3 replies to this topic

[B-2 Spirit]

Dear All,

 

I am currently working on a Steam Assisted Gravity Draining project for recovering oil from oil sands.

First the reserviour pressure is reduced from 600 psig to 100-200 psig after which steam is injected to mobilize the oil in the oil sands, thus it can be pumped out.

 

I am facing a problem in deciding the design condition of piping & equipment handling production fluids from Tubing i.e. produced oil & water.

The reserviour conditions are as follows:

Fracture pressure = 1000 psig

at 1000 psig the steam sat temperature is 546°F so design conditions for the Casing is 1000 psig at 546 °F.

 

The piping d/s of the tubing connections sees the pressure generated by the pump which is approximately 160 psig at the well head. The temperature can be same as the steam temperature. The pump considered is a positive displacement pump and we are taking credit of High Pressure Trip of the pump to limit the design pressure required.

 

My Question is:

IS IT PRACTICALLY POSSIBLE TO GET CASING PRESSURE & TEMPERATURE IN THE TUBING? OR IS THE MECHANICAL CONSTRUCTION OF THE DOWNHOLE PUMP IS SUCH THAT IT WILL NEVER BE EXPOSED TO CASING PRESSURE & TEMPERATURE CONDITIONS.

the answer to this will decide whether we have to consider the casing design pressure and temperature condition for the production fluids ie.e oil + water in tubing from pump discharge.

 

It is somewhat different than the shut-in tubing pressure.

 

I am new to designing oil facilities & steam floods, so please excuse if I have used wrong terminologies.

 

thanks

B2Spirit.

[shan]

Reservoir fluids flow to the surface through oil well tubing.  The design conditions well casing and tubing should be identical.

[B-2 Spirit]

Thanks for your input Shan.

I agree with you that Tubing and Casing should have identical design conditions.

My question is about piping and equipment downstream of tubing.

Here we are having aritificial lift of well fluid by using positive displacement downhole pump. Their are two sources of overpressure in this case:

(1) Pump shut-off --- this we have mitigated by using high pressure trips.

(2) Overpressure from casing i.e. pump or stuffing box (sealing etc) failure and casing fluid getting into tubing.

 

I am not sure whether (2) is practically possible? is it always considered or never considered.

 

thanks
B2 Spirit

[shan]

Generally speaking, casing pressure reflects reservoir conditions and tubing pressure reflects production conditions. When a well is shutdown, its casing pressure and tubing pressure should be at the same value.  You may use max (1) & (2) as your design pressure.  Usually, casing, tubing, and flowline upstream wellhead coke design pressure values are much higher than anticipated conditions to count for uncertainties of reservoir.  Design pressure should be lower at some point of flowline downstream wellhead choke with protection of PSV.