Flow Assurance Technical Section

Greetings,

SPE Professionals

Our one of the high pressure gas well behaves very differently from other gas wells. The well was drilled in 2021 and tested but it has not yet been taken into the production system for xyz reasons. During its PSP we observed that Max WHSIP was reported to be 2555psig, however when the well was flown at  48/64" averaged WHFP was reported to be 2405psig. When the C/size was decreased to 36/64" the averaged WHFP was 2580psig which is 25psig greater than the Max WHSIP. When the C/Size Futher decreased to 28/64" the averaged WHFP was reported to be 2610 which is 55psig greater than the Max WHSIP. I am amazed to see the WHFP is greater than the WHSIP. 
In your opinion what could be the various factors behind that ?

PS: During the testing (right after the completion of dry hole) the same scenario was observed and even during the latest PSP that was conducted last week of March 2023 this same thing happened. 

Looking forward to learning from your rich experience.

------------------------------
Profound Regards

Haris Ahmed Qureshi
Petroleum Engineer
Mari Petroleum Company Limited
Islamabad, Pakistan
Email Id: haris.ahmed@mpcl.com.pk
LinkedIn: pk.linkedin.com/in/harisqureshi1
Cell: +92 333 3507514
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Hello,

could you, please, specify at which conditions the CITHP was recorded? Long shut in or instantaneous shut in pressure? And do you see this effect only on 1 well, is that right? Is there any difference in insulation to the other wells, materials? I would be checking if the u-value is different on the well. If you have a higher tree insulation, you may run into a scenario of high instanteneous pressure at the near shut in conditions due to better insulation at the tree. 

Hello Ksenia,

The CITHP was recorded after long shut-in pressure since the well was already shut-in from Nov 2022. Yes, this effect can only be seen on this particular well, although wells with the same reservoir formation in a radius of ~1km do not show any such kind of behavior. The insulation/surface lines are the same for all these nearby wells. The u-value you are referring to is the temperature at the wellhead depending on total gas expansion on the surface resulting in the heat transfer coefficient. Even the Xmas trees used are of the same specs in all these wells because these wells were drilled in a row. 

------------------------------
Profound Regards

Haris Ahmed Qureshi
Petroleum Engineer
Mari Petroleum Company Limited
Islamabad, Pakistan
Email Id: haris.ahmed@mpcl.com.pk
LinkedIn: pk.linkedin.com/in/harisqureshi1
Cell: +92 333 3507514
------------------------------

Original Message:
Sent: 04-06-2023 01:00 AM
From: Ksenia Arkhipova
Subject: Reasons of WHFP greater than WHSIP ?

Hello,

could you, please, specify at which conditions the CITHP was recorded? Long shut in or instantaneous shut in pressure? And do you see this effect only on 1 well, is that right? Is there any difference in insulation to the other wells, materials? I would be checking if the u-value is different on the well. If you have a higher tree insulation, you may run into a scenario of high instanteneous pressure at the near shut in conditions due to better insulation at the tree. 

Sent from Yahoo Mail on Android

On Fri, 7 Apr 2023 at 12:02, PUNEET KISHORE<puneet_kishore25@yahoo.com> wrote: This phenomena is mainly due to presence of some liquid accumulation at bottom of the well. When well is flowed the liquid gets knocked out and thereafter on shut-in you get a higher shut in pressure. If there is gas -iquid contact near the well or some liquid ingress, liquid may build up again and Shut-in pressure may come down. This is natural phenomena observed in gas wells.

You can lower bottom hole pressure gage to record the gradient and bottom hole pressure and check presence of any liquid column at the bottom. Surface pressure data needs to be correlated with down-hole pressure data, both in flowing and shut-in conditions, then  understanding of well behaviou will be clear.


Regards.
Puneet Kishore. 
Sent from Yahoo Mail on Android


Original Message:
Sent: 4/6/2023 2:00:00 AM
From: Ksenia Arkhipova
Subject: RE: Reasons of WHFP greater than WHSIP ?

Hello,

could you, please, specify at which conditions the CITHP was recorded? Long shut in or instantaneous shut in pressure? And do you see this effect only on 1 well, is that right? Is there any difference in insulation to the other wells, materials? I would be checking if the u-value is different on the well. If you have a higher tree insulation, you may run into a scenario of high instanteneous pressure at the near shut in conditions due to better insulation at the tree. 

This phenomena is mainly due to presence of some liquid accumulation at bottom of the well. When well is flowed the liquid gets knocked out and thereafter on shut-in you get a higher shut in pressure. If there is gas -iquid contact near the well or some liquid ingress, liquid may build up again and Shut-in pressure may come down. This is natural phenomena observed in gas wells.

You can lower bottom hole pressure gage to record the gradient and bottom hole pressure and check presence of any liquid column at the bottom. Surface pressure data needs to be correlated with down-hole pressure data, both in flowing and shut-in conditions, then understanding of well behavior will be clear.

Regards.
Puneet Kishore. 

Sent from Yahoo Mail on Android


Original Message:
Sent: 4/6/2023 2:00:00 AM
From: Ksenia Arkhipova
Subject: RE: Reasons of WHFP greater than WHSIP ?

Hello,

could you, please, specify at which conditions the CITHP was recorded? Long shut in or instantaneous shut in pressure? And do you see this effect only on 1 well, is that right? Is there any difference in insulation to the other wells, materials? I would be checking if the u-value is different on the well. If you have a higher tree insulation, you may run into a scenario of high instanteneous pressure at the near shut in conditions due to better insulation at the tree. 

Thanks, Puneet for your valuable explanation.

------------------------------
Profound Regards

Haris Ahmed Qureshi
Petroleum Engineer
Mari Petroleum Company Limited
Islamabad, Pakistan
Email Id: haris.ahmed@mpcl.com.pk
LinkedIn: pk.linkedin.com/in/harisqureshi1
Cell: +92 333 3507514
------------------------------

Original Message:
Sent: 04-07-2023 10:43 AM
From: Puneet Kishore
Subject: Reasons of WHFP greater than WHSIP ?

This phenomena is mainly due to presence of some liquid accumulation at bottom of the well. When well is flowed the liquid gets knocked out and thereafter on shut-in you get a higher shut in pressure. If there is gas -iquid contact near the well or some liquid ingress, liquid may build up again and Shut-in pressure may come down. This is natural phenomena observed in gas wells.

You can lower bottom hole pressure gage to record the gradient and bottom hole pressure and check presence of any liquid column at the bottom. Surface pressure data needs to be correlated with down-hole pressure data, both in flowing and shut-in conditions, then understanding of well behavior will be clear.

Regards.
Puneet Kishore.

Sent from Yahoo Mail on Android



Original Message:
Sent: 4/6/2023 2:00:00 AM
From: Ksenia Arkhipova
Subject: RE: Reasons of WHFP greater than WHSIP ?

Hello,

could you, please, specify at which conditions the CITHP was recorded? Long shut in or instantaneous shut in pressure? And do you see this effect only on 1 well, is that right? Is there any difference in insulation to the other wells, materials? I would be checking if the u-value is different on the well. If you have a higher tree insulation, you may run into a scenario of high instanteneous pressure at the near shut in conditions due to better insulation at the tree. 

Greetings Haris,

Remember that Wellhead Pressure = Bottomhole Pressure minus Fluid Head (between Bottom Hole & Wellhead).    

If you had pressure sensors at the reservoir depth, I believe we'd both expect to see declining pressure as flow rate increased.  However, your shut-in conditions likely included a denser liquid column between reservoir and wellhead, which would have been lifted from the well when flowing.  If your well is highly productive (high PI or bbl/PSI drawdown) and had a denser column in the tubing when shut-in, the reduction in the fluid density can be greater than the reduction in bottom hole pressure, yielding a higher flowing wellhead pressure.  

As an example:
15000 ft gas well w/ 6500 PSI static BHP.  Gas gradient is 0.1 PSI/ft and water is 0.45 PSI/ft.
When shut-in, there is a 3000 ft water column at the base of the tubing, so WHSIP = 6500 PSI - 3000 x 0.45 - ((15000 - 3000) x 0.1) = 3950 PSI
When flowing, there is 500 PSI draw-down, so FBHP = 6000 PSI.  All the water has been lifted from the tubing, so WHFP = 6000 - 15000 x 0.1 = 4500 PSI.  

The fact that you had such a long shut-in may have provided an opportunity for water or other dense liquids to swap into the well fluids.  You may have also had residual completion or drilling fluids in the wellbore.  

I saw something similar years ago, in Nigeria, where we had some hugely productive wells.  We had a downhole gauge about 500 ft TVD above the formation, and there was brine between the gauge and formation in this newly completed well.  We had a very strict drawdown management plan at start-up, and we expected gauge pressure to drop as we flowed the well.  However, when I opened the choke and started unloading the well, the gauge pressure kept increasing (much like your well), and our plan was suddenly useless for managing this incredibly valuable well.  My poor SLB gauge engineer got an earful about bad data and needing to check his gauge coefficients, but eventually I realized that we were displacing dense brine with lighter oil, lessening the fluid head between the gauge and the reservoir, and this was more than offsetting the very small drawdown we had on the reservoir.  Everything acted normally once all the brine between reservoir and gauge was displaced.  I had to apologize to my gauge engineer after that ... his gauges (and everything else he did) worked flawlessly.  

There may be other explanations, but this may be the simplest. 

Good luck with your wells and stay safe!
R 

------------------------------
Ron Nelson
Subsea Completion Consultant
ron@deep-blue.ca
------------------------------

Hello Rob,

Thanks a ton for your help in clearing up my concept, especially the calculation part!

It was great to learn from your real-time experience.

Cheers
Haris

------------------------------
Profound Regards

Haris Ahmed Qureshi
Petroleum Engineer
Mari Petroleum Company Limited
Islamabad, Pakistan
Email Id: haris.ahmed@mpcl.com.pk
LinkedIn: pk.linkedin.com/in/harisqureshi1
Cell: +92 333 3507514
------------------------------

Original Message:
Sent: 04-06-2023 06:10 PM
From: Ron Nelson
Subject: Reasons of WHFP greater than WHSIP ?

Greetings Haris,

Remember that Wellhead Pressure = Bottomhole Pressure minus Fluid Head (between Bottom Hole & Wellhead).

If you had pressure sensors at the reservoir depth, I believe we'd both expect to see declining pressure as flow rate increased.  However, your shut-in conditions likely included a denser liquid column between reservoir and wellhead, which would have been lifted from the well when flowing.  If your well is highly productive (high PI or bbl/PSI drawdown) and had a denser column in the tubing when shut-in, the reduction in the fluid density can be greater than the reduction in bottom hole pressure, yielding a higher flowing wellhead pressure.

As an example:
15000 ft gas well w/ 6500 PSI static BHP.  Gas gradient is 0.1 PSI/ft and water is 0.45 PSI/ft.
When shut-in, there is a 3000 ft water column at the base of the tubing, so WHSIP = 6500 PSI - 3000 x 0.45 - ((15000 - 3000) x 0.1) = 3950 PSI
When flowing, there is 500 PSI draw-down, so FBHP = 6000 PSI.  All the water has been lifted from the tubing, so WHFP = 6000 - 15000 x 0.1 = 4500 PSI.

The fact that you had such a long shut-in may have provided an opportunity for water or other dense liquids to swap into the well fluids.  You may have also had residual completion or drilling fluids in the wellbore.

I saw something similar years ago, in Nigeria, where we had some hugely productive wells.  We had a downhole gauge about 500 ft TVD above the formation, and there was brine between the gauge and formation in this newly completed well.  We had a very strict drawdown management plan at start-up, and we expected gauge pressure to drop as we flowed the well.  However, when I opened the choke and started unloading the well, the gauge pressure kept increasing (much like your well), and our plan was suddenly useless for managing this incredibly valuable well.  My poor SLB gauge engineer got an earful about bad data and needing to check his gauge coefficients, but eventually I realized that we were displacing dense brine with lighter oil, lessening the fluid head between the gauge and the reservoir, and this was more than offsetting the very small drawdown we had on the reservoir.  Everything acted normally once all the brine between reservoir and gauge was displaced.  I had to apologize to my gauge engineer after that ... his gauges (and everything else he did) worked flawlessly.

There may be other explanations, but this may be the simplest.

Good luck with your wells and stay safe!
R

------------------------------
Ron Nelson
Subsea Completion Consultant
ron@deep-blue.ca
------------------------------