaced points around the circumference of the riser pipe (i.e. 90 degrees apart) and at 100mm vertical intervals.

• The grids may be changed to a higher one [such as 500 mm x 500 mm, etc., i.e. less stringent] or a more stringent one [such as 50 mm x 50 mm in pitted areas], based on the visual condition and in consultation with the Client / Third Party Inspection/Certification Agency.

• Carry out the inspection between (+) 2 meter above the spider deck clamp top (datum) and down up to C level clamp.

• In the case of Monel sheathing in the splash zone, carry out visual inspections of Monel to riser top and bottom circumferential weld joints after proper cleaning. Top weld joints shall be checked by Dye penetrate testing. Monel longitudinal seam welds shall also be visually inspected. The condition and location of Monel plugs shall be checked and if found loose shall be tightened and reported to Client / Third Party Inspection/Certification Agency.

• If any dent is noticed on the riser pipe, dent dimensions shall be measured or recorded. MPI of the dented area shall also be carried out.

• Photographs of the riser above MSL shall be taken before and after the painting work.

Cathodic Protection of Risers

• Confirm the presence, location and secure the attachment of all anodes. • Comment and then remove all major growth and corrosion from the surface of all

anodes. Record any painted or partially painted anodes, remove the paint by water blasting if necessary.

• Estimate the volumetric wastage of all anodes as per 3.1.8 above. • Photograph the most severely depleted (>50%) anode on each riser. • Take cathodic potential reading as follows:

o On each anode and on the adjacent pipe to confirm electrical continuity

between the two areas. o On the entire exposed field joint welds. o On all the areas of exposed bare metal. o On either side of any mechanical pipe joints. o On riser clamp caps, clamp saddles and the risers adjacent to all clamps. o At the back of all uncoated tube turns (100 mm grid).



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7.15 Pipeline Inspections

Scope of inspection is up to 30m away from the bottom butt-weld or flanged joint of riser tube turn.

• Triangulate the approach paths of all pipelines relative to the adjacent jacket face.

• Triangulate the location of all pipeline crossings. • Visually inspect all pipelines out to 30m from the tube turn and report any

damage, corrosion or other anomalies found. • Measure/record the profile of the sea-bed relative to all pipelines at 2m intervals

along the pipeline out to 20 meters from the tube turn. • Record condition of bolts/nuts of any flanged joints for loose nuts, missing nuts,

etc. • Check/record the condition of coating. • In case bare metal exists, measure/record UT wall-thickness at 4 cardinal points,

and CP. • At tube turn, measure/record the offset distance between the riser and the

nearest suitable member of the jacket. • Record all crossing pipelines and the distance between them. Record the

presence of any wedge between the pipelines in contact with each other, and the condition at the contact point.

7.16 Appurtenances This covers inspection of the following:

• Boat landing / fenders/ access ladders. • Launching skids / trusses. • Sump pipes and their supports/guides. • Pump caissons and their supports / guides. • Mud mats.

Boat Landing / Fenders / Access Ladders

• Verify the presence and location of all boat landings/fenders and access ladders. • Clean (but DO NOT remove any paint / coating) and carry out a visual inspection

of all welds attached to these appurtenances. The welds at both the ends of stub-braces should be cleaned and inspected.

• Clean using water-blast and inspect all attachment clamps. Replace any missing bolts/damaged clamps and tighten all loose bolts.



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• Inspect all areas of the boat landings, fenders and access ladders for damage / corrosion. In the case of boat landings and access ladders note in particular any damaged or missing grating, steps or handrails which may render them unsafe.

• Photograph all such appurtenances and all anomalies found during their inspection.

Launch Trusses

• Visually inspect the launching trusses and their attachment welds for damage or

corrosion. • Anode inspection of the launching truss can be limited to one anode per level for

monitoring purposes only. • A CP survey of the launch truss is not required, it is only important to ascertain

the integrity of the connection (with respect to C.P) of the launch truss to the primary structure.

Sumps/Pump Caissons and their supports/guides

• Confirm the location of all sumps/pump caissons and inspect them and their

supports/guides for damage or corrosion. • Note the extent of marine fouling in sump termination/caisson entries. Remove,

by water blasting if necessary, any excess fouling found to be present. • All attachment welds and/or clamps are to be cleaned using water blast and

inspected. • Retighten all loose clamps/bolts, replace any missing clamps/bolts and re-align

any misaligned clamps. • Check the condition of any grating over sump terminations/caisson entries. • Photograph all sump terminations/caisson entries (after cleaning, if necessary)

and take photographs of attachment points/clamps if any anomaly is observed.

7.17 Damages Carry out GVI/DVI & NDT as according to the damages.

• Take sufficient detailed measurements to determine accurate dimensions of, and to precisely locate, the defect.

• Carry out taut-wire out-of-straightness measurements (in two planes at 90 degrees) on all significantly-damaged structural members, risers and pipelines.

• Measure the depth and orientation of all dents or other structural defects. Use a straight-edge to determine the depth of localised defects.

• In the case of holes, dents, wire rope or similar scars in underwater members, take CP and UT wall thickness measurements.

• Report/record weld cracks immediately.



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• All damages shall be immediately reported with information on possible cause of the damage.

• Take still photographs of the damage. Include sketches. • Detailed report including measurements and NDT reports.

All major damages shall be brought to the notice of the certifying agency immediately.

7.18 Flooded Member Detection Flooded member detection may be required on selected braces only (usually vertical diagonal members, horizontal perimeter members and primary horizontal diagonal members). If members are flooded, an additional general visual inspection is required to determine the cause of flooding. If through-thickness cracking of the nodal welds at the ends of the flooded member is suspected to be the cause of the flooding, then a detailed inspection of these nodal welds is required.

7.19 Suggested Remedial works

• Remove and recover all significant debris, within the capabilities of the spread, from the structure and up to at least 20m away from structural members and pipelines and report any damage caused by the debris and all debris that for any reason cannot be recovered to the surface or removed. Remove or cut all wire ropes crossing the pipeline.

• Remove any riser elbow supports which prevent access for riser elbow wall thickness measurements. Replace all supports removed to the preferred distance of three (3) metres along the pipeline from the lower riser elbow butt-weld.

• Support all free spans which exceed the allowable length. Refer to the pipeline database for details of allowable free spans PRIOR to the inspection.

• Secure all loose attachments on the boat landing, if any are present. • Insert missing neoprene liners in the riser clamps unless the risers are designed

to be in electrical continuity with the platform. Remove any neoprene liners from riser clamps where the riser is designed to be in electrical contact with the platform. Confirm the pipelines’ cathodic protection status from the pipelines’ database PRIOR to the inspection and rectification.

• Tighten all loose bolts. Replace all missing nuts/bolts including lock nuts. • Remove redundant riser clamps and replace damaged clamps. • Secure all loose anode mountings. • Replace missing anodes. • Replace all depleted (>90% depleted) anodes. • Remove all riser knee braces. • Clean and remove obstructions from the sump and caisson intakes.



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• All open flood valves should be closed or otherwise sealed. If the valves are jammed some form of bung closure should be inserted, or the valve should be sealed using a "splashtron" compound (or equivalent).

• Replace / repair missing / damaged gratings, hand-rails, etc. on spider deck, boat landing, etc.

• Replace any missing Barge Bumper vertical member chain. • Replace missing/damaged or install new continuity cable to improve low CP

readings. Re-check CP readings 24 hours later to improve it. • Replace missing riser clamps. • At sea-bed, install a suitable wedge such as rubber sheet or wooden wedge, etc.

between two or more pipelines in contact with each other. • In the case of any weld crack, a hole may have to be drilled under the

instructions of Client/Third Party Inspection/Certification Agency at the ends of the crack in order to arrest the propagation of the crack. Further actions include metrology, photos, NDT, etc.

Note: All Remedial Tasks are to be carried out under Client and/or Third Party Inspection/Certification agency’s instruction.

Still photographs Still photographs will be required in case of any damages, discrepancies, anomalies etc. such as the following examples:

• Corrosion. • Hole in member. • Bent member. • Dent in member. • Missing member, clamp. • Loose nuts/bolts. • Missing clamp liner. • Free span of pipeline. • Scour. • Before its removal/relocation, large debris in/near jacket. • Missing coating.

Ultrasonic wall thickness UT wall-thickness readings will be required in the following cases:

• Corrosion. • Rusting. • Pitting. • Loss / damage of coating. • As a part of the as-built survey and Type II/Type III surveys.



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General Notes Coating Any existing coating shall not be removed for any visual/NDT inspection except where specified. CP, UT wall-thickness readings, etc. if required to be taken shall be done at missing coating areas. Depth Readings Record the date and time in which all the depth readings are taken. Discrepancies/Damages Still photos and sketches are required for all damages, discrepancies, anomalies, etc.

• If any anomaly, discrepancy or damage etc. is significant, additional measurements or inspection or NDT as required by the Client / Third Party Inspection/Certification Agency will also be required.

• In the case of a serious defect during General Weld Inspection, for example cracking being observed, full cleaning and detailed inspection shall be carried out on the affected weld.

Cathodic Potential

• Any remedial action for improvement in CP will require re-taking the CP readings 24 hours later to verify that the improvement has indeed occurred.

• Contact C.P. measurements are required; remote CP measurements are not acceptable.

• In case of a significant anomaly between any finding or measured reading [e.g. UT wall thickness, CP value, etc.] and the specified reading, the same shall be re-checked by another diver.

Type II/III welds Selection of welds to be inspected will be taken from the list of low fatigue life / high stress welds and will be included in the Job-Pack. 50% of these welds are to be inspected as Type II [General Weld Inspection] and the remaining by Type-III [detailed inspection including NDT]. During the next inspection campaign, Type II welds shall be inspected as Type III, and vice versa.



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Procedures Procedures related to ACFM, LIZARD/EMA, M.P.I., U.T. and C.P shall be based on international codes/standards, and shall be approved by Client / Third Party Inspection/Certification Agency. With regard to MPI, flexible cable techniques will be given first preference, followed by prod and then yoke, and lastly permanent magnets. Triangulation This may be carried out by means of diver hand-held sonar (either passive or active), or by taking physical measurements to fixed reference points on the structure such as the main legs on the adjacent face.

Remedial jobs

• All critical remedial jobs will be as per an approved procedure supported by approved risk assessments.

• Before carrying out any remedial job, supporting documents such as records, sketches, photographs, video etc. will be required.

8. SELECTION OF DIVING AGENCY Inspection/Diving Agency

• Should possess valid (a) ISO 9001 or similar, and (b) IMCA certifications. Each certification should be at least 2 years old.

• Should have carried out at least two similar jobs [full jacket] in the last 5 years • Will be subjected to pre-mobilization audit by the Client / Third Party

Inspection/Certification agency as per applicable IMCA requirements.

Diving Methodology / Spread

• Air Diving. • Saturation Diving. • The methodology that is proposed to be utilized by the Agency shall be submitted

for Client / Third Party Inspection/Certification Agency’s approval with proper risk assessments of each identified critical activity.

• Each dive should be preceded by a Briefing Meeting and end-of-dive meeting with minutes highlighting the critical findings / actions recorded.

• Divers shall use Hat-Mounted Camera for all dives including shallow dives and monitored by the diving supervisor in Control Room.

• One Supervisor shall monitor and be in control of only one Diver at a time.



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• Minimum on-site diving personnel shall be as per IMCA requirements. • Video recording of all inspection work is required as records. This shall be

submitted along with Diving Agency’s Inspection Report. • Dive Control Room shall be in a proper cabin.

Reporting

• At site, Daily Log Books, minutes of meetings, incident reports, etc. shall be as per applicable IMCA requirements.

• Inspection Report shall be a comprehensive detailed report with inclusion of all records, photos, sketches, etc. Contractor’s Inspection Report format will be reviewed during the pre-mobilization audit.

Diving Vessel

• Should be classed by a reputable IACS Society. • Should have been involved in at least one similar job [full jacket] in the last 5

years. Personnel

• Diving Superintendent o At least 10 years’ overall experience in jacket inspections/surveys and 5

years’ as a Diver. o Should have carried out at least two similar jobs [full jacket] in the last 5

years. o Logbooks signed by Client should be available as evidence. o Medical fitness certificate.

• Diving Supervisor

o At least 10 years’ overall experience in jacket inspections/surveys and 5 years’ as a Diver.

o Should have carried out at least two similar jobs [full jacket] in the last 5 years.

o Logbooks signed by Client / Diving Superintendent should be available as evidence.

o Medical fitness certificate.

• Inspection / Report Coordinator o Should be an Engineering graduate with NDT Level II qualifications of at

least 2 years. o Should have experience of at least one similar job within the last 5 years. o Should be available at all times at the offshore site. o Responsible for all site meetings and minutes.



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• Medical fitness certificate. • Inspection divers

o At least 6 years’ overall experience, with at least 2 years as an Inspection Diver.

o Should have carried out at least one similar jacket job in the last 5 years so as to carry out same activity/inspection.

o Logbooks signed by Client / Diving Superintendent / Diving Supervisor should be available as evidence.

o Qualification, NDT certificates. o Medical fitness certificate including eye test. o ‘Country’ divers are not acceptable.

• Construction divers

o At least 3 years’ overall experience as a Diver. o Should have carried out at least two similar jobs in the last 5 years. o Logbooks signed by Client / Diving Superintendent should be available as

evidence. o Qualification certificates. o Medical fitness certificate. o Will not carry out any inspection. o Country’ divers are not acceptable.

• Technicians

o At least 3 years’ of overall experience. o Should have carried out at least two similar jobs in the last 5 years. o Medical fitness certificate.

• Riggers

o At least 3 years’ overall experience. o Should have carried out at least two similar jobs in the last 5 years. o Qualification certificates. o Medical fitness certificate.

• Safety Officer

o At least 3 years’ overall experience. o Should have carried out at least two similar jobs in the last 5 years. o Qualification certificates. o Medical fitness certificate. o Should be available at all times at the offshore site.

Diving equipment

• Will be subjected to pre-mobilization audit by the Client / Third Party Inspection/Certification agency as per applicable IMCA requirements.



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NDT Instruments

• Calibration certificates of all the instruments shall be available on site at all times. • Functional tests shall be demonstrated during pre-mobilization audit. • Will be subjected to pre-mobilization audit by the Client / Third Party

Inspection/Certification agency as per IMCA requirements.

Safety

• Safety Manual covering all the aspects of the scope of work including risk assessments should be submitted for review.

• Safety Officer shall be present on the site at all times. • Safety briefing should be carried out before the start of job and de-briefing at the

end of job with the minutes submitted to the Client. • Functional trials such as escape to chamber within the prescribed time, etc. shall

be demonstrated at the site before commencement of diving operations. • All equipment including Generator set, etc. shall be certified as fit for use for

offshore work by a reputable Third Party Inspection/Certification Agency. • Pressure vessel/chambers, etc. shall be certified by a Competent Authority

before release by a reputed Third Party Inspection/Certification Agency. • Notwithstanding the on-board presence or absence of Client/Third Party

Inspection Agency/others, it is understood that the Diving Agency is responsible for all safety/health/environmental issues related to the execution of the work.

• Before the first dive, the on-site audit of installed systems shall be carried out by Client/Third Party Inspection Agency.

9. INSPECTION JOB PACKS

Inspection job packs for each inspection campaign shall be developed with reference to the relevant inspection program. The Job-Pack shall include:

• A description of the inspection scope, listing components to inspect and the corresponding inspection technique.

• A reference to the anomaly Criteria for acceptance. • A reference to the standard. • A reference to all relevant inspection and testing procedures. • The details of the component to be inspected, joint details, framing details, anode

lay outs, specifications, as built data etc. • A photocopy of the marked up drawings from the previous inspection, with details

of anomalies, and on which the inspectors made amendments. • A list of un-rectified anomalies from the anomaly database, highlighting which

ones shall be inspected. • A print-out of anomaly photographs. • Anomaly reporting formats.



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10. INSPECTION REPORTING REQUIREMENTS Urgent reports shall be generated for anomalies detected during the survey, as per the Anomaly table below. Report of the work shall be made on the completion of each activity as per the formats included in this manual.

10.1 Anomaly acceptance criteria & reporting

All anomalies and their acceptance criteria for the underwater structure & components shall be as per this table

Anomaly Reject Criteria Reporting Requirements 1. Weld defects

Any cracks, incomplete or absent welds.

o Record weld, position, extent and type of anomaly on drawing.

o If surface weld crack is suspected, do MPI to investigate weld.

o Take Photograph. o Fill in anomaly datasheet. o Subsequent remedial action may include arresting the

crack by drilling a hole at each end of the crack as per an approved procedure and under instruction of Client/Third Party Inspection\Certification agency.

2. Corrosion

Greater than 3 mm depth

o Measure area of corrosion, % cover in area, maximum depth and diameter of pits, and average depth and diameter of pits.

o Record component, position and details on drawing. o Take UT Wall Thickness readings as per a grid pattern

on worst corroded area and take nominal WT next to corroded area.

o Photograph, stand-off of area, close up of largest pit. o Fill in anomaly datasheet, with sketch and details of UT

readings. o Subsequent remedial action may include NDT, paint

coating if above water, etc. 3. Thickness

Less than 75% nominal wall thickness (based on wall thickness of surrounding good material), covering at least 15 % of circumferential area or surface area.

o Report if less or more than the specified thickness. o Record component, position and details on drawing. o Take (additional) UT Wall Thickness readings to

establish extent of anomalous area. o Photograph. o Fill in anomaly datasheet, with sketch and details of UT

readings.

4. Physical Any major damage o Dimension damage.



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damages

due to physical impact / overload or relative movement, leading to rupture or severance.

o Record component, position and details on drawing. o Take close-up and stand-off photography.

5. Vibrations

Any prolonged vibration.

o Note severity, frequency and effect (amount of deflection).

o Identify reason or source. o Record affected components and details of vibration on

drawing. o Subsequent remedial action may include arresting the

vibration suitably. 6. Degradation of coatings/ rusting Damage to paintings

Rusting to the extent of 15 to 20% of surface rusted.

o Record component, position, description of damage and area size in m2 on drawing.

o Photograph damage. o Report CP if underwater. If low, proceed as per 10.

below.

7. Lack of Integrity

Any insecure, loose, misaligned or broken components that can lead to accident. Example: o Loose handrail. o Loose grating

(without clips). o Grating too small. o Missing grating. o Hazardous debris

which may fall and hit someone.

o Grating installed the wrong way.

o Protruding steel.

o Record component, position and describe on drawing. o Reinstate if possible (e.g. loose bolts), and note on

drawing action taken. o Take close-up and stand-off photographs if not

reinstated.

8. Conductor movement

Any movement within guide at any level


o Identify reason or source. o Record affected components and details on drawing. o Subsequent remedial action may include arresting the

movement by means of wooden or similar wedges. 9. Riser movement

Any movement within clamp at any level


o Identify reason or source. o Record affected components and details on drawing. o Subsequent remedial action may include- - Tightening or replacement of clamp nuts/bolts - Arresting the movement by means of wooden or similar

wedges. 10. Low CP readings

Any reading less negative than (-) 840mV

o Report extent/area of low CP readings o Report condition of nearest anode, and attachment. o Subsequent remedial action may include- o Cleaning nearest anode and re-checking for improved

CP 24 hours later o If not, installing continuity cable and re-checking CP 24



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hours later, which process to continue until satisfactory readings are obtained.

11. Anode depletion

- Depletion beyond 50% - Missing anode

As applicable, o Report percentage depletion. o Report presence of marine growth, paint coating, etc o Report integrity of anode/member attachment o Photos, lay-out/location sketches o Subsequent remedial action may include- o Checking CP on the member on which it is/was

attached o Restoring CP by replacement of anode and/or

installation of continuity cable 12. Scour Scouring close to or

more than the designed scour

o Report depth of scouring at several points on each member so as to obtain a fair idea

o Photos, sketches giving adequate details o Subsequent remedial action may include- o Supporting with grout bags or similar o Actions as per results of analysis

13. Pipeline free -span

Freespanning close to or more than the designed value.

o Report depth of freespanning at several points on each member so as to obtain a fair idea

o Photos, sketches giving adequate details o CVI along the length of pipeline for any bends, dents,

absence of coating, etc. o Subsequent remedial action may include- o Supporting with grout bags or similar o Actions as per results of analysis

14. Missing member

Absence of member wrt drawings/sketches furnished with Job-Pack

o Immediate reporting required. o Photos, sketches o Subsequent remedial action may include- - Installing clamp-type [or similar] member after results

of analysis. 15. Hole in member, flooded member

Any hole, flooding of member

o Immediate reporting required. o Photos, sketches o Subsequent remedial action may include- - After results of analysis, installing clamp-type [or

similar] doubler plate with corrosion inhibitor 16. Missing or loose nuts/ bolts

Missing or loose nuts/ bolts

o Report with photos o Report condition of member that is/was supported.

17. Missing clamp

-Missing clamp -Member partly outside the clamp

o Immediate reporting required. o Photos, sketches o Subsequent remedial action may include- o Replacement of clamp

18. Deformation in Riser

‘Offset’ of riser near/at tube-turn [horizontal distance between riser and jacket structure at sea-bed level] less or more than that specified

o Immediate reporting required. o Photos, sketches o Subsequent remedial action may include- o Suitable arrangement to arrest the abnormal offset.

19. Settling of jacket

Settling of jacket into the sea-bed

o Make suitable marking or similar arrangement above water level to determine/measure the amount of settling



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10.2 Anomaly reporting

Reporting shall be as per formats in the attachment.

10.3 Inspection Reports To demonstrate that the safety critical system and the components are suitable and continue to meet their performance requirements, inspection /monitoring records shall be maintained. Such records must be retained for the life of the installation, and shall be covered under a suitable Data Management system and kept updated. The Certification Agency (CA) shall verify and confirm periodically by audit and witnessing compliance to the recommended inspection monitoring program. The inspection reports along with the CA recommendations shall be maintained and followed up. The reports shall also contain information on the scope and extent of the examination undertaken, and clearly identify the equipment verified. Formats appended to this document shall be used for reporting.

11. REVISIONS TO THIS MANUAL

11.1 Events initiating revisions This manual may require changes that are triggered by events such as:



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• Physical changes to installation (e.g. modifications, additions). • Damage / incidents. • Change in record-keeping systems. • Results feed-back from completed verification activities. • Results of any safety assessments. • Out-come of any studies/ analyses, etc. carried out.

12. REFERENCE DOCUMENTS

• API RP 2A. • API RP 2C. • OISD Standards & Guidelines 130,132,137.142,145,153,174. • As-built documentation for PLQP & DDW.



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13. DEFINITIONS/ TERMINILOGY

ABBREVIATION/TERM MEANING CVI Close Visual Inspection, defined as being close enough to be

able to touch the component and clean it with a hand brush, if necessary. CVI of components not accessible on foot requires abseiling, or the use of scaffolding.

GVI General Visual Inspection, without need to clean, prepares a site, or arranges special access. If normal access is not available, GVI is done from a distance, with the help of binoculars.

MPI Magnetic Particle Inspection. N/A Not applicable. NDT Non-Destructive Testing. RE Reliability Engineer. UT Ultrasonic Testing.

14. ANNEXURES

• Annexure-A: Recommended schedules for Inspection & Maintenance of Jacket structures

• Annexure-B: Reporting formats..

35

INSPECTION REPORTING FORMATS

(Annexure-B)

for

OFFSHORE – UNDERWATER STRUCTURES

DEEN DAYAL OFFSHORE FIELD

GUJARAT STATE PETROLEUM CORPORATION LIMITED

DOC. REF: AIMS/UW/IRR-01

Table of Contents

Sl. No. Format Description

1 ANOMALY REPORT

2 AS-BUILT SURVEY

3 BARGE BUMPER / BOAT FENDER INSPECTION

4 CALIBRATION LOG

5 CONDUCTOR INSPECTION

6 DYE PENETRANT TEST REPORT

7 RISER INSPECTION SUMMARY

8 SCOUR SURVEY

9 SPIDER DECK INSPECTION

10 SPLASHZONE INSPECTION - RISER

11 SPLASHZONE SURVEY - LEG / MEMBER

12 GENERAL VISUAL WELD INSPECTION (TYPE II

13 WELD INSPECTION SUMMARY [TYPE III]

14 INSPECTION REPORT - VIDEO LOG

Anomaly Report Gujarat State Petroleum Corporation LtdPlatform: Report No.: Sheet: of Location: Date:

Item / Component: Inspector: Anomaly type: Inspection Co: Drawing Ref:

Weld/Area No. (delete as

appropriate)

Tasks carried out () Readings / Condition / Comment GVI CVI MPI UT Vibration Photo taken

Stand-off Close-up

1

2

3

4

5

Anomaly Sketch (with weld / area numbers) Likely Cause of Anomaly:

ATTACHMENT: Job-Pack, relevant Drawing copy(ies) marked up with anomaly, NDT reports, photos.

Page No.

Report No.

C.P. Dive Marine Growth Comment /

Memb. ( VE) No. Avg. Max. % Spec. Actl. Wast. Anomaly

(mm) (mm) Max. Range

Comment / Anomaly :

Name of Diving Contractor: Vessel: Platform:

Inspection Engineer: Diving Superintendent/Supervisor:

Note: If any anomaly is present, please Number in Column & Refer in Comment Box. Attach photos,

relevant sketches, etc. as applicable.


Level F

Level G

Any other

Spider Deck / Level A

Level B

Level C

Level D

Level E

AS BUILT SURVEY

Anodes


LEG JKT. FACE DATE DIVER DIVE No. LEG JKT. FACE DATE DIVER DIVE No.

BOLTS TIGHT LOOSE MISSING REPLB. BOLTS TIGHT LOOSE MISSING REPLB.

NIL NIL NIL

PIT % COATING CRACK ANOM. PIT % COATING CRACK ANOM.

BF-1 BF-1

BF-2 BF-2

BOLTS TIGHT LOOSE MISSING REPLB. BOLTS TIGHT LOOSE MISSING REPLB.

WELDED

PIT % COATING CRACK ANOM. PIT % CPP COATING ANOM.

BF-3 BF-3

BF-4 BF-4

FENDER UNIT FENDER UNIT

DAMAGED SECURE DAMAGED SECURE

CORROSION MISSING CORROSION MISSING

SHEAR UNIT (NONE) SHEAR UNIT (NONE)

SECURE DISLOCATED SECURE DISLOCATED

REPAIRED SERVICEABLE REPAIRED SERVICEABLE

LEG JKT. FACE DATE DIVER DIVE No. LEG JKT. FACE DATE DIVER DIVE No.

TIGHT LOOSE MISSING REPLB. TIGHT LOOSE MISSING REPLB.

BOLTS BOLTS

PIT % COATING CRACK ANOM. PIT % COATING CRACK ANOM.

BF-1 BF-1

BF-2 BF-2

TIGHT LOOSE MISSING REPLB. TIGHT LOOSE MISSING REPLB.

BOLTS BOLTS

PIT % CPP COATING ANOM. PIT % C.P COATING ANOM.

BF-3 BF-3

BF-4 BF-4

FENDER UNIT FENDER UNIT

DAMAGED SECURE DAMAGED SECURE

CORROSION MISSING CORROSION MISSING

SHEAR UNIT (NONE) SHEAR UNIT NONE

SECURE DISLOCATED SECURE DISLOCATED

REPAIRED SERVICEABLE REPAIRED SERVICEABLE

COMMENTS :


Inspection Engineer: Superintendent/Supervisor:

Page No.

Report Ref.: BARGE BUMPER / BOAT FENDER INSPECTION

Page No.Report Ref.

Location : 1st Dive of project: Last Dive :

UT Wall thickness instrument S. No.: CP Meter S. No.:

Calibration Certificate No.: Calib. Cert. No.:

Calibration Certificate validity date: Calib.Cert.validity date:

Wall Thickness (MM) Cathodic Potential (-V)

Calibn. Time 5.0 10.0 20.0 20.0 Sign Zn. Mg. SignDate Meter(S)

Pre-Dive.

Dive No. Serial No. Pre-Insp.

Post-Insp.

Date Meter(S)Pre-Dive.


Post-Insp.



Post-Insp.



Post-Insp.



Post-Insp.



Post-Insp.



Post-Insp.



Post-Insp.






CALIBRATION LOG


Sketch showing the lay-out of conductors/guides

COND.C.P. READING C.P. VALUE (-ve) AT HORIZONTAL BRACING

No. LOCATION Level C Level E Level G Level J Level L Level N

1 CONDUCTOR

COND. GUIDE

2 CONDUCTOR

COND. GUIDE

3 CONDUCTOR

COND. GUIDE

4 CONDUCTOR

COND. GUIDE

5 CONDUCTOR

COND. GUIDE

6 CONDUCTOR

COND. GUIDE

7 CONDUCTOR

COND. GUIDE

8 CONDUCTOR

COND. GUIDE

9 CONDUCTOR

COND. GUIDE

10 CONDUCTOR

COND. GUIDE

11 CONDUCTOR

COND. GUIDE

12 CONDUCTOR

COND. GUIDE

DIVE No. :

COMMENTS:

CONDUCTOR / CONDUCTOR GUIDE CATHODIC POTENTIALS

STRUCTURE DATE DWG. No. SHEET OF



Page No.

Report Ref.:CONDUCTOR INSPECTION


Page No.

DYE PENETRANT TEST REPORTReport Ref.

Structure : Date : Time : Dive No.

Item : Diameter : Weld Length : Datum Location :

Node / Weld Locn. :

Cleaning : HP Water HP Water/Grit Hydraulic Wire Buff Hand Wire Buff

Other (Specify) : Surface Finish :

Viewing Conditions : Bright Sunlight Subdued Sunlight Darkness

Light Source :

Dye Penetrant Type : Magnaflux Non Chlorinated Type.

No. (mm)from Datum Type, Location and Size of Indication / Sketch

Start Stop

Comments/Test Restrictions :

No Crack Indication Found.

Weld in Good Condition.

Photos attached.



Page No.

RISER INSPECTION SUMMARY

Report No.

Platform : Riser No. : Diameter :

To / From : Service : Nominal W.T. :

Temp °C. : Pressure (P.S.I.) : Installn. Date :

Subj. Comments / Work Completed Recommendations/References

Name of Diving Agency: Vessel:



DA

MA

GE

/

CO

RR

OS

ION

CO

AT

ING

T

YP

E &

CO

ND

CL

AM

P T

YP

E &

CO

ND

CL

AM

P L

INE

R

ST

AT

US

MA

RIN

E

GR

OW

TH

ST

AT

US

WA

LL

TH

ICK

NE

SS

ST

AT

US

AN

OD

ES

AN

D C

.P.

TU

BE

TU

RN

,SC

OU

R,E

TC

.


Page No. :

(+ values indicate amount of burial to top of member, value indicate scour. All in mm). Report. No. :Locn. Scour/ Depth Time Locn. Scour/ Depth Time Locn. Scour/ Depth Time Locn. Scour/ Depth Time

No. % cover (m) Date No. % cover (m) Date No. % cover (m) Date No. % cover (m) Date

Burial Burial Burial Burial

1 31 61 91

2 32 62 92

3 33 63 93

4 34 64 94

5 35 65 95

6 36 66 96

7 37 67 97

8 38 68 98

9 39 69 99

10 40 70 100

11 41 71 101

12 42 72 102

13 43 73 103

Sketch indicating Location No. is attached.

Name of Diving Agency: Vessel: Platform:

Inspection Engineer: Diving Superintendent / Supervisor:

SCOUR SURVEY


Spider Deck :

1. Hand rails damaged. Size :

2. Hand rails missing. Size :

3. Gratings damaged. Size :

4. Gratings missing. Size :

5. Ladder (Sp. deck to cellar

deck condition) :

Risers : Total No. : Side wise :

Size :

Conductors : Total No. :

Condition :

Barge bumper : 1. Total No. :

A 1 A 2 A 3 A 4 B 1 B 2 B 3 B 4

a) No. of bumper :

b) Securing chain/rope :

c) Rubber fender :

d) Nuts/Bolts/Clamps :

Sump :

Pump Caisson :

Boat Landing : B/L Between : Stages :

Upper Stage :



3. Handrails damaged. Size :

4. Handrails missing. Size :

5. Ladder condition :

6. Bracings :

7. Rubbing strakes :

Middle Stage :






6. Bracings :


Lower Stage :






6 Bracings :


Access Ladder condition :

Total bracings (B/L) :

Total rubber strakes (B/L) :

Work Outstanding :

Photos & sketches of all discrepancies are attached.

Page No.

Report Ref.:SPIDER DECK INSPECTION




Page No.:

Report Ref. :

REF. NO. : PLATFORM : RISER NO. : SERVICE : VESSEL

CROSS REF. SHEET : TO : DIA. : DATE :

CLOCK POSn. 12o/c 9o/c 6o/c 3o/c 12o/c

A B C D E F G H I J K L M N O P Q R S T U V W X Y Z

COMMENTS :

RISER MARKED OUT IN 100 m.m. SQUARES FROM DATUM TO

ALL DIMENSIONS ARE IN m.m. FROM DATUM i.e. TOP OF SPIDER DECK CLAMP

ENTER MAXIMUM PIT DEPTH BELOW U.T. READING.

CALIBRATION LOG UT METERS

DATE / MTRS WALL THICKNESS (MM)

DIVER'S NAME CYG. NO. CALIBN. TIME 10 15 20 30PRE. INSP.

POST INSP.

1

2

3

4

GRID 100 mm X 100 mm

READINGS TAKEN AT CENTER OF EACH GRID



SPLASHZONE INSPECTION RISER

DETAILED U.T. READINGS

PIT

PIT

PIT

PIT

PIT

PIT

PIT

PIT

PIT

PIT

PIT

PIT

PIT

PIT

PIT

PIT

3o/c

PIT

PIT

12o/c 9o/c 6o/c

12o/c

9o/c

3o/c

6o/c


Page No.

Report No.

Specified Leg Corrosion Survey

Elv.(m) UT Spec UT Rdg. Dive Memb. Coating W.T. (mm) C.P. Dive

(+) / ( ) (mm) (mm) No. Leg. Ref. Start Ends Spec. Rdg 1 Rdg 2 Rdg 3 ( mV) No.

End of Coating Depth :

Comments :

Name of Diving Agency: Vessel: Platform:

Inspection Engineer: Diving Superintendent / Supervisor:

SPLASHZONE SURVEY LEG / MEMBER


Page No.Report No.

Wall Thickness Readings (mm) CP Readings ( ve)

Weld No. Chord Brace Dive Anomaly

Memb. Spec. 12 6 Memb. Spec. 12 6 12 6 No.

Comment / Anomaly Report :

Note : If Anomalies present, please number in Column & Refer Comment Box. Attach photos, sketches.

Name of Diving Agency: Vessel: Platform:Inspection Engineer: Diving Superintendent/Supervisor:

GENERAL VISUAL WELD INSPECTION (TYPE II)


PAGE NO. :

REPORT REF. :

STRUCTURE : DATE : NODE NO : 2 WELD NO. :

WELD LENGTH : DATUM LOCN. : NODE / WELD LOCN. :

CLEANING : H.P. WATER H.P. WATER/GRIT HYDRAULIC WIRE BUFF HAND WIRE BRUSH

OTHER (specify) : SURFACE FINISH : SA 2.5

RESIDUAL FLUX DETECTION AND DEMAGNETISATION RECORD

FLUX TESTED O° & 90° TO WELD MAGNETISATION AC DC HWDC

RESIDUAL FLUX PRESENT YES NO METHOD USED : COILS PERMANENT MAGNET

AREA DEMAG'D: YES NO N/R AREA DEMAG'D : YES NO N/R

DEMAG CONFIRMED BY FLUX TEST : YES DEMAG CONFIRMED BY FLUX TEST : YES

VIEWING CONDITIONS : BRIGHT SUNLIGHT SUBDUED SUNLIGHT DARKNESS

LIGHT SOURCE : WHITE BLACK BOTH

INK TYPE : DAYLIGHT FLUORESCENT MIXTURE OF BOTH

INK MAKE(S) : MAGNAGLOW 14A

EQUIPMENT : COILS PRODS ELECTRO-MAG PERMANENT MAG

AMPS : AC COIL TURNS. AMP TURNS :

POSITIVE BCI CHECKS AT (mm) /

SUMMARY OF FINDINGS :

TASK DATE DIVE NO. REFERENCES

STAND-OFF PHOTOGRAPHY

MOSAIC PHOTOG.

PRE-GRINDING.

M.P.I. PHOTOG. PRE-GRINDING

MOSAIC PHOTOG. PRE-GRINDING.

C.P. M.P.I. PHOTOG.

MEASUREMENT PRE-GRINDING

U.T. VIDEO

MEASUREMENT

GRINDING &

RE-M.P.I.

POST-TEST

DEMAG.

M.P.I. 314

314

314

314

DEMAG.

D.V.I. 314

314



WELD INSPECTION SUMMARY [TYPE III]

TASK DATE DIVE NO.

CLEANING 314

PRE-TEST

PR

E-T

ES

TM

PI S

PE

C'S

PO

ST

-TE

ST

Report Ref.:

Tape No. : Date Sheet 1 of 1

DIVER COLOUR B &W S I T Other

Subjects :

Tape Time Remarks

Count

INSPECTION REPORT VIDEO LOGPage No.




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