Temperature Inversion 2

[Petro0707]

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.

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)

 

[25362]

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, [sup]o[/sup]C = (PPW,Pa/10)[sup]0.25[/sup][×]10 = 5.62[×] Pa[sup]0.25[/sup]

Pa = pascals

See also thread483-101342

 

[Petro0707]

What is ROT ? & can you pl. suggest NH4Cl ,NH4HS desublimation temperature nomogram or graph please..?

 

[25362]

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.

 

[25362]

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 ~ 100[sup]o[/sup]C.

I'll keep looking for more info. on the two salts of interest.

 

[25362]

The Antoine equation for NH[sub]4[/sub]HS is given by NIST in:

http://webbook.nist.gov/cgi/cbook.cgi?ID=C12124991&Units=SI&Mask=4

regretfully just up to 306.4 K

 

[Milutin]

Petro,

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

 

[Petro0707]

Yes, We sometime process slop which are nothing but an HVGO,HAGO,Diesel like material but usually after shutdown of the unit & these slop processing is not continuous basis, whatever offspec material of above remain, those are processed after analysis of BS&W.

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.

 

[Milutin]

Hi Petro & 25362,

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

 

[25362]

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 ?

 

[Milutin]

25362,

You are right, Petro's formula is ok.

Regards

 

[Petro0707]

Hello..25362,Milutin,0707,

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,

 

[Petro0707]

Hello..25362,Milutin,0707,

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..

 

[Milutin]

Hi Petro,

What is Cl[sup]-[/sup] and NH4[sup]+ [/sup]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 NH[sub]3[/sub] concentration on tower top.
Using graph below you can estimate if there are salt deposition occurs.

Regards,

http://www.hghouston.com/images/NH4CL.gif

 

[Petro0707]

Hi Milutin,

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.

 

[25362]

Petro0707,

Have a look at

http://www.freepatentsonline.com/5269908.html

you may find it interesting, in particular the description of the invention.

 

[Petro0707]

Dear 25362, Thanks for sharing, Just couple of hours back I went through the same article , whether is it commercially proven or executed…that is again a question mark or if we go to the root cause ,then how do I exactly calculate partial pressure of HCl & Partial pressure of NH3 in the overhead section above 1st tray in CDU main column .

 

[25362]

May be Figure 3 in

http://www.mksinst.com/docs/UR/Trap.pdf

will be helpful

 

[Milutin]

Petro,

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

 

[Petro0707]

Dear 25362,Milutin,

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..

 

[25362]

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[&times;]10[sup]-3[/sup]
90 1.3[&times;]10[sup]-2[/sup]
100 2.7[&times;]10[sup]-2[/sup]
110 6.1[&times;]10[sup]-2[/sup]
120 1.0[&times;]10[sup]-1[/sup]