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Abstract
Early detection of a gas kick is crucial for preventing uncontrolled blowout that could cause loss of life, loss of assets, and environmental damage. Multiphase flow experiments conducted in this research demonstrate the capability of downhole fiber optic sensors to detect a potential gas influx in real-time in a 5000 ft deep wellbore. Gas rise velocities estimated independently using fiber optic distributed acoustic sensor (DAS), distributed temperature sensor (DTS), downhole gauges, surface measurements, and multiphase flow correlations show good agreement in each case, demonstrating reliability in the assessment. Real-time data visualization was implemented on a secure cloud-based platform to improve computational efficiency. This study provides novel insights on the effect of circulation rates, gas kick volumes, backpressure, and injection methods on gas rise dynamics in a full-scale wellbore.
© 2020 Optical Society of America under the terms of the OSA Open Access Publishing Agreement
1. Introduction
A gas kick is defined as an unexpected and undesirable gas influx into the wellbore from a permeable geological formation due to an underbalanced condition in which the pressure inside the wellbore is less than formation pressure. If not detected in time, a gas kick can result in a catastrophic blowout at the surface causing personal injury, loss of life, and environmental damage [1]. Conventional kick detection/monitoring methods primarily rely on surface-based measurements, which are sometimes inadequate due to monitoring lag and low metering precision. This time delay can be especially critical in geologically complex operations, such as in offshore environments, where the wind and waves create dynamic downhole conditions more difficult to quantify by solely relying on sensors at the surface [2]. The harsh environmental conditions combined with the continuously changing flow dynamics across thousands of feet in depth makes distributed fiber optic sensing a prime candidate for real-time downhole detection and monitoring of gas kick. The use of fiber optic sensors as a wellbore monitoring system is very attractive since a single lead cable can provide spatially and temporally continuous monitoring along the entire length of the fiber and no additional downhole electronics. Fiber optic sensors can be cemented behind the wellbore casing, strapped to the production tubing, or run on a wireline cable. Thus, a very promising possibility is to strap them to marine risers to detect and investigate the gas kick in the riser [3]. This study presents results from pioneering research that demonstrates this possibility with verified and validated datasets for gas kick migration at full-scale annular conditions.
The experiments conducted on a 5000 ft deep test well at Louisiana State University (LSU) simulate field-scale wellbore conditions and demonstrate the application of fiber optic sensors for early detection and monitoring of gas kick. The test well was instrumented with fiber optic DAS, DTS, four downhole pressure and temperature gauges, and surface measurement instruments. An extensive set of experimental runs were conducted to analyze gas flow characteristics for varying fluid circulation rates, gas kick volumes, backpressure applied at surface, and injection methods mimicking realistic field scenarios. The rate at which gas rises in the wellbore is a key parameter that dictates the well control strategy [4,5]. Thus, for each experimental trial, gas velocity was estimated independently from the DAS, DTS, downhole pressure gauges, and three multiphase flow correlations. The results show good agreement, giving us confidence in the application of fiber optic sensing technology for early kick detection. Given the variety and volume of measurement data generated in the process, a state-of-the-art cloud-based data visualization platform was implemented to improve computational efficiency. The experiments conducted in this research provide novel insights for understanding the gas rise dynamics in full-scale wellbore conditions using distributed fiber optic sensors, which could lead us to more efficient and safer procedures to control a gas kick.
1.1 Distributed fiber optic sensing technology
A typical set-up for distributed fiber optic sensing is shown in Fig. 1(a) [6]. Laser pulses at a given repetition rate are continuously launched into the installed fiber cables. As the light pulse travels, a portion of the photons interact with the glass medium through which it travels and the backscattered photons are picked up by the detector. The backscattered signal consists of the Rayleigh, Raman, and Brillouin bands, as shown in Fig. 1(b). The DTS unit processes the Raman stokes and anti-stokes wavelength band of the spectrum to achieve a distributed temperature profile along the entire length of the fiber. The DAS unit combines the received light with the local oscillator in a heterodyne process to preserve the phase of the Rayleigh back-scattered lights. The phase measurement of the individual pulses gets separated and aggregated during processing to provide an improved dynamic strain profile, more resilient to fading, along the entire length of the installed fiber cable, and thus measure the downhole acoustic source signals responsible for these effects [7]. Knowledge of the propagation time of a pulse along a fiber of a known refractive index enables the position of the interaction to be located and, when used for sensing, the measurand perturbation on the fiber to be determined.
2. Materials and methods
2.1 Experimental set-up
In this study, well-scale gas kick experiments were conducted at the Petroleum Engineering Research & Technology Transfer (PERTT) lab facility at LSU, shown in Fig. 2(a). PERTT lab is a world-renowned facility for the development, integration, and testing of technologies used in the oil and gas industry. There are six wells, up to 5800 ft in depth that provide a unique full-scale environment to test downhole equipment on field-scale tubulars at high pressures. The facility has the ability to inject high-pressure gas at 4000 psi and three gas storage wells providing roughly 280,000 SCF (standard cubic feet) of high-pressure gas storage that can be injected into the test-well to simulate gas influx or kicks.
Fig. 2. (a) PERTT well-scale experimental facility at LSU (b) Schematic of the test-well at PERTT instrumented with fiber optic sensors.
The multiphase kick detection experiments were conducted in one of the test wells at PERTT lab, which is a 5163 ft deep cemented wellbore with a casing outer diameter (OD) of 9.625 in. and a production tubing of OD 2.875 in., as shown in Fig. 2(b). The wellbore replicates a real-world oil and gas well at a field-scale. Fiber optic DAS and DTS were strapped to the outside of the tubing (from the surface to 5025 ft depth), as shown in Fig. 2(b). Additionally, there are four downhole pressure and temperature gauges that read measurements in the annulus. The specifications of the DAS, DTS, and the downhole gauges are summarized in Table 1. The measurements at the surface include the water circulation pump speed (in strokes per minute or SPM), downstream flow rate (in gallons per minute or GPM), and the surface tank volume (in gallons).
Table 1. Measurement specifications for the DTS and DAS systems installed on the test well.
2.2 Methodology
The wellbore was initially filled with water, and a fixed volume of nitrogen gas was injected (the “gas kick volume” measured in barrels), either down the tubing or down the 0.5 in. gas injection line strapped outside the tubing (shown in Fig. 2(b)). Subsequently, water was circulated at a fixed circulation rate (measured in GPM) pushing the gas downwards and eventually upwards through the annulus, while constant backpressure at the surface is maintained on the casing. The objective was to characterize the gas velocity at varying multiphase flow conditions using fiber optic sensors and downhole gauges. While an extensive set of experimental runs were conducted at varying circulation rates, kick volumes, and back pressures, results from three trials, summarized in Table 2, are discussed to illustrate the workflow and the key findings.
Table 2. Flow parameters for the experimental trials discussed in this study.
2.3 Cloud-based visualization of fiber optic data
Distributed fiber optic sensing can generate enormous volumes of real-time data [8]. For example, DAS can create terabytes of data over the course of just a few hours. Given that most well-sites are remote, with limited communications capabilities – issues of data compression, storage, transmittal, and real-time analysis can make the interpretation of this data challenging. The development of cloud computing techniques can help bridge this gap. In this research, a state-of-the-art Google cloud-based solution was utilized for real-time monitoring of the fiber optic DAS and DTS data, as illustrated in the schematic in Fig. 3. At the center of the platform is the ruggedized edge computing device, the Agora Gateway, which collects, analyzes, and transmits data from field devices to the cloud in real-time. By harnessing the power of cloud computing, real-time visualization implemented on a secure IoT platform enables operators to improve computational efficiency and minimize operational risks.
The Agora Gateway is designed to minimize hardware vulnerability. Its robust security policy ensures that only approved applications can run on the device and it only permits outbound connections to known and trusted internet locations. As shown in Fig. 3, the DTS data was streamed via the Agora device to the Google cloud, while the DAS data was collected through an acquisition PC and streamed to the cloud via installed streaming software on an acquisition PC. A real-time surveillance app was developed on the Google cloud platform which picked up the streamed DAS and DTS data and displayed the time-series plots that can be customized by the users. The future plan is for DAS and gauge data to be streamed to the cloud without the need of an acquisition PC.
2.4 Flow correlations
The gas rise velocities in the annulus estimated independently from the DAS, DTS, and the downhole gauges were compared and validated with well-known multiphase flow correlations. Gas velocities were estimated as the sum of the liquid velocity (assumed in this work as the circulation flow rate of the water divided by the annulus cross-sectional area) and the gas slip velocity (vs). Much of the experimental and theoretical work conducted in the development of gas slip velocity correlations are largely dependent on the flow pattern. The gas rise velocities measured by the data acquisition systems deployed in the well and the simulation results [9] strongly suggest that bubble flow is the two-phase pattern prevailing in all experimental trials. The three gas slip correlations considered in this work are summarized in Table 3.
Table 3. Flow correlations used for gas slip velocity estimation.
The first correlation presented in the table was derived by Griffith [10] for slug flow. However, Stanbery [11] proposed that it can be used to predict gas slip velocities for bubble flow, provided that D is considered to be the maximum bubble diameter. In this paper, D is the difference between the inner radius of the casing and the outer radius of the tubing. K1 is a constant that depends on the annulus geometry, and ρl and ρg are respectively the water density and the average density of the nitrogen inside the well. The next correlation presented in Table 3 was derived by Harmathy [12] for bubble flow as a function of the fluid densities and the nitrogen/water surface tension (σ). Zuber and Hench [13] modified the correlation proposed by Harmathy by multiplying it with the liquid holdup (H) squared, to account for the presence of a bubble swarm. Table 3 summarizes the three correlations and the calculated values of slip velocities considering the conditions existing during the experimental trials. An average liquid holdup of 0.9 was assumed as indicated by DAS measurements and simulation results [9].
The gas rise velocity is given by the sum of the upward liquid velocity in the annulus at a given circulation flow rate and the slip velocity calculated in Table 3. For example, in Trial-1, the upward liquid velocity for a circulation flow rate of 150 GPM is 0.91 ft/s (for the annular flow area given by πD2) and the slip velocity for Griffith is 0.94 ft/s. Thus, the gas rise velocity for this Trial, using the Griffith correlation, is 1.85 ft/s. The results for all the trials using each correlation are summarized in Table 4.
Table 4. Summary of average downward and upward gas velocity estimates for all three trials
3. Results and discussion
Gas flow behavior as it travels down the tubing or the injection line, and then upwards in the annulus in a circulating water column was observed using the DAS, DTS, downhole pressure gauges (only in the annulus), and surface measurements for the trials summarized in Table 2. The objective was to estimate the gas velocity independently through each of these sensors and cross-validate the calculation to provide high confidence in the assessment. Published multiphase flow correlations, discussed in the previous section, were used to further corroborate the final results. The time-domain raw data from fiber-optic DAS was processed to obtain frequency band energy (FBE) through the application of fast Fourier transforms. The FBE values correspond to the spectral power of the signal within a specific frequency range [7]. The effect of water circulation flow rate, backpressure at the surface, gas kick volume, and injection method are discussed.
3.1 Trial-1 (Jan 8, 2020)
DAS signature for Trial-1 is shown in Fig. 4 for the frequency range 0 to 5000 Hz. The color in the plot corresponds to the intensity of the spectral power of the acoustic signal in the specific frequency range for the FBE. In this trial, nitrogen is injected down the gas injection line (shown in Fig. 2(b)). The water circulation (at 150 GPM) that follows the gas injection (2 bbl.) starts around 18:39, which appears as the high acoustic energy seen in Fig. 4. Subsequent upward gas migration in the annulus is observed in the DAS signature, with the first arrival of gas at the surface around 19:18. The start of water circulation at 18:39 is also confirmed from the surface gauge plots in Fig. 5 that show an increase in the pump speed and downstream flow rate as the circulation starts, and a decrease in the surface tank volume since the water is flowing out of the surface tank. The first arrival of gas at the surface is indicated by an increase in the surface tank volume as the gas expands as it arrives at the surface, and an increase in the downstream flow rate at 19:17, which is aligned with the observations from the DAS data. The gas rise velocity from DAS is approximated from the slope of the observed signature and it varies from 1.6 ft/s at the bottom to about 2 ft/s at shallower depths. The increase in gas velocity as it travels to the surface is expected due to the diminishing hydrostatic pressure and gas expansion effects [5]. Closer to the surface, the gas signature is very faint, indicating a dispersed gas flow behavior.
Fig. 4. DAS plot for the frequency range 0-5000 Hz for Trial-1 (color corresponds to the intensity of the FBE).
The gas and water flow signatures were observed in the DTS, as shown in Fig. 6, where the top and bottom portions are shown separately to highlight the signatures seen at different temperature ranges. As the water circulation begins at 18:39, a temperature drop is observed in Fig. 6(a), since the injected water is colder than the water in the wellbore. The gas rise in the annulus is observed in Fig. 6(b). The gas signature is also clearly observed in the temperature gradient profiles illustrated in Fig. 7 with respect to depth (Fig. 7(a)) and time (Fig. 7(b)). The first arrival of gas at the surface around 19:17 is observed in Fig. 7(a). The gas arrival time is in good agreement with the DAS and surface measurements. The water circulation that follows the gas injection, upward migration of gas in the annulus, and the gas arrival at the surface can be identified easily. The gas rise velocity in the annulus ranges from about 1.47 ft/s. at the bottom of the well to 1.9 ft/s at shallower depths. The increasing gas velocity at shallower depths is expected due to the lowering of pressure and expansion effects [5]. The gas signature close to the surface indicates a dispersed flow, which is most clearly observed in Fig. 7(a).
The gas rise velocity can also be estimated using the downhole pressure gauges. Figure 8 shows the pressure readings at three downhole pressure gauges subtracted by the backpressure applied at the surface (or the choke pressure) as functions of time. In the figure, time zero is considered to be the moment at which the gas injection begins. The moments at which the pressures start to drop represent the instants that the gas reaches each gauge. Thus, for the gauges at depths of 3502’, 2023’, and 487’ the arrival times are respectively 32, 48, and 63 minutes. Thus, the average gas rise velocity between gauges 3502’ and 2023’ is 1.5 ft/s, while between gauges 2023’ and 487’ it is 1.7 ft/s. This again demonstrates the gas acceleration at shallower depths. The gas rise velocities measured and calculated using the DAS, DTS, surface gauges, and multiphase correlations are in good agreement, as summarized in Table 4.
3.2 Trial-2 (Jan 9, 2020)
Figure 9 shows the DAS data (FBE) corresponding to the frequency range 0 to 5000 Hz. Water circulation (100 GPM) that follows the gas injection (5 bbl.) down the tubing starts around 20:08. The signature of gas going down the tubing is more clearly observed compared to Trial-1 because of injection through the tubing (2.87” OD) rather than the small-diameter injection line (0.5” OD). The injected gas is observed to reach the bottom of the tubing at roughly 20:20. However, the gas signature in the annulus is not very clearly observed in this frequency range. Figure 10 shows the DAS data for a narrower frequency range of 10-50 Hz. In this frequency band, the gas rising in the annulus can be more clearly observed. The gas velocity was estimated from the slope of the gas signature resulting in a velocity of about 1.2 ft/s at the deeper interval and increasing to about 1.56 ft/s at the shallower depths. The increase in the gas velocity with decreasing depth is a result of diminishing hydrostatic pressure and expansion effects [5]. The downward gas velocity in the tubing is about 7 ft/s. Figure 10 shows the first gas arrival at the surface around 21:13. The interpretation of gas injection and first arrival at the surface is confirmed from the surface gauge plots in Fig. 11. Around 20:08, the pump speed and downhole flow rate increase, while the surface tank volume decreases indicating the start of the water circulation down the tubing. Gas approaching the surface results in an increase in the surface tank volume as a result of gas expansion at the surface, as well as an increase in the downstream flow rate at 21:10, which aligns with the interpretation from the DAS data.
Fig. 9. DAS waterfall plot for the frequency range 0-5000 Hz for Trial-2 (color corresponds to the intensity of the FBE).
Fig. 10. DAS waterfall plot for the frequency range 10-50 Hz for Trial-2 (color corresponds to the intensity of the FBE).
Figure 12 shows the DTS plot in which both the downward gas flow in the tubing and the upward movement in the annulus are observed. The signature is more clearly visible compared to Trial-1 likely due to the larger gas kick volume and injection down the tubing rather than the injection line. The temperature gradient plots in Fig. 13, with respect to depth (Fig. 13(a)) and time (Fig. 13(b)) show the beginning of water circulation that follows the gas injection at 20:08 and arrival at the bottom of the tubing around 20:20. The approximate first arrival of gas at the surface is observed around 21:12 from Fig. 13(a). The timing aligns with the DAS and surface gauge observations in Figs. 9–11. Downward gas flow in the tubing, as well as the upward migration in the annulus is clearly observed in Fig. 13. The downward gas velocity is approximately 6 to 7 ft/s, while the annular gas rise velocity varies from about 1.3 ft/s at the bottom of the well to about 1.7 ft/s close to the surface. Both the downward and the upward gas velocities, as well as the surface arrival times, are consistent with the DAS observations. Using the temperature gradients with respect to both the time and depth gives more reliability in detecting the gas signature.
Figure 14 shows the pressure readings at three downhole pressure gauges subtracted by the backpressure applied at the surface (choke pressure) for Trial-2. For the gauges at depths of 3502’, 2023’, and 487’ the gas arrival times are respectively 73, 93, and 108 minutes, based on the observation of pressure drop at those instants. This gives an average gas rise velocity between the gauges at 3502’ and 2023’ as 1.23 ft/s, and between the gauges at 2023’ and 487’ as 1.70 ft/s. The estimation of gas velocities is in good agreement between the DAS, DTS, downhole gauges, and multiphase correlations, as summarized in Table 4.
3.3 Trial-3 (Jan 10, 2020)
The DAS profile for frequency range 0 to 5000 Hz is shown in Fig. 15. The water circulation (100 GPM) that follows the gas injection (5 bbl.) down the tubing, starts around 10:47 which appears as the high acoustic energy. The downward flow of gas in the tubing is clearly observed, similar to Trial-2. The gas reaches the bottom of the tubing around 11:02, however, the upward gas migration in the annulus is not very clear in this frequency range. The DAS profile corresponding to a narrower frequency range of 10 to 50 Hz is shown in Fig. 16. Both the downward and the upward gas movement is more clearly observed in this lower frequency range. The gas velocity calculated from the slopes of the signature is roughly 6.3 ft/s in the tubing and ranges from 1.2 to 1.4 ft/s in the annulus. The gas rise velocity closer to the surface in this trial is lower than Trial-2 due to the higher backpressure applied on the casing (300 psi). Increasing the casing backpressure to control a gas influx is a common field practice [14] and the results of Trials 1 and 2 demonstrate the effect of backpressure on gas rise velocity. The first gas arrival at the surface is roughly around 11:40. DAS observations are also confirmed from the surface gauge measurements shown in Fig. 17, which indicate an increase in the pump speed and flow rate, and a decrease in the surface tank volume at the start of the water circulation around 10:47. The arrival of gas at the surface results in an increase in the surface tank volume and a big jump in downstream flow rate at 11:40, which is aligned with the DAS data. Shortly after 11:41, the downstream flow rate signal was lost due to a technical issue.
Fig. 15. DAS waterfall plot for the frequency range 0-5000 Hz for Trial-3 (color corresponds to the intensity of the FBE).
Fig. 16. DAS waterfall plot for the frequency range 10-50 Hz for Trial-3 (color corresponds to the intensity of the FBE).
The DTS profile in Fig. 18 shows the gas migration signatures both down the tubing and upward in the annulus. The signature is seen more clearly in the temperature gradient plots in Fig. 19, with respect to depth (Fig. 19(a)) and time (Fig. 19(b)). The water circulation that follows the gas injection is observed to start at 10:47, and the gas reaches the bottom of the tubing around 11:01. The downward gas velocity, estimated from the slope, is about 6.5 ft/s and the gas velocity in the annulus varies from 1.26 ft/s close to the bottom of the well, to about 1.37 ft/s at shallower depths. The gas flow becomes increasingly diffused close to the surface, which is observed clearly in the temperature gradient plot in Fig. 19(a). Both the downward and the upward gas velocity estimates and arrival times are consistent between the DTS and DAS data and demonstrate the effect of increasing backpressure on the gas rise.
Figure 20 shows the pressure readings at three downhole pressure gauges subtracted by the backpressure applied at the surface (choke pressure) for Trial-3. For the gauges at depths of 3502’, 2023’, and 487’ the gas arrival times are respectively 50, 68.5, and 87 minutes. The average gas rise velocity between the gauges at 3502’ and 2023’ is 1.33 ft/s while the velocity between the gauges at 2023’ and 487’ is 1.39 ft/s.
The gas velocities estimated independently from the DAS, DTS, downhole gauges, and the three flow correlations for all three trials are summarized in Table 4. In each experimental trial, the velocity estimates are in good agreement, giving us confidence in the reliability of the assessment. The results also demonstrate the effect of gas kick volume, fluid circulation rate, backpressure, and injection method on the gas velocity measurement at well-scale conditions. The gas rise velocity depends strongly on the liquid circulation rate. Higher circulation rates resulted in higher gas rise velocities, while higher casing backpressure resulted in a slight lowering of gas rise velocity. The gas signature was more clearly observed in the fiber optic sensors in the case of larger kick volume. Acceleration of gas at shallower depths was observed in all cases as a result of diminishing hydrostatic pressure and gas expansion. Future experimentation will consist of using drilling muds as the circulating fluid, where the gas-rise velocity is expected to be affected by the drilling fluid’s rheology.
4. Conclusion
Multiphase flow experiments conducted in this study not only substantiate the viability of distributed fiber optic sensing as a reliable gas influx detection method, but also present novel insight into the gas-rise velocity and multiphase flow behavior in a 5163 ft deep wellbore. Gas rise velocities and timings observed, measured, and calculated independently using DAS, DTS, downhole gauges, surface measurements, and three multi-phase flow correlations show very good agreement and consistency. Implementation of a secure cloud-based visualization interface improved computational efficiency by enabling low-latency real-time streaming and visualization of voluminous fiber optic sensor data.
Distributed fiber optic sensing may have an immediate potential application when installed on the drilling riser to detect and monitor the gas kick phenomenon. In the future, when the technologies allow, it may be deployed in the drillstring to detect and monitor kicks while drilling the wells. By providing real-time distributed downhole data along the entire length of the fiber, this emerging technology has the potential to significantly improve our ability to detect gas influx as compared to conventional kick detection which relies on surface measurements and suffers from monitoring lag.
Funding
National Academy of Sciences (200008861).
Acknowledgments
Portions of this work were presented at the OSA Optical Sensors and Sensing Congress, 22-26 June 2020. The authors would also like to thank Mauricio Almeida, Charles Taylor, Andreau Trepagnier, Adam Wilson, Dmitry Kortukov, Devin Paulk, and Douglas Hoy for their inputs and contributions.
Original draft preparation, J.S.; writing-review, editing, and visualization, J.S., O.S., O.O.; analysis and methodology, J.S., O.S., G.F., O.O.; funding acquisition: W.W.
Disclosures
The authors declare no conflicts of interest.
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