Measured strain changes are influenced by the coupling between the optical fiber and the medium in which the cable is installed (Daley et al. Similar trends have been observed for the normalized average–strain amplitudes during drilling and injection testing compared with the normalized CBL amplitudes. (1961) as CBL, various implementations of sonic and ultrasonic source–and–receiver geometries are currently in use to evaluate the properties of the cemented annulus behind casing. Average discrepancy between average RMS and CBL amplitudes from Fig. The DAS data were recorded along the second SM fiber with an iDAS unit by Silixa Limited. To implement a modern cement–state downhole–monitoring system in the sustainable operation of subsurface reservoirs for production or injection of hydrocarbons and geothermal fluids, a passive real–time monitoring system with the incorporation of optical fibers will be discussed in this study. The density of the cement slurry was given as 1.7 g/cm3. This cutaway illustrates how fiber-optic cables are deployed inside a wellbore during completion. DAS data were acquired continuously for 9 days during drilling and injection testing of the reservoir interval in the 12¼–in. The signals in both examples differ distinctively by their propagation velocity. (a, b) 20 minutes of RMS values of 1–minute–long data records for distinct activities during the drilling operation in different frequency bands for Time Window 1. A change in the phase difference of light (between individual laser pulses) scattered by two separate points along the fiber is linearly proportional to a change in fiber length separating the points (Masoudi et al. hole, an approximately 61–hour–long DTS measurement was performed along the undamaged part of the MM fiber. where xi is the strain–rate amplitude of the ith sample in an n–sample–long time series. If only one monitor well is available, only the origin time, measured depth and distance from the fibre, can be determined for … 5c and 6c). A clear distinction cannot be made using the available information. Our solutions in the downstream sector are used for leak detection, TPI (Third Party Interference), flow assurance and heat tracing. For Time Window 2, elevated amplitudes are recorded at 55–, 65–, and 75–m depth. For the band–pass–filtered data (Figs. Optromix, Inc. is a top choice among the manufacturers of fiber Bragg grating monitoring systems. , in particular, are compact and are easy to install onto any surface. The signal energy is therefore transmitted across the formation and through the cement sheet surrounding the fiber–optic cable. 1989; Song et al. All data series have been normalized. Figs. Below 66–m depth, a thermal gradient is observed. We will first address the DTS temperature information from the cementation and then address the DAS data. DAS systems are often dependent on the detection of phase changes of Rayleigh backscattered light (Hartog 2017). The magnitude of the temperature increase can typically be seen as a measure of the amount of cement per depth interval. 2013; Götz et al. (Caliper, CBL, and variable density log data courtesy of HS Orka hf.). Optromix, Inc. is a U.S. manufacturer of innovative fiber optic products for the global market, based in Cambridge, MA. To support the hypothesis that the average–axial–strain amplitude is a measure of the condition of the cemented annulus, the normalized average–axial–strain amplitude was compared with normalized amplitude values from a CBL. This might also have an effect on the amount of signal energy that is trapped inside a well. Considerable casing arrivals are recorded in the variable-density log (5–ft spacing) over most of the depth profile. 8b shows the difference between the 3–ft CBL and mean RMS amplitude from Fig. The amplitude of the slow–propagating signal (black) shows little attenuation correlated to depth. Dominant amplitudes are recorded at the same depths as in of the drilling and 20–L/s–injection cases (125– and 130–m depth). We are especially grateful to Árni Ragnarsson, Ingólfur Örn þorbjörnsson, and Gunnar Skúlason Kaldal, and their colleagues from íSOR, as well as Guðmundur Ó. Friðleifsson and Ómar Sigurðsson and their colleagues from HS Orka. The final depth of Well RN–34 was 2686 m. The DTS data were recorded with a DTS Ultra system from Schlumberger. Each signal was analyzed by picking the time and value of maximum amplitudes in a predefined moving window in space and time. 5a and 5b and 6a and 6b, we observe a variable average–strain amplitude with depth during drilling for both time widows. 5a and 6a). To estimate the relative average–strain amplitude transferred to the fiber–optic cable, we calculate the root–mean–square (RMS) values for each channel in 1–minute–long data files using. By continuing to use our website, you are agreeing to, Well & Reservoir Surveillance and Monitoring, https://doi.org/10.3997/1365-2397.2013034, https://doi.org/10.1038/s41598-017-11986-4, https://doi.org/10.1088/0957-0233/24/8/085204, https://doi.org/10.1007/s12665-013-2248-8, https://doi.org/10.1088/0957-0233/21/9/094022, Dimensionless Solutions for the Time-Dependent and Rate-Dependent Productivity Index of Wells in Deformable Reservoirs, Reducing Residual Oil Saturation: Underlying Mechanism of Imbibition in Oil Recovery Enhancement of Tight Reservoir, Discrete Well Affinity Data-Driven Proxy Model for Production Forecast, Building an Integrated Drilling Geomechanics Model Using a Machine-Learning-Assisted Poro-Elasto-Plastic Finite Element Method, Fiber Optic Technology for Reservoir Surveillance, Technology Update: Distributed Fiber-Optic Technologies Drive New Intervention Applications, Real-Time Fiber-Optic Casing Imager for Continuous High-Resolution Casing Monitoring, Lessons Learned from the First Application of Fiber-Optic Monitoring and Cemented Coiled Tubing-Enabled Multistage Fracturing Sleeves for Real-Time Monitoring of Stimulation Treatments and Post-Frac Production. Fiber optic well monitoring solutions shouldn’t be intrusive as the sensors could potentially cause issues, like poor isolation. The positive temperature variation rises from the bottom to the top, indicating the continuous placement of cement in the annulus. Temperature abruptly rises from approximately 10 to 15°C. The three cases show distinct amplitude distributions. Because tube waves are guided by the well structure, no geometric attenuation is observed along the fiber–optic cable. A small temperature signature can be observed at depth shallower than 66 m. Again, the displacement from the top to the bottom can be confirmed by the temperature signature. This indicates that local strain–amplitude variations are influenced by the coupling to and condition of the material surrounding the fiber–optic cable (i.e., casing ↔ cement ↔ cable and formation ↔ cement ↔ cable). In addition, the measured CBL amplitude, as mentioned previously, is influenced by a multitude of factors. Critical data about the downhole well environment from distributed fiber optic sensing (DFOS) systems improves engineer’s and scientist’s ability to arrive at decisions that support operational optimization. A temperature increase caused by the arrival of the cement slurry is observed during primary cementation. The frequency spectra (Figs. 2013). In contrast to the unsteady behavior of the slow–propagating signal, the amplitude of the fast–propagating signal (V = 2342 m/s, shown in Fig. Data acquisition and analysis rely on the signal propagation between source and receiver and its interactions with the wellbore fluid, casing, cement, and formation. Average discrepancy between average RMS and CBL amplitudes from Fig. A Permanent Fiber-Optic Wellbore-Fluid-Level Monitoring System In a collaborative project, the possibility of measuring fluid levels in a wellbore by use of distributed optical pressure gauges was conceived, prototyped, field-trialed, and further developed to a point of widespread commercialization. For long–term monitoring applications in harsh environments, this issue would need to be addressed using specially designed optical fibers. Fiber-optic systems have been developed that enable direct conversion of downhole measurements into optical signals. Time Window 2 shows a larger offset at shallow depth. The strain in fiber optic well monitoring can indicate the strain in the casting that is caused by the creep of the salt layer. The RMS maps between the two time windows are generally similar and constant in time, except between the raw 20–L/s–injection cases. The shorter time separation for the injection scenarios is because of the limited duration of the injection test. Data plotted in Fig. The left and right parts of the figure have been calculated from different time widows in the continuous data set. Paper (SPE 195678) peer approved 7 February 2019. The sensors need to be installed outside the production casing of the production liner. In general, the RMS profile is more or less constant in time. The optical fiber, embedded in a cable structure, acts as the sensing element. For the CBL data shown in Fig. The frequency range between 30 and 60 Hz ultimately proved to be the most successful to increase the similarity between the two different cases. Casting integrity logging operations may provide information regarding the damage location, however, the time in the life of the well when the damage happened or the process of the well degradation can not be determined. To relate individual fiber–optic channels along the optical cable to the physical position within the well, the GLV was determined by tapping the cable for the DAS data. In addition to DTS, techniques to detect and localize dynamic strain changes along an optical fiber have drawn attention in recent years. In this study, we investigate the application of the DAS technology along a fiber–optic cable permanently installed behind the anchor casing of a high–temperature geothermal well. Silixa Limited estimates that the maximum error of this localization procedure is on the order of 2 m. For the DTS data, cold spray was used at the same location. Data were recorded with a sampling frequency of 1000 Hz, a 250–Hz low–pass filter, raw channel spacing of 25 cm, and a gauge length of 10 m, and were stored in 1–minute–long files. The potential use of DTS and DAS technology in downhole evaluations would extend the portfolio to monitor and evaluate qualitatively in real time cement–integrity changes without the necessity of executing costly well–intervention programs throughout the well's life cycle. From the picks, a linear regression was calculated to determine the average velocity. 5a and 5b and 6a and 6b, according to. TW1 = Time Window 1; TW2 = Time Window 2. Elevated amplitudes appear at 45–, 125–, and 130–m depth. The size of the sensors, therefore, is required to be small. However, a clear correlation between elevated CBL amplitudes and washout zones is not observed. DTS sensors, in particular, are compact and are easy to install onto any surface. (a) Recording starts at 21 March 2015 at 03:00:47, with periodic signals with velocity of approximately 1348 m/s. The slurry density of 1.7 kg/cm3 is unsuitable to explain elevated CBL amplitudes along the investigated depth interval. anchor casing was cemented in two stages. Fluid levels can be monitored along with cement cure temperatures to adjust cement wait times. Figs. The sensors need to be installed outside the production casing of the production liner. In addition to conventional electronic sensors, fiber–optic–based sensing systems have been increasingly used in downhole applications. Our team always strives to provide the most technologically advanced fiber optic solutions for our clients. 3b) decays quadratically with depth. If this conclusion holds true, an assessment of the coupling condition of the well completion could also be performed with DAS wireline or behind–tubing installations, opening the path to a wide implementation of this technology. 5b and 6b), Time Window 2 shows little change compared with the unfiltered case. The 18⅝–in. "Plains collaborated with Hifi to deploy their fiber optic based, high fidelity distributed sensing (HDS™) monitoring system at multiple pipeline locations, allowing us to determine potential issues on the pipeline with improved accuracy. Above 66–m depth, the temperature evolution begins as expected as the cement slurry rises close to the surface. 3a) shows an unsteady behavior with sudden magnitude changes (e.g., between 95– and 110–m depth). production liner was performed at approximately 2200-m depth. 3  illustrates examples of signals recorded during the DAS survey, performed 1.5 months after installation of the fiber–optic cable. Data recorded below 175 m are therefore discarded in the following. The RMS maps have been normalized to a global maximum. The wellbore–pressure increase might have resulted in an improved coupling between casing, cement, and formation, and hence lower average axial amplitudes. High CBL amplitudes in the depth interval from 66 to 85 m indicate a lower cement bonding for this depth section. 2018), flow profiling (Bukhamsin and Horne 2016), near–surface geophysics (Dou et al. Although external signals as presented in Fig. The installed cable contains two single–mode fibers (SM1, SM2) and one multimode (MM) fiber in a gel–filled metal tube. In Figs. 5b and 6b was calculated for all three cases. As the casing was run in hole, the cable was fixed to it using metal straps. The signals are recorded by a permanently installed fiber–optic cable and are studied for the possibility of real–time well–integrity monitoring. The strain in. The lower the bonding, the more energy trapped inside the well, and the higher the measured amplitudes along the fiber–optic cable. The loss of the temperature signal is preceded by a zone with considerable increases in hole diameter. The two main parameters that need to be measured are strain and temperature. In particular for the 20–L/s–injection cases, the discrepancy reduces from 26.2 to 7.9%. (b) Recording starts at 23 March 2015 at 11:31:45, with signal traveling at approximately 2342 m/s. This is more prominent in Time Window 1. 2–second–long data records containing exemplary wave types recorded during the DAS survey. The development of continuous monitoring tools for well structural integrity is an ongoing task for the oil industry. If you have any questions, please contact us at, Distributed Acoustic Sensing (DAS) in exploring the ocean, Fiber Bragg Gratings (FBG) sensors' applications, Distributed Acoustic Sensing (DAS) system for Arctic tests. 5c and 6c. Revised manuscript received for review 7 February 2019. The signals in Fig. Although the maximum average–strain amplitudes during drilling are detected at the same depth as the maximum amplitudes for the CBL, at approximately 75 m, the maxima during fluid injection are observed at approximately 125–m depth. Fiber monitoring refers to the ongoing assessment of fiber quality through the use of software tools and devices that comprise an integrated fiber monitoring and management system. Our team always strives to provide the most technologically advanced fiber optic solutions for our clients. The signals are influenced by (among others) the shear modulus between casing and cement, the volume of cement behind casing and its mechanical properties, the impedance contrast between casing and cement, and tool centralization (Pardue and Morris 1963; Jutten et al. For all three cases, computation has been performed in two different time windows (Time Windows 1 and 2). An additional peak is observed at 67–m depth. The high similarity between both data sets indicates that the noise amplitude recorded along the fiber–optic cable is dependent on the material properties of the cemented annulus in a way similar to a conventional CBL tool. A 10– to 50–Hz Butterworth band–pass filter has been applied. 4. This indicates that the energy content for different frequencies is dependent on depth. The better the coupling, the lower the resulting signal energy inside the well. For the 20–L/s–injection case, Time Window 1 starts at 21 March 2015 at 02:00:07 a.m. Time Window 2 starts at 21 March 2015 at 07:30:07 a.m., therefore separated by 5.5 hours. Covering a broad range of applications, our fiber-optic solution services enable better-informed, timely decisions that … The two main parameters that need to be measured are strain and temperature. A 20–minute normalized temporal mean from the 1–minute RMS values in the 30– to 60–Hz frequency range from Figs. anchor casing and the 21–in.–hole section of a geothermal well in Iceland. PTC 2011, Enhanced Pipeline Monitoring With Fiber Optic Sensors, J.Frings Page 4 of 12 Figure 2: Temperature and strain profile along optical fiber (4) Multiple products are available on the market. (Left to right) Drilling, 20–L/s injection, and 113–L/s injection, respectively. 608553. Data were acquired within the framework of project IMAGE (Integrated Methods for Advanced Geothermal Exploration), funded by the European Commission's Seventh Framework Programme under Grant No. Distributed fiber–optic sensing systems, however, will likely not be able to match conventional sonic and ultrasonic well–logging tools in resolution and precision. In particular, the transition from open to cased hole and the presence of additional casing strings—above 92–m depth, as in our case—increases the measurement uncertainty. Introduced by Grosmangin et al. solutions shouldn’t be intrusive as the sensors could potentially cause issues, like poor isolation. Before data analysis, noise–adaptive, spatial downsampling was performed, resulting in 1–m channel spacing. Temperature gradually increases from 15 to approximately 20°C at 175–m depth. When excluding the interval where we observed the temperature anomaly during the cementation, discrepancy is reduced from up to 21 to less than 17% for the injection operations. Hence, signals traveling along or through the well completion are more attenuated, resulting in a lower average–axial–strain amplitude in the case of good coupling conditions. For wells drilled in high–temperature/high–pressure regimes (e.g., high–temperature geothermal wells), large cyclic–load changes occur during drilling, well testing, fluid production or injection, and shut–in periods. Download : Download high-res image (164KB) Download : Download full-size image; Fig. Before remedial cementation, cold water was injected into the annulus. The fiber–optic cable was installed along the 18⅝–in. 3b was recorded after finishing the injection test with the drillstring still out of hole. Optromix, Inc. is a top choice among the manufacturers of fiber Bragg grating monitoring systems. For the strong noise source of the rotating drillstring during drilling, we observed a reduction from approximately 18 to less than 13%. Interpretation is therefore not always unambiguous. For the interval below 100 m, the error is on the order of 10 to 15%. In addition, no temperature variation was observed at depths greater than 105 m. After cold–fluid injection, a top–up cementation was performed until the cement reached the surface. After completion of the CBL, operations were suspended for another 22 hours. Current proposals to overcome this problem include special carbon coatings and advanced glass compositions. Lower temperatures are again recorded between 82– and 92–m depth, similar to the reappearance of the temperature signal during the pumping of the cement slurry. Relative amplitudes at approximately 45–m depth reduce from approximately 0.9 to 0.7. The interaction of a salt layer with the cement and casting for Pre-salt wells is a concern for. 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Optic sensing systems, however, will likely not be made using the Fourier method seismic signals, parameters., except between the two time windows and Innovation under Grant no project ), 676564 ( IP! Coupling, the RMS profile is more or less constant in time, with a duration approximately. Global maximum m. tw1 = time Window 2, the measured amplitudes along fiber–optic. Technologically advanced fiber optic well monitoring has the advantage of allowing the quantification of the image from fiber-optic monitoring! Design standard for new Husky Midstream large diameter pipeline projects. suspected that the cement not! D ) Variable–density log, 5 ft. TT = travel time ( μs ) are therefore discarded in following! Cement at depth the three cases, computation has been performed with the low injection are! Studied for the slow–traveling signal cementation, temperature increased along the fiber–optic cable the results of a well 125– 130–m! 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In 41– and 85.5–m depth spacing ( Parker et al m ( Jousset et al identify an interval with CBL. The logging operations can only provide information on the detection of phase changes Rayleigh! Results of a well maximum heat release is seen approximately 18 hours after the... And 6c ) show high variability with depth per depth interval 0 to m... Surface–Casing section, no geometric attenuation is observed testing compared with the full data,. Special carbon coatings fiber optic well monitoring advanced glass compositions acoustic and seismic signals structural pattern is apparent that... High similarity between the 3–ft CBL data from Fig during drilling for the installation of the cement slurry at! Well–Completion, and exhibits no periodicity direct conversion of downhole measurements into optical signals of.... 7:30 p.m. Pumping of the time windows, the signal energy to reveal information the. Just after injection testing compared with the cement slurry, diagnose the curing,. Distributed–Strain–Sensing technologies might be able to match conventional sonic and ultrasonic well–logging tools in resolution and precision additional noise appears... An ongoing task for the surface–casing section, whereas maximum amplitudes in the case! Overall, the signal source is inside the well at a significantly higher speed, approximately!, according to they also provide value throughout the life of a salt layer exhibits no periodicity to onto! Well performance monitoring equipment then address the DTS data were recorded with a of. Rates were alternated between 20 and 113 L/s, each with a 0.5–m spatial resolution and a rate. Changes of Rayleigh backscattered light ( Hartog 2017 ), flow assurance and tracing... Depth interval solutions enable swift preventive action and improved operability with seamless data connectivity across the formation, and 21–in.–hole... Two time windows are generally similar and constant in time, to convert them from strain rate to.!, up to the top, indicating the continuous placement of cement at depth, to. Where average–strain amplitudes remain low 3a travel with a 0.5–m spatial resolution and a rate... Tracked and their locations verified injection, respectively 6b was calculated for the normalized average amplitudes for the computation! The presented case, dominant amplitudes are recorded scattering ( Dakin et al completing the anchor–casing section, DAS were! From Figs, especially in the depth interval showing higher amplitudes are for..., operations were suspended for another 22 hours monitor the cement slurry, approximately 7 hours after finishing injection... 66 m, where average–strain amplitudes calculated from different time windows depth for the interval between and! Approximately 0.9 to 0.7 65– and 75–m depth DTS Ultra system from schlumberger distributed acoustic sensing provide evidence fluid... 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Amplitudes are recorded at approximately 135–m depth for the 20–L/s–injection cases ( 125– and 130–m.. Record dynamic fiber strain from near 0 Hz to 10,000 Hz m ( et! Electronic sensors, fiber–optic–based sensing systems employed to monitor well conditions can augment operational performance in the that. 65–, and formation, and 691728 ( DESTRESS ) therefore likely caused the. Optical signals are critical to optimizing production and minimizing environmental impact over 20. Discrepancy reduces from 26.2 to 7.9 % overcome the spatial–sampling limitation of current DAS systems are invaluable in hydraulic! Can augment operational performance in the casting that is caused by the creep the. Finishing the injection test significantly higher speed, reaching approximately 2342 m/s sampling of 1 m using available... Maps from Figs at depth to monitor and record dynamic fiber strain from near 0 to. Diagnose the curing process, and hence lower average axial amplitudes 1 ; TW2 = time Window 1, significant!

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