Giới thiệu Quy trình Quản lý, kiểm soát ăn mòn trên các công trình khai thác dầu khí ngoài khơi của công ty dầu khí Petronas. Chiến lược quản lý ăn mòn bao gồm công tác đánh giá rủi ro do ăn mòn, thiết kế, lựa chọn vật liệu phù hợp, khảo sát, giám sát ăn mòn, phân tích số liệu và lập báo cáo, v.v...
PETRONAS TECHNICAL STANDARDS DESIGN AND ENGINEERING PRACTICE TECHNICAL, PROCEDURAL AND SPECIFICATIONS CORROSION MANAGEMENT PTS 30.00.10.39 MARCH 2010 2010 PETROLIAM NASIONAL BERHAD (PETRONAS) All rights reserved No part of this document may be reproduced, stored in a retrieval system or transmitted in any form or by any means (electronic, mechanical, photocopying, recording or otherwise) without the permission of the copyright owner PTS 30.00.10.39 March 2010 Page ii 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, it is expected of 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 owner The right to use PTS rests with three categories of users: 1) 2) 3) PETRONAS and its affiliates Other parties who are authorised to use PTS subject to appropriate contractual arrangements 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 PTS 30.00.10.39 March 2010 Page iii TABLE OF CONTENTS INTRODUCTION 1.1 SCOPE 1.2 DISTRIBUTION AND INTENDED USE 1.3 DEFINITIONS 1.4 ABBREVIATION 1.5 CROSS-REFERENCES 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 CORROSION MANAGEMENT PLAN 3.1 CONTENT OF CMP 3.2 UPDATING OF CMP APPENDIX APPENDIX 11 PTS 30.00.10.39 March 2010 Page 1 INTRODUCTION 1.1 SCOPE The scope of this philosophy is to set the summary of strategy for Corrosion Management (CM) within PETRONAS 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 PETRONAS 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 document is restricted to companies forming part of or managed by the PETRONAS Group and, where necessary, to Contractors and Manufacturers nominated by them This PTS is intended for use in oil and gas production facilities When PTSs are applied, a Management of Change (MOC) process should be implemented; this is of particular importance when existing facilities are to be modified If national and/or local regulations exist in which some of the requirements may be more stringent than in this PTS, the Contractor shall determine by careful scrutiny which of the requirements are the more stringent and which combination of requirements will be acceptable as regards safety, environmental, economic and legal aspects In all cases the Contractor shall inform the Principal of any deviation from the requirements of this PTS which is considered to be necessary in order to comply with national and/or local regulations The Principal may then negotiate with the Authorities concerned with the object of obtaining agreement to follow this PTS as closely as possible PTS 30.00.10.39 March 2010 Page 1.3 1.4 1.5 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 Appendix 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 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 ABBREVIATION CM - Corrosion Management CMP - Corrosion Management Plan CO2 - Carbon Dioxide CP - Cathodic Protection CRA - Corrosion Resistant Alloy(s) H2S - Hydrogen Sulphide PRBI - PETRONAS Risk Based Inspection SRB - Sulphate Reducing Bacteria UT - Ultrasonic Thickness (Measurements) CROSS-REFERENCES Where cross-references to other parts of the documents are made, the referenced section number is shown in brackets Documents referenced in this document are covered in each "reference to work instruction" section PTS 30.00.10.39 March 2010 Page 1.6 SUMMARY OF CHANGES SINCE PREVIOUS EDITION The previous edition of this PTS was dated November 1995; a summary of the main changes since the last edition is given below Section Change 2.5 Removed reference to WinCairs and Corrosion Management System (CMS) database New section describing the requirements for Corrosion Management plan (CMP) A2.2 Include reference to PTS PTS 39.01.10.11: Selection of Materials for Life-Cycle Performance 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 PETRONAS 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 A1.2.1 and A1.2.2 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 (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 PETRONAS Corrosion Engineers (A1.2.1) PTS 30.00.10.39 March 2010 Page 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 A1.2.1, A1.2.2, A1.2.3 and A1.2.4 and their associated references PTS 30.00.10.39 March 2010 Page 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 A1.2.2 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 Responsibilities for data handling and storage are covered in detail in A1.2.1 and A1.2.2 and their associated references PTS 30.00.10.39 March 2010 Page CORROSION MANAGEMENT PLAN A specific Corrosion Management Plan (CMP) should be developed for each facility or group of facilities to address some of the requirements in (2) CMP is a comprehensive document which describes the technical basis and important information regarding materials selection, corrosion control and monitoring, inspection and corrosion related incident prevention of a facility 3.1 CONTENT OF CMP A CMP document should, as minimum requirement, contain the followings; 3.2 • Detail of Corrosion Risk Assessment including the philosophy adopted, detail of Corrosion Study describing specific corrosion threat to a facility/system/asset and the expected corrosion rate, Risk Rating of an asset highlighting the driving factors, etc • Basis for material selection highlighting specific issues relating to corrosion including potential problem area, recommendations for repair or replacement taking into consideration future process changes, assumption and uncertainties • Corrosion Control and Corrosion Incident Prevention This includes corrosion inhibitor treatments (injection rate, frequency and location), pipeline pigging frequency, critical process conditions, cathodic protection method and estimated life, protective coatings and its estimated life, etc • Corrosion Monitoring which details out the corrosion monitoring devices, showing type and suggested frequency of monitoring, sampling locations and chemical analysis for identification of corrosive agents, pipeline internal inspection, cathodic protection monitoring methods, etc • Recommendation on inspection method, coverage and frequency • Responsibilities of key personnel and recommendation on Key Performance Indicators specific to Corrosion Control & Monitoring UPDATING OF CMP CMP is a live document and should be regularly updated at defined intervals The needs for updating may be due to change in process parameters, availability of previously unknown information, validity of assumptions, change in risk distribution, incorporating recent monitoring data, etc PTS 30.00.10.39 March 2010 Page APPENDIX CM DOCUMENTS TABLE OF CONTENTS A1.1. GENERAL 8 A1.2. CM DOCUMENTS 8 A1.2.1. Development of Corrosion Management for New Projects (ref 1) 8 A1.2.2. Corrosion Management Guidelines (Sweet Facilities) (ref 2) 8 A1.2.3. Monitoring of Internal Corrosion in Oil and Gas Process Vessels and Pipework (ref 3) 9 A1.2.4. Baseline UT Monitoring (ref 4) 9 A1.2.5. Corrosion Inhibition of Downhole Production Tubing, Process Piping and Pipelines (ref 5) 9 A1.2.6. Selection of Corrosion Inhibitor System for Downhole Production Tubing, Process Piping and Pipelines (ref 6) 9 A1.2.7. Selection and Set-Up of Laboratory Test Methods for Corrosion Inhibitors for Sweet Oil and Gas Production and Transport (ref 7) 9 A1.3. REFERENCES 9 PTS 30.00.10.39 March 2010 Page A1.1 GENERAL The hierachy of the corrosion management documents referenced here is given in Figure A1.2 CM DOCUMENTS A1.2.1 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 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 A1.2.2 may cover all the necessary CM requirements; the project team shall assess if it is applicable If the development is sour, A1.2.2 will not be applicable, and a project specific document shall be produced If the development uses CRA's, then A1.2.2 will not be applicable in all cases and a project specific document shall be produced A1.2.2 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 Usage and Inhibitor Residuals • Pigging Sample Analysis • External Above Water Corrosion - Coating Inspection • Internal Pressure Vessel Inspection • Internal Pipeline Corrosion • External Underwater Inspection Failure Analysis PTS 30.00.10.39 March 2010 Page A1.2.3 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) A1.2.4 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 A1.2.5 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 engineer/pipeline engineer can assess what the general corrosion risks are and what general type of inhibitor should be used A1.2.6 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 A1.2.7 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 A1.3 REFERENCES Development of Corrosion Management for New Projects, SEP 47.2 Corrosion Management Guidelines (Sweet Facilities) EDG XW 1003 Monitoring of Internal Corrosion in Oil and Gas Process Vessels and Pipework, SES 48.1 Baseline UT Monitoring, Procedure EDP XW 100l Corrosion Inhibition of Downhole Production Tubing, Process Piping and Pipelines, SEP 47.3 Selection of Corrosion Inhibitor Systems for Downhole Production Tubing, Process Piping and Pipelines, Guideline : ECG.XXX.400l 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 Sulphide Stress Cracking Resistant Metallic Materials for Oilfield Equipment, NACE Standard MROl75 PTS 30.00.10.39 March 2010 Page 10 Corrosion Management (CM) SEP 47.1 Development of CM SEP 47.2 Ref Monitoring of Internal Corrosion Baseline UT Monitoring SEP 48.1 Ref EDP.XW.1001 Ref Corrosion Inhibition of Downhole Production Tubing, Process Piping and Pipelines SEP 47.3 Ref Selection of Corrosion Inhibitor System Laboratory Test Methods for Corrosion Inhibitors ECG.XXX.4001 Ref SEP 48.1 Ref CM Guideline (Sweet Facilities) EDG.XW.1003 Ref CM Guidelines (Sour Facilities) CM Guidelines (New Projects) Note FIGURE 1: HIERARCHY OF CORROSION MANAGEMENT DOCUMENTS NOTE: For new projects that not fall exactly under any existing CM Guidelines Key documents are shown in bold; supporting documents are in normal font PTS 30.00.10.39 March 2010 Page 11 APPENDIX SELECTION OF COMMONLY USED MATERIAL DESIGN OPTIONS TABLE OF CONTENTS A2.1 GENERAL 12 A2.2 MATERIAL DESIGN OPTIONS 12 PTS 30.00.10.39 March 2010 Page 12 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 More detailed approached can be obtained in PTS 39.01.10.11: Selection of Materials for Life-Cycle Performance ... happening at the metal surface ABBREVIATION CM - Corrosion Management CMP - Corrosion Management Plan CO2 - Carbon Dioxide CP - Cathodic Protection CRA - Corrosion Resistant Alloy(s) H2S - Hydrogen... 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. .. Development of Corrosion Management for New Projects (ref 1) 8 A1.2.2. Corrosion Management Guidelines (Sweet Facilities) (ref 2) 8 A1.2.3. Monitoring of Internal Corrosion