PETRONAS TECHNICAL STANDARDS

DESIGN AND ENGINEERING PRACTICE

MANUAL

CORROSION MANAGEMENT

PTS 20.208
NOVEMBER 1995
 PREFACE

PETRONAS Technical Standards (PTS) publications reflect the views, at the time of publication,
of PETRONAS OPUs/Divisions.

They are based on the experience acquired during the involvement with the design, construction,
operation and maintenance of processing units and facilities. Where appropriate they are based
on, or reference is made to, national and international standards and codes of practice.

The objective is to set the recommended standard for good technical practice to be applied by
PETRONAS' OPUs in oil and gas production facilities, refineries, gas processing plants, chemical
plants, marketing facilities or any other such facility, and thereby to achieve maximum technical
and economic benefit from standardisation.

The information set forth in these publications is provided to users for their consideration and
decision to implement. This is of particular importance where PTS may not cover every
requirement or diversity of condition at each locality. The system of PTS is expected to be
sufficiently flexible to allow individual operating units to adapt the information set forth in PTS to
their own environment and requirements.

When Contractors or Manufacturers/Suppliers use PTS they shall be solely responsible for the
quality of work and the attainment of the required design and engineering standards. In
particular, for those requirements not specifically covered, the Principal will expect them to follow
those design and engineering practices which will achieve the same level of integrity as reflected
in the PTS. If in doubt, the Contractor or Manufacturer/Supplier shall, without detracting from his
own responsibility, consult the Principal or its technical advisor.

The right to use PTS rests with three categories of users :

1) PETRONAS and its affiliates.

2) Other parties who are authorised to use PTS subject to appropriate contractual
arrangements.
3) Contractors/subcontractors and Manufacturers/Suppliers under a contract with
users referred to under 1) and 2) which requires that tenders for projects,
materials supplied or - generally - work performed on behalf of the said users
comply with the relevant standards.

Subject to any particular terms and conditions as may be set forth in specific agreements with
users, PETRONAS disclaims any liability of whatsoever nature for any damage (including injury
or death) suffered by any company or person whomsoever as a result of or in connection with the
use, application or implementation of any PTS, combination of PTS or any part thereof. The
benefit of this disclaimer shall inure in all respects to PETRONAS and/or any company affiliated
to PETRONAS that may issue PTS or require the use of PTS.

Without prejudice to any specific terms in respect of confidentiality under relevant contractual
arrangements, PTS shall not, without the prior written consent of PETRONAS, be disclosed by
users to any company or person whomsoever and the PTS shall be used exclusively for the
purpose they have been provided to the user. They shall be returned after use, including any
copies which shall only be made by users with the express prior written consent of PETRONAS.
The copyright of PTS vests in PETRONAS. Users shall arrange for PTS to be held in safe
custody and PETRONAS may at any time require information satisfactory to PETRONAS in order
to ascertain how users implement this requirement.
REVISION REGISTER

Rev. No. Date Details of Revision

A 7/95 Preliminary Draft for Comments. No registered distribution.
0 11/95 Initial issue

CONTROLLED DISTRIBUTION LIST

Copy No Registered Holder Date Distributed

1 lOS/Si 30 November, 1995
2 EDVIl 30 November, 1995
3 ETSI5 30 November, 1995
4 EDV/3 30 November, 1995
6 ETS/6 30 November, 1995
7 EDV/5 30 November, 1995
9 EGP/2 30 November, 1995
10 EGP/3 30 November, 1995
17 EPO/1 30 November, 1995
27 ETS/3 30 November, 1995
28 ETS/4 30 November, 1995
31 OPM/4 30 November, 1995
35 OPM/1/2 30 November, 1995
36 OTS/5 30 November, 1995
55 OPM/44 30 November, 1995
58 ETS 30 November, 1995
TABLE OF CONTENTS

1. INTRODUCTION

1.1 SCOPE

1.2 DISTRIBUTION AND INTENDED USE

1.3 DEFINITIONS

1.4 ABREVIATIONS

1.5 CROSS REFERENCES

2. STRATEGY

2.1 CORROSION RISK ASSESSMENT

2.2 MATERIALS AND DESIGN

2.3 INSPECTION AND MONITORING

2.4 ANALYSIS AND REPORTING

2.5 DATA HANDLING AND STORAGE

3. REFERENCES

APPENDIX 1 - CM DOCUMENTS

APPENDIX 2 - SELECTION OF COMMONLY USED MATERIAL

DESIGN OPTIONS
1. INTRODUCTION

1.1 SCOPE

The scope of this philosophy is to set the overall strategy for Corrosion Management (CM)
within the COMPANY. CM covers:

• ensuring that the risks to personnel, the environment and production facilities from
corrosion related failures are kept as low as is reasonably practical.

• providing a cost effective mechanism for controlling corrosion to maximise the life cycle
cash flow for all assets of the COMPANY both sub-surface and surface, from the
reservoir to the point of sale.

• putting sufficient monitoring systems and analysis techniques in place to demonstrate that
CM is being achieved.

• data management and data custodianship for the lifetime of the production facilities.

• feed forward to the Asset Holder/Custodian/Service Provider of the operational

constraints implied by the materials and corrosion approach chosen at the design stage.
This is of particular importance where the materials of construction chosen are expected
to corrode and activities during day to day operations can greatly influence the
achievement, or not, of the intended design life.

• feed back of corrosion monitoring data to the Asset Holder/Custodian/Service Provider in

order to carry out a condition based monitoring approach. Feed back of corrosion
monitoring data and data on materials performance to new design projects, to ensure that
new designs are not under or over conservative.

There are a number of lower level documents covering specific aspects of CM. A general
overview of these documents is given (Appendix 1), to guide the user to the correct reference.

This document applies to all existing and all future facilities.

1.2 DISTRIBUTION AND INTENDED USE

Unless otherwise authorised by PETRONAS, the distribution of this PTS is confined to

companies forming part of PETRONAS group and to Contractors nominated by them.

The philosophy is intended for use in oil and gas production facilities.
1.3 DEFINITIONS

Asset Holder - Person who is ultimately responsible for that asset. This person has
financial responsibility for all funds spent on that asset. (For a more
rigorous definition see ref. 1)
Asset Custodian - Person authorised by the asset holder to perform the day to day
operation of that asset.
Service Provider - Principal Person authorised by the asset holder to carry out specific
maintenance and inspection tasks on that asset arising from CM
activities.
COMPANY - PETRONAS
Corrosion - The destruction of a material (most commonly a metal), or its
properties, due to an electrochemical reaction with its immediate
environment or surroundings.
Erosion - The destruction of a material (most commonly a metal), by abrasion or
attrition caused by the flow of liquid or gas with or without the additional
factor of suspended solids.
Inspection - Direct physical measurement or visual observation of the condition of
the system (e.g. wall thickness survey, internal vessel inspection).
Monitoring - Indirect measurement of the condition of the system e.g. dewpoint
monitoring, process condition monitoring etc.). Note corrosion
coupons and probes are usually defined as "monitoring" devices rather
than inspection devices since they may not exactly measure the
corrosion happening at the metal surface.

1.4 ABBREVIATION

CM - Corrosion Management
CMS - Corrosion Management System (a PETRONAS Common System).
Computer System used for storing all corrosion monitoring data and all fixed
data required for corrosion analysis
CO2 - Carbon Dioxide
CP - Cathodic Protection
CRA - Corrosion Resistant Alloy(s)
H2S - Hydrogen Sulphide
SRB - Sulphate Reducing Bacteria
UT - Ultrasonic Thickness (Measurements)
WinCairs - Computer Aided Inspection Reporting System (previously called CAIRS):
Computer System currently in use for storing all UT data, and the offshore
CP data.

1.5 CROSS-REFERENCES

Where cross-references to other parts of the documents are made, the referenced section
number is shown in brackets. General References are included (3.0). Other documents
referenced in this document are covered in each "reference to work instruction" section.
2. STRATEGY

2.1 CORROSION RISK ASSESSMENT

On individual facilities a corrosion assessment shall be carried out, which identifies the
corrosion regimes expected, the critical items of equipment and the potential hazards from
loss of containment. The assessment shall also identify how the corrosion mechanisms
change over the field life or for particular operating conditions (e.g. start up, shutdown, well
acidisation etc.).

During the design phase, this assessment is used by the project team to select the materials
against (2.2). During the operational phase, this assessment is used by the COMPANY
Corrosion Engineers to review the corrosion monitoring data against, and to assess whether a
facility is suitable for any changes in operating conditions. This is covered in detail in Al .2.1
and Al .2.2 and their associated references.

2.2 MATERIALS AND DESIGN

Based on the corrosion risk assessment (2.1), the materials and design features shall be
selected to control the corrosion mechanisms identified. This shall cover both normal
operations and special operating conditions. The main design options are given in Appendix
2 (though this does not exclude other options being considered).

Where there are a choice of approaches, an economic appraisal based on the life cycle costs
needs to be carried out (e.g. use of carbon steel with corrosion inhibitors needs to also
consider the cost of inhibition and monitoring throughout the life of the facility).

The selection process shall be carried out by the project team, and reviewed with the
COMPANY Corrosion Engineers (Al .2.1).

2.3 INSPECTION AND MONITORING

The inspection and monitoring required shall be based on the corrosion risk assessment (2.1)
and the materials and design (2.2). The following shall be documented:

The corrosion inspection and monitoring Systems provide:-

• the reasons for the selection of the inspection and monitoring systems and the
inspection and monitoring locations.
• the frequency of inspection and monitoring operations.
• what constitutes an anomaly in the inspection and monitoring data (i.e. the alarm
points).

In selecting the most applicable inspection and monitoring techniques, the following guidance
shall be considered:-

• no single corrosion monitoring technique can be relied upon to monitor a system. Each
individual technique has its disadvantages and advantages. A variety of techniques
should be employed and the data compared in order to give a true picture of the state of
the system being monitored. The type of monitoring will depend on the corrosion,
mechanism expected (e.g. general corrosion, pitting, sulphide corrosion cracking,
hydrogen induced cracking, etc.).
 • for corrosion to occur, the four constituents of the corrosion cell must be present -anode,
cathode, electrolite, current path. If the corrosion in the system is controlled by removal
of one of the required constituents in the corrosion cell, sufficient monitoring is required to
ensure that the control system functions continuously. For example in dry gas systems
corrosion is controlled by removal of the electrolite (water). Dewpoint monitoring is carried
out to ensure that this corrosion control system functions.

• if CRA are used, an acceptable monitoring approach is to verify the operating envelope of
the material, either by a review of published data, or by carrying out laboratory testing at
worst case conditions, then monitor the process conditions to verify that the process
environment stays within the tested operating envelope. Note that there are a number of
applications where carbon steel acts as a CRA (i.e. the service is non-corrosive) and this
approach can be used. The monitoring of the process conditions, should be backed up by
a minimal level of inspection and/or monitoring techniques (e.g. corrosion coupons)

• if carbon steel is used in a corrosive service a baseline inspection survey is required,

followed-up by a full second survey after a period of operation to confirm that the carbon
steel is not corroding any more than expected. Subsequent inspection frequency will be
on a condition based approach, as detailed in the lower level documents (Appendix 1).

• in developing the inspection and monitoring plan, there should be a clear definition of
inspection and monitoring required for corrosion management and any inspection and
monitoring required for statutory requirements, so that the bounds of any condition based
analysis of inspection and monitoring frequency are clearly understood.

• the inspection and monitoring techniques and frequency of inspection and monitoring
needs to be matched with the accessibility and mode of operation of the facility. For
example if a platform is designed to be not normally manned, a monitoring system which
requires weekly manual data collection on-site is not suitable and automation would be
required.

Responsibilities for developing the inspection and monitoring plan and carry out the inspection
and monitoring in the operation phase are covered in detail in Al .2.1, Al .2.2, Al .2.3 and Al
.2.4 and their associated references.

2.4 ANALYSIS AND REPORTING

Data analysis covers comparison of the data against the defined anomaly limits (2.3). For
some types of monitoring individual data points have little meaning, and the analysis process
is looking for long term trends (e.g. changes in water composition, indicating corrosion
problems). For all the monitoring tasks, any anomalies identified shall be quickly highlighted
to the Asset Custodian and Service Provider for any necessary remedial action to be carried
out. A routine report shall also be produced at the end of each survey for the Asset Custodian
and Service Providers detailing the anomalies, as well as all systems that are in an
acceptable condition. On an annual basis a summary report shall be produced for the Asset
Holder. The majority of the analysis and reporting tasks are supported by the database
Systems (2.5).

Responsibilities for analysis and reporting are covered in detail in Al .2.2 and the associated
references

2.5 DATA HANDLING AND STORAGE

This shall be governed by the following guidelines. The long term aim is to produce system
whereby:-
• data is only handled once. For example, process data (pressures, temperatures and flow
rates) already entered in an Operations database should not have to be manually
reentered into a corrosion database to carry out a required analysis process; the data
should be electronically captured and transferred from one system to another or kept in a
central database accessed by all required end user databases. This is to minimise errors
and data entry time.

• routine analysis work and reports are carried out by the database Systems, not manually.

• comparison of the results of a variety of monitoring techniques used for a facility can be
quickly and readily carried out.

• monitored data is collected and reported in an electronic form that can be directly
uploaded into the corrosion database.

• standard naming conventions and coding standards are used to facilitate easy data
transfer between systems.

• for a given type of monitored data, the analysis should be standard, regardless of who
collects the data or who carried out the analysis.

• data is stored with adequate back ups for the lifetime of the facility.

• the systems have the ability to feed forward CM data to new designs to optimise the
design tools.

Two systems have been identified which together will achieve these aims:

• WinCairs database, designed for front end data collection, use by an external contractor
and for preliminary data analysis. It is initially used for some of the UT and CP data, but
can be easily extended to cover all the UT and CP data, plus in addition corrosion coupon
and probe data.

• the Corrosion Management System (CMS) database, designed for data storage, analysis
and reporting of all types of monitoring data, multi-user capability, direct linking to other
databases, storage of fixed data to facilitate analysis work, monitoring work scheduling.
CMS will become operational in early 1996 in the areas of UT and CP (linking to
WinCairs), with extension into all other areas over the next two years.

Until these systems are in place, because of limitations of time and manpower only routine
analysis can be carried out. The analysis is conservative and monitoring is based on fixed
time intervals. With the above systems in place more detailed analysis will be possible and
monitoring will be based on the condition of the system.

Responsibilities for data handling and storage are covered in detail in Al .2.1 and Al .2.2 and
their associated references.
 APPENDIX 1

CM DOCUMENTS

TABLE OF CONTENTS

Al.1 GENERAL

Al .2 CM DOCUMENTS

Al .2.1 Development of Corrosion Management

Al .2.2 General Corrosion Management Operations Manual
Al .2.3 Monitoring of Internal Corrosion in Oil and Gas Process Vessels and Pipework
Al .2.4 Baseline UT Monitoring
Al .2.5 Corrosion Inhibition of Downhole Production Tubing, Process Piping and Pipelines
Al .2.6 Selection of Corrosion Inhibitor Systems for Downhole Production Tubing, Process Piping and
Pipelines
Al .2.7 Selection and Set-Up of Laboratory Test Methods For Corrosion Inhibition for Sweet Oil and
Gas Production and Transportation

Al.3 REFERENCES
Al.1 GENERAL

The Hierachy of the corrosion management documents referenced here is given in figure 1.

Al .2 CM DOCUMENTS

Al .2.1 Development of Corrosion Management for New Projects (ref. 1)

This philosophy covers the instructions to the project team for new development on what they
have to do to meet the requirements of 2.1 through 2.5 for their particular facilities; The
deliverable will be a Corrosion Management Guideline for that particular facility.

If the development is a sweet development then Al .2.2 may cover all the necessary CM
requirements; the project team shall assess if it is applicable. If the development is sour, Al
.2.2 will not be applicable, and a project specific document shall be produced. If the
development uses CRA's, then Al .2.2 will not be applicable in all cases and a project specific
document shall be produced.

Al .2.2 Corrosion Management Guidelines (Sweet Facilities) (ref. 2)

The intent is to document CM practices for operating facilities which produce, transport, or
process sweet gas and/or oil. It is written to meet the CM needs of all existing facilities
constructed prior to the MLNG-DUA project. The CM Guideline meets all the requirements of
SEP 47.1. For CM practice it covers what is done, why it is done, how it is done, who does it
and how often it is done. The intent is to document all the practices currently in use. One of
the aims of this is to ensure that all the practices can be assessed (all together) by a wider
audience. For Corrosion Risk Assessment (2.1), all these systems can be classified as:

• sweet production with only moderate levels of CO2 (up to 12% CO2)
• low levels of produced H2S (less than the levels required to be classified as "sour gas"
(ref. 8))
• most of the oil systems (piping, pipelines and vessels) are currently contaminated with
SRB
• some aging oil production systems with increasing water cuts
• gas export pipelines designed as "dry gas" pipelines

The CM practices covered in this document are:-

• CP surveys from above water/onshore pipelines and structures

• Keypoint surveys (UT Monitoring)
• Process corrosion monitoring (coupons and probes)
• Corrosion Inhibition - Monitoring Useage and Inhibitor Residuals
• Pigging Sample Analaysis
• External Above Water Corrosion - Coating Inspection
• Internal Pressure Vessel Inspection
• Internal Pipeline Corrosion
• External Underwater Inspection Failure Analysis
Al .2.3 Monitoring of Internal Corrosion in Oil and Gas Process Vessels and Pipework (ref. 3)

This specification covers the precise technical requirements for monitoring equipment (e.g.
approved corrosion access fittings and details of how and where to install them).

Al .2.4 Baseline UT Monitoring (ref. 4)

This guideline covers the selection of keypoints for UT surveys. For new projects the selection
work should be carried out by the project engineers who have been involved with 2.1 and 2.2.

Al .2.5 Corrosion Inhibition of Downhole Production Tubing, Process Piping and Pipelines (ref. 5)

This philosophy covers a review of all the flow regimes likely to be found in oilfield production
and transportation systems, their corrosion risk and the applicable methods of inhibition. With
this document, the corrosion engineer/process engneer/pipeline engineer can assess what
the general corrosion risks are and what general type of inhibitor should be used.

Al .2.6 Selection of Corrosion Inhibitor System for Downhole Production Tubing, Process
Piping and Pipelines (ref. 6)

This specification covers the overall process and the responsibilities for selection of an
inhibitor. This document is written to set-up the organisation for an inhibitor test programme.

Al .2.7 Selection and Set-Up of Laboratory Test Methods for Corrosion Inhibitors for Sweet Oil
and Gas Production and Transport (ref. 7)

This report covers the choice of the applicable laboratory test method for selecting an inhibitor
for specific operating conditions.

Al .3. REFERENCES

1. Development of Corrosion Management for New Projects, SEP 47.2.

2. Corrosion Management Guidelines (Sweet Facilities) EDG . XW. 1003.

3. Monitoring of Internal Corrosion in Oil and Gas Process Vessels and Pipework, SES 48.1.

4. Baseline UT Monitoring, Procedure EDP. XW. 100l.

5. Corrosion Inhibition of Downhole Production Tubing, Process Piping and Pipelines, SEP 47.3

6. Selection of Corrosion Inhibitor Systems for Downhole Production Tubing, Process Piping
and Pipelines, Guidelline : ECG.XXX.400l

7. Selection and Set-Up of Laboratory Tests Methods for Corrosion Inhibitors for Sweet Oil and
Gas Production and Transport, KSLA Report, S.F. Keij, AMGR.95.263.

8. Sulphide Stress Cracking Resistant Metallic Materials for Oilfield Equipment, NACE Standard
MROl75.
 FIGURE 1

HIERARCHY OF CORROSION MANAGEMENT DOCUMENTS

NOTE 1: Future document. The MLNG-Dua project is a sour development and is producing a project specific CM Guidelines; this may later be
generalised to a CM Guidelines for sour facilities.

NOTE 2: Future deliverable for new projects that do not fall exactly under any existing CM Guidelines.

Key documents are shown in bold; supporting documents are in normal font.
 APPENDIX 2

SELECTION OF COMMONLY USED MATERIAL DESIGN OPTIONS

TABLE OF CONTENTS

A2.1 GENERAL

A2.2 MATERIAL DESIGN OPTIONS

A2.1 GENERAL

The main design options are given below. This list should not be considered exclusive -other
options can be considered.

A2.2 MATERIAL DESIGN OPTIONS

• carbon steel with a minimal corrosion allowance (1 mm). Suitable for Systems that are
not corrosive, even under upset conditions (e.g. dry gas plant).

• carbon steel with a moderate corrosion allowance (usually 3mm), used in conjunction with
corrosion inhibitors. Suitable for systems where inhibitor performance can be guaranteed
and where inhibitor supply and injection is not problematic.

• carbon steel with a large corrosion allowance (≥ 3mm), allowing the system to corrode.
Suitable for systems that are moderately corrosive and have limited life.

• corrosion resistant alloys (CRA), with minimal (or no) corrosion allowance. Suited to
corrosive systems where long life is required, where there are problems applying
inhibitors.

• non-metallic materials (e.g. GRE), that are not subject to corrosion under the operating
conditions. Particularly suited to low pressure liquid systems containing oxygenated
water (e.g. effluent lines, seawater lines), but can also be used safely at high pressures if
properly designed.