SPE-187441-MS Improved Monitoring System for Heavy Oil SAGD Wells Christopher Baldwin, Weatherford Copyright 2017, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in San Antonio, Texas, USA, 9-11 October 2017. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract This paper provides an overview of the development of fiber optic sensing for SAGD applications including a review of more than 10 years of work in development and field applications in Western Canada. Development of a fiber optic monitoring system to withstand the harsh environments experienced in the SAGD application requires consideration of the materials used to protect the downhole optical fiber, the chemistry of the downhole optical fiber, the basic optical fiber sensing technology implemented, and the optical interrogator functionality. Aspects covering corrosion of materials, hydrogen darkening, and system performance for different monitoring applications will be explored. Design and technical information will be provided along with certain case histories providing the applications and use of downhole fiber optics sensing for the SAGD applications including steamflood monitoring, sub-cool monitoring, and well integrity monitoring. Dealing with a harsh environment experienced downhole in the Western Canada SAGD applications including temperatures exceeding 230° C in high hydrogen environments has meant that the fiber optic sensing technologies have had to adapt and improve to be suitable to function reliably. Various technologies have been implemented throughout the previous 10 to 15 years, from Raman scattering based DTS systems to highly multiplexed Bragg grating based thermal monitoring systems. Multiple optical PT gauges have been designed and implemented. These include Fabry-Perot based systems as well as the Bragg grating based PT gauges. This paper will provide much-needed information to practicing engineers in the field of downhole reservoir monitor introducing them to concepts such as multi-point fiber Bragg grating based thermal monitoring and reliability of the monitoring systems. Information provided in this paper is applicable beyond the SAGD applications. The fiber optic monitoring systems may also be used for intelligent wells, subsea wells, and unconventional wells. Introduction Fiber optic sensors have been finding applications in the downhole oil and gas industry for almost 30 years. One area in particular that has used the unique advantages of fiber optic sensing is thermal monitoring of steam-assisted gravity drainage (SAGD) wells. SAGD wells typically have temperatures exceeding 230°C and pressures nearing 1,000 psi. These wells use heated steam to dilute and reduce of the viscosity of bitumen (a type of heavy oil) in the reservoir. As the bitumen becomes less viscous, gravity drains the bitumen to a lower producing well where the hydrocarbon product can be brought to the surface, usually with the use of 2 SPE-187441-MS electrical submersible or progressive cavity pumps. One particular fiber optic technology that has proven successful in these thermal monitoring applications is wavelength domain multiplexing of Bragg gratingbased fiber optic sensors. Commonly referred to as array temperature sensing (ATS), the Bragg grating arrays can be manufactured splice free for long-term reliability. The number of thermal sensing points can also range from a few to well over 100 for a single cable. Each Bragg grating sensing point provides a real-time, accurate measurement of temperature at that location along the wellbore. ATS systems have been successfully used to monitor the steam injection and production processes in SAGD wells. This technique differs from distribute temperature sensing (DTS) in that the temperature measurements come from discrete points along the optical fiber instead of being spatially averaged along the length. A study comparing the two optical monitoring technologies demonstrated that ATS-type sensors have less than half the noise level of DTS monitoring systems (Barry 2015). Therefore ATS systems are capable of performing more accurate temperature measurements and are able to resolve much smaller temperature features. Bragg grating optical sensors not only provide temperature measurements, but can also be packaged in a transducer to provide pressure and temperature (PT) readings. The optical PT gauge is compatible with the surface instrumentation recording the ATS responses allowing for the PT gauge to be integrated at the end of the ATS optical fiber for single wellhead penetration providing multiplexed, distributed temperature sensing and PT measurements. This monitoring technology has been used in permanent downhole monitoring application of the SAGD process including optimization of production, improving reservoir drainage, and lower operating cost over the life of the well (Gonzalez 2012 and Ficocelli 2016). This paper will provide a general description of the SAGD process and review some of the technical challenges involved with implementing a fiber optic downhole monitoring system. The sensing systems have demonstrated long lifetimes and reliable operation for many years in very hostile, hydrogen-rich environments. The applications are ideally suited for the capabilities of fiber optic sensing and harsh environments. The paper will then provide information on the fiber optic thermal monitoring technique involving multiplexed FBG sensors and a Bragg grating based PT gauge designed for the SAGD environment. Finally, field trial data from a new generation SAGD PT gauge will be presented and an application using coil logging for SAGD wells will be discussed. Heavy Oil Extraction with SAGD Method There are two main methods used to extract bitumen from the Canadian oil sands. For bitumen reserves near the surface, mining operations are used that require removal of the surface material and transportation of the material to a processing facility. Mining operations account for about 20% of the total recoverable oil sand reserves (ConocoPhillips 2017). For the remaining 80% of the Canadian oil sand reserves, an in-situ recovery process like SAGD is used (Papavinasam 2012). The SAGD process involves drilling a horizontal well pair with the two horizontal sections separated by approximately 5 meters. Figure 1 shows an illustration of a typical horizontal well pair. At the start of the SAGD process, steam is injected into both wells in order to form a subsurface steam chamber. This process is referred to as the circulation phase. Once the reservoir reaches an optimum heated condition, the steam injection in the lower of the two horizontal wells is ceased. The heated bitumen in the reservoir now has increased mobility and is able to drain (due to gravity) to the lower well where it is "produced" to the surface. The lower well is commonly referred to as the producer well, while the upper horizontal well continues to inject steam into the reservoir and is referred to as an injection well. As indicated in Figure 1, the producer well is at a lower temperature than the injection well during the production phase due to the extraction of the heated bitumen. If the well pair experiences a shut-in for any reason, another circulation phase is typically performed to restart the production phase. SPE-187441-MS 3 Figure 1—Illustration of paired horizontal wells depicting circulation and production phase Figure 2 illustrates that well pairs of horizontal wells are drilled from a central well pad in order to minimize land disturbance (Papavinasam 2012). Thermal monitoring along the horizontal wells during the circulation phase allows for monitoring of the steam front during the initial injection process and for determining when the steam chamber reaches optimum conditions. Additionally, vertical observation wells may be located around the reservoir with thermal monitoring to measure the extent of the steam injection process away from the well pair. Figure 2—Illustration of a SAGD horizontal well pair and two vertical observation wells Environmental Effects on Downhole Fiber Optic Sensors Oil sands are defined as: sand saturated with a highly viscous crude hydrocarbon material not recoverable in its natural state through a well by ordinary production methods. As defined, bitumen is a hydrocarbonaceous material that consists of carbon and hydrogen with smaller amounts of nitrogen, oxygen, sulfur, and metals (especially nickel and vanadium) (Speight 2009). Therefore, wetted materials (or materials in contact with well fluids) must be able to withstand exposure to potentially corrosive chemicals such as sulfur, high temperature steam, and deal with erosion and wear due to the movement of sand within the bitumen; making material selection a key factor in determining long-term survivability. The requirements for a successful monitoring system in SAGD applications are dictated by the harsh environments experienced downhole. In these environments temperatures can easily exceed 230°C and there is often a high concentration of hydrogen (Baldwin 2014). In the past, the presence of hydrogen in these applications has caused issues with various fiber optic sensing technologies. Improvements in optical 4 SPE-187441-MS fiber design and downhole cable construction has helped to mitigate some of these issues, but any downhole monitoring system must be able to cope with the presence of hydrogen in relatively high temperature environments. Hydrogen effects on optical fibers are influenced by many parameters including temperature, optical fiber composition, optical fiber coating, and the type of hydrogen intrusion. Figure 3 displays a typical attenuation curve for optical fiber exposed to hydrogen. There are two main categories for hydrogen intrusion. The first is free hydrogen (H2) which diffuses into the optical fiber but does not chemically react. This influence is reversible in that the H2 can be evacuated from the optical fiber when it is removed from the high H2 environment (usually performed in ambient atmosphere at elevated temperature, but can also be done in vacuum). This form of hydrogen intrusion affects all silica fibers. The second method of hydrogen intrusion involves hydroxyl species (OH), which chemically react and are mostly irreversible. At elevated temperatures, H2 can react with point defects in the optical fiber core and generate OH absorption at wavelengths around 1420 nm and can also induce a short-wavelength absorption edge (SWE) in Gedoped fibers (Lemaire 1991 and 2007). In recent years, the industry has been turning to hydrogen-resistant, hydrogen-tolerant, pure-core optical fibers. These specialty optical fibers use a core region that is pure silica (no dopants) and a cladding region that has index-of-refraction-lowering dopants such as fluorine to create the light guiding properties (Rehman 2010). Although these optical fiber designs show little effect due to OH intrusion, they are still susceptible to free hydrogen silica effects at particular wavelengths. Figure 3—Absorption spectrum for optical fiber exposed to various contaminants The data presented in Figure 4 is not from a SAGD well, but the effect due to hydrogen absorption would be equivalent and even at a more rapid pace due to the elevated temperatures. The attenuation data was obtained from an optical time domain reflectometer (OTDR) and shows the amount of optical attenuation along the length of an optical fiber within a wellbore (Blount 2015). Each data trace was collected at a different date as indicated in the plot. As observed, there is negligible change in the attenuation, even a few weeks after the fracture, meaning the optical fiber and cable structure survived the fracturing process. In the example, attenuation increases start at the extreme end of the cable and progress up towards the wellhead over time, but do not progress past a certain point (most likely the location of an in-well dry-mate connector). SPE-187441-MS 5 Figure 4—OTDR traces at 1625 nm showing hydrogen induced attenuation vs. time (Blount 2015) Due to these known hydrogen effects on optical fibers, a downhole monitoring system was designed based on Bragg grating technology. The use of Bragg gratings allows many fiber optic sensors to be interrogated on a single common optical fiber through wavelength division multiplexing. Commonly referred to as array temperature sensing (ATS), the Bragg grating arrays can be manufactured splice free for long-term reliability. The number of thermal sensing points can also range from a few points to over 100 for a single cable (Ficocelli 2016). Bragg grating technology has the distinct advantage of enabling relatively high optical power return signals from the downhole sensing locations. Often, the working optical power budget for Bragg grating sensing systems exceeds 55dB. Of course this parameter depends on the reflectivity of the Bragg grating sensors and the Bragg grating interrogation instrumentation. In order to predict expected lifetime of in-well Bragg grating sensors under different conditions, an empirical model was developed to understand the long-term attenuation affects. Displayed in Figure 5, the model provides a worst case scenario for attenuation of Bragg grating sensors at various temperatures. Bragg grating sensors function by relating a wavelength shift response to temperature or pressure, so the attenuation effects do not affect the ability to provide accurate measurements. Application of the model is demonstrated in Figure 6, where attenuation changes from a downhole Bragg grating based PT gauge are plotted versus time. The attenuation model is applied to the trend of the data to provide a prediction of remaining life of the PT gauge due to hydrogen attenuation effects. 6 SPE-187441-MS Figure 5—Attenuation model of hydrogen exposure on optical fibers (Worst case scenarios) Figure 6—PT Gauge optical power data for lifetime prediction Bragg Grating Based PT Gauge The use of a Bragg grating-based fiber optic PT gauge has been examined in many applications within the SAGD wells of Western Canada. The initial goal for the early PT gauge design introduced in 2009 was to provide an in-well pressure measurement that was more accurate and reliable than traditional bubble tubes. Using Bragg grating sensing technology for the PT gauge allowed the gauge to be multiplexed on the same optical fiber as the ATS solution. In many cases, the optical PT gauge was integrated at the end of a thermal monitoring string, and since the ATS and PT gauge are based on Bragg grating sensors they can be interrogated by a single optical sensing instrument reducing system costs. Recently, a new generation design for the Bragg grating PT gauge has been introduced for the SAGD pressure monitoring application. The basis for the new-generation optical PT gauge stems from glass Cane™ technology developed by CiDRA/Weatherford in the late 1990s. The previous-generation optical PT gauge (Figure 7) was based on a bonded Bragg grating sensor design, which allowed for a small form-factor of ¼ inch diameter. The small form-factor enabled the PT gauge to be easily integrated into coil tubes for SPE-187441-MS 7 installation in the wellbores. However, the bonded Bragg grating design posed performance limitations in terms of maximum pressure measurement, a nonlinear pressure response, and poor performance in highvibration environments. Despite these potential limitations, more than 150 bonded Bragg grating gauges have been successfully installed in thermal wells globally. With the use of glass Cane™ technology for the optical PT gauge, the response to pressure is highly linear and the overall design of the gauge has improved manufacturability and increased the operating pressure range. Figure 7—Example of an early generation Bragg grating based PT gauge Development of any new sensor requires evaluation under expected operating conditions. Displayed in Figure 8 is the qualification test plan used for the SAGD PT gauge. The testing included shock and vibration testing, thermal cycling, and pressure loading. Testing also included ensuring that the PT gauge continued to perform within specifications after experiencing an over-pressure to 1.2 times the maximum operating pressure (2400 psi for the SAGD PT Gauge). Multiple prototype PT gauges were subjected to the qualification procedure to ensure that the design was valid across multiple samples. After each test of the procedure, the prototype gauges were tested at room temperature and pressure to determine if any damage had been incurred during the testing. A photo of two of the vibration test fixtures is shown in Figure 9. Additional testing of the PT gauges included extreme over-pressure and over-temperature testing as well as testing to failure. Figure 8—Qualification testing procedures for SAGD Cane PT gauge 8 SPE-187441-MS Figure 9—Vertical and horizontal vibration testing The design of the improved SAGD PT gauge shown in Figure 10 includes materials for corrosive resistance, appropriate wall thickness to support pressure loading, and internal design measures to handle the CTE (coefficient of thermal expansion) mismatch between the Cane glass and metal elements. CTE mismatch is a major design issue for the PT gauges because metal materials will expand much more than the glass components when exposed to the ultrahigh temperatures expected in SAGD downhole applications. The Cane-based gauge also benefits from knowledge gained from more than 15 years of experience from more than 800 installations of a high-pressure high-temperature (HPHT) optical PT gauge. The design is an aggregation of key features leading to a reliable, stable, and accurate optical PT gauge. One key feature of the new design is the protection of the bellows assembly, seen in Figure 7, within the outer diameter of the PT gauge. As stated earlier, the SAGD Cane PT gauge can be integrated onto an ATS sensing cable (shown in Figure 11) to enable thermal profile monitoring and pressure sensing at the tip of the sensing cable. Figure 10—Improve PT Gauge SPE-187441-MS 9 Figure 11—ATS Cable SAGD applications for fiber optic sensing The use of Bragg grating sensors for thermal monitoring in SAGD applications began in 2007 with the first installation of a 40-point sensing array. A few other trials quickly followed and the use of these permanent monitoring systems grew to more than 50 installations a year in 2014. In 2009, an optical PT gauge based on Bragg grating sensors was introduced to the market. The gauge had the ability to serve as a stand-alone sensing point at the termination of the optical cable, or be integrated on the same optical fiber and cable as the Bragg grating sensing arrays for thermal monitoring, as previously discussed. For over a decade, Bragg grating technology has been expanding the number of applications for SAGD wells. The thermal profile traces shown in Figure 12 display a correlation in temperature along the wellbore between both wells during the circulation phase. During the production phase, the lower producer well is observed to be at a lower temperature compared to the injection well. Figure 12—Typical thermal profile of injection and production well during circulation and production phase with time increasing to the left. In-well ATS sensors were used to monitor the steam front as it progressed along the length of the horizontal wellbore (Gonzalez 2012). As illustrated in Figure 13, the spatial separation and real-time data acquisition of the individual sensors provided a means to determine the velocity of the steam front along 10 SPE-187441-MS the wellbore. Also, the fast data sampling rate provided an understanding of how fast the region near each temperature sensor reached a saturation value (approximately 238°C for this particular application). In the figure, the thermal response of the first four FBG sensors is shown. As the steam progressed along the wellbore, each sensor responded based on the velocity of the steam front and the physical location of the sensor. After the first two sensors reach maximum temperature, the steaming was stopped and the sensors measured the cooling rate. The sensor closest to the wellhead was the last cool down. Thermal response data, such as that shown in the figure, can be used by reservoir engineers to model the reservoir and plan for future production operations. This type of data is evaluated not just during circulation, but also following shut-ins to examine changes in the reservoir (Baldwin 2015). Fine tuning of the steam injection rates, temperature, and pressures has led to a lowering of steaming requirements and operational savings (Fococelli 2015). Reductions in the amount of steam required also leads to a reduction in the amount of green-house gas (GHG) emissions from the SAGD operation (Ficocelli 2014). Figure 13—Example of FBG thermal monitoring data of a steam flood (Baldwin, 2015) During the production phase, thermal monitoring is used to measure the temperature difference between the injection and production well. Temperatures in the production well increasing to meet the injection well temperature is an indication of steam breakthrough to the production well. If this occurs, the production well will return the steam (or condensed water) to the surface instead of the bitumen. Keeping an optimum temperature difference between the injection and production well is a key parameter to optimizing SAGD wells through the steam-oil-ratio (SOR) and is referred to as sub-cool monitoring (Gonzalez 2012). Managing the local or zonal subcool along 40 to 60 locations with a reliable optical ATS and PT monitoring system along the lateral section of the well optimizes the production rate. A high local subcool or temperature differential may cause cold spots between the injector and producer wells along the horizontal section and may impair oil production. Real-time monitoring can enable PID feedback loop control to reduce the cumulative SOR and greenhouse gas (GHG) emissions and to increase the production rate (Gates 2012). Intake pressure and motor temperature monitoring at the ESP pump extends the life of the artificial lift system by preventing steam breakthrough, flashing, and cavitation and by monitoring the condition of the pump motor. In SAGD, the management of the injection temperature, pressure, flow rates, and sub-cool SPE-187441-MS 11 and ensuring a uniform chamber growth are more easily accomplished with a reliable optical PT gauge and ATS-based thermal system (Ficocelli 2016). Field Trial of the Improve SAGD Cane PT Gauge The field trial for the SAGD Cane PT was performed in the Athabasca Region of Alberta, Canada. The 1/4-in.-OD downhole sensing cable with 40 point ATS optical fiber and the SAGD Cane PT at the tip of the cable, was installed in a producer well. The first ATS sensors (ATS1) was located near the heel of the well; ATS 40 was landed near the toe. The ATS monitoring cable was pumped into a 2 3/8-in. (60.3-mm) OD guide string using a 1.81-in. (45.97-mm) polymer pig. The pig was attached to the tip of the 1,600meter capillary where the SAGD Cane PT was located. This assembly was delivered through the wellhead hanger, secured, and integrated with the sheave mechanism. A capillary spooler pump truck was used to pump the liquid until the pig and cable began to move and the SAGD Cane PT was landed at the toe. The entire surface data-acquisition system (including configuration of all calibrations for all the SAGD Cane PT and ATS thermal sensors) and the surface fiber optic cables were installed within a 4-hour window after the safety meeting. The capillary pump down technique used for this installation is not the only available method to install the SAGD Cane PT gauge. There are two other installation methods: (1) running the capillary together with coil tubing and (2) clamping to the outside casing or tubing. The data shown in Figure 14 displays the temperature responses along the horizontal wellbore with the final temperature response from a Bragg grating based PT gauge. Another temperature reading near 700 mKB is provided by another Bragg grating based PT gauge on a different sensing cable. From the figure, the measured temperature between the PT gauge near 700 mKB and the nearest ATS sensors are in good agreement. The readings from the ATS sensors display an increasing temperature along the wellbore to approximately 1350 mKB reaching a maximum temperature of 235°C. After this point, the thermal response is observed to decrease at the toe of the well. Figure 14—Thermal profile of the ATS sensing cable (toe string) and temperature response of the bonded FBG PT gauge at (ESP string) Figure 15 presents the pressure in light blue and the temperature in red as reported by the Bragg gratingbased PT gauge located at the toe of the well during the production phase. The dark blue line is the 12 SPE-187441-MS temperature of the last ATS thermal sensor located a couple of meters from the PT gauge. The temperature can be read on the right axis, and the pressure can be read on the left axis. The green line corresponds to the pressure, on the left axis, reported by another Bragg grating-based PT gauge located at the heel of the well. Notice that the pressure reported by the PT gauge at the toe is consistent with the pressure reported at the heel pump with synchronized evolution and variations and a pressure drop of about 100 kPa over the horizontal section. Also notice that the temperature reported by the toe located PT gauge is consistent with the temperature reported by the ATS sensor a couple of meters away. The data displayed in Figure 15 shows that the ATS and PT gauge in-well system has maintained full functionality for over two years of continuous operation. In fact, the majority of the in-well systems have demonstrated high reliability with some of the earliest installed systems still operational after 8 years. Figure 15—Response history of pressure gauge field trial Coil logging Another application for the ATS and SAGD PT gauge that has been explored recently is for use in coil logging operations. The coil logging system provides the high spatial resolution of a DTS system with the accuracy and data frequency of the ATS thermal monitoring system. A SAGD PT gauge is integrated at the end of the ATS sensing cable in the bottom hole assembly (BHA), and both ATS and DTS cables are encased in a single coiled tube as illustrated in Figure 16. Rigless coil tubing deployment provides a cost effective solution for acquiring accurate temperature and pressure data in the harsh, challenging environments of SAGD wells. SPE-187441-MS 13 Figure 16—Illustration of the coil logging string with integrated PT gauge in the BHA Summary This paper has provided an introduction to the development and use of Bragg grating technology for monitoring SAGD well applications. Downhole environmental conditions are a major consideration for this fiber optic sensing technology. The ability to provide long-term reliable operation depends not only on the material selection for wetted components but also the ability for the fiber optic sensors to overcome and mitigate the effects of hydrogen. Bragg grating optical sensing technology has been proven to provide the long-term sensing needed in the SAGD applications with the ability to provide thermal profile measurements and point pressure and temperature measurements. This data is routinely used to examine the steam flood, monitor and optimize the circulation phase, and monitor sub-cool during production. An improved SAGD PT gauge was demonstrated to provide reliable service for over two years in a production well. Finally, a new coil logging service has also been introduced to take advantage of the unique abilities of fiber optic sensing for SAGD applications. References Baldwin, C. 2015. 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