7 replies to this topic

[jawa]

Dear All,

Please advise when I should use the omega method recommended by API for two phase relief valve sizing. Instead, Could I add individual phase relief load areas to arrive at the two phase flow relief area. Will such calculation lead to a large error?

[JoeWong]

Jawa,
More than 9 years ago, common method for two phase relief is additional of gas and liquid relief area. With the released of API RP 521 2000, Joseph Leung OMEGA method is recommended for two phase relieve. Recently API STD 521 2008, HDI method (proposed by Dr. R. Darby) considering thermal and mechanical equilibrium is recommended (whilst maintaining OMEGA two point method for specific condition).

Of course, if you think the two phase relief is deviated very much from thermal and mechanical equilibrium, probably you have employ HNDI, HFM, HNI, etc.

I strongly recommend you to keep up with latest recommendation.

[jawa]

Joe,

I did try the APIOmega Method and conclude there is a vast difference in the calculated areas from the Old API method.

The reason I intended to use the Old method wa s to avoid estimating critical pressures, for different cases of wellfluid compositions, required by the New API Omega procedure. I had performed Hysys simulation for a wellhead platform and for different compositions of wellfluid i arrived at different critical pressures largely deviating from each other. So, with these uncertainities in critical pressures i could not conclude from the different relief areas determined for the PSV on the Test Manifold and Export lines.

However, with a program which did not require me to input this critical parameters, I arrived at relief areas which was close and reasonable.

Another question:

As per API 520 methods, the basis for determining relief valve type, conventional or bellows type shall be established by the back pressure value.

Total Back pressure at the relief valve outlet is determined by the sum of built-up backpressure and the backpressure due to the system(relief/vent header) receiving the load.

However could you please clarify if total backpressure should be considered as less than 10% of set pressure or built up backpressure shall be less than 10% of set pressure to consider for a conventional valve type qualification. API sometimes is unclear.

Your valuable comments appreciated.

Thanks

Jawa

[fallah]

However could you please clarify if total backpressure should be considered as less than 10% of set pressure or built up backpressure shall be less than 10% of set pressure to consider for a conventional valve type qualification. API sometimes is unclear.

Build-up back pressure shall be less than 10% of set pressure at 10% allowable overpressure in a conventional PSV (as per API RP 520 7th Ed. 3.3.3.1.3).

Actually conventional PSV is used in the services with constant superimposed back pressure lower than 10% of set pressure that can be compensated by adjusting the cold differential set pressure (spring load reduction).

Generally total back pressure in a conventional PSV shall not be greater than the calculated critical flow pressure,othrewise its capacity would be affected by the back pressure since flow will be subsonic.

[JoeWong]

I did try the APIOmega Method and conclude there is a vast difference in the calculated areas from the Old API method.

The reason I intended to use the Old method wa s to avoid estimating critical pressures, for different cases of wellfluid compositions, required by the New API Omega procedure. I had performed Hysys simulation for a wellhead platform and for different compositions of wellfluid i arrived at different critical pressures largely deviating from each other. So, with these uncertainities in critical pressures i could not conclude from the different relief areas determined for the PSV on the Test Manifold and Export lines.

However, with a program which did not require me to input this critical parameters, I arrived at relief areas which was close and reasonable.

There have been a lot of studies proved that using the "addition" method potentially under-estimate relief valve sizes. Thus, newer methods i.e. Dr. Leung's Omega (1 point method and/or 2 points method), HDI by Prof. R. Darby, etc have been evaluated seriously. Many experts in the API 521 task force have discussed in depth and come to some agreement and "advise" to use these method (in general two phase relief application).

One very important fact link to apllication of these methods is the thermal and mechanical equilibrium assumption. Any engineer shall evaluate carefully the fluid characteristic, flowing pattern, etc and decide if these recommended methods shall be used or more sophisticated method shall be used.

I believe as engineer, you shall conduct the evaluation which method to use (by considering the recommended method in API as minimum). Ignoring the "recommended method" due to insufficient fluid information may not be acceptable in my opinion. It is process engineer responsibility to provide the best guess (and conservative) of fluid information.

There is no different between "provide an undersized PSV" and "without PSV" from overpressure perspective.

As per API 520 methods, the basis for determining relief valve type, conventional or bellows type shall be established by the back pressure value.

Total Back pressure at the relief valve outlet is determined by the sum of built-up backpressure and the backpressure due to the system(relief/vent header) receiving the load.

However could you please clarify if total backpressure should be considered as less than 10% of set pressure or built up backpressure shall be less than 10% of set pressure to consider for a conventional valve type qualification. API sometimes is unclear.

Your valuable comments appreciated.

I believe Fallah has given you some good points.


There have been many terms related to "backpressure" used :
i) Back pressure
ii) Built-up back pressure
iii) Superimposed back pressure
iv) Variable back pressure
v) Constant back pressure
.
.
.

Let make the definition clear. Let's look at the definition in API STANDARD 520, EIGHTH EDITION, DECEMBER 2008.

3.3
backpressure
The pressure that exists at the outlet of a pressure relief device as a result of the pressure in the discharge system.
Backpressure is the sum of the superimposed and built-up backpressures.

3.7
built-up backpressure
The increase in pressure at the outlet of a pressure relief device that develops as a result of flow after the pressure relief device opens.

3.53
superimposed backpressure
The static pressure that exists at the outlet of a pressure relief device at the time the device is required to operate. Superimposed backpressure is the result of pressure in the discharge system coming from other sources and may be constant or variable.

Above terms are pretty clear from Pressure relief device (process engineer view).
Backpressure (PB) = superimposed backpressure (PBs) + built-up backpressure (PBbu)


Extracted from 5.3.3.1.3
"In a conventional PRV application, built-up backpressure should not exceed 10 % of the set pressure at 10 % allowable overpressure. A higher maximum allowable built-up backpressure may be used for allowable overpressures greater than 10 % provided the built-up backpressure does not exceed the allowable overpressure.
"

For conventional PSV, there is area difference between the disc facing nozzle and outlet chamber. Any increase in built up backpressure will reduce the lifting force of the PSV and subsequently reduce the relieve flow. Above is typical value (shall always confirm with vendor).

[jawa]

Dear Joe/Fallah,

Thank you very much for this information. However, let me cite my application. This is an offshore wellhead platform with a vent system designed for a maximum allowable backpressure of 8 barg. The PSV under investigation is on the Test Manifold relief and the set pressure is 77 barg. The PSV selected was a pilot operated type.

The Built up back pressure for this case was 5.73 barg, calculated from the PSV outlet to the atmospheric vent tip. Considering the set pressure, 77 barg, why could not a Conventional PSV be recommended?

Please advise.

Jawa

[JoeWong]

Dear Joe/Fallah,

Thank you very much for this information. However, let me cite my application. This is an offshore wellhead platform with a vent system designed for a maximum allowable backpressure of 8 barg. The PSV under investigation is on the Test Manifold relief and the set pressure is 77 barg. The PSV selected was a pilot operated type.

The Built up back pressure for this case was 5.73 barg, calculated from the PSV outlet to the atmospheric vent tip. Considering the set pressure, 77 barg, why could not a Conventional PSV be recommended?

Please advise.

Jawa

Jawa,
Your initial question was related to application of Additional method for two phase relief calculation. And now your question is related to type of PSV.

I strongly encourage you to open a new thread in order to keep present thread short, dedicated, easy search, etc. Remember to provide background and information. Don't expect others to look for information from different thread.

[fallah]

Dear Joe/Fallah,

Thank you very much for this information. However, let me cite my application. This is an offshore wellhead platform with a vent system designed for a maximum allowable backpressure of 8 barg. The PSV under investigation is on the Test Manifold relief and the set pressure is 77 barg. The PSV selected was a pilot operated type.

The Built up back pressure for this case was 5.73 barg, calculated from the PSV outlet to the atmospheric vent tip. Considering the set pressure, 77 barg, why could not a Conventional PSV be recommended?

Please advise.

Jawa

Jawa,
Your initial question was related to application of Additional method for two phase relief calculation. And now your question is related to type of PSV.

I strongly encourage you to open a new thread in order to keep present thread short, dedicated, easy search, etc. Remember to provide background and information. Don't expect others to look for information from different thread.

Jawa,

While i am fully agreed with Joe Wong viewpoint,below you will see the reasons for using pilot operated PSV in your case:

-Max. back pressure is higher than 10% of the set pressure

-The back pressure with a maximum value seems to be variable