shooting fluid levels - obtaining down hole information esp wells

[rv13]

we are shooting fluid levels on esp wells with echometer
differences i should expect from normal rod pumped well

any differences in procedures and problems i should
expect ?

thank you

 

[TEXWS6]

Just remember that comparing rod pumps and ESP's are not equivalent. You need to keep SOME sort of constant fluid level with an ESP, opposed to none/minimal with a rod pump (pumped off).

A neat project we did was run actual BHP transducers with the ESP's and then shot fluid levels and then built a model to correlate BHP's across the field where we didn't have the tranducers installed.

 

[rv13]

thanks for your help
i thought i would adjust the hz in 30 minute intervals
and reshoot the fluid levels - what do you think?

we have about 30mscf/d gas
should i expect much loss in pump efficiency

do you think this gave you a good base line as far as bhp
over the field

 

[TEXWS6]

30mscf/d shouldn't be a problem. I've produced 3MMscfd of C02 per day through one without a downhole separator.

 

[d23]

Rv13

First I would suggest you discuss an appropriate test procedure for your well with your equipment supplier. Manufactures have been testing wells for the last 30 to 40 years, use their experience.

Changing speeds on a VFD every 30 minutes will usually result in very bad information. I would suggest you change speeds and let a well stabilize for an absolute minimum for 24 hours before shooting a fluid level and obtaining a test flow rate.

You did not give us enough information about your well to answer your question about gas rates. 30 MCF/D may or may not pose a problem. If you are only producing 100 Bbl of liquid per day and have 30 MCF the GLR is going to be 300 scf per bbl of liquid. If you have a 5 ½” casing, using 400 series equipment, the percent free gas after natural separation will be about 35%. A radial flow submersible pump impeller will not operate in that environment.

To make a reasonable recommendation your manufacture will need to know the expected liquid volume, expected gas volume, oil API, gas gravity, water gravity, bottom hole temperature, surface fluid temperature, the bubble point pressure, producing intake pressure, surface tubing pressure, surface casing pressure ect.

Using a pressure transducer with the submersible pump will offer better information than an echo meter. A pressure transducer includes the effects of water, oil and gas. With Echo Meters you must try to predict the effects of the oil, water and gas. Any prediction requires some assumptions that alter the accuracy.

Usually testing one well in a field will not offer much information about the rest of the wells in the field.

D23

 

[rv13]

thanks for the info.

this is a well with very little information
do not know brand of the pump or even if it has dh sensors

here is what i think i know
oil - 44
water - 1.05
surface tbg. pressure - 130
surface csg. pressure - 85
bhp - 1800 psi
production
20 oil
561 water
30 mscf gas

tbg. 2.88
csg. 9..63

your help & suggestions will be greatly appreciated / we have know choice but to use echometer initially

pump intake is 2000' above perfs. & 2300 above TD

 

[d23]

rv13

I’m guessing this is a west Texas well. With 41 degree API and 30 Mcf/D the GVF is only about 51.6 scf per bbl of liquid. In 9 5/8 casing you should not have much gas interference in the pump.

With 41 degree API you will likely have foam at the producing fluid level during operation. If at all possible you may want to dump about 2 to 3 bbls of produced water down the casing about 5 minutes before shooting a fluid level. The water will kill any possible foam. You will also need to record the casing pressure at the time of each fluid shot. I believe ECHO Meter now has software that predicts foaming, but dumping a little water eliminates the problem.

I would suggest you perform three operating test in about 5 hertz increments. Allow the well to stabilize at a fixed speed for 24 hours before shooting a fluid level. Get about a 1 hour flow test and multiply by 24 for your test flow rate during a stable pump operation.

At the end of the flowing test you should turn the well off for 24 hours and then shoot a static fluid level. Most customers don’t like turning off a unit for 24 hours, but that is the only way to develop an IPR for the well.

Regards,
D23

 

[rv13]

thanks for the great information, i greatly appreciate your time and information. my experience with esp assemblies is limited, but i am trying.

the pump intake is approximately 2000' above the perfs.
seems high

 

[TEXWS6]

That's not a west texas well with casing that size, that almost sounds like an offshore well. One of the largest and VERY rare production casing strings you'll see in W. Texas is 7". Heck, most people are running 9-5/8" for surface casing.

 

[rv13]

the above mentioned well - pump intake appears to be located in the gaseous liquid level of the well. the pump is currently operating at max. rpm & amps @ 60hz

there is no information available on the pump - the last pulling records do not make reference to the new pump installed - the previous pump was a 400 series/40hp motor
from a foreign country. assuming current assembly is close to the same design.

if the current assembly can not be lowered are there any other options. - lost for ideas

thanks

 

[rv13]

because of the cost of lowering the pump - assembly has
a 40 horse motor and is currently running at its max
i was thinking about reducing the hz in small
increments over a 90 day period allowing the the fluid
level to rise - placing the pump intake in a less gaseous
part of the fluid column