Day 2 IWCF

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An Overview to IWCF

Well Control Certification Course

(DRILLER/SUPERVISOR LEVEL)

Day 2

Prepared by:

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DAY-2 --- Session – I

Gas influx behavior

When a well is shut in on a kick that contains gas the gas will percolate or migrate up the hole even if the well is allowed to remain static. Gas migration can cause confusion during a well control operation, because it can be overlooked. Gas or Gas bubbles float or migrate up the hole because they are lighter than mud. When gas bubbles rise they expand or if they are not allowed to expand they cause an increase on all wellbore pressures and surface pressures. Therefore if a well is shut in for a long time, all pressures, wellbore surface etc. will increase causing lost circ. etc., if not relieved by allowing gas to expand. So lowering SIDPP to original value through choke and observing, keeping SIDPP at original value, will prevent this problem.

All pressures will increase during migration of gas except pressure in actual bubble which is usually at formation pressure.

If a gas bubble is allowed to expand without control of any kind it will eventually unload the well. With the well unloaded, kick sizes increasing, causing more unloading. This cycle of influx and unloading has caused the loss of many wells.

Boyles Law is shortened version of equation for gas expansion e.g. P1V1 = P2V2. It generally states that if the volume of gas doubles, the pressure is reduced by half in the bubble.

P1 = Hydrostatic Pressure (W/Gas bubble on bottom) =T.D V1 = Original Pit Gain

P2 = Hydrostatic press at secondary depth

V2 = Gas volume @ surface or at secondary depth V2 = P1V1/P2

Open well migration

The effect of gas migration in an open hole is mentioned below: • Bottom hole pressure reduces

• Gas bubble pressure reduces • Pressure below the bubble reduces

• Pressure above the bubble remains constant We shall discuss each point one by one.

A. BOTTOM HOLE PRESSURE REDUCES

• In open well when wellbore takes a kick,

BHP = Hyd. Pr. of Mud in Annulus + Hyd. Pr. of Kick

• As the kick migrates upward, it expands and unloads mud from the annulus to the pit. • Thus mud volume in annulus decreases.

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• Also due to expansion of kick, the average density of mud column in annulus reduces resulting in reduction in hydrostatic pr.

• This justifies that "Bottom hole pressure reduces as kick migrates up in the open hole".

B. GAS BUBBLE PRESSURE REDUCES

During open hole gas migration, gas bubble moves upwards continuously and the hydrostatic column of mud above gas bubble goes on decreasing. The decrease in hydrostatic pressure above gas bubble facilitates gas bubble to expand.

• Using Gas Equation: P1 V1 = P2 V2, thus, P2 = (P1 V1)/ V2.

• Now consider a situation when kick is at bottom. Its pressure = P1 and volume = V1. • At some height above, the gas expands and now its pressure = P2 and Volume = V2. • Using gas equation: P2 = (P1 V1)/ V2.

• Since V2 increases due to gas expansion, P2 will reduce.

Thus in open hole gas migration, GAS BUBBLE PRESSURE REDUCES as gas migrates upward.

Closed-in (Shut-in) conditions migration

Gas migration is the movement of low-density fluids up the annulus. It tends to build pressure at the surface, if time is allowed for migration. Also, the influx may have a tendency to deteriorate the hole stability and cause either stuck pipe or hole bridging. These problems must also be considered when reading the shut-in pressures.

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Well killing Driller's method

Driller’s method is one of several methods to kill the well. The main idea of driller method is to

kill the well with constant bottom hole pressure. The Driller’s Method of well control requires two complete and separate circulations of drilling fluid in the well.

The first circulation removes influx with original mud weight. When starting to bring pumps

up to speed, casing pressure must be held constant until kill rate is reached. Then drillpipe pressure is held constant to maintain constant bottomhole pressure which is normally equal to, or slightly greater than pore pressure. Drillpipe pressure will be held constant until influx is

removed from annulus. If the wellbore influx is gas, it will expand when it comes close to surface therefore you will see an increase in pit volume and casing pressure.

After the kick is totally removed from the well, when the well is shut-in, drillpipe and casing pressure will be the same value. If not, it means that there is influx still left in the wellbore or trapped pressure.

Before going to the second circulation, we need to know kill mud weight which can be

calculated from initial shut-in drillpipe pressure. The calculation part will be discussed as in next section.

Second circulation kills well with kill mud. When the required kill mud weight is mixed, it is

the time to start the second circulation of driller method. We start with bringing pumps to kill rate by holding casing pressure constant. While circulating with the kill mud, casing pressure must be held constant until kill mud reaches the bit. After that, we need to hold drill pipe

pressure constant then continue circulating with constant drill pipe pressure until kill mud weight reaches at surface. Then shut down pumping operation and observe drillpipe and casing pressure. If the well is successfully killed, both drillpipe and casing pressure will be zero. If not, there is some influx still in the well.

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Preparation of kill sheet

Well Control - Driller's Method

With this method, the well is killed in two circulations. During the first circulation: the influx is circulated out of the hole using the existing mud. Additional influx is prevented by adjusting the choke to maintain a constant bottom hole pressure slightly in excess of the pore pressure.

During the second circulation: the existing mud is replaced by mud of the required density to (over)balance the pore pressure. The choke is adjusted to maintain a constant bottom hole pressure slightly greater than the pore pressure.

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1. Disadvantages of the driller's method

Compared with the balanced mud method, principal disadvantages of the driller's method include the following:

 ·the well must remain closed-in under pressure longer;

 ·the maximum pressure at the casing shoe and against the formation will be higher if the influx is gas (unless the top of the gas reaches the casing shoe before the drillstring would be displaced by heavy mud in the balanced mud method);

 ·the maximum choke pressure when the top of the influx reaches the surface will be higher if the influx is gas.

Before employing the driller's method, it is essential to confirm that exposed formations can support the higher pressures which might be developed during the first circulation.

2 Advantages of the driller's method

Advantages of the driller's method include the following:

 Simplicity: circulation can be started without calculations. This may be useful if expert supervision is not immediately available;

 Pumping can begin as soon as drillpipe pressure build-up is established; there is no delay whilst mud is weighted up. This could be important in case of an H2S influx;

 The well can be effectively controlled (although not killed), even if the weighting material supply is inadequate.

2.1 Procedures

The following procedures concerning the driller's method are discussed:

 ·Closing in the well.

 ·Pressure and pit volume readings.

 ·First circulation: selecting the pump rate.

 ·Standpipe pressure during first circulation.

 ·Determining the height and gradient of the influx.

 ·First circulation: determining travel times (or volumes).

 ·First circulation: standpipe kill graph construction and use.

 ·Determining the pressure at the top of a gas influx at any point in the annulus.

 ·First circulation: action.

 ·Second circulation: determining the gradient of the kill mud.

 ·Second circulation: determining the amount of overbalance.

 ·Second circulation: selecting pump rate.

 ·Second circulation: travel times (or volumes).

 ·Second circulation: standpipe pressures.

 ·Second circulation: standpipe kill graph construction and use.

 ·Second circulation: action.

 ·Procedure after the well has been brought under control.

3 Closing in the well

Close in the well immediately after detecting a kick condition. The procedure is as for the balanced mud method.

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4 Pressure and pit volume readings

Pressure and pit volume readings should be taken as for the balanced mud method

5 First circulation: Selecting the pump rate

The mud is not weighted up for the first circulation: therefore, the pump rate is not limited by the weighting material mixing capacity of the rig. However, the maximum pump rate is limited by other factors such as the increased initial standpipe pressure, the need for choke adjustment, and surface gas handling equipment. Also, if the choke starts blocking-off, pressure surges will be less at reduced circulating rates. Normally, the pump speed selected will not exceed 50% of the usual circulating rate applied for drilling operations.

6 Standpipe pressure during first circulation

The standpipe pressure at the start is the same as with the balanced mud method. The standpipe pressure should then be approximately equal to the normal pre-kick circulation pressure at the selected pump speed, plus the closed-in drillpipe pressure, plus a small margin of 700 kPa (100 psi).

Always make sure that the formation strength at the casing shoe is not exceeded during the circulating process.

Since there is no change in the gradient of the mud being pumped, the initial standpipe pressure must be held constant throughout the first circulation to ensure that the bottom hole pressure is also kept constant.

7 Determining the height and gradient of the influx

This information is not essential, but will give an indication of the pattern of choke pressures and pit level changes that may be expected during the first circulation. The procedure is as for the balanced mud method.

8 First circulation: Determining travel times (or volumes)

The bit-to-shoe and shoe-to-choke times are determined .The total pumping time for the first circulation is that required to displace the annulus, i.e. the sum of the bit-to-shoe and shoe-to-choke times, volumes, or pump strokes.

9 First circulation: Standpipe kill graph construction and use

The standpipe kill graph is a horizontal line equal to the closed-in drillpipe pressure plus the circulating pressure plus the overbalance margin of 100 psi.

10 Determining the pressure at the top of a gas influx at any point in the annulus

When a gas kick is being circulated out of the hole, the influx volume will increase due to expansion and consequently results in increased pit levels.

By calculating the expected annular pressures at the top of the influx at specific points along the hole together with the associated influx volumes at these points, comparisons can be made with actual values observed during circulating out the influx. This information can play an important role in the decision making process during well control operations.

The pressure at the top of a gas bubble at any point in the annulus while circulating it out using the "Driller's method" can be calculated as follows:

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11 First circulation: Action

The procedure for the first circulation is as follows:

1. Open the choke and start pumping the existing mud at the selected pump speed.

2. Adjust the choke opening until the choke pressure equals the closed-in annulus pressure plus

the overbalance margin. Record the choke pressures throughout the first circulation.

3. Read the standpipe pressure. It should agree with the calculated value, i.e. the normal pre-kick

pump test circulation pressure at the selected pump speed plus the closed-in drillpipe pressure, plus a small margin of 700 kPa (100 psi). If the observed standpipe pressure does not agree with the calculated value, consider the observed pressure to be correct.

4. Note the standpipe pressure and thereafter keep it constant whilst maintaining a constant pump

rate, until the influx is circulated out.

5. When all influx has been circulated out, stop the pump and close in the well to check the

closed-in drillpipe and annulus pressures. At the end of the first circulation, the closed-in pressures of the annulus and drillpipe should be the same and equal to the initial closed-in drillpipe pressure. The well is controlled but not killed.

During the first circulation the following should also be carried out:

 ·maintain and record the density of the mud pumped into the drillstring. Ensure that it has the correct value;

 ·measure and record the properties of the mud returns;

 ·de-gas, treat or discard any contaminated mud returns.

12 Second circulation: Determining the gradient of the kill mud

The gradient of the kill mud to balance the formation pressure can be determined as soon as the closed-in standpipe pressure has stabilized. A trip margin can now be added to the kill mud gradient in order to overbalance the formation pressure and to resume normal operations.

13 Second circulation: Determining the amount of overbalance

Normally the overbalance on bottom during well control (neglecting friction losses in the annulus), should not exceed 700 kPa (100 psi). However, since the influx has been displaced with r1 mud during the first circulation, large fluctuations in mud gradient and choke control operations are not expected and therefore, if possible, the density of the mud in the well is raised directly to that required to resume normal operations.

14 Second circulation: Selecting pump rate

This is carried out as for the balanced mud method.

A constant pump rate, approximately one half the speed used for the drilling operation, is maintained during the second circulation.

15 Second circulation: Travel times (or volumes)

Provided that the same pump rate is used, the surface-to-bit and bit-to-choke times are the same as for the balanced mud method Section

16 Second circulation: Standpipe pressure

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Pst =Pdp + Pc1 + margin

During the period that the heavy mud (including the overbalance) is pumped down the

drillstring, the standpipe pressure should decrease until the heavy mud reaches the bit at which time it should be:

Pst = Pc1 * rho2 / rho1 = Pc2

The standpipe pressure should remain constant after the heavy mud has reached the bit.

17 Second circulation: Standpipe kill graph construction and use

The standpipe pressure kill graph for the second circulation is similar to that of the balanced mud method

The procedure for constructing the standpipe kill graph is as follows:

1. Plot the initial circulating pressure plus margin at the start of the second circulation.

2. Plot the heavy mud circulating pressure (Pc2) at the time that the heavy mud reaches the bit. 3. Whilst the heavy mud is being circulated into the annulus, the back pressure should be

progressively reduced to zero at the time when the heavy mud reaches the choke. The standpipe pressure should then equal the heavy mud circulating pressure.

This assumes that the heavy mud gradient includes a suitable overbalance margin.

18 Second circulation: Action

If possible, the density of the mud in the well is raised directly to that required to resume normal operations.

The procedure during the second circulation is as follows:

1. Open the choke and start pumping mud of the required density at the rate selected to kill the

well. Maintain a constant pumping rate.

2. Adjust the choke opening until the choke pressure equals the closed-in annulus pressure plus

margin observed at the end of the first circulation. Choke pressures should be recorded throughout the process.

3. Read the standpipe pressure. This should agree with the calculated standpipe pressure, i.e. the

pre-kick pump test circulating pressure plus the closed-in drillpipe pressure at the end of the first circulation including the margin. If the standpipe pressure does not agree with the calculated value, consider the observed pressure to be correct and modify the standpipe pressure kill graph accordingly.

4. When the heavy mud reaches the surface, stop pumping and check whether the well is dead.

During the second circulation the following should also be carried out:

·maintain and record the density of the mud pumped into the drillstring; ensure that it has the correct value;

 ·measure and record the properties of the mud returns until the well is killed;

 ·de-gas, treat or discard any contaminated mud returns.

19 Procedure after the well has been brought under control

After the well has been brought under control, the well should be flow-checked via the open choke line. The preventers can be opened and normal circulation resumed after any possible flow has ceased from the choke line for a reasonable flow-check time.

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Crewmember responsibilities for shut-in (Well Killing) procedures

Each crewmember has different responsibilities during shut-in procedures. These responsibilities follow and are listed according to job classification.

Floorhand (roughneck)

These responsibilities for shut-in procedures belong to the floorhand: 1. Notify the driller of any observed kick-related warning signs.

2. Assist in installing the full-opening safety valve if a trip is being made. 3. Initiate well-control responsibilities after shut-in.

Derrickman

These responsibilities for shut-in procedures belong to the derrickman: 1. Notify the driller of any observed kick-related warning signs. 2. Initiate well-control responsibilities.

3. Begin mud-mixing preparations.

Driller

These responsibilities for shut-in procedures belong to the driller:

1. Immediately shut in the well if any of the primary kick-related warning signs are observed.

2. If a kick occurs while making a trip, set the top tool joint on the slips and direct the crews in the installation of the safety valve before closing the preventers.

3. Notify all proper company personnel.

Bottom hole pressure change while performing well control operation with

driller’s method

In the first circulation of driller’s method, driller circulates gas kick with 25 spm and the initial circulating pressure (ICP) is 1600 psi. The initial shut in drill pipe pressure is 450 psi. After shift change, another driller accidentally changes pump rate to 30 spm but he still holds drill pipe pressure constant.

What will happen to bottom hole pressure?

Let’ start with the basic formula

ICP = SIDDP + SCR

When the pump speed is increased, slow circulating rate (SCR), which is caused by friction, will increase in order to maintain constant bottom hole pressure. However, for this case, the drill pipe pressure is maintained constant with while increasing pump rate therefore the bottom pressure will decrease.

How much bottom hole pressure will decrease?

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New SCR = 1656 psi

With new pump rate at 30 spm, the new SCR should be 1656psi but the driller maintains the old SCR, 1150 psi. Therefore, the bottom hole pressure will decrease by 506 psi (1656 – 1150).

Conclusion: The point that I would like to mention is that when you change your pump rate

while performing well control operation. You must ensure that you do proper way to maintain bottom hole pressure. Otherwise, you may accidentally either decrease or increase the bottom hole pressure. If you accidentally decrease the bottom hole pressure, the influx will continue coming into a well and you will be in the big trouble. On the other hand, if you accidentally increase the bottom hole pressure, you may break wellbore and end up with lost circulation issue.

How are pressure and pit volume doing during the first circulation of the

driller’s method?

When we perform the first circulation of driller’s method, the casing pressure will increase due to gas expansion and the maximum casing pressure will be observed when the gas influx reaches surface.

When gas is moved upward during circulation, the gas will expand due to pressure decrease (refer to Boyle’s gas law P1V1 = P2V2). The higher gas is moved up inside annulus, the higher expansion will be. Therefore, the system hydrostatic pressure will be decreased. For this reason, the casing pressure will increase in order to maintain constant bottom hole pressure.

Let take a look at the equation

Bottom hole pressure constant = Casing Pressure (increase to compensate for loss hydrostatic pressure) + Hydrostatic Pressure (decrease due to gas expansion).

When the gas in the mud starts coming out on surface, the casing pressure will continually decrease. If the gas kick in the annulus is totally out of hole, casing pressure should be equal to Shut-In Drillpipe Pressure (SIDPP). Casing pressure sometimes may be slightly more than SIDPP due to safety factor that you add while circulating. In addition, pit volume will increase until gas reaches surface due to gas expansion. When gas reaches surface, the pit volume will start to decrease.

The plot below demonstrates pressure profile of both casing pressure and tubing pressure during 1st circulation of driller’s method.

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Establish Circulation in Driller’s Method

The idea of holding casing pressure constant while bring up pumps is to maintain constant bottom hole pressure.

Bring pump up to circulating rate, typically about 2-5 BPM, by holding constant casing pressure. The reason why we need to hold constant casing pressure is to maintain constant bottom hole pressure.

Let’s me explain more by showing you some equations. BHP = Bottom Hole Pressure

HP = Hydrostatic Pressure CP = Casing Pressure FrP = Frictional Pressure

At static condition: BHP = HP in the annulus + CP

At dynamic condition: BHP = HP in annulus + CP + FrP

In the dynamic environment, if we pump as slowly as possible, FrP can be ignored. The equation above tells us that when you hold CP constant, the BHP will be maintained the same.

After you bring pump to kill rate, you will get circulating pressure called Initial Circulating Pressure (ICP). ICP is summation of shut in drill pipe pressure (SIDPP) and pressure to overcome friction called Slow Circulating Rate Pressure (SCR pressure). Hence, we can write the relationship in term of equation below.

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SCR pressure = ICP – SIDPP

Note: Kill rate is normally about 2-5 BPM.

Before performing this operation, you must ensure these following items;

1. Ensure that team members know their role and responsibility. You should have a pre job

safety meeting before killing operation.

2. Eliminate all ignition sources that are close to the rig and vent lines of mud-gas separator. 3. Ensure that a circulating system is lined up properly.

4. Zero strokes counter and record time every activity.

Additional Topics

EQUIVALENT CIRCULATING DENSITY (ECD)

• While drilling, the mud passes through the drill string, comes out of bit nozzle, enters the annulus, travels up the annulus and comes out through flow line.

• In this process when mud travels up in annulus, friction force acts downward.

• The pressure equivalent to this friction force is called Annular Pressure Losses (APL). • Also, hydrostatic pressure acts downwards.

• Thus, BHP = Hydrostatic Pressure + APL

• (MW equivalent of Hyd Pr. + Mw Equivalent of APL) is termed as ECD.

• Equivalent Circulating Density (ppg) =Static Mud Weight (ppg) + (Annular Pressure Loss)/ (TVD ×0.052)

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

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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 as

P1 x V1 = P2 x V1

Where;

P1 = pressure of gas at the first condition V1 = volume of gas at the first condition P2 = pressure of gas at the second condition V2 = 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.

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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.

3. 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) = (OD2-ID2) ÷ 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 known, 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)

PI = Pressure Increment in psi

ACF = Annular Capacity Factor in bbl/ft MW = Mud Weight in the well in ppg

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Gas Behavior and Bottom Hole Pressure in a Shut in well

This is a classic example demonstrating how bottom hole pressure will be due to gas

migration in a shut in well. This is very important concept in well control.

Assumption: For this example, since the volume of the well does not change, and assuming that

no mud or fluid is lost to the formation.

This example will demonstrate the gas behavior in a shut in well. The well is shut-in without pipe in hole. 5 bbl of gas kick is taken and initial shut in casing pressure is equal to 400 psi. Hydrostatic head on top of gas is 4000 psi (see figure 1).

Fig-1 Fig-1

Even though the well is shut in, the gas influx is able to move upward due to gas migration. In this case, we will not allow any gas expansion and let the gas gradually migrate.

The well is shut in and gas is allowed to migrate up hole until hydrostatic pressure underneath gas is 2000 psi (see the figure 2).

What will happen to bottom hole pressure and casing pressure?

With Bolye’s Law concept, we will apply it see how much gas bubble should be. According to this example,

Pressure of gas (P1) is 4400 which equates to the bottom hole pressure. Volume of gas at beginning (V1) is 5 bbl

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4400 x 5 = P2 x 5

P2 = 4400 psi ->Gas pressure remains constant.

You have total of hydrostatic pressure of 4,000 psi at the beginning. Currently, you have 2000 psi of hydrostatic at the bottom therefore you have 2000 psi of hydrostatic on top of gas. See the figure 3.

Fig-3 Fig-4

Let’s see how much casing pressure will be.

Apply hydrostatic pressure concept to solve this problem.

Gas influx pressure = hydrostatic pressure above the gas influx + casing pressure 4400 = 2000 + casing pressure

Casing pressure = 2400 psi

Moreover, you can find the bottom hole pressure by applying the same concept. Bottom hole pressure = hydrostatic pressure of mud + casing pressure

Bottom hole pressure = 4,000 + 2,400

Bottom hole pressure = 6,400 psi. (See Fig-4)

Conclusion:

If the well is shut in and the gas influx is allowed to migrate, gas pressure will remain constant; however, bottom hole pressure and casing pressure will increase. If you let casing pressure (surface pressure) increase too much, you can break formation or damage surface equipment.

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DAY-2 --- Session - II

Well Kill Using Wait and Weight Method (Balanced Method)

The “Wait and Weight” method is the method recommended, in some circumstances, for controlling an influx taken while drilling or circulating on bottom. When drillpipe (string) volume is greater than open hole volume, the influx will already be inside the casing before heavy mud reaches the open hole.

In this case the “Driller’s Method” can be a better solution as the danger of gas expansion is removed immediately while weighing up mud can take hours.

Advantages of “Wait and Weight” method

The annular pressure will usually be lower and the chance of formation breakdown is therefore reduced.

The hole and the wellhead equipment are subjected to high pressures for the shortest possible time since the influx is circulated out and the well is killed in one circulation.

Disadvantages of “Wait and Weight” method

Considerable waiting time while weighing up mud can cause gas migration If large increases in mud weight is required, this may be possible in stages only

This method involves one circulation. Kill mud is prepared and is pumped from surface to bit while following a prepared drillpipe pressure drop schedule. Once the kill mud enters the annulus, a constant drillpipe pressure is maintained until the heavy mud returns to surface.

Procedure

The procedure for the Wait and Weight method is as follows:

After the well has been secured and pressures have stabilised, complete kill sheet including kill graph

Bring pumps up to speed keeping casing pressure constant by manipulating the choke

When pump is up to kill speed the choke is manipulated to keep the drill pipe pressure at initial circulating pressure (ICP).

Pump kill mud down drill pipe keeping casing pressure constant and allowing drill pipe pressure to fall from ICP to final circulating pressure (FCP).

When kill mud reaches the bit the drill pipe pressure should be at FCP. Continue pumping kill mud keeping drill pipe pressure constant at FCP until the kick is circulated out and kill mud reaches surface.

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Equations

KMW = (SIDPP / (0.052 * TVD)) + OMW

Trip margin may not be included in the calculation for kill mud weight. The major reason for this is to avoid any unnecessary additional wellbore pressure that could result in formation

breakdown.

Calculate initial circulating pressure:

ICP = SCRP + SIDPP (psi)

Calculate Final circulating pressure:

FCP =

(

𝐾𝑀𝑊

𝑂𝑀𝑊

) ∗ 𝑆𝐶𝑅𝑃(𝑝𝑠𝑖)

Calculate surface to bit strokes:

Strokes = Drillstring volume (bbls) Pump output (bbls/stroke)

Calculate time to pump surface to bit:

Time (mins) = Total strokes from surface to bit) Strokes per minute Where:

 KMW = Kill mud weight (ppg)

 SIDPP = Shut in Drillpipe pressure (psi)

 TVD = True vertical depth (ft)

 OMW = Original Mud Weight (ppg)

 ICP = Initial circulating pressure (psi)

 SCRP = slow circulating rate pressure (psi)

 FCP = Final circulating pressure (psi)

Wait and Weight Well Control Method (Engineer’s Method)

Wait and Weight Well Control Method or someone calls Engineer’s Method is a method to control well with one circulation. Kill weight mud is displaced into drill string and kick

(wellbore influx) is removed while displacing a wellbore.

Steps of the weight and weight method for well control are as follow: 1. Shut in the well.

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2. Allow pressure to stabilize and record stabilized shut in casing pressure, initial shut in drill

pipe pressure, and pit gain. If you have a float in the drill string, you must bump the float in order to see the shut-in drill pipe pressure

3. Perform well control calculations and following items must be figured out.  Bottomhole pressure based on drill pipe pressure.

 Kill Mud weight necessary to balance the kick

 Drillpipe pressure schedule

 Maximum surface casing pressure during well control operation.

 Maximum pit gain during

4. Raise mud weight in the system to required kill mud weight.

5. Establish circulation to required kill rate by holding casing pressure constant. 6. Follow drill pipe schedule until kill weight mud to the bit.

7. Hold drill pipe pressure constant once kill weight mud out of the bit until complete circulation. 8. Check mud weight out and ensure that mud weight out is equal to kill mud weight.

9. Shut down and flow check to confirm if a well is static. 10. Circulate and condition mud if required.

Maximum pit gain from gas kick in water based mud

In water based mud, you can not only estimate the maximum surface casing pressure, but you are also be able to determine the maximum pit gain due to gas influx.

The following formula demonstrates how to figure out the maximum pit gain from gas influx in water based mud system.

Maximum Pit Gain in bbl P is formation pressure in psi. V is original pit gain in bbl. C is annular capacity in bbl/ft. Kill Weight Mud in ppg

Let’s take a look at this following example in order to get more understanding regarding this topic.

Drill well with water based mud.

Pit gain = 20 bbl Initial shut in casing pressure = 600 psi Initial shut in drill pipe pressure = 500 psi Current mud weight = 12.5 ppg Hole depth = 6,000’MD/4,800’TVD Hole diameter = 12-1/4 inch

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Drill pipe = 5 inch

According to the data, you need to figure out the Kill Mud Weight, formation pressure, and annular capacity.

Kill Weight Mud = current mud weight + (shut in drill pipe pressure ÷ (0.052 x TVD))

Kill Weight Mud = 12.5 + (500 ÷ (0.052 x 4800)) = 14.5 ppg

Formation pressure = surface pressure + hydrostatic pressure

Formation pressure = 500 + (0.052 x 12.5 x 4800) = 3620 psi

Determine annular capacity: Annular capacity = (12.252_{– 5}2_{) ÷ 1029.4 = 0.1215 bbl/ft}

Once you get all parameters required, you can add all of them into the equation like this.

Maximum Pit Gain = 98.5 bbl

Maximum Surface Pressure from Gas Influx in Water Based Mud

When a well is shut in due to well control operation, the casing pressure will increase due to gas migration and gas expansion. In water based mud, you are able to estimate the maximum surface pressure with this following formula.

Max surface pressure in psi. P is expected formation pressure in psi. V is pit volume gain in bbl. KWM is kill weight mud in ppg. An is an annular capacity in bbl/ft.

We can easily estimate surface pressure in water based mud because gas kick is not soluble in

water based mud. On the other hand, with oil based mud, you will not be able to use this

equation because you will not see the real volume of gas kick due to gas solubility in oil.

Determine the maximum surface pressure.

Drill well with water based mud.

Pit gain = 25 bbl Stabilized casing pressure = 600 psi

Initial drill pipe pressure = 450 psi Current mud weight = 12.0 ppg Hole depth = 10,000’MD/9,500’TVD Hole diameter = 8.5 inch

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Drill pipe = 5 inch

Determine kill weight mud with this equation:

KMW = current mud weight + (drill pipe pressure ÷ (0.052 x Hole TVD)). KMW = 12.0 + (450 ÷ (0.052 x 9500)) = 12.91

You need to round the kill weight mud up; therefore, KMW is 13.0 ppg.

Determine formation pressure.

Formation pressure = surface pressure + hydrostatic pressure Formation pressure = 450 + (0.052 x 12.0 x 9500) = 6378 psi

Determine annular capacity: Annular capacity = (8.52 – 52) ÷ 1029.4 = 0.0459 bbl/ft

Once you get all parameters you need, you can determine a figure.

Maximum surface pressure = 1344 psi.

Formation Pressure from Kick Analysis

Once you shut in the well in and obtain shut in drill pipe pressure, you can estimate formation pressure by applying the hydrostatic pressure concept.

This following equation demonstrates you how to figure out formation pressure from the kick analysis.

Formation Pressure = SIDDP + (0.052 x Hole TVD x Current Mud Weight)

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Formation Pressure from Kick Analysis

Formation Pressure in psi SIDDP (shut in drill pipe pressure) in psi Hole TVD (true vertical depth) in ft Current Mud Weight in ppg

Example: Well depth = 8,500′MD/8,000 TVD.

SIDPP = 300 psi

Current mud weight = 10.0 ppg What is the formation pressure in psi?

Formation Pressure = 300+ (0.052 x 8000 x 10.0)

Formation pressure = 4,460 psi

Drill Pipe Pressure Schedule Calculation for Wait and Weight Well Control

Method

Current mud weight = 9.5 ppg Pump output = 0.1 bbl/stroke

Well depth = 9000’MD/9000’TVD Drill string capacity = 0.0178 bbl/ft Surface line volume = 15 bbl. Shut in casing pressure = 700 psi Shut in drill pipe pressure = 500 psi ICP = 1600 psi at 30 spm as kill rate

Please follow steps below to determine the drill pipe pressure schedule (step down chart).

Determine kill weight mud

KWM = OMW + [SIDPP ÷ (0.052 x TVD)]

Where;

KWM is kill weight mud in ppg. OMW is original mud weight in ppg. SIDPP is shut in drill pipe pressure in psi. TVD is true vertical depth of the well in ft. KWM = 9.5+ [500 ÷ (0.052 x 9000)]

KMW = 10.6 ppg

Determine Slow Circulating Rate (SCR) SCR = ICP – SIDPP

SCR is slow circulating rate in psi. ICP is initial circulating pressure in psi. SIDPP is shut in drill pipe pressure in psi. SCR = 1600 – 500 = 1100 psi

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Determine Final Circulating Pressure (FCP) FCP = SCR x KWM ÷ OMW

FCP is final circulating pressure in psi. SCR is slow circulating rate in psi. KWM is kill weight mud in ppg. OMW is original mud weight in ppg.

FCP = 1100 x 10.6 ÷ 9.5 = 1227 psi

Determine stroke from surface to bit

Drill string volume = Drill pipe capacity x TD ÷ Pump output

Drill sting volume is in strokes. Drill pipe capacity is in bbl/ft. TD is well measured depth in ft. Pump output in bbl/stroke. Drill string volume = 0.0178 x 9000 ÷ 0.1 = 1602 strokes

According to this example, you need 1602 stokes in order to bring kill mud to the bit and drill pipe pressure will change from 1600 psi (ICP) to 1227 psi (FCP) within 1602 strokes.

Hence pressure drop per stoke is (ICP – FCP) ÷ surface to bit (1600 – 1227) ÷ 1602 = 0.2328 psi/stroke

This figure (0.2328 psi/stroke) is very small and difficult to make adjustment with equipment on the rig. Therefore, you need to know how much pressure drop per required strokes. For this example, I will determine pressure drop per 200 strokes.

Drill pipe pressure drop = 0.2328 x 200 = 47 psi

Then we need to create a table showing pressure schedule.

For the first line, you need 150 stokes to bring KWM to the rotary table then drill pipe pressure will be dropped approximately 47psi/200 strokes until it reach 1227 which is the final circulating pressure.

The step down table look like this.

Strokes Drill Pipe

Pressure (psi) Remarks

150 1600 You need to pump 150 stokes in order tobring kill from mud pump to rotary table

350 1554 DP drops 47 psi/200 strokes. 550 1506 DP drops 47 psi/200 strokes.

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750 1459 DP drops 47 psi/200 strokes. 950 1412 DP drops 47 psi/200 strokes. 1150 1365 DP drops 47 psi/200 strokes. 1350 1318 DP drops 47 psi/200 strokes. 1550 1271 DP drops 47 psi/200 strokes. 1750 1227 Final circulating pressure

Pressure Profile of Drillpipe and Casing Pressure while killing a well with wait and weight method

Firstly, we will take a look at the drillpipe pressure. When kill weight mud is displaced in the well, drill pipe pressure drops as per the drill pipe schedule. Once kill weight mud is to the bit, drill pipe pressure is maintained until the well is killed. A pressure profile will look like the following chart.

Casing Pressure

Secondly, we will take a look at the casing pressure. The casing pressure will increase because gas expansion while it is being circulated. The maximum casing pressure occurs when gas reaches at surface. Then casing pressure will drop rapidly because gas is coming out on surface. Once gas is totally removed from the surface, there is still some casing pressure due to original mud weight. The casing pressure will gradually decrease and drop to 0 psi which means the well

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is killed with the kill weight mud. A pressure profile demonstrates how casing pressure acts while circulating.

Volumetric Well Control

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 as

P1 x V1 = P2 x V1

P1 = pressure of gas at the first condition V1 = volume of gas at the first condition P2 = pressure of gas at the second condition V2 = volume of gas at the second condition 2. Hydrostatic pressure – Hydrostatic pressure is pressure created by column of fluid. Two

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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.

3. 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) = (OD2-ID2) ÷ 1029.4

ACF = Annular Capacity Factor in bbl/ft OD = Outside Diameter of Annular in inch ID = Inside Diameter of Annular in inch

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Once the ACF is known, 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)

PI = Pressure Increment in psi ACF = Annular Capacity Factor in bbl/ft MW = Mud Weight in the well in ppg

Lubrication or top kill

This method of lubricating gas out of a well is more accurate than the standard lubricating procedure if the well is taking fluid. Comparing the actual and modeled pressures helps quickly spot common sources of error that complicate standard lubrication procedures.

There are two common lubrication procedures:

 Pumping a kill fluid, waiting, and bleeding off pressure

 Continued circulation across the top of the well (the dynamic lubrication procedure). The pump, wait, and bleed method is most commonly used and may require numerous cycles to remove the gas completely. Both methods involve the coordinated use of a pump, a choke, and an accurate measuring tank.

CONVENTIONAL LUBRICATION

The pump, wait, and bleed lubrication procedure involves the following steps:

 Pump fluid into a closed-in well (the surface pressure increases because of fluid compression).

 Allow sufficient time for the fluid to lubricate (fall or slip through the column of gas).

 Determine the hydrostatic pressure of the fluid volume lubricated for the particular cycle. The following formulas can be used to determine the hydrostatic pressure increase after each lubrication cycle:

Hydrostatic increase = (hydrostatic head per barrel of lubricating fluid) x (volume lubricated per cycle).

Hydrostatic head per barrel of lubricating fluid = (fluid -gradient)/(capacity).

The capacity is the linear volume in bbl/ft of the annulus, tubing, or casing, depending on the location of the gas.

 Bleed gas through the choke to reduce bottom-hole pressure by the increase from the compression of the gas and the hydrostatic increase from the lubricating fluid.

The use of this procedure can be tiresome and requires complicated calculations that sometimes prove difficult for field use. The bottom-hole pressure before and after each cycle should be nearly the same. Several sources of error, however, may contribute to differences in bottom hole pressures:

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 The volume measurements are inaccurate because of measuring tank design (excessive surface area), gas-cut fluids bled off, and insufficient time for fluid to lubricate through the gas.

 The well bore is accepting fluids. For example, the fluid can enter open perforations in completed wells, or the fluid can be squeezed into weak zones or below the casing shoe in open well bores.

 The calculations are field dependent.

NEW PROCEDURE

For a gas well, one of the first decisions is whether to bullhead or lubricate for the kill. Fig. 1 is a general schematic of a well type that was often bullheaded dead by the operator. These wells often required several tubing volumes for the kill operation. Because the bullheading operation was thought to damage the formation, a lubrication procedure was later used. The sources of error with the standard lubrication procedure made the process difficult, and excessive amounts of completion brine were still lost to the formation.

The lubrication procedure can be easier and more accurate to use if the following three pressures are properly accounted for during each lubrication cycle: the initial pressure prior to lubrication (P1), the compression pressure increase from pumping in the lubricating fluid (P2), and the final pressure reached after the gas is vented (P3).

Given the following assumptions, Equations 1 and 2 define the lubricating pressure relationships:

 The product of the pressure times the volume of gas remains constant (P1V1 P2V2).

 The lubricating fluid density, once the gas has been displaced, will balance (or overbalance) the formation pressure.

 Only gas is bled from the well.

Equation 1 is for vertical or constant-drift directional wells, and Equation 2 is for deviated wells. The simplicity of Equation 1 makes it well-suited to most lubrication applications. Most often, lubrication is required to remove a vertical column of gas.

Stripping (using Annular Preventer)

The act of putting drillpipe into the wellbore when the blowout preventers (BOPs) are closed and pressure is contained in the well. This is necessary when a kick is taken, since well kill

operations should always be conducted with the drillstring on bottom, and not somewhere up the wellbore. If only the annular BOP has been closed, the drillpipe may be slowly and carefully lowered into the wellbore, and the BOP itself will open slightly to permit the larger diameter tool joints to pass through. If the well has been closed with the use of ram BOPs, the tool joints will not pass by the closed ram element. Hence, while keeping the well closed with either another ram or the annular BOP, the ram must be opened manually, then the pipe lowered until the tool joint is just below the ram, and then the ram closed again. This procedure is repeated whenever a tool joint must pass by a ram BOP. Rig crews are usually required to practice ram-to-ram and ram-to-annular stripping operations as part of their well control certifications. In stripping operations, the combination of the pressure in the well and the weight of the drillstring is such

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that the pipe falls in the hole under its own weight, whereas in snubbing operations the pipe must be pushed into the hole.

Snubbing

The act of putting drillpipe into the wellbore when the blowout preventers (BOPs) are closed and pressure is contained in the well. Snubbing is necessary when a kick is taken, since well kill operations should always be conducted with the drillstring on bottom, and not somewhere up the wellbore. If only the annular BOP has been closed, the drillpipe may be slowly and carefully lowered into the wellbore, and the BOP itself will open slightly to permit the larger diameter tool joints to pass through. If the well has been closed with the use of ram BOPs, the tool joints will not pass by the closed ram element. Hence, while keeping the well closed with either another ram BOP or the annular BOP, the ram must be opened manually, then the pipe lowered until the tool joint is just below the ram, and then closing the ram again. This procedure is repeated whenever a tool joint must pass by a ram BOP. In snubbing operations, the pressure in the wellbore acting on the cross-sectional area of the tubular can exert sufficient force to overcome the weight of the drillstring, so the string must be pushed (or "snubbed") back into the wellbore. In ordinary stripping operations, the pipe falls into the wellbore under its own weight, and no additional downward force or pushing is required.

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Stripping using ram preventer

A ram-type blowout preventer used to provide primary pressure control in high-pressure snubbing operations. Stripping rams are used when the wellhead pressure is higher than the limitations of a stripper bowl.

Stripping with an Annular BOP

Drill pipe can be rotated and tool joints stripped through a closed packer, while maintaining a full seal on the drill pipe. Longest packer life is obtained by adjusting the closing chamber pressure just low enough to maintain a seal on the drill pipe with a slight amount of drilling fluid leakage as the tool joint passes through the packer. The leakage indicates the lowest usable closing pressure for minimum packer wear and provides lubrication for the drill pipe motion through the packer.

A pressure regulator valve should be set to maintain the proper closing pressure. For stripping purposes, the regulator valve is usually too small and cannot respond fast enough for effective control, so a surge bottle is connected as closely as possible to the BOP closing port (particularly for subsea installations). The surge bottle is precharged with nitrogen, and is installed in the BOP closing line in order to reduce the pressure surge which occurs each time a tool joint enters the closed packer during stripping. A properly installed surge bottle helps reduce packer wear when stripping. Check manufacturer’s recommendations for proper nitrogen precharge pressure for your particular operating requirements. In subsea operations, it is advisable to add an

accumulator to the opening chamber line to prevent undesirable pressure variations.

Ram type BOP

A ram-type blowout preventer is basically a large bore valve (see Figure 1B). The ram blowout preventer is designed to seal off the well bore when pipe, casing, or tubing is in the well. In a BOP stack, ram preventers are located between the annular BOP and the wellhead (see Figure 2B). There are typically 3 or 4 ram preventers in a BOP stack. Flanged or hubbed side outlets are located on one or both sides of the ram BOPs. These outlets are sometimes used to attach the valved choke and kill lines to. The outlets enter the wellbore of the ram preventer immediately under the ram cavity.

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Figure 2 Figure 3

Other than sealing off the well bore, rams can be used to hang-off the drill string. A pipe ram, closed around the drill pipe with the tool-joint resting on the top of the ram, can hold up to 600,000 lbs. of drill string.

How wait and weight method controls bottom hole pressure

There are 2 steps that must be took into consideration separately. The first one is when kill weight mud is displaced to the bit and the second one is when the kill weight mud from bit to surface.

1) Displace kill weight mud to the bit

Once kill weight mud is mixed and displaced into drill pipe, drill pipe pressure will be decreased due to increasing in hydrostatic pressure. In order to control bottom hole pressure, a drill pipe

pressure schedule must be developed and followed until kill mud weight to the bit.

Take a look at the equation:

Pressure in drillpipe side = BHP = Pressure in casing side

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DPP is drill pipe pressure. HP is hydrostatic pressure. Frictional P is frictional pressure. CP is casing pressure.

At drillpipe side:

DPP will drop when kill mud weight is displaced. HP will increase due to kill mud weight in the drillstring. Friction P in drillstring will not change so much.

At casing side:

HP will decrease due to gas expansion in the annulus.

CP will increase in order to compensate hydrostatic pressure loss.

Frictional P in annulus had minimal effect on bottom hole pressure due to slow flow rate while killing the well.

2) Displace kill weight mud from bit to surface

Once the kill weight mud comes out of the bit, there is one single column of hydrostatic in the drillstring. Therefore, in order to maintain bottom hole pressure constant, drill pipe pressure

must be maintained while displacing.

Conclusion:

• Use the drill pipe pressure schedule to control constant bottom hole pressure while displacing kill weight mud to the bit.

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Additional Topics

Well kill

A well kill is the operation of placing a column of heavy fluid into a well bore in order to prevent the flow of reservoir fluids without the need for pressure control equipment at the surface. It works on the principle that the hydrostatic head of the "kill fluid" or "kill mud" will be enough to suppress the pressure of the formation fluids. Well kills may be planned in the case of advanced interventions such as workover, or be contingency operations. The situation calling for a well kill will dictate the method taken.

Methods of well kill

Reverse circulation Bullheading

Forward circulation Lubricate and bleed

Well Shut-in

An oil or gas well that is closed off; the well is shut so that it does not produce a fluid product of any kind. When one or more warning signs of kicks are observed, steps should be taken to shut in the well. If there is any doubt that the well is flowing, shut it in and check the pressures. It is important to remember that there is no difference between a small-flow well and a full-flowing well, because both can very quickly turn into a big blowout.

Drilling—land or bottom-supported offshore rig

When a primary kick warning sign has been observed, do the following immediately: 1. Raise the Kelly until a tool joint is above the rotary table.

2. Stop the mud pumps. 3. Close the annular preventer. 4. Notify company personnel.

5. Read and record the shut-in drillpipe pressure, the shut-in casing pressure, and the pit gain.

Raising the Kelly is an important procedure. With the Kelly out of the hole, the valve at the bottom of the Kelly can be closed if necessary. Also, the annular-preventer members can attain a more secure seal on the pipe than a Kelly.

Tripping—land or bottom-supported offshore rig

A high percentage of well-control problems occur when a trip is being made. The kick problems may be compounded when the rig crew is preoccupied with the trip mechanics and fails to observe the initial warning signs of the kick.

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Shut-in procedures

When a primary warning sign of a kick has been observed, do the following immediately: 1. Set the top tool joint on the slips.

2. Install and make up a full-opening, fully opened safety valve on the drillpipe. 3. Close the safety valve and the annular preventer.

4. Notify company personnel. 5. Pick up and make up the Kelly. 6. Open the safety valve.

7. Read and record the shut-in drillpipe pressure, shut-in casing pressure, and pit gain. Installing a fully opened, full-opening safety valve in preference to an inside blowout preventer (BOP), or float, valve is a prime consideration because of the advantages offered by the full-opening valve. If flow is encountered up the drillpipe as a result of a trip kick, the fully opened, full-opening valve is physically easier to stab. Also, a float-type inside-BOP valve would automatically close when the upward-moving fluid contacts the valve.

If wireline work, such as drillpipe perforating or logging, becomes necessary, the full-opening valve will accept logging tools approximately equal to its inside diameter, whereas the float valve may prohibit wireline work altogether. After the kick is shut in, an inside-BOP float valve may be stabbed on the full-opening valve to allow stripping operations.

Pump Output Calculation for Duplex Pump and Triplex Pump

Rig pump output, normally in bbl per stroke, of mud pumps on the rig is important figures that

we really need to know because we will use pump output figures to calculates many things such as bottom up strokes, wash out depth, tracking drilling fluid, etc. In this post, you will learn how to calculate pump output for triplex pump and duplex pump.

Triplex Pump Output Formula

Triplex Pump Output in bbl/stk = 0.000243 x (liner diameter in inch) 2 X (stroke length in inch)

Example: Determine the pump output in bbl/stk at 100% and 97% efficiency

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Triplex pump output: PO @ 100% = 0.000243 x 62 x 12 PO @ 100% = 0.104976 bbl/stk

Adjust the triplex pump output for 97% efficiency: Decimal equivalent = 97 ÷ 100 = 0.97 PO @ 97% = 0.104976 bbl/stk x 0.97 PO @ 97% = 0.101827 bbl/stk

Duplex Pump Output Formula

Duplex Pump Output in bbl/stk = 0.000162 x S x [2(D)2 - d2]

D = liner diameter in inch S = stroke length in inch d = rod diameter in inch

Example: Determine the duplex pump output in bbl/stk at 100% and 85% efficiency

Liner diameter = 6 inch Stroke length = 12 inch

Rod diameter = 2.0 in. Duplex pump efficiency = 100 %.

PO @ 100% = 0.000162 x 12 x [2 (6) 2 -22 ] PO @ 100% = 0.13219 bbl/stk Adjust pump output for 85% efficiency:

PO @ 85% = 0.132192 bbl/stk x 0.85 PO @ 85% = 0.11236 bbl/stk

Calculate inner capacity of open hole/inside cylindrical objects

There are several formulas to calculate inner capacity depending on unit of inner capacity required. Please read and understand the formulas below:

Formula#1) Calculate inner capacity in bbl/ft Inner Capacity in bbl/ft = (ID in.)2_÷1029.4

Example: Determine inner capacity in bbl/ft of a 6-1/8 in. hole:

Inner Capacity in bbl/ft = 6.1252÷1029.4 Inner Capacity in bbl/ft = 0. 0364 bbl/ft

Formula#2) Calculate inner capacity in ft/bbl

Example: Determine inner capacity in ft/bbl of 6-1/8 in. hole:

Inner Capacity in ft/bbl = 1029.4 ÷ 6.1252 Inner Capacity in = 27.439 ft/bbl Inner Capacity in ft/bbl = 1029.4 ÷ (ID in.)

Formula#3) Calculate inner capacity in gal/ft Inner Capacity in gal/ft = (ID in.)2_÷24.51

Example: Determine inner capacity in gal/ft of 6-1/8 in. hole:

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Formula#4) Calculate inner capacity in ft/gal Inner Capacity in ft/gal = 24.51 ÷ (ID in.)2

Example: Determine inner capacity in ft/gal of 6-1/8 in. hole:

Inner Capacity in ft/gal = 24.51 ÷ 6.1252 Inner Capacity in ft/gal = 0.6533 ft/gal

Determine the volume of mud to fill up the inner of the cylindrical objects by the following equation.

Inner Volume = Inner Capacity x Length

Example: Inner capacity = 0. 0364 bbl/ft Length = 3000 ft Volume = 0. 0364 x 3,000 = 109.2 bbl.

Day 2 IWCF

An Overview to IWCF

Well Control Certification Course

(DRILLER/SUPERVISOR LEVEL)

Day 2

Prepared by:

Table of Contents

DAY-2 --- Session – I

Gas influx behavior

Closed-in (Shut-in) conditions migration

Well killing Driller's method

Bottom hole pressure change while performing well control operation with

driller’s method

How are pressure and pit volume doing during the first circulation of the

driller’s method?

Establish Circulation in Driller’s Method

Additional Topics

EQUIVALENT CIRCULATING DENSITY (ECD)

Volumetric Well Control – When It Will Be Used

Gas Behavior and Bottom Hole Pressure in a Shut in well

DAY-2 --- Session - II

Well Kill Using Wait and Weight Method (Balanced Method)

(

) ∗ 𝑆𝐶𝑅𝑃(𝑝𝑠𝑖)

Wait and Weight Well Control Method (Engineer’s Method)

Maximum pit gain from gas kick in water based mud

Maximum Surface Pressure from Gas Influx in Water Based Mud

Formation Pressure from Kick Analysis

Drill Pipe Pressure Schedule Calculation for Wait and Weight Well Control

Method

Volumetric Well Control

Lubrication or top kill

Stripping (using Annular Preventer)

Snubbing

Stripping using ram preventer

How wait and weight method controls bottom hole pressure

Additional Topics

Well kill

Well Shut-in

Pump Output Calculation for Duplex Pump and Triplex Pump

Calculate inner capacity of open hole/inside cylindrical objects