1. ______________________________
1
Chartered Mechanical Engineer, Global Subsea Market Development Manager - HYDRATIGHT
2
Chartered Mechanical Engineer, Global Subsea Leader - HYDRATIGHT
IBP3018_15
EMERGENCY PIPELINE REPAIR SYSTEMS,
AGLOBAL OVERIVEW OF BEST PRACTICE
James A. Rowley1
, Paul A. Hughes 2
Copyright 2015, Brazilian Petroleum, Gas and Biofuels Institute - IBP
This Technical Paper was prepared for presentation at the Rio Pipeline Conference & Exposition 2015, held between September,
22-24, 2015, in Rio de Janeiro. This Technical Paper was selected for presentation by the Technical Committee of the event. The
material as it is presented, does not necessarily represent Brazilian Petroleum, Gas and Biofuels Institute’ opinion or that of its
Members or Representatives. Authors consent to the publication of this Technical Paper in the Rio Pipeline Conference &
Exposition 2015.
Abstract
An Emergency Pipeline Repair System (EPRS) is the result of the process of developing an emergency repair readiness
procedure and retaining the necessary tooling, equipment and services to cope with unplanned repairs, minimizing the
resultant damage to the environment and field operation. As oil and gas production extends into harsher and ever
deeper environments, new challenges are constantly emerging. These include technical issues such as pipeline material
selection, manufacture and installation, well fluid compositions, along with increasing pressures and temperatures and
other infield demands. Commercial issues also exist with regards to the scope of equipment supplied within the
insurance of an EPRS, and the contractual challenges of mobilization, storage and maintenance for the full life service
of the field. With over 30 year’s experience as a leading provider of EPRS coverage, we will explore these growing
commercial, technical and contractual trends within the industry. Pulling on recent case studies and projects, these
trends will be analyzed and a summary of best practices will be provided in the conclusion.
1. Introduction
EPRS has always been used as a type of insurance, protection against the risk of the unknown. By analyzing the value
of pipeline assets and factoring the probability of those pipelines being damaged, operators are able to quantify the risk
to their business. Each operator is responsible for calculating their own cost and probability of damage which is always
field specific and a function of a wide number of considerations including geography, production rates, age of asset and
plans for the future. The level of risk an operator is willing to accept is also specific to them.
When damage occurs to a pipeline, there are a wide number of repair options the Operator can pursue. These options
are dependent on the type of damage, location and the technical requirements of the pipeline system, but can be
summarized briefly as follows:
 Permanent or temporary
 Diver installed or remotely operated
 Welded repair: On deck/subsea/hyperbaric
 Connector repairs: Flange adaptor or pipe-to-pipe coupling
 Clamps repairs: Structural or non-structural
 Leak sealing: Injected epoxy or wrapping
Thirty years ago EPRS was either not considered or a “nice-to-have”, typically encompassing only long lead time
products in the most cost effective manner. As the age of subsea assets increase, the risk associated with those assets
also increase. This combined with much greater focus on mitigating production loss and lowering health, safety and
environmental (HSE) impact has driven the requirements of EPRS to be an essential strategy that is a core component
of ensuring future business growth.
The technology deployed within offshore oils and gas fields is also constantly developing, changing and growing. To
make the most of the available fields, subsea assets are required to operate with increased efficiency and at higher

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temperatures and pressures. The well fluid composition can also change over the life of field introducing issues such as
the presence of carbon dioxide (CO2) and hydrogen sulphide (H2S) which can cause severe corrosion problems in oil
and gas pipelines. These challenges have led to many Operators evaluating and deploying a variety of engineered
pipeline solutions, including corrosion resistant alloy (CRA) Clad and Lined Pipelines, Pipe-in-Pipe (PiP) systems,
Stainless Steel, Duplex and other exotic pipeline materials. To further magnify the challenges faced in planning for the
repair of these assets, Operators should also consider including risers (both Steel Catenary Risers (SCR) and Flexible
risers) as part of the subsea assets to be covered within an EPRS.
2. Damage
EPRS exists to mitigate risk of damage. So, to appreciate the value of EPRS, one must first appreciate the potential
damage that can occur. Section 3 will address Risk.
As part of the risk assessment of pipeline protection, the identification of hazards that can cause damage to pipelines
and risers is a primary step. Table 1 below is referenced from DNV-RP-F107: Risk Assessment of Pipeline Protection
and provides some typical hazards that can cause damage to risers, pipelines and umbilicals:
Table 1. DNV-RP-F107: Risk Assessment of Pipeline Protection
The main causes of failure of pipelines has been researched by the Institute of Petroleum, UKOOA and HSE in their
PARLOC 2001/1/ report which provides statistical information on incidents in the North Sea and the Gulf of Mexico.
At the time the report was issued, a total of 1069 carbon steel pipelines were in operation in the North Sea, with over
32,400km of pipeline in the Gulf of Mexico. Corrosion proved to be the most reported fault (27% North Sea, 40%
GoM). Between the period of 1971 and 2001 there were a total of 65 incidents which resulted in a leakage, the causes
of which are illustrated below:

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Figure 1. All reported incidents in percentage for a) North Sea, and b) the Gulf of Mexico (DNV-RP-F116)
More recently than the PARLOC report (2001) and following a series of anchor damage incidents to offshore subsea
pipelines, the regulator authorities (HSE, DfT, MCA and DECC) identified the need to give additional guidance.
Available standards (e.g. BS EN 14161, PD8010 Part 2, DNV-OS-F101) give limited guidance on protection against
anchor damage, so the Health and Safety Executive provided Guidelines for Pipeline Operators on Pipeline Anchor
Hazards (2009).
3. Understanding Risk
Risk assessments are essentially the estimation of the frequency of an incident occurring and an evaluation of the
consequences of that incident. DNV-RP-F107 Risk Assessment of Pipeline Protection once again provides clear
instruction on how this can be identified, captured and addressed:
Figure 2. Process Description of risk assessment (DNV-RP-F107)
EPRS is simply the management of risk through contingency planning. The manner in which the risk is identified and
evaluated is dependent on the field operator, but as a general rule can be illustrated as:
Probability (frequency) X Cost (consequence) = Risk Rating

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3.1. Probability (frequency)
The probability (frequency) of damage can be assessed considering the following factors:
Location: boarders and travel routes of the offshore asset can cross other industries/ infrastructures/ man-made
activities. For example, the significant fishing activities in the North Sea (yielding around 2.3million tons annually) can
cause damage to pipelines through snaring of fishing nets, dragged anchors and dropped object. The probability of
damage to the pipeline depends on the specific asset location with regards to the harbors, passage routes and fishing
zones. It is also worth noting that large export lines carrying well fluid can increase the temperature of the sea,
attracting fish. Fishing vessels can trawl these routes, significantly increasing the probability of damage occurring.
Environment: The weather and physical geography of the area is a huge consideration. The Atlantic hurricane season
runs from June to November having a huge impact on the Gulf of Mexico. Recent exploration into Arctic drilling (and
the challenges faced in other Northern climates like Russia, Norway etc) creates further risk of damage. Other
geographic challenges include tectonic plate movements (earthquakes) and water depths (pressures). Seabed conditions
(incline, density, currents) also need to be considered.
Asset design: The probability of damage to the subsea asset is dependent on the size of asset (length and diameter), the
age and the condition. The interfaces along the pipelines (flanges, valves, gaskets, subsea structures) also increase the
potential leak paths.
Well Fluid: As the well matures the fluid composition may change. Pressures, temperatures, CO2, H2S and any process
implemented to enable a greater yield from the field may push the operating limit of the existing pipelines.
3.2. Cost
The cost should damage to the asset occur, can include:
Lost production: A moderate export line could be producing in excess of $5m of oil per day to repair a pipeline takes
time. Even with all the equipment and vessels in place, the repair process can take up to 20days causing lost production.
It should be noted that the production is not “lost” in terms of oil being wasted, but it remains in the well, limiting value
produced within that quarter and annum. This will affect the Operators turnover, profit and share price.
Equipment: The repair of an asset can be conducted by a number of methods, but all carry capital expenditure and
operation costs in terms of materials, equipment and facilities. Ongoing storage and maintenance of this equipment is
also key to ensure continued fit-for-purpose.
Repair location: The location and geography has already been identified as affecting the probability of damage
occurring, but it also affects the cost of the repair. The availability and rates of suitable vessels, divers, ROV’s and
technical expertise must be considered, and potentially mitigated through EPRS. A suitable solution for one field may
not be the most cost effective for another.
3.3. Assessing Risk
Once the risk has been accurately assessed (based on the probability and cost of damage) the Operator can then make
an informed decision to what risk is deemed acceptable, and what mitigation can be implementing to reduce either the
probability or the cost should damage occur. In many ways, EPRS is a simply insurance policy against damage
occurring.
The level of cover of this insurance can be changes to meet the bespoke requirements of the operator. An EPRS might
include:
 Long Lead Items
 Ancillary items to enable installation
 Repair spools and flanges
 Spares
 Maintenance contract
 Service agreement with vessels/ divers/ installation contractors
 “Dry run” practices
Every addition to the EPRS reduces the potential risk and operational expenditure should damage occur, but increases
the capital expenditure of initiating the complete system.

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4. Technical challenges
As the demands of the industry have increased, the technology has developed to meet those demands.
4.1. Exotic materials and clad pipelines
As the requirement for production of oil and gas with higher concentrations of CO2 and H2S have increased, pipelines
have been developed with more exotic materials.
Pipeline manufacturers have created a number of duplex stainless steel pipe materials which mitigate corrosion risk.
Ordinary carbon steel grades (being an alloy of Iron), when exposed to oxygen and water will form an iron oxide (rust).
Given sufficient time, oxygen and water, any iron mass will eventually convert entirely to iron oxide and disintegrate.
Stainless steels differ from carbon steel by the amount of chromium present, which leads to chromium oxide being
produced instead of iron oxide. Chromium oxide is a passive substance that blocks oxygen diffusion into the steel
surface – a natural corrosion preventative.
However, although the duplex stainless steels provide excellent corrosion resistance and a very high mechanical
strength (UNS S31803 Duplex has a yield strength similar to an X65 carbon steel, with UNS 32750 super duplex
having similar to an X80 carbon steel) which can lead to reduced wall thicknesses and weights, the repair of these
pipelines create their own unique issues. Welding duplex can be very difficult and require very expensive weld
qualifications. Furthermore, a duplex pipeline cannot come into contact with carbon steel. High alloy stainless (duplex)
is an electro positive material. Carbon steel is a electro negative material. Therefore in an oxygenated environment in a
natural aqueous electrolyte, the duplex may create a cathode, and the carbon an anode, enabling bimetallic corrosion to
take place. To mitigate this from occurring, not only must any EPRS for duplex pipelines also be made of similar
material, but it must be machined, stored and maintained out of contact from other carbon steel products.
It has been a common process to weld clad flange termination with a nickel alloy to reduce the effects of corrosion.
Nickel alloys offer a wide range of corrosion resistance because like stainless steels, it can accommodate large amounts
of alloying elements - mainly chromium, molybdenum, and tungsten, however Nickel can accommodate these elements
in larger quantities than that of iron. Therefore, nickel-base alloys in general can be used in more severe environments
than the stainless steels.
Entire pipelines can now be clad with similar materials to enable the same corrosive resistance properties. In these
systems the well fluid only ever sees the Corrosion Resistant Alloy (CRA) cladding or lining of the pipe, preventing the
corrosion to the carbon steel. However, should damage occur that causes the pipe to rupture or the lining/welding to
fail, the resulting environment can cause permanent damage to the pipe. Traditional permanent repair methods could
also be rendered “temporary” as the integrity of the repair relies on a seal being made to the carbon steel element of the
pipeline, which would corrode when exposed to the well fluid through the ruptured cladding. The seal itself might be
resistant to corrosion, but if the interfacing wall thickness corrodes it will cause a loss of seal (whether it be seal stress
in a connector, or a welded seal).
The challenge of repairing a CRA Clad and Lined Pipeline has been addressed through two traditional methods being
(i) Mechanical Connectors; and (ii) Hyperbaric welding. An ongoing Joint Industry Project has developed, tested and
provided a proof of principle for a dual sealing mechanical connector with an internal graphite sealing system to
prevent the well fluid from bypassing the CRA cladding in the pipeline.
Figure 3. (left) Connector; and (right) Hyperbaric welding habitat

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Figure 4. Seal Housing for Clad Pipe Mechanical Connector
The challenges of hyperbaric welding have been investigated by a number of subsea contractors and track record exists
using a 625 alloy as the weld material through both the CRA lining and the carbon steel. This process does have some
inherent limitations with the performance of the weld and its anisotropic structure (difficult ultrasonic inspection due to
dissimilar materials), but these challenges can be mitigated if welding can be achieved with matching material
(deploying a buffer layer between the two materials)
Figure 5. Three layer weld buffer approach (Welding of CRA Clad Pipelines, O’Neill, Saipem)
4.2. Pipe-In-Pipe (PiP)
As the name suggests, the transported fluid is carried by an internal pipe, which lies within a larger external pipe. The
cavity between the pipe is then either insulated, or another fluid is heated and flushed through. The purpose is to ensure
the transported fluid remains at a temperature that will assist with flow assurance. PiP has been used extensively in
some regions and although provides good mechanical integrity and insulation, creates a major issue in regards to
pipeline repair as multiple repair conditions need to be addressed including (i) breech to outer pipeline only (insulation
loss); (ii) breech to inner pipeline only (transport fluid loss) or (iii) breech to both inner and outer pipelines. In these
situations the repair need include sealing to both the internal and external pipeline and structurally retaining the pipe to
remove any axial loads.
In 2013 The Angolan Deepwater Consortium commissioned a study into deepwater pipeline repair systems for PiP
repairs. Repair options where researched and identified, with a number of new concepts being presented. At the time of
this paper, no further knowledge regarding the progress of these concepts was available.

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Figure 6. Installation concept of PiP End Seal Connector, Pipe Connector and Spool piece
(Connector Subsea Solution, 2013)
5. Global Approaches to EPRS
In accommodating the wide number of challenges, factors and considerations that an EPRS must address, the industry
has responded with a number of approaches to EPRS, all of which are efficient and applicable within the previously
discussed constraints. An overview of these systems is provided.
5.1. Club Membership
Both the UK North Sea and the Gulf of Mexico regions benefit from being serviced from a relatively small
geographical area. There is a wide variety selection of installation contractors, vessels, support services and a high level
of technical expertise readily available. This enables an approach to EPRS whereby support contracts can be put in
place, with the emphasis on contracted response times. A number of EPRS systems exist whereby Operators can pay a
subscription fee that will give them access to long lead items should an emergency repair occur. The EPRS in these
cases are managed by a third party and not the Operator.
This low cap-ex approach deals with providing access to the long lead items only (materials/ flanges/ spools/
Mechanical Connectors) with the assumption and assurance that support vessels and installation contractors would be
available if needs be. If access to stock is required, then an additional charge is made for release of the equipment. With
Club membership, the priority of the repair assets goes to the Operator who “calls off” first. This means that given the
limit of the inventory, there is no guarantee that the products are available, only a reassurance that the stock is being
managed in a way to ensure that it would be highly unlikely that the equipment would not be available.
5.2. Fully build system
Many state owned operators prefer to manage the EPRS inventory themselves as this mitigates risk. The downside of
owning the EPRS is that all items must be supplied from the manufacturer in a fully built and tested state, ready for
deployment (unlike club membership where forged materials etc. could be stored separately at the manufactures site).
In purchasing the long lead items, the Operator then becomes responsible for the inspection, storage and maintenance
of these items over the life of the field (20-30years). As the Original Equipment Manufacturer (OEM) is the only
supplier capable of performing the maintenance to ensure the warranty of the goods, the management of the EPRS
becomes critical to ensure it is fit-for-purpose.
ONGC, the main Operator in India has invested heavily in EPRS tooling specifies astringent storage specifications that
include nitrogen filled pressure containers to mitigate this risk.

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Figure 7. 30” Mechanical Connector complete with Misalignment Flange,
being loaded into a pressure container for long term storage
A fully built system that is stored with the Operator benefits from a significantly reduced mobilization time. As none of
the assets are shared then the risk of any components not being available is completely mitigated and complete control
remains with the owner. A complete system has a higher capital expenditure cost and the responsibility of the system
being fit-for-purpose is solely with the operator. The actual operation to deploy and install the EPRS will be determined
when the repair is required based on the vessels and installation methods (frames, airbags, cranes) available.
5.3. Fully build system with installation
EPRS systems comprising long lead items (as described in 4.2) are common, but there is a growing trend to also
include the installation tooling required to instigate the repair.
Figure 8. Light weight diver operated installation frame
Operators who have previously invested heavily on the supply, storage and maintenance of mechanical connectors, are
now investigating the supply of subsea installation frames to handle, lift and align the connectors and pipe. Spool
pieces are also being stored as part of the EPRS, with any flanges and bolting systems required.
5.4. Fully Remote – small area with vessels
The majority if EPRS systems that exist are for deployment in diver depths, typically up to 120m water depth. EPRS
for deepwater pipelines do exist but are typically bespoke for the Operator’s requirements.
Statoil, A world leading operator for EPRS is based in Norway, where over 25 years they have invested in deepwater
and remote pipeline repair systems using both mechanical connectors and hyperbaric welding. Statoil is using different
repair methods for various pipe sizes and water depths, using diver assisted hyperbaric welding for shallow water
repair, and remote controlled systems for deep water pipelines; remote installed mechanical Morgrip connectors up to
30” and remote hyperbaric welding for larger diameter pipes. The Norway based EPRS system covers the North Sea

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region including Barents Sea and Baltic Sea, and are a complete suite of equipment for all required pipeline repair
operations currently limited to 1300 meter water depth.
Taking responsibility for the whole ERPS system, this operator has a mobilization window of only 21 days should
damage occur.
Figure 9. Remote Operated Connector Installation Frame (CIF)
with integrated pipe handling capability
5.5. Fully Remote – large area with vessels
Another world leading EPRS Operator in Brazil has two separate EPRS solutions for shallow and deepwater, both of
which are stored and maintained in-country. The EPRS systems have a more modular design. This means that more
equipment needs to be stored, but should damage occur then only the equipment necessary needs to be mobilized. A
further advantage is that the individual systems (i.e pipe lifting) can be mobilized for jobs that have nothing to do with
EPRS, but can be deployed for other work such as free-span correction. So although the cost of the EPRS is much
higher, the use and mobility of the equipment is a significant advantage.
Figure 10. Remote Operated lifting frames optimized to enable easy mobilization (containerized)
5.6. Fully Remote – large area without vessels
The growing trend for EPRS leads to logistical and technical challenges. Deepwater fields are being developed where
the infrastructure and technical expertise is limited. This leads to a restriction on vessels, divers, installation contractors
and other services required to support a pipeline repair.
Deepwater EPRS systems can now being developed with size, weight and mobility being a design parameter, enabling
mobilization based on standard 40ft containers. Mobile container lifting gantries also exist that can be tied in with these
systems to enable truly mobile solutions.

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Figure 11. Enerpac Traveling Lift (ETL) Container lifting system (ENERPAC, 2014)
6. Concluding Summary
EPRS is a vital component that must be recognized throughout the entire business and process of a modern oil and gas
industry. Good practice would be for each Operator to have a dedicated focus on EPRS with a responsibility to mitigate
risk identified within their subsea assets. The scope and requirements of this EPRS can no longer simply focus on long
lead items unless the support products, services and required components have also been considered and assessed as
part of a wider risk assessment.
The fundamental purpose of an EPRS is to enable a fast, safe and correct repair response to a pipelines failure.
Therefore, whatever EPRS is put in place must also be in a constant state of fit-for-purpose. This may lead the operator
to have a dedicated and focused team to ensure competent and trained staff are available. Framework agreements and
contracts with subcontractors, suppliers and installation specialists should also be considered.
To properly ensure fit-for-purpose, the operator, contractors and OEM’s need to have a greater focus on the long term
storage and maintenance of these systems, with a sensitivity to the environmental, political and geographical locations
where repairs may be required in the future.
Care must also be taken when optimizing an EPRS. Through Front End Engineering Design, many systems can be
efficiently optimized to reduce weight, mitigate technical risks at interface points while continuing to meet the demand
of the asset, however, an overly optimized solution may not be flexible enough to accommodate future field
development requirements. A balance must be struck with a view to the future.
The technical/operational solution available is directly proportional to the commercial backing the EPRS receives, so
although the wish for a well optimized, controlled and maintained solutions might be significant, given the current state
of the market, EPRS is typically the first victim of cost reduction. To change EPRS from a “Cost” to a “Value Add”,
the system and its components could be made available for other standard operations and maintenance. As with the
example in 5.5, many installation systems, components, tools and clamps could be used in regular operation planning,
while still enabling reduced response times should an emergency repair occur. Given that track record remains the
industries benchmark for reliability and confidence in the solution, it makes further sense that these systems are
deployed, used, tested and proven in regular operation.
7. Bibliography and key references
Recommended Practice DNV-RP-F116. Integrity Management of Submarine pipelines systems, October 2009
Recommended Practice DNV-RP-F107. Risk Assessment of pipeline Protection, October 2010
Health and Safety Executive, Guidelines for pipeline operators on pipeline anchor hazards, December 2009
LIM, G., MAJOR, j. The Challenges of Emergency Pipeline Repairs, December 2009
O’neill, S, Welding of CRA Clad Pipelines, p 3-5 February 2015
Schouten, Hassall, Sanaee, Everstein. Use of EPRS to defend against claims of loss of production income, February
2015