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What is a Safe Wellbore Pressure While Drilling?

We already indicated that the safe mud weight window is between the formation fluid pressure and the formation fracturing pressure, and that we did this to avoid kicks, which is to prevent oil and gas from flowing into the well. Since wellbore fluids are circulated to the surface, the presence of oil and gas in these fluids can be dangerous – oil and gas are combustible, and they can contaminate the drilling mud or other areas if spilled. Another more serious risk, however, is that the presence of gas (and oil to a lesser degree) can change the density of the drilling mud. 

We just discussed that drillers use the density of the drilling mud to control the fluid pressure in the wellbore.  Gas bubbles might be 10 times less dense than the wellbore liquids around them, and as they displace liquids in the wellbore, the drilling fluid density goes down.

If the fluid density in the wellbore decreases, what happens to the downhole hydrostatic pressure?

It will increase


It will decrease


The hydrostatic pressure in the wellbore is a direct function of the wellbore fluid density.  If gas enters the wellbore, it lowers the wellbore fluid density, lowering the wellbore pressure, which then causes more gas to enter the wellbore. If this gas flow proceeds in an uncontrolled fashion, drillers can lose control of the density of the drilling fluid in the wellbore, which means they lose control of the pressure and ultimately the flow, which would lead to blowout.

It will stay the same


Flow from the formation to the wellbore is proportional to the pressure difference between the two.  As mentioned previously, fluids generally flow from high pressure to low pressure, so if the wellbore pressure goes below the formation fluid pore pressure (a condition drillers call underbalanced), the formation fluids will enter the wellbore. To prevent flow into the wellbore, drillers adjust the drilling mud density such that the hydrostatic pressure in the wellbore is equal to (balanced) or slightly greater than the formation fluid pore pressure (overbalanced).

Which of the following is true about overbalanced conditions?

Formation fluid pressure is greater than the wellbore pressure


Fluid flow actually goes from the wellbore into the formation


When conditions are overbalanced, the fluid pressure in the wellbore is greater than in the formation, and because flow goes from high pressure to low pressure, the flow direction is into the formation.

Gas is likely to enter the wellbore from the formation


All of the above


Drawbacks to Drilling Overbalanced

There are two potential drawbacks to drilling overbalanced:

  1. Given that fluid flow moves from high to low pressure, overbalanced conditions can cause unwanted flow of drilling mud from the wellbore into the formation, losing valuable drilling fluid into the formation and plugging up flow pathways in the formation in the new wellbore region. Excessive flow into the formation under these conditions is mitigated by included solids in the drilling mud such as clay which can create a filter cake (residue) on the wellbore wall inhibiting outward flow.
  2. Extreme overbalance may exceed the fracturing pressure of the formation, causing cracks in the formation that allow the drilling mud to escape the wellbore at high rate. This fluid loss could be so severe that it exceeds the rate at which drilling mud is being pumped into the well at the surface, causing the fluid level in the annulus to drop, preventing mud from coming back to the surface via the annulus in what is called “lost circulation”. 

Lost circulation causes the height of the hydrostatic column in the annulus of the wellbore to decrease, which can reduce the wellbore pressure so that it is less than the formation fluid pressure. Under these conditions, a kick is possible, which threatens well control as discussed earlier.

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