Acteon S2S 2

a quarterly review from Acteon

Acquisitions enhance Acteon’s seabed-to-surface portfolio Understanding risers Pushing high-performance boundaries in ultra-deep water

V.2 11-06

inside this issue

Reel service Driving towards the last frontier cutting trouble high-pressure solutions monitoring with integrity simple solution efficient permanent moorings

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linking seabed to surface Diary

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28–30 November DOT 2006, Houston, Texas 5–8 December OSEA 2006, Singapore 14 December Subtech 06, London For further information please contact Paul Alcock T: +44 1603 227012 F: +44 1603 774175 W: www.acteon.com E: paul.alcock@acteon.com © Acteon Group Ltd 2006

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My lead-in for the first issue of our new publication, S2S, described how Acteon has set out to bring together technology that targets the seabed-to-surface area of offshore oil and gas developments. In this light, it gives me great pleasure to welcome Trident Offshore Ltd and Aquatic Engineering & Construction Ltd to the Acteon group.

Deepwater developments are currently receiving a great deal of industry attention, and the Acteon group undoubtedly provides some unique, proven technologies in this area. For example, we offer deepwater pile-driving services and patented SEPLAs, both of which have been used to provide foundations for deepwater development infrastructure.

The arrival of these well-known brands has moved us closer to achieving this objective. We look forward to rolling out these companies’ capabilities to our existing client base and to offering their customers the Acteon group’s full range of expertise. You can read some details about both companies in this issue of S2S.

Continuing on the deepwater theme, an increasing number of such developments have now been operating for many years and attention is turning to their integrity management – keeping them functioning safely and profitably. We have key technologies that are increasingly being deployed to address the need for long-term management of mooring and riser system integrity.

The specific complexities associated with riser integrity management are explored in a feature on page 12.

Technology plays a key role within Acteon, and this issue features some interesting and thought-provoking technologies. We also catch up with InterMoor’s CASIM project, which we featured in the first issue of S2S. One of my hopes for S2S is that it will continue to stimulate interest and debate in our work. The reaction to the first issue has been very positive, and we look forward to hearing your views on each coming issue.

RICHARD HIGHAM GROUP CHIEF EXECUTIVE, ACTEON

However, it should not be forgotten that there is still a lot to be gained from existing and typically marginal shallow-water developments. High-pressure jackup drilling risers are a good example of where Acteon is making a technology contribution to this area, and our slot recovery services are also helping to extend the lives of shallow-water assets.

Whether you face shallow- or deepwater challenges, Acteon has technology, from the early stages of a project to its abandonment, that may well be of relevance.

I hope that you enjoy reading about our problem-solving technology, and that you find something of interest to you in the day-to-day challenges you face when linking the seabed to the surface.

Thanks for taking the time to read this second issue of S2S, and I hope you find it as interesting as you appear to have found the first.

KEVIN BURTON VICE PRESIDENT, TECHNOLOGY, ACTEON

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These two newest members of our group will help us to expand our back-of-the-boat offerings and further our aim of providing cost-effective services linking seabed to surface.

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CASIM shore tests

Location, location, location

In August 2006, InterMoor demonstrated its compensated anchor-handler subsea installation method (CASIM) to 36 client representatives. CASIM is more than a method: it is an integrated service that includes detailed engineering work, dynamic lowering analyses, operational procedures, tools, equipment and offshore personnel. The service helps to provide greater accuracy and control during the installation of equipment such as suction-embedded plate anchors, suction piles, subsea Christmas trees and manifolds from anchor-handling vessels.

Three Acteon companies have recently been on the move. Mirage Machines has a new UK factory, 2H Offshore Projetos in Brazil has a new office and InterMoor has set up a Brazilian company within 2H’s new premises.

The CASIM method uses cylindrical heave-compensation devices to reduce motion and line tension. Representatives from BHP Billiton, BP, Chevron, Kerr-McGee, Shell and W&T Offshore watched as CASIM configurations were demonstrated with two heavecompensation devices in series and in parallel. The group also examined CASIM’s performance under different pressure and load conditions.

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InterMoor has more than 14 miles of chain in the USA

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Mirage needs room to grow, and the new factory in Derby provides space for designing and manufacturing portable on-site machines and tooling packages for increasing client numbers. The Mirage team planned the move meticulously and worked with a heavy-machine-moving company, a laser-levelling company and others to install its numerically controlled machines in just one weekend.

The Brazilian arm of 2H has moved to larger premises in Rio de Janeiro and is sharing the new office with InterMoor do Brazil. InterMoor’s entry into the region as a wholly owned Brazilian company enables it to offer specialised mooring, rig relocation and back-of-the-boat subsea installation services to the local market. John Riggs, newly appointed managing director, says, “It already looks like we are going to be pretty busy servicing the needs of independent oil and drilling companies.”

InterMoor’s entry into the region as a wholly owned Brazilian company enables it to offer specialised mooring, rig relocation and back-of-the-boat subsea installation services to the local market

Subsea protection UWG has designed fishing-friendly protection for Perenco’s subsea distribution and umbilical termination assemblies in the North Sea Davy East field. The protective structure is fixed to the seabed by its own weight and has a smooth profile to allow fishing nets and gravel boards to pass without snagging. The structure is protected from corrosion with premium-quality two-pack epoxy paint and, because the unit could not be tied into the existing cathodic protection system, its own sacrificial anodes to provide additional protection for its 10-year life. The structure was delivered three months after contract award.

Two new acquisitions in Aberdeen Acteon has recently strengthened its foundations and moorings division with the acquisition of two companies, Trident Offshore Ltd and Aquatic Engineering & Construction Ltd, based in Aberdeen, UK. These two companies enhance Acteon’s presence in Aberdeen, an important centre for the international oil industry.

Trident, with over 50 full-time staff, specialises in rig moving services and also in designing and installing mooring systems for drilling rigs and floating production units. The company has a strong presence in the North Sea, offshore West Africa, South America and China.

Trident and Aquatic enhance Acteon’s presence in Aberdeen, an important centre for the international oil industry

The products and services Trident offers are closely aligned with those of existing Acteon companies, in particular, InterMoor. The similarities between the two companies’ skills are obvious; however, their client bases are quite different, which is an excellent basis for the expansion of the mooring services element of Acteon’s business.

Aquatic, which was established in 1976, has over 70 staff; offices in Aberdeen and Peterhead, UK; and satellite sales offices in the Netherlands, Qatar and Southeast Asia. The company provides a comprehensive range of powered reel systems and offers extensive engineering and operational capabilities.

Trident has executed more than 2370 rig moves worldwide in the last 20 years

The addition of Aquatic to the Acteon team adds a key new capability to the moorings and foundations division.

UWG has met a BP challenge to design and manufacture high-specification non-steel centralisers for use in offshore Azerbaijan. BP’s chosen completion strings for the Shaz Deniz project have narrow annuli that require high-tolerance centralisers. UWG’s answer was to machine centralisers from blocks of nylon – the first application of the material in this type of centraliser. Fabricated or cast steel centralisers can be made to high tolerances but must be kept in their matched pairs. The nylon centralisers in a set are virtually identical, which eliminates the need to keep pairs together. They are also lightweight, which makes transport and installation much easier and safer. UWG has manufactured and delivered 700 nylon centralisers of varying sizes for BP this year.

In 2004, MENCK drove piles with a total weight of up to 967 t in Benguela Belize

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Nylon centralisers for BP

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Powered reeling: A single pair of drive towers is skidded along a track to line up in turn with each reel. The individual towers have two sets of hydraulic rams: the first to move the towers inwards to engage with the reel and the second to lift the reel from its cradle and allow its contents to be paid out.

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This recently commissioned set of drive towers brings Aquatic’s current complement to 17 powered-reel systems; the largest is capable of handling 400 t of product. These particular towers can power an 11.4-m reel with a 300-t load. Their first job will be to lay 4 km of 120-mmOD stainless steel tube umbilical in Shell’s Merganser field in the North Sea. In this case, the reel will be fitted with a larger than normal 10-m hub to comply with the minimum bend radius specified for this increasingly popular type of umbilical.

Reel service The recent acquisition of Aberdeen-based Aquatic Engineering & Construction has enhanced Acteon’s seabed-to-surface credentials and, in particular, has bolstered the group’s ability to undertake complex offshore operations from the back of a dynamically positioned boat. In this article, we examine Aquatic’s industry-leading powered-reel systems for flexible pipe laying and retrieval.

The company has recently extended this concept and is now able to offer an industry-standard 9.2-m reel that comes in readily transportable parts – and that has full DNV accreditation.

Mackintosh sees this as providing particular advantages for single-reel operations involving a specialist product at a remote location where returning the reel at the end of the project inevitably raises financial and logistical issues.

There was a time when laying most flexible pipelines, umbilicals or mooring cables demanded a specialist vessel with a fixed reel or a carousel with a dedicated drive system – in essence a huge, permanent winch. It was common for such vessels to spend as much time going to and from the manufacturing facility to collect the product to be laid, each time involving a transpooling operation, as was devoted to the actual offshore installation process.

As well as improving the technology, Aquatic has geared up to provide customers with an integrated installation package.

Given the objectives of the installation project and the specifications of the product to be laid, Aquatic can supply all the necessary equipment – not just powered reels but also power packs, tensioners, stern chutes and so forth. When necessary, deck engineering can be undertaken to adapt the system to the chosen vessel, installation procedures can be prepared, and the logistical side of the project taken care of. Finally, the customer will have the benefit of experienced personnel to support the entire project, both on- and offshore.

The advent of modular, tower-drive reeling systems changed all that. Separating the reel and its drive and putting the drive towers on tracks capable of being fitted to the decks of a variety of vessels improved operational flexibility, opened the way for multiple-reel installation projects and made the whole process safer, faster and more economic.

Aquatic has been at the forefront of this area of offshore technology since 1994 and has used its knowledge and experience to continually improve these modular secondgeneration powered-reel systems.

Equipment manager George Mackintosh describes the thinking behind Aquatic’s development efforts and market offering: “We have concentrated on further reducing the cost of reeling operations and making life easier for the installation contractor. One of the ways we have achieved this is by designing equipment that breaks down into components small enough to be transported by sea or road in standard open-topped containers. Even our largest drive towers, which weigh around 30 t, can be put together or dismantled by our technicians in less than 24 hours. This avoids the contractor having to bring a vessel to pick up the systems from us – we can freight them to wherever they are needed.”

Aquatic’s business philosophy is about providing reliable and efficient reeling equipment backed by first-class service.

“I am proud of what we have achieved at Aquatic; we have introduced some key innovations and we are working on ideas that will move the process even further forward,” says Mackintosh. “For example, at the moment, we are working on new designs that will make better use of the available deck space and permit the equipment to be fitted to a wider range of vessels. We also have a four-track, 40-t pipe-lay tensioner due for completion by the end of this year. This will complement our largest 400-t tower-drive systems and enable us to perform installations in deep water.

“Our reputation is, however, largely based on never letting our customers down – delivering reliable, fit-for-purpose equipment on time. This is a feature of our business that we are determined to maintain.”

Aquatic has two main lines of business. In addition to its powered-reel systems, there is a flourishing manpower services side to the company, as general manager Suzanne Morrison explains. “The reels form the higher-profile part of the business, but we provide an equally valuable service to operators around the world with the provision of qualified people – project managers, engineers, technicians and marine operations specialists. At the last count, we had about 350 people out on contract. We have developed lasting relationships with several companies through our strenuous efforts to understand their operational objectives.

The business is about more than simply supplying good individuals – you have to think in terms of performing a specific project or business function.”

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Another side to the company

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Driving towards the last frontier High-performance hammers capable of driving piles in ultradeep water are being developed by MENCK to support the oil and gas industries’ efforts to develop hydrocarbon reserves in these water depths.

With the hydrocarbon reserves in shallower water already reasonably well accessed, operators have been turning to ever-deeper waters, where the safe and cost-effective development of subsea prospects presents huge execution challenges. Factors such as immense depths to the seabed, high pressures, strong currents, remote locations and complex geology mean that highly reliable engineering solutions are essential.

Fabian Hippe, sales manager, MENCK, says, “We routinely offer highly advanced and reliable underwater pile-driving hammers that can be used to depths of 2000 m. They have helped to install deepwater anchor points on projects around the world and are the only genuinely underwater hammers available.”

“There is no other system that can drive piles in deep water, and now we are extending the capability of our equipment to water depths in excess of 3000 m,” says Hippe. “This will create a host of new opportunities for the industry.”

Experience shows that deepwater driven piles typically provide the most reliable and easy-to-use mooring points.

They facilitate positioning better than drag anchors and are less sensitive to varying soil conditions than suction piles or plate anchors. In addition, they provide solid foundations for any kind of subsea architecture, including mono-piles for subsea manifolds and foundation piles for subsea templates.

They can be used as riser foundations, pipeline termination piles or anchor points, and can even be used to pre-install well conductors.

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Sophisticated solution

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MENCK’s range of hydraulic underwater (MHU) hammers draws on over 130 years of experience in designing and manufacturing pile-driving and hydraulic-based systems.

Three series of hammers are available: the MHU-S range for above- and underwater (to water depths of 400 m) pile driving; the MHU-T for water depths to 2000 m; and the soonto-be-available MHU-U for water depths exceeding 3000 m.

They can all be combined with the company’s dedicated submersible hydraulic power packs, which can be configured to drive various pile sizes.

In deep water, a girdle-type electrohydraulic power pack is fitted to the hammer. This minimises the hydraulic hose length to provide the highest health, safety and environmental standards possible. But the biggest advantage of generating hydraulic power at depth is that it reduces energy losses. If the hydraulic power were to be produced at surface, substantial power would be consumed in overcoming the losses within the umbilical and the hydrostatic pressure.

An umbilical carries the electrical power required by the hydraulic pumps, the communication lines that provide realtime control and feedback, and the compressed air for creating a gas-saturated environment inside the hammer. Electric motors drive a hydraulic piston that has a housing filled with compressed air to increase acceleration and reduce friction.

As a result, the hammer’s efficiency (net driving energy over hydraulic energy) is over 95%.

A sophisticated control system enables the operator to interact with the electronic sensors on all the key components.

This provides real-time feedback during pile installation and generates valuable installation and driving records for postjob analysis.

Breaking new ground MENCK’s deepwater pile-driving systems have been used in 28 deepwater anchoring projects during the last 10 years. As Hippe explains, several milestones have been created along the way: “Our underwater hammer technology was used in the Gulf of Mexico to install the largest tension-leg platform (TLP) ever built,” he says. “It also played a role in the first TLPs in West Africa and Asia–Pacific.”

Hippe continues, “The system was originally developed in the late 1980s for water depths of up to 1000 m, but we have continued to push its use deeper. We were involved when the world depth record for deepwater driven piles was set at 1220 m, at 1400 m and then at 1565 m. We have held the record for the last 15 years.”

Operational experience is an invaluable element of the product development cycle. “We do not just design and manufacture the equipment,” Hippe says. “We also operate our own rental fleet, which gives us vital operational experience that we feed back into the development and design process. This has led to an extensive range of safety features, an expedited commissioning process, easy-to-maintain modular concepts and the highest level of reliability.”

There is no other system that can drive piles in deep water, and now we are extending the capability of our equipment to water depths in excess of 3000 m,” says Hippe. “This will create a host of new opportunities for the industry

Developments in deep and ultra-deep water require outstanding engineering expertise and innovation, plus robust and reliable equipment. MENCK has drawn on its specialist technical know-how in this field to help the oil and gas sector meet these extreme challenges head on, and overcome them.

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MENCK clients undertaking the more challenging projects have recognised the value of commissioning the company to take care of every aspect of the piling process. MENCK’s engineers can become an integral part of the customer’s team by providing optimum pile designs, selecting the most appropriate equipment and managing the pile installation programme to ensure that it aligns with the overall project.

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Cutting trouble

Before lifting a redundant platform from the seabed, it is necessary to ensure that the well conductors and enclosed casings have been completely severed. It is not as easy as it sounds. UWG’s approach takes away all the uncertainty and makes for a safe and efficient lift.

A couple of years ago – before the steep rise in the price of oil – the idea of abandoning declining oil and gas fields was probably higher on most operators’ agendas than it is today. Although oil at $70 per barrel has signalled a reprieve for many ageing production platforms, the challenge of removing redundant structures safely and cost-effectively is never far away.

For this reason, operators often wish to confirm a clean cut by lifting the individual conductors and the casing strings just a few feet immediately after cutting. And therein lies the problem. Even on a small platform in shallow water, this could involve lifting up to 150 t, which is often in excess of the deck’s load-bearing capacity for many older structures.

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“One way around this problem is to use beams to spread the load to the platform jacket,” explains McFadyen. “But this can sometimes mean bringing in impractically large beams and, in any case, many older platform jackets members are simply not up to the job.” McFadyen realised that the element of the structure best able to withstand the weight of the One practical difficulty UWG has identified is cutting the individual conductors and their casing strings was the other surrounds of the well conductors, plus their enclosed casing conductors in the array. strings, beneath the production platform so that the structure can be lifted as a unit from the seabed. Plugging wells with In essence, UWG’s solution involves fixing a spreader beam cement is generally straightforward; as is, or should be, cutting above the conductor array using risers fitted to selected conductors just below the mud line. But you need to be conductors. In this way, the beam can easily be located on confident that the conductors and the casings are completely an upper, less-confined level, above the often congested well free, otherwise you can run into serious trouble and expensive deck. By fitting a hydraulic jack to the beam, each conductor delays when it comes to lifting the structure. “Hiring a heavy- can be easily and safely lifted the few feet necessary to ensure lift vessel and a transport barge accounts for much of the successful severance. Because the conductors are generally expense associated with the decommissioning and removal clustered within a well bay, it is also possible to use a smaller of an offshore platform,” points out Ian McFadyen, formerly spreader beam. This results in smaller bending moments with UWG and now a non-executive director of Acteon. and, most importantly from an operational standpoint, fewer “And it is possible to waste days if you have to go back to access problems. Well casings that have been lifted once deal with any conductors that turn out to have been only can still be used to support the spreader beam by tying them partially severed.” to other casings in the array to ensure they remain vertical under load.

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It is possible to waste days if you have to go back to deal with any conductors that turn out to have been only partially severed

High-pressure solutions The use of subsea facilities tied back to existing infrastructure continues apace in the North Sea. Subsea-based solutions are often considerably more economic than the alternatives, particularly when relatively few subsea Christmas trees are required for a development.

Subsea wells are typically drilled and completed from semisubmersible drilling units using the rig’s subsea blowout preventer (BOP) and drilling riser system. This offers full-bore 18¾-in access to the subsea hardware. Typically, jackup drilling units do not utilise subsea BOPs or drilling risers, or offer such full-bore access to the subsea hardware. Consequently, drilling and completing traditional subsea wells from jackup units can pose unique challenges and difficulties. However, there is a solution – the Claxton high-pressure jackup drilling riser (HPJDR) system.

The Claxton HPJDR system enables traditional subsea wells to be drilled and completed from a jackup unit providing the rig has a full-bore 18¾-in surface BOP system. Claxton offers a full system service, from analysis and specification of the system, through fabrication, equipment rental and writing of operational procedures, for deployment and recovery of the HPJDR system. Full structural, fatigue and vortex-induced-vibration (VIV) assessments can be carried out as necessary, although VIV is rarely an issue because of the tensions employed and the riser system’s diameter.

A typical HPJDR configuration has an 18¾-in hydraulic wellhead connector at the lower end that is suitable for connection to the client’s subsea wellhead system. The riser comprises 40-ft pipe joints of a suitable specification joined by conventional (typically threaded) connectors, with a tension joint and a crossover joint at the upper end. The crossover joint provides the connection to the surface BOP on the rig, and the tension joint interfaces with the rig’s tensioning system, which applies an upward load to the riser system so that it will remain sufficiently stable.

The inside diameter of the HPJDR allows full-bore drift throughout the entire system and into the subsea wellhead, as long as the jackup has an 18¾-in high-pressure surface BOP. This enables traditional 18¾-in subsea wellheads and Christmas trees to be used. Drilling and completion are possible in the same way as if a semisubersible unit had been used.

The Claxton HPJDR system opens up the possibility of using traditional subsea systems from jackups as well as from semisubmersibles.

Four clients have successfully used this approach over the last five years at water depths to 100 m in the southern and central areas of the North Sea. The increasing use of deepwater jackups for development drilling, along with the functionality of the Claxton HPJDR system, offers opportunities to costeffectively drill and complete conventional subsea wells in harsh environments such as the North Sea from jackup as well as semisubmersible units.

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A novel riser design from Claxton provides operators with a greater choice of rigs when it comes to drilling subsea wells.

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Monitoring with integrity Operators have been installing deepwater risers in the Gulf of Mexico and off the coasts of West Africa and Brazil for over 10 years now. Steve Hatton, riser specialist, 2H Offshore, has been involved in providing these critical structures from the beginning and, despite participating in many prominent jointindustry research projects, he freely admits that he still has much to learn.

One of the fundamental advantages of riser monitoring is that it reveals whether the assumptions made during the riser design process were valid. This check is easily carried out by comparing the responses measured at selected places on the structure with the predictions from the original riser analysis.

The operator will hope to see a negative ‘delta’ (actual results lower than predicted) to confirm the validity of the design.

“The more you understand about risers, the more you realise what you do not know,” he says. “They are fatigue driven and their structural responses are highly complex. In my opinion, riser design remains one of the most interesting and challenging areas of offshore engineering there is.”

“Giving the operator confidence that his riser was up to the task was the first aim of most riser monitoring exercises,” says Hatton. “The information also provided valuable input to the design of the next structure. But what operators really want these days is information that enables them to manage their immediate operations and maintenance more effectively – they are seeking input to risk-based integrity management programmes. For this application, you really need to know the peak stresses in the riser and the fatigue life at the most critical locations along its length.

Riser failure is simply not an option. As well as causing massive health, safety and environmental issues, failure inevitably results in lost production and a costly replacement exercise. For these reasons, the industry has tended to adopt a conservative approach to riser design.

Operators were slow to embrace the notion of riser monitoring, as Hatton explains: “Monitoring equipment used to be expensive and unreliable. Also, you often had to strip any protective coatings applied to the riser to fit the sensors, and you could not discount the possibility of the equipment actually degrading the response of the structure. In addition there is the chance of the monitoring system hindering installation of the riser, so you can see why people tried to avoid following this route.”

So what has changed to cause the interest in riser monitoring among operators over the last couple of years? According to Hatton, a series of things: advances in monitoring technology that have reduced the cost and improved the reliability of the available systems; demonstration projects that have proved monitoring is capable of highlighting genuine operational threats; concerns over the severity of the hurricanes in the Gulf of Mexico; and, not least, the current industry focus on risk-based integrity management.

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Instrumentation is obviously a prime ingredient of any monitoring system – you must have robust, reliable and accurate sensors capable of measuring the motion of the riser or the strain induced in it. But just as important is knowing where to locate the sensors and how to interpret the mass of data they generate.

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“A multidisciplinary approach is essential,” says Hatton.

“As well as having knowledge of the instrumentation, you need skills in data sampling, transmission and storage, and signal processing. You also require a deep understanding of riser structural responses, plus experience of riser design engineering, construction, installation and operation.

“Unfortunately, predetermining these critical locations is not easy, as they are affected by the installation process and may shift over time with operational changes and vessel/platform movement. In any case, you might not have access to the critical regions owing to the existence of riser guides, rollers, etc. If you add the fact that the stress gradients on a riser can often be large, you can see it is not hard to miss the areas of peak stress on a structure, even if you install a high density of gauges in the potential problem areas.”

2H has overcome this challenge by a sophisticated back analysis process in which response data measured at a series of discrete locations along the riser is fed into an analysis package to compute the global structural response of the riser. It is then possible to calculate the fatigue properties of the riser along its entire length and to highlight the precise points where problems are most likely to develop.

2H’s monitoring know-how, experience and development record made it a strong candidate to support BP when the operator decided in 2005 to set up an integrity management system to cover all its risers in the Gulf of Mexico, thought to be the first exercise of this kind in the world.

The riser integrity management process follows established risk-based principles and starts with the identification of potential failure modes and threats. Each of these is assessed in terms of the probability of it occurring and its consequences. From this assessment, the operator assigns an overall criticality to each potential failure event. The operator then estimates how much confidence there is in the assessment by, for example, judging how well the failure mode is understood, how predictable it is and how effective the chosen riser monitoring techniques are at detecting

the threat. By combining the criticality analysis with the confidence ratings, the operator is able to formulate a riskbased inspection and monitoring plan.

Hatton stresses the value of starting the risk assessment process early. “Ideally, you need to carry out the risk assessment during the design and construction phase.

Engineering input and information about the inevitable construction-led design changes are readily available then, and the people involved have not yet moved on to the next project.”

“The effort we have made to bring these skills together at 2H has paid dividends, not only in commercial terms but also from the viewpoint of improving the industry’s understanding of these complex structures,” concludes Hatton. “Having been consumed by this subject for the past 12 years, I am probably a little biased; however, I believe that riser design and monitoring provide the key to field developments in ultradeep water and, therefore, will have an impact on the future of the offshore oil industry itself.”

STEVE HATTON, 2H OFFSHORE

The more you understand about risers, the more you realise what you do not know

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Riser monitoring has come a long way since 1994, the year 2H installed its first system; this is due in large part to the many technical advances made in electronics, data management and signal processing. But it has also been important, certainly in Hatton’s opinion, to integrate knowledge in these areas with expertise in riser analysis and engineering.

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Simple solution Claxton Engineering enjoys a fine reputation for coming up with highly effective engineering solutions, often within very tight deadlines. The company is strongly inclined towards practical and reliable designs, but at the same time is not afraid to challenge conventional thinking.

You look at some solutions and they are so elegant, so simple, that you wonder why nobody has thought of them before.

Claxton’s retractable riser guide arms are a perfect example of this. The retractable arms enable drilling or workover risers to be run and landed safely and reliably on subsea wells; they also save rig time and render the whole process reasonably independent of the weather.

But any normal guide arms would do this – what is the advantage of the arms being retractable? The problem is that to fit over the standard guide posts fitted to subsea wells, the fixed arms need to extend about 6 ft from the riser, and so they are incapable of passing through the rotary table of even the biggest jackup drilling rigs. It is therefore normal practice to fit the arms to the riser below the rig floor – maybe on the Texas deck, if the rig has one. But this is not always easy owing to limited access or restrictions on the span of the structure to be fitted. Indeed, on modern jackups the presence of pollution containment units below the rig floor makes the task almost impossible. Then it is sometimes necessary to feed the riser into the rig from a boat stationed below it – with obvious economic and operational implications.

It takes a lateral thinker to challenge the basic assumptions in life – in this case that the guide arms cannot pass through the rotary table. Dannie Claxton is one such thinker. He says, “It was ConocoPhillips who asked us to re-evaluate this problem, and when we got talking it just seemed such an obvious solution to make the arms retractable, so avoiding having to undertake any work at all below the rig floor. The design is relatively straightforward, and we were able to engineer the guide arms, manufacture them and fit them to the stress joint on ConocoPhillips’ chosen riser in the three weeks before the operator proposed deploying it in the North Sea.” In fact, because of a late change of plan, the operator was able to give Claxton more time to fine-tune the design.

The arms were quickly fitted with more powerful hydraulic cylinders than initially specified, and the design of the guide cones that engage with the Regan connector on the guide post was improved. The riser has now been successfully deployed from the Maersk Inspirer drilling rig to workover the ConocoPhillips M08 subsea well, still in the North Sea. Doubtless, the North Sea has seen far more impressive feats of engineering; however, there cannot be many that possess the payback potential of this relatively modest but genuine engineering solution.

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When extended, the retractable guide arms perform in exactly the same manner as their conventional counterparts. But hinges fitted with hydraulic actuators mean the arms can be pulled tightly into the sides of the riser to allow the whole structure to pass easily through the rig’s rotary table.

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DANNIE CLAXTON: LATERAL THINKER

Efficient permanent moorings

The new guidelines require most rigs to have 12, rather than 8, mooring lines. InterMoor’s suction embedded plate anchors (SEPLA), which are cost-effective to manufacture and install, offer increased efficiency at this busy time.

In September 2006, SEPLAs were used to anchor ATP Oil & Gas Corporation’s floating production unit in Mississippi Canyon 711 (formerly Gomez field), Gulf of Mexico. This is their first use as part of a permanent mooring system, although they have been used extensively by companies such as BP, ExxonMobil and Chevron to anchor mobile offshore drilling units in the Gulf of Mexico and off West Africa.

To minimise costs, ATP has converted a semi-submersible drilling rig, the Rowan Midland, to serve as a floating production unit for the expected 10-year life of the field. InterMoor designed and provided a 12-point, taut-leg mooring system using polyester rope and SEPLAs for the unit, which lies in over 920 m of water. The polyester rope costs less and offers better performance than traditional steel cantenary systems, and the SEPLAs are a cost-effective alternative to traditional suction embedded anchors.

SEPLAs are a novel combination of two proven anchoring concepts: suction and plate anchors. The SEPLA system

uses a suction follower (similar to a suction anchor) to embed a comparatively small plate anchor relatively deep into the seabed where the more compacted soil has greater retaining capacity.

To ensure their suitability for permanent moorings, the components of the system were subjected to break tests, and each leg was proof loaded in the field to at least 80% of the maximum intact 100-year hurricane load.

Once an anchor is embedded, the suction follower is retracted and used to install additional plate anchors, which makes the system economic to manufacture. Each SEPLA actually uses only a quarter to a third of the steel required for an equivalent suction anchor.

Because the suction follower is returned to surface, installing each SEPLA can take longer than required for conventional suction anchors. However, a typical anchor-handling boat has the deck capacity for just two suction anchors, so must return to shore six times to install the 12 anchors required by most units. In contrast, SEPLAs are about four times smaller than suction anchors, so more anchors can be carried in one trip.

Half the number of trips were required to install SEPLAs for Rowan Midland than would have been required for suction anchors.

In fact, the costs for SEPLAs are a third to half those of using suction anchors, and the installation can largely be performed off the critical path. As rates for chartering anchor-handling vessels are at a record high, fewer trips and reduced anchormanufacturing costs are welcome benefits.

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Last year in the Gulf of Mexico, 15 rigs were set adrift by a succession of powerful hurricanes. These events prompted the US government’s Minerals Management Service and the United States Coast Guard to work with the oil and gas industry to produce new rig mooring guidelines for the Gulf of Mexico. As a result, demand for anchor-handling boats has never been so high.

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Minding the

gap

The gap between seabed and surface is where you will encounter many of the most complex and demanding oilfield challenges.

With our technology we manage this gap.

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Acteon combines the skills and experience of 11 leading companies to deliver high-quality solutions.

3

linking seabed to surface

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