PROJECT:
IMPLEMENTATION OF ASSET INTEGRITY
MANAGEMENT IN ZUBAIR OIL FIELD
ASSET:
REV. NR.:
Pipelines, flowlines and
Trunklines.Error! Unknown document
property name.
00
REVISION
DATE:
29-01-2022
Page:
0 of 65
DEPARTMENT:
ASSET INTEGRITY
DOCUMENT TITLE:
RBI Methodology for Pipelines in Zubair Field
ABSTRACT
This document provides a semi-quantitative risk based inspection approach for assessing the
Zubair Field Pipelines. The Pof is determined by modifying the API581 and complement with
the Flowchart method and the Cof is determined by the aggregate method.
Revision Record
RINA
RBI Methodology for
Pipelines in Zubair Field
00
29-01-2022
Rev.
Date
AI Engineer
RINA
AI Engineer
Reason for Issue
Prepared
Checked
Approved
2021
RBI Methodology for Pipelines in
Zubair Field
Abstract:
This document provides a semi-quantitative risk based inspection
approach for assessing the Zubair Field Pipelines. The Pof is determined
by modifying the API581 and complement with the Flowchart method
and the Cof is determined by the aggregate method
Eng. Antonio M. N.L. Moura
12/27/2021
RBI Methodology for Pipelines in Zubair Field
Table of Contents
1.
Purpose and scope .......................................................................................................................... 2
1.1.
2.
3.
Zubair Field.............................................................................................................................. 2
Reference Documents..................................................................................................................... 4
2.1.
Company References .............................................................................................................. 4
2.2.
International References ........................................................................................................ 4
2.3.
Other ....................................................................................................................................... 5
Terms and Definitions ..................................................................................................................... 5
3.1.
Definitions ............................................................................................................................... 5
3.2.
Acronyms ................................................................................................................................ 8
4.
Hierarchy of Regulations ................................................................................................................. 8
5.
Technical requirements .................................................................................................................. 9
5.1.
Methodology For Risk-Based Inspection Plan......................................................................... 9
5.2.
Threats/Hazards Identification ............................................................................................. 12
5.3.
Degradation Mechanisms ..................................................................................................... 14
5.4.
Sectioning of pipeline System ............................................................................................... 14
5.5.
Likelihood .............................................................................................................................. 14
5.6.
Consequence ......................................................................................................................... 17
5.7.
Inspection plan and associated interval of frequency .......................................................... 23
Appendix 1 Guidance for likelihood assessment .................................................................................. 27
Corrosion............................................................................................................................................... 27
Thinning Damage Factor ................................................................................................................... 28
External Damage Factor (Atmospheric) ............................................................................................ 31
Third-party threats ................................................................................................................................ 34
Structural .............................................................................................................................................. 36
Appendix 2 Corrosion Rates Model ...................................................................................................... 43
MIC Microbiologically Induced Corrosion ......................................................................................... 44
Erosion Corrosion.............................................................................................................................. 45
CO2 Corrosion ................................................................................................................................... 46
Appendix 3 Inspection / Maintenance Tasks ........................................................................................ 49
Appendix 4 Preventive Barrier .............................................................................................................. 52
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RBI Methodology for Pipelines in Zubair Field
1. Purpose and scope
The purpose of this document is to provide a methodology for the identification of the threats or
hazards possible to affect the flowlines, trunklines and pipelines associated with Zubair Filed and
under the responsibility of the ZFOD asset Integrity Department. It will provide, based on the riskbased approach, the methodology/procedure that allows the determination of the relative risk of each
asset. And will provide guiding in the selection of the most adequate inspection and maintenance
activities to perform and allows to assess the most adequate inspection plan for the assets under
analysis.
1.1.
Zubair Field
The Zubair field is located in the southern area of Iraq, 20 km far from Basra city (See the figure below).
The Zubair Field comprises four domes named respectively (From N to S), Hammar, Shuaiba, Rafdhyia,
and Safwan. The southernmost dome, Safwan, partially extends beyond Iraq’s border and into Kuwait,
where it is known as Abdalli Field. The structure of the Zubair Field is a relatively gentle anticlineoriented NNW - SSE, approximately 60 km long and 10-15 km wide.
Figure 1 - Zubair Field Location (area outlined in green)
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RBI Methodology for Pipelines in Zubair Field
The first discovery was in 1949, the field has been in operation since 1951. There is a significant
existing infrastructure that includes several existing production stations distributed around the field
in addition to IPFs located in Zubair, Hammar and Rafdhyia.
The field is composed of wellheads areas, manifolds, flowlines and different DGSs/IPFs as follows:
• Hammar Mishrif DGS
• Hammar DGS and IPF
• Zubair DGS and IPF
• Zubair Mishrif DGS
• Rafdhyia DGS and IPF
• Safwan DGS
• DGS North
• PPG – Permanent Power Generation.
All Plants shall accommodate process, utilities, storage, transfer pumps, power generation system,
firefighting system, etc.
Each DGS receives crude oil from peripherals oil wells; the crude oil arriving inside the DGS is treated
through process separators and then stored into oil flow tanks. After, the treated oil is sent to the MPS
(Main Pumping Station) through export pumps.
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RBI Methodology for Pipelines in Zubair Field
2. Reference Documents
2.1. Company References
#
1
2
Ref. code
20415.ENG.INT.PRG
02961.ENG.COR.PRG
3
23038.ENG.INT.REL
4
28050.ENG.INT.REL
5
6
7
28755.ENG.INT.PRG
28756.ENG.INT.PRG
23037.ENG.INT.STD
Title
“Criteria for Risk Based Inspections”
“Guidelines for Risk Based Inspections”
“Risk Based Identification of Potential Critical conditions for
offshore Pipelines Integrity Management”
“Risk Based Identification of Potential Critical Conditions for
onshore Pipelines Integrity Management”
“Exposure Levels of Onshore and Offshore Pipelines”
“Risk analysis methodology for Pipelines RBI program”
“External Survey of Pipelines in The Onshore Area”
2.2. International References
#
Ref. code
8
ASME B31.4
9 ASME B31.8
10 ASME B31.8S
11 ASME B31G
12 DNVGL-RP-F101
13 DNVGL-RP-F107
14 DNVGL-RP-F116
15 DNV-RP-G101
16 ISO 16708
17 ISO 19900
18
19
20
21
22
API 1160
API 1163
API RP 580
API RP 581
API RP 579
23 API RP 571
Title
“Pipeline Transportation System for Liquid Hydrocarbons and
Other Liquids”
“Gas Transmission and Distribution. Piping Systems”
“Managing System Integrity of gas pipelines”
“Manual for Determining the Remaining Strength of Corroded
Pipelines”
“Corroded Pipelines”
“Risk assessment of Pipeline protection”
“Integrity management of submarine pipeline system”
“Risk Based Inspection of Offshore Topsides Static Mechanical
Equipment”
“Petroleum and Natural Gas industries – Pipeline
Transportation Systems, Reliability-based limit state
methods”
“Petroleum and natural gas industries – General
requirements for offshore structures”
“Managing System Integrity for Hazardous Liquid Pipeline”
“In-Line Inspection Systems Qualification Standard”
“Risk-based Inspection; 3rd Edition 2016”
“Risk-based Inspection Methodology, 3rd Edition 2016
“Fitness-for-service”
“Damage Mechanisms Affecting Fixed Equipment in the
Refinery Industry”
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RBI Methodology for Pipelines in Zubair Field
2.3. Other
# Ref. code
24 W. Kent Muhlabauer
25 NACE SP0502
26 NACE SP0206
27 NACE SP0208
Title
“Pipeline Risk Management Manual, 3rd Edition”
“Pipelines
External
Corrosion
Direct
Assessment
Methodology”
“Internal Corrosion Direct Assessment Methodology for
Pipelines Carrying Normally Dry Natural Gas (DG-ICDA)”
“Internal Corrosion Direct Assessment Methodology for
Liquid Petroleum Pipelines”
3. Terms and Definitions
The Company is ENI S.p.a or ZFOD or Both.
3.1. Definitions
Asset
Natural resources and all tangible and intangible investments to exploit and to
process them (Including crude oil extraction facilities, storage and import/export
facilities, hydrocarbon refining facilities, conversion and treatment facilities,
power plants and environmental treatment facilities). In this document “Asset”
means the physical portion of the assets.
Cathodic
Technique to reduce the corrosion of a metal surface by making that surface the
protection (CP) cathode of an electromechanical cell.
Component or An individual item or element fitted in line with pipe in a pipeline system, such as,
pipeline
but not limited to, valves, elbows, tees, flanges, and closures.
component
Consequence
The consequence of failure through the unintentional release of hazardous fluids,
of failure
including effects on Health and Safety, of employees, as well as of the public, to
the environment, to the operability of the asset and the company reputation.
Corrosion
Deterioration of a material, usually a metal, that results from an electrochemical
reaction with its environment.
Corrosion
Chemical substance or combination of substances that, when present in the
Inhibitor
environment or on a surface, prevents or reduces corrosion.
Corrosion rate Rate at which corrosion proceeds
Damage (type) The observed effect on a component of the action of a degradation mechanism.
The damage type gives rise to the failure mechanism of a component. Examples
of damage include cracking, uniform wall thinning, and pitting.
Damage Model A mathematical and/or heuristic representation of the results of degradation. This
may express the accumulation of damage over time as functions of physical or
chemical parameters, and normally includes the estimation of the conditions that
give rise to failure.
Defect
A physically examined anomaly with dimensions or characteristics that exceed
acceptable limits.
Design
All related engineering to design the pipeline including both structural as well as
material and corrosion.
Design Life
That period during which an item or component id intended to remain fit for
service under the specified design and operating process conditions.
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RBI Methodology for Pipelines in Zubair Field
Environment
Examination
Failure
Geographic
Information
System (GIS)
High
Consequence
Area
Imperfection
Incident
In-line
inspection (ILI)
Inspection
Integrity
Integrity
Assessment
leak
Maintenance
Maximum
allowable
operating
pressure
(MAOP)
Metal Loss
Mitigation
Monitoring
Surroundings or conditions (physical, chemical, mechanical) in which a material
exists.
Direct physical inspection of a pipeline that may include the use of non-destructive
examination (NDE)
Termination of the ability of a system, structure, or component to perform its
required function of containment of fluid (i.e., loss of containment). Failure may
be unannounced and undetectable until the next inspection (unannounced
failure) or may be announced and detected by any number of methods at the
instance of occurrence (announced failure). The point at which a component
ceases to fulfil its function and the limits placed on it. The failure condition must
be clearly defined in its relationship to the component. Failure can be express, for
example, in terms of non-compliance with design codes, or exceedance of a set
risk limit, neither of which necessarily imply leakage.
System of computer software, hardware, data, and personnel to help manipulate,
analyze, and present information that is tied to a geographic location.
Those locations where a pipeline release might have a significant adverse effect
on an unusually sensitive area, a high populated area, or a commercially navigable
waterway.
An anomaly with characteristics that do not exceed acceptable limits
Unintentional release of fluid due to the failure of a pipeline.
Any instrument device or vehicle that records data and uses non-destructive test
methods or other techniques to inspect the pipeline from the inside. These tools
are also known as intelligent pigs or smart pigs.
The use of a non-destructive testing technique aimed at measure, observe and
confirm the current conditions of an item.
Defines herein as the capability of the pipeline to withstand all anticipated loads
(including hoop stress due to operating pressure) plus the margin of safety.
Process that includes inspection of pipeline facilities, evaluating the indications
resulting from the inspections, examining the pipe using a variety of techniques,
evaluating the results of the examinations, characterizing the evaluation by defect
type and severity, and determining the resulting integrity of the pipeline through
analysis.
An uncontrolled fluid release from a pipeline. The source of the leak may be holes,
cracks (include propagation and no propagating, longitudinal, and
circumferential), Separation or pullout, and loose connections.
All activities designed to retain the pipeline system in a state in which it can
perform its required functions. These activities include inspections, surveys,
testing, servicing, replacement, remedial works and repairs.
Maximum pressure at which a pipeline system may be operated in accordance
with provisions of the construction code.
Types of anomalies in pipe in which metal has been removed from the pipe
surface, usually due to corrosion or gouging.
Limitation or reduction of the probability of occurrence or expected consequence
for a particular event.
Regular recording of operational data and other relevant data needed in order to
establish the current condition of a component and/or to analyze its rate of
degradation.
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RBI Methodology for Pipelines in Zubair Field
Nondestructive
examination
(NDE) or nondestructive
testing (NDT)
Operator
or
operating
company
Pig
Pig Trap
Testing method, such as radiography, ultrasonic, magnetic testing, liquid
penetrant, visual, leak testing, eddy current, and acoustic emission, or a testing
technique, such as magnetic flux leakage, magnetic particle inspection, shearwave ultrasonic, and contact compression-wave ultrasonic.
Individual, partnership, corporation, public agency, owner, agent, or other entity
current responsible for the design, construction, inspection, testing, operation,
and maintenance of the pipeline facilities.
Device run inside a pipeline to clean or inspect the pipeline, or to batch fluids.
An ancillary item of pipeline equipment, with associated pipework and valve, for
introducing a pig into a pipeline or removing a pig from a pipeline.
Pipe
A tubular product, including tubing, made for sale as a production item, used
primarily for conveying a fluid and sometimes for storage. Cylinders formed from
plate during fabrication of auxiliary equipment are not pipe as defined herein
Pipeline
All parts of physical facilities through which fluid moves in transportation,
including pipe, valves fittings. Flanges (including bolting and gaskets), regulators,
pressure vessels, pulsation dampeners, relief valves, appurtenances attached to
pipe, compressor units, metering facilities, pressure-regulating stations, pressurelimiting stations, pressure relief stations, and fabricated assemblies.
Pipeline
Management system designed to endure the safe operation of pipeline system in
Integrity
accordance with the design intent, by control of the physical condition of a
Management
pipeline, the operation conditions within the system an any changes made to the
System (PIMS) system.
Pipeline System Pipelines, stations, supervisory control and data acquisition system (SCADA),
safety systems, corrosion protection systems, and other equipment, facility or
building used in the transportation of fluids
Probability
Likelihood of an event occurring.
Right-of-way
A strip of land on which pipelines, railroads, power lines, roads, highways, and
(ROW)
other similar facilities are constructed. The ROW agreements secure the right to
pass over property owned by others. ROW agreements generally allow the right
of ingress and egress for the operation and maintenance or the facility, and the
installation of the facility. The ROW width can vary with the construction and
maintenance requirements of the facility’s operator and is usually determined
based on negotiation with the affected land-owner by legal action, or by
permitting authority.
Risk
Measure of potential loss in terms of both the incident probability (likelihood) of
occurrence and the magnitude of the consequences.
Risk
Systematic process in which potential hazards from facility operation are
Assessment
identified, and the likelihood and consequences of potential adverse events are
estimated. Risk assessments can have varying scopes, and can be performed at
varying levels of detail depending in the operator’s objectives.
Risk
Overall program consisting of identifying potential threats to an area or
Management
equipment; assessing the risk associated with those threats in terms of incident
likelihood and consequences; mitigating risk by reducing the likelihood, the
consequences, or both; and measuring the risk reduction results achieved.
Rupture
Complete failure of any portion of the pipeline that allows the product to escape
to the environment.
Service life
The time length the system is intended to operate
Segment
Length of pipeline or part of the system that has unique characteristics in a specific
geographic location.
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RBI Methodology for Pipelines in Zubair Field
Survey
Testing
Third-party
damage
Threat
Measurements, Inspections, or observations intended to discover and identify
events or conditions that indicate a departure from normal operation or
undamaged condition of the pipeline.
Applying a load to confirm a measurable property or function of a component or
a system.
Damage to a pipeline facility by an outside party other than those performing
work for the operator. This also includes damage caused by the operator’s
personnel or the operator’s contractors.
An indication of an impending danger or harm to the system, which may have an
adverse influence on the integrity of the system.
3.2. Acronyms
ALARP
BOP
CP
CoF
D
DA
DF
DFI
DMS
ECA
EI
EL
HAZID
HAZOP
HCA
I&M
ILI
IMP
LC
LCI
MFL
N.A.
NDT
PIM
PIMS
PoF
ROV
SCADA
UT
As Low as Reasonably Practical
Bottom of Pipe
Cathodic Protection
Consequence of Failure
External Diameter
Direct Assessment
Damage Factor
Design Fabrication Installation
Data Management System
Engineering Critical Assessment
Elevation
Exposure Level
HAZard Identification
HAZards and Operability issues analysis
High Consequence Area
Inspection and Maintenance
In Line Inspection
Inspection and Maintenance Plan
Location Class
Life Cycle Information
Magnetic Flux Leakage
Non-Applicable
Non-Destructive Test
Pipeline Integrity Management
Pipeline Integrity Management System
Probability Of Failure
Remote Operated Vehicle
Supervisory Control Data Acquisition
Ultrasonic Testing
4. Hierarchy of Regulations
The company has a hierarchy for the precedence of the documents as follows:
• Local Regulations of Iraq;
• Project Specifications and Data Sheets;
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RBI Methodology for Pipelines in Zubair Field
• Company General Specifications;
• International Codes & Standards
Should there be a perceived conflict between this document and the referenced standards or lack of
clear definition as to the applicability of this document, guidance should be sought in the reference
documents, following the hierarchy presented.
5. Technical requirements
5.1. Methodology For Risk-Based Inspection Plan
Introduction Risk Management
Risk management is defined as taking an action, whose aim is to identify, assess and control risks and
complete control of the action taken. The main objective of risk management, in the case of pipeline
systems, is to reduce the occurrence of a failure or when it occurs to limit its effects.
Evaluation of operational reliability is most often referred to as the problem of determining the
frequency of failure and its causes. Reliability by analogy to other systems can be defined as follows:
"The reliability of the piping system is a function of the fulfilment of the task delivery of the specified
medium in the required quantity and quality".
Adverse events are identified with a failure of system security that poses a threat to protected goods.
As a measure of safety, the level of risk is used that determines the likelihood of a hazard and
associated losses.
Pipeline systems damage cannot be completely eliminated. These are extensive systems consisting of
many separate subsystems operating in different changing conditions. The risk of failure is a common
phenomenon, but the determination of this risk and its management until it decreases to a
considerable extent the frequency of the failure and reduces the effects of their occurrence.
Risk Management is understood as taking activities aimed at:
• Recognition;
• Evaluation;
• Risk control;
• Control of actions taken.
The purpose of management is to reduce the risk and protect against its effects.
Risk Assessment is carried out using a variety of measures. Their choice depends on the type of risk
to be assessed. Using quantification, it is possible to identify these risk factors and special attention
should be paid to them.
Controlling is understood as an action to be taken to minimize the risk to the acceptable level. There
are two main approaches to risk control:
• Active which is based on the impact over the causes of the risk;
• Passive focusing upon prevention against possible losses.
Approach
A risk based inspection plan approach contributes to ensuring that the safety level premised in the
design phase is maintained throughout the design life of the pipeline system.
For application to pipeline systems, the risk assessment should:
• Identify the characteristics of the pipelines system under analysis
• Identify the potential threats which may affect the structural integrity of the pipeline system
and estimate the risk associated
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RBI Methodology for Pipelines in Zubair Field
• Identify risk reduction actions in case of unacceptable risk
• Identify risk managing actions in case of acceptable risk
• Provide the basis for long term integrity management planning
The output should be the provision of a frequency of intervention/inspection that allows tackling the
risk to an acceptable level (ALARP). As well as a risk ranking between threats affecting the pipeline
system.
Managing the risk related to the pipeline system threats is essential for maintaining the integrity of
the pipeline system.
Figure 2 - From threats to final consequence
Starting from the hazard analysis, risks arising from the identified threats shall be evaluated.
This is done by identifying possible failure mechanisms and estimating the associated likelihood and
the expected consequences. The results of the risk assessment shall be used to undertake actions to
take the risk of a system failure to a level as low as reasonably practicable.
Since inspection, test and maintenance activities contribute to control and minimize the risks, a
specific Inspection and Maintenance Plan shall be developed on the basis of the risk analysis outcomes.
The risk analysis is based on the following steps:
• Identification of the Threats to be considered, comprehensive of those to the pipeline system
operating phase and on threats that are not expected (not relevant).
• Subdivision of the system into sections (if applies)
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RBI Methodology for Pipelines in Zubair Field
•
•
•
•
•
•
•
Identification of threats for each section
Assessment of the potential cause and effects (damage/anomaly) related to the identified
threats
Evaluation of the applied design criteria, utilization factor and adopted protective means
Estimation of the Probability of Failure (PoF)
Estimation of the Consequence of Failure (CoF)
Estimation of Risk Level
Definition of minimum requirements for the Inspection and Maintenance Plan (type,
extension and frequency of the activities)
A semi-quantitative assessment for the risk is generally considered sufficient in the context of
pipeline integrity management for the development of the inspection plan.
The probability of failure is estimated and reviewed by means of the information available (project,
inspections, maintenance, etc.).
The consequences of a failure are dependent on the failure mode (major pipeline damage, leak, burst)
and physical location.
The mitigation measures implemented during the detail design phase are taken into account in the
evaluation of the failure probability and/or consequence severity.
The risk level associated with each identified threat is evaluated to identify the need for additional
mitigation measures and to support the definition of the inspection frequency.
The risk level is usually represented by means of matrixes having likelihood ranges against severity
levels of consequences. The intersection of the two considerations on the matrix provides an
estimation of the risk level for the various threats considered. The risk is the product of likelihood and
consequences.
The risk based approach for obtaining the inspection plan requires more data and risk analyses results
as basis and support. As an advantage, a risk based approach enables the operator to have a better
knowledge of the pipeline system, a greater degree of flexibility regarding inspection intervals, tools
used, and mitigation techniques employed.
In order to allow the application of the methodology, specific project data shall be collected.
The first stage involves compiling a detailed description of the pipeline system under consideration,
which includes all relevant pipeline details, such as:
• Pipeline mechanical design information
• Pipeline route
• Meteor ocean conditions
• Fluid composition data
• Environmental data (Seawater properties, Air temperature, wind, wave, etc.)
• Pipeline specification
• Pipeline operational data
• Soil data
• Bathymetry chart
• Cathodic protection design and data
Typical sources of information are the following documents but not limited to:
• Design premises and design codes
• Design and remnant life
• Layout drawings
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RBI Methodology for Pipelines in Zubair Field
•
•
•
•
•
•
•
•
•
•
•
•
•
•
P&IDs
Piping class specifications
Heat and material balances
Risk studies (i.e., HAZID and HAZOP)
Structural analysis
Datasheets
Operating data
Failure track records and failure analysis reports
Inspection history and reports
Repair interventions history and reports
Corrosion prevention philosophy studies
Materials selection reports
Cathodic protection specification
Cathodic protection inspection reports
5.2. Threats/Hazards Identification
The most common threats considered for pipelines onshore are grouped as per common industrial
practice and presented in the following table 1. Threats groups were organized in time dependent and
non-time dependent threats.
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Table 1 Pipeline System Threats
PIPELINE SYSTEM THREATS
TIME DEPENDENT
THREAT GROUP
CORROSION/EROSION
TIME NON-DEPENDENT
THREAT GROUP
DFI THREATS
THREAT
INTERNAL CORROSION
EXTERNAL CORROSION
EROSION
THREAT
DESIGN ERRORS
FABRICATION RELATED
INSTALLATION RELATED
THIRD-PARTY THREATS
STRUCTURAL THREATS
NATURAL HAZARD THREATS
INCORRECT OPERATION THREATS
DROPPED OBJECTS
VANDALISM/TERRORISM
TRAFFIC (VEHICLE IMPACT, VIBRATIONS)
OTHER MECHANICAL IMPACT
GLOBAL BUCKLING (EXPOSED)
GLOBAL BUCKLING (BURIED)
END EXPANSION
ON-BOTTOM STABILITY
STATIC OVERLOAD
FATIGUE
EXTREME WEATHER
EARTHQUAKES
LANDSLIDES
SIGNIFICANT TEMPERATURE VARIATIONS
FLOODS
LIGHTNING
INCORRECT PROCEDURES
PROCEDURES NOT IMPLEMENTED
HUMAN ERRORS
INTERNAL PROTECTION SYSTEM RELATED
INTERFACE COMPONENT RELATED
Failures related to DFI threats normally occur during installation and early operation and therefore
are not part of the inspection Program. An incorrect operation can be detected by inspection, but
normally is covered by review/audits and training actions of personnel. After natural Hazards normally
inspections are performed.
The following threats groups will be considered in the proposed methodology for risk evaluation:
• Corrosion/erosion Threats
• Third-party threats
• Structural threats
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5.3. Degradation Mechanisms
The degradation of a component can take place internally or externally or both. The rate at which the
degradation takes place depends upon the combination of several factors:
• Metallurgy of the pipeline
• Internal environment (fluid going through the pipeline) (for internal degradation)
• Environment surrounding the pipeline (atmospheric, soil for buried) (for external degradation)
• Protective measures (chemical injection, cathodic protection, coating, lining, etc.)
• Operation conditions (pressure, temperature, flow, etc.)
Internal and external degradation mechanisms should be identified and evaluated for each section of
the pipeline by a specialist.
The corrosion rate can be determined by several methods:
• Calculated – Usually, this is a conservative approach that uses corrosion models to determine
the corrosion rate. The Models considered in this document can be found in Appendix 2, or
Ref. [21] API 581.
• Measured – There are based on recorded thickness measures over time.
• Estimated – A corrosion specialist experienced with the process is usually a good source of
providing a realistic and appropriate estimated rate.
For the consideration of this document, the thinning corrosion rate is assumed to be constant over
the evaluation period. If multiple thinning (internal) mechanisms are possible the higher corrosion
rate should be the one to consider.
5.4. Sectioning of pipeline System
A pipeline system is provided with a long path, that may run through areas affected by different
conditions, exposed to dissimilar environmental conditions and equipped with diverse protection
barriers. An accurate analysis of the system at the beginning of the activity is required, aimed at
evaluating and identifying if different sections may be distinguished. A proper sectioning process shall
be adopted to subdivide the system into distinct sections and apply the methodology with specifically
tailored outcomes for each portion.
5.5. Likelihood
RBI has as a primary goal the planning of in-service inspection for static mechanical pressure systems
when considering failures by loss of containment of the pressure envelope. These failures occur when
the effect of the applied load is greater than the resistance of the component or material. The
resistance is related to the materials (metallurgy), the design (construction Codes), and the in-service
conditions (Operation conditions) of the Pipeline. The load can be any type of load: functional,
environmental or accidental (associated with threats). The reasons why load can become greater than
the resistance of the component are many, ranging from, e.g. poor design specification, design errors
and material defects, through to, e.g., fabrication errors, degradation in operation, and other
unknown events.
The total probability of failure (PoFTotal) is the sum of the probabilities of all events that can cause a
failure (identified as threats).
It can basically be summarized by Equation 1 - Total Probability of Failure.
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RBI Methodology for Pipelines in Zubair Field
PoFTotal = PoFTechnical + PoFAccidental + PoFGross-error + PoFUnknown
Equation 1 - Total Probability of Failure
PoFTechnical is due to fundamental, natural random variability and normal man-made uncertainties.
PoFAccidental there will be “accidental” events that can affect the components, e.g., dropped objects.
These accidental load events can be predicted in a probabilistic form based on historical data.
PoFGross-error Gross errors during design, fabrication, installation, and operation. Gross errors are
understood to be human mistakes. Management systems addressing, e.g., training, documentation,
communication, project specifications and procedures, quality surveillance etc. are all put in place to
avoid human error.
PoFUnknown unexpected phenomena. Truly unimaginable events are very rare, hard to predict and
should therefore be a low contribution to failure. There is little value, therefore, in attempting to
estimate these probabilities.
The probability of failure due to each identified threat shall be assessed, for each section of the
pipeline system. For the threats considered (Section 5.2) for PoF assessment two (2) different levels
of detail may be applied:
• Flowchart method – Considered for threats that the damage is described by a susceptible
model, is triggered by an external event after a dormant period of unknown duration. No time
dependent value, that once trigged the damage occurs very quick
• Calculations and model predictions – Considered for threats that the damage is described by
a rate model, the damage results in a local or general wall thinning of the component. It is
time dependent and assumes that with time extent of damage increases, resulting in a
decrease of wall thickness. This translates as an increase in the probability of failure with time.
Both approaches lead defining a value of the probability of occurrence, for each portion of the pipeline
system, for each identified threat. Every single probability of failure shall be associated with a specific
likelihood range, properly according to the risk matrix.
Figure 3 - Unbalanced Risk Matrix
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An example of a ranking scale is provided. The output of the probability of failure evaluation is
either a numerical value or a probability of failure category. The following table presents an
example where 5 PoF categories are applied.
Table 2 - PoF Ranking Scales
RANK OR
CATEGORY
5
> 10-2
4
10-3 TO 10-2
3
10-4 TO 10-3
2
10-5 TO 10-4
1
< 10-5
POF RANKING SCALES
FAILURE PROBABILITY
QUANTITATIVE [OCCURRENCES/YEAR]
VERY HIGH / SIGNIFICANT / FREQUENT
FAILURE HAS OCCURRED SEVERAL TIMES A YEAR IN LOCATION
HIGH
FAILURE HAS OCCURRED SEVERAL TIMES A YEAR IN OPERATING COMPANY
MEDIUM / NORMAL / RARE
FAILURE HAS OCCURRED IN OPERATING COMPANY
LOW / REMOTE
FAILURE HAS OCCURRED IN THE INDUSTRY
VERY LOW / NEGLIGIBLE / INSIGNIFICANT / UNREALISTIC
FAILURE HAS NOT OCCURRED IN INDUSTRY
For the determination of the probability of failure by the Flowchart method, simple rules/methods to
evaluate with minimum efforts through a workshop or a desk study is to be applied. The probability
of failure is typically estimated by evaluating key factors which may contribute to a failure. Simple flow
charts with additional simple questions are suggested to be applied as a tool that supports the
assessment. Guidance for Flowchart Probability of failure assessment of 3rd party threats and
structural threats are presented in Appendix 1 Guidance for likelihood assessment
The adoption of calculations and model predictions requires more effort than a Flowchart approach
and should be done as a combination of workshops and individual efforts for thoroughly reviewing
relevant documents and data. The models are more detailed and may involve calculations and
predictions based on recommended practices or more advanced/accurate model tools. This approach
was chosen for the probability of failure assessment of corrosion/erosion threats.
The Ref. [21] API 581 has been developed mainly for the Refinery and Petrochemical industries and is
fully applicable for an RBI study. For the Upstream, most of the API 581 is still applicable however
there are some specific damage mechanisms (e.g., MIC, Sand Erosion) that are typical of upstream
that is not foreseen in API 581 or that are not suitable for assessing the probability of failure. For this
reason, some additional damage methodology assessment modules have been developed or existing
ones have been modified. The following modules have been added referring to the International
Standards indicated:
• MIC Microbiologically Induced Corrosion based on DNVGL-RP-G101,
• Erosion Corrosion / Sand Erosion based on API RP 14E / DNVGL-RP-O501
While the following existing modules have been modified:
• CO2 corrosion based on NORSOK M506 / DeWaard & Milliams
A detailed explanation of each added/modified damage module is reported in Appendix 2 Corrosion
Rates Model. The Ref. [21] API 581.
The probability of Failure obtained for the Corrosion/erosion threat (following the Ref. [21] API 581)
is adjusted by two adjustment factors:
• Factor for documentation, this factor evaluates the availability of the data related to the
pipeline and the quality of this data (if it is accurate with the actual reality of the pipeline)
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Factor for Leakage, this factor evaluates if the pipeline has experience leakage and how many
times it has occurred (the value should be considered as 1 for pipelines with an inspection
Plan already in place)
A resume of how the PoFTotal is calculated is presented in the following figure:
•
Figure 4 - PoFtotal
5.6. Consequence
The consequences of a failure depend on the content of the pipeline, internal conditions, failure mode
and physical location.
Assessment of consequences of failure should consider the following:
• Safety (personnel),
• environment,
• economic (assets),
• Other types of consequences can also be considered as company reputation.
For each section of the pipeline system, the consequence assessment associated with each identified
threat shall be assessed.
The approach followed, is the aggregate method (link-up with Exposure Level), this lead to defining a
value of severity level, for each section of the pipeline system, for each identified threat. The following
table presents the example followed where 5 CoF categories are applied.
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Table 3 CoF Ranking Scales
COF RANKING SCALES
RANK
SAFETY
ECONOMIC
ENVIRONMENT
1/A/L
2/B/M
INSIGNIFICANT
SLIGHT/MINOR
3/C/H
INSIGNIFICANT
SLIGHT/MINOR
INJURY
MAJOR INJURY
LOCAL DAMAGE
INSIGNIFICANT
SLIGHT/MINOR
INJURY
LOCAL EFFECT
4/D/VH
SINGLE FATALITY
MAJOR DAMAGE
MAJOR EFFECT
OTHER
(REPUTATION)
INSIGNIFICANT
SLIGHT/MINOR
IMPACT
CONSIDERABLE
IMPACT
MAJOR NATIONAL
IMPACT
5/E/EH
MULTIPLE
FATALITIES
EXTENSIVE
DAMAGE
MASSIVE EFFECT
MAJOR
INTERNATIONAL
In the aggregated method, the modelling of the consequences results is directly linked to design
considerations through safety classes or location classes: according to the location class assigned and
combining this information with the fluid type conveyed, it is possible to extrapolate the consequence
category to be used to represent the safety, environmental and economic consequences.
In the following tables, tailored definitions are provided to allow a proper assignment of Location Class
level.
Semi-quantitative evaluations are required, whose detail level should be defined according to the
project design phase and the availability of project documentation.
In particular, for the Economics scope, the parameters are intended to take into account the economic
impact associated with pipeline failure. The higher is the production rate, the higher will be the
consequence from an economical point of view.
Two different approaches are specifically provided considering the set of information available:
• quantitative approach, in case the set of available input data is detailed; or
• simplified approach, in case the information should be studied more in deep.
To assign an Economic Location Class, threshold values for production rate or process capability limit
shall be predetermined. Different criteria for the two proposed approaches are here suggested for
identifying if the production rate value associated with the system under analysis is high or low. To
state if the pipeline belongs to a high consequence category, the production rate will be compared
with this threshold value, to be intended as the mean value of yearly production rate in the production
field.
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Table 4 - Safety Location Class
SLC
1
2
SAFETY LOCATION CLASS (SLC)
DESCRIPTION
AREAS NOT AFFECTED BY HUMAN ACTIVITIES AND/OR PERMANENTLY MANNED BUILDINGS
SLC 1 CAN BE TYPICAL FOR LANDS WITH LOW ACCESS DUE TO HARSH ENVIRONMENTAL
CONDITIONS, DESERTIFICATION, ETC.
AREAS WITH A DENSITY OF POPULATION LOWER THAN 50 PEOPLE/KM2.
SLC 2 CAN BE TYPICAL FOR AREAS SPORADICALLY POPULATED, WASTELAND, FARMLAND
AND SIMILAR AREAS
3
AREAS WITH A DENSITY OF POPULATION INCLUDED BETWEEN 50 AND 250 PEOPLE/KM2.
SLC 3 CAN BE TYPICAL FOR AREAS AROUND RESIDENTIAL ZONES, TOWNS, COUNTRIES
WITH MULTIPLE HABITATION UNITS, HOTELS OR OFFICE BUILDINGS REGULARLY MANNED
AND WITH OCCASIONAL INDUSTRIAL BUILDINGS
4
AREAS WITH A DENSITY OF POPULATION HIGHER THAN 250 PEOPLE/KM2.
SLC 4 CAN BE TYPICAL FOR ONSHORE AREAS SUCH AS RESIDENTIAL AREAS, INDUSTRIAL
AREAS AND OTHER POPULATED AREAS
5
AREAS ONSHORE WHERE MULTI-STORY BUILDINGS ARE PRESENT AND WHERE TRAFFIC IS
HEAVY OR DENSE
Table 5 - Environment Location Class
ENLC
1
2
ENVIRONMENTAL LOCATION CLASS (ENLC)
DESCRIPTION
POSSIBILITY TO REACH SENSITIVE TARGETS AND GENERATE IMPACTS IS NEGLIGIBLE
AREAS WITH A DENSITY OF POPULATION LOWER THAN 50 PEOPLE/KM2.
SLC 2 CAN BE TYPICAL FOR AREAS SPORADICALLY POPULATED, WASTELAND, FARMLAND
AND SIMILAR AREAS
3
4
POSSIBILITY TO REACH SENSITIVE TARGETS AND GENERATE IMPACTS IS HIGH BUT THE
EXPECTED
CONSEQUENCES ARE REDUCED IN TIME AND DISTANCES
POSSIBILITY TO REACH SENSITIVE TARGETS AND GENERATE IMPACTS IS HIGH AND THE
EXPECTED
CONSEQUENCES ARE SIGNIFICANT IN TIME AND DISTANCES
5
CONTAMINATION OF SENSITIVE TARGETS IS EXPECTED
AMONG SENSITIVE TARGETS, BIOLOGICAL ENVIRONMENTS, PROTECTED AREAS, SOCIO-ECONOMIC
ENVIRONMENTS (FISHING AREAS, TOURISTIC AREAS, MILITARY AREAS, ETC.) ARE INCLUDED. THE POSSIBILITY
THAT A SENSITIVE TARGET IS REACHED AND IMPACTED DEPENDS STRICTLY ON SEVERAL PARAMETERS: DISTANCE
FROM RELEASE SOURCE , OPERATING CONDITIONS AT RELEASE SOURCE , PHYSICAL CHARACTERISTICS OF THE
ENVIRONMENT (TOPOGRAPHY , TEMPERATURES, BURRIER DEPTH , THE PRESENCE OF A MONITORING SYSTEM,
THE PRESENCE OF AN EMERGENCY PLAN, ETC.).
THE EVALUATION CAN BE DONE BOTH ON THE BASIS OF QUALITATIVE CONSIDERATIONS AND ON THE BASIS OF
TAILORED SIMULATION MODELLING. ALL THE POTENTIALLY IMPACTED SENSITIVE TARGETS SHALL BE IDENTIFIED
AND PROPERLY ASSESSED.
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Table 6 - Economic Location Class (EcLc) - Quantitative Approach
ECLC
1
2
3
4
5
ECONOMIC LOCATION CLASS (ECLC) – QUANTITATIVE APPROACH
DESCRIPTION
POTENTIAL LOSSES ≤ 1% OF RELEVANT YEARLY PRODUCTION
POTENTIAL LOSSES ≤ 3% OF RELEVANT YEARLY PRODUCTION
POTENTIAL LOSSES ≤ 10% OF RELEVANT YEARLY PRODUCTION
POTENTIAL LOSSES ≤ 30% OF RELEVANT YEARLY PRODUCTION
POTENTIAL LOSSES > 30% OF RELEVANT YEARLY PRODUCTION
THE POTENTIAL LOSSES SHALL BE COMPARED WITH EXPECTED YEARLY PRODUCTION OF THE FIELD.
THE AMOUNT OF PRODUCTION LOSSES STRICTLY DEPENDS ON THE MANAGEMENT SYSTEM OF EMERGENCY
SCENARIOS AND CAN VARY ALONG THE PIPELINE SYSTEM.
THE FOLLOWING ISSUES SHALL BE CONSIDERED:
• LOSSES ASSOCIATED TO EXPORT DELIVERY: THE TIME REQUIRED TO ISOLATE THE SYSTEM AND
MINIMIZE THE
•
•
•
•
RELEASED INVENTORY . THIS APPROACH MAY BE CONSERVATIVE BUT SUFFICIENT IN CASE OF LONG
TIME REPAIRS. M ORE ADVANCED QUANTITATIVE MODELS CAN BE APPLIED.
REPAIR COSTS: THE EXTENSION OF THE DAMAGE, THE DURATION OF REQUIRED INTERVENTION, TIME
AND COSTS ASSOCIATED SHALL BE CONSIDERED.
DEPENDING OF LOCAL REGULATIONS, FINES MAY BE RELEVANT TO CONSIDER AS WELL.
COSTS ASSOCIATED TO ENVIRONMENTAL DAMAGE CAN BE SIGNIFICANT DEPENDING ON TYPE OF
FLUID, VOLUMES, COUNTRY AND GEOGRAPHICAL LOCATION.
Table 7 - Economic Location Class (EcLc) - Simplified approach
ECLC
1
2
3
4
5
ECONOMIC LOCATION CLASS (ECLC) – SIMPLIFIED APPROACH
DESCRIPTION
EXTERNAL DIAMETER OF THE LINE ≤ 4”
EXTERNAL DIAMETER OF THE LINE > 4” AND ≤ 8”
EXTERNAL DIAMETER OF THE LINE > 8” AND ≤ 16”
EXTERNAL DIAMETER OF THE LINE > 16” AND ≤ 32”
EXTERNAL DIAMETER OF THE LINE > 32”
After assigning a Location Class to the system for each scope, the characterization of the fluid and the
identification of the relevant fluid category shall be carried out.
In the following table, the criteria to be adopted for the identification of the fluid category are listed.
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Table 8 - Fluid Category
CATEGORY
A
B
C
D
E
FLUID TYPE/CATEGORY
DESCRIPTION
TYPICAL NON-FLAMMABLE WATER-BASED FLUIDS.
FLAMMABLE AND/OR TOXIC FLUIDS WHICH ARE LIQUIDS AT AMBIENT TEMPERATURE AND
ATMOSPHERIC PRESSURE CONDITIONS. TYPICAL EXAMPLES ARE OIL AND PETROLEUM
PRODUCTS. M ETHANOL IS AN EXAMPLE OF A FLAMMABLE AND TOXIC FLUID.
NON-FLAMMABLE FLUIDS WHICH ARE NON-TOXIC GASES AT AMBIENT TEMPERATURE AND
ATMOSPHERIC PRESSURE CONDITIONS. TYPICAL EXAMPLES ARE NITROGEN, CARBON
DIOXIDE , ARGON AND AIR.
N-TOXIC, SINGLE-PHASE NATURAL GAS.
FLAMMABLE AND/OR TOXIC FLUIDS WHICH ARE GASES AT AMBIENT TEMPERATURE AND
ATMOSPHERIC PRESSURE CONDITIONS AND WHICH ARE CONVEYED AS GASES AND/ OR
LIQUIDS.
TYPICAL EXAMPLES WOULD BE HYDROGEN, NATURAL GAS (NOT OTHERWISE COVERED
UNDER
CATEGORY D), ETHANE , ETHYLENE , LIQUEFIED PETROLEUM GAS (SUCH AS PROPANE AND
BUTANE ), NATURAL GAS LIQUIDS, AMMONIA, AND CHLORINE .
The combination of these two parameters, Location Class (table 3 to table 7) and Fluid Category (Table
8 - Fluid Category) for the system plus a third parameter, the External Diameter of the pipeline (D),
allows the assessment of a specific Exposure Level (Table 9 - Exposure Levels) for each scope.
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Table 9 - Exposure Levels
LOCATION
CLASS
LIQUIDS (B)
D ≤ 8"
D >8"
SLC 1
SLC 2
SLC 3
SLC 4
H
SLC 5
VH
ENLC 1
L
M
ENLC 2
L
H
ENLC 3
M
VH
ENLC 4
H
EH
ENLC 5
VH
EH
ELC 1 (*)
ELC 2 (*)
ELC 3 (*)
ELC 4 (*)
ELC 5 (*)
ELC 1 (+)
M
ELC 2 (+)
H
ELC 3 (+)
VH
ELC 4 (+)
EH
ELC 5 (+)
EH
(*) ACCORDING TO QUANTITATIVE APPROACH
(+) ACCORDING TO SIMPLIFIED APPROACH
EXPOSURE LEVELS
FLUID CATEGORY
GAS (D, E)
D ≤ 8"
D >8"
L
M
H
VH
EH
OTHER (A, C)
D ≤ 8"
D >8"
L
L
M
M
M
M
H
L
M
L
L
M
M
M
H
H
L
M
H
VH
EH
L
M
H
VH
EH
M
M
L
L
M
H
VH
The Exposure Levels are defined in Table 10 - Exposure Levels Description.
Table 10 - Exposure Levels Description
CATEGORY
LEVEL
A
LOW
B
MEDIUM
C
HIGH
D
VERY HIGH
E
EXTREMELY HIGH
EXPOSURE LEVELS DESCRIPTION
DESCRIPTION
WHERE FAILURE IMPLIES NEGLIGIBLE RISK OF HUMAN INJURY AND LOW
ENVIRONMENTAL AND ECONOMIC CONSEQUENCES
WHERE FAILURE IMPLIES MINOR RISK OF HUMAN INJURY AND MINOR
ENVIRONMENTAL OR ECONOMIC CONSEQUENCES
WHERE FAILURE IMPLIES RISK OF HUMAN INJURY OR SIGNIFICANT
ENVIRONMENTAL IMPACT OR HIGH ECONOMIC CONSEQUENCES
WHERE FAILURE IMPLIES HIGH RISK OF HUMAN INJURY OR VERY HIGH
ENVIRONMENTAL IMPACT OR VERY HIGH ECONOMIC CONSEQUENCES
WHERE FAILURE IMPLIES VERY HIGH RISK OF HUMAN INJURY OR
EXTREMELY HIGH ENVIRONMENTAL IMPACT AND ECONOMIC
CONSEQUENCES
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For each pipeline system under analysis, one Exposure Level will be estimated for each scope (Safety,
Economic and Environment) of interest. Among them, the highest-one will define the characteristic
Exposure Level to be adopted for consideration as CoF.
5.7. Inspection plan and associated interval of frequency
The Inspection plan shall clearly identify what, where, when and how inspection shall be carried out.
 What to inspect
Inspection programs are based on the understanding of which failure mechanisms can
occur along the pipeline systems and where they are of major relevance. In other words,
all the elements, situations and conditions that could violate the integrity of the pipeline
and its fit-for-purpose and characterize by a level of risk not sufficiently mitigated by
suitable actions, shall be regularly inspected.
 Where to inspect
Inspection efforts should be focused on the important sections of the pipeline system and
on deterioration processes that contribute to the safety and economic risks for all the
pipeline systems.
 When to inspect
Requirements for when to inspect are given based on:
 Authorities and Company requirements;
 EL assigned to the pipeline (or section of the pipeline)
 the approach followed for preparation of the Inspection plan (un-risk or risk
based);
 typology of inspections;
 optimization of various inspections (only for risk based inspection Plan).
 How to inspect
The requirements for the selection of inspection tools and techniques have the scope of
allowing reliable detection of potentially hazardous situations, failure mechanisms and a
collection of inspection data suitable for the pipeline condition assessment. These
requirements take into account:
 the peculiarities of the pipeline system;
 the experience gained on other projects;
 the available technologies and their state of the art.
The minimum requirements for inspections tasks applicable for onshore pipelines Systems can be
found in Appendix 3 of this document.
The inspection frequency will be determined by the “Risk Level” associated with each section of the
pipeline section.
Combining the PoF and the CoF values into the risk matrix, a “Risk Level” is yield.
For each threat identified and study, a dedicated expected frequency may be assessed and a potential
consequence severity may be associated. Combining the related PoF and CoF values, a “Risk Level” is
associated with each threat and a specific inspection interval is identified for those inspection activities
aimed at managing that threat.
A work selection matrix like the one in Table 11 - Inspection Interval (IR) can be used to determine the
base inspection interval (IR).
23 | P a g e
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INCREASE PROBABILITY -->
Table 11 - Inspection Interval (IR)
5
3
1
N/A
N/A
N/A
4
5
3
1
N/A
N/A
3
8
5
3
1
N/A
2
8
8
5
3
1
1
8
8
8
5
3
A
B
C
D
E
INCREASING CONSEQUENCE -->
The final inspection interval (I) is determined by Equation 2 - Final Inspection Interval.
I = IR * C * D
Equation 2 - Final Inspection Interval
where C and D are adjustments factors for confidence in and possible development of probability of
occurrence of the incidental scenario(s).
The adjustment factors are evaluated through the application of the barrier framework method.
Barriers are any kind of measure put in place to prevent a hazardous event (preventive barriers) and
any measure that breaks the chain of events to prevent or minimize consequence escalation should
the hazardous event take place (reactive barriers). Such measures can be physical and/or non-physical
(human/operational/organizational).
According to Ref [14], four groups of preventive barriers have been defined:
 Pressure Containment and Primary Protection – This is considered to be the main barrier group,
comprising the containment system itself and its primary protective system
 Operational/Process Control – Conceptually, this is the second line of defence. It should
ensure that the pipeline system is being operated as intended and that the (relevant)
predefined operational envelopes are maintained and not violated
 Pipeline Integrity Control – The third line of defence consists of processes and systems to
detect and assess anomalies
 Pipeline Integrity Improvement – The last line of defence (conceptually positioned right to the
left of the top event) consists of processes and systems that will improve the integrity where
anomalies have reduced the pipeline system to an unacceptable condition
The four preventive barrier groups comprise several elements as shown in Table 12 - Preventive
barrier function.
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Table 12 - Preventive barrier function
BARRIER FUNCTION
PREVENTIVE BARRIER FUNCTIONS
BARRIER SYSTEM/ELEMENT
DESIGN BASIS
QA AND DOCUMENTATION OF DESIGN, FABRICATION,
INSTALLATION AND MODIFICATIONS
PRESSURE CONTAINMENT AND
PRIMARY PROTECTION
OPERATIONAL/PROCESS CONTROL
PIPELINE INTEGRITY CONTROL
PIPELINE / OTHER PRESSURE CONTAINING COMPONENTS
PIPELINE COVER
PROTECTION AND SUPPORT STRUCTURES
INFORMATION SYSTEM TO 3RD PARTY
RESTRICTION AND SAFETY ZONE SYSTEMS
PRESSURE PROTECTION SYSTEM
EXTERNAL CORROSION PROTECTION SYSTEM
INTERNAL CORROSION PROTECTION SYSTEM
PROCESS CONTROL SYSTEM
OPERATIONAL PROCEDURES
STRATEGIES AND PLANS FOR PIPELINE INTEGRITY CONTROL
SYSTEMS AND PROCESSES FOR INSPECTION, MONITORING AND
TESTING
PIPELINE INTEGRITY IMPROVEMENT
SYSTEMS AND PROCESSES FOR INTEGRITY ASSESSMENT
STRATEGIES AND PLANS FOR PIPELINE INTEGRITY IMPROVEMENT
SYSTEMS AND PROCESSES FOR MITIGATION, INTERVENTION AND
REPAIRS
Reactive barriers contribute to minimizing the consequences of a loss of containment and may
typically include leak detection and emergency shutdown, operational/process control, emergency
response (communication, combat, diversion and rescue) and pipeline repair systems (part of pipeline
integrity improvement).
Further details about the identification and the definition of the barrier are included in Appendix 4 of
this document.
Each of the 17 elements belonging to the set of identified barrier function is to be evaluated, scored,
and used to determine the final inspection frequency, according to the following calculation steps:
1. Each element indicating how well the preventive barrier works is evaluated assigning a scoring
value. Scoring is done by use of 5 categories:
a. category 1 score is a very good score (high efficiency leading to low risk)
b. category 5 score is a very poor score (Low efficiency leading to High risk)
2. Each element is also provided with a relevance score to indicate its importance against each
identified threat. Relevance can change with time (an element may be very important during
the initial period of operation, but less relevant as the pipeline system becomes more mature).
Five relevance categories are used, each with a certain weight:
a. Very High relevance (VH) -> weight=18
b. High Relevance (HR) -> weight=12
c. Medium Relevance (MR), weight=6
d. Low Relevance (LR) -> weight=1
e. Not Relevant (NR) -> weight=0
3. Determine a confidence factor for each element by evaluation of the 17 elements as described
at point 1:
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a. Confidence scores [1, 2, 3, 4, 5] correspond to the factors [1, 0.9, 0.75, 0.5, 0.25].
b. Final overall Confidence factor (C) is set to the weighted average
4. Determine a development factor for each element by evaluating the 17 elements as described
at point 1:
a. Development scores [1, 2, 3, 4, 5] correspond to the factors [1, 0.9, 0.75, 0.5, 0.25].
b. Final development factor (D) is set to the weighted average
5. Determine inspection frequency by use of the selected matrix as per Table 11 - Inspection
Interval (IR), then adjust the frequency by multiplying with the final confidence factor and the
final development factor as per Equation 2 - Final Inspection Interval.
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Appendix 1 Guidance for likelihood assessment
Corrosion
The evaluation of PoF for corrosion/erosion threats will follow the Ref. [21] API 581 methodology, by
the determination of the Damage Factor associated with each identified damage mechanism.
The basic function of the Damage Factor is to statistically evaluate the amount of damage that may
be present as a function of time in service and the effectiveness of inspection activity. Damage Factor
reflects a relative level of concern about the section of the pipeline based on the stated assumption
in each of the applicable sections of the Ref. [21] API 581. For the concern of this document, the
Damage Factor is provided for the following damage mechanisms:
𝑡𝑡ℎ𝑖𝑖𝑖𝑖
• Thinning - 𝐷𝐷𝑓𝑓−𝑔𝑔𝑔𝑔𝑔𝑔
•
𝑒𝑒𝑒𝑒𝑒𝑒𝑒𝑒
External Damage - 𝐷𝐷𝑓𝑓−𝑔𝑔𝑔𝑔𝑔𝑔
Total Damage Factor, Df-total − If more than one damage mechanism is present, is calculated as per
Equation 3 - Total Damage Factor, assuming that thinning and/or external damage mechanisms are
classified as local.
𝑡𝑡ℎ𝑖𝑖𝑖𝑖
𝑒𝑒𝑒𝑒𝑒𝑒𝑒𝑒
Df-total =max [𝐷𝐷𝑓𝑓−𝑔𝑔𝑔𝑔𝑔𝑔
, 𝐷𝐷𝑓𝑓−𝑔𝑔𝑔𝑔𝑔𝑔
]
Equation 3 - Total Damage Factor
The DF calculation for a section of pipeline subject to damage mechanisms that cause general or local
thinning is covered in Thinning Damage Factor section of this Appendix. Thinning associated with
external corrosion and CUI is covered in the External Damage Factor section of this Appendix.
Table 13 - Probability Category, provides the relationship between the Damage Factor range and the
probability range.
Table 13 - Probability Category
PROBABILITY CATEGORY
RANK OR
CATEGORY
5
4
3
2
1
PROBABILITY R ANGE
> 10-2
10-3 TO 10-2
10-4 TO 10-3
10-5 TO 10-4
< 10-5
DAMAGE FACTOR RANGE
[DF-TOTAL]
>1000
100 TO 1000
10 TO 100
1 TO 10
≤1
The Damage Factor is calculated using structural reliability theory. A statistical distribution is applied
to the thinning corrosion rate, accounting for the variability of the actual thinning corrosion rate which
can be greater than the rate assigned. The amount of uncertainty in the corrosion rate is determined
by the number and effectiveness of inspections and the on-line monitoring that has been performed.
Confidence that the assigned corrosion rate is the rate experienced in-service increases with a more
thorough inspection, a greater number of inspections, and/or more relevant information gathered
through the on-line monitoring. The DF is updated based on increased confidence in the measured
corrosion rate provided by using Bayes Theorem and the improved knowledge of the component
condition.
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Thinning Damage Factor
In the thinning Damage Factor calculation, it is assumed that the thinning corrosion rate is constant
over time. This corrosion rate is updated based on the knowledge gained from subsequent inspections.
An Art parameter is determined by calculating the ratio of total component wall loss (using the
assigned corrosion rate during the in-service period) to the wall thickness.
The thinning Damage Factor is calculated for a defined period or Plan Period. In the Damage Factor
calculation, it is assumed that thinning damage would eventually result in failure by plastic collapse.
The uncertainty in the corrosion rate varies, depending on the source and quality of the corrosion rate
data. For general thinning, the reliability of the information sources used to establish a corrosion rate
can be put into the following three categories:
• Low Confidence Information Sources for Corrosion Rates (published data, corrosion rate tables
and expert opinion)
• Medium Confidence Information Sources for Corrosion Rates (laboratory testing with
simulated process conditions or limited in-situ corrosion coupon testing)
• High Confidence Information Sources for Corrosion Rates (extensive field data from thorough
inspections).
Thinning Damage Factor calculations are based on the probability of three damage states being
present. The three damage states used are defined as:
• Damage State 1 – Damage is no worse than expected, or a factor of 1 applied to the expected
corrosion rate
• Damage State 2 – Damage is somewhat worse than expected, or a factor of 2 applied to the
expected corrosion rate
• Damage State 3 – Damage considerably worse than expected, or a factor of 4 applied to the
expected corrosion rate
Inspections are ranked according to their expected effectiveness at detecting thinning and correctly
predicting the rate of thinning Table 16 - Conditional Probability for Inspection Effectiveness provides
the conditional probabilities for each inspection effectiveness category in the thinning Damage Factor
calculations.
The procedure described in Figure 5 - Determination of the Thinning Damage Factor, may be used to
determine the Damage Factor for thinning.
28 | P a g e
RBI Methodology for Pipelines in Zubair Field
Figure 5 - Determination of the Thinning Damage Factor
29 | P a g e
RBI Methodology for Pipelines in Zubair Field
The adjustment factors are determined as described below.
• Adjustment to DF for On-Line Monitoring, FOM – In addition to inspection, on-line monitoring
of corrosion (or key process variables affecting corrosion) is commonly used in many
processes to prevent corrosion failures. Various methods are employed, ranging from
corrosion probes, corrosion coupons, and monitoring of key process variables.
If on-line monitoring is employed, then credit should be given to reflect higher confidence in
the predicted thinning rate. However, these methods have a varying degree of success
depending on the specific thinning mechanism. Using knowledge of the thinning mechanism
and the type of on-line monitoring, determine the on-line monitoring factor from Table 14 On-Line Monitoring Adjustment Factors.
Table 14 - On-Line Monitoring Adjustment Factors
THINNING
MECHANISM
ON-LINE MONITORING ADJUSTMENT F ACTORS
ADJUSTMENT FACTORS AS A F UNCTION OF ON-LINE MONITORING FOM
ELECTRICAL RESISTANCE
KEY PROCESS VARIABLES
CORROSION COUPONS *
PROBES *
SOUR WATER
CORROSION
LOW VELOCITY
20
10
2
≤6 M/S (20 FT/S)
HIGH VELOCITY
10
2
2
>6 M/S (20 FT/S)
*THE EFFECTIVENESS OF OTHER ON-LINE CORROSION MONITORING METHODS (E.G. HYDROGEN FLUX,
FSM, LP PROBE) SHALL BE EVALUATED BY A CORROSION ENGINEER OR OTHER KNOWLEDGEABLE
SPECIALIST.
•
Adjustment For Dead Legs, F DL – Components of piping that normally have no significant flow
are considered Dead legs. If a piping circuit contains a dead leg, then an adjustment should be
made to the thinning DF to account for the higher likelihood of thinning activity at this location.
The adjustment factor is F DL =3. If a highly effective inspection method is used to address the
potential of localized corrosion in the dead leg, then an adjustment is not necessary.
The following tables provide the parameters to be applied in the Step 6.
Table 15 - Prior Probability for Thinning Corrosion Rate
DAMAGE STATE
PRIOR PROBABILITY FOR THINNING CORROSION RATE
LOW CONFIDENCE DATA MEDIUM CONFIDENCE DATA HIGH CONFIDENCE DATA
0.5
0.7
0.8
0.3
0.2
0.15
0.2
0.1
0.05
30 | P a g e
RBI Methodology for Pipelines in Zubair Field
Table 16 - Conditional Probability for Inspection Effectiveness
CONDITIONAL
PROBABILITY OF
INSPECTION
CONDITIONAL P ROBABILITY FOR INSPECTION EFFECTIVENESS
E – NONE OR
INEFFECTIVE
D – POORLY
EFFECTIVE
C – FAIRLY
EFFECTIVE
B – USUALLY
EFFECTIVE
A – HIGHLY
EFFECTIVE
0.33
0.4
0.5
0.7
0.9
0.33
0.33
0.3
0.2
0.09
0.33
0.27
0.2
0.1
0.01
(*) THE EFFECTIVENESS OF OTHER ON-LINE CORROSION MONITORING METHODS SHALL BE
EVALUATED BY A CORROSION ENGINEER OR OTHER KNOWLEDGEABLE SPECIALIST .
External Damage Factor (Atmospheric)
Pipelines located in areas with high annual rainfalls or warmer, marine locations are more prone to
external corrosion than pipelines located in cooler, drier, mid-continent locations.
Mitigation of external corrosion is accomplished through proper painting. A regular program of
inspection for paint deterioration and repainting will prevent most occurrences of external corrosion.
If the component is un-insulated and subject to any of the following, then the component should be
evaluated for external damage from corrosion:
• Carbon steel systems, operating between –12°C and 177°C (10°F and 350°F). External
corrosion is particularly aggressive where operating temperatures cause frequent or
continuous condensation and re-evaporation of atmospheric moisture,
• Systems with deteriorated coating and/or wrappings.
Inspections are ranked according to their expected effectiveness at detecting external corrosion and
correctly predicting the rate of external corrosion Table 16 - Conditional Probability for Inspection
Effectiveness provides the conditional probabilities for each inspection effectiveness category in the
external Damage Factor calculations.
The procedure described in Figure 6 - Determination of the External Corrosion Damage Factor, may
be used to determine the Damage Factor for External Corrosion.
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RBI Methodology for Pipelines in Zubair Field
Figure 6 - Determination of the External Corrosion Damage Factor
32 | P a g e
RBI Methodology for Pipelines in Zubair Field
The corrosion rate that can be applied for the determination of the External Corrosion Damage Factor
is shown in Table 17 - Corrosion Rates for the Calculation of external Corrosion Damage Factor, this
corrosion rate is defined based on the Atmospheric conditions of the area that the exposed section of
pipeline is located.
Table 17 - Corrosion Rates for the Calculation of external Corrosion Damage Factor
CORROSION RATES FOR THE CALCULATION OF E XTERNAL CORROSION D AMAGE FACTOR
OPERATING
CORROSION R ATE (MM/Y)
TEMPERATURE
MARINE
TEMPERATE
ARID/DRY
SEVERE
(ºC)
-12
0
0
0
0
-8
0.025
0
0
0
6
0.127
0.076
0.025
0.254
32
0.127
0.076
0.025
0.254
71
0.127
0.051
0.025
0.254
107
0.025
0
0
0.051
121
0
0
0
0
NOTE:
THE EXTERNAL CORROSION DAMAGE IS THE ONE CAUSED BY ATMOSPHERIC CONDITION
33 | P a g e
RBI Methodology for Pipelines in Zubair Field
Third-party threats
A proper survey should be performed before the assessment. The survey should cover the entire
pipeline, should be supported by tailored (quantitative) analyses and should provide an answer for
the following life cycle information:
• Overview of activities potentially affecting pipeline integrity, e.g.:
o Heavy machinery handling around the pipeline (Cranes, excavators, etc.)
o Traffic in the area around the pipeline
o Construction/Installation activities
o Others (planned construction work, etc.)
• Physical characteristic of the pipeline
o Diameter, wall thickness, coating thickness
o Material (steel and coating)
o Construction details
o Protection (burial, rock dump, protection structures etc.)
o Routing and soil characteristics
Third-party threats are associated with human activities and/or hardware that can cause external
loading to pipelines. The following type of loads may typically be relevant and are normally taken into
account during design, and some mitigations actions considered:
• impact loads
• pull-over loads
• hooking loads
• or a combination of the above.
Third-party threat related events will most likely lead to pipeline damage such as dents, abrasion,
cracks, gouges, local buckles, coating damage, anode damage, and displacements. These types of
damage may with time develop into a loss of containment failure.
Among the typical Third-party threats for onshore pipelines, the following are normally covered by
long term integrity management plans based on risk, dropped object and traffic interference.
Dropped objects
Damages from dropped objects may occur from traffic, passing items and near plants/platforms/fields.
The risk is typically greater during drilling and construction work.
The PoF assessment for dropped objects consists of 2 steps, a flowchart that gives an initial PoF value
followed by an engineering judgment where an adjustment of the PoF can be performed.
34 | P a g e
RBI Methodology for Pipelines in Zubair Field
Figure 7 - Flowchart Dropped Objects
Table 18 - Engineering judgment Adjustment for PoF
5
6
7
8
ADJUSTMENTS OF POF BASED ON ENGINEERING JUDGMENT
ADJUSTMENT QUESTIONS
ADJUSTMENT
PIPELINE EXPOSED TO CYCLIC LOADING (OPERATIONAL, CURRENT,
+1
WAVES)?
D/T > 40?
+1
ADEQUATE CONDITIONS RECENTLY CONFIRMED?
-1
ENGINEERING JUDGMENT OF OTHER ISSUES NOT COVERED
±X
ABOVE
POFADJUSTED
*MAXIMUM POF SCORE = 5
POF + SUM OF ADJUSTMENTS*
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Table 19 - Guidance for Dropped objects
GUIDANCE FOR DROPPED OBJECTS
FIGURE 8 - FLOWCHART DROPPED OBJECTS
DAMAGES DUE TO DROPPED OBJECTS OCCUR MORE FREQUENT IN
1
CLOSE TO PLANT/PLATFORM?
THE VICINITY OF/ INSIDE A PLANT SYSTEM
PIPELINE CONFIRMED PROTECTED (BURIED OR ROCK DUMPED)
2
ADEQUATE PROTECTED?
3
LOW ACTIVITY LEVEL
4
HIGH ACTIVITY LEVEL
AGAINST DROPPED OBJECTS BY INSPECTION AND IT IS NOT
EXPECTED THAT THERE HAVE BEEN ANY SIGNIFICANT CHANGES IN
THE BURIAL DEPTH SINCE THE LAST INSPECTION
LOW ACTIVITY LEVEL ABOVE THE PIPELINE , I.E . UNDER DRILLING
AND CONSTRUCTION WORK
HIGH LEVEL OF ACTIVITY ABOVE THE PIPELINE, I.E. UNDER
DRILLING AND CONSTRUCTION WORK
TABLE 18 - ENGINEERING JUDGMENT ADJUSTMENT FOR PO F
A POTENTIAL DAMAGE TO PIPELINES EXPOSED TO CYCLIC LOADING
PIPELINE EXPOSED TO CYCLING
FROM OPERATION (PRESSURE , TEMPERATURE , SHUT DOWNS),
5
LOADING
ETC. CAN DEVELOP FASTER INTO FAILURE THAN A PIPELINE WITH
LOW EXPOSURE TO CYCLIC LOADING
6
7
D/T > 40
ADEQUATE CONDITION RECENTLY
CONFIRMED
DIAMETER / THICKNESS RATIO ABOVE 40 AND IS THEREFORE
CONSIDERED AS A LESS ROBUST PIPELINE SYSTEM
INSPECTION AND MONITORING PERFORMED SHOWING NO
DAMAGES DUE TO DROPPED OBJECTS AND/ OR VERY LOW ACTIVITY
IN THE AREA ROUND THE PIPELINE. RELEVANT INSPECTIONS CAN
BE ROV INSPECTIONS AND/ OR INTERNAL INSPECTION THAT CAN
DETECT DENTS
8
ENGINEERING JUDGEMENT OF
OTHER ISSUES
“X” IS SELECTED BASED ON THE KNOWLEDGE OF THE SYSTEM
ITSELF HOW IT HAS BEEN OPERATED AND MAINTAINED (I.E .
QUALITY OF INTEGRITY CONTROL AND INTEGRITY IMPROVEMENT
FUNCTIONS IN THE INTEGRITY MANAGEMENT SYSTEM)
Structural
The following structural threats are covered:
• Global buckling (exposed)
• Global buckling (buried) / Upheaval buckling (UHB)
• End expansion (interface between pipeline and connected component)
• On-bottom stability
• Pipeline free spans
Other structural threats are not addressed and are listed below:
• Pipeline Walking - To be considered for both exposed and buried pipelines. Pipeline walking
is a non-reversible axial displacement of the whole pipeline towards one end. It relates to
start-up heat transients and following shut-down cycles. Short pipelines with frequent and
large variations in temperature are most susceptible to pipeline walking. Slopes may enhance
pipeline walking. Steel catenary risers, directly coupled to the pipeline, may also enhance
pipeline walking.
• Collapse – blockage caused by external overpressure is normally an issue during installation.
However, a pipeline can collapse due to external overpressure in case the cross-section has
36 | P a g e
RBI Methodology for Pipelines in Zubair Field
an excessive ovality, dent or is highly corroded. To deform a cross-section from an initial oval
state to a collapse, the pipeline is likely depressurized and filled with gas.
• Propagating buckling – blockage caused by external overpressure is normally an issue during
installation. Propagating buckling needs to be initiated through an event such as a dent or
collapse. The failure runs along the pipeline until the external pressure is lower than the
propagating pressure. Buckle arrestors can be designed to stop a propagating buckle and limit
the damaged section length.
Threats that are not addressed require a re-design/re-qualification and give a PoF category of 5.
The following flowchart, Figure 8 - Flowchart Structural Threats, can be used as guidance for
carrying out a PoF evaluation for the different structural threats. The result from the flowchart is
further adjusted based on the questions from Table 21 - Engineering judgment Adjustment for
PoF – Global Buckling (Exposed) to Table 25 - Engineering judgment Adjustment for PoF – Free
spans / Static overload and fatigue.
The set of tables (the questions to be answered) to be used for adjustment, as well as the “not
applicable” conditions, are presented in the tables from the following sections covering the
considered threats.
Figure 8 - Flowchart Structural Threats
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RBI Methodology for Pipelines in Zubair Field
Table 20 - Guidance for Structural Threats For a Pipeline
GUIDANCE FOR STRUCTURAL THREATS FOR A PIPELINE
FIGURE 8 - FLOWCHART STRUCTURAL THREATS
THREAT ARE
1
APPLICABLE / RELEVANT ?
DESIGN ACTIVITIES HAVE BEEN PERFORMED AND ARE CARRIED
2
DESIGN ACTIVITIES
OUT TO MEET RECOGNIZED DESIGN CODES
3
OPERATIONAL ENVELOP
4
DNV CODES
AN OPERATIONAL ENVELOPE HAS BEEN ESTABLISHED (MAXIMUM
TEMPERATURE , PRESSURE , FLOW -RATE , FREQUENCIES,
ENVIRONMENT LOAD, IMPACT LOADS, MAXIMUM ALLOWABLE
SPAN LENGTHS, MINIMUM COVER HEIGHT , ETC.) AND A PROGRAM
TO CHECK COMPLIANCE IS IN PLACE .
DESIGN IS ACCORDING TO DNV CODES (SUCH A DESIGN CAN GIVE
A P O F CATEGORY BETWEEN 2 AND 4 AS A STARTING POINT
DEPENDING ON SAFETY CLASS AND THE REVISION OF THE CODE –
FOR DESIGN ACCORDING TO OTHER CODES, A P O F CATEGORY OF 3
IS ASSUMED AS A STARTING POINT )
COMPLEMENTARY QUESTIONS
TIME SINCE INSTALLATION OR
LAST EXTERNAL INSPECTION > 5
5
YEARS
INSPECTION RESULTS EVALUATED
6
AND DOCUMENTED ON A
REGULAR BASIS. I S THE
CONDITION AS EXPECTED OR
NOT ?
INSPECTION REPAIRS AND CONDITION ASSESSMENT REPORTS
Global buckling (surface laid pipeline)
Global buckling (exposed) is the lateral displacement of the pipeline caused by thermal and pressure
loading; this phenomenon shall be considered for all exposed pipelines. Experience shows that all
types of pipelines can buckle. Global buckles affect short sections along the pipeline (100-500 meters).
A pipeline that has a small diameter with thick thermal insulation and low lateral resistance is more
susceptible to global buckling compared to a heavy pipeline (large diameter and concrete coated).
Global buckling should be considered for pipelines heated above 20-30°C of its installation
temperature. If a pipeline is heated at 5-10°C or less compared to its installation temperature, global
buckling can be considered not relevant. However, global buckling and expansion are not only linked
to temperature, pressure alone can develop global buckling.
The initial PoF value can be followed by an engineering judgment to have an adjustment of the PoF.
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RBI Methodology for Pipelines in Zubair Field
Table 21 - Engineering judgment Adjustment for PoF – Global Buckling (Exposed)
ADJUSTMENTS OF POF BASED ON ENGINEERING JUDGMENT – GLOBAL BUCKLING (EXPOSED)
CONDITION NOT APPLICABLE AS WELL AS ADJUSTMENT QUESTIONS
•
•
•
7
8
9
10
11
12
NOT APPLICABLE IF POF GIVEN (FIGURE 8 - FLOWCHART STRUCTURAL THREATS) = 1
IF A PIPELINE IS HEATED 5-10ºC OR LESS COMPARED TO ITS INSTALLATION TEMPERATURE.
IF GLOBAL BUCKLING HAS NOT LEAD TO UNACCEPTABLE CONDITIONS HISTORICALLY AND THE
MAXIMUM FLOW CONDITIONS ( TEMPERATURE / PRESSURE ) HAVE ALREADY OCCURRED.
ADJUSTMENT QUESTIONS
ADJUSTMENT
BUCKLING OF PIPELINE DESIGNED NOT TO BUCKLE
+1
DISTANCE BETWEEN OBSERVED BUCKLES LONGER THAN
+1
ACCEPTABLE
UNWANTED GLOBAL BUCKLING AT NON- DESIRABLE LOCATIONS
(PIPELINE CROSSINGS, FREE SPAN SUPPORTS, PRE-MADE TRENCH
THAT AIM TO PROTECT THE PIPELINE FROM INTERFERENCE
LOADS)
OBSERVED COLLISIONS WITH OTHER STRUCTURES
GLOBAL BUCKLING AT END TERMINATIONS OR IN-LINE TEES ETC.
ENGINEERING JUDGMENT OF OTHER ISSUES NOT COVERED
ABOVE (E .G. WITH REGARD TO CONFIDENCE IN DOCUMENTATION
/ INFORMATION FROM DFI AND OPERATION)
POFADJUSTED
+1
+1
+2
±X
POF + SUM OF ADJUSTMENTS
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RBI Methodology for Pipelines in Zubair Field
Global buckling (buried) / Upheaval buckling (UHB)
Global buckling (buried) / Upheaval buckling (UHB) failure is linked to failure in soil resistance. The
potential for UHB increases with higher temperatures, pressures, and flow rates. Other issues to be
considered are reduction (erosion) of the soil layer on top or the risk of liquefaction due to waves (for
offshore systems) or earthquakes. UHB can be considered as the weakest link failure mode (it is the
local loads and resistance along the pipeline that governs).
Table 22 - Engineering judgment Adjustment for PoF – Upheaval Buckling
ADJUSTMENTS OF POF BASED ON ENGINEERING JUDGMENT – UPHEAVAL BUCKLING
CONDITION NOT APPLICABLE AS WELL AS ADJUSTMENT QUESTIONS
•
•
7
8
9
10
11
NOT APPLICABLE IF POF GIVEN (FIGURE 8 - FLOWCHART STRUCTURAL THREATS) = 1
EXPOSED PIPELINE – PIPELINE TRANSPORTING AMBIENT FLUID
ADJUSTMENT QUESTIONS
ADJUSTMENT
TEMPERATURE INCREASE FROM INSTALLED LEVEL ABOVE
+1
ACCEPTABLE OR PRESENCE OF UNPREDICTABLE SUBSIDENCE
OBSERVED NATURAL HAZARDS THAT MAY AFFECT PROTECTION
LAYER ON TOP OF THE PIPELINE (E .G. EARTHQUAKES, RIVER
FLOODS, HURRICANES)
OBSERVED (GRADUAL) SIGNIFICANT LOSS OF BACKFILLED
MATERIAL (SAND, CLAY , ROCK)
TEMPERATURE IS DECLINING BELOW HISTORIC MAXIMUM AND
EXPECTED STAY BELOW *)
ENGINEERING JUDGMENT OF OTHER ISSUES NOT COVERED
ABOVE (E .G. WITH REGARD TO CONFIDENCE IN DOCUMENTATION
/ INFORMATION FROM DFI AND OPERATION)
POFADJUSTED
+1
+1
-1
±X
POF + SUM OF ADJUSTMENTS
*THE RECORDED HISTORIC MAXIMUM OPERATION CONDITION SHOULD INCLUDE TEMPERATURE, PRESSURE AND
FLOW RATE
End expansion
End expansion (at the interface between pipeline and connected components) is to be considered for
all pipeline systems. Internal pressure and temperature will try to elongate a pipeline. End expansion
is normally not a concern for the pipeline itself. However, at each end or intermittent connection point,
components such as spools, flexible tails, risers, jumpers will have the capability to absorb a certain
amount of expansion. If expansion is excessive (or relevant interfacing component is not properly
designed concerning expansion), issues that may become relevant are e.g., displacement out of
position, interaction with other installations, excessive bending, leaks in connectors and valves.
40 | P a g e
RBI Methodology for Pipelines in Zubair Field
Table 23 - Engineering judgment Adjustment for PoF – End Expansion
ADJUSTMENTS OF POF BASED ON ENGINEERING JUDGMENT – END EXPANSION
CONDITION NOT APPLICABLE AS WELL AS ADJUSTMENT QUESTIONS
•
7
8
9
10
NOT APPLICABLE IF POF GIVEN (FIGURE 8 - FLOWCHART STRUCTURAL THREATS) = 1
ADJUSTMENT QUESTIONS
ADJUSTMENT
TEMPERATURE ABOVE ACCEPTABLE
+1
OBSERVED ABNORMAL DISPLACEMENT
+1
OBSERVED INTERFERENCE/COLLISIONS WITH OTHER
+1
INSTALLATIONS/ PARTS
LIMITATION IN ACCEPTABLE END EXPANSION IS LARGER THAN
-1
ESTIMATED END EXPANSION IN THE PIPELINE
ENGINEERING JUDGMENT OF OTHER ISSUES NOT COVERED
ABOVE (E .G. WITH REGARD TO CONFIDENCE IN DOCUMENTATION
/ INFORMATION FROM DFI AND OPERATION)
POFADJUSTED
11
±X
POF + SUM OF ADJUSTMENTS
On-bottom stability
On-bottom stability (lateral displacement of long sections caused by environmental loading) is to be
considered for all exposed pipelines. Limited lateral displacements (in the order of 5-20 meters) of
segments can occur for extreme environmental events (e.g., events with 10-, 100- return period
events).
Table 24 - Engineering judgment Adjustment for PoF – On-bottom Stability
ADJUSTMENTS OF POF BASED ON ENGINEERING JUDGMENT – ON-BOTTOM STABILITY
CONDITION NOT APPLICABLE AS WELL AS ADJUSTMENT QUESTIONS
•
•
NOT APPLICABLE IF POF GIVEN (FIGURE 8 - FLOWCHART STRUCTURAL THREATS) = 1
BURIED PIPELINE
ADJUSTMENT QUESTIONS
7
8
9
10
11
OBSERVED LATERAL DISPLACEMENT OF LONG SECTIONS ABOVE
20M FROM ORIGINAL ROUTE SHOULD INITIATE AN EXTENSIVE
EVALUATION OF MANY P IPELINES ASPECTS
OBSERVED LATERAL DISPLACEMENT AT END-TERMINATIONS, INLINE TEE ’S ETC.
EXPERIENCE HURRICANES, FLOODS OR SIMILAR SINCE LAST
INSPECTION
OPERATION ABOVE 5 YEARS WITHOUT OBSERVED LATERAL
MOTIONS
ENGINEERING JUDGMENT OF OTHER ISSUES NOT COVERED
ABOVE (E .G. WITH REGARD TO CONFIDENCE IN DOCUMENTATION
/ INFORMATION FROM DFI AND OPERATION)
POFADJUSTED
ADJUSTMENT
+1
+1
+1
-1
±X
POF + SUM OF ADJUSTMENTS
Pipeline free spans - Static overload and fatigue
Pipeline free spans are to be considered for exposed parts of a pipeline concerning static overload and
fatigue. Even if a pipeline is buried, free spans can often occur at the end of the pipeline as a result of
41 | P a g e
RBI Methodology for Pipelines in Zubair Field
tie-in geometry. Free span length and gaps are in many cases nonstationary. They can change due to
changes in temperature, pressure and flow rate within the pipeline.
Table 25 - Engineering judgment Adjustment for PoF – Free spans / Static overload and fatigue
ADJUSTMENTS OF POF BASED ON ENGINEERING JUDGMENT – ON-BOTTOM STABILITY
CONDITION NOT APPLICABLE AS WELL AS ADJUSTMENT QUESTIONS
•
•
7
8
NOT APPLICABLE IF POF GIVEN (FIGURE 8 - FLOWCHART STRUCTURAL THREATS) = 1
BURIED PIPELINE ( SECTIONS)
ADJUSTMENT QUESTIONS
ADJUSTMENT
OBSERVED SPANS ABOVE CRITERIA (LENGTH AND GAP)
+1
PIPELINE HAS NOT BUCKLED GLOBALLY AND SPAN CRITERIA ARE
+1
DEVELOPED WITH A PREMISE THAT BUCKLING SHOULD OCCUR
9
EXPERIENCE HURRICANES, FLOODS OR SIMILAR SINCE LAST
INSPECTION
+1
10
ENGINEERING JUDGMENT OF OTHER ISSUES NOT COVERED
ABOVE (E .G. WITH REGARD TO CONFIDENCE IN DOCUMENTATION
/ INFORMATION FROM DFI AND OPERATION)
±X
POFADJUSTED
POF + SUM OF ADJUSTMENTS
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RBI Methodology for Pipelines in Zubair Field
Appendix 2 Corrosion Rates Model
The Ref. [21] API RP 581 Standards have been developed for downstream industry and do not include
some damage mechanisms which are typical of upstream environments or the requirements and
limitations for the application of materials are different.
For this reason, some additional damage methodology assessment modules have been developed or
existing ones have been modified.
The following modules have been added referring to the International Standards indicated:
• MIC Microbiologically Induced Corrosion DNVGL-RP-G101
• Erosion Corrosion / Sand Erosion API RP 14E / DNVGL-RP-O501
While the following existing modules have been modified:
• CO2 corrosion NORSOK M506 / DeWaard & Milliams
The calculation procedure for the following mechanisms existing modules can be found in Ref. [21]
API RP 581, Part 2 Annex 2.B – Determination of Corrosion Rates:
• Sour Water Corrosion
• Soil Side Corrosion
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MIC Microbiologically Induced Corrosion
The effect of MIC is evaluated based on the presence of bacteria, operating conditions, presence of a monitoring system and the final probability of failure
assessed with a graph taken from DNVGL-RP0501.
The result of the module is a probability of failure (category of the probability of failure).
Figure 9 - MIC flowchart
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RBI Methodology for Pipelines in Zubair Field
Erosion Corrosion
For the assessment of the Erosion-Corrosion and Sand/Solids Corrosion, the approach is based on the API-RP14E for the evaluation in the case of a solids-free
system.
When the sand and/or solids are detected or foreseen in the fluids the approach is based on the standard DNVGL-RP-O501. In particular, the erosional velocity
is calculated for the bend geometry which is considered as the worst-case scenario in terms of erosion-corrosion.
The result of the erosion-corrosion module is a probability of failure while the sand erosion module is a corrosion rate.
Figure 10 - Erosion Corrosion Flowchart
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CO2 Corrosion
The damage module in Ref. [21 API 581 is applicable for the downstream sector, based on NORSOK M506 model. While the present module is applicable in
the upstream sector, the module in Ref. [21] API 581 does not take into account some factors, which have a significant effect on CO2 corrosion:
• API grade of the oil;
• Presence/absence of free water in the gas stream;
• Type of water: condensed or formation water;
• Presence of elemental Sulphur.
The final result of this assessment is a corrosion rate.
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RBI Methodology for Pipelines in Zubair Field
Figure 11 - CO2 Corrosion Part 1
47 | P a g e
RBI Methodology for Pipelines in Zubair Field
Figure 12 - CO2 Corrosion Part 2
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Appendix 3 Inspection / Maintenance Tasks
This Appendix provides minimum inspection requirements applicable to rigid pipelines, as per Ref [1].
Intelligent pigging is a key component of the inspection activities applicable to the pipeline system.
For those pipelines where the design does not allow conventional intelligent pigging, consideration
shall be given to modifying the line to enable such inspections or using alternative umbilical pigs.
Where this is considered impossible or impractical, the integrity shall be proven by other means such
as pressure testing or Direct Assessment approaches according to NACE (if applicable).
Table 26 - Onshore Pipelines Inspection/Maintenance Tasks
ONSHORE PIPELINES (AND SECTION OF PIPELINES)
INSPECTION/MAINTENANCE
FREQUENCY
NOTES
TASKS
EL: L / M
EL: H / VH / EH
BASELINE INSPECTION
PIPELINE EXTERNAL SURVEY CARRIED OUT WITHIN THE AS BUILT SURVEY 03516.COS.CNS.STD
(*)
“CONSTRUCTION AND
INSTALLATION OF ONSHORE
PIPELINES”
INTELLIGENT PIGGING
INSPECTION
PIPE TRACKING SYSTEM
CARRIED OUT DURING PRECOMMISSIONING/
COMMISSIONING PHASE (*)
CARRIED OUT WITHIN THE FABRICATION,
CONSTRUCTION AND INSTALLATION OF
PIPELINE
ESD VALVE PERFORMANCE
TESTING
PIPELINE RIGHT OF WAY
(ROW)
SURVEY, PRIVATE AND
PUBLIC
SECTIONS
WALL THICKNESS
MEASUREMENTS OF ABOVE
WITHIN 1 YEARS
IN-SERVICE INSPECTIONS
INSPECTION
NOT > 1 YEARS
23034.ENG.INT.STD
“PIPELINES IN-LINE
INSPECTION”
28083.ENG.INT.STD
“PIPE TRACKING SYSTEM
SPECIFICATION FOR
INSTALLATION
CONTRACTOR ”
TO BE INCLUDED IN
PRODUCTION PROCEDURE
THE REQUIREMENTS FOR THE
23037.ENG.INT.STD
“EXTERNAL SURVEY OF
PIPELINES IN THE ONSHORE
AREA”
WHERE INTERNAL CORROSION
NOT > 2 YEARS
NOT > 7 YEARS
PROVEN THAT INTERNAL
CORROSION IS NOT A
RELEVANT THREAT
ROUTE INSPECTION SHALL BE
IN ACCORDANCE WITH
COMPANY STANDARD
IS IDENTIFIED AS A POSSIBLE
MODE OF FAILURE
GROUND SECTIONS
INTELLIGENT PIGGING
MAY BE AVOIDED IF IT IS
NOT > 5 YEARS
49 | P a g e
RBI Methodology for Pipelines in Zubair Field
ONSHORE PIPELINES (AND SECTION OF PIPELINES)
INSPECTION/MAINTENANCE
FREQUENCY
NOTES
TASKS
EL: L / M
EL: H / VH / EH
UN-PIGGABLE LINES:
23034.ENG.INT.STD
PRESSURE TEST AT MAOP
“PIPELINES IN-LINE
OR D IRECT ASSESSMENT
INSPECTION”
(DA)
IN CASE A CORROSION RISK
NOT > 7 YEARS
ESD VALVE PERFORMANCE
TESTING
RIVER CROSSINGS:
• BURIAL SURVEY
(MAGNETIC OR ACOUSTIC)
• VISUAL INSPECTION AT
LOW TIDE/ DRY SEASON
CATHODIC PROTECTION:
• COMPLETE CATHODIC
PROTECTION (CP) SURVEY
USING “ ON – OFF” METHOD
• MONITOR OUTPUT
NOT > 5 YEARS
TO BE INCLUDED IN
PRODUCTION PROCEDURES
NOT > 1 YEAR
NOT > 6 YEARS
ASSESSMENT IS
PERFORMED:
• IT IS POSSIBLE TO
EXTEND OF MAXIMUM 3 YEARS
THE INSPECTION FREQUENCY IF
CORROSION RISK IS
PROVEN TO BE MINIMAL .
• IN PRESENCE OF SIGNIFICANT
CORROSION RISKS THE
INSPECTION FREQUENCY SHALL
BE REDUCED TO 1-3 YEARS
BETWEEN TWO CONSECUTIVE
SURVEYS.
• NOT REQUIRED IF IT IS
PROVEN THAT INTERNAL
CORROSION IS NOT A RELEVANT
THREAT .
NOT > 3 YEARS
NOT > 2 YEARS
TO BE INCLUDED IN
PRODUCTION PROCEDURES.
11555.VAR.COR.SDS
“GUIDELINES FOR BURIED
PIPELINES CATHODIC
PROTECTION INSPECTION
PLANNING”
VOLTAGE AND CURRENT OF
TRANSFORMER/RECTIFIER
NOT > 1 MONTH
11557.VAR.COR.STD
“CATHODIC PROTECTION
MEASUREMENTS AND SURVEYS
FOR ON LAND BURIED
PIPELINES”
PRESSURE CONTROL AND
PROTECTIVE EQUIPMENT ,
FOLLOW THE MAINTENANCE MANUAL
GIVEN BY THE ITEM SUPPLIER
VALVES AND ANCILLARY
EQUIPMENT
CARRY-OUT COLLECTION
AND ANALYSIS OF
OPERATIONAL DATA:
50 | P a g e
RBI Methodology for Pipelines in Zubair Field
ONSHORE PIPELINES (AND SECTION OF PIPELINES)
INSPECTION/MAINTENANCE
FREQUENCY
NOTES
TASKS
EL: L / M
EL: H / VH / EH
• OPERATING P&T
(INLET/OUTLET)
• FLUID COMPOSITION
(H2S, CO2 CONTENT)
• PRODUCED WATER (BSW,
PH)
• QUANTITY /FREQUENCY
OF INJECTED CORROSION
INHIBITORS
• DETECTION OF SAND AND
ABRASIVE PRODUCED
ELEMENTS.
SCOPE TO BE DETERMINED
BY SPECIFIC EXTRAORDINARY
EVENT
AS REQUIRED
AD-HOC
INSPECTION REVIEWS
FOLLOWING A SIGNIFICANT CHANGE IN THE ENVIRONMENT CONDITIONS,
EXTREME ENVIRONMENTAL EVENTS, DROPPED OBJECTS, THIRD-PARTY
ACTIVITIES, OBSERVED DAMAGES
51 | P a g e
RBI Methodology for Pipelines in Zubair Field
Appendix 4 Preventive Barrier
The four preventive groups compose of several elements as shown in Table 27 - Preventive Barrier
Functions.
Table 27 - Preventive Barrier Functions
PREVENTIVE BARRIER FUNCTIONS
BARRIER FUNCTION
BARRIER SYSTEM/ELEMENT
DESIGN BASIS
QA AND DOCUMENTATION OF DESIGN, FABRICATION,
INSTALLATION AND MODIFICATIONS
PRESSURE CONTAINMENT AND PRIMARY
PROTECTION
OPERATIONAL/PROCESS CONTROL
PIPELINE INTEGRITY CONTROL
PIPELINE INTEGRITY IMPROVEMENT
PIPELINE / OTHER PRESSURE CONTAINING COMPONENTS
PIPELINE COVER
PROTECTION AND SUPPORT STRUCTURES
INFORMATION SYSTEM TO 3RD PARTY
RESTRICTION AND SAFETY ZONE SYSTEMS
PRESSURE PROTECTION SYSTEM
EXTERNAL CORROSION PROTECTION SYSTEM
INTERNAL CORROSION PROTECTION SYSTEM
PROCESS CONTROL SYSTEM
OPERATIONAL PROCEDURES
STRATEGIES AND PLANS FOR PIPELINE INTEGRITY CONTROL
SYSTEMS AND PROCESSES FOR INSPECTION, MONITORING AND
TESTING
SYSTEMS AND PROCESSES FOR INTEGRITY ASSESSMENT
STRATEGIES AND PLANS FOR PIPELINE INTEGRITY IMPROVEMENT
SYSTEMS AND PROCESSES FOR MITIGATION, INTERVENTION AND
REPAIRS
An explanation for each Barrier System associated with the Barrier function is provided as follows:
• The Pressure Containment and Primary Protection function considers:
o Well documented and quality assured development and modification process. This
includes e.g.:
 A well-documented, quality assured and up-to-date Design Basis.
 Well-documented and quality assured (development or modification) design,
fabrication and installation.
o The pipeline itself and other pressure containing components.
o Pipeline Cover may include soil cover, gravel supports and covers, rock dumps,
concrete mattresses, sandbags etc. for protection against external threats and to
control global pipeline behaviour.
o Protection and support structures, different types of protection and support
structures are applied for mechanical protection against external threats and to
control global pipeline behaviour.
o Information system to 3rd parties may include, information to landowners along
pipeline routes (onshore), information signs along pipeline routes (onshore), the
inclusion of pipeline information in public maps and to emergency responders.
52 | P a g e
RBI Methodology for Pipelines in Zubair Field
Restriction and Safety zone systems, both permanent and temporary restriction and
safety zones may be defined and marked up to minimize risk in certain areas. In
addition to defining and marking up such areas, procedures and communication
systems need to be in place and applied correctly by qualified personnel.
o Pressure Protection System comprises the pressure control system and the pressure
safety system. Each of these systems comprises sensors, logic solvers, valves, alarm
and communication systems, procedures and qualified personnel.
o External Corrosion Protection System (valid for all material types) typically comprises
some combination of:
 corrosion allowance
 corrosion protective coatings
 cathodic protection
o Internal Corrosion Protection System (valid for all material types) typically comprises
some combination of:
 Use of internal coating/lining /cladding, and corrosion allowance
 Processing systems for removal of liquid water and/or corrosive agents
 Chemical treatment system
 Pig cleaning system
The operational/process control function ensures that the pipeline system is being operated
as intended. Concerning pipeline systems, operation control measures must be in place to
ensure that critical fluid parameters are kept within the specified design limits. Examples of
parameters that should be controlled are pressure and temperature at the inlet and outlet of
the pipeline, dew point for gas lines, fluid composition, water content and flow rate, density
and viscosity. The operational / process control function comprises:
o Process control hardware and software such as sensors, logic solvers, actuators,
valves, control rooms, alarm and communication systems, and qualified personnel.
o Procedures such as start-up, operations and shutdown procedures, procedures for
the treatment of non-conformances, procedures for implementation of operational
restrictions, instructions for fluid re-filling, etc.
o Qualified personnel
The pipeline integrity control function typically includes:
o Strategies and long-term programs (for inspection, monitoring, testing and integrity
assessment activities) should be in place and should be risk based. Short-term plans
should also be in place and should be based on long-term programs.
o Systems and processes including procedures, tools and vessels (i.e., hardware and
software to such activities), reporting systems, and qualified personnel for:
 Inspection, this includes both external and internal inspection.
 Monitoring is the measurement, collection and review of data that indirectly
can give information on the condition of a component or a system
 Testing, such activities are carried out to test if the system or parts of the
system have the required structural integrity and/or are working properly.
Testing may include strength and leak testing of pipelines and components by
different types of pressure tests (system pressure testing, hydrostatic testing,
gas or media testing, shut-in testing), and functional testing of the pressure
protection system.
 Integrity assessments, these activities involve a detailed review of
information and data gathered through the inspection, monitoring and
testing activities (as well as any other relevant sources), identification of
o
•
•
53 | P a g e
RBI Methodology for Pipelines in Zubair Field
•
defects that require further evaluations, evaluation of selected defects by
applying appropriate methods and adequate levels of detail, and providing
recommendations for further action.
The Pipeline Integrity Improvement function typically includes:
o Strategies and contingency plans for how to handle unacceptable anomalies and
damages should be in place well in advance.
o Systems and processes including procedures, tools and vessels (i.e., hardware and
software to such activities), reporting systems, and qualified personnel for:
 Mitigations regarding internal conditions
 Interventions regarding external conditions,
 Repairs to the containment function and protection system itself
For each element a recommended relevance score is proposed, Table 28 - Barrier relevance to the
different threat groups, to indicate the importance against each identified threat. Relevance can
change with time (an element may be more relevant during the initial operation period and less
important afterwards)
Table 28 - Barrier relevance to the different threat groups
BARRIER RELEVANCE TO THE DIFFERENT THREAT GROUPS
BARRIER SYSTEM/ELEMENT
CORROSION /
EROSION
DESIGN BASIS
QA AND DOCUMENTATION OF DESIGN, FABRICATION,
STRUCTURAL
MR-VH
INSTALLATION AND MODIFICATIONS
PIPELINE / OTHER PRESSURE CONTAINING COMPONENTS
PIPELINE COVER
PROTECTION AND SUPPORT STRUCTURES
INFORMATION SYSTEM TO 3RD PARTY
RESTRICTION AND SAFETY ZONE SYSTEMS
PRESSURE PROTECTION SYSTEM
EXTERNAL CORROSION PROTECTION SYSTEM
INTERNAL CORROSION PROTECTION SYSTEM
PROCESS CONTROL SYSTEM
OPERATIONAL PROCEDURES
STRATEGIES AND PLANS FOR PIPELINE INTEGRITY CONTROL
SYSTEMS AND PROCESSES FOR INSPECTION, MONITORING AND
3RD
PARTY
NR
NR
NR
NR
LR-VH
MR-VH
NR-VH
NR-MR
MR-VH
TESTING
SYSTEMS AND PROCESSES FOR INTEGRITY ASSESSMENT
STRATEGIES AND PLANS FOR PIPELINE INTEGRITY IMPROVEMENT
SYSTEMS AND PROCESSES FOR MITIGATION, INTERVENTION AND
REPAIRS
NOTE:
•
•
•
•
•
MR-VH
NR – N OT R ELEVANT
LR – L OW R ELEVANT
MR – M EDIUM R ELEVANT
HR – H IGH R ELEVANT
VH – V ERY H IGH R ELEVANT
54 | P a g e
RBI Methodology for Pipelines in Zubair Field
Key issues and/or questions to consider as guidance when setting a score to the element evaluation
have been listed in the following tables (table 14 to table 17).
Table 29 -Third-party Threats Evaluation
ELEMENT EVALUATION
DESIGN BASIS
QA AND
DOCUMENTATION OF
DESIGN, FABRICATION,
INSTALLATION AND
MODIFICATIONS
PIPELINE / OTHER
PRESSURE CONTAINING
COMPONENTS
PIPELINE COVER
THIRD-PARTY THREATS
KEY ISSUES
GENERAL
WELL DEFINED ACTIVITY LEVEL - IS THERE ANY UNANTICIPATED ACTIVITY IN THE
AREA THAT CAN INTERFERE WITH THE PIPELINE OR IS THERE EXPECTED ANY SUCH
ACTIVITY IN THE NEAR FUTURE?
EXPOSURE TO CYCLIC LOADING IS WELL DEFINED - A POTENTIAL (3RD PARTY)
DAMAGE TO PIPELINES EXPOSED TO CYCLIC LOADING FROM OPERATION (PRESSURE ,
TEMPERATURE , SHUT DOWNS), CURRENT , WAVES ETC. CAN DEVELOP FASTER INTO
FAILURE THAN A PIPELINE WITH LOW EXPOSURE TO CYCLIC LOADING
DROPPED OBJECTS
POTENTIAL LOADS ARE WELL DEFINED
GENERAL
DESIGNED ACCORDING TO RECOGNIZED STANDARDS AND METHODS
GENERAL
D/T<40? DIAMETER/THICKNESS RATIO ABOVE 40 IS CONSIDERED AS A LESS
ROBUST PIPELINE SYSTEM. ANY RELEVANT DAMAGES DETECTED, ASSESSED,
MITIGATED, TESTED?
RECENTLY CONFIRMED NOT TO BE DAMAGED (NUMBER OF YEARS SINCE LAST
INSPECTION?)
GENERAL
TYPE OF COVER (BURIED OR ROCK DUMPED)
BURIAL DEPTH (0.1-1.0 METERS OR MORE)
PIPELINE CONFIRMED ADEQUATELY PROTECTED (I.E. BURIED OR ROCK DUMPED) BY
INSPECTION
NUMBER OF YEARS SINCE LAST INSPECTION?
PROTECTION AND
SUPPORT STRUCTURES
INFORMATION SYSTEM
TO 3 RD PARTY
RESTRICTION AND
SAFETY ZONE SYSTEMS
PRESSURE PROTECTION
GENERAL
PROTECTION AND SUPPORT STRUCTURE IN PLACE (CONCRETE/WEIGHT COATING,
PROTECTION STRUCTURES) AND CONFIRMED ADEQUATE BY INSPECTION (NUMBER
OF YEARS SINCE LAST INSPECTION?)
GENERAL
INFORMATION SHARING IN PLACE WITH AUTHORITIES, ASSOCIATIONS, MAPS,
CHARTS, ETC.
IF THERE IS A CLEARLY DEFINED RESTRICTION ZONE FOR TRAFFIC AROUND THE
PIPELINE , THE PROBABILITY OF A DAMAGE RELATED TO INTERFERENCE IS
SIGNIFICANTLY REDUCED.
NO UNPROTECTED COMPONENTS WITHIN THE SAFETY ZONE
NR
SYSTEM
EXTERNAL CORROSION
NR
PROTECTION SYSTEM
55 | P a g e
RBI Methodology for Pipelines in Zubair Field
INTERNAL CORROSION
NR
PROTECTION SYSTEM
PROCESS CONTROL
SYSTEM
OPERATIONAL
PROCEDURES
STRATEGIES AND PLANS
FOR PIPELINE INTEGRITY
CONTROL
SYSTEMS AND
PROCESSES FOR
INSPECTION,
MONITORING AND
TESTING
SYSTEMS AND
PROCESSES FOR
INTEGRITY ASSESSMENT
STRATEGIES AND PLANS
FOR PIPELINE INTEGRITY
IMPROVEMENT
SYSTEMS AND
PROCESSES FOR
MITIGATION,
INTERVENTION AND
REPAIRS
EASE OF ACCESS TO PROCESS DATA IN CASE DEFECTS NEED TO BE ASSESSED
URGENTLY .
SYSTEMS IN PLACE TO MAINTAIN ENVELOPES AND FOLLOW UP RESTRICTIONS
GENERAL
PROCEDURES TO RECORD AND EASILY ACCESS PROCESS DATA IN PLACE
PROCEDURES FOR STAYING WITHIN ENVELOPE (INCL. RESTRICTIONS) IN PLACE
GENERAL
LONG TERM INSPECTION MAINTENANCE AND REPAIR PROGRAM IN PLACE (RISK
BASED)
GENERAL
ACTUAL IMPLEMENTATION OF PROGRAM
REGULAR REVIEWS OF OPERATIONAL DATA
VESSEL CONTRACT IN PLACE IN CASE OF NEED FOR URGENT NDT OF RELEVANT
DAMAGE
GENERAL
ASSESSMENT PROCEDURES FOR ASSESSMENT OF RELATED DAMAGES
TOOLS/SOFTWARE FOR ASSESSMENT OF RELATED DAMAGES
VERIFICATION OF SYSTEM AND INTEGRITY ASSESSMENTS (THIRD-PARTY OR BY
RELEVANT RESOURCES WITHIN COMPANY )
GENERAL
REPAIR STRATEGY IN PLACE FOR RELATED THIRD-PARTY DAMAGES
GENERAL
REPAIR SYSTEM AVAILABLE IN CASE OF RELATED DAMAGES S PARE PARTS
VESSEL CONTRACT IN PLACE (FOR INTERVENTION/REPAIRS)
OPERATIONAL RESTRICTIONS (E.G. CYCLIC LOADING)
EMERGENCY PLANS AND PROCEDURES
PROCEDURES IN PLACE TO ASSIST THIRD-PARTY HOOKED IN PIPELINE OR
ASSOCIATED EQUIPMENT
Table 30 - Internal Corrosion Threats Evaluation
ELEMENT EVALUATION
DESIGN BASIS
QA AND
DOCUMENTATION OF
DESIGN, FABRICATION,
INSTALLATION AND
MODIFICATIONS
INTERNAL CORROSION
KEY ISSUES
DESIGN LIFE SPECIFIED, MATERIAL SELECTED, DESIGN AND OPERATIONAL
CONDITION DEFINED (E . G. P, T, FLUID COMPOSITION)
COMPLIANCE WITH ISO-15156 (NACE MR 175), IF RELEVANT
MEANS OF CORROSION CONTROL DEFINED
MATERIALS SELECTION REPORT
PIPE MANUFACTURING AND WELDING ACCORDING TO DESIGN STANDARD
TEMPORARY STORAGE BEFORE INSTALLATION TO REDUCE RISK FOR CORROSION
(E.G. APPLICATION OF END CAPS)
PRESSURE TESTING PROCEDURE (E.G. FLUID TYPE, CLEANING AND DRYING)
3RD PARTY VERIFICATION OR CERTIFICATION BASELINE INSPECTION BY ILI
56 | P a g e
RBI Methodology for Pipelines in Zubair Field
PIPELINE / OTHER
PRESSURE CONTAINING
COMPONENTS
NUMBER OF YEARS SINCE INSTALLATION
NUMBER OF YEARS SINCE LAST ILI?
NO METAL LOSS EXCEEDING THE CORROSION ALLOWANCE?
NO METAL LOSS EXCEEDING 85% OF NOMINAL WALL THICKNESS?
NO LOW POINTS WHICH CAN LEAD TO SIGNIFICANT DROP OUT OF WATER, IF
RELEVANT
ILI – INTERNAL CONDITION BETTER THAN PRESUPPOSED IN DESIGN
PIPELINE COVER
MAY BE RELEVANT IF THE COVER ACTS AS INSULATION TO PREVENT
CONDENSATION AND TOP OF LINE (TOL) CORROSION. OTHERWISE GENERALLY
NOT RELEVANT WITH REGARD TO INTERNAL CORROSION
PROTECTION AND
NR
SUPPORT STRUCTURES
INFORMATION SYSTEM
TO 3 RD PARTY
RESTRICTION AND
NR
NR
SAFETY ZONE SYSTEMS
PRESSURE PROTECTION
SYSTEM
PRESSURE PROTECTION SYSTEM (PPS) IN PLACE AND SET POINTS ARE CORRECT
ACCORDING TO DESIGN AND/ OR PIPELINE OPERATIONAL ENVELOPE
DEFINED PRESSURE LIMITS MONITORED AND WITHIN ENVELOPE?
PPS MAINTENANCE AND TEST PROGRAM IN PLACE AND IMPLEMENTED
PPS TEST RESULTS ARE ACCEPTABLE
EXTERNAL CORROSION
NR
PROTECTION SYSTEM
INTERNAL CORROSION
PROTECTION SYSTEM
PROCESS CONTROL
SYSTEM
OPERATIONAL
PROCEDURES
IS AN INTERNAL CORROSION CONTROL SYSTEM IN PLACE FOR PROTECTING THE
PIPELINE AGAINST INTERNAL CORROSION? (INCLUDE EQUIPMENT FOR ON LINE
MONITORING, CORROSION PROBES, FLUID ANALYSES, CHEMICAL INJECTION
AVAILABILITY , RESIDUAL CHEMICAL ETC.)
IS THE CORROSION CONTROL PROGRAM SATISFACTORY FOR CORROSION CONTROL ?
ARE CHEMICALS USED FOR CORROSION CONTROL QUALIFIED FOR THE INTENDED
SERVICE ?
ARE MONITORED PARAMETERS KEPT WITHIN OPERATIONAL ENVELOPE?
IS AVAILABILITY OF CHEMICAL INJECTION ACCORDING TO DESIGN?
REDUNDANCY OF CHEMICAL INJECTION EQUIPMENT
AVAILABILITY OF SPARE PARTS FOR EQUIPMENT FOR CHEMICAL INJECTION
IS EQUIPMENT FOR CORROSION SURVEILLANCE CALIBRATED AND MAINTAINED
ACCORDING TO PLAN?
IS EQUIPMENT USED FOR CHEMICAL INJECTIONS CALIBRATED AND MAINTAINED
ACCORDING TO PLAN?
IF INTERNAL CLEANING IS DEFINED AS A PART OF CORROSION CONTROL, ARE THE
CLEANING PROGRAMS IMPLEMENTED ACCORDING TO PLAN?
ARE THERE PLANS FOR UPSET CONDITION?
IS PROCESS CONTROL SYSTEM RELIABLE?
IS PROCESS CONTROL SYSTEM MAINTAINED ACCORDING TO PLAN? IS PROCESS
DATA CONCLUDED RELIABLE ?
ARE OPERATIONAL PARAMETERS MONITORED AND WITHIN ENVELOPE? IS THE
PRODUCTION STABLE ?
IS RECOMMENDATIONS GIVEN IN MATERIAL SELECTION REPORT FOR CORROSION
CONTROL IMPLEMENTED?
ARE PROCEDURES FOR OUT OF SPEC. SITUATIONS IN PLACE AND
IMPLEMENTED?
57 | P a g e
RBI Methodology for Pipelines in Zubair Field
STRATEGIES AND PLANS
FOR PIPELINE INTEGRITY
CONTROL
SYSTEMS AND
PROCESSES FOR
INSPECTION,
MONITORING AND
TESTING
SYSTEMS AND
PROCESSES FOR
INTEGRITY ASSESSMENT
STRATEGIES AND PLANS
FOR PIPELINE INTEGRITY
IMPROVEMENT
IS A RISK BASED CORROSION STRATEGY FOR CORROSION CONTROL IN PLACE (ILI,
REGULAR REVIEW OF MONITORING DATA, CORROSION PROBES, ETC.)
IS ILI CARRIED OUT ACCORDING TO THE PLAN?
ARE PROCEDURES FOR PRESERVATION OF PIG LAUNCHERS AND RECEIVERS IN PLACE
AND IMPLEMENTED?
IS MONITORING AND INSPECTION DATA EXPLICITLY EVALUATED AND DOCUMENTED
ON A REGULAR BASIS AND ACCORDING TO PLANS?
IS THE EFFICIENCY OF INJECTED CHEMICALS EVALUATED ON A REGULAR BASIS?
ARE PROCEDURES FOR ASSESSMENT OF CORROSION DEFECTS IN PLACE AND
IMPLEMENTED?
ARE PROCEDURES IN PLACE AND IMPLEMENTED FOR ASSESSING MONITORING
AND INSPECTION DATA?
STRATEGY AND CONTINGENCY PLANS INCLUDING SPECIFICATION OF NEEDS FOR
PRE -INVESTMENTS IN CONTINGENCY REPAIR EQUIPMENT AND SPARES (E .G .
CHEMICAL INJECTION EQUIPMENT , GAS DEHYDRATION SYSTEM)
STRATEGY IN PLACE FOR MITIGATING INTERNAL CORROSION IF ILI INDICATES
HIGHER METAL LOSS THAN ANTICIPATED?
PIPELINE REPAIR STRATEGY AND PIPELINE SPARE PART STRATEGY IN PLACE IN
CASE OF UNACCEPTABLE CORROSION
SYSTEMS AND
PROCESSES FOR
MITIGATION,
INTERVENTION AND
REPAIRS
REPAIR SYSTEM IN PLACE CAPABLE OF REPAIRING DAMAGE BEFORE IT DEVELOPS
INTO FAILURE . SPARE PIPE AND PIPELINE COMPONENTS IN PLACE ACCORDING TO
STRATEGY
ACCESS TO VESSEL CAPABILITIES IN ORDER TO BE ABLE TO ACT REASONABLY
QUICKLY
TESTING AND FOLLOW UP OF REPAIRS TO ENSURE THAT THE SAFETY LEVEL IS REESTABLISHED
EMERGENCY PLANS AND PROCEDURES FOR SAFE AND EFFICIENT HANDLING OF
NECESSARY REPAIR
Table 31 - External Corrosion Threats Evaluation
ELEMENT EVALUATION
DESIGN BASIS
EXTERNAL CORROSION
KEY ISSUES
HAS THE BASIS FOR DESIGN (T, P, DEGREE OF BURIAL, PROTECTION STRUCTURES)
AND THE EXTERNAL CORROSION PROTECTION SYSTEM BEEN SPECIFIED?
IS EXTERNAL CORROSION PROTECTION SYSTEM DESIGN ACCORDING TO RECOGNIZED
STANDARDS? H AS CURRENT DRAIN ITEMS FOR PIPELINE CP-SYSTEM BEEN
IDENTIFIED AND HANDLE THROUGH DESIGN?
58 | P a g e
RBI Methodology for Pipelines in Zubair Field
QA AND
DOCUMENTATION OF
DESIGN, FABRICATION,
INSTALLATION AND
MODIFICATIONS
PIPELINE / OTHER
PRESSURE CONTAINING
COMPONENTS
PIPELINE COVER
PROTECTION AND
SUPPORT STRUCTURES
INFORMATION SYSTEM
TO 3 RD PARTY
RESTRICTION AND
ARE AS-LAID SURVEY REPORTS IN PLACE?
ANY INCIDENTS OR SHORT-COMINGS DURING MANUFACTURING AND
APPLICATION OF COATING AND FIELD JOINT COATINGS? H AS THE CRITICALLY OF
THESE SHORTCOMING BEEN ASSESSED?
ANY INCIDENCES OR SHORTCOMINGS DURING MANUFACTURING AND
INSTALLATION OF ANODES? I S FABRICATION ACCORDING TO RECOGNIZED
STANDARDS? H AS THE CRITICALLY OF ANY SHORTCOMING BEEN ASSESSED?
ARE THE MANUFACTURING QUALIFICATION TRIALS ACCEPTABLE ACCORDING TO
STANDARD?
HAS STORAGE BEFORE INSTALLATION BEEN ADEQUATE?
IS THE DESIGN/FABRICATION/INSTALLATION VERIFIED OR CERTIFIED BY THIRD
PARTY ?
NO EXTERNAL METAL LOSS EXCEEDING THE CORROSION ALLOWANCE?
NO EXTERNAL METAL LOSS EXCEEDING 85% OF NOMINAL WALL THICKNESS?
ILI ASSESSMENT: EXTERNAL CONDITION BETTER THAN ASSUMED IN DESIGN?
NR (NOTICE THAT PIPELINE COVER MAY HAVE A NEGATIVE IMPACT ON EXTERNAL
CORROSION)
NR (NOTICE THAT THESE MAY HAVE A NEGATIVE IMPACT ON EXTERNAL
CORROSION)
NR
NR
SAFETY ZONE SYSTEMS
PPS IN PLACE AND SET POINTS ARE CORRECT ACCORDING TO DESIGN AND/OR
PRESSURE PROTECTION
SYSTEM
EXTERNAL CORROSION
PROTECTION SYSTEM
INTERNAL CORROSION
PIPELINE OPERATIONAL ENVELOPE
DEFINED PRESSURE LIMITS MONITORED AND WITHIN ENVELOPE?
PPS MAINTENANCE AND TEST PROGRAM IN PLACE AND IMPLEMENTED
PPS TEST RESULTS ARE ACCEPTABLE
IS IT POSSIBLE TO MONITOR THE CP-SYSTEM AND INSPECT THE COATING
PERFORMANCE ?
ARE THE CP-SYSTEM AND COATING CONDITION INSPECTED ON A REGULAR BASIS?
ARE ANY COATING DAMAGES REGISTERED? ARE ANY ANODES INACTIVE OR
DAMAGED?
HAS EXCESSIVE ANODE CONSUMPTION BEEN REGISTERED?
HAVE PROTECTIVE POTENTIAL BEEN MEASUREMENTS ON BARE METAL WITHIN
ACCEPTANCE CRITERIA?
NR
PROTECTION SYSTEM
PROCESS CONTROL
SYSTEM
OPERATIONAL
PROCEDURES
STRATEGIES AND PLANS
FOR PIPELINE INTEGRITY
CONTROL
IS PROCESS CONTROL SYSTEM RELIABLE?
IS PROCESS CONTROL SYSTEM MAINTAINED ACCORDING TO PLAN? IS PROCESS
DATA CONCLUDED RELIABLE ?
ARE OPERATIONAL PARAMETERS MONITORED AND WITHIN ENVELOPE? IS THE
PRODUCTION STABLE ?
IS RECOMMENDATIONS GIVEN IN MATERIAL SELECTION REPORT FOR CORROSION
CONTROL IMPLEMENTED?
ARE PROCEDURES FOR OUT OF SPEC. SITUATIONS IN PLACE AND IMPLEMENTED?
IS A RISK BASED CORROSION STRATEGY FOR CORROSION CONTROL IN PLACE (ILI,
ROV INSPECTION, VISUAL INSPECTION, CP MEASUREMENTS)
59 | P a g e
RBI Methodology for Pipelines in Zubair Field
SYSTEMS AND
INSPECTION AND MONITORING CARRIED OUT ACCORDING TO THE PLANS?
PROCESSES FOR
INSPECTION,
MONITORING AND
TESTING
SYSTEMS AND
PROCESSES FOR
INTEGRITY ASSESSMENT
STRATEGIES AND PLANS
FOR PIPELINE INTEGRITY
IMPROVEMENT
SYSTEMS AND
PROCESSES FOR
MITIGATION,
INTERVENTION AND
REPAIRS
ARE PROCEDURES FOR ASSESSMENT OF CORROSION DEFECTS IN PLACE AND
IMPLEMENTED?
STRATEGY AND CONTINGENCY PLANS INCLUDING SPECIFICATION OF REPAIR
EQUIPMENT AND SPARES
STRATEGY IN PLACE FOR MITIGATING EXTERNAL CORROSION IF ILI INDICATES
HIGHER METAL LOSS THAN ANTICIPATED? P IPELINE REPAIR STRATEGY AND PIPELINE
SPARE PART STRATEGY IN PLACE IN CASE OF UNACCEPTABLE CORROSION
REPAIR SYSTEM IN PLACE CAPABLE OF REPAIRING DAMAGE BEFORE IT DEVELOPS
INTO FAILURE . SPARE PIPE AND PIPELINE COMPONENTS IN PLACE ACCORDING TO
STRATEGY
ACCESS TO VESSEL CAPABILITIES IN ORDER TO BE ABLE TO ACT REASONABLY
QUICKLY TESTING AND FOLLOW UP OF REPAIRS TO ENSURE THAT THE SAFETY LEVEL
IS RE -ESTABLISHED
EMERGENCY PLANS AND PROCEDURES FOR SAFE AND EFFICIENT HANDLING OF
NECESSARY REPAIR
Table 32 - Structural Threats Evaluation
ELEMENT EVALUATION
DESIGN BASIS
STRUCTURAL THREATS
KEY ISSUES
GENERAL
DESIGNED ACCORDING TO RECOGNIZED STANDARDS AND METHODS
KNOWN / PROVEN DESIGN APPROACH
GLOBAL BUCKLING (EXPOSED)
KNOWN / PROVEN MATERIAL SELECTION
WELL DEFINED FUNCTIONAL LOADS (P, T)
WELL DEFINED SOIL PARAMETERS
WELL DEFINED SEABED TOPOGRAPHY
GLOBAL BUCKLING (BURIED)
KNOWN / PROVEN MATERIAL SELECTION
WELL DEFINED FUNCTIONAL LOADS (P, T)
WELL DEFINED SOIL PARAMETERS
STATIC OVERLOAD
KNOWN / PROVEN MATERIAL SELECTION
WELL DEFINED SEABED TOPOGRAPHY
WELL DEFINED FUNCTIONAL LOADS (P, T, CONTENT WEIGHT)
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RBI Methodology for Pipelines in Zubair Field
GENERAL
EXPERIENCED DESIGNER
DESIGN VERIFIED BY 3RD PARTY
GLOBAL BUCKLING (EXPOSED)
DESIGN IS BASED UPON SIMPLIFIED AND COARSE METHODS / CONSERVATIVE
QA AND
DOCUMENTATION OF
DESIGN, FABRICATION,
INSTALLATION AND
MODIFICATIONS
APPROACH
MEASURES TO CONTROL PIPELINE EXPANSION BEHAVIOUR CONFIRMED THROUGH
AS-BUILT SURVEY AND PRIOR TO START -UP
GLOBAL BUCKLING (BURIED)
DESIGN IS BASED UPON SIMPLIFIED AND COARSE METHODS / CONSERVATIVE
APPROACH
COVER HEIGHT REQUIREMENT CONFIRMED THROUGH AS-BUILT SURVEY
STATIC OVERLOAD
WELL DEFINED ACCEPTANCE CRITERIA
EXPERIENCED INSTALLATION CONTRACTOR
KNOWN / PROVEN WELDING PROCEDURE ADOPTED
INSTALLATION / WELDING WITNESSED BY 3RD PARTY
INSTALLATION / WELDING WELL DOCUMENTED
GLOBAL BUCKLING (EXPOSED)
PIPELINE OPERATED WITH FUNCTIONAL LOADS (P, T) SIGNIFICANTLY BELOW
DESIGN LIMITS
GLOBAL BUCKLING CONFIRMED ACCEPTABLE AFTER PEAK OPERATION
OBSERVATIONS/INTEGRITY ASSESSMENTS CONFIRM CONSERVATIVE DESIGN
IN CASE OF HIGH UTILIZATION, POF (LOSS OF CONTAINMENT) REDUCED IF:
• PIPE CROSS SECTION NOT SUSCEPTIBLE TO LOCAL BUCKLING (D/T < 30)
• MODERATE 3RD PARTY ACTIVITIES WITH MODERATE GEAR IN THE AREA
• PRODUCTION IS STABLE
GLOBAL BUCKLING (BURIED)
PIPELINE OPERATED WITH FUNCTIONAL LOADS (P, T) SIGNIFICANTLY BELOW
PIPELINE / OTHER
PRESSURE CONTAINING
COMPONENTS
DESIGN LIMITS OR PROCESS PARAMETERS ARE DECREASING PAST MAX PRODUCTION
NO SEABED SUBSIDENCE OR OTHER PHENOMENA CAUSING HORIZONTAL SOIL
MOVEMENT
UPHEAVALS NOT OBSERVED
IN CASE AN UPHEAVAL OCCURS, POF (LOSS OF CONTAINMENT) REDUCED IF:
• PRODUCTION IS STABLE
• PIPE CROSS SECTION NOT SUSCEPTIBLE TO LOCAL BUCKLING (D/T < 30)
• 3RD PARTY ACTIVITIES NOT RELEVANT IN THE AREA
STATIC OVERLOAD
PIPELINE CONFIGURATION CONFIRMED ACCEPTABLE AND STABLE THROUGH INSERVICE INSPECTION
PIPELINE CONFIGURATION NOT SENSITIVE TO OPERATIONAL MODE
PIPELINE CONFIGURATION NOT SENSITIVE TO SEASONAL VARIATIONS
COMBINATIONS WITH OTHER DEFECT TYPES (E.G. METAL LOSS, DENTS) HAVE NOT
BEEN OBSERVED
3RD PARTY ACTIVITIES NOT RELEVANT IN THE AREA
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RBI Methodology for Pipelines in Zubair Field
GLOBAL BUCKLING (EXPOSED)
FEED-IN TO GLOBAL BUCKLES LIMITED BY ROCK COVERS
PIPELINE COVER VERIFIED THROUGH IN-SERVICE INSPECTIONS
NO MECHANISMS PRESENT AFFECTING ROCK COVER OVER TIME
PIPELINE EXPANSION CONTROLLED BY OTHER MEANS
PIPELINE COVER
GLOBAL BUCKLING (BURIED)
PIPELINE CONTINUOUSLY COVERED WITH ARTIFICIAL BACKFILL (ROCK DUMPING)
PIPELINE COVER HEIGHT VERIFIED THROUGH IN-SERVICE INSPECTIONS
NO MECHANISMS PRESENT AFFECTING COVER HEIGHT OR UPLIFT RESISTANCE OVER
TIME
PROTECTION AND
SUPPORT STRUCTURES
INFORMATION SYSTEM
TO 3 RD PARTY
RESTRICTION AND
STATIC OVERLOAD
INTEGRITY OF MITIGATING MEASURES VERIFIED THROUGH IN-SERVICE INSPECTIONS
NO MECHANISMS PRESENT AFFECTING THE MITIGATING MEASURES OVER TIME
GLOBAL BUCKLING (EXPOSED)
NOTE: IMPORTANT TO CONSIDER THIS IN CONJUNCTION WITH THE INFORMATION
RELATED TO THE PIPELINE COVER INTEGRITY (ESPECIALLY WHEN APPLYING THE
WEIGHING FACTORS)
ROBUST SET OF MEASURES CAUSING SUFFICIENT PIPELINE IMPERFECTIONS
INSTALLED (SNAKE LAY , ARTIFICIAL TRIGGERS, ROCK CARPETS, VARYING
SUBMERGED PIPE WEIGHT , ETC.)
GLOBAL BUCKLING (BURIED)
NR
STATIC OVERLOAD
INTEGRITY OF MITIGATING MEASURES VERIFIED THROUGH IN-SERVICE INSPECTIONS
NO MECHANISMS PRESENT AFFECTING THE MITIGATING MEASURES OVER TIME
NR (GENERALLY)
NR (GENERALLY)
SAFETY ZONE SYSTEMS
PRESSURE PROTECTION
NR
SYSTEM
EXTERNAL CORROSION
NR
PROTECTION SYSTEM
INTERNAL CORROSION
NR
PROTECTION SYSTEM
PROCESS CONTROL
SYSTEM
OPERATIONAL
PROCEDURES
STRATEGIES AND PLANS
FOR PIPELINE INTEGRITY
CONTROL
GENERAL
RELIABLE CONTROL SYSTEM IN PLACE TO MEASURE/CONTROL PRESSURE,
TEMPERATURE AND FLOW
EASILY ACCESSIBLE PROCESS DATA
GENERAL
PROCEDURES / ROUTINES IN PLACE TO REGULARLY REVIEW PROCESS DATA
PROCEDURES / ROUTINES IN PLACE TO HANDLE DEVIATIONS
PROCESS DATA CONCLUDED RELIABLE
GENERAL
RISK BASED / CONDITION BASED PLAN FOR INTEGRITY CONTROL EXISTS AND ARE
UPDATED
62 | P a g e
RBI Methodology for Pipelines in Zubair Field
SYSTEMS AND
PROCESSES FOR
INSPECTION,
MONITORING AND
TESTING
GENERAL
PLANNED INSPECTION ACTIVITIES ARE PERFORMED WITH REQUIRED QUALITY
GLOBAL BUCKLING (EXPOSED), GLOBAL BUCKLING (BURIED), STATIC OVERLOAD
PLANNED REVIEWS OF OPERATIONAL DATA ARE PERFORMED AND DOCUMENTED
GLOBAL BUCKLING (EXPOSED)
ASSESSMENT PROCEDURES, CORRESPONDING TOOLS AND E XPERTISE FOR GLOBAL
BUCKLING ARE IN PLACE
HIGH DEGREE OF CORRELATION BETWEEN THEORETICAL PREDICTIONS AND
OBSERVATIONS
OBSERVED DEVIATIONS RELATED TO OPERATIONAL DATA EVALUATED/ASSESSED
SYSTEMS AND
PROCESSES FOR
INTEGRITY ASSESSMENT
GLOBAL BUCKLING (BURIED)
ASSESSMENT PROCEDURES, CORRESPONDING TOOLS AND E XPERTISE FOR UHB IN
PLACE
STATIC OVERLOAD
ASSESSMENT PROCEDURES AND CORRESPONDING TOOLS ARE IN PLACE
HIGH DEGREE OF CORRELATION BETWEEN THEORETICAL PREDICTIONS AND
OBSERVATIONS
RELATED TO PIPELINE CONFIGURATION
OBSERVED DEVIATIONS RELATED TO OPERATIONAL DATA EVALUATED/ASSESSED
GLOBAL BUCKLING (EXPOSED)
REPAIR STRATEGY FOR CROSS SECTION (EXCESSIVE OVALISATION OR LOCAL
BUCKLING) AND FATIGUE / FRACTURE RELATED DAMAGES
STRATEGIES AND PLANS
FOR PIPELINE INTEGRITY
IMPROVEMENT
SYSTEMS AND
PROCESSES FOR
MITIGATION,
INTERVENTION AND
REPAIRS
GLOBAL BUCKLING (BURIED)
REPAIR STRATEGY FOR UPHEAVAL RELATED DAMAGES
STATIC OVERLOAD
REPAIR STRATEGY FOR CROSS SECTION (EXCESSIVE OVALISATION OR LOCAL
BUCKLING) AND FRACTURE RELATED DAMAGES
GENERAL
REPAIR SYSTEM IN PLACE
ROCK DUMP VESSEL CONTRACT IN PLACE
EMERGENCY PLANS AND PROCEDURES
GLOBAL BUCKLING (EXPOSED), GLOBAL BUCKLING (BURIED), STATIC OVERLOAD
VESSEL CONTRACT IN PLACE IN CASE OF NEED FOR URGENT NDT
An example of the application of the Barrier Framework approach for inspection plan activities
regarding structural hazards is presented in Table 33 -Example of application of Barrier Framework
approach.
In the case an initial Inspection Interval (IR) equal to 3 years is estimated at start-up for structural
hazard inspection plan activities, it is possible to investigate the potential barriers in place to adjust
the value of Final Inspection Interval (I*).
During the plant life, after the first inspection set of activities, the investigation and the scoring can be
reviewed and updated.
Table 33 -Example of application of Barrier Framework approach
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RBI Methodology for Pipelines in Zubair Field
STRUCTURAL THREATS (START-UP)
ELEMENTS
1
2
IR
DESIGN BASIS
QA AND DOCUMENTATION OF DESIGN,
FABRICATION, INSTALLATION AND
VH
C
SCORE
3
HR
3
3
VH
3
3
HR
3
3
HR
3
3
RELEVANCE
D
SCORE
C
D
I
I*
0.63
0.75
1.4
1
3
MODIFICATIONS
3
4
5
6
7
8
9
10
11
12
13
PIPELINE / OTHER PRESSURE
CONTAINING COMPONENTS
PIPELINE COVER
PROTECTION AND SUPPORT
STRUCTURES
INFORMATION SYSTEM TO 3RD PARTY
RESTRICTION AND SAFETY ZONE
NR
NR
SYSTEMS
PRESSURE PROTECTION SYSTEM
EXTERNAL CORROSION PROTECTION
SYSTEM
INTERNAL CORROSION PROTECTION
SYSTEM
PROCESS CONTROL SYSTEM
OPERATIONAL PROCEDURES
STRATEGIES AND PLANS FOR PIPELINE
INTEGRITY CONTROL
NR
NR
3
NR
HR
HR
4
4
3
3
HR
4
3
14
SYSTEMS AND PROCESSES FOR
INSPECTION, MONITORING AND
TESTING
HR
4
3
15
SYSTEMS AND PROCESSES FOR
INTEGRITY ASSESSMENT
MR
4
3
MR
4
3
MR
4
3
16
17
STRATEGIES AND PLANS FOR PIPELINE
INTEGRITY IMPROVEMENT
SYSTEMS AND PROCESSES FOR
MITIGATION, INTERVENTION AND
REPAIRS
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