A Semi-quantitative Pipeline Risk Assessment Tool for Piggable and Un-piggable Pipelines

1 Copyright © 2006 by ASME

Proceedings of IPC 2006 6th International Pipeline Conference

September 25 - 29, 2006, Calgary, Alberta, Canada

IPC06-10280

A SEMI-QUANTITATIVE PIPELINE RISK ASSESSMENT TOOL FOR PIGGABLE AND UN-PIGGABLE PIPELINES

Gunnar Weigold ROSEN Technology

and Research Centre Am Seitenkanal 8 49811 Lingen – Germany

Colin Argent MACAW Engineering Ltd.

Howdon Terminal Willington Quay

Newcastle (Wallsend) NE28 6UL - UK

John Healy MACAW Engineering Ltd.



Ian Diggory MACAW Engineering Ltd.



ABSTRACT

ROSEN have developed together with MACAW Engineering Ltd. a Risk Assessment Tool that can be applied to both piggable and un-piggable pipelines. The Risk Model is structured to answer three basic questions relating to pipeline integrity:

• What threats are active on the pipeline? • Will the active threats result in a leak or a rupture? • What is the company liability (cost) in the event of a

failure? The risk assessment criteria on which the model is based

are taken from codes and technical papers that have become accepted as industry norms. The Risk Model itself is semi-quantitative and is based on input data that operators should have for all pipelines.

The results of the risk assessment provide an objective

identification of active threats to pipeline integrity and a first level benchmarking of the operators procedures with regards to industry best practice.

The paper will present the fast and robust Risk Assessment

Approach and illustrate it’s application by different examples as it was used to identify and prioritize active threats mechanism to optimize maintenance expenditures for effective preservation of pipeline integrity.

KEY WORDS

Semi-quantitative pipeline risk assessment, data integration, dynamic segmentation, threat analysis, unpiggable pipelines, benchmarking, audit trail, regulatory compliance, cost-benefit, Pipeline Integrity Management System, Asset Integrity Management

INTRODUCTION Risk assessment is an essential component of all pipeline

integrity management systems. It is fundamental to direct assessment (1), provides the means of prioritising pipelines for intelligent pig inspection and underpins the methodology for risk based inspection (2). A well structured risk assessment system should also provide guidance on the cost – effective deployment of maintenance and preventive budgets.

Several forms of risk assessment are available to the

pipeline engineer. Qualitative risk assessment is the simplest but the subjective ranking of individual threats as ‘high’, ‘medium’ and ‘low’ falls short of the consistent objectivity required. Semi-quantitative risk assessment systems do provide a consistent approach (3) provided the assessment criteria take due account of the standard procedures used in pipeline engineering. In principle quantitative or probabilistic risk assessment overcomes these problems but this approach does require a substantial data base of pipeline performance. Such databases are limited (4, 5, 6) in geographical extent and may not accurately reflect the key issues that influence pipeline integrity in other areas of the world.

The view taken by the authors of this paper was that there

is a need for a simple, code based risk assessment procedure that can be applied to all pipelines for the purposes of prioritising in-line inspection and direct assessment activities. The risk criteria embodied in such a procedure must be traceable and reflect current industry best practice and should not be obscured by what is commonly termed the ‘black box’ approach. It is also obvious that such a system should not be constrained by software compatibility but should inherently be based on an ‘open market’ approach.

This policy statement has been refined into six simple

application criteria for the risk assessment of pipelines.


DESIGN CRITERIA FOR THE RISK ASSESSMENT The criteria for an effective risk assessment were defined

as follows. • The risk assessment procedure should be simple and

applicable to all pipelines regardless of age, condition and ‘piggability’ in order that a unified ranking could be achieved across a complex pipeline system.

• The risk assessment criteria should be based on a traceable

source of direct technical relevance to the operation of hydrocarbon pipelines, i.e. industry codes and standards.

• The output from the risk assessment should include an

unambiguous identification of potentially active threats to pipeline integrity, the probable failure mode if these threats developed to a critical stage and the consequences of such a failure.

• The core risk assessment function should be complemented

by recommendations on audit procedures to provide guidance on the investigation and detailed quantification of potentially active threats to pipeline integrity.

• The outcome of the active threat analysis should be

complemented by recommendations on the appropriate mitigation measures required to bring the active threat under control.

• The risk assessment system should be compatible with

existing data management tools such that risk assessment becomes an integral component of a Pipeline Integrity Management System (PIMS).

In addition it was essential that the proposed risk

assessment system should be compatible with the overall objectives and structure of the Asset Integrity Management Service (AIMS) (13) offered by ROSEN Inspection (see Fig. 1 page 10).

Figure: 2: Overview of assessed threats. Adoption of these criteria imposed a certain discipline on

the structure of the analysis of potentially active threats to pipeline integrity as shown in Figure 2 above and this is

reflected in the high level distinction between time-dependent and time-independent events.

The required link to preventive and maintenance activities

imposed similar discipline at the detailed level of active threat assessment. For example, the sub-divisions of external corrosion include under-protection by the applied CP system, CP shielding by disbonded pipe coating and interference / stray current effects because different preventive and maintenance strategies are required for each of these threats.

SYSTEM STRUCTURE The overall structure and application procedure for the risk

assessment system is comprised of three components: • Risk Assessment Methodology to identify possibly active

degradation mechanisms and to prioritise pipeline sections most at risk

• Risk Verification Procedures that inform operators about the measures they need to undertake to get a more detailed assessment of a particular threat

• Mitigation Strategies that describe control and mitigation measures that may be undertaken to minimize susceptibility to active threats

The risk assessment model uses information gained from a

series of questions to determine the susceptibility of pipeline sections to various integrity threats. The consequences of different failure modes are assessed and combined with susceptibility factors to form a risk factor for each threat. Various combinations of risk factors generate risk parameters that identify and rank those pipeline sections most at risk.

The underlying philosophy is that at the start of a risk

assessment each threat is assumed to be equally likely, with a level of susceptibility set at a maximum value of 100%. It is only in response to the questionnaire that this level of susceptibility may be reduced.

In those countries where a risk based approach is requested

by pipeline regulation (as opposed to prescriptive regulation) this procedure demonstrates to a regulator that an operator has a consistent and auditable assessment of pipeline integrity.

To establish and maintain an audit trail, the software user is

able to store and ‘lock’ assessments irrevocably together with supplementary information such as risk assessment team members, assessment date etc.

Reference to source documents that have been used to

define the susceptibility criteria for each threat can be viewed and presented to regulatory bodies for proving evidence of compliance with codes, standards and industry best practice.


RISK ASSESSMENT PROCESS The overview of a typical risk assessment process is shown

in Figure 3 below. A description of each step is given below.

Data Gathering, alignment and management

Segmentation and customization

Threat analysis

Consequences analysis

Risk Acceptable? Current practice acceptable

Verification(Audit threats)

Threats confirmed Current practice acceptable

Mitigation measures

Risk Acceptable? Current practice acceptable

Yes

No

No

Yes

Yes

No

Figure 3: Risk Assessment Process.

Step 1: Data Gathering The initial step is to gather information about the pipelines

being assessed and guidance is provided in the form of a questionnaire that covers all the data required to run a full risk assessment. However, the system has the flexibility to allow an engineer to select a partial risk assessment, for example to focus only on corrosion.

The scope of the risk assessment is shown in Figure 2 and

the input data needed to run a full assessment includes:

• Pipe data such as grade, wall thickness, manufacturing, route etc.

• Design and operating conditions including pressure, temperature, pressure cycling etc.

• Data on external corrosion control including CP monitoring and coating type and condition.

• Data on internal corrosion including product composition and treatment.

• Basic data on ground conditions and particularly aspects of ground stability.

• Monitoring and prevention measures to limit third party damage.

• Operating controls. • Basic data on the occurrence of specific faults in the

pipeline. The risk assessment does not use intelligent pig inspection

data in the first pass risk assessment because the system has been designed to be applicable to all pipelines regardless of whether they are piggable.

Data from multiple sources are translated, correlated and

made consistent so data can be aligned for observation and assessment. In order to achieve that the data are transformed to a common linear reference system using:

• Odometer, Log-Distance • Milepost • Engineering Stations • Surface References • GPS Coordinates

Establishing a common linear reference system for all

relevant information is key to accomplish data integration and sets the bases for accurate data segmentation.

An example of how data integration is presented by the

program is shown in Figure 4 (page 10). The risk assessment system is very data tolerant and

designed to deliver results even with incomplete data, but where data is missing a ‘worst case scenario’ is assumed.

In total the questionnaire contains 91 questions. At the start

of a risk assessment each threat susceptibility is assumed to be 100% and in response to the questionnaire the level of susceptibility can be reduced.


Step 2: Segmentation and Customization Segmentation is fundamental to an effective Risk

Assessment process, particularly with regard to the definition of High Consequence Areas.

Segments may be defined using selected parameters that

include: • Location class • Wall thickness • CP level • Soil condition • Coating type, etc.

The software allows the user to set break points where key

attributes are changing and by this to define segments in a pipeline. The number of segments defines the level of detail of the risk assessment. In principle a finer segment definition results in higher accuracy for assessment of each segment. Finding the right segment definition is important. In general it is recommended that segmentation starts coarse and is refined as required during the work. Segmentation can be dynamically changed and displayed as shown in Figure 5 below.

Figure 5: Example Dynamic Segmentation. ASME B31.8S (7) states that an effective risk assessment

shall incorporate sufficient resolution of pipeline segment size to analyze data as it exists along the pipeline to identify areas that may need immediate attention.

Segmentation can be updated as required based on the risk

assessment findings in order to account for verification results or mitigative measure that changes the risk in a particular segment. The system allows for both manual and dynamic, or automatic, segmentation.

Step 3: Threat Analysis The scope of the threat analysis is shown in Figure 2 (page

2) and the output provides a simple ranking for each threat. The starting assumption is that all threats are possibly active unless appropriate data is provided, via the questionnaire, to demonstrate that the particular threat is not relevant or is being managed to industry best practice. For example the threat of sour cracking is not relevant to pipelines carrying sweet product.

Assessment of relevant threats must reflect industry standards and codes. For example ISO15589 (8) defines the

criteria for effective cathodic protection and cathodic protection monitoring and so provides a traceable source for the definition of a corrosion risk due to under-protection.

This risk assessment system therefore reflects industry best

practice and provides the dual function of benchmarking. A threat of active corrosion due to under-protection will be returned if:

• The operator is following the monitoring guidelines in ISO

15589 and this has shown inadequate polarisation. • The operator does not meet the minimum monitoring

requirements of ISO 15589. Lack of relevant data will cause a threat of active corrosion

to be returned. An outline of the under-protection threat analysis scoring system is shown in Figure 10 (page 11). The starting assumption is that the threat is active with a score of 1 and this score is adjusted, to reduce the perceived score, in accordance with the criteria shown in the flow chart.

Threat assessment must also be linked to the monitoring

and maintenance activities undertaken by all pipeline operators. In this regard a risk assessment that returns a threat of active external corrosion is not good enough. The commonest causes of external corrosion on buried pipelines are under-protection, CP shielding by disbonded coating and interference effects including stray current. Each of these causes of external corrosion requires specific maintenance and preventive measures:

• Under-protection normally requires modification to the

cathodic protection current supply. • CP shielding due to disbonded coating can only be

eliminated by re-coating. • Interference effects and stray current require a specific

investigation and customised remedial measures.

The detailed procedures for threat analysis have been configured to reflect the specific issues associated with each degradation mechanism. For example, the threat analysis procedure for internal sweet corrosion in hydrocarbon production is shown in Figure 11 (page 12). In this case the predicted corrosion rate is assessed using a model based on the original work of DeWaard and Milliams (9) and this is used to estimate the worst case condition for pit growth to 80% of the nominal wall thickness. Adjustments to the pit growth assessment are made based on the flow conditions and the inhibition programme being used.

It should be noted that in both these examples, under-

protection and inhibition for the control of sweet corrosion, the scoring system becomes more onerous if the operator has not reviewed the corrosion protection within the last 10 years. The concept, that a responsible operator will periodically audit and re-validate the monitoring and maintenance procedures being used is applied throughout the risk assessment procedure.


Step 4: Consequences Analysis Consequence analysis is comprised of two assessments.

The first considers the probable failure mode, leak or rupture, for an active threat and is deemed as ‘Severity’. The second considers the impact this failure mode will have on the immediate environs and is regarded as company ‘Liability’ (cost) in the event of a failure.

The Severity of a line failure depends on the volume and

rate of product release. In general a leak releases less product and at a slower rate than a rupture. Characteristic values from published failure statistics (10, 14) are implemented in the risk model in order to reflect the expected failure mode for a particular threat. Customer specific data to customize probability of leak or rupture (Severity) are possible or use model defaults as per Figure 6 below.

Figure 6: Example of Model Defaults for Severity. Severity values reflect operating stress because pipelines

operating below 30% SMYS are not expected to rupture except:

• A rupture resulting immediately from mechanical interference or sabotage

• A rupture caused by external loading, such as ground collapse Four categories were identified for Liability in the first

instance: • People (death & injury) • Property (damage and clean up) • Company (lost product, repair) • Fines, legal and legislation

The output for each category can be based on a simple numeric ranking or on an estimated cost, in dollars, to the operating company. Consequence costs are defined in look-up tables for these four categories based on US failure cost statistics (11, 12).

The balance of these costs, or the numeric ranking, will

vary with location so four generic Class Locations are used in the consequence assessment:

• Urban / HCA • Suburban • Rural • Site of special environmental interest • Offshore

Figure 7 below gives an example on how e.g. Liability

model defaults are stored and can be modified by an operator in course of a risk assessment.

Figure 7: Example of Model Defaults for Liability. It is anticipated that individual operators may wish to

define a company, country or even segment specific scenario. Therefore the database within the program can be altered and operator specific cost scenarios can be put in.

A further adjustment to the consequence costs makes

allowance for the different volume of product expected to escape from pipelines as a function of diameter and pressure.

Step 5: Assess Risk Risk is generally expressed as the product of the

probability of an event and the consequences of that event. Risk = Probability of Failure x Consequence of Failure Step 3 and 4 of the risk assessment procedure as described

above assess and establish Susceptibility as a measure for probability of failure as well as severity and liability as measure of consequence of failure (COF). Multiplying susceptibility of each threat with severity and liability costs generates a Risk Factor for each combination of threat and failure mode.


Risk Factor = (Susceptibility) * (Severity) * (Liability) Individual risk factors can be combined in various ways to

generate risk indices. Risk Index = fn( Risk Factors) Risk indices can be generated for combinations of threats

to show e.g.:

• External corrosion threats combined • Internal corrosion threats combined • Damage threats combined • Ground movement threats combined, etc.

Detailed analysis of derived risk indices enables other

parameters, such as the maximum risk to a pipeline from a given threat, to be quantified and ranked, for example Probability of failure (POF), consequences of failure (COF) and risk can be assessed for a pipeline network, an individual pipeline or a pipeline segment.

The software allows defining, storing and generation of

specific reports that combine data charts and tables and allow different subject matter experts like e.g. corrosion engineers or senior management to extract information that is of specific interest to them. Examples are shown in Figure 8 and 9.

Figure 8: Report Example, Threat Assessment Overview.

Figure 9: Report Example, Management Summary.

Step 6: Verification This risk assessment procedure was designed to be

applicable to all pipelines regardless of the quality of available data and the completeness of available data. The default condition assumes a threat is potentially active on a pipeline unless the operator has information to demonstrate that it is not. In this regard the system is ‘fail safe’ but the main objective of a risk assessment must be to focus operator attention on the genuine threats to pipeline integrity.

Each threat assessment is therefore complemented by a

verification procedure. The threat assessment returns an indication of a potentially active threat with the reason for that result. The user is then invited to view the verification module that recommends the most efficient and effective measurements or procedures for auditing the threat assessment result.

For example, at any given time in the life of a pipeline, the

actual stage of development of that threat can be quite different, particularly for the time dependent degradation processes.

For pipelines that have been subjected to an intelligent pig

inspection the verification process can be incorporated into the basic risk assessment procedure. Diagnostic feature distributions have been generated for both internal and external


corrosion mechanisms and pattern recognition and matching procedure is used to assess the inspection data for evidence of the various forms of corrosion activity. This function is particularly useful in regard to time dependent external corrosion caused by interference effects because it allows the pipeline segments to be screened for correlations in corrosion activity with specific features such as valve pits, power line crossings, end of line effects etc. It also provides additional insight into the causes and location of internal corrosion and allows a preliminary diagnosis of erosion – corrosion, mesa corrosion and microbial corrosion etc.

Of course intelligent pig inspection data can also provide

the basis for corrosion growth assessment, significance of defect assessment and the estimation of future repair schedules under current operation and with the benefit of revisions to the corrosion control procedures.

Figure 4 (page 10) gives a screen shot example where the

Risk Index along the pipeline is aligned and displayed together with other information like segmentation or inspection data in the course of the risk verification process.

Where possible the structure of the Threat Analysis has

been configured to provide a direct and unambiguous link into the appropriate mitigation strategy. A common problem with risk assessment systems is that they return a non-specific threat analysis which requires further interpretation before an integrity management strategy can be defined.

For example the structure of the threat analysis for external

corrosion was explained in Step 3 above where a clear distinction is made between under-protection, CP shielding and interference / stray current.

Step 7: Mitigation The obvious follow-on action from a risk assessment is for

a pipeline operator to implement a risk management plan to reduce any significant threats to pipeline integrity. The mitigation module provides a simple first stage action plan for an operator to follow as he sets out to define an appropriate integrity management plan. Until a strategy is implemented it will have no impact on risk factors.

DISCUSSION The practical implementation of this software based risk

assessment as part of the Asset Integrity Management Services offered by ROSEN Inspection has been a process of evolution based on the risk assessment and risk mitigation procedures already developed, proved and used by MACAW Engineering Ltd. on pipeline systems around the world as described in the following example.

The threat assessment, validation and mitigation

procedures have been developed over a period of 10 years. From ~2000 these procedures were used to provide a comprehensive corrosion risk assessment of the complete pipeline system of a major North Sea operator. A re-assessment

of the pipeline system is currently under way as part of the routine integrity management strategy of that company.


procedures have been developed over a similar period and within the last 2 years has been used to provide the excavation and direct examination framework for a number of direct assessments. The sampling schedule devised on the basis of the risk assessment procedures provided a robust and effective procedure for the true assessment of the condition of the pipelines.


procedures for external stress corrosion cracking have been developed over a period of 25 years during which time they have been applied to major pipeline systems in the UK, South America and the Far East.

In all cases of the application of these procedures some

measure of customisation has been required to meet the particular needs of the individual pipeline operators. This capability for customisation has been incorporated in the software system such that particular cost structures or the requirement of national legislation can be incorporated. One possible modification would be to adapt the threat analysis system to provide an audit against industry best practice as an alternative measure of the effectiveness of an existing company integrity management strategy.


CASE STUDY

Un-Piggable Pipelines Performing a condition assessment of a pipeline initially

relies on the information that can be gathered about the design, operation, inspection and maintenance of the pipeline.

MACAW have conducted such an assessment for a Client

who operates a network of oil & gas pipelines of which a number are considered to be “unpiggable” using conventional in-line inspection tools. This was due primarily to the absence of launch/receiver facilities, pipeline restrictions such as valves, bends, etc. The pipelines have been in operation for over 20 years.

On this basis it was considered that based on the

established principals of Direct Assessment, Risk Assessment was the most appropriate method for determining the likely conditions of the pipelines, identifying any immediate areas for replacement or rehabilitation and developing pipeline integrity management plans.

For example a Four Step Process is outlined by NACE

RP0502 (1) Pipeline External Corrosion Direct Assessment (ECDA) Methodology (Pre-assessment, Indirect Examination, Direct Examination and Post-assessment) and this was used as a basis for the condition assessment.

In this study, this methodology has been combined with the

MACAW risk Assessment model to identify the likely threats to the integrity of the pipeline and identify ‘high risk’ areas.

The 7 step process described in this paper was applied. The

full range of integrity threats was screened. Based on the available and relevant pipelines data; design, operation experience, inspection (CIPS, DCVG and excavation data, etc.) HCA locations and maintenance records, it was established that the primary threats to the pipelines were; external corrosion, internal corrosion and 3rd party damage.

On this basis, the pipeline was segmented to focus on the

“high risk” areas identified for each of the primary threats. The segmentation criteria for internal and external corrosion are summarised in Table 1 identified for each of the primary threats.

Excavation sites are chosen to validate the actual pipeline conduction using local UT measuring combined with Long Range UT testing (LRUT). On average sample sizes of between 5-15% of the length of pipeline affected by a particular threat were achieved.

On the basis of the observed condition of the pipelines, a

detailed integrity management strategy was developed to define:

• Any immediate repair or rehabilitation on each pipeline

including CP upgrades, localised coating repairs. • Recommendations for more extensive coating

rehabilitation

• Recommendation to make 2 pipelines inspectable using in-

line inspection tools (critically to supply) to fully quantify • The integrity of these pipelines along the entire pipeline

length.

Table 1: Segmentation and Sampling Criteria.

Locations Reason / ThreatLine segments within 200 m

Internal: Water carry over Sample: At low points

Inlet

Line segments within 500 m

External: Interference at line ends

Valves, tees etc

Line segments within 100 m of each installation

External: Interference effects

Special Locations

Crossings with casing External: Water and corrosion in casing

Line segments not meeting -850 mV (or equivalent) criterion for the ground conditions

External: Under-protection

Low points Internal: Water drop out and pooling

Line segments immediately downstream from pumping stations if ‘hot’

External: Coating damage and high pH SCC

Line segments in proximity to dc power lines and dc traction

External: Stray current

Line segments with parallel high voltage ac power lines

External: Induced ac

Line segments coated with cold applied tape

External: Coating failure and CP shielding

Pipeline

Line segments with heat shrink field joint coatings

External: Coating failure and CP shielding


CONCLUSION The risk assessment system described in this paper has

been configured to be applicable to all pipelines to provide a priority ranking.

The sub-division of threats included in the risk assessment

has been structured to provide a direct and unambiguous lead into the appropriate mitigation measures.

Guidance is provided for the validation of the threat

analysis results by the collection, compilation and analysis of more detailed information. Where this information is available, for example from intelligent pig inspections, it can be incorporated into the assessment process.

Results of the assessment can be traced back to industry

codes and standards. The risk assessment system can be customised, for

example to focus on benchmarking maintenance activities with respect to industry best practice.

The threat analysis represents a statement of the

compliance of the operator with industry best practice and so provides an initial step in the process of benchmarking.

REFERENCES [1] NACE RP0502; Pipeline external corrosion direct

assessment methodology [2] API / ANSI RP580; Risk-based Inspection [3] W. Kent Muhlbauer, Pipeline Risk Management

Manual, 3rd Edition [4] DOT OPS statistics on pipeline incidents [5] CONCAWE; Performance of European cross-country

oil pipelines – statistical summary of reported spillages 2003; Report No. 3/05

[6] EGIG; 6th EGIG Report 1970 – 2004 Gas pipeline

incidents [7] ASME B31.8S; Supplement to B31.8 on managing

system integrity of gas pipelines [8] ISO 15589; Petroleum and natural gas industries –

Cathodic protection of pipeline transportation systems – Part 1 On-land pipelines

[9] C DeWaard, U Lotz; Prediction of carbon dioxide

corrosion in carbon steel; NACE 1993 [10] IGE/TD/1, Recommendations on Transmission and

Distribution Practice; Steel Pipelines for High Pressure Gas Transmission, Ed.3; 1993

[11] G H Koch et al; Corrosion costs and preventive strategies in the US; Appendix E, Gas and liquid pipelines, September 2001

[12] DOT RSPA statistics on the costs of pipeline failures [13] Advanced Approaches to Pipeline Integrity

Management, J. Healy, D. Storey, G. Weigold, C. Bal, M, Jaarah; Middle East Pipeline Management Summit; 16-17th January 2006

[14] CFER IPC Pipeline Risk Analysis and Risk Based

Planning, Tutorial at IPC 2004


Figure 1: Typical Integrity Management Process showing how PIMS in general and AIMS components in particular are related to it (13).

Figure 4: Data Alignment and Segmentation. Risk Index along the pipeline is aligned and displayed together with

other information like segmentation or inspection data in the course of the risk verification process.

Data Management

System

Data collection, Analysis & Integration

Baseline Risk Assessment

Reference IMR Scheme

Conduct Inspection or mitigation

Assess Data & Integrity

Statement

Mitigation and Rehabilitation

Strategy

Review influencing

factors

Update Risk Assessment & IMR

Scheme

IM Programme

Data Management

Risk Management

Reference IMR Schemes

Integrity Status & Verification

PIMS Components

ROSEN AIMS Products & Services

Data Management

(SPDW)

Risk Management

(RIS)

Cleaning and Inspection

Defect

Assessment (FFP)

Diagnosis & Mitigation (DIA)


Figure 10: Scoring procedure for the assessment of under-protection.

Time DependentExternal CorrosionUnder-protection

Monitoring atfixed test points

Close intervalpotential survey

'On'potentials No CIPS

More than 10years ago

Some areas donot meet -850 mV

'Off'potentials

Less than 10years ago

All areas meet -850mV

Date Result

-0.1

-0.5

-0.4

-0.3

-0.2

0

Score


Figure 11: Scoring system for the assessment of sweet corrosion where the product composition is known.

Time DependentInternal Corrosion

Sweet Hydrocarbon

Productcomposition

known

Flow regime&

Inhibitor efficiency

Score

Velocity >20m/sAssume 0%

effciency

TurbulentAssume 50%

efficiency

Dose fixed lessthan 10 years ago

Assume 95%efficiency

Dose fixed morethan 10 years ago

Assume 75%efficiency

NoneUse full predicted

rate

Flow likely tocause filmstripping

'Normal'flow

Use the designated rate to calculate predicted time for pits to grow to 80% wall thickness

0

-0.9

-0.6

-0.3

</= 5 years

5 - 10 years

10 - 20 years

>20 years

Documents

A Semi-quantitative Pipeline Risk Assessment Tool for Piggable and Un-piggable Pipelines