Author Archives: Well Control Quiz Team

The information of the well is listed below;

• In the well, there is no tubing string.
• The gas migrates to surface therefore the upper part of casing is full with gas.
• The casing pressure is 1200 psi.
• The main objective is to reduce casing pressure using lubricate and bleed procedure. 150 psi pressure increment and 150 psi safety factor are planned for this operation.

According to the lubricate and bleed procedure, what is the first step?

The information of the well is listed below (same as question 1);

• In the well, there is no tubing string.
• The gas migrates to surface therefore the upper part of casing is full with gas.
• The casing pressure is 1200 psi.
• The main objective is to reduce casing pressure using lubricate and bleed procedure. 150 psi pressure increment and 150 psi safety factor are planned for this operation.

According to the lubricate and bleed procedure, what is the second step?

In worker and completion operation, what are the minimum number(s) of recommended barriers?

For a normal bullheading performed on a producing well, what is the volume of kill fluid pumped into the well?

A normal annular preventer will seal pressure on the dual string completion when closed. Is it true?

What is the objective of the volumetric well control?

Gas migration rate in brine solution will typically faster than the migration rate in drilling mud.

Is this statement true?

Well bore influx (kick) is easier to detect in oil based mud as compared to water based mud.

Is this statement true?

Well information:  TD = 12,000’ MD / 10,000’ TVD.

Shut in tubing pressure = 500 psi.

Fluid weight in the tubing string = 4.0 ppg

What is the formation gradient (psi/ft) of a well?

What is the main function of subsurface safety valve ?

In workover operation, tripping speed is not important  while pulling out of hole the completion string because the completion brine has less viscous therefore the swabbing will not be happened.

Is this statement true?

What are the parameters which people should consider when determining the maximum pressure while bull heading?

Formation pressure is 6,220 psi at 10,000’ TVD. If we consider thermal expansion by heat from the well, what is the brine weight just to balance formation pressure?

After killing the well by bullheading, what should you do in order to hold constant pressure on the formation while you forward circulate to displace the annulus with kill weight mud?

The annulus is full of 11.5 ppg fluid and the tubing is full of 7.0 ppg fluid.

What should you do in order to reverse circulate the well with 11.5 ppg while maintaining bottom hole pressure constant?

The producing well is shut-in and the operator collect the following information from the well as listed below;

Shut In Tubing Pressure (SITP) = 4,500 psi

Formation fluid density = 2.0 ppg

Top of perforation = 12,000’ MD / 10,000’ TVD

What is the kill weight fluid required to kill this well?

Currently, gas migrates to the surface by using volumetric method, what should you do next?

15 bbl/hr of partial losses are recorded and there is no tubing in the well. If personnel fails to keep the hole full for 5 hours, what is bottom hole pressure reduction after 5 hours?

Casing capacity = 0.035 bbl/ft. Current mud weight = 9.2 ppg

Sub surface safety valve is recently tested and the result is goo. Personnel can just only shut the well in using sub surface safety valve without installing back pressure valve and then remove the x-mas tree.

Is it true?

Personnel observe that the annulus pressure on a producing well increases from 0 psi to 300 psi. The well has the packer set to isolate annuls.

What does this indicator tell you?

With gas migration in a shut in well, which one does not increase?

Which production tree valve should not be operated in normal operations?

As long as the fluid weight is more than formation pressure, you can use solid free brine to control the well which has high permeable zones.

Is this statement true?

While working over the well in a zone at 9,000’ TVD with 9.2 ppg fluid, the well is shut in.

Shut In Tubing Pressure = 600 psi

Shut In Casing Pressure = 800 psi

What is the kill weight mud for this well?