Remote open close catching on

August 1, 2011

The benefits of 'remote open close' technology are increasingly being sought out by operators as a new way to approach well interventions and completions, particularly in deepwater and subsea applications where rig time savings are critical. Red Spider's Andy Thomson explains.

Aberdeen-based Red Spider initially set out to focus on well intervention work but the flexibility of the technology coupled with demand from operators for further cost-effective and safe solutions has led to additional Remote Open Close Technology applications tailored to the particular challenges of completion work. The company's first tool to use its patented Remote Open Close Technology was eRED – a downhole computer controlled valve that can be opened and closed by remote control as many times as required using a series of different trigger and action combinations, without the need for intervention or control lines, saving time, money and removing risk.

The valve, used by 13 operators on 24 fields, is estimated to save up to $900,000 during single subsea completion operations, typically reducing slickline runs from eight to one. In subsea workover operations, savings of up to 36 hours and $800,000 have also been recorded in a single job.

While it was developed to be used in intervention-type plugging operations, eRED began to be used for a variety of other applications including: shallow set for tree testing and change out, deep set for completion deployment, packer setting and tubing testing, annulus short string plug in vertical subsea trees, liner deployment with external swellable elastomers and zonal isolation during TCP gun firing.

Further requests from operators for more applications in the completion of wells resulted in extensive research and development work leading to eRED-FB and PowerBall.

Both new technologies received funding through ITF, the oil & gas Industry Technology Facilitator. Operator members, including BG Group, Chevron and Maersk Oil, invested in the development of the technology.

ITF involvement was crucial to delivering the products in a relatively short timeframe as the body secured commitment from the operator sponsors. Through the ITF process, Red Spider was able to pool the knowledge from the project sponsors, drawing on industry experience to close-out potential problems that may have delayed development of the technology.

eRED-FB is the tubing mounted version of eRED. It consists of a remotely actuated full-bore ball valve which can be opened and closed multiple times, controlling flow through the tubing without the need for any well intervention or an umbilical control line.

The use of eRED-FB completely eliminates slickline intervention from completion operations, resulting in savings of up to 32 hours and $1 million in subsea scenarios. Moreover a mechanical downhole barrier is present at any time during operations, to be activated upon request and to take control of the well.

In addition, the eMotion module which controls eRED-FB is particularly flexible and can be used as a downhole pump with third party tools. eMotion can be remotely commanded to pump fluid into any hydraulic device like frac valves and flow control sleeves to provide remote control of devices without requiring control lines up to surface.

PowerBall is a reservoir isolation barrier designed to be run open, then subsequently closed during lower completion deployment and finally to be permanently reopened by remote command for production or injection to commence. It can operate in any type of well, including cased and open-hole wells.

Remote opening of PowerBall happens with no pressure cycles, but on detecting a specific trigger much as with the eRED, thus resulting in a more flexible and faster operation, with potential savings of up to 12 hours and $250,000.

Well completion technology challenges include optimising lower completions, which PowerBall achieves by using electronic logic in its primary opening mechanism. This offers the user increased flexibility during the opening sequence; which is another benefit as the tool set-up can be changed, if required, on the well site.

Debris is a well-documented challenge during well completion activities as the technologies utilised are often exposed to large amounts of debris, leading to operational failure and costly shutdown time. By moving the mechanical parts of the ball mechanism below the closed ball area of the tool, and as a result, protecting them from debris, PowerBall offers maximum reliability in dirty environments. Avoiding remedial action due to failure of a fluid loss device can result in savings in the region of $2m.

Two eREDs were used in series for the first time in a recent North Sea completion, with each tool programmed to respond to its own unique command: a specifically applied pressure over a given time period.

The Eastern Trough Area Project (ETAP) is an integrated development of seven different reservoirs. Four separate fields are operated by BP: Marnock, Mungo, Monan and Machar. The Machar well is a subsea producer tied back to the ETAP platform. The de-completion, sidetrack and two stage re-completion was performed from a semisubmersible rig. eRED was previously used successfully in several platform and subsea operations for BP in the UK and Norwegian sectors.

Following the de-completion and side track, the lower completion and liner hanger were RIH (run-in-hole) to depth in the newly drilled 6in open-hole section. A ball was then dropped and circulated to depth. The completion was then pressured up to set the open hole packers. The pressure was increased to set the liner hanger and release the running tool. In the upper completion, the two traditional plugs were replaced with eREDs; primarily for the benefits of improved safety and removal of risk by removing wireline runs. Both eREDs were pre-installed onshore, one as a deep-set barrier below the production packer (on a standard 4.313in lock) and the second in the tubing hanger (on a standard 4.875in lock). Both eREDs were fully tested from above and below before shipping as normal.

Offshore, a laptop was connected to the eREDs and diagnostic checks were made to ensure they were operating correctly. The upper completion was then RIH with both eREDs fully open allowing fluid to bypass and allowing pressure to access the lower completion for well control. With the completion at depth, the tubing hanger was landed and locked in place.

The deep-set eRED was then instructed to close with a pre-programmed pressure and time command of 750psi (target window of 500-1000psi) applied pressure to the tubing for 10 minutes. A delay of five minutes was included to allow for bleeding-off of applied pressure prior to the ball closing.

The production packer was then set hydraulically by pressuring up against the deep-set eRED. The first attempt to pressure test the production packer was unsuccessful. As the eRED was set up with repeating triggers, the instruction to re-open the ball was given with the same pressure and time command of 750psi (target window of 500-1000psi) applied pressure to tubing for 10 minutes (but no time delay). Following troubleshooting, the eRED was then given the instruction to close again with the same pre-programmed pressure and time command. The production packer then pressured tested successfully on the second attempt.

The tubing hanger eRED was then instructed to close with its different preprogrammed pressure and time command of 1750psi (target window of 1500-2000psi) applied pressure to tubing for 10 minutes. A delay of five minutes was also included.

With both eREDs now closed providing a fully testable dual barrier, the drilling BOP was nippled down and the subsea tree installed and tested. Still without any form of intervention, the tubing hanger eRED was opened remotely with its command trigger. Positive feedback that eRED had opened was observed at surface by a tubing pressure drop. The deep-set eRED was then opened remotely with its command trigger. Again, a tubing pressure drop observed at surface showed the eRED had opened.

Both eREDs functioned as designed, enabling BP to remotely open and close and then perform multiple tests against them. A total of six deep and four shallow wireline runs were eliminated from this particular operation resulting in a significant reduction in HSE exposure.

Success of the operation determined there was:

  • reduced exposure to potential WoW (waiting-on-weather) to rig up slickline and general risks associated with interventions – potentially very significant for winter operations;
  • reduced POB requirements (four man wireline crew required later in the programme and for shorter duration);
  • reduced slickline service costs for both personnel and equipment;
  • operator confidence to remotely open and close eRED; and
  • pre-installed eREDs and annulus filter sub reduced 12 slickline runs to two. OE

Andy Thomson is the product development manager for Red Spider, with extensive experience in well engineering, including completions, well performance optimisation and control. He previously worked for both major and smaller service companies for over 25 years in the UK and internationally. He started his career with Gearhart Geodata and worked for Halliburton immediately prior to joining Red Spider in 2010.



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