to minimize influx (kick)

Kick Penetration For Stripping Operation Kick penetration is one of the most critical concerns for stripping operation because a kick height will change due to change of hole geometry. In this this article, we will describe about this situation.

This is will be happened when the string penetrates the kick.Height of influx will increase when the drillstring penetrates a kick; therefore, hydrostatic pressure decreases and casing pressure increases in order to compensate this situation.If the casing is maintained constant while penetrating the kick, you will have high chance to take more influx because of underbalance situation (Figure 1). This article will teach you about how to determine pressure increment while penetrating into the kick, what to look for, etc.

Figure 1 – Height of Influx increases when the drillstring penetrates into it.

However, if the constant surface pressure is utilized for the stripping operation, you must account for pressure increment due to height of influx change. The equation below is for calculating the increase in casing pressure.

∆CP = ∆H x (MG – KG)

Where: ∆CP = Increase in casing pressure, psi∆H = Change in length of influx, ftMG = Mud Gradient, psi/ftKG = Kick Gradient, psi/ftThe example below demonstrates how to calculate casing pressure increase.Hole TD = 12,000’MD/12,000’TVDHole size =11.75”Drill pipe = 5”Drill collar = 6.5”Drill collar length = 800 ftPit gain = 35 bblMud weight = 12.0 ppgKick gradient = 0.3 psi/ft

Figure 2 illustrates this situation when the string is off bottom.

Hole capacity = 11.752 ÷ 1029.4 = 0.134 bbl/ft

Kick Height in open hole =35 ÷ 0.134 = 261 ft

Hole and 6.5” drill collar capacity = (11.752 -6.52) ÷ 1029.4 = 0.0931 bbl/ft

Kick Height in annulus between hole and DC = 35 ÷ 0.0931 = 376 ft

Mud gradient = 12.0 x 0.052 = 0.624 psi/ft

Kick gradient = 0.3 psi/ft

Figure 2 – Calculation Example for This Situation

Casing pressure increasing is calculated by this following equation.

∆CP = ∆H x (MG – IG)∆CP = (376 – 261) x (0.624 – 0.3)

∆CP = 37 psi

Figure 3 – Casing Pressure Increase Due To Kick Penetration

The increase in casing pressure required for this scenario is 37 psi. This figure tells you that you need to let casing pressure increase by 37 psi in order to compensate to hydrostatic loss.

Practically, you should have the safety factor which is greater than casing pressure increase required for kick penetration and for this case, the safety factor must be more than 37 psi. This will prevent the underbalance situation when the influx is penetrated and you don’t need to worry about the time when the influx penetration will actually happens.

For gas kick, it is impossible to use either the constant pressure method or the volume accounting method because gas will migrate. You must have the method to control the bottom hole pressure and deal with increase in surface pressure due to gas migration. For gas kick, the volumetric control stripping technique must be used. This technique will account for volume of pipe bled back and surface pressure increase. We will discuss this technique separately in a next topic.

Stripping Procedure with Volumetric Control For Migrating Kick

With gas kick in the well, the conventional stripping method is not application because it won’t account for the gas migration and expansion; therefore, the special stripping procedure, Stripping with Volumetric Control, will be utilized for this case. This procedure is designed to strip the drill string back into the well with gas influx while the bottom hold pressure is maintained nearly constant.

Figure 1 – Stripping With Volumetric Control

The Stripping with Volumetric Control procedures are as follows:

1. Calculations

Determine whether the drillstring weight is over the pressure force pushing upwards

Select required Pressure Increment (PI)

Select Safety Factor (SF) Determine Mud Increment (MI)Mud Increment (MI) is calculated by the following equation

Where;

MI = Mud Increment (MI), bbl

PI = Pressure Increment (PI), psi

ACF = annular capacity factor, bbl/ft

MW = mud weight, ppg

Determine how many feet that you need to strip to penetrate the kick. This calculation must be account for gas migration and stripping speed. You can read more details here –

Determine pressure increase when the drillstring penetrate the kick. You can read more details about this topic here –Kick Penetration For Stripping Operation

2. Stab a safety valve (full opening safety valve) and follow by an IBOP valve.

Figure 2 – Stab a safety valve and IBOP

3. Ensure no leakage between connections.

4. Adjust the closing pressure to allow the stripping operation.

5. Strip the drillstring into the well until the casing pressure increase by Safety Factor (SF) + Pressure Increment (PI). No bleeding off during the step#4.

6. Maintain constant casing pressure by bleeding off fluid while stripping until the difference between the drillstring displacement and the actual mud bled back equals to Mud Increment (MI).

7. Strip into the well without bleed off fluid until the casing pressure increases by Pressure Increment (PI).

8. Repeat step#6 and #7 until the drillstring penetrates the gas kick. Once the gas kick is penetrated, you need to allow casing pressure increased by pre-

determined figure. This is will be your new casing pressure. Practically, you can add the pressure increase caused by the kick penetration into the safety factor and use the mud increment based on the volume between drillstring and the casing. This will be the conservative way which can prevent you to be in an underbalanced condition.

9. Strip into the desired depth by repeating step#6 and #7.

Stripping Procedure without Volumetric Control for Non-Migrating InfluxThis article will teach you about the stripping procedure for non-migrating kick. This procedure is used to strip to desired depth but it won’t account for volumetric bleed therefore it is mainly applicable for stripping with non-migrating kicks as water or oil.

The stripping procedures are as follows;

Figure 1 – Stripping to the bottom with non-migrating kick

1. Calculations Determine whether the drillstring weight is over the pressure force pushing

upwards. Determine how many feet that you need to strip to penetrate the kick Determine pressure increase when the drillstring penetrate the kick. Determine safety factor. If you plan to use the constant surface pressure method

for the stripping operation, the safety factor added into the system must be sufficient to compensate the effect of influx penetration.

Determine volume bleed back per stand if you plan to use the volume accounting method.

2. Stab a safety valve (full opening safety valve) and follow by an IBOP valve.

Figure 2 – Stab a safety valve and IBOP

3. Ensure no leakage between connections.

4. Adjust the closing pressure to allow the stripping operation.

5. Strip the drillstring into the well until you get the desired safety factor. While stripping, small volume of fluid leakage around the pipe is a good sign because the closing pressure is not too much but the leak must stop when the stripping operation is stopped.

Figure 3 – Stripping with adjusted closing pressure

6. Strip to the required depth based on your selected method. You have a choice to use either the volume accounting or the constant surface pressure. You can read more details about these two methods from this article “Stripping Methods for Non Migration Kicks When There is an Off Bottom Well Control”.

Volumetric Well Control Example CalculationsThis example demonstrates the calculations and the steps of the volumetric well control which will help you understand about what calculations according to the volumetric procedures.

Gas kick at the bottom but unable to circulate due to drillstring plugged off. The well control information is listed below;

Pit gain = 10 bbl Shut in Drill Pipe Pressure = 0 psi (drillstring plugged) Shut in Casing Pressure = 400 psi Current mud weight = 11.0 ppg Casing shoe depth = 6,000’MD/6,000’TVD Hole TD = 9,000’MD/9,000’TVD Hole size = 12.25” Casing ID = 12.5” Drill pipe size = 5”, 19 ppf BHA consists of 6.5” drill collar Length of BHA = 800 ft Average pipe per stand = 94 ft

Figure 1 – Well Information

The volumetric well control will be utilized in order to bring gas up to surface while maintaining bottom hole pressure almost constant.Safety Factor and Pressure Increment are 100 psi.

Assumption: Gas kick at the bottom

Mud Increment

Mud Increment (MI) is calculated by the following equation

Where;

MI = Mud Increment (MI), bbl


ACF = annular capacity factor between casing and drillstring, bbl/ft


ACF = (12.52 – 52) ÷ 1029.4 = 0.1275 bbl/ft

Mud Increment (MI) = 22.3 bbl

Volumetric Control Procedures1. We determine the Safety Factor (SF), Pressure Increment (PI) and Mud Increment

(MI).o Safety Factor (SF) = 100 psio Pressure Increment (PI) = 100 psio Mud Increment (MI) = 100 psi

2. Wait for casing pressure to increase by Safety Factor (SF) + Mud Increment (MI). For this case, we will wait until casing pressure reaches 600 psi (400 + 200). At this point, the over balance is 200 psi and gas migrates up from the bottom of the well.

Figure 2 – Table- Allow Casing To Increase by SF + PI

Figure 3 – Diagram Showing Gas Migration and Casing Pressure Increases

3. Hold casing pressure constant and bleed off fluid volume by Mud Increment (MI). For this case, the volume of mud bled off is equal to 22.3 bbl. At this point, the over balance will be 100 psi.

Figure 4 – Table- Bleed of Mud Volume by MI

Figure 5 – Diagram Showing Bleeding off Mud Volume by Mud Increment (MI) Holding Casing Pressure

Constant4. Shut the well in and wait until casing pressure increases by Pressure Increment

(PI). At this point, casing pressure will increase to 700 psi and the overbalance of the wellbore is 200 psi.

Figure 6 – Table- Allow Casing Pressure to Increase by Pressure Increment (PI)

Figure 7 – Diagram Showing Gas Migration and Casing Pressure Increases

5. Repeat step#3 and step#4 until gas at surface (casing pressure stops increasing) or the well kill operation can be performed with an alternative method. For example, if the pumps fails and the volumetric well control method is selected because you don’t want the bottom hole pressure increase too much. When the pumps are back in a service, other well control methods as driller’s method or wait & weight can be performed. As per this example, we will perform the volumetric well control until gas at surface.

Figure 8 – Table- Demonstrates Steps of Volumetric Well Control

Referring to Figure 8, you can see that casing pressure is allowed to increase and the mud is bled off to compensate increase in bottom hole pressure. Figure 9 is a summary chart showing casing pressure and over balance during the volumetric operation. The overbalance of the well bore is maintained between 100 psi to 200 psi. In some situations when there is a chance to break formation at a casing shoe, you might consider selecting the lower figure of safety factor as 50 psi.

Figure 9 – Pressure Summary

How To Perform Volumetric Well Control Method This article will demonstrate how to perform volume metric well control. There are a total of 5 steps as listed below;

Step 1 – Calculation

Three calculations must be determined before conducting volumetric well control.

Safety Factor (SF) – The Safety Factor (SF) in an increase in bottom hole pressure which we allow to happen naturally when gas influx migrates up with the shut in well. SF is important because it will allow the bottom hole pressure to be over formation pressure so the well is not in underbalance condition while conducting later steps. Typically, SF is around 50 – 200 psi. If the initial shut in casing pressure is very close to maximum allowable surface pressure. Personnel must select small safety factor to prevent fracturing formation.

Pressure Increment (PI) – It is pressure used as a working pressure while conducting Volume Metric well control. This pressure will be equal amount of hydrostatic pressure of mud bled during each step.

Mud Increment (MI) – It is volume of mud bled off from the annulus to reduce hydrostatic pressure by amount of Pressure Increment. It is very important that the rig must have an accurate measurement to measure small amount of mud bled from annulus. Mud Increment is determined by the following equation:

Where;

Mud Increment is in bbl.

PI is pressure increment in psi.

ACF is annular capacity factor in bbl/ft

MW is mud weight in ppg.

Step 2 – Allow Casing Pressure To Increase To Safety Factor Plus Pressure Increment

After the first step is completed, the 2nd step is to wait until casing pressure increases by an amount equal to Safety Factor (SF) plus Pressure Increment (PI). At this stage, the bottom hole pressure will increase by surface pressure but hydrostatic pressure is still the same.

For example, if SF is 100 psi and PI is 100 psi, we need to wait until casing pressure increase by 200 psi.

Step 3- Hold Casing Pressure Constant While Mud Increment Is Bled Off

Since we have the overbalance in step-2, in order to keep raising casing pressure due to gas migration, hydrostatic pressure must be taken out by bleeding off mud volume. This step will bleed off amount of mud equal to mud increment. Bleeding mud with constant casing pressure is performed to ensure that the bottom hole pressure is decreased by a loss of hydrostatic pressure only. Failure to keep casing pressure constant while bleeding off mud results in reduction of the bottom hole pressure. This can lead to more severe well control problem.

Every bleed off volume (mud increment) will reduce the bottom hole pressure by the amount of Pressure Increment. Once the bleed off is complete, the bottom hole pressure will be over balance by the safety factor.

Step 4 – Wait For Casing Pressure To Increase By Pressure Increment

At this step, we must wait to gas to migrate up until the surface casing pressure increase by Pressure Increment. When this step finishes, the bottom hole pressure will increase by the amount of Pressure Increment therefore the bottom hole pressure will be over balance by the amount of Safety Factor plug Pressure Increment.

Step 5 – Repeat Step 3 and Step 4 Until The Gas Migrates To Surface

The rest of volumetric well control is to repeat step#3 and step#4 until the gas finally migrates all the way to surface. During each step of bleeding off, the gas bubble expands and its pressure decreases. By the time, the gas reach at surface, the gas pressure will greatly reduce and its volume increases according to Boyles’ Laws.

Volumetric Well Control – When It Will Be Used: Volumetric well control method is a special well control method which will be used when the normal circulation cannot be done. It is not a kill method but it the method to control bottom hole pressure and allow influx to migrate without causing any damage to the well.

There are several situations where you cannot circulate the well as follows:

• Pumps broken down

• Plugged drill string/bit

• Drill string above the kick

• Drill string is out of the hole completely

With the volumetric method, the volume of gas influx will allow migrating and casing pressure will increase till a certain figure then a specific amount of mud will bleed off to compensate the increase in casing pressure. The volumetric method will allow the kick to surface while the bottom hole pressure is almost constant. Successful use of volumetric method requires personnel understand three basic concepts .

1. Boyle’s Law – Boyle’s 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. The illustration below demonstrates volume and pressure as per Boyle’s Law.

In term of mathematical relationship, Boyle’s Law can be stated asP1 x V1 = P2 x V1

Where;P1 = pressure of gas at the first conditionV1 = volume of gas at the first conditionP2 = pressure of gas at the second conditionV2 = volume of gas at the second condition

2. Hydrostatic pressure – Hydrostatic pressure is pressure created by column of fluid. Two factors affecting hydrostatic pressure are height of fluid and density of fluid.Pressure at the bottom hole equals to hydrostatic pressure plus surface pressure

Pressure (bottom hole) = Hydrostatic Pressure + Surface Pressure

We will apply this concept to see how the gas bubble will increase the bottom hole pressure.

If the gas bubble is not allowed to expanded, the gas bubble in the well migrates up will act on the mud column below and increase bottom hole pressure. Increasing in the bottom hole pressure equates to hydrostatic pressure below the bubble.

Bottom hole pressure = Gas bubble pressure + Hydrostatic pressure below the bubble

If we don’t want increase in bottom hole pressure, mud need to be bled off the well while the gas migrating up and the casing pressure must increase to compensate loss of hydrostatic pressure from bleed off.

In the volumetric control, there are two ways to control bottom hole pressure while allowing the gas migrating up to surface.

1. Wait and let gas migrate. The migration of gas will increase bottom hole pressure and casing pressure.2. Bleed off mud from the annulus. Mud that is bled off must be equal to the increase in bottom hole pressure.Both steps above must be carefully performed perform in a sequence. We will go to the detailed procedures in later post.

Relationship of height and fluid volume as determined by annular capacity – In order to determine volume of mud that equates to required hydrostatic pressure,

we need to understand annulus capacity. It tells us how many bbl per foot in annulus and it can be calculated by this following formulas:

Annular Capacity Factor (ACF) = (OD 2 -ID 2 ) ÷ 1029.4

Where;

ACF = Annular Capacity Factor in bbl/ft

OD = Outside Diameter of Annular in inch

ID = Inside Diameter of Annular in inch

Once the ACF is know, we can determine Mud Increment (MI) which is the volume of mud bled off from the annulus to reduce the annular hydrostatic pressure by the amount of the pressure required.

Mud Increment (MI) can be calculated by this following equation:

Mud Increment (MI) = (PI x ACF) ÷ (0.052 x MW)

Where;

PI = Pressure Increment in psi

ACF = Annular Capacity Factor in bbl/ft

MW = Mud Weight in the well in ppg

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Lubricate and Bleed in Well Control By DrillingFormulas.Com | October 20, 2013 - 1:08 pm | Well Control

In some special well control cases, you will not be able to circulate kick out of the well then the kick is brought

up to the surface using special well control procedure like “Volume Metric Method”. At this point, surface

pressure is the height because of decreased hydrostatic pressure in the well bore.

How can we remove the gas out of the well bore without allowing more influx coming into the well bore for this scenario?This is the time that we must perform a special well control procedure called “Lubricate and Bleed”.

Lubricate and bleed procedure is the way to remove the gas when the circulation is impossible to conduct.

The basic theory is the same asVolumetric Well Control Method but it is just a reverse process. Surface

pressure will be replaced with hydrostatic pressure by pumping drilling fluid into the wellbore. The gas and

drilling mud are allowed to swap the places and amount of surface pressure will be bled off later.

If you use the current mud weight to perform the lubricate and bleed procedure, the well will not be killed and

there is remaining surface casing pressure. Only surface casing pressure will be decreased to where it

balances to formation pressure. In many cases, it is sometimes desirable to pump heavier mud in to the

wellbore and hopefully it will kill the well too.

You will wonder why I use the phase “hopefully kill the well”. The reason is you may not have enough

hydrostatic height to create extra hydrostatic head to just balance the formation pressure. This is based on

case by case.

The lubricate and bleed procedure is listed in the following steps:Step 1 – Determine hydrostatic pressure

Determine hydrostatic pressure of 1 bbl (I use the oil field unit) of mud that will be pumped into the well.

Step 2 – LubricateSlowly pump a desired volume into the well. The amount of volume depends on well conditions and it may

change during the process. Increasing in surface pressure can be estimated by utilizing Boyle’s Laws (P1V1

= P1V2) and every one bbl of mud pumped into the well, the gas size is reduced by one bbl.

During lubricating, surface casing pressure will be definitely increase. The amount of pressure increase will

depend on the volume of gas being compressed. Small pressure increase indicates large volume of gas.

Additionally, Maximum Allowable Surface Casing Pressure (MAASCP) will reduce because the increase in

hydrostatic pressure during lubrication. Since gas volume also decreases every time that gas is bled off, you

may reach the point to stop lubricating operation in order to prevent breaking out the wellbore. At this point

you will have gas in the wellbore but the lubricate and bleed procedure cannot be performed any more. In

order to know this figure, you may need to play with the kill sheet to find this stopping point. By adjusting

parameters in the kill sheet, you can minimize this issue.

Step 3 – WaitWait for awhile to allow gas and mud swapping out. Drilling mud properties as mud weight and rheology

affects on this step. You need to be patient.

Step 4 – Bleed off pressureBleeding gas from the surface until the amount of pressure is equal to hydrostatic pressure of mud pumped in

hole. If you know that you lubricate in 50 psi, only 50 psi of gas must be bled off. It is very important to bleed

only gas. During this process if you see mud on surface, you must stop and allow gas to swap out. For

instant, you plan to bleed a total of 50 psi but you observe mud coming out when you bleed only 30 psi, you

stop the bleeding process and shut the well in. Then, you continue bleeding the remaining 20 psi later.

If the mud is accidentally allowed to come out during this bleeding process, the bottom hole pressure will

reduce resulting in more influx coming into the wellbore.

Step 5 – Repeat step 2 to 4Repeat step 2 – 4 until you get the gas out of the well or the desired surface casing pressure is reached. As

you know, you may not be able to kill the well with this method because total hydrostatic head is not sufficient

to balance the wellbore.

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Lubricate and Bleed Example Calculations By DrillingFormulas.Com | September 14, 2015 - 11:58 am | Well Control

This example demonstrates the calculations and the steps of lubricate and bleed which will help you

understand about what calculations according to lubricate and bleed procedures.

Gas kick migrates to surface underneath the BOP safely via Volumetric Well Control. The circulation is not

possible due to drillstring plugged off therefore the decision is made to perform Lubricate and Bleed to kill the

well. The well control information is listed below;

Shut in Drill Pipe Pressure = 0 psi (drillstring plugged)

Shut in Casing Pressure = 1,000 psi without any safety factor

Gas on surface at the BOP

Current mud weight = 11.0 ppg

Casing shoe depth = 6,000’MD/6,000’TVD

Hole TD = 9,000’MD/9,000’TVD

Hole size = 12.25”

Casing ID = 12.5”

Drill pipe size = 5”, 19 ppf

BHA consists of 6.5” drill collar

Length of BHA = 800 ft

Average pipe per stand = 94 ft

Wellhed rating = 5000 psi

BOP rating = 10,000 psi

Leak off pressure at shoe = 16.0 ppg

Estimated gas volume at BOP = 70 bbl

Estimated Bottom of gas = 549 ft

Figure 1 – Well Information

Note: Before going onto detailed calculations, it is very important to explain to you that the Lubricate and

Bleed method can kill the well or just reduce surface pressure. It is not 100% every time that the well will be

successfully killed and you will see in the detailed calculations later.

The concept of Lubricate and Bleed is to remove gas at surface when the circulation cannot be performed.

With this method, bottom hole pressure will be almost constant. The mud will be pumped in to the well to

increase bottom hole pressure and later gas will be bled off to compensate what hydrostatic pressure added

into the system.

Lubricate and Bleed CalculationsSelect Safety Factor (SF) – it is recommended to use a small and practical safety factor. For this calculation,

the Safety Factor is 50 psi.

Select Pressure Increment (PI) – this is the hydrostatic of mud which is planned to lubricate into the well.

Pressure Increment (PI) should be a small and practical figure so Pressure Increment (PI) for this calculation

is 50 psi.

Calculate Lube Increment (LI)Lube Increment (LI)is calculated by the following equation

Where;

LI = Lube Increment (MI), bbl


ACF = annular capacity factor between casing and drillstring, bbl/ft, at surface.

ACF = (12.52 – 52) ÷ 1029.4 = 0.1275 bbl/ft


For this example, 14-ppg mud will be used.

** It is suggested to use higher mud weight as practical as possible. The reasons are small Lube Increment

(LI) and higher change to kill the well.

Lube Increment (MI) = 8.8 bbl

Maximum Allowable Surface Casing Pressure (MASCP)We need to know surface limitation prior to inject otherwise it can cause failure on surface equipment or

break formation downhole and for this situation, Leak Off at show (16 ppg) is the limitation. In some cases, if

you work on an old well, casing rating may be a limitation so you need to check and use the lower figure. For

the worst case, we assume that gas will be fully replaced with kill mud (14.0 ppg).

MASCP is calculated by the equation below;

MASCP = Leak off Pressure – Hydrostatic Pressure

Hydrostatic Pressure = Hydrostatic Pressure from Kill Mud (14 ppg) + Hydrostatic Pressure from Current Mud

(11 ppg)

Hydrostatic Pressure = (0.052 × 14 × 549) + (0.052 × 14 x 5,451)

MASCP = (0.052 × 16 × 6,000) – [(0.052 × 14 × 549) + (0.052 × 14 x 5,451)]

MASCP = 4,992– 400 – 3,118

MASCP = 1474 psi

Note: We don’t calculate the MASCP with only current mud weigh because it is not the worst case scenario.

Lubricate and Bleed Steps1. We determine the Safety Factor (SF), Pressure Increment (PI) and Mud Increment (MI).

o Safety Factor (SF) = 50 psi

o Pressure Increment (PI) = 50 psi

o Lube Increment (LI) = 8.8 bbl

2. Lubricate mud volume equal to Lube Increment (LI)For this step, it will add safety factor into the well; however, if surface casing pressure already has safety

factor, step#2 and step#3 must be skipped in order to prevent excessive safety factor which may cause

fracturing shoe.

Volume gas is compressed by lubricated mud.Volume of gas = Volume of gas at previous condition – Lube Increment (LI)

Volume of gas = 70 – 8.8 = 61.2 bbl

Pressure of compressed gas is determined by Boyld’s Law.P2 = (P1 × V1) ÷ V2

Where;

P1 = Pressure of gas at previous condition, psi

V1 = Volume of gas at previous condition, bbl

V2 = Volume of gas compressed by lubricated mud, bbl

P2 = Pressure of gas compressed by lubricated mud, psi

This pressure represents casing pressure due to gas compression.

P2 = (1000 × 70) ÷ 61.2 = 1,144 psi

Overbalance of bottom hole pressureOverbalance = P2 + Hydrostatic Pressure due to Lube Increment (LI) – P1 + Safety Factor

Where;



Hydrostatic Pressure due to Lube Increment (LI) = Pressure Increment (PI)

Safety Factor = 0 psi

Overbalance = 1,144 + 50 – 1000 + 0

Overbalance = 194 psi

Figure 2 – Table Represents Pressure and Volume of Step#2

Figure 3 – Diagram shows mud lubricated into the well

3. Bleed gas via choke until casing pressure reach the initial pressure in step#2This step will establish a Safety Factor (SF) because surface pressure is bleed off to the original value and

the only thing that adds into the wellbore is hydrostatic pressure from Lube Increment (LI) which is 50 psi for

this example.

Overbalance of bottom hole pressureOverbalance = Current Overbalance in step#2 – (Casing Pressure after Lubricating – Casing Pressure after

Bleeding off)

Overbalance = 194 – (1,144 –1,000) = 50 psi


Figure 5 – Diagram shows bleeding gas out of the well

4. Lubricate mud into the well equal to Lube Increment (LI)8.8 bbl of mud is pumped and this will give 50 psi hydrostatic pressure increment.

Gas volume will be compressed by 8.8 bbl therefore the volume of gas will be reduced from 61.2 bbl to 52.4

bbl (61.2-8.8 = 52.4).


Pressure of compressed gas is determined by Boyld’s Law.P2 = (P1 × V1) ÷ V2

Where;


V1 = Volume of gas at previous condition, bbl

V2 = Volume of gas compressed by lubricated mud, bbl



P2 = (1000 × 61.2) ÷ 52.4 = 1,168 psi

Overbalance of bottom hole pressureOverbalance = P2 + Hydrostatic Pressure due to Lube Increment (LI) – P1 + Safety Factor

Where;



Hydrostatic Pressure due to Lube Increment (LI) = Pressure Increment (PI)

Safety Factor = 50 psi ** The safety factor is established from step#2 and step#3.

Overbalance = 1,168 + 50 – 1000 + 50

Overbalance = 268 psi


Figure 7 – Diagram shows mud lubricated into the well

5. Bleed casing pressure until casing pressure is equal to casing pressure in step#4 before lubricating minus Pressure Increment (PI)

This step will intentionally reduce casing pressure which has the same value of Pressure Increment (PI)

which is 50 psi for this case.

Casing pressure @ step#4 before lubricating = 1,000 psi

PI = 50 psi

Casing pressure after bleeding off = 1000 – 50 = 950 psi

Overbalance of bottom hole pressureOverbalance = Current Overbalance in step#4 – (Casing Pressure after Lubricating – Casing Pressure after

Bleeding off)

Overbalance = 268 – (1,168 –950) = 50 psi

Figure 8 – Table Represents Pressure and Volume Bled off of Step#5

Figure 9 – Diagram shows gas bled off to planned pressure

6. Repeat step#4 and step#5 until gas is out of the annulus (well dead) or casing pressure increase to Maximum Allowable Surface Casing Pressure (MASCP)

The table (Figure 10) shows all the required steps as per Lubricate and Bleed.

Figure 10 – Table Represents Pressure and Volume Bled off with Lubricate and Bleed

One thing that we would like to point out is at the last step the volume of gas left in hole is 8.4 bbl. Beyond

this step is impossible because you need to lubricate a lubricate volume of 8.8 bbl and the casing pressure

will exceed the MASCP. Therefore, the operation will stop at this point and casing pressure will be down from

1,000 psi to 750 psi with 50 psi overbalance.

Figure 11 – Not Enough Volume Gas Left in the Well to Lubricate and Casing Pressure Exceeds MASCP

Thing to Remember Lubricate and Bleed may or may not be able to kill the well but at least you can reduce surface casing

pressure in a controlled manner.

Gas volume is getting smaller due to bleed off therefore it may reach the point that when you try to

lubricate the mud, it will create very high surface casing pressure because of Boyle’s law. High surface

pressure can cause either surface equipment damage or fracture formation at a casing shoe. It is very

important to do the full step calculations in order to know when you will not be able to lubricate anymore.

You need to know Maximum Allowable Surface Casing Pressure (MASCP) as your maximum lubricated

pressure.

to minimize influx (kick)

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