Optical extremes
  from: Offshore Engineer
  by: Jennifer Pallanich
  Monday, April 07, 2008

Extreme environments call for sturdy equipment. Monitoring deep reservoirs with high temperatures and high pressures demands durable optical sensing technology, and one service company is finding solutions to the difficulties of packaging sensors that can survive. Jennifer Pallanich reports.

When Weatherford took the call to install a multizone distributed temperature sensing (DTS) system to depths of over 7km, the company needed to protect the optical sensors so reliable results could be provided.

The system combines, on a single optical cable, both DTS for the full length of the well and several optical pressure and temperature gauges in multiple zones in an offshore well off Brunei. Temperature profiling with DTS allows the detection of many types of production-induced events in the wellbore that can result in a change in temperature. Pressure/temperature (P/T) gauges provide high-resolution data at specific locations in the well. The two measurements increase the operator’s understanding of well conditions at all times. Tad Bostick,Weatherford’s VP of optical sensing, says the depth of the installation created special considerations to ensure the cable protected the sensing fiber in the HPHT environment.

To deal with the extended reach distance,Weatherford used an optical cable design that had been deployed worldwide but had never taken the DTS measurement to these depths. The fixed cable design includes three fibers, including one multimode fiber for DTS and two single mode fibers for the optical P/T gauges, which are based on Bragg grating technology. The 1/4in cable employs several layers of mechanical protection for the fiber, including an inner fiber in metal tube (FIMT), a buffering material, an outer nickel alloy armoring and, finally, protective encapsulation to ensure it will survive the trip downhole.

The cable has multiple barriers to protect against hydrogen darkening, a condition that causes light loss in the fiber. The multi-mode fiber for DTS is sensitive to hydrogen penetrating into the core of the fiber and negatively affecting light propagation. First, the FIMT is plated with a special material that prevents hydrogen molecules from penetrating into the inner cable. Second, a gel surrounds the fibers and absorbs hydrogen, should it penetrate into the region of the fibers. Hydrogen darkening does not pose as much of an issue with the P/T sensors.Weatherford uses a hydrogen-resistant single mode fiber for these sensors.

‘That’s a long way to measure DTS, the longest for us so far,’ Bostick says.

Weatherford is developing equipment for use in extreme HPHT conditions, such as deep US targets, where heat may reach nearly 300°C and pressures may register 25,000psi or more, Bostick says.

‘It’s pretty tough for any technology, let alone the sensors,’ he says of the need to protect equipment. ‘It’s primarily a packaging issue and requires special materials and lots of testing.’

While the technology is still new, some customers have been early adopters, Bostick says, while others are waiting for the technology to become more established. ‘There’s more acceptance of optical sensing, and it’s playing a larger role all the time in reservoir monitoring.’

With DTS, the ability to monitor temperature runs from the toe of the well back to the surface instrument, Bostick explains. It allows early detection on problems with injection or production and can reflect how well the equipment is operating, such as detecting a downhole pump that is overheating, which has a warming effect. Measuring temperatures along the reservoir section can provide details about changes in fluid content, such as when gas breaks through into the wellbore, generally producing a cooling effect.

‘We’re trying to allow [operators] to do a better job of managing and optimizing their production’ with DTS, which can give a reasonable temperature accuracy along an extended length, Bostick says.

The downstream oil and gas industry has used DTS in refineries for years, and DTS was introduced into the upstream sector in the 1990s.

‘It’s continuing to gain acceptance in the industry,’ Bostick says.

Weatherford is combining DTS with optical P/T gauges to yield measurements with higher accuracy at certain points.

‘You can correlate the distributed measurement to the high accuracy measurements,’ he says. ‘When you start to produce from multiple zones, it’s very complex. First of all, each individual zone has its own characteristics.’

The zones can communicate, and the sensing equipment gathers details about the production, he notes. ‘Getting those discrete measures in each zone reduces uncertainty when you’re trying to produce.’

DTS is inappropriate when there are few or no detectable temperature changes. ‘You need to have sufficient temperature dynamics to run DTS,’ Bostick says.

For multi-zone applications, the cable can pass through zonal packers or swell packers can mold around the cable itself.

The future, Bostick says, is placing optical sensing in the subsea environment. The main challenges are the availability of optical wet mate connectors in the subsea tree and suitable fibers in the umbilicals. Optical wet mate connectors are starting to be available, he says, and operators are planning to put both multimode and single mode fibers in the umbilicals for a larger percentage of subsea projects going forward.

If fiber is not available in the umbilical or the tieback conditions are complex, there may be a need to install instruments on the seabed, he says.Weatherford has a subsea instrument for P/T sensors but not for DTS, he says. DTS will be a difficult measurement to make subsea, where the temperature accuracy depends on getting a good light signal in the fiber. Long tieback lengths or multiple optical connections can make it difficult or impossible to make a DTS measurement. To enable temperature profiling in a subsea environment,Weatherford plans to place multiple point temperature sensors in the well and effectively create an array of sensors instead of using the fiber itself, Bostick says.

‘We have that capability today for subsea,’ he says. Point temperature sensors based on glass microstructures are stable, high resolution temperature sensors, and optical multiplexing techniques enable many sensors to be installed on a single fiber.

The trade off is it gives less flexibility to measure temperatures over the entire length of the fiber, but it can target critical areas, he adds.Weatherford plans to deploy its Array Temperature Sensing solution in 1Q 2008 in West African deepwater, Bostick says.

Flow check

Weatherford is also working with optical downhole flow meters for monitoring production and injector wells.

‘That’s where we see the industry moving,’ Bostick says.

The service company installed three optical flow meters in a Middle East mutlizone onshore producing intelligent well last year, he says, adding the technology is applicable offshore. Each zone in the three-zone well has an optical flow meter that gathers flow rate data as well as details about the phase fraction, he says. The full bore meter has no restrictions in the well, allowing full access for intervention operations like wireline or coiled tubing, he says.

‘If you’re measuring zonal flow in real time and you start to see changes in rates or fluids, you can act on it,’ Bostick says. ‘That’s where the intelligence starts to come in.’

Over the last two years, Bostick says, in-well flow metering has gained wider industry acceptance. For its part, Weatherford has installed over 40 in-well optical flow meters, of which the majority are offshore. The service company has installed mutlizone meters offshore in injector wells, and the Middle East well is the first mutlizone producer Weatherford has installed the meters in, he says. It was installed in June 2006 and tested in July 2007. Full production was planned by the end of 2007, Bostick says.

Weatherford is lined up for another multizone meter installation in a North Sea producer and other installations in the North Sea in 2008. In the Middle East producer, Weatherford installed all three flow meters with combined pressure and temperature sensors on a single cable. ‘The reason we can do all that on a single cable is because of the optics,’ Bostick says. ‘You’re getting your complexity out of the well but you’re still taking a lot of measurements.’

With optical sensing systems, there are no electronics in the well; rather all complex electronics are at the surface. ‘The wellbore is a tough environment because of the high temperature and pressure for the electronics,’ he says.

‘We’re extending, expanding the capacity of number of sensors you can get on the fiber without having to put any electronics in the well,’ Bostick says. ‘The more sensors you can get into the wellbore, the better a job you can do of optimizing production.’

Weatherford has also installed permanent in-well optical seismic sensors for high resolution imaging and passive monitoring of microseismic events around wells including offshore at Valhall in the North Sea, another field in the Gulf of Mexico and onshore in Kazakhstan.

Bostick says these seismic sensors can monitor or determine where the fluids are being produced or how far the injection is into the reservoir. The sensors can acquire seismic images out to hundreds or thousands of meters from the well.

The Gulf of Mexico installation includes 12 tubing conveyed seismic stations in a producing well, all combined on a single optical cable that also measures pressure and temperature at the reservoir, and multiple 4D data acquisitions have been acquired to date, he says.

Images from the Valhall installation show the sensors are obtaining high resolution of the in-well seismic, Bostick says. Currently the installations are all on platforms and dry trees, he says, adding the future of optical seismic sensors, too, will likely be subsea.

‘The industry is definitely looking to go subsea for seismic sensing as well.’ But these systems require even higher performance of the optical wetmate connectors at the wellhead and of the subsea instruments, he says. OE

Tracing water breakthrough

Norwegian specialist Resman is equipping Dong Energy’s upcoming well in the Siri field in the Danish North Sea with tracer-based monitoring technology to detect when and where water enters the production flow. Resman previously installed its wireless well monitoring technology in three wells on the Norwegian Continental Shelf.

According to Resman CEO Oddvar Solemsli, installation is planned for January 2008.

Dong Energy’s Siri subsurface manager Preben Jensen said the tracer-based monitoring technology was a cost-effective way to monitor water breakthrough in the wells. Dong has operated the Siri field since 2002.

Resman’s previous installations have been in wire wrap sand screens, but this installation will use prefabricated premium screens; the company says it expects to be offering its technology for any type of completion within the next three years.

‘We have now demonstrated not only our ability to develop tracers, but also the ability to adapt to the operational reality of our customers,’ Solemsli says. ‘We can now integrate our tracers with any sand screen on the market. Our next step will be to develop techniques for other completion scenarios.’ OE

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