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(OP)
How does wellhead Shut-in pressure could be determined?
The pressure gauge installed on the X-Tree has been reached to 1200 psig after a long period when the X-Tree output valve is close and there is not any flow from the well.
Can we say that the wellhead shut-in pressure is 1200 psig or for determine/calculate the WHSIP should be considered other parameters?
Replies continue below

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That is the well head shut in pressure, 1200 psig.

Einstein gave the same test to students every year. When asked why he would do something like that, "Because the answers had changed."

(OP)

#### Quote (Petroleum)

That is the well head shut in pressure, 1200 psig
dear petroleum
I agree with your point of view but the subsuface engineer says because of probability change of reservoir conditions in future, the actual wellhead shut-in pressure is grather than 1200 psig and is almost 1500 psig (based on their calculations).
my question is:
Is it possible that based on any reason that wellhead shut-in pressure increase with time?

It is possible that we'll head pressure will change. It usually reduces with production volume removed, but it can also increase. Even if bottom hole pressure remains constant, a lighter column of fluid in the production string, due to oil displacing water, or gas displacing either oil or water in the present production stream, means that there is less pressure to be subtracted from that same downhole pressure, resulting in higher surface pressures probably during both production and during shutin. If the future stream is predicted to contain more of either oil or gas than the present stream has, it is possible to register higher surface production and shutin pressures. It is also possible that downhole pressure increases or decreases later on, perhaps due to water, or oil entering or leaving the formation, thereby changing the hydrostatic head making up the downhole pressure.

During production, there are additional flow losses to consider, so depending on flow rate, string diameter(s) and flowing Pressure drop, surface pressure could go either way. That will be highly dependent on Reservoir fluid contents, rock characteristics, string design and the expected optimum reduction rate. Your reservoir engineer probably knows best what to expect. He has all the information, so believe him, at least until proven wrong.

Of course if injection will be used, well pressures will probably increase everywhere.

At least it is usually easier to design for higher pressures later than it is to design for lower pressures later on.

Einstein gave the same test to students every year. When asked why he would do something like that, "Because the answers had changed."

I agree with all of that from Mr 44.

Your biggest possibility is change of the fluid in the well bore over time ( more gas migrates to the top) or that either water or gas injection into the reservoir is raising the overall field pressure.

Remember - More details = better answers
Also: If you get a response it's polite to respond to it.

(OP)

#### Quote:

Of course if injection will be used, well pressures will probably increase everywhere.
There is not any water/gas injection or gas lift or ESP pump in the site.

#### Quote:

or that either water or gas injection into the reservoir is raising the overall field pressure.
There is not any water/gas injection or gas lift or ESP pump in the site.

Dear friends
Basically I need the wellhead Shut-in pressure value to design and determine the maximum allowable working pressure of the flow line.(down stream of X-tree). which pressure should be consider to calculate the MAWP of the flowline? 1200 psig or 1500 psig? there is not any HIPPS or PSV on the flowline therefor the flowline design pressure shall be calculated based on wellhead Shut-in pressure. Based on my company spec: MAWP of the flowline = WHSIP + 20 psi

my question is: MAWP is 1220 psig or 1520 psig?

It would seem that a prudent designer would select the maximum well shutin pressure predicted to occur over the expected useful lifetime of the well.

It is strange that your design guide apparently does not address such a basic requirement.

Einstein gave the same test to students every year. When asked why he would do something like that, "Because the answers had changed."

If you dont have a custom B31.4 pipeline to transport these fluids, and all downstream piping is B31.3, why not use 1350psig, which is the upper limit of class 600lb at design temp of 200degF for carbon steel?

Work with the WHSIP value in the basis of design document for the field development. That value to be inserted by the "subsurface engineer"

Steve Jones
Corrosion Management Consultant

All answers are personal opinions only and are in no way connected with any employer.

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