Optical Fiber Sensors for Permanent Downwell Monitoring Applications in the Oil and Gas Industry

Transcription

1 400 INVITED PAPER Special Issue on Optical Fiber Sensors Optical Fiber Sensors for Permanent Downwell Monitoring Applications in the Oil and Gas Industry Alan D. KERSEY a), Nonmember SUMMARY This paper reviews the use of fiber optic sensors for downhole monitoring in the oil and gas industry. Due to their multiplexing capabilities and versatility, the use of Bragg grating sensors appears to be particularly suited for this application. Several types of transducer have been developed, each of which can be addressed along a single (common) optical fiber in the well and read-out using a common surface instrumentation system. key words: Bragg gratings, fiber optic sensors, pressure sensors, flow sensors 1. Introduction Fiber optic sensor technology has been under development for the past 20 years [1], [2] and has resulted in several successful new products; fiber optic gyroscopes, temperature sensors, acoustic sensors, accelerometers and chemical probes (particularly biochemical) are examples. Applications of the technology include civil structural monitoring (e.g., smart structures), military systems (e.g., underwater acoustic arrays), industrial applications (e.g., process control sensor networks), chemical sensing (distributed spectroscopy), and security monitoring (intrusion detection) to name a few. This technology is now opening up new capabilities for sensing a wide range of parameters, such as pressure, temperature, vibration, flow, acoustic fields, in downhole oil and gas reservoir monitoring applications. Significant interest is being directed towards this area, and several types of fiber optic sensors have been demonstrated for such downhole use. These include a Distributed Temperature Sensor (DTS) for temperature profiling [3], an optically excited micro-machined resonant pressure sensor [4], an interferometric point sensor [5] for pressure monitoring and Bragg grating based sensors for a range of parameters [6]. Sensors designed for downhole monitoring applications in the oil and gas industry are subjected some of the most extremely hostile environments on earth. Timely, accurate, reliable information about how the reservoir is performing is an important component to optimizing oil yield and production rates. To date, the industry has relied largely on wireline retrievable sensors that are lowered into the well to make measurements of key parameters. Such wireline monitor- Manuscript received November 8, The author is with CiDRA Corporation, 50 Barnes Park North, Wallingford, Ct a) akersey@cidra.com ing provides a snapshot of the well/reservoir, and are usually repeated months or years apart. Permanently installed monitoring systems provide real time data in a continuous manner without interrupting production or requiring a well intervention. Consequently, reliability in the transducer technology is one of the main challenges to realizing the full benefits associated with the permanent deployment of downhole monitoring sensor systems. Conventional electronic gauge technology has been successfully deployed in a range of downhole monitoring applications, predominantly for use in wireline retrievable systems, but also more recently for permanent reservoir monitoring. Unfortunately, electronic systems have inherent limitations that render downhole applications particularly challenging. One fundamental issue with electronic systems is a dramatic decrease in reliability at elevated temperatures. Furthermore, the large number of differing electronic technologies used for downhole measurements (e.g., quartz resonator, thermocouples, strain gauges, gamma detection, resistivity etc.) complicates the telemetry aspects of the overall sensor system. Over the past decade, fiber optic sensing technology has been developed and applied to a wide range of industrial and commercial applications. In efforts to extract the full benefits of fiber sensing systems, these applications have tended to exploit the ability of fiber optics to accurately measure a large number of parameters in harsh conditions on a widely distributed basis, with the fiber serving as both the measurement means and the telemetry channel. These, and other attributes, make them particularly well suited for applications within the oil and gas industry. Since the advent of the side-written grating fabrication approach [7] there has been intense interest in grating based sensors. We have developed transducers based on grating technology for a wide range of applications in the oil and gas industry not limited to downhole production monitoring, but also for seismic sensing, down-stream process monitoring, platform structural and pipeline monitoring, and other sensing requirements covered under the generic fields of exploration, production and transportation. 2. Permanent Downhole Monitoring Compared to simple vertical wells drilled for the ear-

2 KERSEY: OPTICAL FIBER SENSORS FOR PERMANENT DOWNWELL MONITORING APPLICATIONS 401 liest oil production in the industry, modern wells used for the extraction of hydrocarbon reserves (oil/gas) in high production rate fields can be typically complex configurations involving vertical, deviated and multiple horizontal/lateral branches, or components. Furthermore, the reservoir can be split between multiple levels, each producing at differing rates, gas/oil/water ratios, pressures and temperatures. The vision of the reservoir engineer is to be able to extract the most of the hydrocarbon reserves prior to the reservoir being reduced to a water producer, and being abandoned. Unfortunately, the current average recovery efficiency is 35%: i.e., 65% of the oil/gas being left in the reservoir. To optimize the recovery efficiency of such wells, the industry is turning towards the implementation of smart-wells or intelligent completions. Inherent to this trend is the need to add additional sensory capability to the well bore environment on a permanent basis. Bragg Grating Sensors: Fiber Bragg gratings (FBG) are intrinsic sensor elements that can be written into optical fibers via a UV photo-inscription process. The photo-inscription process produces a periodic modulation in the index of the glass in the fiber, which has been show to be a stable structure even at elevated temperatures experienced downhole. The advantages of Bragg grating sensors are well known in the fiber sensor community and include: Simple UV photo-inscription fabrication process Intrinsic intra-core sensor element Wavelength-encoded operation Electrically passive No downhole electronics Intrinsically safe Immune to EMI Capable of high temperature operation Distributed sensing capabilities Low-profile sensor Minimally invasive in the wellbore Compatible with components developed for the fiber telecommunications market Of these advantages, the multiplexed or distributed sensing capabilities of fiber optic sensors is of particular pertinence for downhole applications, were there is the need to monitor a parameter, or parameters, at many spatial locations through the wellbore, or horizontal/multi-lateral components of the well is of interest. We have developed a range of transducers that utilize gratings as the core building block for a suite of wavelength-encoded sensors. This allows us to base our development efforts on a common technology platform approach, in which all types of transducers are compatible with a single form of surface instrumentation hardware. Transducers for pressure, temperature and vibration have been designed, built and tested, and concepts for flow, differential pressure, acoustics, corrosion and Fig. 1 Downhole reservoir monitoring using fiber optic Bragg grating sensors. resitivity are under development. These sensors can be applied to a number of applications for retrievable or permanently installed reservoir monitoring systems. 3. Applications Reservoir Pressure and Temperature Monitoring: Pressure and temperature are fundamental reservoir engineering parameters and permanent monitoring of downhole pressure and temperature is widely utilized. While conventional pressure and temperature sensors are proving to be important reservoir management tools, the current technology has some significant limitations. Due primarily to the required downhole electronics, conventional pressure and temperature sensing technology becomes unreliable at elevated temperatures. Also, multiplexing limitations restrict the spatial resolution provided by conventional sensors. The high operating temperatures and multiplexing capability of fiber optic sensors have the potential to increase both the reliability and resolution of downhole pressure and temperature measurements. The transducer design challenge in producing a precise and repeatable response to pressure and temperature, while protecting the fiber optics from the harsh well environment. Figure 2 shows an example of the calibration characteristics of a FBG-based pressure sensor developed for production monitoring that uses a mechanical translation of pressure into strain in the fiber. The packaged CiDRA pressure transducer is shown in Fig. 3. The sensor exhibits a highly linear response in wavelength shift with pressure. Current transducers have been tested to 175 C, but devices with operating temperature to 200 C and above are currently under development, with sensors capable of operation to 250 C as a design goal. Figure 4 illustrates the accuracy that can be achieved with a 5,000 psi range FBG based sensor. Here, the residual error of the transducer over its pressure and temperature operating range is presented. The error from calibration is within approximately +/ 1

3 402 Fig. 2 Linearity of a Bragg grating based pressure transducer. Fig. 5 Suface instrumentation unit. Fig. 3 Fig. 4 Grating based pressure transducer. Accuracy of transducer. psi over the full operating range. This level of accuracy is comparable to the performance found with the best electrical gauges used in the industry. In addition to the pressure and temperature transducers, we have developed surface instrumentation, cables, connectors and fiber feed-throughs to field complete fiber optic pressure and temperature measuring systems. The surface instrumentation, which interrogates the fiber optic sensor and converts fiber optic output into engineering units, is shown in Fig. 5. The fiber optic cable is deployed in a manner similar to the electrical cables commonly deployed in conventional reservoir monitoring systems. Fiber optic fiber Bragg gratings have the ability to measure multiple parameters in a distributed manner all along a single, common, deployed fiber optic cable that is mechanically identical to a 1/4 in. control line commonly used in the oil and gas industry. Fiber optic sensing systems thus enable a significant increase in the spatial resolution of pressure, temperature, and multiphase flow data provided in a permanent monitoring system. The advantages of distributed measurements within wells are numerous, particularly in wells using advanced completion technologies. Flow Monitoring: Multiphase flow meters measure the flow rates of individual components within coflowing mixtures of oil, gas, and water without requiring separation of the components. Over the past years, the industry has predominately focused on topside and subsea multiphase flow meters, advancing the technology such that today these meters are commercially available. The next step in multiphase flow metering is to move the flowmeters downhole [8], [9]. While maintaining the ability to monitor the entire well stream production, downhole flow meters provide the additional capability of determining the flow rates on a spatial distributed basis from within the well. Unfortunately, the challenges associated with developing accurate, reliable, downhole multiphase flow meters are numerous. The combination of harsh operating conditions, varied multiphase flow regimes, restrictive packaging constraints, data transmission challenges, environmental constraints, and non-intrusive (full bore) requirements have proved to be difficult barriers to overcome. Fiber optic technology enables these measurements to be performed downhole. Exploiting the inherent capabilities of fiber optic sensors to accommodate the harsh temperatures, packaging, environmental, and data transmission requirements, we have developed a downhole, fiber optic multiphase flow meter. The flow meter is non-intrusive, intrinsically safe, and contains

4 KERSEY: OPTICAL FIBER SENSORS FOR PERMANENT DOWNWELL MONITORING APPLICATIONS 403 no downhole electronics. The long-term goal is to develop multiphase flow meters capable of accurate measurement over an expanded range of multiphase flow regimes. The initial system, however, has been designed for quasi-homogenous flow regimes: oil, water cut binary liquid mixtures oil, water, and gas cut in low gas volume fraction mixtures (< 20%) To evaluate the performance of this novel fiber opticbased multiphase flow meter, we recently completed technology demonstrator test of a prototype downhole meter at an independent, industry-recognized, test well. The flow meter is designed into a standard piece of 3 12 in. production tube, approximately 12 ft long. The test facility was capable of producing specified mixtures of oil/water/ and natural gas through the production tubing. The oil, water, and gas components consisted of a 32 API crude, a 7% salinity brine solution and methane, respectively. These fluids were selected as representative of typical production conditions. The test was operated at low temperature (100 F) and low pressure (< 400 psi) conditions. The fiber optic multiphase flow meter was integrated into the production tubing of a 300 ft test well. The flow meter was oriented vertically within the well and performed the structural role of a section of standard production tubing. The flow meter communicated with the surface-based optoelectronics solely via a single armored fiber optic cable assembly. The test facility combined the oil, water, and gas prior to the test section and separated the three components on the surface prior to recirculation through the test section. By monitoring the flow rates of each component, the facility could produce arbitrary multiphase flow mixtures within the desired accuracy. Figure 6 shows the deployment of the flow meter into the test well facility. A primary objective of the test was to assess the ability of the flow meter to determine water cut in crude oil and brine mixtures. Figure 7 shows the measured volumetric phase fraction versus the reference measurement for water cut ranging from 0 100%. The reference measurement was determined from the flow rates of the individual liquids prior to being mixed and passed through the test section. For the objectives of this test, the meter was calibrated by measuring 100% water and 100% oil mixtures prior to calculating the phase fraction of intermediate mixtures. For production monitoring applications, industry required measurement accuracy is approximately 10% relative uncertainty in gas liquid rates and 5% uncertainty in water in liquid ratio. As shown, with the exception of a few outlying data points, the flow meter was able to determine water cut in crude and brine mixture to within +/ 5% over the full range of water cuts. Multiphase flow metering requires flow rate measurement in addition phase fraction. The ability of Fig. 6 Fig. 7 Flow meter deployment into a test well. Phase fraction measurement (water/oil ratio). the flow meter to measure velocity was evaluated for oil/water mixtures from 0 100% ranging from 1 ft/sec (22 gpm) to 25 ft/sec. Figure 8 shows the measured versus reference flow rate for oil/water mixtures over the operating range of the facility. As shown, the flow rate measured by the CiDRA flow meter agrees with the reference flow rate to within approximately 5% over the tested flow range. Although not presented herein, the flow meter performed similarly for low gas volume fractions mixtures of oil, gas, and water. Seismic Applications: Fiber Bragg grating sensors also have great potential for providing distributed sensing of acoustic pressures in downwell environments for the purpose of seismic monitoring. The trend in the industry is currently to utilize the sub-surface imaging capabilities of seismic monitoring not just for oil and gas exploration, but for monitoring reservoir depletion. This time-lapse for 4D seismic monitoring is a powerful new approach to increasing yields in the oil and gas

5 404 measurments, SPE 35559, Presented at the European Production Operations Conference and Expositon, Stavanger, Norway, [9] J.P. Brill, Multiphase flow in wells, J. Petroleum Technology, Jan Fig. 8 Flow rate measurement using the fiber optic flowmeter. industry. Permanently installed sensors located deep in wells can provide such imaging, but are required to survive in-well for > 10 years. Here again, the passive nature of fiber optic sensors allows for high reliability in harsh environments over extended periods. Alan D. Kersey is vice president and chief technology officer for CiDRA Corporation. Alan possesses over twenty year s experience in the field of fiber optic sensing, particularly in the fiber interferometry and bragg grating sensor systems. He received his B.S. in physics and electronics from the University of Warwick, and his Ph.D. from the University of Leeds, United Kingdom. Alan held a Research Fellow position in the Applied Optics Group at the University of Kent, Canterbury, United Kingdom, from September 1981 through November Dr. Kersey s work in the area of applied optics has led to over 100 journals and more than 150 conference publications, 25 USpatents and over 20 applications pending, and contributions to two books on fiber optic sensing. In 1993 he was elected Fellow of the Optical Society of America. 4. Conclusion We have developed and demonstrated high temperature, fiber optic reservoir monitoring system based on fiber Bragg gratings, including pressure, temperature and multiphase flow. This full suite of sensors share a common fiber optic operating principle and can be multiplexed on a single fiber optic cable, and provide enhanced capability to monitor oil and gas reservoir production on a real time, spatially distributed basis. Acknowledgements The author wishes to acknowledge the significant contributions of coworkers at CiDRA Corporation and OptoPlan A.S. to the work presented in this paper. References [1] E. Udd, Fiber Optic Sensors: An Introduction for Engineers and Scientists, Wiley, New York, [2] A.D. Kersey, A review of recent developments in fiber optic sensor technology, Optical Fiber Technol., vol.2, p.291, [3] A.H. Hartog, et al., Distributed temperature sensing in solid core fibers, Electron. Lett., vol.21, p.1061, [4] K.A. Murphy, Extrinsic Fabry-Perot optical fiber sensor, Proc. Optical Fiber Sensor Conference (OFS 92), p.193, [5] OptoPlan A.S., Norway, unpublished work. [6] A. Kersey, et al., Fiber grating sensors, J. Lightwave Technol., vol.15, no.8, [7] G. Meltz, W.W. Morey, and W.H. Glenn, Formation of bragg gratings in optical fibers by a transverse holographic method, Optics Lett., vol.14, p.823, [8] A. Aspelund, et al., Challenges in downhole mulitphase flow