‘Over the next five years, the number of subsea wells we operate will grow to exceed 300,’ Brookes adds. ‘During this time, the investment levels in subsea and deepwater facilities are likely to run in the range of $1.5-2.5 billion a year. It’s therefore imperative we get our technology right, and that it works first time. Intervening to remedy problems in these water depths is a very costly business.’

And it’s not only about going deeper. New fields are likely to present challenges in terms of extremely high reservoir pressures and temperatures – even beyond those currently being addressed in BP’s Thunder Horse deepwater project in the Gulf of Mexico, where pressures of 1200 bar and temperatures of 135ËšC have required dozens of ‘firsts’ to be developed to complete the field’s subsea wells (Frontiers, August 2004). And tieback distances – that is, the distance of subsea wells from host facilities – must be increased to perhaps 200km to capture more outlying reserves, demanding new solutions to ensure the flow of hydrocarbons can be reliably and economically transported over these long distances.

Brookes believes that BP currently has more opportunities to pursue in deep water than any other company, and is well positioned to be the industry leader due to a combination of three key factors.

‘We have a significant, well-managed and focused R&D programme; a team of deepwater experts with world class skills in many disciplines; and the ability to integrate into the management of our projects the learning from hands-on applications and feedback from real deepwater developments. We are confident that this is a platform for success.’

‘Within these five areas, we have several dozen projects under way,’ says Mike Theobald, delivery manager for the deepwater technology programme. ‘These are led by a core BP team of some 40 experts based mainly in the UK and USA, working on both internal developments and collaborating externally, for example in joint industry projects and in others funded solely by BP.

‘The projects are very diverse in nature, ranging from monitoring ocean currents, developing innovative guidelines for very large steel catenary risers, evaluating 20 megawattt subsea gas compressors and 36,000 volt underwater electrical systems, right through to installing and maintaining large subsea structures and floating platforms of many different varieties.

‘Five years ago, people viewed operating in 2000m of water to be the limit, for example in riser and flow assurance technology. Nowadays this is not exceptional – BP is focused on developing new systems for projects already under appraisal nearing 3000m of water.’

‘Unless prohibitively expensive flowline insulation or heating systems are employed, tieback distances for mixed wellfluids are typically limited to around 35km at present,’ explains Theobald. ‘If these step-out distances can be significantly increased so that a greater number of remote wells can be supported from a single hub, the number of costly hubs for new developments could be reduced and additional satellite wells could be tied economically to existing facilities to capture isolated hydrocarbon reserves.’

Subsea wellheads are fitted with an assembly of control valves, known as trees. Today, most subsea developments use a multiplexed electro-hydraulic control system, which routes hydraulic fluid stored in subsea accumulators under pressure to individual valve actuators on the trees, and also to the downhole safety valve deep inside the well. The high pressure hydraulic fluid and control signals are fed to the subsea system from the hub via an umbilical, typically 150-200mm in diameter, containing several individual hydraulic hoses, electric cables and channels for delivering chemicals to the well.

‘These systems have served the industry well and will continue to do so for some years to come,’ Theobald points out. ‘But they do have reliability weaknesses relating to hydraulic fluid cleanliness, materials compatibility and depth effects, reducing overall system availability in some systems to the region of 95%. Long step-out distances to the valves, and the fluid power required, can make the systems very complicated, and due to the way choke valves are opened and closed in small increments, operations are quite slow, measured in terms of tens of minutes from open to closed in some cases. Furthermore, with increasing water depths, especially for high pressure reservoirs, the size of actuators and accumulators plus associated fluid volumes are pushing current industry capabilities to the limit. These and other factors are making electro-hydraulic control systems increasingly expensive to install and operate for long tie-backs in deep waters where high reliability is a prerequisite.’

‘However, if the pipeline conditions did not limit the hydrate formation process to the ‘plugging phase’, the crystals would ultimately become individual submillimetre particles that do not agglomerate, similar to a dry powder suspended in liquid that behaves like a slurry. This hydrate slurry would remain in this stable state and would be transported with the flow. It is this condition we want to attain, which is referred to as “cold flow”. Our research work to date shows that it is certainly possible to achieve this in a laboratory flowloop.’

The key, says Argo, is to mix the hot well fluids rapidly with a cooled wellstream containing hydrate and wax particles that act as seed crystals. This ‘crash cooling’ will cause free water droplets to quickly coat the hydrates as a thin film, and if temperature conditions are right, the film will convert to hydrates and continue to grow outwards, soaking up more and eventually all of the water in the stream. No free water will be inside the crystals and therefore it cannot escape to create a sticky surface and plug the line.

In practice, the ‘crash cooling’ of the wellstream from temperatures typically around 80ËšC to near-ambient around 4ËšC, could be achieved by recycling a cold stream of stabilised dry hydrate slurry taken from a point on the pipeline several kilometres downstream of the subsea well, and injecting this into the warmer stream near the wellhead. This would act as a ‘seed’ to induce further dry hydrate growth. The slurry formed will be more viscous and require pumping on the seabed – subsea pumps to perform this duty are already in an advanced stage of development and are not seen as a potential showstopper. When the slurry reaches the host platform – and it could travel for long distances such as 100km due to its stability – it will be converted back to free water and gas, requiring heat to be tapped from the topsides process. It may even be possible to separate the hydrates – which have a commercial value – and export them as a slurry.

And what of the business benefits that cold flow promises to provide? ‘Cold flow will mean that tie-back flowlines can be installed as uninsulated bare steel pipe without the risk of them becoming blocked and losing production,’ emphasises Argo. ‘And only single lines, rather than loops, will be needed – laboratory tests have shown that you can stop a flowline for many days and restart the flow without problems as the hydrate slurry is stable and can be readily re-mobilised, a significant operational advantage. Continuous chemical injection can also be eliminated. Taken together, these factors mean that tiebacks could become much cheaper and much longer. It is an exciting technology and could cut of the order of $100 million off the cost of a subsea development in deep water. There are also potential applications in onshore Arctic areas such as Siberia, where preventing hydrate and wax problems in long multiphase flowlines can be a problem. There are not many single technology concepts around bearing this potential degree of impact.’

The industry’s workhorse for carrying out IRM tasks in depths far too deep for divers to be involved has long been the remotely operated vehicle (ROV). These large, high powered, sophisticated underwater machines, controlled from the surface through an umbilical tether, have the ability not only to inspect and identify faults associated with subsea hardware and pipelines, they are also designed to employ a variety of specialist tools to a carry out repairs. But these capabilities also bring some operational and cost drawbacks – ROVs require a dedicated support vessel for deployment and they are often called in ‘reactively’ to respond to a problem, taking several days to mobilise before intervention can begin. ROVs also have operational limits due to being tethered – a 40mm diameter control umbilical attached to an ROV designed for 3000m of water weighs in at 18 tonnes, and typically constrains the vehicle to a radius of less than a kilometre from the support vessel.

When ROVs are used proactively in a planned IRM programme, their full capabilities are often not required, although deployment costs remain fixed. For example, a study in BP’s Foinaven and Schiehallion fields to the west of Shetland, encompassing abut 70 subsea wells, showed that almost 90% of the workscope was focused on inspection tasks.

Now, a new breed of underwater vehicle is starting to make its presence felt that could offer a cost effective and flexible alternative to ROVs for some operations, a particularly attractive prospect for deepwater developments.

Typically, an AUV might be powered by lithium ion batteries – although fuel cells could be a longer-term option – and fitted with an inertial navigation system to keep track of the AUV’s position relative to a start location. Onboard computers can be programmed with a complete mission, or stages of a mission requiring recognition of features along the way where the AUV might wait for further instructions. A key feature is the use of sonar scanning or other sensors that seek out ‘anomalies’, for example, detecting objects dropped onto or near a pipeline, at which point the AUV would loop round and pass the point again more slowly for a more detailed inspection – onboard data processing endows the vehicle with the intelligence to do this. Other features are the ability to move vertically up and down and hover on location, not an easy task in strong ocean currents but a necessary performance characteristic for inspecting vertical lines, such as risers and moorings.

Another joint industry project in which BP is involved, funded by the UK government’s Industry Technology Facilitator initiative, is focused on the development of Spinav – subsea pilotless inspection with an autonomous vehicle. The project, run by Seebyte, a spin off from the Ocean Systems Laboratory at Heriott-Watt, has developed the Rauver AUV, which has among its capabilities the ability to hover and track in the vertical mode for risers. The Rauver is to act as a testbed for a range of sensing modules, for example, one using blue light which causes a fluorescent dye – present in a corrosion inhibitor chemical inside a riser – to glow. If there is a leak in the riser, the AUV will detect the glow from the leaking chemical as an abnormal condition.

Next year BP plans to fund a deepwater trial in the Gulf of Mexico. The Alistar 3000 AUV, developed by ECA of France for operation in 3000m of water, is one candidate for the trial.

‘AUVs have proven they can operate as carriers in deep water,’ notes Billingham. ‘The next step is to demonstrate the onboard intelligence to carry out the variety of tasks needed by the oil and gas industry. Once AUV technology matures it will provide low cost and rapid access, particularly to remote subsea facilities. Bringing all this together is going to be the really clever part.’

And being clever is fundamental to the success of BP’s pioneering deepwater technology programme.