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ISSN 2278-2540 | DOI: 10.51583/IJLTEMAS | Volume XV, Issue IV, April 2026
Life Cycle Asset Integrity Management Strategy of Aging Crude Oil
Pipelines
Nwando Maureen Ogu-Jude
*
, John Okoli, Celestine Ebieto
Faculty of Engineering, University of Port Harcourt, Rivers State, Nigeria
*
Corresponding Author
DOI: https://doi.org/10.51583/IJLTEMAS.2026.150400069
Received: 16 April 2026; Accepted: 21 April 2026; Published: 08 May 2026
ABSTRACT
This study developed an asset integrity management strategy to ensure continuous safe operation of the 24in
Trans-Niger pipeline case-study till its design end-of-life in 2025 and life-extension thereafter, despite low flow
conditions and associated ongoing Microbiologically Induced Corrosion (MIC). The case-study for the work is
a 24inches by 55km carbon steel oil pipeline which was commissioned in 1995 to evacuate production from four
(4) flow-stations to an export terminal. In the course of the work, a critical analysis of the current pipeline
integrity management system (PIMS) in place against industry best practices was carried out. A Corrosion
Management System (CMS) for the pipeline asset was developed by defining a company-wide corrosion policy
for this pipeline, conducting a corrosion risk assessment for the threat of low flow conditions, carrying out a
Failure Mode and Effect Analysis for low flow condition, proposing an Integrity Management Team and
developing a roadmap for the execution of the proposed Integrity Management System. Both quantitative &
qualitative data were employed in carrying out the study scope of work. Quantitative data used in the study
included: pipeline design/as-built data, inspection & monitoring data, historical production data, and pipeline
integrity management system. While qualitative data was derived from interviews and discussions with pipeline
integrity and operations personnel. From the analysis conducted, a goal of zero corrosion leaks on the 24in Trans-
Niger pipeline would be achieved through the Corrosion Management Strategy managed by the Head of Pipeline
Integrity. The output of the FMEA rated the criticality of failure mode as high due to the product of the
susceptibility of failure and Asset, Environment, and reputation consequence. An essential component of the
CMS is the CMS execution team composition and their interdependencies, as CMS execution requires team
effort with clear responsibilities and accountabilities. This study concluded that Asset Integrity Management
without following best practice or industry standard methodology is grossly ineffective and would lead to dire
consequences as in the case of the 24in Trans-Niger pipeline case-study with its failure in 2018.
Keywords: Asset integrity; Asset management; Aging pipelines; Life cycle management.
INTRODUCTION
Portraying the significant capacity of flowlines, Kishawy and Gabbar (2010) compared it to that of a human vein
and said: "Pipelines work as veins serving to bringing life-necessities like water or petroleum gas and to remove
life by-products like sewage". "Also, they are viewed as the most preferred method of transportation of oil and
gas in huge amounts". Oil and gas are frequently packed in regions other than where they would be required.
Pipelines transport hydrocarbons over significant distances, from creating wells and districts to send out
terminals, processing plants, and fuel stations. All things considered, pipelines are viewed as the most affordable
and proficient method for huge scope fluid transportation for crude raw petroleum and flammable gas (Ilman,
2014) and are intended for the protected evacuation of estimated hydrocarbon volumes (creation profile) over
their plan life (ordinarily 30years) at suggested stream speeds > 1m/s (Henkes, 2014). The working state of
pipelines decides the plan and the management technique of the pipeline framework. As per Gabbar and Kishawy
(2011), the framework to be set up relies upon whether the pipeline would be exposed to high pressure/high
temperature or low tension/low temperature in activity.
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Pipelines as a method for offtaking oil-based goods is associated with risk and difficulties. Pipelines come up
short in activity due to imperfections like breaks, corrosions, scratches, punctures, and so on, prompting harm
and holes on the pipeline coming about to tremendous downtime, cost, and natural dangers. These issues have
immense natural, financial, wellbeing and security impacts on the pipeline operators and host networks the same.
Awful inland and seaward mishaps credited to pipeline failures are main issues for operators, controllers, and
general society (Peekema, 2013). On many events they have brought about loss of lives for workers and host
networks with more than 2500 lives lost in a span of last 10 years (Okoli, 2019). During the lifecycle of a
pipeline, there are significant changes to forecast volumes due to decline in reservoir performance, shortage of
reservoir discoveries, divestment of production assets, etc. The pipeline asset could be exposed to “low flow”
condition (flow velocity <1m/s), which in aging pipelines become the precursor to asset failure due to
microbiologically induced corrosion (MIC). The MIC can be aggravated by under-deposit corrosion, which is
characterised by settling of suspended solids and precipitated phases (especially water accumulation at low spots)
at the bottom of the pipeline (Moloney, 2017).
The Nigerian oil & gas industry is threatened by the impact of low flow conditions to asset integrity due to oil
reservoir decline and lack of “big” reservoir finds due to insufficient funding caused by the sharp drop in oil
prices since the Covid-19 pandemic (Petroleum Economist, 2020). OPEC, in its 2019 annual statistical bulletin
stated that Nigeria’s crude oil reserves stood at 37.453 billion barrels in 2017 and 2016; 37.062 billion barrels
in 2015 and 37.448 billion barrels in 2014 (ASU, 2019). On February 20, 2020, the Department of Petroleum
Resources (DPR), were taken on record by The Economic confidential (2020) as saying in 49years, it is expected
that the Nigeria oil reserves would be significantly depleted. Both reports allude to the issue of low investments
in the Nigerian Oil and gas industry which would in turn drive a downturn in exploration which is required in
increasing reserve volumes. Probably the most serious issue confronting the pipeline business is the way that the
world's pipeline framework is maturing. As indicated by Achebe et al. (2012), 41% of Nigeria's pipeline network
is over 30 years of age. The vast pipelines joined with their different scope of activities, sizes, materials, age,
and natural impacts add to the perils related with the pipeline business. Regularly, these combined risks make
oil and gas pipeline security an exceptionally complicated process. Interestingly, a study conducted in 2011
(Okoro, 2011) arrived at a projected production profile (captured in Figure 1) for the Nigerian Oil and Gas
industry using the Hubbert’s oil prediction model which seem to agree with more recent predictions. This study
developed an asset integrity management strategy to ensure continuous safe operation of the 24-inch pipeline
case-study till its design end-of-life in 2025 and life-extension thereafter, despite low flow conditions and
associated ongoing MIC.
Figure 1: Hubbert's oil production curve showing Nigeria's likely oil peak (Okoro, 2011)
From figure 1 above, it can be predicted that with steady decline in reserves, the industry would operate aging
assets in low flow conditions which would require smart asset integrity management strategies to ensure
continued safe & profitable operations.
Studies have been conducted to understand the mechanism and impact of microbiologically induced corrosion
(MIC) on production assets as well as the various kinds of operational flow conditions and impact on production
assets (Askari, 2019). But this study looked at establishing the relationship between low flow conditions and
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MIC & other associated integrity threats, as well as propose a management system which would ensure the
operation of the pipeline asset through its lifecycle and the possibility of a life extension.
METHODOLOGY
DATA
Both quantitative & qualitative data were employed in the execution of the methodology expanded below.
Quantitative data used in fulfilling individual objectives included the following:
Pipeline design/as-built data – Such as the pipeline dimensions (wall-thickness, nominal pipe size, length, and
profile of the pipeline) and other design information including pipeline design envelope (pressure, flowrate &
temperatures) gotten through desktop study from pipeline as-built documents and other records from the
company. This data was used in understanding the as-built conditions of the pipeline, the current risks to the
pipeline for data capture and integrity and benchmark of the entire study.
Table 1 Case Study Pipeline as-built data
S/N
PIPELINE PARAMETERS
DATA
1.
Installation year
1995
2.
Pipe length
55km
3.
Pipe diameter
24 inches
4.
Wall thickness
10.31mm
5.
Pipeline pressure limit
12 bar
6.
Temperature limit
35⁰C
7.
Pipe material
Carbon Steel
8.
External Coating
Polyethylene
9.
Insulation
None
10.
Flow rate/ Recommended velocity
>0.5m/s
Table 2 Case Study Pipeline expected fluid content
S/N
PIPELINE FLUID CONTENT
VALUES
1.
Oil condensate
21,000 bls/day
2.
Water
18,000 bls/day
3.
Bicarbonates
122 mgCaCO
3
/day
4.
Sand and Silt
None
Inspection & Monitoring data – this data was gotten using desktop review from the company’s pipeline pigging
records, intelligent pigging reports & water sampling results. Information on the existing maintenance and
operation activities, corrosion damage and defect characterization within the pipeline was used for risk
quantification and assessment with corresponding activities or mitigations set to ensure a lower risk of asset
failure.
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Figure 2: 24in pipeline case-study historical pigging debris load (2003 – 2017)
Historical production data – Twenty-five (25) years production data gotten from the company’s Production
Management Centre database through desktop analysis and was aggregated and used in correlating the impact
of flowrate on flow velocity and therefore established the risk of low flow for the pipeline case-study.
Figure 3: 24in pipeline case-study historical production rate against velocity (1997 – 2018)
Pipeline Integrity Management System – this was achieved through a desktop review of suite of documents
showing the current PIMS as used for the management of the pipeline case-study including organizational
structure/communications & job competence profiles and Operations & Maintenance procedures & activities
which served as a benchmark, reviewed to identify gaps.
0
0.2
0.4
0.6
0.8
1
1.2
1.4
1.6
1.8
0.0
50000.0
100000.0
150000.0
200000.0
250000.0
300000.0
Jan-97
Sep-97
May-98
Jan-99
Sep-99
May-00
Jan-01
Sep-01
May-02
Jan-03
Sep-03
May-04
Jan-05
Sep-05
May-06
Jan-07
Sep-07
May-08
Jan-09
Sep-09
May-10
Jan-11
Sep-11
May-12
Jan-13
Sep-13
May-14
Jan-15
Sep-15
May-16
Jan-17
Sep-17
FLOW VELOCITY (M/S)
PRODUCTION RATES (BBLS/DAY)
PRODUCTION YEARS
24" Pipeline production rates vs Flow velocity
Average production rate Average velocity
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Figure 4: Pipeline integrity management system (Shell Petroleum Development Company, 2014)
Qualitative data was derived from interviews and engagement with pipeline integrity and operations personnel
as summarized in the table below:
Table 3: Comparison between Pipeline Integrity Management System in Place and Best Practices
S/N
PIMS
STRUCTURE
ANALYSED
PIMS IN
PLACE
SHORT FALLS FROM BEST
PRACTICES
BEST PRACTICES
1
Frequency of risk
assessment updates
A generic FMEA
was developed
during the design
stage
no further risk assessment is carried
out except during a management of
change process of which the risks
identified and eventually treated
are risks associated with the change
rather than general pipeline risks or
threats that could lead to failure
General pipeline risks or
treats are to be identified
and mitigated
2
Poor deviations
management
Deviations from
the MRP
timelines were not
properly managed
Poor execution of the MRP,
inability to perform deviations and
poor closeout of existing deviations
Where the MRP activities
are not met within a stated
timeline, it is to be
managed through the
process of deviation which
would highlight the risks
associated with deferring
the activity, stated
mitigations to managing
said risks and a recovery
plan to ensure the
execution of the activities.
3
Lack of a
Corrosion
Management
System
The CMS is
lacking within the
overall PIMS in
place
there is no focused attention on the
management of corrosion risks
A detailed CMS should be
put in place, within the
PIMS to mitigate all
corrosion associated risks.
The 5-why tool (see table 4 below) was deployed to ascertain the root cause of these shortfalls and possible
improvements.
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Table 4: 5-Why Analysis for identified PIMS shortfalls
Corrosion Management System
To address the objective of the development of a corrosion management system for the 24inches by 55km
pipeline case-study, the following strategy was adopted. Several sub-objectives were satisfied in the following
order and as in the figure below
5-Why Analysis
PIMS Shortfalls, Root Cause Analysis and Improvement Paths
Why 1 Why 2 Why 3 Why 4 Why 5 Root Cause Improvement Paths
1
Frequency of risk
assessments updates
Staffing oversight or
poor awareness on
the need for it
Lack of visible
procedure
requirement
Failure to comply
with Process safety
management
requirements
Poor Leadership
oversight on Process
Safety requirements
Non-compliance to the
Management system requirements
Carry out an audit, benchmark
current practices against
existing processes and best
practice guides .e.g. OGP,
identify gaps and close out.
Lack of competence
Poor
training/awareness
Poor Leadership
oversight on Process
Safety requirements
Non-compliance to the
Management system requirements
Secure leadership commitment
to drive effective capability
management which would
ensure effective recruitment
and retention of a fully
competent workforce at all
times
(http://www.hse.gov.uk/offshor
e/kp3review.pdf)
2
Poor deviations
management
Increasing number of
deviations
No awareness of the
impact of SCE on the
risk of major incidents
Poor risk assessment
for raising the
deviations
Weak technical
authority structure in
the organisation
Technical authorities were under
pressure, often reacting to
immediate operational problems
rather than taking a strategic role
to provide expertise and judgement
on key operational engineering
issues.
Secure leadership commitment
to drive the elevation of the
profile of Technical authorities
in the organiation with direct
comunication channels
between management and
technical authorities.
Poor training or
competence of
operators managing
the process on the
asset integrity
requirements
Poor knowldege
retention during staff
reduction
Management focused on cost
cutting objectives over Asset
integrity
Commitment by management
to undertake company-wide
training on Asset integrity
management requirements
3
Lack of a Corrosion
Management Strategy
Non-compliance to
best practice &
guidelines .e.g. EI
corrosion
management guideline
for oil & gas
processing
No awareness of the
impact
Poor training or
competence of
operators managing
the process on the
asset integrity
requirements
Poor capability
management system
Leadership oversight on
importance of capability
development and retention
Secure management support
to conduct capability audit and
gap closure in the area of
corrosion management.
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Figure 5: Corrosion Management System Decision Tree
Define a Corrosion Policy
Based on the guidelines of Energy Institute, a corrosion policy is an integral part of the policy for integrity
management. Hence, to fulfil this objective, a literature review of the integrity management policy documented
in the HSSE & SP control framework of the company. In alignment to the company policy on integrity
management, a corrosion management policy was proposed for the 24in Trans-Niger pipeline case-study based
on the Energy Institute framework as below (publishing.energyinst.org/topics/process-safety):
a) Defined WHO within the organization would deliver CMS.
b) WHAT the expectations and objectives of the CMS are.
c) WHERE this CMS would relate to – in this case the 24in pipeline case study.
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d) WHY this CMS is important to the organization.
e) HOW the CMS would be implemented.
Conduct an FMEA with a Corrosion Risk Assessment
In assuring the process of the need to adapt the corrosion management system to providing mitigation for the
risk of low flow in the 24in Trans-Niger pipeline case-study, Failure Modes, and Effects Analysis (FMEA) for
low flow was developed as below:
1. Failure mode was defined as low flow.
2. The effect of the failure mode was stated.
3. The probable causes of low flow as identified from RCAs and failure investigations highlighted in the
introduction of this report were documented on the FMEA template.
4. The assessment methodology for low flow impact on the asset was also highlighted.
5. Possible controls & mitigations for this failure mode were included in the template and subsequently on
the corrosion management guide to be described in subsequent sections.
6. A corrosion risk assessment was carried out and stated on the template as well. The FMEA described
above was populated on a table as shown in Table 4:
Table 4: FMEA Template
Carry out corrosion risk assessment
To fully populate the FMEA table, a corrosion risk assessment (CRA) was conducted, to assure the business of
the risk rating of the failure mode already defined. Risk is generally expressed as a product of the probability
and consequence of failure. The CRA was carried out using S-Risk Based Inspection Criticality Matrix (Figure
2) below which is aligned to the API RP 580 methodology for Risk Based Inspection (api.org). This tool helped
in readily quantifying the risk of low flow against the metrics of cost of Asset protection, People safety,
Environmental preservation, and reputation of company.
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Figure 6: S-RBI criticality matrix (Shell, 2019)
Propose an Integrity Management Team Composition
To fulfil this objective, a review of the current organizational structure set-up to manage the asset as documented
in the existing Pipeline Integrity Management System was carried out. Comparing it to requirements of the
Energy Institute guideline as well as the requirements of the CMS being developed, a Responsible-Accountable-
Support-Consult-Inform chart (RASCI), which identifies all action parties, activities/scope of work and team’s
interdependencies in delivering the requirements of this CMS.
All objectives satisfied in the preceding sections were put together into the Corrosion Management Guide
(CMG), which puts all the CMS results in a format that can be easily reviewed, executed, and monitored.
In this case, all results already gotten were documented under the following columns:
1. Defined corrosion loop & Sub-system, which is the pipeline case-study.
2. Description of the pipeline case-study, in terms of material of construction, coating, wall-thickness and
other physical properties of the asset.
3. A threat column had low flow specified. Under this column, the probability of failure was highlighted as
well.
4. A barriers column was generated, which captured data on the type of barrier originally planned into the
asset during construction to mitigate the failure mode. In addition, the current status of the barrier was
defined based on the current state of the pipeline asset and the justification for the status was stated as
well.
5. The Integrity Operation Window was populated primarily with process parameters (minimum, maximum
& actual) – flow temperature, pressure, water & oil flowrate, and flow velocity were populated on a
separate column.
6. Proposed monitoring frequency and location based on the corrosion Risk assessment carried out in
previous section.
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7. A Maintenance Reference Plan (MRP) was identified and captured to ensure maintenance of integrity of
the pipeline asset as well as to ensure life extension of the asset. Every MRP activity underwent an Impact
– Cost/Effort criticality assessment based off the matrix represented in Figure 3. Depending on which of
the quadrants the activity falls into would determine if such an activity should be implemented
immediately, implemented if practicable, implemented as a form of continuously improving the system
or an activity should be abandoned.
8. A last column was generated to capture management actions for the maintenance of the CMG and hence
the CMS. Therefore, this column highlighted Key Performance Indicators (KPI), key action owners to
respond to possible excursions and the actions expected to be taken to revert the system back to its
original configuration.
Figure 7: Impact – Cost/Effort Matrix (Shell, 2019)
Integrity Management Execution Roadmap
To develop a roadmap which would help manage the introduction of the CMS into the system in a manner which
would allow for quick adoption and execution required, a literature review of the two leading change
management models, namely, the bridges model postulated by Williams Bridges (wmbridges.com) and the eight
(8) steps change model by John Kotter (kotterinc.com/8-steps-process-for-leading-change/).
Based off the review, the following were developed to generate the roadmap:
1. A proposed change management team composition to drive adoption of the CMS for this specific asset
and similar assets across the organization.
2. A Gantt chart was developed highlighting various diverse company-wide engagements of various
stakeholders. This Gantt chart also highlighted proposed timelines for achieving key milestones of the
launch.
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RESULTS & DISCUSSIONS
Define A Corrosion Policy
Based on the asset integrity policy of the company to “keep their asset safe and know it” (Shell 2019), the
corrosion policy for this proposed CMS is, based on known impact of corrosion on asset integrity, a goal of zero
corrosion leaks on the 24in Trans-Niger pipeline would be achieved through the Corrosion Management Strategy
managed by the Head of Pipeline Integrity, who would ensure the following:
a. All pipeline integrity activities are carried out in accordance with the CMS.
b. Resources (human, tools, equipment) are adequately managed to ensure the execution of the CMS.
c. The CMS is to be regularly reviewed by a multi-disciplinary team quarterly, while an audit is to be carried
out on the entire process bi-annually.
Conduct A Fmea With A Corrosion Risk Assessment
At the conclusion of the FMEA for low flow failure mode, the output of the exercise is captured below (see also
Table 5):
The output of the FMEA rated the criticality of failure mode as high due to the product of the susceptibility of
failure and Asset, Environment and reputation consequence based on the S-RBI tool (directindustry.com) (Figure
2).
Find below the justifications for the susceptibility and consequence levels chosen for each parameter:
1. The susceptibility for failure was assumed ‘High’ on the basis that a failure due to this mode had already
occurred on the case-study pipeline and is currently a prevailing failure mode.
2. The consequence of failure on the asset was rated medium because the direct cost for repairs of damage
& environment clean-up was circa $1mln for the failure currently investigated.
3. The consequence of failure on people was rated negligible, as there was no direct impact of the current
failure of the pipeline on the health & safety of personnel. The consequence of failure for environment
was rated medium because the failure of the pipeline led to spills, circa 3000 barrels which damaged
vegetation and required clean up to remediate. In addition, there were complaints received from the
surrounding communities along the pipeline Right-of-Way.
4. The consequence on reputation was ranked a medium as well, as the community and Government
regulators were aware of the failure in addition to the attention the failure and ongoing repair works
received in national media.
The criticality of a ‘High’ for this failure mode means a detailed investigation of the failure mode is to be
implemented and the CMS executed immediately.
Propose An Integrity Management Team Composition
An essential component of the CMS is the CMS execution team composition and their interdependencies, As
CMS execution requires team effort with clear responsibilities and accountabilities. A team composition (see
Table 6) has been proposed by this study based on analysis of the current work system in place, with gaps
identified to ensure all aspects of the CMS is duly attended to.
Based on the composition, find below the team definition, roles & responsibilities:
The Pipeline Integrity Team – This team led by the Head, Pipeline Integrity is accountable for the performance
of the PIMS, and the CMS proposed. On this role the Head would lead the team to drive the development and
execution of all pipeline integrity activities & tasks tabulated in the RACI above (analyst-
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zone.com/techniques/rasci-chart) and more to ensure the integrity of the pipeline is maintained and business
objectives satisfied. The pipeline integrity engineer would be the focal point of the 24in Trans-Niger pipeline
case-study and would be responsible for the approval of integrity activities & inspection recommendations,
interface management of all support teams, management of all integrity documentation & database, change
management on the asset, review of integrity data and effective communication of results.
The Engineering Discipline Team – acts as custodian to all engineering standards, codes and best practices
used within the organization. For the delivery of the CMS, support would be gotten from the Production
Chemistry, Process Engineering, Materials & Corrosion Engineering and Pipeline Engineering sub-teams.
a) Materials & Corrosion Engineering – They are custodians of all corrosion engineering and inspection &
monitoring related codes & standards as well as the corrosion models of all assets, providing technical
authority oversight on all corrosion related activities. The material & corrosion engineer would management
the execution of inspection requests, analysis, and reporting of inspection & corrosion modelling results. In
the same light, the Technical Authority for Materials & Corrosion would be involved in the evaluation of the
effectiveness of the CMS with respect to corrosion management for the asset. This would involve activities
like attending all strategic reviews & audits, provision of technical advice on corrosion issues and approves
technical deviations related to corrosion prevention over the course of executing the CMS.
b) Pipeline Engineering – They are the custodians of all pipelines related codes and standards, providing
technical authority oversight on all pipeline activities especially in resourcing of critical pipeline integrity
roles.
c) Process Engineering – This team is the custodian of all codes and standards related to the process & flow
assurance of the flow-station producing into the pipeline. They would provide all information and data on
the facilities upstream the pipeline.
d) Production Chemistry – This team is responsible for chemical management system which includes
chemical & chemical vendor qualifications, dosage rates, monitoring of chemical usage and chemical
treatment performance measurements.
Production Operations Team - This team provides oversight to the management of the entire upstream
production process. This involves, plant performance management and monitoring.
The final CMS output is the Corrosion Management Guide (CMG) (assetintegrityengineering.com) which
comprises of three main sections (see Tables 7 – 12).
The first section is the threat and barrier section (Table 7); the properties of the asset, the threat considered (low
flow), the barriers/mitigations & their status are highlighted. For our case-study, most of the barriers are
ineffective in mitigating the known threat of low flow (reasons highlighted).
The Integrity Operating Window of the pipeline containing the current state of the pipeline (Tables 8 – 9) shows
that the pipeline is being operated outside expected production rate limits at circa 39kbbls /day gross, which is
less than the volume required to achieve flow velocities > 0.5m/s.
The aim of the IOW column is to allow for monitoring, failures occur assets when operated outside stated design
limits. Data gathering is to begin on all parameters immediately.
In addition to the IOW monitoring, key integrity actions have been identified for integrity assurance for the asset
(see table 10 – 12). Based on the current state of the asset, there are actions required to be carried out to assure
integrity despite ongoing low flow condition, actions have been articulated as part of the Maintenance Reference
Plan. In addition, all Key Performance Indicators – leading and lagging that would be monitored to ensure that
the state of the system remains visible enough to manage excursions through the clearly identified action parties
are identified.
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Table 5: FMEA Worksheet
Table 6: Responsible – Accountable – Support - Consult – Inform (RASCI) chart of team composition
Failure Mode Effect Cause Assessment Control
Susceptibility
to Failure
Criticality
Asset People Environment Reputation
Low Flow
Solid deposition and
settling leading to
reduced internal
capacity, MIC & UDC
Reduced crude-
oil production
rates
Flow-rate, flow
pressure &
flow velocity
monitoring
Increased
throughput
through
pipeline
High Medium Negligible Medium Medium High
Consequence
FMEA OUTPUT SHEET
S/N
Activity List
Production Operations
Materials & Corrosion Engineer
Pipeline Integrity Engineer
TA2 Materials & Corrosion
TA2 Pipeline Engineer
Production Chemistry
Process Engineer
Pipelines Operations & Maintenance
TA1 Pipelines
TA1 Materials & Corrosion
Head, Pipeline Integrity
Asset Integrity Manager
CMS Implementation
1
Verification of barrier status and IOW monitoring
R R I R I R R I I I A I
2
Identification of actions for barrier maintenance execution
R R R R C R I S S A I
3
Provides current process description and operating conditions for normal
start-up and shut-down conditions.
R I I C A,R I I I A I
4
Identifies existing Mitigations/barriers, operational control and limits for
IOWs, Chemical, injections, pigging, CP, coatings, etc.
R R C R C R R C I S A I
5
Identifies corrosion/damage rate, type of mechanism, locations for
damage, morphology, and prior equipment Inspection history.
R R R R C R C R I S A I
6
Filter actions from the threat assessment and previous tasks.
R A I
7
Develop & update corrosion loops
C R C R I I C I I S A I
8
Secure CMF review/audit agreement & sign-off
R I R I C S S A I
9
Develop Inspection Programme
C R C R C C I C I S A I
10
Implement inspection program
I I I I I I I A I I A I
11
Implement monitoring and sampling program, IOW, Notifications and
alerts/alarms as required.
I C R R I R C R I I A I
12
Ensure systems are in place to update and analyse IOW routinely
R C R C C R C I I I A I
13
Update and maintain CMS
C R C R C I I C I S A I
14
Update and maintain Inspection Plan
C R C R C C I C S S A I
15
Review CMS assurance Improvements (Quarterly reviews & Audits)
C A R S S C S C S S A C
16
Review CMS action close out, assurance and improvements
R C A,R C I S C C A C
R
Responsible
A
Accountable
S
Support
C
Consult
I
Inform
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Table 7: Threats & Barriers table of the CMG for low flow condition of the 24” Pipeline
Table 8: 24in Trans-Niger Pipeline integrity operating window
Corrosion Loop Description Material External coating Insulation Type Notes Likelihood Type Status Reason for Status
Actual CR
(mm/ y)
Low velocity
(<0.5m/ s)
High susceptibility to MIC High Process modification red
Low production flowrate
with respect to the size of
the pipeline (<80kbopd)
Low velocity
(<0.5m/ s)
High susceptibility to MIC High Biocide Injection red No biocide injection.
Low velocity
(<0.5m/ s)
High susceptibility to UDC
induced MIC due to
carbonate scale deposits
as identified from
investigations.
High
Scale inhibition
injection
red
No Scale inhibition.
Low velocity
(<0.5m/ s)
High susceptibility to UDC
induced MIC due to sand
deposits as identified in
reports
High Sand control
Sand screeners are
deployed upstream of the
pipeline, but monitoring
status of the effectiveness
of screens are unknown.
Low velocity
(<0.5m/ s)
High susceptibility to UDC
induced MIC
High Pigging red
Infrequent pigging
schedule as shown by
historical pigging records.
24in Pipeline Threats & Barriers
Threats
Barrier
24" x 55 km TL
WT = 10.31mm
Installation year
1995
Pipeline and
River
crossing
CS
Polyethylene
none
0.5mm/yr from
2012 intelligent
pigging
inspection.
Process Parameter Actual Integrity Min
Integrity
Max
Monitoring
Frequency
Location Notes Standarised actions if outside IOW
Temperature (deg C) 35 0 80 Daily
Inlet & outlet Trend Inform the Integrity Management Team.
Pressure (bar) 12 NA 40 Daily
Inlet & outlet Trend
Shutdown pipeline and inform the Integrity
Management Team.
Oil/ Condensate (bls/ d) 21000 NA NA Daily Inlet Trend
Inform the pipeline integrity and Pipeline
engineering personnel for hydraulic analysis and
advise.
Water (bls/ d) 18000 NA NA Daily
Inlet Trend
Inform the pipeline integrity and Pipeline
engineering personnel for hydraulic analysis and
advise.
Sand content (pptb) NA NA 10 3 Monthly
outlet Trend Ensure status of internal barrier is green
Dissolved H
2
S (ppm)
NA NA 10 6 months Pipeline outlet Trend Inform the Integrity Management Team.
Velocity (m/ s) 0.5 1 4 Daily
Calculated Trend Inform the Integrity Management Team.
Bicarbonates
mgCaCO3/ l
122 NA NA Annually
Inlet & outlet Trend Inform the Integrity Management Team.
Iron Count (ppm) NA
±
10
±
10
3 months Pipeline outlet Trend Inform the Integrity Management Team.
24in Pipeline Integrity Operating Window [sampling and monitoring required].
IOW
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Table 9: 24in Pipeline integrity operating window contd.
Table 10: 24in Trans-Niger Pipeline Maintenance Reference Plan and KPIs
Table 11: 24in Pipeline Maintenance Reference Plan and KPIs Contd.
Process Parameter Actual Integrity Min
Integrity
Max
Monitoring
Frequency
Location Notes Standarised actions if outside IOW
Sessile Bacteria Count
(col/ ml)
NA NA 10
Monthly (every
pig run)
Pig debris Trend Inform the Integrity Management Team.
Planktonic Bacteria
Count (col/ ml)
NA NA 1000 Monthly
pipeline outlet Trend Inform the Integrity Management Team.
Biocide Residuals (ppm) Not started NA 3 Monthly
pipeline outlet Trend Inform the Integrity Management Team.
Scale Inhibitor Residual
analysis
NA 10ppm 3 Monthly
pipeline outlet Trend Inform the Integrity Management Team.
Corrosion rate
(monitoring) mm/ yr
0.5 0.1 0.1 3 months
Desktop
analysis
Trend
Inform the Integrity Management Team.
Max. Defect growth rate
(mm/ y)
0.5 0.1 0.1 3 months
Desktop
analysis
Trend
Inform the Integrity Management Team.
24in Pipeline Integrity Operating Window [sampling and monitoring required].
IOW
Maintenance Reference Plan
Priority
Rank
Implementation Indicator Action Owner Frequency
Target
Indicator
24'' Pipeline
1. Commence biocide & scale inhibition injection
(Use only qualified Inhibitors).
HL
Actual Corrosion Rate mm/ year
Materials &
corrosion
Engineering TA2
Quarterly
< 0.1 mm/ y
2.Conduct weekly routine pigging using brush and
scraper pigs. conduct sampling before and after
each run. Report solids and follow up bacteria count
for the first-run. This should be immediately followed
by batch biocide application between two pigs with
>30mins contact time. Target biocide concentration
=5000ppm only first run. Duration=2 months. For 2
month, complete monitoring and then evaluate
increase to monthly
HL CMS Developed
Materials &
corrosion
Engineering TA3
Quarterly
100%
95%
3. Conduct weekly sampling/ performance
monitoring of sessile/ planktonic bacteria post-
pigging operation. Issue reports to the Integrity
management team for evaluation to optimize
pigging/ batch biocide frequency.
LL
MRP Implemented (all optimization and
improvement recommendations are
implemented by asset)
Pipeline
Integrity/ operati
ons
Quarterly
100%
Not Started
4. Complete MIC assessment and optimise biocide
injection rate.
LL Corrosion Monitoring/ sampling in-place
Production
Chemistry/ Pipeli
ne Integrity
Quarterly
100%
Not Started
24in Pipeline Maintenance reference plan and KPIs.
Management / AIPSM KPI
Maintenance Reference Plan
Priority
Rank
6. Immediate completion of sampling program -
Bacteria, scaling tendency, sand count, Fe
count,chloride content, alkalinity, pressure and
temperature at the inlet etc. (See IOW frequency &
priority).
HL IOW excursions
Materials &
Corrosion
Engineering TA2
/ Pipeline
Integrity
Engineer
Quarterly
Zero
Not Started
7. Install a reinforced thermo-plastic (RTP) as a liner
in current pipeline in place.
HH Hydrocor modelling completed
Materials &
Corrosion
Engineering TA2
/ Pipeline
Integrity
Engineer
Annually
100%
Not Started
8. Update Corrosion & Flow assurance models with
pipeline plan & profile (Model corrosion rates at low
spots, onplot piping and compare with inspection
data)
HL
9. Dig verification: Identify UT monitoring locations
and monitor wall defect growth. Verify IP wall profile
data with UT results
HH
24in Pipeline Maintenance reference plan and KPIs.
Management / AIPSM KPI
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Table 12: 24in Trans-Niger Pipeline Maintenance Reference Plan and KPIs Contd.
Integrity Management Execution Roadmap
A roadmap details the activities to be executed to achieve set objectives. The overall aim of ensuring the 24”
pipeline is operated through to its end-of-life and beyond would be ensured through the execution of the technical
roadmap in Table 13. A change roadmap was also created based on Kotter’s 8-steps (airiodion.com/john-kotter-
change-model/) and Bridges Change management models (wmbridges.com), to ensure that the CMS is setup to
drive a cultural change in the way of working; from undocumented processes, to processes properly documented,
made visible and transparent for the organization. These roadmaps would become templates that would ensure
that this entire CMS process can be replicated across other pipeline assets.
Table 13: Technical Roadmap for the Asset Integrity Management of the 24” Pipeline
Implementation Indicator Action Owner Frequency Indicator 24" Pipeline
Injected chemical residual & water
chemistry sampling/ analysis done to
planned frequency
Production Chemistry
/ Production
Operations TL
Monthly
100%
Not Started
Chemical / Inhibitor availability target as
defined in CMS
Production Chemistry
/ Production
Operations TL
Weekly 100%
Not Started
Performance monitoring / IOW data
carried out and communicated
Pipeline integrity
Engineer
Monthly
100%
Not Started
Monthly CM performance data review
and optimization recommendations issued
to the AM cc: Ops & Mtce TL
Materials & Corrosion
Engineer
Monthly
100%
Not Started
Chemicals injection points / stock
available
Production
Operations TL
Monthly 100%
Not Started
Integrity assessment conducted and
corrosion rate determined as per CMS
recommendation
Pipeline
Integrity/ Materials &
Corrosion
Engineering
6 monthly 100%
Not Started
Asset KPI
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Table 14: Asset Integrity Change Management Roadmap for the 24” Pipeline
CONCLUSION
The 24in Trans-Niger pipeline is a critical asset for the company as it was designed to evacuate circa 100 kbopd
from four (4nos.) production facilities; if the pipeline is not in operation, that translates to a huge economic loss
for the company & Nation (more than N8 million daily). This economic viability of the 24in pipeline is similar
for pipeline assets generally. Pipelines as critical economic infrastructure need to be preserved effectively over
their designed life cycle, to ensure that business & organizational objectives are met. To maintain the integrity
level required to meet business goals is the principal aim of Asset Integrity Management. This study concludes
that Asset Integrity Management without following best practice or industry standard methodology is grossly
ineffective and would lead to dire consequences as in the case of the 24in Trans-Niger pipeline case-study with
its failure in 2018. The Energy Institute Guidance on Corrosion Management in Oil and Gas Processing facilities
premised on the Plan – Do – Check – Act model, provides a method for ensuring the management of an asset in
a visible, transparent, and auditable manner, which ensures that extant threats do not lead to sudden & unexpected
asset failures.
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MANAGEMENT & APPLIED SCIENCE (IJLTEMAS)
ISSN 2278-2540 | DOI: 10.51583/IJLTEMAS | Volume XV, Issue IV, April 2026
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