Periodic calibration of vessel instruments is essential to ensure the continued performance and function of the process vessel. Incorrect instrument calibration often exacerbates poor process vessel design, resulting in unsatisfactory separator operation and low efficiency. In some cases, the position of the instrument can also cause erroneous measurements. This article describes how process conditions can cause incorrect or misunderstood level readings.
The industry has expended a lot of effort to improve the design and configuration of separator and scrubber vessels. However, the selection and configuration of related instruments has received little attention. Usually, the instrument is configured for the initial operating conditions, but after this period, the operating parameters change, or additional contaminants are introduced, the initial calibration is no longer suitable and needs to be changed. Although the overall assessment at the stage of level instrument selection should be comprehensive, the process of maintaining continuous assessment of the operating range and any changes into the appropriate recalibration and reconfiguration of related instruments as needed throughout the life cycle of the process vessel Therefore, experience has shown that, compared with the abnormal internal configuration of the container, the separator failure caused by incorrect instrument data is much more.
One of the key process control variables is liquid level. Common methods of measuring liquid level include sight glasses/level glass indicators and differential pressure (DP) sensors. The sight glass is a method of directly measuring the liquid level, and may have options such as a magnetic follower and/or a level transmitter connected to a modified liquid level glass. Level gauges that use floats as the main measurement sensor are also considered to be a direct means of measuring the liquid level in the process vessel. The DP sensor is an indirect method whose level reading is based on the hydrostatic pressure exerted by the fluid and requires accurate knowledge of the fluid density.
The configuration of the above equipment usually requires the use of two flange nozzle connections for each instrument, an upper nozzle and a lower nozzle. In order to achieve the required measurement, the positioning of the nozzle is essential. The design must ensure that the nozzle is always in contact with the appropriate fluid, such as the water and oil phases for the interface and the oil and steam for the bulk liquid level.
The fluid characteristics under actual operating conditions may be different from the fluid characteristics used for calibration, resulting in erroneous level readings. In addition, the location of the level gauge may also cause false or misunderstood level readings. This article provides some examples of lessons learned in solving instrument-related separator problems.
Most measurement techniques require the use of accurate and reliable characteristics of the fluid being measured to calibrate the instrument. The physical specifications and conditions of the liquid (emulsion, oil, and water) in the container are critical to the integrity and reliability of the applied measurement technology. Therefore, if the calibration of related instruments is to be completed correctly to maximize accuracy and minimize the deviation of liquid level readings, it is very important to accurately evaluate the specifications of the processed fluid. Therefore, in order to avoid any deviation in the liquid level reading, reliable data must be obtained by regularly sampling and analyzing the measured fluid, including direct sampling from the container.
Change with time. The nature of the process fluid is a mixture of oil, water and gas. The process fluid can have different specific gravities at different stages within the process vessel; that is, enter the vessel as a fluid mixture or emulsified fluid, but leave the vessel as a distinct phase. In addition, in many field applications, the process fluid comes from different reservoirs, each with different characteristics. This will result in a mixture of different densities being processed through the separator. Therefore, the continuous change of fluid characteristics will have an impact on the accuracy of the liquid level measurement in the container. Although the margin of error may not be enough to affect the safe operation of the ship, it will affect the separation efficiency and operability of the entire device. Depending on the separation conditions, a density change of 5-15% may be normal. The closer the instrument is to the inlet tube, the greater the deviation, which is due to the nature of the emulsion near the inlet of the container.
Similarly, as the water salinity changes, the level gauge will also be affected. In the case of oil production, water salinity will change due to various factors such as changes in formation water or breakthrough of injected seawater. In most oil fields, the salinity change may be less than 10-20%, but in some cases, the change may be as high as 50%, especially in condensate gas systems and sub-salt reservoir systems. These changes can have a significant impact on the reliability of level measurement; therefore, updating the fluid chemistry (oil, condensate, and water) is essential to maintain instrument calibration.
By using information obtained from process simulation models and fluid analysis and real-time sampling, level meter calibration data can also be enhanced. In theory, this is the best method and is now used as standard practice. However, in order to keep the instrument accurate over time, fluid analysis data should be updated regularly to avoid potential errors that may be caused by operating conditions, water content, increase in oil-to-air ratio, and changes in fluid characteristics.
Note: Regular and proper maintenance is the basis for obtaining reliable instrument data. The standards and frequency of maintenance depend to a large extent on the related preventive and daily factory activities. In some cases, if deemed necessary, deviations from planned activities should be rearranged.
Note: In addition to using the latest fluid characteristics to periodically calibrate the meter, only relevant algorithms or artificial intelligence tools can be used to correct the daily fluctuations of the process fluid to take account of operating fluctuations within 24 hours.
Note: Monitoring data and laboratory analysis of the production fluid will help to understand potential abnormalities in the level readings caused by the oil emulsion in the production fluid.
According to different inlet devices and internal components, experience has shown that gas entrainment and bubbling at the inlet of separators (mainly vertical gas condensate separators and scrubbers) will have a significant impact on liquid level readings, and may lead to poor control and which performed. The decrease in the density of the liquid phase due to the gas content results in a false low liquid level, which can lead to liquid entrainment in the gas phase and affect the downstream process compression unit.
Although gas entrainment and foaming have been experienced in the oil and gas/condensate oil system, the instrument is calibrated due to the fluctuation of the condensate oil density caused by the dispersed and dissolved gas in the condensate phase during the gas entrainment or gas blow-by process. The error will be higher than the oil system.
The level gauges in many vertical scrubbers and separators can be difficult to calibrate correctly because there are different amounts of water and condensate in the liquid phase, and in most cases, the two phases have a common liquid outlet or water outlet line Superfluous due to poor water separation. Therefore, there is continuous fluctuation in operating density. During operation, the bottom phase (mainly water) will be discharged, leaving a higher condensate layer on the top, so the fluid density is different, which will cause the liquid level measurement to change with the change of the liquid layer height ratio . These fluctuations can be critical in smaller containers, risk losing the optimal operating level, and in many cases, correctly operate the downcomer (the downcomer of the aerosol eliminator used to discharge the liquid) The required liquid seal.
The liquid level is determined by measuring the density difference between the two fluids in the equilibrium state in the separator. However, any internal pressure difference may cause a change in the measured liquid level, thereby giving a different liquid level indication due to the pressure drop. For example, a pressure change between 100 to 500 mbar (1.45 to 7.25 psi) between the container compartments due to the overflow of the baffle or coalescing pad will cause the loss of a uniform liquid level, resulting in the interface level in the separator The measurement is lost, resulting in a horizontal gradient; that is, the correct liquid level at the front end of the vessel below the set point and the rear end of the separator within the set point. In addition, if there is a certain distance between the liquid level and the nozzle of the upper liquid level gauge, the resulting gas column may further cause liquid level measurement errors in the presence of foam.
Regardless of the configuration of the process vessel, a common problem that can cause deviations in liquid level measurement is liquid condensation. When the instrument pipe and the container body are cooled, the temperature drop may cause the gas that produces liquid in the instrument pipe to condense, causing the liquid level reading to deviate from the actual conditions in the container. This phenomenon is not unique to the cold external environment. It occurs in a desert environment where the external temperature at night is lower than the process temperature.
Heat tracing for level gauges is a common way to prevent condensation; however, the temperature setting is critical because it may cause the problem it is trying to solve. By setting the temperature too high, the more volatile components may evaporate, causing the density of the liquid to increase. From a maintenance point of view, heat tracing may also be problematic because it is easily damaged. A cheaper option is the insulation (insulation) of the instrument tube, which can effectively keep the process temperature and the external ambient temperature at a certain level in many applications. It should be noted that from a maintenance point of view, the lagging of the instrument pipeline may also be a problem.
Note: A maintenance step that is often overlooked is flushing the instrument and the reins. Depending on the service, such corrective actions may be required weekly or even daily, depending on operating conditions.
There are several flow assurance factors that can negatively affect liquid level measuring instruments. all these are:
Note: In the design stage of the separator, when selecting the appropriate level instrument and when the level measurement is abnormal, the correct flow rate assurance problem should be considered.
Many factors affect the density of the liquid near the nozzle of the level transmitter. Local changes in pressure and temperature will affect the fluid balance, thereby affecting the level readings and the stability of the entire system.
Local changes in liquid density and emulsion changes were observed in the separator, where the discharge point of the downcomer/drain pipe of the demister is located near the nozzle of the liquid level transmitter. The liquid captured by the mist eliminator mixes with a large amount of fluid, causing local changes in density. Density fluctuations are more common in low-density fluids. This may result in continuous fluctuations in the oil or condensate level measurement, which in turn affects the ship’s operation and the control of downstream devices.
Note: The nozzle of the liquid level transmitter should not be near the discharge point of the downcomer because there is a risk of causing intermittent density changes, which will affect the liquid level measurement.
The example shown in Figure 2 is a common level gauge piping configuration, but it can cause problems. When there is a problem in the field, the review of the liquid level transmitter data concludes that the interface liquid level is lost due to poor separation. However, the fact is that as more water is separated, the outlet level control valve gradually opens, creating a Venturi effect near the nozzle under the level transmitter, which is less than 0.5 m (20 in.) from the water level. Water nozzle. This causes an internal pressure drop, which causes the interface level reading in the transmitter to be lower than the interface level reading in the container.
Similar observations have also been reported in the scrubber where the liquid outlet nozzle is located near the nozzle under the liquid level transmitter.
The general positioning of the nozzles will also affect the correct function, that is, the nozzles on the vertical separator housing are more difficult to block or clog than the nozzles located in the lower head of the separator. A similar concept applies to horizontal containers, where the lower the nozzle, the closer it is to any solids that settle, making it more likely to be clogged. These aspects should be considered during the design stage of the vessel.
Note: The nozzle of the liquid level transmitter should not be close to the inlet nozzle, liquid or gas outlet nozzle, because there is a risk of internal pressure drop, which will affect the liquid level measurement.
Different internal structures of the container affect the separation of fluids in different ways, as shown in Figure 3, including the potential development of liquid level gradients caused by baffle overflow, resulting in pressure drops. This phenomenon has been observed many times during troubleshooting and process diagnosis research.
The multi-layer baffle is usually installed in the container at the front of the separator, and it is easy to be submerged due to the flow distribution problem in the inlet part. The overflow then causes a pressure drop across the vessel, creating a level gradient. This results in a lower liquid level at the front of the container, as shown in Figure 3. However, when the liquid level is controlled by the liquid level meter at the rear of the container, deviations will occur in the measurement performed. The level gradient can also cause poor separation conditions in the process vessel because the level gradient loses at least 50% of the liquid volume. In addition, it is conceivable that the relevant high-speed area caused by the pressure drop will produce a circulation area that leads to a loss of separation volume.
A similar situation can occur in floating production plants, such as FPSO, where multiple porous pads are used in the process vessel to stabilize the fluid movement in the vessel.
In addition, the severe gas entrainment in the horizontal container, under certain conditions, due to the low gas diffusion, will produce a higher liquid level gradient at the front end. This will also adversely affect the level control at the rear end of the container, resulting in measurement divergence, resulting in poor container performance.
Note: The gradient level in different forms of process vessels is realistic, and this situation should be minimized as they will cause the separation efficiency to decrease. Improve the internal structure of the container and reduce unnecessary baffles and/or perforated plates, coupled with good operating practices and awareness, to avoid liquid level gradient problems in the container.
This article discusses several important factors that affect the liquid level measurement of the separator. Incorrect or misunderstood level readings can cause poor vessel operation. Some suggestions have been made to help avoid these problems. Although this is by no means an exhaustive list, it helps to understand some potential problems, thereby helping the operations team understand potential measurement and operational issues.
If possible, establish best practices based on lessons learned. However, there is no specific industry standard that can be applied in this field. In order to minimize the risks associated with measurement deviations and control abnormalities, the following points should be considered in future design and operation practices.
I would like to thank Christopher Kalli (adjunct professor at the University of Western Australia in Perth, Australia, Chevron/BP retiree); Lawrence Coughlan (Lol Co Ltd. Aberdeen consultant, Shell retiree) and Paul Georgie (Glasgow Geo Geo consultant, Glasgow, UK) for their support Papers are peer reviewed and criticized. I would also like to thank the members of the SPE Separation Technology Technical Subcommittee for facilitating the publication of this article. Special thanks to the members who reviewed the paper before the final issue.
Wally Georgie has more than 4 years of experience in the oil and gas industry, namely in oil and gas operations, processing, separation, fluid handling and system integrity, operational troubleshooting, elimination of bottlenecks, oil/water separation, process validation, and technical expertise Practice evaluation, corrosion control, system monitoring, water injection and enhanced oil recovery treatment, and all other fluid and gas handling issues, including sand and solid production, production chemistry, flow assurance, and integrity management in the treatment process system.
From 1979 to 1987, he initially worked in the service sector in the United States, the United Kingdom, different parts of Europe and the Middle East. Subsequently, he worked at Statoil (Equinor) in Norway from 1987 to 1999, focusing on daily operations, development of new oilfield projects related to oil-water separation issues, gas treatment desulfurization and dehydration systems, produced water management and handling solid production issues And production system. Since March 1999, he has been working as an independent consultant in similar oil and gas production around the world. In addition, Georgie has served as an expert witness in legal oil and gas cases in the United Kingdom and Australia. He served as SPE Distinguished Lecturer from 2016 to 2017.
He has a master’s degree. Master of Polymer Technology, Loughborough University, UK. Received a bachelor’s degree in safety engineering from the University of Aberdeen, Scotland, and a PhD in chemical technology from the University of Strathclyde, Glasgow, Scotland. You can contact him at wgeorgie@maxoilconsultancy.com.
Georgie hosted a webinar on June 9 “Separating design and operating factors and their impact on the performance of produced water systems in onshore and offshore installations”. Available on demand here (free for SPE members).
Journal of Petroleum Technology is the flagship magazine of the Society of Petroleum Engineers, providing authoritative briefings and topics about the advancement of exploration and production technology, oil and gas industry issues, and news about SPE and its members.
Post time: Jun-17-2021
