Integrated services by Weatherford and Schlumberger implement a practical solution to a complex gas production stabilization problem in the Dutch North Sea.

This story tells how a thorough understanding of production dynamics coupled with a PhD in plumbing helped solve a delicate, but very complex production problem in the Dutch sector of the North Sea.
The gas well K6-DN2 is operated by Total E&P Nederland, and was initially completed with a tapered 5-in. x 41/2-in. x 31/2-in. chrome production string in 1992. The well produces from a 436-ft (133-m) perforated interval and a 1,312-ft (400-m) horizontal 41/2-in. slotted liner. A corrosion-resistant alloy (CRA) production string is necessary because of the presence of 4% CO2 along with bicarbonates and chlorides in fluid composition.

For several years, the well had been slugging water and continuous gas production was not possible. However, through nodal analysis, a practical solution emerged. If a smaller diameter velocity string could be installed, gas production could once again be stabilized. A fairly straightforward solution was postulated in which a 23/8-in. CRA velocity string would be emplaced in the well. Achieving the solution was another matter altogether.

First, there was no rig on the satellite platform which was intended to support minimal slickline and wireline operations due to crane and deck space limitations. The workover operation had to wait until a jackup could be mobilized from a nearby slot recovery operation. Second, it was determined that a live-well intervention was necessary to maintain the delicate dynamic integrity of reservoir drainage. Killing the well would likely cause its demise.

Integrated solution sought

Total assembled a team of completion experts from Weatherford and coiled tubing experts from Schlumberger. Together they designed a completion consisting of a corrosion-resistant two-stage velocity string that could be deployed into the live well using coiled tubing. Mechanical hurdles were considerable. There were several restrictions in the existing completion and a suitable landing that could support the weight of the entire string had to be found. Traditional packers able to pass through 3.813-in. restrictions could not reliably set in 5-in. tubing and support the string weight. Alternative suspension points had to be located. In addition, nothing could jeopardize the integrity of the safety valves or restrict their operation.

Prior live well workovers had used snubbing units, but Total wanted to use coiled tubing mainly because space and cost limitations did not allow the deployment of a hydraulic workover unit. By happy coincidence, a coiled tubing unit was onsite following stimulation work on a nearby well.

The search for suitable landings for the string eliminated several early considerations. Finally, it was decided to run the string in two separate operations. First, a three-section lower string of 1,262-ft (385-m), 2-in. diameter coiled tubing tailpipe on bottom crossed over to 2,132 ft (650 m) of 23/8-in VAM flush joint 13% Cr CRA tubing would be supported by a retrievable no-go locking mandrel (RNG). Above the RNG mandrel the third section consisting of an additional 2,230 ft (680 m) of 23/8-in VAM flush joint tubing was run. A polished bore receptacle (PBR) topped off the bottom string.

The upper string had the PBR stinger on bottom followed by 7,874 ft (2,400 m) of VAM 23/8-in. flush joint 13% Cr tubing. It was supported by a specially-built retrievable 3.78-in. PB Packer designed to set in 5-in. 15 lb/ft tubing. The packer was designed to have extended slip reach. When installed the PB packer only had to support to upper string, the RNG lock mandrel supported the lower string.

Meanwhile over at Schlumberger

Running jointed tubing using a coiled tubing (CT) injector head is not new, but it requires some special rigging. Usually a basket is rigged above the injector head where operators make up the tubing connections with tongs. However, on the K6-DN2 well Total decided to take advantage of the presence of the rig to handle the tubulars. Accordingly, the injector head and six-ram BOPs were rigged below the rig floor and the CT gooseneck and pipe straightener assembly was rigged so it could be set back when it was not being used to guide the coiled tubing. Safety was paramount. A frame was adapted from a hydraulic workover jacking frame to support the lubricator and injector head, with sufficient clearance to allow changeout of pressure control equipment as the tubing size transitioned from 2-in. to 23/8-in. At all times double barrier pressure control was employed.

Because the injector head remained in the worktrain at all times, transitioning between running coiled tubing and jointed pipe and back again was smooth. The CT coil, gooseneck and pipe straightener was positioned above the rig floor so it could be rigged up quickly, and the job continued. Both the lower and upper strings of the velocity tube assembly were deployed on CT, and after some experience up to 26 joints of flush joint tubing per hour could be run into the well.

Just in case

In the event that either the RNG lock mandrel or the PB Packer failed to seal, a dual well control barrier was employed. Dual pump-out subs were pinned into the bottom of the 2-in. tailpipe and a glass disk breakout sub was run with the PBR stinger.

Once the velocity string was set and tested and Total was satisfied with the integrity of the seals, nitrogen was used to shear the glass disks and pump out the two pump-out subs from the bottom of the tailpipe.

The full live-well recompletion was accomplished in 7 days, as per plan, and with no formation damage. The team reckoned the job represented a 65% saving over a conventional workover, which in any case they deemed to be uneconomical.

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