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  • Iain Bennett

why has the industry turned its back on long distance subsea tiebacks?

Updated: May 28, 2021

The first decade of this century witnessed the successful completion of a number of field developments that featured long range tie-back to shore as the facilities solution, notably projects like Snøvhit, West Delta Deep and Ormen Lange. This had the result of increasing the range of tie-back solutions up to 150km, but in the last ten years there have been no further field developments with longer tie-back lengths than this and it is interesting to ask why the interest in tie-back led solutions has waned so significantly. A decade of stagnation in any area of an active and global industry is unusual and worth investigating.

One of the contributing factors may be the emergence of FLNG technology, with its impressive and very visible surface hardware taking up much of the industry’s capital budget and the energy of its best people. Yet at the time of writing, the flagship of the FLNG fleet (Prelude) is still not on-line, despite 5 years of construction and a total gestation period of 10 years. With the water depth only 240m and the distance to nearest distribution network being 600km (Port Hedland, Australia), it was possible to transfer the 700MMscfd of well fluids to shore using a 40” pipeline, saving millions of dollars in development expenditure and shaving months, if not years, off project duration.

So, what are the perceived barriers to pursuing pipeline-to-shore developments and has any technological progress been made in overcoming these obstacles in the last ten years?

liquid slug management

Liquid slugs in multiphase pipelines are an ever-present challenge and, historically, have been handled by the construction of an enormous slug-catcher at the end of the pipeline. This approach is tolerable in a high gas-price world and where the shoreline is sparsely populated and underutilised. Now energy companies are obliged to recognise the reality of current market and the fact that most shorelines tend to be intensively used by indigenous inhabitants for their recreation and, more importantly, their livelihood. These are strong drivers to reduce near-shore land requirements. Rather than taking a reactive response to liquid slug management, imagine the benefits of a proactive approach wherein the pipeline is operated in such a way that limits slug volumes. Transient flow simulators now have much greater processing power and can be used to predict the response of the pipeline to various operating modes well before any pipe is procured.

Modelling novel operational procedures such as “micro-step” ramp-ups have the potential to significantly reduce the size of the onshore slug-catcher and its associated land requirement. Finally, the possibility of creating a Digital Twin of the pipeline for use after installation is now real and so enables the operations team to understand the effects of a slow-down or ramp-up strategy well before it is attempted and thus adjust the strategy to ameliorate slugging.

multi-diameter pipelines

Remote offshore gas field developments typically require large export rates to ensure profitability and transporting such gas volumes across long distances requires wide bore pipelines; but larger diameters increase capital cost and exacerbate liquid slugging challenges. When reconciling these two opposing drivers, it is useful to remember that the actual volumetric flowrate of the gas stream increases along pipeline length due to pressure drop – meaning that the theoretical optimum diameter at the inlet of the pipeline can be much less than at the outlet of the pipeline. Therefore, designing the pipeline to have sequentially larger diameters along its length can help reduce these concerns. Historically, this has been avoided due to the challenges associated with pigging multi-diameter pipelines (as required for pipeline integrity assurance); however, specialist pipeline service providers have matured the hardware required for this task[1]. Thus, tie-backs solutions can now incorporate multiple-bore pipeline designs that minimize capex and help control slugging and improve pipeline constructability.

limitations of deepwater pipelay vessels

Laying large bore pipelines in deep water can make incredible demands on the capabilities of a pipelay vessel, especially its tensioning and support system. Ten years ago, the maximum water depth for installation of a 32” pipeline was 1100m (Greenstream pipeline, laid by the Castoro Sei). Since then, much bigger and more powerful construction vessels have been built by Saipem, AllSeas and McDermott to name a few, providing J-lay or S-lay modes and making it possible to install 32” pipelines down to depths of 2200m (TurkStream pipeline). Construction contractors have responded to the market and provided the means for increased deepwater pipelay capability.

low recovery factor

Conventional subsea tie-backs typically require elevated back pressures at pipeline inlet, which in turn may restrict well deliverability and so reduce overall recovery factor. Selecting a larger pipeline diameter in an attempt to improve recovery can make matters worse by increasing liquid hold-up in the pipeline and thus back-pressure. Subsea pressure boosting is a more definitive means to resolve this issue that requires a much lower wellhead pressure to deliver the same volume of gas. It should be recognised that subsea compression is a maturing technology and, therefore, additional development, qualification and testing will be required before it can be considered fully mature.

However, great strides have been made in the last 3 years with two compression units being installed in 2015 and a third featuring BHGE technology undergoing a testing program. In particular, the system installed in the Åsgard field has achieved 25,000 operational manhours and achieved Technology Readiness Level 7[2]. Three vendors have separately contributed a great deal to the technological advancement of this technology, but clearly a focussed joint industry venture involving collaboration with operators and technology providers would bring much needed energy and purpose to make this technology a fully mature go-to option.

corrosion rates

Carbon steel is still the most cost-effective construction material for hydrocarbon bearing systems and therefore is typically selected for long pipelines unless an alternative situation demands otherwise. The downside with carbon steel is it is easily corroded in the presence of CO2 and, even at very low concentrations, the cumulative removal of metal over the life of the field by corrosion can prohibit its selection. Traditionally, the most common means of controlling corrosion is via direct injection of corrosion inhibitor, but the typical approach taken to determine the efficacy of the inhibitor often leads to a situation whereby significant corrosion allowances are still required.

Consideration of high availability injection systems can mitigate this shortcoming. Another option is to use pipelines clad internally with a corrosion resistant material, but there are still long-term integrity issues to resolve with this technology. Alternative strategies such as pH stabilisation, as developed by Statoil and Total over the last decade or so, should be considered if the conditions allow. Whilst Total have utilised methyldiethanolamine as the stabilising agent and Statoil have generally used sodium bicarbonate, the principle is the same and there are now assets that have many years of successful operational experience using this technique. [3]Whilst recognising that this strategy cannot be adopted for systems carrying large volumes of aquifer water, the overall approach can now be considered a fully mature technology.

inherently safe design requirement

Most operators have observed an inherently safe design approach to their facilities, especially when it comes to manned infrastructure. For pipelines, this has sometimes translated into the design requirement to withstand full wellhead shut-in pressure which, with an increasing proportion of new finds being HPHT, can render the tie-back solution non-economic. Fortuitously, subsea safety-instrumented-systems (such as HIPPS) are now a reality and their use can reduce pipeline design pressure and thus cost considerably. The qualification process of higher pressure and larger-bore HIPPS packages continues and, in parallel, the requirement for SIL-3 systems (like HIPPS) on long tie-backs is being challenged; why do unmanned and remote systems with forgiving response times require a SIL-3 solution, when a lower SIL solution may control the risk satisfactorily?

provision of power, control and chemicals

Supply of power, control and chemicals to remote wells has been a contributory factor in limiting tie-back distance. Considering power supply, huge progress has been made in subsea high voltage DC cables, with the longest installed cable to date being 580km in length, with a capacity of 700MW2[4]. Well control can be securely achieved across much greater distances using fibre optic cables equipped with optical amplifiers. The longest single fibre-optic cable in existence stretches from Germany to Japan, is almost entirely subsea and is 39,000km in length8[5]. Supply of chemicals, to control hydrate formation for example, is solvable using subsea umbilicals from shore or another existing facility. Where these sources are too distant, autonomous buoys may be considered. These unmanned floating facilities are located in-field and can be used to store and provide chemicals and, additionally, to generate and supply power for well operation4[6].

Historically, the use of these buoys has been restricted due to challenges of personnel transfer; frequent use of helicopters introduces safety issues and may not be feasible given their limited range from base (~350km if the return trip is accounted for). However, recent developments in motion-assisted gangways means that the walk-to-work access mode is now a reality1[7]. In this way, the buoy can be supplied with chemicals directly from a supply vessel and the maintenance crew can access the systems safely whenever the need arises. Man-entry safety issues can be addressed by predictive maintenance software like Predix or installation of a parallel buoy that can be completely depowered in the event of extensive maintenance. Lift specialists Versabar are also promoting their own more conventional version of this technology (Versabuoy)[8], which is similar to a minimum facilities semi-sub but uses articulated joints on the pontoons to reduce wave-motion stress and therefore steel cost.

FLNG bias

Over the last decade, many operators faced with the challenge of monetising a remote offshore gas field have made the decision that if it was necessary to mature some form of technology to realize the reserves, then that technology would be FLNG. However, 10 years ago, the gas market was very different. Since the shale gas revolution, the development of US LNG export terminals has brought down the global ceiling on gas prices and challenged the economic viability of FLNG as a technology, which is inherently complex and thus capital intensive. Furthermore, many operators are also realising that the aspiration to redeploy FLNG vessels to multiple gas fields, and therefore extend their useful life, will be more difficult in practice than originally anticipated. Gas processing equipment has always been very susceptible to small variations in composition or pressure and this is unlikely to change any time soon. As for the medium-term energy market trends, there are strong indications that the impending electrification of transport will increase the demand of domestic power, meaning that parts of the world that are devoid of a meaningful demand for energy may soon be attractive destinations for a ready supply of gas. Putting together these market factors and the technological advances detailed above, it may be prudent to reappraise the application of long distance tie-backs as a means of monetising remote gas.

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