Working together on A chAllenging PetrobrAs

Project

AquAtic’s elegAnt solution for techniP

looking At the finAnces: the oil council’s tAke on

oilfield services finAncing

the Acteon customer mAgAzinev12 03–13

04 Deepwater challenges for conDuctor installation07 BuilDing capacity for Deepwater operations

08 fuelling oilfielD services’ financing10 Delivering a clearer picture of the seaBeD

12 fsou mooring anD riser system upgraDe14 fresh thinking for lifting anD hanDling equipment

16 monitoring Developments in the gulf of mexico18 the challenge of lowering a live gas pipeline

20 in Deep anD unDer pressure22 finDing the right comBination

in this issue

Paul AlcockT: +44 1603 227019

F: +44 1603 774175W: www.acteon.com

E: paul.alcock@acteon.com© Acteon Group Ltd 2013

for further information, please contact

High-quality service will always be at the heart of Acteon’s business philosophy. The previous issue of S2S focused on the vital importance of service quality in subsea services and, in this issue we examine the factors that pose a challenge to effective service delivery. Some of the key topics include the emergence of new technologies, changing business circumstances, unexpected field conditions and the pressures associated with short project time frames. To offer outstanding service in the face of these challenges, Acteon companies have to maintain a clear focus on their goals and missions.

Adapting to change can be the key to success. Experience at the Papa Terra oilfield, offshore Brazil (page 4), shows how major technical obstacles can be overcome through collaboration.

In a difficult economic climate, strong financial backing is a key aspect of business success. Ross Campbell, chief executive officer of The Oil Council, examines the financial landscape within subsea services and the sector’s relationship with investors (page 8).

Having confidence in your abilities means you can take on the most demanding challenges. In Indonesia, OIS, NCS Survey and CAPE have completed a unique lowering operation for a live gas pipeline (page 18).

The challenges we face are complex and varied, but, by working together, we know we can find the best solutions.

by working together, we know we can find the best solutions.”

04 Deepwater challenges for conDuctor installation07 BuilDing capacity for Deepwater operations

08 fuelling oilfielD services’ financing10 Delivering a clearer picture of the seaBeD

12 fsou mooring anD riser system upgraDe14 fresh thinking for lifting anD hanDling equipment

16 monitoring Developments in the gulf of mexico18 the challenge of lowering a live gas pipeline

20 in Deep anD unDer pressure22 finDing the right comBination

comment

RICHARD HIGHAMGROUP CHIEF EXECUTIVE, ACTEON

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“

deePWAter chAllenges for conductor installation OVERCOmING OBSTACLES THROUGH GROUP COLLABORATION

Working together enAbled intermoor, menck, 2h offshore, ncs survey, seAtronics And clAxton

to overcome A series of technicAl issues And deliver the Project At A reduced cost And Within

the required time frAme.”

“4

Several Acteon companies have pooled their expertise and experience to deliver a highly challenging conductor installation project for the Papa Terra oilfield in 1200-m water depths in the southern Campos basin, Brazil. Petrobras operates the Papa Terra concession and has a 62.5% interest; Chevron holds the remaining 37.5%.

In march 2010, Petrobras challenged Intermoor do Brasil to install drilling and production conductors with a tolerance of less than 30 cm off centre using its patented cost-saving conductor installation methodology.

The company was to install the conductors before the arrival of the drilling rig. The key benefits of pre-installation are that it removes this task from the critical field development path and eliminates it from the rig procedures so that lower-cost platforms can be utilised to support the offshore installation. The operator does not have to pay a drilling spread rate for this type of operation, so can realise substantial cost savings.

Intermoor was awarded a contract to manufacture 17 conductors of 36-in. outside diameter, 1½-in. wall thickness and 59-m length, and to install 15 of them in 365 contract days. The pipe supplier was to use 160 of these days to fabricate the pipes in morgan City, Louisiana, USA, and deliver them. The challenge was further complicated by the turnkey nature of the project: design, fabrication and installation of the conductors to strict inclination, position and height tolerances.

João Ruiz, subsea manager, Intermoor do Brasil, highlighted the importance of Acteon companies working together on this project. “Working together enabled Intermoor, mENCK, 2H Offshore, NCS Survey, Seatronics and Claxton to overcome a series of technical issues and deliver a seamless solution for the project at a reduced cost and within the required time frame.”

Acteon’s involvement began with Intermoor and mENCK performing a high-level installation review focusing on the impact driving of the single-piece conductors. From the soil data provided by the client, it was decided that using the mENCK mHU 270T deepwater hammer spread (mHU 270T mHP DWS) would provide sufficient installation contingency while ensuring structural integrity and minimum induced fatigue to the conductor system.

Acteon’s involvement continued with 2H Offshore performing the engineering critical assessment (ECA), an analysis based on fracture mechanics principles, which Petrobras reviewed and approved.

milton Pereira, project manager, Intermoor do Brasil, said that one of the main challenges his team faced was getting the welding qualification procedures required approved to DNV standards, which are normally used for the welding qualification of rigid risers. “In addition, the allowable flaw sizes were exceedingly tight,” he says. “These were defined by the ECA and based on critical operational lifetime loads to be induced on the conductors.”

Intermoor manufactured all 17 of the 36-in. conductors and 5 guide templates at its morgan City facility to the DNV-OS-F101 standard and the client’s specification, whereby the ECA determined whether a given flaw was safe from brittle fracture, fatigue, creep or plastic collapse under the specified installation and service life loads.

Pereira explains: “Intermoor inspected all the conductor welds using X-ray, magnetic particle and automated ultrasonic testing (AUT). AUT is a very sensitive non-destructive testing system and required an equipment configuration specifically designed for this project because of the J-bevel joint profile, the 1½-in. pipe thickness and the allowable flaw sizes, as defined by the ECA study.”

After the 17 conductors and 5 templates had been fabricated, inspected and approved in morgan City, Intermoor started the high-level logistics process to transport them safely to Rio de Janeiro, Brazil, using barges for the inland transit from morgan City to Houston followed by a vessel to Rio de Janeiro. This was equipped with two heavy cranes capable of loading the conductors and templates in Houston and offloading them directly onto barges in Brazil. The offloading was performed in two days after the installation vessel arrived and without incident.

Intermoor’s work offshore commenced in the first quarter of 2012 with template installation using a chartered installation vessel equipped with a 250-t offshore crane with active heave compensation, as one of the main challenges on location concerned the positioning and installation tolerances. These were within 30 cm of the conductor target position, and at less than 1° inclination and ±10-cm stick-up.

For this purpose, Intermoor designed five individual templates in cooperation with Claxton. Each 35-t template measured 24 × 4.5 × 1.5 m and would guide three conductors. The templates were needed in a very short delivery time and their manufacturing required an extraordinary amount of collaboration to ensure that the installation measurements would be accurate. The work included onshore 3D modelling of the templates to provide models for use offshore during quality assurance and control. A further challenge was to devise an appropriate procedure for the vessel to lay the templates in the correct position with minimal iteration.

Acteon’s involvement continued with Intermoor and Seatronics providing survey equipment for the long-baseline survey array, which helped in the control and positioning of the templates. Long-baseline surveyors from NCS Survey worked with Intermoor surveyors during the offshore phase.

To install the conductors, Intermoor applied a technique that had only been used once before in deep water: launching the conductors from an auxiliary barge, the Muliceiro-X, which also transported them to the Papa Terra site, and using special tools. The only other project to use this technique so far was an Intermoor project for Shell–Petrobras–ONGC in the Shell-operated BC-10 field in Brazil’s Campos basin in 2008.

www.acteon.com

>>>5

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The Muliceiro-X was modified by the installation of five rails. Two rails served as the track for a special shuttle system to elevate and transport each conductor to the barge’s side. The other three rails served to support the conductors and to sea fasten them. The conductors, connected by a towline to the installation vessel, were side launched from the barge using the shuttle system, which was operated by on-board Intermoor personnel.

mobilising the mENCK mHU 270T mHP DWS onto the installation vessel was another challenge owing to the limited deck space. mENCK’s detailed operational procedures for use offshore and the strategic layout of its equipment helped to mitigate the challenges. The company also designed and fabricated a winch frame for the umbilical winch and a chute to deploy the umbilical used to remotely operate the hammer.

Once the Muliceiro-X arrived on location, the five templates being already in position on the seabed, the installation vessel came alongside and began the conductor launching sequence. All 15 conductors were batch set in one field visit, as michael O’Driscoll, project manager, Intermoor Inc., explains: “Instead of putting one conductor in the mud and then hammering it with the mENCK hammer, we batch set all the conductors. This meant we had all the conductors in the mud in a stable configuration but not yet driven to grade. This helped to minimise the outboard handling of the mENCK hammer. The fewer times you need to handle an 80-t piece of equipment offshore the better!”

He continues, “By batch setting in this way, we only had to launch the hammer once; it drove all 15 conductors and then it was recovered. That was its total use. This approach saved a lot of time offshore and minimised the risks.”

Intermoor used a special suction-to-stability head tool to handle the conductors and safely launch them from the barge into a stable vertical underwater position. This exceptional engineered tool also enables suction to be used to increase the penetration of the conductors beyond their self-weight penetration depths to the minimum allowable depth. Generally, the suction-to-stability heads can increase the penetration depth by up to 5 m.

Installation was completed in April 2012 after template removal and the final as-laid survey. A survey tool specially designed for the final as-laid survey was positioned at the top of each conductor. These confirmed that all the conductors were in their final positions.

“This was a major engineering, procurement, installation and commissioning project that we successfully completed from the financial, logistics, operational, schedule, technical and, particularly, quality, health, safety and environmental aspects,” concludes Ruiz.

>>>

AN ELEGANT SOLUTION FOR HIGH HOLD-BACK TENSION REqUIREmENTS

BUILDING CAPACITy FOR DEEPWATER

OPERATIONS

7www.aquatic.co.uk

Offshore operations are becoming increasingly demanding, with new projects being conducted in deeper waters and more diverse or exposed locations. The deepwater environment poses a special challenge for the installation of flexibles, as the hold-back tensions generated there are significantly greater than those encountered in shallower installations.

Technip Norge AS approached Aquatic in may 2011 seeking to hire a tracked tensioner spread with 85-te hold-back tension capacity to cope with calculated dynamic loads. When it received the initial request, Aquatic did not have a tensioner system with sufficient capacity to satisfy this requirement. As a catalyst to adapting systems to meet the requirements of the deepwater flexibles installation market, the company decided to develop a solution for first use on this particular Technip Norge project.

Drawing on more than 35 years’ experience of the offshore installation of flexibles, Aquatic’s specialist in-house engineering team promptly developed a solution for Technip Norge by combining two 50-te-rated tracked tensioners with a central management and control system.

The Aquatic team adapted a new-build 50-te tensioner called the AqTT-10E-50 DUAL, which can be used either individually or paired with another 50-te-rated tensioner to achieve almost double the line-pull capacity of a single tensioner.

The two tensioner systems, which are essentially identical in specification, are placed in-series and synchronised centrally via an electronic management system. Given the efficiencies of the individual tensioner system, the maximum line-pull rating for the dual system is equivalent to 96 te. A single control cabin offers central manipulation and monitoring of the system. The two in-line four-track tensioners provide a total contact length of 7 m with an applicable product, so sensitive product grip settings can be accommodated.

The central feature of the new dual-tensioner system is a specially designed hydraulic manifold that enables the two machines to work in tandem. The dual-tensioner system is designed to operate from a single electrohydraulic power pack, which provides hydraulic power to

the tensioners via the manifold. The manifold regulates and diverts the hydraulic fluid into two equal streams so that both tensioners operate at exactly the same flow rate and pressure, thereby ensuring a fully balanced operation.

The key to providing effective engineering solutions is to understand exactly what customers and the market require and to work with the objective of ensuring that a system is developed to meet the conditions of a specific project. The collaboration with Technip Norge included gaining detailed understanding of its needs and cooperation in testing the new dual-tensioner system at Aquatic’s operational facility in Peterhead, UK, before its mobilisation onto the Technip vessel.

During 2012, the system was used successfully on several umbilical and riser installation jobs, including projects in the Goliat, Hyme and Vigdis developments in the Norwegian sector of the North Sea, and the Rochelle development in the UK North Sea for Technip UK. Aquatic’s second 96-te dual-tensioner spread came online in February 2013.

Craig Evans, Aquatic proposals engineer, states, “modularity is a vital consideration for any offshore equipment spread. The modular nature of the AqTT-10E-50 DUAL system makes it simple for us to strip it down into component pieces and stow it inside a standard container for transportation by road or sea.

“The ability to transport our equipment in standard (12-m) shipping containers means that it can be installed on relatively small vessels of opportunity that operate from more economical quayside locations. This enables faster mobilisation and demobilisation, and provides an ideal solution to the logistics challenges and cost issues faced by operators.

“In part, Aquatic’s reputation has grown because it can help customers to minimise vessel downtime, which reduces project costs for them. We have received further requests for similar work, including possible floating production, storage and offloading facility mooring line work using synthetic fibre ropes.”

fuelling oilfielD services’ financing ross campBell, chief executive officer, the oil council, DescriBes the current investment anD finance lanDscape in the oilfielD services sector.

The recent performances of companies in the oilfield services sector have, on the whole, been good for investors. many so-called small- and mid-cap services companies have enjoyed stellar performances across global stock exchanges and doubled or tripled their investment values over the past 24–36 months.

During 2009–2011, the market also enjoyed a wave of consolidations in Europe’s services sector. This was driven by the aggressive growth strategies of the larger service companies and energy conglomerates, including Schlumberger and General Electric. These acquisitions helped to boost the flow of deals for banks and advisers, and raise the visibility of the oilfield services sector, which prompted wider investor interest in the energy sector.

However, as a consequence of those deals, there are fewer oilfield services companies in Europe offering attractive growth stories for fund managers to invest in. Normally, this would not cause too many ripples in the sector, but, in 2012, merger and acquisition deal flow decreased significantly and only a handful of oilfield service companies made initial public offerings on exchanges outside North America. Deals are becoming harder to find.

Currently, the financial community is reviewing and recalibrating the companies that emerged from this wave of consolidation. As banks’ profits have an obvious positive correlation to the flow of deals and the number and size of transactions they can make, a perceived lack of opportunities in the oilfield services sector over the past 12 months has made the sector less appealing in terms of bank resourcing and servicing.

The limited awareness about oilfield services, as defined by the few visible players, is both a hindrance and an opportunity; it holds back wider market understanding, yet creates an opportunity for clearer definition of the sector and its key constituents, which includes subsea services.

The hesitancy surrounding investment in oilfield services is partly because some investors do not understand how to accurately determine the risks involved in the sector and, consequently, how to place them in a portfolio.

Outside North America, oilfield service companies sometimes find it difficult to attract the right levels of investor awareness, largely because

there are very few financial institutions in Europe, the middle East and Africa (EmEA) that completely understand the oilfield services sector in comparison with the exploration and production sector.

There are simply not enough specialist buy or sell-side services analysts in the EmEA region. There is only a relatively small group of highly skilled experts, enough to cover all the recognised services companies but not enough to promote the sector effectively across EmEA and reaffirm the value of its stocks. The sector does not have enough champions in the financial sector.

understAnding the mArketThe most important part of making any investment decision is having a clear understanding of the market. The Oil Council assists by bringing investors and companies together, and helping to broker oil and gas sector relationships on a global basis.

Businesses thrive on capital investment. Injecting finance at the right time powers commercial growth and enables diversification. Organisations sometimes need guidance in their search for business partners and financiers. The Oil Council offers a global platform for companies to gain access to sound commercial advice, vital capital and crucial business connections. We do not offer insights into the merits of a particular technology, operational management or geopolitical advice. Our focus is on helping companies to find strategic investment and business solutions, and to choose effective partners.

The processes surrounding a major investment programme or a change of ownership, such as Acteon has recently experienced, lead to closer interactions with banks and other financial institutions. Part of this has to be about promoting better understanding of subsea services, as distinct from subsea construction or subsea equipment provision, because it helps investors to understand and evaluate the companies operating in the sector.

By engaging effectively with the financial and investment communities, companies like Acteon can explain their role and better define subsea services. This gives investors a clearer understanding of the business models that subsea services companies adopt. It helps them to invest with confidence in the sector, as they understand the risks, the timeline of a return on their investment and, most importantly, that they are

8

buying into a long-term value proposition that paves the way for significant upside in the company and, ultimately, the performance of their investment portfolio.

Some banks and brokers still struggle to differentiate the investment stories for oilfield services from those in the exploration and production sector because they lack knowledge and understanding about this industry sector. Of course all banks and brokers cannot be all things to all men.

There were a few exceptions in 2012 to the generally strong and reliable stock performance of oilfield service companies. Last year, a handful of companies issued unexpected profit warnings and their share prices plunged as much as 60% from their year highs. Consequently, some investors shied away from the sector.

Without enough specialist analysts to make sense of what are unique company-specific events, one or two pieces of bad news can overshadow the underlying strength of the sector. Bad news stories seem to linger in the memory, which can prompt investors to treat oilfield service companies that offer good dividends and a relatively stable revenue stream as they would much higher risk/return investments in exploration and production.

Private equity companies, however, have been very active over the past 24–36 months and their influence is still being felt in the oilfield services sector. European private equity has grown substantially in recent years, but little has been invested in international exploration and production. The pattern of investment we are seeing suggests that private equity has a good understanding of the oilfield services sector and can find opportunities not always apparent to public institutions. We only see their interest and allocation of dry powder* in the sector increasing.

To attract more investors to the sector, especially those with larger cheque books, services companies will have to boost cost control and cost-effectiveness, and deliver business performance without scaring the market. Existing and potential investors need to see commercial stability to increase confidence in their investment. Investors are looking for companies and individuals that push boundaries, inspire others and achieve growth in challenging markets.

New revenue streams will bolster confidence and, with the continuing rise of national oil companies, we see this as a key avenue to new

growth for many services companies. As national oil companies have about 70% of global resource holdings, the international oil companies are facing a squeeze to gain access. There are vast opportunities for the oilfield services sector here because of the significant variability in the extent to which national oil companies adopt new technology and in the depth of relationships with their suppliers.

Other performance factors key to growth and renewed investor interest in 2013 include good management, consistent performance, good revenue streams and accurate forecasting for operations in established and emerging markets.

Acteon was a great example of a company performing well in 2012. Consequently, it was nominated for a 2012 Annual Award of Excellence in our category for Oilfield Services Company of the year, but was unfortunately beaten by Petrofac. In making these nominations, our judging panel of 55 industry experts assessed financial and operational performance, the strength of industry partnerships and market reputation, corporate governance and investor relations. All these aspects are crucial to success in the modern oilfield services market and for attracting investment.

Service companies that can achieve these targets and goals and ensure that they have a diverse customer base should be able to attract the investment they require.

In our view, 2013 will be relatively low key in terms of new investment and growth in oilfield services. Capital expenditure in exploration and production has been rising year on year for the past 10 years and the oilfield service sector has grown with it. This year, we anticipate another small rise, which is good news for the services sector, but, with rising costs, we see this margin and investment as having neither negative nor positive effects on growth for most. However, we still see strong dividends and order books being highlighted by many companies; the greatest upside is being seen on those that can remain innovative. Consequently, The Oil Council remains bullish on the sector and committed to helping it achieve new growth in 2013 and in the years to come.

*The amount of capital that has been committed but remains uncalled to private equity funds

outside north America, oilfield service companies sometimes find it difficult to attract the right levels of investor awareness,” says ross campbell (left), chief executive officer of the oil council.”

“

9www.oilcouncil.com

10

In September 2012, BP asked NCS Survey to conduct a survey to support moving a jackup accommodation unit alongside the West Sole Charlie platform in the Southern North Sea. BP has since transferred owner- and operatorship of its Southern North Sea assets to Perenco.

A detailed investigation of the seabed was required to assess its suitability to support a jackup rig alongside the West Sole Charlie platform, and examine the site for the jackup rig and along the anchor corridors. Jackup legs cannot be positioned where there is a risk of debris puncturing the spud can or an uneven seabed that could result in the rig toppling.

The survey utilised NCS Survey’s Gavia autonomous underwater vehicle (AUV), which is equipped with high-resolution side scan sonar and multibeam echo sounder data acquisition systems and a precise Doppler-aided inertial navigation system to provide the best possible images of the seabed.

The aims of the surveying operation, which covered an area of approximately 2 km2, were to identify and measure any seabed debris or features that might cause problems during anchoring operations; reveal the shape and depth of any seabed depressions; and locate any evidence of gas seeping from the seabed or wells within the area.

Dick Whiting, senior project manager, NCS Survey, explains: “The initial approach BP considered for the seabed survey was a conventional survey vessel. However, the presence of such a vessel with a towing spread would significantly affect the local fishing community during

the shellfish season. As a result, BP looked into using alternative AUV technology to reduce the footprint of the survey and, therefore, its impact on the local fishing industry.

The flexibility of the AUV option is that the system can be launched from and retrieved to most of the vessels that operate in the North Sea. Unlike many larger survey companies, NCS Survey does not operate its own vessels but turns available vessels into survey vessels for the duration of a job. This is the ideal model for quick mobilisation on smaller surveys.

The AUV option provides a cost-effective option when compared with either remotely operated vehicle operations or a topside multibeam echo sounder survey with a towed side scan sonar. In addition, using an AUV avoids the potential safety issues of operating towed or tethered vehicles close to an existing platform.

Whiting says, “The operation mobilised out of Great yarmouth, UK, and lasted nine days. Operations in the North Sea in October can be challenging with high wind speeds and unfavourable sea states. Indeed, a significant proportion of this period was spent waiting on weather. However, the surveying work was completed efficiently in the two operational days available.”

Processing started on board the vessel during weather downtime and NCS Survey was able to supply initial images from the two days of surveying 24 hours after each day. There are many linear features close to the east side of the platform (possibly scaffolding poles) and

Delivering a cleArer Picture of the seaBeDRAPID TURNAROUND SURVEy DELIVERS OUTSTANDING ImAGE qUALITy

11

it was thought that these might interact with the proposed spud can locations. However, no obstructions were found within the survey area to affect the installation of a jackup rig.

NCS Survey delivered an informative draft report to BP approximately a week after the surveying operation concluded. This is an unusually quick turnaround: the standard for seabed surveys of this kind can be four to six weeks. Whiting says, “This fast delivery reflects the investment we have made in processing capabilities. For example, in 2009, NCS Survey purchased the survey operations department of Sonar Research and Development, a company specialising in developing 3D visualisation software and multibeam echo sounder processing technology.”

However, the fast turnaround was not at the expense of image quality, as shown in Figure 1.

In seabed surveying, as in many aspects of the oil and gas industry, customers want a responsive and flexible service that can be tailored to their specific requirements. According to Whiting, “NCS Survey is a fairly small, but rapidly growing, company, so we have good relationships with our oil company clients and often work with them to extend our capabilities to answer a specific need. This may include funding to improve or develop a product and push the boundaries of what is possible. Our development processes are driven by customers’ needs.”

One way to meet their needs is by operating a portable and modular system. In 2010, NCS Survey shipped a Gavia AUV to Argentina:

the whole system was packed into a small shipping container. The components of the Gavia can be stripped down to nothing longer than 0.5 m. It is essentially a lightweight, portable platform for various instruments. This modularity means that it can be deployed anywhere in the world within a matter of days.

It also means that NCS Survey can tailor the Gavia to each job. The company can swap modules in and out to give a customer exactly the combination they require in terms of sensors and data gathering options. This modularity also means that the vehicle’s capabilities can be added to and extended almost indefinitely. New sensor modules are under development all the time.

Seabed surveys are a crucial part of oilfield operations, particularly when operators are looking to add new infrastructure to existing field locations, but they have a fixed shelf life. Offshore operators have to repeat them when they plan significant changes to existing developments. A survey’s shelf life is typically three to six months for insurance purposes. Once that shelf life has expired, the survey is no longer valid and a new survey must recheck for the presence of debris in the area. AUVs provide a very cost-effective method for completing this work.

ncs survey delivered a comprehensive draft report to bP approximately a week after the surveying operation concluded. this is an unusually quick turnaround: the standard for seabed surveys of this kind can be four to six weeks.”

“

www.ncs-survey.com

 figure 1: possible scaffold poles close to the platform’s legs.

fsou MoorinG and risEr sYstEM uPGradECOmBINED EFFORT AT LUFENG FIELD BRINGS PROJECT IN AHEAD OF SCHEDULE

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our extensive experience in providing back-of-the-boat solutions was crucial for this project. We developed procedures that enabled simultaneous operations to be performed offshore while working with divers, remotely operated vehicles and the anchor-handling vessel close to the buoy turret-mooring system.”

“a dogbox (above left) and a winch adapter (above right) helped to protect the jacketed spiral strand wires of the moorings.

COmBINED EFFORT AT LUFENG FIELD BRINGS PROJECT IN AHEAD OF SCHEDULE

In August 2012, Intermoor and Offshore Installation Services (OIS) completed a multimillion-dollar project for Chinese installation contractor China Offshore Oil Engineering Co. Ltd (COOEC), a subsidiary of CNOOC Ltd. The Lufeng field’s Nanhai Sheng Kai floating storage and offloading unit (FSOU) mooring and relocation project was undertaken in the South China Sea, 370 km offshore Hong Kong, over six months. This was Acteon’s first major project in China and it was completed on schedule, within budget and with no lost-time incidents.

The Nanhai Sheng Kai FSOU was moored with a single point mooring in a water depth of 142 m using a disconnectable buoy turret-mooring system. The existing mooring system at Well LF 13-1 entered service in 1992 and was operational far beyond its design life of 12 years. The system was showing signs of deterioration and corrosion.

The field operator, CNOOC, planned to extend the service life of the FSOU for another 15 years by refurbishing it and upgrading and relocating its mooring system to Well LF 13-2. This would enable production from Lufeng field to continue in a safe and reliable manner, and would also support future field development.

The project team developed detailed installation procedures before each phase of the offshore work. The overall work scope for the project involved

� the temporary replacement of the buoy turret-mooring system at Well LF 13-1 to accommodate the Nanhai Kai Tuo FSOU and enable continuing production from the field throughout the project

� project management, engineering, procurement and installation of a new buoy turret-mooring system for the upgraded Nanhai Sheng Kai FSOU at Well LF 13-2

� installing a new 8-in. static flow line (1687 m) and an 8-in. dynamic riser (412 m) between the buoy turret-mooring system and the LF 13-2 wellhead platform.

Intermoor and OIS had just eight weeks to organise and mobilise the joint team to China so the project could start on schedule. The ability to put project management solutions in place for complex projects at very short notice is increasingly important in an industry that demands a rapid response to support global operations. The solution that Intermoor and OIS had to deliver included comprehensive in-country, on- and offshore project management for controlling the offshore installation, vessel management, procurement and fabrication activities, and all the quality, health, safety and environmental support.

Planning was complicated by the lack availability of an installation vessel in South East Asia, which meant Intermoor had to bring the Maersk Attender from the UK. In terms of project personnel, a project team was based at COOEC’s offices in Shekou, China, and a 12-man offshore team was based on the Maersk Attender and the local support vessel, the HYSY 708 multi-service vessel. Both teams had staff from OIS and Intermoor.

meticulous planning and management were vital, as martin Kobiela, operations director, Intermoor, explains, “Procurement of equipment for the project involved working closely with local suppliers and coordinating specialist equipment from Singapore and Europe. We selected equipment based on the expected loading and ensured that it was optimised for use with remotely operated vehicles and divers, and sized to reduce the risk of damage when pulling through mooring chain stoppers and the riser J-tube.”

In addition to the standard installation equipment, Intermoor designed custom devices to handle and protect the jacketed spiral strand wires on the winches and at the shark jaws. A dogbox was used to protect the spiral strand wire when stoppered off at the vessel’s shark jaws. A winch adapter was used to prevent overbending of the spiral strand wire at the socket when stowed on the vessel’s winch drum.

Intermoor was responsible for all of the mooring-related activities on the project, including providing a specialist engineering team and the necessary mooring expertise. OIS took responsibility for project management, including offshore management of the Maersk Attender and the HYSY708, and all riser-related activity.

Kobiela says, “Our extensive experience in providing back-of-the-boat solutions was crucial for this project. We developed procedures that enabled simultaneous operations to be performed offshore while working with divers, remotely operated vehicles and the anchor-handling vessel close to the buoy turret-mooring system.”

The Intermoor–OIS project team was assisted on the project by two sister companies: 2H Offshore, which provided riser installation engineering, and Aquatic Engineering and Construction, which supplied offshore personnel and equipment for deploying the flexible riser.

Close collaboration with the customer was key to success, says Kobiela, “This was a very important project for Intermoor. We selected our team of engineers for their technical skills and on the basis of their ability to integrate with client operations and to communicate in both Chinese and English. I am convinced that this was crucial.”

Wang Jiewen, project manager and deputy manager of the engineering department at COOEC, expressed satisfaction with the project, saying, “On behalf of COOEC and our client CNOOC, we would like to thank Intermoor and OIS for their high level of performance on this project and look forward to working with them again in the People’s Republic of China in the near future.”

The successful completion of this project has led to the possibility of winning future work for the same customer. Intermoor is currently looking at similar projects scheduled for 2013 and 2014.

13www.intermoor.com or www.ios-ltd.com

The new Lm Handling joint venture between LDD and mENCK combines LDD’s dynamic and fresh approach to offshore solutions with mENCK’s outstanding expertise and track record in piling operations. The venture aims to provide equipment and services either directly to customers or as part of a package led by LDD and mENCK, thereby enabling them to offer a more holistic integrated service and to provide a single point of contact for turnkey support in offshore projects.

This working arrangement brings together specialist engineers, project managers and equipment for critical tasks such as jacket and monopile installation, and subsea construction work.

According to Andrew Paterson, business development manager, Lm Handling, the joint venture focuses on helping customers to conduct complex operations more efficiently, both operationally and commercially. “The LDD and mENCK personnel in Lm Handling work as a team and the emphasis is always on solving customers’ problems,” he says. “We are currently working on developing new products and services to meet specific industry needs, particularly where there is a limited or ineffective supply.

“Areas we have already identified through close contact with our customers are pile upending and lifting tools, so we are investing heavily in these areas to complement our product range. Hydraulic shackles and pinned and internal lifting tools are just some of the key items.”

The most significant joint development project to date is the StabFrame. This system is the result of collaboration between LDD and mENCK staff. The companies have track records of designing, building and operating their own foundation installation and lifting and handling equipment. This deepwater pile guide and stabilisation frame significantly reduces pile installation risks. By enabling piles to be driven uninterrupted to their intended depth, the StabFrame minimises the need for expensive followers and copes with varying ground conditions that do not rely on a fixed penetration depth. Its primary applications are installing mooring piles for floating production, storage and offloading (FPSO) facilities; offshore wind turbine foundations; pipeline initiation piles; and wave and tidal mooring systems.

The fabrication and testing of the StabFrame involved a tight 11-week schedule so that it was ready for transportation from the UK to Brazil

for its first project, which was for Wellstream to moor the OSX-1 FPSO facility using the offshore construction vessel Aker Wayfarer.

The Waimea piling operation in the Campos basin, offshore Brazil, the first commercial application of the StabFrame, presented a tough test for the new system. Paterson says, “At Waimea, there were unforeseen soil conditions: a hard crust over soft unsupportive sediment. Some piles went into free fall to varying degrees and at various drive depths. Typical pile support frames open at a predetermined depth where the pile is expected to have achieved self-stability. Here the ground conditions were different than anticipated, so the StabFrame proved its ability to reduce installation risk and delay on its first job.”

The StabFrame was developed to fit a particular market niche and designed for rapid despatch to piling operations around the world. Paterson says, “The StabFrame is designed to DNV standards and has a unique modular design that facilitates rapid assembly, disassembly and maintenance activities. For ease of transportation, we can ship the StabFrame in standard 6- and 12-m open-top ISO containers. We can customise the system for special projects, including, for example, hydraulic levelling. It also offers varying mud mat configurations for better weight distribution to cope with a range of soil conditions and seabed relief.

“The StabFrame’s hydraulic sleeves are operated through a work-class, remotely operated vehicle (WROV). This removes the requirement for an automated release system and enables the StabFrame operator to react to variations in the expected piling conditions,” Paterson concludes.

There are further installation projects on the way for StabFrame. The system will be used in a North Sea operation during 2013.

Building on the tool’s success, Lm Handling is developing a lighter slotted version that significantly reduces costs to customers where piles have a lower pad eye and the pile verticality tolerances allow a shorter central sleeve. The slot enables the pad eye to be driven below the mudline, if required. The frame can be split manually or it can be fitted with the same hydraulic actuation as the StabFrame for customers that prefer additional control if the soil conditions are less predictable.

StabFrame is just one of the lifting and handling systems offered by Lm Handling. The pin lifting tool (PLT), for example, offers a very simple,

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fresh thinking for liftinG and handlinG EquiPMEnt Joint vEnturE aiMs to ExPand offErinG and EnhancE collaboration

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fresh thinking for liftinG and handlinG EquiPMEnt

www.lddrill.com or www.menck.com

safe and cost-effective option for installation work and can be easily installed in vertical or horizontal piles. The PLT features a simple single pinning system for securing, upending and lifting piles. Once the pile is in place, a person or an WROV typically removes the pin, which releases the PLT from the pile and enables tool recovery. Remote pin actuation systems are also available. PLTs operate both above and below water; the operational water depth is limited only by the WROV’s depth rating.

Collaboration between the two partner companies is clearly a key part of the Lm Handling joint venture, but, as Paterson points out, there is another side to the coin. “We are pursuing a very collaborative approach with customers and potential customers. The aim is to identify their needs and find opportunities to improve their operations. This gives us the clearest possible understanding of the challenges they face and enables us to develop the best technical and commercial solutions for their operations while strengthening our offering to the industry.”

The emphasis on a close relationship with customers brings benefits to both sides. “quite often,” says Paterson, “customers choose to a develop an in-house bespoke piece of lifting, handling or pile stabilisation equipment, use it on a single project and then recover part of the cost to the project by scrapping it. Lm Handling offers a different model. By working with the customer in these cases, we can achieve the same outcome for them – a tool that perfectly meets their needs. This means potentially less cash coming out of their project and certainly less hassle, as we can build the tool into our portfolio and reuse it on other projects.

“When we can combine our products with the equipment and services of LDD and mENCK, for example, the Waimea job involved a mENCK hydraulic hammer, we create a compelling offer to customers that meets the goal of reducing hassle and the number of interfaces, both operationally and commercially. Lm Handling will continue to expand its range of lifting and handling equipment to suit customers’ requirements. Our aim is to rapidly become a top-of-mind offshore and subsea equipment provider,” Paterson affirms.

We are pursuing a very collaborative approach with customers and potential customers. the aim is to identify their needs and find opportunities to improve their operations.” ”

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MonitorinG dEvEloPMEnts in thE Gulf of MExico PULSE WINS EPIC CONTRACT FOR RISER AND TENSIONER mONITORING SySTEm

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Pulse Structural monitoring is developing a riser and tensioner monitoring system for the Big Foot extended tension leg platform (ETLP) in the Gulf of mexico, which Chevron will operate. The system will actively monitor riser motions and bottom currents in real time and key parameters such as tensioner pressure, stroke inclination and lateral loads on the riser and tensioning system.

This is Pulse’s first engineering, procurement, installation and commissioning (EPIC) contract from Chevron. The company won the contract in August 2012 and is working towards a delivery deadline of April 2013.

The Big Foot development is in the deepwater Gulf of mexico approximately 360 km south of New Orleans, Louisiana, USA, in water depths of 1600 m. The field lies in the Walker Ridge area and contains total recoverable resources in excess of 200 mmbbl of oil equivalent. First oil is anticipated in 2014.

The Big Foot ETLP, which is currently under construction in Korea, will have a production capacity of 75,000 bbl/d for oil and 25 mmcf/d for natural gas. It will feature dry trees and top-tensioned risers, and will have full drilling, workover and sidetrack capabilities on the topsides. A push-up-type tensioner system will enable the ETLP to withstand the harsh conditions prevalent in the area. modelling indicates that the platform should be able to withstand a 1000-year hurricane.

“As part of the preliminary work for the development,” says Wolfgang Ruf, vice president, Pulse, “we have been asked to assist with testing the riser tensioner system. The tensioner uses six push rods to maintain tension. Chevron wants to establish what would happen if one of the rods failed and how it might affect the stability of the system. We will hook up the tensioner and install a monitoring system to track performance during the test. This will be a key design qualification testing milestone.”

The Pulse riser and tension monitoring system aims to offer comprehensive understanding of the risers and wellhead’s performance under severe conditions. It will also provide information the operators can use to accurately measure and quantify fatigue damage to the risers and wellhead. The data, especially from during severe environmental events, can be evaluated offshore or transmitted onshore on demand for further processing and integrity management activities. This information will be invaluable for future drilling operations in similar conditions.

Significantly, the work is taking place under an EPIC contract, i.e., the Pulse system is being supplied as an integral part of the platform’s systems and will be fully integrated into Chevron’s control system. The main driver for Chevron is to monitor the integrity of the structure and to ensure that it has a clear understanding of the condition of the risers and tensioners so that operations can be conducted safely and efficiently.

Post-macondo, structural monitoring has become an increasingly important aspect of operations and is now considered during all stages, from obtaining approvals through to improved management of operational risk. Operators are increasingly focusing on improving the integrity of their operations; monitoring plays a key part in the integrity management process.

Pulse has a long history of providing systems for integrity monitoring to enhance safety and improve efficiency. “Since 1998, we have completed more than 500 deployments to depths of more than 3000 m,” says Ruf. “The contract for the Big Foot development builds on this track record and on the successful completion of a similar project for the recent Tahiti development. As on the Tahiti development, we will be working with our sister company 2H Offshore. They will provide engineering and delivery of the riser system for Big Foot.”

One potential issue for the Big Foot ETLP is the possibility of deep currents affecting its subsea systems. Loop currents are usually only an issue in the uppermost 150–180 m of the water column, but at Big Foot, they may occur at greater water depths. The platform will be close to a subsea escarpment, so there is the possibility of strong currents at depth.

Pulse will install an acoustic Doppler current profiler to measure current speed and direction. This will help to ensure that subsea operations can be conducted safely. For example, knowing the current strength and direction when a remotely operated vehicle is deployed could prevent it from drifting off in a strong current. Conditions near the seabed will vary and will need regular monitoring.

Ruf explains, “We are developing a solution to meet Chevron’s needs exactly, but one that uses a large number of standard components. The main challenges are dealing with the various companies and stakeholder groups within Chevron to ensure that we deliver the information gathered in the form they will find most useful and managing the interfaces to deliver full technical integration into existing infrastructure.

“There are some fundamental physical challenges too. Data transmitted from the seabed to the surface will be in real time. In addition to optimising the interface with Chevron’s system, we have the engineering challenges of managing a 4900-m-long cable in demanding marine conditions. We are building on experience gained in deepwater operations elsewhere in the world to deliver a sound and reliable monitoring solution.”

17www.pulse-monitoring.com

the chAllenge of lowErinG a livE Gas PiPElinE acteon companies comBine on a worlD-first project, offshore inDonesia

major development projects often have implications for existing infrastructure and accommodating the necessary changes may require fresh thinking. This was certainly the case when a proposed expansion programme at Tanjung Perak Port in East Java called for seabed dredging in the shipping channel to provide access for deep-draught vessels.

To accommodate the dredging operation, a 16-in. gas pipeline, which provides fuel to madura Island, needed lowering. The aim was to lower the pipeline by 6 m so that its top was 9 m below the original seabed where it crossed the shipping channel. The gas supply was uninterruptable, so the pipeline remained fully operational and at a pressure of 500 psi throughout the operation.

Offshore Installation Services (OIS) took overall responsibility for the commercial and operational aspects of the project by providing project management, including chartering an offshore supply vessel and managing all the subcontractors, from its base in Aberdeen, UK. It also provided in-country project teams throughout, both on- and offshore.

The project required meticulous planning and an innovative approach to the lowering process, as Tom Selwood, vice president – commercial and business development, OIS, explains, “This unique, multimillion-dollar subsea project presented many technical and logistical challenges. We identified four issues that would be crucial to the project’s success:

� an effective, stable trench design based on the specific seabed conditions

� a reliable engineering system to create a deep trench and enable controlled pipeline lowering

� a system to monitor the progress of the trenching and the pipeline lowering operation in real time to ensure that the bespoke trench design was being achieved

� engineering stress assessment of the pipeline at each step of the lowering process to ensure that the pipeline was not overstressed.”

The first challenge was to ensure that the trench walls were stable and would remain intact throughout the lowering operation. Any soil collapse onto the pipeline might cause stress fracturing and a pipeline rupture, with potentially catastrophic results.

The seabed is a highly variable natural environment. To ensure stability, the project team had to devise a trench design that took account of the local seabed composition. Soil expert Dr Indrasenan Thusyanthan, engineering manager from sister Acteon company Cape Group, designed a stepped, V-shaped trench specifically for this operation. The plan involved moving more than a million cubic metres of soil to create a 9-m-deep trench.

The project team undertook an extensive engineering assessment of the pipeline lowering before work started. This ensured that the stresses in the pipeline would remain below safe limits, as Thusyanthan explains, “No one had any experience of a job like this and some people thought it would be impossible to lower a live gas pipeline without a serious risk of structural failure. Clearly, as the pipeline is lowered from two fixed end points its profile changes and it stretches. Our task was to ensure that the stretching stayed within safe limits. We decided the best and safest option was to lower the pipeline in steps of 0.5 m and monitor at each step to ensure that the bending stresses induced in the pipeline were within acceptable levels.”

OIS contracted Rotech Subsea to conduct the trench excavation work. Rotech provided its T8000 controlled-flow excavation system, which was key to the success of the trenching operation. The T8000 excavator is a state-of-the-art T-shaped tool with two contra-rotating impellers, one at the end of each arm of the tee. It draws seawater in and directs a controllable column of water vertically to the seabed at high volume and high speed but low pressure, which is ideal for working on live targets. It also has a range of nozzles for variable seabed conditions.

In addition to the T8000 system, Rotech supplied a higher-pressure water pumping system that would cut the stiff clay while the controlled-flow water column fluidised the soil to create the trench. This combination of tools enabled safe and controlled lowering of the pipeline.

As the trench was to be lowered in increments, it was vital to monitor the profile in real time and to carefully control each of the lowering passes so that the pipeline was not left resting on free spans. A fourth-generation survey solution from Acteon company NCS Survey monitored the trenching progress and ensured that the Rotech operations matched the engineering design from CAPE.

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This involved mounting NCS Survey’s equipment on the front and back of the T8000 excavating tool to provide real-time before and after analyses of the excavation work. This inspection method was necessary because there were strong currents in the area, which caused significant backfill and would have rendered a post-excavation survey ineffective. The NCS Survey monitoring technology made a crucial contribution: without being able to monitor the trenching operation in real time, the job would not have been so quick or so safe.

The trench was deepened in 14 separate excavation passes over a period of eight months. The project team conducted a detailed stress assessment of the pipeline after each pass to ensure its integrity was not compromised. The oil and gas operators involved and SKmIGAS, the upstream oil and gas regulator, were pleased with the result. The Indonesian authorities independently verified the new burial depth as 9 m below the original seabed.

The lowering operation was a complex challenge requiring innovation in several technical disciplines and a clear vision for project delivery. Seamless working together by the Acteon companies and the subcontractor involved helped with the project’s success.

this unique, multimillion-dollar subsea project presented many technical and logistical challenges. We identified four issues that would be crucial to the project’s success.”

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www.acteon.com

Speed was critical when Statoil wanted to use the West Elara jackup rig to install a high-pressure drilling riser for two subsea wells in the relatively deep water (132 m) of a Gullfaks satellite field, offshore Norway. The riser had to be designed, built and ready for installation in 8 months rather than the usual 12 months to meet a window of opportunity in the rig’s operational schedule.

The project was managed by Claxton Engineering with support from Acteon sister companies 2H Offshore, Pulse Structural monitoring and Subsea Riser Products (SRP), who manufactured the fabricated sections of the riser and supplied the riser spider. The companies combined their skills to deliver a detailed drilling riser solution, bespoke and innovative engineering work, and an advanced monitoring system to track performance.

This project was in unusually deep water for jackup rigs, as Darren Bowyer, project manager, Claxton, explains: “For jackup operations, deep water is depths over 80 m. The depth at which jackup rigs can operate is determined by their leg length. Average jackup rigs are built for 80–100-m water depths; only the larger rigs are capable of deeper operations. New large jackup rigs are now built to work in depths to 150 m, so 132 m was a significant challenge. The main issue is that systems for shallow water environments do not scale up to the needs of deeper water. The greater depth means increased deflections for the jackup rig and the drilling riser caused by currents and waves, and that the whole system is subjected to increased loading.”

Part of the problem is the limited track record of jackup rigs in deep water. According to Bowyer, “The industry has little experience of using jackup rigs in depths greater than 100 m and in harsh environments. This makes for conservatism in design and operations. Furthermore, during high-pressure operations, well control considerations require a large blowout preventer, which adds a stiff component to the drilling riser and changes the dynamics of the string.”

AnAlyticAl methods And oPerAtionAl ProceduresDrilling riser designs are created to minimise the risk of failure and, in addition to meeting design code and standard safety margins, often have a large “comfort factor” built in. This helps to ensure they can cope with complex and unpredictable loading.

The loading that a riser will face is difficult to model and is usually simplified for the design process because some of the relevant factors are not well understood. For example, engineers cannot accurately predict weather patterns and must make assumptions in the input data they use for the model. The fatigue information used in models is often

based on standard industry codes rather than component tests and monitoring. Consequently, designers can find it difficult to calibrate the models they have created with the data they gather during operations. Given the number of unknowns and estimates, it is unsurprising that most designs take an extremely cautious approach.

For this project, 2H set about developing a more complete and accurate model for riser loading. Experience shows that detailed modelling can deliver a modelled loading response that is more than 30% closer to reality. The project team also recommended some changes to operational procedures that would reduce riser deflections in the splash zone caused by wave and current action. The challenges overcome on this project prompted Statoil to set out exactly what it would require and expect in terms of modelling for future work.

chAnges to riser And vesselmodelling indicated the potential for a very high level of fatigue in the original riser design. This made it necessary to change the riser, the rig and the air gap.

The alterations to the drilling riser design included adding a vortex-induced-vibration suppression system; the use of forged rather than welded joints in high-stress and fatigue-prone areas; and an upgraded tensioning system.

Bowyer explains, “Vortex-induced-vibration suppression and drag reduction were achieved by adding special fairings to the riser. This was the first time this approach had been applied to a high-pressure drilling riser in the North Sea. In addition, this 24-in. riser was much larger than a standard application (usually about 133/8 in.). All the fairings used in the project were recovered intact. We also recommended a significant upgrade for the tensioning system. A typical North Sea jackup system has a 200-t rating, but Claxton experience and the 2H analysis suggested that a system rated up to 500 t would be required for this operation.”

The rig design changes included increased load capacity for the Texas deck. For this project, the West Elara rig required increases to its vertical and horizontal load capacity. Subsequently, the West Elara’s sister rigs under construction at the time were also upgraded. A review of its overshot capacity was also necessary. Increasing the overshot capacity would help to restrain lateral motion in the riser and to cope with significant bending loads during storm conditions. However, detailed analysis of the rig’s overshot capacity indicated that it was fit for purpose.

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IN DEEP and UNDER PRESSUREPROVIDING A HIGH-PRESSURE DRILLING RISER IN DEEP WATER

21www.acteon.com

the time frame on this project was extremely challenging and included many design iterations: about 90% of the riser was changed after the contract award. by drawing on successful projects like this, it should be possible to extend jackup drilling deeper.”

“Claxton has more than 20 years’ experience of deploying risers. This was the first use of the NT-2 tool for deploying a riser and it enabled the riser to be pressure tested before make-up to the blowout preventer. The tool can perform a wellbore pressure test of 7000 psi while holding 308 te in tension.

Ivar Traeen, senior subsea engineer, Statoil said, “We were very pleased with the Claxton equipment and operations, and particularly with the clarity of their procedures. The supervisors involved during the installation and monitoring operation both displayed excellent, proactive attitudes and participated fully in the ongoing operations.”

monitoring And integrity mAnAgementmonitoring and integrity management have become key focus areas for offshore operators in recent years. Pulse developed a riser monitoring system that would gather field data; enable integrity management; verify the predicted models; and enable the operator to drill safely.

The system included topside and subsea sensors for recording movement, load and dynamic bending parameters. The data the monitoring system gathered was supplied in real time through a traffic light alarm format. This showed the status as green when all parameters were in normal limits; amber when one parameter was outside normal operating limits and required adjustment; and red if any parameter was outside ultimate operating limits, in which case disconnection was recommended.

This project has provided valuable insights into the use of jackup systems in deeper water. Bowyer says, “The time frame on this project was extremely challenging and included many design iterations: about 90% of the riser was changed after the contract award. By drawing on successful projects like this, it should be possible to extend jackup drilling deeper. Can we do this elsewhere in 150 m of water? yes. But the key to success will be early planning and detailed analysis.”

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findinG thE RIGHt coMbinationTWO-HAmmER mETHOD REDUCES PILEDRIVING NOISE

Subsea noise associated with piledriving is a major issue on installation projects for offshore wind farms. mENCK is taking part in a pioneering project in the German North Sea that combines two hammer systems: a mENCK impact hammer and a vibratory hammer. The combined approach means that noise levels for much of the piledriving work is considerably lower and that the use of additional noise reduction methods, such as bubble curtains, is reduced.

The Global Tech I offshore wind farm array will consist of 80 wind turbines and occupy an area of roughly 41 km2. Each turbine will have a tripod foundation, so 240 piles need driving. HOCHTIEF Solutions is managing the erection of the tripod foundations and turbines. Various systems are being used to minimise noise and the associated disturbance to wildlife, particularly marine mammals.

Christoph Dytert, director of sales and marketing, mENCK, explains: “Thirty years ago, oil and gas platforms were installed in the North Sea with little thought for how the installation process might affect

marine wildlife. New regulations place an onus on operators to install piles and their associated infrastructure with careful regard for the environment.” The pile installation work combines two hammer systems and a large bubble curtain around the installation site. The two hammer processes run in series. An upending vibratory hammer (a high-frequency device that drives piles smoothly into the ground) drives the pile about two-thirds of the way into the ground then a mENCK hydraulic underwater hammer takes over to complete the job and establish the load capacity of the pile.

Using the much quieter vibratory hammer for the first phase means that the bubble curtain only operates when the conventional hammer is running. Consequently, the compressor that generates the bubble curtain runs for only a fraction of the time required for a conventional piling operation: typically, 15 minutes rather than 90 minutes. This also means that significantly less fuel is needed to power the air compressor, so less carbon dioxide is emitted.

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Changing between the two hammers extends the piling operation by about 30 minutes per pile, but the environmental benefits in terms of reduced noise and air pollution are significant.

In this project, the approach has been to use a different crew and separate power packs for each hammer. As part of wider research into noise reduction, mENCK is investigating ways to combine the crews and operate both hammer systems from a single power pack, which will save time for the installation contractor and space on the installation vessel.Dytert says, “This is a new way of working and there will be improvements and enhancements over time. For the past 10 years,

mENCK has taken an active role in learning about the causes and effects of underwater noise. We have developed various systems and methods, including a highly effective system called the mNRS-U, which is a small-bubble curtain placed around the pile. The mNRS-U is a unique combination of effective noise mitigation and fast, easy operation that can easily be combined with the two-hammer method.

“Participating in this project underlines our commitment to helping offshore operators to achieve noise reductions through proven new technology and new working methods,” he concludes.

in this project, the approach has been to use a different crew and separate power packs for each hammer. As part of wider research into noise reduction, menck is investigating ways to combine the crews and operate both hammer systems from a single power pack, which will save time for the installation contractor and space on the installation vessel.”

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DEFINING SUBSEA SERVICES

SUBSEA SERVICES(SUHB-SEE SUR-VIS-ES) Definitive

THE PROVISION OF SPECIALISTEQUIPMENT, SERVICES ANDPERSONNEL, COMPLEMENTARY TO THE CAPABILITIES OF VESSELOWNERS AND SUBSEACONSTRUCTION COMPANIES.

From exploration to decommissioning, Acteoncompanies bring technical ingenuity and a drive forfresh thinking to every stage of offshore activity.This approach to the subsea service market is justone example of how we're defining, shaping andleading subsea services.

Discover a fresh approach to subsea services at www.acteon.com/subsea

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