The WellWatcher BriteBlue fiber installation in a heavy oil thermal recovery application. (Image courtesy of Schlumberger)

On the surface it makes a lot of sense to install a permanent monitoring system in a steam-assisted gravity drainage (SAGD) field. It’s extremely helpful to know where the steam fronts are moving to ensure higher recovery rates.

But steam injection is not kind to downhole equipment. Fiber-optic systems, which are more heat-resistant than electronics, suffer from hydrogen degradation, which shortens their lifetimes considerably.

So Schlumberger embarked on a quest to take its WellWatcher distributed temperature sensor (DTS) system to the next level by experimenting with fiber solutions that could withstand the harsh environment of a SAGD setting. The result is the WellWatcher BriteBlue fiber & WellWatcher Ultra acquisition system.

The challenge

The presence of hydrogen within the core of a fiber-optic line causes high attenuation across a broad wavelength span, reducing the fiber’s ability to transmit data or be used as a sensor. Jacketing the core with a hermetic coating can reduce the initial rate of hydrogen degradation, but it doesn’t stop the process completely.

In an injection well in a SAGD field in Canada, the best available fiber was rendered unusable in less than a month due to hydrogen degradation. Obviously a better fiber solution was needed.

In a testing facility in Lawrence, Kan., work began to find a fiber that was much less susceptible to the damaging effects of hydrogen. The facility was designed around the safety issues attendant with the use of hydrogen at elevated temperature and pressure.

Tests were carried out in stainless-steel pressure vessels that could accommodate up to four 980-ft (300-m) test fibers. The ends of the fibers were accessible through pressure feed-throughs designed to provide a barrier to hydrogen. This allowed the fibers to be interrogated at any time during the test.

Eventually one fiber was chosen as being optimal; this was then tested against two commercially available multimode fibers that are marketed as being suitable for high temperatures. All of the fibers were tested together at 482°F (250°C) under 500 psi pure hydrogen for 410 hours. The performance of the new fiber was determined to be at least an order of magnitude better than the existing fibers at DTS wavelengths.

In the field

Field tests in Canada have been very encouraging — so far tests have demonstrated no discernible reduction in fiber or measurement performance and are providing operators with far more insight into the zones contributing the most to a well’s production during transient conditions. To date, field applications of the system have been running successfully for more than a year.

“The advanced technologies of WellWatcher BriteBlue and WellWatcher Ultra ensure that all system components withstand the challenge of extended harsh environments to deliver the data and answers operators need to make better decisions in real time,” said Gabriel Tirado, business development manager-monitoring for Schlumberger Completions. “Permanent in-well reservoir monitoring with WellWatcher is crucial for operators to improve production management and recovery and to identify and resolve problems quickly to reduce downtime and related costs.”

The fiber can be used for sensing only or for high-speed communication between a downhole sensor and a surface unit. At the surface, the data can be transmitted to multiple remote locations with satellite, Internet, and cable communications, allowing operators to immediately identify the time, location, and reasons for changes in temperature.

In addition to SAGD applications, BriteBlue can be used to optimize gas lift and monitor tubing integrity. Benefits include enhanced production management and recovery through improved reservoir surveillance; reduced downtime and greater productivity because of permanent real-time in-well monitoring and faster, more precise identification of production problems; cost savings as a result of greater operating efficiency, less downtime and increased production; and the ability to monitor events as they occur.

The fiber is pumped through a hydraulic conduit into the well bore after the rig has left the location.

The fiber can be replaced without a workover, meaning that newer fiber systems can be deployed quickly as they become available.

The versatility of the system allows it to be used to monitor reservoir flow in places where production logs can’t be run. SensaLine, a fiber optic-enabled 1?8-in. slickline developed by Schlumberger, was primarily aimed to help optimize gas lift valves in wells that do not already have fiber optics installed. However, this has found another application in a fractured gas wells in Canada. In these wells “the slow production of water along with the gas can eventually kill the wells,” said Robert Greenaway, product champion for fiber optics. “Several clients have found that the one solution to this is to run the production tubing down below the perforations, using the resulting accelerated gas flow up the tubing like a vacuum cleaner to remove the water as it is produced.

“However, this prevents conventional production logging without pulling the tubing. With DTS the thermal flow effects can be seen through the tubing, allowing zonal flow allocation to be determined without the cost and time of a workover rig.”

In addition to the fiber itself, Schlumberger has developed an interpretation and modeling software suite called THERMA to help operators decide when to use the DTS system and to aid in the interpretation of resulting datasets. THERMA enables evaluation of multiple production scenarios by analyzing thermal sensitivity to variables such as zonal productivity indices and gas and water production.

“Oil loses heat as it flows up,” said George Brown, interpretation development manager for Schlumberger. “It’s flow-rate dependent. A change in temperature tells you how much fluid is flowing from each reservoir. The flow causes the pressure drop, which changes the temperature. THERMA takes all of this into account.”

Optimal input data to THERMA software modeling includes:
• Reservoir properties for each layer, including permeability, pressure, rock and flowing-fluid properties, reservoir thickness, skin effect, and drainage radius;
• Completion details, including casing, tubing, cement, wellbore profile, and surrounding fluids; and
• The geothermal gradient, determined theoretically or by measurement.

The software has many uses for SAGD wells. In one test in Canada the fiber was installed in the lower producing well while the upper well was used for steam injection.

The data was monitored on THERMA.

“We loaded everything into the software, plotted it, and visualized it,” Greenaway said. “We could see where the well was getting hot. We could monitor the difference in temperature between the producer and the injector — the software does the calculation.” Even with no sensor in the injector well, THERMA used pressure measurements to calculate the temperature of that well.

The need for these systems is likely to grow in the coming years. Tirado said that it’s estimated that a significant sustained growth of high-temperature wells will occur every year through 2011. “These wells are rated at 350° to 500°F (175° to 260°C). Almost 60% will be related to thermal recovery. That’s severe temperature for today’s technology, and fiber optics will be key.”

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