7 replies to this topic

[alokjaiswal]

How to calculate MDEA Reboiler (for Stripper) heat duty.

Shell side:

Process Gas Flow       : 154475 Nm3/hr (Dry)

Components                H2, N2, CO, CO2, Ar, CH4 = (60.32, 21.08, 0.13, 17.73, 0.25, 0.49) mol% respectively.

Steam                          : 56108 Nm3/hr

Temp., IN                     : 163 deg C

Temp, OUT                  : 130 deg C

Press.                          : 27.6 Kg/cm2g

 

Tube Side:

Component                  : MDEA and CO2 loading in MDEA solution is 18%

Flow                             : 346 ton/hr

Temp. at stripper bottom                    : 115 deg C

Stripper pressure         : 0.49 Kg/cm2g 

 

Please guide me to calculate reboiler duty on MDEA side.

The stripper is provided to strip CO2 from MDEA solution. MDEA solution used for absorption of CO2 is having 40% MDEA concentration.

 

Thanks and regards

Alok

[Art Montemayor]

Alokjaiswal:

 

Your information and submitted data does not make conventional sense as described when applied to an Acid Gas MDEA removal process.  Please note the comments below and submit your explanation and/or revised data and information.  Furnish a detailed sketch of what you are trying to describe.  That is the engineering way to convey detailed information.

 

You don’t state what type of reboiler you are describing.  Is this a thermosyphon type with hot process gas flow in the shell side?  This is very unconventional, although probably possible.  However, the 27.6 Kg/cm²g of pressure you have on the shell side calls for a very special design and a rugged shell side design to withstand the relatively high pressure.

 

You state you have steam in the shell side.  However, at the pressure and temperature conditions you cite for the shell side, the steam does not seem to exist as vapor but as liquid condensate.  Am I correct or have I misinterpreted your data?

 

You state “loading in MDEA solution is 18%”, but what does that mean?  The CO₂ loadings in an amine solution are given as mole of CO₂ per mole of amine and not in percentage figures.  Please explain what you mean.

 

You state the tube side has a flow rate of 346 ton/hr.  Why do you use such unconventional units for flow rate?  The common units for liquid flow used industrially are liters/min, gallons per minute, or mass flow (kg, lb) per hr.

 

You request we guide you “to calculate reboiler duty on MDEA side”.  However, a reboiler’s duty is the same on either the shell or tube side.  Have you done a heat balance around the reboiler?

 

Is this an existing reboiler?  You cannot possibly be designing the reboiler since you already have stated the operating conditions for it.  You state the conditions of the process gas in and out of the reboiler, so the heat load is obviously the heat given out by the process gas flow rate.  It is that simple.  However, that may not be your case.  Please explain in detail what the situation is: is it a design problem or an existing operation?  Is this an academic problem or a real life situation?

 

If you want to read further information on the design of amine reboilers, refer to a thread in our Forums titled MDEA Reboiler Duty Calculation that can be found at:
http://www.cheresour...ty-calculation/

 

Your stated description of heating the reboiler with process gas is not a normal one.  Amine units are frequently heated in a kettle type reboiler that is heated with waste, low pressure steam.  This usually makes for a simple and less expensive operation than the one you describe.

 

For a description of reboiler operation with an MDEA solution, read the attached document.

 Comparison of various parameters of MEA.docx   37.03KB   55 downloads

[alokjaiswal]

Dear Art,

 

1.  The process as described is normally typical of Ammonia plant wherein Process Gas after Low Temperature Shift converter at 210 deg C is cooled to around 170 deg C and enters into CO2 removal system. LT Shift converter outlet gas has CO2 which is to be removed before sending gas to Ammonia Synthesis converter. Hence, to remove to CO2, Process gas is sent to CO2 removal system which is typical BASF two stage aMDEA process. The Process description with a PFD is attached.

 

2. The reboiler described here is thermosiphon type. The pressure stated is correct too and process gas from LT Shift converter is in shell side.

 

3.  As rightly pointed out, there will be condensate at this tempretaure. In ammonia plant, excess steam is added at inlet of Primary Reformer to make-up the amount of steam requirement in Low Temperature Shift converter. Part of this steam gets converted to condensate at this temperature.

 

4. There is slight correction in CO2 loading in MDEA solution. The actual value is around 32 Nm3 of CO2 per ton of MDEA. This is data from lab analysis which may vary slightly.

 

5.  MDEA flow rate is correct, 346 ton per hour or 346000 kg/hr.

 

6.  I have calculated the reboiler duty on Process gas side which is matching. The file is attached. May review the same. However, I intend to match the same duty on MDEA side. 

 

7.  Yes. This is an existing reboiler. My aim is to first check the base case design. Then I will try to find out how much minimum heat is required to reboiler. This is real life operation.

 

Hope, I have made myself clear. Waiting for reply.

 

Alok.

Attached Files

•  Reboiler duty.xls   67KB   73 downloads
•  CO2 removal System.jpg   53.5KB   6 downloads
•  Process description.docx   11.71KB   61 downloads

[Art Montemayor]

Alok:

 

Thank you for the quick and more detailed response.

 

I have reviewed your calculations and attach a copy of your workbook with my comments and questions.  Please respond with your answers to my queries and comments.

 

Why do you have a macro included in your workbook?  Is it important for the calculations shown?  Please tell me so I can decide to leave it or delete it.  Unrequired macros are potential virus transmitters and I want to know the need for it and why.

 

You fail to tell us that there are TWO reboilers involved with this MDEA stripper.  Is that correct?  Additionally your PFD fails to show WHERE the condensed water solution from the Stripper overheads condenser-cooler is going.  This is an important stream because it represents a portion of the MDEA being circulated and can't be removed from the main circulating solution without an equal replacement - which is often very expensive due to the need to have essentially distilled water + MDEA added.  If this stream is being added to the top of the CO₂ stripper, then your reboiler calculations are in more error than I have noted because this stream would be an additional heat duty load to the reboiler.  Traditionally, almost all engineering contractors have designed this condensed stream to be added to the top of the stripper and calling it a "Reflux" (which it certainly is not).  I have always been a proponent of not adding this so-called "reflux" and instead returning the recovered condensate back into the main circulation of the rich solution.  In operating CO₂ strippers in this fashion I have never seen any difference in stripper of reboiler operation.  Tell us where this stream is sent to.

 

The BASF process shown cleverly injects water condensate or steam into the syn gas going to the CO₂ absorber in order to cool it down a bit and also to produce steam within it.  This is then sent to the CO₂ Stripper reboiler where the contained steam vapor condenses inside the reboiler chest and subsequently removed prior to being introduced into the absorber.  While clever, this design also introduces tradeoffs.  The reboiler in use has to be a thermosyphon - which is more expensive than a kettle due to the higher pressue shell side and the tubesheets.  It also has little or no turndown or turnup ratio - which means that you have to operate it only at the design capacity.  The process controls - especially at startup and shutdown - are more complex and require special attention because of the integral heat balance and use of process energy to pump solution.  That is why a lot of producers prefer to use simple low-pressure steam in a kettle reboiler.  Everyone is left to their own preferences and needs.

 

 MDEA CO2 Reboiler duty Calculation.xlsm   281.69KB   107 downloads

[alokjaiswal]

Dear Art,

 

Thanks for such a nice reply. There is always great learning in your threads. I could not reply in the excel sheet since it is password protected.

 

1. Regarding excel sheet in Macros, I have prepared enthalpy calculation of some gases in Macros in form of Enthalpy funtions. I keep on using it whenever I have to calculate the enthalpies of gases based on temperature.

 

2. Regarding queries in excel sheet, Reboiler duty as per PFD is 15.7 Gcal/hr which is total duty of two reboilers as shown in PFD.

 

3. The unit of Enthalpy is Kcal/kgmole.

 

4. This tag no. is of reboilers which I should not have written here. 

 

5. Heat transfer = (Gas Enthalpy at Outlet - Gas Enthalpy at Inlet) x No. of Kgmoles/hr

    As per above equation, I have calculated the sensible heat transfer. Also, in your calculation, will the kgmoles/hr flow of respective components of Process gas not take part in calculation?  Moreover, the reboiler duty is still not matching with PFD figure.

 

6. Regarding the "Reflux" quantity (Overhead water+small MDEA solution), as per PFD, there is no reflux going into stripper. The total quantity of 4079 kg/hr is going into LP Flash vessel.

 

7. I accept my mistake. There are two reboilers for Stripper and Process Gas goes to both the reboilers.

 

Hope, I have made sense.

 

Thanks and regard,

Alok

 

[Art Montemayor]

Alok:

 

Thanks for your reply and explanations.  I perceive that you may be in charge of the syn gas and Hydrogen production unit of an ammonia + urea complex and that your acid gas removal system has been designed (and possibly erected) by BASF using their novel αMDEA process.  Please confirm if that is the case.  I feel more comfortable knowing exactly what the circumstances are in a problem.

 

If, indeed, BASF has furnished the CO₂ removal process design (& erection?) independently or through the main engineering contractor, then there has to be a complete P&ID as well as a PFD with complete heat and mass balance of the unit.  These documents should be part of the BASF license to operate the facility efficiently and in the prescribed manner.  As the operator of the unit, you must have total access to these documents in order to determine if you are operating the unit as prescribed and, if so, what are the results with respect to the specifications for the process.  The heat and mass balance is normally given in a tabular fashion, citing all the process (and utility) streams.  Therefore, the Heat and Mass Balance should state the enthalpy of the process gas entering and leaving the MDEA reboiler.  It should be that simple.  If you have not been supplied with the complete unit documentation, then you have a problem because you can’t comply with the conditions BASF has specified for your process.

 

BASF has developed a clever and novel manner of applying the MDEA process for CO₂ removal.  Instead of relying on pure waste steam for reboiler use, they simply take the Shift Converter outlet stream and use that heat content to reboil (while also injecting steam and condensate prior to the reboiler because the original heat content is not enough).  However, I note in the Process Description that the Stripper overheads is at only 91 ^oC.  I am used to furnishing sufficient heat in the reboiler tube bundle to make the overheads 104 ^oC - well above the boiling point of water.  The description states that the stream is “saturated” with water vapor.  However, it is wise to always furnish an excess of steam vapor in the overheads to ensure that the amine is thoroughly depleted of the design CO₂ loading, making the lean solution as strong as possible in MDEA and making sure that as much CO₂ is removed in the absorber as possible with the given MDEA flow rate and temperature conditions.

Besides, doesn't the 91 ^oC temperature for the saturated CO₂ mean that the Stripper top is at 0.75 kg/cm²A - a partial vacuum?

 

All steam reformers in syn gas plants have the ability to generate low pressure steam for process use.  However, your gas analysis indicates that atmospheric air may be introduced in the upstream syn gas preparation - possibly in an oxidation process (like the old Texaco process?) to produce the hydrogen and nitrogen.  In this case, BASF may have opted to use the hot process gas directly in the MDEA reboilers.  But this integrated process heat use introduces trade offs that I have mentioned before.  The reboilers have to be thermosyphon design (with little or no turn down), the amount of reboil heat is limited to the process gas, the size and shell thickness of the reboilers has to be increased because the heat transfer is almost all latent heat (as would be expected) - so the sensible heat contributed is negligible.  The process gas piping remains relatively large and the cost for so complex a run is more while the complexity and balance of the system - especially at startup is more taxing.  I particularly do not like the low 91 ^oC at the top of the CO₂ strippper and wonder how efficient operation can be done to produce a lean MDEA with low CO₂ loadings (expressed in mole CO₂/Mole MDEA).

 

I don’t know with what intention the reboiler duty has been identified as 15.7 Gcal/hr.  Is this value from the Heat and Mass Balance?  Or is it from some other document?  As I show in the workbook furnished, the sensible heat contribution is negligible - as would be expected (are you sure the stream enthalpy is correct?).  It is the latent heat of the steam content in the Process Gas that is doing most or all of the heat transfer.  Because the reboiler has to handle all the rest of the process gas, it has to be a bulky and rugged design that is expensive to build and install.  The process syn gas, in my opinion is merely acting as an inert vehicle for the steam injected into it further upstream.  As in any other process, it is very expensive to extract the heat from gases because of the very poor heat transfer coefficients involved.  The required heat exchanger turns out to be relatively much larger than a comparable steam-heated device.

 

I am pleased to see that BASF has applied what I already knew and used 55 years ago: you don’t have to employ a so-called “reflux” to an amine stripper to produce adequate lean amine and efficient CO₂ removal.

 

My workbook is not pass word-protected; you can easily un-protect it with a click.  Thank you for the macro explanation. 

[alokjaiswal]

Dear Art,

Thanks for the reply and apologies for late reply from my side.

 

1. I am working in Syngas and hydrogen production wherein CO2 (Acid Gas) is removed by BASF designed CO2 Removal System. They have supplied Heat and Material balance (H&MB) . From H&MB, reboiler heat duty is stated as 15.7 Gcal/hr.

 

2. In Hydrogen and syngas plant, excess steam is added to Primary Reformer to make-up for the Shift Reaction requirement and to provide latent heat duty to Reboiler of Stripper in CO2 Removal System.

 

3. In the PFD, the reboiler duty of 15.7 Gcal/hr is indicated which I want to verify. Then I wish to calculate the minimum heat duty required for Stripper reboiler duty so that I can reduce the quantity of steam added in Primary Reformer. Also, I want to know what should be the stripper top and bottom temperature corresponding to pressure of 0.45 kg/cm2g.

 

4. Therefore my question is how to calculate the reboiler heat duty so that total quantity of CO2 may be stripped from MDEA.

 

Thanks and regards

Alok

[alokjaiswal]

Dear Art,

Waiting for your reply.

Thanks and regards
Alok