Fitness For Purpose

During the fabrication of a pipeline, recognised and proven quality control (or workmanship) limits will ensure that only innocuous defects remain in the pipeline at the start of its life. These control limits are somewhat arbitrary, but they have been proven over time. However, a pipeline will invariably contain larger defects at some stage during its life, and they will require an engineering assessment to determine whether or not to repair the pipeline. This assessment can be based on ‘fitness for purpose’ (see 4.3.3), i.e. a failure condition will not be reached during the operation life of the pipeline.

Engineers have always used fitness for purpose – in the early days an engineer’s intuition or direct experience could help when a defect was discovered in a structure, and there were many ‘rules of thumb’ developed. We are now better positioned in structural analysis, and we have many tools available that can help us progress from these early days. And remember that ‘rule of thumb’ was derived from a very old English law that stated that you could not beat your wife with anything wider than your thumb….

The fitness for purpose of a pipeline containing a defect may be determined by a variety of methods ranging from previous relevant experience, to model testing, to ‘engineering critical assessments’, where a defect is appraised analytically, taking into account its environment and loadings [Anon., 1999a; Anon., 2000]. It should be noted that fitness for purpose is not intended as a single substitute for good engineering judgement; it is an aid.

Generic FFP

There are various technical procedures available for assessing the significance of defects in a range of structures. These methods use fracture mechanics; for example, the British Standard BS 7910 [Anon., 1999a] contains detailed engineering critical assessment methods, and can be applied to defects in pipelines. Also, there is API 579 [Anon., 2000] which has similar methods, but with a bias towards their use in process plant.

Pipeline-Specific FFP

The above standards (API 579 and BS 7910) are generic; they can be conservative when applied to specific structures such as pipelines. Therefore, the pipeline industry has developed its own fitness for purpose methods over the past 35 years. However, it should be noted that they are usually based on experiments, with limited theoretical validation (i.e. ‘semi-empirical’). This means that the methods may become invalid or unreliable if they are applied outside these empirical limits.

The pipeline industry has used their fitness for purpose methods to produce generic guidelines for the assessment of defects in pipelines. These methods and guidelines are based on pioneering work at Battelle Memorial Institute in the USA on behalf of the Pipeline Research Council International [Anon., 1965; Maxey et al, 1972; Kiefner et al, 1973], with the more recent additions of ad hoc guidelines for the assessment of girth weld defects, mechanical damage and ductile fracture propagation produced by the European Pipeline Research Group [Re et al, 1993; Knauf & Hopkins, 1996; Bood et al, 1999].

‘Best practices’ in structural assessments of defects in pipelines are now emerging (e.g. Hopkins and Cosham, 1997; Cosham and Kirkwood; Cosham and Hopkins, 2001; Cosham and Hopkins, 2002), and a Joint Industry Project sponsored by 14 major oil and gas companies will produce a state-of-the-art Pipeline Defect Assessment Manual in 2002 [Cosham and Hopkins, 2001; Cosham and Hopkins, 2002].

Legal Note

It is important to note that in structural assessments of defective structures, FFP is defined as when a particular structure is considered to be adequate for its purpose, provided the conditions to reach failure are not reached (see BS 7910). This is a technical definition, but ‘fitness for purpose’ may have a legal and contractual meaning in certain countries.

For example, in the UK, a consultant engineer is expected to exercise ‘reasonable skill and care’ in his/her work; however, a contractor carrying out a construction has a fundamentally different obligation – he/she is obliged by law to warrant that the completed works will be fit for their intended purpose. This will be implied in his/her contract – it does not have to be stated explicitly.

Therefore, if a consultant gives a warranty (guarantee) for fitness for purpose (on the completed works) and they are not, he/she will be liable even if he/she has used all reasonable skill and care. The damages awarded following a breach of warranty are different from those of negligence:

1. Warranty – costs of making the works fit for purpose, i.e. the work has to be perfect.
2. Negligence – you pay for anything that could have reasonably been foreseeable, i.e. the work does not have to be perfect.

Engineers should check with their professional indemnity insurance – what is covered

as a company/professional? Usually, professionals/consultants are not covered for

warranties.

Reference

http://www.penspen.com/downloads/papers/documents/thestructuralintegrityofoilandgastransmissionpipelines.pdf

Pipeline Corrosion Resistance Alloy Material

Corrosion resistant alloys are mixtures of various metals such as stainless steel, chrome, nickel, iron, copper, cobalt, molybdenum, tungsten and/or titanium. Combined, these metals can resist corrosion more effectively than standard carbon steel pipe. 

The advantages of corrosion resistant alloys in the short term, corrosion resistant alloys protect your well against the damage caused by sour gas. In the long term, corrosion resistant alloys help you realize life-cycle cost advantages by eliminating the need for costly workovers.

Corroded tubulars can lead to lost production and nonproductive time (NPT) on your well. Downhole tools and completion components that corrode can fail, which then require workovers. While completing a sour gas well with carbon steel components may save money up front, the cost of replacing it with a workover will be much higher in the long run. By completing your well with corrosion resistant materials the first time, you can realize life-cycle cost advantages. 

Perhaps as few as one well out of a thousand causes corrosion, contain high levels of hydrogen sulfide (H2S), chlorides (Cl-) or carbon dioxide (CO2) [especially from secondary recovery methods like steam and CO2 injection]. Other reservoirs may contain very high pressure and high temperature (HPHT). These conditions corrode and weaken carbon steel tubulars. 

In weight-loss (general) corrosion, the sour gas uniformly corrodes the metal surface. When carbon dioxide dissolves in liquid, it creates an acid that can cause rapid weight-loss corrosion in carbon and martensitic stainless steels, even at relatively low temperatures. The martensitic or chrome grades provide resistance to CO2 alone. Chlorides and H2S increase the corrosivity of the solution. Duplex and austenitic stainless steels have higher resistance, while nickel alloys generally show complete resistance.

In pitting and crevice corrosion, metal loss is highly localized. Stainless steels are highly susceptible to this type of corrosion, especially from chloride ions. By adding chromium and molybdenum to nickel you can resist pitting and crevice corrosion.

Environment-induced cracking occurs when a tubing string is under high stress in a sour well. To prevent cracking, you must consider the depth of the well (which requires stronger, yet more brittle metal) and the concentration of sour gas.

In some sour environments, corrosion can be controlled by using inhibitors along with carbon steel tubulars. However, inhibitors involve continuing high cost and may be unreliable, especially at higher temperatures. Also, adding corrosion allowance to the tubing wall increases string weight and reduces interior dimensions. 

There are different kinds of corrosion resistant alloys. Each alloy’s precise composition enables it to resist a certain level of corrosion.CRA supplies: 

• Martensitic Stainless Steel (Chromes)
• Duplex Stainless Steel 
• Austenitic Alloy (Alloy 28)
• Nickel-Based Alloys 825, 925, 718, 945, G-3, 2550, 625 & 725 
• Alloy C276

These alloys meet or exceed ISO 13680 and ISO 15156 NACE MR0175 and API standards. The strength of corrosion resistant alloys enables new engineering possibilities and more robust tools without compromising the integrity of the design

Reference

http://www.cralloys.com/FAQs.html

Pipe-in-Pipe

This Section defines the design criteria that are specifically applied to pipe-in-pipe systems. Relevant failure modes for pipelines, are to be considered in the design of pipe-in-pipe systems. 

Strength Criteria 

The design of pipe-in-pipe systems is, in general, to follow the strength criteria. For high temperature/pressure systems, an equivalent strain criterion may be applied as: 

The maximum allowable accumulation of plastic strain is to be based on refined fracture calculations and is to be submitted for approval by the Bureau. The inner pipe burst capacity of the pipe-in-pipe system is determined based on the internal pressure, and local buckling capacity is evaluated based on the outer pipe subjected to the full external pressure. 

Global Buckling 

In terms of structural behavior, a pipe-in-pipe system may be categorized as being either compliant or non-compliant, depending on the method of load transfer between the inner and outer pipes. In compliant systems, the load transfer between the inner and outer pipes is continuous along the length of the pipeline, and no relative displacement occurs between the pipes, whereas in non-compliant systems, force transfer occurs at discrete locations. Due to effective axial force and the presence of out-of-straightness (vertically and horizontally) in the seabed profile, pipe-in-pipe systems are subjected to global buckling, namely, upheaval buckling and lateral buckling. In contrast to upheaval buckling, lateral buckling may be accepted if it does not result in unacceptable stresses and strains. In case global buckling may occur, a detailed finite element analysis is recommended to further investigate the buckling behavior.

Pipe-in-Pipe Appurtenances Design 

Design of pipe-in-pipe appurtenances is to be based on their functional and installation requirements: 

• Field joint design 
• Bulkhead design 
• Spacers 
• Water stops/intermediate bulkheads to prevent water intrusion at the field joints 
• Insulation

Reference

https://www.eagle.org/eagleExternalPortalWEB/ShowProperty/BEA%20Repository/Rules&Guides/Current/64_SubseaPipelineSystems/Pub64_PipelineGuideMar08

Pipeline Ending Manifold (PLEM)

Remote operated sub-sea valves are often integrated into a Pipeline End Manifold (PLEM) to facilitate the (off)-loading. The operation and control system designof these actuated valves is one of the expertise.

Normally the sub-sea valves are hydraulic operated. The Hydraulic Power Unit is either located within the buoy or located sub-sea pending the project requirements. For the Actuated Valves, can be of assistance with both Valve Automation and Valve Controls. In order to integrate the above two described end-elements we provide the interfaces as well: Umbilical, Topsides- and Sub-sea Termination.

Reference

http://www.realbase.com.my/index.php?option=com_content&view=article&id=43&Itemid=53

Thermal Expansion On Pipeline

Materials expand when heated and contract when cooled. Pipes are not immune to these laws of nature, so they will also expand and contract with varying temperature.

This article will introduce the basics of stresses and anchor loads induced by thermal expansion. To stick to the basics, a straight piece of restrained pipe will serve as the example. We will also look at some available options to reduce the pipe stresses and anchor loads.

Stresses Induced by Thermal Expansion-The Basics

We will start with some definitions of commonly used flexibility terms. Stress is defined as force per unit area in a material:

S = F/A (Equation 1)

S = Stress (psi-can be negative or positive)

F = Force (lb_f-can be negative or positive)

A = Area (square inches)

Strain is defined as a percentage or ratio of a change of length divided by the original length:

ε = ΔL/L_o (Equation 2)

ε = Strain (inch/inch-can be negative or positive)

ΔL = Change in length (inches-can be negative or positive)

L_o = Starting length (inches)

Stress and strain are related by Hooke's Law:

S = Eε (Equation 3)

S = Stress (psi)

E = Young's Modulus (psi)

ε = Strain (in/in)

Piping materials exhibit nearly linear expansion and contraction with temperature. The rate of thermal expansion and contraction is characterized by the coefficient of thermal expansion, a, and has units of in/in-°F, or strain per degree Fahrenheit. The change in dimensions of an object is then:

ε = a (T₂-T₁) (Equation 4)

ε = strain (in/in)

a = Coefficient of thermal expansion (in/in-°F)

T₂ = End temperature (°F)

T₁ = Starting temperature (°F)

If the object is a straight bar or pipe, the more familiar form of this equation is:

ΔL = aL_o(T₂-T₁) (Equation 5)

ΔL = Change in length (in)

L_o = Initial length of pipe (in)

Consider a 6 in diameter steel (ASTM A53) pipe, 100 ft long, anchored at one end. The pipe is empty, and the inside is at atmospheric pressure. The temperature is increased to 200 deg F above ambient. The expansion of the pipe from equation (2) is:

a = 6.33 x 10^-6 in/in-°F

L_o = 1,200 in

T₂ = 270 deg F

T₁ = 70 deg F

ΔL = (6.33 x1 0^-6 in/in-°F)(1,200 in)(270°F-70°F)

= 1.52 in

If the pipe is installed at an ambient temperature of 70 deg F, and the temperature of the pipe increases to 270 deg F, we can expect about 1.5 in of expansion in the 100 ft unanchored run. Assuming the pipe is properly supported along its length, the stresses will remain well below the yield point of the steel.

If the pipe is now anchored at both ends and subjected to the same conditions, the stresses in the pipe will significantly increase. The anchors will prevent the pipe from expanding during the temperature rise. The result will likely be failed anchors, a buckled pipe or both.

 

Figure 1. The anchor forces in a 6 in. pipe undergoing thermal expansion

The pipe is in static equilibrium, but the only forces acting on it are the pipe anchors (static indeterminacy). The material properties can tell us how much force and stress will build in the pipe. The reaction force of the anchor must equal the amount of force needed to contract the pipe by 1.5 in (the amount of thermal expansion).

Substituting equations 1 and 4 into equation 3, stress is related to thermal strain by:

F/A = Ea (T₂-T₁) (Equation 6)

To solve for the force in the anchors, equation 6 can be rearranged as:

F = AEa (T₂-T₁) (Equation 6)

Notice that the initial length and change in length do not matter in calculating the stresses and forces. For our 6 in diameter, 100 ft pipe restrained by the anchors:

A = 5.581 in²

E = 27.5 x 10⁶ lb_f/in²

a = 6.33 x 10^-6 in/in-°F

T₂ = 270 deg F

T₁ = 70 deg F

The stress along the longitudinal axis of the pipe is then:

S = Ea (T₂-T₁)

= (27.5 x 10⁶ lb_f/in²)(6.33 x 10^-6 in/in-°F)(270°F-70°F)

= 194,315 lb_f/5.581 in²

= 34,815 psi

The force in the anchors is:

F = stress x pipe area

F = (5.581 in²)(34,815 lb_f/in²)

= 194,315 lb_f (anchor load)

If the pipe has a 2 in diameter, the area is 1.075 in², the reaction force is 37,410 lb_f and the resulting axial stress would be the same, 34,815 psi. The stress in this simple case only depends on the material properties and the temperature change; however, the anchor loads are also dependent on the pipe section dimensions.

 

Table 1. Comparison of the anchor forces for different pipe dieameters (straight pipe only)

A rigid connection to a pump or other piece of equipment behaves like an anchor-to a point. The Hydraulic Institute and API publish standards for allowable pump nozzle loads, and manufacturers of other equipment will have limits on connector loads. It should now be apparent that thermal expansion in piping systems must be addressed during the design of any system subjected to temperature changes.

Relieve the Stress

Now that we have an idea of the magnitude of the stresses and anchor loads in a pipe system, there are several ways to help the situation. The simplest method is to take advantage of the pipe's natural flexibility. If this is not practical, consider pipe expansion joints.

Pipe Flexibility

Pipes bend, even under their own weight. The longer the pipe, the easier it is to bend. If a pipe is bent within its elastic limit (no permanent deformation), it will behave like a spring and return to its original shape after the load is removed. If the elbows and anchors on a pipe system are arranged to allow movement, the forces will be much less than a straight run. Consider Figure 2 with an empty 6 in pipe.

 

Figure 2. Arrangement of empty 6 in. pipe and three anchors, and the resulting anchor loads

(dead weight not included-the forces shown are due to expansion only)

Figure 3. Arrangement of empty 6 in. pipe and two anchors, and the resulting anchor loads

(dead weight not included)

The anchor loads and stresses are much less than in the straight pipe case,but there are tradeoffs. The alternate layout introduces moment (torque) loads on the anchors. The pipes also move 1.5 in, which may not be acceptable for a given system. Geometry can affect this arrangement-if one leg is shorter, the forces and moments will be higher. Calculating the stresses and anchor loads without a computer is also a challenge. Pipe flexibility calculations were significant research topics in the early 20^th century, and several papers were devoted to the subject before pipe stress analysis software became widely available.

Expansion Joints

The geometry of the pipe system will usually determine the anchor loads; however, not every piping arrangement will permit the pipe to naturally flex. A confined space or tunnel is an example. In cases like these, pipe expansion joints are necessary. Expansion joints may employ bellows, hose and braid, ball joints, flexible couplings or sliding mechanisms. All have their unique properties that are appropriate for a given system.

For example, we will consider the case of installing a bellows expansion joint in our 6 in pipe run. If we now consider the pipe is running full, insulated and is under a pressure of 150 psi, the anchor loads are calculated as:

Initial Temperature = 70 deg F

Operating Temperature = 270 deg F

Bellows Effective Area = 40 in² (from manufacturer's data-this is the area calculated from the average diameter of the bellows convolutions)

Test Pressure = 150 psi

 

Figure 4. Belows expansion joint

The anchor load is then the sum of the pressure thrust, the spring force and the friction forces of the pipe guides. For this example:

Bellows pressure thrust = 150 psi x 40 in²

= 6,000 lb

Bellows spring force = Calculated movement (1.5 in) x spring rate (555 lb/in-from manufacturer)

= 832.5 lb

Friction force = Coefficient of friction (assumed at 0.3) x weight of full pipe and insulation (36.5 lb/ft x 100 ft)

= 1,095 lb

Total Anchor Load = 6,000 + 832.5 + 1,095

= 7,927.5 lb

This is still a substantial anchor load, but much less than a pipe without an expansion joint. If the pressures and temperatures permit, a hose and braid expansion joint may be used. The anchor loads will be substantially less in this case.

Figure 5. Flexible loop expansion joint

The anchor loads imposed by a flexible loop expansion joint are simply the movement multiplied by the spring rate of the joint. Using the previous example, the anchor load is:

Anchor load = Axial spring rate (60 lb/in-from manufacturer) x 1.5 in movement

= 90 lb

As in the pipe flexibility example, the dead weights of the pipe, insulation and fluid are not included in the anchor loads. Only the forces imposed by the expansion joints are shown.

Conclusion

It is important to remember that only two examples of expansion joints are presented here. It would be well worth the time and effort to become familiar with the advantages and limitations of other expansion joints available.

Temperature changes will impose stresses on pipes. There is no way around it, but the effects of thermal expansion can be accommodated by careful arrangement of anchors and the proper choice of expansion joints.

Author Bio: 

Marty Rogin, P.E. is with The Metraflex Company, 2323 W. Hubbard St., Chicago, IL 60612, 312-738-3800.

Reference

http://www.pump-zone.com/topics/piping/basics-pipe-thermal-expansion

Upheaval Buckling

Pipelines in service are often subject to high compressive axial forces. These forces are due to temperature and pressure induced axial expansion, which is resisted by the friction force generated between the pipe and the seabed. For upheaval buckling to occur, the pipeline must first have an initial imperfection. Imperfections are typically due to the pipeline being laid over a boulder or due to irregularities in the seabed profile.

The object of the Upheaval Buckling (UPBK) module is to carry out a simplified upheaval buckling analysis based on idealised pipeline imperfections. The UPBK module is suited to the conceptual design stage in order to determine whether upheaval buckling problems exist for a given pipeline.

The UPBK module is used to:

Determine whether the pipeline is susceptible to upheaval buckling;

Evaluate the required height of backfill to prevent upheaval buckling.

Pipeline buckling is very sensitive to the size and shape of the initial imperfection. Small diameter pipelines are particularly susceptible to upheaval buckling problems for the following reasons:

The Pipeline is trenched for protection, therefore preventing lateral movement;

Submerged weights are low since concrete is often necessary for stability;

The contents temperatures are high and Pipeline flexibility is high.

The UPBK module enables the engineer to quickly and easily carry out upheaval buckling calculation. This in turn allows flexibility in conceptual design and assessment of the pipeline for a range of operational and environmental conditions.

Reference

http://www.penspen.com/Services/Software/Modules/Pages/UPBK.aspx

Underwater Welding By Diver

While welding repairs or hot tapping onshore pipelines is a common occurrence, welding repairs on subsea pipelines is most often never even considered. However, the risks involved with welding subsea in-service pipelines underwater is present and needs to be managed by ensuring that, when conducted welding is performed in a reproducible and consistent manner.

The fact that electric arc technology could operate underwater has been known for over a 100 years. The first ever underwater welding was carried out by British Admiralty Dockyard for sealing leaking ship rivets below the water line in the early 1900s and the specific waterproof electrodes and the methods to use underwater were developed in Holland by ‘Van der Willingen’ in 1946.

Increasing the underwater welding practice

In recent years, the number of offshore structures, pipelines, and platforms being installed in deeper waters has increased. Some of these pipelines and structures will experience failures. Any repair for these on location will require the use of underwater welding.

When confronted with the issue of underwater welding, we often question: “Why should we consider underwater welding in the first place?” The immediate answer is “Why not?”

It's true; it is not a commonly-used technique and it does require meticulous planning, availability of highly-skilled tradesmen and tenacity to be successful. Even then, it is still a viable technique.

If the issues are analysed, there is no valid reason not to consider underwater welding, especially if production losses due to outage for repairs is punitive. Sunsea welding generally needs specialised welding knowledge combined with diving skills, which is more demanding than run-of-the-mill commercial divers can offer. Subsea welding covers areas of repairing pipelines, offshore oil platforms and ships.

Subsea welding also reduces the cost for the company by directly carrying out the welding work on location, saving time lost in production to the company.

Furthermore, because of the offshore exploration, drilling, and recovery of gas and oil in deeper waters today, it is necessary to have the capability to repair pipelines and the portion of drill rigs and production platforms which are deep underwater.

Risks and precautions

Welding underwater can be a dangerous profession if precautions aren't taken. The main risks are electric shock and the possibility of producing in the arc mixtures of hydrogen and oxygen in pockets, which might set off an explosion. The other common danger is breathing nitrogen in the air mix, which is absorbed into the blood but not metabolised by the body at depths under pressure. This could turn into bubbles on ascent and paralyse the diver. Curiously, the risk of drowning is not considered in commercial diving because that is the first hurdle to overcome in this profession.

The quantity of dives, dive repetitiveness, depth of the operations, time spent underwater and the exhausting nature of a specific task increase these risks significantly. Appropriate safety measures are provided to the diver via emergency air or gas supply, stand-by divers and decompression chambers. The diving-related health and safety procedures are managed by strict governing guidelines and work procedures.

When subsea welding is completed, both the welder and the structures being welded are at risk. The welder has to be very careful to avoid receiving an electric shock. For this, adequate precaution is taken by insulating the welder and limiting the voltage of welding sets. Continuous control of hydrogen and oxygen build-up is managed by removal and kept away from the arc to minimise any potential explosion.

Lastly, the welder’s time under water is controlled by using saturation diving chambers and regular rest periods in between. Inspection of an underwater weld is very difficult and complicated when compared to surface welding, but as it is the only controlling process of the quality of the weld, it is always done. The weld is inspected very carefully to confirm that no defects remain.

There are many underwater welding schools located in different parts of the world, including Australia, to train commercial divers. Historically, underwater welding was restricted to salvage operations and emergency repair work with limited depths of less than 9 m.

Wet welding – the way to go

There are two well-developed major categories of underwater welding process: one is welding in a wet environment; the other is welding in a dry environment.

Working underwater to weld serves to provide a number of benefits. Firstly, there is no need to pull the structure out from under water to perform work. In addition, many structures like oil rigs and ship hulls may become damaged at sea, necessitating the need for immediate work below the surface.

Because of the poor quality and difficulty in the process of welding underwater in the past, welding in the wet environment was used primarily for emergency repairs in shallow water. For example, to weld a patch for short duration until a complete repair could be performed in dry docks. With more experience and the advent of special welding rods and the persistence of some ambitious individuals and companies improved results were achieved, which has made wet welding a common occurrence.

Today’s underwater arc welding is accomplished in much the same manner as ordinary arc welding the only variations being that the electrode holder and cable is well-insulated to eliminate any possible current leakage and electrolysis of the surrounding water and the coated water-proof electrodes are used so that the electrodes do not get wet.

The most commonly used wet welding technique is shielded metal arc welding, informally known as stick welding. The main differences in wet welding equipment versus onshore welding equipment is that wet welding uses DC current only.

AC is not used as it can electrocute the diver and it is difficult to maintain a welding arc underwater with AC. The inclusion of a single or dual circuit breaker switch and the use of double-insulated cables protect the diver from electrocution. The power source should be a direct current machine rated at 300 or 400 amperes. Motor generator welding machines are most suitable for underwater welding.

Typical pipeline repair methods

Typical repair methods, as described in DNV RP F113, are to use fittings for repairs and tie-in of submarine pipelines.

These fittings include: couplings, clamps, T-branch connections and isolation plugs. Mechanical means are used to connect fittings such as sleeves/couplings and T-branches to the pipeline and welding subsequently used to make the repair permanent.

The section on the strength of the mechanical attachments is also applicable to pipeline recovery tools. Couplings connect pipes by direct attachment to the pipe walls via mechanical means and welded. Flange joins pipes via thick, machined pieces of additional material that is welded to the pipe ends prior to installation. Clamps are fitted externally to the pipeline to prevent leaks or add strength. Hot-tap T-branch connections are fitted externally to the pipeline assembly even during operation. A pressurised pipeline is machined open to allow fluid flow through the branch. Pipeline isolation plugs or smart plugs are pumped with the pipeline fluid to the repair site and then activated to form an isolating barrier that can resist differential pressure.

The pipe itself represents the key member of the repair assembly with consequential limitations such as, but not limited to, pipe wall strength, surface irregularities, and deviations in shape. Fittings for sub-sea repair must be installed with caution to reduce the likelihood of damage. Coupling strength should be sufficient in resisting stresses from all relevant loads, within a factor of safety as defined in the standard.

Avoiding pipeline damage

Pipeline damage after installation may be caused by internal and external corrosion, hydrogen-induced stress cracking, unstable seabed conditions, anchors, and dropped objects from the surface.

The risk of damage depends on the intensity of surface activities such as ship transport and offshore operations, depth, seabed conditions and the design of the pipeline itself. The extent of possible damage will vary from insignificant to a fully buckled or parted pipeline. Consequently, the repair and repair preparedness strategy depends on this.

The following steps have to be taken to select an appropriate repair method:
• Detailed selection criteria – this can be location type and strength requirement of sleeve, sleeve design and fabrication mechanical attachment requirements, handling requirements; and,
• A pipeline repair procedure manual.

This manual should include:
• Avoiding burn-through, factors affecting burn through such as wall thickness, heat input, and operational parameters such as pressure, temperature and flow characteristics;
• Prevention of hydrogen cracking concerns factors;
• Selecting an appropriate procedure – welding procedure options, predicting required heat input, inter-pass temperatures, pre-heating and maintaining;
• Proper electrode handling, welding sequence, and control of heat-input level;
• Welder/procedure qualification;
• Welder training;
• Code and regulatory requirements (changes to API 1104);
• Code requirements for weld deposition repair; and,
• Inspection and testing.

Final thoughts

My experience has shown that defects found in sub-sea pipelines can be permanently repaired by using mechanical intervention and underwater welding technology more safely, quickly and economically than any alternative technique. However, significant amounts of time and resources are still being applied to test and research programs to provide proven solutions for new repair applications. These will in turn provide the worldwide pipeline community with the correct answers and operational security required in the future.

Reference

http://pipeliner.com.au/news/application_of_underwater_welding_processes_for_subsea_pipelines/063794/