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September 2008 Full contents
Tower pressure relief calculation A practical, less-complicated method for different emergency cases
S. Rahimi Mofrad, Petrofac Engineering & Construction, Sharjah, UAE Comments? Write:
[email protected] In the hydrocarbon processing industries and chemical plants, fractionation towers are some of the most complicated equipment from a relief load study point of view. This is due to the variety of tower design parameters and operating conditions. The process designer is responsible for recognizing the different causes of over-pressurization and evaluating the relief load considering all possible operating parameters such as different feed compositions, capacities and product specifications, as well as start/end of run or summer/winter operation. Failure to recognize these effects is likely to expose the column to danger of overpressure and the possibility of catastrophic failure. A conservative and most common method for determining tower relief requirements is to design the pressure protection system based on total gross overhead vapor flowrate. Recent tower relief studies show that this approach is not always conservative, since there is evidence that a relief valve sized on this basis can be even undersized.1 The best available technique for a relief study is dynamic simulation but it requires comprehensive data on equipment specifications and dimension, hydraulic information and control system details. Most of these data are not available or finalized when a relief system is designed. That is why relief load calculations using dynamic simulation is best suited for revamps or debottlenecking projects. Moreover, dynamic model validation with respect to heat and material balance results and dynamic model reaction time compared with actual plant operation is another concern when dealing with dynamic simulation. There are many emergency cases applicable to towers:
Electric power failures (feed pump, reflux pump, air-cooled condenser fan, pumparound pump, overhead gas product compressor failures or a combination of these) Cooling failures (water-cooled condenser, air-cooled condenser, pumparound pump or cooling water pump failures) Control/manual valve malfunctions (feed control valve, reflux control valve, vapor product control valve or cooling water valve closures; liquid product control valve, reboiler steam control valve or heater fuel gas control valve wide openings).
The relief rate for all of these upset conditions can be estimated by following a three-step procedure: reboiler pinch study, relief condition simulation and overhead energy balance. Reboiler pinch study. As column pressure increases from normal operating pressure to relieving pressure, column temperature rises. The reboiler temperature difference may reduce and consequently lead to lower heat input to the tower at relieving condition. The first step should be to determine the reboiler duty at the relieving condition (pinch study).
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• Data collection 1. Collect t in,N, t out,N , T in,N, T out,N, Uc, A, QN from a process flow diagram (PFD) or heat exchanger datasheet. Fig. 1 reflects the schematic representation of reboiler temperatures.
Fig. 1
Schematic representation of reboiler temperatures.
2. Recognize that the heating media inlet temperature will not change when the tower pressure is increasing from operating to relieving, therefore T in,R = T in,N. 3. Obtain tout,R from simulating the bottom liquid composition by using process simulation software. The temperature corresponds to the boiling temperature of the liquid bottom composition at relieving pressure. The bottom composition at the relieving condition is a function of many parameters such as the tower's internal configuration, cause of overpressure, feed and reflux composition, tower sump hold-up time, tray's liquid hold-up, etc. If the tower's internal configuration caused the light liquid coming off the tray to go directly to the reboiler, the temperature pinch will be less probable than when the light liquid is mixed with sump liquid. Different reboiler outlet temperatures will be achieved when the cause of overpressure is feed failure compared with reflux or cooling failure, because different compositions will go to the reboiler. Fig. 2 shows the effect of the tower's internal configuration on bottom liquid composition. The effect of other parameters should be evaluated by the designer. If the designer has no idea about the composition, using the operating composition for relieving condition is often conservative.
Fig. 2
Decision flowchart for selecting tower bottom composition at relieving condition.
• Initial checking Estimating the reboiler duty at relieving condition, QR, is fast and easy if one of the following
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conditions is established: 1. If the fired heater is used as a column reboiler, the temperature pinch rarely (if at all) occurs because firebox temperatures can easily reach 1,700°F–1,800°F. The tower relief study should be carried out with normal reboiler duty (QR = QN). 2. If tout,R ≥ Tin,R, then the heat transfer in the reboiler will gradually be suppressed while the tower pressure increases from operating to relieving pressure. The relief requirement will be zero, due to zero reboiler duty at this condition (QR = 0). 3. If Uc A (Tout,N – tout ,R) ≥ QN, then there is enough differential temperature between both sides of the heat exchanger at relieving condition so that the temperature pinch will never occur. The tower relief study should be carried out with normal reboiler duty (QR = QN). Otherwise, the following method can be used to specify the reboiler duty at relieving condition: • Final calculation 1. Guess QR /QN (first guess could be 0.6). 2. Calculate the estimated process side inlet temperature at relieving condition:
3. Calculate the estimated heating media outlet temperature at relieving condition:
5. Calculate the new ratio of QR /QN and compare it with the previous value. If they are not the same go to Step 2, otherwise go to Step 6. 6. If QR /QN is less than 1.0, the reboiler duty will be decreased to QR at relieving condition otherwise normal reboiler duty is utilized for the relief study of the tower. Relief condition simulation. To predict the effects of the tower's internal stream and tray hydraulics on heat and mass transfer and consequently on tower relief load, which is ignored in common methods, the following method is recommended: 1. Evaluate the latent heat of the tower bottom liquid at relieving condition. If the tower design pressure is near or higher than the liquid critical pressure, the physical properties, including latent heat cannot be calculated easily. Referring to references 2 and 3 is recommended for this purpose. 2. Calculate the reboiler vapor return flowrate at relieving condition by dividing the reboiler duty at relieving condition from the pinch study, QR, by latent heat. 3. Model the tower as an absorber using simulation software. Set the tower pressure at relieving
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pressure and use above vapor flow as inlet gas flow to the tower to get the absorber overhead flowrate, MO,R. The following items should be done before running the simulation: • Availability of feed and reflux streams have to be checked by the process designer. While the tower pressure migrates from operating to design due to emergency cases, feed and/or reflux pumps may not be able to keep the same liquid flow against higher destination pressure. This is seen especially with centrifugal pumps because the shutoff pressure of a centrifugal pump is generally 25% higher than operating differential pressure. If the differential pressure of a feed pump at normal flow is 4.0 barg, it can produce 5.0 barg differential pressures at zero flow. For example, if the tower operating pressure increases as a result of reflux control valve failure from 2.0 barg to design pressure of 3.5 barg, feed flow will also stop. Tower pressure will increase 1.5 barg while the pump's discharge pressure cannot increase more than 1.0 barg. • If a feed failure case is studied, then the reflux stream should be considered as absorbent. • If a reflux failure case is studied, then the feed is taken as absorbent. Sometimes the absorber will not converge because the liquid stream inside the tower is totally vaporized due to contact with hot, high-flow vapor coming from the reboiler. In this case, the summation of the reboiler vapor and absorbent flow should be taken as the overhead flowrate of the tower. Simulation convergence failure may also happen in case of the reboiler vapor being totally condensed by a cold feed/reflux stream. In this case, the tower overhead rate and relief load are null.
Fig. 3
Heat balance boundary definition.
Overhead energy balance. The tower overhead vapor flows to the condensing system in which it is fully or partially condensed. The required relief load is calculated by energy balance for the overhead system. Fig. 3 shows the schematic configuration of a tower overhead system and heat balance boundary limit. The following heat balance can be written for a specific boundary at normal operating conditions:
At relieving condition, the heat accumulation is not zero. Rewriting the equation for relieving condition will give:
The required relief load is calculated with respect to the condensation capacity of the overhead system at relieving condition, qR. Since determining the condensation capacity in an upset condition is not simple due to variations of operating parameters, most of the designers prefer to
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use normal condenser duty for the relief study. This assumption is valid as long as the following situations do not suppress the condenser duty: Electric power failure: Sometimes the designer considers the simultaneous failure of the condensing system and feed or reflux streams to find the maximum required relief rate. If such a scenario is envisaged, it should be noted that the remaining air-cooler cooling capacity after electric power failure, due to a natural convection effect, is usually 20% to 30% of the normal duty for induced draft air coolers and 10% to 15% for forced-draft air coolers. If a water-cooled condenser is used, cooling capacity seems unaffected by power failure; but, since half of the cooling water pumps are usually driven by electrical motors, power failure can cause a 50% reduction in the water-cooled condenser's duty. If all of the cooling water supply pumps are turbine driven, the condensers will run at full capacity when the power is out. If a combination of aircooled and water-cooled condensers are in service, the total condensation capacity after power cutoff is calculated based on the previously mentioned rules. Flooding: Condenser flooding happens when reflux or product streams fail, due to electric power or control valve failure causing loss of overhead condensation. If overhead accumulator surge time is less than 10 minutes, the overhead condensers will be flooded with liquid and their condensation capacity will be negligible at relieving condition. The surge capacity of an overhead accumulator is calculated based on its free volume above normal liquid levels. Vapor blanketing: If the gas product path is blocked as a result of power failure, (e.g., failure of a downstream gas compressor), non-condensable gases will accumulate in the overhead condenser and prevent condensable material from reaching it. In this condition, if the safety valve is located on top of the tower, the condenser will lose most of its condensation capacity. Placing the safety valve on the overhead accumulator will allow non-condensable material to be swept out of the system when a safety valve opens and the normal condensation capacity of the overhead system can be taken into account for the relief study. The required relief rate is obtained by dividing the accumulated heat from Eq. 6 by the enthalpy of overhead vapor, HO,R. As a matter of fact, the amount of overhead gas that should be released from the system to remove energy imbalance is calculated. Electric power failure. Determining the relief load in an electric power failure condition requires a careful plant or system analysis to evaluate what equipment is affected and how the equipment failure affects plant operation. Electric power failure should be analyzed in the following ways: • As a local power failure, where one piece of equipment is affected • As an intermediate power failure, where one distribution center, one motor control center, or one bus is affected. The equipment affected by an intermediate power failure will dispose of its content into the flare header simultaneously. • As a total power failure, where all electrically operated equipment are simultaneously affected. The affected equipment by total power failure will dispose of its content into the flare header simultaneously. This is usually the governing case of a flare system design, especially in oil refineries. For determining tower relief requirements, the designer should review different electric power failure scenarios or any reasonable combination of emergency cases (e.g., simultaneous failure of feed and an overhead gas product compressor) to find the maximum possible column relief rate. Flow cooling failure. All columns are equipped with different types of condensing facilities including water-cooled and air-cooled condensers, pumparounds or a combination of those to meet product specifications, supply reflux and optimize tower and reboiler dimensions. Failure of this equipment due to a cooling medium or power failure can cause tower overpressure. The above described method can be utilized for determining relief requirements in case of cooling failure. If the duration of cooling failure is greater than the overhead accumulator liquid holdup time, reflux is lost. Therefore, the simulation should be carried out without reflux. • Water-cooled condenser failure can take place because of a cooling-water control valve closure,
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inadvertent closure of a manual valve by an operator, cooling-water supply system failure or supply pipe rupture. • Air-cooled condenser failure can happen because of two main reasons. The first is fan failure, due to a mechanical or power failure that causes loss of most of the condensation capacity. In this case, qR will be 20% to 30% of qN for induced-draft air coolers and 10% to 15% of qN for forceddraft air coolers because of natural convection effects. The second is louver closure that may result from automatic control failure, mechanical linkage failure or destructive vibration on a manually positioned louver. Louver closure on air-cooled condensers is considered as a total loss of cooling capacity. • Pumparound circuit failure happens as a result of failure of any component in a circuit. It will lead to heat accumulation in the system and increase the tower overhead flowrate that can be easily predicated by simulating the tower at the relieving condition. Absorbent failure. The American Petroleum Institute API-521 Section 3.7 states,4 that generally no relief requirement results from absorbent failure. However, in an acid gas removal unit where large inlet vapor quantities may be removed in the absorber, absorbent loss could cause a pressure rise to relief pressure, since the downstream system may not be adequate to handle the increased flow. Each individual case must be studied for its process and instrumentation characteristics. Reboiler tube rupture. Reboiler tube rupture will cause huge amounts of hot heating-media (steam, hot water or hot oil) to be released into the boiling process liquid inside the reboiler. There are some guidelines and references in API-521 Section 3.18 for calculating rupture flowrate. Once the tube rupture flowrate is found, the designer can calculate the reboiler vapor rate by dividing the heating-media heat content by the latent heat of process liquid. The next stage is to simulate the tower in relief condition to see the effect of the tower's internal stream on the reboiler vapor and specify the overhead vapor flow, MO,R. Energy balance around the overhead system will give the tower relief load in the reboiler tube rupture condition. External fire. For tower relief requirement during an external fire see references 5 and 6. Control valve failure. Loss of instrument air drives all air-operated valves to their specified fail positions. This action may result in overpressure if the specified valve failure positions were not selected to prevent overpressure. Likewise, electric power failure can drive control systems and electrically operated valves to their specified failure positions. Failure of control valve mechanical parts may lead them to stay opposite of their safe positions. The relief rate due to emergency cases caused by control valve failure such as feed/reflux control valve closure, gas blocked outlet or reboiler steam and heater fuel gas control valve wide open can be calculated considering the guidelines here and reference 7. The last two cases will result in reboiler operation at design duty. Procedures outlined above in the relief condition simulation and overhead energy balance will determine the relief requirements. HP NOMENCLATURE A H DH LMTD M t T q Q Uc
Heat exchanger total area Mass enthalpy Accumulation of heat Log mean temperature difference, calculated by Eq. 4 Mass flowrate Reboiler process side temperature Reboiler heating media side temperature Condenser duty Reboiler duty Heat exchanger overall heat transfer coefficient at clean condition
SUBSCRIPTS in out O V L W
Inlet Outlet Overhead stream Vapor product stream Liquid product stream Water draw-off stream
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N Normal condition R Relieving condition
LITERATURE CITED 1 Bradford, M. and D. G. Durrett, "Avoiding common mistakes in sizing distillation safety valves," Chemical Engineering, July 9,
1984, pp. 78–84. 2 Won, K. W., A. R. Smith and G. A. Zeininger, "Thermodynamic methods for pressure relief system design parameters," Fluid
Phase Equilibria 241, 2006, pp. 41–50. 3 Mofrad, S. Rahima and S. Norouzi, "Designing for pressure releases during fires—Part 1," Hydrocarbon Processing, November
2007, pp. 65–67. 4 American Petroleum Institute, API RP 521, "Guide for pressure relieving and depressuring systems," 4th edition, March 1997. 5 Mofrad, S. Rahimi and S. Norouzi, "Designing for pressure releases during fires—Part 2," Hydrocarbon Processing, December 2007, pp. 117–121. 6 Ouderkirik, R., "Rigorously size relief valves for supercritical fluids," CEP, August 2002, pp. 34–43. 7 Mofrad, S. Rahimi, "Relief rate calculation for control valve failure," Hydrocarbon Processing, January 2008, pp. 105–109.
Saeid Rahimi Mofrad is a process engineer with Petrofac Engineering & Construction. He has worked on a variety of flare and relief system projects, ranging from simple flare and relief valve studies to detailed hydraulic engineering design. Mr. Rahimi has also developed and taught courses on pressure relief load calculation and flare network design. He received his BS degree from Shiraz University, Iran and his MS degree in chemical engineering from Sharif University of Technology.
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