Wireless, fiber-optic technologies show off their value to well integrity

Wireless and fiber-optic technologies are both proving their value in well-integrity monitoring, as demonstrated by two speakers at the 8th Decommissioning & Abandonment Summit, which took place in Houston in the last week of February.

Fiber-optics is proving itself in well integrity (Image credit: royaltystockphoto / iStock)

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Metrol Technology shared a recent case study of how wireless telemetry was used to reduce operational and commercial risk by monitoring the well-barrier envelope during change-outs of four subsea trees at a project in the UK North Sea.

And Fotech Solutions demonstrated how fiber-optic sensing – technology commonly used to detect movement near pipelines, railway tracks or perimeter fences – can be used to complement wireline to conduct a well diagnosis prior to abandonment.

Across the entire lifecycle

Wireless telemetry typically involves inserting a signal from surface at the wellhead, Taylor explained. There are no penetrations, no feedthroughs, no drilling; the tools are simply attached, and transmit right through to wireless transceivers installed lower down in the well.

This technology can be used to actuate intelligent devices such as sliding sleeves, downhole sampling tools, interval control valves, and tubing-conveyed perforating firing heads, he said, adding that these devices can be installed at any stage throughout a well’s lifecycle: including well construction, well-testing, completions, and abandonment monitoring.

In the North Sea case study, Metrol installed gauges with the shallow-set plugs which were being run as part of the base plan. Interrogation took place via wireless subsea-telemetry units placed on the subsea architecture; all subsequent data retrieval was carried out offline, enabling the client to react if well-integrity status changed at any point. The modular nature of Metrol’s designs allowed simple interfacing with the existing downhole- and subsea- completion equipment, while data was collected from gauges installed in multiple locations within the well, Taylor said.

“During pressure testing of the shallow-set plug in one of the wells, Metrol’s gauges immediately detected a leak and an impaired barrier. Although the client could see this leak from surface they didn’t know where it was coming from. By having this downhole set of eyes in the well, the diagnostic process was significantly sped up, resulting in accurate decisions made dynamically, on the critical path, without costing vessel time,” he said.

An abnormal pressure reading warned Metrol of an impaired barrier (Image credit: Metrol)

The barriers and gauges were left in the well for several months and a pressure build-up was noticed below the upper plug in one of the wells, suggesting the completion string was charging up to reservoir pressure. The pressure reading should have been a nice flat line, Taylor said, but instead was showing a gradual buildup over several months, indicating that the deep-set barrier was impaired. Knowledge of this failure prior to the next phase of the intervention allowed the client to plan change efficiently, and apply for impaired-barrier exemption prior to arriving on location, he added.

He summarized the benefits of wireless monitoring with the following: it provided the opportunity to reduce operational risk, in keeping with the objectives of the project; enabled operations to be split over two seasons, avoiding bad winter weather and optimizing the rig time; provided certainty in decision-making; and by conducting data acquisition as an offline activity, it reduced the risks presented by having wire in the well.

Working in tandem

Stuart Large, Fotech’s Product Line Director, described how his firm’s distributed-acoustic sensor (DAS) service is being used to conduct downhole monitoring months before abandonment – allowing operators “to see the entire wellbore at one time”.

By detecting distinct acoustic signatures, DAS enables operators to visualize the energy generated by leak events, including small leaks that might otherwise be missed by traditional detection techniques. The DAS interrogator unit uses a laser to send thousands of pulses of light every second into an optical fiber deployed in a well. A small amount of that light returns to the DAS interrogator through the process of Rayleigh backscatter, which DAS continually monitors. When sound and vibrations disturb the fiber, the characteristics of that backscatter are changed. The DAS interrogator records those changes to identify and locate the disturbance.

In well-integrity investigative work, prior to abandonment, the fiber is most commonly deployed by an intervention method, such as wireline, slickline, or coiled tubing. Here the acoustic disturbance at each point along the fiber allows engineers to visualize and record what is going on down-hole in real time along the entire length of the well.

“As fluids move through perforations into the wellbore they make a noise,” Large explained. “We can recognize the signatures of those noises. We’ve got sand detection, for example: oil producing with sand will make a different sound to nice, clean oil as it comes through those perforations.”

Each type of well-integrity problem has a different signature, Large said. He gave the example of gas leaking through a very small crack in the casing, saying it “can make a very high-pitched whistle, whereas bubbles of oil moving through an annulus typically make quite a low frequency bubbling sound”.

Large explained how DAS and distributed-temperature sensing, or DTS, are used in conjunction with more-traditional wireline-logging tools to reduce the amount of time needed to conduct a well diagnosis.

The process begins by lowering wireline logging tools to the bottom of the well, he said: “We can see it and listen to the wellbore along its entire length for a period of time. During that time, we can manipulate the well; we can try out different pressures, different flow rates, different choke settings – in order to see if we can stimulate any potential leaks that may exist in that well.”

DAS and DTS are then used to highlight particular areas of concern, with wireline logging tools pulled up to these areas to conduct a closer diagnosis. Because of the often-sporadic nature of leaks – which can “perhaps just burst out some gas every 15 minutes or so”, or “perhaps just [occur] under certain well conditions” – the combined approach saves time.

Large commented: “If you’ve just got wireline logging tools, you could be running up and down the well for hours and you’re never in the right place at the right time to hear that.”