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Topic 8: subsea integrity and reliability management

Henry Tan's picture

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oseghale lucas okohue's picture

Subsea Intergrity Management entails that the engineered subsea assets fulfills the following: 1.     The asset/system fulfills the design requirement throughout its whole Lifecycle  2.     Ensures fitness for purpose of assets with optimal use of effort whilst complying with company policies and  regulatory requirements  By definition it can be said to be the continuous process of ‘Knowledge and Experience Management applied throughout the lifecycle to assure that the asset/system is managed cost effectively and safely and remains reliable and available, with due focus on personnel, assets, operations and environment. Reliability gives us an assurance of dependability of the subsea assets why the fulfil their engineered designed lifecycle with minimum or know intervention or repair required during the fulfilment of the engineered lifecycle. It can be said to be the probability that a component or system will operate satisfactory either at any particular instant at which it is required or for a certain length of time. 

Subsea integrity management includes the following elements i.e  company policy, organization and personnel, reporting and communication, operation controls and procedures, management of change, contingency plans, audits and review,  information management, the integrity management process.

 Diagrams:

    Fig 1. Intergrity Life Cycle Management Solution

 

 

Note: The Integrity Management Process (IMP) is the core of the Integrity Management System (IMS)  and consists of the following steps:1. Risk Assessment and Integrity Management (IM) Planning which includes threat identification, risk assessments, long term and short term (annual) inspection planning.2.  Detailed planning and performance of Inspection (external and internal), Monitoring and Testing activities.                                                                3. Integrity Assessment based on inspection and monitoring results and other relevant historical information.4.  Performance of needed Mitigation, Intervention and Repairs activities. 

Henry Tan's picture

The lecture delivered at my course Subsea Integrity by Mark Wilson, Structural Technical Authority of the CNR International, is useful in understanding subsea integrity management concepts. Here are the recorded videos: part1, part2.

Lee Soo Chyi's picture

What is Subsea
Integrity Management?

  “The management of
a subsea system or asset to ensure that it delivers the design requirements,
and does not harm life, health or the environment, through the required life” [1]


Subsea Integrity Management is a continuous
assessment process applied throughout design, construction, installation,
operations, life extension and decommissioning phases to ensure that the subsea
system/ operation is managed cost effectively, safely and remains Reliable and
Available. The most important and frequent asked question is “Is something fit for service? “ It can be a
structure, manifold or other component. This further seeks to specify and
ensure that the component is operated in a manner that does not lead to damage
and degradation and in accordance with the design limitation


Subsea Integrity
Management program includes various aspects such as:

1)     
early
stage planning

2)     
safe
operational limits for the system

3)     
monitoring
system (electronic probe, strain gauge to measure pressure, temperature, motion
of the structure/ system)

4)     
Processing
and analysis of monitored data (be able to filter and analyse the data and respo
nse immediately if there is abnormal behaviour).

5)     
risk
based inspection

6)     
inspection/
maintenance (UT, NDT, MPI

7)     
emergency
response

8)     
audit
and review (annual survey as required by regulatory authorities/ third party
auditor)


 


Reference:


[1] Energy Institute
Guidelines for the Management of Integrity of Subsea Facilities.


 

 


Soo Chyi, Lee

Henry Tan's picture

NDT (non-destructive testing) inspection techniques such as UT (ultrasonic testing), MPI (magnetic particle inspection) will be introduced in the Laboratory of the Subsea Integrity course.

SON CHANGHWAN's picture


Some activity like below function as a feedback system. In
the design stage, the Hazard and Operability Study (HAZOP) is performed for
system being divided into “nodes”. This is conducted by several parties for
example, design team, installation team and operational team. From the study,
researcher identifies the possible causes, related consequences and designed
safeguard. Depends on the criticality, researcher can recommend further
safeguard for risk mitigation and this have to be concluded in some ways i.e. be
rectified or justified.


 


What
is HAZOP?


A HAZOP study is a well-proven team-based
method structured to identify facility hazards during process design completion
or planned modifications. Special techniques are used to conduct detailed
examinations of process and engineering intentions for new or existing
facilities. These techniques help to identify the hazard potential of
operations that may occur outside the design intentions or malfunctions of
individual items of equipment and their consequential effects on the facility
and surrounding area.


 


HAZOP studies are lead by experienced
facilitators. Core teams typically consist of personnel from various
departments including Project Engineering and Operations. These studies may
also require the involvement of process technologists, environmental specialists
and corporate Health & Safety and Environment (HSE) staff. "


 


So HAZOP / HAZID study should be a basis of
subsea intergrity management.
 Plus lesson learned from operational phase e.g. operational misbehavior will be added to subsea intergrity management through internal feedback system. If operators/vendors
are sharing their lesson learned like integrated feedback system, it would be
the best. But I didn’t find the case yet.


 



Reference:


 


[1] Bureau Veritas


http://www.us.bureauveritas.com/wps/wcm/connect/bv_usnew/Local/Home/Our-Services/Industrial_Asset_Management_Services/Hazard_and_Operability_Study_(HAZOP)/

 

SON, CHANG HWAN


Henry Tan's picture

Two years ago (2010) Mr Ji Wen, a Subsea Facilities Engineer of BP plc, gave a lecture to my class on “Subsea engineering integrity and assurance”, here are the recorded video: part 1, part 2. His talk is useful for understanding Subsea Integrity Management concepts, HAZID and HAZOP.

Jonathan Ogbekhilu's picture

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Knowledge of the environmet
(depth, pressure, temperature, corrosive medium inaccessbility to human) plays
a crucial role in the design of subsea equipment and facilities.

Subsea Integrity management
is to ensure that regardless of the environmental contraints and challenges,
subsea equipment nad facilities are designed  and operated safely and relaibly through the
life cycle of the facility. With great care, concern and consideraly for
personnel, environment, and assets.

 

Integrity is therefore in two
stages viz:

1.   
Integrity at
concept and design stage and

2.   
Integrity at
operation phase

 

Establish Integrity

Maintain Integrity

 

 

Fig 1. Integrity Stages

The drivers for Integrity management are:

1.   
Industry Regulation  eg API DNV, ISO, NORSOK, IEC, NACE, ASME etc

2.    Operators

3.    Government
Policy

 

  

Fig 2. Standards and regulation

 

 

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Henry Tan's picture

plese clean the post.

Jonathan Ogbekhilu's picture

Knowledge of the environmet
(depth, pressure, temperature, corrosive medium inaccessbility to human) plays
a crucial role in the design of subsea equipment and facilities.
Subsea Integrity management
is to ensure that regardless of the environmental contraints and challenges,
subsea equipment nad facilities are designed  and operated safely and relaibly through the
life cycle of the facility. With great care, concern and consideraly for
personnel, environment, and assets.
 
Integrity is therefore in two

stages viz:
1.
Integrity at concept and design stage and
2. Integrity at operation phase
 

Establish Integrity Maintain Integrity
 

 ///C:/Documents%20and%20Settings/ogbekhj/My%20Documents/My%20Pictures/stages%20of%20Integrity.bmp

Fig 1. Integrity Stages


The drivers for Integrity management are:
1.   
Industry Regulation  eg API DNV, ISO, NORSOK, IEC, NACE, ASME etc
2.    Operators
3.    Government
Policy
 

///C:/Documents%20and%20Settings/ogbekhj/My%20Documents/My%20Pictures/Copy%20of%20Standards%20and%20Regulations.bmp

Fig 2. Standards and regulation

 

  

YAKUBU ABUBAKAR 51126107's picture

Subsea
fields are being developed at an increasing sea water depth and at a long step
out distances from the control location where their daily operations are
carried out remotely using subsea control systems.

The
used of subsea control systems to produce oil and gas from a remote and smaller
fields are becoming popular especially in the North Sea.

 Because of the recent high profile offshore
disasters in the oil and gas industry most noticeable the British Petroleum
(BP) plc. Worst ever Oil spill at the Louisiana course gulf of Mexico 20th
April, 2010 were over 4.9 billion barrels of crude was leaked and the oil spill
cost the company about 3.8 billion pounds

            The British Petroleum (BP) oil
disaster has now become an awakening call for the oil industry operators as
well as regulators on the need to strengthen safety and reliability
investigation in a subsea oil field development.

Since
then any new subsea installations/equipment design would be scrutinized to ascertain
its safety and reliability capabilities in line with the best industry practice.
Because such offshore failures always have political and financial implications
to the companies involved.

            The subsea operational networks can
be a very complex system, therefore to ensure total safety in an event of any
eventuality an emergency shutdown function is provided for oil wells that can
be activated automatically from a distance of over 100 miles.

References:

1. Yakubu Abubakar MSc thesis
Safety and Reliability Investigation of Subsea Control System 2012.

1. British Broadcasting
Service BBC. BP oil spill disaster at Gulf of Mexico 2010

2. John Strutt, Astrimar
Ltd,Luke Emmet and Gorge Cleland,Adelard LLP. Reliability and Intergrity
Assurance of Subsea Technology using ASCE 2012

 

Andrew Allan's picture

Yakubu,

With fields being drilled at greater and greater depths, there is an increase in the number of high pressure, high temperature (HPHT) wells in operation.  With HPHT service there is an increased challenge on the design engineers to ensure safe and reliable production from these fields.  Given the process characteristics of these fields, with closed in tubing head pressures in excess of 700barg and 200DegC, the ability to install an inherently safe pipeline design becomes problematic as the cost of installing a fully rated pipeline (often over long distances) may make the project unviable from a cost perspective.  This then places a reliance on highly reliable subsea overpressure protection systems, as the pipeline may be rated for a lesser service below the closed in tubing head pressure.  The role of these overpressure protection systems is to detect increases in pressure as production reaches the surface and to automatically initiate control measures to mitigate the risk of overpressuring the pipeline or associated subsea equipment.  Given the great consequences of an overpressure event leading to a large release of production fluid, the overpressure protection system must be highly reliable.  The reliability requirements of the system are evaluated during design and Safety Integrity Level (SIL) level assigned.  This SIL level drives the specification and redundancy of instrumentation and control equipment such that there may be 3 pressure monitors such that if one fails there is still sufficient monitoring in place.

The thorough evaluation of hazards, their likelihood and consequence is therefore essential during design to ensure a robust and reliable overpressure protection system is installed.

 

Mark Nicol's picture

Good
post Allan.

I’d like
to expand a bit on the HIPPS (high integrity pressure protection system). The
HIPPS system is usually located on the manifold and allows the high pressure
part of the pipeline to be de-rated, between the manifold and platform.

This would
reduce the wall thickness of the pipeline /risers between the manifold and
platform or FPSO due to the reduction in pressure.

This
would have an obvious cost benefit to the operator in the design phase, which I
suppose could offset some of the cost of the HIPPS system which I’m assuming
would be quite high, although I have no information on this.

From
what I’ve read the HIPPS system has a dedicated subsea control module which
controls the pipeline safety valves of the HIPPS system. This allows for a
closed loop system operating independently of the production control system. As
you mentioned with the three pressure monitors, there are also three alarm / shut
down control safety systems as follows:

·        
An
alarm is produced when the de-rated section pressure has been breached.

·        
Once
a set higher pressure is reached the HIPPS valves close automatically.

·        
If
there is any loss of electrical or hydraulic power the HIPPS valves are
designed to close. 

Kwadwo Boateng Aniagyei's picture


Good comments by Allan and Mark. I will
like to elaborate on the subsea HIPPS system. HIPPS are critical elements in a
process loop. Malfunction or failure of a HIPPS can seriously affect plant
operation, the environment and personnel. The design of a HIPPS should be based
on sound technical and economic arguments and long-term perspectives.
A subsea HIPPS is a complete functional
loop consisting of

                                                                                                                                                          

1)The initiators that detect the high
pressure.                                                                                        

2)A logic solver, which processes the input from
the initiators to an output to the final element.               

3)The final elements, that actually performs the
corrective action in the field by bringing the process to a safe state.
         
The final element consists of a valve and fail safe actuator and possibly
solenoids.

 

I
agree with Mark's assertion that subsea HIPPS systems have economic benefits.
The cost of a pipeline is largely dependent on the pressure of a reservoir.
Extremely high reservoir pressures will require piping materials of high
thickness and quality. With a HIPPS system in place, this will control the
pressure within the subsea system to an acceptable and desired limit. This will
afford a design engineer to settle for less thick and expensive piping
material, reducing the cost of design. 


 References


http://www.mokveld.com/en/24/subsea-products-of-mokveld/subproducts/20/subsea-hipps

Uko Bassey's picture

 

In
the past, the major drivers of integrity management (IM) were ensuring that a
safe system is in operation with increasing system availability in the short
term. The current practices by subsea facility operators have gone beyond this;
they are now increasing their integrity management system to identifying the
possibilities for extending the field life of their assets past the original
designed conditions.
 

The management of asset
integrity involves three major steps which include operational integrity,
technical integrity & design integrity. These stages or structures are
guided by policy, framework, strategy (plant, process, people) and procedures
and working practices (RCM, RBI, etc.). IM has the following building blocks
risk assessment and IM planning; inspection, monitoring and testing;
integrity assessment and review & update (which may require intervention
for maintenance/or repairs). Providing a reliable system is a major concern in
all industries (manufacturing, energy, IT, etc) but the severity differs.
 

Integrity management has the
following objectives; prevention or reduction in unplanned cost/production
targets, fulfillment of company requirements, protection of  the value of
the assets/reputation, low maintenance and repair costs, compliance with
regulatory and legislative requirements, protection of the environment, health
and safety. The achievements of these objectives are therefore dependent on a
proper IM and reliability programme.


Ref: Subsea Integrity management, a brief overview by Ato Suyanto, PHE ONWJ.


Uko Jonah Bassey.

Subsea Engineering.

 

Uko Bassey's picture

Safety
and reliability are co-dependent words, such that one cannot talk about safety
in anything when it is not reliable be it an integral part of the unit or the entire
system and the reverse is also true. Therefore, safety and reliability are
indispensable words in any field, particularly engineering functions. Viewing reliability
in these two contexts “availability & dependability”, one can only function
on system that have higher degree of reliability. Without reliability in our
systems, the control of subsea equipment ranging from the pumps, ROVs, valves, taps,
etc to the fluid flow factors like pressure, temperature, flow rate, etc will
be a mere desire. Only safe and reliable systems can be productive. Subsea control
and reliability management remains vital; hence, it is not the responsibility
of only one party or individual just as security is every one’s business. Reliability
management of our subsea systems is important if we must operate at optimum
level and remain in business that is only way we will continue to add value to
the investment of our stakeholders.

Uko
Jonah Bassey.

Subsea Engineering

Giorgos Hadjieleftheriou's picture

Topic
8

Subsea
integrity and reliability management

Integrity means the correct management of a system to
produce the desire results exactly as they have been designed without harming,
in general.

An effective management helps the operators of an
offshore production development, for example, to reduce uncertainties related
to design or response of a subsea system. It also allows the managing and controlling
the risks of the production.

In other words the aim of the integrity is to develop
guidance on management practices and tools to assess optimize safety.

Process – Life cycle:

·        
Inspection: equipment checking above and
below the water surface

·        
Monitoring: environmental conditions measurements

·        
Analysis and Testing: analyzing an testing
the data collected

 

The integrity management role is to fulfill company’s
requirement, protect the environment, health and safety and avoid any
accidents. Furthermore to reduce unplanned costs, minimize the maintenance and
repair costs but also to protect the assets.

http://www.offshore-mag.com

http://www.2hoffshore.com

Andreas Kokkinos's picture


The subsea integrity management process has been present to
the Oil and Gas industry for many years. This process includes a documented
integrity management program, an emergency response action plan and a personnel
qualification program. [1]


The benefits of an integrity management strategy are
significant because it can be accomplished with minimum level of work required.
Benefits such as long term field planning for life extension or re-use, reduced
inspection costs through rationalization, next generation design benefits, an
ability to proactively plan for repair and maintenance, increased system uptime
and availability and rationalization is spared. [1]


The main problem with subsea integrity management systems is
the vast quantity of data required such as [1]

  • Historical process and production
    data
  • Erosion and corrosion data
  • Chemical injection data
  • Material sample list
  • Manufacturing history
  • Design documentation
  • Risk assessment methods and results
  • Inspection strategies
  • Industry advances and best practices
  • Future field requirements
  • Specialist analysis and report
  • And many more


Integrity management systems usually look at the present day
status based on historical conditions and very little time is spent looking at
the future suitability of a system. [1]

[1] Integrity
Management of Deepwater Subsea Systems

(Can
be found here:
http://www.woodgroup.com/SiteCollectionDocuments/news-tech-articles/2008-11_ThrulifeIM-Offshore_MCS.pdf)


Andreas Kokkinos

MSc Oil and Gas Engineering

adavis's picture

I had to chuckle when I read, "The main problem
with subsea integrity management systems is the vast quantity of data required".  In
my experience, relevant data is usually one of the most difficult things to
find.  In general, companies are in the business of manufacturing a
commodity or providing a service which is normally not data collection. Most companies spend very little time
gathering data even about their own process or product.  The end
customers, usually the Majors, rarely share information about failures.  In fact, they often don’t even inform the
manufacture of the product that failed.

 

This is why JIPs, Joint Industry Projects, are so
valuable.  Lots of NDAs, non-disclosure
agreements, are signed and the information trickles in but a trickle of
information is better than none.

Uchenna Onyia's picture

A key area of Subsea systems integrity is life extension.
Most subsea production systems in brownfield projects are approaching their prescribed
design life and as such a life extension process has to be adopted. The life extension
or requalification is initialled to continue the operation of a system beyond
its original service life.  This life
extension process documents acceptable system integrity to the end of the
extended service life.  Taking from the
NORSOK standard U-009, the overall life extension methodology is as follows:

·        
The premise/reason for the extension operation
and new threats to the system (such as temperature, pressure, external loads,
new rules and regulations and codes and human factors) has to be defined.

·        
The current conditions of the integrity of the
system have to be assessed;

·        
A reassessment of the system must be carried out
based on current/available technological conditions, available information,
current industry practice;

·        
This reassessment now tells us if the integrity
of the system is acceptable up to the end of the anticipated extended service
life and if not identifies modifications to be made to improve the integrity of
the system.

 

Source: NORSOK standard U-009:
Life extension for subsea systems 

 

uchenna onyia 51232632

MSc Subsea Engineering 

Igwe Veronica Ifenyinwa's picture

subsea integrity and reliability management are procedures employed to proactively discover shortcomings that may have gone unnoticed during subsea development.  It also helps to have a better knowledge of the uncertainties involved, eventually result in potential to reduce these uncertainties and aid in the decision making process while evaluating subsea developments.

Production of oil and gas for a number of years happens to be the stronghold of the economy of many of countries of the world and hence can never be overlooked. Oil and gas industry in several countries aims at the exploitation of all oil and gas reserves. The industries are emerging into deep and utra-deep waters for efficient recovery. This lends to change in environmental conditions experienced compared to that encountered in shallow water. In addition to that, Subsea development projects usually require intense capital, introduction of new technology under unverified conditions and much time to critically exhaust the impending issues within its scope etc. These may lead to higher risk of exposure but also possible opportunities that should be exploited.

Subsea Integrity and Reliability management   using standard new technology in subsea environment and well thought out risk management provides powerful tool to guarantee project objectives are met and uncertainties are managed during the entire life of the project.

/www.onepetro.org/mslib/servlet/onepetropreview?id=OTC-15343-MS

Igwe Veronica Ifenyinwa's picture

Subsea integrity is the state of subsea system where it is realizing its intended functions without being degraded/damaged or its surroundings altered internally or externally while reliability of a subsea components or systems is the prospect that the component or system will not fail for a specific period of time. Also components may be replicated to advance reliability and increase availability of the system functions.

Subsea Integrity and reliability management procedures should be merged into a single process, because they all treat in a similar manner with the identical systems. Since the general aim is to maintain system integrity and availability all through its entire life. All the processes should start early in the design phase of a project and be carried through to decommissioning process

Robbie Potter's picture

An important aspect of subsea integrity management not yet discussed is that of fatigue failure.

The risk of fatigue failure in pipework due to vibration is considerable and is formally assessed
in accordance with the Energy Institute Guidelines for the Avoidance of Vibration Induced Fatigue
Failure in Process Pipework[1]. However, these Guidelines were produced for the assessment of topside
and onshore pipework only.

Subsea vibration has not been an area of integrity management that has been given much consideration.
However, due to the recent increase in the use of subsea processing equipment, deeper production
and subsequently higher flow rates and increasing number of failures due to process driven excitation,
the Energy Institute are developing guidelines relating to fatigue in subsea pipework.

Currently, the consideration of subsea pipework is typically limited to external vortex induced
vibration of riser systems and unsupported pipeline spans due to wave loading. These are basically
classified as environmental excitation mechanisms. As discussed, the increase in subsea equipment
brings with it process associated excitation mechanisms; which include flow induced turbulence, pressure
pulsation and mechanical and acoustic excitation.

The creation of a management strategy to mitigate the risk of subsea fatigue failure is important as
it provides a formal means of evaluating new design and in-service equipment with the ultimate aim of
reducing the probability of a hydrocarbon release.

Due to recent incidents, subsea integrity possesses a much higher profile than previously.

References:

[1] The Energy Institute (2008) Guidelines for the Avoidance of Vibration Induced Fatigue
Failure in Process Pipework. Second Edition, London, UK.

Robbie Potter
Subsea Engineering

Kwadwo Boateng Aniagyei's picture


I agree with Robbie’s comments. However I will
like to air my views in support of what he has said. Subsea integrity will
forever remain a safety concern for offshore oil and gas operators as assets
continue to age and deteriorate. Though many phases of the subsea system integrity
are dealt with at the design stages; vibration-induced fatigue begins to set in
as the equipments age and wear out. Vibration-induced fatigue can lead to pipe
work failure and subsequent hydrocarbon release. Failures of this kind can be
very catastrophic and have significant impact on the industry though its likelihood
is very small.


Assessment of subsea systems to
vibration-induced fatigue has been largely limited to vortex-induced vibration
(VIV) of riser systems and unsupported pipeline spans (i.e. environmental
loading). Until recently, operational experience has indicated that vibration
caused by internal flow (i.e. process excitation) has not been a significant
issue subsea. However, piping vibration due to process excitation has started
to become an issue on manifolds and jumpers, in part associated with increasing
flow rates. The major challenge in this regard is the issue of “hidden
threats”. There is no obvious sign that vibration is occurring (possible
exception is flow induced pulsation from a riser, which may be heard topsides).
To curb this potential risk; the energy institute is developing ‘Guidelines for
the Avoidance of Vibration Induced Fatigue Failure in Process Pipework’. This in
my opinion will help sustain the reliability of our subsea systems and prevent
accidents like hydrocarbon release and explosions.


References


http://www.offshore-mag.com/articles/print/volume-71/issue-9/production-operations/hidden-integrity-threat-looms-in-subsea.html


http://www.subseauk.com/documents/xodus%20group%20-%20subsea%20europe%20paris%202011.pdf


YAKUBU ABUBAKAR 51126107's picture

A very serious threat to safety and integrity of a subsea
pipeline/ equipment that have been overlooked for a long time is the second
tier failure mode which includes among others erosion, environmental cracking and
internal corrosion. These root causes of subsea pipeline and equipment failure remain
dangerous hazards within our high risk subsea operations.

Because of the sensitive nature of the subsea operation
reliability issues and management is of serious concerns and there is a serious
disconnect between the knowledge transfer and safety management.

The corrosion related failures is the most serious among them
but can be handle using a better existing knowledge and the used of different modelling
techniques. Any corrosion management strategy must be very clear and consistent
in improving the integrity of the facilities, operational safety, environmental
friendliness, availability of the equipment and revenue management.

The corrosion integrity management plan must be sequential and
systematic in approach from corrosion management -----corrosion monitoring------pigging------mitigation
and control. ITs important to learn from past experiences of safety issues help  in the improvement and management of safety in the future

YAKUBU ABUBAKAR.

OGE.

Reference: Offshore
integrity management 20 years of overview lessons learns from post Piper Alpha (Binda
Singh, Paul jukes) 2009 offshore Technology Conference.

 

Dike Nwabueze Chinedu.'s picture

Subsea integrity and reliabilty management is assessment and management practice carried out on subsea facilities to ensure that it is fit for purpose, performs as intended and does not pose threat to life, property and environment.

This type of management is carried out from design through to decommissioning stage including possibility for life extension. It is done so as to comply with legislation, protect investment, life and to prevent or reduce unplanned costs.

Lifecycle integrity management involves: Appraise>select>define>execute>operate>decommission.

Integrity management process for operational subsea assets involoves: coporate policy, organisation and integrity management(IM) startegy in the other as follows; define IM programm>implement IM programme>assess performance of IM programm>lessons learned and improvement implemented>reviews(tactical, strategic or independent audit). Basically, this is a plan-do-check-review cycle approach. the coporate policy or standard incapsitulates structural integrity management startegy, pipeline integrity management strategy, subsea facilities integrity management strategy.

For, effective IM at project stage, defining and understanding which component has the highest risk and keeping good records is key.

In all of this, a successful subsea IM requires the technical competence of the management staff and persons involved in the risk management and IM process.

REFERENCES

[1] Subsea integrity lecture presentation by CNR international.

talal slim's picture

In previous commnets the concept of HAZOP has been discussed so in this post will discuss the concept of HAZID . Many times HAZID gets mixed with HAZOP so will try to clarify the main difference between both processes.

A HAZOP/HAZID can be performed at different levels of detail, but the purpose is the same : identifying the risk.

The HAZID is similar in many ways to the HAZOP, in which the basic methodology involves a brainstorming session to identify how a process can malfunction or be incorrectly operated. However , a HAZID is intended to produce  a checklist of potential problems that need to be addressed in later design stages. The HAZOP is intended to reduce the hazard potential for a specific process or procedure by integrating anticipation of any deviation from the design intent.

The main processes involved in the HAZID are as follow :

1) Identify each system , sub-system , component or process that can fail

2) Describe the functions of each item with respect to the top-level assembly or system followed by describing the failure modes/ hazards

3) Identify and document the worst case failure effects /hazard consequences

4) Rank the probability of the failure modes

5) This will allow for ranking the risks and this is the main purpose of conducting the HAZID

After that , a risk mitigation plan or action list is developed by the project team , so as to address the actions required to reduce the identified risks to an ALARP level.

Reference:

FMC Technologies: Subsea Engineering Boot Camp: Houston : 2006

adavis's picture

Textbooks about reliability have numerous examples of about the mathematics behind the concepts.  However, from my experience, they often overlook one of the most basic principles, how to determine the probability of failure of a component or a complex system with limited data.  The Oil Industry, though very risk averse, deals with very costly and complex systems which limits a company’s ability to build and test large numbers of samples.  For instance, in the flexible pipe and umbilical industry, a single dynamic flex fatigue sample may cost up to a half a million dollars to build and test and may take between 3-6 months to complete.  The end result is that projects proceed with a full 

scale sample size of one.  Given this constraint, it’s often difficult to definitely answer the

question, “How reliable is my product?”  To offset this, there are normally numerous small scale test and stacks of analysis reports.

As engineers, we have a tendency to want definitive answers.  Unfortunately, given the constraints of money and time, we often have to be creative in our methods to limit risk and ensure reliability.

Andrew Strachan's picture

100% agree. Subsea equipment in my experience undergoes Performance Verification testing (PVT)(Statistical sample of one) and then each unit manufactured after that under goes a Factory acceptance test, a far less onerous test which proves the individual equipment fit for purpose. The PVT does not normally require taking the as-built part material yield strength into account or geometrical tolerance (i.e. does not test worst case).

This isn't exactly testing for reliability, which is of course usually economically unfeasible.

A question I have been pondering is, can you carry out a meaningful fatigue test with a statistical sample of one?

Tony Morgan's picture

The sample size query is interesting and it may simply amount to the fact that it is better to have tested one as none ! The key to success in risk reduction here is more to consider these systems as prototypes whereby we are simply trying to understand and obtain characterisation information for the samples which pass whilst critically reviewing passes and fails to understand the critical success factors and measured parameters. Remembering the ethos – ‘’you cannot manage what you cannot measure’’ therefore what  you measure is the key and the various standards developed in subsea industry can assist here with methodologies and processes for control and definition.
Previous historical assessment must be made and definition of risk by some method such as Technology risk levels from API 17N and DNV A-203 should go some way to helping to identify exactly what is worth testing.
The use of standardised templates for collecting test and analysis data is critical to support the use of historical data.
Latest industry practice for documenting qualification work, these assist in threading the information used throughout FEMECA and FEMA and FTA work mentioned elsewhere in this thread –
Standardisation of these processes will allow real value adding work to be done and lessons to be included across the organisation based upon testing only the parameters of worth.
http://ballots.api.org/ecs/sc17/ballots/docs/API%20RP%2017Q%20Subsea%20Qualification_Ballot.pdf
http://www.itl.nist.gov/div898/handbook/ppc/section3/ppc333.htm

regards
tony morgan

Elvis.E.Osung's picture

The essence of subsea asset integrity management is to provide continuous knowledge of the working conditions of subsea systems. This knowledge is gotten by means of monitoring to ascertain or evaluate the present state of subsea system. Subsea integrity management is a continuous process which is aimed at observing any anomaly at the initial stage and overcoming the challenge to avert loss of production or disaster due to safety risk that could arise from the failure of subsea systems.  "Subsea systems such as jacket structure, riser-caissons, conductors, templates, risers, and umbilical’s experience highly dynamic loading due to environment combined with internal and external corrosion issues. Therefore, inspection alone cannot ensure the integrity of these structures. A suitable Integrity Management program should employ simulation, monitoring, mitigation, and testing in addition to regular inspection"  http://www.offshore-mag.com/articles/print/volume-69/issue-12/department...

chukwuemeka uzukwu's picture


Industry momentum in recent years has
been towards the implementation of risk-based integrity management (IM) programs
for entire subsea systems where subsea systems encompass all hardware from the
sand face downhole, to the top of the riser, inclusive of system interfaces.


As water depth increases and project
economics become more sensitive to downtime, there is increasing value for
operators to drive for reliability rather than just maintainability to achieve
availability and efficiency of subsea systems. While different approaches may
exist for specific safety-critical asset types such as pipelines and risers,
the use of separate methods may lead to inconsistencies when considering risk
across an entire field system. A holistic approach is required to develop and
implement a subsea integrity management program in the most effective manner. This
approach can be summarized based on the following:


1.     Gathering system data


2.     System supervision and grouping


3.     Risk assessment


4.     Risk-based recommendations


5.     Development of integrity management plan


6.     Implementation of remedial actions


The purpose of any integrity management
plan is to ensure safe operations, retaining technical integrity at minimal
cost throughout the asset life cycle. This holistic approach allows the
optimization of the capability of subsea systems and promotes continual
improvement.


http://www.ccop.or.th/download/PETRAD/PETRAD58_2011-01/Paper12_FarahJulieanaNasriHuang_PETRONASCarigali.pdf


http://www.2hoffshore.com/services/integrity-management


 


Kingsley ENEM's picture

Reliability and integrity management are correlated disciplines with similar definitions. Though, their practice is historically pretty distinct. However, there are thoughts to better integrate reliability and integrity management and several operators have combined subsea reliability and integrity into a single management practice. For example, a Failure Mode Effects Criticality Analysis (FMECA) can be used to provide information to enable operations teams to schedule inspection and maintenance for potential identified failures. Similarly, Reliability Availability Maintainability Analysis (RAM) analysis can be used to ascertain system weaknesses, to assess the possible benefit and optimise sparing and vessel.

Integrity management (IM) is the program of investigation/analysis during operation with typical integrity programs revolving around inspection management. The inspection management plan may be well suited for static equipment's/structures with good ease of access to conduct visual inspection, Cathodic Protection (CP) surveys, and Ultra Test (UT) testing. Though, subsea systems such as jacket structure, riser-caissons, conductors, templates, risers, and umbilicals experience extremely dynamic loading due to environment combined with internal and external corrosion problems. Hence, inspection only cannot safeguard the integrity of these structures. An appropriate IM program should employ simulation, monitoring, mitigation, and testing in addition to regular inspection.

Legislation, Class (if adopted) and operator procedure specifications determine a level of prescriptive requirements. However, most inspection, mitigation, and monitoring requirements are defined by severity, or risk level, to system components. A risk-based approach usually forms the basis for the IM program, as specified in several recommended codes of practice. IM does not interfere with the subsea systems performance but it implements measures to monitor the continuing deterioration of the component and predicts the possibility of the component failure.

The risk assessment should be conducted for each subsea component for all potential failure modes. The failure modes can be categorized in two main classes: age associated (e.g. corrosion of fatigue) or non-age associated (e.g. impact). The probability of each failure mode should be based on evaluation of the design, fabrication, and installation of the system, alongside with operational practice. The consequences should be evaluated based on personnel safety, environmental impact, reputation, and commercial loss. Probability and consequence are joined to obtain a risk ranking for each component

References:

1. http://www.astrimar.com/paper_aberdeen_june_2011.pdf

2. http://www.offshore-mag.com/articles/print/volume-69/issue-12/department...

 

Kingsley ENEM

t01sik12's picture

Reliability Management is an integral part of risk assessment. Reliability is concerned with the process of understanding how equipment can fail and how they can be designed, manufactured, installed, operated and maintained to minimise the risk of failure, analyse failures and redesign to eliminate failure modes. Reliability is the Probabilty that the Product can perform its intended function at its designed or specified time. From experience where I work a field Performance review  is done quarterly to identify overall trends and failure modes at the system, subsystem and component levels.  Reliability can also be said to be "Achieved VS Predicted". Reliability affects : Warranty cost, product availaibility, product safety, Total cost of owner ship, customer confidence and company risk and liability. The Word Reliability has to become a way of doing business in our day to day activity.

Tilak Suresh Kumar's picture

 A joint industry project . . . SURF IM . . . that aims to
enable an integrated approach to integrity management of subsea, umbilical,
riser and flowline (SURF) systems, and develop new best practice guidelines for
subsea integrity management is under way.

As the industry evolves
increasingly towards deepwater developments, exploited through remote and long
distance subsea tiebacks and subsea processing systems, production will become
increasingly reliant on SURF system integrity.

It is generally accepted that subsea inspection
technology lags behind capability for topside and onshore systems, and this is
especially true when it comes to fault-finding capability for evident and
incipient failures and non-destructive testing techniques
.

Ref: http://www.pandjenergy.co.uk/2012/08/predictive-approach-to-integrity-ma...

Tilak S. 

 

 

Oluwatadegbe Adesunloye Oyolola's picture

The Failure Modes and Effects Criticality Analysis (FMECA) is an extension of the Failure Modes and Effect Analysis (FMEA), focusing on the quantitative parameters for a criticality assigned to each probable failure mode, and is discussed below.

The FMECA is analytical tool, which implemented effectively is a powerful design engineering aid. The FMECA extensively used as part of the system engineering function. These industries have their own variance on how to and why conduct a FMEA, however their intent is the same. This list contains all the failure modes that would have a catastrophic effect on a system. The Failure Modes and Effect (Criticality) Analysis is termed as a bottoms up analysis. The FMEA is based on an qualitative approach, whilst the FMECA takes a Quantitative approach and is an extension of the FMEA, assign a criticality and probability of occurrence for each given failure mode.

Even though there are many different types and standards, most FMEAs/FMECAs consist of a common set
of procedures. In general, FMEA analysis is conducted by a cross-functional team at various stages of the design, development and manufacturing process and
typically consists of the following:


 


    Item/Process:
Identify the item or process that will be the subject of the analysis, including some investigation into the design and reliability characteristics. For FMEA analysis of a product or system, the analysis could be performed at
the system, subsystem, component or other level of the system configuration.


    Functions:
Identify the functions that the item or process is expected to perform.


   
Failures:

Identify the known and potential failures that could prevent or degrade the ability of the item/process to perform its designated functions.


    Failure Effects: Identify the known and potential effects that would result from the occurrence of each failure. It may be desirable to consider the effects at
the item level (Local Effects), at the next higher level assembly (Next Higher Level Effects) and/or at the system level (End Effects).


    Failure Causes: Identify the known and potential causes for each failure.


    Current Controls: Examine the control mechanisms that will be in place to eliminate or mitigate the likelihood that the potential failures will occur (e.g. end of line inspections, design reviews, etc.).


    Recommended Actions: Identify the corrective actions that need to be taken in order to eliminate or mitigate the risk and then follow up on the completion of those recommended actions.


    Prioritize Issues: Prioritize issues for corrective action according to a consistent standard that has been established by the organization. Risk Priority Number
(RPN) ratings and Criticality Analysis are common methods of prioritization and they are described in more detail later in this article.


    Other Details: Depending on the particular situation and on the analysis guidelines adopted by the organization, other details may be considered during the analysis, such as the operational mode when the failure occurs or the system’s intended mission.


 
Report
:
Generate a report of the analysis in the standard format that has been established by the organization. In addition, the report may include block diagrams and/or process flow diagrams to illustrate the item or process that is the subject of the analysis. If applicable, the criticality analysis may be included in a separate table and various plots/graphs can be included to display statistics on the modes and rankings.

Reference:

www.monition.com/failure-modes-effect-criticality-analysis.html

www.reliasoft.com/newsletter/3q2002/fmea.htm

www.weibull.com/basics/fmea.htm

www.itemsoft.com/fmeca.html

 

Adesunloye-Oyolola O.

MSc Oil and Gas Engineering

Abdulazeez Bello's picture

The use of ROV for Inspection has improve the Integrity and
reliability of equipment on the seabed. They serve as the eyes and hands of the
operators sitting more than 300m or more above sea water and can go up to 3 knot
current. Their ability to go round the installations and do jobs for longer
period is a plus. ROV’s are Important in the area of Reliability since lack of
Integrity causes accident on hazardous plant. They are used in identifying the
possible threats (Time Independent, dependent and stable) and alongside other
technologies: Time of flight diffraction (TOFD) and Phased array ultrasonic
testing (PAUT) to test weld defects in pipelines and other equipment on seabed.
They are also useful in subsea Interventions though quite expensive.


 

Subsea pipeline integrity
management means subsea pipelines always run in totally reliable operating
conditions which consist of three aspects. The first one is that from
perspective of substance and function, subsea pipelines are integral. Secondly,
they shall be under control all the time. The final is that subsea pipeline
operator has carried out measures and will continue to put effort to prevent
the occurrence of malfunction. The basic workflow for subsea pipeline integrity
management includes potential hazard recognition and preliminary risk analysis,
limit evaluation schedule and integrity management plan, integrity evaluation, trouble
management and repair, protection in advance and continuous assessment, report
and process management, etc. The basis for subsea pipeline integrity management
is integrity evaluation which covers feasibility evaluation, fault diagnosis
and disaster assessment, etc.


Ryan Grekowicz's picture

One of the issues that we run into in the Subsea Industry is that we are constantly developing new equipment and utilizing new materials in order to improve production or address the challenges of producing in deepwater.  The major vendors are developing new and improved technology, but the oil companies can't just take the vendors word that they are delivering a reliable piece of equipment, we need some method for evaluating the equipment to ensure that it is truly ready to be deployed offshore.

We commonly shoot for a piece of subsea equipment to have a design life of 20 years, and not require any maintenance since the most basic maintenance activity can cost millions of dollars in vessel and ROV time.

In my experience we have utilized an assessment process called the Technology Readiness Level Assessment.  It requires a piece of equipment to be evaluated and given a readiness level between "Unproven Technology" up to "Field Proven".  The process incorporates various levels of testing and risk assessments.  By no means is it a fool proof process, but at the end of the day, the project manager can review the assessment and have some level of comfort that they are installing a reliable system.

Felipe.Santana.Lima's picture

As Ryan I was also thinking about subsea integrity and reliability in the context of technology qualification.

According to DNV RP-A203, qualification of a new technology means “a confirmation by examination and provision of evidence that the new technology meets the specified requirements for the intended use. Hence, qualification is a documented set of activities to prove that the technology is fit for purpose”.

That having been said, when you consider a new technology qualified for subsea use for a lifetime of say 25 years, it means that you have sufficient documented evidence to sustain that the system will perform its intended function for the said lifetime; or (being more realistic) that the system reliability meets a minimum acceptance criteria (MTTF, MTBF, etc.) for the period of 25 years. DNV RP-A203 is very much focused on reliability and although it doesn’t use much explicitly the term “integrity” it is fair to say that it also puts a great deal of focus on that concept too.

The question is: how can you qualify a new subsea technology for a 25-year lifetime in a qualification programme which does not last more than 6-12 months? How can you predict the probability profile of time-dependent failure events?

In practice you can use as many risk assessment tools as you wish (HAZID, HAZOP, FMECA, etc.) but these will at best help identify what can go wrong (qualitatively) so you know what to watch out in the operational phase (RBI). But if the technology is truly new, the quantitative measures of reliability that you can get during the qualification process are not more than informed guestimates based on gut feeling. The more experienced the engineers assigning these estimated measures the more accurate they tend to be, true. But quantitative measures of system reliability assigned during the qualification process are still not more than projections, expectations, very different from historic reliability data. 

Leziga Bakor's picture

Subsea integrity management has to do with ensuring the wholeness of subsea structures so that throughout their service life they perform as desired. Several factors affect the performance of the subsea components and thus their integrity. If they lose their integrity it could lead to undesired consequences. Consequences like loose of money, health and safety issues, damage to environment, loss of life and reduction in value of assets. The integrity and reliability management of the subsea system ensures that it works according to its design and thus avoids these undesired consequences. The integrity management runs throughout the lifecycle of the subsea assets from the design stage to the decommissioning of the assets. One major reason why it is very important for the integrity of subsea components to be properly managed is that it is very difficult to carry out intervention on the subsea assets when they have been installed. It also cost very much to carry out these interventions. As a result, several integrity management processes are put in place to manage them.

t01sik12's picture

I earlier spoke on Reliability of Subsea equipment. One cant actually leave to talk about both words. Integrity simply means the quality of being reliable or truthworthy, regarded as honesty. Subsea Integrity is the honesty in the subsea structures to fulfill its design requirement and does not harm life , health or environment. Most subsea structures lose their integrity which could result to unplanned or undesired consequences. As a result of loss of integrity, there would be a negative impact on the environment, threat to human lives ( accident) , loss of assets and not been able to meet production target.

Integrity management plays a vital function in the life of the subsea assets. it is very essential that integrity is considered important in all Subsea assets because of the subsea Intervention operation which proves not to be an easy task and has a high cost.

 

Samuel Kanu

Msc Subsea Engineering

talal slim's picture

Felipe,

Thanks for your post on DNV-RP-A203 . It was really useful . Here I want to touch on another important recommended prcatice routinely used in the subsea industry to deal with reliabiltiy and that is API 17N : Recommended Practice for Subsea Production System Reliability and Technical Risk Management .

 API 17N aims to guide us on the reliability techniques application to all the phases of the subsea project when using both standard and non-standard equipment but API 17N uses some different approach to DNV-RP-203

DNV-RP-203 recommends that the identification of technical risk and in particular equipment failure mode be used as the basis for determining equipment qulification status, while API 17N uses the reliability categorisation of new technology method based on the Technology Readiness Level (TRL) concepts.

TRL is an assessment method used to underpin the qualification process and it indicates the extent to which an item is ready for use . TRL indicates how far the processes in a technology qualification programme for a particular technology have progressed.

API 17N categorises equipment into 8 TRL levels

TRL 0 : unproven concept (basic R&D , paper concept)

TRL 1:Proven Concept (proof of concept as a paper study or R&D experiments )

TRL 2: Validated Concept (experimental proof of concept using physical model tests )

TRL 3: Prototype Tested (system function , performance and reliability tested )

TRL 4: subsea system qualified by testing

TRL 5: subsea system tested

TRL 6:  subsea system installed and tested

TRL 7 : subsea system is field proven

Reference API 17N : RECOMMENDED PRACTICE FOR SUBSEA PRODUCTION SYSTEM RELIABILITY AND TECHNICAL RISK MANAGEMENT

Andrew Strachan's picture

A good Quality Assurance system is critical to providing reliability in the Subsea industry. Equipment can be designed and qualified for reliability but at the end of the day it must be built to specification every time to ensure design intent is met.

This often amounts to ensuring basic requirements have been captured for example material traceability and verification on critical items. At an assembly level small details such as flushing hydraulic systems properly, using correct grease and paint, ensuring fasteners are made up correctly and ensuring electrical continuity where required if not done properly can all cause systems to fail.

Joan.C.Isichei's picture

Subsea
Integrity management usually involves the use of  reliability or risk-based techniques. The reliability
based technique focuses on precautionary or alleviatve methods of maintaining various
subsea components. In contrast, the risk-based technique tries to establish Integrity
Management measures needed to handle high risk related system failures.

In my
opinion,  I believe the best way to resolve
the Subsea integrity management issue is by approaching it from a holistic
perspective. A holistic integrity management approach helps to “identifiy the
inspection, monitoring, analysis, procedural and preventative maintenance
measures advocated to manage the integrity of the subsea system in its’
entirety”[1].
Therefore, it can be safe to surmise that a holistic
approach puts reliability and risk-based IM techniques in equilibrium.

REFERENCE

1.   
Holistic Approach to Subsea Integrity
Management & Reliability and their Application to Greenfield and Brownfield
Projects
. Botto, A; Rees, J; Hull, M.

Omololu Oyebola's picture

All materials have been excited to an energy level during processing and want to get back to their normal state, subsea structures made from iron alloys such as steel and high alloy stainless steel will degrade after some years making integrity management key.

Why manage subsea integrity should first be answered, aside reliability of the system!!! 

The reasons are to

Comply with health and safety legislations

To protect the environment

Protect health and safety of workforce the public and fishing

Prevent or reduce unplanned costs and value of assets

High profile incidents in the oil and gas industry are primarily due to poor integrity management policy such the Alexander Kielland incident due to fatigue crack that grew in a brace member supporting the flotel, the Deep water horizon when investigated as to what caused the incidence was as result of integrity issues as how to drill in deep waters.

The life cycle of subsea asset is very important in operational phase as systems are exposed to failure at this stage. Integrity should not be taken important in the operational phase but at the design stage, material selection concept to ensure designing and selecting reliable and resistant components, installation procedures to reduce the risk of the asset to as low as it is reasonably practicable. 

Proper integrity helps reduce risk and accident from occurring and a statement by the Offshore Technology Conference shows its importance saying that “The achievement of high levels of reliability, integrity and maintainability (RIM) are now regarded as key requirements to be addressed throughout the whole systems life cycle for all subsea equipment” (Strutt, Emmet et al. 2012).

My take on this very good topic by Dr. Tan is that proper integrity and management regime be enforced on subsea and offshore installations.

Reference

(1) STRUTT, J.E., EMMET, L. and CLELAND, G., 2012. Reliability and Integrity Assurance of Subsea Technology using ASCE, Offshore Technology Conference, - 2012 2012.

(2) Key notes from the Industry Lecture on Subsea Integrity Management by Mark Wilson CNRI

William J. Wilson's picture

One element I would like to highlight regarding subsea integrity management is the use of Fault Tree Analysis (FTA), this is a very useful tool used in many sectors of engineering (I have firsthand knowledge of this in aeronautics).  Anyway, FTA is used to estimate and predict system reliability by systematic approach of identifying all possible failure modes of an item or system.  It is best suited to Front-end engineering design (FEED) so that the most effective design changes and performance enhancers can be implemented.  By implementing FTA early stages age would benefit the item throughout its life time.  Furthermore, FTA can be used post FEED to assess the unknown failure mechanisms which in turn would assist in the design of future subsea items.  Reliability can be improved through FTA.
William Wilson
MSc Subsea Engineering

William J. Wilson's picture

I mentioned above that FTA was a very useful tool.  Well it is but I failed to mention the limitations of FTA.  Firstly, the major limitation of FTA is it is not suitable to be used with sequential failure analysis.  Very similar to our studies where Probability of item A failing is or is not dependant on item B failing and the corresponding consequences of this event would be difficult to determine using FTA.  Secondly, complex systems with multiple items would be very difficult to analyse manually and only with accurate reliability data, quantitative analysis, first-rate computer programmes and appropriate levels of management would this mechanism for improving subsea integrity be successful.
William Wilson
MSc Subsea Engineering

talal slim's picture

 William ,

Thanks for touching on the FTA , I have been recently involved in applying FMECA/FTA on a project so I would like to talk a bit about this experience and the relationship between FMECA & FTA.

 Failure Mode, Effects and Criticality Analysis (FMECA) 
 The Operator (oil company ) specifies that the contractor shall perform a Failure Mode, Effects and Criticality Analysis (FMECA) on the various Units he is responsible for (mainly critical items regarding availability, immature technologies and new concept/design). FMECA is initiated as an integral part of the early design process (as soon as the concept is sufficiently detailed) and is periodically reviewed and updated to address any changes or deviations.

The objectives of FMECA is  to:

• Identify simple failures modes and mechanisms that may lead to a fearful event.
• Evaluate corresponding causes and potential consequences on reliability.
• Rank each failure according to a criticality category of failure effect and occurrence.
• Establish mitigation actions to suppress or control the critical risks (with appropriate measures such as design, qualification testing, additional testing, procurement, manufacturing, quality assurance, maintenance, installation …). 

FTA
The Operator (Oil Company ) specify that the contractor shall consolidate their inductive analysis (FMECA) by a deductive study (FTA), as a minimum on
identified fearful events concerning availability and safety.

The main objectives are to identify the critical path which contributes to the top event (qualitative approach)
and its probability of occurrence (quantitative approach).

The quantification of the different undesirable events shall be achieved through a failure tree-diagram, which
enables to get a model of the undesirable events and finally quantify their probability of occurrence . the probability target of failure on demand for the safety functions of the subsea production system was of the order of 5E-3.

Note: FMECA and FTA techniques are compatible methods of risk analysis (FMECA considers only single failures, while FTA considers combination of multiple failures).

talal slim's picture

Kingsley ,

In your post above you mentionned RAM analysis by saying : "Similarly, Reliability Availability Maintainability Analysis (RAM) analysis can be used to ascertain system weaknesses, to assess the possible benefit and optimise sparing and vessel" . I am not sure if RAM is used in other industries but it is one of the main methods used in the subsea industry in order to verify whether the overall subsea  system can be expected to meet its availability targets, as defined by the Operator (Oil Company).

The RAM model is usually  based on  the Monte Carlo simulation .

The following parameters are usually  considered into the RAM analysis:

• Equipment failures
• Redundancy and intervention constraints
• Preventive and Curative maintenance (spare parts, support vessels, repair priority ...)
• Operating policy
• Other parameters (production profile, preservation, emergency shut-downs ...).

The expected results from the RAM analysis is  presented in a final report, including but not limited to the following information :

• Availability results compared to initial target set forth by the Operator 
• Results of sensitivity studies,
• Main contributors to unavailability. 

Note that sensitivity analysis are  considered in order to evaluate the effect on production availability results, from
parameters such as:

• Alternative system configuration.
• Variation in failure rate for critical (or unknown/new) items.
• Repair data (intervention time, maintenance / sparing strategy).

RAM analysis process  include relevant personnel from the Operator and  Contractor , and is  updated after any significant evolution of the design.

Tony Morgan's picture

AS you mention RAM and FEMECA along With FTAs the failings of all of these are that they are generally independant of overall commercial value on their own. It is only when they are used in conjunction with life cycle costing review that the true value of their information presentation is shown.

Most commonly this takes the form in FEED stage where options / solutions are selected for designs or problems and these are directly compared for value over the required life time. The key benefit to this tool is that it factors in CAPEX, OPEX, RISKEX and RAMEX in order to arrive at a true cost based valuation of the decision.

Decision based management is the key to successful projects and this tool effectively combines the technical tools mentioned previously with the commercial aspects that are expected to justify decisions at the management table and in almost all cases is the preferred language of interest to the senior management unless safety or reputation is also at stake.

http://www.ntnu.no/ross/reports/lcc.pdf

OLD but illustrates the concept - http://www.standard.no/PageFiles/1138/O-CR-001r1.pdf

The latest standards for Life cycle costing is covered by ISO 15633 and In relation to reliability and integrity it is useful to look at below which gives outline differences in focus between reliability and integrity focussed efforts. Both require to be addressed and cosnidered in order to perform the life cycle costing excercise.
http://cmcgc.com/Media/Synch/300503/070-1-DEMO/default.htm

As with any of these tools good engineering judgement must be applied and if poor input information is used then poor results shall be obtained therefore critical review of the input data is required in order to ensure validity of the output of the costing review.

There may also be other mitigating or exceptional circumstances which dictate going against the evidenced solution and each project or decision must be taken in context as these are only tools to help with assessment of the complex issues they are not in themselves defining answers !

regards
tony morgan

Manuel Maldonado's picture

Reliability and integrity are two interrelated concepts or disciplines. Both of them aim at a similar goal by definition: to ensure subsea systems operate as intended with minimal risk of failure, not harm to personnel or environment and minimum downtime. The two of them have become very important to the oil companies operations and production strategies because they are linked to the main financial and business goals of the oil companies. "While the production systems are operating, wells are online, people are not under a risk of being injured and oil is kept inside the pipes, oil production can be delivered".

The two disciplines are also becoming even more important for companies developing subsea fields. It is mainly because of the costs of interventions for repairs and also because of the benefits of developing new reserves subsea which could result uneconomical if reliability becomes an issue or if the integrity of those facilities is affected and resulting in environmental catastrophes like the Macondo well in the Mexican golf.

They are liked concepts or disciplines because of a common goal (guarantee continuous production delivery under safety and environmentally friendly operations)  or because of their consequences associated to cost of repairs or financial losses. I would think that saying this in this way would sound crude but it could be a reality. This is a different approach of how this subject has been tackled in thorugh this forum.

Oil companies want to deliver a maximum and continuous production by doing a good management of opex and capex. They would not look at investment in reliability programmes (better materials, preventive maintenance, monitoring and inspection) if they would not see a benefit in reducing down time or cost of interventions especially in deep water or subsea facilities. They would not also look at investing in integrity programmes if they were not force to meet the compliance with regulations or standards or if they would not see the risk to their wealth when causing an accident or creating a big impact in the environment. I think that although it is not a good way to see the why, the reliability and integrity would still remain as concepts as they were before 1980s when not efforts were made to improve that and they were the areas for saving costs.

Now, looking at the benefits of investing in the reliability and integrity programmes, different approaches can be taken by the oil companies to achieve the best value in the longer run. All of this considered within the oil life cycle management which can be considered in two areas (engineering design and operations). Some companies could decide to invest more capital during design stage (better materials, more redundancy, and robust technology) , others companies would take the route to expend more money during the production life (inspection routines, continuous monitoring testing which required ROV and diving interventions) and some others would take both approaches.

Justice J. Owusu's picture

Integrity management system ensures
that equipment and facilities retain their integrity over a required period of
time. Thus implementing an integrity management process may ensure that the
facility functions well, even beyond its originally designed life – this is one
benefit that operators are considering. Integrity management system is more
required for subsea systems (assets below sea level) because inspection
intervals available are limited; defects cannot be noticed easily due to their
location and harsh operating environment. Generally, integrity management processes
are based on risk assessment, inspection and monitoring strategy and periodic
evaluation of the process. For more beneficial results, integrity management
should be carried out throughout the life of the assets.

Ref: Mark Wilson; An Industry Perspective on
Subsea Integrity Management. 2012 September. University of Aberdeen

Justice J. Owusu's picture

In search of knowledge

Justice J. Owusu's picture

I think, even if it is not
required by law, oil and gas field operators must implement integrity
management processes from appraisal through to decommissioning, due to some
benefits listed below:

1.       Assets
perform well with possible life extension or re-use

2.       Capture
and adopt lessons from past experience

3.       Implementing
integrity management from the design stage through the life of subsea assets
saves time and cost as compared with carrying out subsea interventions,
sometimes under very harsh conditions.

4.       Enables
an effective change management to be carried out – e.g. if the reservoir begins
to produce excess sand or water instead of oil, an integrity management system
will enable the operator update the understanding of the risk involved.

Abiaziem Davidson's picture

This is the management of a subsea system or an asset to ensure that is delivers the designed requirements throughout the designed lifecycle without the loss or harm of life, health or to the environment. Subsea integrity and reliability management of a system is considered from the system conception to the decommissioning phase of the project. The corrosion risk assessment is carried out and best option for integrity and reliability is selected with the inspection and maintenance procedure clearly stated out and followed up.

In the development of a system, more time and money is spent on the defining and understanding the risk involved and mitigation plan, designing and selecting reliable components for the system development and developing procedure for inspection and maintenance of the system. This high cost is appreciated because it is relatively low compared to the cost of subsea intervention operation.

Subsea integrity and reliability is carried out to ensure the following:
1. To comply with the lay down legislation
2. To protect the environment from pollution or any harm
3. To protect the health and safety of the personnel working within and around the system
4. To prevent or reduce unplanned cost resulting from sudden or unplanned failure of the system
5. To protect the value of the asset and investment of the stakeholder.

Reference
Wilson .M (2012), ‘An Industry Perspective on Subsea Integrity Management' CNR International.

Abiaziem D.U

Hani Shobaki's picture

Discussion Topic 8: Subsea integrity and reliability management
Looking at the Prudhoe Bay oil spill in 2006, caused by microbially induced corrosion, there are clear implications of the safety issues that can occur if proper integrity and reliability management is not used. By changing the method that the biocides were introduced into the pipelines, their effectiveness was significantly reduced, and in one year many of BP's pipeline were deemed unsafe for use. Before any changes were made to the system a careful analysis should have taken place to assess any negative effects the relocation of biocides would have on the system. If a risk was identified, mitigation factors should have been put in place to ensure adequate prevention of microbial corrosion. When trying to cut costs it is important to look not only at the short term savings by making a change to a system, but also the long term implications and unidentified risks involved.

 

 

1.BP. Prudhoe Bay Fact Sheet. Aug 2006, Prudhoe Bay: British Petroleum Exploration Inc.

2.BP. BP to Shutdown Prudhoe Bay Oil Field. 07 Aug 2006, Anchorage: British Petroleum Exploration Alaska. http://www.bp.com/genericarticle.do?categoryId=2012968&contentId=7020563 (accessed 9 Nov 2012)

Mostafa Tantawi's picture


Indeed Hani the place where Biocides is
injected should be greatly assessed before changing; this is a clear example
about the severe causes of bad integrity management. However I believe BP
didn't have a proper image of the pipeline state, which means that in order to
do any changes in your injected fluids it has to go through the cycle of risk
assessment and risk mitigation, which where I believed BP failed. The whole
state of the pipeline should have been assessed too, to see of you have any
tendency of bacterial corrosion or not, from my understanding SRB (which I
suspect are the reason to cause this failure) are bacteria that tend to grow
better in low temperature conditions, so they should have taken this into consideration.
I am sure the economic implications of the spill caused BP more money than
continuing Injecting the Biocides as before, not taking into consideration the
reputational implications.


Mostafa Tantawi
Masters Of Subsea Engineering, University of Aberdeen

Hani Shobaki's picture

Yes Mostafa, according to Upstream (2012), they were fined multiple times, including a recent $255m for lost Royalties. The total cost ended up being around £500m. It is unknown what amount they saved by relocating the injection system, however it would have had to be very high to offset the cost of the disaster.


Microbial corrosion can be difficult to predict, however if there is sulphur compounds and sulphate reducing bacteria its very likely that MIC will occur. Perhaps if BP had had a better smart pigging program in place they could have detected the corrosion before it had reached such high levels. That way they could have increased biocides in time, saving a lot of money, and preventing such a devastating disaster.

 

 

Baily, A. BP: Learning from Oil Spill Lesson. Petroleum News. Vol.11(20). 2006. http://www.petroleumnews.com/pntruncate/573947058.shtml (accessed 9 Nov 2012)

Upstream. BP to pay $255m for 2006 Prudhoe spill. 9 Nov 2012. http://www.upstreamonline.com/live/article1269507.ece (accessed 10 Nov 2012)

Mostafa Tantawi's picture

Indeed Hani, the pigging process is the fastest way to overcome the MIC threat, now days it is a must that pipelines should be designed for pigging, and also pigging is often considered as an annual or semi annual maintenance procedure. Again it all comes to identifying the threat and follow the right procedures to mitigate it. BP should have aquired the enough information about the bacterial activity in the pipeline, hence it was possible for them to overcome the bactiria build up by having a scheduled pigging procedure to remove the bacteria/debris/ wax in the pipeline, after the extensive cleaning procedure, an ILI (in-line inspection) tool-that could be Magnetic flux leakage or ultrasonic- should be used to assess the corrosion resulted from the presense of the bacteria, by comparing to previous results(from previous pigging), a clear understanding of the corrosion rate and wether it is in the acceptable range or not. BP failed to demonestrate a proper integrity management system.

Mostafa Tantawi
Masters Of Subsea Engineering, University of Aberdeen

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