The reel deal
  from: Offshore Engineer
  by: Rick von Flatern
  Friday, October 01, 2004

Coiled tubing has long been considered a secondary technology, called upon by operators only after they had exhausted all other options. But as US editor Rick von Flatern found out recently, that perception is changing, especially offshore.

'When we look at the curve of drilling vs intervention, we don't think intervention has kicked in yet,' says Schlumberger's business development manager for coiled tubing, Warren Zemlak. 'In deepwater the operators are targeting the biggest opportunity so the life span of a deepwater well may be extended with specific intervention technologies. However, we also recognize that the cost of intervention in the deepwater has to be addressed in terms of unique solutions and ways to approach it.'

Besides the coming intervention market, Zemlak and others see a growing place for coiled tubing as operators pursue new and bypassed reserves. 'I believe two of the areas operators are looking to for more oil are the deepwater and the shelf,' says Halliburton global operations manager for well intervention, Hampton Fowler. 'And there are a number of techniques to go back into existing wellbores to increase recovery from existing assets. I think coiled tubing is going to be one of the keys as to how they do that.'

Taking it offshore
The traditional objections to using coiled tubing offshore have to do with aging platforms and cranes whose lifting limits have been downgraded over time, all of which often renders coiled tubing reels too heavy and power pack and control cabin footprints too large for them. Even in deepwater where very large platforms and cranes rated to lift much more weight than that presented by the largest coiled tubing systems, weight can still be a consideration.

'Even on some of the largest platforms offshore weight is an issue because you cannot put that weight just anywhere,' says Halliburton product manager, coiled tubing and hydraulic workover, Perry Courville. 'There are only certain spots on the deck that can take that footprint and weight. The crane can pick it up with no problems but it has to be put on a special spot on the deck to handle that.'

Coiled tubing has long been more specialized than some services, possibly because it was designed to react to problems rather than anticipate them. 'The issue in the coil business is the customer has a very particular set of problems to overcome and how he overcomes them is a function of the space available on location and the exact nature of the problem,' says BJ Services director of global coiled tubing services, John Misselbrook. 'One day you need a guy with a shovel and the next a backhoe and a whole crew.'

Also, since very specific applications may arise only a few times per year there is little sense in building a whole system for those few cases, he says. The result is today coiled tubing has become a tool that is used for a wide variety of applications but is not necessarily optimized to be 100% efficient at every single one of them.

But as coiled tubing moves offshore, that characteristic also may change to some degree. As Misselbrook points out, avoiding the one or two hours of nonproductive time on land is probably not enough to drive specialty coiled tubing solutions. But in deepwater, where rig costs routinely exceed $200,000/day, the reward for trimming just hours off the process can easily pay for customized coiled tubing equipment. But that will mean planning on the part of operators very early in the project lifecycle, not a traditional practice.

'Coil is not normally a technology the oil company must have for every well they drill,' says Misselbrook. 'It is part of the contingency. There will be some situations where the client wants to use coil as part of the completion or drilling process and know that step is going to happen, but most of the time the clients are thinking they are going to use conventional technology and coil is a contingency if things go wrong.'

To get the most out of coiled tubing then, he says, operators would be well advised to consider the technology and the advice of experts when preparing their rigs and platforms, particularly in the deepwater. 'If you go offshore and review the specific steps involved with rigging up and performing a particular intervention you get a better feel for how all the elements of the rig interact with your equipment and how to safely maneuver your equipment over the well,' explains Misselbrook. 'These sorts of issues have a big impact on efficiencies. If there is one small step that is overlooked it can just cause horrendous slow downs.'

Too, as in any offshore operation the rig's crew normally must be drafted to help rig up coiled tubing. Since the rig crew is usually unfamiliar with coiled tubing, advance planning for its use also allows for some early crew training.

Making the shoe fit
While designing platforms and rigs with an eye towards coiled tubing use may be the optimum from the viewpoint of the provider, working that sort of customization from the opposite direction may serve just as effectively. At least that is the contention behind Schlumberger's CT Seas, recently debuted at BP's Valhall field offshore Norway.

The majority of wells at Valhall have been completed with multiple proppant fractures using a drilling unit to do eight to 12 zones per well. 'It was a very slow process,' says Schlumberger North Sea geomarket technical engineer, Alistair Buchanan. 'In the mid-1990s (BP predecessor) Amoco and us pushed to replace the rig and they started using snubbing and then replaced snubbing with a relatively conventional coiled tubing package.'

The wells were being drilled with a jackup unit through a 16-well template. Once the well was drilled and liner and production strings set, the rig was moved to the next slot to allow completion using a coiled tubing unit in a process BP refers to as simultaneous operations.

'In itself it is almost unique in the world to use coiled tubing as a part of the completion machine,' according to Buchanan. 'The coiled tubing is an extension of the rig or the rig is an extension of the coiled tubing, as we like to say.'

With the prospect of increasing offshore applications and mindful of the continuing industry trend, as Buchanan puts it, 'for safer, more efficient, automated solutions', Schlumberger embarked on streamlining coiled tubing set-ups. 'Besides the basic coil tubing units we had pump units, choke units and shakers,' he notes. 'We were in constant radio communication and had to have someone there, for instance, to constantly adjust the choke to keep the bottom hole pressure constant. It was a very personnel- and equipment-intensive operation.'

Their CT Seas solution grew from a similar Schlumberger concept for land operations called CT Express. Described by the company as a fit-for-purpose unit easily adapted to work on fixed platforms, floaters and TLPs, the system is made up of 10 'primary skids which reduce crane lifts from 53 to 36 on a typical operation in the North Sea'.

'The CT Seas performs the same function (as standard CT systems) with fewer people, more efficient mobilization,' Buchanan says. 'Hardware packaging and some hardware itself has been changed and the whole system was upgraded at the same time from using 6400m of 2 ³/8 in tubing to more than 6000m of 2 ⁷/8 in.'

Though Buchanan says the landoriented CT Express lent much to the offshore system, 'the original idea was to start with a blank sheet'. They first addressed the fact that traditional CT units, because of their land-based heritage where space is seldom much of a problem, are controlled using numerous hydraulic hoses and electric lines with power and control distribution all centralized. As a result, besides having power transfer going through the various pieces of equipment traditional rig up also means a separate power and control line for each function.

In contrast, like the land version, CT Seas has a distributed power system with electronic control based on the item being controlled. The result is fewer lines and hoses and a simpler rig up.

To reduce the number of crane lifts, rig up and mobilization time, the whole of the injector support and well control is brought offshore as two or three skids that fit together with most connections premade and pre-tested. The gooseneck is hydraulically folded and goes offshore as one piece that is remotely extended and placed without human interference. Likewise pipe stabbing is performed using cable pull through, again removing personnel from harm's way.

'And the process control is at a higher level here,' notes Buchanan. 'The operator tells a system that he wants 250bar on the downhole gauge and it does it automatically so you don't need a guy on the gauge.'

While actual results are still a bit guarded, Schlumberger projections for the system shipped at the beginning of last year include an eventual 30% reduction in crew size - from 13 to nine (though strictly speaking the unit can be run with six people). The company is also looking to CT Seas to cut overall operating times by 15%, including a 35-hour reduction in rig up time.

All in the presentation
In the Gulf of Mexico and elsewhere, many operators will continue to view coiled tubing as a commodity. Superior Energy Services of Harvey, Louisiana, a company with a long history with the Gulf and operator requirements, has positioned itself not to fight the perception but to take advantage of it by 'bundling' its coiled tubing with its numerous other services.

'We have the largest fleet of lift boats in the world and we are the only company that has all the well intervention services and lift boats,' observes Superior's Mike Howard. 'We approach it as project management, focus on delivering the customer a product at a lower total cost and not worry about all the different services.'

After first divining those customers objectives, the independent service company uses its staff, including more than 30 petroleum engineers, to work with clients by supplementing mostly independent operator staffs that in recent years have shrunk even as they have aggressively acquired more offshore properties.

'What we do is reverse engineer,' says division technical manager for coiled tubing, Bob Hale. 'Once we know what the customer objective is we start from the opposite end and work towards that objective.'

Like the need to convince operators to consider coiled tubing in the early stages of their offshore project plans, the most difficult aspect Superior coiled tubing engineer Robert Cole encounters in his company's approach is changing operator perception in order that they grasp the overall concept. 'We try to get the operator to look at service companies and look at the best deal dollar-wise and look for the best overall outcome,' he says. 'We are providing a better overall job and routinely it is at a lower cost to operator and once they have one or two of these jobs under their belt they seem to embrace the concept that even though on a day-by-day basis the cost might seem to be a premium over all they are getting more bang for their buck.'

The company also offers clients realtime, remote monitoring capabilities for all coiled tubing jobs from what it has dubbed an 'E-Room'. Using web-based software programs that include procedures and best practices, the customers use the room to pick up daily reports and costs and to track the job in real time. 'We put satellite communication out on every job,' says Howard. 'It is not new technology but is using existing technology in a more efficient way than it has ever been used.'

And, again echoing the sentiment of early involvement, Coles says that being involved from the inception of a project and communicating with the customer maximizes the benefits of a bundled approach. 'We are getting a better idea of what he wants to end up with and we are not getting a bid request from a customer,' he says. 'We are instead providing a solution and we may have ideas that may get him a solution that is more efficient'.

In preparing for this business approach, Superior says it first refurbished all its existing coiled tubing units and then focused on training. 'Our philosophy is that if we can control 100% of the spread on location,' Howard says, 'we can control the outcome of the project and we can control the total cost of the project and are responsible for the total cost of the project.'

Making a connection
A loaded reel is far and away the heaviest single component of a coiled tubing system. This is particularly true in deepwater where greater depths and larger completions require larger OD strings to deliver better hydraulics and reach target depth. The larger reels used for deepwater operations have capacities ranging from 20,000ft of 2in coil up to extremes of 30,000ft of 2 ³/8 in. For fourth and fifth generation semisubmersibles and very large TLPs and spars, cranes are sufficiently large that the heaviest reel is an easy lift and deck space is generally less an issue.

However, the same certainly cannot be said of every floater or platform. As a result, it is often necessary to transfer the coil from a supply vessel to the platform deck in several lifts that in turn creates a need to join the coils. Alternatively operators may choose to use smallerdiameter coiled tubing settling for less than optimal pump rates and weight transfer to the tool on bottom or risk not being able to push the coil to target depth. In some situations, the clients will not or cannot make such compromises and so choose to lift an empty reel to the deck and then spool pipe to it from the back of a boat.

'This is only done in a calm sea state,' says BJ Services' Misselbrook. 'Typically, the preferred approach is to take the coil out in two or three pieces and weld it together on the platform.'

But welding presents certain problems. While not impossible, it is difficult to accurately predict the safe fatigue life of a weld made in any but perfect conditions. 'When you do a weld with an orbital welder in perfect conditions, meaning no drafts or temperature extremes and the pipe is brand new and nice and round and the two pipes are the same wall thickness, you can get a butt weld that is safely 40% the life of a regular piece of pipe,' says Misselbrook. 'That is pretty good and you can do lots of jobs and plenty of runs in and out of hole.'

But the unlikely event of perfect conditions on an offshore platform aside, welding offshore is an expensive and timeconsuming proposition. Welding specialists are required to set up the operation and in most jurisdictions a special work permit is required and a discrete area on the rig used. In many instances wells must be shut in for the duration of the welding job.

Welds must then be x-rayed by yet another set of specialists with more equipment. And as a final deterrent to welding, as tubing diameters grow, discrepancies between wall thicknesses and ovality become more significant and harder to control as small imperfections are magnified.

Given the drawbacks, coiled tubing services suppliers have long sought a spoolable mechanical connector that can perform at least as well and for as long and repeatedly as a good weld. But development was held up by an industrywide perception that such a connector was more a luxury than a necessity and that for single, one-off operations, say to retrieve one piece of pipe with another, simple connectors did exist. 'I guess we all figured this was not something that was easy to do,' offers Misselbrook. 'So we thought: 'Why put in the R&D effort to do it?'. We were managing with what we had but our guys in Norway said we need this.'

At the behest of its Norwegian districts, BJ Services set about delivering the connector. 'To our surprise the development program gave us a connector that by the time we engineered it, tested it, balanced elastic and plastic moduli and got a working design, the connector had a superior life to the best welds we could do' explains Misselbrook. 'Typically people would say a perfect weld made in ideal conditions is 40%; this connector when installed in field conditions is 50% on the 2 ³/8 in and 2 ⁷/8 in diameters developed so far.'

Adding the internal, dimpled connector known as the DuraLink Spoolable Connector to the string slightly reduces the inside diameter where the joint is made. But that is not a problem, says Misselbrook, since the affect of the ID reduction on hydraulics is minimal. Too, the ID reduction is not so great that it compromises the passage of any ball that may be required to operate a downhole tool.

According to Misselbrook, the 'real attraction for the connector is we can now start using bigger sizes of coil offshore without the welding, x-raying, and all - mechanical splicing is quicker but most important the connecter can go in and out of hole multiple times'. The fatigue life of the connector can be measured with a caliper. 'You can detect a one-thousandth inch change on the coil,' he adds. 'The connector itself doesn't change but where the connector attaches to the coil you can measure and the geometry change is linear with fatigue life so as you run in and out of the hole you just go to the reel with a caliper. It is a very easy way of just reassuring yourself that the connector is well within its fatigue life. We know how many cycles it can take from software but it is still nice to have a check.'

The BJ connector has been commercial since early 2004 and used so far only in Norway where larger coil sizes are common. A 1 ³/4 in version is under development and there is great interest in a 1 ¹/2 in size but given it is an internal connection, such small sizes seem problematic at best and their application less certain than in larger, heavier reels.

Tapered string
In designing casing strings, a basic tenet includes choosing a heavy wall casing for the upper sections in order to gain the yield strength necessary to suspend the entire casing string. In response to the offshore industry's trend towards greater drilling depths, both on the shelf and in deepwater, Halliburton has been developing, along with megamajor BP, a single string of coiled tubing with multiple outside diameters.

'The first one will be 2in to 1 ³/4 in OD and we are now working on the 2.375in to 2in OD,' reports Halliburton's Courville. 'What that means is larger overpull capability at the surface with lower stress levels on the tubing. We can pull harder with a larger safety factor.'

Hampton Fowler suggests that tapering the tool string may extend coiled tubing vertical depth capabilities by as much as 30%. The development, he says, is a response to the reality 'that at some point in time we are going to run out of yield strength. Coil pipe manufacturers introduced 50,000lb yield strength 35 years ago and over time have brought it up to 120,000psi yield material but at some point we are not going to be able get any more'.

The practice of using high yield strength coil in the upper section and lighter, thinner wall pipe on lower sections to maximize overall pull capacity is not a new one. But until now, it has been accomplished only by increasing wall thickness through reduced internal diameter, a choice with obvious drawbacks for a technology often dependent on hydraulics to accomplish its work.

'Others have gone to the point of a single wall that gets thicker at the top,' says Fowler. 'The challenge was to have the same or larger ID to get better flow and less friction losses while the tube gets bigger as it comes up and so has more pull capability.'

Since its inception however, coiled tubing surface equipment that provides pressure sealing and injectors that push the coil into the hole against pressure or along horizontal sections have been designed around a uniform outside diameter tubing.

'Now the challenge is how to set up surface equipment for variable sizes, not only on the injector but through the stripper and then the pressure control equipment where several ram sizes are needed,' Fowler says. 'And these are not low-pressure wells. They are high pressure wells and we have to make sure the equipment can seal.'

Halliburton says it overcame these obstacles by working with tubing and equipment manufacturers and its own engineering team and rates the concept very promising. It is now in yard trials at the company's facilities in Duncan, Oklahoma, scheduled for field trials in late September and commercialization of a first version, single taper expected in 2005. Developing multiple tapers is obviously more problematic but not impossible to envision say the Halliburton experts and the idea is being worked on.

As is often the case in research and development, the multiple OD string may hold an unexpected bonus. While the project was driven by the desire to increase yield strength at the upper end of the tubing in order to pull loads from greater depths, the solution may have delivered a tubing that can be pushed farther along horizontal sections, something that would sync well with current industry trends.

'As operators are drilling longer horizontal wells one of the challenges we have is pushing the pipe out into the horizontal because in the heel we have enough compressive loads that the pipe buckles,' Fowler says. 'The bigger the tubing OD, the more resistance it has to buckling. As the compressive loads start to build we typically see the largest ones back towards the heel. So even if you are getting compressive loads and some buckling, you can step up the size at the heel and we see a very interesting possibility to get around some of the limitations of coiled tubing we have seen in the past.'

Heave away
While the spars, floaters and TLPs, with their generous space and very large cranes afford new opportunities to coiled tubing, they also bring the challenges associated with movement and heave compensation. Until now, coiled tubing used on platforms subject to vertical and lateral movement has relied on the heave compensators attached to the platform rig, says Schlumberger coiled tubing surface efficiency champion, Robin Mallalieu. But by definition that meant the rig must be over the same well as the coiled tubing unit.

Now Schlumberger is introducing its CT TComp, a heave compensation system designed into the lifting frame of their coiled tubing unit to allow operations independent of the rig. 'Today, pretty much everyone has a solution for a floater where we go in to the rig with a lift frame and are compensated by the blocks of the rig,' says Mallalieu. 'Compensation is built into the heave compensator itself so we can work in the derrick on a spar. When the spar moves away and leaves a large space we can actually span that space with the frame using the rig beams and it will stand alone and independent once it is rigged up. So we can do interventions on the deepwater applications.'

On a TLP, movement is also lateral which creates added stresses transferred from the coiled tubing unit to the wellhead which generally is able to handle stresses of no more than about 50,000lbs. 'We have developed a passive-active compensated system that can work on a TLP,' reports Mallalieu. 'It can go through the derrick or stand alone while the rig is working on another well.'

Taking a page from the company's CT Seas book, the whole unit goes offshore in two sections: an upper section comprised of a gooseneck and injector and a lower section with BOPs. The system is rated for up to 13,500psi working pressure and the BOPs are pre-assembled and pre-tested before shipping.

Stress generated by TLP lateral movement during coil operations is deflected from the wellhead by a 15ft joint of flexible titanium riser placed directly on top of wellhead with guides that grip the titanium riser when breaking off the well or rigging up. 'Any lateral movement is taken up by the titanium riser so we are not putting any additional forces on wellhead or the platform itself,' Mallalieu explains. 'The wellhead is automatically monitored and we maintain the weight applied to the wellhead by the compensation system. For instance, as you are running pipe in the hole, as you go deeper, weight increases and the system compensates automatically for that in and out of hole.'

As a result of a survey that included 5000 hours of offshore coiled tubing operational data, Schlumberger reckons it can save operators 16% of the rig up and rig down time using the new frame.

Rated to 350t, the frame can be rigged up on the deck independent of the rig, stands about 63ft high, has an operating window to allow deployment of about 35ft of tools and is designed for up to 7ft of compensation.

'The whole system has two other advantages,' says Schlumberger's Zemlak. 'The ability to stand alone with compensation to allow the rig to move elsewhere, plus on a rig you still have to have a driller on the stick during the whole operation which on average can take several days and you need someone standing there the whole time making adjustments. With CT TComp this is automated.'

The system also includes a standalone power pack with PLC controls that work off load cells mounted on the riser and the frame. 'There are also some redundancy systems built in,' says Mallalieu. 'For instance, if we lost the power pack and PLC controls we could tie into our coiled tubing power pack and, in an emergency situation, run the compensator manually.'

The first commercial job was scheduled for load out 30 September for a Shell campaign of several wells and Zemlak reports three separate West Africa operators have requested designs for the systems with inquiries also coming from the North Sea where, he says, the ability to work on a platform independent of a rig 'will be critical'.

Improving with age
There can be little doubt that coiled tubing has come of age primarily because hugely improved manufacturing and monitoring processes allowed the tubes themselves to shed their well-earned reputation for unreliability. As a result coiled tubing has gone from a tool of last resort to one operators would do well to consider during planning stages for inclusion on their most sophisticated projects.

Today, driven by the economics and scales of the shelf and deepwater, innovations are endowing coiled tubing with the potential to not simply accomplish a task at minimal risk, but to actually add to operators' bottom line. As such, the time is now for oil companies to forget their impressions from the past and avail themselves of what is essentially a mature tool. OE

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