Optimal targets: BP's Clair Ridge facility in the UK West of Shetland area Photo: BP
Use of new technology at West of Shetland project could be step change for real-time well monitoring
BP’s massive twin-platform Clair Ridge development in the UK West of Shetland area could see later this year the first deployment of groundbreaking new distributed fibre optic technology for real-time monitoring of wells.
Distributed fibre optics is a growing technology that allows real-time monitoring of wells without the requirement for intervention, Lina Serpa, vice president wells, BP North Sea, tells Upstream.
At Clair Ridge, BP has been working closely with GE-controlled service company Baker Hughes (BHGE) to develop what is thought to be a world-first system.
BP says this will bring step-changes in surveillance data and well-performance functionality, as well as provide a stepping stone to introducing fibre optic data to subsea wells for the first time.
“The new system will have huge value in terms of how we optimise performance of our wells globally,” says Serpa.Data gathering
Fibre optic data-gathering systems have up to now been limited to a single line, limiting data gathering capability and options for well-completion design.
However, this new distributed fibre optic system will be able to infer, in real time, information about multiphase inflow performance, or how much oil, gas and water is coming from which parts of the well.
It will also be able to infer information about well integrity, sanding performance and gas lift performance of wells.
The technology works by shooting light down a fibre optic line that is deployed on the well completion. Thermal and acoustic effects in the well distort the light, which can be interpreted at the surface to show in real time how the well is performing downhole.
The technology therefore does not provide direct measurement of flow, hence why the information is “inferred”.
Systems that rely on a single fibre give either distributed temperature or acoustic measurement, but not both simultaneously.
Existing distributed fibre optic technology can gather data during a well intervention.
However, this is not permanently installed, so it does not allow continuous monitoring, but only for the duration of a well intervention. Flow profiling is also limited, as the fibre is internal to the completion.
A real-time system with a number of fibre optic lines has been conceptually available for some time from BHGE.
The company has an “intelligent” wet-mate system that utilises a downhole wet-mate connector, a fibre-optic component with up to six contacts, together about the size of a human hair, which comes together to connect the upper and lower completion.
The modular wet-mate system also allows for electrical and hydraulic connections.
This makes possible a significant upgrade in data-gathering capability on the well and enables the inclusion of downhole pressure and temperature gauges in the reservoir.
BP says it has supported a rigorous re-engineering of the system in collaboration with BHGE over the past 18 months.
This has included design changes, reliability assessments, system testing and development of robust operational procedures.
Serpa says the challenge is heightened by the harsh well environment and the fact the tight tolerance, highly sensitive connection has to be made up to 3000 metres from the rig floor.
The system also has to perform reliably over the life of a well and be compatible with a number of additional well systems that are used to shut off zones and optimise production in response to the fibre optic data.Optimising production
The completions on the Clair Ridge wells have been designed so they can respond to the data coming in, optimising production by shutting gas and water-dominant zones through the use of remotely actuated sliding sleeves and robust open hole zonal isolation.
In collaboration with Weatherford, sliding sleeve technology has been developed along with an open-hole zonal isolation anchoring system to improve reliability.
“Clair Ridge is a massive, naturally fractured field with generally poor matrix quality rock – good well performance relies on intersecting fractures,” says Serpa.
“Our understanding of placement and long-term behaviour of fractures is poor. The fibre optic data will be used to understand the performance of the fractures in real time in parallel with conventional well surveillance data.
“This will allow for well-placement decisions in field development and well-operational decisions to be made via use of complementary sliding sleeve and zonal isolation technologies.”
The technology also has a number of other functions. The lines can be used to monitor well integrity, sand performance and artificial lift performance in addition to giving in-situ reservoir pressure and temperature data.
It also reduces the requirement for conventional well intervention surveillance activities such as production logging, reducing operational expenditure and demands on platform activity.
If successful on Clair Ridge, the technology could be applied more globally in BP.
“The value of this is, as of yet, unrealised,” says Serpa.
The $5.8 billion Clair Ridge project produced first oil in November.
It is the second phase of development at the giant field where the UK supermajor is already examining future phases.
BP, with partners Shell, Chevron and ConocoPhillips, is sitting on in-place resources of more than 7 billion barrels at the Clair field, discovered in 1977 and first exploited in 2005.
The initial Clair phase one development targeted recoverable resources of 300 million barrels, with BP aiming to produce about 640 million barrels from the larger Clair Ridge scheme.