Temperature Inversion
Temperature Inversion
(OP)
Hi All...
Recently we are facing problem of Tempearature inversion between naphtha draw off & crude fractionator column top temperature.
In normal condition – Naphtha draw off temperature remains around 130 °C & Crude column top temperature remains around 111 °C ( Delta between this two temp. ~ 19 C )
But abnormally after the occurrence of this event as shown in graph, naphtha draw temperature is remaining around 118 C & column top temperature is remaining around 114 C ( Delta ~ 5-6 C) along with sudden increase in Naphtha section Pressure Drop (PDI ) also around 1000-1100 mmwater column ( as shown in the graph)
Pl. see attached graph image by clicking, which indicates trends as specified below:
1.Green colour – Crude column overhead temperature
2.Red colour – Naphtha section pressure drop
3.Pink colour – Naphtha draw temperature
In the trend analysis, you can see sudden dip in Naphtha draw temperature on 16th September.
Naphtha PA return temp. has fallen down by 5 C i.e. from 100 C to 95 C . There is no any significant impact on Naphtha distillation & End point.
I have gone through the thread124-178998: Column Temperature Inversion.
We have got total 3 trays in Naphtha section which is specifically designed HI-FI trays of MOC Monnel.I simulated the Model but it shows that if efficiency of Trays got reduced in naphtha section then in that case top as well as draw both temp. should fall down but here top temp. is higher and draw temp. has fallen down so, is it related to Tray damage or Pump around reflux distribution nozzle damage..Still not sure.There is reduction of Naphtha PA Duty but there is no any major changes in other PA duties of HK, Diesel, HAGO. Please note that we don’t use cold reflux for the column since very long time.
Request for your help please on this…( Regret for long description)
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Recently we are facing problem of Tempearature inversion between naphtha draw off & crude fractionator column top temperature.
In normal condition – Naphtha draw off temperature remains around 130 °C & Crude column top temperature remains around 111 °C ( Delta between this two temp. ~ 19 C )
But abnormally after the occurrence of this event as shown in graph, naphtha draw temperature is remaining around 118 C & column top temperature is remaining around 114 C ( Delta ~ 5-6 C) along with sudden increase in Naphtha section Pressure Drop (PDI ) also around 1000-1100 mmwater column ( as shown in the graph)
Pl. see attached graph image by clicking, which indicates trends as specified below:
1.Green colour – Crude column overhead temperature
2.Red colour – Naphtha section pressure drop
3.Pink colour – Naphtha draw temperature
In the trend analysis, you can see sudden dip in Naphtha draw temperature on 16th September.
Naphtha PA return temp. has fallen down by 5 C i.e. from 100 C to 95 C . There is no any significant impact on Naphtha distillation & End point.
I have gone through the thread124-178998: Column Temperature Inversion.
We have got total 3 trays in Naphtha section which is specifically designed HI-FI trays of MOC Monnel.I simulated the Model but it shows that if efficiency of Trays got reduced in naphtha section then in that case top as well as draw both temp. should fall down but here top temp. is higher and draw temp. has fallen down so, is it related to Tray damage or Pump around reflux distribution nozzle damage..Still not sure.There is reduction of Naphtha PA Duty but there is no any major changes in other PA duties of HK, Diesel, HAGO. Please note that we don’t use cold reflux for the column since very long time.
Request for your help please on this…( Regret for long description)
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RE: Temperature Inversion
How to open picture in proper size?
Regards,
Milutin
RE: Temperature Inversion
Yes,you are right.. somehow it was distorted…pl. try below link for enlarged view of the graph.. This will be more clearer
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RE: Temperature Inversion
Did anything happens on 16th September, like increase/decrease of throughput, upset, switch to different crude, etc...?
I didn't understand which are your top PA draw/return trays?
Regards,
RE: Temperature Inversion
Naphtha section pressure increase is an indication that maybe the 3 trays in Naphtha section are plugged with ammonia chloride deposits.
Uneven distribution of Pump around reflux distribution due to nozzle plugging or other mechanical damage is also to consider.
Your HIFI trays are with sieve holes, float valves or fixed valves?
Luis Marques
RE: Temperature Inversion
I am not sure in tray plugging with ammonia chloride deposits, because, as Petro explained, they don't use cold reflux (from overhead accumulator) so there is no possibility of recycling back ammonia salts or amine salts back to the column.
Salt deposits increase dP on trays and cause tray flooding, so overhead distillation end point should increase, or gap between overhead and side naphtha draw should become smaller.
Regards,
Milutin
RE: Temperature Inversion
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RE: Temperature Inversion
Temperature difference for top P/A decreased, so you lost about 20% top P/A duty for same P/A flow. So as you write other P/A didn't change, I suppose your top P/A flow increased to compensate lower dT. If this is true, increased top P/A flow can contribute to increase of dP in top column section.
How many passes have trays in top section? Vapor/liquid distribution can be affected by distributor or trays damage. If you didn’t have some upsets I don’t see reason for sudden tray/distributor damage, but don’t exclude this scenario.
Reason why asked for throughput change, crude switch etc in my previous post is because it could happen if throughput is lowered and quantity of vapors flowing upward is lowered weeping may develop so it can cause liquid to by-pass trays active area and lowering 4th tray temperature. My next question is what is quantity of overhead naphtha before and after “temperature inversion”?
Sorry for now I have more questions then answers, just to have picture what happens.
P.S.Up till now it is not temperature inversion, becuse 4th tray temperature is higher then top temperature.
Regards,
RE: Temperature Inversion
I am attaching herewith more detail profile of Naphtha section flow as well as temperature along with PA duties, this trend is described as below ( Starting from top to bottom with indication of two point values i.e. before the occurrence of event and after ,for your reference pl.) :
1st trend – Delta P across top Naphtha section (Between 3rd tray and overhead vapour line)
2nd trend – Crude column overhead temperature °C
3rd trend – Naphtha draw temperature
4th trend- Naphtha FBP
5th trend – Naphtha PA Duty MMKcal/hr
6th trend – HK PA Duty ,MMKcal/hr
7th trend – Diesel PA Duty,MMKcal/hr
8th trend – HAGO PA Duty,MMKCal/hr
9th trend- Naphtha PA return temperature °C
10th ,11th & 12th trend- Naphtha circulation flow across exchanger 1,2 & recirculation flow respectively.
We have got 4 pass trays.There was no any increment in PA Flow to compensate dT because PA flow infact it decreased (see second graph) compare to earlier .Kindly note that there was neither any sudden throughput disturbance nor any major crudemix changes.Yes you are right it is not temperature inversion but Delta T between Naphtha draw and overhead temperature got reduced.
Regret for so many complicated graphical trend.
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RE: Temperature Inversion
RE: Temperature Inversion
We have got total 24 bundles and we usually monitor Delta P across Fin fan coolers and even though we inject wash water continuously but if this delta P becomes higher we do offline water wash by isolating 4 bundles one after another and we monitor wash water quality too on continuous basis.
RE: Temperature Inversion
Thank you for graphs. When wrote overhead naphtha I referred to overhead naphta product.
You could make litle experiment, tray to increase other pumparounds (kero, diesel and HGO) if top pumparound is on auto mode with top temperature it will decrease flow.
In this way you will decrease vapor/liquid traffic in top column section. You should watch naphta pumparound draw tray temperature and dP in pumparound tray section. After this you can make changes in other direction - increasing top pumparound.
Regards,
RE: Temperature Inversion
Finally we ended up with the shut down and found 1st Monel tray severely corroded, 2nd tray and 3rd trays are corroded in decreasing order , with subsequent down below intake condition, Lot of depositions and under deposit corrosions found, lot of blockage/plugging of Hi –Fi trays sieve holes .
We were observing corrosion and sever salt deposition / fouling in Naptha pumparound circuit i.e. in S-01 A/B & S -04 A/B ( Naptha / Crude Pumparound Heat exchangers- as shown in the figure) with duty of -42 mmkca/hr these exchangers MOC is CS ,- Tube side naptha and shell side is having crude oil , we were observing lot of salt depositions in shell side i.e. outside of tubes , eventhough as indicated in figure, for 2 months we have injected ester based corroision inhibitior also in naptha pumparound pump . In fact we observed Ni & Cu metal traces in corrosion deposition in exchanger ( may be coming from monel metal in CDU Top section)
One of the incident that was noticed during the sudden delta P increment in naptha section, that was we have taken new bundle in line in one of above stated exchangers because these was routine practice to do repairing/cleaning in naptha / crude p/a exchangers and for that we have kept standby exchangers too. As you can see in the figure that apart from Pumparound heat exchangers , we have got hot bypass to mitigate final return temperature to the column.
As I mentioned earlier we stopped cold reflux since last two years.
You can see chemical injection points also in the figure, , before two years we had similar problem of top tray severe corrosion and that time , deposit analysis found almost Ash is 80 %, Loss of ignition : 20.47 % & others are chloride,Ni – 48.96 wt %,Fe-11.53 , Cu=15.6 ,Na,Si-traces
We are still at a loss : as we already maintain CDU overhead top temperature well above i.e. almost 115 C against water dew point temp. 95 C, but reflux return temp. to CDU column is almost remains between 96 to 105 C. whether is it having significance ???
Desalters operates with 97 – 99 % efficiency – two stage, also injecting caustic in d/s of desalters , sufficient wash water that is 5 – 7 wt % on crudemix.
Still at a wonder as all these corrosion issues are nightmare now ?
The parameters of CDU OH boot water analysis pH also remains between 5.5 to 6.5, wash water quality pH is little bit high as that is 7 – 7.5 as we use nonphenolic water .
Request all of you to throw some light.
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RE: Temperature Inversion
Just a wild thought: Monel 400 is affected (corroded) by a combination of aeration (or oxidizers) and acids. Could the wash water be a source of air entering the system ?
RE: Temperature Inversion
According to drawing you add NH3 as nutraliser to pumparound return. Adding ammonia or some other neutraliser to pumporound can cause severe corrosion to top trays, because ammonia salt deposition.
Deposits in P/A heat exchanger are partially entrained from column by P/A flow. Also in this P/A flow there is always water present, what can bring free water to top tray, and this water can exist locally on top tray.
I test this on our crude unit taking first droplets from P/A heat exchanger outlet pipe drain. Because that drain is the lowest point free water is accumulated.
Overhead wash water quality is not concern because you don't use cold reflux, what is source of your desalter wash water?
Regards,
Milutin
RE: Temperature Inversion
pH : 7 – 9
NH3 : 20 -50 ppm
H2S : ~ 20 ppm
Fe - < 1 ppm
Cynaide : 0.1 ppm
Yes we have got Monel 400 & we don’t monitor oxygen in the wash water going to desalter.
RE: Temperature Inversion
Do you realy use NH3 in pumparound return? If yes that is possible reason for tray corrosion.
Regards,
Milutin
RE: Temperature Inversion
RE: Temperature Inversion
Petro0707, a preferred chloride content after succesful desalting is ≤1 ptb; what is the level in your refinery ?
RE: Temperature Inversion
We usually don’t monitor chlorides in desalter outlet but outlet PTB salts from the desalters always remains below 1 PTB . Furthermore I am attaching one file for your detail perusal / analysis for CDU Column overhead temp. , final reflux return temp. (after p/a exchanger and hot bypass both ) , naphtha draw temp. , naphtha section pressure drop of last 9 months for both train 1 & 2, as we got two trains .Invariably you will find that Train 1 naphtha section pressure drop was very consistent & within limit & suddenly it was increased from 500 mmwc to 1000 mmwc with in couple of days. This chart is Individual value & moving range (difference between two successive individual value ) chart. ( One dot means – 24 hr average of that particular date , and X axis represents no. of data points starting from jan 07 to the incident date in the same order, UCL & LCL is calculated by statistical software (we need not worry about ) but we can see red points means assignable cause and others are chance causes.
One thing we are having doubt is: during those days i.e. sudden raise of pressure drop of naphtha section, if somebody has tried to lined up cold reflux which is dead leg or any bypass line which is almost 50 m-dead line for quite few months (we can say it is dead line – may contain salts, water-we don’t know) ,then with in 15 days this kind of corrosion on trays can occur or not due to this phenomenon ?
Wild idea - One another thing that I would like to mention that we usually do cleaning of Naptha p/a exchangers through fire water- containing high salts , of course after that passivation and air purging also we do before taking in line – can this be the cause ?
Can FeS – Iron sulfide which can form in Naptha / Crude p/a exchangers and which can flowed down to CDU top section trays and subsequently leaded to compounded galvanic corrosion , something like that can happen ?
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RE: Temperature Inversion
From the net:
RE: Temperature Inversion
Increased dP in naphtha section and lower top P/A temperature are caused by tray damage, tray damage is caused by corrosion and maybe with some other causes.
We have similar arrangement on our CDU regarding top P/A - cold reflux. When we want to line up cold reflux first we drain water from low point on that line.
Water is for sure accumulated on that line if it is not in operations for months.
We learn this from experience, in past, during one startup of that line water was in such quantity that when it reached column it immediately boiled (better word is exploded) and PSV on column top opened to relive pressure.
Such event can also damage trays, if they cannot resist downward acting force.
So it would be interesting to check if somebody try to line up cold reflux in date when you noticed increased dP.
You can check column pressure and cold reflux flow.
Also very useful for your analysis would be detail description of first four trays inspection during column inspection. Pictures if exist can be great help.
You should pay attention on: quantity of deposits and their location (deck or downcomer), missing valves, corroded tray deck segments (location on tray), missing or removed tray segments from their original position, are tray segments bent, if yes position upward on downward, are valves stick by corrosion, are tray segments firmly attached to deck....
Such analysis can help you to decide what really caused problems in column top.
Sudden increase in dP in your case can suggest that corrosion is not only reason for tray problems.
Regards,
Milutin
RE: Temperature Inversion
Please find the deposits analysis of that was found in downcomer :
Appearance – Black amorphorous
Magnetic response – slightly
Toluene soluble – 13.77
Loss of ignition – 41.87
Ash : 58.13
Carbon – 4.9 ( It is really miserable from where Carbon is coming )
Sulfur ( as sulfide ) – 11.3
pH of 2 % solution – 4.5
So4- - 0.09
NH3 – 0.01
Metals – Fe – 7 %
Ni – 31.8
Cu – 13.03
Mn – 0.30
Cr – 0.02
Al – 0.01
Si – Not detectable
Zn – 0.19
CO – 0.02
RE: Temperature Inversion
We could find some potential causes as below...
On top trays if top pumparound flow gets doubled than design...is it having some significance in terms of increase in top surface velocity on 1st tray which can make paper thin 1st tray over a period of time or free water that exists on top section of column and that remains circulating through p/a loop and can cause corrosion or errosion..., One thing which was noticed that .. total reflux flow ( p/a flow+hot bypass flow) could be controlled during initial rise of delta p across naptha section and pdi was coming down and then again it was increasing..but yes...during heavy sudden peak of 2000 mmwc --total reflux flow was very high....Is cold reflux really needed as we don't operate since long time...instead of high total p/a + hotbypass flow ..Is any purge/slip stream really required from d/s of naptha p/a pumps to purge deposits/salts etc.from the loop...we keep 10 -12 C higher top overhead temp. than water dew point temperature...but what can be the actual dew point with presence of NH4Cl ,So3- etc..we could not find any PSV poping during this phenomenon..
RE: Temperature Inversion
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RE: Temperature Inversion
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RE: Temperature Inversion
As for the subject of external reflux, it is the internal reflux that determines the degree of fractionation (ASTM gap) between adjacent fractions. Although the top 4 trays are for heat exchange, they are, anyway, considered equivalent to one tray for fractionation purposes.
I suggest, if possible, to read the pertinent chapter in D.S.Jones' Elements of Petroleum Processing (WILEY)
RE: Temperature Inversion
From pictures you posted it is clear why pressure drop increased and naphtha tray collector temperature went down.
Sieve tray holes are plugged or partially plugged by corrosion deposits, that caused increased pressure drop in that tray section. Big holes or missing tray segments below top P/A distributor caused that one part of top P/A flow bay-passed tray deck and reached collector tray without proper contact with hot vapors. Corrosion and erosion caused by liquid stream from distributor are responsible for such big holes.
I don't thing that tray segments are so thinned in short period of time, for how long these trays are in operation? In addition, how much time passed from your last cleaning of these trays?
However, main question is what caused such corrosion on top trays? Most probable answer is free water on that tray. As you mentioned water dew point is 95degC, top P/A return temp. is 95-100degC. This can cause a lot of water to condense and absorb HCl, which is reason for corrosion. As you wrote you find chlorides in deposit analysis, (I am not sure how much).
To prevent, or at least decrease local water condensation you should increase top P/A return temperature, there are several ways:
- Increase top P/A flow, increase top P/A temperature (same duty)
- Increase other pumparounds, this will decrease top P/A duty, what will allow you to keep same top P/A flow and increase top P/A return temperature.
Regards,
Milutin
RE: Temperature Inversion
Actually, within two years, trays are corroded.Because two years back as per the inspection report , everything was alright ,but one thing i would like to mention here that , as per the original design there was one stream from naphtha p/a pump discharge to tray down below ,Naptha Internal Reflux (IR) & we were having only two pumps used as p/a & top trays were valve trays ,but for some other reasons like Naptha End point,to minimize cost etc. we have modified & Naptha IR from p/a discharge to down below tray was removed , valve trays were replaced by Hi-Fi sieve trays,instead of original two pumps , we have added two extra pumps and now we are realizing that by putting extra p/a flows to top tray and that too..by looking at design of top distributor of p/a return to top tray it looks like that there is no equal distributions on top tray..may be possibility is there that at some locations instead of equal shower like distributions ,it may be impingment or localized distributions..
but as i mentioned earlier , we have added ester based corrosion inhibitor for two months (before 5 months back) in naptha p/a pump suction to minimize corrosion in naptha p/a cirucit , can this ester based CI cause glooey,sticky,slusshy deposits on tray..(as we observed)
we are still analyzing what ionic model/corrosion reaction is taking place inside top section ?
WIth in two months--fouling of naptha p/a exchanger & lot of salts deposits inside tube and outside tube --it may be coming from column overhead section ?
RE: Temperature Inversion
As you stated earlier you find copper in your top P/A heat exchangers, if your bundle is made from carbon steel only way to have copper is deposits from column.
This deposits also can cause underdeposit corrosion on heat exchanger bundle, and in that way accelerate corrosion and deposit generation in P/A heat exchangers.
We have similar situation, from pumparaund pump naphtha P/A flow is divided in two and every flow has two heat exchangers in series. I noticed that first heat exchanger in series has much more deposits then second, and we also have tube leaks caused by corrosion only on those (first) heat exchangers. Is it similar fouling in your case?
Reasons for this in my opinion are deposits entrained from column and water. This water is not free water, naphtha from column is saturated with water and when it reaches heat exchanger cold tubes, it cools down and water becomes free water.
You mentioned process changes: installing Hi-Fi trays (high capacity) instead of ordinary valve tray, deleting down flow to tray below, installing new pumps etc… Main reason of all those changes , as I conclude, is decreasing naphtha end point, to do this you need more top P/A duty and high capacity trays (because of increased vapor – liquid traffic in that part of column). This also as process change means you decreased column top temperature. Decreased top temperature also mean higher possibility to have local free water on top tray.
Regards,
Milutin
RE: Temperature Inversion
If you see I-MR charts Overhead temperature of the column was almost on and average 110 which is well above dew point temp of water.
I am still finding some other causes too..
RE: Temperature Inversion
I may be wrong. Kindly recheck your water dew point, at a total pressure of 1.6 bara, it seems that it would be near 99-100oC for a mol fraction of ≥0.6.
RE: Temperature Inversion
If your process changes were because of water dew point, does it means that you have history of such high corrosion rates on top trays? Or in other words did you experience such plugging and corrosion earlier, and what was the life of trays before process changes.
When I refer heat exchangers in series I mean situation as on the picture. Exchanger B was always more fouled then A.
Regards,
Milutin
RE: Temperature Inversion
In my first post I have told you that Naphtha section pressure increase was an indication that maybe the 3 trays in Naphtha section were fouled with ammonia chloride deposits. NH3 as overhead neutralizer is prone to Monel because it promotes ammonium chlorides fouling and corrodes copper by forming dark blue cupric corrosion deposits.
In the past we have experienced a similar situation.
Good luck
Luis Marques
RE: Temperature Inversion
Petro0707, please consider that by stopping the "external" naphtha reflux, the number of naphtha moles distilled dropped, since all this reflux would vaporize together with the normal product, and as a result the mol fraction of steam (water), as well as its partial pressure, increased.
Therefore, I still suggest to recheck the water dew point.
RE: Temperature Inversion
With in almost 2 years of operation -top tray is becoming paper thin .Last time we founded the same problem in other train..how can we achieve atleast 5-6 year runlength.?
By increasing the p/a return temp. or overhead temp
of column will call for higher end point of naptha (at present 163 C & i think simulation study shows that by increasing top temp. by say from 116 to 122 C --> Naptha EP will be 170-172 C, which will create problem for platformer unit..
Should we do NH3 balance ? We are injecting aq. & gaseous NH3 in overhead line, i don't think there is a problem due to this..but yes, H2S,NH3 in crudemix...can create problem.
RE: Temperature Inversion
It is possible increase top P/A return temperature without increasing column top temperature. You could do this if your other (lower) pumparounds have unused capacity.
You should gradually increase this lower P/A duty on maximum capacity, top temperature controller will, suppose it is in cascade with flow controllers in front of top P/A heat exchangers, decrease flow across top P/A heat exchangers. After this you should increase top P/A return temperature set point, as result P/A return temperature go up and P/A flow go up. Final result increased top P/A return temperature.
Regards,
Milutin
RE: Temperature Inversion
RE: Temperature Inversion
The example by D.S.J. Jones, in his book mentioned above, gives, without external reflux, a steam mol fraction of 0.72, with (cold) external reflux it dropped to about 0.6.
RE: Temperature Inversion
Are you talking about the one which has shown on page no. 75 ( Section 6.9 ) in D’Jones or else? , Actually, we are using the below dew point temperature calculation formulae is it in order ?? or what will be the dew point in case of inclusion of NH4Cl,NH4HS desublimation temperature ? Can you pl. help on this (desublimation temperature graph of NH4Cl & NH4HS )
Water mol fraction :WM=(FIC23-(FIC12+FIC83+fI99))*(0.9870*1000/18)
Hydrocarbon mol fraction :HM=(FIC48*0.6470*1000/90)+(FIC36*0.6580*1000/95.4)
TM=WM+HM
MFW=WM/TM
PPW=MFW*0.968*(PIC5+1.03324)
DP=(PPW^0.25)*100
Where
FIC23 –Boot water to sour water stripper
FIC12- Fresh water overhead fin fan cooler Upstream
FIC13- Recycle water from boot water to overhead finfan cooler upstream – Generally remains closed
FIC99- Surge drum to overhead fin fan cooler upstream – Generally remains closed
FIC48- Recontact drum Hydrocarbon flow to Sat gas con
FIC36- Cold reflux – Generally remains closed
PIC5-Column top pressure
DP – Dew point temperature
PPW – Partial pressure of water
As per Crude Assay data, Eocene & Ras gharib contains more potential H2S ( as high as 4800 & 2400 ppm) whether processing these crudes can cause corrosive reactions in crude column top section ?
RE: Temperature Inversion
Petro070
• Pages in Jones' book are OK.
• WM and HM are moles/h, not mole fractions.
• All flows are volume-based.
• Hydrocarbon densities FIC48 and FIC36 should be checked from time to time, to adjust HM.
• Procedure for estimation of Dew Point is OK.
• The last formula is in fact a ROT applicable for water vapor pressures in the temperature range of interest it should be:
DP, oC = (PPW,Pa/10)0.25×10 = 5.62× Pa0.25
Pa = pascals
See also thread483-101342: CDU Waterwash Design
RE: Temperature Inversion
RE: Temperature Inversion
Petro0707, of course, your formula, when the partial pressure is expressed in bara is OK.
ROT: Rule of Thumb, approximation.
I'll look around for those graphs.
RE: Temperature Inversion
In the meantime I found Perry VI table 3-7 shows vapor pressure for ammonium chloride down to 1 mm Hg. Somewhere else I've seen ~0.3 torr for ~ 100oC.
I'll keep looking for more info. on the two salts of interest.
RE: Temperature Inversion
The Antoine equation for NH4HS is given by NIST in:
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regretfully just up to 306.4 K
RE: Temperature Inversion
Do you process slops on crude unit, slops can contains amines which can also react with HCl and deposite as salts on trays?
Regards,
Milutin
RE: Temperature Inversion
Looking to the NH4Cl vapor pressure, incorporation of this component in dewpoint temperature calculation does not required. I am looking for is whether presence of these kind of species can elevate dew point temperature or not ?
If dew point temperature calculation, the same formulae is Online in DCS is true & if there is always delta of 7- 8 °C between PA Return reflux temp. to column & dew point temperature of water as per above formulae, then should I really worry about it ? or as I mentioned earlier , in Root Cause failure mode analysis for this case, it seems there are other things like phosphorous or amine entry in crude or any thing else which is the Critical to quality to me ..i.e. Vital X out of X1,X2,X3…….Xn-causes for these.
RE: Temperature Inversion
I have closer look on formula for dew point calculation. Water calculation is good, although FIC83 it seams to me should be FIC13, maybe typewriting error.
For hydrocarbon moles calculation, because as I understand you calculate water dew point on first tray, you should include hydrocarbons from top pumparound. Your current formula “HM=(FIC48*0.6470*1000/90)+(FIC36*0.6580*1000/95.4)” is ok for overhead line, not for first tray.
When you include this large HC stream water dew point calculation will be even lower then now.
There is good article in Petroleum Technology Quarterly Q4 2007, page 55, Crude unit corrosion – control programme.
Problem described is similar to your, author used ionic modeling to determine salt formation temperature, and it seams that salt underdeposit corrosion is main reason for corrosion .
Although very sophisticated tools used in RCA, part of solution was simple, increase tower top temperature.
Regards,
Milutin
RE: Temperature Inversion
Milutin, please clarify. The overhead vapors are those leaving the first tray. Top pumparound is a liquid. How do you intend to add these moles to the vapor ?
RE: Temperature Inversion
You are right, Petro's formula is ok.
Regards
RE: Temperature Inversion
How are you..?
As I mentioned earlier,we were dozing Corroison inhibitor in naphtha pump around circuit for two months ( ~ 3 ppm C.I. we were maintaining - dozzing rate 8 liter/hr ~10MT was used for entire two months) to cop up with the corrosion before this incident.
In this C.I. supplied by vendor following are the ingredients :
1.Unsaturated dimer fatty acids -55-65 %
2.Aromatic H/C-45-55 %
3.1,3,4 -Trimethyl benzene - < 5 wt %
4.Napthalene - < 3 wt %
we are checking whether this is having pure free fatty acids or ester form of fatty acids,most probably it is ester form of fatty acids but does it really affect plugging on the tray elements...?
Last week I was refering article on Monel 400 corrosion sensitivity where it talks about little amount of air/oxygen presence can increase corrosion rate of M-400 like anything..? at present we intend to carry out testing of dissolved water in desalter wash water...
Thanks & Regards,
RE: Temperature Inversion
How are you..?
As I mentioned earlier,we were dozing Corrosion inhibitor supplied by one of the vendor for about two months before this incident took place to reduce/minimize corrosion in naphtha p/a circuit ,this C.I.MSDS is :
Unsaturated dimer fatty acids : 55-65 wt %
Aromatic H/C : 45-55 %
Napthalene : < 3 wt %
1,3,4-Trimethylbenzene - < 5wt %
Now,we intend to investigate whether this fatty acids was in free form or ester form,most probably it was in ester form..and does it really affect the overhead tray plugging as we founded slusshy,gooey material on tray panels/downcomer...
We also intend to investigate dissolved oxygen in desalter wash water as it may enhance corrosion rate of Monel 400 like anything..
RE: Temperature Inversion
What is Cl- and NH4+ ions concentration in overhead boot water? Maybe you could estimate if there are conditions exist for salt deposition on first tray.
You should subtract ammonia added for overhead neutralization to have value what is coming from column top.
Using your existing simulation you could calculate HCl and NH3 concentration on tower top.
Using graph below you can estimate if there are salt deposition occurs.
Regards,
http://www.hghouston.com/images/NH4CL.gif
RE: Temperature Inversion
You are right,but it seems little difficult to calculate exact HCl & NH3 concentration in tower top section as , organic chlorides which comes along with the feed, it can crack in the CDU Furnace as our CDU COT is as high as 385 C, it can form HCl , Nitrogenous compounds presence in the crude oil it can crack in the furnace and it can form NH3 , over and above we don't monitor gaseous NH3 injectioni in tower top , yes we know aquous NH3 concentration ( 3 - 5 ppm ) going to overhead condenser wash water & we daily monitor NH3 that remains 60 ppm in overhead reciver boot water (we don't monitor NH4+ & Chloride remains almost on and average 25 ppm, but to exactly calculate HCl & NH3 presence in crude tower top section, even ASPEN simulation model I think it does not give me accurate desublimation temperature. Request to throw some more light on this.
RE: Temperature Inversion
Petro0707,
Have a look at
http://www.freepatentsonline.com/5269908.html
you may find it interesting, in particular the description of the invention.
RE: Temperature Inversion
RE: Temperature Inversion
May be Figure 3 in
http://www.mksinst.com/docs/UR/Trap.pdf
will be helpful
RE: Temperature Inversion
On tower top you have gaseous NH3 and HCl, everything what cracked in furnace is cracked, so no more cracking after furnace exit. Cl and NH3 (total NH3 - NH3 added) present in accumulator boot water represent Cl and NH3 from column. If you know Cl and NH3 concentration and water quantity (water to SWS) you can get Cl and NH3 quantity from column.
From process simulation you can get quantity of HC + water in column top.
In this stage you can easily calculate partial pressure for Cl and NH3, and use graph from my previous post.
I didn't understand what is 60 and what is 25ppm from your previous post?
There are companies like Nalco (Pathfinder software) and Baker Petrolite (TopGuard software) which provide service for calculating water and NH4Cl dew point in column top.
Regards
RE: Temperature Inversion
As per past data statistics,On an average, 25 ppm is the total chloride in overhead boot water & 40 ppm is the total ammonia (not free ammonia but all amines etc.) in overhead boot water.So, we assume that 0.1 % of crudemix nitrogen is getting converted in to NH3 in crude furance through cracking & that way I am trying to calculate ,yes I am also trying to calculate through your suggested route also..
Thanks..
RE: Temperature Inversion
From the data in your possession, it shouldn't be too difficult to assess the mol fraction of ammonium chloride in the vapors ex tray #1.
Then, assuming ideality, obtain the partial vapor pressure and using the graph above get the dew point of ammonium chloride. From a quick reading the sublimation=desublimation vapor pressures are:
Celsius torr
80 6.5×10-3
90 1.3×10-2
100 2.7×10-2
110 6.1×10-2
120 1.0×10-1
RE: Temperature Inversion
We use generally phenolic & nonphenolic water as desalter wash water which comes through surge drum , so, with this I am attaching desublimation temperature calculation of NH4Cl for cross validation purpose. The final dissociation constant is in atm.,so, the same after converting into psi, and after have a look in the graph, it seems it falls under deposition region. Here we have tried to calculate NH4+ entry through wash water to CDU column & we assume 20 % of NH4+ gets carried through wash water with crudemix to crude column. Yellow highlighted area indicates that much NH4+ presence in that particular wash water.
Pl. give your suggestion/comment on this.
htt
RE: Temperature Inversion
• Is there a basis to assume that 20% of wash water NH3 migrated to crude ? Otherwise the estimation seems to be right.
• By using external (cold) reflux the mol fraction of water drops. Besides, the azeotropes of water with light hydrocarbons should chase away any liquid water present.
• It would be worth to read the following US patents:
USP 4430196, USP 4599217, USP 4806229, USP 4855035, USP 5211480, USP 5302253, USP 5714664.
RE: Temperature Inversion
I am not sure to what you refer in "Yellow highlighted area indicates...", which yellow area?
You should avoid assumptions like "20 % of NH4+ gets carried through wash water with crudemix to crude column". Because that is base for your calculation.
Right way is Cl, NH3 balance in overhead water.
Regards
RE: Temperature Inversion
Yes, you are right.In that calculation worksheet yellow highlighted cell (raw) indicates NH3 ppm in phenolic water & non phenolic water which is used as desalter wash water.Through overhead NH4+ & Cl- way, still some of the HCl can react inside the column with NH3 & whatever we get in overhead receiver boot water is the unreacted Chloride ions coming from the column.Still both way we need to assume certain thing.Any proven desublime temperature example calculation through overhead NH4+ & Cl- will be highly appreciated & also it will be very helpful to us.
Thanks
Dear 25362,
Yes, I went through patents which you mentioned, it is really imaginative, especially, I learnt that we need to monitor SO4- in boot water , any organic / unextractable chloride in o/l of desalter too .Whether H2S can form NH4HS ? , of course as per original one of the reference threads of 0707 indicates that yes, H2S takes part in the formation of ammonium disulfide,whether we need to monitor NH4HS desublimation temperature along with NH4Cl too ?
RE: Temperature Inversion
Apart from the link I provided on Oct. 25, I was given to understand that as long as temperatures are above 70oC there is no deposition of NH4SH.
RE: Temperature Inversion
How are you ?
We have carried out further analysis of top tray material deposits as well as downcomer weir deposits and we have found & confirmed that there was no any chloride as well as no any sulfide was detected and majority we have found is Ni,Cu,Fe & sulfates.Yes,If NH4Cl depositions would have taken place,some ppm chloride should have reported but it was other way around.Over and above,our Naphtha pumparound sample is having more than 480 min. of oxygen stability number and hardly we could detect dissolved oxygen in wash water also,now,since Ni,Cu (from Monel 400 trays & top shell clading material) was reported in naphtha p/a exchangers,naphtha pump )& in these deposits too, the question is how sulfates can be reported in o/h,what can be the source as 25362 has mentioned it seems hardly any chance for NH4HS depositions because o/h temp. is almost 110 C.Other possibility is any oxygen/air ingress in the column o/h which can accelarate Monel 400 corrosion or H2S reaction mechanisom..for that we need proper ionic model..because..it is still very difficult to find root cause of the problem..
Thanks & Regards,
RE: Temperature Inversion
Thanks everybody ...It seems we need to go for Ionic modelling to improve our reliability of OH Corrosion.
RE: Temperature Inversion
It is really interested case where detail X-ray / scanning electroscopic magnification view of top tray-top and bottom pieces / downcomer pieces talk about cavitation erosion and no any chlorides are detected on the trays but sulfates/sulfides are detected and more predominately Nickel and copper sulfates….and Oxygen is also being reported…we were rigorously thinking about NH4Cl but it could be other way around it seems….Apart from that it is really difficult to distinguish sulfates and sulfides but it is surely sulfates/sulfides,so,what will be your opinions on these particular two pieces sulfates and oxygen…how these two guys creates problem and more important is the source of these guys…how to pinpoint exactly..?
RE: Temperature Inversion
I am not sure if you wrote about your case or about some case from literature.
As 25362 quoted in post from 19 Oct 07 sulfuric acid can cause severe corrosion in column top trays and overhead. Source can be oxygen as we earlier discussed.
To check sulfates presence we analyze overhead boot water on sulfates, usually below detection in our case.
Regards,
Milutin
RE: Temperature Inversion
How are you doing…?
Yes, I wrote for our case and we don’t regularly monitor sulphates in OH boot water but we could do few sulphate analysis in OH boot water in the past and we found sulfates in boot water in the range of 2 – 10 ppm and sulphates in desalter wash water in the range of 2 to 10 ppm and in desalter brine water in the range of 6 to 30 ppm. You mentioned below detection level in your case….does it mean in ppb level? Yes...It seems Monel is not appropriate metallurgy in presence of this much amount of sulphates…It is again a question where no any crude assay data shows sulphates and we do process blend of 8 – 10 crudes….may be due to downstream additives in well ..Sulphates can ingress and end up in CDU OH section or elsewhere….our desalter wash water this much sulphates… (mentioned as above) does it acceptable…?
Thanks & Regards,
RE: Temperature Inversion
Apart from air-oxidation of organosulphur compounds, one may use Sherlock Holmes thinking tips to identify the origin of sulfates in crude, as follows:
• S ranks third after C and H among the constituents of crude oil, and far ahead of O and N.
• It is not a major constituent of biogenic molecules, where it ranks well behind O and N.
• It must have been picked up en route through geological strata, or while standing in reservoirs.
• From isotope measurements experts reached the conclusion that it may derive from sulfates in connate water after the oil has accumulated.
• The connate oilfield waters contain frequently more than 104 ppm of dissolved inorganic salts - principally chlorides and sulfates of sodium, potassium, calcium and magnesium.
• Thus the presence of sulfates in crudes shouldn't be considered a strange event at all.
RE: Temperature Inversion
http://www.freepatentsonline.com/4855035.html
under the heading Description of the preferred embodiments gives interesting information on the possible origin of sulfates and bisulfates.
RE: Temperature Inversion
Thanks for your reply.
I do agree...
It seems in our case dissolved oxygen in desalter wash water which we could not say very confidently 5-6 ppm but it seems in that range (we could do one or two analysis ) as i mentioned earlier that this desalter wash water is phenolic and nonphenolic water from sour water stripper unit and we don't monitor dissolved oxygen on regular basis and that too storage vessel is having Fuel gas as blanketing (oxygen can dissolve through this to desalter wash water)& your attached reference US patent talks about SO2,SO4 speicies can be form in the presence of Oxygen in wash water through reaction with sulfur compounds in crude oil but how much dissolved oxygen is allowed in desalter wash water is it 2 , 3, 4 ppm ?? or how much ppm of oxygen can form these nasty sulphate species..?? What is the allowable sulphate level in overhead boot water ?? ,The mentioned US Patent also talks about corrosion due to sulphates/so2,so3 on CS and not for MONEL-400 while ours is Monel.
Thanks..