journal of petroleum technology - remotely operated valve eliminates intervention in well barrier...

7/23/2019 Journal of Petroleum Technology - Remotely Operated Valve Eliminates Intervention in Well Barrier Placement

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TECHNOLOGY UPDATE 1

Remotely Operated ValveEliminates Intervention inWell Barrier Placement

Andrew Cooper, Halliburton

In offshore deepwater and extended-

reach wells, placing and removing

deep-set barriers is often challenging

largely because of the distances anddepths involved. With operations

more complicated in deviated and

lateral wells, the challenges multiply.

Often, coiled tubing ortractor systems

are needed to set and retrieve deep-

set barriers, increasing the expense,

the time to completethe operation,

and the inherent environmental and

personnelrisks.

Although placing the second, shallow-

set barrier may be easier, it still involves elements of risk and

significant expense because of the rig time needed. In some

cases, up to 15 interventions are required during the

completion phase of a wells construction, thus resulting in

considerable costs and increased safety risks.

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However, if the barriers were deployed as an integral part of

the completion string, and the well could be plugged or

unplugged remotely, as often as required, no well intervention

would be needed. The potential savings in rig time and the

reduced risk would be significant, and having this capability

could change the way that wells are completed.

A New Way to Complete Wells

A major step toward achieving this was taken in 2008 when

Halliburton-Red Spider successfully deployed the eRED valve,

a remotely operated ball valve that could be deployed on a

lock or bridge plug to replace traditional plug and

prong barriers.

The valves primary advantage was its remote operability that

enabled it to be opened and closed as often as needed, eachtime eliminating an intervention. When the well completion is

finished, the assembly is retrieved before the well is brought

online. The valve has been used in about 200 jobs with more

than 400 remote actuations successfully performed.

It soon became clear that a tubing-mounted, full-bore version

of the valve would provide greater benefits because it would

not require retrieval. Thus, the eRED-LV valve (Fig. 1) was

developed, which enables operators to set or remove wellbarriers at any time without intervention or the use of surface

control lines. With retrieval unnecessary, additional savings in

rig time are achieved.

Valve Operation

The full-bore valve uses the developers Remote Open Close

Technology, which enables the operator to activate the valve

remotely without surface control lines. Communication isachieved by applying a predefined pressure at surface for a

predefined time. Integrated electronics are programmed to

recognize this unique pressure/time window as a command

trigger to either open or close the valve.

Pressure applied outside the defined values is ignored by the

valve. This means that pressure can be applied repeatedly to

the tubing, for example, for integrity tests or packer setting,
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without the risk of inadvertently activating it.

The system is highly flexible there is no fixed operational

procedure for its operation. Each well operation is planned on

paper and the valve is programmed subsequently to suit

the application.

Should the valve fail, the ball is mechanically shifted to theopen or closed position by use of a wireline-deployed shifting

tool. The fully open position of the ball is confirmed by

observing a pressure drop at surface and by drifting the

shifting assembly through the valve.

Target Applications of the Valve

The technology can be used in any application in which

wireline plugs are normally used. It is able to achieve the

same results as wireline plugs without requiring repeated

interventions or the use of surface control lines. It is also

particularly suited to completion deployment for setting

production packers and establishing barriers to secure the

well while rigging down blowout preventers and installing

Christmas trees.

Multiple tools can be deployed in a single well, with a unique

signature established for each tool. This capability allows the

operator to communicate with and operate each valve

independently, thus considerably increasing the usefulness of

the valve technology.

Testing and Commercialization

The development project of the full-bore valve began with

testing at a component and subassembly level to prove that

the technology would work and could be integrated into the

main completion design. Potential failure modes were

considered, tested, and documented to ensure a robust final

design. Where applicable, industry standards were adopted

for example, the barrier module was qualified to the newly

introduced ISO 28781:2010.

Once fully qualified, the technology was introduced to oilfield

operations, with its first successful job completed in August

2012 offshore Equatorial Guinea. The technology has since


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been deployed successfully in the North Sea.

Case Study: Equatorial Guinea

Deployed as an integral part of the completion below the

production packer, the full-bore valve was run into the hole in

the open position to approximately 9,100 ft measured depth

at a deviation greater than 80.

With the tubing hanger landed, locked, and tested, the valve

was commanded to close using a preprogrammed

pressure/time trigger of 1,000 psi for 25 minutes. This

pressure was applied against the closed flapper-type fluid loss

device in the lower completion. The packer was set

hydraulically against the closed valve and the tubing was

pressure-tested. The subsurface safety valve was then closed,

inflow tested, equalized, and reopened.

The programmed full-bore valve was reopened using a

different pressure/time trigger of 2,250 psi for 25 minutes. To

prevent a pressure surge on the lower completion, a

programmed delay of 10 minutes allowed the tubing pressure

to be bled down to 600 psi before the ball opening (Fig. 2).

Opening of the valve was verified by a downhole

pressure/temperature gauge reading.

The installation eliminated the need to deploy a conventional

deep-set barrier and maintained the maximum production

flow area. A rig-time saving of 1 days was achieved with

commensurate cost saving. In addition, all risks associated

with the intervention in a highly deviated subsea well

were eliminated.

Technology Evolution Continues

The remotely operated ball valve technology has evolved from

the through-tubing version that is retrieved by wireline at the

end of the completion process to the tubing-mounted, full-

bore version that need not be retrieved. The technology has

proved that it can eliminate interventions during completion

deployment, thereby saving time and expense, and removing

operational risk to the environment and personnel.

This year, the technology development has continued with the
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addition of a remotely activated, tubing-mounted circulation

sleeve valve that will eliminate well interventions that require

fluid displacement after the packer is set. The new circulation

valve is slated to be deployed in Norway by year-end.
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