21 replies to this topic

[attya]

Greetings gentlemen ,

After 5 years of operation of the plant , We have decided to carry on vessel inspection for all equipments in the plant , including Amine sweetening and TEG dehydration ...etc

 

-TEG system is equipped with stripping gas column , which increased TEG purity up to 99.5%

-TEG contactor is structured packing mellapack 250.Y

-plant is designed to handle 50 mmscfd gas with inlet conditions of 1200ppmv H2S and 8%mole CO2 and the gas outlet specifcations are 3 mol% CO2, 50ppmv H2S and a water content of 24 lb/MMscfd.
However  the current conditions are : 12 mmscfd inlet gas with only 250 ppmv H2S and 5%mole CO2 , and the outlet is free of H2S and CO2 and the dew point is very low .

-TEG circulation rate : 19500 lb/hr

-Current TEG samples : purity : 99.08%  ,  PH : 10 

-TEG reboiler temperature : 399F reboiler pressure is 8.7Psig , Still column temperature : 213F (Controlled manually) , Still column is random packing to minimize TEG losses.

-Stripping gas in reboiler :  1670.4 ft3/ hr .

-Design inlet gas temperature is 115F after being cooled after Amine sweetening , But currently it's very low (Around 75F)

 

Inspection scope :

 

1.TEG samples are constantly higher than  PH : 7 ,  in last samples it has been 10 and when we carried on inspection for the TEG filter (that removes MDEA entrained and gets it back into amine regenerator) it has jumped to PH : 11.2 , Conclusion was that this must be amine getting somehow into TEG system , base on my knowledge ,  high PH in TEG increased the tendency to foam right ? 

Also i was worried that amine would degrade in TEG reboiler and form stable salts and cause corrsion to reboiler bundle 

 

 

2.TEG losses recently has become huge (around 40 liters/day)  During investigation , We reduced stripping gas flow rate since the product gas has very low dew point , We have also made sure that still column head temperature is no more than 213F to reduce any amount of TEG lost this way , after further investigation i have found that the difference in temperature control between Lean TEG and inlet gas setpoint was 44F , and found out that this value has been written in suppler manual 44F as a conversion from 5C , which means it has been converted wrongly and right right value should be 9F , After starting to decrease it gradually it has been noted that losses had decreased alot , then when finally got to 9F losses become at the optimum value 

 

Attached is screenshot of the trends of TEG level in TEG surge drum , the first trend is for when temperature difference is 45F , the top and bottom peaks show the day and night time (At day temperature is high and vise versa)  , the 2nd trend is for when it was decreased to 16F , i dont have the 3rd one right now , But after it it became fine .
Problem now is :

After starting being in winter time, inlet gas temperature has reduced from 90F to 75F and sometimes 70F  and lean TEG cooler became unable to handle the 9F difference in temperature , temperature difference at night time jumps to 17F , And losses started again , it really made me think ?  "Is temperature difference that huge of a factor to determine TEG losses ?"  to be honest , I thought it should be something else , and waited until TEG system is opened for vessel inspection to see what's going on

 

3.TEG system in plant is designed to get 99.5% purity when dealing with 50 mmscfd gas,  now it's only 10 mmscfd and TEG is unable to get any close to 99.5% it's around 99.02% all the time   , Tried to reduce reboiler presssure to 8psig it helped very little and got 99.1% purity once , but couldnt lower it any more since it will risk us losing more glycol that way

 

 

 

Findings :

 

1.TEG contactor mist elemenator ( or demister pad as the supplier call it) Was found damage as shown in photos 

http://i42.tinypic.com/dvlrw0.jpg

http://i43.tinypic.com/2cz5wle.jpg

http://i42.tinypic.com/11h5n5c.jpg

http://i40.tinypic.com/11h8ils.jpg

 

 

 

2.TEG reboiler & bundle is covered by yellowish material , It looks like if its corroded when you touch it , But i'm not sure yet since we have not made a sample of this matter , Same appears but not as much in TEG surge drum  as shown in this photo of the reboiler and bundle :

 

http://i40.tinypic.com/okor2r.jpg

 

so my questions are : 

 

1.Could that damage of demister pad be the reason that TEG losses are really high when temperature difference between lean TEG and gas 17F at winter like i described ?  i know that mist eleminator is important but is that damage a huge deal ?

 

2.Do you think that having amine in glycol and its degradation is the reason that TEG reboiler looks this way? What can i do to reduce the PH of TEG or more importantly reduce the amine getting into TEG system ? 

 

 

 

Thanks in advance !

Edited by attya, 10 October 2013 - 04:38 PM.

[Bobby Strain]

Have you considered having someone clean your solvents while the plant is down?

 

Bobby

[attya]

Clean solvents ? 
you mean cleaning TEG solution before loading it back in ?

[Bobby Strain]

Yes, both TEG and amine. There are companies with mobile units to clean them onsite. Check with Google.

 

Bobby

[attya]

We have tried this before ,  But the PH of glycol has increased within a week to 10 again ..

[attya]

I also wonder what's the correct way to store glycol ?

We have drained the glycol from the system into used glycol barrels , but its open in the air

can this cause problems with glycols ?

[Pronab]

Long description, a bit confusion as well. How?

 

plant is designed to handle 50 mmscfd gas with inlet conditions of 1200ppmv H2S and 8%mole CO2 and the gas outlet specifcations are 3 mol% CO2, 50ppmv H2S and a water content of 24 lb/MMscfd-- gas inlet H2S 1200ppmv and outlet 50ppmv- I believe it is amine unit gas specification instead of glycol.
 

so my questions are : 

 

1.Could that damage of demister pad be the reason that TEG losses are really high when temperature difference between lean TEG and gas 17F at winter like i described ?  i know that mist eleminator is important but is that damage a huge deal ? -- It is one of them. 8.7 psig reboiler pressure is high. you can reduce it up to 1.5 psig depending on your system, where the vent en route. Is thee any recovery system outlet of glycol contactor? Adjust stripping gas rate, 4 to 8 scf/gal of glycol circulation is enough.

 

2.Do you think that having amine in glycol and its degradation is the reason that TEG reboiler looks this way? What can i do to reduce the PH of TEG or more importantly reduce the amine getting into TEG system ? - - Yes. Only amine pH is high enough to bring glycol pH higher. Before entering to glycol contactor, sweet gas from amine unit, there should be knock out drum. It will be better understanding if you provide a sketch of your PFD. You should solve glycol pH problem soon, I believe amine is carry over to the glycol system.

 

TEG should be stored under N2 system and should not be contaminated with O2.

If your gas dew point allows, TEG purity is not concern, however 24 Ib/mmscf water content in gas is quite high,normally it is 7 Ib/mmscf.

 

You can get lots of operating parameters on glycol system in the net.

Here is one of them to read worthwhile:

HOW TO BUY GLYCOL DEHYDRATORS- D.W.CHOI, Hydrocarbon Processing July 2006.

 

 

[Art Montemayor]

Attya:

 

Your query is very lengthy and doesn’t give the information and data required to answer your questions.  Our members need as much detailed information as you can supply in order to address your questions with accuracy and correct solutions:

• A detailed Process Flow Diagram, showing tempertures and pressures; this should include the acid/sour gas treating facility before the TEG dehydration unit.
• Who designed and built your acid/sour gas and TEG units?
• How long have these units been working successfully?
• When did the problems with the TEG unit begin to appear?
• Is your natural gas destined for pipeline transport?  If so, why is the water content specification so high?  It normally should be 7 lb/MMScf as a maximum.
• Please show all flow rates for the gas, amine, and TEG clearly in your PFD – both as the original design rates and the present, turndown rates.

Without this information, it is difficult to form any opinion or comment on what is wrong with your units.  But from what you report, your units are operating very badly and out of control.  This problem can be resolved very simply – but detailed and accurate information must be furnished by you.

 

 

[adammusthafa]

1.Could that damage of demister pad be the reason that TEG losses are really high when temperature difference between lean TEG

and gas 17F at winter like i described ?  i know that mist eleminator is important but is that damage a huge deal

 

Damaged demister: Yes it could. Any plugged tray or internal may make probability of liquid (ie glycol) entrainment higher. It could create a localized higher gas velocity that promotes entrainment.

 

Delta Temp of 17F: The 17F difference is normal.  We usually maintain lean TEG temperature 10-20°F above the Gas.

 

However i noticed that your contactor is working at 10 MMscfd gas while was designed for 50 MMscfd. Have you check your tower turndown? Operating at very low flow like this could trigger hydraulic instability. Check the design specification and monitor the level at the bottom and the contactor pressure if any of both fluctuates erracticly, maybe this is the cause of your TEG losses.

 

2.Do you think that having amine in glycol and its degradation is the reason that TEG reboiler looks this way? What can i do to reduce the PH of TEG or more importantly reduce the amine getting into TEG system ? 

 

It is true that Amine could increase your TEG pH. In fact it could stabilize the pH at >7.

 

However, in term of corrosion most of the time this is because there is H2S carryover (or any other sulphur compound) that reacted with your TEG. On such case your TEG pH will be reduced <7 instead of increasing like what happen to your TEG. Do you happen to have alkaly chemical injection upstream the TEG system (corr inhibitor, etc)? This chemical may be carried over to the TEG system.  TEA or borax injection may help.

 

Corrossion may also occur if your glycol is contaminated with O2. They will form a corrossive acid. You should prevent O2 ingress by blanketing your TEG storage, etc, or add  oxidation inhibitors such as hydrazine to prevent corrosion due to oxidized glycol.

 

Degraded TEG could also promotes corrosion. Keep your reboiler Temp < 400F (380F recommended)

 

To reduce amine carryover:

You should check for higher than usual of still temperature. Check for any fouling in condenser tubes or any faulty temp control instrumentation. Fix it and try to maximize your cooling duty to get Reflux condenser outlet temperature <130°F.

 

Amine carry over may also be promoted by foaming due to Hydrocarbon contamination (check for HC layer at reflux accumulator). Check also the condition of your carbon filter. The filter should have prevented this. If foaming still occurs maybe there a problem with the filter.

[attya]

 

A detailed Process Flow Diagram, showing tempertures and pressures; this should include the acid/sour gas treating facility before the TEG dehydration unit.

 

I have attached the PFD with all temperatures/pressures needed 

 

 

Who designed and built your acid/sour gas and TEG units?

Prosernat 

 

How long have these units been working successfully?

5 years , But it depends on what u mean by "successfully"  

Plant is designed to handle 50 mmscfd (Both amine and glycol) but i never worked this way since start , Start was 28 mmscfd and now it's almost 10 mmscfd ,  also TEG PH is jumping to 10 since start (amine carry like i said before)  and TEG purity was never up to 99.5% as designed 

 

When did the problems with the TEG unit begin to appear?

Like i said , TEG PH is since start , TEG losses problems has started recently (5 months)

it stopped once we have reduced the difference in temperature between lean glycol and wet gas to 9F (it was 45 before as i stated since supplier manuals said it should be 45F wrongly)  But then when winter season started,  Inlet gas temperature became really low and TEG coolers become unable to handle the 9F difference so the losses started again (Around 30 liters/day)

 

 

Is your natural gas destined for pipeline transport? If so, why is the water content specification so high? It normally should be 7 lb/MMScf as a maximum.

 

Plant is designed to basicly separate oil from gas , Remove H2S from both and transport the gas to the main gas plant , I will review at work and see if 24 lb/mmscfd is correct value , but that's how its written in the supplier manual , However .. the outlet gas dewpoint is very low.

 

 

Please show all flow rates for the gas, amine, and TEG clearly in your PFD – both as the original design rates and the present, turndown rates.

I have shown the current flow rates for both systems on PFD
about the design : 
MDEA (45%MDEA  1% Hydroxy ethylpiperazine)  258,000 lb/hr

TEG 19500 lb/hr ( Same from now , unchanged )

GAS 50 mmscfd at pressure of 170psi at amine contactor and 160 psig at TEG contactor 


Please sir , let me know if some other piece of information is missing .

Attached Files

•  amine PFD.jpg   166.32KB   28 downloads
•  TEG PFD 1.jpg   146.66KB   30 downloads
•  TEG PFD 2.jpg   118.4KB   18 downloads

[attya]

About Adam: 

However i noticed that your contactor is working at 10 MMscfd gas while was designed for 50 MMscfd. Have you check your tower turndown? Operating at very low flow like this could trigger hydraulic instability. Check the design specification and monitor the level at the bottom and the contactor pressure if any of both fluctuates erracticly, maybe this is the cause of your TEG losses.

 

 

The level is stable , same for the pressure .

 

 

 

It is true that Amine could increase your TEG pH. In fact it could stabilize the pH at >7.

 

It doesnt stabalize at 7 sir , it's always 10 , Also when we carried visual inspection before for TEG filter ( The tower that removes entrained amine and sends it back to amine regenarator before the gas enters TEG contactor) The PH became 11 since the TEG filter was isolated and bypassed

 

However, in term of corrosion most of the time this is because there is H2S carryover (or any other sulphur compound) that reacted with your TEG. On such case your TEG pH will be reduced <7 instead of increasing like what happen to your TEG. Do you happen to have alkaly chemical injection upstream the TEG system (corr inhibitor, etc)? This chemical may be carried over to the TEG system. TEA or borax injection may help.

 

Hmm , there's no way that H2S would carryover  , all sweet gas samples are 0 ppmv H2S

 

[Propacket]

Really weird observations attya.

 

Gas coming to the TEG plant is 3% CO2. Some of the CO2 must be absorbed by the TEG making it somewhat acidic (PH<7). But you are getting a basic TEG (PH>7). Amine is the only base involved in your process and so amine carryover could be the reason of higher PH. However, it is hard to believe that amine carryover is so much that absorbed amine can even counter the effect of absorbed CO2 changing it to a basic solution. Are you keeping track of amine losses in amine plant?These should be pretty high. May be a damaged demister there too.

 

High glycol losses due to reduction in temperature to 75 degF are also difficult to explain. The contactor should have cooled down reducing the glycol losses. By the way if gas flow is reduced to 10 MMSCFD, why dont you cut the TEG flow too. It will help reduce the losses. Also,  why the reboiler pressure is high? Keep it as low as possible to reduce the losses. 

Edited by Propacket, 21 October 2013 - 03:04 AM.

[attya]

hello propacket ,    thanks for your reply 

 

Gas coming to the TEG plant is 3% CO2

I think you miss read that , Gas is coming to TEG plant is 3% CO2 In "Design" case , Right now it's 0% CO2

 

Are you keeping track of amine losses in amine plant?These should be pretty high. May be a damaged demister there too.

 

Amine losses are somewhat high , But not like TEG losses like i mentioned , Like i mentioned there's no CO2 going at all to TEG  , So i think not very large amount of amine is required to levitate the PH up to 10 , also when we carried visual inspection on TEG inlet filter (The column that removes amine entrained in gas and send it back to amine regeneration) the PH jumped to 11-11.5 since the column was bypassed

 

 

High glycol losses due to reduction in temperature to 75 degF are also difficult to explain. The contactor should have cooled down reducing the glycol losses

that's right , But design case is that inlet gas should be 115F , now it's down to 75F , TEG trim coolers are unable to cool lean TEG to make difference of 9F between inlet gas and TEG

 

 

 

why the reboiler pressure is high? Keep it as low as possible to reduce the losses. 

 

 

This is something that needs explaining because i feel like i miss understand something here.

the current reboiler pressure is 8.7,  I thought that lowering reboiler pressure increases the amount of TEG removed with water at reboiler & going out of still column  , which increased glycol losses and increases glycol purity  ?

Can you explain to me please what is the correct effect of reboiler pressure on TEG losses ?
Also if you look at TEG reboiler PFD , TEG still outlet was used to go to "Acid gas incenerator"

But since the startup of the plant , TEG reboiler outlet was causing alot of trips to the acid gas incinerator (HH temperature trip)

and since acid gas incinerator takes long time to warm up , They decided to not let it go to acid gas , and send it to flare instead (Regardless of BTEX effect on going to flare)

 

 

Now the TEG  still column pressure is controlled by the PCV seen on the line going to Low pressure flare line.

[Propacket]

TEG purity suffers at high pressure and more stripping gas is required. High stripping gas is major culprit for high glycol losses from the reboiler.

 

Problem is that many companies have their standard pre-designed regenerators for a given duty. Reboiler, accumulator, still, stripping column, reflux coil everything is pre-sized.This leads to many operating problems like inability of packing to handle high gas stripping gas rates at high pressure, packing gets flooded, leaked reflux coil etc. All of these are contributors to high glycol losses. 

Edited by Propacket, 24 October 2013 - 02:20 AM.

[Art Montemayor]

Attya:

 

As I’ve mentioned previously, your units are operating very badly and out of control.  THAT, I believe is the main subject of this topic and the solution or mitigation of this issue should be the prime concern.

 

You are operating your MDEA and TEG units at 20% of design and the type of process design employed in your units is not capable of doing that.  You have bubble caps in your MDEA absorber and stripper and structured packing in your TEG contactor.  While you have turned down your MDEA circulation rate, you continue to operate with the design TEG flow rate of 19, 500 lb/hr (35 gpm).  Although you haven’t stated it, I think I know why you are operating at these flow rates:

• 20% of the design MDEA flow rate is 52,000 lb/hr and your plate seepage in both absorber and stripper can’t operate efficiently at that reduced rate;
• If you reduce the TEG design rate (35 gpm) down to reduced flow of approx. 7 gpm, the structured packing in the contactor will not operate as per design to produce the specified dew point in the product gas because of excessive channeling and bad TEG distribution in the packing.
• Consequently, you are stuck in the basic design of the units.  Have you contacted Prosernat to request advice and recommendations on how to modify the 3 columns so that they will operate at the reduced flow rates?  If not, this should be done on a priority basis.  You are losing a lot of valuable, excess stripping gas and burning excess natural gas in the TEG reboiler.  For all practical purposes you can forget about the damaged mist pads you found in the towers.  These items cause negligible bad results – especially when the gas flow rate is 20% of design.  The superficial vapor velocity through the MDEA absorber is drastically reduced – and so is the expected entrainment of amine.  The existing TEG Contactor Inlet Filter/Coalescer (V-2191) should be sufficiently sized and designed to capture any entrainment from the MDEA absorber at design rates.  If there is any MDEA entraining even at the reduced 20% turndown rate, it should be detected at this vessel.

You should be operating the TEG reboiler at 400 oF and a minimum of pressure – unless Prosernat instructions are otherwise.  For information on how stripping gas rates affect the Lean TEG purity, refer to the attached paper.

 

 6 TEG Dehydration Stripping Gas Charts for Lean TEG Regeneration June 2013.docx   743.38KB   168 downloads

 

[Pronab]

I am more worried about TEG pH. If amine is not carry-over and amine inventory is same, then really it is a concern. Without amine it is not possible to increase pH of TEG.

[attya]

Pronab, that's my concern too

for Art  ,  Can you explain more please what's the effect of pressure in TEG reboiler ? 

My knowledge is basically the less the pressure is , The better TEG quality but risks more TEG losses and vise versa for increasing the pressure

i see all TEG units working with such low pressure except ours  , Also prosernat has made a "low" alarm if reboiler pressure is any lower than 4 psig.

[Art Montemayor]

Attya:

 

Are you still working under a Prosernat performance warranty?  What does their operating manual state about operating conditions and the Turndown ratio allowable in your MDEA absorber and TEG Contactor?  This is vital information that reveals how “tight” of a process design they furnished you with.  Please be frank and candid with us by telling us what communications you have had with Prosernat and their recommendations.  I have a suspicion that you have not established communications with Prosernat because of reasons of your own and that is why you are sharing your query with us.  As I have inferred before, a turndown of 20% of design capacity is a MAJOR change in the process design of any process plant and it can cause serious impacts on its performance.  That is why I have stressed the communication with the design / supplier of the units.

 

The internals of the MDEA absorber don’t worry me as much as the structured packing in the TEG contactor.  Tray design can be retro-modified in the field, but structured packing is more difficult to change.

 

As I have stated, assuming that Prosernat did a proper process design on the MDEA absorber and downstream vapor-liquid separator (V-2191), you should certainly not have any MDEA entrainment into the TEG contactor.  The high pH would also worry me and I would install a water spray either into the overhead pipe out of the MDEA absorber or in the downstream vapor-liquid separator.  This water would be separated and drained out at the vapor-liquid separator and its subsequent analysis would quickly tell you if there is any MDEA being carried over.  A water wash section is something I have always endorsed and used on amine absorbers and I am surprised one was not included in your plant.

 

Please read the paper I uploaded for you.  Propacket is correct; increasing the pressure in the TEG reboiler will cause you to consume more stripping gas to keep the specified Lean TEG purity (and therefore ensure the product gas dewpoint).  By lowering the reboiler pressure, you use less stripping gas and logically there will be less vapor volume going up the TEG still, through the top reflux condenser coil, and out of the system.  That being the case, there will be certainly less entrainment of TEG out of the still and to the flare.  The Lean TEG rates should be approx. 20% of the original design flow rate set by Prosernat.  That is one of the issues you should obtain from Prosernat – as well as the recommended MDEA circulation flow rate reduction.

 

Prosernat’s design might require a minimum of 4 psig in the reboiler because of the system’s pressure drop and the need to flow the exit gas + water vapor to the flare.  Again, this is an item that should be covered and described in the Prosernat Operating Manual.  If you don’t have all this vital design operating information discussed in the Operating Manual, then Prosernat should furnish you with the required information.  We on the Forum can’t do that because we are ignorant of the process design incorporated in your units.  What I have done in the past when confronted with a process that would not work as designed and the engineering contractor would not/could not help me resolve the problems (and this has happened many times) is that I undertook the responsibility to identify the process bottle necks and modify the design accordingly.  Sometimes when a process engineer in the field finds himself/herself at odds or in difficulties with the process engineering contractor, one has to take matters into ones hand in order to meet plant production requirements.  Lawyers and negotiators are not going to solve process problems for us; they complicate things even more by their delays and lack of interest.

 

 

[attya]

Mr.Art ,

i have contacted Prosernat multiple times , They barely answers ,

Last time i sent them an email (Regarding the difference in temperature between lean TEG and gas) it took them a month to answer ,

I'm only 2 years exprienced and i cannot take a decition on my own .

The senior engineer on plant decided to replace the entire TEG solution in plant , I tried to convience them to use a special company to clean the solution but it didnt work out , They replaced it

The first sample after 1 day of operation was TEG PH of 8.7  , and TEG purity of 98%

the 2nd sample after 2 days of operation was TEG PH of 8.8 , TEG purity of 99.29%

About water wash section , Yes i have seen this in every plant i have looked into  ,

 

I will try again to contact prosernat , And their manuals havent stated anything about the allowed turndown ratio .

 

 

Also i got one more technical concern :

 

For the Same Stripping gas rate  , and letting Lean TEG purity variable and subsequently the gas dew point ,

Does reducing reboiler pressure decrease or increase TEG losses ?

Edited by attya, 28 October 2013 - 12:42 PM.

[RockDock]

I don't see an amine wash above the amine absorber in your drawings. Adding a wash can potentially reduce your amine carryover rate significantly. While you should not have much MDEA carry over compared to MEA or DEA, you will have some.

 

There was a was a plant we helped solve a similar issue a few years back. We installed a water line directly into the the top of the column and reduced their MDEA losses by 99%. It's been working well for about 2 years now.

 

Basically, what we did was generate a ProMax model of both the amine and glycol units. Their amine unit was plain MDEA with no piperazine. So, they had a good amount of CO2 going to the TEG unit. After modeling we found that the TEG unit was massively over circulating the glycol and had high amounts of stripping gas. Their Hysys model had apparently shown that their circulation rate needed to be about 2x what ProMax predicted. Once we changed that, and added the water wash, the unit had no more build up of MDEA in the glycol.

 

I come across units like this all the time. It is bad design and operation using the wrong tools. These plants are just setting themselves up for failure.

 

One time, I was called out to another Prosernat designed amine plant. This one had a crazy amount of foaming right at startup. The plant was losing money daily, lost confidence in Prosenat to fix it and flew me to the site. It took about 30 minutes of modeling to see the problem - an order of magnitude problem in the amine circulation rate of MDEA! We made the change in the plant that day and all operations stabilized in a few hours.

 

Moral of the story: start with the basics. More times than not, it is a fundamental issue.

Edited by RockDock, 31 October 2013 - 10:44 AM.

[RockDock]

In case I wasn't clear, even 1 ppm MDEA carry over will accumulate in the TEG. It will most likely stabilize at a pH of about 9 if sour components exist and about 12 if they don't. So, you will have corrosion. The most likely place to see it is the reboiler. Any sour components will be vapor and your solution will be the most basic there.

 

Also, your amine absorber pressure will help determine the MDEA carry over.

[attya]

Mr RockDock , 

your reply was very helpful 

Can you please explain more how was the water line installed ?

Also @ the plant that was foaming , can you explain how was MDEA Circulation rate affecting the foaming ?

Also how would amine absorber pressure determine the amount of carry over ? We currently operate around 175 psig