Reducing Intervention in Subsea Wells With Fiber-Optic Technology
Fiber-optic-system installations have reduced the need for intervention by logging tools and have given crucial insights into wellbore integrity and reservoir production.
Fiber-optic-system installations have reduced the need for intervention by logging tools and have given crucial insights into wellbore integrity and reservoir production. Consequently, a prime application of fiber technology should be in deepwater fields, where intervention can be prohibitively expensive. The reluctance to incorporate downhole fiber appears to be caused by limitations of technology relating to cables, deployment, acquisition, and interfacing. These barriers are slowly being eliminated, and a small number of subsea wells have now been implemented with in-well fiber.
Permanently installed fiber-optic systems have been commercially available in the oil field since the early 1990s, with the bulk of the deployments providing fiber-optic distributed temperature based upon Raman backscattering. This Raman distributed-temperature-sensing (DTS) measurement system provides continuous data along the length of the completion without the need for intervention and without introducing restrictions in the inner diameter of the completion tubulars, restrictions that could impede subsequent wellbore access. Typical DTS spatial resolution is better than one data point per meter, with a temperature resolution of 0.01°C. Applications of the distributed-temperature data have included calculating flow contributions across the sandface, evaluating water-injection profiles, diagnosing the effectiveness of fracture jobs, finding cement tops behind casing, and identifying crossflow between producing zones.
The growth of fiber installations for dry-tree (land and platform) applications is increasing exponentially. More than 1,200 installations have been deployed by one service company alone. Most of those installations were single-stage completions, often for thermal or steam-assisted-gravity-drainage (SAGD) application, and relied upon the ability to pump fiber along a control line to convey the sensing fiber. Approximately 20 of those wells have fiber pumped along the sandface of dual-stage openhole-gravel-pack (OHGP) completions.
A significant advantage of the pumped fiber was that, if the fiber degraded over time, it could be pumped out and replaced. This was particularly important before the discovery of how to construct fibers with some immunity to darkening from H+ and OH− ions. With hydrogen resistance came the possibility of increased longevity for fixed-fiber cables, and, since 2006, an alternative to pumped fiber has been available that combines multiple hydrogen-resistant fibers with an electronic line to create a hybrid cable (Fig. 1). This cable can power high-accuracy quartz gauges and can also give the benefits of fully distributed Raman DTS. More than 60 such systems have been deployed to date.
Fiber-optic applications run the full range of production monitoring. Reservoir-production examples have been cited in which the data from the fiber across the sand screen has detailed flow allocation, fluid type, and changes in reservoir pressure. This last point may seem a surprising inference to obtain from DTS until it is noted that the temperature of an incoming fluid is strongly influenced by the drawdown pressure as a consequence of the Joule-Thomson effect. Indeed, it is typically crucial to link near-wellbore reservoir modeling (for pressure drawdown and fluid temperature), pressure variation along wellbore (e.g., by nodal analysis), and temperature advection/conduction modeling in both wellbore and reservoir. Because of the dependence of temperature on drawdown, quartz-pressure-gauge data thus remain an important complement to the fiber-optic DTS.
The use of temperature in monitoring cement integrity and flow behind casing is a classic example of temperature logging from production-logging tools. Typically, however, it requires multiple logging passes in order to distinguish completion and reservoir effects from temperature effects caused by fluid movement. This need for multiple passes is removed by permanent fiber systems because they inherently provide data at multiple points in time.
An example combining both upper-completion integrity and production optimization has been provided (see complete paper for details) in which the combination of DTS on a hybrid cable with zonal pressure data allowed the allocation of zonal contributions from multilayer reservoirs, which was the primary purpose of deploying the fiber. The combination also allowed the operator to manage drawdown and mitigate effects of potential sanding. Two unexpected benefits from the fiber were related to integrity (a leaking gas lift valve) and the identification of a completion update to mitigate water production.
These applications are both representative of typical uses of fiber DTS and of key interest to many subsea-field developments. Consequently, a prime application of fiber technology should be in deepwater fields, where intervention can be prohibitively expensive, if not impossible. Yet that has not led to significant subsea fiber deployments. Assuming that this service company’s data are representative of the industry, fewer than 0.1% of wells instrumented with fiber have been subsea.
Possibly the biggest change in the last decade relates to cable. Because fibers cannot be pumped in wet-tree applications, a permanent cable is a necessity. That eliminates the ability to pump out fibers that have darkened because of exposure to H+ and OH− ions. Significant research was launched in the mid-1990s to understand the diffusion of these ions into the fiber core. Joint development between service companies and vendors led to fibers that demonstrated excellent longevity in oilfield conditions, even to 300°C. Concurrent with the enhancement of these fibers was the realization that a stable, low-drift pressure gauge was crucial to the interpretation of sandface temperature data. This led to the development of hybrid cables that could provide both hydrogen-resistant fiber and electrical power/communications data for permanent quartz gauges. These cables can provide a backbone of future fiber-optic subsea solutions when incorporated with reliable splice equipment. Of the roughly 60 hybrid systems deployed worldwide, approximately 5% have been subsea. In particular, the hybrid cable has been deployed for subsea monitoring of cementing, integrity, methane-hydrate analysis, and cleanup.
The Japan Oil, Gas and Metals National Corporation (JOGMEC) conducted a drilling campaign in the Nankai Trough area during 2003–2004 as part of the activities of the MH21 Research Consortium. Through this campaign, various subsea-hydrate studies were conducted using various data, including data from logging while drilling, wireline, coring, and temperature measurement. In particular, using fiber-cable technology, a precise in-situ temperature-measurement system was successfully developed and deployed at the beginning of the drilling campaign. The temperature of the hydrate-bearing sediment was monitored in a deepwater well for 1.5 months. Equilibrated formation temperatures could be readily determined after observing the thermal relaxation from drilling and sensor-deployment effects. The temperature profile and the temperature gradient through the hydrate-bearing zone were estimated in a quasisteady-state condition.
In 2013, an extensive integrity-monitoring campaign is being planned for a series of wells in the North Sea that are relatively close to a platform. For this scenario, the laser acquisition system will be on the surface. The DTS acquisition will be performed with a device using Raman techniques that has a maximum sensing distance of 20 km. The sensing distance is long enough that an umbilical can be run from the surface to the subsea well and then below the tubing hanger to a hybrid cable. Greater distances could be possible by converting from Raman to Brillouin techniques or by adopting a combination of both.
These optical subsea examples are single-stage installations with hybrid cables along the completion and answer products derived from a combination of DTS and downhole-pressure gauges. The digital temperature arrays are the only technology to have broken past this barrier. Because they can be powered by inductive coupling across completion stages, they can be incorporated into a variety of completion topologies (OHGP, cased-hole frac-pack, and expandable-reservoir-completion wells). The arrays provide the added advantage of being easily combinable with multiple quartz pressure sensors.
The inductive coupler itself can become a platform, with applications not only on the lower completion but also at multiple locations. For example, recent inductive couplers can have the mechanical attributes of a section of liner or casing, which means that they can be deployed in the upper completion with sensors exterior to the casing electrically connected to them. When the tubing hanger is landed, a corresponding mating coupler can be aligned to complete the circuit, and the sensor data are then passed to the surface along the same cable used for sandface data. This has obvious applicability to B-annulus measurements. Indeed, the combination of DTS in the upper completion and pressure gauges in the B-annulus would be a powerful technique to monitor upper-completion integrity in subsea wells.
The use of sandface-temperature arrays as an alternative to fiber does not completely eliminate the need to manage subsea interfaces. For example, a typical Gulf of Mexico completion with, say, 100 temperature sensors can be anticipated to require approximately 50 W—significantly more than the commonly used standard of 24 W—so that will need advance planning. Similarly, while data telemetry rates are low compared with those of fiber DTS (less than 9.6 kbaud), this is an increase over a single pressure gauge and can add a burden, especially to legacy systems. But these obstacles represent far less than the significant interface hurdles seen in implementing subsea fiber, especially in multistage completions. Accordingly, the digital arrays need to be included in any road map of subsea sandface-monitoring technology.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 23929, “Reducing Intervention in Subsea Wells With Fiber-Optic Technology,” by John Lovell, Schlumberger, prepared for the 2013 Offshore Technology Conference, Houston, 6–9 May. The paper has not been peer reviewed. Copyright 2013 Offshore Technology Conference. Reproduced by permission.