PIPELINE SYSTEMS 

The most popular measure to prevent a pipeline from corrosion is the use of inhibitors which form a protective film on the inner surface of the pipe. It is necessary to continuously throw in the proper inhibitor in the proper amount. Mishandling of inhibitors may cause upset of sweetening units or dehydrators.

Wall shear stress is a main parameter limiting the application of corrosion inhibitors. The maximum acceptable wall shear stress and, thus, maximum flow rate, depends on the inhibitor used and the geometry. The maximum acceptable flow rate will be higher in a smooth section than in flow restriction. Today’s green (environmentally friendly) inhibitors generally have lower film strength than the more toxic ones which may restrict application of C-Mn pipelines.

Pipelines carrying wet gas with condensed water are generally difficult to corrosion protect due to low pH of the unbuffered water. Research on the influence of pH on corrosivity has shown that the corrosivity is decreased by increasing the pH to above 6 by using such as bicarbonate. By doing this the general corrosion rate became lower, but the steel suffered from Pitting corrosion. Another disadvantage by using buffers is that the efficiency of the pH stabiliser to prevent corrosion is reduced below 50°C. Application of buffers alone is thus not recommended. Combination of moderate buffering and corrosion inhibitors seems on the other hand to be very effective. Internal corrosion control of wet gas pipelines with this method can extend the application limits of C-Mn steel pipelines. It must, however, be born in mind that buffers cannot be used in pipelines with formation waters since they can lead to scaling deposition.

Plastic coated pipes are widely used. Their coated surface is soft and must be carefully handled, and welding of pipe joints is especially difficult. Plastic coated pipes have an additional problem of durability because of loss due to abrasion by rapid flow velocity.

One of the main advantages of the flexible lines is the ability to recover and relay used flexible lines in new projects. The used lines are recovered from the sea bottom, transported to onshore base and submitted to this procedure to assure a safe and efficient utilisation:

The cost/benefit relation of this procedure is very impressive. The main reason for this is low installation costs. In order to compare the life costs of flexible and rigid pipelines it must be possible to carry out lifetime prediction for rigid as well as flexible pipelines. Presently the knowledge on lifetime prediction for flexible pipes is insufficient.

The pressure and tensile armour are encapsulated between an outer and an inner polymer barrier, and one may believe that the armour wires remain unaffected by both the sea water and the fluid carried in the pipe as long as the polymer barriers are intact. Polymers are; however, open to diffusion of gases such as CH_4, CO₂, H₂S and water vapour. Diffusion of water and corrosive gases into the annulus means that the armour wires are exposed to a corrosive environment. It is well known that the fatigue properties of metallic materials become poorer in corrosive environments. Fatigue testing of wires in corrosive CO₂/water environments has clearly shown the number of cycles to failure is significantly reduced in the corrosive environment compared to non-corrosive conditions. Lifetime estimation of flexible pipes should therefore include the effect of corrosion fatigue. It may be necessary to design flexible pipes in such a way that this failure mechanism is avoided.

Ageing properties of polymers for flexible pipes are also extensively investigated. Two years testing of PA-11, PVDF and PEX at 400 bar and 90°C in methane/oil/water show that PA-11 exposed to water become brittle, while PVDF and PEX are nearly unaffected. Polymers such as PA-11 and PVDF contain 12-15% plasticiser. During service the plasticiser will leak out and the polymer will shrink. PEX, on the other hand, will swell. The consequences of this also have to be investigated.

Duplex stainless steel has been used successfully for completion of highly corrosive wells. The corrosion resistance and mechanical properties make it attractive for highly corrosive pipelines. The advantages of using corrosion resistant alloy instead of C-Mn steel are that corrosion monitoring, intelligent pigging and uncertainties connected to inhibition are avoided and the risk for leakage and oil spill is reduced. The wall thickness can be reduced since the tensile strength is higher than C-Mn steel, and no corrosion allowance is required. Stainless steel is the most economical and effective solution against general corrosion and thus is widely used. In the use of stainless steel, care must be taken as to weldability, stress corrosion cracking (SCC), and the precipitation of chromium carbide which causes intergranular corrosion called ‘’weld decay’’. The biggest problem in the use of the corrosion resistant alloys such as brass, bronze, stainless steel, Monel, Titanium, etc., is high cost as they contain energy consuming such as Cu, Cr, Ni and Titanium.

The common factors which play a role in determining the particular economic benefit of using duplex stainless steels are listed below:

Clad steel pipe is also being tried as a possible solution to the above economic problem. This is a reliable and effective measure both in corrosion resistance and strength. There are several methods to clad materials, such as hot-roll, over-lay welding, explosion, etc., but all these methods require special costly techniques especially in the preparation of joined surfaces, and it is difficult to obtain a completely bonded surface. Further, the tensile residual stress in the clad layer which is generated in the cladding process may be a cause of stress corrosion cracking.

A key advantage of the bundle concept is the ability to use very effective (low k-value), low cost insulation materials in the annulus of the bundle. Another advantage is the ability to incorporate subsea manifold or even a subsea template in a towhead structure. The incentive is to reduce installation requirements and costs for subsea installation and tie-ins.

The bottom-tow configuration requires the casing be pressurised in order to withstand external hydrostatic collapse, and to allow the use of open-cell polyurethane foam insulation. As design water depth increases, up to several pressurisation stages are required during the tow to site to avoid burst or collapse during tow. Therefore, the maximum bundle length is limited, necessitating mid-line tie-ins of bundle segments. Each such segment must be optionally designed for its appropriate depth range.

The leading technical issues for towed bundles in deepwater concern 1) the need for high D/t casings, which lead to low safety factors against burst and collapse, 2) the lack of experience with mid-line tie-ins, 3) the needs for analysis tools and methods to predict bundle thermal performance, and 4) the need to evaluate bundle damage consequences.

If a hydrate plug occurs in a singly laid insulated flowline, it may be difficult or impossible to use flowline depressurisation or local chemical treatment to sublimate the plug. Hydrostatic pressure from the fluid column in the deepwater flowline and riser may exceed the minimum pressure required at ambient seawater temperatures. Local chemical treatments may require running coiled tubing to target the chemical at the plug, and the flowline lengths may limit the ability to run coiled tubing in this manner. From an operational standpoint, the bundled flowline configuration provides certain advantages that cannot be realised using individually laid and insulated flowlines. Since all flowlines can be contained within the same insulated space, warm fluids can be circulated through adjacent looped flowlines to sublimate a hydrate plug. Such additional flowlines could be incorporated in the bundle to provide a dedicated circulation loop. Heat-traced flowlines still requires the flowline to be insulated in order to conserve heat, generally using singly insulated pipe or pipe-in-pipe configuration.

Rigid, polymeric centralizers placed periodically in a pipe-in-pipe system do not improve the collapse resistance of the outer pipe, unless spaced less than 3 pipe diameters apart.

Pipe-in-pipe carrier pipes with higher D/t values exhibited significant increases in collapse resistance and critical curvature when foam insulation completely filled the annulus.

Pipe-in pipe flowlines with an evacuated annulus maintained by a platform based pump spread is technologically feasible with available materials, fabrication processes, pumping capacities, and installation methods. However, the operational risks involved with annular flooding will require extensive development of rapid and economic repair technique.

The application of weldable modified 13%Cr linepipe is considered a cost effective alternative to solid duplex stainless steels and bi-metallics currently used by the Oil & gas industry for subsea Corrosion Resistant Alloy (CRA) pipelines.

The use of martensitic 13%Cr stainless steels offer excellent resistance to corrosion in CO₂ containing fluids and consequently have been extensively used as downhole tubular products for the oil and gas industry. More recently, the development of super 13%Cr steels has improved the general corrosion resistance of these materials and offers limited resistance to SSCC in environments containing small amounts of H₂S.

In the past, 13%Cr stainless steels have been precluded from use as linepipe due to their poor weldability. As these materials are considerably cheaper than duplex stainless steels and offer comparable corrosion resistance in CO₂ environments containing small amounts of H₂S, there has been considerable interest in recent years for the development of a weldable 13%Cr. On the basis of this, linepipe manufacturers have undertaken extended development programmes to produce a weldable 13%Cr linepipe. This was claimed to be achieved by principally lowering of carbon and nitrogen contents.

A testing programme performed by a Group Sponsored project using mechanised PGMAW and manual GTAW with duplex (25%Cr) filler wires has shown good weldability of 13%Cr linepipe similar to duplex stainless steels, and satisfactory welds made in a productive manner with desirable and corrosion properties.

13%Cr steel used for this test has low Carbon and Nitrogen levels to offer good weldability and minimise hardness values in a HAZ. In addition the materials are highly alloyed with Nickel (Ni). All material were supplied in the quench and tempered condition and varied between laboratory and production samples. The addition of Molybdenum (Mo) is claimed to improve SSCC resistance in the HAZ and Ni to obtain a single martensitic phase plus increase toughness.

For pipeline welding, a fundamental factor in the selection of the welding process/system is being able to achieve the required weld quality and properties at the desired productivity levels. An additional consideration for CRA’s is the requirement for back purging of the root bead to avoid oxidation. Based on these considerations, the (PGMAW) process using an internal pipeline clamp with copper backing shoes, which supports the solidifying weld pool, was selected. This technique when applied in the form of a mechanised process (welding bug and band system), offers the maximum productivity for a single sided welding technique. One restricting factor with such a technique is the minimum internal pipeline size available with copper backing shoes. This at present is limited to 8’’ diameter pipe size and above. For 6’’ diameter and smaller, this technique has not yet been fully developed for single sided welding without the use of internal clamp with copper backing shoes, therefore, an alternative welding process was selected for these diameters, namely , GTAW.