Q. Why is the monitoring of oil wells important?

A. Monitoring oil wells allows petroleum and reservoir engineers to make informed decisions to ensure that reservoirs are being produced efficiently.

Q. What is the history of monitoring developments?

A. Historically, monitoring has been achieved by wireline logging. However, as wells have become more complicated, it has become more difficult to rely solely on this form of logging. Wells are now routinely drilled horizontally or highly deviated, and subsea wells are increasingly common. The associated complicated completions often prevent the running of conventional logging tools, and, as a result, permanent monitoring is often the only solution.

In heavy oil steam applications, permanent temperature logging is sometimes provided by thermocouples. However, this method has its limitations: It only provides a single point of measurement and, therefore, even in a medium-sized zone, several dozen thermocouples must be put in place to acquire meaningful data. There is also a physical limitation to the number of wires that can be placed in slickline completion tubing.

Pressure gauges are also used for permanent monitoring purposes, but they only provide data on wellbore pressures.

Q. So was monitoring along extended intervals the next challenge?

A. Yes. The next step was to obtain temperature measurements across the whole reservoir interval. This is where fiber optics is used.

In the late 1980s, a method was developed for measuring the temperature along a fiber-optic cable using a specially developed distributed temperature sensor (DTS) system. The first DTS systems were sold to industrial sites for measuring power losses and for safety monitoring in escalators. In the mid-1990s, fiber optics began to be installed in steamflood heavy oil wells in California using similar DTS systems to collect temperature readings. This technology allowed engineers to locate the steam front and to see whether it had broken through. There was little attempt to further analyze the information at this stage. Nevertheless, this showed that using fiber optics was a viable method to measure temperatures in thermal production wells.

By the end of the 1990s, it had become apparent that this form of permanent measurement of temperatures in wells would be a significant breakthrough. Now that this technology has been perfected, the main emphasis of our work has been to convert the temperature measurements into flow from the reservoir intervals along the wellbore. To me, this is where it gets interesting.

Q. Is this fiber-optic line similar to a standard telecom fiber line?

A. Yes and no. Yes, from the point of view that it is an optical fiber with a core through which you send pulses of light; no, because the coating on the outside of the fiber is different from that associated with standard telecom fiber line.

One of the problems is that the ingress of hydrogen degrades the optic line by blackening it, and therefore the quantity of light being transmitted is significantly reduced—so much so that no useful data can be obtained. The coatings—of which there are various specifications, depending on the well’s anticipated temperatures and the fluids being produced—are designed to act as a barrier to hydrogen degradation.

Q. You mention hydrogen degradation—what challenges would be faced running a fiber-optic cable in, say, a hydrogen sulfide (H₂S) gas well?

A. H₂S gas has very high hydrogen content. Not only would the control line need to be immune to H₂S embrittlement, but it would also be necessary to prevent H₂S coming into contact with the fiber. With some additional precautions, running fiber-optic cable in an H₂S well could prove as successful as in other situations.

Q. How is Sensa installed into a well?

A. When a well is being completed, a 1/4-in diameter control-line smooth-bore tube is run. This is the same type of tube used to control subsurface safety valves and intelligent downhole hydraulic valves. The fiber-optic line is pumped down this tube using water pressure (which, due to the hydrogen degradation mentioned above, is ultimately replaced with silica), and, once in place, is physically protected by the tube. If the fiber is pumped down a U-tube, then it can easily be withdrawn and replaced without having to withdraw the whole control line. Once installed downhole, the cable usually requires no further attention.

Q. Is this the only way to obtain DTS measurements?

A. No. One alternative method involves an 1/8-in diameter steel cable slickline that contains a fiber in its core. This type of slickline is normally run in a cased hole to undertake a variety of duties—such as setting a pressure gauge or pulling a valve—and the fiber cable allows DTS measurements to be taken as well. Of course this method will not be applicable to horizontal wells or permanent installation.

Q. How does the Sensa system actually work?

A. It is important to understand that the fiber is both the temperature measurement system and the data transmission system.

The system includes a device that sends out pulses of light at 10-ns intervals. When the light passes down the fiber, a small fraction of the light is backscattering as it interacts with molecules in the fiber. This backscattered light passes back up to the end from where it originated.

This backscattered light holds the key to Sensa technology. Since we know the speed of light, we know where this backscatter has occurred, and, by splitting up our fiber into distinct intervals, we can examine the spectrum of light being returned from each interval. There are two parts to this spectrum that are of interest to us: the Stokes Raman band and the anti-Stokes Raman band. One has been positively shifted and is not temperature sensitive, and the other has been negatively shifted and is temperature sensitive. As you can imagine, to convert the constant stream of pulses, the backscattered light and the control data into meaningful information requires considerable ongoing analysis.

The unique aspect of the Sensa DTS system and its most significant function, is that it allows measurement at 1-m intervals along the entire length of the fiber-optic cable. This means that in a typical steam-assisted gravity drainage (SAGD) operation, we could be monitoring 1,200 or more individual points of interest on a permanent basis.

Q. How can Sensa benefit heavy oil production?

The advantage of the Sensa system in a heavy-oil environment is that the temperature of the steam does not harm the fiber-optic cable. Fiber optics can handle higher temperatures than standard logging tools, up to 250 degC.

Indeed this robustness is a key benefit—in a huff’n’puff operation, for example, where steam is injected and oil produced from the same borehole, one installation of fiber-optic cable can be used for all cycles of the operation. When steam is being injected in a well, the usefulness of the data is limited, but when the well begins to produce, the converse is true. With the interpretation expertise of the Data and Consulting Services (DCS) team, Schlumberger can help you see which zones are contributing to production, where the steam is having an impact, and where the steam front has broken through. This is all vital information in the costly world of thermal production.

Q. Can Sensa fiber-optic technology be run in every type of well?

A. From a heavy oil perspective, we have fiber-optic cable operating n various thermal production operations, including horizontal SAGD wells and 6,000-m-deep oil wells with intelligent completions. Only light-oil horizontal wells in high-permeability reservoirs do not have interpretable thermal responses.

Q. So does this level of accurate temperature monitoring produce a financial return?

A. Essentially, monitoring various parameters in your well enables engineers to make educated assumptions on production details, and thereafter, appropriate decisions. Heavy oil production is more expensive mainly due to investment in steam generating equipment and the ongoing energy costs. As a result, running permanent measurements in a heavy oil environment is even more important. You simply have to have measurements to understand what is going on.

The bottom line is that without measurements, and in a heavy oil production environment this specifically includes temperature, you are likely to make ill-informed decisions and the profitability of the resource will inevitably suffer.

Q. Will this type of monitoring replace existing wireline logging and drillstem testing techniques?

A. Not at all. There is always a place for these production-logging systems. Sensa technology is a complementary system that is especially important for wells where traditional logs cannot be easily run.