Mathieu Molenaar
Royal Dutch Shell PLC
Calgary
David Hill
QinetiQ Group PLC
Calgary
Vianney Koelman
Royal Dutch Shell PLC
Houston
Recordings made during operations in tight gas wells indicate that fiber optic distributed acoustic sensing is a sensitive, robust, and cost-effective technology for real-time monitoring of well operations, including hydraulic fracturing,
The technology also holds promise for distributed flow measurement, sand detection, gas breakthrough, artificial lift optimization, smart-well completion monitoring, and wellbore monitoring.
Shell and QinetiQ have started a 3-year collaboration to evaluate the potential of DAS for oil and gas applications.
Downhole test
Shell first tested DAS for downhole applications during the completion of a tight gas well in February 2009. The test recorded DAS signals during the running in hole with the tools, setting bridge plugs, perforating, and during the hydraulic fracturing treatment.
The technology proved sufficiently reliable and sensitive to detect and monitor these downhole activities.
The passive nature and inherent long-term reliability of fiber optic sensors, together with the ability to produce thousands of individual sensing elements in a downhole deployable, single optical fiber cable makes the technology an effective platform for permanent sensing in producing wells.
This test led to the collaborative effort between Shell and QinetiQ's OptaSense business.
Acoustic sensing
The industry first used downhole fiber optic sensing in the 1990s for single-point pressure and temperature sensors. Distributed temperature sensing followed.
A technology currently in an early deployment phase is ultrasensitive distributed strain sensing for well integrity and reservoir deformation monitoring (RTCM technology).1
DAS is the latest addition to the growing toolbox of fiber optic techniques in exploration and production.
In essence, DAS turns a standard several kilometers long telecom fiber into an array of microphones. This works because acoustic disturbances along the optical fiber affect the interference of back-reflected laser light. One can deploy this technology in new wells or in most existing installations that have standard telecom optical fibers installed.
The DAS system (Fig. 1) uses a technique called coherent optical time domain reflectometry that involves the successive transmission of short pulses of highly coherent light down an optical fiber and the observation of the very small levels of backscattered signal due to heterogeneities in the glass core.
Vibroacoustic disturbances reaching the fiber optic cable alter, on a microscopic level, scattering sites within the glass of the fiber. This results in changes to the Rayleigh backscattered laser signal.2 An interrogator unit analyzes the changes in the backscatter signal and generates a series of independent, simultaneously sampled acoustic signals for each 1-10 m long segment (channel) along the fiber.
This technology has no discrete sensors deployed. It simply uses a standard single-mode optical fiber deployed along the wellbore length and a topside interrogator unit for optimizing parameters such as sample rate, spatial resolution, and several channels.
Raw acoustic data pass from the interrogator unit to the processing unit that provides signal interpretation and visualization.
DAS provides a broad spectrum of envisioned downhole and areal monitoring applications including distributed flow measurement, sand detection, gas breakthrough, artificial lift optimization, smart-well completion monitoring, near-wellbore monitoring, as well as other applications.
This article will illustrate the potential of this new technology for real-time monitoring of wellbore activities and hydraulic fracture stimulation.
Downhole monitoring
One obvious use for DAS is to detect and monitor wellbore activities that have an acoustic signature. Our tests confirmed that DAS can monitor well intervention tools travelling up and down the wellbore, perforation shots, and packer settings operations.
Fig. 2 shows a field example from a vertical well in Canada. In this well, the DAS technology monitored the acoustic noise generated by a wireline tool for setting a bridge plug in the wellbore.
The setting tool converts gas pressure produced by a burning explosive powder charge to hydraulic force. This hydraulic force is then converted to mechanical energy to set the bridge plug inside the production casing.
The tool works by first applying electrical current down the wireline to ignite the primary igniter that ignites the secondary igniter and in turn ignites the powder charge. The bridge plug sets securely in the casing after the powder charge burns completely.
The measured data show, in real time, the location of where the plug sets as well the three rapid ignitions of the charges. Seen also are the tube waves induced by the explosives all the way to the wellhead.
The example shows how DAS can be used to confirm the proper placement of downhole tools such as packers and perforation guns.
The system can use any channel along the fiber as a microphone to listen to downhole operations such as milling and fishing as well as monitor more permanent downhole equipment such as electrical submersible pumps.
Hydraulic fracturing monitoring
In tight sand and shale gas developments, the completion of a well is the largest single cost component after drilling. Balancing the expense for hydraulic fracture stimulation vs. the production benefits, therefore, is crucial.
Historically, frac engineers have been limited to using surface wellhead rates and pressures, and on occasion downhole pressures, as their main sources of real-time information. Traditional diagnostic techniques such as radioactive tracers have limitations when faced with the complexities associated with hydraulic fracture treatments.
To address these limitations, Shell has for several years deployed distributed temperature sensors in tight and shale gas wells for hydraulic fracturing diagnostics.3 Building on this experience, real-time monitoring with DAS is a logical next step in enhancing the ability to monitor and optimize well treatments.
Shell has installed several DAS systems for real-time fracture monitoring in its tight gas fields in Canada. The company can use the information obtained from the DAS recordings to:
- Optimize fluid and proppant placement through real-time intervention.
- Diagnose the effectiveness of limited-entry designs.
- Achieve cost saving in real-time during the treatment and through postjob diagnostics and optimization.
One example is a horizontal well that was hydrualically fractured with five isolated stages. Each stage had one to four sets of perforation clusters.
Fig. 3 shows the data recorded for a stage with four perforation clusters and a limited-entry design for obtaining a uniform distribution of the fracturing fluids into all sets of perforations. In practice, however, limited-entry fracturing does not guarantee even distribution of fluid placement.
In the figure, the acoustic signal amplitude is color coded (red is high, blue is low) and displayed along about 600 m of wellbore throughout the stimulation job. The colors represent noise levels that one can correlate with injection rates by careful selection of the frequency bands.
The signals easily identify that the most active perforation clusters during the acid injection and before the hydraulic fracturing treatment (Period a) are Clusters 2 and 3. This continues through the start of the hydraulic fracture initiation (Period b). But after the second fracture initiation at a higher injection rate, Cluster 1 seems to become the most active. Early in the treatment, it was clear that Cluster 1 was the dominant fracture.
One method for improving the injection distribution is the application of ball diverters, which seal the perforations with the dominant injection. During the treatment, Cluster 1 remained the dominant fracture until diversion occurred after the third ball drop attempt (Period c).
First indications are that the DAS measurements can capture the dynamic changes throughout the hydraulic fracturing exceptionally well. The broad frequency content enables discrimination of which perforations are active during acid injection and which perforations are taking most of the fluid and proppant throughout the job.
This type of information is essential for optimizing the volume placement design and for improving future treatments.
Acknowledgments
Many staff members in the joint Shell-QinetiQ DAS team contributed to the work discussed in this article. OGJ
References
1. Pearce, et al., "Applications and Deployments of the Real-Time Compaction Monitoring System," SPWLA 51st Annual Logging Symposium, Perth, Australia, June 19-23, 2010.
2. Healey, P., "Fading in Heterodyne OTDR," Electronics Letters, Vol. 20, No. 1, 1984.
3. Huckabee, P., "Optic Fibre Distributed Temperature for Fracture Stimulation Diagnostics and Well Performance Evaluation," Paper No. SPE 118831, SPE Hydraulic Fracturing Technology Conference, The Woodlands, Tex., Jan. 19-21, 2009.
The authors
M. Mathieu Molenaar ([email protected]) is a senior production engineer at Shell Canada Ltd., Calgary. He previous worked as a geomechanics specialist at Shell's research laboratory in the Netherlands, and a production engineer supporting new business developments in the Middle East and West Siberia. At Shell Canada, he works on a team for tight sand and shale gas developments. Molenaar holds an MSc in mechanical engineering from Delft University of Technology. He is an SPE member.
David Hill is the technical director of QinetiQ OptaSense in the UK and has more than 25 years of research and development experience in the field of acoustic sensing. For almost half of that time, he has been involved in developing fiber optic based sensors for oil and gas applications as well as for the military. His background includes acoustic array processing, transducer design, and experimentation. He also has contributed to the development of four-component all fiber optic seismic arrays. Hill has a BSc in imaging sciences from the University of Westminster, London and a PhD in physics, specializing in fiber optic sensors, from the University of Kent in the UK.
J. Vianney Koelman is chief scientist and team leader in well technology for Shell International E&P Co., Houston. He has held research and operational positions on assignments in the Netherlands, UK, Nigeria, Oman, and US. Among a variety of other roles, he led the reservoir management team for Brent and held the position of head of petrophysics for Europe as well as for Africa. Currently he is leading Shell's R&D efforts in the area of fiber optic well and reservoir surveillance. Koelman holds a degree as a physicist and a PhD in engineering sciences from Eindhoven University of Technology in the Netherlands. He is a member of SPE.
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