Chapter 4 is taken directly from the TPG4560 project report by Steinsheim [1]. This chapter is included to provide an important foundation for the extended literature study conducted in Part I and for the flow loop project in Part II.
4.1 Clamp-on Acoustic Transit Time Flow Meter
The clamp-on acoustic transit time (CATT) flow meter is used for measuring flow rates.
The clamp-on feature makes it non-intrusive on the flow, which allows for easy mounting on the rig, no disturbance of the flow, and no stop in operations due to mounting or main-tenance. It consists of three main parts, which are transducers, clamping arrangement, and a unit for processing the signals. Oscillators inside the transducer send acoustic waves through the pipe walls and fluid. The signals are detected by the oppositely mounted trans-ducer. This process is alternating between the two transducers, sending the acoustic waves both upstream and downstream. The transit times are measured and compared to each other. Together with the known geometry and distance between the two transducers, this can be used to calculate the average velocity of the fluid and hence the flow rate [15].
Experiments with a CATT flow meter was carried out at a hydropower plant in Sassello, Italy by Schwery et al. [15]. They found several parameters that affect the resolution, reliability, and accuracy of the measurement. Emitting acoustic waves with high frequency will improve temporal resolution. This is especially important for small diameter pipes.
If the travel length of the acoustic waves is short, the accuracy of the measurement will decrease. Wave signal damping can occur if the flow regime is bubbly, there are solids in the flow, or the pipe walls are too thick. In these cases, emitting a low-frequency wave can work better as it is less affected by damping. Other factors that influenced the results were temperature and the speed of sound in the pipe material. The roughness of the inside pipe surface was used to correct the flow profile and had to be known in order to get accurate
measurements. After the experiments, it was concluded that the CATT flow meter could be used for cooling systems and to detect leak flow in the hydropower plant system. The uncertainty was too high to be used for efficiency and comparative measurements.
4.2 Acoustic Leak Flow Analyzer
Acoustic measurements can be used for leak flow detection. The acoustic leak flow ana-lyzer (ALFA) is based on passive acoustic measurements. During logging a hydrophone measures amplitudes and frequencies caused by vibrations due to fluid movement. From analyzing different amplitudes and frequencies the location of the leaks can be identified, as well as the size of the leaking apertures. It can also give an indication of the type of fluid and qualitative flow rate. Channeling and flow behind pipes can be detected if the signals vary sufficiently from the signals within the pipe. Detecting leaking casings or packers is one of the most important functions of the ALFA, as a pressure build-up in the annulus can lead to severe well control issues. The frequency is dependent on the size of the aper-tures. The tighter the aperture, the higher the frequency. The wellbore stream will lead to low-frequency signals, which appear as noise and should be identified. This will make it easier to separate the continuous noise from the signals caused by irregularities. The amplitude depends on several factors, such as fluid type and flow rate. High amplitudes would indicate gas, but there is no clear measured boundary to distinguish between gas and liquids. The acoustic measurements are often combined with temperature measurements to strengthen the interpretation [16].
4.3 Distributed Acoustic Sensing
Distributed acoustic sensing (DAS) is based on a passive fiber optic sensor. The sensor can detect acoustic fields along the length of the fiber. The measurements are made by pulsing a laser signal down the fiber and record the intensity of the light that is backscattered. The backscattered light is different from the original signal due to vibrations inducing changes in the refractive index. The time it takes before the backscattered light is recorded can be used to find the point along the sensor where the recorded event occurred. Signal phase and frequency can also be computed by doing repeated pulsing of the laser signal. It is important to wait until a backscattered signal has returned before sending a new signal, in order for the system to distinguish between the different pulses. A large amount of data is recorded and needs to be processed and stored. The data is often displayed by a waterfall model, with time and space on the axes and a color scale representing the signal intensity.
DAS is often chosen due to the spatial resolution, responsiveness to high frequency and the signal-to-noise ratio (SNR) it offers [17].
There are several areas where the DAS technology can be utilized. Downhole monitoring during hydraulic fracturing stimulation, flow profiling, and multiphase flow metering are some examples to be described. Further examples are presented in [18], such as well in-tegrity monitoring, vertical seismic profiling, gas-lift optimization, and sand detection.
DAS could be used for downhole monitoring during hydraulic fracturing stimulation of producing wells. This allows for real-time monitoring of the different clusters and could enable immediate and individual adjustments for each cluster. During multistage plug-and-perf completion the real-time monitoring would make it possible to intervene before moving on to fracturing the next stage. Adjustments could include diverter spheres, change in injection rate, or increasing the time spent on hydraulic fracturing for the specific clus-ter. The result would have to be an increase in production that could justify the cost of downhole installation and monitoring. A challenge with real-time monitoring during perforation is not damaging the DAS fiber when setting of the perforation gun. Correct orientation of the perforations is a prerequisite for this to be successful [18]. Looking at DAS in combination with distributed temperature sensing can increase the evaluation of the hydraulic fracturing stimulation when using cold injection fluids. The time it takes for the temperature to return to the geothermal gradient can be correlated to the amount of cold treatment fluid injected into the formation [17].
Flow profiling is possible with DAS. Different fluids are associated with different fre-quency ranges, even though there are no clear cut-off values. Gas is typically presented by high frequency, while water and oil are presented by low frequency, with oil lower than water. When several phases flow together it becomes more complex. One method to overcome the challenges is by having a collection of noises associated with different flow regimes. By comparing the recorded noise to this collection an estimate of the flow regime of the different perforations can be made. Multiphase flow metering could be possible with DAS. The speed of sound varies with different phases, as the sound travels slower through mediums of low density. The speed of sound of the wellbore fluid can be found by tracking the noise along the fiber. By comparing the computed speed of sound in the direction with and against the well stream the Doppler shift and velocity of the fluid can be determined [17].
The DAS system provides many advantages. It can often be used for the whole lifetime of the well and it can be shared with other technologies that utilize optic fibers. The mea-surements can be done continuously or in time laps and can cover the full length of the well. The spatial resolution can be as small as 1 meter and the sample rates as high as 20 kHz. The need for interventions is usually not present due to the robustness of the fiber.
The main parts of the set-up are the cable in the well and an interrogator at the surface.
The interrogator can be connected to cables in different wells, which offers the opportunity to monitor several wells with just one interrogator. The cables are permanently mounted in the wells and only the connection from the interrogator needs to be switched in order to shift between wells. There are different methods of mounting the cable. It can be ce-mented outside the casing, clamped on the outside of the tubing, or lowered into the well for temporary measurements, as done during logging. A cable installed as a part of a smart completion can be seen inFig. 4.1. The most common methods are based on permanent mounting, which means that the cable is ready in the well when data is needed. This saves time by eliminating tripping into and out of the well for every measurement period. The permanent mounting is also non-intrusive, so it does not affect the flow and there is no required stop in production to start the measurements. Eliminating the need for
interven-tions after installation does not only save time but also reduces the health, safety, security and environment (HSSE) risk and cost management [19].
Fig. 4.1– Example of smart completion including a fiber optic cable [19].
There are several reasons why DAS is not widely implemented. Making absolute measures of acoustic signals is generally not possible. To be able to compare results calibration is important. Factors that impact measurements are the characteristics of the fiber cable, the design of the DAS system, location, mounting, and settings on the sensor that are configurable. There is no universal standard for interpreting and comparing DAS data.
This combined with the relatively high installation cost is the reason why many operators have chosen to not implement DAS in their completion design [18].
4.4 Multipoint Acoustic Sensing
Multipoint acoustic sensing (MAS) is used for detection of third-party interference and leaks in pipelines. Several hydrophones are placed along the pipeline and recorded anoma-lies can, together with the GPS position of the hydrophone, give an indication of the lo-cation and cause of the issue. The theory behind the technology is that any interaction with the pipeline will affect the flow by creating acoustic waves or altering existing waves.
Third-party interference can be both by intentional theft or accidental, for instance during service and repair work, or by unrelated work carried out too close to the pipelines. The consequences of third-party interference, or leaks due to other reasons, can be of severe importance. Damage to personnel, civilians, equipment, and environment are possible ef-fects. Damage to business by demolished reputation or economic losses can also occur [20].
4.5 Acoustic Sand Monitoring
Acoustic sand monitoring is based on the impingement of solids on the pipe wall. The sensor is usually a clamp-on type and is not invasive on the flow. It does not take up a lot of space on the rig, and mounting does not require a stop in the operation. The sensor is usually mounted downstream and close to a bend, where the solids will hit the pipe wall in the bend. This can be seen in Fig. 4.2. The technology converts the impacts from the solids on the pipe wall to electrical signals. The signals are dependent on the energy associated with the impingement, which can be affected by both the velocity and size of the solids. Velocity can vary during production and the distribution of sand particle size can be large. To be able to get a quantitative reading these variables need to be averaged based on an evaluation of the current state of the wellbore stream [21].
Fig. 4.2– Acoustic sensor mounted close to a 90-degree bend [21].
The long term, qualitative measurement of sand production is more important than the real-time quantitative measurement. The goal of the operator is often to have the maximum inflow from the reservoir to the well without having a harming production of sand. There are several reasons why operators want to avoid sand production. In the near-wellbore area production of sand can lead to formation damage, which could result in decreased permeability and in the worst case plugging off the area around the well. One of the biggest problems with sand in the well stream is the eroding effect. This will lead to wear and tear of equipment and could cause equipment damage and tool failure, both downhole and top site. The presence of sand can contaminate the petroleum products and large amounts can cause plugging of the entire wellbore. Many wells are completed with sand screens to avoid the problem, but if sand production arises it will often escalate by itself, for instance by the decreasing stability of the formation and by erosion of the apertures in the screens. Monitoring of sand production is important so that corrective measures can
be taken to reduce or eliminate it. This is important for the production, lifetime, and cost of the well. It is also a safety measure because sudden tool failures or leaks caused by erosion can have catastrophic effects, and there is always risk involved when performing a workover or an intervention [21].