Gaining control

April 1, 2017

Inflow control valves and in-well fiber-optics have given Nexen far greater visibility of what’s going in and out of their reservoirs on the Golden Eagle field. Elaine Maslin reports.

Golden Eagle with the Safe Caledonia alongside. Photo from Nexen.

When the Golden Eagle field was discovered in 2007, it was one of the biggest oil discoveries in the UK North Sea, after the huge Buzzard field.

But, with a complex reservoir and some uncertainty over the level of connectivity and aquifer support, careful consideration had to be given over how to develop the field.

Nexen Petroleum UK opted for so-called intelligent well technology, using interval control valves, which allows for different reservoir zones to be opened and closed remotely. The technology, which includes fiber-optic sensing, meant Nexen could reduce the number of wells it needed to drill on Golden Eagle. Using this technology has also given Nexen far more information about its reservoirs than it would have with conventional well completions, reduced intervention requirements and meant the waterflood could be tracked and managed more efficiently.

The field

Golden Eagle is 100km northeast of Aberdeen and was developed using a wellhead and production, utilities and quarters platform, with two subsea tiebacks to date (Peregrine and Solitaire). The development, which came onstream in October 2014, under budget and ahead of schedule, has 19 wells, comprising of 14 producers and five water injectors. All were completed with fiber-optic downhole distributed pressure and temperature monitoring. Most have intelligent completions, i.e. interval control valves (ICVs). The two subsea satellites, north and south drill centers, also have production and injection wells with fiber-optic intelligent completions.

The main reason for using intelligent completions was the reservoir, which is two different formations, Punt and Burns, says Craig Durham, production engineering advisor at Nexen.

The Burns reservoir is the oldest, and underlines the Punt sands – a former meandering riverbed, which makes it quite layered and connected in different ways, Durham says. Burns is a larger area, connected to a large aquifer that gives pressure support, but is not connected to the Punt sands, which rely on water injection to produce.

Managing this scenario would be, “very difficult without intelligent technology, without being able to control flow from separate zones and being able to inject into separate zones. This is why we went for intelligent technology,” Durham says. “All the wells were completed with fiber-optic, downhole pressure, temperature and flowrate monitoring for the production wells. Most of our wells are intelligent wells.”


In the reservoir section in a normal well that requires sand control there would be a production packer, some sand screens, maybe some open hole isolation, Durham says. “In an intelligent well, on the other hand, it is a lot more complicated.”

On Golden Eagle, Nexen divided up the sand face section into three separate zones. “We still have a production packer and we still have pressure, temperature and flowrate monitoring at the top, but we also have an interval control valve (ICV) immediately under the first packer,” Durham says. “We still have sand screens and open hole isolation. But, then we have a second ICV and second pressure, temperature and flowrate monitoring and so on into the third zone.”

The number of zones is limited to three because the ICVs have hydraulic controls; the number of control lines that can physically fit into the tubing hanger and across a completion is limited.

Pressure and temperature data are gathered from the tubing side, but also the annulus, so that if a zone is shut in, engineers know what the reservoir pressure is. The fiber-based distributed temperature sensing system (DTS) runs along the length of the liner string, and provides useful information for inflow performance, because temperature changes at different flow rates in the well. These data supplement information from the single downhole flowrate meter, which only gives a cumulative rate – not what is coming through each zone.

The DTS is especially useful on the water injection wells, because of the geothermal temperature gradient when you shut a well in and get “warm back.” The well heats up in quite close proportion to how much water has been injected, Durham says. “Through thermodynamics, heat conductivity etc., we’re able to quantify, almost to production logging standards, what the percentage injection is into these zones.” This includes subsea wells, where production-logging quality data can be gathered, without having to intervene in the well, in any way.

It’s not quite as simple on the production wells, where the temperature trend is not as great and the quality of the DTS resolution is not as good. But, this is being worked on, Durham says. They are also doing temperature transient analysis, using the single point temperature gauges and seeing how temperature changes in proportion to flowrate, which has offered useful information.


The ICVs themselves can have 10 positions, from fully closed to fully open, making them chokable, which is useful for water injection wells, Durham says, to reduce any thermal fracking effect in the reservoir due to the shock from the cold water coming in, as well as being able to vary how much is injected into each zone.

The ICVs are controlled using SmartWell Master, which allows the operator to select a position at the click of a mouse and SmartWell Master sets out the control sequence to open or close the sleeve. The operator has a screen with just the valve status, while production engineers get all the data they want; pressures, temperatures, flowrates, what flowrate is going through each sleeve, etc., viewed through an integrated visualization and management system.

“We can see temperature on each zone, annulus and tubing side, the pressure drop across the sleeve, the downhole flow meter, what the measured rate is and what the calculated rate is,” Durham says. Five different methods are used to estimate what the flowrate should be and it’s compared with the downhole meter and shown in green if they’re within 5%, to ensure everything is as it should be.


A big benefit of the ICVs, with monitoring, is flexibility, Durham says. “In a normal well, if you set an isolation plug to isolate water breakthrough, you isolate production, too, so it’s not very efficient. In later life, you might want to take these plugs out to get the last oil out, but they might not be easy to get out,” Durham says.

A zone can be shut, and the annulus gauge monitored, and re-opened. “If you are injecting in a well a kilometer away and see the pressure going up, you know you have connectivity. From a reservoir management point of view, there’s a huge amount of information that you would never have on a conventional well.” Water cut from individual zones can also be ascertained and what injectors are connecting with which producers monitored.

Instead of taking months and using up a 12-man crew for a wireline operation to shut in a zone, the ICV can also be moved in just hours, in theory, although Durham says, in reality, ICV moves are planned a few weeks in advance to ensure that the maximum amount of information is obtained from the move.


To date, 19 wells have been drilled on Golden Eagle, four of those are subsea. Some 36 ICVs have been fitted, 10 of those are subsea. The wells contain a total of 14 optical flow meters, three of which are in subsea wells, and 164 fiber-optic sensors.

Just over 100 ICV moves had been made, as of early December 2016. The ICVs are moved every six months as a minimum, to prevent sticking, and to gain opportunistic data. Forty of those moves were in the subsea wells. About 20 pressure build up analyses have been done on individual zones, as well as four water injection distributed temperature surveys and a couple of temperature transience analyses, Durham says.

It’s not all been perfect. The ICVs have not been moved, on the first subsea well, due to subsea control line contamination, he says. The fiber-optic sensors also failed on the same well, due to an issue with the wet mate connector. Because different computer systems control the ICVs from the rest of the platform, the interface between the two has sometimes tripped, requiring an engineer call-out to reset. But, this is still much cheaper than sending a 12-man wireline crew out for an intervention to achieve the same result in a conventional well, Durham says.

And, thanks to these tools, 40 different zones on Golden Eagle are being produced from only 19 wells, which has helped reduce the well count, and enabled greater reservoir management, understanding and operation.

“Intelligent wells are more expensive compared to a normal well with more rig time and hardware. But, overall, there’s lower total capex because we’ve completed fewer wells and there’s reduced opex as we will not need as many interventions,” Durham says.

Nexen Petroleum is owned by China’s CNOOC and operates Golden Eagle (36.54% interest) with partners Suncor Energy (26.69%), Maersk Oil (31.56%) and Dyas EOG (4.74%) and Oranje-Nassau Energie (0.46%).

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