Causes of Kick (Wellbore Influx)

A “Kick” or “Wellbore Influx” is undesirable flow of formation fluid into the wellbore and it happens when formation pressure is more than hydrostatic pressure in wellbore.

Deepwater Horizon offshore drilling unit on fire 2010

Deepwater Horizon offshore drilling unit on fire 2010 (Wiki)

Several causes of Kick (Wellbore Influx) are listed below:

1. Lack of knowledge and experience of personnel (Human error)– Lacking of well-trained personnel can cause well control incident because they don’t have any ideas what can cause well control problem. For example, personnel may accidentally pump lighter fluid into wellbore and if the fluid is light enough, reservoir pressure can overcome hydrostatic pressure.

2. Light density fluid in wellbore It results in decreasing hydrostatic pressure. There are several reasons that can cause this issue such as

• Light pills, sweep, spacer in hole

• Accidental dilution of drilling fluid

• Gas cut mud

3. Abnormal pressure – If abnormally high pressure zones are over current mud weight in the well, eventually kick will occur.

4. Unable to keep the hole full all the time while drilling and tripping. If hole is not full with drilling fluid, overall hydrostatic pressure will decrease.

5. Severe lost circulation – Due to lost circulation in formation, if  the well could not be kept fully filled all the time, hydrostatic pressure will be decreased.

Lost circulation usually caused when the hydrostatic pressure of drilling fluid exceeds formation pressure. There are several factors that can cause lost circulation such as

• Mud properties – mud weight is too heavy and too viscous.

• High Equivalent Circulating Density

• High surge pressure due to tripping in hole so fast

• Drilling into weak formation strength zone

6. Swabbing causes reducing wellbore hydrostatic pressure.

Swabbing is the condition that happens when anything in a hole such as drill string, logging tool, completion sting, etc is pulled and it brings out decreasing hydrostatic pressure. Anyway, swabbing can be recognized while pulling out of hole by closely monitoring hole fill in trip sheet.

Reference book: Well Control Books

Boyle’s Gas Law and Its Application in Drilling

Understand Boyle’s Gas Law

Boyle’s gas law states that at constant temperature, the absolute pressure and the volume of a gas are inversely proportional in case of constant temperature within a closed system.  Bolye’s law can be illustrate in the graph shown in figure 1.

Figure 1 – Boyle’s Law

Well, we can describe the statement above into simple mathematics as following formula:

Boyle’s Gas Law

P x V = constant

Or express Boyle’s law in another term:

P1 x V1 = P2 x V2

Where;

P1 = Pressure at condition # 1

 V1 = Volume at condition # 1

P2 = Pressure at condition # 2

 V2 = Volume at condition # 2

Note: You can use any unit for Bolye’s gas law as long as P1 and P2 are the same unit and V1 and V2 are the same unit.

Let’s apply Boyle’s law into our drilling business

Calculate the volume of gas you will have on the surface, 14.7 psi for atmospheric pressure, when 1 bbl of gas kick is circulated out from reservoir where has formation pressure of 3,000 psi. Figure 2 and 3 shows the condition of this well.

Figure 2 – Gas Kick 1st condition at the bottom

Figure 3 – Gas Kick 2nd condition

Apply the Boyle’s Gas Law:

P1 x V1 = P2 x V2

P1= 3000 psi (reservoir pressure)

V1 = 1 bbl (volume at bottom hole)

P2 = 14.7 psi (atmosphere pressure)

V2 = ? (volume at surface)

P1 x V1 = P2 x V2

3000 x 1 = 14.7 x V2

V2 = 204 bbl

Figure 4 – Gas

References

Cormack, D. (2007). An introduction to well control calculations for drilling operations. 1st ed. Texas: Springer.

Crumpton, H. (2010). Well Control for Completions and Interventions. 1st ed. Texas: Gulf Publishing.

Grace, R. (2003). Blowout and well control handbook [recurso electrónico]. 1st ed. Paises Bajos: Gulf Professional Pub.

Grace, R. and Cudd, B. (1994). Advanced blowout & well control. 1st ed. Houston: Gulf Publishing Company.

Watson, D., Brittenham, T. and Moore, P. (2003). Advanced well control. 1st ed. Richardson, Tex.: Society of Petroleum Engineers.

Let’s apply U-Tube concept

After learning about U-tube concept, let’s get a example in order to understand clearly about physical meaning of U-tube. This is very important concept so you need to clear about it.

Mud weight inside drill pipe is 9.8 PPG is all the way to bit and mud weight in the annulus is 9.2 PPG all the way to surface. Hole depth is 10,000’MD/8500’TVD. The well is shut in and drill pipe pressure is equal to 0 psi. Determine casing pressure.

According to U-tube concept, both sides (casing and drill pipe) have the same bottom hole pressure so we can write the equation to describe the U-tube concept as shown below;

SP (casing) + HP (casing) = BHP = SP (drill pipe) + HP (drill pipe)

At drill pipe side: BHP = 0 psi (Drill pipe Pressure) + 0.052×9.8×8,500 (Hydrostatic Pressure at drill pipe side) = 4,331 psi

At casing side: BHP = 4,331 psi = (Casing Pressure) + 0.052×9.2×8,500 (Hydrostatic Pressure at casing)

With this relationship (SP (casing) + HP (casing) = BHP = SP (drill pipe) + HP (drill pipe) ),we can solve casing pressure.

4331 = Casing Pressure + 4066

Casing Pressure = 4331 – 4066 = 265 psi

U tube

Ref books: 

Lapeyrouse, N.J., 2002. Formulas and calculations for drilling, production and workover, Boston: Gulf Professional publishing.

Bourgoyne, A.J.T., Chenevert , M.E. & Millheim, K.K., 1986. SPE Textbook Series, Volume 2: Applied Drilling Engineering, Society of Petroleum Engineers.

Mitchell, R.F., Miska, S. & Aadny, B.S., 2011. Fundamentals of drilling engineering, Richardson, TX: Society of Petroleum Engineers.

Understand U-Tube Concept and Importance of U-Tube

We can use the behavior of one of the fluid columns to describe behavior regarding what is happening in another side of fluid column, if two fluid columns are connected at bottom. Basically, this situation is simply described in common oil field name as “U Tube”.

In oil field especially drilling business, “U Tube” can be considered as a string of pipe (drill pipe and tubing) is in a wellbore and fluids are able to pass inside of string of pipe (drill pipe and tubing) and the annulus (area between wellbore and string of pipe). The figure 1 below demonstrates “U Tube” in our drilling business.

Figure 1 - U-Tube Diagram Represents Both Sides of Fluid Columns

Figure 1 – U-Tube Diagram Represents Both Sides of Fluid Columns

A horizontal tube connects the right-hand side of the U-Tube and fluid levels in both columns should equalize when a fluid with consistent density is added. Furthermore, the hydrostatic pressure should be equal at the bottom of both columns. The pressure found at the base of both columns is considered ‘bottomhole pressure’. To replicate the opening through the nozzles in the bit, the opening at the base exists.

The mathematical relationship for this is shown below;

BHP = HP + SP

Where;

BHP = bottomhole pressure

HP = hydrostatic pressure

SP = surface pressure

With the U-tube concept applied, both sides of fluid columns can be described with the equation below;

 BHP = SIDPP + HP string = SICP + HP annulus

Where;

BHP = bottomhole pressure

SIDPP = shut in drillpipe pressure

HP string = hydrostatic pressure  in drill string

SICP = shut in casing pressure

HP annulus = hydrostatic pressure in annulus

When fluid density in both columns is equal, U-Tubes can be relatively simple. Surface pressures on the drillpipe and casing sides will be the same when the drillpipe and casing are themselves full of the same fluid density. However, U-Tubes become more difficult when fluids with varying densities are found in the columns. Despite the same BHP, both HP and SP will differ.

With hydrostatic and surface pressure equal in both columns, U-Tubes aren’t too interesting because both columns are filled with fluids of the same density. For example, when the annulus and drillpipe contain the same weight drilling mud while a bit is run to the hole’s bottom. The hydrostatic pressure is equal at both the casing and drillpipe side, fluid levels are static at the top, and the surface pressure on the drillpipe and casing sides are zero.

On the other hand, when columns are occupied by fluids of different densities, there’s likely to be a difference in both surface pressure and hydrostatic pressure in both columns (drillstring and casing side). For example, this is commonly seen in a kick with the bit on bottom as you can see from the figure 2 diagram. As formation pressure increases above hydrostatic pressure (generated by mud in the well), it kicks. The well will stop flowing if it’s shut-in; a surface pressure on the drillpipe gauge is then a reflection of the pressure underbalance. As opposed to drilling mud in the annulus, the fluid now contains lighter weight formation fluid and this leads to a reduction in total hydrostatic pressure (within the annulus). The shut-in casing pressure increases above shut-in drillpipe pressure to compensate to the underbalanced in the annulus side compared to the drillpipe side.

Figure 2 - U-Tube Diagram Represents Both Sides of Fluid Columns with Gas Kick

Figure 2 – U-Tube Diagram Represents Both Sides of Fluid Columns with Gas Kick

Why is U-Tube very important?

It is very vital to keep a basic concept of U-Tube in mind.

If there are two different fluids between inside of string and annulus, fluids always flow from a higher pressure area to a lower pressure.

If the system is NOT closed, lighter fluid will be flown out and it will be stopped when system pressure is stabilized (see the figure 3 below).

Figure 3 - U-Tube Diagram Represents Both Sides of Fluid Columns Without a Closed System

Figure 3 – U-Tube Diagram Represents Both Sides of Fluid Columns Without a Closed System

If the system is closed, for example the well shut in, pressure must be the same at the bottom point where both sides of U-tube are connected . Therefore, drill pipe pressure and casing pressure (annulus pressure) will be responded based on fluid in each side and formation pressure at bottom hole (see the figure 4 below).

Figure 4 demonstrates different in hydrostatic pressure between drill pipe and casing when mud weight 9.8 ppg is pumped to the bit and the well is shut in. This example helps understand how to use the equation to solve the problem.

The calculation is shown below.

BHP = SIDPP + HP string = SICP + HP annulus

BHP = 0 + (0.052 × 10,000  × 9.8) = 5,096 psi

5,096 psi = SICP + (0.052 × 10,000  × 9.2)

5,096 psi =  SICP + 4,784 psi

SICP = 312 psi

Note – you can find more information about hydrostatic pressure calculation here – Understand Hydrostatic Pressure

Figure 4 - U-Tube Diagram Represents Both Sides of Fluid Columns With a Closed System

Figure 4 – U-Tube Diagram Represents Both Sides of Fluid Columns With a Closed System

The U-Tube concept can be widely applied in many drilling and workover application such as well control, cementing, hole monitoring, pulling out of hole, pumping slug, etc.

Ref books: 

Lapeyrouse, N.J., 2002. Formulas and calculations for drilling, production and workover, Boston: Gulf Professional publishing.

Bourgoyne, A.J.T., Chenevert , M.E. & Millheim, K.K., 1986. SPE Textbook Series, Volume 2: Applied Drilling Engineering, Society of Petroleum Engineers.

Mitchell, R.F., Miska, S. & Aadny, B.S., 2011. Fundamentals of drilling engineering, Richardson, TX: Society of Petroleum Engineers.

Bottom Hole Pressure Relationship

This article will show you about bottom hole pressure relationship because this concept is very important for well control concept. The bottom hole pressure is a summation of all the pressure acting on the bottom hole.

Bottom Hole Pressure (BHP) = Surface Pressure (SP) + Hydrostatic Pressure (HP)

The image below demonstrates the relationship of bottom hole pressure.

Note: BHP created by hydrostatic column of drilling fluid is the primary well control in drilling.

Looking more into details,

If BHP is more than FP (formation pressure), this situation is called “Overbalance”.

If BHP is equal to FP (formation pressure), this situation is called “Balance”.

If BHP is less than FP (formation pressure), this situation is called “Underbalance”.

For more understanding, please follow this example below it demonstrates the relationship of BHP, SP and HP.

Bottom Hole Pressure (BHP) = Surface Pressure (SP) + Hydrostatic Pressure (HP)

Bottom Hole Pressure Relationship 2

We assume that formation pressure is normal pressure gradient of water (0.465 psi/ft) so formation pressure at 8000’ TVD = 8000 ft x 0.465 psi/ft = 3720 psi. Click here to learn how to calculate hydrostatic pressure in oilfield.

The first case: Hydrostatic column is water which is equal to formation pressure gradient so SP is equal to 0 psi

The second case: BHP is still be water gradient but fluid column is oil (0.35 psi/ft) which is lower density than water gradient (0.465 psi/ft). Therefore, in order to balance BHP, we need Surface Pressure (SP) of 920 psi (SP = 3720 – (0.35 x 8000)).

The third case: BHP is still be water gradient but fluid column is gas (0.1 psi/ft) which is even lower density than water gradient (0.465 psi/ft). Therefore, in order to balance BHP, we need Surface Pressure (SP) of 2,920 psi (SP = 3720 – (0.1 x 8000)).

According to the example, Surface Pressure (SP) will compensate the lack of hydrostatic pressure (HP) in order to balance formation pressure (FP).

References

Cormack, D. (2007). An introduction to well control calculations for drilling operations. 1st ed. Texas: Springer.

Crumpton, H. (2010). Well Control for Completions and Interventions. 1st ed. Texas: Gulf Publishing.

Grace, R. (2003). Blowout and well control handbook [recurso electrónico]. 1st ed. Paises Bajos: Gulf Professional Pub.

Grace, R. and Cudd, B. (1994). Advanced blowout & well control. 1st ed. Houston: Gulf Publishing Company.

Watson, D., Brittenham, T. and Moore, P. (2003). Advanced well control. 1st ed. Richardson, Tex.: Society of Petroleum Engineers.