Category: Refining

Accurate measurement and prediction of crude oil and natural gas liquid (NGL) products vapor pressure are important for safe storage and transportation, custody transfer, minimizing vaporization losses and environmental protection. Vapor pressure specifications are typically stated in Reid Vapor Pressure (RVP) or/and True Vapor Pressure (TVP). In addition to the standard procedures for their measurements, there are rigorous and shortcut methods for their estimation and conversion.

There are figures and monographs for conversion of RVP to TVP for NGLs (Natural Gas Liquids) and crude oil at a specified temperature. This tip will present simple correlations for conversion from RVP to TVP and vice versa at a specified temperature. The correlations are easy to use for hand or spreadsheet calculations. Figures generated using these correlations will be presented, too.

Chapter 5 of reference [1] presents an excellent overview of TVP and RVP including their definitions, standard procedures for their measurements and diagrams for their conversion. The proceeding two paragraphs are extracted with minor revisions from reference [1].

TVP is the actual vapor pressure of a liquid product at a specified temperature and is measured with a sample cylinder. TVP specifications must always be referenced to a temperature, which frequently falls between 30-50°C (86-122°F). TVP is difficult to measure and depends on the ratio of the vapor to liquid, V/L, in the measurement device. If V/L = 0, the vapor pressure is essentially equivalent to the bubble point of the mixture which is the highest vapor pressure value for the liquid. As V/L increases, i.e., a small amount of vapor exists at the point of measurement, the measured vapor pressure will decrease. The relationship between the measured TVP and V/L depends on the composition of the mixture. For “near pure” component mixtures, V/L has little effect on the measured vapor pressure. For mixtures with a large composition range, such as crude oil or condensate, the effect of V/L on the measured vapor pressure can be significant (See ASTM D 6377 – 10 for detail). Reference [1] lists the Standards used for TVP measurements.

Because of the difficulty in accurately measuring TVP, an alternative method of measuring vapor pressure is frequently used. This is the RVP.  The RVP is a standard test set out in ISO 3007:1999, Petroleum products and crude petroleum – Determination of vapour pressure – Reid method. Another standard that applies to RVP is:  ASTM D323 – 08, Standard Test Method for Vapor Pressure of Petroleum Products (Reid Method). The RVP test is applicable for crude oils, condensates, and petroleum products such as gasoline (petrol) mixtures. A liquid sample is collected in the lower 20% chamber (see Fig 5.12 of reference [1]). The 80% chamber, which is filled with air (may also contain a small amount of water vapor) at atmospheric pressure.  Both chambers are cooled to 0°C (32°F). The 80% air chamber (at atmospheric pressure) is then connected to the 20% liquid chamber. The connecting valve is opened and the cylinder is heated in a water bath to 37.8°C (100°F). The pressure indicated on the gauge is the RVP.

Reference [1] provides Figure 5.14 for conversion RVP to TVP for motor gasoline (petrol) and natural gasoline (C₅₊ NGLs) at various temperatures. Figure 5.15 of reference [1] is a nomograph that shows the approximate relationship between RVP and TVP for crude oil. It is commonly used for converting RVP to TVP at custody transfer points where the vapor pressure specification for the oil is a TVP, but the actual vapor pressure measurement is an RVP.

Vazquez-Esparragoza et al. [2] present an algorithm to calculate RVP without performing the actual test. The algorithm, based on an air-and-water free model, uses the Gas Processors Association Soave-Redlich-Kwong [3] equation of state and assumes liquid and gas volumes are additive. This algorithm can be used to predict RVP of any hydrocarbon mixture of known composition. Since the calculations are iterative, it should be incorporated into a general purpose process simulator. Vazquez-Esparragoza et al. [2] reported good agreement between predicted and experimental values.

Riazi et al. [4] presented a new correlation for predicting the RVP of gasoline and naphtha based on a TVP correlation. The input parameters for this correlation are the mid-boiling point, specific gravity, critical temperature, and critical pressure, where the critical properties may be estimated from the boiling point and specific gravity using available methods. They evaluated their proposed correlation with data collected on 50 gasoline samples from crude oils from around the world with API gravity ranges from 41 to 87, average boiling point ranges from 43 to 221 °C (110 to 430 °F) and RVP of 0.7 to 115 kPa (0.1–17 psi). The average error from their proposed correlation is about 6 kPa (0.88 psi) [4].

Development of Model for Motor Gasoline and Natural Gasoline

To develop the desired correlations for conversion of motor gasoline and natural gasoline RVP to TVP and vice versa, this tip generated 127 data points from Figure 5.14 of reference [1]. These data covered the full ranges of temperature, RVP and TVP of Figure 5.14.

RVP to TVP: This tip used these data to determine the parameters to the Equations 1 through 3. The API 2517 originally reported the same forms of equations for crude oil.

TVP to RVP: Similarly this tip proposes the following equations for conversion from TVP to RVP.

where:

T          = Temperature, °C (°F)

RVP    = Reid Vapor Pressure, kPa (psi)

TVP    = True Vapor Pressure, kPaa (psia)

Note that the values of A₁, A₂, B₁, and B₂ are different in the above two sets of equations. The value of “C” is a function of the chosen units (SI versus FPS) and is consistent.

Table 1 presents the optimized values of A₁, A₂, B₁, B₂, and C for three sets of data in FPS (Foot-Pound-Second) and SI (System International). The data set labeled “All” included 127 data points covering all of the data of combined motor gasoline and natural gasoline. The data set “Motor Gasoline’ and “Natural Gasoline’ cover 76 and 51 data points for motor gasoline and natural gasoline, respectively. Table 1 also presents the Average Absolute Percent Deviation (AAPD), the Maximum Absolute Percent Deviation (MAPD), Average Absolute Deviation (AAD), and the number of data points (NP) for each data set. The error analysis of Table 1 indicates that the accuracy of the proposed correlations is good. Their accuracy is as good as the quality of tabular data generated from Figure 5.14.

Table 1. The optimized parameters for motor gasoline and natural gasoline

¹AAPD           = Average Absolute Percent Deviation
²MAPD           = Maximum Absolute Percent Deviation
³AAD              = Average Absolute Deviation
⁴NP                 = Number of data Points (NP)

Figures 1a (SI) and 1b (FPS) present the tabular data (generated from Figure 5.14 of reference [1]) in the form of “legends”. This figure also presents the predicted TVP by the proposed correlations (Equations 1 through 3 and the corresponding parameters listed in Table 1) as a function of temperature and RVP in the form of “continuous lines” and “broken lines” for motor gasoline and natural gasoline, respectively.

Development of Model for Crude Oil

To develop the desired correlations for conversion of crude oil RVP to TVP and vice versa, this tip generated 196 data points from Figure 5.15 of reference [1] using the correlations reported in API 2517. The API 2517 equations are the same as shown in Equations 1 through 3. These data covered the full ranges of temperature, RVP and TVP of Figure 5.15.

RVP to TVP: Table 2 presents the API 2517 FPS parameters of A₁, A₂, B₁, B₂, and C for Equations 1a, 2a, and 3a (T, °F, RVP, psi and TVP, psia). This tip determined the SI (T, °C, RVP, kPa and TVP, kPaa) corresponding parameters. Table 2 also presents the SI parameters.

Table 2. API 2517 parameters for crude oil TVP calculations
(For use with Equations 1a, 2a and 3a)

Figures 2a (SI) and 2b (FPS) present the predicted TVP by Equations 1a, 2a and 3a and the corresponding parameters listed in Table 2 as a function of temperature and RVP for crude oil.

TVP to RVP: To cover the full ranges of Figure 5.15 of reference [1], this tip proposes the following equations for conversion of TVP to RVP.

where:

T          = Temperature, °C (°F)

RVP    = Reid Vapor Pressure, kPa (psi)

TVP    = True Vapor Pressure, kPaa (psia)

Table 3 presents the optimized values of A₁, A₂, A₃, B₁, B₂, B₃, and C for RVP calculation in FPS and SI for the proposed Equations 1c through 3c. Table 3 also presents the Average Absolute Percent Deviation (AAPD), the Maximum Absolute Percent Deviation (MAPD), Average Absolute Deviation (AAD), and the Number of data Points (NP). The error analysis of Table 3 indicates that the accuracy of the proposed correlations is good and can be used for the estimation purposes.

Table 3. The optimized parameters for crude oil TVP conversion to RVP

(For use with Equations 1c, 2c & 3c)

1AAPD           = Average Absolute Percent Deviation

2MAPD           = Maximum Absolute Percent Deviation

3AAD              = Average Absolute Deviation

4NP                 = Number of data Points (NP)

 

Conclusions:

For converting RVP to TVP of motor gasoline and natural gasoline, this tip presented simple correlations similar to the ones reported in API 2517 for crude oil RVP to TVP. This tip determined the correlation parameters by regressing the data generated from available diagrams. These correlations were also extended for easy conversion from TVP to RVP. Tables 1, 2, and 3 present the correlation parameters in SI and FPS system of units. Tables 1 and 3 presents the accuracy of the proposed correlations against the data generated from diagrams. Tables 1 and 3 indicate that the accuracy of these correlations is as good as the quality of the data in the original diagram and can be used for easy conversion of RVP to TVP or vice versa. These correlations are easy to use for hand or spreadsheet calculations and should be used for estimation purposes. For accurate measurements, correction procedures outlined in ASTM D 6377–10 and other guidelines should be consulted.  Several organizations are currently working to improve the accuracy of TVP estimation from RVP and/or VPCR(x) (ASTM D6377) measurement techniques. In all cases, Federal and State Laws and Regulations should be followed for safety and environmental protection.

To learn more about similar cases and how to minimize operational problems, we suggest attending our G4 (Gas Conditioning and Processing), G5 (Advanced Applications in Gas Processing), and PF4 (Oil Production and Processing Facilities), courses.

PetroSkills offers consulting expertise on this subject and many others. For more information about these services, visit our website at http://petroskills.com/consulting, or email us at consulting@PetroSkills.com.

By: Dr. Mahmood Moshfeghian

References:

1. Campbell, J.M., Gas Conditioning and Processing, Volume 1: The Basic Principles, 9^th Edition, 2^nd Printing, Editors Hubbard, R. and Snow–McGregor, K., Campbell Petroleum Series, Norman, Oklahoma, 2014.
2. Vazquez-Esparragoza, J.J., et al, “How to Estimate Reid Vapor Pressure (RVP) of Blends”, Bryan Research and Engineering, Inc, Bryan, Texas, 2015.

3. Soave, Chem. Eng. Sci. 27, 1197-1203, 1972.
4. Riazi, M.R., Albahri, T.A. and Alqattan, A.H., “Prediction of Reid Vapor Pressure of Petroleum Fuels”, Petroleum Science and Technology, 23: 75–86, 2005.

Molecular sieves are used upstream of turboexpander units and LNG facilities to dehydrate natural gas to <0.1 ppmv water content.   In the natural gas industry, the molecular sieves employ heat to drive off the adsorbed water.  Figure 1 shows a typical flow schematic for a 2 tower system; Figure 2 shows a 3 tower system.

The cyclical heating/cooling of the adsorbent results in a capacity (kg water/100 kg adsorbent; lb_m water/100 lb_m adsorbent) decline due to a gradual loss of crystalline structure and/or pore closure.  A more troublesome cause of capacity decline is contamination of the molecular sieves due to liquid carryover from the upstream separation equipment.

Figure 3 shows a generic molecular sieve capacity decline curve.  A few important observations can be made from Figure 3:

1. The life of the adsorbent is a function of the number of cycles, not the elapsed calendar time.
2. The capacity decline is steep at the beginning but gradually flattens out. This assumes no step-change events such as NGL, glycol, and/or liquid amine carryover, bed support failure, etc.
3. Shown in this figure are “Good”, “Average” and “Poor” curves that are a function of site specific factors.
4. Locating one data point on Figure 3 from a performance test allows you to extrapolate the decline curve of the unit in question.

If your regeneration circuit has excess capacity over the “normal design conditions”, i.e., a design factor, you have standby time.   This excess capacity allows you to reduce your online adsorption time and “turn the beds around” faster by regenerating the beds in a shorter cycle time.   When you are involved in the design of an adsorption unit, it is recommended to add 10 – 20% excess regeneration capacity.

Because of the capacity decline curves flatten out, available standby time may be able to extend the life of a molecular sieve unit when your unit is operating on fixed cycle times.  Other operating options include: running each cycle to water breakthrough; and, reducing the cycle times in discreet steps throughout the life of the adsorbent.

 

To illustrate the benefits of standby time, consider the following case study.   A natural gas processing plant has commissioned a new 3 tower molecular sieve dehydration unit to process 11.3 x 10⁶ std m³/d (400 MMscfd) prior to flowing to a deep ethane recovery unit.  The unit is expected to run for 3 years before needing a recharge and the plant turnaround is based on this expectation.  The following assumptions are made:

• 3 tower system (2 towers on adsorption, 1 on regeneration)
• External Insulation
• Tower ID = 2.9 m (9.5ft)
• Each tower contains 24630 kg [54300 lbm] of Type 4A 4×8 mesh beads
• Regeneration circuit capable of handling an extra 15% of flow
• Unit is operated on fixed time cycles
• No step-change events such as liquid carryover, poor flow distribution, etc.

The design basis and molecular sieve design summary are shown in Tables 1 and 2.  The additional 15% of flow from the regeneration gas heater is well below the point at which bed lifting will occur.

The calculations presented here are valid for low pressure regeneration (less than 4100 kPaa (600 psia).  Using the concepts outlined in Chapter 18 of Gas Conditioning and Processing, Volume 2 [1]:  The Equipment Modules (9^th Edition) we find a design life factor, F_L, of 0.6 after 3 years (1 095 cycles) of operation at design conditions.  This point lies slightly above the “average” life curve as seen in Figure 4.

After 12 months of operation, a Performance Test Run (PTR) is conducted.  The results are shown in Table 3.  The feed flow rate and temperature are slightly lower compared to the design values.  A water breakthrough time of 20.9 hours is recorded.  The F_L is determined (using the concepts in Chapter 18) to be 0.68 after 365 cycles (one year of operation).  It is important and useful to understand the equation sequence of the concepts in Chapter 18, as shown by Equations 18.5 through 18.10 to arrive at the cited value for FL.   This data point is shown in Figure 5 and is seen to lie just below the generic “Average” curve.   Note that the slope of the curves are starting to flatten out.  Since the PTR F_L is lower than the Design F_L, the molecular sieves will experience water breakthrough if operated at design conditions in less than three years. Figure 6 shows the projected life factor, F_L, after 3 years of service at design conditions.  If the capacity decline continues to follow the same trend as seen from the PTR, water breakthrough will occur after 750 cycles or just a little over 2 years from startup if operation continues at design conditions.  This is shown in Figure 7.

Table 3. Results of Performance Test Run (PTR) after 12 months of operation

            Because the unit has a regeneration circuit that can handle an additional 15% of flow, the complete regeneration cycle (heating, cooling, de- and re- pressurization) can be reduced to 7.0 hours.  This allows the beds to turn around faster.

Using the reduced cycle time (the complete cycle time is now 21 hours vs the original 24 hours), we find an F_L = 0.53.  This is because less water is being adsorbed per cycle.  This occurs at around the 1500 cycle mark as shown in Figure 8.

If the plant elects to take advantage of the standby time and operate at reduced cycle time immediately following the PTR, the molecular sieves should last an additional 2.7 years, resulting in a total life of 3.7 years.   In this case, standby time will allow the unit to operate until the scheduled plant turnaround.

            We can draw the following conclusions from this case study:

1. The methods presented allow the user to estimate the decline of their adsorbent based on only one performance test run for molecular sieve dehydrators using low pressure regeneration. This permits early formulation of a credible action plan.
2. Site-specific factors will determine your unit’s decline curve. Consequently, conducting more than one performance test is highly recommended.  A poorly performing inlet separator, for example, could result in a unit exhibiting a more pronounced decline than indicated by the generic curves in Figure 3.
3. Standby time offers a large degree of operating flexibility because the decline curves tend to level off; always try to build in standby time in any new molecular sieve design.
4. Adsorption capacity is a function of the number of cycles, not calendar time.
5. Install a good filter coalescer or filter separator upstream of your adsorption unit to keep the contaminants out of the system.

The approach discussed in this Tip of the Month should help a facility engineer plan for the inevitable replacement of molecular sieves in their natural gas dehydration facility.

To learn more about similar cases and how to minimize operational problems, we suggest attending our G4 (Gas Conditioning and Processing) and PF4 (Oil Production and Processing Facilities) courses.

PetroSkills offers consulting expertise on this subject and many others. For more information about these services, visit our website at http://petroskills.com/consulting, or email us at consulting@PetroSkills.com.

By: Harvey M. Malino

Reference:

1. Campbell, J.M., Gas Conditioning and Processing, Volume 2: The Equipment Modules, 9^th Edition, 2^nd Printing, Editors Hubbard, R. and Snow–McGregor, K., Campbell Petroleum Series, Norman, Oklahoma, 2014.

One of the most common problems in Oil and Gas Processing facilities is underperforming vapor / liquid separators. The most common types of gas-liquid separators are:

• Slug catchers
  • Vessel / Finger-type
• “Conventional” separators
  • Vertical / Horizontal
• Scrubbers (i.e. Compressor Suction Scrubbers)
• Gas “polishers”
  • Coalescing Filters / Filter Separators

Underperforming separators generally result from either: 1. the wrong type of equipment was selected for the application, or 2. the correct type of equipment was selected, but the sizing methodology was inadequate. The type of separator required for an application depends largely on the gas-liquid ratio of the stream to be treated, and the flow variability of the process, as shown in Figure 1. As the flow variability increases with low to moderate gas-liquid ratios, the separator selection will move from a conventional separator to a slug catcher. For applications where there is a high gas-liquid ratio (i.e. very low liquid content), and the flow variability is moderately low, scrubbers and gas polishers would be the appropriate equipment selection depending upon the gas quality requirement for the treated stream.

Unfortunately, once the equipment has been selected and installed, it is very costly to replace if the separator was not specified properly. Common separator performance issues are: too much liquid in the separated gas, inadequate slug/surge capacity, and too much gas in the separated liquid.

This paper is focused on troubleshooting inadequate liquid removal from the gas for conventional separators (moderate to high liquid loads) and scrubbers (very low liquid loads).

A troubleshooting methodology is provided in Figure 2 [Reference No]. The problem, in this case, is too much liquid in the separated gas stream. In order to effectively troubleshoot separator performance, it is required to understand the metrics of good performance, and the functions and analysis of the various components of the separation equipment.

Typical performance metrics for separators are provided in Table 1. The specific performance requirements for a given separator are set by the sensitivity of the downstream process / equipment to the presence of liquids. For example, the product gas (sales gas) off of the cold separator in an NGL Extraction facility is sensitive to the presence of entrained liquids. The product gas can go off specification if there is too much carryover of liquids from the cold separator. On the other hand, the sensitivity of the downstream equipment from the facility inlet separator is much less, and the amount of liquids entrained in the gas is more tolerable.Table 1. Example separator performance metrics [1]

Separator Components

The main components of a separator, shown in Figure 3, are the feed pipe, inlet device, gas gravity separation section, mist extractor and the liquid gravity separation section. The gas/liquid separator components will be briefly discussed in regards to their effects on gas/liquid separation performance. These effects need to be understood and quantified in order to troubleshoot separator operations, and to identify modifications that can be made to improve performance. The liquid gravity separation section will not be discussed.

Inlet Feed Pipe

The inlet feed pipe sizing and geometry is important as it is desired to keep the multiphase flow pattern “stabilized” in the piping to minimize the production of small liquid droplets, and liquid entrainment into the gas phase. Figure 4 [2] shows the effect of feed pipe velocity on liquid entrainment. Figure 5 [2] demonstrates how quickly the liquid entrainment increases once the entrainment inception point is reached.

Some general guidelines for inlet piping to minimize liquid entrainment are:

• Provide 10 diameters of straight pipe upstream of the inlet nozzle without valves, expansions/contractions or elbows.
• If a valve is required, only use full port gate or ball valves.

Inlet Device

The main purpose of an inlet device is to improve separation performance. This is achieved by maximizing the amount of gas-liquid separation occurring in the feed pipe, minimizing droplet shearing, and optimizing the downstream velocity distributions of the separated phases into the separator. Schematics for inlet devices are shown in Figure 6. In large capacity, more critical separation applications, the vane-type and cyclonic inlet devices are commonly used. The simpler, and less expensive, impact (or diverter plates) are often used where the separation performance is less critical.

Table 2 provides a comparison of the performance of various inlet devices.

Table 2. Comparison of inlet devices [2]

The inlet momentum (ρ_mV²_m – density*velocity² of the mixture) of the feed stream is typically used to select and size inlet devices. Table 3 provides the suggested upper limits of inlet momentum values. For conditions where it is not practical to avoid higher feed pipe velocities, it must be recognized that failure to do so will result in higher entrainment loads, smaller droplet sizes, and more difficult separation conditions.

Table 3. Inlet device ρV² upper limits [3]

The quality of the flow distribution downstream of the inlet device is critical to mist extractor performance. Historically, tracer surveys have been used to provide an approximate indication of the continuous phase velocity within separators. In more recent years, the use of CFD (Computational Fluid Dynamics) has provided insight into the flow behavior of fluids, and has resulted in significant improvement in separator internals design. Separator performance is to a large degree dependent on the removal of droplets/ bubbles from the continuous phase. The efficiency of this removal is a function of the continuous phase velocity, thus the importance of understanding the factors that affect velocity profiles. Figure 7 provides an example of ideal versus actual gas velocity profiles within a separator.

Gas Gravity Separation Section

The gas gravity separation section of a separator has two main functions: 1) reduction of entrained liquid load not removed by the inlet device, 2) improvement / straightening of the gas velocity profile.

Most mist extractors have limitations on the amount of entrained liquid droplets that can be efficiently removed from the gas, thus the importance of the gas gravity section to remove the liquids to an acceptable level upstream of the mist extractor. This is particularly important for separators handling higher liquid loads. For scrubber applications with low liquid loadings, the K_s value will be primarily dependent on the mist extractor type, and the gas gravity separation section becomes less important.

For the higher liquid load applications, there are two approaches for sizing the gravity separation section to remove liquid droplets from the gas: 1) K_s method, 2) Droplet settling theory.

Historically the K_s method has been employed as it can provide reasonable results and is easy to use, but has shortcomings in terms of quantifying separator performance. References 3-5 provide the details on the droplet settling theory methods which can be used to more accurately quantify separator performance. The K_s approach is limited in that it only informs of the average droplet size, but cannot quantify the amount of liquid droplets exiting the gas gravity section.

The K_s method (Equation 1) is an empirical approach to estimate the maximum allowable gas velocity to achieve a desired droplet separation.

Where:

ρ_L             = liquid density kg/m³ (lbm/ft³)

ρ_g         = gas density kg/m³ (lbm/ft³)

Vgmax = maximum allowable gas velocity m/s (ft/sec)

K_S        = an empirical constant m/s (ft/sec)

Figure 8 provides the relationship of K_s values for various droplet sizes and separator operating pressures for the gas gravity section. Typically, a K_s value is selected that will achieve removal of all entrained droplets larger than a specified target droplet diameter in the original design of the separator. For conventional separators the target droplet diameter is typically 150 microns, and for scrubbers the target droplet size should not exceed ~500 microns. This correlation can also be used to determine the performance of the gas gravity section based upon current operating conditions. The separator K_s value can be estimated from the actual velocity and fluid conditions, and the droplet size removed in the gas gravity section can be estimated from Figure 8.

Mist Extraction Section

The mist extractor is the final gas cleaning device in a conventional separator. The selection, and design to a large degree, determine the amount of liquid carryover remaining in the gas phase. The most common types include wire mesh pads (“mesh pads”), vane-type (vane “packs”) and axial flow demisting cyclones. Figure 9 shows the location and function of a typical mist extractor in a vertical separator.

Mist extractor capacity is defined by the gas velocity at which re-entrainment of the liquid collected in the device becomes appreciable. This is typically characterized by a K_s value, as shown in Equation 1. Mesh pads are the most common type of mist extractors used in vertical separator applications. The primary separation mechanism is liquid impingement onto the wires, followed by coalescence into droplets large enough to disengage from the mesh pad. Figure 10 provides some mesh pad examples. Table 4 provides a summary of mesh pad characteristics and performance parameters.

Table 4. Mesh pads summary of characteristics and performance parameters [1,4]

Notes:

• Flow direction is vertical (upflow).
• Assume mesh pad Ks values decline with pressure as shown in Table 5. Table 5 was originally developed for mesh pads, but is used as an approximation for other mist extractor types. [6].
• If liquid loads reaching the mesh pad exceed the values given in Table 4, assume capacity (K_s) decreases by 10% per 42 L/min/m² (10% per gal/min/ft²). [3-5].
• These parameters are approximate.

Table 5. Mesh pad K_s deration factors as a function of pressure [2]

Vane packs, like mesh pads, capture droplets primarily by inertial impaction. The vane bend angles force the gas to change direction while the higher density liquid droplets tend to travel in a straight-line path, and impact the surface of the vane where they are collected and removed from the gas flow. Figure 11 shows a schematic of a single-pocket vane mist extractor. Table 6 provides vane pack performance characteristics.

Table 6. Typical vane-pack characteristics [1,4]

Notes:

1. Assume vane-pack K_s values decline with pressure as shown in Table 5.
2. If liquid loads reaching the vane pack exceed the values given in Table 4, assume capacity K_s decreases by 10% per 42 L/min/m² (10% per gal/min/ft²). [3-5].
3. These parameters are approximate only. The vane-pack manufacturer should be contacted for specific information.

In the case of demisting cyclones, the vendor should be consulted in regards to performance for the current operations of interest.

Troubleshooting

When troubleshooting a separator, one needs to quantify the acceptable performance of the separator in terms of the amount of liquids in the separated gas. The separator physical condition and design is then assessed to determine the liquid removal capability of the separation equipment installed. Each separator component should be analyzed in terms of the current operating conditions versus the original design specifications.

Table 7 provides a few common causes of inadequate liquid removal performance of a separator. The separator components that need to be reviewed are identified to determine the specific limitation. This table can serve as a road map for the calculations to work through when doing this type of analysis.

Table 7. Common conditions resulting in inadequate separated gas quality [1]

There are numerous options available to improve the performance of a separator depending upon what the cause for the poor performance is. Depending upon the size and construction of the separator, it may be possible to retro-fit the separator internals. Another option may be modification of the inlet feed piping geometry and number of fittings upstream of the vessel if this is found to be less than ideal. The inlet device may be damaged, or in the bottom of the vessel. Higher efficiency inlet devices may be an option for consideration. Frequently, different mist extraction equipment can be selected to improve performance. For example, if the mist extractor K_s value is greater than the original design, a different mist extraction device could improve performance. The separator internals modifications may or may not be possible without welding on the vessel (which adds additional complications and cost to the project).

The operating liquid levels should also be reviewed in terms of the distance of the normal operating liquid level in relation to the inlet feed device. If the liquid level is too high, the gas velocity from the inlet could be re-entraining liquids that were previously separated in the feed piping / inlet device. Unfortunately, in some cases the only way to improve performance is to cut rate (i.e. gas velocity) through the separator.

To learn more about troubleshooting separators and other production equipment, we suggest attending our PF-49 (Troubleshooting Oil and Gas Processing Facilities), or PF-42 (Separation Equipment Selection and Sizing) for more details on the selection and specification of separators.

By: Kindra Snow-McGregor

Reference:

1. PF-49, Troubleshooting Oil and Gas Processing Facilities, Bothamley, M., 2014, © PetroSkills, LLC. All Rights reserved.
2. Campbell, J.M., Gas Conditioning and Processing, Volume 2: The Equipment Modules, 9^th Edition, 2^nd Printing, Editors Hubbard, R. and Snow–McGregor, K., Campbell Petroleum Series, Norman, Oklahoma, 2014.
3. Bothamley, M. 2013. Gas-Liquid Separators – Quantifying Separation Performance Part 1. SPE Oil and Gas Facilities, Aug. (22 – 29).
4. Bothamley, M. 2013. Gas-Liquid Separators – Quantifying Separation Performance Part 2. SPE Oil and Gas Facilities, Oct. (35 – 47)
5. Bothamley, M. 2013. Gas-Liquid Separators – Quantifying Separation Performance Part 2. SPE Oil and Gas Facilities, Dec. (34 – 47)
6. Fabian, P., Cusack, R., Hennessey, P., Neuman, M. 1993. Demystifying the Selection of Mist Eliminators, Part 1: The Basics. Chem Eng 11 (11): 148 – 156.